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, 1994

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
(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
Preferred Stock Purchase Rights New York Stock Exchange
Pacific Stock Exchange
12 3/4% Subordinated Debentures due New York Stock Exchange
March 15, 2001
13% Exchange Notes due New York Stock Exchange
December 1, 2000

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 March 1, 1995, the aggregate market value of the voting stock held by
nonaffiliates of the registrant was approximately $254,557,348 based upon the
closing price of its shares on the New York Stock Exchange Composite tape. At
March 1, 1995, there were 24,534,430 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 1995 Annual Meeting Part III

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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 in petroleum refining and
marketing, natural gas exploration and production, and wholesale marketing of
fuel and lubricants. 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.

During 1994, the Company consummated a recapitalization plan and equity
offering whereby a major portion of the Company's outstanding debt was
restructured and all of its preferred stock and dividend arrearages were
eliminated and which, among other matters, deferred $44 million of debt service
requirements, increased stockholders' equity by approximately $82 million and
eliminated $9.2 million of annual preferred dividend requirements. In addition,
the recapitalization enabled the Company to enter into a $125 million corporate
Revolving Credit Facility and obtain $15 million financing for a major addition
to the Company's refinery. For further information concerning the
recapitalization and offering, see Note C 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, in the area west of
the Rocky Mountains and in certain Far Eastern markets. During 1994, products
from the Company's refinery accounted for approximately 65% of such sales,
including products received on exchange in the U.S. West Coast market, with the
remaining 35% being purchased from other refiners and suppliers.

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 product. The refinery is designed to process crude oil with a
sulphur content of up to 1%. Alaska North Slope ("ANS") and Cook Inlet crude
oils, the primary crude oils currently used as feedstock for the refinery, are
below this limit. 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 1994, the refinery
processed approximately 59% ANS crude oil, 32% Cook Inlet crude oil and 9% other
refinery feedstocks, which yielded refined products consisting of approximately
25% gasoline, 43% middle distillates and refinery fuel and 32% of residual
product.

During 1994, the Company continued its operational strategy to improve the
refinery's economics, which included upgrading feedstocks, more closely matching
production with product demand within Alaska and initiating new marketing
efforts within and outside Alaska. These efforts reduced the Company's overall
refinery production in 1994, particularly residual fuel oil. The markets for
residual fuel oil have generally been weak for the past several years due to a
global oversupply of this product. During 1994, the Company reduced its average
daily refinery throughput and production by 7% from the 1993 levels, resulting
in a cumulative reduction from the 1992 levels of 25%. This reduction in
throughput enabled the Company to reduce the percentage of lower-quality ANS
crude oil in the feedstock mix to 59% in 1994, compared with 72% in 1993. By
utilizing a greater percentage of higher-quality feedstocks (which results in
higher-valued production yields), the Company can economically operate the
refinery at reduced throughput levels. Operating the refinery at lower
throughput levels resulted in less production of certain products, particularly
residual product, for which there is no significant market in Alaska.

The Company has installed a vacuum unit, which became operational in
December 1994, that is expected to reduce the refinery's yield of residual
product about 50% by further processing these volumes into higher-valued
products. With the vacuum unit now operational, the Company is pursuing
marketing initiatives to

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increase demand for the refinery's production which would increase the
refinery's capacity utilization and improve efficiencies.

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 1994, approximately 59% of the refinery's feedstock
was ANS crude oil, of which approximately 28,700 barrels per day were purchased
under a royalty crude oil purchase contract with the State, which expired at the
end of 1994. The Company and the State have extended this contract through 1995.
The agreement between the Company and the State requires the Company to purchase
approximately 40,000 barrels per day at the weighted average net-back price
reported by the three major North Slope producers for ANS crude oil delivered to
the U.S. West Coast. The Company does not currently anticipate increasing the
percentage of ANS crude oil utilized as feedstock at the refinery. Under its
agreement with the State, the Company has the right to sell or to exchange up to
20% of the ANS crude oil to be purchased from the State during 1995. The Company
is currently negotiating with the State for a new three-year contract for the
period January 1, 1996 through December 31, 1998. Based on preliminary
discussions with the State, the Company believes that a new contract will
provide for the purchase of approximately the same volumes of ANS royalty crude
oil as the current contract and believes that such crude oil will be priced at
the weighted average price reported to the State by a major North Slope producer
for ANS crude oil as valued at Pump Station No. 1 on the Trans Alaska Pipeline
System ("TAPS"). All ANS crude oil feedstock is delivered to the refinery by
tanker through the Kenai Pipe Line Company ("KPL") marine terminal. The Company
and KPL have entered into an agreement whereby the Company will purchase KPL,
subject to regulatory approval. The Company expects that this purchase
transaction will be consummated in early 1995.

COOK INLET CRUDE OIL. Cook Inlet crude oil, a lighter crude oil that
contains an average of .1% sulphur, accounted for approximately 32% of the
refinery's feedstock supply in 1994. The Company obtains Cook Inlet crude from
several producers on the Kenai Peninsula under short-term contracts. Cook Inlet
crude oil is delivered by tanker or through an existing pipeline to the
refinery.

OTHER SUPPLY. In 1994, the Company's refinery obtained approximately 9% of
its feedstock supply from other sources. This feedstock supply was primarily
heavy atmospheric gas oil ("HAGO") and was purchased from a local competitor's
refineries and from a U.S. West Coast refinery under short-term contracts. HAGO
is a refinery byproduct which generates various light refined products with no
residual fuel oil.

From time to time, the Company evaluates the economic viability of
processing foreign crude oil in its Alaska refinery and occasionally purchases
spot quantities to supplement its normal crude oil supply. This foreign crude
oil is also delivered to the refinery by tanker through the KPL marine terminal.

ANS AGREEMENT. In January 1993, the Company entered into an agreement with
the State ("ANS Agreement") that settled a contractual dispute concerning the
value of ANS royalty crude oil sold to the Company. The ANS Agreement provided
that $97.1 million was owed to the State by the Company. Under the ANS
Agreement, the Company paid the State $10.3 million in January 1993 and is
obligated to make variable monthly payments to the State through December 2001
on a per barrel charge that is currently 16 cents and increases to 33 cents on
the volume of feedstock processed at the Company's refinery. In 1994 and 1993,
the Company's variable payments to the State totaled $2.8 million and $2.6
million, respectively. 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 December 2001 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 variable monthly payments are secured
by a mortgage on the Company's refinery. The Company's obligations under the ANS
Agreement and the mortgage may be subordinated to current and future senior debt
obligations (including, without limitation, principal, interest and related
expenses) of up to $175 million plus any indebtedness incurred subsequent to the
date of the

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Agreement to improve the Company's refinery. For further information concerning
the Company's settlement with the State, see Note I of Notes to Consolidated
Financial Statements in Item 8.

REFINING AND MARKETING ACTIVITIES

The following table summarizes the Company's refining and marketing
operations for the three years ended December 31, 1994, 1993 and 1992:

YEARS ENDED DECEMBER 31,
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1994 1993 1992
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Refinery Throughput (average daily barrels)...................... 46,032 49,753 61,425
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Refinery Production (average daily barrels):
Gasoline....................................................... 11,728 12,021 14,188
Middle distillates............................................. 18,839 19,441 23,305
Heavy oils and residual product................................ 15,118 17,573 23,444
Refinery fuel.................................................. 1,776 2,046 2,491
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Total Refinery Production.............................. 47,461 51,081 63,428
====== ====== ======
Product Sales (average daily barrels):
Gasoline....................................................... 23,191 22,466 25,196
Middle distillates............................................. 33,256 29,354 38,313
Heavy oils and residual product................................ 14,228 16,945 23,931
------ ------ ------
Total Product Sales.................................... 70,675 68,765 87,440
====== ====== ======
Product Sales Prices ($/barrel):
Gasoline....................................................... $27.03 27.82 28.89
Middle distillates............................................. $24.47 27.39 26.93
Heavy oils and residual product................................ $10.93 11.19 11.60

ALASKA MARKETING

GASOLINE. In 1994, the Company distributed virtually all of the gasoline
produced at the refinery to end users in Alaska, either by retail sales through
its 7-Eleven convenience store locations and two other Company operated
locations, by wholesale sales through 88 branded and 24 unbranded dealers and
jobbers and by deliveries to two major oil companies for their retail operations
in Alaska in exchange for gasoline delivered to the Company on the U.S. West
Coast. During 1994, the Company's refinery production of gasoline was
essentially balanced with the Alaskan market demand. The Company holds an
exclusive license agreement for all 7-Eleven convenience stores in Alaska and
operates such stores in 38 locations, 32 of which sell Company-branded gasoline.
During 1994, these convenience stores sold an average of 71,100 gallons of
gasoline per day.

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 the 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 and other distillate
production is sold on a wholesale basis in Alaska primarily for marine and
industrial purposes. Approximately 6% of the Company's diesel fuel production in
1994 was sold for on-highway use. 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. 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.

HEAVY OILS AND RESIDUAL PRODUCT. Since there is no significant demand for
heavy oils and residual product in Alaska, substantially all of the Company's
refinery production of such products is exported from Alaska. During 1994, the
Company sold and transported a substantial volume of its residual product to the
U.S. West Coast, where it was generally used as a refinery feedstock. Prior to
1993, the Company's primary market for residual product was the Far Eastern
bunker fuel markets. Marketing the residual product as a

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feedstock has reduced the Company's exposure to the pricing volatility that
exists in the Far Eastern bunker fuel markets. In addition, the refinery's
reduced throughput and reduction of ANS crude oil as a percentage of total
feedstock during 1994 caused residual product output to decrease from
approximately 17,600 barrels per day in 1993 to approximately 15,100 barrels per
day during 1994. The Company has recently completed the installation of a vacuum
unit at the refinery at a cost of $25 million. The vacuum unit, which uses
residual product as a feedstock, is anticipated to reduce the refinery's yield
of residual product by approximately 50% 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.

U.S. WEST COAST MARKETING

The Company conducts domestic wholesale marketing operations, primarily in
California, Oregon and Washington with its principal office located in Long
Beach, California. During 1994, these operations sold approximately 31,400
barrels per day of refined products, of which approximately 30% was received
from major oil companies in exchange for products from the Company's refinery
and 70% was purchased from other suppliers. The Company sells these refined
products in the bulk market and through 27 terminal locations, of which four are
owned by the Company.

TRANSPORTATION

In October 1994, the Company chartered an American flag vessel, the Potomac
Trader, under a charter agreement expiring in September 1996 with two one-year
renewal options. The Potomac Trader is used primarily to transport ANS crude oil
from the TAPS terminal at Valdez, Alaska to the Company's refinery. The Potomac
Trader is smaller and less expensive than the previous vessel utilized by the
Company and better matches the Company's logistical requirements. The Company
also has a charter for another American flag vessel, the Baltimore Trader, under
a one-year agreement expiring in January 1996. The Baltimore Trader is used to
transport residual product to the U.S. West Coast and occasionally to transport
feedstocks to the Company's refinery. 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 1994, the pipeline
transported an average of approximately 23,800 barrels of petroleum 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

UNITED STATES

During 1994, the Company concentrated its activities in the Bob West Field,
which is located in the southern part of the Wilcox Trend in Starr and Zapata
Counties, Texas. The Company, which does not operate the field, owns an average
50% revenue interest in approximately two-thirds of the field and a 28% revenue
interest in the remainder. Pursuant to an agreement with the operator, the
Company has an option with respect to the 50% revenue interest portion of the
field to elect, subject to certain conditions, to assume operations of that
portion of the field. The Wilcox Trend extends from Northern Mexico through
South Texas into Western Louisiana. 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, discovered in
1990, has resulted in the Company's net proven natural gas reserves increasing
from 120 billion cubic feet ("Bcf") at December 31, 1993 to 129 Bcf at December
31, 1994, reflecting a replacement of 129% of 1994 production. Two exploratory
and 20 development wells were drilled and

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completed in this field during 1994, bringing the number of producing wells to
46 at December 31, 1994 with an additional two wells being drilled and four
wells awaiting completion at year-end. Of these six additional wells, two were
subsequently completed as producing wells and the remainder are in the
completion phase. Twenty-four additional well locations have been selected for
further development of this 4,000-acre field, most of which are expected to be
drilled during 1995 and 1996, the timing of which is dependent upon, among other
factors, the price the Company receives for its natural gas production. During
December 1994, the Company's net production from the Bob West Field wells
averaged approximately 130 million cubic feet ("Mmcf") per day, which
represented approximately 90% of the Company's year-end 1994 net deliverability.
From time to time, the Company may increase or decrease its natural gas
production in response to market conditions. Due to weakened spot market natural
gas prices, beginning in January 1995, the Company and one of its partners
initiated a voluntary reduction of natural gas production sold in the spot
market. The Company's share of this reduction is estimated to be approximately
34 Mmcf per day, representing 33% of the Company's estimated current net
deliverability of natural gas available for sale in the spot market. This
voluntary reduction has continued through February 1995. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Exploration and Production".

In addition to the continued development of the Bob West Field, during 1994
the Company also participated in the drilling of five exploratory wells and one
unsuccessful development well in other areas of South Texas. One of the
exploratory wells was successful, two were dry holes and two were in progress at
December 31, 1994. One of the wells in progress at year-end was subsequently
abandoned and the other is in the process of being completed.

TENNESSEE GAS CONTRACT. The Company has interests in two 352-acre
producing units in the Bob West Field that are subject to a Gas Purchase and
Sales Agreement (the "Tennessee Gas Contract") with Tennessee Gas Pipeline
Company ("Tennessee Gas") expiring on January 31, 1999. The Tennessee Gas
Contract requires Tennessee Gas to purchase gas from the two producing units at
escalating prices that are substantially above current spot market prices for
natural gas. During 1994, for example, Tennessee Gas purchased approximately 21%
of the Company's net gas production from the Bob West Field under the Tennessee
Gas Contract pursuant to a contract price of $8.01 per thousand cubic feet
("Mcf") which was substantially above the 1994 average spot market price of
$1.64 per Mcf. The Tennessee Gas Contract is presently the subject of litigation
with Tennessee Gas. In June 1992, the trial court returned a verdict in favor of
the Company upholding the terms of the Tennessee Gas Contract. The Court of
Appeals upheld the validity of the Tennessee Gas Contract but remanded the case
for further consideration of legal issues which might limit certain terms of the
Tennessee Gas Contract. The ruling of the Court of Appeals is presently being
reviewed by the Supreme Court of Texas. Pending the decision of the Supreme
Court of Texas, the trial court, pursuant to a bond hearing, ordered that
Tennessee Gas pay for gas at $3.00 per Mmbtu, which approximates $3.00 per Mcf
("Bond Price"), for the period September 17, 1994 through August 1, 1995 and
post a bond which, together with the anticipated sales of natural gas to
Tennessee Gas at the Bond Price, will equal the anticipated value of the
Tennessee Gas Contract during this interim period. The Bond Price is
nonrefundable by the Company, and the Company retains the right to receive the
full contract price for all gas sold to Tennessee Gas. Prior to the bond
hearing, the Company was receiving the contract price from Tennessee Gas for
purchases of gas under the Tennessee Gas Contract. The Company continues to
recognize revenues under the Tennessee Gas Contract based on the contract price.
See Legal Proceedings in Item 3 and Notes L and P of Notes to Consolidated
Financial Statements in Item 8.

GAS PROCESSING, GATHERING AND TRANSPORTATION. The Company owns a 70%
interest in the Bob West Field's central gas processing facility which was
expanded during 1994 to enable a processing capacity of 350 Mmcf per day. The
Company owns a 70% interest in Starr County Gathering System which consists of
two ten-inch diameter and one twenty-inch diameter pipelines that transport
natural gas eight miles from the field to common carrier pipeline facilities.
The Company does not operate either of such facilities. From February 1994 until
May 1994, the pipeline facilities were at capacity and production subject to
spot market prices was being curtailed. In 1994, the Company acquired a 50%
interest in a twenty-inch diameter natural gas pipeline that was constructed
during 1994 and which eliminated the curtailment of natural gas production
subject to spot market sales prices. The Company believes that these expansions
in pipeline capacity,

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gathering systems and processing capacities have minimized the risk of
significant marketing constraints for the foreseeable future.

BOLIVIA

The Company's Bolivian exploration and production operations are located in
southern Bolivia near the border with Argentina, where, since 1976, the Company
has discovered four significant natural gas fields. At December 31, 1994, Tesoro
was the second largest holder of proved natural gas reserves in Bolivia, with
estimated net proved natural gas reserves of 96 Bcf. The Company is the operator
of a joint venture that holds two Contracts of Operation with YPFB, the Bolivian
state-owned oil and gas company. The Company has a 75% interest in a Contract of
Operation, which expires in 2007, covering approximately 93,000 acres in Block
XVIII. The Company has drilled five exploratory wells and 12 development wells
within three separate fields in Block XVIII. During 1994, the Company's net
production from these fields averaged 22 Mmcf of gas per day and 733 barrels of
condensate per day, a production level that exceeded that of the average of the
prior three years, primarily due to the inability of another producer during
1994 to satisfy gas supply requirements. The Company and its joint venture
participant are entitled to receive a quantity of hydrocarbons equal to 40% of
the total production, net of Bolivian taxes and royalties on production, which
are payable in kind. The Company is currently selling all of its natural gas
production from the La Vertiente, Escondido and Taiguati Fields in Block XVIII
to YPFB which in turn sells the natural gas to Yacimientos Petroliferos
Fiscales, S.A.("YPF"), a publicly-held company based in Argentina. The contract
between YPFB and YPF was recently extended through March 31, 1997. The contract
extension maintained approximately the same volumes as their previous contract,
but with a small decrease in price. The Company's contract for the sale of
natural gas to YPFB has expired and is subject to renegotiation. The Company is
currently selling its natural gas production to YPFB based on the pricing terms
in the contract between YPFB and YPF. The Company anticipates that any
renegotiation of its contract with YPFB will result in the Company receiving a
lower price than it received under its previous contract with YPFB. Any
renegotiation may result in a reduction of volumes purchased from the Company
due to new supply sources that commenced production near the end of 1994.

The Company has a 72.6% interest in a Contract of Operation, which expires
in 2008, covering approximately 1.2 million acres in Block XX. The Company and
its joint venture participant are entitled to receive a quantity of hydrocarbons
equal to 50% of the total production, net of Bolivian taxes and royalties on
production, which are payable in kind. The development of Block XX is currently
limited by a lack of access to major gas-consuming markets. Prior to 1993, one
successful commercial gas discovery well, the Los Suris No. 1, was drilled on
the block and is shut-in pending the approval by the Government of Bolivia of a
commercialization agreement. A work plan for Block XX that included a three-well
exploratory program was approved by YPFB and the Government of Bolivia. Under
the plan, the Company drilled a well, the Los Suris No. 2, which was completed
in February 1994 and tested gross production potential of approximately 9 Mmcf
of gas per day and approximately 120 barrels of condensate per day from two
producing intervals. The Los Suris No. 2 is also shut-in pending the approval of
a commercialization agreement. The second exploratory well, San Antonio X-1, was
abandoned in September 1994 and Palo Marcado X-3, the third exploratory well,
was spudded in December 1994 and is currently being drilled to a proposed depth
of 3,000 meters. To guarantee the drilling of the second and third exploratory
wells, the Company submitted bank guarantees to YPFB in the aggregate amount of
$4.0 million. Upon abandonment of the San Antonio X-1, YPFB released the Company
from the first $2.0 million guarantee. The Company may postpone the
relinquishment of inactive acreage until July 15, 1996 by submitting, no later
than July 1, 1995, an additional two-well drilling program that is acceptable to
YPFB.

During 1994, feasibility studies proceeded for several pipeline projects to
new markets in Brazil, Chile and Paraguay. In August 1994, the governments of
Brazil and Bolivia announced an extension of their previous agreement to jointly
construct a pipeline from gas fields in Bolivia to the industrial area along the
Atlantic seaboard of Brazil. Both YPFB and Petrobras, the Brazilian state-owned
petroleum company, have selected natural gas transmission industry partners for
their respective portions of this project. A preliminary

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financing proposal has been announced for the Brazilian pipeline project,
although no final decision on the construction or the completion date of this
pipeline has been made.

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

OPERATING STATISTICS

The following table summarizes the Company's exploration and production
activities for the years ended December 31, 1994, 1993 and 1992. Effective May
1, 1992, the Company sold its Indonesian operations:

YEARS ENDED DECEMBER 31,
------------------------------
1994 1993 1992
-------- ------ ------

Net Natural Gas Production (average daily Mcf):
United States(1)............................................. 83,796 38,767 13,960
Bolivia(2)................................................... 22,082 19,232 19,421
-------- ------ ------
Total................................................ 105,878 57,999 33,381
======== ====== ======
Net Crude Oil Production (average barrels per day):
Bolivia (condensate)......................................... 733 663 660
Indonesia.................................................... -- -- 2,714
-------- ------ ------
Total................................................ 733 663 3,374
======== ====== ======
Average Realized Sales Prices -- Natural Gas (per Mcf):
United States(1)............................................. $ 3.00 3.55 3.68
Bolivia...................................................... $ 1.20 1.22 1.67
Average Realized Sales Prices -- Crude Oil (per barrel):
Bolivia (condensate)......................................... $ 13.28 14.26 17.65
Indonesia.................................................... $ -- -- 18.20
Average Lifting Cost (per net equivalent Mcf):
United States(3)............................................. $ .45 .48 .74
Bolivia...................................................... $ .06 .14 .08
Indonesia.................................................... $ -- -- 1.94
Depletion Rates (per net equivalent Mcf):
United States................................................ $ .79 .78 .95
Indonesia.................................................... $ -- -- .15
Net Exploratory Wells Drilled:
United States --
Net productive wells...................................... 1.53 .38 1.00
Net dry holes............................................. 1.12 .50 .50
Net Development Wells Drilled:
Net productive wells --
United States............................................. 11.09 7.87 3.85
Indonesia................................................. -- -- --
-------- ------ ------
Total................................................ 11.09 7.87 3.85
======== ====== ======
Net dry holes --
United States............................................. .38 -- --
Indonesia................................................. -- -- --
-------- ------ ------
Total................................................ .38 -- --
======== ====== ======

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(1) See Legal Proceedings in Item 3 and Note L of Notes to Consolidated
Financial Statements in Item 8 regarding litigation concerning the Tennessee
Gas contract.

(2) The Company's natural gas production from Bolivia as presented above
represents the Company's net production before Bolivian taxes.

(3) Average lifting costs for the Company's U.S. operations include such items
as severance taxes, property taxes, insurance, materials and supplies and
transportation of natural gas production through Company-owned pipelines.
Since severance taxes are based upon sales prices of natural gas, the
average lifting costs presented above include the impact of above-market
prices for sales under the Tennessee Gas Contract. Lifting costs per Mcf of
natural gas sold in the spot market were approximately $.38, $.39 and $.63
for 1994, 1993 and 1992, respectively.

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9

ACREAGE AND WELLS

The following table sets forth the Company's gross and net acreage and
productive wells at December 31, 1994:

DEVELOPED UNDEVELOPED
ACREAGE ACREAGE
------------- --------------
GROSS NET GROSS NET
----- --- ----- ----

Acreage (in thousands):
United States................................................ 4 2 8 3
Bolivia...................................................... 38 29 1,210 880
----- --- ----- ----
Total................................................ 42 31 1,218 883
==== === ===== ====

GROSS NET
----- ----

Productive Gas Wells:
United States............................................................. 48 26.8
Bolivia................................................................... 15 11.2
----- ----
Total*............................................................ 63 38.0
===== ====

- ---------------
* Included in total productive wells is 1 gross (.6 net) well in the United
States and 8 gross (6.0 net) wells in Bolivia with multiple completions. At
December 31, 1994, the Company was participating in the drilling of 8 gross
(4.6 net) wells in the United States and 1 gross (.7 net) well in Bolivia.

For further information regarding the Company's exploration and production
activities, see Notes B and P of Notes to Consolidated Financial Statements in
Item 8.

