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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, 1998
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
Premium Income Equity Securities New York 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 March 1, 1999, the aggregate market value of the voting stock held by
nonaffiliates of the registrant was approximately $244,326,264 based upon the
closing price of its Common Stock on the New York Stock Exchange Composite tape.
At March 1, 1999, there were 32,341,386 shares of the registrant's Common Stock
outstanding.
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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........................................................ 3
Refining and Marketing...................................... 4
Marine Services............................................. 8
Exploration and Production.................................. 9
Competition and Other....................................... 17
Government Regulation and Legislation....................... 19
Employees................................................... 22
Risk Factors and Investment Considerations.................. 22
Item 2. Properties...................................................... 26
Item 3. Legal Proceedings............................................... 26
Item 4. Submission of Matters to a Vote of Security Holders............. 28
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters....................................................... 28
Item 6. Selected Financial Data......................................... 29
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations......................................... 31
General..................................................... 31
Business Environment........................................ 32
Results of Operations....................................... 33
Capital Resources and Liquidity............................. 42
Forward-Looking Statements.................................. 48
Item 7A. Quantitative and Qualitative Disclosures About Market Risk...... 49
Item 8. Financial Statements and Supplementary Data..................... 50
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.......................................... 86
PART III
Item 10. Directors and Executive Officers of the Registrant.............. 86
Item 11. Executive Compensation.......................................... 90
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................... 99
Item 13. Certain Relationships and Related Transactions.................. 102
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K........................................................... 102
SIGNATURES................................................................ 108
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 48.
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PART I
ITEM 1. BUSINESS
Tesoro Petroleum Corporation and its subsidiaries ("Tesoro" or the
"Company") is a natural resource company engaged in petroleum refining,
distribution and marketing of petroleum products, marine services, and the
exploration and production of natural gas and oil. These operations are
conducted through three business segments: Refining and Marketing, Marine
Services, and Exploration and Production.
On May 29, 1998, the Company completed the acquisition (the "Hawaii
Acquisition") of all of the outstanding capital stock of BHP Petroleum Americas
Refining Inc. and BHP Petroleum South Pacific Inc. (together, "BHP Hawaii") from
BHP Hawaii Inc. and BHP Petroleum Pacific Islands Inc. ("BHP Sellers"),
affiliates of The Broken Hill Proprietary Company Limited ("BHP"). The Hawaii
Acquisition included a 95,000-barrel per day refinery and 32 retail gasoline
stations located in Hawaii. Tesoro paid $252.2 million in cash for the Hawaii
Acquisition, including $77.2 million for working capital. In addition, Tesoro
issued an unsecured, non-interest bearing, promissory note for the Hawaii
Acquisition in the amount of $50 million, payable in five equal annual
installments of $10 million each, beginning in 2009. On August 10, 1998, the
Company completed the acquisition (the "Washington Acquisition" and together
with the Hawaii Acquisition, the "Acquisitions") of all of the outstanding stock
of Shell Anacortes Refining Company ("Shell Washington"), an affiliate of Shell
Oil Company ("Shell"). The Washington Acquisition included a 108,000-barrel per
day refinery in Anacortes, Washington and related assets. The total cash
purchase price for the Washington Acquisition was $280.1 million, including
$43.1 million for working capital. For information relating to the Acquisitions,
see Note C of Notes to Consolidated Financial Statements in Item 8.
In conjunction with the Acquisitions and refinancing of its then-existing
indebtedness in 1998, the Company issued equity and debt securities providing
the Company with $533 million of net proceeds and entered into a $500 million
senior credit facility. For information related to the financings, see Note D of
Notes to Consolidated Financial Statements in Item 8.
Downstream, the Acquisitions complemented the Company's existing asset base
and expanded its marketing areas. The Refining and Marketing segment now
operates three petroleum refineries located in: Kenai, Alaska ("Alaska
Refinery"), Kapolei, Hawaii ("Hawaii Refinery") and Anacortes, Washington
("Washington Refinery"). The Company sells gasoline through wholesale marketing
activities and a network of branded stations in Alaska, Hawaii and the Pacific
Northwest. This segment is also a major supplier of jet fuel to the Anchorage,
Honolulu and Seattle/Tacoma airports and diesel fuel to the fishing and marine
industries in Alaska, Washington, Hawaii and American Samoa. The Company's
Marine Services segment operates through a network of 19 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 in Texas, Louisiana and Bolivia. The Company's
net proved worldwide reserves totaled 555 billion cubic feet equivalents
("Bcfe") of natural gas at year-end 1998.
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 Notes E and O of Notes to Consolidated
Financial Statements in Item 8.
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REFINING AND MARKETING
OVERVIEW
The Company operates petroleum refineries in Alaska, Hawaii and Washington
and sells refined products to a wide variety of customers in Alaska, Hawaii and
American Samoa, along the U.S. West Coast, primarily in the Pacific Northwest,
and in certain other South Pacific and East Asian markets, including Russia.
During 1998, products from the refineries accounted for approximately 91% of
these sales volumes, including products received on exchange in the U.S. West
Coast market, with the remainder purchased from other refiners and suppliers. By
comparison, in 1997 the Refining and Marketing segment refined about 78% of its
sales volume with 22% purchased from others.
REFINERIES
The Company owns three refineries with combined rated throughput capacity
of 275,000 barrels per day ("bpd"). Capacity and actual 1998 throughput
(thousand bpd) by refinery are summarized below. Throughput volumes for Hawaii
and Washington refineries are since the 1998 acquisition dates, averaged over
the periods owned.
1998
REFINERY CAPACITY THROUGHPUT
-------- -------- ----------
Alaska...................................................... 72 58
Hawaii...................................................... 95 82
Washington.................................................. 108 102
--- ---
Total.................................................. 275 242
=== ===
The Company's refineries primarily manufacture gasoline, jet fuel, diesel
fuels and residual fuel oil. Other products manufactured include liquefied
petroleum gas, naphtha, liquid asphalt and sulphur. Refined products
manufactured are summarized below. Manufactured volumes for 1998 include amounts
from the Hawaii and Washington refineries since the acquisition dates, averaged
over the entire year.
1998 1997
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VOLUME % VOLUME %
------ --- ------ ---
Refined Products Manufactured (thousand bpd):
Gasoline and gasoline blendstocks.................. 51 33 13 26
Jet fuel........................................... 41 27 15 29
Diesel fuel........................................ 19 12 6 12
Heavy oils and residual products................... 33 21 15 29
Other, including light naphtha..................... 10 7 2 4
--- --- -- ---
Total Refined Products Manufactured............. 154 100 51 100
=== === == ===
The Alaska Refinery is located in Kenai, Alaska, approximately 70 miles
southwest of Anchorage, Alaska, where it has access to multiple sources of crude
oil. The Alaska Refinery is capable of producing liquefied petroleum gas,
gasoline, jet fuel, diesel fuel, heating oil, liquid asphalt, heavy oils and
residual products. In October 1997, the Company completed an expansion of the
Alaska Refinery's hydrocracker unit, which increased the unit's capacity by
approximately 25% to 12,500 bpd and enables the Company to produce more jet
fuel. The expansion, together with the addition of a new, high-yield jet fuel
hydrocracker catalyst, began to improve the Alaska Refinery's product slate
during the fourth quarter of 1997. At the time of the expansion, the Company
completed a scheduled 30-day maintenance turnaround of all major process units
at the Alaska Refinery. The next turnaround is scheduled for June 1999.
The Hawaii Refinery, located at Kapolei in an industrial park 22 miles west
of Honolulu, was acquired by the Company in May 1998. This acquisition added
volumes to the Company's existing slate of refined products. The Hawaii Refinery
also produces light naphtha, which is sold to Hawaii's gas utility company as
feedstock for their manufacture of synthetic natural gas distributed through the
Honolulu gas utility pipeline system. The Hawaii Refinery began operations in
1972 and has been expanded progressively in capacity and
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complexity. Major product upgrade units include the distillate hydrocracker,
vacuum distillation and catalytic reformer units. All major process units were
included in a 30-day maintenance turnaround in June 1998.
The Washington Refinery, located in Anacortes on Puget Sound, about 60
miles north of Seattle, was acquired from Shell in August 1998. The Washington
Refinery includes fluid catalytic cracker ("FCC"), vacuum distillation and
catalytic reformer units. The Washington Refinery is the most complex of the
Company's refineries. The FCC and other product upgrade units enable the
Washington Refinery to produce 85% of its output as gasoline, diesel and jet
fuel. The acquisition of the Washington Refinery shifted the Company's
manufactured product mix by increasing gasoline yield and decreasing lower-value
heavy oil and residual products. The FCC can also upgrade heavy vacuum gas oils
from the Alaska and Hawaii refineries. In mid-1998 before Tesoro acquired the
operations, the FCC and certain other process units were included in a
maintenance turnaround, and a new asphalt plant was completed. A maintenance
turnaround of the crude distillation and catalytic reformer units is scheduled
for September 1999.
CRUDE OIL SUPPLY
Crude oil feedstocks for the Company's refineries are supplied from several
sources, primarily in Alaska, Canada, Australia, Papua New Guinea and Southeast
Asia. Purchases are made through short-term contracts and spot market purchases.
Prices under the short-term contracts fluctuate with market prices of the crude
oil.
The Alaska Refinery primarily runs Alaskan crude oils, both Cook Inlet and
Alaskan North Slope ("ANS"), with occasional spot market purchases of other
crudes. Crude oil is delivered by tanker to the Alaska Refinery through the
Kenai Pipe Line Company ("KPL") marine terminal, which is a Company-owned,
common carrier and marine dock facility, and by a pipeline connected directly
with some of the Cook Inlet producing fields. During 1998, the Company purchased
approximately 31,500 bpd of ANS crude oil from the State of Alaska under a
three-year contract that expired on December 31, 1998. The Company continues to
purchase ANS crude on a spot basis. Cook Inlet crude oil is generally purchased
from several suppliers under annual contracts with renewal provisions and other
crudes are purchased in the spot market.
For information related to a settlement of a contractual dispute with the
State of Alaska, see Note D of Notes to Consolidated Financial Statements in
Item 8.
The Hawaii Refinery's crude oil supply is sourced primarily from Alaska,
Australia, Papua New Guinea and Southeast Asia. In connection with the Hawaii
Acquisition, the Company and a BHP affiliate entered into a crude oil supply
agreement pursuant to which the BHP affiliate will assist the Company in
acquiring crude oil feedstocks sourced outside of North America and arrange for
the transportation of such crude oil to the Hawaii Refinery. The supply
agreement is for a two-year period, expiring in May 2000, and provides for
annual payments of $1.4 million by the Company to the BHP affiliate for such
services. The Company also purchases ANS for the Hawaii Refinery. Crude oil for
the Hawaii Refinery is received through a deep-water, offshore mooring and
pipeline system, which also can be used for receiving and loading refined
products.
The Washington Refinery's crude oil is sourced primarily from Alaska and
Canada, with occasional spot market purchases of other crudes. Alaskan and other
crudes are delivered by tanker at the Washington Refinery's ship dock at
Anacortes. Crude oil from Canada is received at the Washington Refinery through
the Transmountain Pipeline system. Both Alaskan and Canadian crudes are
purchased from a variety of producers under short-term contracts.
The Company continuously evaluates the economics of processing
opportunistic crude oils, and makes adjustments in the volumes and mix of
feedstocks processed at each refinery. Occasionally, a better economic
opportunity displaces a previous crude oil purchase commitment and results in
the resale of crude oil.
MARKETING
Gasoline. The Company sells gasoline in both the wholesale bulk and retail
markets in Alaska and Hawaii and on the U.S. West Coast. The demand for gasoline
is seasonal in Alaska and the Pacific Northwest with lowest demand during the
winter months. The Company sells up to 35% of the Washington Refinery's
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gasoline production to Equilon, a major refiner on the West Coast, through an
off-take agreement. This agreement, which has a minimum term of two years, began
in August 1998. The Company also sells gasoline to wholesale customers and bulk
end-users under supply contracts. Gasoline is also delivered to refiners and
marketers in exchange for product received at other locations on the West Coast.
The Washington Refinery exchanges 30% of its gasoline production with a major
oil company for gasoline received elsewhere on the West Coast. Product is
distributed through Company-owned terminals, third-party terminals and truck
racks. Gasoline produced in excess of market demand in Alaska is shipped to the
U.S. West Coast or exported to East Asia, including Russia.
The Company distributes gasoline to end users in Alaska, Hawaii, Washington
and Oregon, by retail sales through 61 Company-operated stations in Alaska and
Hawaii, and by wholesale sales through 171 branded dealer stations in Alaska,
Washington, Oregon and Hawaii. The Company's retail presence in Oregon and
Washington was expanded during 1998 by adding 14 branded stations, bringing the
number of "Tesoro" branded gasoline stations in the Pacific Northwest to 44 at
year-end. In Hawaii, 32 stations were acquired with the Hawaii Refinery in May
1998. In total, Company-operated stations sold an average of 118,000 gallons per
month in 1998, as well as merchandise through convenience stores and gas station
kiosks. The Company also sells, at wholesale, to unbranded jobbers and dealers.
In 1998, the Company introduced its new "treasure-burst" logo and related
signage. All retail stations in Hawaii were re-imaged in conjunction with the
Hawaii Acquisition, and renovation and re-imaging projects were launched at
Company-operated stations in Alaska. Thirty Alaska stations with convenience
stores are also being re-imaged with Tesoro's new "2GO" trademark.
Middle Distillates. The Company is a major supplier of commercial jet fuel
to passenger and cargo airlines in Alaska, Hawaii, American Samoa and
Washington. The Company now produces about 15% of the jet fuel manufactured in
the West Coast-Alaska-Hawaii area. Several marketers, including the Company,
import jet fuel into Alaska and Hawaii. The expansion of the Alaska Refinery's
hydrocracker unit in 1997 increased the Company's jet fuel production to supply
the growing Alaska market.
The Company's diesel fuel production is sold primarily on a wholesale basis
for marine, transportation and industrial purposes. Lesser amounts are sold to
end-users through marine terminals and retail gas stations and for power
generation in Hawaii and American Samoa. The Company sells diesel fuel through
its 110,000-barrel capacity terminal in Ketchikan, Alaska. Diesel fuel is
supplied to this terminal from the Alaska and Washington refineries by marine
barge. Generally, the production of diesel fuel by refiners in Alaska, Hawaii
and the Pacific Northwest is in balance with demand. There are occasions when
diesel fuel is imported into or exported from Alaska and Hawaii because of the
variability of demand. 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.
The Company markets jet fuel, diesel and gasoline in American Samoa where
Tesoro operates the government-owned fuel terminals at Pago Pago Harbor and Pago
Pago International Airport. Total capacity of the terminal facilities is 244,000
barrels.
Heavy Oils and Residual Products. All three of the Company's refineries
have vacuum units that use crude tower bottoms as a feedstock and further
process these volumes into light vacuum gas oil ("LVGO"), medium vacuum gas oil
("MVGO"), heavy vacuum gas oil ("HVGO") and vacuum tower bottoms ("VTBs"). LVGO
and MVGO are further processed in the Alaska and Hawaii hydrocrackers, where
they are converted into gasoline feedstock, diesel and jet fuel. HVGO is used as
an FCC feedstock at the Washington Refinery or sold to other refineries. The
VTBs are used to produce liquid asphalt and marine bunker fuel sold on the U.S.
West Coast. The Hawaii Refinery also supplies electric power producers in Hawaii
with low-sulphur fuel oil. The Company sells its liquid asphalt for paving
materials in Alaska, Hawaii and Washington. In Alaska and Washington, demand for
liquid asphalt is seasonal because mild weather conditions are needed for
highway construction.
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TRANSPORTATION
The Company charters two American flag vessels, the Potomac Trader and the
Chesapeake Trader, which 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 Alaska Refinery. The vessels are also
used to transport heavy oils and residual products from the Alaska Refinery to
the Washington Refinery or other West Coast destinations. The Potomac Trader and
Chesapeake Trader are chartered under five-year agreements expiring September
2000 and May 2000, respectively. The Company charters a Russian flag vessel, the
Igrim, primarily to transport refined products from the Alaska Refinery to the
Far East, including Russia. The Igrim is chartered under an agreement expiring
in June 2000. From time to time, the Company also charters other tankers and
ocean-going barges to transport petroleum products to its customers in Alaska,
on the U.S. West Coast and in the Far East.
The Company operates a common carrier petroleum products pipeline from the
Alaska Refinery to its terminal in Anchorage and to the Anchorage airport. This
ten-inch diameter pipeline has a capacity to transport approximately 40,000 bpd
of products and allows the Company to transport light products to the terminal
throughout the year regardless of weather conditions. The KPL facilities assure
the Company of uninterrupted use of the dock and pipeline for unloading crude
oil feedstocks and loading product inventory on tankers and barges.
Crude oil is transported to Hawaii by tankers and discharged through a
single-point mooring terminal ("SPM") about 1.5 miles offshore from the Hawaii
Refinery. Three underwater pipelines connect the SPM to the Hawaii Refinery to
allow crude oil and products to be transferred to the Hawaii Refinery and to
load products from the Hawaii Refinery to ships and barges. The Company
transports petroleum products to its terminal facilities and customers in the
Hawaiian Islands using tugs and barges under long-term charters. A foreign flag
vessel is used under a short-term charter to transport middle distillates and
gasoline to Company-operated terminal facilities in American Samoa and fuel oil
to a customer in Tahiti. The vessel is also used occasionally to transport
refined product imports and exports between Hawaii and the Far East.
The Company distributes refined products to customers on the island of Oahu
through a pipeline system with connections to the military at several locations,
to commercial customers via third-party terminals at Honolulu International
Airport and Honolulu Harbor, and by barge to Company-owned and third-party
terminal facilities on the neighbor islands of Maui, Kauai and Hawaii. Product
pipelines connect the Hawaii Refinery to Barbers Point Harbor which is 2.5 miles
away. The Barbers Point Harbor is able to accommodate barges and product tankers
up to 800 feet in length and helps relieve traffic at the SPM.
The Washington Refinery receives crude oil from Canada through the 24-inch
Transmountain Pipeline which originates in Edmonton, Canada. Other crudes,
including ANS, are received through the Washington Refinery's ship dock. The
pipeline and the ship dock are each capable of providing almost 100% of the
Washington Refinery's feedstock needs.
Over 90% of the Washington Refinery's clean products (gasoline, jet fuel
and diesel) leave via the Olympic Pipeline system. Olympic serves the Seattle
area with 16-inch and 20-inch lines and continues to Portland, Oregon with a
14-inch line. A small amount of gasoline is delivered through a neighboring
refinery's truck rack, and some diesel fuel is distributed through a truck rack
at the Washington Refinery. Jet fuel is occasionally shipped by barge. The
Washington Refinery has the capability to move significant volumes of all clean
products over its ship dock. All of the fuel oil production is shipped by water.
Propane is shipped by both truck and rail.
For further information on transportation, see "Government Regulation and
Legislation -- Environmental Controls."
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REFINING AND MARKETING STATISTICS
The following table summarizes the Company's refining and marketing
operations for the years ended December 31, 1998, 1997 and 1996:
1998 1997 1996
----- ---- ----
REFINERY THROUGHPUT (thousand bpd):
Alaska.................................................... 57.6 50.2 47.5
Hawaii(a)................................................. 82.3 -- --
Washington(a)............................................. 101.8 -- --
----- ---- ----
Total Refinery Throughput............................ 241.7 50.2 47.5
===== ==== ====
REFINED PRODUCTS MANUFACTURED (thousand bpd)(a):
Gasoline and gasoline blendstocks......................... 50.9 12.8 12.8
Jet fuel.................................................. 40.6 15.4 14.0
Diesel fuel............................................... 18.8 6.2 6.0
Heavy oils and residual products.......................... 33.5 14.8 13.7
Other..................................................... 9.7 2.3 2.6
----- ---- ----
Total Refined Products Manufactured.................. 153.5 51.5 49.1
===== ==== ====
BRANDED RETAIL STATIONS:
Alaska --
Company-operated....................................... 31 35 33
Dealer-operated........................................ 125 129 126
Pacific Northwest -- Dealer-operated...................... 44 30 18
Hawaii --
Company-operated....................................... 30 -- --
Dealer-operated........................................ 2 -- --
----- ---- ----
Total Branded Retail Stations..................... 232 194 177
===== ==== ====
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(a) Throughput volumes for the Hawaii and Washington refineries are since the
dates of acquisition, averaged over the periods owned. Manufactured volumes
for 1998 include amounts from the acquired Hawaii and Washington operations
since the dates of acquisition, averaged over the full year.
MARINE SERVICES
OVERVIEW
The Company's Marine Services segment markets and distributes a broad range
of petroleum products, 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 are conducted through a
network of 16 terminals located on the Texas Gulf Coast in Galveston, Freeport,
Harbor Island, Port O'Connor, Sabine Pass and Houston, along the Louisiana Gulf
Coast in Cameron, Intracoastal City, Berwick, Venice, Port Fourchon and Amelia,
and a fleet of tugboats and barges. In January 1998, the Company's Marine
Services segment was 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. These terminals are located at Port Hueneme and Stockton,
California and Vancouver, Washington.
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. The Company also provides petroleum products to tugboats
and barges using the Intracoastal Canal System, as well as ships entering
various ports in Texas, Louisiana and the U.S. West Coast. The Company's Marine
Services segment obtains its supply of fuel from local area refiners.
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Total gallons of fuel, primarily diesel fuel, sold by this segment amounted to
181 million, 156 million, and 143 million in 1998, 1997 and 1996, respectively.
The Company is a distributor of major brands of marine lubricants and
greases, offering a full spectrum of grades. Total gallons of lubricants sold by
the Company's Marine Services segment amounted to 2.3 million, 2.7 million and
2.3 million in 1998, 1997 and 1996, respectively.
LOGISTICAL SERVICES
Through many of its Gulf Coast terminals, the Company provides full-service
shore-based support for offshore drilling rigs and production platforms. These
quay-side services provide cranes, forklifts and loading docks for supply boats
serving the offshore exploration and production industry. In addition, the
Company provides warehousing, office space, living quarters, helicopter landing
pads, and long-term parking for offshore workers. The Company's terminals also
serve as delivery points for drilling products, primarily drilling muds, by
providing warehousing, blending, inventory control and delivery services. In
1998, 1997 and 1996, revenues from these logistical services were $11.6 million,
$11.3 million and $8.7 million, respectively.
EXPLORATION AND PRODUCTION
OVERVIEW
The Company's Exploration and Production segment is engaged in the
exploration for and development and production of natural gas and oil 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 1998, the Company increased its worldwide net proved reserves by
7% to 555 Bcfe of natural gas. Worldwide net production of natural gas and oil
averaged 121 million cubic feet equivalents ("MMcfe") per day during 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 outside the Bob West Field rose to 55% of
its total U.S. production in 1998, compared to 6% during 1996. During the past
three years, the Company has increased its net undeveloped acres in the U.S.
from 7,000 at the beginning of 1996 to 154,000 at December 31, 1998. During this
timeframe, the Exploration and Production segment purchased interests in the
Frio/Vicksburg Trend and the Wilcox Trend along the Gulf Coast of Texas and
Louisiana, the Val Verde Basin in Southwest Texas, the East Texas Basin, and the
Morrow Trend in the Texas Panhandle. By the end of 1998, the Company served as
operator of 48% of its U.S. net production, compared to 5% at year-end 1996.
During 1998, the Company's U.S. net proved reserve volumes increased 15% to 174
Bcfe and net production averaged 92 MMcfe per day. The Company participated in
the completion of 23 gross development wells and eleven gross exploratory wells
in 1998, with seven gross wells drilling or completing at year-end.
In Bolivia, the Company operates under five contracts with the Bolivian
government to explore for and produce hydrocarbons. The Company's Bolivian
natural gas production is currently 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 third-party, 1,900-mile pipeline from
Bolivia to Brazil. The pipeline is expected to begin operations during the
second quarter of 1999. During 1998, the Company's Bolivian net proved reserve
volumes increased by 4% to 381 Bcfe and net production averaged 29 MMcfe per
day.
During 1998, the Company wrote-down the capitalized costs of its U.S. and
Bolivian oil and gas properties by $28.4 million and $39.9 million,
respectively, as required by cost ceiling limitations under full-cost
accounting. These write-downs were primarily the result of declines in oil and
gas prices during the fourth quarter of 1998.
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WORLDWIDE RESERVE REPLACEMENT AND COSTS OF ADDING RESERVES
In 1998, the Company's worldwide net proved reserve additions included 141
Bcfe from discoveries, extensions and purchases of proved properties (70 Bcfe in
Bolivia and 71 Bcfe in the U.S.), partly offset by 57 Bcfe from downward
revisions of previous estimates. Excluding revisions, 141 Bcfe were added for a
320% replacement of 44 Bcfe of production. Additions were realized with a 77%
drilling success rate during 1998, reflecting an 88% success rate on 26
development wells and a 64% success rate on 22 exploratory wells. The Company's
three-year worldwide average cost of adding these reserves was $0.60 per Mcfe.
In the U.S., 71 Bcfe were added through discoveries, extensions and acquisitions
for a 209% replacement of 34 Bcfe of production. In Bolivia, 70 Bcfe were added
through discoveries, extensions and acquisitions, a seven-fold replacement of 10
Bcfe of production. The three-year average cost of adding reserves was $1.26 per
Mcfe in the U.S. and $0.24 per Mcfe in Bolivia. See Note O of Notes to
Consolidated Financial Statements in Item 8.
UNITED STATES
RESERVES
The following table shows the estimated net proved reserves, based on
evaluations audited by Netherland, Sewell & Associates, Inc., and gross
producing wells for each of the Company's U.S. fields:
DECEMBER 31, 1998 DECEMBER 31, 1997
------------------------------------------ -----------------
PRESENT NET PROVED NET PROVED
VALUE OF GROSS GAS RESERVES GAS RESERVES
PROVED PRODUCTIVE -------------- -----------------
FIELD LOCATION RESERVES(A) WELLS BCFE % BCFE %
----- -------- ------------ ---------- ----- --- ------ ----
($ MILLIONS)
Bob West South Texas $ 36.2 63 39.0 23 59.0 39
Vinegarone East Southwest Texas 24.7 10 26.7 15 14.3 10
Stiles Ranch Texas Panhandle 8.4 22 15.7 9 -- --
Bethel Dome East East Texas 8.8 2 13.4 8 -- --
Los Indios South Texas 9.2 31 11.1 6 15.3 10
Kent Bayou South Louisiana 13.0 1 10.3 6 10.5 7
Oak Hill East Texas 3.7 7 9.9 6 9.9 7
Woodlawn East Texas 4.4 5 9.1 5 6.5 4
La Reforma South Texas 5.7 20 6.7 4 7.7 5
Other 25.8 125 31.9 18 27.2 18
------ --- ----- --- ----- ---
$139.9 286 173.8 100 150.4 100
====== === ===== === ===== ===
- ---------------
(a) Represents the discounted future net cash flows before income taxes. See
Note O of Notes to Consolidated Financial Statements in Item 8 for
additional information regarding the Company's proved reserves and
standardized measure.
WILCOX TREND
The Company has 24,597 net acres, including 18,227 net undeveloped acres,
under lease in the Wilcox Trend. Approximately 29% (50.9 Bcfe) of the Company's
U.S. net proved reserve volumes are located in 13 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. From 1991 to 1997, the Company participated in the completion
of 77 gross wells in this 4,000-acre field, including 14 gross wells that were
sold in 1995. During 1998, the Company's net natural gas production from the Bob
West Field averaged approximately 42 million cubic feet ("MMcf") per day. The
Company's estimated net proved reserve
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volumes in the Bob West Field totaled 39 Bcfe at December 31, 1998. 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 a 25% interest in the field's central compression facility,
rated at 19,270 horsepower with an estimated gross capacity of 82 MMcf per day.
FRIO/VICKSBURG TREND
The Company has 23,217 net acres, including 18,129 net undeveloped acres,
under lease in the Frio/ Vicksburg Trend. Approximately 19% (32.4 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. The Company's
working interest covers 11,700 gross acres, which has been evaluated using 50
square miles of three-dimensional ("3-D") seismic data. During 1997 and 1998,
three exploratory wells and six development wells were completed. Production
from these two fields has increased from 4.8 MMcfe per day net at the date of
acquisition to an average of 8 MMcfe per day net in 1998. The Company's
estimated net proved reserve volumes in these fields totaled 18 Bcfe at December
31, 1998. Additional drilling is planned in 1999.
Kent Bayou Field. During 1997 and 1998, the Company purchased working
interests totaling 89% 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 in 1998 averaged 2 MMcfe per day net. A 3-D
seismic survey is being analyzed to identify potential development locations.
The Company's estimated net proved reserve volumes in this field totaled 10.3
Bcfe at December 31, 1998.
EAST TEXAS BASIN
The Company has 17,777 net acres, including 14,691 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 analyzing 3-D
seismic surveys to evaluate its acreage holdings. Approximately 22% (38.4 Bcfe)
of the Company's U.S. net proved reserve volumes are in five fields 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, which included
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, seven of which were drilled during 1998. The
Company's estimated net proved reserves in these fields increased from 21 Bcfe
to 25 Bcfe during 1998. Net production averaged approximately 2.2 MMcfe per day
during 1998.
Bethel Dome Field. The Company discovered the Bethel Dome Field, located in
Anderson County, Texas in December 1998. The Company's working interest in the
field ranges from 75% to 100%. The discovery well was being completed at
year-end and is expected to flow to sales in the first quarter of 1999. The well
was drilled using 3-D seismic data covering the 1,060 gross acres of controlled
leasehold. The discovery added 13 Bcfe to the Company's year-end net proved
reserves. The potential for additional development will be evaluated in 1999.
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VAL VERDE BASIN
The Company has 81,081 net acres, primarily undeveloped, under lease in the
Val Verde Basin in Edwards and Val Verde Counties, Texas. Approximately 15%
(26.7 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%. The field began production in September 1997 following
completion of a 10-mile, 6-inch gathering line. Two exploration and eight
development wells were completed in this field during 1997 and 1998. Net
production from this field averaged 15 MMcfe per day in 1998. Additional
exploration and development wells are planned in 1999.
MORROW TREND
During the third quarter of 1998, the Company acquired properties in four
producing fields in the Morrow Trend. The properties were acquired in two
separate acquisitions with a combined purchase price of $18 million cash plus
the conveyance of a working interest in an undeveloped prospect owned by the
Company in South Texas. Through these producing property acquisitions and
through previous acquisitions of undeveloped acreage, the Company acquired
25,163 net acres, including 17,742 net undeveloped acres in the Morrow Trend
during 1998. The Morrow Trend extends from the Texas Panhandle through the
western part of Oklahoma. By the end of 1998, 3-D seismic data had been acquired
and is being evaluated over the undeveloped acreage. The acquired properties
represent approximately 12% (20.1 Bcfe) of the Company's U.S. net proved reserve
volumes at year-end. The largest of these four fields is the Stiles Ranch Field.
Stiles Ranch Field. The Company's working interest in the Stiles Ranch
Field, located in Wheeler County in the Texas Panhandle, covers 10,200 gross
acres, which is being evaluated by a 3-D seismic acquisition program. Subsequent
to the acquisition, four development wells were completed in 1998 and the field
was producing an average of 2.1 MMcfe per day net at year-end.
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 that transports
natural gas 26 miles from the Starr County Gathering System to a market hub at
Fandango, Texas. The Company does not operate either pipeline. During 1998,
gross throughput averaged 118 MMcf per day for both the Starr County Gathering
System and the Starr-Zapata Pipe Line, with approximately 35% of the throughput
consisting of the Company's net working interest share of Bob West Field
production. The Starr County Gathering System receives a transportation fee of
$0.06 per thousand cubic feet ("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
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tables set forth the Company's U.S. gross and net acreage (thousands of acres)
and productive wells at December 31, 1998:
UNDEVELOPED DEVELOPED
ACREAGE ACREAGE
-------------- -------------
LOCATION GROSS NET GROSS NET
-------- ----- ----- ----- ----
Val Verde Basin, Southwest Texas............................ 103.4 80.0 1.4 1.1
East Texas Basin, East Texas................................ 65.2 14.7 3.5 3.1
Wilcox Trend, South Texas................................... 60.3 18.2 19.9 6.4
Morrow Trend, Texas Panhandle............................... 39.2 17.7 17.9 7.4
Frio/Vicksburg Trend, South Texas........................... 22.8 16.5 10.6 4.9
Frio/Vicksburg Trend, South Louisiana....................... 1.6 1.6 0.3 0.2
Other....................................................... 3.2 1.4 2.4 1.5
----- ----- ---- ----
Total Leased Acres..................................... 295.7 150.1 56.0 24.6
Fee Acres, Various Locations................................ 15.8 4.4 0.3 0.3
----- ----- ---- ----
Total Acres............................................ 311.5 154.5 56.3 24.9
===== ===== ==== ====
GAS WELLS OIL WELLS
-------------- -------------
GROSS NET GROSS NET
----- ----- ----- ----
Productive Wells (a)........................................ 241 124.4 45 17.3
- ---------------
(a) Includes 8 gross (3.6 net) gas wells and 1 gross (0.5 net) oil well with
multiple completions. At December 31, 1998, the Company was participating in
drilling or completing 7 gross (3.7 net) wells.
U.S. OPERATING STATISTICS
The following table summarizes the Company's U.S. exploration and
production activities for the years ended December 31, 1998, 1997 and 1996:
1998 1997 1996
------ ------ ------
Average Daily Net Production:
Natural gas (MMcf)........................................ 90.5 86.1 87.7
Oil (thousand barrels).................................... 0.3 0.1 --
Total (MMcfe)............................................. 92.4 86.8 87.7
Average Prices:
Natural gas ($/MMcf)(a)(b)................................ $ 2.02 $ 2.17 $ 2.75
Oil ($/barrel)............................................ $11.88 $18.90 $21.99
Average Operating Expenses ($/Mcfe):
Lease operating expenses.................................. $ 0.25 $ 0.20 $ 0.14
Severance taxes........................................... 0.04 0.03 0.03
------ ------ ------
Total production costs................................. 0.29 0.23 0.17
Administrative support and other.......................... 0.06 0.07 0.10
------ ------ ------
Total Operating Expenses............................... $ 0.35 $ 0.30 $ 0.27
====== ====== ======
Depletion ($/Mcfe)(c)....................................... $ 1.04 $ 0.93 $ 0.79
Exploratory Wells Drilled(d):
Productive -- gross....................................... 11.0 8.0 4.0
Productive -- net......................................... 6.3 6.3 1.7
Dry holes -- gross........................................ 8.0 4.0 2.0
Dry holes -- net.......................................... 5.7 2.9 1.0
Development Wells Drilled(d):
Productive -- gross....................................... 23.0 9.0 15.0
Productive -- net......................................... 17.0 5.1 6.3
Dry holes -- gross........................................ 3.0 2.0 1.0
Dry holes -- net.......................................... 2.8 1.0 0.5
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- ---------------
(a) Includes effects of the Company's natural gas commodity price agreements
which amounted to a gain of $0.04 per Mcf in 1998 and losses of $0.05 per
Mcf and $0.11 per Mcf in 1997 and 1996, respectively.
(b) Includes effects in 1996 of above-market pricing provisions under a natural
gas contract which was terminated effective October 1, 1996 (see Notes E and
F of Notes to Consolidated Financial Statements in Item 8).
(c) Does not include the effect of the 1998 oil and gas properties write-down.
(d) 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 C, E and O 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 381 Bcfe at December 31, 1998. The
Company intends to complete additional seismic studies and appraisal wells
before assigning proved reserves to the sixth field. With gross production of 41
MMcfe per day in 1998, the Company is one of the largest operators in Bolivia.
The Company holds five Shared Risk Contracts with Yacimientos Petroliferos
Fiscales Bolivianos ("YPFB"), the Bolivian governmental agency responsible for
administration of these contracts, covering a total of 1.1 million gross acres.
The contract for Block 18 is through the year 2017. The contracts for Block 20
are through the year 2018 for Block 20-Los Suris, which is in the development
phase, and through 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. 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. Total may also satisfy its
drilling obligation to earn a full 75% interest by drilling the first well and
paying cumulative drilling costs of $40 million. Total commenced drilling the
first well in June 1998, which is expected to reach target depth and be tested
by the second quarter of 1999.
MARKET FOR NATURAL GAS
A lack of market access has constrained natural gas production in Bolivia.
With little internal gas demand, all of the Company's Bolivian natural gas
production is sold under contract to the Bolivian government for export to
Argentina. Management believes that a third-party, 1,900-mile pipeline from
Bolivia to Brazil, which is expected to begin operations during the second
quarter of 1999, will provide access to potentially larger gas-consuming
markets.
The Company's natural gas production is currently sold to YPFB, which in
turn sells the natural gas to Yacimientos Petroliferos Fiscales, SA ("YPF"), a
publicly-held company based in Argentina. The Company's sale of natural gas
production is based on the volume and pricing terms in a take-or-pay contract
("Argentina Contract") between YPFB and YPF. The Argentina Contract's primary
term ends March 31, 1999 and has been extended an additional five months to
August 31, 1999, at which time the Argentina Contract is expected to expire
without renewal. The Company's share of the minimum contract volumes from the
Argentina Contract are 37 MMcf per day gross (26 net) through March 31, 1999 and
12 MMcf per day gross (9 net) from April 1999 through August 1999.
Beginning in the second quarter of 1999, sales of natural gas through the
new pipeline to Brazil will be governed by a 20-year take-or-pay contract
("Brazil Contract") between YPFB and Petroleo Brasileiro, S.A. ("Petrobras").
