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, 1995

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:

TITLE OF EACH CLASS NAME OF EACH EXCHANGE 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 March 15, 2001 New York Stock Exchange

13% Exchange Notes due December 1, 2000 New York Stock Exchange

SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: None
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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, 1996, the aggregate market value of the voting stock held by
nonaffiliates of the registrant was approximately $204,974,831 based upon the
closing price of its shares on the New York Stock Exchange Composite tape. At
March 1, 1996, there were 25,734,991 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 1996 Annual Meeting Part III

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TESORO PETROLEUM CORPORATION

INDEX TO ANNUAL REPORT ON FORM 10-K

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PART I
Item 1. BUSINESS..................................................................... 3
Refining and Marketing..................................................... 3
Exploration and Production................................................. 7
Marine Services............................................................ 13
Competition................................................................ 14
Other...................................................................... 14
Government Regulation and Legislation...................................... 15
Employees.................................................................. 18
Executive Officers of the Registrant....................................... 18

Item 2. PROPERTIES................................................................... 20

Item 3. LEGAL PROCEEDINGS............................................................ 20

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.......................... 23

PART II

Item 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS........ 23

Item 6. SELECTED FINANCIAL DATA...................................................... 24

Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS................................................................. 25

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.................................. 39

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE................................................................. 73

PART III

Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT........................... 73

Item 11. EXECUTIVE COMPENSATION....................................................... 73

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT............... 73

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS............................... 73

PART IV

Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K............. 73

SIGNATURES.............................................................................. 81

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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 marine services. The
Company was incorporated in Delaware in 1968 (a successor by merger to a
California corporation incorporated in 1939). For financial information relating
to industry segments, see Management's Discussion and Analysis of Financial
Condition and Results of Operations in Item 7 and Note C of Notes to
Consolidated Financial Statements in Item 8.

RECENT EVENTS

On March 10, 1996, Peter M. Detwiler resigned as a director of the Company
in order to devote more time to other business interests. Mr. Detwiler, who
joined the Board of Directors in 1967, would not be eligible to stand for
reelection at the Company's next annual meeting due to exceeding the policy on
term limits under the Company's governance policy.

Patrick J. Ward was elected to the Company's Board of Directors on March
11, 1996. Mr. Ward has 47 years of experience in international energy operations
with Caltex Petroleum Corporation, where he recently retired as Chairman,
President and Chief Executive Officer.

During 1995, the Company restructured certain operations in its former Oil
Field Supply and Distribution segment by exiting the land-based portion of its
petroleum product distribution business and, in February 1996 the Company
acquired Coastwide Energy Services, Inc. ("Coastwide") and combined these
operations with the Company's remaining oil field supply and distribution
operations, forming a Marine Services segment. The Company's Marine Services
segment will provide a broad range of products and logistical support services
to the offshore drilling and drilling-related businesses operating in the Gulf
of Mexico. See "Marine Services" discussed below and Notes B and C of Notes to
Consolidated Financial Statements in Item 8.

On December 26, 1995, a group of five holders of Tesoro's Common Stock, led
by Kevin S. Flannery (the "Flannery Group"), beneficially owning in the
aggregate approximately 5.7% of the outstanding shares of Tesoro Common Stock,
filed a Form 13D with the Securities and Exchange Commission ("SEC") announcing
that they had formed a "group" identified as "The Stockholders' Committee for
New Management of Tesoro Petroleum Corporation" (the "Committee"), to seek to
acquire control of Tesoro through the replacement of the current Tesoro Board of
Directors with persons selected by the Committee. For further information on
this matter, see Item 3, Legal Proceedings.

REFINING AND MARKETING

OVERVIEW

The Company conducts petroleum refining operations in Alaska and sells
refined products to a wide variety of customers in Alaska, along the U.S. West
coast, in the Pacific Northwest and in certain Far Eastern markets. During 1995,
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.
Entering 1996, the Company's purchases from other refiners and suppliers should
decline as the Company discontinues its operations in California which is
further discussed below.

The Company's refinery, which is located in Kenai, Alaska, has a rated
throughput capacity of 72,000 barrels per day and is capable of producing
liquefied petroleum gas, gasoline, jet fuel, diesel fuel, heating oil, heavy
oils and residual products. Alaska North Slope ("ANS") and Cook Inlet crude oils
are the primary feedstocks for the refinery. To assure the availability of crude
oil to the refinery, the Company has a royalty crude oil purchase contract with
the State of Alaska ("State") (see "Crude Oil Supply" discussed below). During
1995, the refinery processed approximately 68% ANS crude oil, 26% Cook Inlet
crude oil and 6% other

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refinery feedstocks, which yielded refined products consisting of approximately
27% gasoline, 45% middle distillates, 10% heavy oils and 18% residual product.

In December 1994, the Company completed the installation of a vacuum unit
at the refinery, at a cost of $25 million, which reduces the refinery's yield of
residual products by further processing these volumes into higher-valued
products. In 1995, the Company implemented initiatives that increased the demand
for the refinery's production and improved the refinery's capacity utilization
and efficiencies. In this regard, the Company expanded its marketing efforts by
branding and rebranding sales outlets in Alaska and the Pacific Northwest and by
exporting products to the Russia Far East.

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 1995, approximately 68% of the refinery's feedstock
was ANS crude oil, of which approximately 37,500 barrels per day were purchased
under a royalty crude oil purchase contract with the State, which expired at the
end of 1995. The agreement between the Company and the State required 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. Under this agreement, the Company had the
right to sell or exchange up to 20% of the ANS crude oil purchased from the
State during 1995. In 1995, the Company renegotiated a new three-year contract
with the State covering the period January 1, 1996 through December 31, 1998.
The new contract provides for the purchase of approximately the same volumes of
ANS royalty crude oil as the previous contract with such crude oil being priced
at the weighted average price reported to the State by a major North Slope
producer of ANS crude oil as valued at Pump Station No. 1 on the Trans Alaska
Pipeline System ("TAPS"). Under the new contract, the Company is required to
utilize in its refinery operations volumes equal to at least 80% of the ANS
crude oil to be purchased from the State. This contract contains provisions
that, under certain conditions, allow the Company to temporarily or permanently
reduce its purchase obligation.

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

Cook Inlet Crude Oil. Cook Inlet crude oil, a lighter crude oil that
contains an average of .1% sulphur, accounted for approximately 26% of the
refinery's feedstock supply in 1995. The Company obtains Cook Inlet crude oil
from several producers on the Kenai Peninsula under short-term contracts. Cook
Inlet crude oil is delivered by tanker through the Company's KPL terminal or
through an existing pipeline to the refinery.

Other Supply. In 1995, the Company's refinery obtained approximately 6% of
its feedstock supply from other sources. The other supply consisted of heavy
atmospheric gas oil ("HAGO") and foreign crude oil. The HAGO feedstock was
purchased from a local competitor's refinery and from a U.S. West Coast refinery
under short-term contracts. HAGO is a refinery byproduct which generates various
light refined products with no residual fuel oil. The foreign crude oil,
purchased in spot quantities, is delivered to the refinery by tanker through the
KPL marine terminal. The Company evaluates the economic viability of processing
foreign crude oil in its refinery and will occasionally purchase spot quantities
to supplement its normal crude oil supply.

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 previously 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
based on a per barrel charge on the volume of feedstock processed at the
Company's refinery. For 1995, 1994 and 1993, based on a per barrel throughput
charge of 16 cents, the Company's variable payments to the State amounted to
$2.9 million, $2.8 million and $2.6 million, respectively. The per barrel charge
increases to 24 cents in 1996 and to 30 cents in 1998 with one cent annual
incremental increases thereafter through 2001. In January 2002, the Company is

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obligated to pay the State $60 million; provided, however, that such payment may
be deferred indefinitely by continuing the variable monthly payments to the
State beginning at 34 cents per barrel for 2002 and increasing one cent per
barrel annually thereafter. Variable monthly payments made after January 2002
will not reduce the $60 million obligation to the State. The $60 million
obligation is evidenced by a security bond, and the bond and the variable
monthly payments are secured by a mortgage on the Company's refinery. The
Company's obligations under the ANS 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. 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, 1995, 1994 and 1993:

YEARS ENDED DECEMBER 31,
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1995 1994 1993
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Refinery Throughput (average daily barrels)...................... 50,569 46,032 49,753
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Refinery Production (average daily barrels):
Gasoline....................................................... 14,298 11,728 12,021
Middle distillates and other................................... 23,182 20,615 21,487
Heavy oils and residual products............................... 14,516 15,118 17,573
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Total Refinery Production.............................. 51,996 47,461 51,081
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Product Sales (average daily barrels):
Gasoline....................................................... 24,526 23,191 22,466
Middle distillates............................................. 37,988 33,256 29,354
Heavy oils and residual products............................... 14,787 14,228 16,945
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Total Product Sales.................................... 77,301 70,675 68,765
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Product Sales Prices ($/barrel):
Gasoline....................................................... $28.21 27.03 27.82
Middle distillates............................................. $24.40 24.47 27.39
Heavy oils and residual products............................... $13.66 10.93 11.19

ALASKA MARKETING

Gasoline. With the vacuum unit operational in late 1994, the Company's
refinery production of gasoline increased by 22% in 1995. As a result, the
Company implemented initiatives to increase the Company's market share of
gasoline sales in Alaska. By the end of 1995, the Company had successfully
increased its market share to approximately 43% in its geographic market area,
from 29% at 1994 year-end, primarily by adding 42 stations to its marketing
locations. These additions included the branding and rebranding of 31 stations.

The Company distributes gasoline 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 97 branded and 28 unbranded
dealers and jobbers and by deliveries to major oil companies for their retail
operations in Alaska in exchange for gasoline delivered to the Company on the
U.S. West Coast. 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 1995, these convenience stores
sold an average of 72,000 gallons of gasoline per day. Gasoline produced in
excess of Alaska's market demand is shipped to the U.S. West Coast or exported
to the Far East by chartered vessel.

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

Heavy Oils and Residual Products. The vacuum unit, which uses residual
fuel oil as a feedstock, reduced the refinery's yield of residual product 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. The vacuum
unit has reduced the percentage of production sold as bunker fuel from 32% in
1994 to 18% in 1995.

U.S. WEST COAST AND PACIFIC NORTHWEST MARKETING

During 1995, the Company conducted domestic wholesale marketing operations,
primarily in California, Oregon and Washington with its principal office located
in Long Beach, California. These operations sold approximately 29,100 barrels
per day of refined products in 1995, of which approximately 18% was received
from major oil companies in exchange for products from the Company's refinery,
approximately 12% was received directly from the refinery and 70% was purchased
from other suppliers. In 1995, the Company expanded its presence in the Pacific
Northwest by branding ten stations in five cities in Washington and Oregon.
During 1995, the Company sold refined products in the bulk market and through 27
terminal facilities, of which four are owned by the Company.

Due to market conditions, the Company is currently in the process of
discontinuing its operations in California and intends to sell three of its
Company-owned facilities. The Company will continue to sell refined products in
the Pacific Northwest through branded stations in addition to six terminal
facilities, one of which is owned by the Company.

TRANSPORTATION

The Company charters an American flag vessel, the Potomac Trader, whose
primary use is to transport ANS crude oil from the TAPS terminal at Valdez,
Alaska to the Company's refinery. The Company charters another American flag
vessel, the Chesapeake Trader, which is used primarily to transport heavy oils
and residual product to the U.S. West Coast and occasionally to transport
feedstocks to the Company's refinery. The Potomac Trader and Chesapeake Trader
are chartered under five-year agreements expiring in 2000. Also, in 1995, the
Company chartered a Russian flag vessel, the Igrim, under a six-month agreement
with three six-month renewal options. In late 1995, the Company exercised its
right to renew the charter for six months. The Igrim is used primarily to
transport refined products from the Company's refinery to the Far East. 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 1995, the pipeline
transported an average of approximately 22,100 barrels of petroleum products per
day, all of which were transported for the Company.

In March 1995, the Company acquired all of the outstanding stock of Kenai
Pipe Line Company ("KPL"), a common carrier pipeline and dock facility, for $3
million. By owning this facility, the Company is

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assured of uninterrupted use of the dock and pipeline for unloading crude oil
feedstocks and loading product inventory on tankers and barges. During 1995, KPL
transported approximately 49,900 barrels of crude oil per day and 33,700 barrels
of refined products per day, all of which were transported for the Company.

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

EXPLORATION AND PRODUCTION

OVERVIEW

The Company's exploration and production strategy is to use its proven
experience and technology to capitalize on the underexplored formations of the
Wilcox Trend in South Texas and of the Chaco Basin in Bolivia. During 1995, the
Company's U.S. program began its initial shift from the Bob West Field, an
almost fully developed field, to other portions of the Wilcox Trend in South
Texas. Within its target region, the Company will primarily pursue prospects in
underexplored zones similar to those in the Bob West Field, from 10,000 feet to
15,000 feet deep. The Company is building its prospect inventory from an
8,500-mile seismic database and an extensive well log library. The Company
currently has 15 South Texas prospects in inventory encompassing 20,000 gross
(8,000 net) acres. Since 1976, the Company has operated two concessions in
Bolivia and, since that date, discovered six fields. Three of these Bolivian
fields are producing gas at market restricted rates, two fields are currently
shut-in and one field has been discovered subsequent to year-end.

UNITED STATES

Bob West Field. During 1995, the Company's U.S. operations were
concentrated primarily in the Bob West Field, a field that was discovered by the
Company in 1990. The Bob West Field is located in the southern part of the
Wilcox Trend in Starr and Zapata Counties, Texas. The Wilcox Trend extends from
Northern Mexico through South Texas into the other Gulf Coast states. Multiple
pay sands exist within the Wilcox Trend, where extensive faulting has trapped
hydrocarbons in numerous producing zones.

Continued successful development of the Bob West Field led to the
completion of 17 gross development wells during 1995, bringing the cumulative
number of gross producing wells in the field in which the Company participated
to 63. Three additional wells were being drilled at year-end and seven
additional well locations, the majority of which are expected to be drilled
during 1996, have been selected for further development of this 4,000-acre
field.

In September 1995, the Company sold, effective April 1, 1995, certain
interests in its producing and non-producing oil and gas properties located in
the Bob West Field in South Texas. The interests sold included the Company's
approximate 55% net revenue interest and 70% working interest in Units C, D and
E and a convertible override in Unit F of the Bob West Field. These units do not
include acreage related to the Company's natural gas sales contract with
Tennessee Gas Pipeline Company, which as discussed in Note N of Notes to
Consolidated Financial Statements in Item 8, is the subject of current
litigation. Also excluded from the sale were the Company's interests in the
State Park and Sanchez-O'Brien leases and the Ramirez USA E-6 well within the
Bob West Field. In total, the sale included interests in 14 gross producing
wells amounting to 77 billion cubic feet ("Bcf"), or 40%, of the Company's total
net proved domestic reserves at the time of the sale. Through the date of the
sale, natural gas production from the interests sold had contributed
approximately $11 million to revenues and $4 million to operating profit of the
Company's Exploration and Production segment for 1995. Consideration for the
sale was $74 million, which was adjusted on a preliminary basis for production,
capital expenditures and certain other items after the effective date to
approximately $68 million in cash received at closing, resulting in a gain of
approximately $33 million in the 1995 third quarter. The consideration received
by the Company, which is subject to final post-closing adjustments, was used to
redeem $34.6 million of the Company's outstanding 12 3/4% Subordinated
Debentures, reduce borrowing under the Company's Revolving Credit Facility and
improve corporate liquidity. The Company does not expect any final post-closing
adjustments to be material.

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After the sale of certain interests, at December 31, 1995, the Company owns
interests in 49 gross wells, or approximately 100 Bcf of net proved reserves, in
the Bob West Field. The Company's revenue interests in the field range from 28%
to 57% and its working interests range from 33% to 70%. In addition, the Company
owns a 70% interest in the field's central gas processing facility which has a
capacity of 350 million cubic feet ("Mmcf") per day.

During 1995, the Company's net production from the Bob West Field wells
averaged approximately 113 Mmcf per day. Excluding the production from the 14
wells that were sold during September 1995, the Company's net production from
the field averaged 89 Mmcf per day.

Other Areas of South Texas. In addition to the continued development of
the Bob West Field, during 1995 the Company also participated in the drilling of
nine exploratory wells in other portions of the Wilcox Trend in South Texas,
five of which were successfully completed as producing wells. One of the wells,
the Tesoro Longoria #1 exploratory well in Webb County of South Texas, marked
the discovery of a new natural gas field (the "Tea Jay Field"). Tesoro serves as
operator of this well which is currently flowing at a gross rate of 5 Mmcf per
day of natural gas. At year-end 1995, the Company held a 45% working interest in
the Tea Jay Field and has subsequently acquired an additional 4% working
interest. As a result of the initial exploratory well, the Company added
approximately 4 Bcf to its net proved reserves in 1995. A seismic program has
been completed at the 2,400-acre Tea Jay Field to assist in identifying future
drilling sites. The Tesoro Longoria #2 delineation well, which began drilling in
February 1996, incurred a blowout on March 15, 1996 before reaching target
depth. The Company is currently in the process of determining whether the well
can be salvaged or whether it will have to drill a replacement well. The
Company does not anticipate any significant adverse economic impact from the
well blowout. The Company is uncertain as to the future impact of this field
upon its operations.

Reserves. The following table shows the estimated proved reserves for each
of the Company's U.S. fields as of December 31, 1995, based on evaluations
prepared by Netherland, Sewell & Associates, Inc.:

PRESENT NET NET
SOUTH VALUE OF PROVED PROVED GROSS
TEXAS PROVED GAS OIL PRODUCING
FIELD NAME COUNTY OPERATORS RESERVES(1) RESERVES RESERVES WELLS
- ----------- ------ -------------------------- ------------- -------- ---------- ---------
($ THOUSANDS) (MMCF) (THOUSANDS
OF
BARRELS)

Bob West Starr Coastal Oil & Gas Corp. and $ 160,901(2) 100,014 -- 49
Sanchez-O'Brien Oil & Gas
Tea Jay Webb Tesoro 4,913 4,248 8 1
Lopeno Zapata Mustang Oil & Gas Corp. 2,920 2,111 -- 3
Other 5 4 -- 4
--------- ------- ---- -----
$ 168,739 106,377 8 57
========== ======= ==== =====

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

(2) See Legal Proceedings in Item 3 and Notes N and Q of Notes to Consolidated
Financial Statements in Item 8 regarding litigation concerning the
Tennessee Gas Contract. Based on the Contract Price, the discounted future
net cash flows before income taxes at December 31, 1995 was $168.7 million,
compared with $120.7 million at spot market prices.

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Reserve Replacement. In 1995, the Company's U.S. proved reserve additions,
including revisions, totaled 96 Bcf, replacing 230% of its U.S. production of 42
Bcf. Excluding revisions, 50 Bcf were added for a 120% U.S. replacement rate.
These reserve additions were achieved at a low cost, bringing the Company's
three-year average finding cost to $.70 per thousand cubic feet equivalent
("Mcfe"), as illustrated by the following table:

YEARS ENDED DECEMBER 31,
------------------------------- THREE YEAR
1995 1994 1993 TOTAL
------- ------- ------- ----------

Expenditures (in thousands)............... $49,446 $60,379 $28,640 $138,465
Proved Natural Gas Reserves Added,
including Revisions (Mmcfe)............. 96,494 39,487 60,595 196,576
Costs per Mcfe............................ $ .51 $ 1.53 $ .47 $ .70

These additions were realized with an 85% domestic drilling success rate
during 1995, reflecting a 100% success rate on the 17 development wells and a
56% success rate on the nine exploratory wells.

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
pursuant to a contract price ("Contract Price"). During the month of December
1995, the Contract Price was in excess of $8.60 per Mcf which was substantially
above the average spot market price of $1.84 per Mcf. The Tennessee Gas Contract
is presently the subject of litigation. In 1995, approximately 17% of the
Company's total U.S. production was sold under the Tennessee Gas Contract
representing 57% of the Company's U.S. natural gas revenues for the year. See
Legal Proceedings in Item 3 and Notes N and Q of Notes to Consolidated Financial
Statements in Item 8.