OIL FIELD SUPPLY AND DISTRIBUTION

The Company sells lubricants, fuels and specialty petroleum products
primarily to onshore and offshore drilling contractors. The Company's products
are sold through six land terminals and 11 marine terminals in various Texas and
Louisiana locations. These products are used to power and lubricate machinery on
drilling and production locations. The Company also provides products for
marine, commercial and industrial applications. Effective March 31, 1994, the
Company discontinued its environmental remediation products and services
operations and recorded charges of $1.9 million during 1994 in connection with
such discontinuance. The Company is continuing its wholesale marketing of fuel
and lubricants.

COMPETITION

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 to the United
States, thereby further increasing competition in the domestic natural gas
market.

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 three other refineries in Alaska and, to a
lesser extent, refineries on the U.S. West Coast. Given the refinery's proximity
to the Alaskan market, the Company believes it enjoys a cost advantage in that
market versus refineries on the U.S. West Coast. However, there is no assurance
that the Company's cost advantage can be maintained. The Company's

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refining competition in Alaska consists of a refinery situated near Fairbanks
owned by MAPCO, Inc. and two refineries situated near Valdez and Fairbanks,
respectively, owned by Petro Star Inc. The Company estimates that such other
refineries have a combined capacity to process approximately 172,000 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 product. The Company's refinery is not directly connected to the
TAPS, and the Company, therefore, cannot return its residual product to the
TAPS. In general, the competing refineries in Alaska do not have the same
downstream capabilities that the Company currently possesses. The Company
estimates that its refinery has the capacity to produce approximately twice the
volume of light products per barrel of ANS crude oil that any of the competing
refineries is currently able to produce.

The Company's marketing business in Alaska is segmented by product line.
The Company believes it is the largest producer and distributor of gasoline in
Alaska, with the largest network of branded and unbranded dealers and jobbers.
The Company is the principal supplier for two major oil companies through
product exchange agreements, 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 two principal suppliers
to, and the only supplier with a direct pipeline into, 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.

The Company's U.S. West Coast marketing business is primarily a
distribution business selling to independent dealers and jobbers outside major
urban areas. The Company competes against independent marketing companies and,
to a lesser extent, integrated oil companies when engaging in these marketing
operations.

OTHER

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.

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11

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.

The FERC's latest action in this area, 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 is being implemented
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. In many
instances, the result of the FERC initiatives has been to substantially reduce
or bring to an end the interstate pipelines' traditional role as wholesalers of
natural gas in favor of providing 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.

Although Order No. 636 does not regulate gas producers, such as the
Company, the FERC has stated that 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. In addition,
numerous petitions seeking judicial review of Orders No. 636, 636A and 636B and
seeking review of the FERC's orders approving open access tariffs for the
individual pipelines have already been filed. Because the restructuring
requirements that emerge from this lengthy process may be significantly
different from those of Order No. 636 as originally promulgated, it is not
possible to predict what effect, if any, the final rule resulting from Order No.
636 will have on the Company. The Company does not believe that it will be
affected by any action taken with respect to Order No. 636 any differently than
other gas producers and marketers with which it competes.

In late 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. In 1994, the FERC granted a number of
interstate pipeline applications to abandon certificated gathering facilities to
non-jurisdictional entities. The rates charged by these entities, which may or
may not be affiliated with the interstate pipeline, are no longer regulated by
the FERC. Under the individual orders, gathering services must be continued to
existing customers and be provided in an open-access and non-discriminatory
manner. These orders are now subject to rehearing before the FERC and numerous
parties will likely seek judicial review.

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.

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12

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 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 (the "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. At this time, the Company can only estimate when new standards
will be imposed by the EPA or relevant state agencies, or what technologies or
changes in processes the Company may have to install or undertake to achieve
compliance with any applicable new requirements. The Company's refinery as well
as some other Company facilities will require submission of an application for a
Clean Air Act Amendment Title V permit during 1995. When issued, although
specifics are still undetermined, the amended permit will involve stricter
monitoring requirements and additional equipment. The Company believes it can
comply with these new requirements without adversely affecting operations.

The passage of the Federal Clean Air Act Amendments of 1990 prompted
adoption of regulations by the State 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. In the fall of 1994, the State mandated
the use of oxygenated fuels containing ethanol in the Anchorage area, from
January 1, through February 28, 1995. This was a shortened period due to time
constraints faced by gasoline sellers in transporting ethanol to Alaska, and in
making the necessary modifications to terminal facilities for blending of the
products. In following years, the period for use of oxygenated gasoline in
Anchorage will be 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. The EPA supported the State's position and formalities for obtaining
the exemption were completed on September 27, 1993. The EPA, in a letter to the
State dated September 30, 1993, stated that the EPA was completing the final
documentation regarding the waiver and that Alaska would have a low priority for
enforcement of the diesel fuel regulations, pending publication of a final
decision, which has not yet occurred. 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. The Company estimates
that such sales accounted for less than 1% of its refined product sales in
Alaska during 1994. 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
spot 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

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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 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.

Current State regulations in Alaska require installation of dike liners in
secondary containment systems for petroleum storage tanks by January 1997. This
requirement affects all storage tanks. New storage tanks built after 1992 must
have such liners and older tanks must be retrofitted and have liners installed.
The Company expects the deadline for this work to be extended and possibly
changed to lessen its financial impact. However, if such changes do not occur,
expenditures in the range of $8 million by January 1997 will be required to
bring the Company's tanks into compliance.

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 may be required to make significant expenditures for removal or
upgrading of underground storage tanks at several of its current and former
service station locations by December 22, 1998; however, the Company does not
expect to make any material capital expenditures for such purposes during 1995
and 1996 and does not expect that such expenditures subsequent to 1996 will have
a material adverse effect on the financial condition of the Company.

ENVIRONMENTAL EXPENDITURES. The Company incurred capital expenditures of
approximately $2.7 million for environmental control purposes during 1994 and
anticipates incurring approximately $2 million for such purposes during 1995,
primarily for the removal and upgrading of underground storage tanks, and
approximately $8 million during 1996 for the installation of dike liners
required under Alaska environmental regulations as discussed above. 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 General Law
of Hydrocarbons and various other laws and regulations. The General Law of
Hydrocarbons imposes certain limitations on the Company's ability to conduct its
operations in Bolivia. In the Company's opinion, neither the General Law of
Hydrocarbons nor other limitations currently imposed by Bolivian laws,
regulations and practices will have a material adverse effect upon its Bolivian
operations.

TAXES

UNITED STATES

The Revenue Reconciliation Act of 1993 will impose a tax of 4.3 cents per
gallon on commercial aviation fuel effective October 1, 1995. The Company does
not believe such tax will have a material adverse effect on the Company's future
operations.

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BOLIVIA

The Company is subject to Bolivian taxation at the rate of 30% of the gross
production of hydrocarbons at the wellhead, which is retained and paid by YPFB
for the Company's account. In 1987, the Bolivian General Corporate Income Tax
Law was replaced by a tax system, including a value-added tax, which is not
imposed on net income. As a result, it is uncertain whether the Company can
treat the Bolivian hydrocarbons tax as creditable in the United States for
federal income tax purposes. However, due to the Company's net operating loss
carryforwards, the Company does not now, or in the near future, expect to use
these taxes as credits for federal income tax purposes. In December 1994,
Bolivia modified its 1987 tax system, and reintroduced a tax on net income.
Until such time as regulations are issued, it is unclear whether the Company can
treat the 30% gross production taxes as creditable for U.S. tax purposes.

In 1990, the Bolivian Government passed a General Law of Hydrocarbons
containing provisions designed to ensure the creditability, for United States
federal income tax purposes, of these hydrocarbon taxes if the Company makes an
election that may subject it to a higher Bolivian tax rate in the future.
Regulations under this law have not been issued; however, the Company does not
anticipate that this law will have a material adverse effect on the Company's
Bolivian operations.

EMPLOYEES

At December 31, 1994, the Company employed approximately 870 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.

EXECUTIVE OFFICERS OF THE REGISTRANT

The following is a list of the Company's executive officers, their ages and
their positions with the Company at March 1, 1995.

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

Michael D. Burke................. 51 President and Chief Executive July 1992
Officer
Gaylon H. Simmons................ 55 Executive Vice President September 1993
Bruce A. Smith................... 51 Executive Vice President and September 1993
Chief Financial Officer
James W. Queen................... 55 Senior Vice President February 1994
James C. Reed, Jr. .............. 50 Senior Vice President, General August 1994
Counsel and Secretary
Don E. Beere..................... 54 Vice President, Controller February 1992
William T. Van Kleef............. 43 Vice President, Treasurer March 1993
Gregory A. Wright................ 45 Vice President, Corporate February 1995
Communications

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.

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

Michael D. Burke -- President and Chief Executive Officer since July 1992.
President and Chief Executive Officer of T.E. Products Pipeline
Company, L.P., an affiliate of Texas Eastern Corporation, from
1990 to 1992. President of Texas Eastern Products Pipeline
Company and Group Vice President of Texas Eastern Corporation
from 1986 to 1990.

Gaylon H. Simmons -- Executive Vice President responsible for Refining, Marketing
and Crude Supply Operations since September 1993. Senior Vice
President, Refining, Marketing and Crude Supply from January
1993 to September 1993. President and Chief Executive Officer
of Simmons Sirvey Group, Inc. from 1991 to December 1992.
President and Chief Executive Officer of Permian Corporation
from 1989 to 1991. Vice President, Supply and Marketing for
MAPCO Petroleum, Inc. from 1985 to 1989.

Bruce A. Smith -- Executive Vice President responsible for Exploration and
Production Operations and Chief Financial Officer since
September 1993. 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. -- Senior Vice President, General Counsel and Secretary since
August 1994. 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. Assistant General
Counsel and Assistant Secretary from 1982 to 1990.

Don E. Beere -- Vice President, Controller since February 1992. Vice President,
Internal Audit and Management Systems of Tesoro Petroleum
Companies, Inc. from 1990 to 1992. Director, Internal Audit and
Management Systems from 1989 to 1990. Director, Internal Audit
from 1986 to 1989.

William T. Van Kleef -- Vice President, Treasurer since March 1993. Financial
Consultant from January 1992 to February 1993. Consultant to
Parker & Parsley (successor to the assets and operations of
Damson Oil Corporation and its affiliates) from February 1991
to December 1991. Vice President and Chief Financial Officer of
Damson Oil Corporation from 1986 to 1991.

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

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ITEM 2. PROPERTIES

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

ITEM 3. LEGAL PROCEEDINGS

TENNESSEE GAS CONTRACT. The Company is selling a portion of the gas from
its Bob West Field to Tennessee Gas Pipeline Company ("Tennessee Gas") under a
Gas Purchase and Sales Agreement (the "Tennessee Gas Contract") which provides
that the price of gas shall be the maximum price as calculated in accordance
with Section 102(b)(2) ("Contract Price") of the Natural Gas Policy Act of 1978
("NGPA"). Tennessee Gas filed suit against the Company in the District Court of
Bexar County, Texas alleging that the Tennessee Gas Contract is not applicable
to the Company's properties and that the gas sales price should be the price
calculated under the provisions of Section 101 of the NGPA rather than the
Contract Price. During December 1994, the Contract Price was in excess of $8.00
per Mcf, the Section 101 price was $4.81 per Mcf and the average spot market
price was $1.56 per Mcf. Tennessee Gas also claimed that the contract should be
considered an "output contract" under Section 2.306 of the Texas Business and
Commerce Code and that the increases in volumes tendered under the contract
exceeded those allowable for an output contract.

The District Court judge returned a verdict in favor of the Company on all
issues. On appeal by Tennessee Gas, the Court of Appeals for the Fourth Supreme
Judicial District of Texas affirmed the validity of the Tennessee Gas Contract
as to the Company's properties and held that the price payable by Tennessee Gas
for the gas was the Contract Price. The Court of Appeals remanded the case to
the trial court based on its determination (i) that the Tennessee Gas Contract
was an output contract and (ii) that a fact issue existed as to whether the
increases in the volumes of gas tendered to Tennessee Gas under the contract
were made in bad faith or were unreasonably disproportionate to prior tenders.
The Company sought review of the appellate court ruling on the output contract
issue in the Supreme Court of Texas. Tennessee Gas also sought review of the
appellate court ruling denying the remaining Tennessee Gas claims in the Supreme
Court of Texas. The Supreme Court of Texas heard arguments in December 1994
regarding the output contract issue and certain of the issues raised by
Tennessee Gas but has not yet issued its opinion.

Although the outcome of any litigation is uncertain, management, based upon
advice from outside legal counsel, is confident that the decision of the trial
and appellate courts will ultimately be upheld as to the validity of the
Tennessee Gas Contract and the Contract Price. If the Supreme Court of Texas
were to affirm the appellate court ruling, the Company believes that the only
issue for trial should be whether the increases in the volumes of gas tendered
to Tennessee Gas from the Company's properties were made in bad faith or were
unreasonably disproportionate. The appellate court decision was the first
reported decision in Texas holding that a take-or-pay contract was an output
contract. As a result, it is not clear what standard the trial court would be
required to apply in determining whether the increases were in bad faith or
unreasonably disproportionate. The appellate court acknowledged in its opinion
that the standards used in evaluating other kinds of output contracts would not
be appropriate in this context. The Company believes that the appropriate
standard would be whether the development of the field was undertaken in a
manner that a prudent operator would have undertaken in the absence of an
above-market sales price. Under that standard, the Company believes that, if
this issue is tried, the development of the Company's gas properties and the
resulting increases in volumes tendered to Tennessee Gas will be found to have
been reasonable and in good faith. Accordingly, the Company has recognized
revenues, net of production taxes and marketing charges, for natural gas sales
through December 31, 1994, under the Tennessee Gas Contract based on the
Contract Price, which net revenues aggregated $36.9 million more than the
Section 101 prices and $69.5 million in excess of the spot market prices. If
Tennessee Gas were ultimately to prevail in this litigation, the Company could
be required to return to Tennessee Gas $52.5 million, plus interest if awarded
by the court, representing the difference between the spot market price and the
Contract Price received by the Company through September 17, 1994 (the date on
which the Company entered into a bond agreement discussed below). In addition,
the Company's calculation of the standardized measure of discounted future net
cash flows relating to proved reserves in the United States at December 31, 1994
of $127 million was determined in part using the Contract Price as

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compared with $73 million at spot market prices. An adverse judgment in this
case could have a material adverse effect on the Company.

On August 4, 1994, the trial court rejected a motion by Tennessee Gas to
post a supersedeas bond in the form of monthly payments into the registry of the
court representing the difference between the Contract Price and spot market
price of gas sold to Tennessee Gas pursuant to the Tennessee Gas Contract. The
court advised Tennessee Gas that should it wish to supersede the judgment,
Tennessee Gas had the option to post a bond which would be effective only until
August 1, 1995, in an amount equal to the anticipated value of the Tennessee Gas
Contract during that period. In September 1994, the court ordered that,
effective until August 1, 1995, Tennessee Gas (i) take at least its entire
monthly take-or-pay obligation under the Tennessee Gas Contract, (ii) pay for
gas at $3.00 per Mmbtu, which approximates $3.00 per Mcf ("Bond Price"), and
(iii) post a $120 million bond with the court representing an amount which,
together with anticipated sales of natural gas to Tennessee Gas at the Bond
Price, will equal the anticipated value of the Tennessee Gas Contract during
this interim period. The Bond Price is nonrefundable by the Company, and the
Company retains the right to receive the full Contract Price for all gas sold to
Tennessee Gas. The Company continues to recognize revenues under the Tennessee
Gas Contract based on the Contract Price. At December 31, 1994, the Company had
recognized cumulative revenues in excess of spot market prices (through
September 17, 1994) and in excess of the Bond Price (subsequent to September 17,
1994) totaling $65.7 million. Receivables at December 31, 1994, included $17.7
million from Tennessee Gas, of which $13.2 million represented the difference
between the Contract Price and the Bond Price. For further information regarding
the Tennessee Gas Contract, see Notes L and P of Notes to Consolidated Financial
Statements in Item 8.

MINERAL ESTATE CLAIM. In February 1995, a lawsuit was filed in the U.S.
District Court for the Southern District of Texas, McAllen Division, by the
Heirs of H.P. Guerra, Deceased ("Plaintiffs") against the United States and
Tesoro and other working and overriding royalty interest owners to recover the
oil and gas mineral estate under 2,706.34 acres situated in Starr County, Texas.
The oil and gas mineral estate sought to be recovered underlies lands taken by
the United States in connection with the construction of the Falcon Dam and
Reservoir. In their lawsuit, the Plaintiffs allege that the original taking by
the United States in 1948 was unlawful and void and the refusal of the United
States to revest the mineral estate to H.P. Guerra or his heirs was arbitrary
and capricious and unconstitutional. Plaintiffs seek (i) restoration of their
oil and gas estate; (ii) restitution of all proceeds realized from the sale of
oil and gas from their mineral estate, plus interest on the value thereof; and
(iii) cancellation of all oil and gas leases issued by the United States to
Tesoro and the other working interest owners covering their mineral estate. The
lawsuit covers a significant portion of the mineral estate in the Bob West
Field; however, none of the acreage covered is dedicated to the Tennessee Gas
Contract. The Company cannot predict the ultimate resolution of this matter but,
based upon advice from outside legal counsel, believes the lawsuit is without
merit.

REFUND CLAIM. In July 1994, Simmons Oil Corporation, also known as David
Christopher Corporation, a former customer of the Company ("Customer"), filed
suit against the Company in the United States District Court for the District of
New Mexico for a refund in the amount of approximately $1.2 million, plus
interest of approximately $4.4 million and attorney's fees, related to a
gasoline purchase from the Company in 1979. The Customer also alleges
entitlement to treble damages and punitive damages in the aggregate amount of
$16.8 million. The refund claim is based on allegations that the Company
renegotiated the acquisition price of gasoline sold to the Customer and failed
to pass on the benefit of the renegotiated price to the Customer in violation of
Department of Energy price and allocation controls then in effect. The Company
cannot predict the ultimate resolution of this matter but believes the claim is
without merit.

ENVIRONMENTAL MATTERS. In March 1991, the Company entered into a Consent
Order with the Alaska Department of Environmental Conservation ("ADEC")
substantially similar to Consent Orders reached with the EPA in September 1989.
These Consent Orders provide for the investigation and cleanup of hydrocarbons
in the soil and groundwater at the Company's Alaska refinery, which resulted
from sewer hub seepage associated with the underground oil/water sewer system.
The Consent Orders formalized efforts, which commenced in 1987, to remedy the
presence of hydrocarbons in the soil and groundwater and provide for the
performance of additional future work. The Company has replaced or rebuilt the
drainage hubs and has

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initiated a subsurface monitoring and interception system designed to identify
the extent of hydrocarbons present in the groundwater and to remove the
hydrocarbons.

In March 1992, the Company received a Compliance Order and Notice of
Violation from the Environmental Protection Agency (the "EPA") alleging
violations by the Company of the New Source Performance Standards under the
Clean Air Act at its Alaska refinery. These allegations include failure to
install, maintain and operate monitoring equipment over a period of
approximately six years, failure to perform accuracy testing on monitoring
equipment, and failure to install certain pollution control equipment. From
March 1992 to July 1993, the EPA and the Company exchanged information relevant
to these allegations. In addition, the EPA conducted an environmental audit of
the Company's refinery in May 1992. As a result of this audit, the EPA is also
alleging violation of certain regulations related to asbestos materials. In
October 1993, the EPA referred these matters to the Department of Justice
("DOJ"). The DOJ contacted the Company to begin negotiating a resolution of
these matters. The DOJ has indicated that it is willing to enter into a judicial
consent decree with the Company and that this decree would include a penalty
assessment. Negotiations on the penalty are in progress. The DOJ has proposed a
penalty assessment of approximately $3.7 million. The Company is continuing to
negotiate with the DOJ but cannot predict the ultimate outcome of the
negotiations.

The Company, along with numerous other parties, has been identified by the
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. The Company arranged for the disposal of
a minimal amount of materials at this location, but CERCLA imposes joint and
several liability on each PRP. 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. At this
time, the Company is unable to determine the extent of the Company's liability
related to this site; however, the extent of the Company's allocated financial
contribution to the cleanup of this site is expected to be minimal based on the
number of companies and the volumes of waste involved and the payment by the
Company of a de minimus settlement amount of $2,500 at a similar site in
Louisiana. The Company believes that the aggregate amount of such liability, if
any, would not have a material adverse effect on the Company.

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

None.

PART II

ITEM 5. MARKET FOR THE 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 1994 and 1993 are summarized
below:

1994 1993
------------ -----------
QUARTERS HIGH LOW HIGH LOW
----------------------------------------------- ---- --- --- ---

First.......................................... $12 3/8 5 1/4 5 5/8 3
Second......................................... $12 1/8 9 7/8 6 5/8 5
Third.......................................... $11 1/4 8 1/2 7 3/4 5 1/8
Fourth......................................... $ 10 8 1/2 7 1/2 5 1/8

At March 1, 1995, there were approximately 4,300 holders of record of the
Company's 24,534,430 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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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 THREE MONTHS YEARS ENDED
DECEMBER 31, ENDED SEPTEMBER 30,
---------------------- DECEMBER 31, ---------------
1994 1993 1992 1991(1) 1991 1990
------ ----- ----- ------------ ------------ ------------
(IN MILLIONS EXCEPT PER SHARE AMOUNTS)

STATEMENTS OF OPERATIONS DATA
Gross Operating Revenues:
Refining and Marketing................................... $687.0 687.2 810.7 196.8 898.6 860.5
Exploration and Production(2)............................ 106.3 63.1 42.7 12.5 59.2 32.4
Oil Field Supply and Distribution........................ 77.9 80.7 93.5 36.5 134.3 103.7
Intersegment eliminations(3)............................. -- -- (.4) (5.2) (7.1) --
------ ----- ----- ----- ------------ -----
Total Gross Operating Revenues......................... $871.2 831.0 946.5 240.6 1,085.0 996.6
====== ===== ===== ============ ====== =====
Segment Operating Profit (Loss):
Refining and Marketing................................... $ 2.4 15.2 (14.9) 1.7 19.3 48.2
Exploration and Production(2)............................ 64.3 40.7 29.1 7.4 35.6 16.8
Oil Field Supply and Distribution........................ (2.3) (3.6) (4.7) (1.2) (.5) 2.9
------ ----- ----- ----- ------------ -----
Total Segment Operating Profit......................... $ 64.4 52.3 9.5 7.9 54.4 67.9
====== ===== ===== ============ ====== =====
Earnings (Loss) Before Extraordinary Loss and the
Cumulative Effect of Accounting Changes.................. $ 20.5 17.0 (45.3) (.4) 3.9 22.7
Extraordinary Loss on Extinguishment of Debt............... (4.8) -- -- -- -- --
Cumulative Effect of Accounting Changes.................... -- -- (20.6) -- -- --
------ ----- ----- ----- ------------ -----
Net Earnings (Loss)(4)..................................... $ 15.7 17.0 (65.9) (.4) 3.9 22.7
====== ===== ===== ============ ====== =====
Net Earnings (Loss) Applicable to Common Stock(4).......... $ 13.0 7.8 (75.1) (2.7) (5.3) 13.5
====== ===== ===== ============ ====== =====
Earnings (Loss) per Primary and Fully Diluted* Share(4)(5):
Earnings (loss) before extraordinary loss and the
cumulative effect of accounting changes................ $ .77 .54 (3.87) (.19) (.37) .96
Extraordinary loss on extinguishment of debt............. (.21) -- -- -- -- --
Cumulative effect of accounting changes.................. -- -- (1.47) -- -- --
------ ----- ----- ----- ------------ -----
Net earnings (loss)...................................... $ .56 .54 (5.34) (.19) (.37) .96
====== ===== ===== ============ ====== =====
Average Common and Common Equivalent Shares Outstanding(5):
Primary.................................................. 23.2 14.3 14.1 14.1 14.1 14.1
Fully diluted............................................ 24.7 19.1 18.8 18.8 18.8 18.8
CAPITAL EXPENDITURES
Refining and Marketing................................... $ 32.0 7.1 3.7 .8 4.4 6.9
Exploration and Production............................... 65.6 29.3 9.3 3.0 19.3 13.2
Other.................................................... 2.0 1.1 2.4 .1 .8 3.0
------ ----- ----- ----- ------------ -----
Total Capital Expenditures............................. $ 99.6 37.5 15.4 3.9 24.5 23.1
====== ===== ===== ============ ====== =====
BALANCE SHEET AND OTHER DATA
Total Assets............................................... $484.4 434.5 446.7 494.7 496.8 504.9
Working Capital............................................ $ 85.9 124.5 122.6 106.1 95.4 117.9
Long-Term Debt and Other Obligations, Including Current
Portion(5)............................................... $199.6 185.5 201.7 189.4 184.7 168.0
Redeemable Preferred Stock(5).............................. $ -- 78.1 71.7 57.4 57.4 57.4
Common Stock and Other Stockholders' Equity(5)(6).......... $160.7 58.5 50.7 137.0 137.4 141.4

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

* Anti-dilutive.