Initial Brazilian demand estimates are approximately 125 MMcf per day and are
expected to
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15
increase to the 200 MMcf per day level by the end of 1999. Looking forward from
1999, Petrobras estimates that demand from Brazil will increase to the one
billion cubic feet per day maximum pipeline capacity in the 2003-2005 timeframe.
Tesoro has a preferential right to 22% of the first 200 MMcf per day sold
under the Brazil Contract. For incremental demand above 200 MMcf per day,
Petrobras, in its capacity as a producer, has a preferential right to sell
production from its Bolivian wells. During March 1999, Petrobras exercised its
preferential right for 23% of the first increment of 123 MMcf per day of gas to
be sold beginning in 2000 and for 100% of the second increment of 105 MMcf per
day of gas to be sold beginning in 2001. Excluding Petrobras' preferential right
for gas volumes in excess of 200 MMcf per day, remaining gas sales will be
allocated by YPFB to the other producers according to a number of factors,
including each producer's reserve volumes and production capacity. Although the
new Bolivia-to-Brazil pipeline creates the potential for increased Tesoro gas
sales, Tesoro cannot be assured that it will be able to maintain its approximate
20% historical market share for gas sold in excess of 200 MMcf per day.
BOLIVIAN TAXES
Reserves are classified by the Bolivian government as either existing or
new hydrocarbons depending upon whether they were in production prior to May 1,
1996 ("Existing Hydrocarbons") or after that date ("New Hydrocarbons"). Existing
Hydrocarbons are subject to a 29% royalty to YPFB, plus Bolivian taxes that are
equal to an additional 31% of gross revenue. New Hydrocarbons are subject to a
more favorable tax treatment. New Hydrocarbons are subject to a tax equal to 18%
of gross revenue plus 25% of net income, and there is no royalty paid to YPFB.
Under certain circumstances, New Hydrocarbons may be subject to additional taxes
including a tax on remittances abroad and a surtax on oil and gas production.
BLOCK 18
The Company has a 100% working interest in a Shared Risk Contract covering
92,625 acres in Block 18. Approximately 35% (133 Bcfe) of the Company's Bolivian
reserve volumes are in the Escondido, La Vertiente and Taiguati Fields of Block
18. During 1998, the Company's net production from this block averaged 24 MMcf
of gas per day and 700 barrels of condensate per day. A 3-D seismic survey over
the Escondido Field was completed in 1997 to identify additional drilling
locations. The Escondido X7 well was drilled in 1998, adding 25 Bcfe of net
proved reserves. With the exception of the Escondido X7, which is classified as
New Hydrocarbons, Block 18 production is classified as Existing Hydrocarbons for
tax purposes.
BLOCK 20
The Company has a 100% working interest in Block 20-Los Suris and Block
20-East and a 25% working interest in Block 20-West, which is subject to the
provisions of the farmout agreement with Total. All of Block 20 production is
classified as New Hydrocarbons for tax purposes.
Block 20-Los Suris. This contract covers 12,350 acres of the Los Suris
Field, where approximately 37% (141 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 and two exploration wells were drilled in 1998, adding 31 Bcfe of
proved reserves.
Block 20-East. This contract, which is in the exploration phase, covers
385,938 acres and includes the Palo Marcado Field, where approximately 28% (106
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, and the Palo Marcado X5 was drilled in 1998. Although the
well has not reached final depth, the Palo Marcado X5 added 14 Bcfe to net
proved reserves at year-end based upon intermediate well logs.
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
15
16
reach target depth by the second quarter of 1999. Total estimates that the cost
of this well will exceed $30 million due to the mountainous location and depth
of the objective.
BERETI BLOCK
In November 1998, Total and Tesoro executed a new Shared Risk Contract
covering 249,000 gross acres adjacent to the Company's existing acreage. Tesoro
holds a 25% working interest in the new acreage, and Total holds the remaining
75%.
RESERVES
The table below shows the estimated net proved reserves, based on
evaluations prepared by Netherland, Sewell & Associates, Inc., and productive
wells for each of the Company's Bolivian fields. Each of the following fields is
operated by the Company:
DECEMBER 31, 1998 DECEMBER 31,
------------------------------------------------------------------- 1997
NET PROVED RESERVES ------------
---------------------------------- NET PROVED
PV-10 AFTER OIL RESERVES
BOLIVIAN TAXES(a) PRODUCTIVE (MILLIONS GAS TOTAL ------------
FIELD BLOCK ($ MILLIONS) WELLS OF BARRELS) (Bcf) (Bcfe) % BCFE %
----- ------------ ----------------- ---------- ----------- ----- ------ --- ------ ---
Los Suris............. 20-Los Suris $ 9.5 4 1.6 131.8 141.4 37 104.2 28
Palo Marcado.......... 20-East 3.1 2 1.4 98.0 106.4 28 152.1 42
Escondido............. 18 11.5 5 4.3 82.5 108.3 28 87.6 24
La Vertiente.......... 18 4.3 4 0.6 21.1 24.7 7 22.0 6
Taiguati.............. 18 -- 1 -- 0.3 0.3 -- 0.4 --
----- -- --- ----- ----- --- ------ ---
$28.4 16 7.9 333.7 381.1 100 366.3 100
===== == === ===== ===== === ====== ===
- ---------------
(a) Represents the discounted future net cash flows after Bolivian taxes. See
Note O of Notes to Consolidated Financial Statements in Item 8 for
additional information regarding the Company's proved reserves and
standardized measure.
BOLIVIAN ACREAGE AND PRODUCTIVE WELLS
The following table sets forth the Company's Bolivian gross and net acreage
(thousands of acres) and productive wells at December 31, 1998:
GROSS NET
--------- -------
Acreage:
Developed................................................. 92.6 92.6
Undeveloped............................................... 1,036.3 613.3
Productive Gas Wells(a)..................................... 16 16
- ---------------
(a) Included in productive gas wells are seven gross (seven net) wells with
multiple completions. The Company has no producing oil wells in Bolivia.
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BOLIVIA OPERATING STATISTICS
The following table summarizes the Company's Bolivian exploration and
production activities for the years ended December 31, 1998, 1997 and 1996:
1998 1997 1996
------ ------ ------
Average Daily Net Production:
Natural gas (MMcf)........................................ 24.4 19.5 20.3
Condensate (thousand barrels)............................. 0.7 0.5 0.6
Total (MMcfe)............................................. 28.6 22.6 23.8
Average Price:
Natural gas ($/Mcf)....................................... $ 0.81 $ 1.15 $ 1.33
Condensate ($/barrel)..................................... $12.80 $15.71 $17.98
Average Operating Expenses ($/Mcfe):
Production costs.......................................... $ 0.11 $ 0.11 $ 0.10
Administrative support and other.......................... 0.28 0.31 $ 0.32
------ ------ ------
Total Operating Expenses............................... $ 0.39 $ 0.42 $ 0.42
====== ====== ======
Depletion ($/Mcfe)(a)....................................... $ 0.25 $ 0.19 $ 0.15
Exploratory Wells Drilled(b):
Productive -- gross....................................... 3.0 -- 2.0
Productive -- net......................................... 3.0 -- 1.5
- ---------------
(a) Does not include the effect of the 1998 oil and gas properties write-down.
(b) No exploratory dry holes or development wells were drilled in Bolivia during
the periods presented.
For further information regarding the Company's Bolivian operations, see
Notes E and O of Notes to Consolidated Financial Statements in Item 8.
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 Alaska
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 267,000 bpd 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 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 Alaska Refinery is not directly connected to the TAPS, and the
Company, therefore, cannot return its residual products to the TAPS. The
Company's refining competition
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from the U.S. West Coast includes large, integrated oil companies that do
business in Alaska and have materially greater financial and other resources.
The Hawaii Refinery competes primarily with one other refinery in Hawaii which
is also located at Kapolei and which has a rated capacity of 54,000 bpd of crude
oil. Historically, the other refinery produced lower volumes of jet fuel than
the Hawaii Refinery. The Washington Refinery competes with several refineries on
the U.S. West Coast, including refineries which are larger than the Washington
Refinery and which are owned by companies substantially larger than the Company.
The Company is a major producer and distributor of gasoline in Alaska and
Hawaii through a large network of Company-operated stations and branded and
unbranded dealers and jobbers. The Company supplies 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. The Company also
supplies a major oil company in Hawaii through a gasoline sales agreement. The
Washington Refinery sells up to 35% of its gasoline to a major refiner through
an off-take agreement, and provides another major oil company with about 30% of
its gasoline production in exchange for gasoline received elsewhere on the West
Coast.
Competitive factors affecting the retail marketing of gasoline in Alaska,
Hawaii and the Pacific Northwest 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. The Company believes it is in a position to
compete effectively as a marketer of gasoline in Alaska and Hawaii because of
its strong presence in these markets. The Company's Pacific Northwest marketing
business sells to independent dealers and jobbers. The Company also sells its
gasoline through 44 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 Company's jet fuel sales in Alaska are concentrated in Anchorage, where
it is one of the principal suppliers to the Anchorage International Airport, a
major hub for air cargo traffic between manufacturing regions in the Far East
and consuming regions in the United States and Europe. In Hawaii, jet fuel sales
are concentrated in Honolulu, where the Company is the principal supplier to the
Honolulu International Airport. The Company also serves four airports on other
islands in Hawaii. In Washington, jet fuel sales are concentrated at the
Seattle/Tacoma International Airport. Other refiners and marketers compete for
sales at all of these airports.
The Company sells its diesel fuel primarily on a wholesale basis, competing
with other refiners and marketers in all of its market areas. Refined products
from foreign sources also compete for distillate markets in the Company's
Alaskan market area.
Demand for services and products offered by the Company's Marine Services
segment is closely related to the level of oil and gas exploration, development
and production in the Gulf of Mexico. Various factors, including general
economic conditions, demand for and prices of natural gas, availability of
equipment and materials, and government regulations and energy policies cause
exploration and development activity to fluctuate and directly impact the
revenues of the Marine Services segment. Management believes that the principal
competitive factors affecting the Marine Services operations are location of
facilities, availability of logistical support services, experience of personnel
and dependability of service. The market for the Marine Services segment's
products and services, particularly diesel fuel, is price sensitive. The Company
competes with several independent operators, and in certain locations with one
or more major mud companies who maintain their own marine terminals.
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.
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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 a third-party,
1,900-mile pipeline from Bolivia to Brazil, which is expected to begin
operations during the second quarter of 1999, will provide access to potentially
larger gas-consuming markets. Tesoro has a preferential right to 22% of the
first 200 MMcf per day sold under the Brazil Contract. For incremental demand
above 200 MMcf per day, Petrobras, in its capacity as a producer, has a
preferential right to sell production from its Bolivian wells. During March
1999, Petrobras exercised its preferential right for 23% of the first increment
of 123 MMcf per day of gas to be sold beginning in 2000 and for 100% of the
second increment of 105 MMcf per day of gas to be sold beginning in 2001.
Excluding Petrobras' preferential right for gas volumes in excess of 200 MMcf
per day, remaining gas sales will be allocated by YPFB to the other producers
according to a number of factors, including each producer's reserve volumes and
production capacity. Although the new Bolivia-to-Brazil pipeline creates the
potential for increased Tesoro gas sales, Tesoro cannot be assured that it will
be able to maintain its approximate 20% historical market share for gas sold in
excess of 200 MMcf per day.
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, both of 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, culminating in the Order No. 636 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.
The FERC believes "open access" policies are 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. As a result of the Order No. 636 program,
the marketing and pricing of natural gas has been significantly altered. The
interstate pipelines' traditional role as wholesalers of natural gas was
terminated and replaced by regulations which require pipelines to provide
transportation and storage service to others who buy and sell natural gas.
Although the FERC's 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.
Some aspects of the Order No. 636 program are still being reviewed by the
courts and the FERC. In addition, on July 29, 1998, the FERC issued a Notice of
Proposed Rulemaking in Docket No. RM98-10 proposing yet another round of
revisions to its regulations governing the market for short-term transportation
services on regulated gas pipelines. These new regulations are intended to
create even greater competition among short-term service offerings and include,
among other things, a proposal to require all available short-term capacity to
be subject to capacity auctions. The FERC also issued a Notice of Inquiry on
July 29, 1998 in Docket No. RM98-12 requesting comments on its pricing policies
in the existing long-term transportation services market and the market for new
capacity. While the Notice of Inquiry does not propose any specific changes to
existing regulations, the FERC seeks comments on whether fundamental aspects of
its pricing for long-term service and new capacity should be modified to be more
effective in the current, more competitive
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environment. It is unclear what impact, if any, increased competition within the
natural gas industry will have on the Company and its gas sales efforts. It is
not possible to predict what, if any, effect the Order No. 636 program or the
new proceedings in Docket Nos. RM98-10 and RM98-12 will have on the Company. The
Company believes, however, that it will not 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 regulations at the state and local levels. Such
regulations include 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.
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. Specifics as to
the cost of these requirements at certain facilities are still being determined.
As part of these requirements, the Company's refineries as well as certain other
Company facilities submitted applications for Clean Air Act Amendment Title V
permits in 1997. Each application has subsequently been deemed complete by the
respective state agencies, and most applications are expected to undergo
technical review in 1999. The Company believes it can comply with these new
requirements, and in some cases already has done so, without adversely affecting
operations.
Additional Federal environmental regulations promulgated on August 21,
1990, and effective on October 1, 1993, set limits on the quantity of sulphur in
on-highway diesel fuels which the Company produces. The State of Alaska 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. The EPA has
since extended the temporary exemption to July 1, 1999. The Company estimates
that capital expenditures will be required for the Company to produce lower
sulphur diesel fuel to meet these federal regulations. If the State of Alaska is
unable to obtain a permanent waiver from the federal regulations, the Company
would produce lower sulphur diesel fuel for on-highway use based on market
demand. The Company estimates that such sales accounted for less than 1% of its
refined product sales in Alaska. 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 and contingency plans
for use during an oil spill response. The Company has prepared and submitted
these plans
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for approval and 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, on a long-term and short-term basis,
tankers and barges for shipment of crude oil from foreign and domestic sources
to its Alaska, Hawaii and Washington refineries. 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. As an example, the
State of Alaska requires the Company to provide spill-response capability to
contain or control and cleanup, 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 such requirements, the
Company has entered into contracts with various parties to provide initial spill
response services, with the Company later to assume those responsibilities after
mutual agreement with spill response providers or the state and federal On-Scene
Coordinators. The Company has entered into spill response agreements with (i)
Cook Inlet Spill Prevention and Response, Incorporated for oil spill response
services near the Alaska Refinery; (ii) Clean Islands Council for response
services throughout the State of Hawaii; and (iii) Clean Sound Incorporated for
response actions associated with the Washington Refinery. In addition, for
larger spill contingency capabilities the Company has entered into contracts
with Marine Spill Response Corporation in Hawaii and in the Gulf Coast region.
The Company believes these contracts and those with other regional spill
response organizations that are in place on a location by location basis,
provide the additional services necessary to meet spill response requirements
established by state and federal law.
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 in Alaska. The total estimated cost of these
improvements is approximately $8 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 include locations in Alaska and
Hawaii. The Company had upgraded all of its underground storage tanks by
December 22, 1998.
Total Environmental Expenditures. The Company's total capital expenditures
for environmental control purposes were $10 million during 1998. Capital
expenditures for the alternative secondary containment systems discussed above
were $1 million in 1998 and are estimated to be $2 million in 1999 and $1
million in 2000. The remaining $4 million is expected to be spent by 2002.
Capital expenditures for other environmental control purposes, including tank
vapor control seals at the Washington Refinery, waste water treatment system
upgrades at the Alaska Refinery and reliability upgrades at the Hawaii
Refinery's sulphur recovery unit, are estimated to be $12 million in 1999 and $5
million in 2000. 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.
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EMPLOYEES
At December 31, 1998, the Company employed approximately 2,140 persons, of
whom approximately 66 were located in foreign countries. Approximately 175
employees at the Washington Refinery are covered by a collective bargaining
agreement. The Company considers its relations with its employees to be
satisfactory.
RISK FACTORS AND INVESTMENT CONSIDERATIONS
VOLATILITY OF PRICES; EFFECT ON EARNINGS AND CASH FLOWS
The Company's refining and marketing earnings and cash flows from
operations are dependent upon the margin above fixed and variable expenses
(including the cost of crude oil feedstocks) at which the Company is able to
sell refined products. In recent years, the prices of crude oil and refined
products have fluctuated substantially. These prices depend on numerous factors,
including the demand for crude oil, gasoline and other refined products, which
in turn depend on, among other factors, changes in the economy, the level of
foreign and domestic production of crude oil and refined products, political
conditions in the Middle East, the availability of imports of crude oil and
refined products, the marketing of alternative and competing fuels and the
extent of government regulations. The prices received by the Company for its
refined products are also affected by local factors such as local market
conditions and the level of operations of other refineries in Alaska, Hawaii and
Washington.
The price at which the Company can sell its refined products will be
strongly influenced by the commodity price of crude oil. Generally, an increase
or decrease in the price of crude oil results in a corresponding increase or
decrease in the price of gasoline and other refined products and could have a
significant short-term impact on the Company's refining operations and the
earnings and cash flows of the Company as a whole. However, each of the
Company's refineries maintains inventories of crude oil, intermediate products
and refined products, the value of each of which is subject to rapid fluctuation
in market prices. In addition, crude oil supply contracts are generally
contracts with market-responsive pricing provisions.
Any significant decline in the price for natural gas could have a material
adverse effect on the Company's exploration and production operations and the
financial condition of the Company as a whole. Prices for natural gas are
subject to wide fluctuations in response to relatively minor changes in the
supply of and demand for natural gas, market uncertainty and a variety of
additional factors that are beyond the control of the Company. These factors
include the domestic and foreign supply of natural gas, the level of consumer
demand, weather conditions, domestic and foreign government regulations, the
price and availability of alternative fuels and overall economic conditions.
While the Company from time to time enters into agreements with respect to a
portion of its future production in an effort to reduce price risk, including
commodity price contracts and forward sales agreements, there can be no
assurance that such transactions will reduce risk or mitigate the effect of any
substantial or prolonged decline in the price of natural gas.
CRUDE OIL SUPPLY
The Company believes an adequate supply of crude oil will be available to
its three refineries to sustain the Company's refining operations for the
foreseeable future at substantially the levels currently being experienced.
However, there can be no assurance that this situation will continue. If
additional supplemental crude oil becomes necessary at one or more of its
refineries, the Company intends to implement available alternatives that are
most advantageous under then prevailing conditions. Implementation of some
alternatives could require the consent or cooperation of third parties and other
considerations beyond the control of the Company. If the Company is unable to
obtain such supplemental crude oil volumes, or is only able to obtain such
volumes at uneconomic prices, the Company's results from operations could be
materially adversely effected.
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HAWAII REFINED PRODUCT MARKET; ECONOMIC CONDITIONS IN HAWAII
In the Hawaii refined product market, local refined products supply
currently is reasonably balanced to slightly surplus for all finished products
except jet fuel. This could limit the potential future growth in earnings
generated by the Hawaii Refinery. One competing gasoline marketer has been
importing gasoline for retail sale in Hawaii. In addition, the growth rate in
Hawaii's gross state product from 1991 through 1997 was substantially below the
U.S. average. If these trends continue, they may have an adverse effect on the
business and results of operations of the Company.
HAWAII GASOLINE RETAILING RESTRICTIONS AND STATE GOVERNMENT ALLEGATIONS
In 1991 and 1993 at the request of independent gasoline dealers, the Hawaii
legislature enacted a series of two-year moratorium periods during which
refiners and jobbers were prevented or restricted from operating additional
retail stations pending the outcome of legislative studies. In 1995, legislation
was enacted which restricted refiners and jobbers to only one company-operated
station per dealer station opened, subject to a maximum of two company-operated
stations. In 1997, the Hawaii legislature ended the moratorium with the
enactment of a statute that permits refiners and jobbers to acquire or build any
number of retail stations, provided these are situated at least one-eighth of a
mile from any existing dealer station in the urban Honolulu area and at least
one-fourth of a mile from any existing dealer station in the remainder of the
State.
On October 1, 1998, the Attorney General for the State of Hawaii filed a
lawsuit in the U.S. District Court for the District of Hawaii against thirteen
oil companies, including Tesoro Petroleum Corporation and Tesoro Hawaii
Corporation, alleging anti-competitive marketing practices in violation of
federal and state anti-trust laws. See Item 3, Legal Proceedings, contained
herein.
RISKS ASSOCIATED WITH BOLIVIAN AND OTHER INTERNATIONAL OPERATIONS
The Company's international operations are primarily conducted in Bolivia,
where it has operated for over 25 years and where it currently explores for and
produces hydrocarbons through five contracts with the Bolivian government.
Substantially all of the Company's current Bolivian production is sold under
contract to the Bolivian government for export to Argentina, as there is
currently little internal demand in Bolivia for natural gas. As a result, the
Company's Bolivian operations are heavily dependent on its relations with the
Bolivian government. Moreover, a majority of the Company's Bolivian reserves are
currently shut-in. The Company believes that the recent completion of the
construction of a third-party, 1,900-mile pipeline from Bolivia to Brazil will
provide access to gas-consuming markets. The Company faces intense competition
from major and independent natural gas companies operating in Bolivia for a
share of the contractual volumes to be exported to Brazil. Tesoro has a
preferential right to 22% of the first 200 MMcf per day sold under the Brazil
Contract. For incremental demand above 200 MMcf per day, Petrobras, in its
capacity as a producer, has a preferential right to sell production from its
Bolivian wells. During March 1999, Petrobras exercised its preferential right
for 23% of the first increment of 123 MMcf per day of gas to be sold beginning
in 2000 and for 100% of the second increment of 105 MMcf per day of gas to be
sold beginning in 2001. Excluding Petrobras' preferential right for gas volumes
in excess of 200 MMcf per day, remaining gas sales will be allocated by YPFB to
the other producers according to a number of factors, including each producer's
reserve volumes and production capacity. Although the new Bolivia-to-Brazil
pipeline creates the potential for increased Tesoro gas sales, Tesoro cannot be
assured that it will be able to maintain its approximate 20% historical market
share for gas sold in excess of 200 MMcf per day. When the pipeline begins
operating, which is expected to occur in the second quarter of 1999, the
Company's Bolivian gas production will become dependent to a large extent upon
the continued demand for natural gas in Brazil and the stability of such
markets. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations" in Item 7 and "Exploration and Production -- Bolivia"
discussed above.
The future success of the Company's international operations in Bolivia and
elsewhere is subject to political, economic and other uncertainties, including,
among others, risk of war, revolution, border disputes, expropriation,
renegotiation or modification of existing contracts, import, export and
transportation regulations and tariffs, taxation policies, including royalty and
tax increases and retroactive tax claims, exchange controls,
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currency fluctuations and other uncertainties arising out of foreign government
sovereignty over the Company's international operations. The Company's
international operations may also be adversely affected by laws and policies of
the United States affecting foreign trade, taxation and investment. Furthermore,
in the event of a dispute arising from its Bolivian or other international
operations, the Company may be subject to the exclusive jurisdiction of foreign
courts or may not be successful in subjecting foreign persons to the
jurisdiction of courts in the United States. The Company believes Bolivia
possesses relatively stable political and economic environments in which to
operate; however, there can be no assurance that political and economic and
other uncertainties will not develop in Bolivia or neighboring countries. Such
uncertainty or instability could result in new governments or the adoption of
new policies that might assume a substantially more hostile attitude toward
foreign investment. In an extreme case, such a change could result in voiding
pre-existing contracts and/or expropriation of foreign-owned assets.
REPLACEMENT OF RESERVES
The future success of the Company's exploration and production operations
depends upon the ability to find, develop or acquire additional oil and gas
reserves that are economically recoverable. The proved reserves of the Company
will generally decline as reserves are depleted, except to the extent that the
Company conducts successful exploration or development activities, acquires
properties containing proved reserves, or both. In order to increase reserves
and production, the Company must continue its development and exploration
drilling and recompletion programs or undertake other replacement activities.
The Company's current strategy includes continuing to exploit its existing
properties, discovering new reserves through exploration and increasing its
reserve base through acquisitions of producing properties. There can be no
assurance, however, that the Company's planned exploration, development and
acquisition activities will result in significant additional reserves or that
the Company will have continuing success drilling productive wells at low
finding and development costs. For a discussion of the Company's reserves, see
"Exploration and Production -- U.S. -- Reserves" and "Exploration and
Production -- Bolivia -- Reserves" discussed above.
DRILLING RISKS
Drilling activities are subject to many risks, including the risk that no
commercially productive reservoirs will be encountered. There can be no
assurance that new wells drilled by the Company will be productive or that the
Company will recover all or any portion of its investment. Drilling for oil and
natural gas may involve unprofitable efforts, not only from dry wells, but from
wells that are productive but do not produce sufficient net revenues to return a
profit after drilling, completing, operating, and other costs. The cost of
drilling, completing and operating wells is often uncertain. The Company's
drilling operations may be curtailed, delayed or canceled as a result of
numerous factors, many of which are beyond the Company's control, including
title problems, weather conditions, compliance with governmental requirements
and shortages or delays in the delivery of equipment and services.
RELIANCE ON ESTIMATES OF PROVED RESERVES
There are numerous uncertainties inherent in estimating quantities of
proved reserves, including many factors beyond the control of the Company. The
Company's historical reserve information set forth herein represents estimates
based on evaluations either prepared by or audited by Netherland, Sewell &
Associates, Inc., as of December 31, 1998.
Petroleum engineering is not an exact science. Information relating to the
Company's proved oil and gas reserves is based upon engineering estimates.
Estimates of economically recoverable oil and gas reserves and of future net
cash flows necessarily depend upon a number of variable factors and assumptions,
such as historical production from the area compared with production from other
producing areas, the assumed effects of regulations by governmental agencies and
assumptions concerning future oil and gas prices, future operating costs,
severance and excise taxes, development costs and workover and remedial costs,
all of which may in fact vary considerably from actual results. For these
reasons, estimates of the economically recoverable quantities of oil and gas
attributable to any particular group of properties, classifications of such
reserves based on risk of recovery and estimates of the future net cash flows
expected therefrom prepared by different engineers or by
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the same engineers at different times may vary substantially. Actual production,
revenues and expenditures with respect to the Company's reserves will likely
vary from estimates, and such variances may be material. See "Exploration and
Production -- U.S. -- Reserves" and "Exploration and Production -- Bolivia --
Reserves" discussed above.
The discounted future net cash flows of proved reserves (sometimes referred
to herein as "PV10") should not be construed as the current market value of the
estimated oil and gas reserves attributable to the Company's properties. In
accordance with applicable requirements of the Securities and Exchange
Commission ("SEC"), the estimated discounted future net cash flows from proved
reserves are generally based on prices and costs as of the date of the estimate,
whereas actual future prices and costs may be materially higher or lower. Actual
future net cash flows also will be affected by factors such as the amount and
timing of actual production, supply and demand for oil and gas, curtailments or
increases in consumption by gas purchasers and changes in governmental
regulations or taxation. The timing of actual future net cash flows from proved
reserves, and thus their actual present value, will be affected by the timing of
both the production and the incurrence of expenses in connection with
development and production of oil and gas properties. In addition, the 10%
discount factor, which is required by the SEC to be used to calculate discounted
future net cash flows for reporting purposes, is not necessarily the most
appropriate discount factor based on interest rates in effect from time to time
and risks associated with the Company or the oil and gas industry in general.
OPERATING HAZARDS AND UNINSURED RISKS
The Company's operations are subject to hazards and risks inherent in
drilling for, producing and transporting oil and natural gas and refining crude
oil, such as fires, natural disasters, explosions, blowouts, cratering, pipeline
ruptures, and spills, any of which can result in loss of hydrocarbons,
environmental pollution, personal injury claims, and other damage to properties
of the Company and others. As protection against operating hazards, the Company
maintains insurance coverage against some, but not all, potential losses. The
Company's coverages include, but are not limited to, operator's extra expense,
physical damage on certain assets, employer's liability, comprehensive general
liability, automobile, workers' compensation and loss of production income
insurance. The Company believes that its insurance is adequate and customary for
companies of a similar size engaged in operations similar to those of the
Company, but losses could occur for uninsurable or uninsured risks or in amounts
in excess of existing insurance coverage. The occurrence of an event that is not
fully covered by insurance could have an adverse impact on the Company's
financial condition and results of operations.
CONCENTRATION OF OPERATIONS
A significant portion of the Company's domestic exploration and production
operations are located in the Wilcox Trend along the Texas and Louisiana Gulf
Coast. During 1998, the Company made significant progress in diversifying its
operations to areas other than the mature Bob West Field, which is located in
the Wilcox Trend. At December 31, 1998, approximately 23% of the Company's
domestic net proved gas reserves were located in the Bob West Field compared to
39% at December 31, 1997. As a result, any interruption of the Company's
production in the Bob West Field due to any one or more of a variety of
conditions and events, including natural disaster, reservoir damage, mechanical
difficulties, unavailability of equipment and supplies, transportation problems,
title and contractual controversies or government regulation, could have a
material adverse effect on the Company's operations and its ability to service
debt and other obligations. See "Exploration and Production -- U.S. -- Reserves"
discussed above.
The Company's refining activities are conducted at its three refineries in
Hawaii, Alaska and Washington. The refineries are three of the Company's
principal operating assets. As a result, the operations of the Company, and its
ability to service debt and other obligations are subject to significant
interruption if one or more of the refineries were to experience a major
accident, be damaged by severe weather or other natural disaster, or otherwise
be forced to shut down. Although the Company maintains business interruption
insurance against some types of risks in amounts which the Company believes to
be economically prudent, if the refineries were to experience an interruption in
operations, the Company's business could be materially adversely affected. See
"Refining and Marketing" discussed above.
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OTHER
For information on competitive factors affecting the Company's business,
see "Competition and Other" discussed above. A discussion of environmental
controls and factors are included in "Government Regulation and Legislation"
discussed above. Matters related to Year 2000 readiness are addressed in
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" contained in Item 7 herein. See also "Legal Proceedings" in Item 3
herein.
ITEM 2. PROPERTIES
See information appearing under Item 1, Business herein and Notes C, E and
O of Notes to Consolidated Financial Statements in Item 8.
ITEM 3. LEGAL PROCEEDINGS
Environmental. The Company is currently involved with the EPA regarding a
waste disposal site near Abbeville, Louisiana and the Casmalia Disposal Site in
Santa Barbara County, California. The Company has been named a potentially
responsible party ("PRP") under the Federal Comprehensive Environmental
Response, Compensation and Liability Act ("CERCLA" or "Superfund") at both
sites. Although the Superfund law might impose joint and several liability upon
each party at the sites, the extent of the Company's allocated financial
contributions for cleanup is expected to be de minimis based upon the number of
companies, volumes of waste involved, and total estimated costs to close each
site. The Company believes, based on these considerations and discussions with
the EPA, that its liability at the Abbeville site will not exceed $25,000. The
Company believes that its liability at the Casmalia Site is de minimis based on
a February 1, 1999 notification from the EPA indicating that the Company's
liability will not exceed $125,000.
On August 26, 1998, the United States Coast Guard issued a Notice of
Federal Interest For An Oil Pollution Incident to Tesoro Hawaii Corporation
("Tesoro Hawaii"), a subsidiary of the Company, in connection with an oil spill
which occurred on August 24, 1998, at Tesoro Hawaii's single point mooring at
Barbers Point, Oahu, Hawaii. Tesoro Hawaii, the Coast Guard and the Hawaii
Department of Health ("HDOH") responded to the spill immediately and clean up
efforts have been completed. Under the Federal Water Pollution Control Act and
the Oil Pollution Act of 1990, the responsible party is liable for removal costs
and damages, including damages from injury to natural resources and may be
assessed administrative or civil penalties. The Company carries insurance to
provide protection against pollution damages. The Company believes that the
resolution of this oil spill will not have a material adverse effect on the
Company.
On October 2, 1998, the Alaska Department of Environmental Conservation
("ADEC") issued a Notice of Violation ("NOV") against the Alaska Refinery
related to non-compliance with the facility air quality permit. This NOV alleges
that an air emission treatment unit at the Alaska Refinery groundwater treatment
system did not maintain the air contaminant removal efficiency rate required in
the facility air quality permit. The Company has initiated discussions with the
ADEC on this matter and believes that the resolution thereof will not have a
material adverse effect on the Company.
As previously reported, on October 16, 1998, the HDOH issued a Notice of
Apparent Violation of Hawaii state law to Tesoro Hawaii in connection with a
spill on September 23, 1998. During the loading of a time-chartered barge,
diesel fuel was spilled into the state waters at Barbers Point Harbor, Oahu,
Hawaii. It was immediately cleaned up by the charterer of the barge. Hawaii law
requires that appropriate action to correct an apparent violation must be taken
and further provides for civil penalties. HDOH notified Tesoro Hawaii on
November 24, 1998 that due to the Tesoro Hawaii immediate response, clean-up and
implementation of corrective and preventive measures, HDOH does not intend to
pursue an enforcement action against Tesoro Hawaii.
The Company is currently involved with a waste water disposal site in
Redwood City, California. On December 18, 1998, the Port of Redwood City filed
suit against numerous defendants, including the Company, for contribution
pursuant to CERCLA and the Resource Conservation and Recovery Act ("RCRA"). The
Company has negotiated with the Port of Redwood City and expects to settle its
liability in
26
27
early 1999. The Company believes it is not subject to joint and several
liability for the clean-up of the site and that its liability will not exceed
$40,000.
The EPA issued a NOV on June 24, 1997, against the Hawaii Refinery alleging
violations of the Clean Water Act associated with the content and implementation
of the Hawaii Refinery's Spill Prevention, Control and Countermeasures ("SPCC")
Plan, and further alleging violations based on a series of oil releases. The
Company and the EPA remain engaged in settlement discussions with remaining
issues limited to alleged deficiencies in the content and implementation of the
Hawaii Refinery's SPCC. This proceeding is subject to the indemnity provision of
the environmental agreement between the BHP Sellers and the Company, and the
Company believes that resolution of this matter will not have a material adverse
effect on the Company.
Also on June 24, 1997, a NOV was issued against BHP companies pursuant to
Section 103 of the CERCLA and Section 304 of the Emergency Planning and
Community Right to Know Act ("EPCRA") regarding past releases of reportable
quantities of regulated substances and oil. This matter remains subject to EPA
review and penalty amounts have not been assessed to date. This proceeding is
subject to the indemnity provisions of the environmental agreement between the
BHP Sellers and the Company, and the Company believes that resolution of this
matter will not have a material adverse effect on the Company.
On August 5, 1996, the EPA issued a Finding of Violation ("FOV") against
BHP Hawaii pursuant to disclosures made by BHP Hawaii pursuant to a permit
application for compliance with Title V of the Clean Air Act. The parties have
engaged in settlement negotiations and no penalty amount has been assessed. This
proceeding is subject to the indemnity provision of the environmental agreement
between the BHP Sellers and the Company, and the Company believes that
resolution of this matter will not have a material adverse effect on the
Company.
As previously reported, on May 19, 1998, the EPA issued a NOV against
Tesoro Alaska Petroleum Company, a subsidiary of the Company, alleging
violations of the RCRA associated with the failure to maintain closure of
certain containers of hazardous waste at the Alaska Refinery when not in use and
the failure to retain on-site certain records of land disposal restriction
notifications. On August 28, 1998, the EPA conducted a subsequent inspection at
the facility and issued a finding of no violations of RCRA.
Other. As previously reported, on October 1, 1998, the Attorney General for
the State of Hawaii filed a lawsuit in the U.S. District Court for the District
of Hawaii against thirteen oil companies, including Tesoro Petroleum Corporation
and Tesoro Hawaii Corporation, alleging anti-competitive marketing practices in
violation of federal and state anti-trust laws, and seeking injunctive relief
and compensatory and treble damages and civil penalties against all defendants
in an amount in excess of $500 million. On March 25, 1999, the Attorney General
filed an amended complaint with the U.S. District Court seeking damages against
all defendants for such alleged anti-competitive marketing practices in an
amount in excess of $1.3 billion. The Company believes that it has not engaged
in any anti-competitive activities and will defend this litigation vigorously.
This proceeding is subject to the indemnity provision of the stock sale
agreement between the BHP Sellers and the Company which provides for
indemnification in excess of $2 million and not to exceed $65 million.
27
28
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The 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 1998 and
1997 are summarized below:
1998 1997
------------- -------------
QUARTERS ENDED HIGH LOW HIGH LOW
-------------- ---- --- ---- ---
March 31............................................ $17 7/8 $14 3/4 $14 1/2 $10 3/8
June 30............................................. $21 3/8 $15 5/8 $15 $10 1/4
September 30........................................ $19 13/16 $11 3/4 $18 3/16 $14 3/4
December 31......................................... $16 1/4 $ 9 9/16 $18 3/16 $15
At March 1, 1999, there were approximately 3,200 holders of record of the
Company's 32,341,386 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 D of Notes to Consolidated Financial Statements in
Item 8. The Board of Directors has no present plans to pay dividends on Common
Stock. However, from time to time, the Board of Directors reevaluates the
feasibility of declaring future dividends on Common Stock.