Gas Gathering and Transportation. The Company owns a 70% interest in the
Starr County Gathering System which consists of two ten-inch diameter pipelines
and one twenty-inch diameter pipeline that transport natural gas eight miles
from the Bob West Field to common carrier pipeline facilities. In addition, the
Company owns a 50% interest in the twenty-inch diameter Starr-Zapata natural gas
pipeline that was constructed during 1994 to transport gas 26 miles from the
Starr County Gathering System to a market hub at Fandango, Texas. The Company
does not operate either facility. During 1995, the gross average daily
throughput was 223 Mmcf per day and 178 Mmcf per day for the Starr County
Gathering System and the Starr-Zapata pipeline, respectively, of which 113 Mmcf
per day and 93 Mmcf per day, respectively, were for the Company's production.
The Starr County Gathering System receives a transportation fee of $.06 per Mcf
and the Starr-Zapata Pipeline receives a fee of $.07 per Mcf for volumes
transported.

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

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U.S. Operating Statistics

YEARS ENDED DECEMBER 31,
--------------------------------
1995 1994 1993
-------- ------- -------

Net Natural Gas Production (average daily Mcf)............... 114,490 83,796 38,767
Average Natural Gas Sales Price ($/Mcf)(1):
Spot market................................................ $ 1.34 1.48 1.89
Tennessee Gas Contract(2).................................. $ 8.41 7.93 7.51
Weighted average........................................... $ 2.57 2.86 3.43
Average Operating Expenses ($/Mcf):
Lease operating expenses................................... $ .11 .11 .12
Severance taxes -- spot market............................. .09 .09 .11
-------- ------ ------
Total production costs -- spot market(1)........... .20 .20 .23
Administrative support and other........................... .07 .08 .09
-------- ------ ------
Total operating expenses -- spot market............ $ .27 .28 .32
======== ====== ======
Severance taxes -- Tennessee Gas Contract.................. $ 0.58 0.52 0.50
Total weighted average production costs(1)................. $ 0.29 0.29 0.34
Total weighted average operating expenses.................. $ 0.35 0.37 0.42
Depletion Rate ($/Mcf)....................................... $ .69 .79 .78
Exploratory Wells Drilled:
Productive -- Gross........................................ 5.0 3.0 1.0
Productive -- Net.......................................... 1.5 1.5 .4
Dry holes -- Gross......................................... 4.0 2.0 1.0
Dry holes -- Net........................................... 2.1 1.1 .5
Development Wells Drilled:
Productive -- Gross........................................ 17.0 20.0 15.0
Productive -- Net.......................................... 9.7 11.1 7.9
Dry holes -- Gross......................................... -- 1.0 --
Dry holes -- Net........................................... -- .4 --

DECEMBER 31,
1995
--------------
GROSS NET
----- ----

Productive Gas Wells(3)....................................................... 57 28.3
Acreage (in thousands):
Developed................................................................... 5 2
Undeveloped................................................................. 19 7

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

(1) Amounts previously reported have been restated for certain
reclassifications between revenues and operating expenses.

(2) See Item 3, Legal Proceedings, and Notes N and Q of Notes to Consolidated
Financial Statements in Item 8 regarding litigation concerning the
Tennessee Gas Contract.

(3) Included in total productive wells is 1 gross (.6 net) well with multiple
completions. At December 31, 1995, the Company was participating in the
drilling of 3 gross (1.0 net) wells.

BOLIVIA

The Company's Bolivian exploration and production operations are located in
southern Bolivia near the border of Argentina, where the Company has discovered
six fields since 1976. With estimated net proved natural gas reserves of 98 Bcfe
at December 31, 1995 and average gas production of 18.7 Mmcf per day in 1995,
Tesoro is one of the largest independent producers of natural gas in Bolivia.
The Company is the

10
11

operator of a joint venture that holds two Contracts of Operation with
Yacimientos Petroliferos Fiscales Bolivianos ("YPFB"), the Bolivian state-owned
oil and gas company.

Block 18. The Company has a 75% interest in a Contract of Operation, which
expires in 2007, covering approximately 93,000 acres in Block 18. The Company
has drilled five exploratory wells and 12 development wells within three
separate fields in Block 18. During 1995, the Company's net production from
these fields averaged 18.7 Mmcf of gas per day and 567 barrels of condensate per
day.

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 18 to YPFB which in turn sells the
natural gas to Yacimientos Petroliferos Fiscales, S.A. ("YPF"), a publicly-held
company based in Argentina. During 1994, the contract between YPFB and YPF was
extended through March 31, 1997, maintaining approximately the same volumes as
the previous contract. Currently, the Company is selling its natural gas
production to YPFB based on the volume and pricing terms in the contract between
YPFB and YPF.

Block 20. The Company has a 72.6% interest in a Contract of Operation,
which expires in 2008, covering approximately 1.2 million acres in Block 20. 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 20
is currently limited by a lack of access to major gas-consuming markets, which
is further discussed below.

Prior to 1995, the Company discovered the Los Suris Field with two wells
that are shut-in pending the approval by the Government of Bolivia of a
commercialization agreement. During 1995, the Company discovered the Palo
Marcado Field by completing a discovery well that is also shut in. The Palo
Marcado well was the third well of a five-well exploratory program that was
approved by YPFB and the Government of Bolivia. The fourth well was drilling at
year-end 1995 on the Ibibobo prospect. After completion of the five-well
exploratory program in July 1996, the existing Contract of Operation provides
that YPFB will select inactive parcels to be relinquished from the 1.2 million
acres currently under contract in Block 20 with the Company retaining only its
producing fields and indicated discoveries.

Reserves. The table below shows the estimated proved reserves for each of
the Company's Bolivian fields as of December 31, 1995, based on evaluations
prepared by Netherland, Sewell & Associates, Inc. These evaluations assume that
the Company's access to markets is limited to current sales rates through the
termination dates of the existing Contracts of Operation (see "Proposed Bolivian
Hydrocarbons Law" and "Access to New Markets" discussed below). Each of the
following fields is operated by the Company:

PRESENT NET NET NUMBER OF GROSS WELLS
VALUE OF PROVED PROVED ------------------------------
CONTRACT OF PROVED GAS OIL PRODUCING SHUT-IN WELLS IN
OPERATION FIELD RESERVES(1) RESERVES RESERVES WELLS WELLS PROGRESS
- ------------ ----------------- ------------- -------- ---------- --------- ------- --------
($ THOUSANDS) (MMCF) (THOUSANDS
OF
BARRELS)

Block 18 Escondido $26,863 45,020 869 3 2 --
La Vertiente 13,910 16,646 406 5 -- --
Taiguati 681 833 16 1 -- --
Block 20 Los Suris 7,272 25,897 305 -- 2 --
Palo Marcado(2) -- -- -- -- 1 --
Ibibobo(3) -- -- -- -- -- 1
---------- ------ -------- ----- ---- ----
$48,726 88,396 1,596 9 5 1
========== ====== ======== ===== ==== ====

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

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

11
12

(2) The Palo Marcado discovery is not counted in the Company's proved reserves
at year-end due to current limitations on the Company's access to markets.
See "Proposed Bolivian Hydrocarbons Law" and "Access to New Markets"
discussed below.

(3) The Ibibobo X-2 was completed subsequent to year-end 1995.

Proposed Bolivian Hydrocarbons Law. On February 14, 1996, the President of
Bolivia submitted to the Bolivian Congress proposed legislation that would, if
enacted, significantly impact the Company's operations in Bolivia. Among other
matters, the proposed legislation would grant the Company the option to convert
its Contracts of Operation to new Shared Risk Contracts or to remain under the
old contract terms. If converted, the new Shared Risk Contracts would include
extended contract termination dates, more favorable acreage relinquishment
terms, and a revised fiscal regime of taxes and tariffs. The new contract terms
could extend the Company's contracts on Block 18 and Block 20 to 2017 and 2029
from their current expiration dates of 2007 and 2008, respectively. This could
result in an immediate increase of up to 35% in the Company's proved Bolivian
reserves, which are currently limited by the contract termination dates. In
addition to retaining the Company's producing fields and indicated discoveries,
the new acreage relinquishment terms could allow the Company to retain
approximately two-thirds of the remaining unexplored Block 20 acreage, subject
to exploration drilling obligations to be specified by the Bolivian government.
The Company is currently assessing all aspects of this proposed legislation.

Access To New Markets. 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 Rio Grande in
central 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. The proposed pipeline to Brazil, with a capacity of 1
Bcf per day, is currently expected to begin construction in 1997 and is expected
to be operational by early 1999. The planned capacity of the pipeline would
ultimately increase the Bolivian natural gas export capacity to six times
current levels. The Company currently supplies over 20% of the Bolivian natural
gas export volumes. Details of the proposed pipeline to Brazil are in the
process of being finalized. The Company is assessing how the proposed pipeline
will impact the demand for the Company's gas or the ability of the Company to
market its gas.

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

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13

Bolivia Operating Statistics

YEARS ENDED DECEMBER 31,
-----------------------------
1995 1994 1993
------- ------ ------

Net Production(1):
Natural gas (average daily Mcf)............................... 18,650 22,082 19,232
Condensate (average barrels per day).......................... 567 733 663
Average Sales Price:
Natural gas ($/Mcf)........................................... $ 1.28 1.20 1.22
Condensate ($/barrel)......................................... $ 14.39 13.28 14.26
Average Operating Expenses ($/net equivalent Mcf):
Production costs.............................................. $ .07 .06 .14
Value-added taxes............................................. .06 .10 .09
Administrative support and other.............................. .35 .25 .27
------- ------ ------
Total Operating Expenses.............................. $ .48 .41 .50
======= ====== ======
Depletion Rate ($/net equivalent Mcf)........................... $ .03 -- --
Exploratory Wells Drilled:
Productive -- Gross........................................... 1.0 1.0 --
Productive -- Net............................................. .7 .7 --
Dry Holes -- Gross............................................ -- 1.0 --
Dry Holes -- Net.............................................. -- .7 --

DECEMBER 31,
1995
--------------
GROSS NET
----- ----

Productive Gas Wells(2)...................................................... 14 10.4
Acreage (in thousands):
Developed.................................................................. 38 29
Undeveloped................................................................ 1,210 880

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

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

(2) Included in total productive wells are 8 gross (6.0 net) wells with
multiple completions. At December 31, 1995 the Company was participating
in the drilling of 1 gross (.7 net) well.

MARINE SERVICES (FORMERLY OIL FIELD SUPPLY AND DISTRIBUTION)

In 1995, the Company restructured certain operations in its former Oil
Field Supply and Distribution segment by exiting the land-based portion of its
petroleum product distribution business, reducing the number of Company sites to
14 terminals, primarily marine-based, at year-end. These operations, which are
located at various sites along the Texas and Louisiana Gulf Coast, sold
lubricants, fuels and specialty petroleum products primarily to onshore and
offshore drilling contractors. These products are used to power and lubricate
machinery on drilling and production locations. The Company also provided
products for marine, commercial and industrial applications. In 1995, sales of
refined products, primarily diesel fuel, amounted to approximately 7,300 barrels
per day from the Company's petroleum products distribution business.

In February 1996, the Company purchased 100% of the outstanding capital
stock of Coastwide Energy Services, Inc. ("Coastwide"). Coastwide is primarily a
provider of services and a wholesale distributor of diesel fuel and lubricants
to the offshore drilling industry in the Gulf of Mexico. The Company will
combine its remaining petroleum distribution operations with Coastwide, forming
a Marine Services segment. As a combined operation, the Marine Services segment
will consist of 20 terminals, primarily marine-based, along the Texas and
Louisiana Gulf Coast and will provide a broad range of products and logistical
support services to the offshore industries operating in the Gulf of Mexico.
Customers include companies engaged in oil and

13
14

gas exploration and production and seismic evaluation, as well as offshore
construction and other drilling-related businesses. See Notes B and C of Notes
to Consolidated Financial Statements in Item 8.

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 refining
competition in Alaska consists of a refinery situated near Fairbanks owned by
MAPCO, Inc. and two refineries situated near Valdez and Fairbanks owned by Petro
Star Inc. The Company estimates that such other refineries have a combined
capacity to process approximately 176,000 barrels per day of crude oil. ANS
crude oil is the only feedstock used in these competing refineries. After
processing the crude oil and removing the lighter-end products, which represent
approximately 30% of each barrel processed, these refiners are permitted,
because of their direct connection to the TAPS, to return the remainder of the
processed crude back into the pipeline system as "return oil" in consideration
for a fee, thereby eliminating their need to market residual 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 a supplier to a major oil company through a product exchange
agreement, whereby gasoline in Alaska is provided in exchange for gasoline
delivered to the Company on the U.S. West Coast. Jet fuel sales are concentrated
in Anchorage, where the Company is one of 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 and Pacific Northwest 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

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15

and adverse economic conditions in the foreign countries, the future effects of
which the Company is unable to predict.

GOVERNMENT REGULATION AND LEGISLATION

UNITED STATES

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

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

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 Order Nos. 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

15
16

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.

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 cannot estimate the cost of the new
standards imposed by the EPA or what technologies or changes in processes the
Company may have to install or undertake to achieve compliance with the
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 1996 and 1997. 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 issued its final notice on March 22, 1994 approving an
extension for the State until

16
17

October 1, 1996. In December 1995, the State submitted an additional application
for a permanent waiver. The EPA has not acted on the State's December 1995
application for a permanent waiver. 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 1995. While the Company is unable to predict the outcome of these
matters; their ultimate resolution should not have a material impact on its
operations.

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

The Company currently charters a tanker to transport crude oil from the
Valdez, Alaska pipeline terminal through Prince William Sound and Cook Inlet to
its refinery. In addition, the Company routinely charters, on a long-term and
short-term basis, additional tankers and barges for shipment of crude oil and
refined products through Cook Inlet, as well as other locations. OPA 90
requires, as a condition of operation, that the Company demonstrate the
capability to respond to the "worst case discharge" to the maximum extent
practicable. Alaska law requires the Company to provide spill-response
capability to contain or control, and clean-up within 72 hours, an amount equal
to 50,000 barrels for a tanker carrying fewer than 500,000 barrels of crude oil
or equal to 300,000 barrels for a tanker carrying more than 500,000 barrels. To
meet these requirements, the Company has entered into a contract with Alyeska
Pipeline Service Company ("Alyeska") to provide initial spill response services
in Prince William Sound, with the Company later to assume those responsibilities
after mutual agreement with Alyeska and State and Federal On-Scene Coordinators.
The Company has also entered into an agreement with Cook Inlet Spill Prevention
and Response, Incorporated for oil spill response 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 starting in 1996 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 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's capital expenditures for
environmental control purposes amounted to approximately $1 million during 1995.
The Company anticipates that it will incur capital

17
18

expenditures for such purposes in 1996 of approximately $3 million, primarily
for the removal and upgrading of underground storage tanks, and starting in 1996
approximately $8 million for the installation of dike liners; however, the
Company is applying for an alternate compliance schedule, allowed for under the
Alaska regulations, regarding dike liner installation at the Company's Alaska
facilities. This alternate schedule, if granted, will allow the Company
additional time to assess an alternate remedy to the requirement, under Alaska
environmental regulations. There can be no assurance that an alternate schedule
will be granted. 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.

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. 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.

For information on proposed legislation regarding a Bolivian hydrocarbons
law, see "Exploration and Production -- Bolivia" discussed above.

EMPLOYEES

At December 31, 1995, the Company employed approximately 840 persons, of
which approximately 35 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, 1996.

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

Bruce A. Smith............... 52 President and Chief Executive Officer September 1995
James C. Reed, Jr............ 51 Executive Vice President, General Counsel September 1995
and Secretary
Gaylon H. Simmons............ 56 Executive Vice President September 1993
William T. Van Kleef......... 44 Senior Vice President and Chief Financial September 1995
Officer
Don E. Beere................. 55 Vice President, Controller February 1992
Thomas E. Reardon............ 49 Vice President, Human Resources and September 1995
Environmental
Gregory A. Wright............ 46 Vice President, Corporate Communications September 1995
and Treasurer

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

18
19

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

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

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

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

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.

William T. Van Kleef....... Senior Vice President and Chief Financial Officer
since September 1995. Vice President, Treasurer
from March 1993 to September 1995. 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.

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.

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

Gregory A. Wright.......... Vice President, Corporate Communications and
Treasurer since September 1995. Vice President,
Corporate Communications from February 1995 to
September 1995. Vice President, Corporate
Communications of Tesoro Petroleum Companies, Inc.
from January 1995 to February 1995. Vice President,
Business 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, C and
Q of Notes to Consolidated Financial Statements in Item 8.

ITEM 3. LEGAL PROCEEDINGS

Gas Purchase and Sales Contract. The Company is selling a portion of the
gas produced from its Bob West Field to Tennessee Gas Pipeline Company
("Tennessee Gas") under a Gas Purchase and Sales Agreement ("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"). In August 1990, 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 the month of
December 1995, the Contract Price was in excess of $8.60 per Mcf and the average
spot market price was $1.84 per Mcf. For the year ended December 31, 1995,
approximately 17% of the Company's net U.S. natural gas production was sold
under the Tennessee Gas Contract. Tennessee Gas also claimed that the contract
should be considered an "output contract" under Section 2.306 of the Texas
Uniform Commercial Code ("UCC") 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 appellate court decision was the first decision reported in
Texas holding that a take-or-pay contract was an output contract. The Supreme
Court of Texas heard arguments in December 1994 regarding the output contract
issue and certain of the issues raised by Tennessee Gas. On August 1, 1995, the
Supreme Court of Texas, in a divided opinion, affirmed the decision of the
appellate court on all issues, including that the price under the Tennessee Gas
Contract is the Contract Price, and determined that the Tennessee Gas Contract
was an output contract and remanded the case to the trial court for
determination of whether gas volumes tendered by the Company to Tennessee Gas
were tendered in good faith and were not unreasonably disproportionate to any
normal or otherwise comparable prior output or stated estimates in accordance
with the UCC. The Company filed a motion for rehearing before the Texas Supreme
Court on the issue of whether the Tennessee Gas Contract is an output contract.
The Company believes that, if this issue is tried, the gas volumes tendered to
Tennessee Gas will be found to have been in good faith and otherwise in
accordance with the requirements of the UCC. However, there can be no assurance
as to the ultimate outcome at trial.

In conjunction with the District Court judgment and on behalf of all
sellers under the Tennessee Gas Contract, Tennessee Gas is presently required to
post a supersedeas bond in the amount of $206 million. Under the terms of this
bond, for the period September 17, 1994 through April 30, 1996, Tennessee Gas is
required to take at least its entire monthly take-or-pay obligation and pay for
gas taken at $3.00 per Mmbtu, which approximates $3.00 per Mcf ("Bond Price").
The $206 million bond represents an amount which together with anticipated sales
of natural gas at the Bond Price will equal the anticipated value of the
Tennessee Gas Contract from September 17, 1994 through April 30, 1996. Except
for the period September 17, 1994 through August 13, 1995, the difference
between the spot market price and the Bond Price is refundable in the event
Tennessee Gas ultimately prevails in the litigation. The Company retains the
right to receive the Contract Price for all gas sold to Tennessee Gas.

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21

Through December 31, 1995, under the Tennessee Gas Contract, the Company
recognized cumulative net revenues in excess of spot market prices totaling
approximately $117.3 million. Of the $117.3 million incremental net revenues,
the Company has received $11.0 million that is nonrefundable and $55.6 million
which the Company could be required to repay in the event of an adverse ruling.
The remaining $50.7 million of incremental net revenues is classified in the
Company's Consolidated Balance Sheet as a noncurrent receivable at December 31,
1995 and represents the unpaid difference between the Contract Price and the
Bond Price as described above. An adverse outcome of this litigation could
require the Company to reverse as much as $106.3 million of the incremental
revenues and could require the Company to repay as much as $55.6 million for
amounts received above spot prices, plus interest if awarded by the court. See
Notes N and Q of Notes to Consolidated Financial Statements in Item 8.