(1) The Company's fiscal year-end was changed from September 30 to December 31,
effective January 1, 1992.

(2) The Company is involved in litigation related to a natural gas sales
contract. For additional information concerning this dispute, see Legal
Proceedings in Item 3 and Notes L and P of Notes to Consolidated Financial
Statements in Item 8.

(3) Intersegment eliminations represent sales from Refining and Marketing to Oil
Field Supply and Distribution, at prices which approximate market.

(4) The net loss for 1992 included a charge of $20.6 million for the cumulative
effect of the adoption of SFAS No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions" and SFAS No. 109, "Accounting
for Income Taxes". Net earnings for 1994 included a $4.8 million
extraordinary loss related to an early extinguishment of debt in connection
with a recapitalization.

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

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

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

CAPITAL RESOURCES AND LIQUIDITY

During 1994, the Company significantly strengthened its short-term and
long-term liquidity and increased its equity capital and financial resources.
These improvements were achieved by consummation of a recapitalization plan and
equity offering whereby a major portion of the Company's outstanding debt was
restructured and all of its preferred stock and dividend arrearages were
eliminated and which, among other matters, deferred $44 million of debt service
requirements, increased stockholders' equity by approximately $82 million and
eliminated $9.2 million of annual preferred dividend requirements (see Note C of
Notes to Consolidated Financial Statements in Item 8). In addition, the Company
entered into a $125 million corporate Revolving Credit Facility and obtained $15
million financing for a major addition to the Company's refinery. These
accomplishments, together with the Company's cash flows from operations, enabled
the Company to invest $99.6 million in capital projects during 1994 and have
better positioned the Company for future profitability and growth.

The Company operates in an environment where markets for crude oil, natural
gas and refined products historically have been volatile and are likely to
continue to be volatile in the future. The Company's operating margins and
liquidity are subject to fluctuation in response to changes in the supply of and
demand for crude oil, natural gas and refined petroleum products, market
uncertainty and a variety of additional factors that are beyond the control of
the Company. These factors 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 economic conditions. The Company cannot predict the future markets and
prices for the Company's natural gas or refined products and the resulting
future impact on earnings and cash flows. Due to the effect of depressed market
conditions (see "Results of Operations" below), the Company's operations will
continue to be adversely affected for so long as these market conditions exist.
The Company's future capital expenditures, borrowings under its credit
arrangements and other sources of capital will be affected by these conditions.

CREDIT ARRANGEMENTS

During April 1994, the Company entered into a three-year, $125 million
corporate Revolving Credit Facility with a consortium of ten banks, replacing
certain interim financing arrangements. The Revolving Credit Facility, which is
subject to a borrowing base, provides for (i) the issuance of letters of credit
up to the full amount of the borrowing base as calculated and (ii) cash
borrowings up to the amount of the borrowing base attributable to domestic oil
and gas reserves. Outstanding obligations under the Revolving 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, 1994, the borrowing base of
approximately $107 million included a domestic oil and gas reserve component of
$45 million. At December 31, 1994, the Company had outstanding letters of credit
under the Revolving Credit Facility of approximately $48 million with no cash
borrowings outstanding. Although at December 31, 1994 there were no cash
borrowings outstanding under the Revolving Credit Facility, the Company expects
to incur short-term borrowings from time to time in 1995 under the Revolving
Credit Facility to finance working capital requirements and, to a lesser extent,
capital expenditures.

Under the terms of the Revolving Credit Facility, as amended, the Company
is required to maintain specified levels of working capital, tangible net worth,
consolidated cash flow and refinery cash flow, as defined in the Revolving
Credit Facility. Among other matters, the Revolving Credit Facility has certain
restrictions with respect to (i) capital expenditures, (ii) incurrence of
additional indebtedness, and (iii) dividends on capital stock. The Revolving
Credit Facility contains other covenants customary in credit arrangements of
this kind. During the third and fourth quarters of 1994, the Company did not
satisfy the refinery cash flow requirement which required a waiver and an
amendment to the Revolving Credit Facility. Future compliance with financial
covenants under the amended Revolving Credit Facility is primarily dependent on
the

20
21

Company's cash flows from operations, capital expenditures, levels of borrowings
under the Revolving Credit Facility and the value of the Company's domestic oil
and gas reserves. Based on current market conditions, including the volatility
in refinery margins and the recent downturn in the price of natural gas,
continued compliance with such covenants is not assured. If the Company is not
able to continue to comply with its financial covenants, it will be required to
seek waivers or amendments from its banks. If such an event occurs, the Company
believes it will be able to negotiate terms and conditions with its banks under
the Revolving Credit Facility which will allow the Company to adequately finance
its operations. For further information concerning such restrictions and
covenants, see Note I of Notes to Consolidated Financial Statements in Item 8.

During May 1994, the National Bank of Alaska and the Alaska Industrial
Development & Export Authority agreed to provide a loan to the Company of up to
$15 million of the cost of the vacuum unit for the Company's refinery (the
"Vacuum Unit Loan"). The Vacuum Unit Loan matures January 1, 2002 and is secured
by a first lien on the refinery. At December 31, 1994, the Company had borrowed
$15 million under the Vacuum Unit Loan. The Vacuum Unit Loan contains covenants
and restrictions similar to those under the Revolving Credit Facility. At
December 31, 1994, the Company satisfied all of its covenants except for an
annual refinery cash flow requirement, as defined in the Vacuum Unit Loan. The
lenders waived this refinery cash flow requirement for the year ended December
31, 1994. For further information on the Vacuum Unit Loan, see Note I of Notes
to Consolidated Financial Statements in Item 8.

DEBT AND OTHER OBLIGATIONS

The Company's funded debt obligations as of December 31, 1994 included
approximately $64.6 million principal amount of 12 3/4% Subordinated Debentures
("Subordinated Debentures"), which bear interest at 12 3/4% per annum and
require sinking fund payments sufficient to annually retire $11.25 million
principal amount of Subordinated Debentures. As part of a recapitalization,
$44.1 million principal amount of Subordinated Debentures was tendered in
exchange for a like principal amount of new 13% Exchange Notes ("Exchange
Notes"). This exchange satisfied the 1994 sinking fund requirement and, except
for $.9 million, will satisfy sinking fund requirements for the Subordinated
Debentures through 1997. The indenture governing the Subordinated Debentures
contains certain covenants, including a restriction that prevents the current
payment of cash dividends on Common Stock and currently limits the Company's
ability to purchase or redeem any shares of its capital stock. The Exchange
Notes bear interest at 13% per annum, mature December 1, 2000 and have no
sinking fund requirements. The limitation on dividend payments included in the
indenture governing the Exchange Notes is less restrictive than the limitation
imposed by the Subordinated Debentures. The Subordinated Debentures and Exchange
Notes are redeemable at the option of the Company at 100% of principal amount,
plus accrued interest. For further information on redemption provisions and
restrictions on dividends, see Note I of Notes to Consolidated Financial
Statements in Item 8.

Under an agreement reached in 1993, which settled a contractual dispute
with the State of Alaska ("State"), the Company paid the State $10.3 million in
January 1993 and is obligated to make variable monthly payments to the State
through December 2001 based on a per barrel charge that is currently 16 cents
and increases to 33 cents on the volume of feedstock processed at the Company's
refinery. In 1994, the Company's variable payments to the State totaled $2.8
million. 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 December 2001 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.

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CAPITAL EXPENDITURES

Capital spending in 1994 amounted to $99.6 million, compared with $37.5
million in 1993. The Company's cash flows from operating activities of $60
million in 1994, together with existing cash and a $15 million borrowing under
the Vacuum Unit Loan, enabled the Company to invest in significant capital
projects during the year. The Company's exploration and production activities in
South Texas accounted for approximately 66% of the capital expenditures in 1994,
primarily for continued development of the Bob West Field. During 1994, the
Company participated in the drilling of 20 development wells and two exploratory
wells in this field and expanded the field's gas processing facilities and
pipelines. In addition, the Company participated in the drilling of five
exploratory wells and one unsuccessful development well in other areas of South
Texas. Capital projects for the Company's refining and marketing operations for
1994 totaled $32 million, of which $25 million was associated with the
refinery's installation of the vacuum unit. The vacuum unit, which became
operational in December 1994, will reduce the refinery's yield of residual
product about 50% by further processing these volumes into higher-valued
products.

Capital spending for 1995 is expected to be financed through a combination
of cash flows from operations and borrowings under the Revolving Credit
Facility. For 1995, the Company has under consideration total capital
expenditures of approximately $65 million. Capital expenditures for the
continued development of the Bob West Field and exploratory drilling in other
areas of South Texas in 1995 are projected to be $55 million. The amount of such
expenditures for exploration and production activities is dependent upon, among
other factors, the price the Company receives for its natural gas production.
Capital expenditures for 1995 for the refining and marketing segment are
projected to be $10 million, primarily for capital improvements at the refinery
and expansion of the Company's retail locations in Alaska. For information on
litigation related to a natural gas sales contract and the related impact on the
Company's cash flows from operations, see "Tennessee Gas Contract" below and
Notes L and P of Notes to Consolidated Financial Statements in Item 8.

CASH FLOWS FROM OPERATING, INVESTING AND FINANCING ACTIVITIES

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

1994 1993 1992
------ ----- -----

Cash Flows From (Used In):
Operating Activities..................................... $ 60.3 21.8 11.4
Investing Activities..................................... (91.2) (23.4) (21.1)
Financing Activities..................................... 8.3 (8.7) (4.5)
------ ----- -----
Decrease in Cash and Cash Equivalents...................... $(22.6) (10.3) (14.2)
====== ===== =====

During 1994, net cash from operating activities increased to $60 million,
compared with $22 million in 1993. This increase in cash flows was primarily
related to sales of increased natural gas production from the Bob West Field,
partially offset by lower prices received for such sales of natural gas and
reduced cash flows from the refining and marketing operations. Variable payments
to the State of Alaska totaled $2.8 million in 1994. Net cash used in investing
activities of $91 million during 1994 included capital expenditures of $100
million, an increase of $63 million from the prior year. 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 the equity offering after exercise of an option granted by MetLife
Louisiana (see Note C 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. At December
31, 1994, the Company's cash totaled $14 million and working capital amounted to
$86 million.

During 1993, cash and cash equivalents decreased by $10 million and
short-term investments decreased by $14 million. Net cash from operating
activities of $22 million in 1993 was primarily due to net earnings adjusted for
certain noncash charges, partially offset by payments totaling $12.9 million to
the State (under

22
23

the settlement agreement entered into in January 1993) and increased working
capital requirements. Net cash used in investing activities of $23 million
during 1993 included capital expenditures of $37 million, mainly for exploration
and production activities in the Bob West Field. During 1993, the Company
completed the expansion of a gas processing facility and pipeline and
participated in the drilling of 15 development gas wells in this field. In
addition, the Company participated in drilling four exploratory wells and one
development well outside of the Bob West Field in 1993. These uses of cash in
investing activities were partially offset by the net decrease of $14 million in
short-term investments. Net cash used in financing activities of $9 million in
1993 included the repurchase of $11.25 million principal amount of Subordinated
Debentures for $9.7 million in cash, partially offset by borrowings of $5
million under interim financing arrangements. The Company did not pay dividends
on preferred stocks in 1993.

During 1992, cash and cash equivalents decreased by $14 million and
short-term investments increased by $20 million. Cash flows from operating
activities of $11 million included a net loss, offset by certain significant
noncash charges, including the cumulative effect of accounting changes,
depreciation, depletion and amortization and the settlement with the State, and
by reduced working capital requirements. Net cash used in investing activities
of $21 million in 1992 was mainly due to capital expenditures of $15 million,
primarily for continued exploration and development activities in the Bob West
Field and capital improvements in Alaska, and to the purchase of short-term
investments of $24 million. Partially offsetting cash used in investing
activities in 1992 were net proceeds of $13 million from sales of assets. During
1992, the Company received, before expenses, $6.8 million from the sale of its
Indonesian operations, $3.3 million from the sale of its corporate aircraft and
related assets and $2.1 million from the sale of certain exploration and
production properties outside of the Bob West Field. Cash flows used in
financing activities of $4 million in 1992 included repayment of long-term debt.
The Company deferred payments of dividends on preferred stocks in 1992.

TENNESSEE GAS CONTRACT

The Company is selling a portion of the gas from its Bob West Field to
Tennessee Gas Pipeline Company ("Tennessee Gas") under a Gas Purchase and Sales
Agreement (the "Tennessee Gas Contract") which provides that the price of gas
shall be the maximum price as calculated in accordance with Section 102(b)(2)
("Contract Price") of the Natural Gas Policy Act of 1978 ("NGPA"). Tennessee Gas
filed suit against the Company in the District Court of Bexar County, Texas
alleging that the Tennessee Gas Contract is not applicable to the Company's
properties and that the gas sales price should be the price calculated under the
provisions of Section 101 of the NGPA rather than the Contract Price. During
December 1994, the Contract Price was in excess of $8.00 per Mcf, the Section
101 price was $4.81 per Mcf and the average spot market price was $1.56 per Mcf.
Tennessee Gas also claimed that the contract should be considered an "output
contract" under Section 2.306 of the Texas Business and Commerce Code and that
the increases in volumes tendered under the contract exceeded those allowable
for an output contract.

The District Court judge returned a verdict in favor of the Company on all
issues. On appeal by Tennessee Gas, the Court of Appeals for the Fourth Supreme
Judicial District of Texas affirmed the validity of the Tennessee Gas Contract
as to the Company's properties and held that the price payable by Tennessee Gas
for the gas was the Contract Price. The Court of Appeals remanded the case to
the trial court based on its determination (i) that the Tennessee Gas Contract
was an output contract and (ii) that a fact issue existed as to whether the
increases in the volumes of gas tendered to Tennessee Gas under the contract
were made in bad faith or were unreasonably disproportionate to prior tenders.
The Company sought review of the appellate court ruling on the output contract
issue in the Supreme Court of Texas. Tennessee Gas also sought review of the
appellate court ruling denying the remaining Tennessee Gas claims in the Supreme
Court of Texas. The Supreme Court of Texas heard arguments in December 1994
regarding the output contract issue and certain of the issues raised by
Tennessee Gas but has not yet issued its opinion.

Although the outcome of any litigation is uncertain, management, based upon
advice from outside legal counsel, is confident that the decision of the trial
and appellate courts will ultimately be upheld as to the validity of the
Tennessee Gas Contract and the Contract Price. If the Supreme Court of Texas
were to affirm the appellate court ruling, the Company believes that the only
issue for trial should be whether the increases in the volumes of gas tendered
to Tennessee Gas from the Company's properties were made in bad faith or were

23
24

unreasonably disproportionate. The appellate court decision was the first
reported decision in Texas holding that a take-or-pay contract was an output
contract. As a result, it is not clear what standard the trial court would be
required to apply in determining whether the increases were in bad faith or
unreasonably disproportionate. The appellate court acknowledged in its opinion
that the standards used in evaluating other kinds of output contracts would not
be appropriate in this context. The Company believes that the appropriate
standard would be whether the development of the field was undertaken in a
manner that a prudent operator would have undertaken in the absence of an
above-market sales price. Under that standard, the Company believes that, if
this issue is tried, the development of the Company's gas properties and the
resulting increases in volumes tendered to Tennessee Gas will be found to have
been reasonable and in good faith. Accordingly, the Company has recognized
revenues, net of production taxes and marketing charges, for natural gas sales
through December 31, 1994, under the Tennessee Gas Contract based on the
Contract Price, which net revenues aggregated $36.9 million more than the
Section 101 prices and $69.5 million in excess of the spot market prices. If
Tennessee Gas were ultimately to prevail in this litigation, the Company could
be required to return to Tennessee Gas $52.5 million, plus interest if awarded
by the court, representing the difference between the spot market price and the
Contract Price received by the Company through September 17, 1994 (the date on
which the Company entered into a bond agreement discussed below). In addition,
the Company's calculation of the standardized measure of discounted future net
cash flows relating to proved reserves in the United States at December 31, 1994
of $127 million was determined in part using the Contract Price as compared with
$73 million at spot market prices. An adverse judgment in this case could have a
material adverse effect on the Company.

On August 4, 1994, the trial court rejected a motion by Tennessee Gas to
post a supersedeas bond in the form of monthly payments into the registry of the
court representing the difference between the Contract Price and spot market
price of gas sold to Tennessee Gas pursuant to the Tennessee Gas Contract. The
court advised Tennessee Gas that should it wish to supersede the judgment,
Tennessee Gas had the option to post a bond which would be effective only until
August 1, 1995, in an amount equal to the anticipated value of the Tennessee Gas
Contract during that period. In September 1994, the court ordered that,
effective until August 1, 1995, Tennessee Gas (i) take at least its entire
monthly take-or-pay obligation under the Tennessee Gas Contract, (ii) pay for
gas at $3.00 per Mmbtu, which approximates $3.00 per Mcf ("Bond Price"), and
(iii) post a $120 million bond with the court representing an amount which,
together with anticipated sales of natural gas to Tennessee Gas at the Bond
Price, will equal the anticipated value of the Tennessee Gas Contract during
this interim period. The Bond Price is nonrefundable by the Company, and the
Company retains the right to receive the full Contract Price for all gas sold to
Tennessee Gas. The Company continues to recognize revenues under the Tennessee
Gas Contract based on the Contract Price. At December 31, 1994, the Company had
recognized cumulative revenues in excess of spot market prices (through
September 17, 1994) and in excess of the Bond Price (subsequent to September 17,
1994) totaling $65.7 million. Receivables at December 31, 1994, included $17.7
million from Tennessee Gas, of which $13.2 million represented the difference
between the Contract Price and the Bond Price. For further information regarding
the Tennessee Gas Contract, see Notes L and P of Notes to Consolidated Financial
Statements in Item 8.

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 remedial responses and has incurred cleanup
expenditures associated with environmental matters at a number of sites,
including certain of its own properties. In addition, the Company is holding
discussions with the Department of Justice concerning the assessment of
penalties with respect to certain alleged violations of the Clean Air Act. (See
"Legal Proceedings -- Environmental Matters".) At December 31, 1994, the
Company's accruals for environmental matters, including the alleged violations
of the Clean Air Act, amounted to $10.8 million. Based on currently available
information, including the participation of other parties or former owners in
remediation actions, the Company believes these accruals are adequate. In
addition, to comply with environmental laws and

24
25

regulations, the Company anticipates that it will be required to make capital
improvements in 1995 of approximately $2 million, primarily for the removal and
upgrading of underground storage tanks, and approximately $8 million during 1996
for the installation of dike liners required under Alaska environmental
regulations. 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.

The Company transports its crude oil and a substantial portion of its
refined products utilizing Kenai Pipe Line Company's ("KPL") pipeline and marine
terminal facilities in Kenai, Alaska. In March 1994, KPL filed a revised tariff
with the Federal Energy Regulatory Commission ("FERC") for dock loading
services, which would have increased the Company's annual cost of transporting
products through KPL's facilities from $1.2 million to $11.2 million. Following
FERC's rejection of KPL's tariff filing and the commencement of negotiations for
the purchase by the Company of the dock facilities, KPL filed a temporary tariff
that has increased the Company's annual cost by approximately $1.5 million. The
Company and KPL have entered into an agreement for the purchase by the Company
of KPL, subject to regulatory approval. The Company expects that this purchase
transaction will be consummated in early 1995.

The Company's contract with the State for the purchase of royalty crude oil
expires on December 31, 1995. The Company is currently negotiating with the
State for a new three-year contract for the period January 1, 1996 through
December 31, 1998. Based on preliminary discussions with the State, the Company
believes that a new contract will provide for the purchase of approximately the
same volumes of Alaska North Slope ("ANS") royalty crude oil, the primary
feedstock for the refinery, as the current contract and will be priced at the
weighted average price reported to the State by a major North Slope producer for
ANS crude oil as valued at Pump Station No. 1 on the Trans Alaska Pipeline
System.

As discussed in Note L of Notes to Consolidated Financial Statements in
Item 8, the Company is involved with other litigation and claims, none of which
is expected to have a material adverse effect on the financial condition of the
Company.

RESULTS OF OPERATIONS

Net earnings of $15.7 million ($.56 per share) for 1994 compare with $17.0
million ($.54 per share) in 1993. The comparability between 1994 and 1993 was
impacted by certain significant transactions. The 1994 earnings included a
noncash extraordinary loss of $4.8 million on the extinguishment of debt in
connection with a recapitalization in early 1994. Earnings before the
extraordinary loss were $20.5 million, or $.77 per share, for 1994. Earnings for
1994 were favorably impacted by a refund of $8.5 million received in settlement
of a tariff dispute and a gain of $2.4 million from the sale of assets,
partially offset by net charges of approximately $7 million related to
environmental contingencies and other matters. During 1993, the Company's
earnings benefited from the resolution of several state tax issues, resulting in
a net reduction of $3.0 million in income tax expense and $5.2 million in
interest expense. In addition, a gain of $1.4 million was recognized in 1993 for
the retirement of $11.25 million principal amount of Subordinated Debentures,
which were purchased in January 1993 to satisfy the initial sinking fund
requirement. Excluding these significant transactions from both periods, the
improvement in net earnings of approximately $9 million in 1994 was primarily
attributable to increased natural gas production from the Company's exploration
and production operations in South Texas, partially offset by the impact of
lower spot market prices for sales of natural gas and lower operating results
from the Company's refining and marketing operations.

Net earnings of $17.0 million ($.54 per share) in 1993 compare with a net
loss of $65.9 million ($5.34 per share) in 1992. As described above, earnings in
1993 benefited from the reduction in income taxes and interest expense together
with the gain on early extinguishment of debt. The 1992 loss included charges of
$20.6 million for the cumulative effect of accounting changes, $10.5 million for
settlement of a contractual dispute with the State and $9.1 million for a cost
reduction program and other employee terminations, partially offset by a gain of
$5.8 million from the sale of the Company's Indonesian operations. Excluding
these transactions,

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26

the improvement in 1993 net earnings compared with 1992 was attributable to
increased gross margins on sales of refined products, increased natural gas
production from the Bob West Field and reduced general and administrative
expenses.

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 Oil Field Supply and Distribution.