28
29
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. Financial results of acquired entities
in the Refining and Marketing segment during 1998 and the Marine Services
segment during 1996 have been included in the amounts below since their
respective acquisitions date (see Note C of Notes to Consolidated Financial
Statements in Item 8).
YEARS ENDED DECEMBER 31,
------------------------------------------------
1998 1997 1996 1995 1994
-------- ------ -------- -------- ------
(DOLLARS IN MILLIONS EXCEPT PER SHARE AMOUNTS)
REVENUES
Gross Operating Revenues:
Refining and Marketing
Refined products.................................... $1,198.2 $643.7 $ 620.8 $ 664.5 $582.7
Other, primarily crude oil resales and
merchandise....................................... 69.8 77.2 124.6 106.5 104.3
Marine Services....................................... 118.6 132.2 122.5 74.5 77.9
Exploration and Production
U.S.(a)............................................. 71.5 73.6 93.8 113.0 90.6
Bolivia............................................. 10.5 11.2 13.7 11.7 13.2
-------- ------ -------- -------- ------
Total Gross Operating Revenues.................... 1,468.6 937.9 975.4 970.2 868.7
Other income(a)......................................... 21.7 5.5 64.4 32.7 3.2
-------- ------ -------- -------- ------
Total Revenues.................................... $1,490.3 $943.4 $1,039.8 $1,002.9 $871.9
======== ====== ======== ======== ======
SEGMENT OPERATING PROFIT (LOSS)(b)
Refining and Marketing................................ $ 69.7 $ 20.5 $ 6.0 $ 0.7 $ 2.4
Marine Services....................................... 8.6 6.3 6.1 (4.4) (2.3)
Exploration and Production
U.S. before write-down(a)........................... 45.9 37.3 123.9 102.0 55.0
Bolivia before write-down........................... 3.4 8.6 8.8 7.6 9.3
Write-downs of oil and gas properties(c)............ (68.3) -- -- -- --
-------- ------ -------- -------- ------
Total Segment Operating Profit.................... $ 59.3 $ 72.7 $ 144.8 $ 105.9 $ 64.4
======== ====== ======== ======== ======
EARNINGS (LOSS) BEFORE EXTRAORDINARY ITEM............... $ (15.0) $ 30.7 $ 76.8 $ 57.5 $ 20.5
EXTRAORDINARY LOSS ON DEBT EXTINGUISHMENTS, NET OF
INCOME TAXES(d)....................................... (4.4) -- (2.3) (2.9) (4.8)
-------- ------ -------- -------- ------
NET EARNINGS (LOSS)..................................... (19.4) 30.7 74.5 54.6 15.7
PREFERRED DIVIDEND REQUIREMENTS......................... 6.0 -- -- -- 2.7
-------- ------ -------- -------- ------
NET EARNINGS (LOSS) APPLICABLE TO COMMON STOCK.......... $ (25.4) $ 30.7 $ 74.5 $ 54.6 $ 13.0
======== ====== ======== ======== ======
NET EARNINGS (LOSS) PER SHARE -- BASIC(d)............... $ (0.86) $ 1.16 $ 2.87 $ 2.22 $ 0.58
NET EARNINGS (LOSS) PER SHARE -- DILUTED(d)............. $ (0.86) $ 1.14 $ 2.81 $ 2.18 $ 0.56
WEIGHTED AVERAGE COMMON SHARES -- BASIC (MILLIONS)...... 29.4 26.4 26.0 24.6 22.6
WEIGHTED AVERAGE COMMON SHARES AND POTENTIALLY DILUTIVE
COMMON SHARES -- DILUTED (MILLIONS)................... 29.4 26.9 26.5 25.1 23.2
EBITDA, CONSOLIDATED(e)................................. $ 152.9 $103.8 $ 174.8 $ 127.8 $ 83.1
CASH FLOWS FROM (USED IN)
Operations............................................ $ 116.5 $ 95.6 $ 178.9 $ 35.4 $ 60.3
Investing............................................. (718.6) (151.5) (94.2) 2.4 (91.2)
Financing............................................. 606.6 41.5 (75.9) (37.8) 8.3
-------- ------ -------- -------- ------
Increase (Decrease) in Cash and Cash Equivalents.... $ 4.5 $(14.4) $ 8.8 $ -- $(22.6)
======== ====== ======== ======== ======
CAPITAL EXPENDITURES(f)
Refining and Marketing................................ $ 38.0 $ 43.9 $ 11.1 $ 9.3 $ 32.0
Marine Services....................................... 4.2 9.4 6.9 0.4 0.2
Exploration and Production
U.S. ............................................... 87.5 65.4 59.7 49.6 65.6
Bolivia............................................. 47.6 27.5 6.9 3.8 --
Other................................................. 7.8 1.3 0.4 0.8 1.8
-------- ------ -------- -------- ------
Total Capital Expenditures.......................... $ 185.1 $147.5 $ 85.0 $ 63.9 $ 99.6
======== ====== ======== ======== ======
29
30
YEARS ENDED DECEMBER 31,
------------------------------------------------
1998 1997 1996 1995 1994
-------- ------ -------- -------- ------
(DOLLARS IN MILLIONS EXCEPT PER SHARE AMOUNTS)
BALANCE SHEET DATA
Current Assets........................................ $ 390.6 $181.8 $ 237.3 $ 182.5 $182.1
Property, Plant and Equipment, Net.................... $ 894.6 $413.8 $ 316.5 $ 261.7 $273.3
Total Assets.......................................... $1,428.4 $627.8 $ 582.6 $ 519.2 $484.4
Current Liabilities................................... $ 208.2 $107.5 $ 137.8 $ 105.0 $ 96.2
Total Long-Term Debt and Other Obligations(g)......... $ 543.9 $132.3 $ 89.3 $ 164.5 $199.6
Stockholders' Equity(g)(h)............................ $ 559.2 $333.0 $ 304.1 $ 216.5 $160.7
Current Ratio......................................... 1.9:1 1.7:1 1.7:1 1.7:1 1.9:1
Working Capital....................................... $ 182.4 $ 74.3 $ 99.5 $ 77.5 $ 85.9
Total Debt to Capitalization(g)....................... 49% 28% 23% 43% 55%
Common Stock Outstanding (million shares)(g)(h)....... 32.3 26.3 26.4 24.8 24.4
Book Value Per Common Share........................... $ 12.19 $12.66 $ 11.51 $ 8.74 $ 6.59
- ---------------
(a) In the Exploration and Production segment, operating profit included income
of $21.3 million in 1998 from an operator in the Bob West Field,
representing funds no longer needed as a contingency reserve for litigation;
$60 million in 1996 from termination of a natural gas contract; and a gain
in 1995 of $33 million from the sale of certain interests in the Bob West
Field. In addition, operating profit included $25 million, $47 million and
$39 million in 1996, 1995 and 1994, respectively, from the excess of the
natural gas contract prices over spot market prices.
(b) Segment operating profit (loss) equals 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 and other
expenses are not included in determining segment operating profit. In 1998,
a charge of $19.9 million for special incentive compensation, of which $7.9
million related to operating segments, was classified as corporate other
expense and not charged to segment operating profit. See Notes E, F and L of
Notes to Consolidated Financial Statement in Item 8.
(c) In 1998, write-downs of oil and gas properties were $68.3 million ($28.4
million in the U.S. and $39.9 million in Bolivia), or $43.2 million ($1.47
per basic share) aftertax.
(d) Extraordinary losses on debt extinguishments, net of income tax benefits,
were $4.4 million ($0.15 per basic and diluted share), $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 1998,
1996, 1995 and 1994, respectively. See Note D of Notes to Consolidated
Financial Statements in Item 8.
(e) EBITDA represents earnings before extraordinary items, interest expense,
income taxes and depreciation, depletion and amortization (including oil and
gas property write-downs in 1998). While not purporting to reflect any
measure of the Company's operations or cash flows, EBITDA is presented for
additional analysis. Prior period amounts have been restated to conform with
current presentation.
(f) Excluding amounts to fund acquisitions in the Refining and Marketing and
Marine Services segments.
(g) In conjunction with the acquisitions in 1998, the Company refinanced its
existing indebtedness and issued senior subordinated notes and additional
equity securities, including $165 million of 7.25% Mandatorily Convertible
Preferred Stock which is included in stockholders' equity. See Note D of
Notes to Consolidated Financial Statements in Item 8.
(h) The Company has not paid dividends on its Common Stock since 1986.
30
31
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 48 for discussion
of the factors which could cause actual results to differ materially from those
projected in such statements.
GENERAL
The Company's strategy is to (i) maximize earnings, cash flows and return
on capital employed and increase the competitiveness of each of its business
units by reducing costs, increasing operating efficiencies and optimizing
existing assets and (ii) expand its overall market presence through a
combination of internal growth initiatives and selective acquisitions which are
both accretive to earnings and provide significant operational synergies. 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. Improved profitability has
positioned the Marine Services segment to participate in the consolidation of
the industry by pursuing opportunities for expansion, as well as optimizing
existing operations. In the Exploration and Production segment, the strategy
focuses on generating and operating exploration projects in an effort to
diversify its oil and gas production and reserve base. Selectively, the Company
uses acquisitions and enhanced technical capabilities. The Company has made
significant progress in diversifying its U.S. operations to areas other than the
Bob West Field and has taken steps to begin serving emerging markets in South
America.
As part of this strategy, the Company completed the following Refining and
Marketing acquisitions during 1998:
- On May 29, 1998, the Company completed the acquisition (the "Hawaii
Acquisition") of all of the outstanding capital stock of BHP Petroleum
Americas Refining Inc. and BHP Petroleum South Pacific Inc. (together,
"BHP Hawaii") from BHP Hawaii Inc. and BHP Petroleum Pacific Islands
Inc., affiliates of The Broken Hill Proprietary Company Limited ("BHP").
The Hawaii Acquisition included a 95,000-barrel per day refinery (the
"Hawaii Refinery") and 32 retail gasoline stations located in Hawaii.
Tesoro paid $252.2 million in cash for the Hawaii Acquisition, including
$77.2 million for working capital. In addition, Tesoro issued 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.
- On August 10, 1998, the Company completed the acquisition (the
"Washington Acquisition" and together with the Hawaii Acquisition, the
"Acquisitions") of all of the outstanding stock of Shell Anacortes
Refining Company ("Shell Washington"), an affiliate of Shell Oil Company.
The Washington Acquisition included a 108,000-barrel per day refinery
(the "Washington Refinery") in Anacortes, Washington and related assets.
The total cash purchase price for the Washington Acquisition was $280.1
million, including $43.1 million for working capital.
The Acquisitions are expected to triple Tesoro's historical annual revenues
and significantly increase the scope of its refining and marketing operations.
The Acquisitions had a positive impact on earnings and cash flows in the fourth
quarter of 1998, and management expects that the Acquisitions will add to
earnings and cash flows in 1999. Management believes that there are significant
cost-saving and revenue-enhancement opportunities available by integrating the
Hawaii and Washington refineries with the Alaskan operations and has identified
approximately $25 million of potential annual cost saving and revenue enhancing
synergies. Management expects to realize the full annual impact of such
synergies during 1999. The Company will continue to pursue other opportunities
that are operationally and geographically complementary with its asset base.
In conjunction with the Acquisitions and refinancing of its then-existing
indebtedness ("Refinancing") in 1998, the Company issued equity and debt
securities providing the Company with $533 million of net proceeds
31
32
and entered into a $500 million senior credit facility ("Senior Credit
Facility"). For information related to the financings, see Note D of Notes to
Consolidated Financial Statements in Item 8.
BUSINESS ENVIRONMENT
The Company operates in an environment where its earnings and cash flows
are sensitive to volatile changes in energy prices. Fluctuations in the cost of
crude oil used for refinery feedstocks and the price of refined products can
result in changes in margins from the Refining and Marketing operations, as
prices received for refined products may or may not keep pace with changes in
crude oil costs. These energy prices, together with volume levels, also
determine the carrying value of crude oil and refined product inventory. The
Company uses the last-in, first-out ("LIFO") method of accounting for
inventories of crude oil and U.S. wholesale refined products 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. If, however, fluctuations in market prices cause the
market value of inventories to fall below their LIFO cost, the Company would
write-down its inventories to estimated realizable value.
Changes in crude oil and natural gas prices also influence the level of
drilling activity in the Gulf of Mexico. The Company's Marine Services segment,
whose customers include offshore drilling contractors and related industries,
can be impacted by significant fluctuations in natural gas, condensate and oil
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.
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 segment. The Company may increase or decrease its
natural gas production in response to market conditions. The carrying costs of
oil and gas assets are subject to noncash write-downs based on decreases in
natural gas and oil prices and other determining factors. In 1998, the Company
recorded a $68.3 million noncash write-down of its oil and gas properties. It is
reasonably possible that the present value of proved oil and gas reserves could
be significantly reduced during the first quarter of 1999 due to further
decreases in natural gas and oil prices since year-end. This could result in
further write-downs of the Company's oil and gas properties.
32
33
RESULTS OF OPERATIONS
SUMMARY
Tesoro's net loss for 1998 was $19.4 million, compared with net earnings of
$30.7 million and $74.5 million in 1997 and 1996, respectively. In 1998 and
1996, the Company incurred aftertax extraordinary losses of $4.4 million and
$2.3 million, respectively, for early extinguishments of debt. Results before
extraordinary losses amounted to a loss of $15.0 million in 1998 and earnings of
$30.7 million and $76.8 million in 1997 and 1996, respectively. The net loss per
share for 1998 was $0.86 (basic and diluted) after preferred dividends, compared
with net earnings per basic share of $1.16 ($1.14 diluted) and $2.87 ($2.81
diluted) in 1997 and 1996, respectively. Significant items, including
write-downs of oil and gas properties, which affect the comparability between
results for the years ended December 31, 1998, 1997 and 1996 are highlighted in
the table below (in millions except per share amounts):
1998 1997 1996
------ ----- ------
Net earnings (loss) as reported............................. $(19.4) $30.7 $ 74.5
Extraordinary loss on debt extinguishments, net of income
tax benefit............................................... 4.4 -- 2.3
------ ----- ------
Earnings (loss) before extraordinary items.................. (15.0) 30.7 76.8
------ ----- ------
Significant items affecting comparability, pretax:
Write-downs of oil and gas properties..................... (68.3) -- --
Income from receipt of contingency funds from a U.S. gas
field operator......................................... 21.3 -- --
Charge for special incentive compensation................. (19.9) -- --
Income from settlement of a natural gas contract.......... -- -- 60.0
Operating profit from excess of natural gas contract
prices over spot market prices......................... -- -- 24.6
Other..................................................... -- 4.0 5.5
------ ----- ------
Total significant items, pretax........................ (66.9) 4.0 90.1
Income tax effect...................................... (24.6) 1.2 27.2
------ ----- ------
Total significant items, aftertax...................... (42.3) 2.8 62.9
------ ----- ------
Net earnings excluding significant items and extraordinary
items..................................................... 27.3 27.9 13.9
Preferred dividend requirements............................. 6.0 -- --
------ ----- ------
Net earnings applicable to Common Stock, excluding
significant items and extraordinary items................. $ 21.3 $27.9 $ 13.9
====== ===== ======
Earnings (loss) per share -- basic:
As reported............................................... $(0.86) $1.16 $ 2.87
Extraordinary loss........................................ (0.15) -- (0.09)
Effect of other significant items......................... (1.43) 0.10 2.43
------ ----- ------
Excluding significant items and extraordinary items....... $ 0.72 $1.06 $ 0.53
====== ===== ======
Earnings (loss) per share -- diluted:
As reported............................................... $(0.86) $1.14 $ 2.81
Extraordinary loss........................................ (0.15) -- (0.09)
Effect of other significant items......................... (1.42) 0.10 2.37
------ ----- ------
Excluding significant items and extraordinary items....... $ 0.71 $1.04 $ 0.53
====== ===== ======
Excluding the significant items affecting comparability, net earnings would
have been $27.3 million in 1998, compared with net earnings of $27.9 million in
1997 and $13.9 million in 1996. Increased Refining and Marketing results in 1998
were substantially offset by higher interest and financing costs and lower
natural gas sales prices in the Exploration and Production segment. When
comparing 1997 with 1996, after excluding significant items, the $14 million
improvement in net earnings was primarily attributable to better refined product
margins, higher spot market natural gas prices and lower interest expense.
Net earnings per share, after excluding significant items, would have been
$0.72 per basic share ($0.71 diluted) for 1998, compared with $1.06 per basic
share ($1.04 diluted) in 1997 and $0.53 per basic and
33
34
diluted share in 1996. On a per share basis, the Company's results for 1998 were
reduced by dividends on Preferred Stock and the impact of issuing additional
shares of Common Stock during the year.
The accompanying consolidated financial statements and related notes,
together with the following discussion and analysis, are intended to provide
shareholders and other investors with a reasonable basis for assessing the
Company's operations, but should not serve as the only criteria for predicting
the future performance of the Company.
REFINING AND MARKETING
1998 1997 1996
-------- ------ ------
(DOLLARS IN MILLIONS EXCEPT
PER BARREL AMOUNTS)
GROSS OPERATING REVENUES
Refined products.......................................... $1,198.2 $643.7 $620.8
Other, primarily crude oil resales and merchandise........ 69.8 77.2 124.6
-------- ------ ------
Gross Operating Revenues............................. $1,268.0 $720.9 $745.4
======== ====== ======
SEGMENT OPERATING PROFIT
Gross margin:
Refinery(a)............................................ $ 307.3 $116.9 $ 92.4
Non-refinery, primarily merchandise(a)................. 22.6 13.0 14.9
-------- ------ ------
Total gross margin................................... 329.9 129.9 107.3
Operating expenses and other.............................. 235.1 96.7 88.8
Depreciation and amortization............................. 25.1 12.7 12.5
-------- ------ ------
Segment Operating Profit............................. $ 69.7 $ 20.5 $ 6.0
======== ====== ======
CAPITAL EXPENDITURES........................................ $ 38.0 $ 43.9 $ 11.1
======== ====== ======
REFINERY THROUGHPUT (thousand of barrels per day)(b)
Alaska.................................................... 57.6 50.2 47.5
Hawaii.................................................... 82.3 -- --
Washington................................................ 101.8 -- --
-------- ------ ------
Total Refinery Throughput............................ 241.7 50.2 47.5
======== ====== ======
REFINED PRODUCTS MANUFACTURED (thousands of barrels per
day)(b)
Gasoline and gasoline blendstocks......................... 50.9 12.8 12.8
Jet fuel.................................................. 40.6 15.4 14.0
Diesel fuel............................................... 18.8 6.2 6.0
Heavy oils and residual products.......................... 33.5 14.8 13.7
Other, including synthetic natural gas and liquefied
petroleum gas.......................................... 9.7 2.3 2.6
-------- ------ ------
Total Refined Products Manufactured.................. 153.5 51.5 49.1
======== ====== ======
REFINERY PRODUCT SPREAD ($/barrel)(a)....................... $ 5.67 $ 6.38 $ 5.33
======== ====== ======
34
35
1998 1997 1996
-------- ------ ------
(DOLLARS IN MILLIONS EXCEPT
PER BARREL AMOUNTS)
SEGMENT PRODUCT SALES (thousands of barrels per day)(b)(c)
Gasoline and gasoline blendstocks......................... 58.4 17.4 17.4
Middle distillates........................................ 70.7 30.6 29.7
Heavy oils, residual products and other................... 38.7 17.9 15.1
-------- ------ ------
Total Product Sales.................................. 167.8 65.9 62.2
======== ====== ======
SEGMENT PRODUCT SALES PRICES ($/barrel)
Gasoline.................................................. $ 24.22 $33.71 $32.72
Middle distillates........................................ $ 19.79 $28.36 $29.01
Heavy oils and residual products.......................... $ 12.12 $17.30 $17.61
SEGMENT GROSS MARGINS ON PRODUCT SALES ($/barrel)(d)
Average sales price....................................... $ 19.56 $26.76 $27.28
Average costs of sales.................................... 14.49 21.92 23.15
-------- ------ ------
Gross Margin...................................... $ 5.07 $ 4.84 $ 4.13
======== ====== ======
- ---------------
(a) Amounts reported for 1997 and 1996 have been reclassified to conform with
current presentation, primarily to reclassify retail margins and
intrasegment transportation revenues from non-refinery margin to refinery
product spread.
(b) Sales and manufactured volumes for 1998 included amounts from the acquired
Hawaii and Washington operations since the acquisition dates, averaged over
the full year. Refinery throughput for 1998 included volumes from the Hawaii
and Washington refineries, averaged over the periods owned since
acquisition.
(c) Sources of total product sales included products manufactured at the
Company's refineries, products drawn from inventory balances and products
purchased from third parties.
(d) Gross margins on product sales included margins on sales of manufactured and
purchased products and the effects of inventory changes.
1998 Compared with 1997. Segment operating profit from the Refining and
Marketing operations totaled $69.7 million in 1998, an increase of $49.2 million
from segment operating profit of $20.5 million in 1997. The increase in segment
operating profit was primarily due to higher throughput and sales volumes,
primarily from the acquired refineries (see Note C to Consolidated Financial
Statements in Item 8), and improved refined product yields in Alaska. Financial
results from the acquired operations have been included since the dates of
acquisition. The Hawaii Acquisition was completed on May 29, 1998, and the
Washington Acquisition was completed on August 10, 1998. The Acquisitions
contributed positively to the segment's operating profit in 1998; however, on a
consolidated basis, these results were largely offset by corporate interest and
financing costs.
During 1998, the Company's refined product yields in Alaska benefitted from
an expansion of the hydrocracker unit completed in October 1997. The expansion,
which increased the unit's capacity by approximately 25%, enables production of
more jet fuel. Segment results were favorably impacted by this expansion
beginning in the fourth quarter of 1997. During 1998, average throughput at the
Alaska Refinery increased by 7,400 barrels per day, a 15% increase over 1997
which included a 30-day maintenance turnaround. Production of jet fuel at this
refinery increased by approximately 30% over 1997 due to the hydrocracker
expansion and higher throughput levels.
The Alaska hydrocracker expansion and the Acquisitions contributed to an
increase in the proportion of higher value gasoline and middle distillates
manufactured by the Company in 1998. Conversely, the proportion of lower value
heavy oils and residual products manufactured by the Company decreased in 1998.
The higher-value mix of product partly offset market pressures which decreased
year-to-year refinery product spreads to $5.67 per barrel in 1998 from $6.38 per
barrel in 1997. Increased gross margins of $5.07 per barrel in 1998, which
compare to $4.84 per barrel in 1997, reflected the higher-value mix of
manufactured product and a reduction in products purchased and resold. In 1998,
products from the Company's refineries accounted for
35
36
approximately 91% of its sales volume, compared with 78% in 1997, enabling the
Company to reduce the amounts of products purchased from others which generally
sell at lower margins.
Revenues from sales of refined products in the Refining and Marketing
segment increased during 1998 primarily due to the higher sales volumes from the
Acquisitions, partially offset by lower sales prices. Export sales of refined
products increased to $35.5 million in 1998, compared with $16.1 million in
1997, primarily due to sales from Hawaii to Asia partly offset by a decrease in
exports from the Alaska Refinery to the Far East. Other revenues included crude
oil resales of $29.9 million in 1998 compared to $44.4 million in 1997.
Merchandise sales, also included in other revenues, increased in 1998 due to the
Hawaii Acquisition which included 30 Company-operated retail stations. The
increase in costs of sales reflected higher volumes associated with the
Acquisitions, partly offset by lower feedstock prices. Margins from non-refinery
activities increased to $22.6 million in 1998, compared with $13.0 million in
1997, primarily due to the higher merchandise sales. Operating expenses and
depreciation and amortization were higher in 1998 primarily due to the
Acquisitions.
With the acquisitions of the Hawaii and Washington refineries, enhancements
of product mix and expansion of market areas, the Company has improved the
fundamental earnings potential of this segment. Management plans to further
improve profitability by enhancing processing capabilities, strengthening
marketing channels and improving supply and transportation functions. The
ability to supply these expanded markets with a higher proportion of
manufactured products, rather than purchased products, is also expected to
improve profitability. 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.
1997 Compared with 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 was due in part to the Company's
initiatives to enhance its product slate, improve efficiencies and sell a larger
portion of the Alaska Refinery's production within the core Alaska market. The
expansion of the hydrocracker unit discussed above began to favorably impact
this segment's results in the fourth quarter of 1997. In October 1997, the
Company began purchasing approximately 25,000 barrels per day of Cook Inlet
crude oil in addition to the 9,000 barrels per day under previously existing
contracts.
During 1997, the Company's production of refined products increased by 5%.
The operational changes, discussed above, resulted in an 8% increase in the
production of higher-value middle distillates, primarily jet fuel, while
production of lower-value heavy oils, residual products and other increased by
5%. The improved product slate, which better matches the Company's product
supply with demand in Alaska, reflected a change of the hydrocracker catalyst in
late 1996, as well as 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 $6.38 per barrel in
1997, compared to $5.33 per barrel in 1996. Both years included scheduled 30-day
maintenance turnarounds.
Revenues from sales of refined products in the Refining and Marketing
segment increased during 1997, reflecting a 6% increase in sales volumes,
partially offset by slightly lower average sales prices. Total refined product
sales averaged 65,900 barrels per day in 1997, compared to 62,200 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 Alaska Refinery increased by 2,700 barrels per day, or 6%,
from 1996. Export sales of refined products, including sales to Russia, 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 decreased to $13.0 million in 1997 due
primarily to lower margins on refined product purchased for resale. Operating
expenses and other increased 9% in 1997 due primarily to higher employee costs,
professional fees and marketing expenses.
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MARINE SERVICES
1998 1997 1996
------ ------ ------
(DOLLARS IN MILLIONS)
Gross Operating Revenues
Fuels..................................................... $ 91.1 $104.5 $ 98.9
Lubricants and other...................................... 15.9 16.4 14.9
Services.................................................. 11.6 11.3 8.7
------ ------ ------
Gross Operating Revenues............................... 118.6 132.2 122.5
Costs of Sales.............................................. 79.0 96.7 93.0
------ ------ ------
Gross Profit........................................... 39.6 35.5 29.5
Operating Expenses and Other................................ 28.6 27.5 22.2
Depreciation and Amortization............................... 2.4 1.7 1.2
------ ------ ------
Segment Operating Profit............................... $ 8.6 $ 6.3 $ 6.1
====== ====== ======
Sales Volumes (millions of gallons):
Fuels, primarily diesel................................... 180.8 156.4 142.7
Lubricants................................................ 2.3 2.7 2.3
Capital Expenditures........................................ $ 4.2 $ 9.4 $ 6.9
1998 Compared with 1997. Gross operating revenues decreased 10% from $132.2
million in 1997 to $118.6 million in 1998, reflecting a $13.4 million decline in
fuel revenues from lower market prices partly offset by a 16% increase in fuel
sales volumes. The increase in fuel volumes was attributable to operations in
the Gulf of Mexico and the transfer of three West Coast terminals from the
Company's Refining and Marketing segment to Marine Services in January 1998. The
decrease in costs of sales also reflected lower fuel prices, partly offset by
increased volumes. Gross profit, which improved by $4.1 million due to higher
volumes, was partly offset by additional operating expenses from the West Coast
terminals and higher depreciation and amortization resulting from upgrades to
facilities. Despite lower rig activity in the Gulf of Mexico, total segment
operating profit increased by $2.3 million largely due to the Company's ability
to emphasize customer service, control expenses and increase sales volumes.
Profitability of the Marine Services segment can be affected significantly
by the level of oil and gas drilling, workover, construction and seismic
activity in the Gulf of Mexico. With depressed oil and gas prices continuing
into 1999, exploration and production activity in the Gulf of Mexico has
significantly declined. While the Company's Marine Services segment has taken
initiatives to be a low-cost provider and has expanded its operations into the
West Coast, its operating results will be adversely impacted by reduced sales
volumes and pressure on margins in the near term.
1997 Compared with 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 reflected a 10% increase in sales volumes, partially offset
by lower prices. The 30% increase in service revenue 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 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 largely
offset by higher operating and other expenses associated with the increased
activity and higher depreciation and amortization expense.
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EXPLORATION AND PRODUCTION
1998 1997 1996
------ ------ ------
(DOLLARS IN MILLIONS
EXCEPT PER UNIT AMOUNTS)
U.S.(a)(b)
Gross operating revenues.................................. $ 71.5 $ 73.6 $ 93.8
Other income(c)........................................... 22.4 3.2 64.8
Production costs.......................................... 9.7 7.4 5.3
Administrative support and other operating expenses....... 2.4 2.3 3.8
Depreciation, depletion and amortization.................. 35.9 29.8 25.6
Write-down of oil and gas properties...................... 28.4 -- --
------ ------ ------
Segment Operating Profit -- U.S...................... 17.5 37.3 123.9
------ ------ ------
BOLIVIA
Gross operating revenues.................................. 10.5 11.2 13.7
Other income (expense).................................... (0.5) 2.2 --
Production costs.......................................... 1.2 0.9 0.8
Administrative support and other operating expenses....... 2.8 2.4 2.8
Depreciation, depletion and amortization.................. 2.6 1.5 1.3
Write-down of oil and gas properties...................... 39.9 -- --
------ ------ ------
Segment Operating Profit (Loss) -- Bolivia........... (36.5) 8.6 8.8
------ ------ ------
TOTAL SEGMENT OPERATING PROFIT (LOSS) -- EXPLORATION AND
PRODUCTION................................................ $(19.0) $ 45.9 $132.7
====== ====== ======
U.S.
Average Daily Net Production:
Natural gas (million cubic feet, "MMcf")............... 90.5 86.1 87.7
Oil (thousand barrels)................................. 0.3 0.1 --
Total (million cubic feet equivalent, "MMcfe")......... 92.4 86.8 87.7
Average Prices:
Natural gas ($/thousand cubic feet, "Mcf")(b)(d)....... $ 2.02 $ 2.17 $ 2.75
Oil ($/barrel)......................................... $11.88 $18.90 $21.99
Average Operating Expenses ($/thousand cubic feet equivalent,
"Mcfe"):
Lease operating expenses............................... $ 0.25 $ 0.20 $ 0.14
Severance taxes........................................ 0.04 0.03 0.03
------ ------ ------
Total production costs............................... 0.29 0.23 0.17
Administrative support and other....................... 0.06 0.07 0.10
------ ------ ------
Total Operating Expenses............................. $ 0.35 $ 0.30 $ 0.27
====== ====== ======
Depletion ($/Mcfe)........................................ $ 1.04 $ 0.93 $ 0.79
Capital Expenditures (including U.S. gas
transportation)........................................ $ 87.5 $ 65.4 $ 59.7
BOLIVIA
Average Daily Net Production:
Natural gas (MMcf)..................................... 24.4 19.5 20.3
Condensate (thousand barrels).......................... 0.7 0.5 0.6
Total (MMcfe).......................................... 28.6 22.6 23.8
Average Prices:
Natural gas ($/Mcf).................................... $ 0.81 $ 1.15 $ 1.33
Condensate ($/barrel).................................. $12.80 $15.71 $17.98
Average Operating Expenses ($/Mcfe):
Production costs....................................... $ 0.11 $ 0.11 $ 0.10
Administrative support and other....................... 0.28 0.31 0.32
------ ------ ------
Total Operating Expenses............................... $ 0.39 $ 0.42 $ 0.42
====== ====== ======
Depletion ($/Mcfe)........................................ $ 0.25 $ 0.19 $ 0.15
Capital Expenditures...................................... $ 47.6 $ 27.5 $ 6.9
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- ---------------
(a) Represents the Company's U.S. oil and gas operations combined with gas
transportation activities.
(b) Results for 1996 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. During 1996, the spot
market price for natural gas was $1.95 per Mcf, while the average price,
including the impact of the Tennessee Gas contract, was $2.75 per Mcf. Net
natural gas production sold under the contract averaged approximately 11
MMcf per day in 1996. Operating profit for 1996 included $24.6 million from
the excess of these contract prices over spot market prices. Upon
termination of the contract, the Company recorded other income and operating
profit of $60 million during the fourth quarter of 1996. See Note F of Notes
to Consolidated Financial Statements in Item 8.
(c) Operating profit for 1998 included income from receipt of $21.3 million from
an operator in the Bob West Field, representing funds that were no longer
needed as a contingency reserve for litigation.
(d) Includes effect of the Company's natural gas commodity price agreements
which amounted to a gain of $0.04 per Mcf in 1998 and to losses of $0.05 per
Mcf in 1997 and $0.11 per Mcf in 1996.
EXPLORATION AND PRODUCTION -- U.S.
1998 Compared with 1997. Segment operating profit from the Company's U.S.
exploration and production operations was $17.5 million, compared with $37.3
million in 1997. Comparability between these years was impacted by certain
significant items. Results for 1998 included income from receipt of $21.3
million from an operator in the Bob West Field, representing funds that were no
longer needed as a contingency reserve for litigation, and a write-down of its
domestic oil and gas properties of $28.4 million. In 1997, the Company
recognized income of $1.8 million for retroactive severance tax refunds.
Excluding these significant items, segment operating profit decreased by $10.9
million in 1998 primarily due to lower prices, higher depletion and increased
production costs.
Gross operating revenues from the Company's U.S. operations decreased by
$2.1 million as lower sale prices generally offset higher production volumes.
Prices realized by the Company on its natural gas production declined to $2.02
per Mcf in 1998 from $2.17 per Mcf in 1997. The Company's U.S. production
averaged 92.4 MMcfe per day in 1998, compared with 86.8 MMcfe per day in 1997.
The 5.6 MMcfe per day increase consisted of a 30.3 MMcfe per day increase in
production from outside the Bob West Field, partially offset by a 24.7 MMcfe per
day decline at the Bob West Field. Production from outside the Bob West Field
provided 55% of the Company's total production in 1998, compared to 24% in 1997.
Total production costs increased $2.3 million, to $9.7 million in 1998 from
$7.4 million in 1997. On a per unit basis, total production costs increased to
$0.29 per Mcfe in 1998 from $0.23 per Mcfe in 1997. Production costs from
outside the Bob West Field increased by $3.0 million due to the higher volumes
from these newer fields, but on a per unit basis, production costs from these
fields declined to $0.32 per Mcfe in 1998 from $0.40 per Mcfe in 1997.
Production costs at the Bob West Field decreased by $0.7 million due to the
decline in volumes which resulted in an increase in the per unit cost to $0.25
per Mcfe in 1998 from $0.18 per Mcfe in 1997.
Depreciation, depletion and amortization increased by $6.1 million, or 20%,
due to a higher depletion rate and increased production volumes. The higher
depletion rate of $1.04 per Mcfe in 1998, compared to $0.93 per Mcfe in 1997,
was due, in part, to the Company's emphasis on exploration, which accounted for
more than half of the total drilling costs in 1998. The Company's $28.4 million
write-down of capitalized costs of oil and gas properties, which was required by
the cost ceiling limitation under full-cost accounting, was primarily the result
of declines in oil and gas prices during the fourth quarter of 1998. Although
the effect of the write-down resulted in a noncash charge to operating profit in
1998, it will positively impact future earnings through lower depletion rates,
beginning in the first quarter of 1999. The 1998 year-end write-down reduced
amortizable domestic costs by 14%. It is reasonably possible that further
decreases in oil and natural gas prices since 1998 year-end may cause the
Company to reduce its capitalized costs of oil and gas properties in the near
term.
For information related to natural gas commodity price agreements, see Item
7A contained herein.
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40
1997 Compared with 1996. Segment operating profit from the Company's U.S.
exploration and production 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 other income of $60 million upon
termination of the contract. In 1996, the Exploration and Production segment's
operating profit also included $24.6 million from the excess of Tennessee Gas
contract prices over spot market prices. See Notes E and F 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.
Excluding the impact of the incremental contract value and income from the
severance tax refunds, segment operating profit from the Company's U.S.
operations would have been $35.5 million in 1997 compared with $34.3 million in
1996. The resulting increase of $1.2 million was primarily attributable to
higher spot market prices for natural gas sales, 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 includes 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 0.9 MMcfe per day from 1996. This decrease
consisted of a 16.1 MMcfe per day decline from the Bob West Field, largely
offset by a 15.2 MMcfe per day increase from other U.S. fields.
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)
mainly due to costs at the Bob West Field. 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.
EXPLORATION AND PRODUCTION -- BOLIVIA
1998 Compared with 1997. Segment operating results for the Company's
Bolivian operations decreased to a loss of $36.5 million, compared to operating
profit of $8.6 million in 1997. Results for 1998 included a $39.9 million
write-down of the Bolivian oil and gas properties, while results for 1997
included $2.2 million of income related to the collection of a receivable for
production in prior years. Excluding the write-down in 1998 and other income in
1997, segment operating profit for 1998 would have been $3.4 million compared to
$6.4 million in 1997. The decrease of $3.0 million in segment operating profit
was primarily due to the decline in Bolivian natural gas prices, which are
contractually indexed to posted New York fuel oil prices. Natural gas prices
fell 30% to $0.81 per Mcf in 1998 from $1.15 per Mcf in 1997. Condensate prices
also fell to $12.80 per barrel in 1998 from $15.71 per barrel in 1997. Net
production volumes, however, increased to 28.6 MMcfe per day from 22.6 MMcfe per
day. The Company's share of net production increased in 1998 as a result of the
July 1997 buyout of interests held by its former joint venture participant, and
the remaining production difference resulted in part from production constraints
in 1997 arising from repairs to a third-party pipeline that transports gas from
Bolivia to Argentina.