Consent Solicitation. On December 26, 1995, a group of five holders of
Tesoro's Common Stock, led by Kevin S. Flannery (the "Flannery Group"),
beneficially owning in the aggregate approximately 5.7% of the outstanding
shares of Tesoro Common Stock, filed a Form 13D with the Securities and Exchange
Commission ("SEC") announcing that they had formed a "group" identified as "The
Stockholders' Committee for New Management of Tesoro Petroleum Corporation" (the
"Committee"), to seek to acquire control of Tesoro through the replacement of
the current Tesoro Board of Directors with persons selected by the Committee. In
the Schedule 13D filed by the Flannery Group, the Flannery Group stated that it
would seek to accomplish its goal of replacing the Tesoro Board of Directors by
soliciting the written consent of holders of Tesoro Common Stock through a
consent solicitation. On December 26, 1995, the Committee filed preliminary
materials with the SEC to solicit stockholders' written consents.

On December 26, 1995, the Flannery Group filed a suit in the Federal
District Court for the Western District of Texas, San Antonio Division (Civil
Action SA95CA1298) against the Company and Bruce A. Smith, its President and
Chief Executive Officer. The suit asks the court (i) to enjoin the Company and
Mr. Smith from bringing legal action for wrongdoing by the plaintiffs in any
other court, (ii) to declare that the Company's Shareholder Rights Plan does not
apply to the Committee's efforts to solicit written consents, (iii) to declare
that the Company's By-laws permit stockholders to remove directors by consent,
(iv) to declare that the plaintiffs have complied with certain federal
securities laws and (v) to enjoin the Company and Mr. Smith from taking any
action to delay or otherwise unlawfully interfere with the Committee's efforts
to solicit consents. However, the complaint contains no allegations whatsoever
that either the Company or Mr. Smith has done anything to delay or otherwise
unlawfully interfere with the Committee's solicitation.

On January 8, 1996, the Company moved to dismiss the Flannery Group's
complaint since it does not allege an actual case or controversy, does not
allege any actual illegal conduct by the Company and otherwise improperly
requests that the court make legal determinations that are not ripe for
consideration. The Company also filed an answer and counterclaims which include
allegations that the Flannery Group or members thereof and others have violated
the federal securities laws, have disseminated false and misleading information
to the Company's stockholders in an effort to take control of the Company and
tortiously interfered with the business of the Company, resulting in significant
harm to the Company.

Also, on January 8, 1996, the United States District Court, at the request
of the Company, issued a temporary restraining order restraining the Flannery
Group from taking any action in furtherance of its consent solicitation,
including soliciting or attempting to solicit consents, filing or disseminating
to the Company's stockholders or the public any Schedule 13D or 14A statements
relating to the Company, or making any false or misleading statements regarding
the Company. In connection with the request for the restraining order, the
Company volunteered not to commence any judicial proceedings in any other forum
that would require litigation of issues common to those before the court or to
take any action unlawfully to delay or interfere with the plaintiffs' efforts to
solicit written consents. On January 12, 1996, the court entered an order
disqualifying counsel for the Flannery Group and subsequently extended the
temporary restraining order as a result. On January 31, 1996, the court held a
hearing on the Company's preliminary injunction motion. In connection therewith,
the Flannery Group filed with the court a substantially revised Schedule 14A
statement purporting to correct the false and misleading statements that the
Company claims are in the Flannery Group's initial 14A statement. On February 1,
1996, the court dissolved the temporary restraining order and denied the motion
for a preliminary injunction. Based on information contained in a filing with
the SEC, the

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22

Flannery Group on or about February 29, 1996 mailed its consent solicitation
material to the Company's stockholders. On March 5, 1996, the Company mailed its
consent revocation material to the Company's stockholders.

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. In May 1995,
the court issued an order granting the Company's motion for summary judgment and
dismissed with prejudice all the claims in the Customer's complaint. In June
1995, the Customer filed a notice of appeal with the U.S. Court of Appeals for
the Federal Circuit. 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 substantially
similar to Consent Orders reached with the Environmental Protection Agency
("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 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 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 is currently considering a penalty assessment of approximately
$1.5 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 "Site"). The Company arranged for
the disposal of a minimal amount of materials at the Site, but CERCLA might
impose joint and several liability on each PRP at the Site. The EPA is seeking
reimbursement for its response costs incurred to date at the Site, as well as a
commitment from the PRPs either to conduct future remedial activities or to
finance such activities. At this time, the Company is unable to determine the
extent of the Company's liability related to the Site; however, the extent of
the Company's allocated financial contribution to the cleanup of these sites is
expected to be minimal based on the number of companies and the volumes of waste
involved. The Company believes that its liability at the Site will be limited
based upon the payment by the Company of a de minimis 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.

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

None.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND

RELATED STOCKHOLDER MATTERS

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 1995 and 1994 are summarized
below:

1995 1994
------------- ------------
QUARTERS HIGH LOW HIGH LOW
-------- ----- --- ---- ---

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

At March 1, 1996, there were approximately 4,000 holders of record of the
Company's 25,734,991 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.

THREE
MONTHS YEAR
ENDED ENDED
YEARS ENDED DECEMBER 31, DECEMBER SEPTEMBER
------------------------------ 31, 30,
1995 1994 1993 1992 1991(1) 1991
------ ----- ----- ----- ------ ------
(IN MILLIONS EXCEPT PER SHARE AMOUNTS)

STATEMENTS OF OPERATIONS DATA
Gross Operating Revenues:
Refining and Marketing...................................... $771.0 687.0 687.2 810.7 196.8 898.6
Exploration and Production
Oil and gas producing(2)(3)............................... 119.0 100.7 61.0 42.1 12.5 59.0
Gas transportation(3)..................................... 5.7 3.1 1.0 -- -- --
Marine Services............................................. 74.5 77.9 80.7 93.5 36.5 134.3
Intersegment Eliminations(4)................................ -- -- -- (.4) (5.2) (7.1)
------ ----- ----- ----- ------ ------
Total Gross Operating Revenues........................ $970.2 868.7 829.9 945.9 240.6 1,084.8
====== ===== ===== ===== ====== ======
Segment Operating Profit (Loss),
Including Gain on Sales of Assets(5):
Refining and Marketing...................................... $ .7 2.4 15.2 (14.9) 1.7 19.3
Exploration and Production
Oil and gas producing(2)(5)............................... 104.5 61.4 39.8 29.1 7.4 35.6
Gas transportation........................................ 5.1 2.9 .9 -- -- --
Marine Services............................................. (4.4) (2.3) (3.6) (4.7) (1.2) (.5)
------ ----- ----- ----- ------ ------
Total Segment Operating Profit........................ $105.9 64.4 52.3 9.5 7.9 54.4
====== ===== ===== ===== ====== ======
Earnings (Loss) Before Extraordinary Loss and the Cumulative
Effect of Accounting Changes................................ $ 57.5 20.5 17.0 (45.3) (.4) 3.9
Extraordinary Loss on Extinguishment of Debt.................. (2.9) (4.8) -- -- -- --
Cumulative Effect of Accounting Changes....................... -- -- -- (20.6) -- --
------ ----- ----- ----- ------ ------
Net Earnings (Loss)(6)........................................ $ 54.6 15.7 17.0 (65.9) (.4) 3.9
====== ===== ===== ===== ====== ======
Net Earnings (Loss) Applicable to Common Stock(6)............. $ 54.6 13.0 7.8 (75.1) (2.7) (5.3)
====== ===== ===== ===== ====== ======
Earnings (Loss) per Primary and Fully Diluted* Share(6)(7):
Earnings (loss) before extraordinary loss and the cumulative
effect of accounting changes.............................. $ 2.29 .77 .54 (3.87) (.19) (.37)
Extraordinary loss on extinguishment of debt................ (.11) (.21) -- -- -- --
Cumulative effect of accounting changes..................... -- -- -- (1.47) -- --
------ ----- ----- ----- ------ ------
Net earnings (loss)......................................... $ 2.18 .56 .54 (5.34) (.19) (.37)
====== ===== ===== ===== ====== ======
Average Common and Common Equivalent Shares Outstanding(7):
Primary..................................................... 25.1 23.2 14.3 14.1 14.1 14.1
Fully diluted............................................... 25.1 24.7 19.1 18.8 18.8 18.8

CAPITAL EXPENDITURES
Refining and Marketing...................................... $ 9.3 32.0 7.1 3.7 .8 4.4
Exploration and Production
Oil and gas producing..................................... 53.2 60.4 28.6 9.3 3.0 19.3
Gas transportation........................................ .2 5.2 .7 -- -- --
Other....................................................... 1.2 2.0 1.1 2.4 .1 .8
------ ----- ----- ----- ------ ------
Total Capital Expenditures............................ $ 63.9 99.6 37.5 15.4 3.9 24.5
====== ===== ===== ===== ====== ======
BALANCE SHEET AND OTHER DATA
Total Assets.................................................. $519.2 484.4 434.5 446.7 494.7 496.8
Working Capital............................................... $ 77.5 85.9 124.5 122.6 106.1 95.4
Long-Term Debt and Other Obligations, Less Current
Portion(7).................................................. $155.0 192.2 180.7 175.5 130.3 127.0
Redeemable Preferred Stock(7)................................. $ -- -- 78.1 71.7 57.4 57.4
Common Stock and Other Stockholders' Equity(7)(8)............. $216.5 160.7 58.5 50.7 137.0 137.4

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

* Anti-dilutive.

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(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 N and Q of Notes to Consolidated Financial
Statements in Item 8.
(3) Amounts previously reported have been restated for certain reclassifications
between revenues and operating expenses.
(4) Intersegment eliminations represented sales from Refining and Marketing to
Marine Services (formerly Oil Field Supply and Distribution), at prices
which approximated market.
(5) Segment operating profit represents pretax earnings (loss) before certain
corporate expenses, interest income and interest expense. Operating profit
from Exploration and Production in 1995 included a gain of approximately $33
million from the sale of certain interests in the Bob West Field (see Note B
of Notes to Consolidated Financial Statements in Item 8).
(6) Net earnings for 1995 and 1994 included extraordinary losses of $2.9 million
and $4.8 million, respectively, related to early extinguishments of debt.
The net loss for 1992 included a charge of $20.6 million for the cumulative
effect of the adoption of SFAS No. 106, "Employer's Accounting for
Postretirement Benefits Other Than Pensions," and SFAS No. 109, "Accounting
for Income Taxes."
(7) For information on the Company's recapitalization and equity offering in
1994, see Note H of Notes to Consolidated Financial Statements in Item 8.
(8) No dividends were paid on common shares during the periods presented above.

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

RESULTS OF OPERATIONS

Net earnings of $54.6 million ($2.18 per share) in 1995 compare to $15.7
million ($.56 per share) in 1994. Noncash extraordinary losses on
extinguishments of debt amounted to $2.9 million ($.11 per share) in 1995 and
$4.8 million ($.21 per share) in 1994, both relating to early redemptions of the
Company's 12 3/4% Subordinated Debentures ("Subordinated Debentures"). Earnings
before extraordinary loss amounted to $57.5 million ($2.29 per share) in 1995
and $20.5 million ($.77 per share) in 1994. Net earnings for 1994 were reduced
by $2.7 million of dividend requirements on preferred stock. Comparability
between 1995 and 1994 was further impacted by certain significant transactions.
Earnings for 1995 included an after-tax gain of approximately $33 million from
the sale of certain interests in the Bob West Field in South Texas and a charge
of approximately $5 million for employee terminations and other restructuring
costs. During 1994, earnings 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. Excluding these
significant transactions from both years, the improvement in net earnings of
approximately $12 million in 1995 was primarily attributable to increased
natural gas production from the Company's exploration and production operations
in South Texas and improvements in the Company's refining and marketing
operations, in spite of difficult industry conditions that prevailed throughout
most of the year.

Net earnings of $15.7 million ($.56 per share) in 1994 compare with $17.0
million ($.54 per share) in 1993. Earnings before the extraordinary loss in 1994
were $20.5 million ($.77 per share). As described above, earnings in 1994
benefited from a refund received in settlement of a tariff dispute and a gain
from the sale of assets, partially offset by net charges related to
environmental contingencies and other matters. During 1993, the Company's
earnings benefited from the resolutions 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 to satisfy the initial sinking fund requirement on such
debt. Excluding these transactions, 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.

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

25
26

Company. The Company conducts its operations in the following business segments:
Refining and Marketing; Exploration and Production; and Marine Services
(formerly Oil Field Supply and Distribution).

REFINING AND MARKETING

1995 1994 1993
------- ------- -------
(DOLLARS IN MILLIONS EXCEPT
PER BARREL AMOUNTS)

GROSS OPERATING REVENUES
Refined products................................................ $ 664.5 582.7 590.9
Other, primarily crude oil resales and merchandise.............. 106.5 104.3 96.3
------- ------- -------
Gross Operating Revenues..................................... $ 771.0 687.0 687.2
======= ======= =======
OPERATING PROFIT
Gross margin -- refined products................................ $ 85.3 85.3 89.4
Gross margin -- other........................................... 12.3 13.1 13.2
------- ------- -------
Gross margin................................................. 97.6 98.4 102.6
Operating expenses.............................................. 84.7 88.2 76.9
Depreciation and amortization................................... 11.9 10.4 10.3
Other, including gain on asset sales............................ .3 (2.6) .2
------- ------- -------
Operating Profit............................................. $ .7 2.4 15.2
======= ======= =======
CAPITAL EXPENDITURES.............................................. $ 9.3 32.0 7.1
======= ======= =======
REFINERY OPERATIONS -- THROUGHPUT (average daily barrels)......... 50,569 46,032 49,753
======= ======= =======
REFINERY OPERATIONS -- PRODUCTION (average daily barrels)
Gasoline........................................................ 14,298 11,728 12,021
Middle distillates and other.................................... 23,182 20,615 21,487
Heavy oils and residual products................................ 14,516 15,118 17,573
------- ------- -------
Total Refinery Production.................................... 51,996 47,461 51,081
======= ======= =======
REFINERY OPERATIONS -- PRODUCT SPREAD ($/barrel)
Average yield value of products manufactured.................... $ 20.35 19.48 20.11
Cost of raw materials........................................... 16.88 15.65 15.73
------- ------- -------
Refinery Product Spread...................................... $ 3.47 3.83 4.38
======= ======= =======
REFINING AND MARKETING -- TOTAL PRODUCT SALES (average daily
barrels)
Gasoline........................................................ 24,526 23,191 22,466
Middle distillates.............................................. 37,988 33,256 29,354
Heavy oils and residual products................................ 14,787 14,228 16,945
------- ------- -------
Total Product Sales.......................................... 77,301 70,675 68,765
======= ======= =======
REFINING AND MARKETING -- TOTAL PRODUCT SALES PRICES ($/barrel)
Gasoline........................................................ $ 28.21 27.03 27.82
Middle distillates.............................................. $ 24.40 24.47 27.39
Heavy oils and residual products................................ $ 13.66 10.93 11.19

REFINING AND MARKETING -- GROSS MARGINS ON TOTAL PRODUCT SALES
($/barrel)
Average sales price............................................. $ 23.55 22.59 23.54
Average costs of sales*......................................... 20.53 19.67 19.98
------- ------- -------
Gross margin................................................. $ 3.02 2.92 3.56
======= ======= =======

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

* 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.

26
27

Sources of total product sales include products manufactured at the
refinery, 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 margin on total product sales presented
above. During 1995, 1994 and 1993, the Company's purchases of refined products
for resale approximated 25,500, 27,200 and 19,300 average daily barrels,
respectively. The refinery product spread presented above represents the excess
of yield value of the products manufactured at the refinery over the cost of raw
materials used to manufacture such products.

1995 Compared to 1994. The Refining and Marketing segment attained
operating profit of $.7 million in 1995, despite industry refining margins that
were among the lowest in a decade. These results compare with operating profit
of $2.4 million in 1994, which benefited from an $8.5 million refund received in
settlement of a tariff dispute, a gain of $2.4 million from the sale of assets
and favorable feedstock cost adjustments of $1.5 million, partially offset by
$6.6 million for environmental contingencies and other matters. There were no
comparable significant transactions recorded in 1995. Excluding these items from
1994, operating profit in 1995 reflected an improvement of $4.1 million from the
1994 operating results.

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

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

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

Revenues from sales of refined products in 1995 were higher than in 1994
due to higher sales prices and the increase in sales volumes. To optimize the
refinery's feedstock mix and in response to market conditions, the Company at
times resells previously purchased crude oil which aggregated $75.8 million in
1995 and $72.3 million in 1994. Costs of sales were higher in 1995 due to higher
volumes and prices. Operating expenses decreased by $3.5 million in 1995
primarily due to lower environmental costs, partly offset by increased employee
costs and fuels and utilities expense. Depreciation and amortization increased
by $1.5 million in 1995 due to capital additions, primarily the vacuum unit,
completed in late 1994. Included in 1994 was a $2.4 million gain from the sale
of assets.

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 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

27
28

results was primarily attributable to lower gross margins on sales of refined
products, which fell to $2.92 per barrel in 1994, from $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 to $62.1
million in 1993. 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 improved 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. During 1994, the Company reduced its average
daily refinery throughput and production by 7% from the 1993 levels. 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 in 1994,
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 East markets. These markets
had generally been weak for 1994 and the past several years due to a global
oversupply of this product.

EXPLORATION AND PRODUCTION

1995 1994 1993
-------- ------ ------
(DOLLARS IN MILLIONS EXCEPT
PER UNIT AMOUNTS)

U.S. OIL AND GAS
Gross operating revenues(1)(2)............................... $ 107.3 87.5 48.4
Production costs(2).......................................... 12.0 9.0 4.7
Other operating expenses..................................... 2.9 2.3 1.2
Depreciation, depletion and amortization..................... 29.0 24.1 11.1
Gain on sale of assets....................................... 33.5 -- --
-------- ------ ------
Operating Profit -- U.S. Oil and Gas...................... 96.9 52.1 31.4
-------- ------ ------
U.S. GAS TRANSPORTATION
Gross operating revenues..................................... 5.7 3.1 1.0
Operating expenses........................................... .3 -- .1
Depreciation and amortization................................ .3 .2 --
-------- ------ ------
Operating Profit -- U.S. Gas Transportation............... 5.1 2.9 .9
-------- ------ ------
BOLIVIA
Gross operating revenues..................................... 11.7 13.2 12.6
Production costs............................................. .6 .6 1.2
Other operating expenses..................................... 3.2 3.3 3.0
Depreciation, depletion and amortization..................... .3 -- --
-------- ------ ------
Operating Profit -- Bolivia............................... 7.6 9.3 8.4
-------- ------ ------
TOTAL OPERATING PROFIT -- EXPLORATION AND PRODUCTION........... $ 109.6 64.3 40.7
======== ====== ======
U.S.
Capital expenditures (including U.S. gas transportation)..... $ 49.6 65.6 29.3
======== ====== ======
Net natural gas production (average daily Mcf) --
Spot market and other..................................... 94,668 65,841 28,168
Tennessee Gas Contract(1)................................. 19,822 17,955 10,599
-------- ------ ------
Total Production..................................... 114,490 83,796 38,767
======== ====== ======

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29

1995 1994 1993
-------- ------ ------
(DOLLARS IN MILLIONS EXCEPT
PER UNIT AMOUNTS)

Average natural gas sales price per Mcf(2) --
Spot market............................................... $ 1.34 1.48 1.89
Tennessee Gas Contract(1)................................. $ 8.41 7.93 7.51
Average................................................... $ 2.57 2.86 3.43
Average production costs per Mcf(2)(3)....................... $ .29 .29 .34
Total operating expenses per Mcf............................. $ .35 .37 .42
Depletion per Mcf............................................ $ .69 .79 .78
BOLIVIA
Capital expenditures......................................... $ 3.8 -- --
Net natural gas production (average daily Mcf)............... 18,650 22,082 19,232
Average natural gas sales price per Mcf...................... $ 1.28 1.20 1.22
Net crude oil (condensate) production (average daily
barrels).................................................. 567 733 663
Average crude oil price per barrel........................... $ 14.39 13.28 14.26
Average production costs per net equivalent Mcf.............. $ .07 .06 .14
Total operating expenses per net equivalent Mcf.............. $ .48 .41 .50

- ---------------
(1) The Company is involved in litigation with Tennessee Gas Pipeline Company
("Tennessee Gas") relating to a natural gas sales contract ("Tennessee Gas
Contract"). See "Capital Resources and Liquidity -- Tennessee Gas Contract"
and Notes N and Q of Notes to Consolidated Financial Statements in Item 8.

