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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, 1997
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM . . . . TO . . . .
COMMISSION FILE NUMBER 1-3473
TESORO PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 95-0862768
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
8700 TESORO DRIVE, SAN ANTONIO, TEXAS 78217-6218
(Address of principal executive offices) (Zip Code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE:
210-828-8484
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SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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Common Stock, $0.16 2/3 par value New York Stock Exchange
Pacific Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
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Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
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At February 27, 1998, the aggregate market value of the voting stock held
by nonaffiliates of the registrant was approximately $404,566,324 based upon the
closing price of its Common Stock on the New York Stock Exchange Composite tape.
At February 27, 1998, there were 26,661,845 shares of the registrant's Common
Stock outstanding.
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DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's Proxy Statement pertaining to the 1998 Annual
Meeting of Stockholders are incorporated by reference into Part III hereof.
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TESORO PETROLEUM CORPORATION
ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
PAGE
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PART I
Item 1. Business.................................................... 1
Recent Development..................................... 1
Refining and Marketing................................. 2
Exploration and Production............................. 6
Marine Services........................................ 14
Competition and Other.................................. 15
Government Regulation and Legislation.................. 17
Employees.............................................. 19
Executive Officers of the Registrant................... 20
Item 2. Properties.................................................. 21
Item 3. Legal Proceedings........................................... 21
Item 4. Submission of Matters to a Vote of Security Holders......... 21
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters.................................... 22
Item 6. Selected Financial Data..................................... 23
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations.............................. 25
General................................................ 25
Results of Operations.................................. 26
Capital Resources and Liquidity........................ 37
Forward-Looking Statements.................................. 42
Item 8. Financial Statements and Supplementary Data................. 43
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure............................... 76
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 76
Item 11. Executive Compensation...................................... 76
Item 12. Security Ownership of Certain Beneficial Owners and
Management............................................. 76
Item 13. Certain Relationships and Related Transactions.............. 76
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K.................................................... 76
SIGNATURES............................................................ 83
THIS ANNUAL REPORT CONTAINS STATEMENTS WITH RESPECT TO THE COMPANY'S
EXPECTATIONS OR BELIEFS AS TO FUTURE EVENTS. THESE TYPES OF STATEMENTS ARE
FORWARD-LOOKING AND SUBJECT TO UNCERTAINTIES. SEE "FORWARD-LOOKING STATEMENTS"
ON PAGE 42.
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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,
distributing and marketing of petroleum products, marine logistics services and
the exploration and production of natural gas and oil. These operations are
conducted through three business segments: Refining and Marketing, Exploration
and Production, and Marine Services.
Downstream, the Company's Refining and Marketing segment owns and operates
a petroleum refinery at Kenai, Alaska ("Kenai Refinery"), markets refined
products through a large network of branded stations in Alaska and is expanding
its marketing presence in the Pacific Northwest. This segment is also a major
supplier of jet fuel to the Anchorage airport and diesel fuel to Alaska's
fishing and marine industry. The Company's Marine Services segment operates
through a network of 23 marine terminals located in Louisiana and Texas and on
the U.S. West Coast, distributing petroleum products and providing logistics
services to the offshore Gulf of Mexico drilling industry and other customers.
Upstream, the Company's Exploration and Production segment focuses on
exploration, development and production of natural gas and oil onshore in Texas,
Louisiana and Bolivia. The Company's net proved worldwide reserves totaled 517
billion cubic feet equivalents ("Bcfe") of natural gas at year-end 1997. The
Company is focused on its long-term strategy to maximize returns and develop
full value of its assets through strategic expansions, acquisitions and
diversifications in all three of its operating segments.
Tesoro was incorporated in Delaware in 1968 (a successor by merger to a
California corporation incorporated in 1939). Its principal executive offices
are located at 8700 Tesoro Drive, San Antonio, Texas 78217-6218 and its
telephone number is (210) 828-8484.
For financial and statistical information relating to the Company's
operations, see Management's Discussion and Analysis of Financial Condition and
Results of Operations in Item 7 and Note B of Notes to Consolidated Financial
Statements in Item 8.
RECENT DEVELOPMENT
On March 18, 1998, the Company entered into a stock sale agreement ("Stock
Sale Agreement") with BHP Hawaii Inc. and BHP Petroleum Pacific Islands Inc.
(collectively, the "Sellers"), subsidiaries of The Broken Hill Proprietary
Company Limited ("BHP"), whereby Tesoro will purchase all of the outstanding
stock of BHP Petroleum Americas Refining Inc. ("BHP Refining") and BHP Petroleum
South Pacific Inc. ("BHP South Pacific"). BHP Refining owns and operates a
95,000-barrel a day refinery in Kapolei, Hawaii on the island of Oahu,
approximately 20 miles west of Honolulu, and 32 retail gasoline stations on the
islands of Oahu, Maui and Hawaii. The acquisition, which is subject to
regulatory review and other customary conditions, is anticipated to close on May
29, 1998. Under the terms of the Stock Sale Agreement, the Company has deposited
$5 million into an escrow account for this acquisition.
At closing Tesoro will pay the Sellers a cash purchase price currently
estimated to be approximately $275 million, less the $5 million escrow deposit,
for the stock of BHP Refining and BHP South Pacific. The cash purchase price
will be adjusted after the closing based on the amount by which net working
capital of BHP Refining and BHP South Pacific at closing is in excess of or less
than $100 million. In addition, Tesoro will issue an unsecured, non-interest
bearing, promissory note in the amount of $50 million payable in five equal
annual installments of $10 million each, beginning on the eleventh anniversary
date of closing. The note provides for earlier payment to the extent of one-half
of the amount by which earnings from the acquired assets, before interest
expense, income taxes and depreciation, depletion and amortization, as specified
in the note, exceed $50 million in any calendar year. Upon acceleration due to
an event of default, the amount outstanding to be paid under the note will be
reduced to present value using a discount rate of 9%. The Stock Sale Agreement
contains representations and warranties and other general provisions that are
customary for transactions of this nature.
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The parties will execute a separate environmental agreement at closing,
whereby the Sellers will indemnify Tesoro and BHP Refining and BHP South Pacific
for environmental costs arising out of conditions which exist at, or existed
prior to, closing subject to a maximum limit of $9.5 million. Under the
environmental agreement, the first $5 million of these liabilities will be the
responsibility of the Sellers and the next $6 million will be shared on the
basis of 75% by the Sellers and 25% by Tesoro. The environmental indemnity will
survive for a ten-year period. Certain environmental claims arising out of prior
operations will not be subject to the $9.5 million limit or the ten-year time
limit for claims made.
BHP will guarantee all of the obligations of the Sellers under the Stock
Sale Agreement and the environmental agreement.
Tesoro and an affiliate of BHP will enter into a crude supply agreement
pursuant to which the BHP affiliate will assist Tesoro in acquiring crude oil
feedstock sourced outside of North America and arrange for transportation of
such crude oil to the Hawaiian refinery. The crude supply agreement will be for
a period of two years and provides for annual payments of $1.4 million by Tesoro
to the BHP affiliate for such services.
For further information regarding the proposed acquisition, see
Management's Discussion and Analysis of Financial Condition and Results of
Operations in Item 7 and Note O of Notes to Consolidated Financial Statements in
Item 8.
REFINING AND MARKETING
OVERVIEW
The Company conducts petroleum refining operations in Alaska and sells
refined products to a wide variety of customers in Alaska, along the U.S. West
Coast, primarily in the Pacific Northwest, and in certain Far Eastern markets,
including Russia. During 1997, products from the Kenai Refinery accounted for
approximately 78% of these sales volumes, including products received on
exchange in the U.S. West Coast market, with the remaining 22% being purchased
from other refiners and suppliers.
REFINERY
The Kenai Refinery in 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, liquid asphalt, heavy oils and residual
products. Alaska North Slope ("ANS") and Cook Inlet crude oils are the primary
feedstocks for the Kenai Refinery. To assure the availability of crude oil to
the Kenai Refinery, the Company has a royalty crude oil purchase contract with
the State of Alaska ("State") and contracts with various Cook Inlet producers
(see "Crude Oil Supply" discussed below). During 1997, the Kenai Refinery
processed approximately 71% ANS crude oil, 26% Cook Inlet crude oil and 3% other
feedstocks, which yielded refined products consisting of approximately 25%
gasoline, 42% middle distillates, 29% heavy oils and residual products and 4%
other products. Throughput at the Kenai Refinery was reduced during both 1997
and 1996 for scheduled 30-day maintenance turnarounds.
In early October 1997, the Company completed an expansion of the Kenai
Refinery's hydrocracker unit, which increased the unit's capacity by
approximately 25% to 12,500 barrels per day and enables the Company to produce
more jet fuel, a product in short supply in Alaska. The expansion, together with
the addition of a new, high-yield jet fuel hydrocracker catalyst, cost
approximately $19 million and has a projected payback period of two years. The
expansion began to improve the Kenai Refinery's product slate during the fourth
quarter of 1997.
CRUDE OIL SUPPLY
The Kenai Refinery is designed to process crude oil with up to 1.0% sulphur
content. As such, the Kenai Refinery can process Cook Inlet, ANS and certain
other foreign and domestic crude oils.
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ANS Crude Oil. ANS crude oil, a heavy crude oil which has a sulphur content
of approximately 1.0%, accounted for 71% of the Kenai Refinery's feedstock in
1997. The Company purchased approximately 35,700 barrels per day of ANS crude
oil during 1997 under the royalty crude oil purchase contract with the State.
This contract, which covers the period January 1, 1996 through December 31,
1998, provides for the purchase of 30% of the State's ANS royalty crude oil
produced from the Prudhoe Bay Unit at prices based on royalty values computed by
the State. The contract contains provisions that, under certain conditions,
allow the Company to temporarily or permanently reduce its purchase obligation.
Under the contract, the Company is required to utilize in its refinery
operations volumes equal to at least 80% of the ANS crude oil purchased from the
State. The Company is presently in discussions with the State in regard to
extending this contract for an additional year.
The Company also purchases approximately 6,000 barrels per day of ANS crude
oil from a producer under a contract with a term of one year beginning January
1, 1998.
ANS crude oil feedstock is delivered to the Kenai Refinery by tanker
through the Kenai Pipe Line Company ("KPL") marine terminal, which is owned and
operated by the Company.
For information related to a settlement of a contractual dispute with the
State in 1993, see Note I of Notes to Consolidated Financial Statements in Item
8.
Cook Inlet Crude Oil. Cook Inlet crude oil, a lighter crude oil that
contains an average of 0.1% sulphur, accounted for 26% of the Kenai Refinery's
feedstock in 1997. In the first nine months of 1997, the Company processed
approximately 9,300 barrels per day of Cook Inlet crude oil, or 19% of the Kenai
Refinery's throughput, which was obtained from several producers on the Kenai
peninsula under short-term contracts. During October 1997, the Company began
purchasing all of the approximately 34,000 barrels per day of Cook Inlet
production from various producers under contracts that extend through December
1998. A contract to purchase 4,500 barrels per day, of the 34,000 barrels per
day, has been extended through March 31, 2001. During the fourth quarter of
1997, the Company processed approximately 24,900 barrels per day of Cook Inlet
crude oil, or approximately 44% of the Kenai Refinery's throughput.
Cook Inlet crude oil is delivered by tanker through KPL's marine terminal
or by pipeline to the Kenai Refinery.
Other Supply. In 1997, the Kenai Refinery obtained 3% of its feedstock
supply from other sources. The other supply primarily consisted of spot
purchases of crude oil which were delivered to the Kenai Refinery by tanker
through KPL's marine terminal. The Company evaluates the economic viability of
processing various types of foreign and domestic crude oils in the Kenai
Refinery and will occasionally purchase spot quantities to supplement its normal
crude oil supply.
MARKETING IN ALASKA
Gasoline. The Company distributes gasoline to end users in Alaska, either
by retail sales through 35 Company-operated stations, by wholesale sales through
129 branded and 28 unbranded dealers and jobbers or by deliveries to major oil
companies for their retail operations in Alaska in exchange for gasoline
delivered to the Company on the U.S. West Coast. The Company holds an exclusive
license agreement for all 7-Eleven convenience stores in Alaska, which are
operated by the Company. During 1997, these Company-operated retail stations
sold an average of 93,000 gallons of gasoline per day.
In 1997, the Company initiated a three-year, $50 million retail marketing
expansion program focused primarily in Anchorage, Alaska, the State's largest
motor fuel market. During the year, two new retail facilities were built, three
stations were remodeled and two uneconomic outlets were closed. In addition, in
late 1997, the Company purchased the Union 76 marketing assets in Alaska, which
included two retail stations located in Southeast Alaska and the rights to use
the Union 76 trademark within Alaska.
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 a majority of its production being marketed
to passenger and cargo airlines. The demand for jet fuel in Alaska is growing
and currently exceeds the production of all refiners in Alaska. Several
marketers, including the Company, import jet fuel into Alaska to meet excess
demand. The expansion of the Kenai Refinery's hydrocracker unit has increased
the Company's jet fuel production to help meet this growing market.
Substantially all of the Company's diesel fuel production is sold on a
wholesale basis in Alaska, primarily for marine, transportation and industrial
purposes. As part of the purchase of the Union 76 marketing assets discussed
above, the Company acquired a terminal with a 110,000-barrel capacity in
Ketchikan, Alaska. Diesel fuel will be supplied to this terminal from the Kenai
Refinery and the U.S. West Coast. The product will be delivered to the terminal
by marine barge. Generally, the production of diesel fuel by refiners in Alaska
is in balance with demand; however, because of the 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 Kenai Refinery's vacuum unit uses
crude tower bottoms as a feedstock and further processes these volumes into
light vacuum gas oil ("LVGO"), heavy vacuum gas oil ("HVGO") and vacuum tower
bottoms ("VTBs"). The LVGO is further processed in the Kenai 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 fluid catalytic cracker
feedstock. The VTBs are used to produce liquid asphalt or the VTBs are sold on
the U.S. West Coast where they are blended with light cycle oil to produce
bunker fuel. The Company sells its liquid asphalt, which is used in the
manufacturing of highway paving materials, primarily in Alaska where the demand
is seasonal because mild weather conditions are needed for highway construction.
During 1997, the Company opened an asphalt marketing facility in Anchorage,
which helped increase sales of this product in Alaska.
MARKETING OUTSIDE OF ALASKA
U.S. West Coast. The Company conducts wholesale marketing operations along
the U.S. West Coast, primarily in Oregon and Washington, selling refined
products in the bulk market and through eight terminal facilities, including
three operated by the Company. In 1997, these operations sold approximately
10,300 barrels per day of refined products, primarily gasoline and diesel fuel,
of which approximately 25% was received from major oil companies in exchange for
products from the Kenai Refinery, approximately 24% was received directly from
the Kenai Refinery and 51% was purchased from other suppliers. In January 1998,
operations of the three Company-operated facilities on the U.S. West Coast were
transferred to the Company's Marine Services segment.
The Company's retail presence in Oregon and Washington was expanded during
1997 by adding twelve branded stations, bringing the number of "Tesoro Alaska"
branded gasoline stations in the Pacific Northwest to 30 at year-end.
Far East. From time to time, the Company exports refined products from the
Kenai Refinery to certain markets in the Far East, including Russia. These
exported products, primarily gasoline, are transported to the Far East by a
chartered Russian flag vessel, described below, or at times by spot charters.
TRANSPORTATION
The Company charters two American flag vessels, the Potomac Trader and the
Chesapeake Trader. These vessels are used to transport ANS crude oil from the
Trans Alaska Pipeline System ("TAPS") terminal at Valdez, Alaska and Cook Inlet
crude oil from the Drift River terminal to the Kenai Refinery. The vessels are
also used to transport heavy oils and residual products to the U.S. West Coast
and occasionally to transport other feedstocks or products to the Kenai
Refinery. The Potomac Trader and Chesapeake Trader are chartered under five-year
agreements expiring in 2000. The Company charters a Russian flag vessel, the
Igrim, to primarily transport refined products from the Kenai Refinery to the
Far East. The Igrim is chartered under
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an agreement expiring in June 1998, which may be extended at the Company's
option through June 2000. The Company plans to continue marketing its products
in the Far East and is evaluating transportation alternatives. From time to
time, the Company also charters tankers and ocean-going barges to transport
petroleum products to its customers within Alaska, on the U.S. West Coast and in
the Far East.
The Company operates a common carrier petroleum products pipeline from the
Kenai 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 1997, the pipeline
transported an average of approximately 24,100 barrels of petroleum products per
day, all of which were transported for the Company. The Company also owns and
operates KPL, a common carrier pipeline and marine dock facility, which assures
the Company of uninterrupted use of the dock and pipeline for unloading crude
oil feedstocks and loading product inventory on tankers and barges. During 1997,
KPL transported approximately 49,700 barrels of crude oil per day and 37,300
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."
REFINING AND MARKETING STATISTICS
The following table summarizes the Company's refining and marketing
operations for the years ended December 31, 1997, 1996 and 1995:
1997 1996 1995
------- ------- -------
Kenai Refinery Throughput:
Barrels per day..................................... 50,207 47,486 50,569
% ANS crude oil..................................... 71% 72% 68%
Refined Products Manufactured (average daily barrels):
Gasoline and gasoline blendstocks................... 12,851 12,763 14,298
Middle distillates, including jet fuel and diesel
fuel............................................. 21,636 19,975 20,693
Heavy oils and residual products.................... 14,752 13,739 14,516
Other............................................... 2,279 2,600 2,489
------- ------- -------
Total Refined Products Manufactured......... 51,518 49,077 51,996
======= ======= =======
Total Segment Product Sales (average daily
barrels)(a):
Gasoline............................................ 17,393 17,427 24,526
Middle distillates.................................. 30,576 29,651 37,988
Heavy oils and residual products.................... 17,929 15,089 14,787
------- ------- -------
Total Product Sales......................... 65,898 62,167 77,301
======= ======= =======
Total Segment Product Sales Prices ($/barrel):
Gasoline............................................ $ 33.71 $ 32.72 $ 28.21
Middle distillates.................................. $ 28.36 $ 29.01 $ 24.40
Heavy oils and residual products.................... $ 17.30 $ 17.61 $ 13.66
Number of Stations Selling the Kenai Refinery's
Gasoline(b):
Alaska --
Company-operated(c).............................. 35 33 32
Branded.......................................... 129 126 99
Unbranded........................................ 28 29 28
Pacific Northwest -- branded........................ 30 18 10
------- ------- -------
Total Stations.............................. 222 206 169
======= ======= =======
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(a) Sources of total product sales include products manufactured at the Kenai
Refinery, products drawn from inventory balances and products purchased
from third parties. The Company's purchases of refined
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products for resale were approximately 11,300, 11,600 and 25,500 average
daily barrels for 1997, 1996 and 1995, respectively.
(b) Branded gasoline stations sell the Kenai Refinery's gasoline under the
"Tesoro Alaska" name in Alaska, Oregon and Washington (total of 192
stations) and under the "Union 76" name in Southeast Alaska (total of two
stations). Stations that sell the Company's gasoline under a different name
are considered unbranded.
(c) Company-operated stations include branded 7-Eleven convenience store
locations in Alaska.
EXPLORATION AND PRODUCTION
OVERVIEW
The Company's Exploration and Production segment is engaged in the
exploration, development and production of natural gas and oil onshore in Texas,
Louisiana and Bolivia. This segment also includes the transportation of natural
gas, including the Company's production, to common carrier pipelines in South
Texas. During 1997, the Company increased its worldwide net proved reserves by
39% to 517 Bcfe of natural gas. Worldwide net production of natural gas and oil
averaged 109 million cubic feet equivalents ("MMcfe") per day during 1997 and
increased to approximately 125 MMcfe per day in January 1998.
In the U.S., the Company has made significant progress in diversifying its
operations to areas other than the mature Bob West Field in South Texas. The
Company's U.S. production from fields other than the Bob West Field rose to 50%
of its total U.S. production in January 1998, as compared to 7% at year-end
1996. During the past two years, the Company has acquired approximately 120,000
net undeveloped acres in the U.S., bringing its total to approximately 133,000
net undeveloped U.S. acres at December 31, 1997. During 1996 and 1997, the
Exploration and Production segment purchased interests in the Frio/Vicksburg
Trend and the Wilcox Trend in South Texas, in the Val Verde Basin in Southwest
Texas and in the East Texas Basin. By January 1998, the Company served as
operator of 44% of its U.S. net production, compared to 5% at year-end 1996.
During 1997, the Company's U.S. net proved reserve volumes increased 27% to 150
Bcfe and net production averaged 87 MMcfe per day. The Company participated in
the completion of nine gross development wells and eight gross exploratory wells
in 1997, with seven gross wells drilling at year-end.
In Bolivia, the Company operates under four contracts with the Bolivian
government to explore for and produce hydrocarbons. The Company's Bolivian
natural gas production is sold under contract to the Bolivian government for
export to Argentina. The majority of the Company's natural gas and oil reserves
in Bolivia are shut-in awaiting access to gas-consuming markets which is
expected to be provided by a 1,900-mile pipeline from Bolivia to Brazil.
Pipeline construction began in 1997 and first gas deliveries are expected in
early 1999. In July 1997, the Company acquired the interests of its former joint
venture participant, increasing its net proved reserve volumes in Bolivia by
35%. During 1997, the Company's Bolivian net proved reserve volumes increased in
total by 45% to 366 Bcfe and net production averaged 23 MMcfe per day.
UNITED STATES
WILCOX TREND
The Company has 23,088 net acres, including 17,147 net undeveloped acres,
under lease in the Wilcox Trend. Approximately 52% (78.4 Bcfe) of the Company's
U.S. net proved reserve volumes are located in eleven producing fields in this
trend, including the Bob West Field, the Company's largest U.S. field. 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.
Bob West Field. The Bob West Field, which was discovered by the Company in
1990, is located in the southern part of the Wilcox Trend in Starr and Zapata
Counties, Texas. Continued successful development of the Bob West Field led to
the completion of three development wells during 1997. This concluded the
drilling program in this 4,000-acre field, after drilling and completing a total
of 77 gross wells since 1991, 14 of which were sold during 1995. During 1997,
the Company's net natural gas production from the Bob West Field
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averaged approximately 66 million cubic feet ("MMcf") per day. The Company's
estimated net proved reserve volumes in the Bob West Field totaled 59 Bcfe at
December 31, 1997.
The Company's working interests in wells located in the Bob West Field
range from 33% to 70%. In addition, the Company owns a 70% interest in the
field's central gas processing facility which has a gross capacity of 350 MMcf
per day. The Company also owns 25% of a central compression facility, rated at
17,770 horsepower with an estimated gross capacity of 150 MMcf per day.
Berry R. Cox Field. In December 1997, a development well, the Gonzales No.
8, located in Webb County, Texas, was completed in the Berry R. Cox Field.
Tesoro has a 100% working interest in the Gonzales unit. The Company purchased
its working interest in the unit in transactions during 1996 and 1997 for a
total of $3.2 million. At the time of the initial purchase, the unit had two
wells producing a total of 1.8 MMcf per day and three shut-in wells. The Company
began a drilling program in the fall of 1996 that included the drilling and
completion of the Gonzales No. 7 exploratory well in 1996 and the Gonzales No. 8
development well plus a recompletion of one existing well in 1997. Production
from this field, including the Gonzales No. 8 well, averaged 33 MMcf per day
gross (25 net) in January 1998. The locations for the Gonzales No. 8 well and
the currently drilling Gonzales No. 9 well were identified using
three-dimensional ("3-D") seismic data. Because there is an offset operator in
the reservoir containing the Gonzales No. 7 and No. 8 wells, the Company has
applied to the Texas Railroad Commission for the determination of a fair
allocation formula governing allowable production from the reservoir by each
operator. On February 24, 1998, the Commission issued a temporary order
restricting each operator's production from that reservoir to 25 MMcf per day
gross (19 net) until final disposition is made related to the Company's
application. The Company's estimated net proved reserve volumes in the Berry R.
Cox Field totaled 8.6 Bcfe at December 31, 1997.
FRIO/VICKSBURG TREND
The Company has 7,667 net acres, including 2,897 net undeveloped acres,
under lease in the Frio/Vicksburg Trend. Approximately 24% (36.5 Bcfe) of the
Company's U.S. net proved reserve volumes are located in eight producing fields
in this trend, primarily the Los Indios, La Reforma and Kent Bayou Fields. The
Frio/Vicksburg Trend lies between the Gulf Coast shoreline and the Wilcox Trend.
Los Indios and La Reforma Fields. In December 1996, the Company purchased
25% to 50% working interests in portions of the Los Indios and La Reforma
Fields, located in Hidalgo and Starr Counties in South Texas, for $15 million.
The Company's working interest covers 11,700 gross acres, which is being
evaluated using 50 square miles of 3-D seismic data. During 1997, two
exploratory wells and two development wells were completed in the La Reforma
Field. These two fields produced an average of 5 MMcfe per day net in 1997.
Additional drilling is planned in 1998. The Company's estimated net proved
reserve volumes in these fields totaled 23 Bcfe at December 31, 1997, an
increase of 17% over year-end 1996.
Kent Bayou Field. In November 1997, the Company purchased a 73.7% working
interest in one producing well and a 100% working interest in 920 acres
adjoining the producing unit located in the Kent Bayou Field in Terrebonne
Parish, Louisiana. Production for January 1998 averaged 3 MMcf per day gross
(1.5 net) of natural gas and 114 barrels per day gross (59 net) of condensate. A
3-D seismic survey is being analyzed to identify potential development
locations. The Company's estimated net proved reserve volumes in the Kent Bayou
Field totaled 10.5 Bcfe at December 31, 1997.
EAST TEXAS BASIN
The Company has 16,988 net acres, including 14,064 net undeveloped acres,
under lease in the East Texas Basin. The undeveloped acreage is located on
prospects in the Cotton Valley Pinnacle Reef play and on prospects targeting
various Cretaceous aged objectives. The Company is currently acquiring 3-D
seismic surveys to evaluate its acreage holdings. Approximately 14% (21.3 Bcfe)
of the Company's U.S. net proved reserve volumes are in this basin, which is
located in the northeastern part of Texas.
Oak Hill, Woodlawn and Carthage Fields. In December 1997, the Company
purchased interests in three natural gas fields in East Texas from private
interests for approximately $5.1 million. The properties included
7
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interests in the Oak Hill Field in Rusk County, the Woodlawn Field in Harrison
County and the Carthage Field in Panola County. The Company purchased an average
90% working interest in seven mature producing wells and approximately 3,500 net
acres. The Company serves as operator of these properties. Under current spacing
rules regulating development of these fields, approximately 30 infill drilling
locations have been identified. A drilling program in these fields commenced
during the first quarter of 1998. The Company's estimated net proved reserves in
these fields totaled 21 Bcfe at December 31, 1997. Production during January
1998 averaged approximately 1.3 MMcfe per day gross (0.9 net).
VAL VERDE BASIN
The Company has 94,761 net acres, primarily undeveloped, under lease in the
Val Verde Basin in Edwards and Val Verde Counties, Texas. Approximately 10%
(14.3 Bcfe) of the Company's U.S. net proved reserve volumes are in this basin,
which is located in the southwestern part of Texas.
Vinegarone East Field. The Company discovered the Vinegarone East Field,
located in Edwards County, Texas, in 1996. The Company's working interests range
from 75% to 100%. A second exploration well and two development wells were
completed in this field during 1997. The field began production in September
1997 following completion of a 10-mile, 6-inch gathering line. Production from
this field averaged 8 MMcf per day net during the last four months of 1997 and
9.5 MMcf per day net during the first two months of 1998. Additional development
wells are planned in 1998. The Company's estimated net proved reserves in this
field totaled 14 Bcfe at December 31, 1997.
RESERVES
The following table shows the estimated net proved reserves, based on
evaluations audited by Netherland, Sewell & Associates, Inc., and gross
producing wells for each of the Company's U.S. fields:
DECEMBER 31, 1997 DECEMBER 31, 1996
------------------------------------------- ------------------
PRESENT NET PROVED GAS NET PROVED GAS
VALUE OF GROSS RESERVES RESERVES
PROVED PRODUCTIVE -------------- ------------------
FIELD LOCATION RESERVES(A) WELLS BCFE % BCFE %
----- -------- ------------- ---------- ------ ---- ------- -----
($ THOUSANDS)
Bob West South Texas $ 74,659 63 59.0 39% 88.0 75%
Los Indios South Texas 11,751 26 15.3 10 16.8 14
Vinegarone East Southwest Texas 16,457 4 14.3 10 -- --
Kent Bayou South Louisiana 13,749 1 10.5 7 -- --
Oak Hill East Texas 5,389 5 9.9 7 -- --
Berry R. Cox South Texas 14,426 5 8.6 6 2.9 3
La Reforma South Texas 8,558 18 7.7 5 2.8 2
Woodlawn East Texas 3,883 2 6.5 4 -- --
Carthage East Texas 2,740 -- 4.7 3 -- --
Other 15,883 54 13.9 9 7.4 6
-------- --- ----- --- ----- ---
$167,495 178 150.4 100% 117.9 100%
======== === ===== === ===== ===
- ---------------
(a) Represents the discounted future net cash flows before income taxes. See
Note N of Notes to Consolidated Financial Statements in Item 8 for
additional information regarding the Company's proved reserves and
standardized measure.
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 in South
Texas to common carrier pipeline facilities. In addition, the Company owns a 50%
interest in the twenty-inch diameter Starr-Zapata Pipe Line, which transports
natural gas 26 miles from the Starr County Gathering System to a market hub at
Fandango, Texas. The Company does not operate either
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pipeline. During 1997, gross throughput averaged 169 MMcf per day for both the
Starr County Gathering System and the Starr-Zapata Pipe Line, with approximately
50% of the throughput consisting of the Company's working interest of Bob West
Field production. The Starr County Gathering System receives a transportation
fee of $0.06 per Mcf and the Starr-Zapata Pipe Line receives a fee of $0.07 per
Mcf for volumes transported.
MARKETING
The Company's U.S. natural gas production is sold on the spot market and
under short-term contracts with a variety of purchasers, including intrastate
and interstate pipelines, their marketing affiliates, independent marketing
companies and other purchasers who have the ability to move the gas under firm
transportation or interruptible agreements. Prices for the Company's natural gas
production are subject to regional discounts or premiums tied to regional spot
market prices.