The increase in depreciation, depletion and amortization was due to the
higher production volumes and a higher depletion rate. The Company's $39.9
million write-down of capitalized costs of oil and gas properties,
40
41
which was required by the cost ceiling limitation under full-cost accounting,
was primarily the result of declines in oil and gas prices during the fourth
quarter of 1998. Although the effect of the write-down resulted in a noncash
charge to operating profit in 1998, it will positively impact future earnings
through lower depletion rates, beginning in the first quarter of 1999. The 1998
year-end write-down reduced amortizable Bolivian costs by 28%. It is reasonably
possible that further decreases in oil and natural gas prices since 1998
year-end may cause the Company to reduce its capitalized costs of oil and gas
properties in the near term.
1997 Compared with 1996. Segment operating profit from the Company's
Bolivian operations decreased to $8.6 million in 1997 from $8.8 million 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, segment
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, early in 1997, the Company's Bolivian
natural gas production was lower due to a reduction in minimum takes under the
contract between Yacimientos Petroliferos Fiscales ("YPFB") and Yacimientos
Petroliferos Fiscales ("YPF") and also due to constraints arising from repairs
to a third-party 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 with $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.
Other Factors. The Company's Bolivia natural gas is currently sold to YPFB,
a Bolivian government agency, which in turn sells the natural gas to YPF, a
publicly-held company based in Argentina. Currently, the Company's sale of
natural gas production is based on the volume and pricing terms in a take-or-pay
contract ("Argentina Contract") between YPFB and YPF. The Argentina Contract's
primary term ends March 31, 1999, and has been extended an additional five
months to August 31, 1999. The Company's share of the minimum contract volumes
from the Argentina Contract are 37 MMcf per day gross (26 net) through March 31,
1999 and 12 MMcf per day gross (9 net) from April 1999 through August 1999.
A lack of market access has constrained natural gas production in Bolivia.
Management believes that a third-party, 1,900-mile pipeline from Bolivia to
Brazil, which is expected to begin operations during the second quarter of 1999,
will provide access to potentially larger gas-consuming markets. Pipeline sales
will be governed by a 20-year take-or-pay contract ("Brazil Contract") between
YPFB and Petroleo Brasileiro, S.A. ("Petrobras"). Initial Brazilian demand
estimates are approximately 125 MMcf per day and are expected to increase to the
200 MMcf per day level by the end of 1999. Tesoro has a preferential right to
22% of the first 200 MMcf per day sold under the Brazil Contract. For
incremental demand above 200 MMcf per day, Petrobras, in its capacity as a
producer, has a preferential right to sell production from its Bolivian wells.
During March 1999, Petrobras exercised its preferential right for 23% of the
first increment of 123 MMcf per day of gas to be sold beginning in 2000 and for
100% of the second increment of 105 MMcf per day of gas to be sold beginning in
2001. Excluding Petrobras' preferential right for gas volumes in excess of 200
MMcf per day, remaining gas sales will be allocated by YPFB to the other
producers according to a number of factors, including each producer's reserve
volumes and production capacity. Although the new Bolivia-to-Brazil pipeline
creates the potential for increased Tesoro gas sales, Tesoro cannot be assured
that it will be able to maintain its approximate 20% historical market share for
gas sold in excess of 200 MMcf per day.
In Bolivia, the Company's reserves are classified by the government as
either existing or new hydrocarbons depending upon whether they were in
production prior to May 1, 1996 ("Existing Hydrocarbons") or after that date
("New Hydrocarbons"). Existing Hydrocarbons are subject to a 29% royalty to
YPFB, plus Bolivian taxes that are equal to an additional 31% of gross revenues.
New Hydrocarbons are subject to a more favorable tax treatment. New Hydrocarbons
are subject to a tax equal to 18% of gross revenues plus 25% of net income, and
there is no royalty paid to YPFB. Under certain circumstances, New Hydrocarbons
may be subject to additional taxes. During 1998, the Company paid taxes of $5.2
million to the Bolivian government which are netted against the income tax
benefit in the Consolidated Statement of Operations in Item 8 hereof.
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42
GENERAL AND ADMINISTRATIVE EXPENSES
General and administrative expenses were $19.7 million in 1998, compared
with $13.6 million in 1997 and $12.7 million in 1996. The $6.1 million increase
in 1998 was primarily due to higher employee costs and professional fees partly
due to the design and implementation of an integrated enterprise-wide software
system. System design and implementation will continue in phases until all
system modules are implemented by the fourth quarter of 1999. When comparing
1997 to 1996, the increase was primarily due to higher employee costs, partially
offset by lower professional fees and insurance costs.
INTEREST AND FINANCING COSTS
Interest and financing costs totaled $33.0 million in 1998, compared with
$8.3 million in 1997 and $18.2 million in 1996. The $24.7 million increase in
1998 was primarily due to higher borrowings under the Company's credit
arrangements, including the new Senior Credit Facility, and the issuance of debt
securities which were used to fund the Acquisitions and the Refinancing and to
fund working capital requirements and capital expenditures (see Note D of Notes
to Consolidated Financial Statements in Item 8). When comparing 1997 with 1996,
the $9.9 million decrease in interest and financing costs reflected the interest
savings from redemption of $74 million in debt during November 1996.
INTEREST INCOME
Interest income was $2.0 million in 1998, compared with $1.6 million in
1997 and $8.4 million in 1996. In 1996, interest income included 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 F of Notes to Consolidated Financial Statements in Item 8).
OTHER OPERATING COSTS AND OTHER EXPENSES
Other expense totaled $24.1 million in 1998, compared with $3.3 million in
1997 and $7.2 million in 1996. In 1998, the Company incurred a charge for
special incentive compensation which was earned in the second quarter when the
market price of the Company's Common Stock achieved a specific performance
target. This charge totaled $19.9 million, of which $7.9 million related to
operating segment employees. There were no material comparable charges recorded
in 1997. When comparing 1997 to 1996, the decrease in other expense was due to
costs incurred in 1996 of $2.3 million to resolve a shareholder consent
solicitation, together with a write-off of deferred financing costs and expenses
related to former operations. See Note F of Notes to Consolidated Financial
Statements in Item 8.
INCOME TAX PROVISION
The Company recorded an income tax benefit of $0.5 million in 1998,
compared with income tax provisions of $18.4 million in 1997 and $38.3 million
in 1996. The income tax benefit in 1998 was due to the Company's loss in 1998,
but was largely offset by Bolivian taxes. When comparing 1997 to 1996, the
income tax provision decreased due to lower earnings, partially offset by
Bolivian taxes. See "Results of Operations -- Exploration and
Production -- Bolivia."
CAPITAL RESOURCES AND LIQUIDITY
OVERVIEW
The Company's primary sources of liquidity are its cash flows from
operations and borrowing availability under a revolving line of credit. Capital
requirements are expected to include capital expenditures, working capital, debt
service and preferred dividend requirements. Based upon current and anticipated
needs, management believes that available capital resources will be adequate to
meet anticipated future capital requirements.
42
43
The Company operates in an environment where its liquidity and capital
resources are impacted by changes in price, supply 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.
CAPITALIZATION
During 1998, the Company invested $536 million in the Acquisitions and
spent an additional $185 million on natural gas property additions and other
capital projects. These investing activities, together with the Refinancing,
were funded with net proceeds of $533 million from equity and debt offerings,
cash flows from operations of $116 million and borrowings under term loans and
revolving credit lines. At December 31, 1998, the Company's total debt to
capitalization ratio was 49%.
Major changes in the Company's capitalization during 1998 were as follows:
- The issuance of 10,350,000 Premium Income Equity Securities ("PIES"),
representing fractional interests in the Company's 7.25% Mandatorily
Convertible Preferred Stock ("Preferred Stock"), provided the Company
with gross proceeds of $165 million. Holders of PIES are entitled to
receive a cash dividend. The PIES will automatically convert into shares
of Common Stock on July 1, 2001, at a rate based upon a formula dependent
upon the market price of Common Stock at the time of conversion. Before
July 1, 2001, each PIES is convertible, at the option of the holder
thereof, into 0.8455 shares of Common Stock, subject to adjustment in
certain events.
- The issuance of 5,750,000 shares of Common Stock provided the Company
with gross proceeds of $92 million.
- The issuance of $300 million aggregate principal amount of Senior
Subordinated Notes ("Senior Subordinated Notes") provided the Company
with $287 million of net proceeds. The Senior Subordinated Notes mature
in 2008, without sinking fund requirements, and are subject to optional
redemption by the Company after five years at declining premiums. The
indenture for the Senior Subordinated Notes contains covenants and
restrictions which are customary for notes of this nature. These
covenants and restrictions are less restrictive than those under the
Senior Credit Facility, discussed below.
- Substantially all of the Company's existing indebtedness at May 29, 1998,
including an obligation to the State of Alaska and loans which were used
to improve the Alaska Refinery, were refinanced in 1998.
- The Company entered into a $500 million Senior Credit Facility, comprised
of term loans aggregating $200 million and a revolving credit and letter
of credit facility aggregating $300 million, which bear interest at
variable rates. This facility replaced an interim credit facility which
was entered into in May 1998 to complete the Hawaii Acquisition and the
Refinancing, to pay related fees and expenses and for general corporate
purposes. The interim credit facility replaced the Company's previous
corporate revolving credit agreement. For further information on the
Senior Credit Facility, see "Credit Arrangements" discussed below.
- As part of the Hawaii Acquisition, the Company issued an unsecured,
non-interest bearing promissory note ("BHP Note") in the amount of $50
million, payable in five equal annual installments of $10 million each,
beginning 2009. The BHP Note provides for early payments based upon
achievement of a specified level of cash flows from the acquired assets.
The Senior Credit Facility, Senior Subordinated Notes and PIES impose
various restrictions and covenants on the Company that could potentially limit
the Company's ability to respond to market conditions,
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to provide for anticipated capital investments, to raise additional debt or
equity capital or to take advantage of business opportunities.
For further information on the Company's capital structure, see Note D of
Notes to Consolidated Financial Statements in Item 8.
CREDIT ARRANGEMENTS
During July 1998, the Company entered into the Senior Credit Facility,
comprised of term loans aggregating $200 million ("Term Loans") and a revolving
credit and letter of credit facility aggregating $300 million ("Revolver"). The
Senior Credit Facility is guaranteed by substantially all of the Company's
active direct and indirect subsidiaries ("Guarantors") and is secured by
substantially all of the domestic assets of the Company and each of the
Guarantors. At December 31, 1998, the Company had outstanding borrowings of
$149.5 million under the Term Loans and $61.2 million under the Revolver.
Outstanding letters of credit totaled $14 million at 1998 year-end. Unused
availability under the Senior Credit Facility and Term Loans was approximately
$275 million at December 31, 1998. On January 4, 1999, the final $50 million
tranche under the Term Loans was borrowed and used to reduce outstanding
borrowings under the Revolver. The Revolver terminates in July 2001, while the
Term Loans mature over varying periods through the end of 2003.
The Senior Credit Facility requires the Company to maintain specified
levels of consolidated leverage and interest coverage and contains other
covenants and restrictions customary in credit arrangements of this kind. The
Company was in compliance with these covenants at December 31, 1998. Future
compliance with financial covenants under the Senior Credit Facility is
primarily dependent on the Company's cash flows and levels of borrowings under
the Revolver. Based on market conditions in the first quarter of 1999, including
depressed natural gas prices and downturn in refinery margins, continued
compliance with such covenants is not assured. If the Company is not able to
continue to comply with its financial covenants, it will be required to seek
waivers or amendments from its lenders. If such an event occurs, management of
the Company believes that it will be able to obtain waivers and/or negotiate
terms and conditions with its lenders under the Senior Credit Facility which
will allow the Company to adequately finance its operations.
The terms of the Senior Credit Facility allow for payment of cash dividends
on the Company's Common Stock not to exceed an aggregate of $10 million in any
year and also allow for payment of required dividends on its Preferred Stock.
The Board of Directors has no present plans to pay dividends on Common Stock.
However, from time to time the Board of Directors reevaluates the feasibility of
declaring future dividends.
Provisions of the Senior Credit Facility require prepayments to the Term
Loans, with certain defined exceptions, in an amount equal to: (i) 100% of the
net proceeds of certain incurred indebtedness; (ii) 100% of the net proceeds
received by the Company and its subsidiaries (other than certain net proceeds
reinvested in the business of the Company or its subsidiaries) from the
disposition of any assets, including proceeds from the sale of stock of the
Company's subsidiaries; and (iii) a percentage of excess cash flow, as defined,
depending on certain credit statistics. No prepayments were required for 1998.
For further information concerning debt maturities and restrictions and
covenants, see Note D of Notes to Consolidated Financial Statements in Item 8.
CAPITAL SPENDING (EXCLUDING AMOUNTS TO FUND DOWNSTREAM ACQUISITIONS)
Capital spending in 1998 totaled $185 million which was funded from
internally-generated cash flows from operations and external financing. Capital
expenditures for the Exploration and Production segment were approximately $135
million, including $87 million for U.S. operations and $48 million for Bolivia
operations. In the U.S., capital expenditures were principally for participation
in the drilling of 26 development wells (23 completed), 19 exploratory wells (11
completed), the purchase of 28 billion cubic feet equivalent of proved reserves
and 56,000 net leased acres and seismic activity. In Bolivia, capital projects
included the drilling of three exploration wells (all successful), the
construction of gathering lines and seismic activity. Capital projects for the
Refining and Marketing segment in 1998 totaled $38 million, which included costs
of a
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long-term capital program to improve marketing operations, upgrades to the
refineries and environmental projects. In the Marine Services segment, capital
spending totaled $4 million during 1998, primarily for equipment and facilities
upgrades. Capital expenditures of $8 million for corporate projects in 1998 were
primarily directed towards the design and implementation of an integrated
enterprise-wide software system, which is expected to be completed in the fourth
quarter of 1999. An additional $12 million is expected to be spent on this
system project in 1999.
For 1999, the Company has a capital budget program totaling $170 million.
The Exploration and Production segment accounts for $75 million, or 44%, of the
budget with $50 million planned for U.S. activities and $25 million for Bolivia.
In the U.S., the Company will focus on exploration of undeveloped acreage using
3-D seismic data to increase its proved reserves. Thirty exploration wells and
15 development wells are budgeted for drilling in 1999. Other capital
investments include geophysical studies that may lead to additional discoveries
in the U.S. In Bolivia, the Company does not plan any additional drilling in
Bolivia during 1999 beyond one well in progress, and is directing the majority
of its capital program toward improving its gas processing facilities to enable
the Company to process higher production volumes expected to result when the
new, third-party Bolivia-to-Brazil pipeline begins operations expected in the
second quarter of 1999. Capital spending for the Refining and Marketing segment
is planned at $68 million, which includes $34 million for refining and
distribution projects, $19 million for retail marketing operations and $15
million for environmental and safety. The Marine Services capital budget is $7
million and is primarily directed towards facility and terminal improvements.
Corporate capital improvements are planned for $20 million in 1999, which
include the remaining costs of the integrated enterprise-wide system as well as
costs for other corporate projects. Actual capital expenditures for 1999 are
expected to be financed primarily from operating cash flows. Actual capital
expenditures may vary from these projections due to a number of factors,
including the timing of projects which could be impacted by the ability of the
Company to generate cash flows in depressed industry conditions.
CASH FLOW SUMMARY
Components of the Company's cash flows are set forth below (in millions):
1998 1997 1996
------- ------- ------
Cash Flows From (Used In):
Operating Activities...................................... $ 116.5 $ 95.6 $178.9
Investing Activities...................................... (718.6) (151.5) (94.2)
Financing Activities...................................... 606.6 41.5 (75.9)
------- ------- ------
Increase (Decrease) in Cash and Cash Equivalents............ $ 4.5 $ (14.4) $ 8.8
======= ======= ======
During 1998, net cash from operating activities totaled $116 million,
compared with $96 million in 1997. Operating cash flows in 1998 included higher
levels of earnings before noncash charges, including depreciation, depletion and
amortization and write-downs of oil and gas properties. The Company's results in
1998 included income from receipt of $21 million pretax ($14 million aftertax)
from an operator in the Bob West Field (see Note F in Notes to Consolidated
Financial Statements in Item 8). In addition, changes in working capital
components contributed positively to cash flows from operations in 1998. Net
cash used in investing activities of $719 million in 1998 included $536 million
for the Acquisitions and $185 million for capital expenditures. Net cash from
financing activities of $607 million in 1998 primarily included net proceeds of
$533 million from the issuance of equity and debt securities and $150 million
from Term Loans, partially offset by net repayments of other debt. Gross
borrowings under revolving credit lines and interim credit facility amounted to
$944 million, while repayments totaled $916 million. Payments of dividends on
preferred stock totaled $3 million in 1998. At December 31, 1998, the Company's
working capital totaled $182 million, including cash and cash equivalents of $13
million, compared with working capital of $74 million at year-end 1997. The
working capital ratio at December 31, 1998 improved to 1.9:1, compared with
1.7:1 at the end of 1997.
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During 1997, net cash from operating activities totaled $96 million, which
included $77 million from earnings before depreciation, depletion and
amortization and $7 million from favorable working capital changes. Net cash
used in investing activities of $151 million in 1997 included capital
expenditures of $93 million for exploration and production activities, $44
million for refining and marketing projects and $9 million for upgrades in
marine services. Net cash from financing activities of $41 million in 1997
included net borrowings of $28 million under the former 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 Company's former credit facility were
$150 million, with $122 million of repayments.
During 1996, net cash from operating activities totaled $179 million, which
included $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
contributed to higher cash flows from operations. Partially offsetting these
increases were higher working capital balances, particularly receivables which
increased primarily due to higher year-end sales volumes together with higher
prices. In 1996, net cash used in investing activities of $94 million included
capital expenditures of $85 million and cash consideration of nearly $8 million
for a marine services acquisition. Net cash used in financing activities of $76
million was primarily due to the redemption of 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.
ENVIRONMENTAL
The Company is subject to extensive federal, state and local environmental
laws and regulations. These laws, which change frequently, regulate the
discharge of materials into the environment and may require the Company to
remove or mitigate the environmental effects of the disposal or release of
petroleum or chemical substances at various sites or install additional controls
or other modifications or changes in use for certain emission sources. The
Company is currently involved in remedial responses and has incurred cleanup
expenditures associated with environmental matters at a number of sites,
including certain of its own properties. At December 31, 1998, the Company's
accruals for environmental expenses amounted to $9.3 million. Based on currently
available information, including the participation of other parties or former
owners in remediation actions, the Company believes these accruals are adequate.
To comply with environmental laws and regulations, the Company anticipates that
it will make capital improvements of approximately $12 million in 1999 and $5
million in 2000. In addition, capital expenditures for alternative secondary
containment systems for existing storage tank facilities are estimated to be $2
million in 1999 and $1 million in 2000 with a remaining $4 million expected to
be spent by 2002.
Conditions that require additional expenditures may exist for various
Company sites, including, but not limited to, the Company's refineries, retail
gasoline stations (operating and closed locations) and petroleum product
terminals, and for compliance with the Clean Air Act and other state and federal
regulations. The amount of such future expenditures cannot currently be
determined by the Company. For further information on environmental
contingencies, see Note M of Notes to Consolidated Financial Statements in Item
8.
YEAR 2000 READINESS DISCLOSURE
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 production and distribution,
information management services and financial reporting, as well as in various
administrative functions. The goal of the Company's Year 2000 project is to
prevent any disruption to the Company's business processes or its ability to
conduct business resulting from Year 2000 computer issues.
The Year 2000 may cause problems in systems that use dates. Many systems
such as computers, computer applications, process equipment used in refineries,
phone systems, and electrical components have embedded chips that are subject to
failure. Failures result from the practice of representing the year as a
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2-digit number, and then treating "00" as the year 1900, not 2000. Other
failures may result if the Year 2000 is not recognized as a leap year.
Disruptions may also be caused by computer failures of external sources such as
vendors, service providers and customers.
To identify and eliminate potential disruptions, the Company developed a
Year 2000 compliance plan ("Compliance Plan") with respect to those Systems and
Programs that are deemed to be critical to the Company's operations and safety.
The Compliance Plan, which covers information technology ("IT") and non-IT
aspects, is divided into the following sections: Plant Facilities (includes
non-IT embedded systems such as process control systems, environmental systems
and the physical equipment and facilities at the Company's exploration and
production locations, refineries and transportation vessels), Business Systems
(includes IT hardware, software, and network systems serving the Company's
business units), Office Facilities (includes telephone, security, and office
equipment) and External Sources (customers, suppliers and vendors).
Implementation of the Compliance Plan is led by an oversight committee,
made up of representatives from each of the Company's major facilities. The
Compliance Plan is monitored weekly and progress is reported to management and
the Board of Directors.
The Compliance Plan includes the following phases and scheduled completion
dates:
SCHEDULED
% COMPLETE COMPLETION DATE
---------- ---------------
- - Awareness: Establish a Year 2000 team and develop a detailed
plan...................................................... 100 Complete
- - Assessment: Identify critical business processes and systems
that must be modified; assess and prioritize risk
factors................................................... 100 Complete
- - Remediation: Convert, replace or eliminate hardware and
software.................................................. 80 July 1999
- - Validation: Test and verify................................. 75 July 1999
- - Implementation: Put new and renovated systems into
production; monitor and continually evaluate.............. 60 July 1999
- - Contingency Plans: Develop contingency plans for critical
items that cannot be tested............................... 10 September 1999
The Company has utilized both internal and external resources in evaluating
its Systems and Programs, as well as manual processes, external interfaces with
customers and services supplied by vendors, to identify potential Year 2000
compliance problems. The Company has identified and is replacing a number of
Systems and Programs that are not Year 2000 compliant. Based on current
information, the Company expects to attain Year 2000 compliance and complete
appropriate testing of its modifications and replacements in advance of the Year
2000 date change. Modification or replacement of the Company's Systems and
Programs is being performed in-house by Company personnel and external
consultants.
The Company believes that, with hardware replacement and modifications to
existing software or conversions to new software, the Year 2000 date change will
not pose a significant operational problem for the Company. However, because
most computer systems are, by their very nature, interdependent, 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. Approximately 3,000
questionnaires were sent to vendors who were identified as providing goods and
services to the Company's operations. Vendors were asked questions relating to
their Year 2000 preparation and readiness. Over half of the vendors either
returned the questionnaire or were contacted and interviewed personally. Of
those contacted, none could foresee that they would have a problem with the
delivery of goods or services on or after January 1, 2000. Efforts will continue
to contact the remaining critical vendors by June 1999. The utility companies
providing electricity and water to the Company's various locations were
contacted and questioned about their ability to provide uninterrupted service
and have all responded positively.
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The Company is in the process of contacting 500 key customers to determine
their Year 2000 preparation and readiness. This effort is expected to be
completed by June 1999. Although the effort of contacting key customers and
vendors is not complete, management believes that the Company's risk is minimal
as it relates to key vendors and suppliers.
The Company expects that expenses and capital expenditures associated with
the Year 2000 compliance project will not have a material effect on its
business, financial condition or results of operations. The Company spent
approximately $1 million in 1998 and expects to spend $4 million in 1999 to
become Year 2000 compliant. The costs of Year 2000 compliance are the best
estimates of the Company's management and are believed to be reasonably
accurate. In the event the Compliance Plan is not successfully or timely
implemented, the Company may need to devote more resources to the process and
additional costs may be incurred. The costs of implementing the integrated
enterprise-wide system are excluded as this system implementation was undertaken
primarily to improve business processes.
If the Company were not able to satisfactorily complete its Compliance
Plan, including identifying and resolving problems encountered by the Company's
external service providers, potential consequences could include, among other
things, unit downtime at, or damage to, the Company's refineries, gas stations,
terminal facilities and pipelines; delays in transporting refinery feedstocks
and refined products; reduction in natural gas production; impairment of
relationships with significant suppliers or customers; loss of accounting data
or delays in processing such data; and loss of or delays in internal and
external communications. The occurrence of any or all of the above could result
in a material adverse effect on the Company's results of operations, liquidity
or financial condition. Although the Company currently believes that it will
satisfactorily complete its Compliance Plan prior to January 1, 2000, there can
be no assurance that it will be completed by such time or that the Year 2000
problem will not adversely affect the Company and its business.
The foregoing statements in the above paragraphs under "Year 2000 Readiness
Disclosure" herein are intended to be and are hereby designated "Year 2000
Readiness Disclosure" statements within the meaning of the Year 2000 Information
and Readiness Disclosure Act.
NEW ACCOUNTING STANDARD
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standard ("SFAS") No. 133, "Accounting for Derivative
Instruments and Hedging Activities," which establishes accounting and reporting
standards for derivative instruments, including certain derivative instruments
embedded in other contracts and for hedging activities. SFAS No. 133 requires
that an entity recognize all derivatives as either assets or liabilities in the
statement of financial position and measure those instruments at fair value. The
accounting for changes in the fair value of a derivative depends on the intended
use of the derivative and the resulting designation. SFAS No. 133 is effective
for all quarters of fiscal years beginning after June 15, 1999 and should not be
applied retroactively to financial statements of prior periods. From time to
time, the Company enters into agreements to reduce commodity price risks. Gains
or losses on these hedging activities are recognized when the related physical
transactions are recognized as sales or purchases. The Company is evaluating the
effects that this new statement will have on its financial condition, results of
operations and financial reporting and disclosures.
FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains certain statements that are
"forward-looking" statements within the meaning of Section 27A of the Securities
Act of 1933, as amended (the "Securities Act") and Section 21E of the Securities
Exchange Act of 1934, as amended (the "Exchange Act"). These forward-looking
statements include, among other things, discussions of anticipated revenue
enhancements and cost savings following the Acquisitions, the Company's business
strategy and expectations concerning the Company's market position, future
operations, margins, profitability, liquidity and capital resources,
expenditures for capital projects and attempts to reduce costs. Although the
Company believes that the assumptions upon which the forward-looking statements
contained in this Form 10-K are based are reasonable, any of the assumptions
could prove to be inaccurate and, as a result, the forward-looking statements
based on those
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assumptions also could be incorrect. All phases of the operations of the Company
involve risks and uncertainties, many of which are outside the control of the
Company and any one of which, or a combination of which, could materially affect
the results of the Company's operations and whether the forward-looking
statements ultimately prove to be correct. Actual results and trends in the
future may differ materially depending on a variety of factors including, but
not limited to, 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; changes in the cost or availability of
third-party vessels, pipelines and other means of transporting feedstocks and
products; execution of planned capital projects; adverse changes in the credit
ratings assigned to the Company's trade credit; future well performance; the
extent of the Company's success in acquiring oil and gas properties and in
discovering, developing and producing reserves; 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;
adverse rulings, judgments, or settlements in litigation or other legal matters,
including unexpected environmental remediation costs in excess of any reserves;
actions of customers and competitors; weather conditions affecting the Company's
operations or the areas in which the Company's products are marketed;
earthquakes or other natural disasters affecting operations; political
developments in foreign countries; and the conditions of the capital markets and
equity markets during the periods covered by the forward-looking statements. All
subsequent written and oral forward-looking statements attributable to the
Company or persons acting on its behalf are expressly qualified in their
entirety by the foregoing. 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.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company utilizes various financial instruments and enters into
agreements which inherently have some degree of market risk. The primary sources
of market risk include fluctuations in commodity prices and interest rate
fluctuations.
PRICE FLUCTUATIONS
The Company's results of operations are highly dependent upon prices
received for refined products and natural gas production and on the prices paid
for crude oil and other refinery feedstocks. The volatility of prices and their
effect on the Company's earnings and cash flows are discussed in "Risk Factors
and Investment Considerations" in Item 1 and "Business Environment" in Item 7.
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 1998, 1997 and 1996, the Company used such agreements to set the
price of 13%, 9% and 30%, respectively, of the natural gas production that it
sold in the spot market. In 1998, the Company recognized a gain of $1.3 million
($0.04 per Mcf) from these price agreements. During 1997 and 1996, the effects
of natural gas price agreements resulted in losses of $1.6 million ($0.05 per
Mcf) and $3.1 million ($0.11 per Mcf), respectively. As of year-end 1998, the
Company had remaining price agreements outstanding through March 31, 1999 for
500 MMcf of natural gas production with an average Houston Ship Channel floor
price of $2.15 per Mcf and an average ceiling price of $2.59 per Mcf.
INTEREST RATE RISK
Total debt at December 31, 1998 included $211 million of floating-rate debt
attributed to the Term Loans and the Revolver and $333 million of fixed-rate
debt. As a result, the Company's annual interest cost in 1999 will fluctuate
based on short-term interest rates. The impact on annual cash flows of a 10%
change in the floating rate (approximately 70 basis points) would be
approximately $1.5 million.
At December 31, 1998, the fair market value of the Company's fixed-rate
debt approximated its book value of $333 million. The floating-rate debt will
mature over varying periods through the end of 2003. Fixed-rate debt of $297
million will mature in 2008, while other fixed-rate notes and obligations will
mature over varying periods through 2013.
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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, 1998 and 1997, and the
related statements of consolidated operations, stockholders' equity and cash
flows for each of the three years in the period ended December 31, 1998. 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, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1998 in conformity with generally accepted accounting principles.
/s/ DELOITTE & TOUCHE LLP
San Antonio, Texas
January 29, 1999
(March 25, 1999 as to Note M)
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TESORO PETROLEUM CORPORATION
STATEMENTS OF CONSOLIDATED OPERATIONS
(IN MILLIONS EXCEPT PER SHARE AMOUNTS)
YEARS ENDED DECEMBER 31,
------------------------------
1998 1997 1996
-------- ------ --------
REVENUES
Refining and marketing.................................... $1,268.0 $720.9 $ 745.4
Marine services........................................... 118.6 132.2 122.5
Exploration and production................................ 82.0 84.8 107.5
Other income.............................................. 21.7 5.5 64.4
-------- ------ --------
Total Revenues.................................... 1,490.3 943.4 1,039.8
-------- ------ --------
OPERATING COSTS AND EXPENSES
Refining and marketing.................................... 1,172.6 687.1 726.1
Marine services........................................... 107.9 124.7 115.3
Exploration and production................................ 16.2 13.2 13.0
Depreciation, depletion and amortization.................. 66.0 45.7 40.6
Write-downs of oil and gas properties..................... 68.3 -- --
-------- ------ --------
Total Operating Costs and Expenses................ 1,431.0 870.7 895.0
-------- ------ --------
SEGMENT OPERATING PROFIT.................................... 59.3 72.7 144.8
Other operating costs and expenses.......................... (7.9) -- --
General and administrative.................................. (19.7) (13.6) (12.7)
Interest and financing costs, net of capitalized interest in
1998 and 1997............................................. (33.0) (8.3) (18.2)
Interest income............................................. 2.0 1.6 8.4
Other expense, net.......................................... (16.2) (3.3) (7.2)
-------- ------ --------
EARNINGS (LOSS) BEFORE INCOME TAXES AND EXTRAORDINARY
ITEM...................................................... (15.5) 49.1 115.1
Income tax provision (benefit).............................. (0.5) 18.4 38.3
-------- ------ --------
EARNINGS (LOSS) BEFORE EXTRAORDINARY ITEM................... (15.0) 30.7 76.8
Extraordinary loss on extinguishments of debt (net of income
tax benefit of $2.6 in 1998 and $0.9 in 1996)............. (4.4) -- (2.3)
-------- ------ --------
NET EARNINGS (LOSS)......................................... (19.4) 30.7 74.5
Preferred dividend requirements............................. (6.0) -- --
-------- ------ --------
NET EARNINGS (LOSS) APPLICABLE TO COMMON STOCK.............. $ (25.4) $ 30.7 $ 74.5
======== ====== ========
NET EARNINGS (LOSS) PER SHARE -- BASIC...................... $ (0.86) $ 1.16 $ 2.87
======== ====== ========
NET EARNINGS (LOSS) PER SHARE -- DILUTED.................... $ (0.86) $ 1.14 $ 2.81
======== ====== ========
WEIGHTED AVERAGE COMMON SHARES -- BASIC..................... 29.4 26.4 26.0
======== ====== ========
WEIGHTED AVERAGE COMMON SHARES AND POTENTIALLY DILUTIVE
COMMON SHARES -- DILUTED.................................. 29.4 26.9 26.5
======== ====== ========
The accompanying notes are an integral part of these consolidated financial
statements.
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TESORO PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
(DOLLARS IN MILLIONS EXCEPT PER SHARE AMOUNTS)
DECEMBER 31,
------------------
1998 1997
-------- ------
ASSETS
CURRENT ASSETS
Cash and cash equivalents................................. $ 12.9 $ 8.4
Receivables, less allowance for doubtful accounts......... 157.5 76.3
Inventories............................................... 208.2 87.3
Prepayments and other..................................... 12.0 9.8
-------- ------
Total Current Assets................................. 390.6 181.8
-------- ------
PROPERTY, PLANT AND EQUIPMENT
Refining and marketing.................................... 841.0 370.2
Marine services........................................... 50.8 43.1
Exploration and production, full-cost method of
accounting:
Properties being amortized........................... 393.3 251.6
Properties not yet evaluated......................... 25.1 31.9
Gas transportation................................... 8.1 7.9
Corporate................................................. 21.4 13.6
-------- ------
1,339.7 718.3
Less accumulated depreciation, depletion and
amortization........................................... 445.1 304.5
-------- ------
Net Property, Plant and Equipment.................... 894.6 413.8
-------- ------
OTHER ASSETS................................................ 143.2 32.2
-------- ------
Total Assets...................................... $1,428.4 $627.8
======== ======
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable.......................................... $ 126.4 $ 58.8
Accrued liabilities....................................... 69.3 31.7
Current maturities of long-term debt and other
obligations............................................ 12.5 17.0
-------- ------
Total Current Liabilities............................ 208.2 107.5
-------- ------
DEFERRED INCOME TAXES....................................... 69.9 28.8
-------- ------
OTHER LIABILITIES........................................... 59.7 43.2
-------- ------
LONG-TERM DEBT AND OTHER OBLIGATIONS, LESS CURRENT
MATURITIES................................................ 531.4 115.3
-------- ------
COMMITMENTS AND CONTINGENCIES (Note M)
STOCKHOLDERS' EQUITY
Preferred stock, no par value; authorized 5,000,000
shares:
7.25% Mandatorily Convertible Preferred Stock, 103,500
shares issued and outstanding in 1998.................. 165.0 --
Common stock, par value $0.16 2/3; authorized 100,000,000
shares (50,000,000 in 1997); 32,654,138 shares issued
(26,506,601 in 1997)................................... 5.4 4.4
Additional paid-in capital................................ 278.6 190.9
Retained earnings......................................... 115.6 141.0
Treasury stock, 320,022 common shares (216,453 in 1997),
at cost................................................ (5.4) (3.3)
-------- ------
Total Stockholders' Equity........................... 559.2 333.0
-------- ------
Total Liabilities and Stockholders' Equity........ $1,428.4 $627.8
======== ======
The accompanying notes are an integral part of these consolidated financial
statements.
52
53
TESORO PETROLEUM CORPORATION
STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY
(IN MILLIONS)
PREFERRED STOCK COMMON STOCK ADDITIONAL TREASURY STOCK
--------------- --------------- PAID-IN RETAINED ---------------
SHARES AMOUNT SHARES AMOUNT CAPITAL EARNINGS SHARES AMOUNT
------ ------ ------ ------ ---------- -------- ------ ------
BALANCE AT JANUARY 1, 1996.............. -- $ -- 24.8 $4.1 $176.6 $ 35.8 -- $ --
Net earnings.......................... -- -- -- -- -- 74.5 -- --
Issuance of Common Stock.............. -- -- 1.3 0.2 11.1 -- -- --
Other, primarily exercise of stock
options and awards................. -- -- 0.3 0.1 1.7 -- -- --
--- ------ ---- ---- ------ ------ ---- -----
BALANCE AT DECEMBER 31, 1996............ -- -- 26.4 4.4 189.4 110.3 -- --
Net earnings.......................... -- -- -- -- -- 30.7 -- --
Shares repurchased.................... -- -- -- -- -- -- (0.2) (3.7)
Other, primarily exercise of stock
options and awards................. -- -- 0.1 -- 1.5 -- -- 0.4
--- ------ ---- ---- ------ ------ ---- -----
BALANCE AT DECEMBER 31, 1997............ -- -- 26.5 4.4 190.9 141.0 (0.2) (3.3)
Net loss.............................. -- -- -- -- -- (19.4) -- --
Preferred dividend requirements....... -- -- -- -- -- (6.0) -- --
Issuance of Common Stock.............. -- -- 5.7 0.9 85.8 -- -- --
Issuance of Preferred Stock........... 0.1 165.0 -- -- (5.7) -- -- --
Other, primarily related to shares
issued under special incentive
strategy........................... -- -- 0.4 0.1 7.6 -- (0.1) (2.1)
--- ------ ---- ---- ------ ------ ---- -----
BALANCE AT DECEMBER 31, 1998............ 0.1 $165.0 32.6 $5.4 $278.6 $115.6 (0.3) $(5.4)
=== ====== ==== ==== ====== ====== ==== =====
The accompanying notes are an integral part of these consolidated financial
statements.