(2) Amounts previously reported have been restated for certain
reclassifications between revenues and operating expenses.

(3) Production costs for the Company's U.S. operations include such items as
severance taxes, property taxes, insurance and materials and supplies.
Since severance taxes are based upon sales prices of natural gas, the
average production costs presented above include the impact of above-market
prices for sales under the Tennessee Gas Contract. Production costs per Mcf
of natural gas sold in the spot market were approximately $.20, $.20 and
$.23 for 1995, 1994 and 1993, respectively.

EXPLORATION AND PRODUCTION -- UNITED STATES

1995 Compared to 1994. Operating profit of $96.9 million in 1995 from the
Company's U.S. oil and gas operations included a gain of approximately $33
million from the sale of certain interests in the Bob West Field. Excluding this
gain, operating profit from these operations would have been approximately $63
million in 1995 compared with $52 million in 1994, reflecting a continued
successful drilling program which resulted in an increase in the Company's U.S.
natural gas production in South Texas. After the sale of certain Bob West Field
interests in September 1995, which included interests in 14 gross producing
wells, the number of wells in which the Company had an interest was reduced to
57 at year-end 1995, compared with 48 producing wells at year-end 1994. The
Company's U.S. natural gas production sold into the spot market increased by 44%
and production sold under the Tennessee Gas Contract increased by 10%. Revenues
increased by $20 million due to these increases in production, but were
partially offset by lower spot market natural gas sales prices. The Company's
weighted average sales price decreased to $2.57 per Mcf during 1995 from $2.86
per Mcf in 1994, reflecting lower spot market sales prices and a lower
percentage of production sold to Tennessee Gas at above-market prices. In 1995,
approximately 17% of the Company's total U.S. production was sold to Tennessee
Gas, compared to 21% in 1994 and 27% in 1993. The Company recognizes revenues
for sales to Tennessee Gas based on a contract price, which exceeded a
nonrefundable cash price by an aggregate of $41 million, net of severance taxes,
in 1995. Total production costs and other operating expenses were higher in 1995
due to the increased production levels and severance taxes related to the
above-market pricing of sales to Tennessee Gas, but were relatively unchanged on
a per Mcf basis. The impact of the increased production volumes on depletion
expense was substantially offset by a 13% reduction in the depletion rate

29
30

which resulted from additions to proved reserves during the year and elimination
of proportionately higher future development costs on the reserves sold in the
Bob West Field.

In 1995, operating results from the Exploration and Production segment
included natural gas production of approximately 24 Mmcf per day, revenues of
$11 million and operating profit of $4 million related to the interests that
were sold in the Bob West Field. For further information regarding the sale of
these interests, see Note B of Notes to Consolidated Financial Statements in
Item 8.

Under the terms of a bond posting related to the Tennessee Gas litigation,
Tennessee Gas must until April 30, 1996 take at least its entire monthly
take-or-pay obligation and pay for gas taken at $3.00 per Mmbtu. Without the
bonding arrangements associated with the litigation, Tennessee Gas could 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, subject to the provisions of the bond posting. 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 the bond posting. See
"Capital Resources and Liquidity -- Tennessee Gas Contract" and Notes N and Q of
Notes to Consolidated Financial Statements in Item 8.

The Company enters into commodity price swap agreements to reduce the risk
caused by fluctuations in the prices of natural gas in the spot market. During
1995 and 1994, the Company used such arrangements to set the price of 38% and
11%, respectively, of the natural gas production that it sold in the spot
market. During each of the years 1995 and 1994, the Company realized net gains
in gas revenues of approximately $.3 million from these price swap arrangements.
These gains had the effect of adding $.01 per Mcf to the Company's average spot
market sales price for 1995 and 1994. As of January 9, 1996, the Company had
entered into such price swaps for 1996 production totaling 8.4 billion cubic
feet for an average Houston Ship Channel price of $1.77 per Mcf. In 1995, the
Company's average spot market wellhead price per Mcf was $.25 less than the
average Houston Ship Channel index, the difference representing transportation
and marketing costs from the wellhead in South Texas. For further information on
the Company's natural gas price swap agreements, see Note P of Notes to
Consolidated Financial Statements in Item 8.

In addition to the natural gas producing activities, during 1995 the
Company's results included revenues of $5.7 million and operating profit of $5.1
million for transportation of natural gas to common carrier pipelines in the
South Texas area, of which approximately 51% relates to transportation of the
Company's production. The increase in these results in 1995, compared to 1994,
was due to higher transmission volumes stemming primarily from the development
of the Bob West Field together with an expansion of the pipeline in mid-1994.

1994 Compared to 1993. The number of producing wells in which the Company
has a working interest increased to 48 at year-end 1994, compared with 26 at the
end of 1993, resulting in a 116% increase in the Company's U.S. natural gas
production. Revenues from the U.S. oil and gas operations increased by $39.1
million in 1994 primarily due to the increased production. However, revenues
were adversely impacted by a 17% decline in the weighted average sales price of
natural gas, which included a 22% 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
production costs and depreciation, depletion and amortization were higher in
1994 due to the increased production level.

Operating results from the Company's natural gas transportation operations
increased by $2.0 million due to higher transmission volumes associated with the
increased production levels in South Texas. Transportation of the Company's
production accounted for approximately 58% and 74% of these results in 1994 and
1993, respectively.

30
31

EXPLORATION AND PRODUCTION -- BOLIVIA

1995 Compared to 1994. Operating profit from the Company's Bolivian
operations decreased by $1.7 million in 1995, reflecting a 16% decrease in net
natural gas production. During 1994, the Company had benefited from higher
levels of production due to the inability of another producer to satisfy gas
supply requirements. Partially offsetting the decrease in production in 1995
were increases in the average prices of natural gas and condensate production.
The Company's Bolivian natural gas production is sold to Yacimientos
Petroliferos Fiscales Bolivianos ("YPFB"), which in turn sells the natural gas
to Yacimientos Petroliferos Fiscales, S.A. ("YPF"), a publicly-held company
based in Argentina. During 1994, the contract between YPFB and YPF was extended
through March 31, 1997, maintaining approximately the same volumes as the
previous contract. Currently, the Company is selling its natural gas production
to YPFB based on the volume and pricing terms in the contract between YPFB and
YPF.

1994 Compared to 1993. 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.

MARINE SERVICES

1995 1994 1993
------ ----- -----
(DOLLARS IN MILLIONS)

Gross Operating Revenues........................................... $ 74.5 77.9 80.7
Costs of Sales..................................................... 64.9 67.5 68.4
------ ----- -----
Gross Margin..................................................... 9.6 10.4 12.3
Operating and Other Expenses....................................... 13.7 12.4 15.5
Depreciation and Amortization...................................... .3 .3 .4
------ ----- -----
Operating Loss................................................... $ (4.4) (2.3) (3.6)
====== ===== =====
Capital Expenditures............................................... $ .4 .2 .3
====== ===== =====
Refined Product Sales (average daily barrels)...................... 7,336 7,774 7,368
====== ===== =====

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

In February 1996, the Company purchased 100% of the outstanding capital
stock of Coastwide Energy Services, Inc. ("Coastwide"). Coastwide is primarily a
provider of services and a wholesale distributor of diesel fuel and lubricants
to the offshore drilling industry in the Gulf of Mexico. The Company will
combine its remaining petroleum distribution operations with Coastwide, forming
a Marine Services segment. As a combined operation, the Marine Services segment
will consist of 20 terminals, primarily marine-based, and will provide a broad
range of products and logistical support services to the offshore drilling and
drilling-related businesses. On a pro forma basis, if the purchase would have
occurred at the beginning of 1995, the Coastwide operations would have added
approximately $40 million to the Company's 1995 revenues. For additional
information on this acquisition, see Note B of Notes to Consolidated Financial
Statements in Item 8.

1994 Compared to 1993. Although sales volumes of refined products
increased by 6% in 1994, sales prices and gross margins were impacted by strong
competition in an oversupplied market. By consolidating certain of the Company's
terminals and discontinuing the environmental products marketing operations,
operating and other expenses 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.

31
32

GENERAL AND ADMINISTRATIVE EXPENSES

General and administrative expenses of $16.4 million in 1995 compare with
$14.7 million in 1994 and $16.7 million in 1993. The increase in 1995 was
primarily due to higher employee and other benefit costs. The decrease in 1994,
compared to 1993, was principally due to lower expenses resulting from cost
reduction measures previously implemented at the Company.

INTEREST EXPENSE

Interest expense of $20.9 million in 1995 compares with $18.7 million in
1994 and $14.5 million in 1993. The increase in 1995, compared with 1994, was
primarily due to interest on the vacuum unit financing and cash borrowings under
the Revolving Credit Facility during 1995 and interest capitalized in 1994
related to the construction of the vacuum unit. As discussed in Notes H and I of
Notes to Consolidated Financial Statements, in December 1995, the Company
redeemed $34.6 million of its Subordinated Debentures which, together with lower
borrowings under the Company's Revolving Credit Facility, are expected to result
in future annual interest expense savings of approximately $5 million. The
increase in 1994, compared with 1993, 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 of capitalized
interest in 1994.

OTHER EXPENSE

Other expense of $8.5 million in 1995 compares with $7.4 million in 1994
and $4.2 million in 1993. The increase in 1995, compared with 1994, was
primarily due to severance costs and related benefits of $3.8 million resulting
from a reduction in administrative workforce and other employee terminations
(see Note J of Notes to Consolidated Financial Statements in Item 8), partially
offset by lower environmental and other expenses related to the Company's former
operations. The increase in 1994, compared with 1993, was primarily due to
higher environmental and other costs associated with the Company's former
operations and to a gain of $1.4 million recorded in 1993 for the extinguishment
of debt.

INCOME TAXES

Income taxes of $4.4 million in 1995 compare with $5.6 million in 1994 and
$1.7 million in 1993. The decrease in 1995 was primarily due to lower state
income taxes. No income taxes were provided on the gain on sales of assets
during 1995 due to the utilization of previously unrecognized net operating
losses and other carryforwards. 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.

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 used
for refinery feedstocks and the price of refined products can result in a change
in gross margin from the refining and marketing operations, as prices received
for refined products may or may not keep pace with changes in crude oil costs.
These energy prices, together with volume levels, also determine the carrying
value of crude oil and refined product inventory.

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. From time to time, the Company may
increase or decrease its natural gas production in response to market
conditions. 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.

CAPITAL RESOURCES AND LIQUIDITY

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 liquidity and capital
resources are significantly impacted by changes in the supply of and demand for
crude oil, natural

32
33

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 its natural gas or
refined products and the resulting future impact on earnings and cash flows. The
Company's future capital expenditures, borrowings under its credit arrangements
and other sources of capital will be affected by these conditions. Although the
Company expects continued market improvement, the Company's operations in the
past have been adversely affected by depressed market conditions.

The Company continues to assess its existing asset base in order to
maximize returns and financial flexibility through diversification, acquisitions
and divestitures in all of its operating segments. This ongoing assessment
includes, in the Exploration and Production segment, evaluating ways in which
the Company might diversify the mix of its oil and gas assets and reduce the
asset concentration associated with the Bob West Field. In the Refining and
Marketing segment, the Company has been engaged in an ongoing effort to evaluate
these assets and operations and has considered possible joint ventures,
strategic alliances or business combinations; however, such evaluations have not
resulted in any transaction. The Company continues to assess its Marine Services
segment, pursuing opportunities to consolidate operations and improve
efficiencies. As a result of this ongoing assessment, the Company has taken two
significant steps in 1995:

o In September 1995, the Company sold certain interests in the Bob West
Field which would have required approximately $19 million of capital
expenditures for future development of proven reserves. Net proceeds from
the sale of these interests in the Bob West Field were used to redeem
$34.6 million of the Company's outstanding Subordinated Debentures, reduce
borrowings under its Revolving Credit Facility and improve corporate
liquidity (see Notes B and I of Notes to Consolidated Financial Statements
in Item 8).

o During 1995, the Company restructured certain operations in its former
Oil Field Supply and Distribution segment by exiting the land-based
portion of its petroleum product distribution business, and in February
1996 the Company acquired Coastwide and combined these operations with the
Company's remaining oil field supply and distribution operations. At
closing, consideration for the stock of Coastwide includes 946,883 shares
of Tesoro's Common Stock and approximately $5.9 million in cash. The
market price of Tesoro's Common Stock was $9.00 per share at closing of
this transaction. Upon exchange of Coastwide's remaining warrants, options
and convertible debentures, the Company will issue approximately 440,000
additional shares of Tesoro's Common Stock and pay $1.8 million in cash.

CREDIT ARRANGEMENTS

The Company has financing and credit arrangements under a three-year
corporate Revolving Credit Facility ("Facility") dated April 20, 1994, with a
consortium of ten banks. The 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 and (ii) cash borrowings up to the amount of the borrowing base
attributable to domestic oil and gas reserves. Outstanding obligations under the
Facility are secured by liens on substantially all of the Company's trade
accounts receivable and product inventory and by mortgages on the Company's
refinery and South Texas natural gas reserves. Under the terms of the Facility,
which has been amended from time to time, the Company is required to maintain
specified levels of working capital, tangible net worth, consolidated cash flow
and refining and marketing cash flow, as defined. Among other matters, the
Facility contains certain restrictions with respect to (i) capital expenditures,
(ii) incurrence of additional indebtedness, and (iii) dividends on capital
stock. The Facility contains other covenants customary in credit arrangements of
this kind. Future compliance with certain financial covenants is primarily
dependent on the Company's maintenance of specified levels of cash flows from
operations, capital expenditures, levels of borrowings and the value of the
Company's domestic oil and gas reserves. In October 1995, the Facility was
amended which, among other matters, (i) reduced available commitments from $100
million to $90 million, (ii) permitted the Company to redeem a portion of its
outstanding Subordinated Debentures, and (iii) reduced the required level

33
34

of refining and marketing cash flow. If the Company's refining and marketing
cash flow, as defined, does not meet required levels, the $90 million
availability will be incrementally reduced, but not below $80 million.

At December 31, 1995, the Company had available commitments under the
Facility of $90 million which included a domestic oil and gas reserve component
of $40 million. At December 31, 1995, the Company had outstanding letters of
credit under the Facility of approximately $50 million and no cash borrowings
outstanding, with remaining unused available commitments of $40 million. For the
year ended December 31, 1995, the Company's gross borrowings and repayments
under the Facility totaled $262 million, averaging approximately $6 million
outstanding per day, which were used on a short-term basis to finance working
capital requirements and capital expenditures.

DEBT AND OTHER OBLIGATIONS

On December 1, 1995, the Company redeemed $34.6 million of its outstanding
Subordinated Debentures at a price equal to 100% of the principal amount, plus
accrued interest to the redemption date. Following this partial redemption, all
future sinking fund requirements are satisfied and the Company has $30 million
principal amount of Subordinated Debentures outstanding, which is due March 15,
2001 and bears interest at 12-3/4% per annum. The Company's funded debt
obligations as of December 31, 1995 also included $44.1 million principal amount
of 13% Exchange Notes ("Exchange Notes") which bear interest at 13% per annum,
mature December 1, 2000 and have no sinking fund requirements. The Subordinated
Debentures and Exchange Notes are redeemable at the option of the Company at
100% of principal amount, plus accrued interest. The Company continuously
reviews financing alternatives with respect to its Subordinated Debentures and
Exchange Notes. However, there can be no assurance whether or when the Company
would propose other refinancings. During 1995, the Company reduced its ratio of
long-term debt to capitalization from 54% at year-end 1994 to 42% at year-end
1995.

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 limitation of dividend payments
included in the indenture governing the Exchange Notes is less restrictive than
the limitation imposed by the Subordinated Debentures. 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 on the volume of feedstock
processed at the Company's refinery. In 1995, 1994 and 1993, based on a per
barrel throughput charge of 16 cents, the Company's variable payments to the
State amounted to $2.9 million, $2.8 million and $2.6 million, respectively. The
per barrel charge increases to 24 cents in 1996 and to 30 cents in 1998 with one
cent annual incremental increases thereafter through 2001. In January 2002, the
Company is obligated to pay the State $60 million; provided, however, that such
payment may be deferred indefinitely by continuing the variable monthly payments
to the State beginning at 34 cents per barrel for 2002 and increasing one cent
per barrel annually thereafter. Variable monthly payments made after January
2002 will not reduce the $60 million obligation to the State. The $60 million
obligation is evidenced by a security bond, and the bond and the throughput
barrel obligations are secured by a mortgage on the Company's refinery. The
Company's obligations under the agreement with the State and the mortgage are
subordinated to current and future senior debt of up to $175 million plus any
indebtedness incurred subsequent to the date of the agreement to improve the
Company's refinery.

CAPITAL EXPENDITURES

Capital spending in 1995 amounted to $64 million, which was funded from
available cash reserves, cash flows from operations and borrowings under the
Facility. Capital expenditures for the Company's exploration and production
segment were approximately $53 million, or 83%, of total capital expenditures.
During 1995, the Company participated in the drilling of 17 development wells in
the Bob West Field and nine exploratory

34
35

wells in other areas of South Texas. Capital projects for the Company's refining
and marketing operations for 1995 totaled $9 million, primarily for capital
improvements at the refinery and expansion of the Company's retail locations in
Alaska and the Pacific Northwest.

For 1996, the Company has under consideration total capital expenditures of
approximately $51 million (excluding amounts related to the purchase of
Coastwide). The exploration and production segment accounts for $41 million, or
80%, of the budgeted expenditures with $36 million planned for U.S. activities
and $5 million for Bolivia. Planned U.S. expenditures include $21 million for
exploration, development and acquisition outside of the Bob West Field and $15
million for development of the Bob West Field which the Company expects to
substantially complete in 1996. As a result of the sale in September 1995 of
certain interests in the Bob West Field, the Company reduced future capital
expenditures by approximately $19 million which would otherwise have been
required to develop the proved reserves that were sold. In Bolivia, the drilling
program includes two exploratory wells, one of which is currently being tested.
Capital spending for the refining and marketing segment is projected to be $9
million, which includes amounts for installation of facilities to allow the
Company to begin producing and marketing asphalt in Alaska and for improvements
and upgrades at the Company's refinery and convenience store operations. Capital
expenditures for 1996 are expected to be financed through a combination of cash
flows from operations, available cash reserves and borrowings under the
Facility.

CASH FLOWS FROM OPERATING, INVESTING AND FINANCING ACTIVITIES

At December 31, 1995, the Company's net working capital totaled $77.5
million, which included cash and cash equivalents of $13.9 million. 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 N and Q of Notes to Consolidated Financial Statements
in Item 8. Components of the Company's cash flows are set forth below (in
millions):

1995 1994 1993
------ ----- -----

Cash Flows From (Used In):
Operating Activities..................................... $ 35.4 60.3 21.8
Investing Activities..................................... 2.4 (91.2) (23.4)
Financing Activities..................................... (37.9) 8.3 (8.7)
------ ----- -----
Decrease in Cash and Cash Equivalents...................... $ (.1) (22.6) (10.3)
====== ===== =====

During 1995, net cash from operating activities totaled $35 million,
compared with $60 million in 1994. Although natural gas production from the
Company's South Texas operations increased during 1995, lower cash receipts for
sales of natural gas adversely affected the Company's cash flows from
operations. Under a settlement agreement entered into in 1993, variable payments
to the State totaled $2.9 million in 1995. Net cash from investing activities of
$2 million in 1995 included proceeds of $70 million from sales of assets,
primarily certain interests in the Bob West Field, partially offset by $64
million of capital expenditures and $3 million for acquisition of the Kenai Pipe
Line Company ("KPL"). Net cash used in financing activities of $38 million in
1995 was primarily related to the redemption of $34.6 million of Subordinated
Debentures and other payments of long-term debt. The Company's gross borrowings
and repayments under the Facility totaled $262 million during 1995.