U.S. ACREAGE AND PRODUCTIVE WELLS
The Company holds its U.S. acreage through oil and natural gas leases and
lease options. The leases have a variety of primary terms and may require delay
rentals to continue the primary term if not productive. The leases may be
surrendered by the operator at any time for various reasons, which may include
cessation of production, fulfillment of commitments, or failure to make timely
payment of delay rentals. The following tables set forth the Company's U.S.
gross and net acreage and productive wells at December 31, 1997:
UNDEVELOPED ACREAGE DEVELOPED ACREAGE
-------------------- ------------------
LOCATION GROSS NET GROSS NET
-------- -------- -------- ------- -------
Val Verde Basin, Southwest Texas............. 98,466 94,401 480 360
East Texas Basin, East Texas................. 56,278 14,064 3,303 2,924
Wilcox Trend, South Texas.................... 37,986 17,147 19,349 5,941
Frio/Vicksburg Trend, South Texas............ 4,034 2,017 10,556 4,538
Frio/Vicksburg Trend, South Louisiana........ 880 880 315 232
------- ------- ------ ------
Total Leased Acres......................... 197,644 128,509 34,003 13,995
Fee Acres, Various Locations................. 15,838 4,352 338 325
------- ------- ------ ------
Total Acres................................ 213,482 132,861 34,341 14,320
======= ======= ====== ======
GAS WELLS OIL WELLS
------------------ ----------------
GROSS NET GROSS NET
------- ------- ------ ------
Productive Wells(a).......................... 168 86.9 10 5.4
- ---------------
(a) Includes three gross (1.6 net) gas wells and two gross (1.0 net) oil wells
with multiple completions. At December 31, 1997, the Company was
participating in the drilling of seven gross (6.3 net) wells.
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U.S. OPERATING STATISTICS
The following table summarizes the Company's U.S. exploration and
production activities for the years ended December 31, 1997, 1996 and 1995:
1997 1996 1995
------ ------- --------
Average Daily Net Production:
Natural gas (Mcf)................................... 86,052 87,654 114,490
Oil (barrels)....................................... 118 27 1
Total (Mcfe)........................................ 86,760 87,816 114,496
Average Prices:
Natural gas ($/Mcf)--
Spot market(a)................................... $ 2.17 $ 1.95 $ 1.34
Average(b)....................................... $ 2.17 $ 2.75 $ 2.57
Oil ($/barrel)...................................... $18.90 $ 21.99 $ 16.82
Average Operating Expenses ($/thousand cubic feet
equivalent ("Mcfe")):
Lease operating expenses............................ $ 0.20 $ 0.14 $ 0.11
Severance taxes..................................... 0.03 0.03 0.18
------ ------- --------
Total production costs........................... 0.23 0.17 0.29
Administrative support and other.................... 0.07 0.10 0.06
------ ------- --------
Total Operating Expenses......................... $ 0.30 $ 0.27 $ 0.35
====== ======= ========
Depletion ($/Mcfe).................................... $ 0.93 $ 0.79 $ 0.69
Exploratory Wells Drilled(c):
Productive -- gross................................. 8.0 4.0 5.0
Productive -- net................................... 6.3 1.7 1.5
Dry holes -- gross.................................. 4.0 2.0 4.0
Dry holes -- net.................................... 2.9 1.0 2.1
Development Wells Drilled(c):
Productive -- gross................................. 9.0 15.0 17.0
Productive -- net................................... 5.1 6.3 9.7
Dry holes -- gross.................................. 2.0 1.0 --
Dry holes -- net.................................... 1.0 0.5 --
- ---------------
(a) Includes effects of the Company's natural gas commodity price agreements
which amounted to losses of $0.05 per Mcf and $0.11 per Mcf in 1997 and
1996, respectively, and a gain of $0.01 per Mcf in 1995 (see Note N of
Notes to Consolidated Financial Statements in Item 8).
(b) Includes effects in 1996 and 1995 of above-market pricing provisions under
a natural gas contract which was terminated effective October 1, 1996 (see
Note D of Notes to Consolidated Financial Statements in Item 8).
(c) All of the Company's drilling is performed by independent drilling
contractors.
For further information regarding the Company's U.S. exploration and
production operations, see Notes B, C and N of Notes to Consolidated Financial
Statements in Item 8.
BOLIVIA
The Company's Bolivian exploration, development and production operations
are located in the Chaco Basin in southern Bolivia near the border of Argentina.
The Company has discovered six fields in Bolivia since 1976, five of which have
currently estimated proved reserves totaling 366 Bcfe at December 31, 1997. The
Company intends to complete additional seismic studies and appraisal wells
before assigning proved reserves
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to the sixth field. With gross production of 37 MMcfe per day in 1997, the
Company is one of the largest operators in Bolivia. The Company holds four
Shared Risk Contracts with Yacimientos Petroliferos Fiscales Bolivianos
("YPFB"), the Bolivian governmental agency responsible for administration of
these contracts, covering a total of 879,938 gross acres in Block 18 and Block
20.
ACQUISITION
In July 1997, the Company purchased the interests held by its former joint
venture participant in the then existing two contract blocks, consisting of a
25% interest in Block 18 and a 27.4% interest in Block 20. Upon completion of
this purchase, the Company held a 100% interest in both blocks, subject to a
farmout agreement discussed below. The purchase price was approximately $20
million, which included working capital and assumption of certain liabilities.
The Company's net proved Bolivian reserve volumes increased by approximately 35%
as a result of this acquisition.
BOLIVIAN HYDROCARBONS LAW
In 1996, a new Hydrocarbons Law was passed by the Bolivian government that
significantly impacts the Company's operations in Bolivia. The new law, among
other matters, granted the Company the option to convert its Contracts of
Operation to new Shared Risk Contracts. On November 6, 1997, the Company
completed the conversion of its Contracts of Operation into four Shared Risk
Contracts. The new contracts, which have an effective date of July 29, 1996,
extend the Company's term of operation, provide more favorable acreage
relinquishment terms and provide for a more favorable fiscal regime of royalties
and taxes. The new contract for Block 18 is extended to the year 2017. The new
contracts for Block 20 are extended to the year 2018 for Block 20-Los Suris,
which is in the development phase, and to the year 2029 for Block 20-West and
Block 20-East, which are in the exploration phase.
FARMOUT AGREEMENT
A farmout agreement executed June 19, 1997, between the Company and Total
Exploration Production Bolivie S.A. ("Total"), an affiliate of Total S.A.,
covers a portion of Block 20-West. Pursuant to the farmout agreement, Total
established a financial guarantee to the Bolivian government to guarantee the
performance of exploration work on Block 20-West. Total has the right to drill,
at its sole cost, two exploratory wells to earn a 75% interest in the farmout
area which consists of 315,000 acres of Block 20-West. If Total drills only one
well, Total will earn a 37.5% interest in the farmout area. On December 31,
1997, the Company assigned a 75% interest and operatorship in the farmout area
to Total, subject to reversion if Total does not drill two wells.
YPF AND YPFB CONTRACT
The Company is currently selling all of its natural gas production from
Block 18 to YPFB, which in turn sells the natural gas to Yacimientos
Petroliferos Fiscales, SA ("YPF"), a publicly-held company based in Argentina.
Currently, the Company's sales of natural gas are based on the volume and
pricing terms in the contract between YPFB and YPF. The Company has historically
provided approximately 20% of the contract volumes required by YPF. The contract
to sell gas to YPF expired March 31, 1997 and a contract extension was signed
effective April 1, 1997 extending the contract term two years to March 31, 1999,
with an option to extend the contract a maximum of one additional year if the
pipeline being constructed from Bolivia to Brazil is not complete. In the
contract extension, YPF negotiated an 11% reduction in the minimum contract
volume that it is required to import from Bolivia, which in turn resulted in a
corresponding 11% reduction of the Company's minimum contract volume to 36.9
MMcf per day gross (26.2 net). The contract gas prices fluctuate because they
are linked to a monthly average fuel oil price posted in the New York spot
market.
ACCESS TO NEW MARKETS
A lack of market access has constrained natural gas production in Bolivia.
With little internal gas demand, all of the Company's Bolivian natural gas
production is sold under contract to the Bolivian
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government for export to Argentina. Major developments in South America indicate
that new markets will open for the Company's production. Construction of a new
1,900-mile pipeline that will link Bolivia's extensive gas reserves with markets
in Brazil commenced in 1997 and is expected to be operational in early 1999. The
owners of the new pipeline include Petrobras (the Brazilian state oil company),
other Brazilian investors, Enron Corp., Shell International Gas Ltd., British
Gas PLC, El Paso Energy Corp., BHP, and Bolivian pension funds. When completed,
the new pipeline will have a capacity of approximately 1 billion cubic feet
("Bcf") per day.
BLOCK 18
The Company has a 100% working interest in a Shared Risk Contract covering
92,625 acres in Block 18. Approximately 30% (110 Bcfe) of the Company's Bolivian
reserve volumes are in the La Vertiente, Escondido and Taiguati Fields of Block
18. During 1997, the Company's net production from this block averaged 19.5 MMcf
of gas per day and 518 barrels of condensate per day. A 3-D seismic survey over
the Escondido Field was completed in 1997 to identify additional drilling
locations.
The Block 18 contract provides that the Company will be subject to a 29%
royalty to YPFB, and the payment of Bolivian income taxes and taxes on gross
revenues equal to 31% of gross revenues, leaving the Company with 40% of Block
18 revenues after royalties and Bolivian taxes. In respect to Block 18, the
aftertax effect of the Shared Risk Contract is approximately the same as the
previous Contract of Operation.
BLOCK 20
The Company has a 100% working interest in two Shared Risk Contracts, Block
20-Los Suris and Block 20-East, and a 25% working interest in a Shared Risk
Contract, Block 20-West, which is subject to the provisions of the farmout
agreement with Total.
Block 20-Los Suris. This contract covers 12,350 acres of the Los Suris
Field, where approximately 28% (104.2 Bcfe) of the Company's Bolivian reserve
volumes are located. Although this contract is in the development phase,
existing wells are shut-in awaiting access to markets. A 3-D seismic survey over
Block 20-Los Suris was completed in 1997 to identify additional drilling
locations.
Block 20-East. This contract, which is in the exploration phase, covers
385,938 acres and includes the Palo Marcado Field, where approximately 42%
(152.1 Bcfe) of the Company's proved Bolivian reserves are located. A 3-D
seismic survey was completed over the Palo Marcado Field in 1997 to identify
additional drilling locations.
Block 20-West. This contract covers 389,025 acres, of which 315,000 acres
are subject to the Total farmout agreement, and extends into the difficult
terrain of the Andes mountains. Total has contracted, at its sole cost, for the
drilling of the first well under the farmout agreement and it is anticipated
that this well will spud by mid-1998. The drilling cost in this area can exceed
$20 million per well due to the mountainous location and depth of the objective.
The previous Block 20 Contract of Operation provided for Bolivian taxes
equal to 31% of gross revenues and a royalty of 19% to YPFB. Under the Shared
Risk Contracts, a combination of Bolivian income taxes and taxes on gross
revenues are expected to approximate the 31% gross revenue tax in the previous
Contract of Operation and the 19% royalty to YPFB has been eliminated.
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RESERVES
The table below shows the estimated proved reserves, based on evaluations
prepared by Netherland, Sewell & Associates, Inc., and productive wells for each
of the Company's Bolivian fields. Each of the following fields is operated by
the Company:
DECEMBER 31,
DECEMBER 31, 1997 1996
----------------------------------------------------------------- -----------------
NET PROVED RESERVES
--------------------------------
OIL
(MILLIONS
PRODUCTIVE OF GAS TOTAL PV-10 AFTER PV-10 AFTER
FIELD BLOCK WELLS BARRELS) (BCF) (BCFE) % BOLIVIAN TAXES(A) BOLIVIAN TAXES(A)
----- ----- ---------- --------- ----- ------ --- ----------------- -----------------
($ THOUSANDS) ($ THOUSANDS)
Palo Marcado......... 20 2 2.0 140.1 152.1 42% $ 38,871 $24,667
Los Suris............ 20 2 1.1 97.6 104.2 28 32,685 13,135
Escondido............ 18 4 1.6 78.0 87.6 24 23,926 23,330
La Vertiente......... 18 4 0.5 19.0 22.0 6 5,971 3,090
Taiguati............. 18 1 -- 0.4 0.4 -- -- 221
-- --- ----- ----- --- -------- -------
13 5.2 335.1 366.3 100% $101,453 $64,443
== === ===== ===== === ======== =======
- ---------------
(a) Represents the discounted future net cash flows after Bolivian taxes. See
Note N of Notes to Consolidated Financial Statements in Item 8 for
additional information regarding the Company's proved reserves and
standardized measure.
BOLIVIAN ACREAGE AND PRODUCTIVE WELLS
The following table sets forth the Company's Bolivian gross and net acreage
and productive wells at December 31, 1997:
GROSS NET
------- -------
Acreage:
Developed................................................. 92,625 92,625
Undeveloped............................................... 787,313 551,063
Productive Gas Wells(a)..................................... 13 13
- ---------------
(a) Included in productive gas wells are five gross (five net) wells with
multiple completions. The Company has no producing oil wells in Bolivia.
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BOLIVIA OPERATING STATISTICS
The following table summarizes the Company's Bolivian exploration and
production activities for the years ended December 31, 1997, 1996 and 1995:
1997 1996 1995
------- ------- -------
Average Daily Net Production:
Natural gas (Mcf)................................... 19,537 20,251 18,650
Condensate (barrels)................................ 518 584 567
Total (Mcfe)........................................ 22,645 23,755 22,052
Average Price:
Natural gas ($/Mcf)................................. $ 1.15 $ 1.33 $ 1.28
Condensate ($/barrel)............................... $ 15.71 $ 17.98 $ 14.39
Average Operating Expenses ($/Mcfe):
Production costs.................................... $ 0.11 $ 0.10 $ 0.07
Value-added taxes................................... -- 0.05 0.06
Administrative support and other.................... 0.31 0.27 0.35
------- ------- -------
Total Operating Expenses......................... $ 0.42 $ 0.42 $ 0.48
======= ======= =======
Depletion ($/Mcfe).................................... $ 0.19 $ 0.15 $ 0.03
Exploratory Wells Drilled:
Productive -- gross................................. -- 2.0 1.0
Productive -- net................................... -- 1.5 0.7
Dry holes -- gross.................................. -- -- --
Dry holes -- net.................................... -- -- --
For further information regarding the Company's Bolivian operations, see
Notes B, C and N of Notes to Consolidated Financial Statements in Item 8.
WORLDWIDE RESERVE REPLACEMENT AND COSTS OF ADDING RESERVES
In 1997, the Company's worldwide net proved reserve additions included 156
Bcfe from discoveries, extensions and purchases of proved properties (89 Bcfe in
Bolivia and 67 Bcfe domestically) and 30 Bcfe from revisions of previous
estimates. Excluding revisions, 156 Bcfe were added for a 390% replacement of 40
Bcfe of production. Additions were realized with a 74% drilling success rate
during 1997, reflecting an 82% success rate on 11 development wells and a 67%
success rate on 12 exploratory wells. The Company's three-year worldwide average
cost of adding these reserves was $0.43 per Mcfe. Domestically, 67 Bcfe were
added through discoveries, extensions and acquisitions for a 209% replacement of
32 Bcfe of production. In Bolivia, 89 Bcfe were added through an acquisition, a
more than tenfold replacement of 8 Bcfe of production. The three-year average
cost of adding reserves was $0.85 per Mcfe in the U.S. and $0.14 per Mcfe in
Bolivia. See Note N of Notes to Consolidated Financial Statements in Item 8.
MARINE SERVICES
OVERVIEW
The Company's Marine Services segment markets and distributes a broad range
of products, including diesel fuel, lubricants, chemicals and supplies, and
provides logistical support services to the marine and offshore exploration and
production industries operating in the Gulf of Mexico. These operations were
conducted in 1997 through a network of 18 marine and two land terminals located
on the Texas Gulf Coast in Galveston, Freeport, Harbor Island, Port O'Connor,
Sabine Pass, Channelview and Houston and along the Louisiana Gulf Coast in
Cameron, Intracoastal City, Berwick, Venice, Port Fourchon, Amelia and Harahan.
The marine terminals are generally deep water and are bulkheaded and dredged to
provide easy access to vessels receiving products for delivery to customers.
Products are delivered offshore aboard vessels owned or chartered by customers,
which include companies engaged in oil and gas exploration and production,
seismic
14
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evaluation, offshore construction and other drilling-related businesses. In
January 1998, the Marine Services operations were expanded to include the
operations of three terminals located on the U.S. West Coast, previously
operated by the Company's Refining and Marketing segment (see "Refining and
Marketing -- Marketing Outside of Alaska" discussed above).
FUELS AND LUBRICANTS
Fuels and lubricants, which are used by operations such as offshore
drilling rigs, offshore production and transmission platforms and various ships
and equipment engaged in seismic surveys, are marketed and distributed from the
Company's terminals. These terminals and a fleet of seven tugboats (including
five owned by the Company) and 14 barges (including 12 owned by the Company)
serve offshore workboats, tugboats and barges using the Intracoastal Canal
System, as well as ships entering the ports of Houston, New Orleans, Lake
Charles, Corpus Christi and Port Arthur. Tesoro obtains its supply of fuel from
refiners in the Gulf Coast area. Total gallons of fuel, primarily diesel fuel,
sold by Marine Services amounted to 156.4 million, 142.7 million and 112.5
million in 1997, 1996 and 1995, respectively.
The Company is a distributor of major brands of marine lubricants and
greases, offering a full spectrum of grades. Lubricants are delivered to
customers by trucks or tugs and barges. Total gallons of lubricants sold by
Marine Services amounted to 2.7 million, 2.3 million and 2.5 million in 1997,
1996 and 1995, respectively.
LOGISTICAL SERVICES
Through many of its terminals, the Company provides full-service
shore-based support for offshore drilling rigs and production platforms. These
quayside services provide cranes, forklifts and loading docks for supply boats
serving the offshore exploration and production industry. In addition, the
Company provides long-term parking for offshore workers, helicopter landing pads
and office space with living quarters. Tesoro terminals also serve as delivery
points for drilling products, primarily mud, by providing warehousing, blending,
inventory control and delivery services. In 1997, 1996 and 1995, revenues from
these logistical services were $11.3 million, $8.7 million and $0.6 million,
respectively.
COMPETITION AND OTHER
The petroleum industry is highly competitive in all phases, including the
refining of crude oil, the marketing of refined petroleum products, the search
for and development of oil and gas reserves and the marine services business.
The industry also competes with other industries that supply the energy and fuel
requirements of industrial, commercial and individual consumers. The Company
competes with a substantial number of major integrated oil companies and other
companies having materially greater financial and other resources than the
Company. These competitors have a greater ability to bear the economic risks
inherent in all phases of the industry. In addition, unlike the Company, many of
its competitors produce large volumes of crude oil which can then be used in
connection with their refining operations. The North American Free Trade
Agreement has further streamlined and simplified procedures for the importation
and exportation of natural gas among Mexico, the United States and Canada. These
changes are likely to enhance the ability of Canadian and Mexican producers to
export natural gas and other products to the United States, thereby further
increasing competition for domestic sales.
The refining and marketing businesses are highly competitive, with price
being the principal factor in competition. In the refining industry, the Kenai
Refinery competes primarily with other refineries in Alaska and on the U.S. West
Coast. The Company's refining competition in Alaska includes two refineries
situated near Fairbanks and one refinery situated near Valdez. The Company
estimates that such other refineries have a combined capacity to process
approximately 184,000 barrels per day of crude oil. The Company believes that
ANS crude oil is the only feedstock used in these competing refineries. After
processing the crude oil and removing the lighter-end products, which the
Company believes represent approximately 30% of each barrel processed, these
refiners are permitted, because of their direct connection to the TAPS, to
return the remainder of the processed crude back into the pipeline system as
"return oil" in consideration for a fee, thereby eliminating their need to
market residual products. The Kenai Refinery is not directly connected to
15
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the TAPS, and the Company, therefore, cannot return its residual products to the
TAPS. The Company's refining competition from the U.S. West Coast includes many
large, integrated oil companies that do substantial business in Alaska and have
materially greater financial and other resources.
The Company is a major producer and distributor of gasoline in Alaska
through a large network of Company-operated stations and branded and unbranded
dealers and jobbers. The Company is also 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.
Competitive factors affecting the marketing of gasoline in Alaska include such
factors as product price, location and quality together with station appearance
and brand-name identification. The Company competes with other petroleum
companies, distributors and other developers for new locations. Tesoro believes
it is in a position to compete effectively as a marketer of gasoline because of
its strong presence in its core Alaska market.
The Company's jet fuel sales are concentrated in Anchorage, where it is one
of the principal suppliers to the Anchorage International Airport, which is a
major hub for air cargo traffic between manufacturing regions in the Far East
and consuming regions in the United States and Europe. The Company sells its
diesel fuel primarily on a wholesale basis. Refined products from foreign
sources also compete for distillate markets in the Company's Alaskan market
area.
The Company's Pacific Northwest marketing business is primarily a
distribution business selling to independent dealers and jobbers. In addition,
the Company sells its gasoline through 30 branded gasoline stations in the
Pacific Northwest. The Company competes against independent marketing companies
and integrated oil companies when engaging in these marketing operations.
The exploration for and production of natural gas and oil is highly
competitive in both the United States and in South America. In seeking to
acquire producing properties, new leases, concessions and exploration prospects,
the Company faces competition from both major and independent oil and natural
gas companies. Many of these competitors have financial and other resources
substantially in excess of those available to the Company and, therefore, may be
better positioned to acquire and develop prospects, hire personnel and market
production. The larger competitors may also be able to better respond to factors
that influence the market for oil and natural gas production, such as changes in
worldwide prices and governmental regulations. Such factors are beyond the
control of the Company.
The Company's natural gas production in Bolivia is sold under contract to
YPFB, which in turn exports the natural gas to Argentina, as the internal demand
for natural gas in Bolivia is limited. The Company believes that the completion
of a 1,900-mile pipeline from Bolivia to Brazil will provide access to larger
gas-consuming markets. The owners of the new pipeline include Petrobras (the
Brazilian state oil company), other Brazilian investors, Enron Corp., Shell
International Gas Ltd., British Gas PLC, El Paso Energy Corp., BHP, and Bolivian
pension funds. Upon completion of this pipeline, the Company will face intense
competition from major and independent natural gas companies operating in
Bolivia for a share of the contractual volumes to be exported to Brazil. It is
anticipated that each producer's share of the contractual volumes will be
allocated by YPFB according to a number of factors, including each producer's
reserve volumes and production capacity. Although the Company expects gas
deliveries on the pipeline to begin in early 1999, there can be no assurance
that the pipeline will be operational by such date. With the exception of the
volumes currently under contract with the Bolivian government, the Company
cannot be assured of the amount of additional volumes that will be exported to
Brazil upon completion of the pipeline.
Demand for services and products offered by the Company's Marine Services
segment is closely related to the level of oil and gas exploration, development
and production in the Gulf of Mexico. Various factors, including general
economic conditions, demand for and prices of natural gas, availability of
equipment and materials and government regulations and energy policies cause
exploration and development activity to fluctuate and directly impact the
revenues of the Marine Services segment. Management believes that the principal
competitive factors affecting the Marine Services operations are location of
facilities, availability of logistical support services, experience of personnel
and dependability of service. The market for the Marine Services segment's
products and services, particularly diesel fuel, is price sensitive. The Company
competes
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with several independent operations, and in certain locations with one or more
major mud companies who maintain their own marine terminals.
A portion of the Company's operations are conducted in foreign countries
where the Company is also subject to risks of a political nature and other risks
inherent in foreign operations. The Company's operations outside the United
States in recent years have been, and in the future may be, materially affected
by host governments through increases or variations in taxes, royalty payments,
export taxes and export restrictions and adverse economic conditions in the
foreign countries, the future effects of which the Company is unable to predict.
GOVERNMENT REGULATION AND LEGISLATION
UNITED STATES
Natural Gas and Oil 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 federal natural gas wellhead pricing and sales regulation
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 gas.
Since the latter part of 1985, through a series of orders, 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. 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
result of the changes has brought 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. Although these orders do not directly regulate gas producers,
such as the Company, they are 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 will have on the Company
and its gas sales efforts. Several aspects of these orders are still being
reviewed by the courts and the FERC. It is not possible to predict what, if any,
effect these proceedings will have on the Company. The Company does not believe,
however, that it will be affected any differently than other gas producers or
marketers with which it competes.
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.
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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 ("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, such as gasoline tank roof seal replacements at the Kenai
Refinery. Specifics as to the cost of these requirements at certain facilities
are still being determined. As part of these requirements, the Kenai Refinery as
well as some other Company facilities submitted applications for Clean Air Act
Amendment Title V permits in 1997. Each application was subsequently deemed
complete by the State of Alaska and will undergo technical review in 1998. The
Company believes it can comply with these new requirements, and in some cases
already has done so, without adversely affecting operations.
The passage of the Federal Clean Air Act Amendments of 1990 prompted
adoption of regulations by the State of Alaska obligating the Company to produce
oxygenated gasoline for delivery to the Anchorage and Fairbanks, Alaska markets
starting on November 1, 1992. Controversies surrounding the potential health
effects in Arctic regions of oxygenated gasoline containing methyl tertiary
butyl ether ("MTBE") prompted early discontinuance of the program in Fairbanks.
The EPA has been directed to conduct studies of potential health effects of
oxygenated fuel in Alaska. The State of Alaska mandated the use of oxygenated
fuels containing ethanol in the Anchorage area. No requirements for use of such
products in Fairbanks have been issued, but are expected. Additional federal
regulations promulgated on August 21, 1990, which went into effect on October 1,
1993, set limits on the quantity of sulphur in on-highway diesel fuels which the
Company produces. The State filed an application with the federal government in
February 1993 for a waiver from this requirement since only 5% of the diesel
fuel sold in Alaska was for on-highway vehicles. On March 14, 1994, the EPA
granted the State of Alaska a waiver from the requirements of the EPA's low
sulphur diesel fuel program, permanently exempting Alaska's remote areas and
providing a temporary exemption for areas served by the Federal Aid Highway
System until October 1, 1996. On August 19, 1996, the EPA extended the temporary
exemption until October 1, 1998. The Company estimates that substantial capital
expenditures would be required to enable the Company to produce low-sulphur
diesel fuel to meet these federal regulations. If the State is unable to obtain
a permanent waiver from the federal regulations, the Company would discontinue
sales of diesel fuel for on-highway use after October 1, 1998. The Company
estimates that such sales accounted for less than 1% of its refined product
sales in Alaska during 1997. 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 tankers to transport crude oil from the
Valdez, Alaska pipeline terminal through Prince William Sound and Cook Inlet to
the Kenai 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 (i) 50,000 barrels for a tanker carrying fewer than 500,000 barrels of crude
oil or (ii) 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
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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.
Regulations promulgated by the Alaska Department of Environmental
Conservation ("ADEC") would have required the installation of dike liners in
secondary containment systems for petroleum storage tanks by January 1997.
However, on December 18, 1996, ADEC approved the Company's alternative
compliance schedule which allows the Company until the year 2002 to implement
alternative secondary containment systems for all of the Company's existing
petroleum storage tank facilities. The total estimated cost of these
improvements is approximately $9 million, which is expected to be spent over a
five-year period beginning in 1998.
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 in Alaska.
The Company is required to make expenditures, that are expected to cost
approximately $1 million, for removal or upgrading of underground storage tanks
at several of its current and former service stations by December 22, 1998.
Total Environmental Expenditures. The Company's total capital expenditures
for environmental control purposes were $2.2 million during 1997. Capital
expenditures for the alternative secondary containment systems discussed above
are estimated to be $2 million in 1998 and $2 million in 1999 with the remaining
$5 million to be spent by 2002. Capital expenditures for other environmental
control purposes are estimated to be $7 million in 1998 and $2 million in 1999.
For further information regarding environmental matters, see "Legal Proceedings"
in Item 3 and "Environmental Controls", "Oil Spill Prevention and Response" and
"Underground Storage Tanks" discussed above.
BOLIVIA
The Company's operations in Bolivia are subject to the Bolivian
Hydrocarbons Law and various other laws and regulations. In the Company's
opinion, neither the Hydrocarbons Law nor other requirements currently imposed
by Bolivian laws, regulations and practices will have a material adverse effect
upon its Bolivian operations. For information on the Bolivian Hydrocarbons Law
and Bolivian taxation, see "Exploration and Production -- Bolivia" discussed
above.
EMPLOYEES
At December 31, 1997, the Company employed approximately 1,100 persons, of
which approximately 40 were located in foreign countries. None of the Company's
employees are represented by a union. The Company considers its relations with
its employees to be satisfactory.
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EXECUTIVE OFFICERS OF THE REGISTRANT
The following is a list of the Company's executive officers, their ages and
their positions with the Company at February 27, 1998.
NAME AGE POSITION POSITION HELD SINCE
---- --- -------- -------------------
Bruce A. Smith.......... 54 Chairman of the Board of Directors,
President and Chief Executive
Officer June 1996
William T. Van Kleef.... 46 Executive Vice President, Operations September 1996
James C. Reed, Jr....... 53 Executive Vice President, General
Counsel and Secretary September 1995
Donald A. Nyberg........ 46 President, Tesoro Marine Services,
Inc. November 1996
Robert W. Oliver........ 43 President, Tesoro Exploration and
Production Company September 1995
Stephen L. Wormington... 53 President, Tesoro Alaska Petroleum
Company September 1995
Don E. Beere............ 57 Vice President, Controller April 1992
Thomas E. Reardon....... 51 Vice President, Human Resources and
Environmental September 1995
Gregory A. Wright....... 48 Vice President and Treasurer September 1995
There are no family relationships among the officers listed, and there are
no arrangements or understandings pursuant to which any of them were elected as
officers. Officers are elected annually by the Board of Directors at its first
meeting following the Annual Meeting of Stockholders, each to hold office until
the corresponding meeting of the Board in the next year or until a successor
shall have been elected or shall have qualified.