53
54
TESORO PETROLEUM CORPORATION
STATEMENTS OF CONSOLIDATED CASH FLOWS
(IN MILLIONS)
YEARS ENDED DECEMBER 31,
--------------------------
1998 1997 1996
------- ------- ------
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES
Net earnings (loss)....................................... $ (19.4) $ 30.7 $ 74.5
Adjustments to reconcile net earnings to net cash from
operating activities:
Depreciation, depletion and amortization............... 67.1 46.4 41.5
Write-downs of oil and gas properties.................. 68.3 -- --
Amortization of goodwill and deferred charges.......... 4.0 1.0 1.6
Extraordinary loss on extinguishments of debt, net of
income tax benefit................................... 4.4 -- 2.3
Other noncash charges, including noncash portion of
special incentive compensation and loss on sales of
assets............................................... 9.6 0.5 0.8
Changes in operating assets and liabilities:
Receivables.......................................... (31.0) 56.8 8.1
Inventories.......................................... 1.6 (11.5) 7.2
Other assets......................................... (13.7) 0.3 (3.5)
Accounts payable and accrued liabilities............. 39.4 (37.9) 28.1
Deferred income taxes................................ (11.4) 9.7 14.6
Obligation payments to State of Alaska............... (3.0) (4.4) (4.0)
Other liabilities and obligations.................... 0.6 4.0 7.7
------- ------- ------
Net cash from operating activities................ 116.5 95.6 178.9
------- ------- ------
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES
Capital expenditures...................................... (185.1) (147.5) (85.0)
Acquisitions.............................................. (536.5) (5.1) (7.7)
Proceeds from sales of assets............................. 3.2 0.1 2.6
Other..................................................... (0.2) 1.0 (4.1)
------- ------- ------
Net cash used in investing activities............. (718.6) (151.5) (94.2)
------- ------- ------
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES
Proceeds from equity offerings, net....................... 246.0 -- --
Proceeds from debt offerings, net......................... 286.7 -- --
Borrowings under term loans............................... 150.0 -- --
Refinancing and repayments of debt and obligations........ (93.3) (4.1) (77.9)
Borrowings under revolving credit and interim facilities,
net of repayments...................................... 27.6 32.7 0.9
Issuance of other long-term debt.......................... -- 16.2 --
Payment of dividends on Preferred Stock................... (3.0) -- --
Repurchase of Common Stock................................ -- (3.7) --
Financing costs and other................................. (7.4) 0.4 1.1
------- ------- ------
Net cash from (used in) financing activities...... 606.6 41.5 (75.9)
------- ------- ------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS............ 4.5 (14.4) 8.8
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR................ 8.4 22.8 14.0
------- ------- ------
CASH AND CASH EQUIVALENTS, END OF YEAR...................... $ 12.9 $ 8.4 $ 22.8
======= ======= ======
SUPPLEMENTAL CASH FLOW DISCLOSURES
Interest paid, net of capitalized interest of $0.1 in 1998
and $0.4 in 1997........................................ $ 12.0 $ 2.1 $ 12.5
======= ======= ======
Income taxes paid......................................... $ 16.4 $ 22.4 $ 6.3
======= ======= ======
The accompanying notes are an integral part of these consolidated financial
statements.
54
55
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,
distribution and marketing of petroleum products, marine logistics services and
the exploration for and production of natural gas and oil.
Use of Estimates and Presentation
Preparation of the Company's Consolidated Financial Statements in
conformity with generally accepted accounting principles requires the use of
management's best estimates and judgment that affect the reported amounts of
assets and liabilities and disclosures of contingent assets and liabilities at
the date of the financial statements and the reported amounts of revenues and
expenses during the year. Actual results could differ from those estimates.
Certain reclassifications have been made to information previously reported
to conform to current presentation.
Cash and Cash Equivalents
Cash equivalents consist of highly-liquid debt instruments such as
commercial paper and certificates of deposit purchased with an original maturity
date of three months or less. Cash equivalents are stated at cost, which
approximates market value. The Company's policy is to invest cash in
conservative, highly-rated instruments and to invest in various institutions to
limit the amount of credit exposure in any one institution. The Company performs
ongoing evaluations of the credit standing of these financial institutions.
Financial Instruments
The carrying amounts of financial instruments, including cash and cash
equivalents, accounts receivable, accounts payable and certain accrued
liabilities, approximate fair value because of the short maturity of these
instruments. The carrying amounts of the Company's long-term debt and other
obligations approximate the Company's estimates of the fair value of such items.
Inventories
Inventories are stated at the lower of cost or market. The last-in,
first-out ("LIFO") method is 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 services terminals, is determined principally on the
first-in, first-out ("FIFO") method. The carrying value of petroleum inventories
is sensitive to volatile market prices. Merchandise and materials and supplies
are valued at average cost, not in excess of market value. See Note I.
Property, Plant and Equipment
Additions to property, plant and equipment and major improvements and
modifications are capitalized at cost. Depletion of oil and gas producing
properties is determined principally by the unit-of-production method and is
based on estimated proved 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 8
to 30 years for refining, marketing and pipeline assets, 13 to 15 years for
service equipment and marine fleets, and three to seven years for corporate and
other assets.
55
56
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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. Capitalized costs within a
cost center, together with estimates of costs for future development,
dismantlement and abandonment, are amortized by the unit-of-production method
using the proved oil and gas reserves for each cost center. The Company's
investment in certain oil and gas properties is excluded from the amortization
base until the properties are evaluated. Gain or loss is recognized only on the
sale of oil and gas properties involving significant reserves. Proceeds from the
sale of insignificant reserves and undeveloped properties are applied to reduce
the costs in the cost centers. 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 unevaluated
properties included in the cost center. See Notes E and O for write-downs of oil
and gas properties in 1998. It is reasonably possible that the present value of
future net revenues from estimated production of proved oil and gas reserves
could be significantly reduced due to further decreases in oil and natural gas
prices since 1998 year-end. This could result in further write-downs of
capitalized costs of oil and gas properties in the near term.
Other Assets
The cost over the fair value of net assets acquired (goodwill) is amortized
by the straight-line method over 28 years for refining and marketing assets and
20 years for marine services assets.
Debt issue costs are deferred and amortized using the effective interest
method over the estimated terms of each instrument.
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 extend the life or increase the capacity of
facilities, or expenditures that mitigate or prevent environmental contamination
that is yet to occur, are capitalized. Expenditures that relate to an existing
condition caused by past operations, and which do not contribute to current or
future revenue generation, are expensed. Liabilities are recorded when
environmental assessments and/or remedial efforts are probable. Cost estimates
are based on the expected timing and extent of remedial actions required by
applicable governing agencies, experience gained from similar sites on which
environmental assessments or remediation have been completed, and the amount of
the Company's anticipated liability considering the proportional liability and
financial abilities of other responsible parties. Generally, the timing of these
accruals coincides with the completion of a feasibility study or the Company's
commitment to a formal plan of action. Estimated liabilities are not discounted
to present value.
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
56
57
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
pay to acquire the stock, except for stock options granted under the special
incentive compensation which became fully vested in May 1998 (see Note L).
New Accounting Standards
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standard ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities," which establishes accounting and
reporting standards for derivative instruments, including certain derivative
instruments embedded in other contracts and for hedging activities. SFAS No. 133
requires that an entity recognize all derivatives as either assets or
liabilities in the statement of financial position and measure those instruments
at fair value. The accounting for changes in the fair value of a derivative
depends on the intended use of the derivative and the resulting designation.
SFAS No. 133 is effective for all quarters of fiscal years beginning after June
15, 1999 and should not be applied retroactively to financial statements of
prior periods. From time to time, the Company enters into agreements to reduce
commodity price risks. Gains or losses on these hedging activities are
recognized when the related physical transactions are recognized as sales or
purchases. The Company is evaluating the effects that this new statement will
have on its financial condition, results of operations and financial reporting
and disclosures.
In 1998, the Company adopted SFAS No. 130, "Reporting Comprehensive
Income," which established standards for reporting and displaying comprehensive
income and its components in the financial statements. The Company did not have
any material amounts which would be reported separately from net income as
"other comprehensive income."
57
58
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE B -- EARNINGS PER SHARE
Basic earnings per share is determined by dividing net earnings applicable
to Common Stock 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. The assumed conversion of Preferred
Stock to 8.75 million shares of Common Stock, or a weighted average of 4.37
million for the year ended December 31, 1998, produced an anti-dilutive result
and, in accordance with SFAS No. 128, was not included in the dilutive
calculation. Earnings (loss) per share calculations for the years ended December
31, 1998, 1997 and 1996 are presented below (in millions except per share
amounts):
1998 1997 1996
------- ------ ------
BASIC:
Numerator:
Earnings (loss) before extraordinary item.............. $ (15.0) $ 30.7 $ 76.8
Extraordinary loss on extinguishments of debt, after
tax.................................................. (4.4) -- (2.3)
------- ------ ------
Net earnings (loss).................................... (19.4) 30.7 74.5
Less preferred dividends............................... 6.0 -- --
------- ------ ------
Net earnings (loss) applicable to common shares........ $ (25.4) $ 30.7 $ 74.5
======= ====== ======
Denominator:
Weighted average common shares outstanding............. 29.4 26.4 26.0
======= ====== ======
Basic earnings (loss) per share:
Before extraordinary item.............................. $ (0.71) $ 1.16 $ 2.96
Extraordinary loss, after tax.......................... (0.15) -- (0.09)
------- ------ ------
Net.................................................... $ (0.86) $ 1.16 $ 2.87
======= ====== ======
DILUTED:
Numerator:
Net earnings (loss) applicable to common shares........ $ (25.4) $ 30.7 $ 74.5
Plus income impact of assumed conversions of preferred
stock (only if dilutive)............................. -- -- --
------- ------ ------
Net earnings (loss).................................... $ (25.4) $ 30.7 $ 74.5
======= ====== ======
Denominator:
Weighted average common shares outstanding............. 29.4 26.4 26.0
Add potential dilutive securities:
Incremental dilutive shares from assumed conversion
of stock options and other (only if dilutive)..... -- 0.5 0.5
Incremental dilutive shares from assumed conversion
of preferred stock (only if dilutive)............. -- -- --
------- ------ ------
Total diluted shares................................... 29.4 26.9 26.5
======= ====== ======
Diluted earnings (loss) per share:
Before extraordinary item............................ $ (0.71) $ 1.14 $ 2.90
Extraordinary loss, after tax........................ (0.15) -- (0.09)
------- ------ ------
Net............................................... $ (0.86) $ 1.14 $ 2.81
======= ====== ======
58
59
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE C -- ACQUISITIONS AND EXPANSIONS
Acquisitions of Hawaii Refinery and Washington Refinery
On May 29, 1998, the Company acquired (the "Hawaii Acquisition") all of the
outstanding capital stock of BHP Petroleum Americas Refining Inc. and BHP
Petroleum South Pacific Inc. (together, "BHP Hawaii") from BHP Hawaii Inc. and
BHP Petroleum Pacific Islands Inc. ("BHP Sellers"), affiliates of The Broken
Hill Proprietary Company Limited ("BHP"). The Hawaii Acquisition included a
95,000-barrel per day refinery (the "Hawaii Refinery") and 32 retail gasoline
stations in Hawaii. Tesoro and a BHP affiliate entered into a two-year crude
supply agreement pursuant to which the BHP affiliate will assist Tesoro in
acquiring crude oil feedstocks sourced outside of North America and arrange for
the transportation of such crude oil to the Hawaii Refinery. Tesoro paid $252.2
million in cash for the Hawaii Acquisition, including $77.2 million for working
capital. In addition, Tesoro issued an unsecured, non-interest bearing,
promissory note ("BHP Note") for $50 million. The present value of the BHP Note
amounted to $17.4 million, after the accelerated payment provision (see Note D),
and was recorded as part of the purchase price.
On August 10, 1998, the Company acquired (the "Washington Acquisition" and
together with the Hawaii Acquisition, the "Acquisitions") all of the outstanding
stock of Shell Anacortes Refining Company ("Shell Washington"), an affiliate of
Shell Oil Company ("Shell"). The Washington Acquisition included a
108,000-barrel per day refinery (the "Washington Refinery") in Anacortes,
Washington and related assets. The total cash purchase price for the Washington
Acquisition was $280.1 million, including $43.1 million for working capital.
The Acquisitions were accounted for as purchases whereby the purchase
prices were allocated to the assets acquired and liabilities assumed based upon
their respective fair market values at the dates of acquisition. Under purchase
accounting, financial results of the Acquisitions have been included in Tesoro's
consolidated financial statements since the dates of acquisition. Had these
results been included in Tesoro's results since January 1, 1997, and the
Refinancing and Offerings completed (as defined in Note D below), Tesoro's
consolidated results for the years ended December 31, 1998 and 1997, on a pro
forma basis, would have been as follows (in millions except per share amounts):
1998 1997
-------- --------
(UNAUDITED)
Revenues.................................................... $2,270.8 $2,980.4
Earnings (loss) before extraordinary item................... $ (12.0) $ 30.5
Net earnings (loss)......................................... $ (16.4) $ 30.5
Earnings (loss) per share -- basic.......................... $ (0.88) $ 0.58
Earnings (loss) per share -- diluted........................ $ (0.88) $ 0.57
The 1998 extraordinary loss on extinguishment of debt amounted to $0.14 per
share (basic and diluted) on a proforma basis.
See Note D for information related to financing the Acquisitions and Note M
for related environmental matters.
Alaska Refining and Marketing
In October 1997, the Company completed an expansion of its Alaska refinery
hydrocracker unit which enabled 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.
In December 1997, the Company 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.
59
60
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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. Subsequent to the acquisition, Tesoro repaid approximately
$4.5 million of Coastwide's outstanding debt. The acquired operations provide
logistical support services and distribute petroleum products to the offshore
oil and gas industry in the Gulf of Mexico. 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.
Exploration and Production
In September 1998, the Company purchased oil and gas assets for $10
million, which included working interests in producing wells and undeveloped
acreage in the Morrow gas play located in Wheeler County in the Texas Panhandle,
together with undeveloped acres in prospective areas of the onshore Texas Gulf
Coast. In August 1998, the Company purchased a working interest in the Stiles
Ranch Field, located in Wheeler County in the Texas Panhandle, for $8 million in
cash plus the conveyance of a working interest in an undeveloped prospect owned
by the Company in South Texas. Also in 1998, the Company acquired additional
undeveloped acreage for $6 million, located primarily in the onshore Gulf Coast
of Texas and in Wheeler County in the Texas Panhandle.
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 $3.3 million for undeveloped acreage with the
remainder for working capital and assumption of certain liabilities.
In the U.S., the Company purchased proved and unproved properties totaling
$22 million during 1997. These purchases included interests in fields in
southern Louisiana, South Texas and East Texas. During 1996, the Company
acquired proved and unproved properties totaling $25.7 million in South Texas
and East Texas.
For further information related to exploration and production activities,
see Note O.
NOTE D -- CAPITALIZATION
Credit Facility
In conjunction with closing the Hawaii Acquisition (see Note C) on May 29,
1998, Tesoro refinanced substantially all of its then-existing indebtedness
("Refinancing"). The Company recorded an extraordinary loss on early
extinguishment of debt of approximately $7.0 million pretax ($4.4 million
aftertax, or $0.15 per basic and diluted share) for the Refinancing during the
second quarter of 1998.
The total amount of funds required by Tesoro to complete the Hawaii
Acquisition and the Refinancing, to pay related fees and expenses and for
general corporate purposes was financed through a secured credit facility
("Interim Credit Facility"), which replaced the Company's previous corporate
revolving credit agreement. In the third quarter of 1998, the Company refinanced
all borrowings under the Interim Credit Facility with net proceeds from the
Offerings (as defined below) and borrowings under the Senior Credit Facility (as
defined below).
On July 2, 1998, and in connection with the Notes Offering (defined below)
and the Washington Acquisition, the Company entered into a senior credit
facility ("Senior Credit Facility") in the amount of $500 million. The Senior
Credit Facility is comprised of term loan facilities aggregating $200 million
(the "Tranche A Term Loans" and the "Tranche B Term Loan," collectively, the
"Term Loans") and a
60
61
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
$300 million revolving credit and letter of credit facility ("Revolver"). The
Senior Credit Facility is guaranteed by substantially all of the Company's
active direct and indirect subsidiaries ("Guarantors") and is secured by
substantially all of the domestic assets of the Company and each of the
Guarantors. At December 31, 1998, the Company had outstanding borrowings of
$149.5 million under the Term Loans and $61.2 million under the Revolver.
Outstanding letters of credit totaled $14 million at December 31, 1998. Unused
availability under the Senior Credit Facility and Term Loans was approximately
$275 million at December 31, 1998. On January 4, 1999, the final $50 million
tranche under the Term Loans was borrowed and used to reduce borrowings under
the Revolver. The Revolver terminates on July 2, 2001, while the Term Loans
mature in varying quarterly installments through 2003. Maturities under the
Tranche A Term Loans, including the final $50 million borrowed in 1999,
aggregate to $10.0 million, $22.5 million, $25.0 million, $27.5 million and
$15.0 million in 1999, 2000, 2001, 2002 and 2003, respectively. Maturities of
outstanding borrowings under the Tranche B Term Loan equal $1 million annually
in 1999 through 2002 and $95.5 million in 2003.
The Senior Credit Facility requires the Company to maintain specified
levels of consolidated leverage and interest coverage and contains other
covenants and restrictions customary in credit arrangements of this kind. The
Company was in compliance with these covenants at December 31, 1998. Future
compliance with financial covenants under the Senior Credit Facility is
primarily dependent on the Company's cash flows and levels of borrowings under
the Revolver. Based on market conditions in the first quarter of 1999, including
depressed natural gas prices and downturn in refinery margins, continued
compliance with such covenants is not assured. If the Company is not able to
continue to comply with its financial covenants, it will be required to seek
waivers or amendments from its lenders. If such an event occurs, management of
the Company believes that it will be able to obtain waivers and/or negotiate
terms and conditions with its lenders under the Senior Credit Facility which
will allow the Company to adequately finance its operations.
The Revolver and the Tranche A Term Loans bear interest, at the Company's
election, at either the Base Rate (as defined in the Senior Credit Facility)
plus a margin ranging from 0.00% to 0.625% or the Eurodollar Rate (as defined in
the Senior Credit Facility) plus a margin ranging from 1.125% to 2.125%. The
Tranche B Term Loan bears interest, at the Company's election, at either the
Base Rate plus a margin ranging from 0.50% to 0.625% or the Eurodollar Rate plus
a margin ranging from 2.00% to 2.125%. At December 31, 1998, the interest rates
were 7.75% on the Revolver, 6.315% on the Tranche A Term Loans and 7.19% on the
Tranche B Term Loan.
The terms of the Senior Credit Facility allow for payment of cash dividends
on the Company's Common Stock not to exceed an aggregate of $10 million in any
year and also allow for payment of required dividends on its 7.25% Mandatorily
Convertible Preferred Stock.
Provisions of the Senior Credit Facility require prepayments to the Term
Loans, with certain defined exceptions, in an amount equal to: (i) 100% of the
net proceeds of certain incurred indebtedness; (ii) 100% of the net proceeds
received by the Company and its subsidiaries (other than certain net proceeds
reinvested in the business of the Company or its subsidiaries) from the
disposition of any assets, including proceeds from the sale of stock of the
Company's subsidiaries; and (iii) a percentage of excess cash flow, as defined,
depending on certain credit statistics. No prepayments were required for 1998.
Senior Subordinated Notes
On July 2, 1998, concurrently with the syndication of the Senior Credit
Facility, the Company issued $300 million aggregate principal amount of 9%
senior subordinated notes due 2008 through a private offering ("Notes
Offering"). Each $1,000 principal amount of its unregistered and outstanding
senior subordinated notes due 2008 was exchanged for $1,000 principal amount of
the Company's registered 9% Senior Subordinated Notes due 2008, Series B
("Senior Subordinated Notes") in September 1998. The Senior Subordinated Notes
have a ten-year maturity without sinking fund requirements and are subject to
optional redemption by the Company after five years at declining premiums. The
indenture ("Indenture") for the
61
62
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Senior Subordinated Notes contains covenants and restrictions which are
customary for notes of this nature. The restrictions under the Indenture are
less restrictive than those in the Senior Credit Facility. To the extent the
Company's fixed charge coverage ratio, as defined in the Indenture, allows for
the incurrence of additional indebtedness, the Company will be allowed to pay
cash dividends on Common Stock. The effective interest rate on the Senior
Subordinated Notes is 9.16%, after giving effect to the discount at the date of
issue.
Common Stock and Preferred Stock
On May 14, 1998, the Company filed a universal shelf registration statement
("Shelf Registration") for $600 million of debt or equity securities for
acquisitions or general corporate purposes. The Company offered Premium Income
Equity Securities ("PIES") and Common Stock (collectively, the "Equity
Offerings" and together with the Notes Offering, the "Offerings") from the Shelf
Registration to provide partial funding for the Acquisitions discussed in Note
C. On July 1, 1998, the Company issued 9,000,000 PIES, representing fractional
interests in the Company's 7.25% Mandatorily Convertible Preferred Stock
("Preferred Stock"), with gross proceeds of approximately $143.4 million, and
5,000,000 shares of Common Stock, with gross proceeds of $79.7 million. Upon
exercise of the over-allotment options granted to the underwriters of the Equity
Offerings, on July 8, 1998, the Company issued 1,350,000 PIES with gross
proceeds of $21.5 million and 750,000 shares of Common Stock with gross proceeds
of $11.9 million. Holders of PIES are entitled to receive a cash dividend. The
PIES will automatically convert into shares of Common Stock on July 1, 2001, at
a rate based upon a formula dependent upon the market price of Common Stock.
Before July 1, 2001, each PIES is convertible, at the option of the holder
thereof, into 0.8455 shares of Common Stock, subject to adjustment in certain
events, such as Common Stock splits and stock dividends.
In connection with filing the Shelf Registration in May 1998, the Company's
Board of Directors approved terminating a repurchase program for Tesoro's Common
Stock that was initiated in May 1997. Under that program in 1997, the Company
used cash flows of $3.7 million to repurchase 236,800 shares of Common Stock.
For information relating to stock-based compensation and Common Stock
reserved for exercise of options and conversion of Preferred Stock, see Note L.
BHP Note
In connection with the Hawaii Acquisition (Note C), Tesoro issued an
unsecured, non-interest bearing, promissory note ("BHP Note") for the purchase
in the amount of $50 million, payable in five equal annual installments of $10
million each, beginning in 2009. The BHP Note provides for early payments to the
extent of one-half of the amount by which earnings from the Hawaii Acquisition,
before interest expense, income taxes and depreciation and amortization, as
specified in the BHP Note, exceed $50 million in any calendar year. Based on
1998 earnings from the Hawaii Acquisition, an early principal payment will be
made on the BHP Note in 1999. The present value of the BHP Note, discounted at
10% and including the effect of the early principal payment, was recorded as
part of the purchase price of the Hawaii Acquisition. The future effects of any
additional accelerated payments under the BHP Note, if required, would be
accounted for as additional cost of the acquired assets and amortized over the
remaining life of the assets.
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 was 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 Alaska refinery crude unit. In 1997,
based on a per barrel throughput charge of 24 cents, the Company's variable
payment to the State totaled $4.4 million. In 1998, based on a per barrel
throughput charge of 30 cents, the Company's variable payments to the State
totaled
62
63
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
$3.0 million. The per barrel charge increased to 30 cents in 1998 with one cent
annual incremental increases thereafter through 2001. The Agreement obligated
the Company to pay the State $60 million in January 2002; provided, however,
that such payment could 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. Under
the Agreement, variable monthly payments made after January 2002 would 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%.
Beginning June 1, 1998, the State released the Company from all payment
obligations, and all mortgages, liens and security interests in connection
therewith, under the Agreement in exchange for a payment of $66.1 million. The
Company is only obligated to continue payment of the per barrel throughput
charge through 2001 with respect to barrels of feedstock processed at the
refinery which exceed 50,000 barrels per day on a monthly basis, subject to
available credits (as defined in the Agreement) for amounts by which the barrels
of feedstock processed average less than 50,000 barrels per day on a monthly
basis.
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, 1998, the Company's remaining obligation is to pay the
DOE $7.9 million, plus interest at 6%, over the next four years.
Hydrocracker Unit and Vacuum Unit Loans
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 Alaska refinery hydrocracker
expansion (see Note C). In 1994, NBA and the AIDEA provided a $15 million loan
to the Company towards the cost of the Company's Alaska refinery vacuum unit
("Vacuum Unit Loan"). The Hydrocracker Unit Loan and Vacuum Unit Loan were
repaid and terminated on May 29, 1998, in connection with the Refinancing
described above.
Capital Leases
Capital leases are primarily for tugs and barges used in transportation of
petroleum products within Hawaii. At December 31, 1998, the cost of capital
leases included in fixed assets was $9.3 million and the related accumulated
amortization was $0.9 million. Capital lease obligations included in long-term
debt totaled $9.8 million and $1.6 million at December 31, 1998 and 1997,
respectively.
1996 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. The redemption was accounted for as
an early extinguishment of debt in the 1996 third quarter, resulting in a pretax
charge of $3.2 million ($2.3 million aftertax) which represented a write-off of
unamortized bond discount and issue costs.
63
64
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Summary Table of Long-Term Debt and Other Obligations
Long-term debt and other obligations at December 31, 1998 and 1997
consisted of the following (in millions):
1998 1997
------ ------
Credit Facilities:
Revolving credit lines.................................... $ 61.2 $ 33.6
Tranche A Term Loan....................................... 50.0 --
Tranche B Term Loan....................................... 99.5 --
9% Senior Subordinated Notes (net of discount of $3.1)...... 296.9 --
BHP Note (net of discount of $31.8)......................... 18.2 --
Liability to State of Alaska................................ -- 62.0
Liability to Department of Energy........................... 7.9 9.2
Hydrocracker Loan........................................... -- 16.2
Vacuum Unit Loan............................................ -- 9.1
Other, primarily capital leases............................. 10.2 2.2
------ ------
543.9 132.3
Less current maturities..................................... 12.5 17.0
------ ------
Long-term debt, less current maturities..................... $531.4 $115.3
====== ======
At December 31, 1998, aggregate maturities of outstanding long-term debt
and other obligations, including the Term Loans and Revolver, for each of the
five years following December 31, 1998 were as follows: 1999 - $12.5 million;
2000 - $14.6 million; 2001 - $78.5 million; 2002 - $18.4 million; and 2003 -
$104.1 million.
NOTE E -- OPERATING SEGMENTS
The Company's revenues are derived from three operating segments: Refining
and Marketing, Marine Services and Exploration and Production. Management has
identified these segments for managing operations and investing activities. The
segments are organized primarily by petroleum industry classification as
upstream (Exploration and Production) and downstream (Refining and Marketing,
and Marine Services). These classifications represent significantly different
activities with respect to investment, asset development, asset valuations,
production, maintenance, supply and market distribution. The downstream
businesses are organized into two operating segments representing (i) the
manufacturing and marketing of refined products and (ii) product distribution
and logistics services provided to the marine industry.
Refining and Marketing
Refining and Marketing operates three petroleum refineries located in
Alaska, Hawaii and Washington, which manufacture gasoline and gasoline
components, 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, the Pacific
Northwest, Hawaii and American Samoa. In addition, Refining and Marketing
markets gasoline, other petroleum products and convenience store items through
Company-operated retail stations in Alaska and Hawaii. Refining and Marketing
also markets petroleum products through branded and unbranded stations located
in Alaska, Hawaii, American Samoa and the Pacific Northwest. Revenues from
export sales, primarily to Far East markets, amounted to $35.5 million, $16.1
million and $22.0 million in 1998, 1997 and 1996, respectively. The Company at
times resells previously purchased crude oil, sales of which amounted to $29.9
million, $44.4 million and $93.8 million in 1998, 1997 and 1996, respectively.
See Note C for information related to Acquisitions in this segment during 1998.
64
65
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Marine Services
The Marine Services segment markets and distributes petroleum products,
water, drilling mud, and other supplies and services primarily to the marine and
offshore exploration and production industries operating in the Gulf of Mexico.
This segment currently operates through terminals along the Texas and Louisiana
Gulf Coast and on the U.S. West Coast.
Exploration and Production
The Exploration and Production segment is engaged in the exploration,
production and development of natural gas and oil 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 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. A new, third-party
pipeline that will link Bolivia's gas reserves with markets in Brazil is
expected to begin operations in the second quarter of 1999.
In Exploration and Production, segment operating profit in 1998 included
fourth quarter write-downs of oil and gas properties totaling $68.3 million in
1998 ($28.4 million in the U.S. and $39.9 million in Bolivia) and other income
of $21.3 million in the second quarter representing funds received from an
operator that were no longer needed as a contingency reserve for litigation.
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. Segment operating profit in 1996 included $60
million of other income from termination of a natural gas contract and $5
million from retroactive severance tax refunds. In 1996, Exploration and
Production's segment operating profit also included $24.6 million from the
excess of natural gas contract prices over spot market prices (see Note F).
Other
Segment operating profit includes those revenues and expenses that are
directly attributable to management of the respective segment. For the years
presented, revenues were generated from sales to external customers, and
intersegment revenues were not significant. Income taxes, interest and financing
costs, interest income and corporate general and administrative expenses are not
included in determining segment operating profit. Corporate and unallocated
costs in 1998 included $19.9 million for special incentive compensation (see
Note L) and $33.0 million from interest and financing costs primarily related to
the Acquisitions (see Notes C and D).
EBITDA represents earnings before extraordinary items, interest and
financing costs expense, income taxes, write-downs of oil and gas properties 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. Operating segment EBITDA is equal to segment operating
profit before depreciation, depletion and amortization related to each segment.
65
66
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Identifiable assets are those assets utilized by the segment. Corporate
assets are principally cash and other assets that are not directly associated
with the operations of a business segment. Segment information for the three
years ended December 31, 1998 is as follows (in millions):
1998 1997 1996
-------- ------ --------
REVENUES
Gross operating revenues:
Refining and Marketing --
Refined products..................................... $1,198.2 $643.7 $ 620.8
Other, primarily crude oil resales and merchandise... 69.8 77.2 124.6
Marine Services........................................ 118.6 132.2 122.5
Exploration and Production --
U.S., including gas transportation................... 71.5 73.6 93.8
Bolivia.............................................. 10.5 11.2 13.7
-------- ------ --------
Total Gross Operating Revenues....................... 1,468.6 937.9 975.4
Other income.............................................. 21.7 5.5 64.4
-------- ------ --------
Total Revenues.................................... $1,490.3 $943.4 $1,039.8
======== ====== ========
SEGMENT OPERATING PROFIT (LOSS)
Refining and Marketing.................................... $ 69.7 $ 20.5 $ 6.0
Marine Services........................................... 8.6 6.3 6.1
Exploration and Production --
U.S., including gas transportation, before
write-down........................................... 45.9 37.3 123.9
Bolivia before write-down.............................. 3.4 8.6 8.8
Write-downs of oil and gas properties.................. (68.3) -- --
-------- ------ --------
Total Segment Operating Profit....................... 59.3 72.7 144.8
Corporate and Unallocated Costs........................... (74.8) (23.6) (29.7)
-------- ------ --------
Earnings (Loss) Before Income Taxes and Extraordinary
Item................................................... $ (15.5) $ 49.1 $ 115.1
======== ====== ========
EBITDA
Refining and Marketing.................................... $ 94.8 $ 33.2 $ 18.5
Marine Services........................................... 11.0 8.0 7.3
Exploration and Production --
U.S. .................................................. 81.8 67.1 149.5
Bolivia................................................ 6.0 10.1 10.1
-------- ------ --------
Total Operating Segment EBITDA....................... 193.6 118.4 185.4
Corporate and Unallocated................................. (40.7) (14.6) (10.6)
-------- ------ --------
Total Consolidated EBITDA............................ 152.9 103.8 174.8
Depreciation, Depletion and Amortization(a)............... (135.4) (46.4) (41.5)
Interest and Financing Costs.............................. (33.0) (8.3) (18.2)
-------- ------ --------
Earnings (Loss) Before Income Taxes and Extraordinary
Item................................................... $ (15.5) $ 49.1 $ 115.1
======== ====== ========
IDENTIFIABLE ASSETS
Refining and Marketing.................................... $1,077.7 $337.4 $ 317.0
Marine Services........................................... 59.2 59.3 56.0
Exploration and Production --
U.S., including gas transportation..................... 175.8 158.2 143.6
Bolivia................................................ 58.9 50.8 27.0
Corporate................................................. 56.8 22.1 39.0
-------- ------ --------
Total Assets........................................... $1,428.4 $627.8 $ 582.6
======== ====== ========
66
67
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1998 1997 1996
-------- ------ --------
DEPRECIATION, DEPLETION AND AMORTIZATION
Refining and Marketing.................................... $ 25.1 $ 12.7 $ 12.5
Marine Services........................................... 2.4 1.7 1.2
Exploration and Production --
U.S., including gas transportation(a).................. 64.3 29.8 25.6
Bolivia(a)............................................. 42.5 1.5 1.3
Corporate................................................. 1.1 0.7 0.9
-------- ------ --------
Total Depreciation, Depletion and Amortization......... $ 135.4 $ 46.4 $ 41.5
======== ====== ========
CAPITAL EXPENDITURES
Refining and Marketing(b)................................. $ 38.0 $ 43.9 $ 11.1
Marine Services........................................... 4.2 9.4 6.9
Exploration and Production --
U.S., including gas transportation..................... 87.5 65.4 59.7
Bolivia................................................ 47.6 27.5 6.9
Corporate................................................. 7.8 1.3 0.4
-------- ------ --------
Total Capital Expenditures............................. $ 185.1 $147.5 $ 85.0
======== ====== ========
- ---------------
(a) Including 1998 write-downs of oil and gas properties of $28.4 million in the
U.S. and $39.9 million in Bolivia.
(b) Excluding 1998 Acquisitions of $536.5 million.
NOTE F -- OTHER INCOME AND EXPENSE
Other income and other expense for the years ended December 31, 1998, 1997
and 1996 included the following (in millions):
1998 1997 1996
----- ---- -----
Other Income:
Receipt of contingency funds.............................. $21.3 $ -- $ --
Retroactive severance tax refunds......................... -- 1.8 5.0
Collection of Bolivian receivable......................... -- 2.2 --
Natural gas contract settlement........................... -- -- 60.0
Gain (loss) on sale of assets and other................... 0.4 1.5 (0.6)
----- ---- -----
Total Other Income................................ $21.7 $5.5 $64.4
===== ==== =====
Other Operating Costs and Expenses:
Special incentive compensation............................ $ 7.9 $ -- $ --
===== ==== =====
Other Expense:
Special incentive compensation............................ $12.0 $ -- $ --
Depreciation and amortization -- Corporate................ 1.1 0.7 0.9
Shareholder consent solicitation.......................... -- -- 2.3
Other..................................................... 3.1 2.6 4.0
----- ---- -----
Total Other Expense............................... $16.2 $3.3 $ 7.2
===== ==== =====
In 1998, the Exploration and Production segment received $21.3 million from
an operator in the Bob West Field, representing funds that were no longer needed
as a contingency reserve for litigation.
67
68
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
In 1996, the Company settled all claims and disputes with Tennessee Gas
Pipeline Company ("Tennessee Gas") and agreed to terminate the Tennessee Gas
contract effective October 1, 1996. The 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 in 1996. The
severance taxes were subsequently received in 1997.
In 1998, other expenses included $19.9 million for special incentive
compensation earned when the market price of the Company's stock achieved a
certain performance target (see Note L), of which $7.9 million was included in
other operating costs and expenses since it related to the operating segments.
NOTE G -- INCOME TAXES
The income tax provision (benefit) for the years ended December 31, 1998,
1997 and 1996 included the following (in millions):
1998 1997 1996
----- ----- -----
Federal -- Current.......................................... $ 5.4 $ 3.4 $16.2
Federal -- Deferred......................................... (9.7) 9.4 17.4
Foreign..................................................... 5.2 4.9 3.6
State....................................................... (1.4) 0.7 1.1
----- ----- -----
Income Tax Provision (Benefit)............................ $(0.5) $18.4 $38.3
===== ===== =====
Deferred income taxes and benefits are provided for differences between
financial statement carrying amounts of assets and liabilities and their
respective tax bases. Temporary differences and the resulting deferred tax
liabilities and assets at December 31, 1998 and 1997 are summarized as follows
(in millions):
1998 1997
----- -----
Deferred Federal Tax Liabilities:
Accelerated depreciation and property-related items....... $82.2 $57.8
Deferred charges and other................................ 5.6 --
----- -----
Total Deferred Federal Tax Liabilities................. 87.8 57.8
----- -----
Deferred Federal Tax Assets:
Investment tax and other credits.......................... 4.8 9.6
Accrued postretirement benefits........................... 17.2 10.5
Settlement with the Department of Energy.................. 2.8 3.2
Environmental reserve..................................... 3.3 3.1
Other..................................................... 1.1 5.3
----- -----
Total Deferred Federal Tax Assets...................... 29.2 31.7
----- -----
Net Deferred Federal Tax Liability.......................... 58.6 26.1
State Income and Other Taxes................................ 11.3 2.7
----- -----
Net Deferred Tax Liability................................ $69.9 $28.8
===== =====
In 1998, the Acquisitions described in Note C resulted in net deferred
federal tax liabilities of $46.7 million and net deferred state liabilities of
$11.1 million as of the dates of acquisition.