Net cash from operating activities increased to $60 million in 1994,
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 totaled $2.8 million in 1994. Net cash used in investing activities
of $91 million during 1994 included capital expenditures of $100 million, mainly
for exploration and production activities in the Bob West Field and installation
of the vacuum unit at the Company's refinery. During 1994, the Company
participated in the drilling of 20 development wells and two exploratory wells
in the Bob West Field and the expansion of the field's gas processing facilities
and pipelines. In addition, the Company participated in the drilling of five
exploratory wells and one unsuccessful

35
36

development well in other areas of South Texas. These uses of cash in investing
activities in 1994 were partially offset by a net decrease of $6 million in
short-term investments and cash proceeds of $3 million from sales of assets. Net
cash from financing activities of $8 million during 1994 included $15 million in
borrowings under the Vacuum Unit Loan and $4 million net proceeds from an equity
offering (see Note H 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. During 1994,
cash and cash equivalents decreased by $23 million.

During 1993, cash and cash equivalents decreased by $10 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 a settlement agreement 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 a 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.

TENNESSEE GAS CONTRACT

The Company is selling a portion of the gas produced from its Bob West
Field to Tennessee Gas Pipeline Company ("Tennessee Gas") under a Gas Purchase
and Sales Agreement ("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"). In
August 1990, 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 the month of December 1995, the Contract Price was in
excess of $8.60 per Mcf and the average spot market price was $1.84 per Mcf. For
the year ended December 31, 1995, approximately 17% of the Company's net U.S.
natural gas production was sold under the Tennessee Gas Contract. Tennessee Gas
also claimed that the contract should be considered an "output contract" under
Section 2.306 of the Texas Uniform Commercial Code ("UCC") 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 appellate court decision was the first decision reported in
Texas holding that a take-or-pay contract was an output contract. The Supreme
Court of Texas heard arguments in December 1994 regarding the output contract
issue and certain of the issues raised by Tennessee Gas. On August 1, 1995, the
Supreme Court of Texas, in a divided opinion, affirmed the decision of the
appellate court on all issues, including that the price under the Tennessee Gas
Contract is the Contract Price, and determined that the Tennessee Gas Contract
was an output contract and remanded the case to the trial court for
determination of whether gas volumes tendered by the Company to Tennessee Gas
were tendered in good faith and were not unreasonably

36
37

disproportionate to any normal or otherwise comparable prior output or stated
estimates in accordance with the UCC. The Company filed a motion for rehearing
before the Texas Supreme Court on the issue of whether the Tennessee Gas
Contract is an output contract. The Company believes that, if this issue is
tried, the gas volumes tendered to Tennessee Gas will be found to have been in
good faith and otherwise in accordance with the requirements of the UCC.
However, there can be no assurance as to the ultimate outcome at trial.

In conjunction with the District Court judgment and on behalf of all
sellers under the Tennessee Gas Contract, Tennessee Gas is presently required to
post a supersede as bond in the amount of $206 million. Under the terms of this
bond, for the period September 17, 1994 through April 30, 1996, Tennessee Gas is
required to take at least its entire monthly take-or-pay obligation and pay for
gas taken at $3.00 per Mmbtu, which approximates $3.00 per Mcf ("Bond Price").
The $206 million bond represents an amount which together with anticipated sales
of natural gas at the Bond Price will equal the anticipated value of the
Tennessee Gas Contract from September 17, 1994 through April 30, 1996. Except
for the period September 17, 1994 through August 13, 1995, the difference
between the spot market price and the Bond Price is refundable in the event
Tennessee Gas ultimately prevails in the litigation. The Company retains the
right to receive the Contract Price for all gas sold to Tennessee Gas.

Through December 31, 1995, under the Tennessee Gas Contract, the Company
recognized cumulative net revenues in excess of spot market prices totaling
approximately $117.3 million. Of the $117.3 million incremental net revenues,
the Company has received $11.0 million that is nonrefundable and $55.6 million
which the Company could be required to repay in the event of an adverse ruling.
The remaining $50.7 million of incremental net revenues is classified in the
Company's Consolidated Balance Sheet as a noncurrent receivable at December 31,
1995 and represents the unpaid difference between the Contract Price and the
Bond Price as described above. An adverse outcome of this litigation could
require the Company to reverse as much as $106.3 million of the incremental
revenues and could require the Company to repay as much as $55.6 million for
amounts received above spot prices, plus interest if awarded by the court. For
further information concerning the Tennessee Gas Contract, see Note Q of Notes
to Consolidated Financial Statements in Item 8.

OTHER MATTERS

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 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. At
December 31, 1995, the Company's accruals for environmental matters, including
the alleged violations of the Clean Air Act, amounted to $9.9 million. Also
included in this amount is a noncurrent liability of approximately $4 million
for remediation of the KPL properties, which liability has been funded by the
former owners of KPL through a restricted escrow deposit. Based on currently
available information and 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 1996 of
approximately $3 million, primarily for the removal and upgrading of underground
storage tanks, and starting in 1996 approximately $8 million for the
installation of dike liners; however, the Company is applying for an alternate
compliance schedule, allowed for under the Alaska regulations, regarding dike
liner installation at the Company's Alaska facilities. This alternate schedule,
if granted, will allow the Company additional time to assess an alternate remedy
to the dike liner requirement, under Alaska environmental regulations.

37
38

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 N of Notes to Consolidated
Financial Statements in Item 8 and "Government Regulation and
Legislation -- United States -- Environmental Controls" in Item 1.

Crude Oil Purchase Contract

In 1995, the Company renegotiated a new three-year contract with the State
for the purchase of royalty crude oil covering the period January 1, 1996
through December 31, 1998. The new contract provides for the purchase of
approximately 40,000 barrels per day of ANS royalty crude oil, the primary
feedstock for the Company's refinery, and is priced at the weighted average
price reported to the State by a major North Slope producer of ANS crude oil as
valued at Pump Station No. 1 on the Trans Alaska Pipeline System. Under this
agreement, the Company is required to utilize in its refinery operations volumes
equal to at least 80% of the ANS crude oil to be purchased from the State. This
contract contains provisions that, under certain conditions, allow the Company
to temporarily or permanently reduce its purchase obligations. The Company's
previous contract with the State, for the purchase of approximately 40,000
barrels per day of ANS, expired on December 31, 1995.

Severance Tax Exemption

In February 1996, the Texas Railroad Commission certified substantially all
of the Company's reserves in the Bob West Field as high cost gas from a tight
formation. As a result of the certification, the Company anticipates that the
Texas Comptroller's office will exempt the Company's gas production from tight
formations in the Bob West Field from Texas severance taxes. If the severance
tax exemption is received from the Comptroller's office, the Company estimates
that the pretax present value of proved reserves as of December 31, 1995 will
increase by approximately $7.7 million and that the Company could be eligible
for a refund and tax credits for prior taxes paid of approximately $6 million.
The potential refund and tax credits have not been recorded in the Company's
financial statements. There is no assurance that the Company will receive the
exemption or related refund or tax credits. For further information on the
Company's reserves and standardized measure, see Note Q of Notes to Consolidated
Financial Statements in Item 8.

Other

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

RECENTLY ISSUED PRONOUNCEMENTS

The Company has adopted Statement of Financial Accounting Standards
("SFAS") No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of," which had no material impact on the
Company's financial condition or results of operations in 1995.

In October 1995, SFAS No. 123, "Accounting for Stock-Based Compensation,"
was issued which addresses the measurement of compensation expense for the
issuance of stock options. The Company has evaluated SFAS No. 123 and intends to
continue following APB Opinion No. 25 for expense recognition purposes, but will
expand its disclosures regarding the fair value of issuance of stock options as
required by SFAS No. 123 effective for the year ended December 31, 1996.

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39

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, 1995 and 1994, and the
related statements of consolidated operations, stockholders' equity and cash
flows for each of the three years in the period ended December 31, 1995. 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, 1995 and 1994, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1995, in conformity with generally accepted accounting principles.

DELOITTE & TOUCHE LLP

San Antonio, Texas
February 2, 1996
(February 20, 1996 as to Notes B and N)

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40

TESORO PETROLEUM CORPORATION

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

YEARS ENDED DECEMBER 31,
------------------------------
1995 1994 1993
---------- ------- -------

REVENUES
Refining and marketing........................................ $ 771,035 686,994 687,231
Exploration and production.................................... 124,670 103,773 62,038
Marine services............................................... 74,467 77,917 80,699
Gain on sales of assets and other............................. 32,711 3,259 456
---------- ------- -------
Total Revenues........................................ 1,002,883 871,943 830,424
---------- ------- -------
OPERATING COSTS AND EXPENSES
Refining and marketing........................................ 758,329 676,697 662,133
Exploration and production.................................... 19,055 15,302 10,171
Marine services............................................... 77,803 80,507 84,050
Depreciation, depletion and amortization...................... 41,776 35,041 21,793
---------- ------- -------
Total Operating Costs and Expenses.................... 896,963 807,547 778,147
---------- ------- -------
OPERATING PROFIT................................................ 105,920 64,396 52,277

General and Administrative...................................... (16,453) (14,750) (16,712)
Interest Expense, Net of Capitalized Interest................... (20,902) (18,749) (14,550)
Interest Income................................................. 1,845 2,522 1,803
Other Expense, Net.............................................. (8,542) (7,363) (4,165)
---------- ------- -------
EARNINGS BEFORE INCOME TAXES AND
EXTRAORDINARY LOSS ON EXTINGUISHMENT
OF DEBT....................................................... 61,868 26,056 18,653
Income Tax Provision............................................ 4,379 5,573 1,697
---------- ------- -------
EARNINGS BEFORE EXTRAORDINARY LOSS ON EXTINGUISHMENT OF DEBT.... 57,489 20,483 16,956
Extraordinary Loss on Extinguishment of Debt.................... (2,857) (4,752) --
---------- ------- -------
NET EARNINGS.................................................... 54,632 15,731 16,956
Dividend Requirements on Preferred Stock........................ -- 2,680 9,207
---------- ------- -------
NET EARNINGS APPLICABLE TO COMMON STOCK......................... $ 54,632 13,051 7,749
========== ======= =======
EARNINGS PER SHARE
Earnings Before Extraordinary Loss on Extinguishment of
Debt....................................................... $ 2.29 .77 .54
Extraordinary Loss on Extinguishment of Debt.................. (.11) (.21) --
---------- ------- -------
Net Earnings.................................................. $ 2.18 .56 .54
========== ======= =======
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES............ 25,107 23,196 14,290
========== ======= =======

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

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TESORO PETROLEUM CORPORATION

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

DECEMBER 31,
------------------
1995 1994
-------- -------

ASSETS
CURRENT ASSETS
Cash and cash equivalents............................................... $ 13,941 14,018
Receivables, less allowance for doubtful accounts....................... 77,534 91,140
Inventories............................................................. 80,453 68,302
Prepayments and other................................................... 10,536 8,648
-------- -------
Total Current Assets............................................ 182,464 182,108
-------- -------
PROPERTY, PLANT AND EQUIPMENT
Refining and marketing.................................................. 322,023 309,925
Exploration and production, full cost method of accounting:
Properties being amortized........................................... 119,836 131,930
Properties not yet evaluated......................................... 5,118 3,758
Gas transportation................................................... 6,703 6,543
Marine services......................................................... 12,757 14,689
Corporate............................................................... 12,443 12,271
-------- -------
478,880 479,116
Less accumulated depreciation, depletion and amortization............ 217,191 205,782
-------- -------
Net Property, Plant and Equipment............................... 261,689 273,334
-------- -------
RECEIVABLE FROM TENNESSEE GAS PIPELINE COMPANY............................ 50,680 --
-------- -------
OTHER ASSETS.............................................................. 24,320 28,918
-------- -------
Total Assets............................................... $519,153 484,360
======== =======
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable........................................................ $ 61,389 53,573
Accrued liabilities..................................................... 34,073 35,266
Current portion of long-term debt and other obligations................. 9,473 7,404
-------- -------
Total Current Liabilities....................................... 104,935 96,243
-------- -------
OTHER LIABILITIES......................................................... 42,697 35,175
-------- -------
LONG-TERM DEBT AND OTHER OBLIGATIONS, LESS CURRENT PORTION................ 155,007 192,210
-------- -------
COMMITMENTS AND CONTINGENCIES (Notes M and N)

STOCKHOLDERS' EQUITY
Preferred stock, no par value; authorized 5,000,000 shares including
redeemable preferred shares; none issued or outstanding
Common stock, par value $.16 2/3; authorized 50,000,000 shares;
24,780,134 shares issued and outstanding (24,389,801 in 1994)........ 4,130 4,065
Additional paid-in capital.............................................. 176,599 175,514
Retained earnings (accumulated deficit)................................. 35,785 (18,847)
-------- -------
Total Stockholders' Equity...................................... 216,514 160,732
-------- -------
Total Liabilities and Stockholders' Equity................. $519,153 484,360
======== =======

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

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TESORO PETROLEUM CORPORATION

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

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

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
options............. -- -- -- -- 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
options............. -- -- -- -- 36 7 285 --
------ -------- ------ ------- ------ ------ -------- --------
DECEMBER 31, 1994........ -- -- -- -- 24,390 4,065 175,514 (18,847)
Net earnings........... -- -- -- -- -- -- -- 54,632
Stock awards and
options............. -- -- -- -- 390 65 1,085 --
------ -------- ------ ------- ------ ------ -------- --------
DECEMBER 31, 1995........ -- $ -- -- $ -- 24,780 $4,130 $ 176,599 $ 35,785
====== ======== ====== ======= ====== ====== ======== ========

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

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43

TESORO PETROLEUM CORPORATION

STATEMENTS OF CONSOLIDATED CASH FLOWS
(IN THOUSANDS)

YEARS ENDED DECEMBER 31,
----------------------------
1995 1994 1993
-------- ------- -------

CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES
Net earnings................................................... $ 54,632 15,731 16,956
Adjustments to reconcile net earnings to net cash from
operating activities:
Depreciation, depletion and amortization.................... 42,620 36,016 22,591
Loss (gain) on extinguishment of debt....................... 2,857 4,752 (1,422)
Gain on sales of assets..................................... (32,659) (2,379) (60)
Amortization of deferred charges and other.................. 1,556 2,800 3,323
Changes in operating assets and liabilities:
Receivable from Tennessee Gas Pipeline Company............ (37,456) (13,224) --
Receivables, other trade.................................. 9,746 (7,279) 7,539
Inventories............................................... (11,599) 5,884 325
Other assets.............................................. (1,133) (1,808) (3,609)
Accounts payable and accrued liabilities.................. 4,605 20,567 (12,800)
Obligation payments to State of Alaska.................... (2,892) (2,754) (12,910)
Other liabilities and obligations......................... 5,136 1,991 1,901
-------- ------- -------
Net cash from operating activities..................... 35,413 60,297 21,834
-------- ------- -------
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES
Capital expenditures........................................... (63,930) (99,587) (37,451)
Proceeds from sales of assets.................................. 69,786 2,544 194
Sales of short-term investments................................ -- 7,926 40,314
Purchases of short-term investments............................ -- (1,974) (26,245)
Other.......................................................... (3,452) (50) (247)
-------- ------- -------
Net cash from (used in) investing activities........... 2,404 (91,141) (23,435)
-------- ------- -------
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES
Repurchase of debentures....................................... (34,634) -- (9,675)
Payments of long-term debt..................................... (2,979) (1,383) (1,643)
Net borrowings (repayments) under revolving credit
facilities.................................................. -- (5,000) 5,000
Issuance of long-term debt..................................... -- 15,000 --
Proceeds from issuance of common stock, net.................... -- 56,967 --
Repurchase of common and preferred stock....................... -- (52,948) --
Dividends on preferred stocks.................................. -- (1,684) --
Costs of Recapitalization and other............................ (281) (2,686) (2,354)
-------- ------- -------
Net cash from (used in) financing activities........... (37,894) 8,266 (8,672)
-------- ------- -------
DECREASE IN CASH AND CASH EQUIVALENTS............................ (77) (22,578) (10,273)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR................... 14,018 36,596 46,869
-------- ------- -------
CASH AND CASH EQUIVALENTS AT END OF YEAR......................... $ 13,941 14,018 36,596
======== ======= =======
SUPPLEMENTAL CASH FLOW DISCLOSURES
Interest paid, net of $915 capitalized in 1994................. $ 18,132 15,898 19,288
======== ======= =======
Income taxes paid.............................................. $ 4,046 5,361 5,125
======== ======= =======

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

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44

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
marine services.

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 that affect the
reported amounts of assets and liabilities and disclosures of contingent assets
and liabilities at the date of the financial statements and the reported amounts
of revenues and expenses during the year. Actual results could differ from those
estimates.

Certain previously reported amounts have been reclassified to conform with
the 1995 presentation.

CASH AND CASH EQUIVALENTS

Cash equivalents consist of highly-liquid debt instruments such as
commercial paper and certificates of deposit purchased with an original maturity
date of three months or less. Cash equivalents are stated at cost, which
approximates market value. The Company's policy is to invest cash in
conservative, highly-rated instruments and to invest in various institutions to
limit the amount of credit exposure in any one institution. The Company performs
ongoing evaluations of the credit standing of these financial institutions.

INVENTORIES

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.

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 33 years
Exploration and Production........................................ 3 years to 25 years
Marine Services................................................... 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
using the proved oil and gas reserves for each cost center. The Company's
investment in certain oil and gas properties is excluded from the amortization
base until the properties are evaluated. Gain or loss is recognized only on the
sale of oil and gas properties involving significant reserves. Proceeds from the
sale of insignificant reserves and undeveloped properties are applied to reduce
the costs in the cost centers.

44
45

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

INCOME TAXES

Deferred tax assets and liabilities are recognized for future income 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. 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.

ENVIRONMENTAL EXPENDITURES

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

FINANCIAL INSTRUMENTS

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

EARNINGS PER SHARE

Primary earnings per share is calculated on net earnings 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 per share was the same as primary earnings per share
since the assumed conversion of preferred stocks in 1994 and 1993 to common
shares would be anti-dilutive.

RECENTLY ISSUED PRONOUNCEMENTS

The Company adopted Statement of Financial Accounting Standards ("SFAS")
No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of," which had no material impact on the Company's
financial condition or results of operations in 1995.

45
46

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In October 1995, SFAS No. 123, "Accounting for Stock-Based Compensation,"
was issued which addresses the measurement of compensation expense for the
issuance of stock options. The Company has evaluated SFAS No. 123 and intends to
continue following APB Opinion No. 25 for expense recognition purposes, but will
expand its disclosures regarding the fair value of issuance of stock options as
required by SFAS No. 123 effective for the year ended December 31, 1996.

NOTE B -- ACQUISITIONS AND DIVESTITURES

In September 1995, the Company sold, effective April 1, 1995, certain
interests in its producing and non-producing oil and gas properties located in
the Bob West Field in South Texas. The interests sold included the Company's
approximate 55% net revenue interest and 70% working interest in Units C, D and
E and a convertible override in Unit F of the Bob West Field. These units do not
include acreage related to the Company's natural gas sales contract with
Tennessee Gas Pipeline Company, which, as discussed in Note N, is the subject of
current litigation. Also excluded from the sale were the Company's interests in
the State Park and Sanchez-O'Brien leases and the Ramirez USA E-6 well within
the Bob West Field. In total, the sale included interests in 14 gross producing
wells amounting to 77 Bcf, or 40%, of the Company's total net proved domestic
reserves at the time of the sale. Through the date of the sale, natural gas
production from the interests sold had contributed approximately $11 million to
revenues and $4 million to operating profit of the Company's Exploration and
Production segment for 1995. For information regarding changes in proved
domestic reserves, see Note Q. Consideration for the sale was $74 million, which
was adjusted on a preliminary basis for production, capital expenditures and
certain other items after the effective date to approximately $68 million in
cash received at closing, resulting in a gain of approximately $33 million in
the 1995 third quarter. The consideration received by the Company, which is
subject to final post-closing adjustments, was used to redeem $34.6 million of
the Company's outstanding 12 3/4% Subordinated Debentures, reduce borrowings
under the Company's Revolving Credit Facility and improve corporate liquidity
(see Note I). The Company does not expect any final post-closing adjustments to
be material.