All of the Company's executive officers have been employed by the Company
or its subsidiaries in an executive capacity for at least the past five years,
except for those named below who have had the business experience indicated
during that period. Positions, unless otherwise specified, are with the Company.
William T. Van Kleef.... Executive Vice President, Operations since September 1996.
Senior Vice President and Chief Financial Officer from
September 1995 to September 1996. Vice President, Treasurer
from March 1993 to September 1995. Independent financial
consultant from January 1992 to February 1993.
Donald A. Nyberg........ President of Tesoro Marine Services, Inc., a subsidiary of
the Company, since November 1996. Vice President, Strategic
Planning, of MAPCO Inc. from January 1996 to November 1996.
President and Chief Executive Officer of Marya Resources
from August 1994 to January 1996. President and Chief
Executive Officer of BP Pipelines Inc. and Vice President,
BP Exploration, of The British Petroleum Group, Ltd., from
1991 to 1994.
Robert W. Oliver........ President of Tesoro Exploration and Production Company, a
subsidiary of the Company, since September 1995. Independent
consultant from November 1994 to September 1995. Vice
President, Exploration/ Acquisitions, of Bridge Oil (USA)
Inc. from December 1988 to November 1994.
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Stephen L. Wormington... President of Tesoro Alaska Petroleum Company, a subsidiary
of the Company, since September 1995. Vice President, Supply
and Operations Coordination, of Tesoro Alaska Petroleum
Company from April 1995 to September 1995. General Manager,
Strategic Projects, from January 1995 to April 1995.
Executive Vice President, Special Projects, of MG Refining &
Marketing, Inc. from January 1994 to January 1995. Executive
Vice President of MG Natural Gas Corp. from May 1992 to
January 1994.
Thomas E. Reardon....... Vice President, Human Resources and Environmental since
September 1995. Vice President, Human Resources and
Environmental Services of Tesoro Petroleum Companies, Inc.,
a subsidiary of the Company, from October 1994 to September
1995. Vice President, Human Resources of Tesoro Petroleum
Companies, Inc. from February 1990 to October 1994.
Gregory A. Wright....... Vice President and Treasurer since September 1995. Vice
President, Corporate Communications from February 1995 to
September 1995. Vice President, Corporate Communications of
Tesoro Petroleum Companies, Inc., a subsidiary of the
Company, 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.
ITEM 2. PROPERTIES
See information appearing under Item 1, Business herein and Notes B, C and
N of Notes to Consolidated Financial Statements in Item 8.
ITEM 3. LEGAL PROCEEDINGS
The Company, along with numerous other parties, has been identified by the
Environmental Protection Agency ("EPA") as a potentially responsible party
("PRP") pursuant to the Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA") for the Mud Superfund site in Abbeville, Louisiana
("Site"). The Company arranged for the disposal of a minimal amount of materials
at the Site, but CERCLA might impose joint and several liability on each PRP at
the Site. The EPA is seeking reimbursement for its response costs incurred to
date at the Site, as well as a commitment from the PRPs either to conduct future
remedial activities or to finance such activities. The extent of the Company's
allocated financial contributions to the cleanup of the site is expected to be
limited based upon the number of companies, volumes of waste involved, and an
estimated total cost of approximately $500,000 among all of the parties to close
the Site. The Company is currently involved in settlement discussions with the
EPA and other PRPs involved at the Site. The Company expects, based on these
discussions, that its liability at the Site will not exceed $25,000.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
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PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's Common Stock is listed under the symbol "TSO" on the New York
Stock Exchange and the Pacific Stock Exchange. The per share market price ranges
for the Company's Common Stock on the New York Stock Exchange during 1997 and
1996 are summarized below:
1997 1996
---------------------- ----------------------
QUARTERS ENDED HIGH LOW HIGH LOW
-------------- ---- --- ---- ---
March 31..................................... $14 1/2 $10 3/8 $9 1/8 $ 8
June 30...................................... $15 $10 1/4 $11 5/8 $8 1/4
September 30................................. $18 3/16 $14 3/4 $13 1/2 $10 1/2
December 31.................................. $18 3/16 $15 $15 1/2 $12 7/8
At February 27, 1998, there were approximately 3,500 holders of record of
the Company's 26,661,845 outstanding shares of Common Stock. The Company has not
paid dividends on its Common Stock since 1986.
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. The Board of Directors has no present plans to pay dividends. However,
from time to time, the Board of Directors reevaluates the feasibility of
declaring future dividends.
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ITEM 6. SELECTED FINANCIAL DATA
The selected consolidated financial data should be read in conjunction with
Management's Discussion and Analysis of Financial Condition and Results of
Operations in Item 7 and the Company's Consolidated Financial Statements,
including the notes thereto, in Item 8.
YEARS ENDED DECEMBER 31,
-----------------------------------------------
1997 1996 1995 1994 1993
------- -------- -------- ------ ------
(DOLLARS IN MILLIONS EXCEPT PER SHARE AMOUNTS)
REVENUES
Gross Operating Revenues:
Refining and Marketing
Refined products.................................... $ 643.7 $ 620.8 $ 664.5 $582.7 $590.9
Other, primarily crude oil resales and
merchandise....................................... 77.2 124.6 106.5 104.3 96.3
Exploration and Production
U.S.(a)............................................. 73.6 93.8 113.0 90.6 49.4
Bolivia............................................. 11.2 13.7 11.7 13.2 12.6
Marine Services(b).................................... 132.2 122.5 74.5 77.9 80.7
------- -------- -------- ------ ------
Total Gross Operating Revenues...................... 937.9 975.4 970.2 868.7 829.9
Income from Settlement of a Natural Gas Contract and
Other(a).............................................. 5.5 64.4 32.7 3.2 0.5
------- -------- -------- ------ ------
Total Revenues...................................... $ 943.4 $1,039.8 $1,002.9 $871.9 $830.4
======= ======== ======== ====== ======
SEGMENT OPERATING PROFIT (LOSS)(C)
Refining and Marketing................................ $ 20.5 $ 6.0 $ 0.7 $ 2.4 $ 15.2
Exploration and Production
U.S.(a)............................................. 37.3 123.9 102.0 55.0 32.3
Bolivia............................................. 8.6 8.8 7.6 9.3 8.4
Marine Services(b).................................... 6.3 6.1 (4.4) (2.3) (3.6)
------- -------- -------- ------ ------
Total Segment Operating Profit...................... $ 72.7 $ 144.8 $ 105.9 $ 64.4 $ 52.3
======= ======== ======== ====== ======
EARNINGS BEFORE EXTRAORDINARY ITEM...................... $ 30.7 $ 76.8 $ 57.5 $ 20.5 $ 17.0
EXTRAORDINARY LOSS ON DEBT EXTINGUISHMENTS,
NET OF INCOME TAXES(D)................................ -- (2.3) (2.9) (4.8) --
------- -------- -------- ------ ------
NET EARNINGS............................................ $ 30.7 $ 74.5 $ 54.6 $ 15.7 $ 17.0
======= ======== ======== ====== ======
NET EARNINGS APPLICABLE TO COMMON STOCK................. $ 30.7 $ 74.5 $ 54.6 $ 13.0 $ 7.8
======= ======== ======== ====== ======
NET EARNINGS PER SHARE -- BASIC(E)...................... $ 1.16 $ 2.87 $ 2.22 $ 0.58 $ 0.55
NET EARNINGS PER SHARE -- DILUTED(E).................... $ 1.14 $ 2.81 $ 2.18 $ 0.56 $ 0.54
WEIGHTED AVERAGE COMMON SHARES -- BASIC................. 26.4 26.0 24.6 22.6 14.1
WEIGHTED AVERAGE COMMON SHARES AND POTENTIALLY DILUTIVE
COMMON SHARES -- DILUTED.............................. 26.9 26.5 25.1 23.2 14.3
EBITDA, CONSOLIDATED(F)................................. $ 102.2 $ 172.0 $ 125.4 $ 80.8 $ 55.8
CASH FLOWS FROM (USED IN)
Operations............................................ $ 95.6 $ 178.9 $ 35.4 $ 60.3 $ 21.8
Investing............................................. (151.5) (94.2) 2.4 (91.2) (23.4)
Financing............................................. 41.5 (75.9) (37.8) 8.3 (8.7)
------- -------- -------- ------ ------
Increase (Decrease) in Cash and Cash Equivalents.... $ (14.4) $ 8.8 $ -- $(22.6) $(10.3)
======= ======== ======== ====== ======
CAPITAL EXPENDITURES
Refining and Marketing................................ $ 43.9 $ 11.1 $ 9.3 $ 32.0 $ 7.1
Exploration and Production
U.S................................................. 65.4 59.7 49.6 65.6 29.3
Bolivia............................................. 27.5 6.9 3.8 -- --
Marine Services....................................... 9.4 6.9 0.4 0.2 0.3
Other................................................. 1.3 0.4 0.8 1.8 0.8
------- -------- -------- ------ ------
Total Capital Expenditures.......................... $ 147.5 $ 85.0 $ 63.9 $ 99.6 $ 37.5
======= ======== ======== ====== ======
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YEARS ENDED DECEMBER 31,
-----------------------------------------------
1997 1996 1995 1994 1993
------- -------- -------- ------ ------
(DOLLARS IN MILLIONS EXCEPT PER SHARE AMOUNTS)
BALANCE SHEET
Current Assets........................................ $ 181.8 $ 237.3 $ 182.5 $182.1 $196.5
Property, Plant and Equipment, Net.................... $ 413.8 $ 316.5 $ 261.7 $273.3 $213.2
Total Assets.......................................... $ 627.8 $ 582.6 $ 519.2 $484.4 $434.5
Current Liabilities................................... $ 107.5 $ 137.8 $ 105.0 $ 96.2 $ 72.0
Long-Term Debt and Other Obligations, Less Current
Maturities(d)(g).................................... $ 115.3 $ 79.3 $ 155.0 $192.2 $180.7
Redeemable Preferred Stock(g)......................... $ -- $ -- $ -- $ -- $ 78.1
Stockholders' Equity(g)(h)............................ $ 333.0 $ 304.1 $ 216.5 $160.7 $ 58.5
Current Ratio......................................... 1.69:1 1.72:1 1.74:1 1.89:1 2.73:1
Working Capital....................................... $ 74.3 $ 99.5 $ 77.5 $ 85.9 $124.5
Long-Term Debt and Redeemable Preferred
Stock to Capitalization(d)(g)....................... 26% 21% 42% 54% 82%
Common Stock Outstanding (millions)(g)................ 26.3 26.4 24.8 24.4 14.1
Book Value Per Common Share........................... $ 12.66 $ 11.51 $ 8.74 $ 6.59 $ 1.81
- ---------------
(a) Results for 1996, 1995, 1994 and 1993 include revenues from above-market
pricing provisions of a natural gas contract which was terminated effective
October 1, 1996. Operating profit included $25 million, $47 million, $39
million and $20 million in 1996, 1995, 1994 and 1993, respectively, from
the excess of these contract prices over spot market prices. Upon
termination of the contract, the Exploration and Production segment
recorded other income and operating profit of $60 million. In 1995, the
Exploration and Production segment recorded other income and operating
profit of $33 million from the sale of certain interests in the Bob West
Field. See Notes C and D of Notes to Consolidated Financial Statements in
Item 8.
(b) Beginning in February 1996, the Marine Services segment includes the
results of operations of an acquired entity. See Note C of Notes to
Consolidated Financial Statements in Item 8.
(c) Segment operating profit (loss) is gross operating revenues, gains and
losses on asset sales and other income less applicable segment costs of
sales, operating expenses, depreciation, depletion and other items. Income
taxes, interest expense and corporate general and administrative expenses
are not included in determining operating profit.
(d) Extraordinary losses on debt extinguishments, net of income tax benefits,
were $2.3 million ($0.09 per basic and diluted share), $2.9 million ($0.12
per basic share, $0.11 per diluted share) and $4.8 million ($0.21 per basic
and diluted share) in 1996, 1995 and 1994, respectively. See Note I of
Notes to Consolidated Financial Statements in Item 8.
(e) Earnings per share amounts for periods prior to 1997 have been restated,
where appropriate, to conform with the requirements of Statement of
Financial Accounting Standard ("SFAS") No. 128. See Note A of Notes to
Consolidated Financial Statements in Item 8.
(f) EBITDA, consolidated, represents earnings before extraordinary item,
interest expense, income taxes and depreciation, depletion and
amortization. While not purporting to reflect any measure of the Company's
operations or cash flows, EBITDA is presented for additional analysis.
(g) In 1994, the Company restructured its outstanding debt and preferred stock
by completing a recapitalization and equity offering.
(h) The Company has not paid dividends on its Common Stock since 1986.
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Those statements in the Management's Discussion and Analysis that are not
historical in nature should be deemed forward-looking statements that are
inherently uncertain. See "Forward-Looking Statements" on page 42 for discussion
of the factors which could cause actual results to differ materially from those
projected in such statements.
GENERAL
The Company is focused on its long-term strategy to maximize returns and
develop full value of its assets through strategic expansions, acquisitions and
diversifications in all of its operating segments. In the Refining and Marketing
segment, the Company has been engaged in studies to improve profitability and
continues to explore and evaluate opportunities for possible expansion through
acquisitions, as well as joint ventures and strategic alliances. Operating
strategies have been implemented to optimize the refinery product slate, improve
efficiencies and reliability, and expand marketing to increase placement of
products in Alaska. In 1998, the Company plans to further improve profitability
in the Refining and Marketing segment by enhancing processing capabilities,
strengthening marketing channels and improving supply and transportation
functions. In the Exploration and Production segment, the strategy includes
evaluating ways in which the Company can continue to diversify its oil and gas
reserve base through both acquisitions and activities at the drill bit and
enhance its technical capabilities. The Company has made significant progress in
diversifying its U.S. operations to areas other than the mature Bob West Field
and has taken steps to begin serving emerging markets in South America. In the
Marine Services segment, improved profitability has positioned this segment to
participate in the consolidation of the industry by pursuing opportunities for
expansion, as well as optimizing existing operations.
In March 1998, the Company entered into an agreement to acquire the
Hawaiian refining and marketing assets of BHP Petroleum Americas Refining Inc.
("BHP Refining") and BHP Petroleum South Pacific Inc. ("BHP South Pacific"). The
acquisition, if consummated, will nearly double Tesoro's annual revenues and
significantly increase the scope of Tesoro's refining and marketing operations.
The Company expects that the results of the acquisition will be accretive to
earnings and cash flows, although it may be neutral in 1998 primarily due to a
scheduled maintenance turnaround at the Hawaii refinery to begin in June. The
Company is currently in discussions with its investment bankers to arrange for
financing of the acquisition and associated working capital and letter of credit
requirements, and in connection with such discussions, the Company has been
advised that sufficient funds will be made available. The Company will continue
to pursue other opportunities that are operationally and geographically
complementary with its asset base. For further information regarding the
proposed acquisition, see "Capital Resources and Liquidity" herein and Note O of
Notes to Consolidated Financial Statements in Item 8.
As part of the Company's long-term strategy, growth initiatives are planned
in 1998 with a capital budget of $195 million, excluding the acquisition
discussed above. The 1998 capital budget represents an increase of 33% over 1997
capital expenditures. Approximately 70% of the 1998 capital budget is directed
toward increased drilling, both in Bolivia and the U.S. Another 25% is planned
for downstream operations, primarily improvements in the Alaska marketing
operations. External growth initiatives are primarily aimed at acquisitions
which would add value from the combination with the Company's existing assets,
such as strengthening marketing opportunities, reducing logistic expenses or, in
the downstream operations, offering increased processing opportunities.
Initiatives to improve the profitability of each of the business segments,
together with a debt-to-capitalization ratio of 26%, have positioned the Company
to fund possible acquisitions and the capital budget with low-cost capital.
The Company operates in an environment where its results and cash flows are
sensitive to volatile changes in energy prices. Major shifts in the cost of
crude oil used for refinery feedstocks and the price of refined products can
result in a change in margin from the Refining and Marketing operations, as
prices received for refined products may or may not keep pace with changes in
crude oil costs. These energy prices, together with volume levels, also
determine the carrying value of crude oil and refined product inventory. The
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Company uses the last-in, first-out ("LIFO") method of accounting for
inventories of crude oil and U.S. wholesale refined products in its Refining and
Marketing segment. This method results in inventory carrying amounts that are
less likely to represent current values and in costs of sales which more closely
represent current costs. Likewise, changes in natural gas, condensate and oil
prices impact revenues and the present value of estimated future net revenues
and cash flows from the Company's Exploration and Production operations. The
Company may increase or decrease its natural gas production in response to
market conditions. The carrying value of oil and gas assets may be subject to
noncash write-downs based on changes in natural gas prices and other determining
factors. Changes in natural gas prices also influence the level of drilling
activity in the Gulf of Mexico. The Company's Marine Services operation, whose
customers include offshore drilling contractors and related industries, could be
impacted by significant fluctuations in natural gas prices. The Company's Marine
Services segment uses the first-in, first-out ("FIFO") method of accounting for
inventories of fuels. Changes in fuel prices can significantly impact inventory
valuations and costs of sales in this segment.
RESULTS OF OPERATIONS
SUMMARY
Tesoro's net earnings for 1997 were $30.7 million ($1.16 per basic share,
$1.14 per diluted share) compared to $74.5 million ($2.87 per basic share, $2.81
per diluted share) in 1996 and $54.6 million ($2.22 per basic share, $2.18 per
diluted share) in 1995. In 1996 and 1995, the Company incurred noncash aftertax
extraordinary losses of $2.3 million and $2.9 million, respectively, for early
extinguishments of debt. Earnings before extraordinary losses amounted to $76.8
million ($2.96 per basic share, $2.90 per diluted share) and $57.5 million
($2.34 per basic share, $2.29 per diluted share) in 1996 and 1995, respectively.
Results for 1996 and 1995 included revenues from sales of natural gas at
above-market prices under a contract with Tennessee Gas Pipeline Company
("Tennessee Gas") which was terminated effective October 1, 1996. Results of
operations in 1997 and future years no longer benefit from above-market revenues
under this contract. Significant items, including the impact of the Tennessee
Gas contract, which affect the comparability between results for the years ended
December 31, 1997, 1996 and 1995 are highlighted in the table below (in millions
except per share amounts):
1997 1996 1995
----- ----- ------
Net Earnings as Reported................................... $30.7 $74.5 $ 54.6
Extraordinary Loss on Debt Extinguishments, Net of Income
Tax Benefit.............................................. -- 2.3 2.9
----- ----- ------
Earnings Before Extraordinary Item......................... 30.7 76.8 57.5
----- ----- ------
Significant Items Affecting Comparability, Pretax:
Income from retroactive severance tax refunds............ 1.8 5.0 --
Income from collection of Bolivian receivable............ 2.2 -- --
Income from settlement of a natural gas contract......... -- 60.0 --
Operating profit from excess of contract prices over spot
market prices......................................... -- 24.6 47.1
Interest and reimbursement of fees and costs from
resolution of litigation.............................. -- 8.1 --
Gain (loss) on sale of assets............................ -- (0.8) 33.5
Costs to resolve shareholder consent solicitation........ -- (2.3) --
Employee termination costs and other..................... -- (4.5) (5.2)
----- ----- ------
Total Significant Items, Pretax....................... 4.0 90.1 75.4
Income Tax Effect..................................... 1.2 27.2 --
----- ----- ------
Total Significant Items, Aftertax..................... 2.8 62.9 75.4
----- ----- ------
Net Earnings (Loss) Excluding Significant Items and
Extraordinary Item....................................... $27.9 $13.9 $(17.9)
===== ===== ======
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1997 1996 1995
----- ----- ------
Earnings Per Share -- Basic:
As reported.............................................. $1.16 $2.87 $ 2.22
Extraordinary loss....................................... -- (0.09) (0.12)
Impact of contract prices over spot market prices and
settlement income..................................... -- 2.28 1.92
Effect of other significant items........................ 0.10 0.15 1.15
----- ----- ------
Excluding significant items and extraordinary item....... $1.06 $0.53 $(0.73)
===== ===== ======
Earnings Per Share -- Diluted:
As reported.............................................. $1.14 $2.81 $ 2.18
Extraordinary loss....................................... -- (0.09) (0.11)
Impact of contract prices over spot market prices and
settlement income..................................... -- 2.23 1.88
Effect of other significant items........................ 0.10 0.14 1.14
----- ----- ------
Excluding significant items and extraordinary item....... $1.04 $0.53 $(0.73)
===== ===== ======
As shown above, excluding the significant items, the Company's net earnings
would have been $27.9 million ($1.06 per basic share, $1.04 per diluted share)
in 1997, as compared to net earnings of $13.9 million ($0.53 per basic and
diluted share) in 1996 and a net loss of $17.9 million ($0.73 per basic and
diluted share) in 1995. The resulting $14 million increase in net earnings in
1997 was primarily attributable to better refined product margins, higher spot
market natural gas prices and lower corporate interest expense.
When comparing 1996 to 1995, after excluding significant items, the
improvement in net earnings of approximately $32 million was primarily
attributable to improvements within the Company's Refining and Marketing and
Marine Services segments together with reduced general and administrative
expenses and interest expense. These improvements were partially offset by an
increase in the Company's total effective tax rate in 1996 as earnings subject
to U.S. taxes exceeded available net operating loss and tax credit
carryforwards.
A discussion and analysis of the factors contributing to these results are
presented below. The accompanying consolidated financial statements and related
footnotes, together with the following information, are intended to provide
shareholders and other investors with a reasonable basis for assessing the
Company's operations, but should not serve as the sole criterion for predicting
the future performance of the Company.
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REFINING AND MARKETING
1997 1996 1995
---------- ---------- ----------
(DOLLARS IN MILLIONS EXCEPT PER BARREL
AMOUNTS)
GROSS OPERATING REVENUES
Total refined products............................ $ 643.7 $ 620.8 $ 664.5
Other, primarily crude oil resales and
merchandise.................................... 77.2 124.6 106.5
------- ------- -------
Gross Operating Revenues..................... $ 720.9 $ 745.4 $ 771.0
======= ======= =======
TOTAL OPERATING PROFIT
Gross margin:
Refinery(a).................................... $ 93.3 $ 74.6 $ 63.5
Non-refinery(b)(c)............................. 36.6 32.7 34.1
------- ------- -------
Total gross margin........................... 129.9 107.3 97.6
Operating expenses................................ 96.0 87.9 84.7
Depreciation and amortization..................... 12.7 12.5 11.9
Loss on sales of assets and other................. 0.7 0.9 0.3
------- ------- -------
Operating Profit............................. $ 20.5 $ 6.0 $ 0.7
======= ======= =======
CAPITAL EXPENDITURES................................ $ 43.9 $ 11.1 $ 9.3
======= ======= =======
KENAI REFINERY THROUGHPUT
Barrels per day................................... 50,207 47,486 50,569
% Alaska North Slope ("ANS") crude oil............ 71% 72% 68%
REFINED PRODUCTS MANUFACTURED (average daily
barrels)
Gasoline and gasoline blendstocks................. 12,851 12,763 14,298
Middle distillates, including jet fuel and diesel
fuel........................................... 21,636 19,975 20,693
Heavy oils and residual products.................. 14,752 13,739 14,516
Other............................................. 2,279 2,600 2,489
------- ------- -------
Total Refined Products Manufactured.......... 51,518 49,077 51,996
======= ======= =======
REFINERY PRODUCT SPREAD ($/barrel)(c)............... $ 5.09 $ 4.29 $ 3.44
======= ======= =======
TOTAL SEGMENT PRODUCT SALES (average daily
barrels)(d)
Gasoline.......................................... 17,393 17,427 24,526
Middle distillates................................ 30,576 29,651 37,988
Heavy oils and residual products.................. 17,929 15,089 14,787
------- ------- -------
Total Product Sales.......................... 65,898 62,167 77,301
======= ======= =======
TOTAL SEGMENT PRODUCT SALES PRICES ($/barrel)
Gasoline.......................................... $ 33.71 $ 32.72 $ 28.21
Middle distillates................................ $ 28.36 $ 29.01 $ 24.40
Heavy oils and residual products.................. $ 17.30 $ 17.61 $ 13.66
TOTAL SEGMENT GROSS MARGINS ON PRODUCT SALES
($/barrel)(e)
Average sales price............................... $ 26.76 $ 27.28 $ 23.55
Average costs of sales............................ 21.92 23.15 20.53
------- ------- -------
Gross Margin................................. $ 4.84 $ 4.13 $ 3.02
======= ======= =======
- ---------------
(a) Represents throughput at the Company's refinery ("Kenai Refinery") times
refinery product spread.
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(b) Non-refinery margin includes margins on products purchased and resold,
margins on products sold in markets outside of Alaska, intrasegment
pipeline revenues, retail margins, and adjustments due to selling a volume
and mix of products that is different than actual volumes manufactured.
(c) Amounts reported in prior periods have been reclassified to conform with
current presentation.
(d) Sources of total product sales include products manufactured at the Kenai
Refinery, products drawn from inventory balances and products purchased
from third parties. The Company's purchases of refined products for resale
averaged approximately 11,300, 11,600 and 25,500 barrels per day in 1997,
1996 and 1995, respectively.
(e) Gross margins on total product sales include margins on sales of purchased
products, together with the effect of changes in inventories.
1997 Compared to 1996. The Refining and Marketing segment's operating
profit of $20.5 million in 1997 increased $14.5 million from operating profit of
$6.0 million in 1996. The improvement in results from Refining and Marketing has
been due in part to the Company's initiatives to enhance its product slate,
improve efficiencies and sell a larger portion of the Kenai Refinery's
production within the core Alaska market. In these regards, in early October
1997, the Company completed an expansion of the Kenai Refinery's hydrocracker
unit, which increased the unit's capacity by approximately 25% and enables the
Company to produce more jet fuel, a product in short supply in Alaska. The
expansion, together with the addition of a new, high-yield jet fuel hydrocracker
catalyst, began to favorably impact this segment's results in the fourth quarter
of 1997. The Company estimates that its yield of middle distillates will average
45% of total products manufactured at the Kenai Refinery during 1998. With
respect to crude oil supply, during 1997, the Company negotiated contracts to
purchase the remaining Cook Inlet crude oil production available for sale and,
in October 1997, began purchasing approximately 25,000 barrels per day of Cook
Inlet crude oil in addition to the approximate 9,000 barrels per day under
previously existing contracts. Substantially all of the contracts for purchases
of Cook Inlet crude oil are for various periods extending through December 1998.
As part of a three-year, $50 million retail marketing expansion program
initiated in 1997, the Company built two new retail facilities, remodeled three
stations, bought two stations and closed two uneconomic outlets. At year-end
1997, the total number of retail stations selling the Company's gasoline totaled
222 as compared to 206 in 1996. Of these stations, 30 are located in the Pacific
Northwest, compared to 18 at year-end 1996.
During 1997, the Company's production of refined products increased in
total by 5% due to higher throughput levels at the Kenai Refinery. The
operational changes, previously discussed, resulted in an 8% increase in the
production of middle distillates, primarily jet fuel, while gasoline production
remained flat. Production of heavy oils and residual products increased by 7% in
1997. The improved product slate, which better matches the Company's product
supply with demand in Alaska, reflected the change of a hydrocracker catalyst in
late 1996 and the hydrocracker expansion and catalyst change in late 1997. The
Company's sales of refined products within Alaska increased by 6% in 1997
contributing to higher product margins. The improved product slate and marketing
efforts, together with generally favorable industry conditions, resulted in an
increase in the Company's refinery spread to $5.09 per barrel in 1997, compared
to $4.29 per barrel in 1996, reflecting a 10% decrease in the Company's per
barrel feedstock cost with only a 5% decline in per barrel yield value. Both
years included scheduled 30-day maintenance turnarounds.
Revenues from sales of refined products in the Company's Refining and
Marketing segment increased during 1997 due primarily to a 6% increase in sales
volumes, partially offset by slightly lower average sales prices. Total refined
product sales averaged 65,898 barrels per day in 1997 as compared to 62,167
barrels per day in 1996. Other revenues, which included crude oil resales of
$44.4 million in 1997 and $93.8 million in 1996, declined due to lower sales
volumes and prices. The Company had less crude oil available for resale in 1997
as throughput at the Kenai Refinery increased by 2,721 barrels per day, or 6%,
from 1996 and fewer spot purchases of crude oil were made. Export sales of
refined products, including sales to the Russian Far East, amounted to $16.1
million in 1997 compared to $22.0 million in 1996. Costs of sales decreased in
1997 due to lower spot purchases of crude oil and lower prices. Margins from
non-refinery activities increased to $36.6 million in 1997 due primarily to
higher retail sales and improved margins on products sold outside of
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Alaska. Operating expenses increased in 1997 due primarily to higher employee
costs, professional fees and marketing expenses.
The Company's initiatives to enhance its product slate and sell more
product within Alaska, as discussed above, have improved the fundamental
earnings potential of this segment. Certain of these initiatives, such as the
hydrocracker expansion and additional crude oil supply contracts, were completed
in the fourth quarter of 1997. Future years will benefit from the impact of
these initiatives for a full period. Future profitability of this segment,
however, will continue to be influenced by market conditions, particularly as
these conditions influence costs of crude oil relative to prices received for
sales of refined products, and other additional factors that are beyond the
control of the Company.
1996 Compared to 1995. Results from the Company's Refining and Marketing
segment improved during 1996 with operating profit of $6.0 million, compared to
operating profit of $0.7 million in 1995. This improvement was achieved during a
year when the industry was facing rapidly rising prices in the crude oil market.
In addition, the Company's production level at the Kenai Refinery was reduced in
September 1996 for a scheduled 30-day maintenance turnaround. Despite these
factors, the Company was able to achieve a refinery product spread of $4.29 per
barrel for 1996, compared to $3.44 per barrel in 1995. The Company's results
were helped by its initiatives to control costs, improve the Kenai Refinery's
product slate and expand the marketing program for its refined products. The
Company's average refined product yield value per barrel increased by 19% in
1996, while the Company's feedstock costs per barrel increased by 17%.