68
69
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following tables set forth domestic and foreign components of the
Company's results of operations (in millions) and a reconciliation of the normal
statutory federal income tax rate with the Company's effective tax rate
(percent):
1998 1997 1996
------ ----- ------
Earnings (Loss) Before Income Taxes and Extraordinary
Item:
U.S. ................................................... $ 20.2 $40.2 $106.7
Foreign................................................. (35.7) 8.9 8.4
------ ----- ------
Total Earnings (Loss) Before Income Taxes and
Extraordinary Item................................. $(15.5) $49.1 $115.1
====== ===== ======
Statutory U.S. Corporate Tax Rate......................... 35% 35% 35%
Effect of:
Foreign income taxes, net of tax benefit................ (26) 5 2
State income taxes, net of tax benefit.................. 1 1 1
Other................................................... (7) (4) (5)
------ ----- ------
Effective Income Tax Rate................................. 3% 37% 33%
====== ===== ======
At December 31, 1998, the Company had approximately $3.5 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, 1998, the Company had approximately
$1.3 million of alternative minimum tax credit carryforwards, with no expiration
dates, to offset future regular tax liabilities.
NOTE H -- 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 and amounted to $1.7 million and $1.4 million at December 31, 1998 and
1997, respectively.
NOTE I -- INVENTORIES
Components of inventories at December 31, 1998 and 1997 were as follows (in
millions):
1998 1997
------ -----
Crude oil and wholesale refined products, at LIFO........... $182.4 $68.2
Merchandise and other refined products...................... 10.5 13.4
Materials and supplies...................................... 15.3 5.7
------ -----
Total inventories......................................... $208.2 $87.3
====== =====
At December 31, 1998 and 1997, inventories valued using LIFO were lower
than replacement cost by approximately $3.3 million and $4.4 million,
respectively.
69
70
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE J -- ACCRUED LIABILITIES
The Company's current accrued liabilities and noncurrent other liabilities
as shown in the Consolidated Balance Sheets at December 31, 1998 and 1997
included the following (in millions):
1998 1997
----- -----
Accrued Liabilities -- Current:
Accrued environmental costs............................... $ 6.9 $ 5.8
Accrued employee costs.................................... 21.5 12.4
Accrued taxes other than income taxes..................... 14.8 4.1
Accrued interest.......................................... 16.8 1.4
Other..................................................... 9.3 8.0
----- -----
Total Accrued Liabilities -- Current................... $69.3 $31.7
===== =====
Other Liabilities -- Noncurrent:
Accrued postretirement benefits........................... $49.1 $32.2
Accrued environmental costs............................... 2.4 2.7
Other..................................................... 8.2 8.3
----- -----
Total Other Liabilities -- Noncurrent.................. $59.7 $43.2
===== =====
NOTE K -- BENEFIT PLANS
Pension Benefits and Other Postretirement Benefits
The Company sponsors multiple defined benefit pension plans which consist
of a retirement plan, executive security plans and a non-employee director
retirement plan.
The Company provides a qualified noncontributory retirement plan
("Retirement Plan") for all eligible employees. 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. Retirement plan assets are primarily comprised of common stock and
bond funds. As a result of the Washington Acquisition, the Retirement Plan's
benefit obligation increased by $9.1 million during 1998.
The Company's executive security plans ("ESP Plans") provide executive
officers and other key personnel with supplemental death or retirement plans.
Such benefits are provided by two nonqualified, noncontributory plans and are
based on years of service and compensation. The Company makes contributions to
one plan based upon estimated requirements. Assets of the funded plan consist of
a group annuity contract.
The Company had previously established an unfunded non-employee director
retirement plan ("Director Retirement Plan") which provided eligible directors
retirement payments upon meeting certain age or other requirements. However, in
March 1997, the Board of Directors elected to freeze the Director Retirement
Plan and transfer accrued benefits of current directors to the Tesoro Petroleum
Corporation Board of Directors Phantom Stock Plan (see Note L). After the
amendment and transfer, only those retired directors or beneficiaries who had
begun to receive benefits remained participants in the Director Retirement Plan.
The projected benefit obligation, accumulated benefit obligation, and fair
value of plan assets for the pension plans with accumulated benefit obligations
in excess of plan assets were $85.7 million, $66.2 million and $59.1 million,
respectively as of December 31, 1998, and $54.6 million, $45.9 million, and
$51.0 million, respectively, as of December 31, 1997.
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 provided to qualified dependents of
70
71
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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. As a result of the Acquisitions,
the postretirement health and life insurance benefit obligations increased by
$7.4 million during 1998.
Assumed health care cost trend rates have a significant effect on the
amounts reported for the health care and life insurance plans. A
one-percentage-point change in assumed health care cost trend rates could have
the following effects (in millions):
1-PERCENTAGE- 1-PERCENTAGE-
POINT INCREASE POINT DECREASE
-------------- --------------
Effect on service and interest cost components........... $0.6 $(0.4)
Effect on postretirement benefit obligations............. $4.7 $(3.8)
Financial information related to the Company's pension plans and other
postretirement benefits is presented below (in millions except percentages):
PENSION BENEFITS POSTRETIREMENT BENEFITS
----------------- ------------------------
1998 1997 1998 1997
------- ------ --------- ---------
Change in benefit obligation:
Benefit obligation at beginning of year.............. $ 61.8 $57.5 $ 27.1 $ 25.9
Service cost......................................... 4.2 2.0 1.2 0.8
Interest cost........................................ 4.9 4.1 2.2 1.9
Actuarial (gain) loss................................ 20.3 4.7 5.0 (0.3)
Benefits paid........................................ (5.8) (6.7) (1.3) (0.6)
Acquisitions (see Note C)............................ 9.1 -- 7.4 --
Curtailments, special termination benefits and
other............................................. 0.1 0.2 -- (0.6)
------ ----- ------ ------
Benefit obligation at end of year................. 94.6 61.8 41.6 27.1
------ ----- ------ ------
Change in plan assets:
Fair value of plan assets at beginning of year....... 58.7 53.5 -- --
Actual return on plan assets......................... 8.4 9.4 -- --
Employer contributions............................... 8.4 3.0 -- --
Administrative expenses.............................. (0.6) (0.6) -- --
Benefits paid........................................ (5.8) (6.6) -- --
------ ----- ------ ------
Fair value of plan assets at end of year.......... 69.1 58.7 -- --
------ ----- ------ ------
Benefit obligations in excess of plan assets........... (25.5) (3.1) (41.6) (27.1)
Unrecognized prior service cost........................ 0.6 0.6 -- --
Unrecognized net transition asset...................... (0.5) (1.6) -- --
Unrecognized net actuarial (gain) loss................. 23.9 8.5 2.2 (2.8)
------ ----- ------ ------
Prepaid (accrued) benefit cost.................... $ (1.5) $ 4.4 $(39.4) $(29.9)
====== ===== ====== ======
Amounts recognized in consolidated balance sheets:
Accrued liabilities.................................. $ (9.7) $(2.3) $(39.4) $(29.9)
Prepaid benefit cost................................. 8.2 6.7 -- --
------ ----- ------ ------
Net amount recognized............................. $ (1.5) $ 4.4 $(39.4) $(29.9)
====== ===== ====== ======
71
72
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
PENSION BENEFITS POSTRETIREMENT BENEFITS
------------------------------------------ -----------------------
1998 1997 1996 1998 1997 1996
------------ ------------ ------------ ----- ----- -----
Weighted average assumptions as
of December 31 (%):
Discount rate.................. 6.75 7.50 7.50 6.75 7.50 7.50
Rate of compensation
increase.................... 4.25 to 5.00 5.00 5.00 4.25 5.00 5.00
Expected return on plan
assets...................... 7.00 to 8.50 7.00 to 8.50 7.50 to 8.50 -- -- --
For measurement purposes, the weighted average annual assumed rate of
increase in the per capita cost of covered health care benefits was assumed to
be 7.5% for 1998, decreasing gradually to 5% by the year 2010 and remaining
level thereafter.
PENSION BENEFITS POSTRETIREMENT BENEFITS
--------------------- ------------------------
1998 1997 1996 1998 1997 1996
----- ----- ----- ------ ------ ------
Components of net periodic benefit cost:
Service cost.................................... $ 4.2 $ 2.0 $ 1.7 $1.2 $0.8 $0.7
Interest cost................................... 4.9 4.1 3.8 2.2 1.9 1.8
Expected return on plan assets.................. (4.2) (3.9) (3.7) -- -- --
Amortization of unrecognized transition asset... (1.1) (1.1) (1.1) -- -- --
Recognized net actuarial (gain) loss............ 1.0 0.9 0.6 -- -- --
Curtailments, settlements and special
termination benefits......................... 0.5 1.1 0.9 -- -- --
----- ----- ----- ---- ---- ----
Net periodic benefit cost.................. $ 5.3 $ 3.1 $ 2.2 $3.4 $2.7 $2.5
===== ===== ===== ==== ==== ====
Thrift Plan
The Company sponsors an employee thrift plan ("Thrift Plan") which provides
for contributions by eligible employees into designated investment funds with a
matching contribution by the Company. Employees may contribute a portion 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 September 1, 1998, the Thrift Plan was amended to change
the Company's 100% matching contribution, from a maximum of 4% to 6% of the
employee's eligible contribution, with at least 50% of the Company's matching
contribution invested in Common Stock of the Company. In addition, the maximum
employee contribution changed from 10% to 15%. The Company's contributions
amounted to $1.7 million, $1.2 million and $0.8 million during 1998, 1997 and
1996, respectively.
NOTE L -- STOCK-BASED COMPENSATION
Incentive Stock Plans
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 Common Stock may be granted under the 1993 Plan in a variety of
forms, including restricted stock, incentive stock options, nonqualified stock
options, stock appreciation rights and performance share and performance unit
awards. In 1998, the aggregate number of shares of Common Stock which can be
granted under the 1993 Plan was increased from 2,650,000 to 4,250,000. Stock
options may be granted at exercise prices not less than the fair market value on
the date the options are granted. The options granted generally become
exercisable after one year in 20%, 25% or 33% increments per year and expire ten
years from the date
72
73
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
of grant. The 1993 Plan will expire, unless earlier terminated, as to the
issuance of awards in the year 2003. At December 31, 1998, the Company had
893,880 shares available for future grants under the 1993 Plan.
The 1982 Plan expired in 1994 as to issuance of stock appreciation rights,
stock options and stock awards; however, grants made before the expiration date,
that have not been fully exercised, remain outstanding pursuant to their terms.
The 1995 Plan provides for the grant of up to an aggregate of 150,000
nonqualified stock options to eligible non-employee directors of the Company.
These automatic, non-discretionary stock options are granted at an exercise
price equal to the fair market value per share of the Company's Common Stock as
of the date of grant. Under the 1995 Plan, each person serving as a non-employee
director on February 23, 1995, or elected thereafter, initially receives 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. The term of each option is ten years, and
an option first becomes exercisable six months after the date of grant. The 1995
Plan will terminate as to issuance of stock options in February 2005. At
December 31, 1998, the Company had 62,000 options outstanding and 71,000 shares
available for future grants under the 1995 Plan.
A summary of stock option activity in the Plans is set forth below
(thousands of shares):
NUMBER OF WEIGHTED-
OPTIONS AVERAGE
OUTSTANDING EXERCISE PRICE
----------- ----------------
Outstanding January 1, 1996.............................. 1,172.1 $ 7.16
Granted................................................ 1,095.5 13.45
Exercised.............................................. (315.7) 5.67
Forfeited and expired.................................. (95.2) 8.50
-------
Outstanding December 31, 1996............................ 1,856.7 11.05
Granted................................................ 431.0 16.73
Exercised.............................................. (43.8) 8.45
Forfeited and expired.................................. (36.0) 8.40
-------
Outstanding December 31, 1997............................ 2,207.9 12.26
Granted................................................ 801.2 15.94
Exercised.............................................. (34.1) 10.42
Forfeited and expired.................................. (23.4) 12.16
-------
Outstanding December 31, 1998............................ 2,951.6 13.28
=======
At December 31, 1998, 1997 and 1996, exercisable stock options totaled 1.4
million, 0.7 million and 0.4 million, respectively.
73
74
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The following table summarizes information about stock options outstanding
under the Plans at December 31, 1998 (thousands of shares):
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..... 175.8 4.2 years $ 4.50 175.8 $ 4.50
$ 7.20 to $10.45..... 523.0 6.5 years 8.63 360.9 8.73
$10.46 to $13.72..... 394.0 7.4 years 11.41 373.0 11.40
$13.73 to $16.98..... 1,858.8 8.9 years 15.82 510.3 15.35
------- -------
$ 3.92 to $16.98..... 2,951.6 8.0 years 13.28 1,420.0 11.29
======= =======
Phantom Stock Agreement and Phantom Stock Plan
In 1997, the Compensation Committee of the Board of Directors granted
175,000 phantom stock options to an executive officer of the Company at 100% of
the fair market value of the Company's Common Stock on the grant date, or
$16.9844 per share. These phantom stock options vest in 15% increments in each
of the first three years and the remaining 55% increment vests in the fourth
year. At December 31, 1998, 26,250 of these phantom stock options were
exercisable. 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 under the
1993 Plan.
To more closely align director compensation with shareholders' interests,
in March 1997, the lump-sum accrued benefit of each of the current non-employee
directors was transferred from the Director Retirement Plan (see Note K) into an
account ("Account") in the Company's Board of Directors Deferred Phantom Stock
Plan ("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 1998, the Company credited
expense for approximately $110,000 related to the Phantom Stock Plan due to the
net depreciation in the market price of the Company's Common Stock. In 1997, the
Company recorded expense of approximately $127,000 due to the increase in the
market price of the Company's Common Stock.
Incentive Compensation
In October 1998, the Company's Board of Directors unanimously approved the
1998 Performance Incentive Compensation Plan ("1998 Performance Plan"), which is
intended to advance the best interests of the Company and its stockholders by
directly targeting Company performance to align with the ninetieth percentile
historical stock-price growth rate for the Company's peer group. In addition,
the 1998 Performance Plan will provide the Company's employees with additional
compensation, contingent upon achievement of the targeted objectives, thereby
encouraging them to continue in the employ of the Company. Under the 1998
Performance Plan, targeted objectives are comprised of the fair market value of
the Company's Common Stock equaling or exceeding an average of $35 per share
("First Performance Target") and $45 per share ("Second Performance Target") on
any 20 consecutive trading days during a period commencing on October 1, 1998
and ending on the earlier of September 30, 2002, or the date on which the Second
Performance Target is achieved ("Performance Period"). The 1998 Performance Plan
has several tiers of
74
75
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
awards, with the award generally determined by job level. Most eligible
employees have contingent cash bonus opportunities of 25% of their annual "basic
compensation" (as defined in the 1998 Performance Plan) and three executive
officers have contingent awards totaling 655,000 shares of phantom stock which
will be payable solely in cash. Upon achievement of the First Performance
Target, one-fourth of the contingent award will be earned, with payout deferred
until the end of the Performance Period. The remaining 75% will be earned only
upon achievement of the Second Performance Target, with payout occurring 30 days
thereafter. Employees will need to have at least one year of regular, full-time
service at the time the Performance Period ends in order to be eligible for a
payment. The Company estimates that it will incur aftertax costs of
approximately 1% of the total aggregate increase in shareholder value if the
First Performance Target is reached and will incur an additional 2% aftertax
charge if the Second Performance Target is reached.
Under a previous special incentive compensation strategy, approved
unanimously by the Company's Board of Director in June 1996, eligible employees
were provided with incentives to achieve a significant increase in the market
price of the Company's Common Stock. Under this strategy, awards were earned
when the market price of the Company's Common Stock reached an average price per
share of $20 or higher over 20 consecutive trading days after June 30, 1997 and
before December 31, 1998 ("Performance Target"). In connection with this
strategy, certain executives were granted, from the Company's 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 vested upon achieving the Performance Target in May of 1998.
Non-executive employees earned cash bonuses equal to 25% of their individual
payroll amounts for the previous twelve complete months. In May 1998, the
Company recorded a pretax charge of approximately $20 million ($10 million
related to the noncash vesting of restricted stock awards and stock options and
$10 million for cash bonuses) for this strategy. On an aftertax basis, the
charge totaled approximately $13 million, representing approximately 5% of the
total aggregate increase in shareholder value since approval of the special
incentive strategy in 1996.
Pro Forma Information
The Company applies APB No. 25 and related interpretations in accounting
for its stock-based compensation. Had compensation cost been determined based on
the fair value at the grant dates for awards in accordance with SFAS No. 123,
"Accounting for Stock-Based Compensation," the Company's pro forma results in
1998, 1997 and 1996 would have been a net loss of approximately $22.3 million
($0.96 per basic and diluted share), net earnings of $28.5 million ($1.08 per
basic share, $1.06 per diluted share) and net earnings of $72.6 million ($2.79
per basic share, $2.74 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 49%, 32% and 30%; risk free interest rates of 4.7%, 6.7% and 6.6%;
expected lives of seven years; and no dividend yields for 1998, 1997 and 1996,
respectively. The estimated average fair value per share of options granted
during 1998, 1997 and 1996 were $7.85, $5.96 and $4.26, respectively. The fair
value of phantom stock awards in 1998 was $0.82 per share and the fair value of
restricted stock awards in 1996 was $0.95 per share.
Shares Reserved
Shares of unissued Common Stock reserved for the Plans were 3,928,466 at
December 31, 1998. In addition, at December 31, 1998, 8,750,925 shares of
unissued Common Stock were reserved for the conversion of Preferred Stock (see
Note D).
75
76
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE M -- 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, 1998, for
operating leases having initial or remaining noncancelable lease terms in excess
of one year, excluding marine charters, were as follows (in millions):
1999........................................................ $ 14.4
2000........................................................ 12.5
2001........................................................ 11.8
2002........................................................ 10.5
2003........................................................ 10.3
Remainder................................................... 117.0
------
Total Minimum Lease Payments........................... $176.5
======
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 refineries. At December 31, 1998,
future minimum annual lease payments remaining for these two vessels, which
include operating costs, are approximately $28 million for 1999 and $16 million
for 2000. Operating costs related to these vessels, which may vary from year to
year, comprised approximately 30% of the total minimum payments during 1998. The
Company also enters into various month-to-month and other short-term rentals,
including three charters for vessels primarily used to transport refined
products from the Company's refineries to the Far East and South Pacific. The
Company also leases tugs and barges for Hawaii operations under capital leases
(see Note D). Under these leases, the Company pays operating costs, including
personnel, repairs, maintenance and dry-docking, estimated at $9 million for
1999.
Total rental expense for short-term and long-term leases, excluding marine
charters, amounted to approximately $20 million, $11 million and $12 million for
1998, 1997 and 1996, respectively. In addition, expenses related to charters of
marine vessels were $34 million in 1998 and 1997 and $30 million in 1996.
In November 1998, the Company entered into a lease agreement to become the
sole tenant of an office building to be constructed in 1999. Upon substantial
completion of the building, annual base lease commitments will range from $1.8
million to $2.4 million over a 15-year lease term.
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 the Environmental Protection Agency
("EPA") regarding a waste disposal site near Abbeville, Louisiana and the
Casmalia Disposal Site in Santa Barbara County, California. The Company has been
named a potentially responsible party ("PRP") under the Federal Comprehensive
Environmental Response, Compensation and Liability Act ("CERCLA" or "Superfund")
at both sites. Although the Superfund law might impose joint and several
liability upon each party at the sites, the extent of the Company's allocated
financial contribution for cleanup is expected to be de minimis based upon the
number of companies, volumes of waste involved and total estimated costs to
close each site. The Company believes, based on these considerations and
discussions with the EPA, that its liability at the
76
77
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Abbeville site will not exceed $25,000. The Company believes that its liability
at the Casmalia Site is de minimis based on a 1999 notification from the EPA
indicating that the Company's liability will not exceed $125,000.
The Company is currently involved with a waste water disposal site in
Redwood City, California. On December 18, 1998, the Port of Redwood City filed
suit against numerous defendants, including the Company, for contribution
pursuant to CERCLA and the Resource Conservation and Recovery Act ("RCRA"). The
Company has negotiated with the Port of Redwood City and expects to settle its
liability in early 1999. The Company believes that it is not subject to joint
and several liability for the cleanup of the site and that its liability will
not exceed $40,000.
In connection with the Hawaii Acquisition discussed in Note C, the BHP
Sellers and the Company have executed a separate environmental agreement,
whereby the BHP Sellers have indemnified the Company for environmental costs
arising out of conditions which existed at or prior to closing. This
indemnification is subject to a maximum limit of $9.5 million and expires after
a period of ten years. Under the environmental agreement, the first $5.0 million
of these liabilities will be the responsibility of the BHP Sellers and the next
$6.0 million will be shared on the basis of 75% by the BHP Sellers and 25% by
the Company. Certain environmental claims arising out of prior operations will
not be subject to the $9.5 million limit or the ten-year time limit.
Under the agreement related to the Washington Acquisition discussed in Note
C, Shell Refining Holding Company, a subsidiary of Shell (the "Shell Seller"),
generally has agreed to indemnify the Company for environmental liabilities at
the Washington Refinery arising out of conditions which existed at or prior to
the closing date and identified by the Company prior to August 1, 2001. The
Company is responsible for environmental costs up to the first $0.5 million each
year, after which the Shell Seller will be responsible for annual environmental
costs up to $1.0 million. Annual costs greater than $1.0 million will be shared
equally between the Company and the Shell Seller, subject to an aggregate
maximum of $5.0 million and a ten-year term.
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, 1998, the Company's
accruals for environmental expenses amounted to $9.3 million. Based on currently
available information, including the participation of other parties or former
owners in remediation actions, the Company believes these accruals are adequate.
To comply with environmental laws and regulations, the Company anticipates
that it will make capital improvements of approximately $12 million in 1999 and
$5 million in 2000. In addition, capital expenditures for alternative secondary
containment systems for existing storage tank facilities are estimated to be $2
million in 1999 and $1 million in 2000, with a remaining $4 million expected to
be spent by 2002.
Conditions that require additional expenditures may exist for various
Company sites, including, but not limited to, the Company's refineries, retail
gasoline stations (operating and closed locations) and petroleum product
terminals, and for compliance with the Clean Air Act and other state and federal
regulations. The amount of such future expenditures cannot currently be
determined by the Company.
Other
On October 1, 1998, the Attorney General for the State of Hawaii filed a
lawsuit in the U.S. District Court for the District of Hawaii against thirteen
oil companies, including Tesoro Petroleum Corporation and Tesoro Hawaii
Corporation, alleging anti-competitive marketing practices in violation of
federal and state anti-trust laws, and seeking injunctive relief and
compensatory and treble damages and civil penalties against all defendants in an
amount in excess of $500 million. On March 25, 1999, the Attorney General filed
an amended complaint with the U.S. District Court seeking damages against all
defendants for such alleged
77
78
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
anti-competitive marketing practices in an amount in excess of $1.3 billion. The
Company believes that it has not engaged in any anti-competitive activities and
will defend this litigation vigorously. This proceeding is subject to the
indemnity provision of the stock sale agreement between the BHP Sellers and the
Company which provides for indemnification in excess of $2 million and not to
exceed $65 million.
NOTE N -- QUARTERLY FINANCIAL DATA (UNAUDITED)
QUARTERS
------------------------------------ TOTAL
FIRST SECOND THIRD FOURTH YEAR
------ ------ ------ ------ --------
(IN MILLIONS EXCEPT PER SHARE AMOUNTS)
1998
Revenues:
Gross operating revenues................ $195.2 $258.3 $472.5 $542.6 $1,468.6
Other income............................ 0.8 20.6 0.2 0.1 21.7
------ ------ ------ ------ --------
Total Revenues..................... $196.0 $278.9 $472.7 $542.7 $1,490.3
====== ====== ====== ====== ========
Segment Operating Profit (Loss)............ $ 17.9 $ 50.8 $ 28.6 $(38.0) $ 59.3
====== ====== ====== ====== ========
Net Earnings (Loss)........................ $ 6.1 $ 6.2 $ 7.8 $(39.5) $ (19.4)
====== ====== ====== ====== ========
Net Earnings (Loss) Per Share -- Basic..... $ 0.23 $ 0.23 $ 0.15 $(1.32) $ (0.86)
Net Earnings (Loss) Per Share -- Diluted... $ 0.23 $ 0.23 $ 0.15 $(1.32) $ (0.86)
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
====== ====== ====== ====== ========
Segment 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
The 1998 second quarter included pretax other income of $21.3 million for
receipt of funds from an operator and a pretax charge of $19.9 million for
special incentive compensation (Note L). In addition, an aftertax extraordinary
loss of $4.4 million was recorded in the 1998 second quarter for the early
extinguishment of debt (Note D). During the 1998 fourth quarter, pretax
write-downs of oil and gas properties totaled $68.3 million (Notes A and O).
Earnings per share in the 1998 third and fourth quarters were reduced by the
effects of dividends on Preferred Stock issued in July 1998.
Other income in 1997 included severance tax refunds of $1.6 million and
$0.2 million in the first and second quarters, respectively. 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.
78
79
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE O -- OIL AND GAS PRODUCING ACTIVITIES
The information presented below represents the oil and gas producing
activities of the Company's Exploration and Production segment, excluding
amounts related to its U.S. natural gas transportation operations. Other
information pertinent to the Exploration and Production segment is contained in
Notes C and E.
Capitalized Costs Relating to Oil and Gas Producing Activities
DECEMBER 31,
--------------------------
1998 1997 1996
------ ------ ------
(IN MILLIONS)
Capitalized Costs:
Unevaluated properties................................. $393.3 $251.6 $179.4
Unproved properties not being amortized................ 25.1 31.9 12.4
------ ------ ------
418.4 283.5 191.8
Accumulated depreciation, depletion and amortization... 221.9 112.5 78.2
------ ------ ------
Net Capitalized Costs............................... $196.5 $171.0 $113.6
====== ====== ======
The Company's investment in oil and gas properties included $25 million in
unevaluated properties, primarily undeveloped leasehold costs and seismic costs,
which have been excluded from the amortization base at December 31, 1998. Of
this amount, $14 million, $8 million and $3 million of such costs were incurred
in 1998, 1997 and 1996, respectively. The Company anticipates that the majority
of these costs will be included in the amortization base during the next three
years.
During the fourth quarter of 1998, the Company wrote down its capitalized
costs of oil and gas properties by $68.3 million ($28.4 million in U.S. and
$39.9 million in Bolivia). These write-downs, which were required by the cost
ceiling limitation under full-cost accounting, were primarily the result of
declines in oil and gas prices during the fourth quarter of 1998.
Costs Incurred in Oil and Gas Property Acquisition, Exploration and
Development Activities
U.S. BOLIVIA TOTAL
------- ------- ------
(IN MILLIONS)
1998
Property acquisitions --
Proved................................................ $17.8 $ -- $ 17.8
Unproved.............................................. 6.8 -- 6.8
Exploration.............................................. 32.0 28.3 60.3
Development.............................................. 29.2 13.2 42.4
----- ----- ------
$85.8 $41.5 $127.3
===== ===== ======
1997
Property acquisitions --
Proved................................................ $14.7 $11.9 $ 26.6
Unproved.............................................. 7.1 3.3 10.4
Exploration.............................................. 24.6 11.0 35.6
Development.............................................. 17.8 1.3 19.1
----- ----- ------
$64.2 $27.5 $ 91.7
===== ===== ======
79
80
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
U.S. BOLIVIA TOTAL
------- ------- ------
(IN MILLIONS)
1996
Property acquisitions --
Proved................................................ $20.5 $ -- $ 20.5
Unproved.............................................. 5.2 -- 5.2
Exploration.............................................. 11.8 6.7 18.5
Development.............................................. 22.2 0.2 22.4
----- ----- ------
$59.7 $ 6.9 $ 66.6
===== ===== ======
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 MILLIONS EXCEPT AS INDICATED)
1998
Gross revenues -- sales to unaffiliates(a)............. $ 68.1 $ 10.5 $ 78.6
Production costs....................................... 9.7 1.2 10.9
Administrative support and other....................... 1.9 2.8 4.7
Depreciation, depletion and amortization............... 35.6 2.6 38.2
Write-downs of oil and gas properties.................. 28.4 39.9 68.3
Other income (expense)(b).............................. 22.4 (0.5) 21.9
------ ------ ------
Pretax results of operations........................... 14.9 (36.5) (21.6)
Income tax expense (benefit)........................... 5.2 (9.4) (4.2)
------ ------ ------
Results of operations from producing activities(c)..... $ 9.7 $(27.1) $(17.4)
====== ====== ======
Depletion per net equivalent thousand cubic feet
("Mcfe")............................................ $ 1.04 $ 0.25
====== ======
1997
Gross revenues -- sales to unaffiliates(a)............. $ 68.8 $ 11.2 $ 80.0
Production costs....................................... 7.4 0.9 8.3
Administrative support and other....................... 2.2 2.4 4.6
Depreciation, depletion and amortization............... 29.3 1.5 30.8
Other income(b)........................................ 3.2 2.2 5.4
------ ------ ------
Pretax results of operations........................... 33.1 8.6 41.7
Income tax expense..................................... 11.6 4.9 16.5
------ ------ ------
Results of operations from producing activities(c)..... $ 21.5 $ 3.7 $ 25.2
====== ====== ======
Depletion per Mcfe..................................... $ 0.93 $ 0.19
====== ======
80
81
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
U.S. BOLIVIA TOTAL
-------- --------- --------
(IN MILLIONS EXCEPT AS INDICATED)
1996
Gross revenues -- sales to unaffiliates(a)............. $ 88.3 $ 13.7 $102.0
Production costs....................................... 5.3 0.9 6.2
Administrative support and other....................... 3.6 2.8 6.4
Depreciation, depletion and amortization............... 25.2 1.3 26.5
Income from settlement of a natural gas contract....... 60.0 -- 60.0
Income from severance tax refunds...................... 5.0 -- 5.0
------ ------ ------
Pretax results of operations........................... 119.2 8.7 127.9
Income tax expense..................................... 41.7 5.4 47.1
------ ------ ------
Results of operations from producing activities(c)..... $ 77.5 $ 3.3 $ 80.8
====== ====== ======
Depletion per Mcfe..................................... $ 0.79 $ 0.15
====== ======
- ---------------
(a) Revenues included the effects of natural gas commodity price agreements
which amounted to a gain of $1.3 million ($0.04 per thousand cubic feet
("Mcf")) in 1998 and to losses of $1.6 million ($0.05 per Mcf) and $3.1
million ($0.11 per Mcf) in 1997 and 1996, respectively. The Company had
entered into these agreements to reduce risks caused by fluctuations in the
prices of natural gas in the spot market. During 1998, 1997 and 1996, the
Company used such agreements to set the price of 13%, 9%, and 30%,
respectively, of the natural gas that it sold in the spot market. At
year-end, the Company had natural gas price agreements outstanding through
March 31, 1999.
(b) Other income included $21.3 million in 1998 from an operator in the Bob West
Field, representing funds that are no longer needed as a contingency reserve
for litigation. Other income in 1997 primarily represented retroactive
severance tax refunds in the U.S. and income related to a collection of a
receivable in Bolivia.
(c) Excludes corporate general and administrative expenses and financing costs.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Reserves (Unaudited)
The following table sets forth the computation of the standardized measure
of discounted future net cash flows relating to proved reserves and the changes
in such cash flows in accordance with SFAS No. 69. The standardized measure is
the estimated excess future cash inflows from proved reserves less estimated
future production and development costs, estimated future income taxes and a
discount factor. Future cash inflows represent expected revenues from production
of year-end quantities of proved reserves based on year-end prices and any fixed
and determinable future escalation provided by contractual arrangements in
existence at year-end. Escalation based on inflation, federal regulatory changes
and supply and demand are not considered. Estimated future production costs
related to year-end reserves are based on year-end costs. Such costs include,
but are not limited to, production taxes and direct operating costs. Inflation
and other anticipatory costs are not considered until the actual cost change
takes effect. Estimated future income tax expenses are computed using the
appropriate year-end statutory tax rates. Consideration is given for the effects
of permanent differences, tax credits and allowances. A discount rate of 10% is
applied to the annual future net cash flows.
The methodology and assumptions used in calculating the standardized
measure are those required by SFAS No. 69. The standardized measure is not
intended to be representative of the fair market value of the Company's proved
reserves. The calculations of revenues and costs do not necessarily represent
the amounts to be received or expended by the Company.
81
82
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
U.S. BOLIVIA TOTAL
------ ------- ------
(IN MILLIONS)
DECEMBER 31, 1998
Future cash inflows....................................... $330.4 $275.0 $605.4
Future production costs................................... 77.8 60.9 138.7
Future development costs.................................. 24.4 70.6 95.0
------ ------ ------
Future net cash flows before income tax expense........... 228.2 143.5 371.7
10% annual discount factor................................ 88.3 73.7 162.0
------ ------ ------
Discounted future net cash flows before income taxes...... 139.9 69.8 209.7
Discounted future income tax expense(a)................... 27.9 41.4 69.3
------ ------ ------
Standardized measure of discounted future net cash
flows.................................................. $112.0 $ 28.4 $140.4
====== ====== ======
DECEMBER 31, 1997
Future cash inflows....................................... $347.9 $490.3 $838.2
Future production costs................................... 81.0 86.5 167.5
Future development costs.................................. 29.4 48.8 78.2
------ ------ ------
Future net cash flows before income tax expense........... 237.5 355.0 592.5
10% annual discount factor................................ 70.0 148.5 218.5
------ ------ ------
Discounted future net cash flows before income taxes...... 167.5 206.5 374.0
Discounted future income tax expense(a)................... 32.3 107.3 139.6
------ ------ ------
Standardized measure of discounted future net cash
flows.................................................. $135.2 $ 99.2 $234.4
====== ====== ======
DECEMBER 31, 1996
Future cash inflows....................................... $376.1 $368.1 $744.2
Future production costs................................... 66.5 72.8 139.3
Future development costs.................................. 13.2 30.6 43.8
------ ------ ------
Future net cash flows before income tax expense........... 296.4 264.7 561.1
10% annual discount factor................................ 73.7 130.9 204.6
------ ------ ------
Discounted future net cash flows before income taxes...... 222.7 133.8 356.5
Discounted future income tax expense(a)................... 70.2 80.1 150.3
------ ------ ------
Standardized measure of discounted future net cash
flows.................................................. $152.5 $ 53.7 $206.2
====== ====== ======
- ---------------
(a) For Bolivia, the discounted future income tax expense includes Bolivian
taxes of $41.4, $105.0 million and $69.4 million at December 31, 1998, 1997
and 1996, respectively, and U.S. income taxes of $2.3 million and $10.7
million at December 31, 1997 and 1996, respectively.