In February 1996, the Company purchased 100% of the capital stock of
Coastwide Energy Services, Inc. ("Coastwide"). At closing, the consideration for
the stock of Coastwide includes 946,883 shares of Tesoro's Common Stock and $5.9
million in cash. The market price of Tesoro's Common Stock was $9.00 per share
at closing of this transaction. Upon exchange of Coastwide's remaining warrants,
options and convertible debentures, the Company will issue approximately 440,000
additional shares of Tesoro's Common Stock and pay $1.8 million in cash.
Coastwide is primarily a provider of services and a wholesale distributor of
diesel fuel and lubricants to the offshore drilling industry in the Gulf of
Mexico. The Company will combine its existing marine petroleum distribution
operations with Coastwide, forming a Marine Services segment. The acquisition of
Coastwide will be accounted for as a purchase in the first quarter of 1996.
Accordingly, the purchase price will be allocated to the net assets acquired
based upon their estimated fair values.

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

NOTE C -- BUSINESS SEGMENTS

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

Refining and Marketing includes the operations of the Company's refinery in
Kenai, Alaska, which produces gasoline, jet fuel, diesel fuel, 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

46
47

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 $75.8 million, $72.3 million and $62.1
million in 1995, 1994 and 1993, respectively. From time to time, Refining and
Marketing exports products to customers in Far East markets. Revenues from such
export sales amounted to $18.5 million, $5.2 million and $20.5 million in 1995,
1994 and 1993, respectively.

Exploration and Production is engaged in the exploration, development and
production of natural gas, primarily in the Wilcox Trend in South Texas and the
Chaco Basin in Bolivia. The majority of the Company's South Texas production
currently comes from the Bob West Field. See Notes N and Q for information
regarding a natural gas sales contract in the Bob West Field that is the subject
of litigation. In addition to natural gas producing activities, Exploration and
Production activities include the transportation of natural gas to common
carrier pipelines in the South Texas area, including transportation of the
Company's production. In Bolivia, the Company operates through an interest in a
joint venture agreement to explore for and produce hydrocarbons. The majority of
the Company's Bolivian natural gas and condensate reserves are shut-in awaiting
access to gas-consuming markets.

Marine Services, which includes operations previously reported as 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 1995,
the Company consolidated certain operations in this segment by exiting the
land-based portion of its petroleum product distribution business. In 1994, the
Company discontinued its environmental remediation products and services
operations formerly associated with this segment. With the recent acquisition of
Coastwide discussed in Note B, the Company will combine its remaining marine
petroleum distribution operations with Coastwide, forming a Marine Services
segment which will provide a broad range of products and logistical support
services to the offshore drilling and drilling-related businesses operating in
the Gulf of Mexico.

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
corporate general and administrative expenses are not included in determining
operating profit. Operating profit from the Exploration and Production segment
in 1995 included a gain of approximately $33 million from the sale of certain
interests in the Bob West Field. 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. Revenues previously reported for U.S. oil and gas and transportation
operations have been restated for certain reclassifications between revenues and
operating expenses.

47
48

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Identifiable assets are those assets utilized by the segment. Corporate
assets are principally cash, investments and other assets that cannot be
directly associated with the operations of a business segment.

YEARS ENDED DECEMBER 31,
--------------------------
1995 1994 1993
------ ----- -----
(IN MILLIONS)

GROSS OPERATING REVENUES
Refining and Marketing --
Refined products.............................................. $664.5 582.7 590.9
Other, primarily crude oil resales and merchandise............ 106.5 104.3 96.3
Exploration and Production --
U.S. oil and gas.............................................. 107.3 87.5 48.4
U.S. gas transportation....................................... 5.7 3.1 1.0
Bolivia....................................................... 11.7 13.2 12.6
Marine Services.................................................. 74.5 77.9 80.7
------ ----- -----
Total Gross Operating Revenues........................... $970.2 868.7 829.9
====== ===== =====
OPERATING PROFIT (LOSS), INCLUDING GAIN ON SALES OF ASSETS
Refining and Marketing........................................... $ .7 2.4 15.2
Exploration and Production --
U.S. oil and gas.............................................. 96.9 52.1 31.4
U.S. gas transportation....................................... 5.1 2.9 .9
Bolivia....................................................... 7.6 9.3 8.4
Marine Services.................................................. (4.4) (2.3) (3.6)
------ ----- -----
Total Operating Profit................................... 105.9 64.4 52.3
Corporate and Unallocated Costs.................................. (44.0) (38.3) (33.6)
------ ----- -----
Earnings Before Income Taxes and Extraordinary Loss.............. $ 61.9 26.1 18.7
====== ===== =====
IDENTIFIABLE ASSETS
Refining and Marketing........................................... $313.3 309.1 281.5
Exploration and Production --
U.S. oil and gas.............................................. 128.9 105.5 65.2
U.S. gas transportation....................................... 7.8 8.4 2.0
Bolivia....................................................... 17.8 11.1 6.5
Marine Services.................................................. 18.0 19.8 21.3
Corporate........................................................ 33.4 30.5 58.0
------ ----- -----
Total Assets............................................. $519.2 484.4 434.5
====== ===== =====
DEPRECIATION, DEPLETION AND AMORTIZATION
Refining and Marketing........................................... $ 11.9 10.4 10.3
Exploration and Production --
U.S. oil and gas.............................................. 29.0 24.1 11.1
U.S. gas transportation....................................... .3 .2 --
Bolivia....................................................... .3 -- --
Marine Services.................................................. .3 .3 .4
Corporate........................................................ .8 1.0 .8
------ ----- -----
Total Depreciation, Depletion and Amortization........... $ 42.6 36.0 22.6
====== ===== =====

48
49

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

YEARS ENDED DECEMBER 31,
--------------------------
1995 1994 1993
------ ----- -----
(IN MILLIONS)

CAPITAL EXPENDITURES
Refining and Marketing........................................... $ 9.3 32.0 7.1
Exploration and Production --
U.S. oil and gas.............................................. 49.4 60.4 28.6
U.S. gas transportation....................................... .2 5.2 .7
Bolivia....................................................... 3.8 -- --
Marine Services.................................................. .4 .2 .3
Corporate........................................................ .8 1.8 .8
------ ----- -----
Total Capital Expenditures............................... $ 63.9 99.6 37.5
====== ===== =====

NOTE D -- RECEIVABLES

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

YEARS ENDED DECEMBER 31,
--------------------------
1995 1994 1993
------ ----- -----

Balance at Beginning of Year............................... $1,816 2,487 2,587
Charged to Costs and Expenses.............................. 300 299 667
Recoveries of Amounts Previously Written Off and Other..... 122 (4) 71
Write-off of Doubtful Accounts............................. (396) (966) (838)
------ ----- -----
Balance at End of Year................................... $1,842 1,816 2,487
====== ===== =====

Receivables at December 31, 1994 included $13.2 million for sales under a
natural gas sales contract that is the subject of litigation, representing the
difference between a contract price and the price being received by the Company
under the terms of a court-ordered bonding arrangement. At December 31, 1995, a
receivable of $50.7 million related to this contract was classified as
noncurrent. For further information on this litigation, see Notes N and Q.

NOTE E -- INVENTORIES

Components of inventories at December 31, 1995 and 1994 were as follows (in
thousands):

DECEMBER 31,
-------------------
1995 1994
------- -------

Crude Oil and Wholesale Refined Products, at LIFO....................... $70,406 58,798
Merchandise and Retail Refined Products................................. 5,153 5,934
Materials and Supplies.................................................. 4,894 3,570
------ -----
Inventories........................................................... $80,453 68,302
======= ======

49
50

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

At December 31, 1995 and 1994, inventories valued using LIFO were lower
than replacement cost by approximately $3.8 million and $1.8 million,
respectively.

NOTE F -- ACCRUED LIABILITIES

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

DECEMBER 31,
------------------
1995 1994
------- ------

Accrued Environmental Costs....................................... $ 5,935 10,829
Accrued Interest.................................................. 2,879 4,223
Accrued Employee and Pension Costs................................ 6,839 7,884
Accrued Taxes..................................................... 3,910 3,242
Other............................................................. 14,510 9,088
------- ------
Accrued Liabilities............................................. $34,073 35,266
======= ======

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

DECEMBER 31,
------------------
1995 1994
------- ------

Accrued Postretirement Benefits................................... $28,706 26,131
Deferred Income Taxes............................................. 5,389 4,582
Accrued Environmental Costs....................................... 3,968 --
Other............................................................. 4,634 4,462
------- ------
Other Liabilities............................................... $42,697 35,175
======= ======

NOTE G -- INCOME TAXES

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

YEARS ENDED DECEMBER 31,
---------------------------
1995 1994 1993
------ ----- ------

Federal -- Current........................................ $ 708 700 --
Foreign................................................... 3,183 3,588 3,419
State..................................................... 488 1,285 (1,722)
------ ----- ------
Income Tax Provision.................................... $4,379 5,573 1,697
====== ===== ======

50
51

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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,
--------------------
1995 1994
-------- -------

Deferred Tax Assets:
Net operating losses available for utilization through the
year 2008.................................................. $ 29,695 16,921
Investment tax and other credits.............................. 9,762 8,196
Accrued postretirement benefits............................... 9,424 8,865
Settlement with the State of Alaska........................... 810 21,650
Settlement with Department of Energy.......................... 3,981 4,443
Other......................................................... 8,594 8,994
-------- -------
Total Deferred Tax Assets............................. 62,266 69,069
Deferred Tax Liabilities:
Receivable related to gas contract............................ (17,699) --
Accelerated depreciation and property-related items........... (39,734) (43,621)
-------- -------
Deferred Tax Assets Before Valuation Allowance.................. 4,833 25,448
Valuation Allowance............................................. (4,833) (25,448)
State Income and Other Taxes.................................... (5,389) (4,332)
Other........................................................... -- (250)
-------- -------
Net Deferred Tax Liability............................ $ (5,389) (4,582)
======== =======

The following tables set 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,
------------------------------
1995 1994 1993
-------- ------ ------

Earnings Before Income Taxes and Extraordinary Loss:
United States........................................ $ 55,221 18,336 10,906
Foreign.............................................. 6,647 7,720 7,747
-------- ------ ------
$ 61,868 26,056 18,653
======== ====== ======
Income Taxes at Statutory U.S. Corporate Tax Rate...... $ 21,654 9,120 6,529
Effect of:
Foreign income taxes................................. 3,183 3,588 3,419
State income taxes (benefit)......................... 488 1,285 (1,722)
Accounting recognition of operating loss tax
benefits.......................................... (20,615) (9,120) (6,529)
Other................................................ (331) 700 --
-------- ------ ------
Income Tax Provision................................. $ 4,379 5,573 1,697
======== ====== ======

At December 31, 1995, the Company's net operating loss carryforwards were
approximately $84.8 million for regular tax and approximately $71.0 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 2007. Also at December
31, 1995, 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.
Additionally, at December 31, 1995, the Company had approximately $1.6 million
of alternative minimum tax credit carryforwards to offset future regular tax
liabilities. There is no expiration date for these credits.

51
52

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

NOTE H -- RECAPITALIZATION AND EQUITY OFFERING

RECAPITALIZATION

In 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 a further redemption of debt in 1995, were as follows:

(i) The Company in February 1994 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, together
with the redemption of $34.6 million of Subordinated Debentures in 1995,
has satisfied all future sinking fund requirements resulting in $30 million
principal amount of Subordinated Debentures due in 2001 (see Note I). The
exchange of the Subordinated Debentures in 1994 and redemption in 1995 were
accounted for as early extinguishments of debt, resulting in charges in
1995 and 1994 of $2.9 million and $4.8 million, respectively, which
represented write-offs of unamortized bond discount and issue costs. No tax
benefits were available to offset the extraordinary losses 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 in 1994 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.

52
53

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.

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

NOTE I -- LONG-TERM DEBT AND OTHER OBLIGATIONS

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

DECEMBER 31,
--------------------
1995 1994
-------- -------

12 3/4% Subordinated Debentures due 2001........................ $ 27,806 59,146
13% Exchange Notes due 2000..................................... 44,116 44,116
Liability to State of Alaska.................................... 62,313 61,856
Vacuum Unit Loan................................................ 13,393 15,000
Liability to Department of Energy............................... 11,874 13,194
Industrial Revenue Bonds........................................ 1,654 2,385
Capital Lease Obligations (interest at 11%)..................... 2,693 3,540
Other........................................................... 631 377
-------- -------
164,480 199,614
Less Current Portion............................................ 9,473 7,404
-------- -------
$155,007 192,210
======== =======

Aggregate maturities of long-term debt and obligations for each of the five
years following December 31, 1995 are as follows (in thousands):

1996............................................................. $9,473
1997............................................................. $9,963
1998............................................................. $9,594
1999............................................................. $9,581
2000............................................................. $9,795

REVOLVING CREDIT FACILITY

The Company has financing and credit arrangements under a three-year
corporate Revolving Credit Facility ("Facility") dated April 20, 1994, with a
consortium of ten banks. The 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 and (ii) cash borrowings up to the amount of the borrowing base
attributable to domestic oil and gas reserves. Outstanding obligations under the
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

53
54

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

natural gas reserves. Under the terms of the Facility, which has been amended
from time to time, the Company is required to maintain specified levels of
working capital, tangible net worth, consolidated cash flow and refining and
marketing cash flow, as defined. Among other matters, the Facility contains
certain restrictions with respect to (i) capital expenditures, (ii) incurrence
of additional indebtedness, and (iii) dividends on capital stock. The Facility
contains other covenants customary in credit arrangements of this kind. Future
compliance with certain financial covenants is primarily dependent on the
Company's maintenance of specified levels of cash flows from operations, capital
expenditures, levels of borrowings and the value of the Company's domestic oil
and gas reserves. In October 1995, the Facility was amended which, among other
matters, (i) reduced available commitments from $100 million to $90 million,
(ii) permitted the Company to redeem a portion of its outstanding Subordinated
Debentures, and (iii) reduced the required level of refining and marketing cash
flow. If the Company's refining and marketing cash flow, as defined, does not
meet required levels, the $90 million availability will be incrementally
reduced, but not below $80 million.

At December 31, 1995, the Company had available commitments under the
Facility of $90 million which included a domestic oil and gas reserve component
of $40 million. At December 31, 1995, the Company had outstanding letters of
credit under the Facility of approximately $50 million and no cash borrowings
outstanding, with remaining unused available commitments of $40 million. For the
year ended December 31, 1995, the Company's gross borrowings and repayments
under the Facility totaled $262 million, averaging approximately $6 million
outstanding per day, which were used on a short-term basis to finance working
capital requirements and capital expenditures.

Under the Facility, 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 $40 million. 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 fixed charge coverage ratio, as defined, while the excess of
total available commitments over cash borrowings and outstanding letters of
credit incur fees of one-half of 1% per annum. Cash borrowings under the
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 (i) 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%, or (ii) the Eurodollar rate,
as defined, plus an additional percentage ranging from 1.25% to 2.25%, depending
upon the Company's cash flow coverage ratio, as defined in the Facility.

VACUUM UNIT LOAN

In 1994, the National Bank of Alaska and the Alaska Industrial Development
& Export Authority provided 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 equal quarterly payments of
approximately $536,000 and bears interest at the unsecured 90-day commercial
paper rate, adjusted quarterly, plus 2.6% per annum (8.42% at December 31, 1995)
for two-thirds of the amount borrowed and at the National Bank of Alaska
floating prime rate plus one-fourth of 1% per annum (8.75% at December 31, 1995)
for the remainder. The Vacuum Unit Loan is secured by a first lien on the
Company's refinery. The Vacuum Unit Loan contains covenants and restrictions
similar to those under the Facility. At December 31, 1995, the Company satisfied
all of its covenants except for an annual refinery cash flow requirement, as
defined in the Vacuum Unit Loan agreement. The lenders waived this refinery cash
flow requirement for the year ended December 31, 1995.

54
55

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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
Subordinated 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 in
January 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, satisfied sinking fund requirements for
the Subordinated Debentures through 1997. In December 1995, the Company redeemed
$34.6 million of its outstanding Subordinated Debentures. Following this
redemption, which satisfied all future sinking fund requirements, the Company
has $30 million principal amount of outstanding Subordinated Debentures due
2001. See Note H for further information on the Recapitalization and redemption
of debt. At December 31, 1995 and 1994, Subordinated Debt amounted to $27.8
million (net of discount of $2.2 million) and $59.1 million (net of discount of
$5.5 million), respectively. The indenture contains restrictions on payment of
dividends on the Company's Common Stock and purchases or redemptions of any of
its capital stock. Due to losses in prior years, as of December 31, 1995, the
Company must generate approximately $60 million of future net earnings
applicable to Common Stock or from the issuance of capital stock before future
dividends can be paid on Common Stock or before purchases or redemptions can be
made of capital stock.

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 1993, the Company entered into an agreement ("Agreement") with the State
of Alaska ("State") that settled a contractual dispute with the State. Under the
Agreement, the Company 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 on the volume of feedstock processed at the
Company's refinery. In 1995, 1994 and 1993, based on a per barrel throughput
charge of 16 cents, the Company's variable payments to the State totaled $2.9
million, $2.8 million and $2.6 million, respectively. The per barrel charge
increases to 24 cents in 1996 and to 30 cents in 1998 with one cent annual
incremental increases thereafter through 2001. In January 2002, the Company is
obligated to pay the State $60 million; provided, however, that such payment may
be deferred indefinitely by continuing the variable monthly payments to the
State beginning at 34 cents per barrel for 2002 and increasing one cent per
barrel annually thereafter. Variable monthly payments made after January 2002
will not reduce the $60 million obligation to the State. The imputed rate of
interest used by the Company on the $60 million obligation was 13%. The $60
million obligation is evidenced by a security bond, and the bond and the
throughput barrel obligations are secured by a mortgage on the Company's
refinery. The Company's obligations under the Agreement and the mortgage are
subordinated to current and future senior debt of up to $175 million plus any
indebtedness incurred subsequent to the date of the Agreement to improve the
Company's refinery.

55
56

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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, 1995, the Company had paid $44.2 million to the
DOE since 1989. The Company's remaining obligation is to pay $11.9 million,
exclusive of interest at 6%, over the next seven 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, 1995), 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 $6.1 million at December 31,
1995.

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, 1995 included assets held under capital leases of $5.2 million with
a net book value of $1.2 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. The Company's funding policy is to make contributions at a minimum
in accordance with the requirements of applicable laws and regulations, but no
more than the amount deductible for income tax purposes. The components of net
pension expense for the Company's retirement plan are presented below (in
thousands):

YEARS ENDED DECEMBER 31,
------------------------------
1995 1994 1993
------- ------ -------

Service Costs........................................... $ 1,147 1,121 931
Interest Cost........................................... 3,549 3,351 3,513
Actual Return on Plan Assets............................ (8,299) (217) (5,695)
Net Amortization and Deferral........................... 4,288 (3,408) 1,488
------ ------ ------
Net Pension Expense................................... $ 685 847 237
====== ====== ======

56
57

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

DECEMBER 31,
------------------
1995 1994
------- ------

Actuarial Present Value of Benefit Obligation:
Vested benefit obligation....................................... $39,012 35,877
====== =====
Accumulated benefit obligation.................................. $41,659 38,102
====== =====
Plan Assets at Fair Value......................................... $42,406 38,100
Projected Benefit Obligation...................................... 47,992 43,650
------ -----
Plan Assets Less Than Projected Benefit Obligation................ (5,586) (5,550)
Unrecognized Net Loss............................................. 7,319 9,029
Unrecognized Prior Service Costs.................................. (415) (490)
Unrecognized Net Transition Asset................................. (4,412) (5,648)
------ -----
Accrued Pension Expense Liability............................... $(3,094) (2,659)
====== =====

Retirement plan assets are primarily comprised of common stock and bond
funds. Actuarial assumptions used to measure the projected benefit obligations
at December 31, 1995, 1994 and 1993 included a discount rate of 7 1/2%, 8 1/2%
and 7%, respectively, and a compensation increase rate of 5%, 6% and 4 1/2%,
respectively. The expected long-term rate of return on assets was 8 1/2% for
1995 and 9% for 1994 and 1993.