During 1996, the Company's production of refined products declined in total
by 6%, which included the impact of the scheduled maintenance period. Of this
decline, gasoline production decreased by 11% and middle distillates decreased
by only 3%. These reductions reflected the change of a hydrocracker catalyst
during the maintenance period, which allows for increased production of jet fuel
and reduced production of gasoline beginning in the fourth quarter of 1996,
which better matches the Company's product supply with demand in Alaska.
During 1996, the Company's marketing efforts added 31 locations in Alaska
and eight locations in the Pacific Northwest, bringing the total to 188 branded,
unbranded and Company-operated stations in Alaska and 18 branded stations in the
Pacific Northwest at year-end 1996. Two uneconomic outlets in these areas were
closed in 1996. In addition, the Company began producing and marketing liquid
asphalt, which is a seasonal product in Alaska. Export sales of refined
products, including sales to the Russian Far East, amounted to $22.0 million in
1996 and $18.5 million in 1995.
Revenues from sales of refined products in the Company's Refining and
Marketing segment decreased in 1996 due primarily to a 20% decline in sales
volumes, partially offset by a 16% increase in average sales prices. Total
refined product sales averaged 62,167 barrels per day in 1996 as compared to
77,301 barrels per day in 1995. This decline reflected the lower production
volumes and the Company's withdrawal from certain U.S. West Coast markets during
1996, which also reduced the Company's purchases from other refiners and
suppliers to 11,600 barrels per day in 1996 as compared to 25,500 barrels per
day in 1995. One of the U.S. West Coast facilities was sold in 1996 resulting in
a loss of $0.8 million. Sales of previously purchased crude oil increased to
$93.8 million in 1996, compared to $75.8 million in 1995, due primarily to
higher crude oil prices and in part due to sales of excess crude supply volumes
during the maintenance period. Costs of sales decreased in 1996 due to lower
volumes of refined products, partially offset by higher prices for crude oil and
refined products. Operating expenses were higher in 1996 due primarily to higher
environmental and employee costs partially offset by lower insurance costs.
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EXPLORATION AND PRODUCTION
1997 1996 1995
---------- ---------- -----------
(DOLLARS IN MILLIONS EXCEPT PER UNIT
AMOUNTS)
U.S. (a)(b)
Gross operating revenues............................. $ 73.6 $ 93.8 $ 113.0
Income from settlement of a natural gas contract..... -- 60.0 --
Other income, including gain on asset sale in 1995... 3.2 4.8 33.5
Production costs..................................... 7.4 5.3 12.0
Administrative support and other operating
expenses.......................................... 2.3 3.8 3.2
Depreciation, depletion and amortization............. 29.8 25.6 29.3
------- ------- --------
Operating Profit -- U.S........................... 37.3 123.9 102.0
------- ------- --------
BOLIVIA
Gross operating revenues............................. 11.2 13.7 11.7
Other income related to collection of a receivable... 2.2 -- --
Production costs..................................... 0.9 0.8 0.6
Administrative support and other operating
expenses.......................................... 2.4 2.8 3.2
Depreciation, depletion and amortization............. 1.5 1.3 0.3
------- ------- --------
Operating Profit -- Bolivia....................... 8.6 8.8 7.6
------- ------- --------
TOTAL OPERATING PROFIT -- EXPLORATION AND PRODUCTION... $ 45.9 $ 132.7 $ 109.6
======= ======= ========
U.S.
Average Daily Net Production:
Natural gas (Mcf)................................. 86,052 87,654 114,490
Oil (barrels)..................................... 118 27 1
Total (thousand cubic feet equivalent "Mcfe")..... 86,760 87,816 114,496
Average Prices:
Natural gas ($/Mcf) --
Spot market(c).................................. $ 2.17 $ 1.95 $ 1.34
Average(b)...................................... $ 2.17 $ 2.75 $ 2.57
Oil ($/barrel).................................... $ 18.90 $ 21.99 $ 16.82
Average Operating Expenses ($/Mcfe):
Lease operating expenses.......................... $ 0.20 $ 0.14 $ 0.11
Severance taxes................................... 0.03 0.03 0.18
------- ------- --------
Total production costs....................... 0.23 0.17 0.29
Administrative support and other.................. 0.07 0.10 0.06
------- ------- --------
Total Operating Expenses..................... $ 0.30 $ 0.27 $ 0.35
======= ======= ========
Depletion ($/Mcfe)................................... $ 0.93 $ 0.79 $ 0.69
Capital Expenditures (including U.S. gas
transportation)................................... $ 65.4 $ 59.7 $ 49.6
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1997 1996 1995
---------- ---------- -----------
(DOLLARS IN MILLIONS EXCEPT PER UNIT
AMOUNTS)
BOLIVIA
Average Daily Net Production:
Natural gas (Mcf)................................. 19,537 20,251 18,650
Condensate (barrels).............................. 518 584 567
Total (Mcfe)...................................... 22,645 23,755 22,052
Average Prices:
Natural gas ($/Mcf)............................... $ 1.15 $ 1.33 $ 1.28
Condensate ($/barrel)............................. $ 15.71 $ 17.98 $ 14.39
Average Operating Expenses ($/Mcfe):
Production costs.................................. $ 0.11 $ 0.10 $ 0.07
Value-added taxes................................. -- 0.05 0.06
Administrative support and other.................. 0.31 0.27 0.35
------- ------- --------
Total Operating Expenses..................... $ 0.42 $ 0.42 $ 0.48
======= ======= ========
Depletion ($/Mcfe)................................... $ 0.19 $ 0.15 $ 0.03
Capital Expenditures................................. $ 27.5 $ 6.9 $ 3.8
- ---------------
(a) Represents the Company's U.S. oil and gas operations combined with gas
transportation activities.
(b) Results for 1996 and 1995 included revenues from above-market pricing
provisions of a contract with Tennessee Gas which was terminated effective
October 1, 1996. Operating profit for 1996 and 1995 included $24.6 million
and $47.1 million, respectively, for the excess of these contract prices
over spot market prices. Net natural gas production sold under the contract
averaged approximately 11 million cubic feet ("MMcf") per day in 1996 and
20 MMcf per day in 1995. Upon termination of the contract, the Company
recorded other income and operating profit of $60 million during the fourth
quarter of 1996. See Note D of Notes to Consolidated Financial Statements
in Item 8.
(c) Includes effects of the Company's natural gas commodity price agreements
which amounted to losses of $0.05 per thousand cubic feet ("Mcf") and $0.11
per Mcf in 1997 and 1996, respectively, and a gain of $0.01 per Mcf in
1995.
EXPLORATION AND PRODUCTION -- U.S.
1997 Compared to 1996. Operating profit from the Company's U.S. operations
was $37.3 million in 1997, compared with $123.9 million in 1996. Comparability
between these years was impacted by several major transactions in 1996,
including the favorable resolution in August 1996 of litigation regarding the
Tennessee Gas contract and the termination of the remainder of the contract
effective October 1, 1996. As provided for in the Tennessee Gas contract, which
was to expire in January 1999, the Company was selling a portion of the gas
produced in the Bob West Field pursuant to a contract price, which was above the
average spot market price. In total, during 1996 the Company received
approximately $120 million in cash for the resolution of litigation and
termination of the Tennessee Gas contract, with the Company's Exploration and
Production segment recording operating profit of $60 million upon termination of
the contract. In 1996 and 1995, the Exploration and Production segment's
operating profit also included $24.6 million and $47.1 million, respectively,
from the excess of Tennessee Gas contract prices over spot market prices. See
Note D of Notes to Consolidated Financial Statements in Item 8.
Additionally, during 1996, substantially all of the Company's proved
producing reserves in the Bob West Field were certified by the Texas Railroad
Commission as high-cost gas from a designated tight formation, eligible for
state severance tax exemptions from the date of first production through August
2001. Accordingly, no severance tax is recorded on current production from the
exempt wells in the Bob West Field beginning in 1996. In 1997 and 1996, the
Company recognized income of $1.8 million and $5.0 million, respectively, for
retroactive severance tax refunds for production in prior years.
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Excluding the impact of the incremental contract value and income from the
severance tax refunds, operating profit from the Company's U.S. operations would
have been $35.5 million in 1997 compared to $34.3 million in 1996. The resulting
increase of $1.2 million was primarily attributable to higher spot market prices
for sales of natural gas, partially offset by higher depletion and operating
expenses.
Prices realized by the Company on its natural gas production sold in the
spot market increased 11% to $2.17 per Mcf in 1997 from $1.95 per Mcf in 1996.
The Company's weighted average sales price, which included the above-market
pricing of the Tennessee Gas contract in 1996, decreased in 1997 due to the
termination of the contract. The Company's net production averaged 86.8 MMcfe
per day in 1997, a decrease of 1.0 MMcfe per day from 1996. This decrease
consisted of a 16.1 MMcf per day decline from the Bob West Field, partially
offset by a 15.1 MMcfe per day increase from other U.S. fields. The Company's
U.S. production outside of the Bob West Field rose to 50% of its total U.S.
production by January 1998, as compared to 7% at 1996 year-end.
Gross operating revenues from the Company's U.S. operations, after
excluding amounts related to Tennessee Gas, increased due to the higher spot
market prices. Production costs were higher by $2.1 million ($0.06 per Mcfe) due
mainly to costs at the Bob West Field, including increased compression costs and
a charge for ad valorem taxes in 1997 as well as the impact of lower processing
fees in 1996. Administrative support and other operating expenses decreased by
$1.5 million. Depreciation and depletion increased by $4.2 million, or 16%, due
to a higher depletion rate.
From time to time, the Company enters into commodity price agreements to
reduce the risk caused by fluctuations in the prices of natural gas in the spot
market. During 1997, 1996 and 1995, the Company used such agreements to set the
price of 9%, 30% and 38%, respectively, of the natural gas production that it
sold in the spot market. During 1997 and 1996, the Company realized losses of
$1.6 million ($0.05 per Mcf) and $3.1 million ($0.11 per Mcf), respectively,
from these price agreements. In 1995, the effects of natural gas price
agreements resulted in a gain of $0.3 million ($0.01 per Mcf). The Company had
no remaining price agreements outstanding at December 31, 1997.
1996 Compared to 1995. Operating profit of $123.9 million from the
Company's U.S. operations in 1996 increased $21.9 million from operating profit
of $102.0 million in 1995. Comparability between these years was impacted by
several major transactions. As discussed above, the 1996 results included the
impact of the incremental value of the Tennessee Gas contract. Operating profit
for 1995 included a gain of $33.5 million from the sale of certain interests in
the Bob West Field (see Note C of Notes to Consolidated Financial Statements in
Item 8). Excluding the impact of the incremental contract value from both years
and the gain on sale of assets from 1995, operating profit from the Company's
U.S. operations for 1996 would have been $34 million compared to $21 million for
1995. The resulting increase was primarily due to higher spot market prices for
sales of natural gas, as industry demand increased due to unusually cold weather
combined with below-normal storage levels.
Prices realized by the Company on its natural gas production sold in the
spot market increased 46% to $1.95 per Mcf in 1996 from $1.34 per Mcf in 1995.
Excluding 24,500 Mcf per day related to the sold interests from 1995, the
Company's spot production increased by 6,600 Mcf per day during 1996. The
Company's exploration and acquisition programs outside of the Bob West Field
contributed 3,800 Mcf per day of the increase in spot production with the
remaining increase attributable to sales to Tennessee Gas at spot prices
effective October 1, 1996. The Company's weighted average sales price increased
7% to $2.75 per Mcf in 1996 as compared to $2.57 per Mcf in 1995. For the Bob
West Field, production declined by 6,100 Mcf per day after excluding amounts
related to sold interests in 1995.
Gross operating revenues from the Company's U.S. operations, after
excluding $11.7 million related to the sold interests from 1995, decreased by
$7.5 million due primarily to the decline in volumes sold under the Tennessee
Gas contract, and losses under commodity price agreements discussed above,
partially offset by increases in spot market sales prices and production. The
decline in production costs of $6.7 million, or $0.12 per Mcfe, was mainly
attributable to the severance tax exemptions in the Bob West Field. Total
depreciation, depletion and amortization was lower in 1996 due to lower
production volumes, partially offset by a higher depletion rate.
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EXPLORATION AND PRODUCTION -- BOLIVIA
The Company's Bolivian natural gas production is sold to Yacimientos
Petroliferos Fiscales Bolivianos ("YPFB"), a Bolivian governmental agency, which
in turn sells the natural gas to Yacimientos Petroliferos Fiscales, SA ("YPF"),
a publicly-held company based in Argentina. Currently, the Company's sales of
natural gas production are based on the volume and pricing terms in a contract
between YPFB and YPF, which was extended in April 1997 for an additional two
years to March 31, 1999, with an option to extend the contract a maximum of one
additional year if a pipeline being constructed from Bolivia to Brazil is not
complete. In the contract extension, YPF negotiated an 11% reduction in the
minimum contract volume that it is required to import from Bolivia, which in
turn resulted in a corresponding 11% reduction of the Company's minimum contract
volume to 36.9 MMcf per day gross (26.2 net). The contract gas prices fluctuate
since they are linked to a monthly average fuel oil price posted in the New York
spot market.
A lack of market access has constrained natural gas production in Bolivia.
The Company believes that the completion of a 1,900-mile pipeline from Bolivia
to Brazil will provide access to larger gas-consuming markets. Upon completion
of this pipeline, the Company will face intense competition from major and
independent natural gas companies operating in Bolivia for a share of the
contractual volumes to be exported to Brazil. It is anticipated that each
producer's share of the contractual volumes will be allocated by YPFB according
to a number of factors, including each producer's reserve volumes and production
capacity. Although the Company expects gas deliveries on the pipeline to begin
in early 1999, there can be no assurance that the pipeline will be operational
by such date. With the exception of the volumes currently under contract with
the Bolivian government, the Company cannot be assured of the amount of
additional volumes that will be exported to Brazil upon completion of the
pipeline.
1997 Compared to 1996. Operating profit from the Company's Bolivian
operations decreased to $8.6 million in 1997, from $8.8 million operating profit
in 1996. Results for 1997 benefited from income of $2.2 million related to the
collection of a receivable for prior years' production. Without this income,
operating profit would have decreased by $2.4 million in 1997 due to declines in
natural gas and condensate production and prices. With the Company's purchase of
interests held by its former joint venture participant in July 1997, the
Company's share of production from Bolivia increased by approximately 33%
beginning in the 1997 third quarter (see Note C of Notes to Consolidated
Financial Statements in Item 8). However, earlier in the year, the Company's
Bolivian natural gas production was lower due to a reduction in minimum takes
under the new contract between YPFB and YPF and also due to constraints arising
from repairs to a non-Company-owned pipeline that transports gas from Bolivia to
Argentina. In addition, during 1996, production was higher due to requests from
YPFB for additional production from the Company to meet export specifications.
Natural gas prices fell 14% to $1.15 per Mcf in 1997, compared to $1.33 per Mcf
in 1996. Condensate prices fell 13% to $15.71 per barrel in 1997, compared to
$17.98 per barrel in 1996.
1996 Compared to 1995. Operating profit from the Company's Bolivian
operations increased to $8.8 million in 1996, from the $7.6 million operating
profit in 1995. This improvement was primarily due to a 9% increase in
production of natural gas, primarily due to increased demand from YPFB during
the second and third quarters of 1996, together with higher prices received for
both natural gas and condensate. Operating expenses declined by 12% on a per
unit basis reflecting a 6% decrease in costs combined with the increase in
volumes. Partially offsetting these improvements was an increase in
depreciation, depletion and amortization of $1.0 million.
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MARINE SERVICES
1997 1996 1995
------ ------ ------
(DOLLARS IN MILLIONS)
Gross Operating Revenues
Fuels.................................................. $104.5 $ 98.9 $ 61.9
Lubricants and other................................... 16.4 14.9 12.0
Services............................................... 11.3 8.7 0.6
------ ------ ------
Gross Operating Revenues............................ 132.2 122.5 74.5
Costs of Sales........................................... 96.7 93.0 64.9
------ ------ ------
Gross Profit........................................ 35.5 29.5 9.6
Operating Expenses and Other............................. 27.5 22.2 13.7
Depreciation and Amortization............................ 1.7 1.2 0.3
------ ------ ------
Operating Profit (Loss)............................. $ 6.3 $ 6.1 $ (4.4)
====== ====== ======
Sales Volumes (millions of gallons):
Fuels, primarily diesel................................ 156.4 142.7 112.5
Lubricants............................................. 2.7 2.3 2.5
Capital Expenditures..................................... $ 9.4 $ 6.9 $ 0.4
1997 Compared to 1996. Gross operating revenues increased by $9.7 million,
which included a $7.1 million increase in fuels and lubricant revenues and a
$2.6 million increase in service revenues. The increase in fuels and lubricant
revenues was primarily due to a 10% increase in sales volumes, partially offset
by lower prices. The service revenue increase of 30% was due in part to
increased rig activity in the Gulf of Mexico and the Company's focus to serve
these customers. Additional terminal locations stemming from an acquisition
consummated in February 1996 together with internal growth initiatives have
enabled the Company to increase its sales activity. Costs of sales increased in
1997 due to the higher volumes. The improvement of $6.0 million in gross profit
was offset by higher operating and other expenses associated with the increased
activity together with upgrades to facilities and services.
The Marine Service's segment business is largely dependent upon the level
of oil and gas drilling, workover, construction and seismic activity in the Gulf
of Mexico.
1996 Compared to 1995. In February 1996, the Company acquired Coastwide
Energy Services, Inc. ("Coastwide") and combined these operations with the
Company's marine petroleum products distribution business, forming a Marine
Services segment. Operating results from Coastwide have been included in the
Company's Marine Services segment since the date of acquisition. See Note C of
Notes to Consolidated Financial Statements in Item 8.
The Marine Services segment consisted of 20 terminals at year-end 1996,
compared to 14 at the prior year-end. The increase of $39.9 million in fuels and
lubricants revenues was primarily due to the added locations and associated
volumes combined with higher fuel prices. In addition, revenues from services
grew by $8.1 million. These increases in revenues together with improved margins
during 1996 were partially offset by higher operating and other expenses
associated with the increased activity. Depreciation and amortization increased
during 1996 due to capital additions during the year. In total, operating profit
of $6.1 million in 1996 reflected a turnaround from the losses incurred in the
prior year.
GENERAL AND ADMINISTRATIVE EXPENSES
General and administrative expenses were $13.6 million in 1997, compared
with $12.7 million in 1996 and $16.4 million in 1995. The increase in 1997 was
primarily due to higher employee costs partially offset by lower professional
fees and insurance costs. When comparing 1996 to 1995, the decrease was
primarily due to lower employee and labor costs resulting from cost reduction
measures implemented by the Company in late 1995.
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INTEREST EXPENSE AND INTEREST INCOME
Interest expense totaled $6.7 million in 1997, compared with $15.4 million
in 1996 and $20.9 million in 1995. The Company's redemption of public debt of
$74.1 million in November 1996 and $34.6 million in December 1995 contributed to
these interest savings.
Interest income was $1.6 million in 1997, compared with $8.4 million in
1996 and $1.8 million in 1995. The fluctuation in 1996 included interest of
approximately $7 million received from Tennessee Gas in conjunction with the
collection of a receivable which resulted from underpayment for natural gas sold
in prior periods (see Note D of Notes to Consolidated Financial Statements in
Item 8).
OTHER EXPENSE, NET
Other expense was $4.9 million in 1997, compared with $10.0 million in 1996
and $8.5 million in 1995. In 1996, the Company incurred costs of $2.3 million to
resolve a shareholder consent solicitation, together with a write-off of
deferred financing costs and increased expenses related to the Company's former
operations. There were no material comparable costs recorded in 1997. When
comparing 1996 to 1995, the increase in other expense was due to the costs
recorded in 1996, partially offset by lower employee termination and
restructuring costs.
INCOME TAX PROVISION
The income tax provision was $18.4 million in 1997, compared with $38.3
million in 1996 and $4.4 million in 1995. Effective income tax rates were 37%,
33% and 7% in 1997, 1996 and 1995, respectively (see Note H of Notes to
Consolidated Financial Statements in Item 8). The decrease in the income tax
provision in 1997 was primarily attributable to lower earnings, partially offset
by a higher effective rate due to Bolivian taxes. When comparing 1996 to 1995,
the income tax provision increased due to earnings subject to U.S. taxes
exceeding available net operating loss and tax credit carryforwards.
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39
CAPITAL RESOURCES AND LIQUIDITY
OVERVIEW
The Company's primary sources of liquidity are its cash and cash
equivalents, internal cash generation and external financing. During 1997, the
Company made capital expenditures of $147 million, which were funded through a
combination of cash flows from operations of $96 million, external financing and
available cash balances. At December 31, 1997, the Company's
debt-to-capitalization ratio was 26% which enhances the Company's ability to
access capital markets.
Additional financing will be required for the proposed acquisition of BHP
Refining and BHP South Pacific and associated working capital and letters of
credit requirements. The Company is currently in discussions with its investment
bankers to arrange for such financing, and in connection with such discussions,
the Company has been advised that sufficient funds will be made available. See
Note O of Notes to Consolidated Financial Statements in Item 8.
The Company operates in an environment where its liquidity and capital
resources are impacted by changes in the supply of and demand for crude oil,
natural gas and refined petroleum products, market uncertainty and a variety of
additional risks that are beyond the control of the Company. These risks
include, among others, the level of consumer product demand, weather conditions,
the proximity of the Company's natural gas reserves to pipelines, the capacities
of such pipelines, fluctuations in seasonal demand, governmental regulations,
the price and availability of alternative fuels and overall market and economic
conditions. The Company's future capital expenditures as well as borrowings
under its credit arrangements and other sources of capital will be affected by
these conditions.
CREDIT ARRANGEMENTS
The Company's amended and restated corporate revolving credit agreement
("Credit Facility"), which expires in April 2000, provides total commitments of
$150 million from a consortium of nine banks. The Company, at its option, has
currently activated $100 million of these commitments. The Credit Facility
provides for the issuance of letters of credit, and for cash borrowings up to
$100 million, with the aggregate subject to a borrowing base (which amount
exceeded total commitments at December 31, 1997). Outstanding obligations under
the Credit Facility are collateralized by first liens on substantially all of
the Company's trade receivables, product inventories and South Texas natural gas
reserves and by a third lien on the Kenai Refinery.
At December 31, 1997, the Company had outstanding cash borrowings of $28
million under the Credit Facility. Cash borrowings under the Credit Facility are
generally used on a short-term basis to finance working capital requirements and
capital expenditures. Under the Credit Facility, at December 31, 1997, the
Company had outstanding letters of credit of $34 million, primarily for royalty
crude oil purchases from the State of Alaska. Unused availability, including
unactivated commitments, under the Credit Facility at December 31, 1997 for
additional borrowings and letters of credit totaled $88 million. The Company is
also permitted to utilize unsecured letters of credit outside of the Credit
Facility up to $40 million (none outstanding at December 31, 1997).
The Credit Facility, which has been amended from time to time, requires the
Company to maintain specified levels of consolidated working capital, tangible
net worth, cash flow and interest coverage and contains other covenants
customary in credit arrangements of this kind. Among other matters, the terms of
the Credit Facility allow for general open market stock repurchases and the
payment of cash dividends subject to a cumulative amount available for
restricted payments (defined as the difference of (i) the sum since December 31,
1995, of (a) $5 million and (b) 50% of consolidated net earnings of the Company
in any calendar year and (ii) any restricted payments made since June 1996). At
December 31, 1997, the cumulative amount available for restricted payments was
approximately $58 million. In addition to the cumulative restriction, the Credit
Facility further limits these general open market stock repurchases and cash
dividends to a maximum of $5 million annually. The Credit Facility also permits
the Company to repurchase a limited amount of Common Stock, up to $10 million
annually, specifically for oddlot buyback programs and employee
37
40
benefit or compensation plans. The Board of Directors has no present plans to
pay dividends. However, from time to time, the Board of Directors reevaluates
the feasibility of declaring future dividends.
For further information on the Company's credit arrangements, see Note I of
Notes to Consolidated Financial Statements in Item 8.
DEBT AND OTHER OBLIGATIONS
Under an agreement reached in 1993, which settled a contractual dispute
with the State of Alaska ("State"), the Company is obligated to make variable
monthly payments to the State through December 2001 based on a per barrel charge
on the volume of feedstock processed through the Kenai Refinery's crude unit. In
1997 and 1996, based on a per barrel throughput charge of 24 cents, the
Company's variable payments to the State totaled $4.4 million and $4.0 million,
respectively. In 1995, based on a per barrel throughput charge of 16 cents, the
Company's variable payments to the State totaled $2.9 million. The per barrel
charge increases to 30 cents in 1998 with one cent annual incremental increases
thereafter through 2001. In January 2002, the Company is obligated to pay the
State $60 million; provided, however, that such payment may be deferred
indefinitely, at the Company's option, 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 collateralized by a fourth lien on the Kenai
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 Kenai Refinery. Loans obtained to finance the expansion of the
hydrocracker unit and install the vacuum unit, discussed in Note I of Notes to
Consolidated Financial Statements in Item 8, qualify as indebtedness incurred
subsequent to this agreement to improve the Kenai Refinery.
STOCK REPURCHASE PROGRAM
On May 7, 1997, the Company's Board of Directors authorized the repurchase
of up to 3 million shares (approximately 11% of outstanding shares) of Tesoro
Common Stock in a buyback program that will extend through the end of 1998.
Under the program, subject to certain conditions, the Company may repurchase
from time to time Tesoro Common Stock in the open market and through privately
negotiated transactions. Purchases will depend on price, market conditions and
other factors and will be made primarily from cash flows. The repurchased Common
Stock is accounted for as treasury stock and may be used for employee benefit
plan requirements and other corporate purposes. During 1997, the Company used
cash flows of $3.7 million to repurchase 236,800 shares of Common Stock, of
which 20,347 shares have been reissued for an employee benefit plan. For
information related to restrictions under the Credit Facility, see Note I of
Notes to Consolidated Financial Statements in Item 8.
CAPITAL SPENDING
Capital spending in 1997 totaled $147 million which was funded from
available cash reserves, internally-generated cash flows from operations and
external financing. Capital expenditures for the Exploration and Production
segment were approximately $93 million, including $65 million for U.S.
operations and $28 million for Bolivia operations. In the U.S., capital
expenditures were principally for participation in the drilling of eleven
development wells (nine completed), 12 exploratory wells (eight completed), the
purchase of 33 Bcfe of proved reserves and 82,000 net undeveloped lease acres
and seismic activity. In Bolivia, capital expenditures included the purchase of
contract interests from its former joint venture participant (see Note C of
Notes to Consolidated Financial Statements in Item 8), exploratory drilling,
seismic activity and workovers. Capital projects for the Refining and Marketing
segment in 1997 totaled $44 million, primarily for costs related to the
hydrocracker expansion and the commencement of a long-term capital program to
improve marketing operations. In the Marine Services segment, capital spending
totaled $9 million during 1997, primarily for expansion and improvement of
operations along the Gulf of Mexico.
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41
For 1998, the Company has a total capital budget of approximately $195
million, excluding the acquisition of BHP Refining and BHP South Pacific. The
Exploration and Production segment accounts for $139 million, or 71%, of the
budget with $82 million planned for U.S. activities and $57 million for Bolivia.
Planned U.S. expenditures include $25 million for acquisitions, $21 million for
development drilling (participation in 30 wells), $17 million for leasehold,
geological and geophysical, and $17 million for exploratory drilling
(participation in 20 wells). In Bolivia, the drilling program is budgeted at $14
million for development drilling (three wells) and $12 million for exploratory
drilling (two wells), with the remainder planned for upgrading a gas processing
plant, constructing a liquid petroleum gas plant, workovers and three-
dimensional seismic activity. Capital spending, other than acquisitions, for the
Refining and Marketing segment is planned at $39 million, which includes $20
million towards the retail marketing expansion program in Alaska started in
1997, $8 million for environmental and $8 million for refinery improvements. The
Marine Services capital budget is $9 million, primarily directed towards
equipment and facility upgrades together with potential acquisitions. Capital
expenditures for 1998 are expected to be financed through a combination of cash
flows from operations, available cash reserves and additional borrowings under
the Credit Facility. Actual capital expenditures may vary from these projections
due to a number of factors, including the timing of drilling projects and the
extent to which properties are acquired.
CASH FLOW SUMMARY
Components of the Company's cash flows are set forth below (in millions):
1997 1996 1995
------- ------ ------
Cash Flows From (Used In):
Operating Activities.......................... $ 95.6 $178.9 $ 35.4
Investing Activities.......................... (151.5) (94.2) 2.4
Financing Activities.......................... 41.5 (75.9) (37.8)
------- ------ ------
Increase (Decrease) in Cash and Cash
Equivalents................................... $ (14.4) $ 8.8 $ --
======= ====== ======
During 1997, net cash from operating activities totaled $96 million,
compared with $179 million in 1996. Operating cash flows in 1997 included a $57
million decrease in receivables due in part to collections related to product
and crude oil sales volumes at 1996 year-end, Bolivian production sold in prior
years and retroactive severance taxes, partially offset by income tax and other
payments. The 1996 operating cash flows included the impact of receipts from
Tennessee Gas. Net cash used in investing activities of $151 million in 1997
included capital expenditures of $93 million for the Company's Exploration and
Production activities, $44 million for Refining and Marketing activities and $9
million for Marine Services. Net cash from financing activities of $41 million
in 1997 included net borrowings of $28 million under the Credit Facility and
receipt of $16 million under a loan for the hydrocracker expansion, partially
offset by payments of other long-term debt and repurchases of Common Stock.
During 1997, gross borrowings under the Credit Facility were $150 million, with
$122 million of repayments. At December 31, 1997, the Company's net working
capital totaled $74 million, which included cash and cash equivalents of $8
million.
During 1996, net cash from operating activities totaled $179 million,
compared with $35 million in 1995. This increase in operating cash flows in 1996
was primarily due to the receipt of $120 million from Tennessee Gas for the
favorable resolution of litigation in August 1996 and termination of the natural
gas purchase and sales contract effective October 1, 1996. In addition, improved
profitability plus noncash items, such as depreciation, depletion and
amortization and deferred income taxes, contributed to higher cash flows from
operations. Partially offsetting these increases were higher net working capital
balances, particularly receivables which increased primarily due to higher
year-end sales volumes together with higher prices. Net cash used in investing
activities of $94 million in 1996 included capital expenditures of $85 million
and cash consideration of nearly $8 million for the acquisition of Coastwide.