82
83
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Changes in Standardized Measure of Discounted Future Net Cash Flows
(Unaudited)
1998 1997 1996
------- ------ ------
(IN MILLIONS)
Sales of oil and gas produced, net of production costs...... $ (61.9) $(69.5) $(93.3)
Net changes in prices and production costs.................. (144.6) (88.5) 39.4
Extensions, discoveries and improved recovery............... 61.6 42.2 81.2
Changes in future development costs......................... 14.7 (7.5) (17.7)
Revisions of previous quantity estimates.................... (27.5) 15.8 (7.2)
Purchases (sales) of minerals in-place...................... 16.7 79.0 55.5
Changes in timing of production............................. (60.6) 10.3 --
Extension of Bolivian contract terms........................ -- -- 26.6
Other changes in Bolivian Hydrocarbons Law.................. -- -- 32.9
Accretion of discount....................................... 37.4 35.7 21.7
Net changes in income taxes................................. 70.2 10.7 (78.5)
------- ------ ------
Net increase (decrease)..................................... (94.0) 28.2 60.6
Beginning of period......................................... 234.4 206.2 145.6
------- ------ ------
End of period............................................... $ 140.4 $234.4 $206.2
======= ====== ======
83
84
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, 1998 and 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 FASB, 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 (billions of cubic feet)(a)
January 1, 1996........................................... 106.4 88.4 194.8
Extension of Bolivian contract terms(b)................ -- 33.0 33.0
Other changes in Bolivian Hydrocarbons Law(b).......... -- 56.7 56.7
Revisions of previous estimates........................ (4.8) (0.1) (4.9)
Extensions, discoveries and other additions............ 23.0 59.9 82.9
Production............................................. (32.1) (7.4) (39.5)
Purchases of minerals in-place......................... 24.3 -- 24.3
----- ----- -----
December 31, 1996......................................... 116.8 230.5 347.3
Revisions of previous estimates........................ (3.0) 30.6 27.6
Extensions and discoveries............................. 33.6 -- 33.6
Production............................................. (31.4) (7.1) (38.5)
Purchases of minerals in-place......................... 30.5 81.2 111.7
----- ----- -----
December 31, 1997......................................... 146.5 335.2 481.7
Revisions of previous estimates........................ (12.3) (43.5) (55.8)
Extensions and discoveries............................. 40.9 50.9 91.8
Production............................................. (33.0) (8.9) (41.9)
Sales of minerals in-place............................. (1.5) -- (1.5)
Purchases of minerals in-place......................... 22.3 -- 22.3
----- ----- -----
December 31, 1998(c)...................................... 162.9 333.7 496.6
===== ===== =====
NET PROVED DEVELOPED GAS RESERVES (billions of cubic feet)
December 31, 1995......................................... 95.9 72.5 168.4
December 31, 1996......................................... 107.5 123.1 230.6
December 31, 1997......................................... 112.4 181.4 293.8
December 31, 1998(c)...................................... 129.0 260.5 389.5
Table continued on next page
84
85
TESORO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
U.S. BOLIVIA TOTAL
----- ------- -----
NET PROVED OIL RESERVES (millions of barrels)(a)
January 1, 1996........................................... -- 1.6 1.6
Extension of Bolivian contract terms(b)................ -- 0.5 0.5
Other changes in Bolivian Hydrocarbons Law(b).......... -- 0.9 0.9
Revisions of previous estimates........................ -- 0.1 0.1
Extensions, discoveries and other additions............ -- 0.8 0.8
Production............................................. -- (0.2) (0.2)
Purchases of minerals in-place......................... 0.2 -- 0.2
----- ----- -----
December 31, 1996......................................... 0.2 3.7 3.9
Revisions of previous estimates........................ -- 0.4 0.4
Extensions and discoveries............................. 0.1 -- 0.1
Production............................................. -- (0.2) (0.2)
Purchases of minerals in-place......................... 0.4 1.3 1.7
----- ----- -----
December 31, 1997......................................... 0.7 5.2 5.9
Revisions of previous estimates........................ -- (0.1) (0.1)
Extensions and discoveries............................. 0.3 3.1 3.4
Production............................................. (0.1) (0.3) (0.4)
Purchases of minerals in-place......................... 0.9 -- 0.9
----- ----- -----
December 31, 1998(c)...................................... 1.8 7.9 9.7
===== ===== =====
NET PROVED DEVELOPED OIL RESERVES (millions of barrels)
December 31, 1995......................................... -- 1.4 1.4
December 31, 1996......................................... 0.1 2.3 2.4
December 31, 1997......................................... 0.3 3.1 3.4
December 31, 1998(c)...................................... 1.2 4.6 5.8
- ---------------
(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 the Bolivian Hydrocarbons Law passed in 1996, the Company converted
its Contracts of Operation for Block 18 and Block 20 into Shared Risk
Contracts, which, among other matters, extended the Company's term of
operation, provided more favorable acreage relinquishment terms and provided
for a more favorable royalty and tax structure.
(c) No major discovery or adverse event has occurred since December 31, 1998
that would cause a significant change in net proved reserve volumes.
85
86
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
DIRECTORS OF THE REGISTRANT
The Company's Board of Directors (sometimes referred to herein as the
"Board") consists of seven members, each to hold office until the 1999 Annual
Meeting of Stockholders or until their successors are duly elected and
qualified. Certain information as to each of the Company's directors is set
forth in the table below and in the following paragraphs. Certain of the
information appearing in the table and the notes thereto has been furnished to
the Company by the respective directors.
SERVED AS
AGE AT DIRECTOR OF
MARCH 1, THE COMPANY OTHER POSITIONS AND OFFICES
NAME 1999 SINCE WITH THE COMPANY
---- -------- ------------ -----------------------------------
Steven H. Grapstein................ 41 1992 Vice Chairman of the
Board of Directors(a)(b)(c)(d)
William J. Johnson................. 64 1996 (b)(d)
Alan J. Kaufman.................... 61 1996 (b)(d)
Raymond K. Mason, Sr............... 72 1983 (a)(d)
Bruce A. Smith..................... 55 1995 Chairman of the Board of Directors,
President and Chief Executive
Officer(a)
Patrick J. Ward.................... 68 1996 (c)(d)
Murray L. Weidenbaum............... 72 1992 (a)(c)
- ---------------
(a) Member of the Executive Committee (Mr. Smith, Chairman).
(b) Member of the Audit Committee (Mr. Grapstein, Chairman).
(c) Member of the Governance Committee (Dr. Weidenbaum, Chairman).
(d) Member of the Compensation Committee (Mr. Mason, Chairman).
On December 26, 1995, the Stockholders' Committee for New Management of
Tesoro Petroleum Corporation (the "Committee"), comprised at that time of five
holders of the Company's Common Stock, announced its intention to engage in a
solicitation of written consents for the primary purpose of removing the then
current members of the Board and replacing them with a new board. On April 4,
1996, a settlement agreement was reached between the Committee and certain
related parties (the "Solicitation Parties"), the Company and Ardsley Advisory
Partners ("Ardsley"), the Company's then largest stockholder. Pursuant to the
settlement agreement, the Solicitation Parties severally agreed, among other
things, that for a period beginning as of April 4, 1996, and ending on the
earlier of the day after the Company's 1999 annual meeting or June 30, 1999 (the
"Standstill Period"), he or it shall not in any way, directly or indirectly,
without the approval of the Board, make, encourage, participate or assist in (a)
any attempt to take control of the Company, (b) any consent solicitation to
remove any member of the Company's Board of Directors, (c) any solicitation of
proxies to vote or become a participant in any election contest to remove any
member of the Company's Board of Directors, (d) the nomination or election of
any alternate director or slate of directors proposed from the floor at any
meeting of the Company's stockholders, or (e) any offers or indications of
interest with respect to the acquisition or disposition of the Company or any of
its business units. In accordance with the settlement agreement, Alan J.
Kaufman, M.D., and William J. Johnson are serving as directors of the Company.
Pursuant to the settlement agreement, Dr. Kaufman and Mr. Johnson shall continue
subject to the terms of the settlement agreement to be nominated for election as
part of the Board's
86
87
recommended slate throughout the Standstill Period. In the case of Dr. Kaufman,
the settlement agreement provides that, in the event any of the Solicitation
Parties breaches the terms of the standstill, confidentiality and
non-disparagement provisions of the settlement agreement or in the event Dr.
Kaufman reduces his holdings of Company Common Stock below 400,000 shares or
votes for any nominee for director other than those supported by a majority of
the Board, Dr. Kaufman shall immediately tender his resignation and, at the
option of the Company, be removed from the Board.
Steven H. Grapstein has been Chief Executive Officer of Kuo Investment
Company and subsidiaries ("Kuo"), an international investment group, since
January 1997. From September 1985 to January 1997, Mr. Grapstein was a Vice
President of Kuo. He is also a director of several of the Kuo companies. Mr.
Grapstein has been a Vice President of Oakville N.V. ("Oakville"), a Kuo
subsidiary, since 1989.
William J. Johnson has been a petroleum consultant and president of JonLoc
Inc., a private company engaged in oil and gas investments, since 1994. From
1990 through 1994, Mr. Johnson served as President, Chief Operating Officer and
a director of Apache Corporation, a large independent oil and gas company. Mr.
Johnson is on the Board of Directors of Snyder Oil Corporation, an exploration
and production company, and J. Ray McDermott, S.A., an engineering and
construction company.
Alan J. Kaufman, M.D., is an investor in a number of companies and a
retired neurosurgeon. Since 1987, he has been a director of Newpark Resources,
Inc., a company engaged primarily in providing oil field services.
Raymond K. Mason, Sr., has been Chairman of the Board of Directors of
American Banks of Florida, Inc., since 1978.
Bruce A. Smith has been Chairman of the Board of Directors, President and
Chief Executive Officer of the Company since June 1996. He has been a director
of the Company since July 1995. Mr. Smith was President and Chief Executive
Officer of the Company from September 1995 to June 1996; Executive Vice
President, Chief Financial Officer and Chief Operating Officer of the Company
from July 1995 to September 1995; Executive Vice President responsible for
Exploration and Production and Chief Financial Officer of the Company from
September 1993 to July 1995.
Patrick J. Ward has 47 years of experience in international energy
operations with Caltex Petroleum Corporation, a 50/50 joint venture of Chevron
Corp. and Texaco, Inc., engaged in the business of refining and marketing. Prior
to his retirement in August 1995, he was Chairman, President and Chief Executive
Officer of Caltex, positions he had held since 1990. Mr. Ward served on the
Board of Directors of Caltex from 1989 to 1995.
Murray L. Weidenbaum, an economist and educator, has been the Mallinckrodt
Distinguished University Professor and Chairman of the Center for the Study of
American Business at Washington University in St. Louis, Missouri, since 1975.
Dr. Weidenbaum is a director of May Department Stores Company.
No director of the Company has a family relationship with any other
director or executive officer of the Company.
87
88
EXECUTIVE OFFICERS OF THE REGISTRANT
The following is a list of the Company's executive officers, their ages and
their positions with the Company at March 1, 1999.
POSITION HELD
NAME AGE POSITION SINCE
---- --- -------- -------------
Bruce A. Smith........... 55 Chairman of the Board of Directors, June 1996
President and Chief Executive Officer
William T. Van Kleef..... 47 Executive Vice President and Chief July 1998
Operating Officer
James C. Reed, Jr........ 54 Executive Vice President, General Counsel September 1995
and Secretary
Thomas E. Reardon........ 52 Senior Vice President, Corporate Resources May 1998
Donald A. Nyberg......... 47 President, Tesoro Marine Services, Inc. November 1996
Robert W. Oliver......... 44 President, Tesoro Exploration and September 1995
Production Company
Stephen L. Wormington.... 54 Executive Vice President and Chief May 1998
Operating Officer, Tesoro Refining,
Marketing & Supply Company
Don E. Beere............. 58 Vice President, Information Technology May 1998
Projects
Bobby J. Culpepper....... 49 Vice President, Information Technology July 1998
Don M. Heep.............. 49 Vice President, Controller May 1998
Gregory A. Wright........ 49 Vice President, Finance and Treasurer May 1998
There are no family relationships among the officers listed, and there are
no arrangements or understandings pursuant to which any of them were elected as
officers. Officers are elected annually by the Board of Directors at its first
meeting following the Annual Meeting of Stockholders, each to hold office until
the corresponding meeting of the Board in the next year or until a successor
shall have been elected or shall have qualified.
The 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.
Thomas E. Reardon........... Senior Vice President, Corporate Resources
since May 1998. Vice President, Human Resources
and Environmental, from September 1995 to May
1998. 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.
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,
88
89
Exploration/Acquisitions, of Bridge Oil (USA)
Inc. from December 1988 to November 1994.
Stephen L. Wormington....... Executive Vice President and Chief Operating
Officer of Tesoro Refining, Marketing & Supply
Company, a subsidiary of the Company, since May
1998. President of Tesoro Alaska Petroleum
Company, a subsidiary of the Company, from
September 1995 to August 1998. 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.
Bobby J. Culpepper.......... Vice President, Information Technology since
July 1998. Vice President, Information
Technology, of Tesoro Petroleum Companies,
Inc., a subsidiary of the Company, since June
1998. Vice President, Operations of Microage
Integration Group from July 1997 to May 1998.
Vice President, Information Technology, of
Phillips 66 Company, a division of Phillips
Petroleum Company from May 1991 to June 1997.
Don M. Heep................. Vice President, Controller since May 1998.
Senior Vice President, Administration for
Tesoro Alaska Petroleum Company, a subsidiary
of the Company, from November 1996 to May 1998.
Senior Vice President and Chief Financial
Officer of Valero Energy Corporation from 1994
to 1996. Vice President and Chief Accounting
Officer of Valero Energy Corporation from 1992
to 1994.
Gregory A. Wright........... Vice President, Finance and Treasurer since May
1998. Vice President and Treasurer from
September 1995 to May 1998. 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.
SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Securities Exchange Act of 1934, as amended ("Exchange
Act"), requires the Company's directors, executive officers and holders of more
than 10% of the Company's voting stock to file with the Securities and Exchange
Commission ("SEC") initial reports of ownership and reports of changes in
ownership of Common Stock or other equity securities of the Company. The Company
believes that during the fiscal year ended December 31, 1998, its directors,
executive officers and holders of more than 10% of the Company's voting stock
complied with all Section 16(a) filing requirements with the following
exception: Mr. Grapstein failed to timely report an aggregate of eleven
transactions in January 1998 with respect to 131,000 shares of the Company's
Common Stock sold by Oakville, of which Mr. Grapstein is a Vice President; and a
transaction in July 1998 with respect to 4,000 Premium Income Equity Securities
("PIES"), for which he disclaims beneficial ownership, acquired for the accounts
of Mr. Grapstein's minor children.
89
90
ITEM 11. EXECUTIVE COMPENSATION
COMPENSATION OF EXECUTIVE OFFICERS
SUMMARY OF COMPENSATION
The following table contains information concerning the annual and
long-term compensation for services in all capacities to the Company for fiscal
years ended December 31, 1998, 1997 and 1996, of those persons who were on
December 31, 1998, (i) the Chief Executive Officer and (ii) the other four most
highly compensated officers of the Company (collectively, the "named executive
officers").
SUMMARY COMPENSATION TABLE
LONG-TERM COMPENSATION
---------------------------------------------
ANNUAL COMPENSATION AWARDS
---------------------------------- -------------------------------- PAYOUTS
OTHER ANNUAL RESTRICTED SECURITIES ----------
SALARY BONUS COMPENSATION STOCK UNDERLYING OPTIONS LTIP
NAME AND PRINCIPAL POSITION YEAR ($) ($) ($)(A) AWARD(S)($) /SARS(#)(B) PAYOUTS($)
--------------------------- ---- -------- -------- ------------ ----------- ------------------ ----------
Bruce A. Smith................ 1998 $616,667 $640,000 $-- -- 281,900 $4,087,500(c)
Chairman of the Board 1997 578,269 715,000 -- -- 175,000 --
of Directors, President 1996 510,096 680,960 -- (c) 170,000 --
and Chief Executive Officer
William T. Van Kleef.......... 1998 $345,833 $325,000 $-- -- 166,020 $1,532,813(c)
Executive Vice President 1997 290,231 320,000 -- -- 60,000 --
and Chief Operating 1996 236,269 248,900 -- (c) 100,000 --
Officer
James C. Reed, Jr............. 1998 $308,333 $285,000 $-- -- 48,860 $1,532,813(c)
Executive Vice President, 1997 278,269 295,000 -- -- 45,000 --
General Counsel and 1996 243,673 232,750 -- (c) 50,000 --
Secretary
Stephen L. Wormington (e)..... 1998 $290,000 $250,000 $-- -- 43,780 $ (c)
Executive Vice President 1997 268,269 280,000 -- -- 45,000 --
and Chief Operating 1996 -- -- -- -- (c) --
Officer, Tesoro Refining,
Marketing & Supply Company
Robert W. Oliver(e)........... 1998 $230,000 $173,000 $-- -- 31,390 $ (c)
President, Tesoro
Exploration 1997 208,269 210,000 -- -- 25,000 --
and Production Company 1996 -- -- -- -- (c) --
ALL OTHER
COMPENSATION
NAME AND PRINCIPAL POSITION ($)(D)
--------------------------- ------------
Bruce A. Smith................ $1,359,460
Chairman of the Board 1,142,017
of Directors, President 790,751
and Chief Executive Officer
William T. Van Kleef.......... $ 466,900
Executive Vice President 369,341
and Chief Operating 216,207
Officer
James C. Reed, Jr............. $ 877,859
Executive Vice President, 914,363
General Counsel and 1,004,676
Secretary
Stephen L. Wormington (e)..... $ 6,400
Executive Vice President 6,400
and Chief Operating --
Officer, Tesoro Refining,
Marketing & Supply Company
Robert W. Oliver(e)........... $ 6,723
President, Tesoro
Exploration 6,400
and Production Company --
- ---------------
(a) No payments were made to the named executive officers which are reportable
in Other Annual Compensation. The aggregate amount of perquisites and other
personal benefits was less than either $50,000 or 10% of the total annual
salary and bonus reported for the named executive officers for all periods
shown.
(b) Amounts represent traditional stock options granted to each named executive
officer during 1998, 1997 and 1996, except for grants to Mr. Smith in 1997
which were in the form of phantom stock options. At the discretion of the
Compensation Committee of the Board of Directors, the 175,000 phantom stock
options granted to Mr. Smith in 1997 may be converted to traditional stock
options under the Amended and Restated Executive Long-Term Incentive Plan
("1993 Plan"). See table, "Long-Term Incentive Plans-Awards in 1998," on
page 92 for information related to contingent awards of phantom stock and
cash bonus opportunities under the 1998 Performance Incentive Compensation
Plan ("1998 Performance Plan").
(c) In 1996, the Compensation Committee of the Board of Directors approved a
special incentive strategy comprised of long-term performance-vested
restricted stock and stock options for the executive officers. Awards of
restricted Common Stock and stock options under this strategy were earned
when the market price of the Company's Common Stock reached an average price
of $20 or higher over any 20 consecutive trading days after June 30, 1997,
and before December 31, 1998 ("Performance Target"). In connection with this
strategy, Messrs. Smith, Van Kleef and Reed were awarded 200,000, 75,000 and
75,000 shares, respectively, of restricted Common Stock, and Messrs.
Wormington and Oliver were each granted 75,000 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). On May
12, 1998, the
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Performance Target was achieved which resulted in the lapse of restrictions
on the restricted Common Stock and vesting of the stock options. Long-term
incentive plan ("LTIP") payouts presented above represent the shares of
Common Stock awarded under the incentive compensation strategy times
$20.4375 per share, or the average market price of the Company's Common
Stock on the day of reaching the Performance Target. Although Mr. Wormington
and Mr. Oliver became fully vested in the stock options granted under this
strategy upon reaching the Performance Target, none of the stock options
have been exercised.
(d) All Other Compensation for 1998 includes amounts contributed by the Company
and earnings on the respective executive officer's account in the Funded
Executive Security Plan (see "Retirement Benefits" below) of $1,353,060,
$460,500 and $871,459 for Mr. Smith, Mr. Van Kleef and Mr. Reed,
respectively; and amounts contributed to the Company's Thrift Plan of $6,400
each for Mr. Smith, Mr. Van Kleef, Mr. Reed and Mr. Wormington and $6,723
for Mr. Oliver. All Other Compensation for 1997 includes amounts contributed
by the Company and earnings on the respective executive officer's account in
the Funded Executive Security Plan of $1,135,617, $362,941 and $907,963 for
Mr. Smith, Mr. Van Kleef and Mr. Reed, respectively; and amounts contributed
to the Company's Thrift Plan of $6,400 for each of the named executive
officers. All Other Compensation for 1996 includes amounts contributed by
the Company and earnings on the respective executive officer's account in
the Funded Executive Security Plan of $786,251, $211,707 and $1,000,176 for
Mr. Smith, Mr. Van Kleef and Mr. Reed, respectively; and amounts contributed
to the Company's Thrift Plan of $4,500 for each of these executive officers.
(e) Since Mr. Wormington and Mr. Oliver were not considered executive officers
during 1996, information is not given for that year.
OPTION GRANTS IN 1998
The following table sets forth information concerning individual grants of
traditional stock options pursuant to the 1993 Plan to the named executive
officers during the year ended December 31, 1998. No Stock Appreciation Rights
("SARs") were granted under the 1993 Plan during 1998.
OPTION GRANTS IN 1998
INDIVIDUAL GRANTS POTENTIAL REALIZABLE VALUE
------------------------------------------------------ AT ASSUMED ANNUAL RATES
NUMBER OF % OF TOTAL OF STOCK PRICE
SECURITIES OPTIONS APPRECIATION
UNDERLYING GRANTED TO EXERCISE OR FOR OPTION TERM
OPTIONS EMPLOYEES BASE PRICE EXPIRATION --------------------------
NAME GRANTED(#)(A) IN 1998 ($/SHARE)(B) DATE 5%($) 10%($)
---- ------------- ---------- ------------ ---------- ----------- -----------
Bruce A. Smith.......... 281,900 35.5 $ 15.9375 10/27/08 $2,825,487 $7,160,337
William T. Van Kleef.... 166,020 20.9 15.9375 10/27/08 1,664,021 4,216,954
James C. Reed, Jr....... 48,860 6.1 15.9375 10/27/08 489,722 1,241,061
Stephen L. Wormington... 43,780 5.5 15.9375 10/27/08 438,808 1,112,026
Robert W. Oliver........ 31,390 3.9 15.9375 10/27/08 314,624 797,315
- ---------------
(a) The right to exercise these options vests in four equal annual installments
beginning one year from the date of grant.
(b) The exercise price per share is equal to the public offering price of a
share of the Company's Common Stock on July 1, 1998, which was above the
market price for the Company's Common Stock on the date of grant of these
options in October 1998.
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AGGREGATED OPTION/SAR EXERCISES IN 1998 AND OPTION/SAR VALUES AT DECEMBER 31,
1998
The following table reflects the number of unexercised stock options and
SARs remaining at year-end and the potential value thereof based on the year-end
market price of the Company's Common Stock of $12 1/8 per share. No stock
options or SARs were exercised by the named executive officers during 1998.
NUMBER OF SECURITIES VALUE OF UNEXERCISED
UNDERLYING UNEXERCISED IN-THE-MONEY
OPTIONS/SARS AT OPTIONS/SARS AT
SHARES DECEMBER 31, 1998(#) DECEMBER 31, 1998($)
ACQUIRED ON VALUE --------------------------- ---------------------------
NAME EXERCISE(#) REALIZED($) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
---- ----------- ----------- ----------- ------------- ----------- -------------
Bruce A. Smith........... -- -- 356,384(a) 541,516(a) $1,216,600 $202,275
William T. Van Kleef..... -- -- 118,706 254,614 188,315 40,204
James C. Reed, Jr........ -- -- 92,384 112,476 207,225 46,650
Stephen L. Wormington.... -- -- 144,916(b) 110,864 149,250 62,000
Robert W. Oliver......... -- -- 112,916(b) 68,474 114,375 38,750
- ---------------
(a) The number of unexercised options/SARs include 26,250 exercisable phantom
stock options and 148,750 unexercisable phantom stock options which were
granted to Mr. Smith in 1997.
(b) The number of exercisable options for Mr. Wormington and Mr. Oliver includes
75,000 stock options each which were earned in May 1998 when the Performance
Target was attained under the special incentive compensation strategy.
LONG-TERM INCENTIVE PLANS -- AWARDS IN 1998
In October 1998, the Company's Board of Directors unanimously approved the
1998 Performance Incentive Compensation Plan ("1998 Performance Plan"), which is
intended to advance the best interests of the Company and its stockholders by
directly targeting Company performance to align with the ninetieth percentile
historical stock-price growth rate for the Company's peer group. In addition,
the 1998 Performance Plan will provide the Company's employees with additional
compensation, contingent upon achievement of the targeted objectives, thereby
encouraging them to continue in the employ of the Company. The 1998 Performance
Plan has several tiers of awards, with the award generally determined by job
level. The following table and notes thereto provide information concerning
contingent long-term incentive awards granted under the 1998 Performance Plan to
the named executive officers during the year ended December 31, 1998. The
long-term incentive awards under the 1998 Performance Plan are not included in
the Summary Compensation Table on page 90.
LONG-TERM INCENTIVE PLANS -- AWARDS IN 1998
ESTIMATED FUTURE PAYOUTS
NUMBER OF PERFORMANCE UNDER NON-STOCK
SHARES, UNITS OR OTHER PRICE-BASED PLANS
OR OTHER PERIOD UNTIL ------------------------
RIGHTS MATURATION THRESHOLD MAXIMUM
(#) OR PAYOUT(a) ($ OR #) ($ OR #)
------------- ------------ --------- -----------
Bruce A. Smith.............................. 340,000(b) (a)
William T. Van Kleef........................ 190,000(b) (a)
James C. Reed, Jr........................... 125,000(b) (a)
Stephen L. Wormington....................... -- (a) $377,000(c) $1,508,000(c)
Robert W. Oliver............................ -- (a) $239,200(c) $ 956,800(c)
- ---------------
(a) Under the 1998 Performance Plan, targeted objectives are comprised of the
fair market value of the Company's Common Stock equaling or exceeding an
average of $35 per share ("First Performance Target") and $45 per share
("Second Performance Target") on any 20 consecutive trading days during a
period commencing on October 1, 1998 and ending on the earlier of September
30, 2002, or the date on which the Second Performance Target is achieved
("Performance Period"). Upon achievement of the
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First Performance Target, one-fourth of the contingent awards will be
earned, with payout deferred until the end of the Performance Period. The
remaining 75% will be earned only upon achievement of the Second Performance
Target.
(b) Shares represent contingent awards of performance-vested phantom stock
granted to Mr. Smith, Mr. Van Kleef and Mr. Reed. If the Second Performance
Target is achieved, the executive officer would be entitled to receive in
cash an amount equal to the number of shares of phantom stock granted to him
multiplied by the fair market value of a share of Common Stock on the last
day of the Performance Period. If the First Performance Target is attained
but the Second Performance is not attained, the executive officer would
receive one-fourth of the amount specified in the preceding sentence.
(c) Mr. Wormington and Mr. Oliver were awarded contingent cash bonus
opportunities under the Performance Plan. If the Second Performance Target
is achieved, Mr. Wormington and Mr. Oliver would be entitled to receive a
cash bonus equal to five times and four times, respectively, of their annual
"basic compensation," as defined in the 1998 Performance Plan. If the First
Performance Target is attained but the Second Performance is not attained,
Mr. Wormington and Mr. Oliver would receive one-fourth of the amount
specified in the preceding sentence. Based on current salary rates for Mr.
Wormington and Mr. Oliver, estimated future payouts shown above represent
the attainment of the First Performance Target (vesting in one-fourth of the
award) under "Threshold" and the attainment of the Second Performance Target
(earning 100% of the award) under "Maximum."
RETIREMENT BENEFITS
The Company maintains a noncontributory qualified Retirement Plan which
covers officers and other eligible employees. Benefits under the plan are
payable on a straight life annuity basis and are based on the average monthly
earnings and years of service of participating employees. Average monthly
earnings used in calculating retirement benefits are primarily salary and bonus
received by the participating employee during the 36 consecutive months of the
last 120 months of service which produces the highest average monthly rate of
earnings.
In addition, the Company maintains an unfunded executive security plan, the
Amended Executive Security Plan ("Amended Plan"), for executive officers and
other key personnel selected by the Chief Executive Officer. The Amended Plan
provides for a monthly retirement income payment during retirement equal to a
percentage of a participant's Earnings. "Earnings" is defined under the Amended
Plan to mean a participant's average monthly rate of total compensation,
primarily salary and bonus earned, including performance bonuses and incentive
compensation paid after December 1, 1993, in the form of stock awards of the
Company's Common Stock (excluding stock awards under the special incentive
compensation strategy and contingent awards under the 1998 Performance Plan),
for the 36 consecutive calendar months within the last ten-year period which
produce the highest average monthly rate of compensation for the participant.
The monthly retirement benefit percentage is defined as the sum of 4 percent of
Earnings for each of the first ten years of employment, plus 2 percent of
Earnings for each of the next ten years of employment, plus 1 percent of
Earnings for each of the next ten years of employment. The maximum percentage is
70 percent. The Amended Plan provides for the payment of the difference, if any,
between (a) the total retirement income payment calculated above and (b) the sum
of retirement income payments from the Company's Retirement Plan and Social
Security benefits.
The Company also maintains the Funded Executive Security Plan ("Funded
Plan") which covers only selected persons approved by the Chief Executive
Officer, who are also participants in the Amended Plan, and provides
participants with substantially the same aftertax benefits as the Amended Plan.
Advance payments are made to the extent a participant is expected to incur a
pre-retirement tax liability as a result of his participation in the Funded
Plan. The Funded Plan is funded separately for each participant on an
actuarially determined basis through a bank trust whose primary asset is an
insurance contract providing for a guaranteed rate of return for certain
periods. Amounts payable to participants from the Funded Plan reduce amounts
otherwise payable under the Amended Plan.
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The following table shows the estimated annual benefits payable upon
retirement under the Company's Retirement Plan, Amended Plan and the Funded Plan
for employees in specified compensation and years of benefit service
classifications without reference to any amount payable upon retirement under
the Social Security law or any amount advanced before retirement. The estimated
annual benefits shown are based upon the assumption that the plans continue in
effect and that the participant receives payment for life. For limitation years
ending with or within calendar year 1998 or 1999, the federal tax law generally
limits maximum annual retirement benefits payable by the Retirement Plan to any
employee to $130,000, adjusted annually to reflect increases in the cost of
living and adjusted actuarially for retirement. However, since the Amended Plan
and the Funded Plan are not qualified under Section 401 of the Internal Revenue
Code of 1986, as amended (the "Code"), it is possible for certain retirees to
receive annual benefits in excess of this tax limitation.
HIGHEST AVERAGE NUMBER OF YEARS OF BENEFIT SERVICE
ANNUAL RATE --------------------------------------------
OF COMPENSATION 10 15 20 25
--------------- -------- -------- -------- --------
$ 100,000....................................... $ 40,000 $ 50,000 $ 60,000 $ 65,000
$ 200,000....................................... $ 80,000 $100,000 $120,000 $130,000
$ 300,000....................................... $120,000 $150,000 $180,000 $195,000
$ 400,000....................................... $160,000 $200,000 $240,000 $260,000
$ 500,000....................................... $200,000 $250,000 $300,000 $325,000
$ 600,000....................................... $240,000 $300,000 $360,000 $390,000
$ 700,000....................................... $280,000 $350,000 $420,000 $455,000
$ 800,000....................................... $320,000 $400,000 $480,000 $520,000
$ 900,000....................................... $360,000 $450,000 $540,000 $585,000
$1,000,000...................................... $400,000 $500,000 $600,000 $650,000
$1,100,000...................................... $440,000 $550,000 $660,000 $715,000
$1,200,000...................................... $480,000 $600,000 $720,000 $780,000
$1,300,000...................................... $520,000 $650,000 $780,000 $845,000
The years of benefit service as of December 31, 1998, for the named
executive officers were as follows: Mr. Smith, 6 years; Mr. Van Kleef, 5 years;
Mr. Reed, 24 years; Mr. Wormington, 4 years; and Mr. Oliver, 3 years.
In addition to the retirement benefits described above, the Amended Plan
provides for a pre-retirement death benefit payable over eight years of four
times a participant's annual base pay as of December 1 preceding a participant's
date of death, less the amount payable from the Funded Plan at the date of
death. The amount payable from the Funded Plan at death is based on the
actuarial value of the participant's vested accrued benefit, payable in 96
monthly installments or as a life annuity if a surviving spouse is the
designated beneficiary.
COMPENSATION OF DIRECTORS
Each member of the Board of Directors who is not an officer of the Company
receives a base retainer of $18,000 per year, and an additional $2,000 for each
meeting of the Board of Directors or any committee thereof attended in person,
and $1,000 for each telephone meeting, including committee meetings held on the
same day as a meeting of the Board of Directors. The non-executive Vice Chairman
of the Board of Directors receives $25,000 per year for his service. In
addition, the Chairman of the Audit Committee, Chairman of the Compensation
Committee and Chairman of the Governance Committee each receive $5,000 per year
for their service in such positions. The Company provides group life insurance
benefits in the amount of $100,000 and accidental death and dismemberment
insurance up to a maximum of $350,000 for each of the members of the Board of
Directors who are not employees of the Company. The premium for such insurance
ranged from $265 to $5,844 for each of these directors during fiscal year 1998.
Commencing with the 1997 Annual Meeting of Stockholders, one-half of each of the
director's annual retainer is paid in Common Stock of the Company on an annual
basis. The Company issues to each director within 30 days after the annual
meeting of
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stockholders of the Company at which the director is elected a number of shares
equal to one-half of the annual retainer in effect on the date of such meeting
divided by the average of the closing prices for the Common Stock, as reported
on the New York Stock Exchange ("NYSE") composite tape, for the ten trading days
prior to such annual meeting. The shares of Common Stock issued to the directors
will be held by the Company and will not be sold, pledged or otherwise disposed
of and will not be delivered to the directors until the earlier of (i) the first
anniversary date of the annual meeting which immediately preceded the issuance
of such shares or (ii) the date on which the person ceases to be a director. The
directors will have full voting rights with respect to such shares of Common
Stock.
The Company had established an unfunded Non-Employee Director Retirement
Plan ("Director Retirement Plan") in December 1994 which provided that any
eligible non-employee director who elected to participate in the Director
Retirement Plan and 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' interest, in March 1997, the
Board of Directors amended the Director Retirement Plan to freeze the plan and
convert the accrued benefits of each current director under the plan to a
lump-sum present value which was transferred to an account ("Account") for each
director 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. By participating in the Phantom
Stock Plan, each director waives any and all rights under the Director
Retirement Plan. Commencing with 1997, each current and future non-employee
director ("Participant") shall have credited to his Account as of the last day
of the year a yearly accrual equal to $7,250, prorated to $6,042 for 1997
(limited to 15 accruals, including previous accruals of retirement benefits
under the Director Retirement Plan); and each Participant who is serving as a
chairman of a committee of the Board of Directors immediately prior to his
termination as director and who has served at least three years as a director
shall have an additional $5,000 credited to his Account. The Phantom Stock Plan
allows for pro rata calculations of the yearly accrual in the event a director
serves for part of a year. In addition, a Participant may elect to defer any
part or all of the cash portion of his annual director retainer into his
Account. Each transfer, accrual or deferral shall be credited quarterly to the
Participant's Account in units based upon the number of shares that could have
been purchased with the dollars credited based upon the closing price of the
Company's Common Stock on the NYSE on the date the amount is credited. Dividends
or other distributions accrue to the Participant's Account. Participants are
vested 100 percent at all times with respect to deferrals and, if applicable,
the chairman fee portion of his Account. Participants vest in amounts
transferred from the Director Retirement Plan and the yearly accruals upon
completion of three full years of service (including all service prior to March
6, 1997) as a member of the Board. If a Participant voluntarily resigns or is
removed from the Board prior to serving three years on the Board, he shall
forfeit all amounts not vested. If a director dies, retires, or becomes
disabled, he shall be 100 percent vested in his Account without regard to
services. Distributions from the Phantom Stock Plan shall be made in cash, based
on the closing market price of the Company's Common Stock on the NYSE on the
business day immediately preceding the date on which the cash distribution is to
be made, and such distributions shall be made in either a lump-sum distribution
or in annual installments not exceeding ten years. Death, disability, retirement
or cessation of a Participant as a director of the Company constitute an event
requiring a distribution. Upon the death of a Participant, the Participant's
beneficiary will receive as soon as practicable the cash value of the
Participant's Account as of the date of death. At December 31, 1998, each
Participant's Account was comprised of 4,474 units, 1,767 units, 2,299 units,
14,736 units, 2,209 units and 7,433 units of phantom stock for Messrs.
Grapstein, Johnson, Kaufman, Mason, Ward and Weidenbaum, respectively.
Under the Tesoro Petroleum Corporation Board of Directors Deferred
Compensation Plan ("Deferred Compensation Plan"), a director electing to
participate may defer between 20 percent and 100 percent of his total cash
compensation for the ensuing year, which deferred fees are credited to an
interest-bearing account maintained by the Company. Interest is applied to each
quarter's deferral at the prime rate published in The Wall Street Journal on the
last business day of such quarter plus two percentage points (9.75% at December
31, 1998). All payments under the Deferred Compensation Plan are the sole
obligation of the
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Company. Upon the death of a participating director, the balance in his account
under the Deferred Compensation Plan is paid to his beneficiary or beneficiaries
in one lump sum. In the event of the disability, retirement or the removal or
resignation prior to the death, disability or retirement of a participating
director, the balance in his account will be paid to such director in ten equal
annual installments. In the event of a change of control (as "change of control"
is defined in the Deferred Compensation Plan), the balance in each participating
director's account will be distributed to him as a lump sum within 30 days after
the date of the change of control. The Company also has an agreement with Frost
National Bank of San Antonio, Texas, under which the Tesoro Petroleum
Corporation Board of Directors Deferred Compensation Trust was established for
the sole purpose of creating a fund to provide for the payment of deferred
compensation to participating directors under the Deferred Compensation Plan.
The Company's 1995 Non-Employee Director Stock Option Plan ("1995 Plan")
provides for the grant to non-employee directors of automatic, non-discretionary
stock options, at an exercise price equal to the fair market value of the Common
Stock as of the date of grant. Under the 1995 Plan, each person serving as a
non-employee director on February 23, 1995, or elected thereafter, initially
receives an option to purchase 5,000 shares of the Company's 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.
All options under the 1995 Plan become exercisable six months after the date of
grant. The 1995 Plan will terminate as to the issuance of stock options in
February 2005. Under the 1995 Plan, stock options for 1,000 shares with an
exercise price of $16.1875 per share were granted to each non-employee director
of the Company on July 30, 1998. At March 1, 1999, the Company had 62,000
options outstanding and 71,000 shares available for future grants under the 1995
Plan.
EMPLOYMENT CONTRACTS, MANAGEMENT STABILITY AGREEMENTS
AND CHANGE-IN-CONTROL ARRANGEMENTS
Under an amendment effective October 28, 1998 to an employment agreement
dated November 1, 1997, Mr. Smith is employed until November 1, 2000, at an
annual base salary of $700,000. Under separate employment agreements, Mr. Van
Kleef and Mr. Reed are employed until October 28, 2000, at annual base salaries
of $450,000 and $350,000, respectively. In addition to their base salaries, each
of the employment agreements for the above executives provides that the Company
shall establish an annual incentive compensation strategy for executive officers
in which each executive shall be entitled to participate in a manner consistent
with his position with the Company and the evaluations of his performance by the
Board of Directors or any appropriate committee thereof. The target incentive
bonus under the 1998 annual incentive compensation strategy was a percentage of
the respective executive officer's annual base salary and was 100% for Mr.