EXECUTIVE SECURITY PLAN

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

YEARS ENDED DECEMBER 31,
-----------------------
1995 1994 1993
----- ---- ----

Service Costs................................................ $ 364 474 426
Interest Cost................................................ 205 273 291
Actual Return on Plan Assets................................. (325) (230) (256)
Net Amortization and Deferral................................ 471 228 295
----- ---- ----
Net Pension Expense........................................ $ 715 745 756
===== ==== ====

During 1995, 1994 and 1993, the Company incurred additional ESP expense of
$1.5 million, $.4 million and $.5 million, respectively, for settlements,
curtailments and other benefits resulting from a cost reduction program and
other employee terminations.

57
58

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

DECEMBER 31,
----------------
1995 1994
------ -----

Actuarial Present Value of Benefit Obligation:
Vested benefit obligation......................................... $2,470 3,071
====== =====
Accumulated benefit obligation.................................... $3,038 3,621
====== =====
Plan Assets at Fair Value........................................... $4,447 3,822
Projected Benefit Obligation........................................ 4,155 4,075
------ -----
Plan Assets in Excess of (Less Than) Projected Benefit Obligation... 292 (253)
Unrecognized Net Loss............................................... 2,343 2,158
Unrecognized Prior Service Costs.................................... 395 495
Unrecognized Net Transition Obligation.............................. 643 843
------ -----
Prepaid Pension Asset............................................. $3,673 3,243
====== =====

Assets of the ESP consist of a group annuity contract. Actuarial
assumptions used to measure the projected benefit obligation at December 31,
1995, 1994 and 1993 included a discount rate of 7 1/2%, 8 1/2% and 7%,
respectively, and a compensation increase rate of 5%, 5% and 4 1/2%,
respectively. The expected long-term rate of return on assets was 8% for 1995
and 9% for 1994 and 1993.

NON-EMPLOYEE DIRECTOR RETIREMENT PLAN

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

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

58
59

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The components of net periodic postretirement benefits expense, other than
pensions, for 1995, 1994 and 1993 included the following (in thousands):

YEARS ENDED DECEMBER 31,
--------------------------
1995 1994 1993
------ ----- -----

Health Care:
Service costs............................................ $ 447 471 420
Interest costs........................................... 1,399 1,264 1,396
------ ----- -----
Net Periodic Postretirement Expense................... $1,846 1,735 1,816
====== ===== =====
Life Insurance:
Service costs............................................ $ 174 198 100
Interest costs........................................... 584 518 492
------ ----- -----
Net Periodic Postretirement Expense................... $ 758 716 592
====== ===== =====

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

DECEMBER 31,
------------------
1995 1994
------- ------

Health Care:
Accumulated Postretirement Benefit Obligation --
Retirees........................................................ $13,831 14,066
Active participants eligible to retire.......................... 1,382 1,309
Other active participants....................................... 4,118 3,490
------- ------
19,331 18,865
Unrecognized net gain (loss).................................... 328 (164)
------- ------
Accrued Postretirement Benefit Liability..................... $19,659 18,701
======= ======
Life Insurance:
Accumulated Postretirement Benefit Obligation --
Retirees........................................................ $ 5,888 5,321
Active participants eligible to retire.......................... 452 421
Other active participants....................................... 1,590 1,324
------- ------
7,930 7,066
Unrecognized net loss........................................... (665) (438)
------- ------
Accrued Postretirement Benefit Liability..................... $ 7,265 6,628
======= ======

The weighted average annual rate of increase in the per capita cost of
covered health care benefits is assumed to be 8% for 1996, 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, 1995 by $3.7 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, 1995, 1994 and 1993 included a discount rate of 7 1/2%, 8 1/2% and
7%, respectively, and a compensation rate increase of 5%, 6% and 4 1/2%,
respectively.

59
60

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 $400,000, $547,000 and $482,000 during 1995, 1994 and 1993,
respectively.

EMPLOYEE TERMINATIONS AND OTHER COSTS

In 1995, the Company incurred a charge of $5.2 million, primarily for
employee termination costs associated with restructuring the Company's
organization and operations. Other expense included $3.8 million of this charge,
representing primarily severance and related benefits resulting from a reduction
in administrative workforce and other employee terminations together with
settlements and curtailments under the Company's executive security plan.
Operating expenses and other included the remaining $1.4 million of this charge
which was related to employee terminations and exit costs in the Company's
operating segments. The Company's Consolidated Balance Sheet as of December 31,
1995 included an accrual of approximately $.9 million relating to these costs,
the majority of which will be paid during the first quarter of 1996.

NOTE K -- 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"), and a 1995 Non-Employee Director Stock Option Plan (the "1995
Plan") (collectively, the "Plans"). Shares of unissued Common Stock reserved for
the Plans totaled 1,767,724 at December 31, 1995, which included 39,315 shares
representing awards granted under the Plans that had not yet been issued.

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, 1995, the Company had
407,287 shares available for future grants under the 1993 Plan.

Stock appreciation rights under the 1982 Plan 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
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 1995 and 1993, no compensation expense was
recognized since the market value of the Company's Common Stock remained below
the exercise price.

Stock options under the 1982 Plan and 1993 Plan 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 1982 Plan and 1993 Plan amounted to 137,253 and 83,015 common shares
in 1994 and 1993, respectively. No stock awards

60
61

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

or performance shares were granted in 1995. 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 and $572,000
in 1994 and 1993, respectively.

The 1995 Plan, which was approved by the Company's stockholders on May 4,
1995, provides for the granting of an aggregate of 150,000 nonqualified stock
options to eligible non-employee directors of the Company. The option price per
share is equal to the fair market value per share of the Company's Common Stock
on the date of grant. The term of each option is ten years, and an option first
becomes exercisable six months after the date of grant. Under the 1995 Plan,
each person serving as a non-employee director on February 23, 1995, received an
option to purchase 5,000 shares of Common Stock. In addition, each non-employee
director, while the 1995 Plan is in effect and shares are available to grant,
will be granted an option to purchase 1,000 shares of Common Stock on the next
day after each annual meeting of the Company's stockholders but not later than
June 1. At December 31, 1995, the Company had 36,000 options outstanding and
114,000 shares available for future grants under the 1995 Plan.

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

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

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............................................. 1,496,293 478,879
Granted at $8.000 to $11.375................................ 450,000 --
Becoming exercisable........................................ -- 615,103
Exercised................................................... (507,467) (507,467)
Cancelled or expired........................................ (266,745) (225,736)
----------- -----------
December 31, 1995 ($2.925 to $12.625)......................... 1,172,081 360,779
========= ========

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

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............................................. 51,260 51,260
Cancelled or expired........................................ (16,219) (16,219)
--------- --------
December 31, 1995 ($8.375 to $12.625)......................... 35,041 35,041
========= ========

61
62

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE L -- 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. In December 1995, the Company's Board of Directors extended the
expiration date of the rights to the close of business on July 24, 1996. At
December 31, 1995, there were 24,780,134 rights outstanding.

NOTE M -- OPERATING LEASES

The Company has various noncancellable operating leases related to
convenience stores, equipment, property and other facilities. Lease terms range
from one year to 35 years and generally contain multiple renewal options. In
addition, the Company has long-term leases expiring in the year 2000 for two
vessels which are used to transport crude oil and refined products to and from
the Company's refinery. Future minimum annual payments for operating leases,
existing at December 31, 1995, were as follows (in thousands):

CHARTERED
VESSELS OTHER TOTAL
--------- ------ -------

1996.................................................. $ 25,771 4,734 30,505
1997.................................................. 27,354 4,051 31,405
1998.................................................. 28,128 3,844 31,972
1999.................................................. 28,705 1,436 30,141
2000.................................................. 16,581 1,286 17,867
Remainder............................................. -- 11,144 11,144
--------- ------ -------
Total Minimum Lease Payments................ $ 126,539 26,495 153,034
======== ====== =======

In addition to the long-term lease commitments listed above, the Company
enters into various month-to-month and other short-term rentals, including a
six-month charter of a vessel used to primarily transport refined products from
the Company's refinery to the Far East. Assuming exercise of renewal options,
lease payments under this charter, which was entered into in May 1995 and
includes three six-month renewal options, would be approximately $3.3 million
for the year 1996.

Total rental expense, including short-term leases in addition to rents paid
and accrued under long-term lease commitments, amounted to approximately $35.6
million, $33.6 million and $32.5 million for 1995, 1994 and 1993, respectively.
Rental expense included amounts related to chartered vessels of approximately
$26.3 million, $24.6 million and $22.9 million for 1995, 1994 and 1993,
respectively.

NOTE N -- COMMITMENTS AND CONTINGENCIES

GAS PURCHASE AND SALES CONTRACT

The Company is selling a portion of the gas produced from its Bob West
Field to Tennessee Gas Pipeline Company ("Tennessee Gas") under a Gas Purchase
and Sales Agreement ("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"). In
August 1990, Tennessee Gas filed suit against the Company in the District Court
of Bexar County, Texas, alleging that the

62
63

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 the month of
December 1995, the Contract Price was in excess of $8.60 per Mcf and the average
spot market price was $1.84 per Mcf. For the year ended December 31, 1995,
approximately 17% of the Company's net U.S. natural gas production was sold
under the Tennessee Gas Contract. Tennessee Gas also claimed that the contract
should be considered an "output contract" under Section 2.306 of the Texas
Uniform Commercial Code ("UCC") 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 appellate court decision was the first decision reported in
Texas holding that a take-or-pay contract was an output contract. The Supreme
Court of Texas heard arguments in December 1994 regarding the output contract
issue and certain of the issues raised by Tennessee Gas. On August 1, 1995, the
Supreme Court of Texas, in a divided opinion, affirmed the decision of the
appellate court on all issues, including that the price under the Tennessee Gas
Contract is the Contract Price, and determined that the Tennessee Gas Contract
was an output contract and remanded the case to the trial court for
determination of whether gas volumes tendered by the Company to Tennessee Gas
were tendered in good faith and were not unreasonably disproportionate to any
normal or otherwise comparable prior output or stated estimates in accordance
with the UCC. The Company filed a motion for rehearing before the Texas Supreme
Court on the issue of whether the Tennessee Gas Contract is an output contract.
The Company believes that, if this issue is tried, the gas volumes tendered to
Tennessee Gas will be found to have been in good faith and otherwise in
accordance with the requirements of the UCC. However, there can be no assurance
as to the ultimate outcome at trial.

In conjunction with the District Court judgment and on behalf of all
sellers under the Tennessee Gas Contract, Tennessee Gas is presently required to
post a supersedeas bond in the amount of $206 million. Under the terms of this
bond, for the period September 17, 1994 through April 30, 1996, Tennessee Gas is
required to take at least its entire monthly take-or-pay obligation and pay for
gas taken at $3.00 per Mmbtu, which approximates $3.00 per Mcf ("Bond Price").
The $206 million bond represents an amount which together with anticipated sales
of natural gas at the Bond Price will equal the anticipated value of the
Tennessee Gas Contract from September 17, 1994 through April 30, 1996. Except
for the period September 17, 1994 through August 13, 1995, the difference
between the spot market price and the Bond Price is refundable in the event
Tennessee Gas ultimately prevails in the litigation. The Company retains the
right to receive the Contract Price for all gas sold to Tennessee Gas.

Through December 31, 1995, under the Tennessee Gas Contract, the Company
recognized cumulative net revenues in excess of spot market prices totaling
approximately $117.3 million. Of the $117.3 million incremental net revenues,
the Company has received $11.0 million that is nonrefundable and $55.6 million
which the Company could be required to repay in the event of an adverse ruling.
The remaining $50.7 million of incremental net revenues is classified in the
Company's Consolidated Balance Sheet as a noncurrent receivable at December 31,
1995 and represents the unpaid difference between the Contract Price and the
Bond Price as described above. An adverse outcome of this litigation could
require the Company to reverse as much as $106.3 million of the incremental
revenues and could require the Company to repay as much as

63
64

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

$55.6 million for amounts received above spot prices, plus interest if awarded
by the court. For further information concerning the Tennessee Gas Contract, see
Note Q.

ENVIRONMENTAL

The Company is subject to extensive federal, state and local environmental
laws and regulations. These laws, which change frequently, regulate the
discharge of materials into the environment and may require the Company to
remove or mitigate the environmental effects of the disposal or release of
petroleum or chemical substances at various sites or install additional controls
or other modifications or changes in use for certain emission sources. The
Company is currently involved with a waste disposal site near Abbeville,
Louisiana, at which it has been named a potentially responsible party under the
Federal Superfund law. Although this law might impose joint and several
liability upon each party at the site, the extent of the Company's allocated
financial contributions to the cleanup is expected to be limited based upon the
number of companies and the volumes of waste involved. The Company believes that
its liability at the Abbeville, Louisiana site will be limited based upon the
payment by the Company of a de minimis 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 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 is currently
considering a penalty assessment of approximately $1.5 million. The Company is
continuing to negotiate with the DOJ but cannot predict the ultimate outcome of
the negotiations.

At December 31, 1995, the Company's accruals for environmental matters,
including the alleged violations of the Clean Air Act, amounted to $9.9 million.
Also included in this amount is a noncurrent liability of approximately $4
million for remediation of the KPL properties, which liability has been funded
by the former owners through a restricted escrow deposit. Based on currently
available information, including the participation of other parties or former
owners in remediation actions, the Company believes these accruals are adequate.
In addition, to comply with environmental laws and regulations, the Company
anticipates that it will be required to make capital improvements in 1996 of
approximately $3 million, primarily for the removal and upgrading of underground
storage tanks, and starting in 1996 approximately $8 million for the
installation of dike liners; however, the Company is applying for an alternate
compliance schedule, allowed for under the Alaska regulations, regarding dike
liner installation at the Company's Alaska facilities. This alternate schedule,
if granted, will allow the Company additional time to assess an alternate remedy
to the requirement, under Alaska environmental regulations. There can be no
assurance that an alternate schedule will be granted.

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

64
65

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

product terminals, and for compliance with the Clean Air Act. The amount of such
future expenditures cannot currently be determined by the Company.

CRUDE OIL PURCHASE CONTRACT

In 1995, the Company renegotiated a new three-year contract with the State
for the purchase of royalty crude oil covering the period January 1, 1996
through December 31, 1998. The new contract provides for the purchase of
approximately 40,000 barrels per day of Alaska North Slope ("ANS") royalty crude
oil, the primary feedstock for the Company's refinery, and is priced at the
weighted average price reported to the State by a major North Slope producer of
ANS crude oil as valued at Pump Station No. 1 on the Trans Alaska Pipeline
System. Under this agreement, the Company is required to utilize in its refinery
operations volumes equal to at least 80% of the ANS crude oil to be purchased
from the State. This contract contains provisions that, under certain
conditions, allow the Company to temporarily or permanently reduce its purchase
obligations. The Company's previous contract with the State, for the purchase of
approximately 40,000 barrels per day of ANS, expired on December 31, 1995.

REFUND CLAIM

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 DOE price and
allocation controls then in effect. In May 1995, the court issued an order
granting the Company's motion for summary judgment and dismissed with prejudice
all the claims in the Customer's complaint. In June 1995, the Customer filed a
notice of appeal with the U.S. Court of Appeals for the Federal Circuit. The
Company cannot predict the ultimate resolution of this matter but believes the
claim is without merit.

SEVERANCE TAX EXEMPTION

In February 1996, the Texas Railroad Commission certified substantially all
of the Company's reserves in the Bob West Field as high cost gas from a tight
formation. As a result of the certification, the Company anticipates that the
Texas Comptroller's office will exempt the Company's gas production from the
tight formations in the Bob West Field from Texas severance taxes. If the
severance tax exemption is received from the Comptroller's office, the Company
estimates that the pretax present value of proved reserves as of December 31,
1995 will increase by approximately $7.7 million and that the Company could be
eligible for a refund and tax credits for prior taxes paid of approximately $6
million. The potential refund and tax credits have not been recorded in the
Company's financial statements. There is no assurance that the Company will
receive the exemption or related refund or tax credits. For further information
on the Company's reserves and standardized measure, see Note Q.

65
66

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)

1995
Gross Operating Revenues*............................... $234.0 264.2 244.2 227.8
====== ==== ==== ====
Operating Profit........................................ $ 12.4 19.1 53.8 20.6
====== ==== ==== ====
Earnings Before Extraordinary Loss...................... $ 1.8 7.4 36.8 11.5
Extraordinary Loss...................................... -- -- -- (2.9)
------ ---- ---- ----
Net Earnings......................................... $ 1.8 7.4 36.8 8.6
====== ==== ==== ====
Earnings Per Share:
Earnings before extraordinary loss................... $ .07 .30 1.47 .46
Extraordinary loss................................... -- -- -- (.11)
------ ---- ---- ----
Net earnings......................................... $ .07 .30 1.47 .35
====== ==== ==== ====
1994
Gross Operating Revenues*............................... $188.8 210.0 251.1 218.8
====== ==== ==== ====
Operating Profit........................................ $ 18.3 11.7 7.1 27.3
====== ==== ==== ====
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 Share:
Earnings (loss) before extraordinary loss............ $ .27 .02 (.13) .61
Extraordinary loss................................... (.24) -- -- --
------ ---- ---- ----
Net earnings (loss).................................. $ .03 .02 (.13) .61
====== ==== ==== ====

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

* Amounts previously reported have been restated for insignificant
reclassifications between revenues and operating expenses.

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

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 H) 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.

NOTE P -- NATURAL GAS PRICE SWAP AGREEMENTS

The Company enters into commodity price swap agreements to reduce the risk
caused by fluctuations in the prices of natural gas in the spot market. During
1995 and 1994, the Company used such arrangements to set the price of 38% and
11%, respectively, of the natural gas production that it sold in the spot
market. It is the Company's current policy to use such arrangements to set the
price of not more than 50% of the annual volumes of natural gas production that
are sold in the spot market. The agreements provide for the Company

66
67

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

to receive, or make, payments based upon the differential between a specified
fixed price and the market price for natural gas. The market price is determined
by reference to a published index for natural gas traded at the Houston Ship
Channel. The Houston Ship Channel index is the price upon which the cash prices
for substantially all of the Company's spot market gas sales are based and,
accordingly, the risk of losses from large fluctuations in the basis
differentials (normally approximating the cost of transporting gas between the
Henry Hub and the Houston Ship Channel) is substantially eliminated. The Company
includes the related gains or losses in gas revenues in the period in which the
gas is produced. During each of the years 1995 and 1994, the Company realized
net gains of approximately $.3 million from these price swap arrangements. These
gains had the effect of adding $.01 per Mcf to the Company's average spot market
sales price for 1995 and 1994. As of January 9, 1996, the Company had entered
into such price swaps for 1996 production totaling 8.4 billion cubic feet for an
average Houston Ship Channel price of $1.77 per Mcf. In 1995, the Company's
average spot market wellhead price per Mcf for gas sales was $.25 less than the
average Houston Ship Channel index, the difference representing transportation
and marketing costs from the wellhead in South Texas.

NOTE Q -- 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 C, have
been excluded. For information related to the sale of certain interests in the
Bob West Field, see Note B.

CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES

DECEMBER 31,
-------------------------------
1995 1994 1993
-------- ------- ------
(IN THOUSANDS)

Capitalized Costs:
Proved properties........................................... $119,836 131,930 73,345
Unproved properties not being amortized(1).................. 5,118 3,758 1,959
-------- ------- ------
124,954 135,688 75,304
Accumulated depreciation, depletion and amortization........ 51,549 50,261 26,118
-------- ------- ------
Net Capitalized Costs............................... $ 73,405 85,427 49,186
======== ======= ======

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

(1) The Company anticipates that the majority of the costs at December 31,
1995, incurred primarily in 1995, will be included in the amortization
base during 1996.