REFINING AND MARKETING

1994 1993 1992
------- ------ ------
(DOLLARS IN MILLIONS
EXCEPT PER BARREL AMOUNTS)

GROSS OPERATING REVENUES:
Refined products..................................................................... $ 582.7 590.9 745.6
Other, primarily crude oil resales and merchandise................................... 104.3 96.3 65.1
------- ------ ------
Gross Operating Revenues....................................................... $ 687.0 687.2 810.7
======= ====== ======
OPERATING PROFIT (LOSS):
Gross margin -- refined products..................................................... $ 85.3 89.4 59.0
Gross margin -- other................................................................ 13.1 13.2 12.8
------- ------ ------
Gross margin................................................................... 98.4 102.6 71.8
Operating expenses................................................................... 88.2 76.9 75.3
Depreciation and amortization........................................................ 10.4 10.3 10.2
Other, including gain on asset sales................................................. (2.6) .2 1.2
------- ------ ------
Operating Profit (Loss)........................................................ $ 2.4 15.2 (14.9)
======= ====== ======
PRODUCT SALES (average daily barrels):
Gasoline............................................................................. 23,191 22,466 25,196
Middle distillates................................................................... 33,256 29,354 38,313
Heavy oils and residual product...................................................... 14,228 16,945 23,931
------- ------ ------
Total Product Sales............................................................ 70,675 68,765 87,440
======= ====== ======
PRODUCT SALES PRICES ($/barrel):
Gasoline............................................................................. $ 27.03 27.82 28.89
Middle distillates................................................................... $ 24.47 27.39 26.93
Heavy oils and residual product...................................................... $ 10.93 11.19 11.60
Average Sales Price.................................................................. $ 22.59 23.54 23.30
Average Costs of Sales*.............................................................. 19.67 19.98 21.12
------- ------ ------
Gross Sales Margin................................................................... $ 2.92 3.56 2.18
======= ====== ======
REFINERY THROUGHPUT (average daily barrels)............................................ 46,032 49,753 61,425
======= ====== ======
REFINERY PRODUCTION (average daily barrels):
Gasoline............................................................................. 11,728 12,021 14,188
Middle distillates................................................................... 18,839 19,441 23,305
Heavy oils and residual product...................................................... 15,118 17,573 23,444
Refinery fuel........................................................................ 1,776 2,046 2,491
------- ------ ------
Total Refinery Production...................................................... 47,461 51,081 63,428
======= ====== ======
REFINED PRODUCT SPREAD ($/barrel):
Average yield value of products produced............................................. $ 19.48 20.11 20.66
Cost of raw materials................................................................ 15.65 15.73 17.35
------- ------ ------
Spread......................................................................... $ 3.83 4.38 3.31
======= ====== ======

- ---------------
* Computations of per barrel average costs of sales in 1994 exclude the benefits
of an $8.5 million tariff refund and $1.5 million in favorable feedstock cost
adjustments. Excluded in the computation for 1992 was a charge of $10.5
million for a settlement with the State. The effects of noncash LIFO
adjustments, most significantly a charge of $3.9 million in 1992, have been
included in the per barrel average costs of sales computations.

26
27

In addition to products manufactured at the refinery, other sources of
refined products available for sale include existing inventory balances and
products purchased from third parties. Margins on sales of purchased products,
together with the effect of changes in inventories, are included in the gross
sales margin presented above. During 1994, 1993 and 1992, the Company purchased
for resale approximately 27,200, 19,300 and 25,200 average daily barrels of
refined products, respectively. While margins on sales of purchased product
remained relatively steady in 1994 and 1993, these margins were lower in 1992
due to product purchased to satisfy a contract commitment.

1994 COMPARED TO 1993. Throughout most of 1994, the Refining and Marketing
segment was adversely affected by the volatile product market and increased
demand for ANS crude oil. The Company's average sales price for refined products
decreased from $23.54 per barrel in 1993 to $22.59 per barrel in 1994. Although
the Company's average crude costs were lower in 1994, decreased production of
ANS crude oil, combined with an increased demand for ANS crude oil for use as a
feedstock in West Coast refineries, resulted in an increase in the cost of ANS
crude oil supplied to the Company's refinery. As a result, the Company's refined
product margins were severely depressed in 1994 and will continue to be
depressed as long as the cost of ANS crude oil remains high relative to the
price received for the Company's sales of refined products.

The adverse effect of market conditions on the segment's 1994 results,
combined with charges of $6.6 million for environmental contingencies and other
matters, was partially offset by a refund of $8.5 million 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. Excluding these items, the
segment's operating profit of $2.4 million for 1994 would be reduced to a loss
of $3.4 million, compared with operating profit of $15.2 million in 1993. The
decrease in operating results in 1994 was primarily attributable to lower gross
margins on sales of refined products, which fell to $2.92 per barrel in 1994,
compared with $3.56 per barrel in 1993. Revenues from sales of refined products
in 1994 were lower than 1993 due to lower sales prices. However, these lower
refined product revenues in 1994 were partially offset by crude oil resales of
$72.3 million, compared with $62.1 million in 1993. To optimize the refinery's
feedstock mix and in response to market conditions, the Company at times resells
previously purchased crude oil. The increase in operating expenses of $11.3
million was primarily for environmental matters and, to a lesser extent, higher
advertising and maintenance expenses.

During 1994, the Company continued its operational strategy to improve the
refinery's economics, which included upgrading feedstocks, more closely matching
production with product demand within Alaska and initiating new marketing
efforts within and outside Alaska. These efforts reduced the Company's overall
refinery production in 1994, particularly residual fuel oil. The markets for
residual fuel oil have generally been weak for the past several years due to a
global oversupply of this product. During 1994, the Company reduced its average
daily refinery throughput and production by 7% from the 1993 levels, resulting
in a cumulative reduction from the 1992 levels of 25%. This reduction in
throughput enabled the Company to reduce the percentage of lower-quality ANS
crude oil in the feedstock mix to 59% in 1994, compared with 72% in 1993. By
utilizing a greater percentage of higher-quality feedstocks (which results in
higher-valued production yields), the Company can economically operate the
refinery at reduced throughput levels. Operating the refinery at lower
throughput levels resulted in less production of certain products, particularly
residual fuel oil, for which there is no significant market in Alaska. During
1994, residual fuel oil produced at the refinery was exported from Alaska and
sold into U.S. West Coast and Far Eastern markets. The Company has installed a
vacuum unit, which became operational in December 1994, that is expected to
reduce the refinery's yield of residual product about 50% by further processing
these volumes into higher-valued products. With the vacuum unit now operational,
the Company is pursuing marketing initiatives to increase demand for the
refinery's production which would increase the refinery's capacity utilization
and improve efficiencies.

1993 COMPARED TO 1992. Similar to the reasons discussed above,
implementation of the Company's operational strategy reduced refinery throughput
and production during 1993 by 19%. The decrease in volumes was a significant
factor in the change in revenues when comparing 1993 with 1992. Average sales
prices were essentially unchanged; however, gross margins increased in 1993.
Partially offsetting the decrease in revenues from refined products was a $33.8
million increase in resales of crude oil. Costs of sales in 1993 decreased due
to lower volumes and prices and to the $10.5 million charge in 1992 for
settlement of a contractual dispute

27
28

with the State relating to the purchase of crude oil. The $30.1 million
improvement in overall operating profit was primarily due to the improved
margins on refined product sales, part of which was attributable to favorable
market conditions during the fourth quarter of 1993. While the price of crude
oil dropped in the 1993 fourth quarter, the Company's refined product margins
held steady or improved.

EXPLORATION AND PRODUCTION

1994 1993 1992
------- ------ ------
(DOLLARS IN MILLIONS
EXCEPT PER UNIT AMOUNTS)

UNITED STATES:
Gross operating revenues*..................................... $ 93.1 50.5 18.8
Lifting cost.................................................. 13.8 6.8 3.8
Depreciation, depletion and amortization...................... 24.3 11.1 4.9
Other......................................................... -- .3 1.2
------- ------ ------
Operating Profit -- United States..................... 55.0 32.3 8.9
------- ------ ------
BOLIVIA:
Gross operating revenues...................................... 13.2 12.6 17.9
Lifting cost.................................................. .6 1.2 .7
Other......................................................... 3.3 3.0 4.6
------- ------ ------
Operating Profit -- Bolivia........................... 9.3 8.4 12.6
------- ------ ------
INDONESIA(sold effective May 1, 1992):
Gross operating revenues...................................... -- -- 6.0
Lifting cost.................................................. -- -- 3.7
Depreciation, depletion and amortization...................... -- -- .3
Gain on sales of assets and other............................. -- -- (5.6)
------- ------ ------
Operating Profit -- Indonesia......................... -- -- 7.6
------- ------ ------
TOTAL OPERATING PROFIT -- EXPLORATION AND PRODUCTION............ $ 64.3 40.7 29.1
======= ====== ======
UNITED STATES:
Net natural gas production (average daily Mcf) --
Spot market and other...................................... 65,841 28,168 9,986
Tennessee Gas Contract*.................................... 17,955 10,599 3,974
------- ------ ------
Total Production...................................... 83,796 38,767 13,960
======= ====== ======
Average natural gas sales price per Mcf --
Spot market................................................ $ 1.64 2.03 1.83
Tennessee Gas Contract*.................................... $ 8.01 7.59 4.46
Average.................................................... $ 3.00 3.55 3.68
Average lifting cost per Mcf.................................. $ .45 .48 .74
Depletion per Mcf............................................. $ .79 .78 .95
BOLIVIA:
Net natural gas production (average daily Mcf)................ 22,082 19,232 19,421
Average natural gas sales price per Mcf....................... $ 1.20 1.22 1.67
Net crude oil (condensate) production (average daily
barrels)................................................... 733 663 660
Average crude oil sales price per barrel...................... $ 13.28 14.26 17.65
Average lifting cost per net equivalent Mcf................... $ .06 .14 .08
INDONESIA (sold effective May 1, 1992):
Net crude oil production (average daily barrels).............. -- -- 2,714
Average crude oil sales price per barrel...................... $ -- -- 18.20
Average lifting cost per net equivalent Mcf................... $ -- -- 1.94

- ---------------
* The Company is involved in litigation with Tennessee Gas relating to a natural
gas sales contract. See "Capital Resources and Liquidity -- Tennessee Gas
Contract" and Notes L and P of Notes to Consolidated Financial Statements in
Item 8.

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29

1994 COMPARED TO 1993. The Exploration and Production segment's U.S.
operations, which are concentrated in the Bob West Field in South Texas,
achieved a record level of operating profit in 1994. Successful development
drilling in the Bob West Field increased the number of producing wells in which
the Company has a working interest to 46 at year-end 1994, compared with 25 at
the end of 1993, resulting in a 116% increase in the Company's U.S. natural gas
production. Revenues from the U.S. operations increased by $42.6 million in 1994
primarily due to the increased production. However, revenues were adversely
impacted by a 15% decline in the weighted average sales price, which included a
19% drop in spot market prices. Due to the increase in volumes sold in the spot
market, the percentage contribution of sales at above-market prices under the
Tennessee Gas Contract was reduced. In 1994, approximately 21% of the Company's
net production from the Bob West Field was sold under the Tennessee Gas
Contract, compared with 27% in 1993. Total lifting costs and depreciation,
depletion and amortization were higher in 1994 due to the increased production
level, but were relatively unchanged on a per Mcf basis.

Tennessee Gas may elect, and from time to time has elected, not to take gas
under the Tennessee Gas Contract. The Company recognizes revenues under the
Tennessee Gas Contract based on the quantity of natural gas actually taken by
Tennessee Gas. While Tennessee Gas has the right to elect not to take gas during
any contract year, this right is subject to an obligation to pay, within 60 days
after the end of such contract year, for gas not taken. The contract year ends
on January 31 of each year. Although the failure to take gas could adversely
affect the Company's income and cash flows from operating activities within a
contract year, the Company should recover reduced cash flows shortly after the
end of the contract year under the take-or-pay provisions of the Tennessee Gas
Contract, subject to the provisions of a bond posted by Tennessee Gas which is
discussed in "Capital Resources and Liquidity -- Tennessee Gas Contract" and
Notes L and P of Notes to Consolidated Financial Statements in Item 8.

From time to time, the Company may increase or decrease its natural gas
production in response to market conditions. As a result of weakened spot market
gas prices, beginning in January 1995, the Company and one of its partners
initiated a voluntary reduction of natural gas production sold in the spot
market. The Company's share of this reduction is estimated to be approximately
34 Mmcf per day. Primarily as a result of this voluntary reduction, the
Company's share of spot natural gas production in South Texas averaged 77 Mmcf
per day in January 1995 as compared to 104 Mmcf per day in December 1994. This
voluntary reduction has continued through February 1995.

Results from the Company's Bolivian operations improved by $.9 million in
1994, primarily due to a 15% increase in average daily natural gas production.
The Company was producing gas at higher levels during 1994 due to the inability
of another producer to satisfy gas supply requirements. Natural gas production
volumes in early 1995 have declined to approximately 19,400 average daily Mcf
from the 22,100 average daily Mcf in 1994. 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. The contract between YPFB
and YPF, which was recently extended through March 31, 1997, maintains
approximately the same volumes as their previous contract, but with a small
decrease in price. The Company's contract for the sale of natural gas to YPFB
has expired and is subject to renegotiation. The Company is currently selling
its natural gas production to YPFB based on the pricing terms in the contract
between YPFB and YPF. The Company anticipates that any renegotiation of its
contract with YPFB will result in the Company receiving a lower price than it
received under the previous contract. Any renegotiation may also result in a
reduction of volumes purchased from the Company due to new supply sources that
commenced production near the end of 1994.

1993 COMPARED TO 1992. The number of producing wells in the United States
in which the Company has an interest increased to 25 at year-end 1993 compared
with ten at the end of 1992. The resulting increase in the Company's U.S.
production levels contributed to higher revenues. However, the increase in
production was partially offset by a decline in average sales prices to $3.55
per Mcf in 1993 from $3.68 per Mcf in 1992. Total lifting costs and
depreciation, depletion and amortization increased in 1993 due to the higher
production volumes; however, the depletion rate decreased due to a 63% increase
in proved reserves.

29
30

The Bolivian operations experienced a decline in revenues in 1993 primarily
due to reduced contractual sales prices for natural gas production. The 1992
operating results from the Indonesian operations, which were sold effective May
1, 1992, included a $5.8 million gain from the sale.

OIL FIELD SUPPLY AND DISTRIBUTION

1994 1993 1992
------ ----- -----
(DOLLARS IN MILLIONS)

Gross Operating Revenues........................................... $ 77.9 80.7 93.5
Costs of Sales..................................................... 67.5 68.4 82.4
------ ----- -----
Gross Margin............................................. 10.4 12.3 11.1
Operating Expenses and Other....................................... 12.4 15.5 15.3
Depreciation and Amortization...................................... .3 .4 .5
------ ----- -----
Operating Loss........................................... $( 2.3) (3.6) (4.7)
====== ===== =====
Refined Product Sales (average daily barrels)...................... 7,774 7,368 8,476
====== ===== =====

1994 COMPARED TO 1993. Although sales volumes of refined products
increased by 6% in 1994, sales prices and gross margins continued to be impacted
by strong competition in an oversupplied market. By consolidating certain of the
Company's terminals and discontinuing the environmental products marketing
operations, operating expenses and other were reduced to $12.4 million in 1994
from $15.5 million in 1993. Included in operating expenses in 1994 were charges
of $1.9 million for discontinuing the Company's environmental products marketing
operations. The Company is continuing its wholesale marketing of fuel and
lubricants.

1993 COMPARED TO 1992. Revenues and costs of sales in this segment
decreased in 1993 due to the discontinuance of a wholesale distribution
operation in Oklahoma during the second quarter of 1992. In addition, the
decrease in crude oil prices during 1993 resulted in a corresponding decrease in
refined product prices. Notwithstanding such decreases, margins on both refined
product and merchandise sales improved in 1993 due to the consolidation of
certain of the Company's locations and elimination of marginally profitable
locations, including the facility in Oklahoma. Effective at year-end 1992, the
Company acquired the remaining 50% interest in Tesoro-Leevac Petroleum Company,
a joint venture, which allowed the Company to consolidate certain of its marine
terminals; however, this acquisition did not have a material impact on the
revenues and margins of this segment in 1993.

GENERAL AND ADMINISTRATIVE EXPENSES

General and administrative expenses of $14.7 million in 1994 compare with
$16.7 million in 1993 and $25.9 million in 1992. The Company continues to
closely monitor corporate activities in an effort to minimize costs. These
efforts resulted in a 12% decrease in general and administrative expenses in
1994. The decrease in 1993, compared with 1992, was primarily due to the
inclusion in 1992 of expenses for a cost reduction program and other employee
terminations totaling $9.1 million, of which $1.3 million was charged to the
operating segments. There were no significant comparable charges recorded in
1994 or 1993. The remaining decrease in 1993 was attributable to the effects of
the cost reduction program.

GAIN ON SALES OF ASSETS

During 1994, the Company realized a gain of $2.4 million from the sale of
assets, primarily a terminal facility in Valdez, Alaska. The sale of assets
during 1993 was immaterial, whereas 1992 included a $5.8 million gain from the
sale of the Company's Indonesian operations, partially offset by a $1.8 million
loss from the sale of drilling rigs and costs related to the disposition of the
Company's remaining oil field tool rental assets.

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31

INTEREST EXPENSE

Interest expense of $18.7 million in 1994 compares with $14.5 million in
1993 and $21.1 million in 1992. The increase in 1994 was primarily due to a
reduction of $5.2 million recorded in 1993 related to the resolution of
outstanding issues with several state taxing authorities, partially offset by
$.9 million capitalized interest in 1994 related to construction of the vacuum
unit. When comparing 1993 with 1992, the change was also due to the reduction
related to the resolution of state tax issues.

INCOME TAXES

Income taxes of $5.6 million in 1994 compare with $1.7 million in 1993 and
$5.4 million in 1992. The increase in 1994, compared with 1993, was primarily
due to a reduction of $3.0 million recorded in 1993 for resolution of
outstanding issues with several state taxing authorities. The decrease in 1993,
compared with 1992, was also due to the reduction related to state tax issues
together with lower foreign income taxes resulting from the Company's reduced
revenues from its Bolivian operations.

IMPACT OF CHANGING PRICES

The Company's operating results and cash flows are sensitive to the
volatile changes in energy prices. Major shifts in the cost of crude oil 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.

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 carrying value of oil and gas assets
may also be subject to noncash write-downs based on changes in natural gas
prices and other determining factors.

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32

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, 1994 and 1993, and the
related statements of consolidated operations, stockholders' equity and cash
flows for each of the three years in the period ended December 31, 1994. 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, 1994 and 1993, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1994, in conformity with generally accepted accounting principles.

As discussed in Note A of Notes to Consolidated Financial Statements, in
1992 the Company changed its methods of accounting for postretirement benefits
other than pensions and accounting for income taxes.

DELOITTE & TOUCHE LLP

San Antonio, Texas
February 1, 1995

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33

TESORO PETROLEUM CORPORATION

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

YEARS ENDED DECEMBER 31,
--------------------------------
1994 1993 1992
-------- ------- -------

REVENUES:
Gross operating revenues................................... $871,211 831,007 946,446
Interest income............................................ 2,522 1,803 3,170
Gain on sales of assets.................................... 2,379 60 4,024
Other...................................................... 1,048 2,040 732
-------- ------- -------
Total Revenues..................................... 877,160 834,910 954,372
-------- ------- -------
COSTS AND EXPENSES:
Costs of sales and operating expenses...................... 775,051 756,764 926,082
General and administrative................................. 14,750 16,712 25,849
Depreciation, depletion and amortization................... 36,016 22,591 16,552
Interest expense, net of capitalized interest.............. 18,749 14,550 21,115
Other...................................................... 6,538 5,640 4,636
-------- ------- -------
Total Costs and Expenses........................... 851,104 816,257 994,234
-------- ------- -------
EARNINGS (LOSS) BEFORE INCOME TAXES, EXTRAORDINARY LOSS ON
EXTINGUISHMENT OF DEBT AND THE CUMULATIVE EFFECT OF
ACCOUNTING CHANGES......................................... 26,056 18,653 (39,862)
Income Tax Provision......................................... 5,573 1,697 5,383
-------- ------- -------
EARNINGS (LOSS) BEFORE EXTRAORDINARY LOSS ON EXTINGUISHMENT
OF DEBT AND THE CUMULATIVE EFFECT OF ACCOUNTING CHANGES.... 20,483 16,956 (45,245)
Extraordinary Loss on Extinguishment of Debt................. (4,752) -- --
Cumulative Effect of Accounting Changes...................... -- -- (20,630)
-------- ------- -------
NET EARNINGS (LOSS).......................................... 15,731 16,956 (65,875)
Dividend Requirements on Preferred Stock..................... 2,680 9,207 9,207
-------- ------- -------
NET EARNINGS (LOSS) APPLICABLE TO COMMON STOCK............... $ 13,051 7,749 (75,082)
======== ======= =======

EARNINGS (LOSS) PER PRIMARY AND FULLY DILUTED* SHARE:
Earnings (Loss) Before Extraordinary Loss on Extinguishment
of Debt and the Cumulative Effect of Accounting
Changes................................................. $ .77 .54 (3.87)
Extraordinary Loss on Extinguishment of Debt............... (.21) -- --
Cumulative Effect of Accounting Changes.................... -- -- (1.47)
-------- ------- -------
Net Earnings (Loss)........................................ $ .56 .54 (5.34)
======== ======= =======

WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES......... 23,196 14,290 14,063
======== ======= =======

- ---------------
* Anti-dilutive

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

33
34

TESORO PETROLEUM CORPORATION

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

DECEMBER 31,
--------------------
1994 1993
-------- -------

ASSETS
CURRENT ASSETS:
Cash and cash equivalents (includes restricted cash of $25,420 in
1993).............................................................. $ 14,018 36,596
Short-term investments................................................ -- 5,952
Receivables, net...................................................... 91,140 69,637
Inventories........................................................... 68,302 74,186
Prepaid expenses and other............................................ 8,648 10,136
-------- -------
Total Current Assets.......................................... 182,108 196,507
-------- -------
PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment......................................... 479,116 385,463
Less accumulated depreciation, depletion and amortization............. 205,782 172,312
-------- -------
Net Property, Plant and Equipment............................. 273,334 213,151
-------- -------
OTHER ASSETS:
Investment in Tesoro Bolivia Petroleum Company........................ 10,295 6,310
Other................................................................. 18,623 18,554
-------- -------
Total Other Assets............................................ 28,918 24,864
-------- -------
Total Assets............................................. $484,360 434,522
======== =======
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable...................................................... $ 53,573 43,192
Accrued liabilities................................................... 35,266 24,017
Current portion of long-term debt and other obligations............... 7,404 4,805
-------- -------
Total Current Liabilities..................................... 96,243 72,014
-------- -------
OTHER LIABILITIES....................................................... 35,175 45,272
-------- -------
LONG-TERM DEBT AND OTHER OBLIGATIONS,
LESS CURRENT PORTION.................................................. 192,210 180,667
-------- -------
COMMITMENTS AND CONTINGENCIES (Note L)

$2.20 REDEEMABLE CUMULATIVE CONVERTIBLE PREFERRED STOCK AND ACCRUED
DIVIDENDS; $1 stated value, 2,875,000 shares issued and outstanding in
1993; liquidation and redemption value of $78,056 in 1993............. -- 78,051
-------- -------
STOCKHOLDERS' EQUITY:
Preferred stock, no par value; authorized 5,000,000 shares including
redeemable preferred shares:
$2.16 Cumulative convertible preferred stock; $1 stated value,
1,319,563 shares issued and outstanding in 1993; liquidation value
of $42,134 in 1993................................................ -- 1,320
Common stock, par value $.16 2/3; authorized 50,000,000 shares;
24,389,801 shares issued and outstanding (14,089,236 in 1993)...... 4,065 2,348
Additional paid-in capital............................................ 175,514 86,748
Accumulated deficit................................................... (18,847) (31,898)
-------- -------
Total Stockholders' Equity.................................... 160,732 58,518
-------- -------
Total Liabilities and Stockholders' Equity............... $484,360 434,522
======== =======

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

34
35

TESORO PETROLEUM CORPORATION

STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)

$2.20 $2.16
CUMULATIVE CUMULATIVE
CONVERTIBLE CONVERTIBLE RETAINED
PREFERRED STOCK PREFERRED STOCK COMMON STOCK ADDITIONAL EARNINGS
------------------- ------------------ ----------------- PAID-IN (ACCUMULATED
SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT CAPITAL DEFICIT)
------ -------- ------ ------- ------ ------ ---------- ------------