Net cash used in financing activities of $76 million during 1996 was primarily
due to the redemption of public debt aggregating $74 million together with
payments of other long-term debt. During 1996, the Company's gross borrowings
and repayments under its corporate revolving credit line amounted to $165
million.
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During 1995, net cash from operating activities totaled $35 million.
Although natural gas production from the Company's South Texas operations
increased during 1995, lower cash receipts for sales of natural gas adversely
affected the Company's cash flows from operations. Net cash from investing
activities of $2 million in 1995 included proceeds of $70 million from sales of
assets, primarily certain interests in the Bob West Field, partially offset by
$64 million of capital expenditures and $3 million for acquisition of the Kenai
Pipe Line Company ("KPL"). Net cash used in financing activities of $38 million
in 1995 was primarily related to the redemption of $34.6 million of public debt
and payments of other long-term debt. The Company's gross borrowings and
repayments under the Facility totaled $262 million during 1995.
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 a remedial response and has incurred cleanup
expenditures associated with environmental matters at a number of sites,
including certain of its own properties. At December 31, 1997, the Company's
accruals for environmental expenses amounted to $8.5 million, which included a
noncurrent liability of $2.7 million for remediation of KPL's properties that
has been funded by the former owners of KPL 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.
To comply with environmental laws and regulations, the Company anticipates
that it will make capital improvements of approximately $7 million in 1998 and
$2 million in 1999. In addition, capital expenditures for alternative secondary
containment systems for existing storage tank facilities are estimated to be $2
million in 1998 and $2 million in 1999 with a remaining $5 million to be spent
by 2002.
Conditions that require additional expenditures may exist for various
Company sites, including, but not limited to, the Kenai Refinery, retail
gasoline outlets (current and closed locations) and petroleum product terminals,
and for compliance with the Clean Air Act. The amount of such future
expenditures cannot currently be determined by the Company. For further
information on environmental contingencies, see Note L of Notes to Consolidated
Financial Statements in Item 8.
CRUDE OIL PURCHASE CONTRACTS
The Company has a contract with the State of Alaska for the purchase of
royalty crude oil, a primary feedstock for the Kenai Refinery, covering the
period January 1, 1996 through December 31, 1998. This contract provides for the
purchase of 30% of the State's ANS royalty crude oil produced from the Prudhoe
Bay Unit at prices based on royalty values computed by the State. During 1997,
the Company purchased approximately 35,700 barrels per day of ANS crude oil
under this contract. The contract contains provisions that, under certain
conditions, allow the Company to temporarily or permanently reduce its purchase
obligations. Under this contract, the Company is required to utilize in its
refinery operations volumes equal to at least 80% of the ANS crude oil purchased
from the State. The Company is presently in discussions with the State in regard
to extending this contract for an additional year.
The Company also purchases approximately 6,000 barrels per day of ANS crude
oil from a producer under a contract with a term of one year beginning January
1, 1998.
During October 1997, the Company began purchasing all of the approximately
34,000 barrels per day of Cook Inlet crude oil production from various producers
under contracts extending through December 1998. A contract to purchase 4,500
barrels per day, of the 34,000 barrels per day, has been extended through March
31, 2001.
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YEAR 2000 COMPLIANCE
The efficient operation of the Company's business is dependent on its
computer hardware, operating systems and software programs (collectively,
"Systems and Programs"). These Systems and Programs are used in several key
areas of the Company's business, including information management services and
financial reporting, as well as in various administrative functions. The Company
has been evaluating its Systems and Programs to identify potential year 2000
compliance problems, as well as manual processes, external interfaces with
customers and services supplied by vendors. The year 2000 problem refers to the
limitations of the programming code in certain existing hardware and software
programs to recognize date sensitive information for the year 2000 and beyond.
Unless replaced or modified prior to the year 2000, such hardware and systems
may not properly recognize such information and could generate erroneous data or
cause a system to fail to operate properly.
Based on current information, the Company expects to attain year 2000
compliance and institute appropriate testing of its modifications and
replacements in a timely fashion and in advance of the year 2000 date change. It
is anticipated that modification or replacement of the Company's Systems and
Programs will be performed in-house by company personnel. The Company believes
that, with hardware replacement and modifications to existing software or
conversions to new software, the year 2000 problem will not pose a significant
operational problem for the Company. It is possible that non-compliant third
party computer systems or programs may not interface properly with the Company's
computer systems. The Company has requested assurance from third parties that
their computers, systems or programs be year 2000 compliant. The Company could,
however, be adversely affected by the year 2000 problem if it or unrelated
parties fail to successfully address this issue. Management of the Company
currently anticipates that the expenses and capital expenditures associated with
its year 2000 compliance project will not have a material effect on its
financial position or results of operations.
NEW ACCOUNTING STANDARDS
In June 1997, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 130, "Reporting Comprehensive Income," which establishes standards for
reporting and display of comprehensive income and its components in a full set
of general-purpose financial statements. SFAS No. 130, which becomes effective
for the Company in 1998, requires that all items that are required to be
recognized under accounting standards as components of comprehensive income be
reported in a financial statement that is displayed with the same prominence as
other financial statements. Also, in June 1997, the FASB issued SFAS No. 131,
"Disclosures about Segments of an Enterprise and Related Information," which
establishes standards for reporting information about operating segments in
annual financial statements and requires that selected information about
operating segments be included in interim financial reports issued to
shareholders. SFAS No. 131 also establishes standards for related disclosures
about products and services, geographic areas and major customers. SFAS No. 131
becomes effective for the Company's 1998 year-end and need not be applied to
interim financial information until 1999. In February 1998, the FASB issued SFAS
No. 132, "Employers' Disclosures about Pensions and Other Postretirement
Benefits," which standardizes the disclosures related to pensions and other
postretirement benefits to the extent practicable, requires additional
information on changes in the benefit obligations and fair values of plan assets
and eliminates certain disclosures previously required. SFAS No. 132 becomes
effective for the Company in 1998. All three statements contain provisions for
restatement of prior period information. The Company is evaluating the effects
that these new statements will have on its financial reporting and disclosures.
The new statements will have no effect on the Company's results of operations,
financial position or cash flows.
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FORWARD-LOOKING STATEMENTS
Statements in this Annual Report on Form 10-K, including those contained in
the foregoing discussion and other items herein, concerning the Company which
are (a) projections of revenues, earnings, earnings per share, capital
expenditures or other financial items, (b) statements of plans and objectives
for future operations, including acquisitions, (c) statements of future economic
performance, or (d) statements of assumptions or estimates underlying or
supporting the foregoing are forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934. The ultimate accuracy of forward-looking statements is
subject to a wide range of business risks and changes in circumstances, and
actual results and outcomes often differ from expectations. Any number of
important factors could cause actual results to differ materially from those in
the forward-looking statements herein, including the following: the timing and
extent of changes in commodity prices and underlying demand and availability of
crude oil and other refinery feedstocks, refined products, and natural gas;
actions of customers and competitors; changes in the cost or availability of
third-party vessels, pipelines and other means of transporting feedstocks and
products; state and federal environmental, economic, safety and other policies
and regulations, any changes therein, and any legal or regulatory delays or
other factors beyond the Company's control; execution of planned capital
projects; weather conditions affecting the Company's operations or the areas in
which the Company's products are marketed; future well performance; the extent
of Tesoro's success in acquiring oil and gas properties and in discovering,
developing and producing reserves; political developments in foreign countries;
the conditions of the capital markets and equity markets during the periods
covered by the forward-looking statements; earthquakes or other natural
disasters affecting operations; adverse rulings, judgments, or settlements in
litigation or other legal matters, including unexpected environmental
remediation costs in excess of any reserves; and adverse changes in the credit
ratings assigned to the Company's trade credit. The Company undertakes no
obligation to publicly release the result of any revisions to any such
forward-looking statements that may be made to reflect events or circumstances
after the date hereof or to reflect the occurrence of unanticipated events.
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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, 1997 and 1996, and the
related statements of consolidated operations, stockholders' equity and cash
flows for each of the three years in the period ended December 31, 1997. 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, 1997 and 1996, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1997, in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
San Antonio, Texas
January 28, 1998
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TESORO PETROLEUM CORPORATION
STATEMENTS OF CONSOLIDATED OPERATIONS
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
YEARS ENDED DECEMBER 31,
------------------------------------
1997 1996 1995
-------- ---------- ----------
REVENUES
Refining and marketing............................... $720,868 $ 745,413 $ 771,035
Exploration and production........................... 84,798 107,415 124,670
Marine services...................................... 132,251 122,533 74,467
Income from settlement of a natural gas contract..... -- 60,000 --
Gain on sale of assets and other income.............. 5,543 4,417 32,711
-------- ---------- ----------
Total Revenues............................... 943,460 1,039,778 1,002,883
-------- ---------- ----------
OPERATING COSTS AND EXPENSES
Refining and marketing............................... 687,036 726,029 758,329
Exploration and production........................... 13,230 12,968 19,055
Marine services...................................... 124,725 115,314 77,803
Depreciation, depletion and amortization............. 45,729 40,627 41,776
-------- ---------- ----------
Total Operating Costs and Expenses........... 870,720 894,938 896,963
-------- ---------- ----------
OPERATING PROFIT....................................... 72,740 144,840 105,920
General and Administrative............................. (13,588) (12,733) (16,453)
Interest Expense, Net of Capitalized Interest in
1997................................................. (6,699) (15,382) (20,902)
Interest Income........................................ 1,597 8,423 1,845
Other Expense, Net..................................... (4,930) (10,001) (8,542)
-------- ---------- ----------
EARNINGS BEFORE INCOME TAXES AND EXTRAORDINARY ITEM.... 49,120 115,147 61,868
Income Tax Provision................................... 18,435 38,347 4,379
-------- ---------- ----------
EARNINGS BEFORE EXTRAORDINARY ITEM..................... 30,685 76,800 57,489
Extraordinary Loss on Extinguishments of Debt (Net of
Income Tax Benefit of $886 in 1996).................. -- (2,290) (2,857)
-------- ---------- ----------
NET EARNINGS........................................... $ 30,685 $ 74,510 $ 54,632
======== ========== ==========
NET EARNINGS PER SHARE -- BASIC........................ $ 1.16 $ 2.87 $ 2.22
======== ========== ==========
NET EARNINGS PER SHARE -- DILUTED...................... $ 1.14 $ 2.81 $ 2.18
======== ========== ==========
WEIGHTED AVERAGE COMMON SHARES -- BASIC................ 26,410 25,999 24,557
======== ========== ==========
WEIGHTED AVERAGE COMMON SHARES AND POTENTIALLY DILUTIVE
COMMON SHARES -- DILUTED............................. 26,868 26,499 25,107
======== ========== ==========
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,
----------------------
1997 1996
-------- --------
ASSETS
CURRENT ASSETS
Cash and cash equivalents................................. $ 8,352 $ 22,796
Receivables, less allowance for doubtful accounts......... 76,282 128,013
Inventories............................................... 87,359 74,488
Prepayments and other..................................... 9,842 12,046
-------- --------
Total Current Assets.............................. 181,835 237,343
-------- --------
PROPERTY, PLANT AND EQUIPMENT
Refining and marketing.................................... 370,174 328,522
Exploration and production, full-cost method of
accounting:
Properties being amortized............................. 251,604 179,433
Properties not yet evaluated........................... 31,918 12,344
Gas transportation..................................... 7,889 6,703
Marine services........................................... 43,072 33,820
Corporate................................................. 13,689 12,531
-------- --------
718,346 573,353
Less accumulated depreciation, depletion and
amortization.......................................... 304,523 256,842
-------- --------
Net Property, Plant and Equipment...................... 413,823 316,511
-------- --------
OTHER ASSETS................................................ 32,150 28,733
-------- --------
Total Assets...................................... $627,808 $582,587
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable.......................................... $ 58,767 $ 80,747
Accrued liabilities....................................... 31,372 33,256
Current income taxes payable.............................. 354 13,822
Current maturities of long-term debt and other
obligations............................................ 17,002 10,043
-------- --------
Total Current Liabilities......................... 107,495 137,868
-------- --------
DEFERRED INCOME TAXES....................................... 28,824 19,151
-------- --------
OTHER LIABILITIES........................................... 43,211 42,243
-------- --------
LONG-TERM DEBT AND OTHER OBLIGATIONS, LESS CURRENT
MATURITIES................................................ 115,314 79,260
-------- --------
COMMITMENTS AND CONTINGENCIES (Note L)
STOCKHOLDERS' EQUITY
Preferred stock, no par value; authorized 5,000,000 shares
including redeemable preferred shares; none issued or
outstanding
Common stock, par value $0.16 2/3; authorized 50,000,000
shares; 26,506,601 shares issued (26,414,134 in
1996).................................................. 4,418 4,402
Additional paid-in capital................................ 190,925 189,368
Retained earnings......................................... 140,980 110,295
Treasury stock, 216,453 common shares in 1997, at cost.... (3,359) --
-------- --------
Total Stockholders' Equity............................. 332,964 304,065
-------- --------
Total Liabilities and Stockholders' Equity........ $627,808 $582,587
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
45
48
TESORO PETROLEUM CORPORATION
STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY
(IN THOUSANDS)
RETAINED
COMMON STOCK ADDITIONAL EARNINGS TREASURY STOCK
--------------- PAID-IN (ACCUMULATED ----------------
SHARES AMOUNT CAPITAL DEFICIT) SHARES AMOUNT
------ ------ ---------- ------------ ------ -------
BALANCE AT DECEMBER 31, 1994............ 24,390 $4,065 $175,514 $(18,847) -- $ --
Net earnings.......................... -- -- -- 54,632 -- --
Shares issued pursuant to exercise of
stock options and stock awards..... 390 65 1,085 -- -- --
------ ------ -------- -------- ---- -------
BALANCE AT DECEMBER 31, 1995............ 24,780 4,130 176,599 35,785 -- --
Net earnings.......................... -- -- -- 74,510 -- --
Issuance of Common Stock.............. 1,308 218 11,054 -- -- --
Shares issued pursuant to exercise of
stock options and stock awards..... 326 54 1,715 -- -- --
------ ------ -------- -------- ---- -------
BALANCE AT DECEMBER 31, 1996............ 26,414 4,402 189,368 110,295 -- --
Net earnings.......................... -- -- -- 30,685 -- --
Shares repurchased.................... -- -- -- -- (236) (3,701)
Shares issued pursuant to exercise of
stock options and stock awards and
employee benefit plans............. 45 7 440 -- 20 342
Other................................. 48 9 1,117 -- -- --
------ ------ -------- -------- ---- -------
BALANCE AT DECEMBER 31, 1997............ 26,507 $4,418 $190,925 $140,980 (216) $(3,359)
====== ====== ======== ======== ==== =======
The accompanying notes are an integral part of these consolidated financial
statements.
46
49
TESORO PETROLEUM CORPORATION
STATEMENTS OF CONSOLIDATED CASH FLOWS
(IN THOUSANDS)
YEARS ENDED DECEMBER 31,
-------------------------------
1997 1996 1995
--------- -------- --------
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES
Net earnings.............................................. $ 30,685 $ 74,510 $ 54,632
Adjustments to reconcile net earnings to net cash from
operating activities:
Depreciation, depletion and amortization............... 46,363 41,459 42,620
Loss (gain) on sales of assets......................... 523 835 (32,659)
Amortization of deferred charges and other............. 951 1,601 1,556
Extraordinary loss on extinguishments of debt, net of
income tax benefit................................... -- 2,290 2,857
Changes in operating assets and liabilities:
Receivables.......................................... 56,785 (42,542) 9,746
Receivable from Tennessee Gas Pipeline Company....... -- 50,680 (37,456)
Inventories.......................................... (11,517) 7,210 (11,599)
Other assets......................................... 296 (3,521) (3,573)
Accounts payable and accrued liabilities............. (37,854) 28,165 4,605
Deferred income taxes................................ 9,673 14,649 807
Obligation payments to State of Alaska............... (4,401) (4,047) (2,892)
Other liabilities and obligations.................... 4,131 7,673 6,769
--------- -------- --------
Net cash from operating activities................ 95,635 178,962 35,413
--------- -------- --------
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES
Capital expenditures...................................... (147,498) (84,957) (63,930)
Proceeds from sales of assets............................. 112 2,569 69,786
Other..................................................... (4,159) (11,812) (3,452)
--------- -------- --------
Net cash from (used in) investing activities...... (151,545) (94,200) 2,404
--------- -------- --------
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES
Payments of long-term debt................................ (4,095) (3,838) (2,979)
Net borrowings under revolving credit facilities.......... 32,728 883 --
Issuance of long-term debt................................ 16,200 -- --
Repurchase of common stock................................ (3,701) -- --
Repurchase of debentures and notes........................ -- (74,116) (34,634)
Other..................................................... 334 1,164 (281)
--------- -------- --------
Net cash from (used in) financing activities...... 41,466 (75,907) (37,894)
--------- -------- --------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS............ (14,444) 8,855 (77)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR................ 22,796 13,941 14,018
--------- -------- --------
CASH AND CASH EQUIVALENTS, END OF YEAR...................... $ 8,352 $ 22,796 $ 13,941
========= ======== ========
SUPPLEMENTAL CASH FLOW DISCLOSURES
Interest paid, net of $419 capitalized in 1997............ $ 2,127 $ 12,450 $ 18,132
========= ======== ========
Income taxes paid......................................... $ 22,412 $ 6,285 $ 4,046
========= ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
47
50
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE A -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The accompanying Consolidated Financial Statements include the accounts of
Tesoro Petroleum Corporation and its subsidiaries (collectively, the "Company"
or "Tesoro"). All significant intercompany accounts and transactions have been
eliminated. Tesoro is a natural resource company engaged in petroleum refining,
distributing and marketing of petroleum products, marine logistics services and
the exploration and production of natural gas and oil.
Use of Estimates and Presentation
The preparation of the Company's Consolidated Financial Statements in
conformity with generally accepted accounting principles 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.
Cash and Cash Equivalents
Cash equivalents consist of highly-liquid debt instruments such as
commercial paper and certificates of deposit purchased with an original maturity
date of three months or less. Cash equivalents are stated at cost, which
approximates market value. The Company's policy is to invest cash in
conservative, highly-rated instruments and to invest in various institutions to
limit the amount of credit exposure in any one institution. The Company performs
ongoing evaluations of the credit standing of these financial institutions.
Inventories
Inventories are stated at the lower of cost or market. The last-in,
first-out ("LIFO") method was used to determine the cost of the Company's
refining and marketing inventories of crude oil and U.S. wholesale refined
products. The cost of remaining refined product inventories, including fuel at
the Company's marine service terminals, was determined principally on the
first-in, first-out ("FIFO") method. Merchandise and materials and supplies are
valued at average cost, not in excess of market value. See Note F.
Property, Plant and Equipment
Additions to property, plant and equipment and major improvements and
modifications are capitalized at cost. Maintenance and repairs are charged to
operations when incurred. Depletion of oil and gas producing properties is
determined principally by the unit-of-production method and is based on
estimated recoverable reserves. Depreciation of other property, plant and
equipment is generally computed on the straight-line method based upon the
estimated useful life of each asset. The weighted average lives range from 12 to
30 years for refining, marketing and pipeline assets, 11 to 16 years for service
equipment and marine fleets, and five to seven years for corporate and other
assets.
Oil and gas properties are accounted for using the full-cost method of
accounting. Under this method, all costs associated with property acquisition
and exploration and development activities are capitalized into cost centers
that are established on a country-by-country basis. For each cost center, the
capitalized costs are subject to a limitation so as not to exceed the present
value of future net revenues from estimated production of proved oil and gas
reserves, net of income tax effect, plus the lower of cost or estimated fair
value of unproved properties included in the cost center. Capitalized costs
within a cost center, together with estimates of costs for future development,
dismantlement and abandonment, are amortized on a unit-of-production method
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
48
51
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
recognized only on the sale of oil and gas properties involving significant
reserves. Proceeds from the sale of insignificant reserves and undeveloped
properties are applied to reduce the costs in the cost centers.
Income Taxes
Deferred tax assets and liabilities are recognized for future income tax
consequences attributable to differences between financial statement carrying
amounts of assets and liabilities and their respective tax bases. Measurement of
deferred tax assets and liabilities is based on enacted tax rates expected to
apply to taxable income in the years in which those temporary differences are
expected to be recovered or settled. The effect on deferred tax assets and
liabilities of a change in tax rates is recognized in the period that includes
the enactment date.
Environmental Expenditures
Environmental expenditures that relate to current operations are expensed
or capitalized as appropriate. Expenditures that extend the life, increase the
capacity, or mitigate or prevent environmental contamination, are capitalized.
Expenditures that relate to an existing condition caused by past operations, and
which do not contribute to current or future revenue generation, are expensed.
Liabilities are recorded when environmental assessments and/or remedial efforts
are probable and the cost can be reasonably estimated. Such amounts are based on
the estimated timing and extent of remedial actions required by applicable
governing agencies, experience gained from similar sites on which environmental
assessments or remediation has been completed, and the amount of the Company's
anticipated liability considering the proportional liability and financial
abilities of other responsible parties. Generally, the timing of these accruals
coincides with completion of a feasibility study or the Company's commitment to
a formal plan of action. Estimated liabilities are not discounted to present
value.
Financial Instruments
The carrying amount of financial instruments including cash and cash
equivalents, accounts receivable, accounts payable and certain accrued
liabilities approximates fair value because of the short maturity of these
instruments. The carrying amount of the Company's long-term debt and other
obligations approximated the Company's estimates of the fair value of such
items.
49
52
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Earnings Per Share
Earnings per share have been determined in accordance with Statement of
Financial Accounting Standard ("SFAS") No. 128 which establishes standards for
computing and presenting basic and diluted earnings per share calculations.
Basic earnings per share is determined by dividing net earnings by the weighted
average number of common shares outstanding during the period. The Company's
calculation of diluted earnings per share takes into account the effect of
potentially dilutive shares, principally stock options, outstanding during the
period. Prior period amounts have been restated to conform with the requirements
of SFAS No. 128. Earnings per share calculations for the years ended December
31, 1997, 1996 and 1995 are presented below (in thousands except per share
amounts):
1997 1996 1995
------- ------- -------
Earnings Applicable to Common Shareholders (Basic and
Diluted Numerator):
Earnings before extraordinary item.................. $30,685 $76,800 $57,489
Extraordinary loss on extinguishments of debt,
aftertax......................................... -- (2,290) (2,857)
------- ------- -------
Net earnings..................................... $30,685 $74,510 $54,632
======= ======= =======
Basic:
Weighted average common shares (Basic
denominator)..................................... 26,410 25,999 24,557
======= ======= =======
Basic earnings per share --
Before extraordinary item........................ $ 1.16 $ 2.96 $ 2.34
Extraordinary loss, aftertax..................... -- (0.09) (0.12)
------- ------- -------
Net.............................................. $ 1.16 $ 2.87 $ 2.22
======= ======= =======
Diluted:
Weighted average common shares...................... 26,410 25,999 24,557
Incremental shares from assumed conversion of stock
options and other................................ 458 500 550
------- ------- -------
Total diluted shares (Diluted denominator).......... 26,868 26,499 25,107
======= ======= =======
Diluted earnings per share --
Before extraordinary item........................ $ 1.14 $ 2.90 $ 2.29
Extraordinary loss, aftertax..................... -- (0.09) (0.11)
------- ------- -------
Net.............................................. $ 1.14 $ 2.81 $ 2.18
======= ======= =======
In accordance with SFAS No. 128, restricted Common Stock awards totaling
350,000 shares and options to purchase 340,000 shares of Common Stock under the
Company's special incentive compensation strategy (see Note K) were not included
in the computations of earnings per share in 1997 and 1996. No shares were
issuable under this strategy since the attainment of a specified market price of
the Company's Common Stock had not been reached during the periods presented.
These awards and options remained outstanding at December 31, 1997.
Stock-Based Compensation
The Company accounts for stock-based compensation using the intrinsic value
method prescribed in Accounting Principles Board ("APB") No. 25, "Accounting for
Stock Issued to Employees," and related interpretations. Accordingly,
compensation cost for stock options is measured as the excess, if any, of the
quoted market price of the Company's Common Stock at the date of grant over the
amount an employee must pay to acquire the stock. The Company has adopted the
disclosure requirements of SFAS No. 123, "Accounting for Stock-Based
Compensation," as included in Note K.
50
53
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
New Accounting Standards
In June 1997, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 130, "Reporting Comprehensive Income," which establishes standards for
reporting and display of comprehensive income and its components in a full set
of general-purpose financial statements. SFAS No. 130, which becomes effective
for the Company in 1998, requires that all items that are required to be
recognized under accounting standards as components of comprehensive income be
reported in a financial statement that is displayed with the same prominence as
other financial statements. Also, in June 1997, the FASB issued SFAS No. 131,
"Disclosures about Segments of an Enterprise and Related Information," which
establishes standards for reporting information about operating segments in
annual financial statements and requires that selected information about
operating segments be included in interim financial reports issued to
shareholders. SFAS No. 131 also establishes standards for related disclosures
about products and services, geographic areas and major customers. SFAS No. 131
becomes effective for the Company's 1998 year-end and need not be applied to
interim financial information until 1999. In February 1998, the FASB issued SFAS
No. 132, "Employers' Disclosures about Pensions and Other Postretirement
Benefits," which standardizes the disclosures related to pensions and other
postretirement benefits to the extent practicable, requires additional
information on changes in the benefit obligations and fair values of plan assets
and eliminates certain disclosures previously required. SFAS No. 132 becomes
effective for the Company in 1998. All three statements contain provisions for
restatement of prior period information. The Company is evaluating the effects
that these new statements will have on its financial reporting and disclosures.
The new statements will have no effect on the Company's results of operations,
financial position or cash flows.
NOTE B -- BUSINESS SEGMENTS
The Company's revenues are derived from three business segments: Refining
and Marketing, Exploration and Production, and Marine Services.
Refining and Marketing operates a petroleum refinery at Kenai, Alaska,
which manufactures gasoline, jet fuel, diesel fuel, heavy oils and residual
products. These products, together with products purchased from third parties,
are sold at wholesale through terminal facilities and other locations in Alaska
and the Pacific Northwest. In addition, Refining and Marketing markets gasoline,
other petroleum products and convenience store items at retail through 35
Company-operated stations in Alaska. Refining and Marketing also markets
petroleum products through 129 branded and 28 unbranded stations located in
Alaska and the Pacific Northwest. Revenues from export sales, primarily to Far
East markets, amounted to $16.1 million, $22.0 million and $18.5 million in
1997, 1996 and 1995, respectively. The Company at times resells previously
purchased crude oil, sales of which amounted to $44.4 million, $93.8 million and
$75.8 million in 1997, 1996 and 1995, respectively.
The Exploration and Production segment is engaged in the exploration,
production and development of natural gas and oil onshore in Texas, Louisiana
and Bolivia. This segment also includes the transportation of natural gas,
including the Company's production, to common carrier pipelines in South Texas.
In Bolivia, the Company operates under four contracts with the Bolivian
government to explore for and produce hydrocarbons. The Company's Bolivian
natural gas production is sold under contract to the Bolivian government for
export to Argentina. The majority of the Company's Bolivian natural gas and oil
reserves are shut-in awaiting access to gas-consuming markets. Major
developments in South America indicate that new markets may open for the
Company's production in the near future. Construction of a new 1,900-mile
pipeline that will link Bolivia's gas reserves with markets in Brazil commenced
in 1997 and is expected to be operational in early 1999.
Marine Services markets and distributes petroleum products and provides
logistics services, primarily to the marine and offshore exploration and
production industries operating in the Gulf of Mexico. This segment
51
54
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
currently operates through 20 terminals along the Texas and Louisiana Gulf Coast
and three terminals on the U.S. West Coast.
Segment operating profit is gross operating revenues, gains and losses on
asset sales and other income less applicable segment costs of sales, operating
expenses, depreciation, depletion and other items. Income taxes, interest
expense, interest income and corporate general and administrative expenses are
not included in determining operating profit. In the Exploration and Production
segment, operating profit in 1997 included income of $1.8 million for severance
tax refunds and $2.2 million related to the collection of a receivable for prior
years Bolivian production. Operating profit in the Exploration and Production
segment in 1996 included $60 million of income from termination of a natural gas
contract and $5 million for retroactive severance tax refunds, and 1995 included
a gain of $33 million from the sale of certain interests in the Bob West Field.
In 1996 and 1995, the Exploration and Production segment's operating profit
included $24.6 million and $47.1 million, respectively, from the excess of
natural gas contract prices over spot market prices (see Note D).