Smith, 90% for Mr. Van Kleef and 75% for Mr. Reed. Each of the employment
agreements also provides that the executive will receive an annual amount
("flexible perquisite amount") to cover various business-related expenses such
as dues for country, luncheon or social clubs; automobile expenses; and
financial and tax planning expenses. The executive may elect at any time by
written notice to the Company to receive in cash any of such flexible perquisite
amount which has not been paid to or on behalf of the executive. The annual
flexible perquisite amount is $30,000, $20,000 and $20,000 for Mr. Smith, Mr.
Van Kleef and Mr. Reed, respectively. Each employment agreement also provides
that the Company will pay initiation fees for social clubs and reimburse the
executive for related tax expenses to the extent the Board of Directors, or a
duly authorized committee thereof, determines such fees are reasonable and in
the best interest of the Company.
Each of the employment agreements with Mr. Smith, Mr. Van Kleef and Mr.
Reed provides that in the event the Company should terminate such executive
officer's employment without cause, if he should resign his employment for "good
reason" (as "good reason" is defined in the employment agreements), or if the
Company shall not have offered to such executive officer prior to the
termination date of his employment agreement the opportunity to enter into a new
employment agreement, with terms, in all respects, no less favorable to the
executive than the terms of his current employment agreement, such executive
will be paid a lump-sum payment equal to (i) two times the sum of (a) his base
salary at the then current rate and (b) the
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sum of the target bonuses under all of the Company's incentive bonus plans
applicable to such executive for the year in which the termination occurs and
(ii) if termination occurs in the fourth quarter of a calendar year, the sum of
the target bonuses under all of the Company's incentive bonus plans applicable
to such executive for the year in which the termination occurs prorated daily
based on the number of days from the beginning of the calendar year in which the
termination occurs to and including the date of termination. Each executive
shall also receive all unpaid bonuses for the year prior to the year in which
the termination occurs and shall receive (i) for a period of two years
continuing coverage and benefits comparable to all life, health and disability
insurance plans which the Company from time to time makes available to its
management executives and their families, (ii) a lump-sum payment equal to two
times the flexible perquisites amount and (iii) two years additional service
credit under the Amended Plan and the Funded Plan, or successors thereto, of the
Company applicable to such executive on the date of termination. All unvested
stock options held by the executive on the date of the termination shall become
immediately vested and all restrictions on "restricted stock" then held by the
executive shall terminate, except for awards under the 1998 Performance Plan.
Each employment agreement further provides that, in the event such
executive officer's employment is involuntarily terminated within two years of a
change of control or if the executive officer's employment is voluntarily
terminated within two years of a change of control "for good reason," as defined
in each of the employment agreements, he shall be paid within ten days of such
termination (i) a lump-sum payment equal to three times his base salary at the
then current rate; (ii) a lump-sum payment equal to the sum of (a) three times
the sum of the target bonuses under all of the Company's incentive bonus plans
applicable to such executive for the year in which the termination occurs or the
year in which the change of control occurred, whichever is greater, and (b) if
termination occurs in the fourth quarter of a calendar year, the sum of the
target bonuses under all of the Company's incentive bonus plans applicable to
such executive for the year in which the termination occurs prorated daily based
on the number of days from the beginning of the calendar year in which the
termination occurs to and including the date of termination; and (iii) a
lump-sum payment equal to the amount of any accrued but unpaid bonuses. The
Company (or its successor) shall also provide (i) for a period of three years
continuing coverage and benefits comparable to all life, health and disability
plans of the Company in effect at the time a change of control is deemed to have
occurred; (ii) a lump-sum payment equal to three times the flexible perquisites
amount; and (iii) three years additional service credit under the Amended Plan
and the Funded Plan, or successors thereto, of the Company applicable to such
executive on the date of termination. A change in control shall be deemed to
have occurred if (i) there shall be consummated (a) any consolidation or merger
of the Company in which the Company is not the continuing or surviving
corporation or pursuant to which shares of the Company's Common Stock would be
converted into cash, securities or other property, other than a merger of the
Company where a majority of the Board of Directors of the surviving corporation
are, and for a two-year period after the merger continue to be, persons who were
directors of the Company immediately prior to the merger or were elected as
directors, or nominated for election as director, by a vote of at least
two-thirds of the directors then still in office who were directors of the
Company immediately prior to the merger, or (b) any sale, lease, exchange or
transfer (in one transaction or a series of related transactions) of all or
substantially all of the assets of the Company, or (ii) the shareholders of the
Company shall approve any plan or proposal for the liquidation or dissolution of
the Company, or (iii)(A) any "person" (as such term is used in Sections 13(d)
and 14(d)(2) of the Exchange Act) other than the Company or a subsidiary thereof
or any employee benefit plan sponsored by the Company or a subsidiary thereof,
shall become the beneficial owner (within the meaning of Rule 13d-3 under the
Exchange Act) of securities of the Company representing 20 percent or more of
the combined voting power of the Company's then outstanding securities
ordinarily (and apart from rights accruing in special circumstances) having the
right to vote in the election of directors, as a result of a tender or exchange
offer, open market purchases, privately negotiated purchases or otherwise, and
(B) at any time during a period of two years thereafter, individuals who
immediately prior to the beginning of such period constituted the Board of
Directors of the Company shall cease for any reason to constitute at least a
majority thereof, unless the election or the nomination by the Board of
Directors for election by the Company's shareholders of each new director during
such period was approved by a vote of at least two-thirds of the directors then
still in office who were directors at the beginning of such period.
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Each employment agreement further provides that if remuneration or benefits
of any form paid to them by the Company or any trust funded by the Company
during or after their employment with the Company are excess parachute payments
as defined in Section 280G of the Code, and are subject to the 20 percent excise
tax imposed by Section 4999 of the Code, the Company shall pay Mr. Smith, Mr.
Van Kleef and Mr. Reed a bonus no later than seven days prior to the due date
for the excise tax return in an amount equal to the excise tax payable as a
result of the excess parachute payment and any additional federal income taxes
(including any additional excise taxes) payable by them as a result of the
bonus, assuming that they will be subject to federal income taxes at the highest
individual margin rate.
The Company has separate Management Stability Agreements ("Stability
Agreements") with Mr. Wormington and Mr. Oliver which are only operative in the
event of a change of control of the Company. The Stability Agreements provide
that, if Mr. Wormington's or Mr. Oliver's employment is involuntarily terminated
within two years of a change of control or if Mr. Wormington's or Mr. Oliver's
employment is voluntarily terminated within two years of a change of control
"for good reason," as defined in the Stability Agreements, he shall be paid
within ten days of such termination (i) a lump-sum payment equal to two times
his base salary at the then current rate and (ii) a lump-sum payment equal to
the sum of (a) two times the sum of the target bonuses under all of the
Company's incentive bonus plans applicable to Mr. Wormington and Mr. Oliver for
the year in which the termination occurs or the year in which the change of
control occurred, whichever is greater, and (b) if termination occurs in the
fourth quarter of a calendar year, the sum of the target bonuses under all of
the Company's incentive bonus plans applicable to Mr. Wormington and Mr. Oliver
for the year in which the termination occurs prorated daily based on the number
of days from the beginning of the calendar year in which the termination occurs
to and including the date of termination. The Company (or its successor) shall
also provide continuing coverage and benefits comparable to all life, health and
disability plans of the Company for a period of 24 months from the date of
termination and Mr. Wormington and Mr. Oliver would each receive two years
additional service credit under the Amended Plan and the Funded Plan, or
successors thereto, of the Company applicable to such executive on the date of
termination. A change of control shall be deemed to have occurred if (i) there
shall be consummated (a) any consolidation or merger of the Company in which the
Company is not the continuing or surviving corporation or pursuant to which
shares of the Company's Common Stock would be converted into cash, securities or
other property, other than a merger of the Company where a majority of the Board
of Directors of the surviving corporation are, and for a two-year period after
the merger continue to be, persons who were directors of the Company immediately
prior to the merger or were elected as directors, or nominated for election as
director, by a vote of at least two-thirds of the directors then still in office
who were directors of the Company immediately prior to the merger, or (b) any
sale, lease, exchange or transfer (in one transaction or a series of related
transactions) of all or substantially all of the assets of the Company, or (ii)
the shareholders of the Company shall approve any plan or proposal for the
liquidation or dissolution of the Company, or (iii)(A) any "person" (as such
term is used in Sections 13(d) and 14(d)(2) of the Exchange Act) other than the
Company or a subsidiary thereof or any employee benefit plan sponsored by the
Company or a subsidiary thereof, shall become the beneficial owner (within the
meaning of Rule 13d-3 under the Exchange Act) of securities of the Company
representing 20 percent or more of the combined voting power of the Company's
then outstanding securities ordinarily (and apart from rights accruing in
special circumstances) having the right to vote in the election of directors, as
a result of a tender or exchange offer, open market purchases, privately
negotiated purchases or otherwise, and (B) at any time during a period of one
year thereafter, individuals who immediately prior to the beginning of such
period constituted the Board of Directors of the Company shall cease for any
reason to constitute at least a majority thereof, unless the election or the
nomination by the Board of Directors for election by the Company's shareholders
of each new director during such period was approved by a vote of at least
two-thirds of the directors then still in office who were directors at the
beginning of such period, or (iv) there shall be, in the cases of Mr. Wormington
or Mr. Oliver, the Company's refining and marketing business or exploration and
production business, respectively, (A) a direct or indirect sale of all or
substantially all of the assets of the Company's refining and marketing business
or exploration and production business, or (B) the sale of stock of a subsidiary
(or affiliate) of the Company that conducts all or substantially all of the
Company's refining and marketing business or exploration and production
business, or (C) a merger, joint venture or other business combination
98
99
involving the Company's refining and marketing business or exploration and
production business, and as a result of such sale of assets, sale of stock,
merger, joint venture or other business combination, the Company shall cease to
have the power to elect a majority of the Board of Directors (or the other
equivalent governing or managing body) of the entity which acquires, or
otherwise controls or conducts, the Company's refining and marketing business or
exploration and production business.
In order to participate in the 1998 Performance Plan, the parties to the
employment agreements and management stability agreements described above are
required to acknowledge that the rights and benefits under the 1998 Performance
Plan shall not be deemed an "incentive bonus plan" or other bonus or
compensation arrangement which shall be accelerated, multiplied or otherwise
required to be provided or enhanced under the employment agreement or management
stability agreement.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
At the beginning of the 1998 fiscal year, the Compensation Committee was
comprised of four members: Raymond K. Mason, Sr., Alan J. Kaufman, Patrick J.
Ward and William J. Johnson. In July 1998, following the annual meeting of
stockholders, Mr. Grapstein was added to the Compensation Committee. No members
of the Compensation Committee served or had formerly served as an executive
officer of the Company or had any relationships or related transactions as
described in Item 13 hereof.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
The following table sets forth information based on filings made with the
SEC as to each person or group who on March 1, 1999, beneficially owned more
than 5 percent of the outstanding shares of Common Stock of the Company.
AMOUNT AND NATURE OF
BENEFICIAL OWNERSHIP
---------------------
NUMBER PERCENT
TITLE OF CLASS NAME AND ADDRESS OF BENEFICIAL OWNER OF SHARES OF CLASS
-------------- ------------------------------------ --------- --------
Common Stock.................... Wanger Asset Management, L.P.(a) 3,692,700 11.418
227 West Monroe Street, Suite 3000
Chicago, IL 60606
Common Stock.................... Dimensional Fund Advisors Inc.(b) 1,857,700 5.744
1299 Ocean Avenue, 11th Floor
Santa Monica, CA 90401
Common Stock.................... Boston Partners Asset Management, L.P.(c) 1,795,700 5.411
28 State Street, 20th Floor
Boston, MA 02109
- ---------------
(a) According to Amendment No. 3 to a Schedule 13G ("Amendment No. 3") filed
with the SEC, Wanger Asset Management, L.P. ("WAM"), states that it is a
Delaware limited partnership and an Investment Adviser registered under
Section 203 of the Investment Advisers Act of 1940 and Wanger Asset
Management Ltd. states that it is a Delaware corporation and the General
Partner of the Investment Adviser. Amendment No. 3 indicates that the shares
reported therein have been acquired on behalf of discretionary clients of
WAM and that persons other than WAM are entitled to receive all dividends
from, and proceeds from the sale of, those shares. According to Amendment
No. 3, within the meaning of Rule 13d-3 of the Exchange Act, WAM
beneficially owns the shares shown in the table above and possesses shared
power to vote or to direct the vote and shared power to dispose or direct
the disposition of these shares.
(b) According to a Schedule 13G filed with the SEC, Dimensional Fund Advisors
Inc. ("Dimensional") states that it is a Delaware corporation and an
investment adviser registered under the Investment Advisers Act of 1940. In
the Schedule 13G, Dimensional states that it furnishes investment advice to
four investment companies registered under the Investment Company Act of
1940 and serves as investment
99
100
manager to certain other investment vehicles, including commingled group
trusts. These investment companies and investment vehicles are the
"Portfolios." In the Schedule 13G, Dimensional states that in its role as
investment adviser and investment manager, Dimensional possesses both voting
and investment power over the 1,857,700 shares of Common Stock that are
owned by the Portfolios. Dimensional states that the 1,857,700 shares of
Common Stock are owned by the Portfolios and disclaims beneficial ownership
of such securities.
(c) In a Schedule 13G filed with the SEC, Boston Partners Asset Management, L.P.
("BPAM") states that is a Delaware limited partnership; Boston Partners,
Inc. ("Boston Partners") states that it is a Delaware corporation; and
Desmond John Heathwood states that he is a United States citizen. According
to the Schedule 13G, BPAM, Boston Partners and Mr. Heathwood (collectively,
the "Reporting Persons") may be deemed to own beneficially 1,795,700 shares
of Common Stock (including 845,500 shares of Common Stock issuable upon
conversion of 1,000,000 shares of PIES). The Schedule 13G states that BPAM
owns 950,200 shares of Common Stock and 1,000,000 shares of PIES. Because
each PIES is convertible into 0.8455 shares of Common Stock, BPAM may be
deemed to own beneficially 845,500 shares of Common Stock related thereto.
According to the Schedule 13G, BPAM may be deemed to own beneficially a
total of 1,795,700 shares of Common Stock; as sole general partner of BPAM,
Boston Partners may be deemed to own beneficially all of the shares of
Common Stock that BPAM may be deemed to own beneficially; as principal
stockholder of Boston Partners, Mr. Heathwood may be deemed to own
beneficially all of the Common Stock that Boston Partners may be deemed to
own beneficially; and, therefore, each of the Reporting Persons may be
deemed to own beneficially 1,795,700 shares of Common Stock of Tesoro. The
Schedule 13G states that all Reporting Persons have shared power to dispose
or to direct the disposition of and shared power to vote or to direct the
vote of 1,795,700 shares. In the Schedule 13G, each of Boston Partners and
Mr. Heathwood expressly disclaims beneficial ownership of any shares of
Common Stock of Tesoro. According to the Schedule 13G, BPAM holds all of the
above 1,795,700 shares under management for its clients, who have the right
to direct the receipt of dividends, to receive dividends from such shares
and to receive the proceeds from the sale of such shares.
100
101
SECURITY OWNERSHIP OF MANAGEMENT AND DIRECTORS
The following table shows the beneficial ownership of the Company's Common
Stock reported to the Company as of March 1, 1999, including shares as to which
a right to acquire ownership exists (for example, through the exercise of stock
options or stock awards or conversion of PIES) within the meaning of Rule
13d-3(d)(1) under the Exchange Act for each director and the named executive
officers and, as a group, such persons and other executive officers. Unless
otherwise indicated, each person or member of the group listed has sole voting
and investment power with respect to the shares of Common Stock listed. The
PIES, which represent fractional interests in the Company's 7.25% Mandatorily
Convertible Preferred Stock, have no voting rights.
BENEFICIAL OWNERSHIP OF
COMMON STOCK ON
MARCH 1, 1999
-------------------------
PERCENT
SHARES OF CLASS
--------- --------
Steven H. Grapstein......................................... 860,010(a)(b) 2.658
William J. Johnson.......................................... 8,328(a) 0.026
Alan J. Kaufman............................................. 650,828(a)(c) 2.012
Raymond K. Mason, Sr........................................ 27,756(a) 0.086
Bruce A. Smith.............................................. 463,193(d) 1.418
Patrick J. Ward............................................. 15,328(a)(e) 0.047
Murray L. Weidenbaum........................................ 11,328(a) 0.035
William T. Van Kleef........................................ 178,520(f) 0.550
James C. Reed, Jr........................................... 152,789(g) 0.471
Stephen L. Wormington....................................... 146,390(h) 0.451
Robert W. Oliver............................................ 114,502(i) 0.353
All directors and executive officers as a group (17
individuals).............................................. 2,910,490(j) 8.701
- ---------------
(a) The shares shown for Mr. Grapstein, Mr. Mason and Dr. Weidenbaum include
9,000 shares each which such directors had the right to acquire through the
exercise of stock options on March 1, 1999, or within 60 days thereafter.
The shares shown for Mr. Johnson, Dr. Kaufman and Mr. Ward include 7,000
shares, 8,000 shares and 8,000 shares, respectively, which such directors
had the right to acquire though the exercise of stock options on March 1,
1999, or within 60 days thereafter. In addition, the shares shown for each
director include 510 shares of restricted Common Stock as payment of
one-half of each director's annual retainer for fiscal year 1998 (see
"Compensation of Directors" discussed above). Units of phantom stock payable
in cash which have been credited to the directors under the Phantom Stock
Plan and to Mr. Smith, Mr. Van Kleef and Mr. Reed under the 1998 Performance
Plan are not included in the shares shown above.
(b) The shares shown include 846,300 shares of the Company's Common Stock owned
by Oakville. Mr. Grapstein is an officer of Oakville. As an officer, Mr.
Grapstein shares voting and investment power with respect to such shares.
The shares shown also include 3,382 shares of Common Stock which could be
obtained upon the conversion of 4,000 PIES into Common Stock at March 1,
1999, for which Mr. Grapstein disclaims beneficial ownership, held in
accounts for his minor children. Each PIES is convertible into 0.8455 shares
of Common Stock.
(c) The shares shown include 9,000 shares held in the name of Dr. Kaufman's
spouse for which he disclaims beneficial ownership, and 20,000 shares owned
by the Kaufman Children's Trust for which Dr. Kaufman has sole power to vote
and direct the disposition thereof.
(d) The shares shown include 3,311 shares credited to Mr. Smith's account under
the Company's Thrift Plan and 330,134 shares which Mr. Smith had the right
to acquire through the exercise of stock options on March 1, 1999, or within
60 days thereafter.
(e) The shares shown include 6,000 shares owned by the P&L Family Partnership
Ltd. which Mr. Ward and his spouse control through 90% ownership.
101
102
(f) The shares shown include 2,344 shares credited to Mr. Van Kleef's account
under the Company's Thrift Plan and 124,706 shares which Mr. Van Kleef had
the right to acquire through the exercise of stock options or stock awards
on March 1, 1999, or within 60 days thereafter.
(g) The shares shown include 1,352 shares credited to Mr. Reed's account under
the Company's Thrift Plan and 92,384 shares which Mr. Reed had the right to
acquire through the exercise of stock options on March 1, 1999, or within 60
days thereafter.
(h) The shares shown include 1,474 shares credited to Mr. Wormington's account
under the Company's Thrift Plan and 144,916 shares which Mr. Wormington had
the right to acquire through the exercise of stock options on March 1, 1999,
or within 60 days thereafter.
(i) The shares shown include 586 shares credited to Mr. Oliver's account under
the Company's Thrift Plan and 112,916 shares which Mr. Oliver had the right
to acquire through the exercise of stock options on March 1, 1999, or within
60 days thereafter. The shares shown also include 1,000 shares held in the
name of Mr. Oliver's spouse for which he disclaims beneficial ownership.
(j) The shares shown include 13,215 shares credited to the accounts of executive
officers and directors under the Company's Thrift Plan and 1,103,123 shares
which directors and executive officers had the right to acquire through the
exercise of stock options or stock awards on March 1, 1999, or within 60
days thereafter. The shares shown also include 3,382 shares which an
executive officer could obtain upon the conversion of 4,000 PIES into Common
Stock at March 1, 1999. Each PIES is convertible into 0.8455 shares of
Common Stock. The shares shown also include 2,334 shares held in the name of
executive officers' spouses for which each executive officer disclaims
beneficial ownership and 3,000 shares acquired in the name of an executive
officer's mother with respect to which such executive officer has voting and
investment power.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
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................................ 50
Statements of Consolidated Operations -- Years Ended
December 31, 1998, 1997 and 1996.......................... 51
Consolidated Balance Sheets -- December 31, 1998 and 1997... 52
Statements of Consolidated Stockholders' Equity -- Years
Ended December 31, 1998, 1997 and 1996.................... 53
Statements of Consolidated Cash Flows -- Years Ended
December 31, 1998, 1997 and 1996.......................... 54
Notes to Consolidated Financial Statements.................. 55
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.
102
103
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).
2.3 -- Stock Sale Agreement, dated March 18, 1998, among the
Company, BHP Hawaii Inc. and BHP Petroleum Pacific
Islands Inc. (incorporated by reference herein to Exhibit
2.1 to Registration Statement No. 333-51789).
2.4 -- Stock Sale Agreement, dated May 1, 1998, among Shell
Refining Holding Company, Shell Anacortes Refining
Company and the Company (incorporated by reference herein
to the Company's Quarterly Report on Form 10-Q for the
period ended March 31, 1998, 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).
3.7 -- Certificate of Amendment, dated as of August 3, 1998, to
Certificate of Incorporation of the Company, amending
Article IV, increasing the number of authorized shares of
Common Stock from 50,000,000 to 100,000,000 (incorporated
by reference herein to Exhibit 3.1 to the Company's
Quarterly Report on Form 10-Q for the period ended
September 30, 1998, File No. 1-3473.)
3.8 -- Certificate of Designation of 7.25% Mandatorily
Convertible Preferred Stock (incorporated by reference
herein to Exhibit 4.1 to the Company's Current Report on
Form 8-K filed on July 1, 1998, File No. 1-3473).
103
104
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
4.1 -- 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).
4.2 -- 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).
4.3 -- 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).
4.4 -- Indenture, dated as of July 2, 1998, between Tesoro
Petroleum Corporation and U.S. Bank Trust National
Association, as Trustee (incorporated by reference herein
to Exhibit 4.4 to Registration Statement No. 333-59871).
4.5 -- Form of 9% Senior Subordinated Notes due 2008 and 9%
Senior Subordinated Notes due 2008, Series B (filed as
part of Exhibit 4.4 hereof) (incorporated by reference
herein to Exhibit 4.5 to Registration Statement No.
333-59871).
4.6 -- Third Amended and Restated Credit Agreement ("Credit
Agreement"), dated as of July 2, 1998, among Tesoro
Petroleum Corporation, the Lenders parties thereto,
Lehman Brothers Inc., as Arranger, Lehman Commercial
Paper Inc., as Syndication Agent, the First National Bank
of Chicago, as Co-Administrative Agent and as General
Administrative Agent, Paribas, as Co-Administrative Agent
and as Collateral Agent and The Bank of Nova Scotia, as
Documentation Agent (incorporated by reference herein to
Exhibit 4.6 to Registration Statement No. 333-59871).
4.7 -- Consent and Confirmation, dated as of July 2, 1998, with
respect to the Credit Agreement, dated as of July 2, 1998
(incorporated by reference herein to Exhibit 4.7 to
Registration Statement No. 333-59871).
4.8 -- Deposit Agreement among the Company, The Bank of New York
and the holders from time to time of depository receipts
executed and delivered thereunder (incorporated by
reference to Exhibit 4.2 to the Company's Current Report
on Form 8-K filed on July 1, 1998, File No. 1-3473).
4.9 -- Form of depository receipt evidencing ownership of
Premium Income Equity Securities (filed as a part of
Exhibit 4.8 hereof) (incorporated by reference herein to
Exhibit 4.9 to Registration Statement No. 333-59871).
10.1 -- Registration Rights Agreement, dated as of July 2, 1998,
among Tesoro Petroleum Corporation, Lehman Brothers Inc.,
Bear, Stearns & Co. Inc. and Salomon Smith Barney
(incorporated by reference herein to Exhibit 10.1 to
Registration Statement No. 333-59871).
+10.2 -- The Company's Amended Executive Security Plan, as amended
through November 13, 1989, and Funded Executive Security
Plan, as amended through February 28, 1990, for executive
officers and key personnel (incorporated by reference
herein to Exhibit 10(f) to the Company's Annual Report on
Form 10-K for the fiscal year ended September 30, 1990,
File No. 1-3473).
+10.3 -- 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).
104
105
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
+10.4 -- 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).
*+10.5 -- Eighth Amendment to the Company's Amended Executive
Security Plan and Ninth Amendment to the Company's Funded
Executive Security Plan, both dated effective June 6,
1996.
*+10.6 -- Ninth Amendment to the Company's Amended Executive
Security Plan and Tenth Amendment to the Company's Funded
Executive Security Plan, both dated effective October 1,
1998.
+10.7 -- Amended and Restated Employment Agreement between the
Company and Bruce A. Smith dated November 1, 1997
(incorporated by reference herein to Exhibit 10.4 to the
Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 1997, File No. 1-3473).
*+10.8 -- First Amendment dated October 28, 1998 to Amended and
Restated Employment Agreement between the Company and
Bruce A. Smith dated November 1, 1997.
*+10.9 -- Amended and Restated Employment Agreement between the
Company and William T. Van Kleef dated as of October 28,
1998.
*+10.10 -- Amended and Restated Employment Agreement between the
Company and James C. Reed, Jr. dated as of October 28,
1998.
*+10.11 -- Management Stability Agreement between the Company and
Don M. Heep dated December 12, 1996.
+10.12 -- Management Stability Agreement between the Company and
Donald A. Nyberg dated December 12, 1996 (incorporated by
reference herein to Exhibit 10.7 to the Company's Annual
Report on Form 10-K for the fiscal year ended December
31, 1997, File No. 1-3473).
+10.13 -- Management Stability Agreement between the Company and
Robert W. Oliver dated September 27, 1995 (incorporated
by reference herein to Exhibit 10.8 to the Company's
Annual Report on Form 10-K for the fiscal year ended
December 31, 1997, File No. 1-3473).
+10.14 -- Management Stability Agreement between the Company and
Steve Wormington dated September 27, 1995 (incorporated
by reference herein to Exhibit 10.9 to the Company's
Annual Report on Form 10-K for the fiscal year ended
December 31, 1997, File No. 1-3473).
+10.15 -- 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).
+10.16 -- 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).
+10.17 -- 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).
105
106
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
+10.18 -- 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).
+10.19 -- Resolution approved by the Company's stockholders on
April 30, 1992 extending the term of the Company's
Amended Incentive Stock Plan of 1982 to February 24, 1994
(incorporated by reference herein to Exhibit 10(o) to the
Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 1992, File No. 1-3473).
+10.20 -- Copy of the Company's Amended and Restated Executive
Long-Term Incentive Plan, as amended through July 29,
1998 (incorporated by reference herein to Exhibit 10.2 to
the Company's Quarterly Report on Form 10-Q for the
period ended September 30, 1998, File No. 1-3473).
+10.21 -- Copy of the Company's 1998 Performance Incentive
Compensation Plan (incorporated by reference herein to
Exhibit 10.1 to the Company's Quarterly Report on Form
10-Q for the period ended September 30, 1998, File No.
1-3473).
+10.22 -- 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).
+10.23 -- 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).
+10.24 -- 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).
+10.25 -- 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).
+10.26 -- Phantom Stock Option Agreement between the Company and
Bruce A. Smith dated effective October 29, 1997
(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, 1997, File No. 1-3473).
10.27 -- 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).
10.28 -- 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).
10.29 -- 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).
106
107
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
10.30 -- 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).
10.31 -- 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).
10.32 -- 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 (December 31, 1998)
**27.2 -- Restated Financial Data Schedule (December 31, 1997)
**27.3 -- Restated Financial Data Schedule (December 31, 1996)
- ---------------
* Filed herewith.
+ Identifies management contracts or compensatory plans or arrangements
required to be filed as exhibits hereto pursuant to Item 14(c) of Form 10-K.
** The Financial Data Schedule shall not be deemed "filed" for purposes of
Section 11 of the Securities Act of 1933 or Section 18 of the Securities
Exchange of 1934, and is included as an exhibit only to the electronic filing
of this From 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, 1998.
107
108
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, 1999 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 Directors March 30, 1999
- ------------------------------------------------ and Director, President and
(Bruce A. Smith) Chief Executive Officer
(Principal Executive Officer)
/s/ GREGORY A. WRIGHT Vice President, Finance and March 30, 1999
- ------------------------------------------------ Treasurer (Principal Financial
(Gregory A. Wright) Officer)
/s/ DON M. HEEP Vice President, Controller March 30, 1999
- ------------------------------------------------ (Principal Accounting Officer)
(Don M. Heep)
/s/ STEVEN H. GRAPSTEIN Vice Chairman of the March 30, 1999
- ------------------------------------------------ Board of Directors and Director
(Steven H. Grapstein)
/s/ WILLIAM J. JOHNSON Director March 30, 1999
- ------------------------------------------------
(William J. Johnson)
/s/ ALAN J. KAUFMAN Director March 30, 1999
- ------------------------------------------------
(Alan J. Kaufman)
/s/ RAYMOND K. MASON, SR. Director March 30, 1999
- ------------------------------------------------
(Raymond K. Mason, Sr.)
/s/ PATRICK J. WARD Director March 30, 1999
- ------------------------------------------------
(Patrick J. Ward)
/s/ MURRAY L. WEIDENBAUM Director March 30, 1999
- ------------------------------------------------
(Murray L. Weidenbaum)
108
109
EXHIBIT INDEX
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).
2.3 -- Stock Sale Agreement, dated March 18, 1998, among the
Company, BHP Hawaii Inc. and BHP Petroleum Pacific
Islands Inc. (incorporated by reference herein to Exhibit
2.1 to Registration Statement No. 333-51789).
2.4 -- Stock Sale Agreement, dated May 1, 1998, among Shell
Refining Holding Company, Shell Anacortes Refining
Company and the Company (incorporated by reference herein
to the Company's Quarterly Report on Form 10-Q for the
period ended March 31, 1998, 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).
3.7 -- Certificate of Amendment, dated as of August 3, 1998, to
Certificate of Incorporation of the Company, amending
Article IV, increasing the number of authorized shares of
Common Stock from 50,000,000 to 100,000,000 (incorporated
by reference herein to Exhibit 3.1 to the Company's
Quarterly Report on Form 10-Q for the period ended
September 30, 1998, File No. 1-3473.)
110
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
3.8 -- Certificate of Designation of 7.25% Mandatorily
Convertible Preferred Stock (incorporated by reference
herein to Exhibit 4.1 to the Company's Current Report on
Form 8-K filed on July 1, 1998, File No. 1-3473).
4.1 -- 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).
4.2 -- 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).
4.3 -- 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).
4.4 -- Indenture, dated as of July 2, 1998, between Tesoro
Petroleum Corporation and U.S. Bank Trust National
Association, as Trustee (incorporated by reference herein
to Exhibit 4.4 to Registration Statement No. 333-59871).
4.5 -- Form of 9% Senior Subordinated Notes due 2008 and 9%
Senior Subordinated Notes due 2008, Series B (filed as
part of Exhibit 4.4 hereof) (incorporated by reference
herein to Exhibit 4.5 to Registration Statement No.
333-59871).
4.6 -- Third Amended and Restated Credit Agreement ("Credit
Agreement"), dated as of July 2, 1998, among Tesoro
Petroleum Corporation, the Lenders parties thereto,
Lehman Brothers Inc., as Arranger, Lehman Commercial
Paper Inc., as Syndication Agent, the First National Bank
of Chicago, as Co-Administrative Agent and as General
Administrative Agent, Paribas, as Co-Administrative Agent
and as Collateral Agent and The Bank of Nova Scotia, as
Documentation Agent (incorporated by reference herein to
Exhibit 4.6 to Registration Statement No. 333-59871).
4.7 -- Consent and Confirmation, dated as of July 2, 1998, with
respect to the Credit Agreement, dated as of July 2, 1998
(incorporated by reference herein to Exhibit 4.7 to
Registration Statement No. 333-59871).
4.8 -- Deposit Agreement among the Company, The Bank of New York
and the holders from time to time of depository receipts
executed and delivered thereunder (incorporated by
reference to Exhibit 4.2 to the Company's Current Report
on Form 8-K filed on July 1, 1998, File No. 1-3473).
4.9 -- Form of depository receipt evidencing ownership of
Premium Income Equity Securities (filed as a part of
Exhibit 4.8 hereof) (incorporated by reference herein to
Exhibit 4.9 to Registration Statement No. 333-59871).
10.1 -- Registration Rights Agreement, dated as of July 2, 1998,
among Tesoro Petroleum Corporation, Lehman Brothers Inc.,
Bear, Stearns & Co. Inc. and Salomon Smith Barney
(incorporated by reference herein to Exhibit 10.1 to
Registration Statement No. 333-59871).
+10.2 -- 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).
111
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
+10.3 -- 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).
+10.4 -- 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).
*+10.5 -- Eighth Amendment to the Company's Amended Executive
Security Plan and Ninth Amendment to the Company's Funded
Executive Security Plan, both dated effective June 6,
1996.
*+10.6 -- Ninth Amendment to the Company's Amended Executive
Security Plan and Tenth Amendment to the Company's Funded
Executive Security Plan, both dated effective October 1,
1998.
+10.7 -- Amended and Restated Employment Agreement between the
Company and Bruce A. Smith dated November 1, 1997
(incorporated by reference herein to Exhibit 10.4 to the
Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 1997, File No. 1-3473).
*+10.8 -- First Amendment dated October 28, 1998 to Amended and
Restated Employment Agreement between the Company and
Bruce A. Smith dated November 1, 1997.
*+10.9 -- Amended and Restated Employment Agreement between the
Company and William T. Van Kleef dated as of October 28,
1998.
*+10.10 -- Amended and Restated Employment Agreement between the
Company and James C. Reed, Jr. dated as of October 28,
1998.
*+10.11 -- Management Stability Agreement between the Company and
Don M. Heep dated December 12, 1996.
+10.12 -- Management Stability Agreement between the Company and
Donald A. Nyberg dated December 12, 1996 (incorporated by
reference herein to Exhibit 10.7 to the Company's Annual
Report on Form 10-K for the fiscal year ended December
31, 1997, File No. 1-3473).
+10.13 -- Management Stability Agreement between the Company and
Robert W. Oliver dated September 27, 1995 (incorporated
by reference herein to Exhibit 10.8 to the Company's
Annual Report on Form 10-K for the fiscal year ended
December 31, 1997, File No. 1-3473).
+10.14 -- Management Stability Agreement between the Company and
Steve Wormington dated September 27, 1995 (incorporated
by reference herein to Exhibit 10.9 to the Company's
Annual Report on Form 10-K for the fiscal year ended
December 31, 1997, File No. 1-3473).
+10.15 -- 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).
112
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
+10.16 -- 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).
+10.17 -- 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).
+10.18 -- 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).
+10.19 -- Resolution approved by the Company's stockholders on
April 30, 1992 extending the term of the Company's
Amended Incentive Stock Plan of 1982 to February 24, 1994
(incorporated by reference herein to Exhibit 10(o) to the
Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 1992, File No. 1-3473).
+10.20 -- Copy of the Company's Amended and Restated Executive
Long-Term Incentive Plan, as amended through July 29,
1998 (incorporated by reference herein to Exhibit 10.2 to
the Company's Quarterly Report on Form 10-Q for the
period ended September 30, 1998, File No. 1-3473).
+10.21 -- Copy of the Company's 1998 Performance Incentive
Compensation Plan (incorporated by reference herein to
Exhibit 10.1 to the Company's Quarterly Report on Form
10-Q for the period ended September 30, 1998, File No.
1-3473).
+10.22 -- 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).
+10.23 -- 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).
+10.24 -- 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).
+10.25 -- 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).
+10.26 -- Phantom Stock Option Agreement between the Company and
Bruce A. Smith dated effective October 29, 1997
(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, 1997, File No. 1-3473).
10.27 -- 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).
113
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
10.28 -- 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).
10.29 -- 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).
10.30 -- 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).
10.31 -- 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).
10.32 -- 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 (December 31, 1998)
**27.2 -- Restated Financial Data Schedule (December 31, 1997)
**27.3 -- Restated Financial Data Schedule (December 31, 1996)
- ---------------
* Filed herewith.
+ Identifies management contracts or compensatory plans or arrangements
required to be filed as exhibits hereto pursuant to Item 14(c) of Form 10-K.
** The Financial Data Schedule shall not be deemed "filed" for purposes of
Section 11 of the Securities Act of 1933 or Section 18 of the Securities
Exchange of 1934, and is included as an exhibit 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.