DECEMBER 31, 1991.............. -- $ -- 1,320 $ 1,320 14,067 $2,344 $ 86,522 $ 46,785
Net loss..................... -- -- -- -- -- -- -- (65,875)
Accrued dividends on
preferred stocks........... -- -- -- -- -- -- -- (20,525)
Stock awards and other....... -- -- -- -- 4 1 125 (32)
------ -------- ------ ------- ------ ------ ---------- ------------
DECEMBER 31, 1992.............. -- -- 1,320 1,320 14,071 2,345 86,647 (39,647)
Net earnings................. -- -- -- -- -- -- -- 16,956
Accrued dividends on
preferred stocks........... -- -- -- -- -- -- -- (9,175)
Stock awards and other....... -- -- -- -- 18 3 101 (32)
------ -------- ------ ------- ------ ------ ---------- ------------
DECEMBER 31, 1993.............. -- -- 1,320 1,320 14,089 2,348 86,748 (31,898)
Net earnings................. -- -- -- -- -- -- -- 15,731
Accrued dividends on
preferred stocks........... -- -- -- -- -- -- -- (2,680)
Reclassification of $2.16
Preferred Stock and accrued
and unpaid dividends
thereon into Common
Stock...................... -- -- (1,320) (1,320) 6,598 1,099 9,670 --
Issuance of Common Stock in
connection with
reclassification of $2.20
Preferred Stock and accrued
dividends thereon into
equity..................... 2,875 57,500 -- -- 1,900 317 20,914 --
Costs of Recapitalization.... -- -- -- -- -- -- (3,327) --
Offering, net................ -- -- -- -- 5,851 975 55,992 --
Exercise of MetLife Louisiana
Option..................... (2,875) (57,500) -- -- (4,084) (681) 5,232 --
Stock awards and other....... -- -- -- -- 36 7 285 --
------ -------- ------ ------- ------ ------ ---------- ------------
DECEMBER 31, 1994.............. -- $ -- -- $ -- 24,390 $4,065 $175,514 $(18,847)
====== ========= ====== ======== ====== ======= ========= ============

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

35
36

TESORO PETROLEUM CORPORATION

STATEMENTS OF CONSOLIDATED CASH FLOWS
(IN THOUSANDS)

YEARS ENDED DECEMBER 31,
--------------------------------
1994 1993 1992
-------- ------- -------

CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net earnings (loss)........................................ $ 15,731 16,956 (65,875)
Adjustments to reconcile net earnings (loss) to net cash
from operating activities:
Depreciation, depletion and amortization................ 36,016 22,591 16,552
Loss (gain) on extinguishment of debt................... 4,752 (1,422) --
Cumulative effect of accounting changes................. -- -- 20,630
Gain on sales of assets................................. (2,379) (60) (4,024)
Amortization of deferred charges and other, net......... 2,800 3,323 4,231
Changes in assets and liabilities:
Receivables........................................... (20,503) 7,539 12,320
Inventories........................................... 5,884 325 7,986
Investment in Tesoro Bolivia Petroleum Company........ (3,985) (3,524) 3,908
Other assets.......................................... 2,177 (85) 3,484
Accounts payable and other current liabilities........ 20,567 (12,800) (5,282)
Obligation payments to State of Alaska................ (2,754) (12,910) --
Other liabilities and obligations..................... 1,991 1,901 17,458
-------- ------- -------
Net cash from operating activities................. 60,297 21,834 11,388
-------- ------- -------
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Capital expenditures....................................... (99,587) (37,451) (15,446)
Proceeds from sales of assets, net......................... 2,544 194 12,905
Purchases of short-term investments........................ (1,974) (26,245) (23,976)
Sales of short-term investments............................ 7,926 40,314 3,955
Other...................................................... (50) (247) 1,478
-------- ------- -------
Net cash used in investing activities.............. (91,141) (23,435) (21,084)
-------- ------- -------
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Proceeds from issuance of common stock, net................ 56,967 -- --
Repurchase of common and preferred stock................... (52,948) -- --
Repurchase of debentures................................... -- (9,675) --
Payments of long-term debt................................. (11,383) (1,643) (6,468)
Issuance of long-term debt................................. 20,000 5,000 2,024
Dividends on preferred stocks.............................. (1,684) -- --
Costs of Recapitalization and other........................ (2,686) (2,354) (20)
-------- ------- -------
Net cash from (used in) financing activities....... 8,266 (8,672) (4,464)
-------- ------- -------
DECREASE IN CASH AND CASH EQUIVALENTS........................ (22,578) (10,273) (14,160)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR............... 36,596 46,869 61,029
-------- ------- -------
CASH AND CASH EQUIVALENTS AT END OF YEAR..................... $ 14,018 36,596 46,869
======== ======= =======
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Interest paid, net of $915 capitalized in 1994............. $ 15,898 19,288 17,805
======== ======= =======
Income taxes paid.......................................... $ 5,361 5,125 6,446
======== ======= =======

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

36
37

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE A -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Tesoro Petroleum Corporation is a natural resource company engaged in
petroleum refining and marketing, natural gas exploration and production, and
wholesale marketing of fuel and lubricants.

PRINCIPLES OF CONSOLIDATION AND PRESENTATION

The Consolidated Financial Statements include the accounts of Tesoro
Petroleum Corporation and its subsidiaries (collectively, the "Company" or
"Tesoro") after elimination of significant intercompany balances and
transactions. The preparation of these Consolidated Financial Statements
required the use of management's best estimates and judgment. Certain previously
reported amounts have been reclassified to conform with the 1994 presentation.

CASH AND CASH EQUIVALENTS AND SHORT-TERM INVESTMENTS

The Company considers all highly liquid investments purchased with a
maturity of three months or less to be cash equivalents. Short-term debt
securities with original maturities in excess of 90 days are classified as
short-term investments on the Company's Consolidated Balance Sheets. Cash
equivalents and short-term investments are stated at cost, which approximates
market value. For information regarding restricted cash, see Note I.

INVENTORIES

The Company follows the lower of cost (last-in, first-out basis -- LIFO) or
market method for valuing inventories of crude oil and wholesale refined
products. All other inventories are valued principally at the lower of cost
(generally on a first-in, first-out or weighted-average basis) or market.

HEDGES

The Company, at times, enters into futures and other contracts in its
refining and marketing and natural gas operations to hedge the price risks
associated with inventories and anticipated transactions. The impact of changes
in the market value of these contracts is deferred until the gain or loss is
recognized on the hedged inventory or commitment. At December 31, 1994 and 1993,
deferred gains and losses related to hedge transactions were not material.
Amounts recognized in the Statements of Consolidated Operations related to these
transactions for the years ended December 31, 1994, 1993 and 1992 were not
material.

PROPERTY, PLANT AND EQUIPMENT

The annual provisions for depreciation on the Company's property, plant and
equipment have been computed in accordance with the following ranges of rates:

Refining and Marketing.................................... 3 years to 34 years
Exploration and Production................................ 3 years to 20 years
Oil Field Supply and Distribution......................... 3 years to 45 years
Corporate................................................. 3 years to 20 years

The Company uses the full-cost method of accounting for oil and gas
properties. 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

37
38

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. No gain or loss is recognized on the
sale of oil and gas properties except in the case of the sale of properties
involving significant remaining reserves. Proceeds from the sale of
insignificant reserves and undeveloped properties are applied to reduce the
costs in the cost centers.

Assets recorded under capital leases have been capitalized in accordance
with promulgations from the Financial Accounting Standards Board. Amortization
of such assets is recorded over the shorter of lease terms or useful lives under
methods that are consistent with the Company's depreciation policy for owned
assets.

Depreciation of other property is provided using primarily the
straight-line method with rates based on the estimated useful lives of the
properties and with an estimated salvage value of generally 20% for refinery
assets and 10% for other assets. Amortization of leasehold improvements is
provided using the straight-line method over the term of the respective lease or
the useful life of the asset, whichever period is less.

RETIREE HEALTH CARE AND LIFE INSURANCE BENEFITS

The Company accounts for retiree health care and life insurance benefits in
accordance with Statement of Financial Accounting Standards No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions" ("SFAS No. 106").
The projected future cost of providing postretirement benefits other than
pensions, such as health care and life insurance, are expensed as employees
render service instead of when benefits are paid. Prior to the adoption of SFAS
No. 106, the Company had expensed these benefits on a pay-as-you-go basis. The
adoption of SFAS No. 106, effective January 1, 1992, resulted in a net charge of
$21.6 million, or $1.54 per share, for the cumulative effect of the change in
accounting principle for periods prior to 1992, which were not restated. In
addition, the adoption of SFAS No. 106 resulted in an increase of $1.2 million,
or $.09 per share, in the 1992 net loss before cumulative effect of accounting
changes.

INCOME TAXES

The Company accounts for income taxes in accordance with Statement of
Financial Accounting Standards No. 109, "Accounting for Income Taxes" ("SFAS No.
109"). Deferred tax assets and liabilities are recognized for future tax
consequences attributable to differences between financial statement carrying
amounts of existing 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. Under SFAS No. 109, the
effect on deferred tax assets and liabilities of a change in tax rates is
recognized in income in the period that includes the enactment date. The Company
adopted SFAS No. 109 effective January 1, 1992 by recognizing a net benefit of
$1.0 million, or $.07 per share, for the cumulative effect of the accounting
change. Periods prior to 1992 were not restated. The adoption of SFAS No. 109
did not have a significant effect on 1992 results of operations.

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

38
39

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

timing of these accruals coincides with completion of a feasibility study or the
Company's commitment to a formal plan of action.

EARNINGS (LOSS) PER SHARE

Primary earnings (loss) per share is calculated on net earnings (loss)
after deducting dividend requirements on preferred stocks and is based on the
weighted average number of common and common equivalent shares outstanding
during the period. Fully diluted earnings (loss) per share was the same as
primary earnings (loss) per share since the assumed conversion of preferred
stocks to common shares would be anti-dilutive.

NOTE B -- BUSINESS SEGMENTS

The Company's revenues are derived from three business segments: Refining
and Marketing, Exploration and Production, and Oil Field Supply and
Distribution.

Refining and Marketing includes the operations of the Company's refinery in
Kenai, Alaska, which produces gasoline, jet fuel, diesel fuel, and heavy oils
and residual product. These products, together with other purchased products,
are sold primarily at wholesale through terminal facilities and other locations
in Alaska, California and the Pacific Northwest. In addition, Refining and
Marketing sells gasoline, petroleum products and convenience store items at
retail through a chain of 7-Eleven convenience stores in Alaska. To optimize the
refinery's feedstock mix and in response to market conditions, the Company at
times resells previously purchased crude oil. These crude oil resales amounted
to $72.3 million, $62.1 million and $28.3 million in 1994, 1993 and 1992,
respectively. From time to time, Refining and Marketing exports products to
customers in Far Eastern markets. Revenues from such export sales amounted to
$5.2 million, $20.5 million and $101.0 million in 1994, 1993 and 1992,
respectively.

Exploration and Production is engaged in the exploration, development and
production of natural gas, primarily in the Bob West Field in South Texas. In
addition to natural gas producing activities, Exploration and Production
activities include the transportation of natural gas to processing facilities
and common carrier pipelines in the South Texas area. The Company also holds an
interest in a joint venture agreement to explore for and produce hydrocarbons in
Bolivia. These operations in Bolivia include natural gas and condensate
reserves, the majority of which are shut-in awaiting access to gas-consuming
markets. See Notes L and P for information regarding a natural gas sales
contract that is the subject of litigation.

Oil Field Supply and Distribution is involved with the wholesale marketing
of fuels, lubricants and specialty petroleum products, primarily to onshore and
offshore drilling contractors along the Texas and Louisiana Gulf Coast area.
During 1994, the Company discontinued its environmental remediation products and
services operations formerly associated with this segment.

Segment operating profit is gross operating revenues and gains on asset
sales less applicable segment costs of sales, operating expenses, depreciation,
depletion and other items. Income taxes, interest expense, interest income and
general and administrative expenses are not included in determining operating
profit. In 1992, the Company sold its Indonesian exploration and production
operations, resulting in a $5.8 million gain that is included in operating
profit presented below. Also in 1992, revenues and operating profit from the
South Texas oil and gas producing activities include $5.4 million from a change
in estimate of the Company's revenues from its natural gas production. 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.

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.

39
40

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

YEARS ENDED DECEMBER 31,
--------------------------
1994 1993 1992
------ ----- -----
(IN MILLIONS)

GROSS OPERATING REVENUES:
Refining and Marketing --
Refined products.............................................. $582.7 590.9 745.6
Other, primarily crude oil resales and merchandise............ 104.3 96.3 65.1
Exploration and Production --
U.S. oil and gas.............................................. 91.8 50.2 18.8
Bolivia....................................................... 13.2 12.6 17.9
Other, including U.S. gas transportation...................... 1.3 .3 --
Indonesia..................................................... -- -- 6.0
Oil Field Supply and Distribution................................ 77.9 80.7 93.5
Intersegment Eliminations........................................ -- -- (.4)
------ ----- -----
Total Gross Operating Revenues................................ $871.2 831.0 946.5
====== ===== =====
OPERATING PROFIT (LOSS), INCLUDING GAIN ON SALES OF ASSETS:
Refining and Marketing........................................... $ 2.4 15.2 (14.9)
Exploration and Production --
U.S. oil and gas.............................................. 52.1 31.4 8.9
Bolivia....................................................... 9.3 8.4 12.6
Other, including U.S. gas transportation...................... 2.9 .9 --
Indonesia..................................................... -- -- 7.6
Oil Field Supply and Distribution................................ (2.3) (3.6) (4.7)
------ ----- -----
Total Operating Profit........................................ 64.4 52.3 9.5
Corporate and Unallocated Costs.................................... (38.3) (33.6) (49.4)
------ ----- -----
Earnings (Loss) Before Income Taxes, Extraordinary Loss and the
Cumulative Effect of Accounting Changes.......................... $ 26.1 18.7 (39.9)
====== ===== =====
IDENTIFIABLE ASSETS:
Refining and Marketing........................................... $309.1 281.5 308.0
Exploration and Production --
U.S. oil and gas.............................................. 105.5 65.2 33.1
Bolivia....................................................... 11.1 6.5 2.9
Other, including U.S. gas transportation...................... 8.4 2.0 1.0
Indonesia..................................................... -- -- .3
Oil Field Supply and Distribution................................ 19.8 21.3 23.2
Corporate........................................................ 30.5 58.0 78.2
------ ----- -----
Total Assets.................................................. $484.4 434.5 446.7
====== ===== =====
DEPRECIATION, DEPLETION AND AMORTIZATION:
Refining and Marketing........................................... $ 10.4 10.3 10.2
Exploration and Production --
U.S. oil and gas.............................................. 24.1 11.1 4.9
Other, including U.S. gas transportation...................... .2 -- --
Indonesia..................................................... -- -- .3
Oil Field Supply and Distribution................................ .3 .4 .5
Corporate........................................................ 1.0 .8 .7
------ ----- -----
Total Depreciation, Depletion and Amortization................ $ 36.0 22.6 16.6
====== ===== =====
CAPITAL EXPENDITURES:
Refining and Marketing........................................... $ 32.0 7.1 3.7
Exploration and Production --
U.S. oil and gas.............................................. 60.4 28.6 8.9
Other, including U.S. gas transportation...................... 5.2 .7 --
Indonesia..................................................... -- -- .4
Oil Field Supply and Distribution................................ .2 .3 1.1
Corporate........................................................ 1.8 .8 1.3
------ ----- -----
Total Capital Expenditures.................................... $ 99.6 37.5 15.4
====== ===== =====

40
41

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE C -- RECAPITALIZATION AND OFFERING

RECAPITALIZATION

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, together
with the applicable accounting effects, were as follows:

(i) The Company exchanged $44.1 million principal amount of new 13%
Exchange Notes ("Exchange Notes") due December 1, 2000 for a like principal
amount of 12 3/4% Subordinated Debentures ("Subordinated Debentures") due
March 15, 2001. This exchange satisfied the 1994 sinking fund requirement
and, except for $.9 million, will satisfy sinking fund requirements for the
Subordinated Debentures through 1997.

The exchange of the Subordinated Debentures was accounted for as an
early extinguishment of debt in the first quarter of 1994, resulting in a
charge of $4.8 million as an extraordinary loss on this transaction, which
represented the excess of the estimated market value of the Exchange Notes
over the carrying value of the Subordinated Debentures. The carrying value
of the Subordinated Debentures exchanged was reduced by applicable
unamortized debt issue costs. No tax benefit was available to offset the
extraordinary loss as the Company has provided a 100% valuation allowance
to the extent of its deferred tax assets.

(ii) The 1,319,563 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 aggregating
$9.5 million at February 9, 1994, were reclassified into 6,465,859 shares
of Common Stock. The Company also issued an additional 132,416 shares of
Common Stock on behalf of the holders of $2.16 Preferred Stock in
connection with the settlement of litigation related to the
reclassification of the $2.16 Preferred Stock. In addition, the Company
paid $.5 million for certain legal fees and expenses in connection with
such litigation. The reclassification of the $2.16 Preferred Stock
eliminated annual preferred dividend requirements of $2.9 million on the
$2.16 Preferred Stock.

The issuance of the Common Stock in connection with the
reclassification and settlement of litigation that was recorded in 1994
resulted in an increase in Common Stock of approximately $1 million, equal
to the aggregate par value of the Common Stock issued, and an increase in
additional paid-in capital of approximately $9 million.

(iii) The Company and MetLife Security Insurance Company of Louisiana
("MetLife Louisiana"), the holder of all of the Company's outstanding $2.20
Cumulative Convertible Preferred Stock ("$2.20 Preferred Stock"), entered
into an agreement pursuant to which MetLife Louisiana 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 $21.2 million at February 9, 1994) to have been paid, and to
grant to the Company a three-year option (the "MetLife Louisiana Option")
to purchase all of MetLife Louisiana's holdings of $2.20 Preferred Stock
and Common Stock for approximately $53 million prior to June 30, 1994
(after giving effect to the cash dividend on the $2.20 Preferred Stock paid
in May 1994), all in consideration for, among other things, the issuance by
the Company to MetLife Louisiana of 1,900,075 shares of Common Stock. Such
additional shares were also subject to the MetLife Louisiana Option.

These actions resulted in the reclassification of the $2.20 Preferred
Stock into equity capital at its aggregate liquidation preference of $57.5
million and the recording of an increase in additional paid-in capital of
approximately $21 million in February 1994.

41
42

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

EQUITY OFFERING

In June 1994, the Company completed a public offering (the "Offering") of
5,850,000 shares of its Common Stock for the purpose of raising funds to
exercise the MetLife Louisiana Option. Net proceeds to the Company from the
Offering, after deduction of associated expenses, were approximately $57.0
million. On June 29, 1994, the Company exercised the MetLife Louisiana Option in
full for approximately $53.0 million, acquiring 2,875,000 shares of $2.20
Preferred Stock having a liquidation value of $57.5 million and 4,084,160 shares
of Common Stock having an aggregate market value of $45.9 million (based on a
closing price of $11.25 per share on June 28, 1994). The exercise eliminated
annual preferred dividend requirements of $6.3 million on the $2.20 Preferred
Stock. The Offering and the exercise in full of the MetLife Louisiana Option
resulted in a net increase of 1,765,840 outstanding shares of Common Stock, the
retirement of $57.5 million of the $2.20 Preferred Stock, and increases in
Common Stock of approximately $.3 million, additional paid-in capital of
approximately $61.2 million and cash of approximately $4.0 million in June 1994.

If the Recapitalization and Offering had been completed at the beginning of
the year, the pro forma earnings per share before extraordinary loss would have
increased from $.77 to $.82 on both a primary and fully diluted basis for the
year ended December 31, 1994, reflecting the elimination of all preferred stock
dividend requirements and the issuance of additional shares of Common Stock
associated with the Recapitalization and Offering reduced by shares of Common
Stock acquired and retired upon exercise of the MetLife Louisiana Option.

See Note I for information on the Company's long-term debt, including
restrictions on dividend payments.

NOTE D -- RECEIVABLES

The Company's allowance for doubtful accounts is reflected as a reduction
of receivables in the Consolidated Balance Sheets. The following table
reconciles the change in the Company's allowance for doubtful accounts (in
thousands):

YEARS ENDED DECEMBER 31,
---------------------------
1994 1993 1992
------ ----- ------

Balance at Beginning of Year...................................... $2,487 2,587 4,068
Charged to Costs and Expenses..................................... 299 667 937
Recoveries of Amounts Previously Written Off and Other............ (4) 71 396
Write-off of Doubtful Accounts.................................... (966) (838) (2,814)
------ ----- ------
Balance at End of Year....................................... $1,816 2,487 2,587
====== ===== ======

Receivables at December 31, 1994 included $17.7 million relating to sales
under a natural gas sales contract that is the subject of litigation. Of this
amount, $13.2 million represented the difference between the contract price and
the price currently being received by the Company under the terms of a
court-ordered bonding arrangement. For further information on this litigation,
see Notes L and P.

42
43

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE E -- INVENTORIES

Components of inventories at December 31, 1994 and 1993 were as follows (in
thousands):

DECEMBER 31,
------------------
1994 1993
------- ------

Crude Oil and Wholesale Refined Products, at LIFO......................... $58,798 62,959
Merchandise and Retail Refined Products................................... 5,934 8,052
Materials and Supplies.................................................... 3,570 3,175
------- ------
Inventories............................................................. $68,302 74,186
======= ======

At December 31, 1994, inventories valued using LIFO were lower than
replacement cost by approximately $1.8 million. At December 31, 1993,
inventories valued using LIFO approximated replacement cost.

NOTE F -- PROPERTY, PLANT AND EQUIPMENT

Components of property, plant and equipment at December 31, 1994 and 1993
were as follows (in thousands):

DECEMBER 31,
--------------------
1994 1993
-------- -------

Refining and Marketing.................................................. $309,925 282,286
Exploration and Production, Full-Cost Method of Accounting:
Properties being amortized............................................ 131,930 73,345
Properties not yet evaluated.......................................... 3,758 1,959
Other................................................................. 6,543 1,339
Oil Field Supply and Distribution....................................... 14,689 15,413
Corporate............................................................... 12,271 11,121
-------- -------
479,116 385,463
Less Accumulated Depreciation, Depletion and Amortization............... 205,782 172,312
-------- -------
Net Property, Plant and Equipment..................................... $273,334 213,151
======== =======

NOTE G -- ACCRUED LIABILITIES

The Company's current accrued liabilities as shown in the Consolidated
Balance Sheets included the following (in thousands):

DECEMBER 31,
------------------
1994 1993
------- ------

Accrued Environmental Costs............................................... $10,829 6,171
Accrued Interest.......................................................... 4,223 5,185
Accrued Employee and Pension Costs........................................ 7,884 4,028
Accrued Product Taxes..................................................... 3,009 749
Other..................................................................... 9,321 7,884
------- ------
Accrued Liabilities..................................................... $35,266 24,017
======= ======

43
44

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Other liabilities classified as noncurrent in the Consolidated Balance
Sheets consisted of the following (in thousands):

DECEMBER 31,
------------------
1994 1993
------- ------

Accrued Postretirement Benefits........................................... $26,131 27,270
Deferred Income Taxes..................................................... 4,582 3,792
Accrued Dividends on $2.16 Preferred Stock................................ -- 9,145
Other..................................................................... 4,462 5,065
------- ------
Other Liabilities....................................................... $35,175 45,272
======= ======

NOTE H -- INCOME TAXES

The income tax provision included the following (in thousands):

YEARS ENDED DECEMBER 31,
---------------------------
1994 1993 1992
------ ------ -----

Federal:
Current......................................................... $ 700 -- 418
Deferred........................................................ -- -- (454)
Foreign........................................................... 3,588 3,419 5,104
State............................................................. 1,285 (1,722) 315
------ ------ -----
Income Tax Provision............................................ $5,573 1,697 5,383
====== ====== =====

During 1993, the Company resolved several outstanding issues with state
taxing authorities resulting in a reduction of $3.0 million in state income tax
expense and $5.2 million in related interest expense.