Identifiable assets are those assets utilized by the segment. Corporate
assets are principally cash, investments and other assets that cannot be
directly associated with the operations of a business segment. Segment
information for the years ended December 31, 1997, 1996 and 1995 is as follows
(in millions):
1997 1996 1995
------ -------- --------
REVENUES
Gross operating revenues:
Refining and Marketing --
Refined products.................................. $643.7 $ 620.8 $ 664.5
Other, primarily crude oil resales and
merchandise.................................... 77.2 124.6 106.5
Exploration and Production --
U.S., including gas transportation................ 73.6 93.8 113.0
Bolivia........................................... 11.2 13.7 11.7
Marine Services..................................... 132.2 122.5 74.5
------ -------- --------
Total Gross Operating Revenues.................... 937.9 975.4 970.2
Income from settlement of a natural gas contract and
other............................................... 5.5 64.4 32.7
------ -------- --------
Total Revenues................................. $943.4 $1,039.8 $1,002.9
====== ======== ========
OPERATING PROFIT (LOSS)
Refining and Marketing................................. $ 20.5 $ 6.0 $ 0.7
Exploration and Production --
U.S., including gas transportation.................. 37.3 123.9 102.0
Bolivia............................................. 8.6 8.8 7.6
Marine Services........................................ 6.3 6.1 (4.4)
------ -------- --------
Total Operating Profit......................... 72.7 144.8 105.9
Corporate and Unallocated Costs........................ (23.6) (29.7) (44.0)
------ -------- --------
Earnings Before Income Taxes and Extraordinary Item.... $ 49.1 $ 115.1 $ 61.9
====== ======== ========
52
55
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
1997 1996 1995
------ -------- --------
IDENTIFIABLE ASSETS
Refining and Marketing................................. $337.4 $ 317.0 $ 313.3
Exploration and Production --
U.S., including gas transportation.................. 158.2 143.6 136.7
Bolivia............................................. 50.8 27.0 17.8
Marine Services........................................ 59.3 56.0 18.0
Corporate.............................................. 22.1 39.0 33.4
------ -------- --------
Total Assets................................... $627.8 $ 582.6 $ 519.2
====== ======== ========
DEPRECIATION, DEPLETION AND AMORTIZATION
Refining and Marketing................................. $ 12.7 $ 12.5 $ 11.9
Exploration and Production --
U.S., including gas transportation.................. 29.8 25.6 29.3
Bolivia............................................. 1.5 1.3 0.3
Marine Services........................................ 1.7 1.2 0.3
Corporate.............................................. 0.7 0.9 0.8
------ -------- --------
Total Depreciation, Depletion and
Amortization................................. $ 46.4 $ 41.5 $ 42.6
====== ======== ========
CAPITAL EXPENDITURES
Refining and Marketing................................. $ 43.9 $ 11.1 $ 9.3
Exploration and Production --
U.S., including gas transportation.................. 65.4 59.7 49.6
Bolivia............................................. 27.5 6.9 3.8
Marine Services........................................ 9.4 6.9 0.4
Corporate.............................................. 1.3 0.4 0.8
------ -------- --------
Total Capital Expenditures..................... $147.5 $ 85.0 $ 63.9
====== ======== ========
NOTE C -- ACQUISITIONS, EXPANSIONS AND DIVESTITURES
Refining and Marketing
In October 1997, the Company completed an expansion of its refinery
hydrocracker unit which enables the Company to increase its jet fuel production.
The expansion, together with the addition of a new, high-yield jet fuel
hydrocracker catalyst, was completed at a cost of approximately $19 million. For
information on financing of this expansion, see Note I.
In December 1997, the Refining and Marketing segment purchased the Union 76
marketing assets in Southeast Alaska, consisting of one terminal, two retail
stations and the rights to use the Union 76 trademark within Alaska. The Company
also expanded its Alaskan retail operations throughout the year with
construction of two new facilities and remodeling of three existing stations.
Two uneconomic outlets in Alaska were closed in 1997.
Exploration and Production
In July 1997, the Company purchased the interests held by its former joint
venture participant in the then existing two contract blocks in southern
Bolivia, consisting of a 25% interest in Block 18 and a 27.4% interest in Block
20. The purchase price was approximately $20 million, which included $11.9
million for proved reserves and $3.4 million for undeveloped acreage with the
remainder for working capital and assumption of certain liabilities.
53
56
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In the U.S., the Exploration and Production segment purchased proved and
unproved properties totaling $22 million during 1997. These purchases included
the acquisition of interests in the Kent Bayou Field in Terrebonne Parish in
southern Louisiana for $5 million and interests in the La Blanca, San Salvador
and San Carlos Fields in the Frio/Vicksburg Trend of Hildago County in South
Texas for $3.1 million during November 1997. Also included was the acquisition
of interests in three natural gas fields in East Texas, including the Carthage
Field in Panola County, the Woodlawn Field in Harrison County and the Oak Hill
Field in Rusk County, for $5.1 million in December 1997.
During 1996, the Company's Exploration and Production segment recorded
acquisitions of proved and unproved properties totaling $25.7 million. The most
significant of these was the purchase in December 1996 of interests in the Los
Indios and La Reforma Fields, located in Hidalgo and Starr counties of South
Texas, for $15 million. These two fields are in the Frio/Vicksburg Trend, which
lies immediately adjacent to the Wilcox Trend. Other acquisitions in 1996
included the purchase of interests in the Berry R. Cox and the West Goliad
Fields, both located in the Wilcox Trend, for $5.4 million and the purchase of
acreage in East Texas for $5.3 million.
In September 1995, the Company sold, effective April 1, 1995, certain
interests in its producing and non-producing oil and gas properties located in
the Bob West Field in South Texas. The interests sold included the Company's
approximate 55% net revenue interest and 70% working interest in Units C, D and
E and a convertible override in Unit F of the Bob West Field. Excluded from the
sale were the Company's interests in the State Park and Sanchez-O'Brien leases
and the Ramirez USA E-6 well within the Bob West Field. In total, the sale
included interests in 14 gross producing wells amounting to 77 Bcf, or 40%, of
the Company's total net proved domestic reserves at the time of the sale (see
Note N). For 1995, natural gas production from the interests sold had
contributed approximately $11.7 million to revenues and $4 million to operating
profit in the Company's Exploration and Production segment. Consideration for
the sale was $74 million, which was adjusted for production, capital
expenditures and certain other items after the effective date to approximately
$68 million in cash received at closing, resulting in a gain of approximately
$33 million in the 1995 third quarter. The consideration received by the Company
was used to redeem $34.6 million of the Company's outstanding 12 3/4%
Subordinated Debentures in 1995, reduce borrowings under the Company's revolving
credit facility and improve corporate liquidity (see Note I).
For further information related to exploration and production activities,
see Note N.
Marine Services
In February 1996, the Company purchased 100% of the capital stock of
Coastwide Energy Services, Inc. ("Coastwide"). The consideration included
approximately 1.4 million shares of Tesoro's Common Stock and $7.7 million in
cash. The market price of Tesoro's Common Stock was $9.00 per share at closing
of this transaction. In addition, Tesoro repaid approximately $4.5 million of
Coastwide's outstanding debt. Coastwide was primarily a provider of logistical
support services and a distributor of petroleum products to the offshore oil and
gas industry in the Gulf of Mexico. The Company combined the Coastwide operation
with its marine petroleum distribution operations, forming a Marine Services
segment. The acquisition was accounted for as a purchase whereby the purchase
price was allocated to the assets acquired and liabilities assumed based upon
their estimated fair values.
NOTE D -- GAS PURCHASE AND SALES CONTRACT
Resolution of Litigation in 1996
On August 16, 1996, the Supreme Court of Texas issued a mandate that denied
a motion for rehearing by Tennessee Gas Pipeline Company ("Tennessee Gas") and
upheld all aspects of a Gas Purchase and Sales Agreement ("Tennessee Gas
Contract") which had been the subject of litigation since 1990. As provided for
54
57
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
in the Tennessee Gas Contract, the Company was selling a portion of the gas
produced from the Bob West Field to Tennessee Gas at a maximum price as
calculated in accordance with Section 102(b)(2) ("Contract Price") of the
Natural Gas Policy Act of 1978. Subsequent to the mandate, the Company received
cash of $67.7 million from Tennessee Gas, which included collection of a $59.6
million bonded receivable for underpayment for natural gas sold in prior
periods. The remaining $8.1 million received was for interest and reimbursement
of legal fees and court costs, which resulted in income during the 1996 third
quarter. Tennessee Gas resumed paying the Contract Price to the Company for gas
taken beginning with May 1996 volumes up until termination of the Tennessee Gas
Contract discussed below.
Settlement and Termination of Contract in 1996
On December 24, 1996, the Company settled all other claims and disputes
with Tennessee Gas, including litigation in Zapata County, Texas filed by
Tennessee Gas, and agreed to terminate the Tennessee Gas Contract effective
October 1, 1996. The Tennessee Gas Contract would have extended through January
1999. Under the settlement, the Company received $51.8 million and the right to
recover severance taxes paid by Tennessee Gas of approximately $8.2 million,
which resulted in income of $60 million to the Company during the 1996 fourth
quarter. The severance taxes were subsequently collected in 1997.
NOTE E -- RECEIVABLES
Concentrations of credit risk with respect to accounts receivable are
limited, due to the large number of customers comprising the Company's customer
base and their dispersion across the Company's industry segments and geographic
areas of operations. The Company performs ongoing credit evaluations of its
customers' financial condition and in certain circumstances requires letters of
credit or other collateral arrangements. The Company's allowance for doubtful
accounts is reflected as a reduction of receivables in the Consolidated Balance
Sheets. The following table reconciles the change in the Company's allowance for
doubtful accounts for the years ended December 31, 1997, 1996 and 1995 (in
thousands):
1997 1996 1995
------ ------ ------
Balance at Beginning of Year............................. $1,515 $1,842 $1,816
Charged to Costs and Expenses............................ 23 589 300
Recoveries of Amounts Previously Written Off and Other... 189 (44) 122
Write-off of Doubtful Accounts........................... (354) (872) (396)
------ ------ ------
Balance at End of Year................................. $1,373 $1,515 $1,842
====== ====== ======
NOTE F -- INVENTORIES
Components of inventories at December 31, 1997 and 1996 were as follows (in
thousands):
1997 1996
------- -------
Crude Oil and Wholesale Refined Products, at LIFO........... $68,227 $55,858
Merchandise and Other Refined Products...................... 13,377 13,539
Materials and Supplies...................................... 5,755 5,091
------- -------
Total Inventories......................................... $87,359 $74,488
======= =======
At December 31, 1997 and 1996, inventories valued using LIFO were lower
than replacement cost by approximately $4.4 million and $17.7 million,
respectively.
55
58
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE G -- ACCRUED LIABILITIES
The Company's current accrued liabilities and noncurrent other liabilities
as shown in the Consolidated Balance Sheets at December 31, 1997 and 1996
included the following (in thousands):
1997 1996
------- -------
Accrued Liabilities -- Current:
Accrued environmental costs............................... $ 5,817 $ 5,367
Accrued employee costs.................................... 12,406 7,759
Accrued taxes other than income taxes..................... 4,137 5,988
Accrued interest.......................................... 1,349 1,155
Other..................................................... 7,663 12,987
------- -------
Total Accrued Liabilities -- Current................... $31,372 $33,256
======= =======
Other Liabilities -- Noncurrent:
Accrued postretirement benefits........................... $32,206 $30,508
Accrued environmental costs............................... 2,659 3,496
Other..................................................... 8,346 8,239
------- -------
Total Other Liabilities -- Noncurrent.................. $43,211 $42,243
======= =======
NOTE H -- INCOME TAXES
The income tax provision for the years ended December 31, 1997, 1996 and
1995 included the following (in thousands):
1997 1996 1995
------- ------- ------
Federal -- Current..................................... $ 3,413 $16,206 $ 708
Federal -- Deferred.................................... 9,421 17,405 --
Foreign................................................ 4,920 3,654 3,183
State.................................................. 681 1,082 488
------- ------- ------
Income Tax Provision................................. $18,435 $38,347 $4,379
======= ======= ======
Deferred income taxes and benefits are provided for differences between
financial statement carrying amounts of assets and liabilities and their
respective tax bases. Temporary differences and the resulting deferred tax
assets and liabilities at December 31, 1997 and 1996 are summarized as follows
(in thousands):
1997 1996
-------- --------
Deferred Federal Tax Assets:
Investment tax and other credits.......................... $ 9,639 $ 11,962
Accrued postretirement benefits........................... 10,480 9,941
Settlement with Department of Energy...................... 3,233 3,694
Environmental reserve..................................... 3,048 3,335
Other..................................................... 5,265 1,523
-------- --------
Total Deferred Federal Tax Assets...................... 31,665 30,455
Deferred Federal Tax Liabilities:
Accelerated depreciation and property-related items....... (57,778) (47,147)
-------- --------
Net Deferred Federal Liability.............................. (26,113) (16,692)
State Income and Other Taxes................................ (2,711) (2,459)
-------- --------
Net Deferred Tax Liability................................ $(28,824) $(19,151)
======== ========
56
59
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following tables set forth the components of the Company's results of
operations (in thousands) and a reconciliation of the normal statutory federal
income tax rate with the Company's effective tax rate:
1997 1996 1995
------- -------- -------
Earnings Before Income Taxes and Extraordinary Item:
U.S................................................ $40,200 $106,675 $55,221
Foreign............................................ 8,920 8,472 6,647
------- -------- -------
Total Earnings Before Income Taxes and
Extraordinary Item............................ $49,120 $115,147 $61,868
======= ======== =======
Statutory U.S. Corporate Tax Rate.................... 35% 35% 35%
Effect of:
Foreign income taxes, net of tax benefit........... 5 2 5
State income taxes, net of tax benefit............. 1 1 1
Accounting recognition of operating loss tax
benefits........................................ -- (4) (33)
Other.............................................. (4) (1) (1)
------- -------- -------
Effective Income Tax Rate............................ 37% 33% 7%
======= ======== =======
At December 31, 1997, the Company had approximately $6.9 million of
investment tax credits and employee stock ownership credits available for
carryover to subsequent years, which, if not used, will expire in the years 1999
through 2006. Additionally, at December 31, 1997, the Company had approximately
$2.7 million of alternative minimum tax credit carryforwards, with no expiration
dates, to offset future regular tax liabilities.
NOTE I -- LONG-TERM DEBT AND OTHER OBLIGATIONS
Long-term debt and other obligations at December 31, 1997 and 1996
consisted of the following (in thousands):
1997 1996
-------- -------
Liability to State of Alaska................................ $ 62,016 $62,079
Corporate Revolving Credit Facility......................... 28,000 --
Marine Services Loan Facility............................... 5,611 883
Hydrocracker Loan........................................... 16,200 --
Vacuum Unit Loan............................................ 9,107 11,250
Liability to Department of Energy........................... 9,235 10,555
Other....................................................... 2,147 4,536
-------- -------
132,316 89,303
Less Current Maturities..................................... 17,002 10,043
-------- -------
$115,314 $79,260
======== =======
Aggregate maturities of long-term debt and obligations for each of the five
years following December 31, 1997 are as follows: 1998 -- $17.0 million;
1999 -- $11.9 million; 2000 -- $40.1 million; 2001 -- $13.6 million; and
2002 -- $5.6 million. In addition, in the year 2002, a $60 million payment is
due to the State of Alaska, but may be deferred indefinitely, at the Company's
option, by continuing a variable per barrel throughput charge described below.
57
60
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
State of Alaska
In 1993, the Company entered into an agreement ("Agreement") with the State
of Alaska ("State") that settled a contractual dispute with the State. Under the
Agreement, the Company is obligated to make variable monthly payments to the
State through December 2001 based on a per barrel charge on the volume of
feedstock processed through the Company's refinery crude unit. In 1997 and 1996,
based on a per barrel throughput charge of 24 cents, the Company's variable
payments to the State totaled $4.4 million and $4.0 million, respectively. In
1995, based on a per barrel throughput charge of 16 cents, the Company's
variable payments to the State totaled $2.9 million. The per barrel charge
increases to 30 cents in 1998 with one cent annual incremental increases
thereafter through 2001. In January 2002, the Company is obligated to pay the
State $60 million; provided, however, that such payment may be deferred
indefinitely, at the Company's option, 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 collateralized by a fourth lien 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. Loans obtained to finance the expansion of
the hydrocracker unit and install the vacuum unit, both discussed below, qualify
as indebtedness incurred subsequent to the Agreement to improve the Company's
refinery.
Corporate Revolving Credit Facility
The Company's amended and restated corporate revolving credit agreement
("Credit Facility"), which expires in April 2000, provides total commitments of
$150 million from a consortium of nine banks. The Company, at its option, has
currently activated $100 million of these commitments. The Credit Facility
provides for the issuance of letters of credit, and for cash borrowings up to
$100 million, with the aggregate subject to a borrowing base (which amount
exceeded total commitments at December 31, 1997). Outstanding obligations under
the Credit Facility are collateralized by first liens on substantially all of
the Company's trade receivables, product inventories and South Texas natural gas
reserves and by a third lien on the Company's refinery.
At December 31, 1997, the Company had outstanding cash borrowings of $28
million under the Credit Facility. During 1997, gross borrowings under the
Credit Facility were $150 million, with $122 million of repayments. During 1996
and 1995, the Company's gross borrowings equaled repayments under the Credit
Facility and totaled $165 million and $262 million, respectively. These cash
borrowings are generally used on a short-term basis to finance working capital
requirements and capital expenditures. Under the Credit Facility, at December
31, 1997, the Company had outstanding letters of credit of $34 million,
primarily for royalty crude oil purchases from the State of Alaska. Unused
availability, including unactivated commitments, under the Credit Facility at
December 31, 1997 for additional borrowings and letters of credit totaled $88
million. The Company is also permitted to utilize unsecured letters of credit
outside of the Credit Facility up to $40 million (none outstanding at December
31, 1997).
Cash borrowings under the Credit Facility bear interest at (i) the London
Interbank Offered Rate ("LIBOR") plus 1.0% per annum or (ii) the prime rate per
annum, at the Company's option. Fees on outstanding letters of credit under the
Credit Facility are 1.0% per annum.
The Credit Facility, which has been amended from time to time, requires the
Company to maintain specified levels of consolidated working capital, tangible
net worth, cash flow and interest coverage and contains other covenants
customary in credit arrangements of this kind. Among other matters, the terms of
the Credit Facility allow for general open market stock repurchases and the
payment of cash dividends subject to a
58
61
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
cumulative amount available for restricted payments (defined as the difference
of (i) the sum since December 31, 1995, of (a) $5 million and (b) 50% of
consolidated net earnings of the Company in any calendar year and (ii) any
restricted payments made since June 1996). At December 31, 1997, the cumulative
amount available for restricted payments was approximately $58 million. In
addition to the cumulative restriction, the Credit Facility further limits these
general open market stock repurchases and cash dividends to a maximum of $5
million annually. The Credit Facility also permits the Company to repurchase a
limited amount of Common Stock, up to $10 million annually, specifically for
oddlot buyback programs and employee benefit or compensation plans.
Marine Services Loan Facility
In January 1998, the Company terminated a $10 million loan facility which
had provided a three-year line of credit to the Marine Services segment at the
bank's prime rate. The outstanding balance of $5.6 million at December 31, 1997
was repaid subsequent to year-end.
Hydrocracker Loan
In October 1997, the National Bank of Alaska ("NBA") and the Alaska
Industrial Development and Export Authority ("AIDEA"), under a loan agreement
("Hydrocracker Loan") entered into between the Company and NBA, provided a $16.2
million loan to the Company towards the cost of its refinery hydrocracker
expansion (see Note C). One-half of the loan was funded by NBA and the other
half was funded by AIDEA. The Hydrocracker Loan matures on or before April 1,
2005 and requires 28 equal quarterly principal payments beginning April 1998
together with interest at the unsecured 90-day commercial paper rate (5.55% at
December 31, 1997) adjusted quarterly plus (i) 2.6% per annum on 50% of the
amount borrowed and (ii) 2.35% per annum on the other 50% borrowed. The
Hydrocracker Loan is collateralized by a second lien on the refinery. Under the
terms of the Hydrocracker Loan, the Company is required to maintain specified
levels of working capital and tangible net worth.
Vacuum Unit Loan
In 1994, the NBA and the AIDEA provided a $15 million loan to the Company
towards the cost of the Company's refinery vacuum unit ("Vacuum Unit Loan"). The
Vacuum Unit Loan matures January 1, 2002, requires equal quarterly payments of
approximately $536,000 and bears interest at the unsecured 90-day commercial
paper rate, adjusted quarterly, plus 2.6% per annum (8.11% at December 31, 1997)
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, 1997)
for the remainder. The Vacuum Unit Loan is collateralized by a first lien on the
Company's refinery. Under the terms of the Vacuum Unit Loan, as amended, the
Company is required to maintain specified levels of working capital and tangible
net worth.
Department of Energy
A Consent Order entered into by the Company with the Department of Energy
("DOE") in 1989 settled all issues relating to the Company's compliance with
federal petroleum price and allocation regulations from 1973 through decontrol
in 1981. At December 31, 1997, the Company's remaining obligation is to pay the
DOE $9.2 million, exclusive of interest at 6%, over the next five years.
Repurchase of Debentures and Notes
In November 1996, the Company fully redeemed its two public debt issues,
totaling approximately $74 million, at a price equal to 100% of the principal
amount, plus accrued interest to the redemption date. The redemption of debt was
comprised of $44.1 million of outstanding 13% Exchange Notes and $30 million of
outstanding 12 3/4% Subordinated Debentures ("Subordinated Debentures"). The
redemption was
59
62
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
accounted for as an early extinguishment of debt in the 1996 third quarter,
resulting in a pretax charge of $3.2 million ($2.3 million aftertax) which
represented a write-off of unamortized bond discount and issue costs. The
extraordinary loss on debt extinguishments of $2.9 million in 1995 related to
the redemption of $34.6 million principal amount of Subordinated Debentures in
December 1995.
NOTE J -- BENEFIT PLANS
Retirement Plan
For all eligible employees, the Company provides a qualified
noncontributory retirement plan. Plan benefits are based on years of service and
compensation. The Company's funding policy is to make contributions at a minimum
in accordance with the requirements of applicable laws and regulations, but no
more than the amount deductible for income tax purposes. The components of net
pension expense for the Company's retirement plan for the years ended December
31, 1997, 1996 and 1995 are presented below (in thousands):
1997 1996 1995
------- ------- -------
Service Costs......................................... $ 1,502 $ 1,306 $ 1,147
Interest Cost......................................... 3,696 3,536 3,549
Actual Return on Plan Assets.......................... (8,817) (6,212) (8,299)
Net Amortization and Deferral......................... 4,105 1,687 4,288
------- ------- -------
Net Pension Expense................................. $ 486 $ 317 $ 685
======= ======= =======
The funded status of the Company's retirement plan and amounts included in
the Company's Consolidated Balance Sheets at December 31, 1997 and 1996 are set
forth in the following table (in thousands):
1997 1996
------- -------
Actuarial Present Value of Benefit Obligation:
Vested benefit obligation................................. $41,601 $40,539
======= =======
Accumulated benefit obligation............................ $44,877 $43,404
======= =======
Plan Assets at Fair Value................................... $50,982 $46,356
Projected Benefit Obligation................................ 52,685 50,163
------- -------
Plan Assets Less Than Projected Benefit Obligation.......... (1,703) (3,807)
Unrecognized Net Loss....................................... 2,003 5,903
Unrecognized Prior Service Costs............................ (267) (341)
Unrecognized Net Transition Asset........................... (1,940) (3,176)
------- -------
Accrued Pension Liability................................. $(1,907) $(1,421)
======= =======
Retirement plan assets are primarily comprised of common stock and bond
funds. Actuarial assumptions used to measure the projected benefit obligations
included a discount rate of 7 1/2% and a compensation increase rate of 5% for
December 31, 1997, 1996 and 1995. The expected long-term rate of return on
assets was 8 1/2% for 1997, 1996 and 1995.
60
63
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Executive Security Plan
The Company's executive security plan ("ESP") provides executive officers
and other key personnel with supplemental death or retirement benefits in
addition to those benefits available under the Company's group life insurance
and retirement plans. These supplemental retirement benefits are provided by a
nonqualified, noncontributory plan and are based on years of service and
compensation. Contributions are made by the Company based upon the estimated
requirements of the plan. The components of net pension expense for the ESP for
the years ended December 31, 1997, 1996 and 1995 are presented below (in
thousands):
1997 1996 1995
------ ----- -----
Service Costs............................................. $ 521 $ 354 $ 364
Interest Cost............................................. 363 204 205
Actual Return on Plan Assets.............................. (596) (439) (325)
Net Amortization and Deferral............................. 1,196 751 471
------ ----- -----
Net Pension Expense..................................... $1,484 $ 870 $ 715
====== ===== =====
During 1997, 1996 and 1995, the Company incurred additional ESP expense of
$1.2 million, $0.9 million and $1.5 million, respectively, for settlements,
curtailments and other benefits resulting from employee terminations.
The funded status of the ESP and amounts included in the Company's
Consolidated Balance Sheets at December 31, 1997 and 1996 are set forth in the
following table (in thousands):
1997 1996
------ ------
Actuarial Present Value of Benefit Obligation:
Vested benefit obligation................................. $4,885 $3,300
====== ======
Accumulated benefit obligation............................ $5,585 $4,434
====== ======
Plan Assets at Fair Value................................... $7,732 $7,139
Projected Benefit Obligation................................ 8,683 6,467
------ ------
Plan Assets in Excess of (Less Than) Projected Benefit
Obligation................................................ (951) 672
Unrecognized Net Loss....................................... 6,442 4,532
Unrecognized Prior Service Costs............................ 895 537
Unrecognized Net Transition Obligation...................... 314 417
------ ------
Prepaid Pension Asset..................................... $6,700 $6,158
====== ======
Assets of the ESP consist of a group annuity contract. Actuarial
assumptions used to measure the projected benefit obligation at December 31,
1997, 1996 and 1995 included a discount rate of 7 1/2% and a compensation
increase rate of 5%. The expected long-term rate of return on assets was 7% for
1997 and 8% for 1996 and 1995.
Retiree Health Care and Life Insurance Benefits
The Company provides health care and life insurance benefits to retirees
who were participating in the Company's group insurance program at retirement.
Health care is also provided to qualified dependents of participating retirees.
These benefits are provided through unfunded, defined benefit plans. The health
care plans are contributory, with retiree contributions adjusted periodically,
and contain other cost-sharing features such as deductibles and coinsurance. The
life insurance plan is noncontributory. The Company funds its share of the cost
of postretirement health care and life insurance benefits on a pay-as-you-go
basis. The components
61
64
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
of net periodic postretirement benefits expense, other than pensions, for the
years ended December 31, 1997, 1996 and 1995 included the following (in
thousands):
1997 1996 1995
------ ------ ------
Health Care:
Service costs.......................................... $ 676 $ 558 $ 447
Interest costs......................................... 1,304 1,294 1,399
------ ------ ------
Net Periodic Postretirement Expense................. $1,980 $1,852 $1,846
====== ====== ======
Life Insurance:
Service costs.......................................... $ 190 $ 158 $ 174
Interest costs......................................... 580 548 584
------ ------ ------
Net Periodic Postretirement Expense................. $ 770 $ 706 $ 758
====== ====== ======
The following tables show the status of the plans reconciled with the
amounts in the Company's Consolidated Balance Sheets at December 31, 1997 and
1996 (in thousands):
1997 1996
------- -------
Health Care:
Accumulated Postretirement Benefit Obligation --
Retirees.................................................. $12,591 $12,549
Active participants eligible to retire.................... 1,638 1,203
Other active participants................................. 4,584 4,181
------- -------
18,813 17,933
Unrecognized Net Gain....................................... 3,211 2,621
------- -------
Accrued Postretirement Benefit Liability............... $22,024 $20,554
======= =======
Life Insurance:
Accumulated Postretirement Benefit Obligation --
Retirees.................................................. $ 6,393 $ 6,274
Active participants eligible to retire.................... 608 484
Other active participants................................. 1,299 1,205
------- -------
8,300 7,963
Unrecognized Net Loss....................................... (380) (115)
------- -------
Accrued Postretirement Benefit Liability............... $ 7,920 $ 7,848
======= =======
The weighted average annual rate of increase in the per capita cost of
covered health care benefits is assumed to be 8% for 1998, decreasing gradually
to 6% by the year 2005 and remaining at that level thereafter. This health care
cost trend rate assumption has a significant effect on the amount of the
obligation and periodic cost reported. For example, an increase in the assumed
health care cost trend rates by one percentage point in each year would increase
the accumulated postretirement obligation at December 31, 1997 by $3.8 million
and the aggregate of service cost and interest cost components of net periodic
postretirement benefits for the year then ended by $0.5 million. Actuarial
assumptions used to measure the accumulated postretirement benefit obligation at
December 31, 1997, 1996 and 1995 included a discount rate of 7 1/2% and a
compensation rate increase of 5%.
Thrift Plan
The Company sponsors an employee thrift plan which provides for
contributions by eligible employees into designated investment funds with a
matching contribution by the Company. Employees may contribute
62
65
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
up to 10% of their compensation, subject to certain limitations, and may elect
tax deferred treatment in accordance with the provisions of Section 401(k) of
the Internal Revenue Code. Effective October 1, 1996, the thrift plan was
amended to change the Company's matching contribution from 50% (of up to 6% of
the employee's eligible contribution) to 100% (of up to 4% of the employee's
eligible contributions), with at least 50% of the Company's match invested in
Common Stock of the Company. The Company's contributions amounted to $1.2
million, $0.8 million and $0.4 million during 1997, 1996 and 1995, respectively.
Non-Employee Director Retirement Plan and Phantom Stock Plan
The Company had previously established an unfunded Non-Employee Director
Retirement Plan ("Director Retirement Plan"), which provided that any eligible
non-employee director who had served on the Company's Board of Directors for at
least three full years would be entitled to a retirement payment in cash
beginning the later of the director's sixty-fifth birthday or such later date
that the individual's service as a director ended. However, to more closely
align director compensation with shareholders' interests, in March 1997, the
Board of Directors amended the Director Retirement Plan to freeze the plan and
convert all of the accrued benefits of the current directors under the plan to a
lump-sum present value which was transferred to and became the initial account
balance of the directors in the Tesoro Petroleum Corporation Board of Directors
Deferred Phantom Stock Plan ("Phantom Stock Plan"). After the amendment and
transfer, only those retired directors or beneficiaries who had begun receiving
benefits remained participants in the Director Retirement Plan. At December 31,
1997 and 1996, the projected benefit obligation and present value of the vested
and accumulated benefit obligations, discounted at 7 1/2%, of the Director
Retirement Plan were estimated to be $0.4 million and $0.8 million,
respectively. The Company's Consolidated Balance Sheets at December 31, 1997 and
1996 included $0.4 million and $0.7 million, respectively, in other liabilities
related to the Director Retirement Plan.
Upon establishment of the Phantom Stock Plan, the lump-sum accrued benefit
of each of the current non-employee directors was transferred from the Director
Retirement Plan into an account ("Account") in the Phantom Stock Plan. Under the
Phantom Stock Plan, a yearly credit of $7,250 (prorated to $6,042 for 1997) is
made to the Account of each director in units, based upon the closing market
price of the Company's Common Stock on the date of credit. In addition, a
director may elect to have the value of his cash retainer fee deposited
quarterly into the Account in units. The value of each Account balance, which is
a function of the amount, if any, by which the market value of the Company's
Common Stock changes, is payable in cash at retirement, death, disability or
termination, if vested. In 1997, the Company incurred expenses of approximately
$127,000 related to the Phantom Stock Plan due to the increase in the market
price of the Company's Common Stock.