67
68

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

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

Year Ended December 31, 1995:
Property acquisition, unproved................................. $ 1,432 -- 1,432
Exploration.................................................... 10,011 2,994 13,005
Development.................................................... 38,003 792 38,795
------- ----- ------
$49,446 3,786 53,232
======= ===== ======
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
======= ===== ======

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 TOTAL
--------- ------- -------
(IN THOUSANDS EXCEPT AS
INDICATED)

Year Ended December 31, 1995:
Gross revenues -- sales to nonaffiliates.................... $107,276 11,707 118,983
Production costs............................................ 12,005 600 12,605
Administrative support and other............................ 2,842 3,289 6,131
Gain on sales of assets(2).................................. 33,532 -- 33,532
Depreciation, depletion and amortization.................... 29,004 250 29,254
-------- ------ -------
Pretax results of operations................................ 96,957 7,568 104,525
Income tax expense.......................................... 33,935 4,718 38,653
-------- ------ -------
Results of operations from producing activities(3).......... $ 63,022 2,850 65,872
======== ====== =======
Depletion rates per net equivalent Mcf...................... $ .69 .03
======== ======

68
69

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

UNITED
STATES(1) BOLIVIA TOTAL
-------- ------ -------
(IN THOUSANDS EXCEPT AS
INDICATED)

Year Ended December 31, 1994:
Gross revenues -- sales to nonaffiliates.................... $ 87,478 13,211 100,689
Production costs............................................ 8,945 619 9,564
Administrative support and other............................ 2,289 3,242 5,531
Depreciation, depletion and amortization.................... 24,143 -- 24,143
-------- ------ -------
Pretax results of operations................................ 52,101 9,350 61,451
Income tax expense.......................................... 19,104 5,605 24,709
-------- ------ -------
Results of operations from producing activities(3).......... $ 32,997 3,745 36,742
======== ====== =======
Depletion rates per net equivalent Mcf...................... $ .79 --
======== ======
Year Ended December 31, 1993:
Gross revenues -- sales to nonaffiliates.................... $ 48,474 12,594 61,068
Production costs............................................ 4,752 1,152 5,904
Administrative support and other............................ 1,196 3,046 4,242
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(3).......... $ 24,768 3,236 28,004
======== ====== =======
Depletion rates per net equivalent Mcf...................... $ .78 --
======== ======

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

(1) See Note N regarding litigation involving a natural gas sales contract.
(2) Represents gain on sale of certain interests in the Bob West Field (see Note
B).
(3) Excludes corporate general and administrative expenses and financing costs.

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

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

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

As indicated in Note N, 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

69
70

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 discounted future net cash flows
before income taxes relating to proved reserves in the United States at December
31, 1995 was $168.7 million, compared with $120.7 million at spot market prices.
For information regarding a contingency related to a severance tax exemption and
a potential increase of approximately $7.7 million to the Company's pretax
discounted future net cash flows, see Note N.

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

UNITED
STATES(1) BOLIVIA TOTAL
--------- ------- -------
(IN THOUSANDS)

December 31, 1995:
Future cash inflows........................................ $265,379 120,510 385,889
Future production costs.................................... 53,095 32,005 85,100
Future development costs................................... 8,625 7,548 16,173
-------- -------- --------
Future net cash flows before income tax expense............ 203,659 80,957 284,616
10% annual discount factor................................. 34,920 32,231 67,151
-------- -------- --------
Discounted future net cash flows before income taxes....... 168,739 48,726 217,465
Discounted future income tax expense....................... 45,939 25,897 71,836
-------- -------- --------
Standardized measure of discounted future net cash flows... $122,800 22,829 145,629
======== ======== ========
December 31, 1994:
Future cash inflows........................................ $292,620 120,886 413,506
Future production costs.................................... 52,534 30,873 83,407
Future development costs................................... 29,933 7,258 37,191
-------- -------- --------
Future net cash flows before income tax expense............ 210,153 82,755 292,908
10% annual discount factor................................. 30,706 34,674 65,380
-------- -------- --------
Discounted future net cash flows before income taxes....... 179,447 48,081 227,528
Discounted future income tax expense....................... 52,661 26,092 78,753
-------- -------- --------
Standardized measure of discounted future net cash flows... $126,786 21,989 148,775
======== ======== ========
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
10% annual discount factor................................. 45,810 44,055 89,865
-------- -------- --------
Discounted future net cash flows before income taxes....... 162,560 55,235 217,795
Discounted future income tax expense....................... 59,808 28,795 88,603
-------- -------- --------
Standardized measure of discounted future net cash flows... $102,752 26,440 129,192
======== ======== ========

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

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

70
71

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

YEARS ENDED DECEMBER 31,
---------------------------------
1995 1994 1993
--------- ------- -------
(IN THOUSANDS)

Sales and transfers of oil and gas produced, net of
production costs.......................................... $(106,378) (88,751) (52,766)
Net changes in prices and production costs.................. (32,931) 12,834 (21,160)
Extensions, discoveries and improved recovery............... 83,045 54,503 73,792
Development costs incurred.................................. 38,795 51,148 25,510
Revisions of estimated future development costs............. (19,574) (34,738) (24,052)
Revisions of previous quantity estimates.................... 60,800 1,818 31,031
Sales of minerals in-place.................................. (48,698) -- --
Accretion of discount....................................... 14,878 12,919 11,071
Net changes in income taxes................................. 6,917 9,850 (24,945)
--------- ------- -------
Net increase (decrease)..................................... (3,146) 19,583 18,481
Beginning of period......................................... 148,775 129,192 110,711
--------- ------- -------
End of period............................................... $ 145,629 148,775 129,192
========= ======= =======

RESERVE INFORMATION (UNAUDITED)

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

UNITED
STATES(1) BOLIVIA TOTAL
--------- ------- -------
(MILLIONS OF CUBIC FEET)

NET PROVED GAS RESERVES(2)
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............................................. 129,099 95,756 224,855
Revisions of previous estimates............................. 46,239 (553) 45,686
Extensions, discoveries and other additions................. 50,201 -- 50,201
Production.................................................. (41,789) (6,807) (48,596)
Sales of minerals in-place.................................. (77,373) -- (77,373)
--------- -------- --------
December 31, 1995(3).......................................... 106,377 88,396 194,773
========= ======== ========
NET PROVED DEVELOPED GAS RESERVES (included above)
December 31, 1992............................................. 34,160 91,376 125,536
December 31, 1993............................................. 65,652 99,295 164,947
December 31, 1994............................................. 110,071 81,558 191,629
December 31, 1995(3).......................................... 95,930 72,500 168,430

71
72

TESORO PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

UNITED
STATES(1) BOLIVIA TOTAL
--------- ------- -----
(THOUSANDS OF BARRELS)

NET PROVED OIL RESERVES(2)
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................................................. -- 1,793 1,793
Revisions of previous estimates................................. 1 10 11
Extensions, discoveries and other additions..................... 8 -- 8
Production...................................................... (1) (207) (208)
---- ------- -----
December 31, 1995(3).............................................. 8 1,596 1,604
===== ======= =====
NET PROVED DEVELOPED OIL RESERVES (included above)
December 31, 1992................................................. -- 2,098 2,098
December 31, 1993................................................. -- 2,173 2,173
December 31, 1994................................................. -- 1,627 1,627
December 31, 1995(3).............................................. 4 1,407 1,411

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

(1) See Note N regarding litigation involving a natural gas sales contract.
(2) The Company was not required to file reserve estimates with federal
authorities or agencies during the periods presented.
(3) No major discovery or adverse event has occurred since December 31, 1995
that would cause a significant change in net proved reserve volumes.

72
73

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
1996 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
1996 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
1996 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
1996 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.......................................................... 39
Statements of Consolidated Operations -- Years Ended December 31, 1995, 1994 and
1993................................................................................ 40
Consolidated Balance Sheets -- December 31, 1995 and 1994............................. 41
Statements of Consolidated Stockholders' Equity -- Years Ended December 31, 1995,
1994 and 1993....................................................................... 42
Statements of Consolidated Cash Flows -- Years Ended December 31, 1995, 1994 and
1993................................................................................ 43
Notes to Consolidated Financial Statements............................................ 44

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.

73
74

3. EXHIBITS

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

2(a) Agreement and Plan of Merger dated as of November 20, 1995, between the Company,
Coastwide Energy Services, Inc. and CNRG Acquisition Corp. (incorporated by
reference herein to Registration Statement No. 333-00229).
2(b) First Amendment to Agreement and Plan of Merger dated effective February 19, 1996
between the Company, Coastwide Energy Services, Inc. and CNRG Acquisition Corp.
2(c) Copy of the Purchase and Sale Agreement by and between Tesoro E&P Company, L.P., as
Seller, and Coastal Oil & Gas of Texas, L.P., as Purchaser (incorporated by
reference herein to Exhibit 2 to the Company's Current Report on Form 8-K dated
September 26, 1995, File No. 1-3473).
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 September 27, 1995 (incorporated by
reference herein to Exhibit 3 to the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1995, File No. 1-3473).
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) Copy of resolution of the Company's Board of Directors extending the Expiration Date
relating to the Company's Preferred Stock Purchase Rights (incorporated by reference
herein to the Company's Current Report on Form 8-K dated December 15, 1995, File No.
1-3473).

74
75

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

4(g) 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 Quarterly Report on Form 10-Q for the quarter ended
March 31, 1994, File No. 1-3473).
4(h) 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 Quarterly Report
on Form 10-Q for the quarter ended March 31, 1994, File No. 1-3473).
4(i) 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 Quarterly Report on Form 10-Q for the
quarter ended March 31, 1994, File No. 1-3473).
4(j) 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 Quarterly Report
on Form 10-Q for the quarter ended March 31, 1994, File No. 1-3473).
4(k) 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 Quarterly Report on Form 10-Q for the quarter ended
March 31, 1994, File No. 1-3473).
4(l) 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 Quarterly 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
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
Quarterly Report on Form 10-Q for the quarter ended March 31, 1994, File No.
1-3473).
4(n) 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 Quarterly Report
on Form 10-Q for the quarter ended March 31, 1994, File No. 1-3473).
4(o) 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 Quarterly 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 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 Quarterly Report on Form 10-Q for the quarter ended March 31, 1994, File
No. 1-3473).
4(q) 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).

75
76

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

4(r) 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(s) $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(t) 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(u) 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(v) Security Agreement dated as of May 26, 1994 between Tesoro Alaska Petroleum Company
and NBA, entered into in connection with the Loan Agreement (incorporated by
reference herein to Exhibit 4.35 to Registration Statement No. 33-53587).
4(w) 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(x) 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 Quarterly Report on Form 10-Q for the quarter ended September 30,
1994, File No. 1-3473).
4(y) 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
(incorporated by reference herein to Exhibit 4(z) to the Company's Annual Report on
Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473).
4(z) Copy of First Amendment to the Loan Agreement dated as of January 26, 1995 among
Tesoro Alaska Petroleum Company, Tesoro Petroleum Corporation and NBA (incorporated
by reference herein to Exhibit 4(aa) to the Company's Annual Report on Form 10-K for
the fiscal year ended December 31, 1994, File No. 1-3473).
4(aa) Copy of Consent and Waiver No. 2 dated as of July 31, 1995 to the Company's Credit
Agreement dated as of April 20, 1994 (incorporated by reference herein to Exhibit 4
to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1995,
File No. 1-3473).
4(bb) Copy of Second Amendment and Supplement to Credit Agreement effective as of
September 1, 1995 among Tesoro and TCB as Issuing Bank and as Agent, and certain
other banks named therein (incorporated by reference herein to Exhibit 4.1 to the
Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1995,
File No. 1-3473).
4(cc) Copy of Third Amendment to Credit Agreement effective as of October 24, 1995 among
Tesoro and TCB as Issuing Bank and as Agent, and certain other banks named therein
(incorporated by reference herein to Exhibit 4.2 to the Company's Quarterly Report
on Form 10-Q for the quarter ended September 30, 1995, File No. 1-3473).
4(dd) Warrant Agreement dated effective as of October 29, 1993, between Coastwide Energy
Services, Inc. and Chemical Shareholder Services Group, Inc., as Warrant Agent
(incorporated by reference herein to Exhibit 4.1 to Post-Effective Amendment No. 1
to Registration No. 333-00229).
4(ee) Warrant Assumption and Conversion Agreement dated as of February 20, 1996, between
the Company, Coastwide Energy Services, Inc. and Chemical Shareholder Services
Group, Inc., as Warrant Agent (incorporated by reference herein to Exhibit 4.2 to
Post-Effective Amendment No. 1 to Registration No. 333-00229).

76
77

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

4(ff) Form of 8% Convertible Subordinated Debenture (incorporated by reference herein to
Exhibit 4.3 to Post-Effective Amendment No. 1 to Registration No. 333-00229).
4(gg) Debenture Assumption and Conversion Agreement dated as of February 20, 1996, between
the Company, Coastwide Energy Services, Inc. and CNRG Acquisition Corp.
(incorporated by reference herein to Exhibit 4.4 to Post-Effective Amendment No. 1
to Registration No. 333-00229).
4(hh) Form of Stock Option Agreement for option grant under the Coastwide Energy Services,
Inc. 1993 Long-Term Incentive Plan (incorporated by reference herein to Exhibit 4.5
to Post-Effective Amendment No. 1 to Registration No. 333-00229).
4(ii) Form of Cancellation/Substitution Agreement by and between the Company, Coastwide
Energy Services, Inc. and Optionee (incorporated by reference herein to Exhibit 4.6
to Post-Effective Amendment No. 1 to Registration No. 333-00229).
10(a) 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(b) 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(c) Seventh Amendment to the Company's Amended Executive Security Plan and Eighth
Amendment to the Company's Funded Executive Security Plan, both dated effective
December 8, 1994 (incorporated by reference herein to Exhibit 10(f) to the Company's
Annual Report on Form 10-K for the fiscal year ended December 31, 1994, File No.
1-3473).
10(d) 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(e) First Amendment and Extension to Employment Agreement between the Company and
Michael D. Burke dated December 14, 1994 (incorporated by reference herein to
Exhibit 10(h) to the Company's Annual Report on Form 10-K for the fiscal year ended
December 31, 1992, File No. 1-3473).
10(f) Termination Agreement between the Company and Michael D. Burke, dated September 26,
1995 (incorporated by reference herein to Exhibit 10(i) to Registration Statement
No. 333-00229).
10(g) Consulting Agreement between the Company and M.D. Burke & Company (formerly M.D.
Burke Enterprises, Inc.) dated September 26, 1995 (incorporated by reference herein
to Exhibit 10(j) to Registration Statement No. 333-00229).
10(h) 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(i) Form of Amendment to Executive Agreement 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(j) Form of Second Amendment to Executive Agreement 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).

77
78

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

10(k) 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(l) First Amendment and Extension to Employment Agreement between the Company and Bruce
A. Smith dated December 14, 1994 (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,
1994, File No. 1-3473).
10(m) Second Amendment to Employment Agreement between the Company and Bruce A. Smith
dated September 29, 1995 (incorporated by reference herein to Exhibit 10(m) to
Registration Statement No. 333-00229).
10(n) Letter Agreement extending the term of the Employment Agreement, as amended, between
the Company and Bruce A. Smith dated December 14, 1995 (incorporated by reference
herein to Exhibit 10(n) to Registration Statement No. 333-00229).
10(o) Amended and Restated Employment Agreement between the Company and Bruce A. Smith
dated February 15, 1996.
10(p) 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(q) First Amendment and Extension to Employment Agreement between the Company and Gaylon
H. Simmons dated December 14, 1994 (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, 1994, File No. 1-3473).
10(r) Employment Agreement between the Company and James C. Reed, Jr. dated December 14,
1994 (incorporated by reference herein to Exhibit 10(m) to the Company's Annual
Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473).
10(s) First Amendment to Employment Agreement between the Company and James C. Reed, Jr.
dated as of September 27, 1995 (incorporated by reference herein to Exhibit 10(r) to
Registration Statement No. 333-00229).
10(t) Employment Agreement between the Company and William T. Van Kleef dated December 14,
1994 (incorporated by reference herein to Exhibit 10(n) to the Company's Annual
Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473).
10(u) First Amendment to Employment Agreement between the Company and William T. Van Kleef
dated as of September 27, 1995 (incorporated by reference herein to Exhibit 10(t) to
Registration Statement No. 333-00229).
10(v) Management Stability Agreement between the Company and Don E. Beere dated December
14, 1994 (incorporated by reference herein to Exhibit 10(o) to the Company's Annual
Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473).
10(w) Management Stability Agreement between the Company and Gregory A. Wright dated
February 23, 1995 (incorporated by reference herein to Exhibit 10(p) to the
Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1994,
File No. 1-3473)
10(x) Management Stability Agreement between the Company and Thomas E. Reardon dated
December 14, 1994 (incorporated by reference herein to Exhibit 10(w) to Registration
Statement No. 333-00229).
10(y) 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).

78
79

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

10(z) 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(aa) 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(bb) Copy of the Company's Non-Employee Director Retirement Plan dated December 8, 1994
(incorporated by reference herein to Exhibit 10(t) to the Company's Annual Report on
Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473).
10(cc) Copy of the Company's Board of Directors Deferred Compensation Plan dated February
23, 1995 (incorporated by reference herein to Exhibit 10(u) to the Company's Annual
Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473).
10(dd) Copy of the Company's Board of Directors Deferred Compensation Trust dated February
23, 1995 (incorporated by reference herein to Exhibit 10(v) to the Company's Annual
Report on Form 10-K for the fiscal year ended December 31, 1994, File No. 1-3473).
10(ee) 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(ff) 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
(incorporated by reference herein to Exhibit 10(x) to the Company's Annual Report on
Form 10-K for the year ended December 31, 1994, File No. 1-3473).
10(gg) Agreement for the Sale and Purchase of State Royalty Oil dated as of April 21, 1995
by and between Tesoro Alaska Petroleum Company and the State of Alaska (incorporated
by reference herein to Exhibit 10 to the Company's Quarterly Report on Form 10-Q for
the quarter ended June 30, 1995, File No.1-3473).
10(hh) 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(ii) 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(jj) Gas Purchase and Sales Agreement dated January 16, 1979 (incorporated by reference
herein to Exhibit 10(p) to Registration Statement No. 33-68282).
11 Information Supporting Earnings 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

79
80

(b) REPORTS ON FORM 8-K

A Current Report on Form 8-K, dated September 26, 1995, was filed on
October 11, 1995, reporting under Item 2, Acquisition or Disposition of Assets,
that on September 26, 1995 the Company sold, effective April 1, 1995, certain
interests in the Company's producing and non-producing oil and gas properties
located in the Bob West Field, Zapata and Starr Counties, Texas.

A Current Report on Form 8-K, dated December 15, 1995, was filed on
December 18, 1995, reporting under Item 5, Other Events, that the Company's
Board of Directors extended the expiration date of its Preferred Stock Purchase
Rights to July 24, 1996.

A Current Report on Form 8-K, dated January 30, 1996, was filed on January
31, 1996, reporting under Item 5, Other Events, that the Company announced
earnings for the year ended December 31, 1995 and information regarding its
natural gas reserves and 1996 capital budget.

No financial statements were filed as part of the current reports listed
above.

80
81

SIGNATURES

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

TESORO PETROLEUM CORPORATION

By: /s/ BRUCE A. SMITH
--------------------------------
Bruce A. Smith
President and Chief Executive
Officer
March 22, 1996

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

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

/s/ BRUCE A. SMITH Director, President and Chief March 22, 1996
- --------------------------------------------- Executive Officer (Principal
(Bruce A. Smith) Executive Officer)

/s/ WILLIAM T. VAN KLEEF Senior Vice President and Chief March 22, 1996
- --------------------------------------------- Financial Officer (Principal
(William T. Van Kleef) Financial Officer and
Accounting Officer)

/s/ ROBERT J. CAVERLY Chairman of the Board of March 22, 1996
- --------------------------------------------- Directors and Director
(Robert J. Caverly)

/s/ STEVEN H. GRAPSTEIN Vice Chairman of the Board of March 22, 1996
- --------------------------------------------- Directors and Director
(Steven H. Grapstein)

/s/ RAYMOND K. MASON, SR. Director March 22, 1996
- ---------------------------------------------
(Raymond K. Mason, Sr.)

/s/ JOHN J. MCKETTA, JR. Director March 22, 1996
- ---------------------------------------------
(John J. McKetta, Jr.)

Director March , 1996
- ---------------------------------------------
(Patrick J. Ward)

/s/ MURRAY L. WEIDENBAUM Director March 22, 1996
- ---------------------------------------------
(Murray L. Weidenbaum)

81
82

INDEX TO EXHIBITS

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

2(b) First Amendment to Agreement and Plan of Merger dated effective February 19, 1996
between the Company, Coastwide Energy Services, Inc. and CNRG Acquisition Corp.
10(o) Amended and Restated Employment Agreement between the Company and Bruce A. Smith
dated February 15, 1996.
11 Information Supporting Earnings 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