Deferred income taxes and benefits are provided for differences between
financial statement carrying amounts of existing assets and liabilities and
their respective tax bases. Temporary differences and the resulting deferred tax
assets and liabilities are summarized as follows (in thousands):

DECEMBER 31,
--------------------
1994 1993
-------- -------

Deferred Tax Assets:
Net operating losses available for utilization through the year
2008............................................................... $ 16,921 24,890
Investment tax and other credits...................................... 8,196 8,196
Settlement with the State of Alaska................................... 21,650 21,583
Accrued postretirement benefits....................................... 8,865 8,359
Settlement with Department of Energy.................................. 4,443 4,443
Other................................................................. 8,994 7,220
-------- -------
Total Deferred Tax Assets..................................... 69,069 74,691
Deferred Tax Liabilities:
Accelerated depreciation and property-related items................... (43,621) (45,965)
-------- -------
Deferred Tax Assets Before Valuation Allowance.......................... 25,448 28,726
Valuation Allowance..................................................... (25,448) (28,726)
State Income and Alternative Minimum Taxes.............................. (4,332) (3,350)
Other................................................................... (250) (442)
-------- -------
Net Deferred Tax Liability............................................ $ (4,582) (3,792)
======== =======

44
45

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table sets forth the components of the Company's results of
operations and a reconciliation of the normal statutory federal income tax with
the provision for income taxes (in thousands):

YEARS ENDED DECEMBER 31,
------------------------------
1994 1993 1992
------- ------ -------

Earnings (Loss) Before Income Taxes, Extraordinary Loss and the
Cumulative Effect of Accounting Changes:
United States............................................. $18,336 10,906 (60,117)
Foreign................................................... 7,720 7,747 20,255
------- ------ -------
$26,056 18,653 (39,862)
======= ====== =======

Income Taxes at Statutory U.S. Corporate Tax Rate.............. $ 9,120 6,529 (13,553)
Effect of:
Foreign income taxes, net of U.S. tax benefit................ 3,588 3,419 5,104
State income taxes (benefit), net of U.S. tax benefit........ 1,285 (1,722) 315
Accounting limitation (recognition) of operating loss
tax benefits.............................................. (9,120) (6,529) 13,553
Other........................................................ 700 -- (36)
------- ------ -------
Income Tax Provision...................................... $ 5,573 1,697 5,383
======= ====== =======

At December 31, 1994, the Company's net operating loss carryforwards were
approximately $48.3 million for regular tax and approximately $26.2 million for
alternative minimum tax. These tax loss carryforwards are available for future
years and, if not used, will begin to expire in the year 2004. Also at December
31, 1994, the Company had approximately $8.2 million of investment tax credits
and employee stock ownership credits available for carryover to subsequent
years. These credits, if not used, will begin to expire in the year 2001.

NOTE I -- LONG-TERM DEBT AND OTHER OBLIGATIONS

Long-term debt and other obligations consisted of the following (in
thousands):

DECEMBER 31,
---------------------
1994 1993
-------- --------

12 3/4% Subordinated Debentures due 2001............................... $ 59,146 98,154
13% Exchange Notes due 2000............................................ 44,116 --
Liability to State of Alaska........................................... 61,856 61,666
Vacuum Unit Loan....................................................... 15,000 --
Liability to Department of Energy...................................... 13,194 13,194
Exploration and Production Loan........................................ -- 5,000
Industrial Revenue Bonds............................................... 2,385 2,752
Capital Lease Obligations (interest at 11%)............................ 3,540 3,934
Other.................................................................. 377 772
-------- --------
199,614 185,472
Less Current Portion................................................... 7,404 4,805
-------- --------
$192,210 180,667
======== ========

Based on closing market prices, at December 31, 1994, the Company estimated
that the fair value of the Subordinated Debentures, exclusive of accrued
interest, was approximately $65.0 million and the fair value of the Exchange
Notes, exclusive of accrued interest, approximated $44.7 million. The carrying
value of the other long-term debt and obligations approximated the Company's
estimate of the fair value of such items.

45
46

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

As discussed in Note C, approximately four years of sinking fund
requirements on the Subordinated Debentures were satisfied by the exchange offer
included in the Recapitalization. After giving effect to the Recapitalization,
sinking fund requirements and aggregate maturities of long-term debt and
obligations for each of the five years following December 31, 1994 are as
follows (in thousands):

SINKING
AGGREGATE FUND
MATURITIES REQUIREMENTS TOTAL
---------- ------------ -------

1995....................................................... $7,404 -- 7,404
1996....................................................... $9,870 -- 9,870
1997....................................................... $9,606 884 10,490
1998....................................................... $9,604 11,250 20,854
1999....................................................... $9,593 11,250 20,843

REVOLVING CREDIT FACILITY

During April 1994, the Company entered into a three-year, $125 million
corporate revolving credit facility ("Revolving Credit Facility") with a
consortium of ten banks. The Revolving Credit Facility, which is subject to a
borrowing base, provides for (i) the issuance of letters of credit up to the
full amount of the borrowing base as calculated, but not to exceed $125 million,
and (ii) cash borrowings up to the amount of the borrowing base attributable to
domestic oil and gas reserves. The Company currently has $100 million in
available commitments under the Revolving Credit Facility. The Company may at
any time designate all or a portion of the remaining $25 million under the
Revolving Credit Facility as available commitments. Outstanding obligations
under the Revolving 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, 1994, the borrowing base, which is comprised of eligible
accounts receivable, inventory and domestic oil and gas reserves, was
approximately $107 million. At December 31, 1994, the Company had outstanding
letters of credit under the Revolving Credit Facility of approximately $48
million, with remaining unused available commitments of approximately $52
million. Cash borrowings are limited to the amount of the domestic oil and gas
reserve component of the borrowing base, which has most recently been determined
to be approximately $45 million. Under the terms of the Revolving Credit
Facility, the oil and gas component of the borrowing base is redetermined at
least semi-annually. The lenders or the Company may request additional
redeterminations. Fees on outstanding letters of credit range from 1.25% to
2.25% per annum, depending upon the Company's cash flow coverage ratio, as
defined, while the excess of total available commitments over cash borrowings
and outstanding letters of credit incur fees of .5% per annum. The Company pays
a fee equal to 1/4 of 1% per annum on amounts that have not been designated as
available commitments. Cash borrowings under the Revolving Credit Facility will
reduce the availability of letters of credit on a dollar-for-dollar basis;
however, letter of credit issuances will not reduce cash borrowing availability
unless the aggregate dollar amount of outstanding letters of credit exceeds the
sum of the accounts receivable and inventory components of the borrowing base.
Cash borrowings bear interest at the higher of the prime rate, as defined, or
the federal funds rate, as defined, plus an additional percentage ranging from
one-fourth of 1% to 1.25%, depending upon the Company's cash flow coverage
ratio, as defined. At December 31, 1994, there were no cash borrowings under the
Revolving Credit Facility.

Under the terms of the Revolving Credit Facility, as amended, the Company
is required to maintain specified levels of working capital, tangible net worth,
consolidated cash flow and refinery cash flow, as defined in the Revolving
Credit Facility. Among other matters, the Revolving Credit Facility has certain
restrictions with respect to (i) capital expenditures, (ii) incurrence of
additional indebtedness, and (iii) dividends on capital stock. The Revolving
Credit Facility contains other covenants customary in credit arrangements of
this

46
47

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

kind. During the third and fourth quarters of 1994, the Company did not satisfy
the refinery cash flow requirement which required a waiver and an amendment to
the Revolving Credit Facility. Future compliance with financial covenants under
the amended Revolving Credit Facility is primarily dependent on the Company's
cash flows from operations, capital expenditures, levels of borrowings under the
Revolving Credit Facility and the value of the Company's domestic oil and gas
reserves. Based on current market conditions, including the volatility in
refinery margins and the recent downturn in the price of natural gas, continued
compliance with such covenants is not assured. If the Company is not able to
continue to comply with its financial covenants, it will be required to seek
waivers or amendments from its banks. If such an event occurs, the Company
believes it will be able to negotiate terms and conditions with its banks under
the Revolving Credit Facility which will allow the Company to adequately finance
its operations.

The Revolving Credit Facility replaced certain interim financing
arrangements that the Company had been using since the termination of its prior
letter of credit facility in October 1993. The interim financing arrangements
that were cancelled in conjunction with the completion of the Revolving Credit
Facility included a waiver and substitution of collateral agreement with the
State of Alaska and a $30 million reducing revolving exploration and production
credit facility. The completion of the Revolving Credit Facility provides the
Company significant flexibility in the investment of excess cash balances, as
the Company is no longer required to maintain minimum cash balances or to secure
letters of credit with cash. At December 31, 1993, the Company had arranged for
the issuance of $25.4 million of outstanding letters of credit which were
secured by restricted cash deposits.

VACUUM UNIT LOAN

During May 1994, the National Bank of Alaska and the Alaska Industrial
Development & Export Authority agreed to provide a loan to the Company of up to
$15 million of the cost of the vacuum unit for the Company's refinery (the
"Vacuum Unit Loan"). The Vacuum Unit Loan matures January 1, 2002, requires 28
equal quarterly payments beginning April 1995 and bears interest at the
unsecured 90-day commercial paper rate, adjusted quarterly, plus 2.6% per annum
(7.8% at December 31, 1994) for two-thirds of the amount borrowed and at the
National Bank of Alaska floating prime rate plus 1/4 of 1% per annum (8.75% at
December 31, 1994) for the remainder. The Vacuum Unit Loan is secured by a first
lien on the Company's refinery. At December 31, 1994, the Company had borrowed
$15 million under the Vacuum Unit Loan. The Vacuum Unit Loan contains covenants
and restrictions similar to those under the Revolving Credit Facility. At
December 31, 1994, the Company satisfied all of its covenants except for an
annual refinery cash flow requirement, as defined in the Vacuum Unit Loan. The
lenders waived this refinery cash flow requirement for the year ended December
31, 1994.

12 3/4% SUBORDINATED DEBENTURES AND 13% EXCHANGE NOTES

In 1983, the Company issued $120 million of 12 3/4% Subordinated Debentures
at a price of 84.559% of the principal amount, due March 15, 2001. The
debentures are redeemable at the option of the Company at 100% of principal
amount plus accrued interest. Sinking fund payments sufficient to retire $11.25
million principal amount of debentures annually commenced on March 15, 1993. The
Company satisfied the initial sinking fund requirement by purchasing $11.25
million principal amount of debentures at market value on January 26, 1993. The
exchange of $44.1 million principal amount of Subordinated Debentures for
Exchange Notes in February 1994 satisfied the 1994 sinking fund requirement and,
except for $.9 million, will satisfy sinking fund requirements for the
Subordinated Debentures through 1997 (see Note C). At December 31, 1994 and
1993, subordinated debt amounted to $59.1 million (net of discount of $5.5
million) and $98.2 million (net of discount of $10.6 million), respectively. The
indenture contains restrictions on payment of dividends on the Company's common
stock and purchases or redemptions of common or preferred stocks. Due to losses
incurred, as of December 31, 1994 the Company must generate approximately $113
million of future net earnings applicable to common stock or from the issuance
of capital stock before future dividends

47
48

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

can be paid on common stock or before purchases or redemptions can be made of
common or preferred stocks. The Exchange Notes mature December 1, 2000, and have
no sinking fund requirements. The Exchange Notes are redeemable at the option of
the Company at 100% of principal amount plus accrued interest except that no
optional redemption may be made unless an equal principal amount of, or all the
outstanding, Subordinated Debentures are concurrently redeemed. The Exchange
Notes rank pari passu with the other senior debt of the Company and with the
Subordinated Debentures, and senior in right of payment of the obligation to the
State of Alaska (discussed below) and all other subordinated indebtedness of the
Company. The indenture governing the Exchange Notes contains limitations on
dividends that are less restrictive than the limitation under the Subordinated
Debentures.

STATE OF ALASKA

In January 1993, the Company and its subsidiary, Tesoro Alaska Petroleum
Company ("Tesoro Alaska"), entered into an agreement ("Agreement") with the
State of Alaska ("State") that settled Tesoro Alaska's contractual dispute with
the State. In addition to $62 million accrued through September 30, 1992, a
charge of $10.5 million for the settlement was included in the Company's
operations during the fourth quarter of 1992.

Under the Agreement, Tesoro Alaska paid the State $10.3 million in January
1993 and is obligated to make variable monthly payments to the State through
December 2001 based on a per barrel charge that is currently 16 cents and
increases to 33 cents on the volume of feedstock processed at the Company's
refinery. In 1994 and 1993, the Company's variable payments to the State totaled
$2.8 million and $2.6 million, respectively. In January 2002, Tesoro Alaska 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 December 2001
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. Tesoro Alaska'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.

The State's claim against Tesoro Alaska arose out of certain provisions in
present and past contracts with the State that required Tesoro Alaska to pay the
State additional retroactive amounts if the State prevailed in litigation
against the producers of North Slope crude oil ("Producers"). As a result of
settlements between the State and the Producers, the State claimed that the
royalty oil it sold Tesoro Alaska and others was undervalued to the extent that
the Producers undervalued their oil.

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. Through December 31, 1994, the Company had paid $42.1 million to the
DOE since 1989. The Company's remaining obligation is to pay $13.2 million,
exclusive of interest at 6%, over the next eight 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 3/8% at
December 31, 1994), 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 $6.5 million at December 31,
1994.

48
49

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CAPITAL LEASE OBLIGATIONS

The Company is the lessee of certain buildings and equipment under capital
leases with remaining lease terms of three to 13 years. These buildings and
equipment are primarily used in the Company's convenience store operations in
Alaska. The assets and liabilities under capital leases are recorded at the
present value of the minimum lease payments. Property, plant and equipment at
December 31, 1994 included assets held under capital leases of $6.2 million with
a net book value of $2.1 million.

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. It is the Company's policy to fund costs accrued to the extent
such costs are tax deductible. The components of net pension expense for the
Company's retirement plan are presented below (in thousands):

YEARS ENDED DECEMBER 31,
-------------------------------
1994 1993 1992
------- ------ ------

Service Costs................................................. $ 1,121 931 717
Interest Cost................................................. 3,351 3,513 3,492
Actual Return on Plan Assets.................................. (217) (5,695) (1,763)
Net Amortization and Deferral................................. (3,408) 1,488 (2,231)
------- ------ ------
Net Pension Expense................................. $ 847 237 215
======= ====== ======

In addition to the retirement plan pension expense above, during 1992 the
Company recognized a curtailment gain of $1.0 million for employee terminations
in conjunction with a cost reduction program.

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

DECEMBER 31,
------------------
1994 1993
------- ------

Actuarial Present Value of Benefit Obligation:
Vested benefit obligation............................................... $35,877 41,200
======= ======
Accumulated benefit obligation.......................................... $38,102 43,694
======= ======
Plan Assets at Fair Value................................................. $38,100 40,718
Projected Benefit Obligation.............................................. 43,650 48,700
------- ------
Plan Assets Less Than Projected Benefit Obligation........................ (5,550) (7,982)
Unrecognized Net Loss..................................................... 9,029 11,997
Unrecognized Prior Service Costs.......................................... (490) (518)
Unrecognized Net Transition Asset......................................... (5,648) (6,883)
------- ------
Accrued Pension Expense Liability....................................... $(2,659) (3,386)
======= ======

Retirement plan assets are primarily comprised of common stock and bond
funds. Actuarial assumptions used to measure the projected benefit obligations
at December 31, 1994, 1993 and 1992 included a discount rate of 8 1/2%, 7% and
9%, respectively, and a compensation increase rate of 6%, 4 1/2% and 6%,
respectively. The expected long-term rate of return on assets was 9% for 1994,
1993 and 1992.

49
50

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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. Funding is provided based upon the estimated requirements of the
plan. The components of net pension expense for the ESP are presented below (in
thousands):

YEARS ENDED DECEMBER 31,
-------------------------
1994 1993 1992
----- ---- ------

Service Costs...................................................... $ 474 426 293
Interest Cost...................................................... 273 291 353
Actual Return on Plan Assets....................................... (230) (256) (1,004)
Net Amortization and Deferral...................................... 228 295 994
----- ---- ------
Net Pension Expense.............................................. $ 745 756 636
===== ==== ======

During 1994, 1993 and 1992, the Company incurred additional ESP expense of
$.4 million, $.5 million and $3.5 million, respectively, for settlement losses
and other benefits resulting from a cost reduction program, other employee
terminations and sales of assets.

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

DECEMBER 31,
----------------
1994 1993
------ -----

Actuarial Present Value of Benefit Obligation:
Vested benefit obligation................................................. $3,071 2,394
====== =====
Accumulated benefit obligation............................................ $3,621 2,792
====== =====
Plan Assets at Fair Value................................................... $3,822 3,139
Projected Benefit Obligation................................................ 4,075 3,069
------ -----
Plan Assets in Excess of (Less Than) Projected Benefit Obligation........... (253) 70
Unrecognized Net Loss....................................................... 2,158 1,177
Unrecognized Prior Service Costs............................................ 495 619
Unrecognized Net Transition Obligation...................................... 843 1,110
------ -----
Prepaid Pension Asset..................................................... $3,243 2,976
====== =====

Assets of the ESP consist of a group annuity contract. Actuarial
assumptions used to measure the projected benefit obligation at December 31,
1994, 1993 and 1992 included a discount rate of 8 1/2%, 7% and 9%, respectively,
and a compensation increase rate of 5%, 4 1/2% and 5%, respectively. The
expected long-term rate of return on assets was 9% for 1994, 1993 and 1992.

RETIREE HEALTH CARE AND LIFE INSURANCE BENEFITS

The Company provides health care and life insurance benefits to retirees
and eligible dependents who were participating in the Company's group insurance
program at retirement. 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

50
51

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

insurance plan is noncontributory. The Company continues to fund the cost of
postretirement health care and life insurance benefits on a pay-as-you-go basis.

As discussed in Note A, the Company adopted SFAS No. 106 effective January
1, 1992 and incurred a net charge of $21.6 million ($16.1 million for health
care benefits and $5.5 million for life insurance benefits) for the cumulative
effect of the change in accounting principle. The components of net periodic
postretirement benefits expense, other than pensions, for 1994, 1993 and 1992
included the following (in thousands):

YEARS ENDED DECEMBER 31,
--------------------------
1994 1993 1992
------ ----- -----

Health Care:
Service costs.................................................... $ 471 420 400
Interest costs................................................... 1,264 1,396 1,332
------ ----- -----
Net Periodic Postretirement Expense...................... $1,735 1,816 1,732
====== ===== =====
Life Insurance:
Service costs.................................................... $ 198 100 100
Interest costs................................................... 489 492 457
Net amortization................................................. 29 -- --
------ ----- -----
Net Periodic Postretirement Expense...................... $ 716 592 557
====== ===== =====

The following tables show the status of the plans reconciled with the
amounts in the Company's Consolidated Balance Sheets (in thousands):

DECEMBER 31,
------------------
1994 1993
------- ------

Health Care:
Accumulated Postretirement Benefit Obligation--
Retirees................................................................ $14,066 19,079
Active participants eligible to retire.................................. 1,309 1,566
Other active participants............................................... 3,490 5,824
------- ------
18,865 26,469
Unrecognized net loss................................................... (164) (8,685)
------- ------
Accrued Postretirement Benefit Liability............................. $18,701 17,784
======= ======
Life Insurance:
Accumulated Postretirement Benefit Obligation --
Retirees................................................................ $ 5,321 4,915
Active participants eligible to retire.................................. 421 571
Other active participants............................................... 1,324 1,658
------- ------
7,066 7,144
Unrecognized net loss................................................... (438) (1,044)
------- ------
Accrued Postretirement Benefit Liability............................. $ 6,628 6,100
======= ======

The weighted average annual assumed rate of increase in the per capita cost
of covered health care benefits was assumed to be 8% for 1995, decreasing
gradually to 6% by the year 2009 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,

51
52

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

1994 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
$.4 million. Actuarial assumptions used to measure the accumulated
postretirement benefit obligation at December 31, 1994, 1993 and 1992 included a
discount rate of 8 1/2%, 7% and 8 1/2%, respectively, and a compensation rate
increase of 6%, 4 1/2% and 6%, respectively.

THRIFT PLAN

The Company's employee thrift plan provides for contributions by eligible
employees into designated investment funds with a matching contribution by the
Company of 50% of the employee's basic contribution. The Company's contributions
amounted to $547,000, $482,000 and $474,000 during 1994, 1993 and 1992,
respectively.

COST REDUCTION PROGRAM AND OTHER EMPLOYEE TERMINATIONS

In addition to the ESP settlement losses and other benefits and the
retirement plan curtailment gain discussed above, during 1992 the Company
incurred charges of $6.6 million for expenses to implement a cost reduction
program and other employee terminations.

NOTE K -- OPERATING LEASES

The Company has various noncancellable operating leases related to
convenience stores, equipment, property, vessels and other facilities. Lease
terms range from one year to 38 years and generally contain multiple renewal
options. Future minimum annual payments for operating leases, existing at
December 31, 1994, were as follows (in thousands):

1995............................................................................. $ 18,122
1996............................................................................. 14,829
1997............................................................................. 3,724
1998............................................................................. 3,528
1999............................................................................. 1,217
Thereafter....................................................................... 12,908
--------
Total.......................................................................... $ 54,328
=======

Total rental expense was approximately $33.6 million, $32.5 million and
$24.3 million for 1994, 1993 and 1992, respectively. Rental expense for 1994,
1993 and 1992 included $24.6 million, $22.9 million and $12.0 million,
respectively, related to the lease of vessels used to transport crude oil and
refined products to and from the Company's refinery. The lease on one vessel
expired in October 1994 and was replaced with a charter agreement for another
vessel. This charter agreement expires in September 1996 and contains two
one-year renewal options. The Company has a charter for another vessel under a
one-year agreement expiring in January 1996.

NOTE L -- COMMITMENTS AND CONTINGENCIES

GAS PURCHASE AND SALES CONTRACT

The Company is selling a portion of the gas from its Bob West Field to
Tennessee Gas Pipeline Company ("Tennessee Gas") under a Gas Purchase and Sales
Agreement (the "Tennessee Gas Contract") which provides that the price of gas
shall be the maximum price as calculated in accordance with Section 102(b)(2)
(the "Contract Price") of the Natural Gas Policy Act of 1978 (the "NGPA").
Tennessee Gas filed suit against the Company in the District Court of Bexar
County, Texas alleging that the Tennessee Gas Contract is not applicable to the
Company's properties and that the gas sales price should be the price calculated
under the provisions of Section 101 of the NGPA rather than the Contract Price.
During December 1994, the

52
53

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Contract Price was in excess of $8.00 per Mcf, the Section 101 price was $4.81
per Mcf and the average spot market price was $1.56 per Mcf. Tennessee Gas also
claimed that the contract should be considered an "output contract" under
Section 2.306 of the Texas Business and Commerce Code and that the increases in
volumes tendered under the contract exceeded those allowable for an output
contract.

The District Court judge returned a verdict in favor of the Company on all
issues. On appeal by Tennessee Gas, the Court of Appeals for the Fourth Supreme
Judicial District of Texas affirmed the validity of the Tennessee Gas Contract
as to the Company's properties and held that the price payable by Tennessee Gas
for the gas was the Contract Price. The Court of Appeals remanded the case to
the trial court based on its determination (i) that the Tennessee Gas Contract
was an output contract and (ii) that a fact issue existed as to whether the
increases in the volumes of gas tendered to Tennessee Gas under the contract
were made in bad faith or were unreasonably disproportionate to prior tenders.
The Company sought review of the appellate court ruling on the output contract
issue in the Supreme Court of Texas. Tennessee Gas also sought review of the
appellate court ruling denying the remaining Tennessee Gas claims in the Supreme
Court of Texas. The Supreme Court of Texas heard arguments in December 1994
regarding the output contract issue and certain of the issues raised by
Tennessee Gas but has not yet issued its opinion.