NOTE K -- STOCKHOLDERS' EQUITY
Stock Repurchase Program
On May 7, 1997, the Company's Board of Directors authorized the repurchase
of up to 3 million shares (approximately 11% of current outstanding shares) of
Tesoro Common Stock in a buyback program that will extend through the end of
1998. Under the program, subject to certain conditions, the Company may
repurchase from time to time Tesoro Common Stock in the open market and through
privately negotiated transactions. Purchases will depend on price, market
conditions and other factors and will be made primarily from cash flows. The
repurchased Common Stock is accounted for as treasury stock and may be used for
employee benefit plan requirements and other corporate purposes. During 1997,
the Company used cash flows of $3.7 million to repurchase 236,800 shares of
Common Stock, of which 20,347 shares have been reissued for an employee benefit
plan. For information related to restrictions under the Credit Facility, see
Note I.
63
66
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Stock Plans and Incentive Compensation Strategy
The Company has two employee incentive stock plans, the Amended and
Restated Executive Long-Term Incentive Plan ("1993 Plan") and Amended Incentive
Stock Plan of 1982 ("1982 Plan"), and the 1995 Non-Employee Director Stock
Option Plan ("1995 Plan") (collectively, the "Plans"). Shares of unissued Common
Stock reserved for the Plans were 2,717,611 at December 31, 1997.
The 1993 Plan provides for the grant of up to 2,650,000 shares of the
Company's Common Stock in a variety of forms, including restricted stock,
incentive stock options, nonqualified stock options, stock appreciation rights
and performance share and performance unit awards. Stock options may be granted
at exercise prices not less than the fair market value on the date the options
are granted. The options granted generally become exercisable after one year in
20%, 25% or 33% increments per year and expire ten years from date of grant. The
1993 Plan will expire, unless earlier terminated, as to the issuance of awards
in the year 2003. At December 31, 1997, the Company had 66,420 shares available
for future grants under the 1993 Plan.
In 1997, the Compensation Committee of the Board of Directors granted
175,000 phantom stock options to an executive officer of the Company. These
phantom stock options, which were granted at 100% of the fair market value of
the Company's Common Stock on the grant date, vest in 15% increments in each of
the first three years and the remaining 55% increment vests in the fourth year.
Upon exercise, the executive officer would be entitled to receive in cash the
difference between the fair market value of the Common Stock on the date of the
phantom stock option grant and the fair market value of Common Stock on the date
of exercise. At the discretion of the Compensation Committee, these phantom
stock options may be converted to traditional stock options upon sufficient
shares becoming available under the 1993 Plan.
The 1982 Plan expired in 1994 as to issuance of stock appreciation rights,
stock options and stock awards; however, grants made before the expiration date
that have not been fully exercised remain outstanding pursuant to their terms.
The 1995 Plan provides for the grant of up to an aggregate of 150,000
nonqualified stock options to eligible non-employee directors of the Company.
The option price per share is equal to the fair market value per share of the
Company's Common Stock on the date of grant. The term of each option is ten
years, and an option first becomes exercisable six months after the date of
grant. Under the 1995 Plan, each person serving as a non-employee director on
February 23, 1995 or elected thereafter, initially received an option to
purchase 5,000 shares of Common Stock. Thereafter, 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, if
no annual meeting is held. At December 31, 1997, the Company had 68,000 options
outstanding and 77,000 shares available for future grants under the 1995 Plan.
In June 1996, the Company's Board of Directors unanimously approved a
special incentive compensation strategy in order to encourage a longer-term
focus for all employees to perform at an outstanding level. The strategy
provides eligible employees with incentives to achieve a significant increase in
the market price of the Company's Common Stock. Under the strategy, awards would
be earned only if the market price of the Company's Common Stock reaches an
average price per share of $20 or higher over any 20 consecutive trading days
after June 30, 1997 and before December 31, 1998 (the "Performance Target"). In
connection with this strategy, non-executive employees will be able to earn cash
bonuses equal to 25% of their individual payroll amounts for the previous twelve
complete months and certain executives have been granted, from the 1993 Plan, a
total of 340,000 stock options at an exercise price of $11.375 per share, the
fair market value (as defined in the 1993 Plan) of a share of the Company's
Common Stock on the date of grant, and 350,000 shares of restricted Common
Stock, all of which vest only upon achieving the Performance Target.
64
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TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
A summary of stock option activity in the Plans is set forth below:
NUMBER OF
OPTIONS WEIGHTED-AVERAGE
OUTSTANDING EXERCISE PRICE
----------- ----------------
Outstanding December 31, 1994............................ 1,496,293 $ 6.37
Granted................................................ 450,000 8.34
Exercised.............................................. (507,467) 4.85
Forfeited and expired.................................. (266,745) 9.10
---------
Outstanding December 31, 1995............................ 1,172,081 7.16
Granted................................................ 1,095,500 13.45
Exercised.............................................. (315,664) 5.67
Forfeited and expired.................................. (95,171) 8.50
---------
Outstanding December 31, 1996............................ 1,856,746 11.05
Granted................................................ 431,000 16.73
Exercised.............................................. (43,800) 8.45
Forfeited and expired.................................. (36,013) 8.40
---------
Outstanding December 31, 1997............................ 2,207,933 12.26
=========
At December 31, 1997, 1996 and 1995, exercisable stock options totaled 0.7
million, 0.4 million and 0.4 million, respectively.
The following table summarizes information about stock options outstanding
under the Plans at December 31, 1997:
OPTIONS OUTSTANDING
------------------------------------------------- OPTIONS EXERCISABLE
WEIGHTED-AVERAGE ------------------------------
RANGE OF NUMBER REMAINING WEIGHTED-AVERAGE NUMBER WEIGHTED-AVERAGE
EXERCISE PRICES OUTSTANDING CONTRACTUAL LIFE EXERCISE PRICE EXERCISABLE EXERCISE PRICE
--------------- ----------- ---------------- ---------------- ----------- ----------------
$ 3.92 to $ 7.19 179,740 5.2 years $ 4.52 159,272 $ 4.42
$ 7.20 to $10.45 551,100 7.5 years 8.65 279,300 8.84
$10.46 to $13.72 398,593 8.4 years 11.41 31,593 11.68
$13.73 to $16.98 1,078,500 9.2 years 15.72 210,173 14.94
--------- ---------
$ 3.92 to $16.98 2,207,933 8.3 years 12.26 680,338 9.82
========= =========
The Company applies APB No. 25 and related interpretations in accounting
for its stock plans. Accordingly, no compensation expense has been recognized
for stock option transactions or the incentive compensation strategy discussed
above. Had compensation cost for the Plans been determined based on the fair
value at the grant dates for awards (granted after January 1, 1995) in
accordance with SFAS No. 123, "Accounting for Stock-Based Compensation," the
Company's pro forma net earnings in 1997, 1996 and 1995 would have been
approximately $28.5 million ($1.08 per basic share, $1.06 per diluted share),
$72.6 million ($2.79 per basic share, $2.74 per diluted share), and $53.8
million ($2.19 per basic share, $2.15 per diluted share), respectively. The fair
value of each option grant was estimated on the date of grant using the Black-
Scholes option-pricing model with the following weighted-average assumptions:
expected volatility of 32%, 30% and 45%; risk free interest rates of 6.7%, 6.6%
and 6.1%; expected lives of seven years; and no dividend yields for 1997, 1996
and 1995, respectively. The estimated fair value per share of options granted
during 1997, 1996 and 1995 were $5.96, $4.26 and $3.65, respectively, and the
fair value per share of restricted stock awards in 1996 was $0.95 per share.
65
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TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE L -- COMMITMENTS AND CONTINGENCIES
Operating Leases
The Company has various noncancellable operating leases related to
buildings, equipment, property and other facilities. These long-term leases have
remaining primary terms generally up to ten years, with terms of certain
rights-of-way extending up to 34 years, and generally contain multiple renewal
options. Future minimum annual lease payments as of December 31, 1997, for
operating leases having initial or remaining noncancelable lease terms in excess
of one year, excluding marine charters, were as follows (in thousands):
1998........................................................ $ 6,135
1999........................................................ 3,378
2000........................................................ 2,907
2001........................................................ 2,514
2002........................................................ 2,272
Remainder................................................... 13,962
-------
Total Minimum Lease Payments.............................. $31,168
=======
In addition to the long-term lease commitments above, the Company has
leases for two vessels that are primarily used to transport crude oil and
refined products to and from the Company's refinery. At December 31, 1997,
future minimum annual lease payments remaining for these two vessels, which
include operating costs, are approximately $28 million for each of the years
1998 and 1999 and $16 million for the year 2000. Operating costs related to
these vessels, which may vary from year to year, comprised approximately 30% of
the total minimum payments during 1997. The Company also enters into various
month-to-month and other short-term rentals, including a charter of a vessel
primarily used to transport refined products from the Company's refinery to the
Far East.
Total rental expense for short-term and long-term leases, excluding marine
charters, amounted to approximately $11 million, $12 million and $10 million for
1997, 1996 and 1995, respectively. In addition, expenses related to charters of
marine vessels were approximately $34 million, $30 million and $26 million for
1997, 1996 and 1995, respectively.
Environmental
The Company is subject to extensive federal, state and local environmental
laws and regulations. These laws, which change frequently, regulate the
discharge of materials into the environment and may require the Company to
remove or mitigate the environmental effects of the disposal or release of
petroleum or chemical substances at various sites or install additional controls
or other modifications or changes in use for certain emission sources. The
Company is currently involved with a waste disposal site near Abbeville,
Louisiana, at which it has been named a potentially responsible party under the
Federal Superfund law. Although this law might impose joint and several
liability upon each party at the site, the extent of the Company's allocated
financial contributions to the cleanup of the site is expected to be limited
based upon the number of companies, volumes of waste involved, and an estimated
total cost of approximately $500,000 among all of the parties to close the site.
The Company is currently involved in settlement discussions with the
Environmental Protection Agency ("EPA") and other potentially responsible
parties at the Abbeville, Louisiana site. The Company expects, based on these
discussions, that its liability will not exceed $25,000. The Company is also
involved in remedial responses and has incurred cleanup expenditures associated
with environmental matters at a number of sites, including certain of its own
properties.
At December 31, 1997, the Company's accruals for environmental expenses
amounted to $8.5 million, which included a noncurrent liability of $2.7 million
for remediation of the Kenai Pipe Line Company's
66
69
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
("KPL") properties that has been funded by the former owners of KPL 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.
To comply with environmental laws and regulations, the Company anticipates
that it will make capital improvements of approximately $7 million in 1998 and
$2 million in 1999. In addition, capital expenditures for alternative secondary
containment systems for existing storage tank facilities are estimated to be $2
million in 1998 and $2 million in 1999 with a remaining $5 million to be spent
by 2002.
Conditions that require additional expenditures may exist for various
Company sites, including, but not limited to, the Company's refinery, retail
gasoline stations (current and closed locations) and petroleum product
terminals, and for compliance with the Clean Air Act. The amount of such future
expenditures cannot currently be determined by the Company.
Crude Oil Purchase Contracts
The Company has a contract with the State of Alaska for the purchase of
royalty crude oil covering the period January 1, 1996 through December 31, 1998.
The contract provides for the purchase of 30% of the State's ANS royalty crude
oil produced from the Prudhoe Bay Unit at prices based on royalty values
computed by the State. During 1997, the Company purchased approximately 35,700
barrels per day of ANS crude oil under this contract. The contract contains
provisions that, under certain conditions, allow the Company to temporarily or
permanently reduce its purchase obligations. Under this contract, the Company is
required to utilize in its refinery operations volumes equal to at least 80% of
the ANS crude oil purchased from the State. The Company is presently in
discussions with the State in regard to extending this contract for an
additional year.
The Company also purchases approximately 6,000 barrels per day of ANS crude
oil from a producer under a contract with a term of one year beginning January
1, 1998.
During October 1997, the Company began purchasing all of the approximately
34,000 barrels per day of Cook Inlet crude oil production from various producers
under contracts extending through December 1998. A contract to purchase 4,500
barrels per day, of the 34,000 barrels per day, has been extended through March
31, 2001.
67
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TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE M -- QUARTERLY FINANCIAL DATA (UNAUDITED)
QUARTERS
--------------------------------- TOTAL
FIRST SECOND THIRD FOURTH YEAR
------ ------ ------ ------ --------
(IN MILLIONS EXCEPT PER SHARE AMOUNTS)
1997
Revenues:
Gross operating revenues........................ $233.3 $210.7 $251.0 $242.9 $ 937.9
Other income.................................... 1.6 2.6 0.4 0.9 5.5
------ ------ ------ ------ --------
Total Revenues............................. $234.9 $213.3 $251.4 $243.8 $ 943.4
====== ====== ====== ====== ========
Operating Profit................................... $ 15.0 $ 19.9 $ 19.4 $ 18.4 $ 72.7
====== ====== ====== ====== ========
Net Earnings....................................... $ 6.1 $ 9.7 $ 8.0 $ 6.9 $ 30.7
====== ====== ====== ====== ========
Net Earnings Per Share -- Basic.................... $ 0.23 $ 0.36 $ 0.30 $ 0.26 $ 1.16
Net Earnings Per Share -- Diluted.................. $ 0.23 $ 0.36 $ 0.30 $ 0.26 $ 1.14
1996
Revenues:
Gross operating revenues........................ $238.6 $233.8 $262.8 $240.2 $ 975.4
Income from settlement of natural gas
contract...................................... -- -- -- 60.0 60.0
Other income.................................... 5.0 0.1 (0.7) -- 4.4
------ ------ ------ ------ --------
Total Revenues............................. $243.6 $233.9 $262.1 $300.2 $1,039.8
====== ====== ====== ====== ========
Operating Profit................................... $ 20.7 $ 27.6 $ 25.2 $ 71.3 $ 144.8
====== ====== ====== ====== ========
Earnings Before Extraordinary Item................. $ 6.0 $ 12.0 $ 16.2 $ 42.6 $ 76.8
Extraordinary Loss on Debt Extinguishments, Net.... -- -- (2.3) -- (2.3)
------ ------ ------ ------ --------
Net Earnings............................... $ 6.0 $ 12.0 $ 13.9 $ 42.6 $ 74.5
====== ====== ====== ====== ========
Net Earnings Per Share -- Basic.................... $ 0.24 $ 0.46 $ 0.53 $ 1.62 $ 2.87
Net Earnings Per Share -- Diluted.................. $ 0.23 $ 0.45 $ 0.52 $ 1.59 $ 2.81
Pretax other income related to severance tax refunds of $1.6 million and
$0.2 million were recorded in the 1997 first and second quarters, respectively.
Pretax other income of $2.2 million related to the collection of a Bolivian
receivable for prior years production was recorded in the 1997 second quarter.
The 1996 first quarter included pretax other income of $5 million related
to retroactive severance tax refunds. The 1996 third quarter included pretax
income of $8 million for interest and reimbursement of costs from Tennessee Gas
(see Note D) and an aftertax extraordinary loss of $2.3 million for the early
extinguishment of debt (see Note I). The contract with Tennessee Gas was
terminated during the 1996 fourth quarter resulting in pretax income of $60
million (see Note D). Operating profit included approximately $8 million pretax
in each of the first, second and third quarters of 1996 from the excess of
natural gas contract prices over spot market prices.
68
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TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE N -- OIL AND GAS PRODUCING ACTIVITIES
The information presented below represents the oil and gas producing
activities of the Company's Exploration and Production segment, excluding
amounts related to its U.S. natural gas transportation operations. Other
information pertinent to the Exploration and Production segment is contained in
Notes B, C and D.
Capitalized Costs Relating to Oil and Gas Producing Activities
DECEMBER 31,
--------------------------------
1997 1996 1995
-------- -------- --------
(IN THOUSANDS)
Capitalized Costs:
Proved properties................................ $251,604 $179,433 $119,836
Unproved properties not being amortized.......... 31,918 12,344 5,118
-------- -------- --------
283,522 191,777 124,954
Accumulated depreciation, depletion and
amortization.................................. 112,562 78,222 51,549
-------- -------- --------
Net Capitalized Costs......................... $170,960 $113,555 $ 73,405
======== ======== ========
The Company's investment in oil and gas properties included $31.9 million
in unevaluated properties, primarily undeveloped leasehold costs and seismic
costs, which have been excluded from the amortization base at December 31, 1997.
Of this amount, $26.3 million and $5.6 million of such costs were incurred in
1997 and 1996, respectively. The Company anticipates that the majority of these
costs will be included in the amortization base during the next two years.
Costs Incurred in Oil and Gas Property Acquisition, Exploration and
Development Activities
U.S. BOLIVIA TOTAL
------- ------- -------
(IN THOUSANDS)
1997
Property acquisitions --
Proved........................................... $14,723 $11,892 $26,615
Unproved......................................... 7,127 3,370 10,497
Exploration......................................... 24,584 10,972 35,556
Development......................................... 17,798 1,279 19,077
------- ------- -------
$64,232 $27,513 $91,745
======= ======= =======
1996
Property acquisitions --
Proved........................................... $20,454 $ -- $20,454
Unproved......................................... 5,216 -- 5,216
Exploration......................................... 11,830 6,704 18,534
Development......................................... 22,228 149 22,377
------- ------- -------
$59,728 $ 6,853 $66,581
======= ======= =======
1995
Property acquisition, unproved...................... $ 1,432 $ -- $ 1,432
Exploration......................................... 10,011 2,994 13,005
Development......................................... 38,003 792 38,795
------- ------- -------
$49,446 $ 3,786 $53,232
======= ======= =======
69
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TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Results of Operations from Oil and Gas Producing Activities
The following table sets forth the results of operations for oil and gas
producing activities, in the aggregate by geographic area, with income tax
expense computed using the statutory tax rate for the period adjusted for
permanent differences, tax credits and allowances.
U.S. BOLIVIA TOTAL
---- -------- -----
(IN THOUSANDS EXCEPT AS INDICATED)
1997
Gross revenues -- sales to unaffiliates(a)........ $ 68,843 $11,189 $ 80,032
Production costs.................................. 7,424 932 8,356
Administrative support and other.................. 2,217 2,321 4,538
Depreciation, depletion and amortization.......... 29,350 1,538 30,888
Other income(b)................................... 3,238 2,184 5,422
-------- ------- --------
Pretax results of operations...................... 33,090 8,582 41,672
Income tax expense................................ 11,582 4,915 16,497
-------- ------- --------
Results of operations from producing
activities(c).................................. $ 21,508 $ 3,667 $ 25,175
======== ======= ========
Depletion per net equivalent thousand cubic feet
("Mcfe")....................................... $ 0.93 $ 0.19
======== =======
1996
Gross revenues -- sales to unaffiliates(a)........ $ 88,358 $13,701 $102,059
Production costs.................................. 5,326 837 6,163
Administrative support and other.................. 3,649 2,830 6,479
Depreciation, depletion and amortization.......... 25,235 1,279 26,514
Income from settlement of a natural gas
contract(d).................................... 60,000 -- 60,000
Income from severance tax refunds................. 5,000 -- 5,000
-------- ------- --------
Pretax results of operations...................... 119,148 8,755 127,903
Income tax expense................................ 41,702 5,439 47,141
-------- ------- --------
Results of operations from producing
activities(c).................................. $ 77,446 $ 3,316 $ 80,762
======== ======= ========
Depletion per Mcfe................................ $ 0.79 $ 0.15
======== =======
1995
Gross revenues -- sales to unaffiliates(a)........ $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(e)........................ 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(c).................................. $ 63,022 $ 2,850 $ 65,872
======== ======= ========
Depletion per Mcfe................................ $ 0.69 $ 0.03
======== =======
- ---------------
(a) Revenues included the effects of natural gas commodity price agreements
which amounted to losses of $1.6 million ($0.05 per thousand cubic feet
("Mcf")) and $3.1 million ($0.11 per Mcf) in 1997 and 1996, respectively,
and to a gain of $0.3 million ($0.01 per Mcf) in 1995. The Company had
entered into these agreements to reduce risks caused by fluctuations in the
prices of natural gas in the spot market. During 1997, 1996 and 1995, the
Company used such agreements to set the price of 9%, 30% and 38%,
70
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TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
respectively, of the natural gas that it sold in the spot market. The
Company has no remaining natural gas price agreements outstanding at
December 31, 1997.
(b) Primarily represents income from retroactive severance tax refunds in the
U.S. operations and income related to a collection of a receivable in
Bolivian operations.
(c) Excludes corporate general and administrative expenses and financing costs.
(d) See Note D.
(e) Represents gain on sale of certain interests in the Bob West Field (see
Note C).
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.
U.S. BOLIVIA TOTAL
-------- -------- --------
(IN THOUSANDS)
DECEMBER 31, 1997
Future cash inflows.............................. $347,904 $490,337 $838,241
Future production costs.......................... 81,011 86,546 167,557
Future development costs......................... 29,362 48,860 78,222
-------- -------- --------
Future net cash flows before income tax
expense....................................... 237,531 354,931 592,462
10% annual discount factor....................... 70,036 148,461 218,497
-------- -------- --------
Discounted future net cash flows before income
taxes......................................... 167,495 206,470 373,965
Discounted future income tax expense(a).......... 32,284 107,318 139,602
-------- -------- --------
Standardized measure of discounted future net
cash flows(b)................................. $135,211 $ 99,152 $234,363
======== ======== ========
71
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TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
U.S. BOLIVIA TOTAL
-------- -------- --------
(IN THOUSANDS)
DECEMBER 31, 1996
Future cash inflows.............................. $376,103 $368,119 $744,222
Future production costs.......................... 66,524 72,766 139,290
Future development costs......................... 13,156 30,632 43,788
-------- -------- --------
Future net cash flows before income tax
expense....................................... 296,423 264,721 561,144
10% annual discount factor....................... 73,687 130,915 204,602
-------- -------- --------
Discounted future net cash flows before income
taxes......................................... 222,736 133,806 356,542
Discounted future income tax expense (a)......... 70,251 80,102 150,353
-------- -------- --------
Standardized measure of discounted future net
cash flows.................................... $152,485 $ 53,704 $206,189
======== ======== ========
DECEMBER 31, 1995
Future cash inflows.............................. $265,379 $120,510 $385,889
Future production costs.......................... 53,095 32,005 85,100
Future development costs......................... 8,625 7,548 16,173
-------- -------- --------
Future net cash flows before income tax
expense....................................... 203,659 80,957 284,616
10% annual discount factor....................... 34,920 32,231 67,151
-------- -------- --------
Discounted future net cash flows before income
taxes......................................... 168,739 48,726 217,465
Discounted future income tax expense(a).......... 45,939 25,897 71,836
-------- -------- --------
Standardized measure of discounted future net
cash flows.................................... $122,800 $ 22,829 $145,629
======== ======== ========
- ---------------
(a) For Bolivia, the discounted future income tax expense includes Bolivian
taxes of $105.0 million, $69.4 million and $21.6 million as of December 31,
1997, 1996 and 1995, respectively, and U.S. income taxes of $2.3 million,
$10.7 million and $4.3 million at December 31, 1997, 1996 and 1995,
respectively.
(b) Gross rates for the Company's Bolivian production were increased from 40
million cubic feet ("MMcf") per day to 120 MMcf per day in the year 2000
due to the anticipated completion of the Bolivia-Brazil pipeline during
early 1999 as discussed in Note B. This increase accounted for
approximately $57 million of the standardized measure of discounted future
net cash flows for Bolivia at December 31, 1997.
Changes in Standardized Measure of Discounted Future Net Cash Flows
(Unaudited)
1997 1996 1995
-------- -------- ---------
(IN THOUSANDS)
Sales of oil and gas produced, net of production
costs............................................. $(69,567) $(93,275) $(106,378)
Net changes in prices and production costs.......... (88,473) 39,409 (32,931)
Extensions, discoveries and improved recovery....... 42,191 81,201 83,045
Changes in future development costs................. (7,495) (17,704) 19,221
Revisions of previous quantity estimates............ 15,819 (7,244) 60,800
Purchases (sales) of minerals in-place.............. 79,024 55,484 (48,698)
Changes in timing of Bolivian production............ 10,271 -- --
Extension of Bolivian contract terms................ -- 26,564 --
Other changes in Bolivian Hydrocarbons Law.......... -- 32,894 --
Accretion of discount............................... 20,619 14,563 14,878
Net changes in income taxes......................... 25,785 (71,332) 6,917
-------- -------- ---------
Net increase (decrease)............................. 28,174 60,560 (3,146)
Beginning of period................................. 206,189 145,629 148,775
-------- -------- ---------
End of period....................................... $234,363 $206,189 $ 145,629
======== ======== =========
72
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TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.,
except for U.S. net reserves at December 31, 1997 which were prepared by
in-house engineers and audited 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.
U.S. BOLIVIA TOTAL
------- ------- -------
NET PROVED GAS RESERVES (millions of cubic feet)(a)
December 31, 1994......................................... 129,099 95,756 224,855
Revisions of previous estimates........................ 46,239 (553) 45,686
Extensions, discoveries and other additions............ 50,201 -- 50,201
Production............................................. (41,789) (6,807) (48,596)
Sales of minerals in-place............................. (77,373) -- (77,373)
------- ------- -------
December 31, 1995......................................... 106,377 88,396 194,773
Extension of Bolivian contract terms(b)................ -- 32,998 32,998
Other changes in Bolivian Hydrocarbons Law(b).......... -- 56,704 56,704
Revisions of previous estimates........................ (4,792) (149) (4,941)
Extensions, discoveries and other additions............ 22,977 59,964 82,941
Production............................................. (32,081) (7,412) (39,493)
Purchases of minerals in-place......................... 24,309 -- 24,309
------- ------- -------
December 31, 1996......................................... 116,790 230,501 347,291
Revisions of previous estimates........................ (3,063) 30,567 27,504
Extensions and discoveries............................. 33,648 -- 33,648
Production............................................. (31,409) (7,131) (38,540)
Purchases of minerals in-place......................... 30,527 81,229 111,756
------- ------- -------
December 31, 1997 (c)..................................... 146,493 335,166 481,659
======= ======= =======
NET PROVED DEVELOPED GAS RESERVES (millions of cubic feet)
December 31, 1994......................................... 110,071 81,558 191,629
December 31, 1995......................................... 95,930 72,500 168,430
December 31, 1996......................................... 107,509 123,154 230,663
December 31, 1997 (c)..................................... 112,385 181,402 293,787
73
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TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
U.S. BOLIVIA TOTAL
------- ------- -------
NET PROVED OIL RESERVES (thousands of barrels)(a)
December 31, 1994......................................... -- 1,793 1,793
Revisions of previous estimates........................ 1 10 11
Extensions, discoveries and other additions............ 8 -- 8
Production............................................. (1) (207) (208)
------- ------- -------
December 31, 1995......................................... 8 1,596 1,604
Extension of Bolivian contract terms(b)................ -- 459 459
Other changes in Bolivian Hydrocarbons Law(b).......... -- 913 913
Revisions of previous estimates........................ (4) 150 146
Extensions, discoveries and other additions............ -- 840 840
Production............................................. (10) (214) (224)
Purchases of minerals in-place......................... 188 -- 188
------- ------- -------
December 31, 1996......................................... 182 3,744 3,926
Revisions of previous estimates........................ (5) 349 344
Extensions and discoveries............................. 87 -- 87
Production............................................. (43) (189) (232)
Purchases of minerals in-place......................... 430 1,301 1,731
------- ------- -------
December 31, 1997 (c)..................................... 651 5,205 5,856
======= ======= =======
NET PROVED DEVELOPED OIL RESERVES (thousands of barrels)
December 31, 1994......................................... -- 1,627 1,627
December 31, 1995......................................... 4 1,407 1,411
December 31, 1996......................................... 126 2,291 2,417
December 31, 1997 (c)..................................... 296 3,137 3,433
- ---------------
(a) The Company is required to file annual estimates of its proved reserves with
the Department of Energy. Such filings have been consistent with the
information presented herein.
(b) Under a new Hydrocarbons Law passed by the Bolivian government in 1996, the
Company converted its Contracts of Operation for Block 18 and Block 20 into
four Shared Risk Contracts, which, among other matters, extend the Company's
term of operation, provide more favorable acreage relinquishment terms and
provide for a more favorable royalty and tax structure.
(c) No major discovery or adverse event has occurred since December 31, 1997
that would cause a significant change in net proved reserve volumes.
NOTE O -- SUBSEQUENT EVENT (UNAUDITED)
On March 18, 1998, the Company entered into a stock sale agreement with BHP
Hawaii Inc. and BHP Petroleum Pacific Islands Inc., subsidiaries of The Broken
Hill Proprietary Company Limited ("BHP"), whereby Tesoro will purchase all of
the outstanding stock of BHP Petroleum Americas Refining Inc. ("BHP Refining")
and BHP Petroleum South Pacific Inc. ("BHP South Pacific"). The primary assets
of BHP Refining and BHP South Pacific include a 95,000-barrel per day refinery
and 32 retail gasoline stations located in Hawaii. In addition, Tesoro and a BHP
affiliate will enter into a two-year crude supply agreement pursuant to which
the BHP affiliate will assist Tesoro in acquiring crude oil feedstock sourced
outside of North America and arrange for the transportation of such crude oil to
the Hawaiian refinery. The acquisition is expected to close by the end of May
1998, subject to regulatory review and other customary conditions. Under the
terms of the stock sale agreement, the Company has deposited $5 million into an
escrow account for this acquisition. The purchase price to be paid at closing
includes $275 million in cash, less the amount of the escrow deposit. After
closing, the cash purchase price will be increased by an amount that net working
capital acquired
74
77
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
exceeds $100 million or reduced by an amount that the net working capital
acquired is less than $100 million. In addition, Tesoro will issue an unsecured,
non-interest bearing, promissory note for the purchase in the amount of $50
million, payable in five equal annual installments of $10 million each,
beginning in 2009. The note will provide for early payment to the extent of
one-half of the amount by which earnings from the acquired assets, before
interest expense, income taxes and depreciation, depletion and amortization, as
specified in the note, exceed $50 million in any calendar year. Upon
acceleration due to an event of default, the amount outstanding to be paid under
the note will be reduced to present value using a discount rate of 9%. The
acquisition, which significantly increases the scope of the Company's refining
and marketing operations, will be accounted for as a purchase whereby the
purchase price will be allocated to the assets acquired and liabilities assumed
based on their estimated fair values at the date of acquisition. The Company is
currently in discussions with its investment bankers to arrange for financing of
the acquisition and associated working capital and letter of credit
requirements.