Although the outcome of any litigation is uncertain, management, based upon
advice from outside legal counsel, is confident that the decision of the trial
and appellate courts will ultimately be upheld as to the validity of the
Tennessee Gas Contract and the Contract Price. If the Supreme Court of Texas
were to affirm the appellate court ruling, the Company believes that the only
issue for trial should be whether the increases in the volumes of gas tendered
to Tennessee Gas from the Company's properties were made in bad faith or were
unreasonably disproportionate. The appellate court decision was the first
reported decision in Texas holding that a take-or-pay contract was an output
contract. As a result, it is not clear what standard the trial court would be
required to apply in determining whether the increases were in bad faith or
unreasonably disproportionate. The appellate court acknowledged in its opinion
that the standards used in evaluating other kinds of output contracts would not
be appropriate in this context. The Company believes that the appropriate
standard would be whether the development of the field was undertaken in a
manner that a prudent operator would have undertaken in the absence of an
above-market sales price. Under that standard, the Company believes that, if
this issue is tried, the development of the Company's gas properties and the
resulting increases in volumes tendered to Tennessee Gas will be found to have
been reasonable and in good faith. Accordingly, the Company has recognized
revenues, net of production taxes and marketing charges, for natural gas sales
through December 31, 1994, under the Tennessee Gas Contract based on the
Contract Price, which net revenues aggregated $36.9 million more than the
Section 101 prices and $69.5 million in excess of the spot market prices. If
Tennessee Gas were ultimately to prevail in this litigation, the Company could
be required to return to Tennessee Gas $52.5 million, plus interest if awarded
by the court, representing the difference between the spot market price and the
Contract Price received by the Company through September 17, 1994 (the date on
which the Company entered into a bond agreement discussed below). An adverse
judgment in this case could have a material adverse effect on the Company.

On August 4, 1994, the trial court rejected a motion by Tennessee Gas to
post a supersedeas bond in the form of monthly payments into the registry of the
court representing the difference between the Contract Price and spot market
price of gas sold to Tennessee Gas pursuant to the Tennessee Gas Contract. The
court advised Tennessee Gas that should it wish to supersede the judgment,
Tennessee Gas had the option to post a bond which would be effective only until
August 1, 1995, in an amount equal to the anticipated value of the Tennessee Gas
Contract during that period. In September 1994, the court ordered that,
effective until August 1, 1995, Tennessee Gas (i) take at least its entire
monthly take-or-pay obligation under the Tennessee Gas Contract, (ii) pay for
gas at $3.00 per Mmbtu, which approximates $3.00 per Mcf (the "Bond Price"), and
(iii) post a $120 million bond with the court representing an amount which,
together with anticipated sales of natural gas to Tennessee Gas at the Bond
Price, will equal the anticipated value of the Tennessee Gas Contract during
this interim period. The Bond Price is nonrefundable by the Company, and the
Company

53
54

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

retains the right to receive the full Contract Price for all gas sold to
Tennessee Gas. The Company continues to recognize revenues under the Tennessee
Gas Contract based on the Contract Price. At December 31, 1994, the Company had
recognized cumulative revenues in excess of spot market prices (through
September 17, 1994) and in excess of the Bond Price (subsequent to September 17,
1994) totaling $65.7 million. Receivables at December 31, 1994 included $17.7
million from Tennessee Gas, of which $13.2 million represented the difference
between the Contract Price and the Bond Price. For further information
concerning the effect of the Tennessee Gas Contract on certain of the Company's
revenues and cash flows, see Note P.

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 in 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 contribution to the
cleanup of this site is expected to be limited based upon the number of
companies and the volumes of waste involved and the payment by the Company of a
de minimus settlement amount of $2,500 at a similar site in Louisiana. 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. In addition, the Company is holding
discussions with the Department of Justice ("DOJ") concerning the assessment of
penalties with respect to certain alleged violations of regulations promulgated
under the Clean Air Act as discussed below.

In March 1992, the Company received a Compliance Order and Notice of
Violation from the Environmental Protection Agency (the "EPA") alleging
violations by the Company of the New Source Performance Standards under the
Clean Air Act at its Alaska refinery. These allegations include failure to
install, maintain and operate monitoring equipment over a period of
approximately six years, failure to perform accuracy testing on monitoring
equipment, and failure to install certain pollution control equipment. From
March 1992 to July 1993, the EPA and the Company exchanged information relevant
to these allegations. In addition, the EPA conducted an environmental audit of
the Company's refinery in May 1992. As a result of this audit, the EPA is also
alleging violation of certain regulations related to asbestos materials. In
October 1993, the EPA referred these matters to the DOJ. The DOJ contacted the
Company to begin negotiating a resolution of these matters. The DOJ has
indicated that it is willing to enter into a judicial consent decree with the
Company and that this decree would include a penalty assessment. Negotiations on
the penalty are in progress. The DOJ has proposed a penalty assessment of
approximately $3.7 million. The Company is continuing to negotiate with the DOJ
but cannot predict the ultimate outcome of the negotiations.

At December 31, 1994, the Company's accruals for environmental matters,
including the alleged violations of the Clean Air Act, amounted to $10.8
million. Based on currently available information, including the participation
of other parties or former owners in remediation actions, the Company believes
these accruals are adequate. In addition, to comply with environmental laws and
regulations, the Company anticipates that it will be required to make capital
improvements in 1995 of approximately $2 million, primarily for the removal and
upgrading of underground storage tanks, and approximately $8 million during 1996
for the installation of dike liners required under Alaska environmental
regulations. 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.

54
55

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

OTHER

The Company transports its crude oil and a substantial portion of its
refined products utilizing Kenai Pipe Line Company's ("KPL") pipeline and marine
terminal facilities in Kenai, Alaska. In March 1994, KPL filed a revised tariff
with the Federal Energy Regulatory Commission ("FERC") for dock loading
services, which would have increased the Company's annual cost of transporting
products through KPL's facilities from $1.2 million to $11.2 million. Following
FERC's rejection of KPL's tariff filing and the commencement of negotiations for
the purchase by the Company of the dock facilities, KPL filed a temporary tariff
that has increased the Company's annual cost by approximately $1.5 million. The
Company and KPL have entered into an agreement for the purchase by the Company
of KPL, subject to regulatory approval. The Company expects that this purchase
transaction will be consummated in early 1995.

In July 1994, a former customer of the Company ("Customer") filed suit
against the Company in the United States District Court for the District of New
Mexico for a refund in the amount of approximately $1.2 million, plus interest
of approximately $4.4 million and attorney's fees, related to a gasoline
purchase from the Company in 1979. The Customer also alleges entitlement to
treble damages and punitive damages in the aggregate amount of $16.8 million.
The refund claim is based on allegations that the Company renegotiated the
acquisition price of gasoline sold to the Customer and failed to pass on the
benefit of the renegotiated price to the Customer in violation of Department of
Energy price and allocation controls then in effect. The Company cannot predict
the ultimate resolution of this matter but believes the claim is without merit.

In February 1995, a lawsuit was filed in the U.S. District Court for the
Southern District of Texas, McAllen Division, by the Heirs of H.P. Guerra,
Deceased ("Plaintiffs") against the United States and Tesoro and other working
and overriding royalty interest owners to recover the oil and gas mineral estate
under 2,706.34 acres situated in Starr County, Texas. The oil and gas mineral
estate sought to be recovered underlies lands taken by the United States in
connection with the construction of the Falcon Dam and Reservoir. In their
lawsuit, the Plaintiffs allege that the original taking by the United States in
1948 was unlawful and void and the refusal of the United States to revest the
mineral estate to H.P. Guerra or his heirs was arbitrary and capricious and
unconstitutional. Plaintiffs seek (i) restoration of their oil and gas estate;
(ii) restitution of all proceeds realized from the sale of oil and gas from
their mineral estate, plus interest on the value thereof; and (iii) cancellation
of all oil and gas leases issued by the United States to Tesoro and the other
working interest owners covering their mineral estate. The lawsuit covers a
significant portion of the mineral estate in the Bob West Field; however, none
of the acreage covered is dedicated to the Tennessee Gas Contract. The Company
cannot predict the ultimate resolution of this matter but, based upon advice
from outside legal counsel, believes the lawsuit is without merit.

NOTE M -- INCENTIVE STOCK PLANS

The Company has two employee incentive stock plans, the Amended Incentive
Stock Plan of 1982 (the "1982 Plan") and the Executive Long-Term Incentive Plan
(the "1993 Plan") (collectively, the "Plans"). 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 1993 Plan provides for
the issuance of awards in a variety of forms, including restricted stock,
incentive stock options, nonqualified stock options, stock appreciation rights
and performance share and performance unit awards. The 1993 Plan, which provides
for the grant of up to 1,250,000 shares of the Company's Common Stock, will
expire, unless earlier terminated, as to the issuance of awards in the year
2003. At December 31, 1994, the Company had 588,147 shares available for future
grants under the 1993 Plan. Shares of unissued Common Stock reserved for the
Plans totaled 2,381,603 at December 31, 1994, which included 245,903 shares
representing awards granted under the Plans that had not yet been issued.

Stock appreciation rights become exercisable in three to five annual
installments, normally beginning with the first anniversary of the date of the
grant, and expire ten years from the date of grant. Stock

55
56

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

appreciation rights entitle the employee to receive, without payment to the
Company, the incremental increase in market value of the related stock from date
of grant to date of exercise, payable in cash. Related compensation expense is
charged to earnings over periods earned. During 1994, compensation expense
related to stock appreciation rights was approximately $20,000 as a result of
the market price of the related stock exceeding the exercise price of the stock
appreciation rights. During 1993 and 1992, no compensation expense was
recognized since the market value of the Company's Common Stock remained below
the exercise price.

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% increments per year and expire ten years from
date of grant. Options granted to certain officers under the 1982 Plan are
subject to accelerated vesting provisions based upon the improvement in the
market price of the Company's Common Stock during a period immediately preceding
their employment anniversary dates.

Stock awards and performance shares granted to officers and key employees
under the Plans amounted to 137,253, 83,015 and 100,000 common shares in 1994,
1993 and 1992, respectively. 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 $1,319,000, $572,000 and
$142,000 in 1994, 1993 and 1992, respectively.

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

STOCK OPTIONS
---------------------------
OUTSTANDING EXERCISABLE
----------- -----------

September 30, 1991.................................................... 221,805 159,623
Granted at $3.925 to $4.840......................................... 600,000 --
Becoming exercisable................................................ -- 34,243
Cancelled or expired................................................ (109,171) (90,786)
----------- -----------
December 31, 1992..................................................... 712,634 103,080
Granted at $2.925 to $5.250......................................... 349,680 --
Becoming exercisable................................................ -- 127,044
Cancelled or expired................................................ (45,444) (44,278)
----------- -----------
December 31, 1993..................................................... 1,016,870 185,846
Granted at $8.938 to $9.500......................................... 524,600 --
Becoming exercisable................................................ -- 312,880
Exercised........................................................... (18,764) (18,764)
Cancelled or expired................................................ (26,413) (1,083)
----------- -----------
December 31, 1994 ($2.925 to $12.625)................................. 1,496,293 478,879
========= ========

56
57

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

STOCK APPRECIATION RIGHTS
---------------------------
OUTSTANDING EXERCISABLE
----------- -----------

September 30, 1991.................................................... 243,864 181,680
Becoming exercisable................................................ -- 34,248
Cancelled or expired................................................ (119,414) (101,030)
----------- -----------
December 31, 1992..................................................... 124,450 114,898
Becoming exercisable................................................ -- 7,042
Cancelled or expired................................................ (54,687) (53,521)
----------- -----------
December 31, 1993..................................................... 69,763 68,419
Becoming exercisable................................................ -- 1,344
Exercised........................................................... (14,921) (14,921)
Cancelled or expired................................................ (3,582) (3,582)
----------- -----------
December 31, 1994 ($8.375 to $12.625)................................. 51,260 51,260
========= ========

NOTE N -- PREFERRED STOCK PURCHASE RIGHTS

In November 1985, the Company's Board of Directors declared a distribution
of one preferred stock purchase right for each share of the Company's Common
Stock. Each right will entitle the holder to buy 1/100 of a share of a newly
authorized Series A Participating Preferred Stock at an exercise price of $35
per right. The rights become exercisable on the tenth day after public
announcement that a person or group has acquired 20% or more of the Company's
Common Stock. The rights may be redeemed by the Company prior to becoming
exercisable by action of the Board of Directors at a redemption price of $.05
per right. If the Company is acquired by any person after the rights become
exercisable, each right will entitle its holder to purchase stock of the
acquiring company having a market value of twice the exercise price of each
right. At December 31, 1994, there were 24,389,801 rights outstanding, which
will expire in December 1995.

57
58

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE O -- QUARTERLY FINANCIAL DATA (UNAUDITED)

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

1994
Gross Operating Revenues................................ $189.1 210.7 251.8 219.6
Operating Profit........................................ $ 18.3 11.7 7.1 27.3
Net Earnings (Loss) Before Extraordinary Loss........... $ 7.2 1.3 (3.3) 15.3
Extraordinary Loss...................................... 4.8 -- -- --
------ ------ ----- ------
Net Earnings (Loss)..................................... $ 2.4 1.3 (3.3) 15.3
====== ===== ===== =====
Earnings (Loss) Per Primary and Fully Diluted Share:
Earnings (loss) before extraordinary loss............ $ .27 .02 (.13) .61
Extraordinary loss................................... (.24) -- -- --
------ ------ ----- ------
Net earnings (loss).................................. $ .03 .02 (.13) .61
====== ===== ===== =====
1993
Gross Operating Revenues................................ $224.5 185.6 214.5 206.4
Operating Profit........................................ $ 6.0 8.9 13.1 24.3
Net Earnings (Loss)..................................... $( 2.9) 1.5 1.7 16.7
Earnings (Loss) Per Share:
Primary.............................................. $ (.37) (.06) (.04) 1.00
Fully Diluted........................................ $ (.37) (.06) (.04) .87

The 1994 first quarter included an extraordinary loss of $4.8 million on
the early extinguishment of debt in connection with the Recapitalization (see
Note C) and a gain of $2.8 million from the sale of assets. During the 1994
fourth quarter, a refund of $8.5 million was recognized for settlement of a
tariff dispute, partially offset by charges of approximately $4 million related
to environmental contingencies and other matters. The 1993 second and fourth
quarters included benefits of $3.0 million and $5.2 million, respectively, for
resolution of several state tax issues. A $5.0 million charge for an inventory
erosion was recorded in the 1993 third quarter. Included in the 1993 fourth
quarter, however, was a $5.7 million offset to the inventory adjustment taken
earlier in the year. Inventory levels at year-end 1993 were greater than
projected earlier in the year due to changing market conditions. The 1993 fourth
quarter benefited from the decline in crude oil prices, while the Company's
refined product margins held steady or improved.

58
59

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE P -- 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.

CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES

DECEMBER 31,
------------------------------
1994 1993 1992
-------- ------ ------
(IN THOUSANDS)

Capitalized Costs:
Proved properties............................................ $116,558 60,489 34,050
Unproved properties:
Properties being amortized................................ 15,372 12,856 11,132
Properties not being amortized............................ 3,758 1,959 1,482
-------- ------ ------
135,688 75,304 46,664
Accumulated depreciation, depletion and amortization......... 50,261 26,118 15,006
-------- ------ ------
Net Capitalized Costs..................................... $ 85,427 49,186 31,658
======== ====== ======

COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT
ACTIVITIES

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

Year Ended December 31, 1994:
Property acquisition, unproved...................... $ 438 -- -- 438
Exploration......................................... 8,808 -- -- 8,808
Development......................................... 51,133 -- -- 51,133
------- ----- ------- ------
$60,379 -- -- 60,379
======= ===== ======= ======
Year Ended December 31, 1993:
Property acquisition, unproved...................... $ 887 -- -- 887
Exploration......................................... 2,257 -- -- 2,257
Development......................................... 25,496 -- -- 25,496
------- ----- ------- ------
$28,640 -- -- 28,640
======= ===== ======= ======
Year Ended December 31, 1992:
Property acquisition, unproved...................... $ 9 -- -- 9
Exploration......................................... 977 6 333 1,316
Development......................................... 7,922 -- 109 8,031
------- ---- ------ ------
$ 8,908 6 442 9,356
======= ===== ======= ======

The Company's investment in oil and gas properties included $3.8 million in
unevaluated properties, which have been excluded from the amortization base as
of December 31, 1994. The Company anticipates that the majority of these costs,
substantially all of which were incurred in 1994, will be included in the
amortization base during 1995.

59
60

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(1) BOLIVIA INDONESIA TOTAL
------- ------ --------- --------
(IN THOUSANDS EXCEPT AS INDICATED)

Year Ended December 31, 1994:
Gross revenues -- sales to nonaffiliates........... $91,791 13,211 -- 105,002
Lifting costs...................................... 13,855 619 -- 14,474
Administrative support and other................... 1,692 3,242 -- 4,934
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(2)................................... $32,997 3,745 -- 36,742
======= ====== ======= =======
Depletion rate per net equivalent Mcf.............. $ .79 -- --
======= ====== =======
Year Ended December 31, 1993:
Gross revenues -- sales to nonaffiliates........... $50,228 12,594 -- 62,822
Lifting costs...................................... 6,763 1,152 -- 7,915
Administrative support and other................... 939 3,046 -- 3,985
Depreciation, depletion and amortization........... 11,111 -- -- 11,111
------- ------ --------- --------
Pretax results of operations....................... 31,415 8,396 -- 39,811
Income tax expense................................. 6,647 5,160 -- 11,807
------- ------ --------- --------
Results of operations from producing
activities(2)................................... $24,768 3,236 -- 28,004
======= ====== ======= =======
Depletion rate per net equivalent Mcf.............. $ .78 -- --
======= ====== =======
Year Ended December 31, 1992:
Gross revenues -- sales to nonaffiliates........... $18,850 17,898 5,975 42,723
Lifting costs...................................... 3,796 688 3,698 8,182
Administrative support and other................... 1,216 4,635 107 5,958
Gain (loss) on sales of assets..................... (3) -- 5,750(3) 5,747
Depreciation, depletion and amortization........... 4,862 -- 336 5,198
------- ------ --------- --------
Pretax results of operations....................... 8,973 12,575 7,584 29,132
Income tax expense................................. 305 7,108 3,066 10,479
------- ------ --------- --------
Results of operations from producing
activities(2)................................... $ 8,668 5,467 4,518 18,653
======= ====== ======= =======
Depletion rate per net equivalent Mcf.............. $ .95 -- .15
======= ====== =======

- ---------------
(1) See Note L regarding litigation involving a natural gas sales contract.

(2) Excludes corporate general and administrative and financing costs.

(3) Represents gain from the sale of the Company's Indonesian operations
effective May 1, 1992.

60
61

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 Statement of Financial Accounting
Standards No. 69 ("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 after income taxes.

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.

As indicated in Note L, certain of the Company's U.S. production activities
are involved in litigation pertaining to a natural gas sales contract with
Tennessee Gas. Although the outcome of any litigation is uncertain, based upon
advice from outside legal counsel, management believes that the Company will
ultimately prevail in this dispute. Accordingly, the Company has based its
calculation of the standardized measure of discounted future net cash flows on
the Contract Price. However, if Tennessee Gas were to prevail, the impact on the
Company's future revenues and cash flows would be significant. Based on the
Contract Price, the standardized measure of discounted future net cash flows
relating to proved reserves in the United States at December 31, 1994 was $127
million, compared with $73 million at spot market prices.

61
62

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED
RESERVES (UNAUDITED)

UNITED
STATES(1) 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
Future income tax expense................................. (61,419) (44,537) (105,956)
--------- ------- --------
Future net cash flows..................................... 148,734 38,218 186,952
10% annual discount factor................................ (21,948) (16,229) (38,177)
--------- ------- --------
Standardized measure of discounted future net cash
flows.................................................. $ 126,786 21,989 148,775
======== ======= ========
December 31, 1993:
Future cash inflows....................................... $ 315,788 133,363 449,151
Future production costs................................... (59,398) (31,092) (90,490)
Future development costs.................................. (48,020) (2,981) (51,001)
--------- ------- --------
Future net cash flows before income tax expense........... 208,370 99,290 307,660
Future income tax expense................................. (76,500) (52,334) (128,834)
--------- ------- --------
Future net cash flows..................................... 131,870 46,956 178,826
10% annual discount factor................................ (29,118) (20,516) (49,634)
--------- ------- --------
Standardized measure of discounted future net cash
flows.................................................. $ 102,752 26,440 129,192
======== ======= ========
December 31, 1992:
Future cash inflows....................................... $ 215,172 146,555 361,727
Future production costs................................... (33,162) (40,374) (73,536)
Future development costs.................................. (30,294) (9,248) (39,542)
--------- ------- --------
Future net cash flows before income tax expense........... 151,716 96,933 248,649
Future income tax expense................................. (42,884) (56,682) (99,566)
--------- ------- --------
Future net cash flows..................................... 108,832 40,251 149,083
10% annual discount factor................................ (21,744) (16,628) (38,372)
--------- ------- --------
Standardized measure of discounted future net cash
flows.................................................. $ 87,088 23,623 110,711
======== ======= ========

62
63

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)

YEARS ENDED DECEMBER 31,
--------------------------------
1994 1993 1992
-------- ------- -------
(IN THOUSANDS)

Sales and transfers of oil and gas produced, net of
production costs........................................... $(88,751) (52,766) (31,208)
Net changes in prices and production costs................... 12,834 (21,160) (32,397)
Extensions, discoveries and improved recovery................ 54,503 73,792 104,219
Development costs incurred................................... 51,148 25,510 10,012
Revisions of estimated future development costs.............. (34,738) (24,052) (18,666)
Revisions of previous quantity estimates..................... 1,818 31,031 (15,384)
Purchases and sales of minerals in-place..................... -- -- (5,884)
Accretion of discount........................................ 12,919 11,071 8,174
Net changes in income taxes.................................. 9,850 (24,945) 4,863
-------- ------- -------
Net increase................................................. 19,583 18,481 23,729
Beginning of period.......................................... 129,192 110,711 86,982
-------- ------- -------
End of period................................................ $148,775 129,192 110,711
======== ======= =======

- ---------------
(1) See Note L regarding litigation involving a natural gas sales contract.

63
64

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

RESERVE INFORMATION (UNAUDITED)

The following estimates of the Company's proved oil and gas reserves are
based on evaluations prepared by Netherland, Sewell & Associates, Inc. (except
for estimates of reserves at December 31, 1991 for properties in Bolivia and
Indonesia, which estimates were prepared by the Company's in-house engineers).
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.

UNITED
STATES(2) BOLIVIA TOTAL
--------- --------- -------

PROVED GAS RESERVES (millions of cubic feet)(1):
December 31, 1991........................................... 36,884 113,465 150,349
Revisions of previous estimates.......................... (9,601) 651 (8,950)
Extensions, discoveries and other additions.............. 53,952 -- 53,952
Production............................................... (5,110) (7,108) (12,218)
Sales of minerals in-place............................... (2,372) -- (2,372)
--------- --------- -------
December 31, 1992........................................... 73,753 107,008 180,761
Revisions of previous estimates.......................... 16,304 (693) 15,611
Extensions, discoveries and other additions.............. 44,291 -- 44,291
Production............................................... (14,150) (7,020) (21,170)
--------- --------- -------
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(3)........................................ 129,099 95,756 224,855
======= ======= =======
PROVED DEVELOPED GAS RESERVES included above (millions of
cubic feet):
December 31, 1991........................................... 21,187 106,036 127,223
December 31, 1992........................................... 34,160 91,376 125,536
December 31, 1993........................................... 65,652 99,295 164,947
December 31, 1994(3)........................................ 110,071 81,558 191,629

64
65

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

BOLIVIA INDONESIA TOTAL
--------- --------- -------

PROVED OIL RESERVES (thousands of barrels)(1):
December 31, 1991........................................... 2,771 5,571 8,342
Revisions of previous estimates.......................... (266) -- (266)
Production............................................... (242) (328) (570)
Sales of minerals in-place............................... -- (5,243) (5,243)
--------- --------- -------
December 31, 1992........................................... 2,263 -- 2,263
Revisions of previous estimates.......................... 152 -- 152
Production............................................... (242) -- (242)
--------- --------- -------
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(3)........................................ 1,793 -- 1,793
======= ======= =======
PROVED DEVELOPED OIL RESERVES included above (thousands of
barrels):
December 31, 1991........................................... 2,680 5,571 8,251
December 31, 1992........................................... 2,098 -- 2,098
December 31, 1993........................................... 2,173 -- 2,173
December 31, 1994(3)........................................ 1,627 -- 1,627

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

(2) See Note L regarding litigation involving a natural gas sales contract.

(3) No major discovery or adverse event has occurred since December 31, 1994
that would cause a significant change in proved reserves.

65
66

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
1995 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
1995 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
1995 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
1995 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......................................................... 32
Statements of Consolidated Operations -- Years Ended December 31, 1994, 1993 and
1992............................................................................... 33
Consolidated Balance Sheets -- December 31, 1994 and 1993............................ 34
Statements of Consolidated Stockholders' Equity -- Years Ended December 31, 1994,
1993 and 1992...................................................................... 35
Statements of Consolidated Cash Flows -- Years Ended December 31, 1994, 1993 and
1992............................................................................... 36
Notes to Consolidated Financial Statements........................................... 37

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.

66
67

3. EXHIBITS

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

3 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(a) Bylaws of the Company, as amended through February 23, 1995.
3(b) 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(c) 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(d) 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(e) 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(a) 12 3/4% Subordinated Debentures due March 15, 2001, Form of Indenture, dated March
15, 1983 (incorporated by reference herein to Exhibit 4(b) to Registration Statement
No. 2-81960).
4(b) 13% Exchange Notes due December 1, 2000, Indenture, dated February 8, 1994
(incorporated by reference herein to Exhibit 2 to the Company's Registration
Statement on Form 8-A filed March 2, 1994).
4(c) Copy of Indenture between the Company and Bankers Trust Company, a Trustee, pursuant
to which the Exchange Notes Due December 1, 2000 were issued (incorporated by
reference herein to Exhibit 2 to the Company's Registration Statement on Form 8-A
filed March 2, 1994).
4(d) Rights Agreement dated December 16, 1985 between the Company and Chemical Bank, N.A.
successor to InterFirst Bank Fort Worth, N.A. (incorporated by reference herein to
Exhibit 4(i) to the Company's Annual Report on Form 10-K for the fiscal year ended
September 30, 1985, File No. 1-3473).
4(e) Amendment to Rights Agreement dated December 16, 1985 between the Company and
Chemical Bank, N.A. (incorporated by reference herein to Exhibit 4(c) to the
Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1992,
File No. 1-3473).
4(f) Tesoro Exploration and Production Company's Loan Agreement dated as of October 29,
1993 (incorporated by reference herein to Exhibit 4(b) to the Company's report on
Form 10-Q for the quarter ended September 30, 1993, File No. 1-3473).
4(g) Agreement for Waiver and Substitution of Collateral dated as of September 30, 1993
by and between Tesoro Alaska Petroleum Company and the State of Alaska (incorporated
by reference herein to Exhibit 4(c) to the Company's report on Form 10-Q for the
quarter ended September 30, 1993, File No. 1-3473).
4(h) Credit Agreement (the "Credit Agreement") dated as of April 20, 1994 among the
Company and Texas Commerce Bank National Association ("TCB") as Issuing Bank and as
Agent, and certain other banks named therein (incorporated by reference herein to
Exhibit 10.1 to the Company's report on Form 10-Q for the quarter ended March 31,
1994, File No. 1-3473).
4(i) Guaranty Agreement dated as of April 20, 1994 among various subsidiaries of the
Company and TCB, as Issuing Bank and as Agent, and certain other banks named therein
(incorporated by reference herein to Exhibit 10.2 to the Company's report on Form
10-Q for the quarter ended March 31, 1994, File No. 1-3473).

67
68

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

4(j) Mortgage, Deed of Trust, Assignment of Production, Security Agreement and Financing
Statement dated as of April 20, 1994 from Tesoro Exploration and Production Company,
entered into in connection with the Credit Agreement (incorporated by reference
herein to Exhibit 10.3 to the Company's report on Form 10-Q for the quarter ended
March 31, 1994, File No. 1-3473).
4(k) Deed of Trust, Security Agreement and Financing Statement dated as of April 20, 1994
among Tesoro Alaska Petroleum Company, TransAlaska Title Insurance Agency, Inc., as
Trustee, and TCB, as Agent, entered into in connection with the Credit Agreement
(incorporated by reference herein to Exhibit 10.4 to the Company's report on Form
10-Q for the quarter ended March 31, 1994, File No. 1-3473).
4(l) Pledge Agreement dated as of April 20, 1994 by the Company in favor of TCB, entered
into in connection with the Credit Agreement (incorporated by reference herein to
Exhibit 10.5 to the Company's report on Form 10-Q for the quarter ended March 31,
1994, File No. 1-3473).
4(m) Security Agreement (Accounts and Inventory) dated as of April 20, 1994 between the
Company and TCB, entered into in connection with the Credit Agreement (incorporated
by reference herein to Exhibit 10.6 to the Company's report on Form 10-Q for the
quarter ended March 31, 1994, File No. 1-3473).
4(n) Security Agreement (Accounts and Inventory) dated as of April 20, 1994 between
Tesoro Alaska Petroleum Company and TCB, entered into in connection with the Credit
Agreement (incorporated by reference herein to Exhibit 10.7 to the Company's report
on Form 10-Q for the quarter ended March 31, 1994, File No. 1-3473).
4(o) Security Agreement (Accounts) dated as of April 20, 1994 between Tesoro Petroleum
Distributing Company and TCB, entered into in connection with the Credit Agreement
(incorporated by reference herein to Exhibit 10.8 to the Company's report on Form
10-Q for the quarter ended March 31, 1994, File No. 1-3473).
4(p) Security Agreement (Accounts and Inventory) dated as of April 20, 1994 between
Tesoro Exploration and Production Company and TCB, entered into in connection with
the Credit Agreement (incorporated by reference herein to Exhibit 10.9 to the
Company's report on Form 10-Q for the quarter ended March 31, 1994, File No.
1-3473).
4(q) Security Agreement (Accounts and Inventory) dated as of April 20, 1994 between
Tesoro Refining, Marketing & Supply Company and TCB, entered into in connection with
the Credit Agreement (incorporated by reference herein to Exhibit 10.10 to the
Company's report on Form 10-Q for the quarter ended March 31, 1994, File No.
1-3473).
4(r) 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).
4(s) 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(t) $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(u) 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(v) 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(w) 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).

68
69

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

4(x) Consent and Intercreditor Agreement dated as of May 26, 1994 among NBA, TCB, as
Agent, and the Company, entered into in connection with the Credit Agreement
(incorporated by reference herein to Exhibit 4.36 to Registration Statement No.
33-53587).
4(y) Copy of Consent and Waiver No. 1 dated October 27, 1994 to the Company's Credit
Agreement dated as of April 20, 1994 (incorporated by reference herein to Exhibit 4
to the Company's report on Form 10-Q for the quarter ended September 30, 1994, File
No. 1-3473).
4(z) Copy of First Amendment to Credit Agreement dated as of January 20, 1995 among the
Company and TCB as Issuing Bank and as Agent, and certain other banks named therein.
4(aa) Copy of First Amendment to the Loan Agreement dated as of January 26, 1995 among
Tesoro Alaska Petroleum Company, Tesoro Petroleum Corporation and NBA.
10(a) Form of Executive Agreement providing for continuity of management between the
Company and James W. Queen dated June 28, 1984 (incorporated by reference herein to
Exhibit 10(b) to the Company's Annual Report on Form 10-K for the fiscal year ended
September 30, 1984, File No. 1-3473).
10(b) Form of Amendment to Executive Agreements between the Company and James W. Queen
dated September 30, 1987 (incorporated by reference herein to Exhibit 10(c) to the
Company's Annual Report on Form 10-K for the fiscal year ended September 30, 1987,
File No. 1-3473).
10(c) Form of Second Amendment to Executive Agreements between the Company and James W.
Queen dated February 28, 1990 (incorporated by reference herein to Exhibit 10(e) to
the Company's Annual Report on Form 10-K for the fiscal year ended September 30,
1990, File No. 1-3473).
10(d) 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(e) Sixth Amendment to the Company's Amended Executive Security Plan and Seventh
Amendment to the Company's Funded Executive Security Plan, both dated effective
March 6, 1991 (incorporated by reference herein to Exhibit 10(g) to the Company's
Annual Report on Form 10-K for the fiscal year ended September 30, 1991, File No.
1-3473).
10(f) 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.
10(g) Employment Agreement between the Company and Michael D. Burke dated July 27, 1992
(incorporated by reference herein to Exhibit 10(j) to the Company's Annual Report on
Form 10-K for the fiscal year ended December 31, 1992, File No. 1-3473).
10(h) First Amendment and Extension to Employment Agreement between the Company and
Michael D. Burke dated December 14, 1994.
10(i) Employment Agreement between the Company and Bruce A. Smith dated September 14, 1992
(incorporated by reference herein to Exhibit 10(k) to the Company's Annual Report on
Form 10-K for the fiscal year ended December 31, 1992, File No. 1-3473).
10(j) First Amendment and Extension to Employment Agreement between the Company and Bruce
A. Smith dated December 14, 1994.
10(k) Employment Agreement between the Company and Gaylon H. Simmons dated January 4, 1993
(incorporated by reference herein to Exhibit 10(l) to the Company's Annual Report on
Form 10-K for the fiscal year ended December 31, 1992, File No. 1-3473).
10(l) First Amendment and Extension to Employment Agreement between the Company and Gaylon
H. Simmons dated December 14, 1994.
10(m) Employment Agreement between the Company and James C. Reed, Jr. dated December 14,
1994.
10(n) Employment Agreement between the Company and William T. Van Kleef dated December 14,
1994.
10(o) Management Stability Agreement between the Company and Don E. Beere dated December
14, 1994.

69
70

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

10(p) Management Stability Agreement between the Company and Gregory A. Wright dated
February 23, 1995.
10(q) 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(r) 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(s) Copy of the Company's Executive Long-Term Incentive Plan (incorporated by reference
to Exhibit 10(k) to the Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 1993, File No. 1-3473).
10(t) Copy of the Company's Non-Employee Director Retirement Plan dated December 8, 1994.
10(u) Copy of the Company's Board of Directors Deferred Compensation Plan dated February
23, 1995.
10(v) Copy of the Company's Board of Directors Deferred Compensation Trust dated February
23, 1995.
10(w) Agreement for the Sale and Purchase of Royalty Oil between Tesoro Alaska Petroleum
Company and the State of Alaska (for the sale of Prudhoe Bay Royalty Oil), dated
February 26, 1982 (incorporated by reference herein to Exhibit 10(p) to the
Company's Annual Report on Form 10-K for the fiscal year ended September 30, 1984,
File No.1-3473).
10(x) Agreement for the Sale and Purchase of State Royalty Oil dated as of September 27,
1994 by and between Tesoro Alaska Petroleum Company and the State of Alaska.
10(y) 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(z) 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(aa) Gas Purchase and Sales Agreement dated January 16, 1979 (incorporated by reference
herein to Exhibit 10(p) of the Company's Registration Statement No. 33-68282 on Form
S-4).
11 Information Supporting Earnings (Loss) Per Share Computations.
21 Subsidiaries of the Company.
23(a) Consent of Deloitte & Touche LLP.
23(b) Consent of Netherland, Sewell & Associates, Inc.
27 Financial Data Schedule.

(b) REPORTS ON FORM 8-K

No reports on Form 8-K were filed by the Company during the quarter ended
December 31, 1994.

70
71

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

March 16, 1995 By: /s/ MICHAEL D. BURKE
------------------------------------
Michael D. Burke
President and Chief Executive
Officer

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

Chairman of the Board of March , 1995
- ------------------------------------------ Directors and Director
(Charles Wohlstetter)

/s/ MICHAEL D. BURKE Director, President and Chief March 16, 1995
- ------------------------------------------ Executive Officer (Principal
(Michael D. Burke) Executive Officer)

/s/ BRUCE A. SMITH Executive Vice President and March 16, 1995
- ------------------------------------------ Chief Financial Officer
(Bruce A. Smith) (Principal Financial Officer and
Accounting Officer)

/s/ ROBERT J. CAVERLY Vice Chairman of the Board of March 16, 1995
- ------------------------------------------ Directors and Director
(Robert J. Caverly)

/s/ PETER M. DETWILER Director March 16, 1995
- ------------------------------------------
(Peter M. Detwiler)

/s/ STEVEN H. GRAPSTEIN Director March 16, 1995
- ------------------------------------------
(Steven H. Grapstein)

/s/ RAYMOND K. MASON, SR. Director March 16, 1995
- ------------------------------------------
(Raymond K. Mason, Sr.)

/s/ JOHN J. MCKETTA, JR. Director March 16, 1995
- ------------------------------------------
(John J. McKetta, Jr.)

/s/ MURRAY L. WEIDENBAUM Director March 16, 1995
- ------------------------------------------
(Murray L. Weidenbaum)

Director March , 1995
- ------------------------------------------
(Joel V. Staff)

71
72
EXHIBIT INDEX

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

3 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(a) Bylaws of the Company, as amended through February 23, 1995.
3(b) 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(c) 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(d) 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(e) 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(a) 12 3/4% Subordinated Debentures due March 15, 2001, Form of Indenture, dated March
15, 1983 (incorporated by reference herein to Exhibit 4(b) to Registration Statement
No. 2-81960).
4(b) 13% Exchange Notes due December 1, 2000, Indenture, dated February 8, 1994
(incorporated by reference herein to Exhibit 2 to the Company's Registration
Statement on Form 8-A filed March 2, 1994).
4(c) Copy of Indenture between the Company and Bankers Trust Company, a Trustee, pursuant
to which the Exchange Notes Due December 1, 2000 were issued (incorporated by
reference herein to Exhibit 2 to the Company's Registration Statement on Form 8-A
filed March 2, 1994).
4(d) Rights Agreement dated December 16, 1985 between the Company and Chemical Bank, N.A.
successor to InterFirst Bank Fort Worth, N.A. (incorporated by reference herein to
Exhibit 4(i) to the Company's Annual Report on Form 10-K for the fiscal year ended
September 30, 1985, File No. 1-3473).
4(e) Amendment to Rights Agreement dated December 16, 1985 between the Company and
Chemical Bank, N.A. (incorporated by reference herein to Exhibit 4(c) to the
Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1992,
File No. 1-3473).
4(f) Tesoro Exploration and Production Company's Loan Agreement dated as of October 29,
1993 (incorporated by reference herein to Exhibit 4(b) to the Company's report on
Form 10-Q for the quarter ended September 30, 1993, File No. 1-3473).
4(g) Agreement for Waiver and Substitution of Collateral dated as of September 30, 1993
by and between Tesoro Alaska Petroleum Company and the State of Alaska (incorporated
by reference herein to Exhibit 4(c) to the Company's report on Form 10-Q for the
quarter ended September 30, 1993, File No. 1-3473).
4(h) Credit Agreement (the "Credit Agreement") dated as of April 20, 1994 among the
Company and Texas Commerce Bank National Association ("TCB") as Issuing Bank and as
Agent, and certain other banks named therein (incorporated by reference herein to
Exhibit 10.1 to the Company's report on Form 10-Q for the quarter ended March 31,
1994, File No. 1-3473).
4(i) Guaranty Agreement dated as of April 20, 1994 among various subsidiaries of the
Company and TCB, as Issuing Bank and as Agent, and certain other banks named therein
(incorporated by reference herein to Exhibit 10.2 to the Company's report on Form
10-Q for the quarter ended March 31, 1994, File No. 1-3473).

73

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

4(j) Mortgage, Deed of Trust, Assignment of Production, Security Agreement and Financing
Statement dated as of April 20, 1994 from Tesoro Exploration and Production Company,
entered into in connection with the Credit Agreement (incorporated by reference
herein to Exhibit 10.3 to the Company's report on Form 10-Q for the quarter ended
March 31, 1994, File No. 1-3473).
4(k) Deed of Trust, Security Agreement and Financing Statement dated as of April 20, 1994
among Tesoro Alaska Petroleum Company, TransAlaska Title Insurance Agency, Inc., as
Trustee, and TCB, as Agent, entered into in connection with the Credit Agreement
(incorporated by reference herein to Exhibit 10.4 to the Company's report on Form
10-Q for the quarter ended March 31, 1994, File No. 1-3473).
4(l) Pledge Agreement dated as of April 20, 1994 by the Company in favor of TCB, entered
into in connection with the Credit Agreement (incorporated by reference herein to
Exhibit 10.5 to the Company's report on Form 10-Q for the quarter ended March 31,
1994, File No. 1-3473).
4(m) Security Agreement (Accounts and Inventory) dated as of April 20, 1994 between the
Company and TCB, entered into in connection with the Credit Agreement (incorporated
by reference herein to Exhibit 10.6 to the Company's report on Form 10-Q for the
quarter ended March 31, 1994, File No. 1-3473).
4(n) Security Agreement (Accounts and Inventory) dated as of April 20, 1994 between
Tesoro Alaska Petroleum Company and TCB, entered into in connection with the Credit
Agreement (incorporated by reference herein to Exhibit 10.7 to the Company's report
on Form 10-Q for the quarter ended March 31, 1994, File No. 1-3473).
4(o) Security Agreement (Accounts) dated as of April 20, 1994 between Tesoro Petroleum
Distributing Company and TCB, entered into in connection with the Credit Agreement
(incorporated by reference herein to Exhibit 10.8 to the Company's report on Form
10-Q for the quarter ended March 31, 1994, File No. 1-3473).
4(p) Security Agreement (Accounts and Inventory) dated as of April 20, 1994 between
Tesoro Exploration and Production Company and TCB, entered into in connection with
the Credit Agreement (incorporated by reference herein to Exhibit 10.9 to the
Company's report on Form 10-Q for the quarter ended March 31, 1994, File No.
1-3473).
4(q) Security Agreement (Accounts and Inventory) dated as of April 20, 1994 between
Tesoro Refining, Marketing & Supply Company and TCB, entered into in connection with
the Credit Agreement (incorporated by reference herein to Exhibit 10.10 to the
Company's report on Form 10-Q for the quarter ended March 31, 1994, File No.
1-3473).
4(r) 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).
4(s) 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(t) $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(u) 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(v) 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(w) 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).

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EXHIBIT
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4(x) Consent and Intercreditor Agreement dated as of May 26, 1994 among NBA, TCB, as
Agent, and the Company, entered into in connection with the Credit Agreement
(incorporated by reference herein to Exhibit 4.36 to Registration Statement No.
33-53587).
4(y) Copy of Consent and Waiver No. 1 dated October 27, 1994 to the Company's Credit
Agreement dated as of April 20, 1994 (incorporated by reference herein to Exhibit 4
to the Company's report on Form 10-Q for the quarter ended September 30, 1994, File
No. 1-3473).
4(z) Copy of First Amendment to Credit Agreement dated as of January 20, 1995 among the
Company and TCB as Issuing Bank and as Agent, and certain other banks named therein.
4(aa) Copy of First Amendment to the Loan Agreement dated as of January 26, 1995 among
Tesoro Alaska Petroleum Company, Tesoro Petroleum Corporation and NBA.
10(a) Form of Executive Agreement providing for continuity of management between the
Company and James W. Queen dated June 28, 1984 (incorporated by reference herein to
Exhibit 10(b) to the Company's Annual Report on Form 10-K for the fiscal year ended
September 30, 1984, File No. 1-3473).
10(b) Form of Amendment to Executive Agreements between the Company and James W. Queen
dated September 30, 1987 (incorporated by reference herein to Exhibit 10(c) to the
Company's Annual Report on Form 10-K for the fiscal year ended September 30, 1987,
File No. 1-3473).
10(c) Form of Second Amendment to Executive Agreements between the Company and James W.
Queen dated February 28, 1990 (incorporated by reference herein to Exhibit 10(e) to
the Company's Annual Report on Form 10-K for the fiscal year ended September 30,
1990, File No. 1-3473).
10(d) 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(e) Sixth Amendment to the Company's Amended Executive Security Plan and Seventh
Amendment to the Company's Funded Executive Security Plan, both dated effective
March 6, 1991 (incorporated by reference herein to Exhibit 10(g) to the Company's
Annual Report on Form 10-K for the fiscal year ended September 30, 1991, File No.
1-3473).
10(f) 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.
10(g) Employment Agreement between the Company and Michael D. Burke dated July 27, 1992
(incorporated by reference herein to Exhibit 10(j) to the Company's Annual Report on
Form 10-K for the fiscal year ended December 31, 1992, File No. 1-3473).
10(h) First Amendment and Extension to Employment Agreement between the Company and
Michael D. Burke dated December 14, 1994.
10(i) Employment Agreement between the Company and Bruce A. Smith dated September 14, 1992
(incorporated by reference herein to Exhibit 10(k) to the Company's Annual Report on
Form 10-K for the fiscal year ended December 31, 1992, File No. 1-3473).
10(j) First Amendment and Extension to Employment Agreement between the Company and Bruce
A. Smith dated December 14, 1994.
10(k) Employment Agreement between the Company and Gaylon H. Simmons dated January 4, 1993
(incorporated by reference herein to Exhibit 10(l) to the Company's Annual Report on
Form 10-K for the fiscal year ended December 31, 1992, File No. 1-3473).
10(l) First Amendment and Extension to Employment Agreement between the Company and Gaylon
H. Simmons dated December 14, 1994.
10(m) Employment Agreement between the Company and James C. Reed, Jr. dated December 14,
1994.
10(n) Employment Agreement between the Company and William T. Van Kleef dated December 14,
1994.
10(o) Management Stability Agreement between the Company and Don E. Beere dated December
14, 1994.

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EXHIBIT
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10(p) Management Stability Agreement between the Company and Gregory A. Wright dated
February 23, 1995.
10(q) 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(r) 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(s) Copy of the Company's Executive Long-Term Incentive Plan (incorporated by reference
to Exhibit 10(k) to the Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 1993, File No. 1-3473).
10(t) Copy of the Company's Non-Employee Director Retirement Plan dated December 8, 1994.
10(u) Copy of the Company's Board of Directors Deferred Compensation Plan dated February
23, 1995.
10(v) Copy of the Company's Board of Directors Deferred Compensation Trust dated February
23, 1995.
10(w) Agreement for the Sale and Purchase of Royalty Oil between Tesoro Alaska Petroleum
Company and the State of Alaska (for the sale of Prudhoe Bay Royalty Oil), dated
February 26, 1982 (incorporated by reference herein to Exhibit 10(p) to the
Company's Annual Report on Form 10-K for the fiscal year ended September 30, 1984,
File No.1-3473).
10(x) Agreement for the Sale and Purchase of State Royalty Oil dated as of September 27,
1994 by and between Tesoro Alaska Petroleum Company and the State of Alaska.
10(y) 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(z) 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(aa) Gas Purchase and Sales Agreement dated January 16, 1979 (incorporated by reference
herein to Exhibit 10(p) of the Company's Registration Statement No. 33-68282 on Form
S-4).
11 Information Supporting Earnings (Loss) Per Share Computations.
21 Subsidiaries of the Company.
23(a) Consent of Deloitte & Touche LLP.
23(b) Consent of Netherland, Sewell & Associates, Inc.
27 Financial Data Schedule.