75
78
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
1998 Proxy Statement, incorporated herein by reference.
See also Executive Officers of the Registrant under Business in Item 1
hereof.
ITEM 11. EXECUTIVE COMPENSATION
Information required under this Item will be contained in the Company's
1998 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
1998 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
1998 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................................ 43
Statements of Consolidated Operations -- Years Ended
December 31, 1997, 1996 and 1995.......................... 44
Consolidated Balance Sheets -- December 31, 1997 and 1996... 45
Statements of Consolidated Stockholders' Equity -- Years
Ended December 31, 1997, 1996 and 1995.................... 46
Statements of Consolidated Cash Flows -- Years Ended
December 31, 1997, 1996 and 1995.......................... 47
Notes to Consolidated Financial Statements.................. 48
2. FINANCIAL STATEMENT SCHEDULES
No financial statement schedules are submitted because of the absence of
the conditions under which they are required or because the required information
is included in the Consolidated Financial Statements or notes thereto.
76
79
3. EXHIBITS
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
2.1 -- Agreement and Plan of Merger dated as of November 20,
1995, between the Company, Coastwide Energy Services,
Inc. and CNRG Acquisition Corp. (incorporated by
reference herein to Registration Statement No.
333-00229).
2.2 -- First Amendment to Agreement and Plan of Merger dated
effective February 19, 1996 between the Company,
Coastwide Energy Services, Inc. and CNRG Acquisition
Corp. (incorporated by reference herein to Exhibit 2(b)
to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 1995, File No. 1-3473).
3.1 -- Restated Certificate of Incorporation of the Company
(incorporated by reference herein to Exhibit 3 to the
Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 1993, File No. 1-3473).
3.2 -- By-Laws of the Company, as amended through June 6, 1996
(incorporated by reference herein to Exhibit 3.2 to the
Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 1996, File No. 1-3473).
3.3 -- Amendment to Restated Certificate of Incorporation of the
Company adding a new Article IX limiting Directors'
Liability (incorporated by reference herein to Exhibit
3(b) to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 1993, File No. 1-3473).
3.4 -- Certificate of Designation Establishing a Series of $2.20
Cumulative Convertible Preferred Stock, dated as of
January 26, 1983 (incorporated by reference herein to
Exhibit 3(c) to the Company's Annual Report on Form 10-K
for the fiscal year ended December 31, 1993, File No.
1-3473).
3.5 -- Certificate of Designation Establishing a Series A
Participating Preferred Stock, dated as of December 16,
1985 (incorporated by reference herein to Exhibit 3(d) to
the Company's Annual Report on Form 10-K for the fiscal
year ended December 31, 1993, File No. 1-3473).
3.6 -- Certificate of Amendment, dated as of February 9, 1994,
to Restated Certificate of Incorporation of the Company
amending Article IV, Article V, Article VII and Article
VIII (incorporated by reference herein to Exhibit 3(e) to
the Company's Annual Report on Form 10-K for the fiscal
year ended December 31, 1993, File No. 1-3473).
4.1 -- Amended and Restated Credit Agreement ("Credit Facility")
dated as of June 7, 1996 among the Company and Banque
Paribas, individually, as an Issuing Bank and as
Administrative Agent, and The Bank of Nova Scotia,
individually and as Documentation Agent, and certain
other financial institutions named therein (incorporated
by reference herein to Exhibit 4.1 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June
30, 1996, File No. 1-3473).
4.2 -- First Amendment to Credit Facility among the Company,
Banque Paribas, Bank of Nova Scotia and other financial
institution parties thereto, effective as of March 21,
1997 (incorporated by reference herein to Exhibit 4.1 to
the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1997, File No. 1-3473).
4.3 -- Second Amendment to Credit Facility among the Company,
Banque Paribas, Bank of Nova Scotia and other financial
institution parties thereto, effective as of March 31,
1997 (incorporated by reference herein to Exhibit 4.2 to
the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1997, File No. 1-3473).
77
80
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
4.4 -- Third Amendment of Credit Facility among the Company,
Banque Paribas, Bank of Nova Scotia and other financial
institution parties thereto, effective as of September
15, 1997 (incorporated by reference herein to Exhibit 4.3
to the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1997, File No. 1-3473).
4.5 -- Second Amended and Restated Guaranty Agreement dated as
of January 28, 1997 among various subsidiaries of the
Company and Banque Paribas, individually, as
Administrative Agent and as an Issuing Bank, and certain
other financial institutions named therein, entered into
in connection with the Credit Facility (incorporated by
reference herein to Exhibit 4.2 to the Company's Annual
Report on Form 10-K for the fiscal year ended December
31, 1996, File No. 1-3473).
4.6 -- Amended and Restated Security Agreement (Accounts and
Inventory) dated as of June 7, 1996 between the Company
and Banque Paribas, entered into in connection with the
Credit Facility (incorporated by reference herein to
Exhibit 4.3 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 1996, File No.
1-3473).
4.7 -- Amended and Restated Security Agreement (Accounts and
Inventory) dated as of June 7, 1996 between Tesoro Alaska
Petroleum Company and Banque Paribas, entered into in
connection with the Credit Facility (incorporated by
reference herein to Exhibit 4.4 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June
30, 1996, File No. 1-3473).
4.8 -- Amended and Restated Security Agreement (Accounts and
Inventory) dated as of June 7, 1996 between Tesoro
Refining, Marketing & Supply Company and Banque Paribas,
entered into in connection with the Credit Facility
(incorporated by reference herein to Exhibit 4.5 to the
Company's Quarterly Report on Form 10-Q for the quarter
ended June 30, 1996, File No. 1-3473).
4.9 -- Security Agreement (Accounts and Inventory) dated as of
June 7, 1996 between Kenai Pipe Line Company and Banque
Paribas, entered into in connection with the Credit
Facility (incorporated by reference herein to Exhibit 4.6
to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1996, File No. 1-3473).
4.10 -- Security Agreement (Accounts and Inventory) dated as of
June 7, 1996 between Tesoro Coastwide Services Company
and Banque Paribas, entered into in connection with the
Credit Facility (incorporated by reference herein to
Exhibit 4.7 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 1996, File No.
1-3473).
4.11 -- Security Agreement (Accounts and Inventory) dated as of
June 7, 1996 between Coastwide Marine Services, Inc. and
Banque Paribas, entered into in connection with the
Credit Facility (incorporated by reference herein to
Exhibit 4.8 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 1996, File No.
1-3473).
4.12 -- Security Agreement (Accounts) dated as of June 7, 1996
between Tesoro Vostok Company and Banque Paribas, entered
into in connection with the Credit Facility (incorporated
by reference herein to Exhibit 4.9 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June
30, 1996, File No. 1-3473).
78
81
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
4.13 -- Amended and Restated Security Agreement (Pledge) dated as
of June 7, 1996 by the Company in favor of Banque
Paribas, entered into in connection with the Credit
Facility (incorporated by reference herein to Exhibit
4.10 to the Company's Quarterly Report on Form 10-Q for
the quarter ended June 30, 1996, File No. 1-3473).
4.14 -- First Amendment to Amended and Restated Security
Agreement (Pledge) dated as of September 12, 1996 between
the Company and Banque Paribas, entered into in
connection with the Credit Facility (incorporated by
reference herein to Exhibit 4.11 to the Company's Annual
Report on Form 10-K for the fiscal year ended December
31, 1996, File No. 1-3473).
4.15 -- First Amendment to Deed of Trust, Security Agreement and
Financing Statement dated as of June 7, 1996 among Tesoro
Alaska Petroleum Company, TransAlaska Title Insurance
Agency, Inc., as Trustee, and Banque Paribas, as
Administrative Agent, entered into in connection with the
Credit Facility (incorporated by reference herein to
Exhibit 4.11 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 1996, File No.
1-3473).
4.16 -- First Amendment to Mortgage, Deed of Trust, Assignment of
Production, Security Agreement and Financing Statement
dated as of June 7, 1996 from Tesoro E&P Company, L.P.,
entered into in connection with the Credit Facility
(incorporated by reference herein to Exhibit 4.12 to the
Company's Quarterly Report on Form 10-Q for the quarter
ended June 30, 1996, File No. 1-3473).
4.17 -- Mortgage, Deed of Trust, Assignment of Production,
Security Agreement and Financing Statement dated as of
June 7, 1996 from Tesoro E&P Company, L.P., entered into
in connection with the Credit Facility (incorporated by
reference herein to Exhibit 4.13 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June
30, 1996, File No. 1-3473).
4.18 -- Form of Coastwide Energy Services Inc. 8% Convertible
Subordinated Debenture (incorporated by reference herein
to Exhibit 4.3 to Post-Effective Amendment No. 1 to
Registration No. 333-00229).
4.19 -- 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).
4.20 -- 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).
4.21 -- Form of Cancellation/Substitution Agreement by and
between the Company, Coastwide Energy Services, Inc. and
Optionee (incorporated by reference herein to Exhibit 4.6
to Post-Effective Amendment No. 1 to Registration No.
333-00229).
+10.1 -- The Company's Amended Executive Security Plan, as amended
through November 13, 1989, and Funded Executive Security
Plan, as amended through February 28, 1990, for executive
officers and key personnel (incorporated by reference
herein to Exhibit 10(f) to the Company's Annual Report on
Form 10-K for the fiscal year ended September 30, 1990,
File No. 1-3473).
79
82
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
+10.2 -- Sixth Amendment to the Company's Amended Executive
Security Plan and Seventh Amendment to the Company's
Funded Executive Security Plan, both dated effective
March 6, 1991 (incorporated by reference herein to
Exhibit 10(g) to the Company's Annual Report on Form 10-K
for the fiscal year ended September 30, 1991, File No.
1-3473).
+10.3 -- Seventh Amendment to the Company's Amended Executive
Security Plan and Eighth Amendment to the Company's
Funded Executive Security Plan, both dated effective
December 8, 1994 (incorporated by reference herein to
Exhibit 10(f) to the Company's Annual Report on Form 10-K
for the fiscal year ended December 31, 1994, File No.
1-3473).
*+10.4 -- Amended and Restated Employment Agreement between the
Company and Bruce A. Smith dated November 1, 1997.
+10.5 -- Amendment and Restated Employment Agreement between the
Company and William T. Van Kleef dated as of December 12,
1996 (incorporated by reference herein to Exhibit 10.6 to
the Company's Annual Report on Form 10-K for the fiscal
year ended December 31, 1996, File No. 1-3473).
+10.6 -- Amendment and Restated Employment Agreement between the
Company and James C. Reed, Jr. dated as of December 12,
1996 (incorporated by reference herein to Exhibit 10.5 to
the Company's Annual Report on Form 10-K for the fiscal
year ended December 31, 1996, File No. 1-3473).
*+10.7 -- Management Stability Agreement between the Company and
Donald A. Nyberg dated December 12, 1996.
*+10.8 -- Management Stability Agreement between the Company and
Robert W. Oliver dated September 27, 1995.
*+10.9 -- Management Stability Agreement between the Company and
Steve Wormington dated September 27, 1995.
+10.10 -- 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).
+10.11 -- 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).
+10.12 -- 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).
+10.13 -- The Company's Amended Incentive Stock Plan of 1982, as
amended through February 24, 1988 (incorporated by
reference herein to Exhibit 10(t) to the Company's Annual
Report on Form 10-K for the fiscal year ended September
30, 1988, File No. 1-3473).
+10.14 -- 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).
80
83
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
+10.15 -- Copy of the Company's Amended and Restated Executive
Long-Term Incentive Plan, as amended through June 6, 1996
(incorporated by reference herein to Exhibit 10.12 to the
Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 1996, File No. 1-3473).
+10.16 -- 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).
+10.17 -- 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).
+10.18 -- 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).
+10.19 -- Copy of the Company's Board of Directors Deferred Phantom
Stock Plan (incorporated by reference herein to Exhibit
10 to the Company's Quarterly Report on Form 10-Q for the
quarter ended March 31, 1997, File No. 1-3473).
*+10.20 -- Phantom Stock Option Agreement between the Company and
Bruce A. Smith dated effective October 29, 1997.
10.21 -- 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).
10.22 -- 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).
10.23 -- 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).
10.24 -- Settlement and Standstill Agreement, dated as of April 4,
1996, among Kevin S. Flannery, Alan Kaufman, Robert S.
Washburn, James H. Stone, George F. Baker, Douglas
Thompson, Gales E. Galloway, Whelan Management Corp.,
Ardsley Advisory Partners and Tesoro Petroleum
Corporation (incorporated by reference herein to Exhibit
99 to the Company's Quarterly Report on Form 10-Q for the
quarter ended March 31, 1996, File No. 1-3473).
10.25 -- Settlement Agreement and Release, entered into and
effective as of October 1, 1996, by and between Tesoro
E&P Company, L.P., acting through its General Partner,
Tesoro Exploration and Production Company, Coastal Oil &
Gas Corporation and Coastal Oil & Gas USA, L.P., and
Tennessee Gas Pipeline Company (incorporated by reference
herein to Exhibit 10.20 to the Company's Annual Report on
Form 10-K for the fiscal year ended December 31, 1996,
File No. 1-3473).
81
84
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
10.26 -- Termination Agreement, entered into and effective as of
October 1, 1996, by and between Tesoro E&P Company, L.P.,
acting through its General Partner, Tesoro Exploration
and Production Company, Coastal Oil & Gas Corporation and
Coastal Oil & Gas USA, L.P., and Tennessee Gas Pipeline
Company (incorporated by reference herein to Exhibit
10.21 to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 1996, File No. 1-3473).
*21 -- Subsidiaries of the Company
*23.1 -- Consent of Deloitte & Touche LLP
*23.2 -- Consent of Netherland, Sewell & Associates, Inc.
**27.1 -- Financial Data Schedule
**27.2 -- Restated Financial Data Schedule 1996
**27.3 -- Restated Financial Data Schedule 1995
- ---------------
* Filed herewith.
+ Identifies management contracts or compensatory plans or arrangements
required to be filed as an exhibit hereto pursuant to Item 14(c) of Form
10-K.
** The Financial Data Schedule and Restated Financial Data Schedules shall not
be deemed "filed" for purposes of Section 11 of the Securities Act of 1933 or
Section 18 of the Securities Exchange Act of 1934, and are included as
exhibits only to the electronic filing of this Form 10-K in accordance with
Item 601(c) of Regulation S-K and Section 401 of Regulation S-T.
Copies of exhibits filed as part of this Form 10-K may be obtained by
stockholders of record at a charge of $0.15 per page, minimum $5.00 each
request. Direct inquiries to the Corporate Secretary, Tesoro Petroleum
Corporation, 8700 Tesoro Drive, San Antonio, Texas, 78217-6218.
(B) REPORTS ON FORM 8-K
No reports on Form 8-K were filed by the Company during the quarter ended
December 31, 1997.
82
85
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
TESORO PETROLEUM CORPORATION
March 30, 1998 By: /s/ BRUCE A. SMITH
------------------------------------------------
Bruce A. Smith
Chairman of the Board of Directors,
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
--------- ----- ----
/s/ BRUCE A. SMITH Chairman of the Board of March 30, 1998
- ----------------------------------------------------- Directors and Director,
(Bruce A. Smith) President and Chief
Executive Officer
(Principal Executive
Officer)
/s/ JAMES C. REED, JR. Executive Vice President, March 30, 1998
- ----------------------------------------------------- General Counsel and
(James C. Reed, Jr.) Secretary (Principal
Financial Officer)
/s/ DON E. BEERE Vice President, Controller March 30, 1998
- ----------------------------------------------------- (Principal Accounting
(Don E. Beere) Officer)
/s/ STEVEN H. GRAPSTEIN Vice Chairman of the Board of March 30, 1998
- ----------------------------------------------------- Directors and Director
(Steven H. Grapstein)
/s/ WILLIAM J. JOHNSON Director March 30, 1998
- -----------------------------------------------------
(William J. Johnson)
/s/ ALAN J. KAUFMAN Director March 30, 1998
- -----------------------------------------------------
(Alan J. Kaufman)
/s/ RAYMOND K. MASON, SR. Director March 30, 1998
- -----------------------------------------------------
(Raymond K. Mason, Sr.)
/s/ PATRICK J. WARD Director March 30, 1998
- -----------------------------------------------------
(Patrick J. Ward)
/s/ MURRAY L. WEIDENBAUM Director March 30, 1998
- -----------------------------------------------------
(Murray L. Weidenbaum)
83
86
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
2.1 -- Agreement and Plan of Merger dated as of November 20,
1995, between the Company, Coastwide Energy Services,
Inc. and CNRG Acquisition Corp. (incorporated by
reference herein to Registration Statement No.
333-00229).
2.2 -- First Amendment to Agreement and Plan of Merger dated
effective February 19, 1996 between the Company,
Coastwide Energy Services, Inc. and CNRG Acquisition
Corp. (incorporated by reference herein to Exhibit 2(b)
to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 1995, File No. 1-3473).
3.1 -- Restated Certificate of Incorporation of the Company
(incorporated by reference herein to Exhibit 3 to the
Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 1993, File No. 1-3473).
3.2 -- By-Laws of the Company, as amended through June 6, 1996
(incorporated by reference herein to Exhibit 3.2 to the
Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 1996, File No. 1-3473).
3.3 -- Amendment to Restated Certificate of Incorporation of the
Company adding a new Article IX limiting Directors'
Liability (incorporated by reference herein to Exhibit
3(b) to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 1993, File No. 1-3473).
3.4 -- Certificate of Designation Establishing a Series of $2.20
Cumulative Convertible Preferred Stock, dated as of
January 26, 1983 (incorporated by reference herein to
Exhibit 3(c) to the Company's Annual Report on Form 10-K
for the fiscal year ended December 31, 1993, File No.
1-3473).
3.5 -- Certificate of Designation Establishing a Series A
Participating Preferred Stock, dated as of December 16,
1985 (incorporated by reference herein to Exhibit 3(d) to
the Company's Annual Report on Form 10-K for the fiscal
year ended December 31, 1993, File No. 1-3473).
3.6 -- Certificate of Amendment, dated as of February 9, 1994,
to Restated Certificate of Incorporation of the Company
amending Article IV, Article V, Article VII and Article
VIII (incorporated by reference herein to Exhibit 3(e) to
the Company's Annual Report on Form 10-K for the fiscal
year ended December 31, 1993, File No. 1-3473).
4.1 -- Amended and Restated Credit Agreement ("Credit Facility")
dated as of June 7, 1996 among the Company and Banque
Paribas, individually, as an Issuing Bank and as
Administrative Agent, and The Bank of Nova Scotia,
individually and as Documentation Agent, and certain
other financial institutions named therein (incorporated
by reference herein to Exhibit 4.1 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June
30, 1996, File No. 1-3473).
4.2 -- First Amendment to Credit Facility among the Company,
Banque Paribas, Bank of Nova Scotia and other financial
institution parties thereto, effective as of March 21,
1997 (incorporated by reference herein to Exhibit 4.1 to
the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1997, File No. 1-3473).
4.3 -- Second Amendment to Credit Facility among the Company,
Banque Paribas, Bank of Nova Scotia and other financial
institution parties thereto, effective as of March 31,
1997 (incorporated by reference herein to Exhibit 4.2 to
the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1997, File No. 1-3473).
87
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
4.4 -- Third Amendment of Credit Facility among the Company,
Banque Paribas, Bank of Nova Scotia and other financial
institution parties thereto, effective as of September
15, 1997 (incorporated by reference herein to Exhibit 4.3
to the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1997, File No. 1-3473).
4.5 -- Second Amended and Restated Guaranty Agreement dated as
of January 28, 1997 among various subsidiaries of the
Company and Banque Paribas, individually, as
Administrative Agent and as an Issuing Bank, and certain
other financial institutions named therein, entered into
in connection with the Credit Facility (incorporated by
reference herein to Exhibit 4.2 to the Company's Annual
Report on Form 10-K for the fiscal year ended December
31, 1996, File No. 1-3473).
4.6 -- Amended and Restated Security Agreement (Accounts and
Inventory) dated as of June 7, 1996 between the Company
and Banque Paribas, entered into in connection with the
Credit Facility (incorporated by reference herein to
Exhibit 4.3 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 1996, File No.
1-3473).
4.7 -- Amended and Restated Security Agreement (Accounts and
Inventory) dated as of June 7, 1996 between Tesoro Alaska
Petroleum Company and Banque Paribas, entered into in
connection with the Credit Facility (incorporated by
reference herein to Exhibit 4.4 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June
30, 1996, File No. 1-3473).
4.8 -- Amended and Restated Security Agreement (Accounts and
Inventory) dated as of June 7, 1996 between Tesoro
Refining, Marketing & Supply Company and Banque Paribas,
entered into in connection with the Credit Facility
(incorporated by reference herein to Exhibit 4.5 to the
Company's Quarterly Report on Form 10-Q for the quarter
ended June 30, 1996, File No. 1-3473).
4.9 -- Security Agreement (Accounts and Inventory) dated as of
June 7, 1996 between Kenai Pipe Line Company and Banque
Paribas, entered into in connection with the Credit
Facility (incorporated by reference herein to Exhibit 4.6
to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1996, File No. 1-3473).
4.10 -- Security Agreement (Accounts and Inventory) dated as of
June 7, 1996 between Tesoro Coastwide Services Company
and Banque Paribas, entered into in connection with the
Credit Facility (incorporated by reference herein to
Exhibit 4.7 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 1996, File No.
1-3473).
4.11 -- Security Agreement (Accounts and Inventory) dated as of
June 7, 1996 between Coastwide Marine Services, Inc. and
Banque Paribas, entered into in connection with the
Credit Facility (incorporated by reference herein to
Exhibit 4.8 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 1996, File No.
1-3473).
4.12 -- Security Agreement (Accounts) dated as of June 7, 1996
between Tesoro Vostok Company and Banque Paribas, entered
into in connection with the Credit Facility (incorporated
by reference herein to Exhibit 4.9 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June
30, 1996, File No. 1-3473).
88
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
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4.13 -- Amended and Restated Security Agreement (Pledge) dated as
of June 7, 1996 by the Company in favor of Banque
Paribas, entered into in connection with the Credit
Facility (incorporated by reference herein to Exhibit
4.10 to the Company's Quarterly Report on Form 10-Q for
the quarter ended June 30, 1996, File No. 1-3473).
4.14 -- First Amendment to Amended and Restated Security
Agreement (Pledge) dated as of September 12, 1996 between
the Company and Banque Paribas, entered into in
connection with the Credit Facility (incorporated by
reference herein to Exhibit 4.11 to the Company's Annual
Report on Form 10-K for the fiscal year ended December
31, 1996, File No. 1-3473).
4.15 -- First Amendment to Deed of Trust, Security Agreement and
Financing Statement dated as of June 7, 1996 among Tesoro
Alaska Petroleum Company, TransAlaska Title Insurance
Agency, Inc., as Trustee, and Banque Paribas, as
Administrative Agent, entered into in connection with the
Credit Facility (incorporated by reference herein to
Exhibit 4.11 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 1996, File No.
1-3473).
4.16 -- First Amendment to Mortgage, Deed of Trust, Assignment of
Production, Security Agreement and Financing Statement
dated as of June 7, 1996 from Tesoro E&P Company, L.P.,
entered into in connection with the Credit Facility
(incorporated by reference herein to Exhibit 4.12 to the
Company's Quarterly Report on Form 10-Q for the quarter
ended June 30, 1996, File No. 1-3473).
4.17 -- Mortgage, Deed of Trust, Assignment of Production,
Security Agreement and Financing Statement dated as of
June 7, 1996 from Tesoro E&P Company, L.P., entered into
in connection with the Credit Facility (incorporated by
reference herein to Exhibit 4.13 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June
30, 1996, File No. 1-3473).
4.18 -- Form of Coastwide Energy Services Inc. 8% Convertible
Subordinated Debenture (incorporated by reference herein
to Exhibit 4.3 to Post-Effective Amendment No. 1 to
Registration No. 333-00229).
4.19 -- 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).
4.20 -- 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).
4.21 -- Form of Cancellation/Substitution Agreement by and
between the Company, Coastwide Energy Services, Inc. and
Optionee (incorporated by reference herein to Exhibit 4.6
to Post-Effective Amendment No. 1 to Registration No.
333-00229).
+10.1 -- The Company's Amended Executive Security Plan, as amended
through November 13, 1989, and Funded Executive Security
Plan, as amended through February 28, 1990, for executive
officers and key personnel (incorporated by reference
herein to Exhibit 10(f) to the Company's Annual Report on
Form 10-K for the fiscal year ended September 30, 1990,
File No. 1-3473).
89
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
+10.2 -- Sixth Amendment to the Company's Amended Executive
Security Plan and Seventh Amendment to the Company's
Funded Executive Security Plan, both dated effective
March 6, 1991 (incorporated by reference herein to
Exhibit 10(g) to the Company's Annual Report on Form 10-K
for the fiscal year ended September 30, 1991, File No.
1-3473).
+10.3 -- Seventh Amendment to the Company's Amended Executive
Security Plan and Eighth Amendment to the Company's
Funded Executive Security Plan, both dated effective
December 8, 1994 (incorporated by reference herein to
Exhibit 10(f) to the Company's Annual Report on Form 10-K
for the fiscal year ended December 31, 1994, File No.
1-3473).
*+10.4 -- Amended and Restated Employment Agreement between the
Company and Bruce A. Smith dated November 1, 1997.
+10.5 -- Amendment and Restated Employment Agreement between the
Company and William T. Van Kleef dated as of December 12,
1996 (incorporated by reference herein to Exhibit 10.6 to
the Company's Annual Report on Form 10-K for the fiscal
year ended December 31, 1996, File No. 1-3473).
+10.6 -- Amendment and Restated Employment Agreement between the
Company and James C. Reed, Jr. dated as of December 12,
1996 (incorporated by reference herein to Exhibit 10.5 to
the Company's Annual Report on Form 10-K for the fiscal
year ended December 31, 1996, File No. 1-3473).
*+10.7 -- Management Stability Agreement between the Company and
Donald A. Nyberg dated December 12, 1996.
*+10.8 -- Management Stability Agreement between the Company and
Robert W. Oliver dated September 27, 1995.
*+10.9 -- Management Stability Agreement between the Company and
Steve Wormington dated September 27, 1995.
+10.10 -- 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).
+10.11 -- 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).
+10.12 -- 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).
+10.13 -- The Company's Amended Incentive Stock Plan of 1982, as
amended through February 24, 1988 (incorporated by
reference herein to Exhibit 10(t) to the Company's Annual
Report on Form 10-K for the fiscal year ended September
30, 1988, File No. 1-3473).
+10.14 -- 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).
90
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
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+10.15 -- Copy of the Company's Amended and Restated Executive
Long-Term Incentive Plan, as amended through June 6, 1996
(incorporated by reference herein to Exhibit 10.12 to the
Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 1996, File No. 1-3473).
+10.16 -- 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).
+10.17 -- 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).
+10.18 -- 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).
+10.19 -- Copy of the Company's Board of Directors Deferred Phantom
Stock Plan (incorporated by reference herein to Exhibit
10 to the Company's Quarterly Report on Form 10-Q for the
quarter ended March 31, 1997, File No. 1-3473).
*+10.20 -- Phantom Stock Option Agreement between the Company and
Bruce A. Smith dated effective October 29, 1997.
10.21 -- 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).
10.22 -- 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).
10.23 -- 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).
10.24 -- Settlement and Standstill Agreement, dated as of April 4,
1996, among Kevin S. Flannery, Alan Kaufman, Robert S.
Washburn, James H. Stone, George F. Baker, Douglas
Thompson, Gales E. Galloway, Whelan Management Corp.,
Ardsley Advisory Partners and Tesoro Petroleum
Corporation (incorporated by reference herein to Exhibit
99 to the Company's Quarterly Report on Form 10-Q for the
quarter ended March 31, 1996, File No. 1-3473).
10.25 -- Settlement Agreement and Release, entered into and
effective as of October 1, 1996, by and between Tesoro
E&P Company, L.P., acting through its General Partner,
Tesoro Exploration and Production Company, Coastal Oil &
Gas Corporation and Coastal Oil & Gas USA, L.P., and
Tennessee Gas Pipeline Company (incorporated by reference
herein to Exhibit 10.20 to the Company's Annual Report on
Form 10-K for the fiscal year ended December 31, 1996,
File No. 1-3473).
91
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
10.26 -- Termination Agreement, entered into and effective as of
October 1, 1996, by and between Tesoro E&P Company, L.P.,
acting through its General Partner, Tesoro Exploration
and Production Company, Coastal Oil & Gas Corporation and
Coastal Oil & Gas USA, L.P., and Tennessee Gas Pipeline
Company (incorporated by reference herein to Exhibit
10.21 to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 1996, File No. 1-3473).
*21 -- Subsidiaries of the Company
*23.1 -- Consent of Deloitte & Touche LLP
*23.2 -- Consent of Netherland, Sewell & Associates, Inc.
**27.1 -- Financial Data Schedule
**27.2 -- Restated Financial Data Schedule 1996
**27.3 -- Restated Financial Data Schedule 1995
- ---------------
* Filed herewith.
+ Identifies management contracts or compensatory plans or arrangements
required to be filed as an exhibit hereto pursuant to Item 14(c) of Form
10-K.
** The Financial Data Schedule and Restated Financial Data Schedules shall not
be deemed "filed" for purposes of Section 11 of the Securities Act of 1933 or
Section 18 of the Securities Exchange Act of 1934, and are included as
exhibits only to the electronic filing of this Form 10-K in accordance with
Item 601(c) of Regulation S-K and Section 401 of Regulation S-T.