Texaco Inc. was incorporated in Delaware on August 26, 1926, as The Texas
Corporation. Its name was changed in 1941 to The Texas Company and in 1959 to
Texaco Inc. It is the successor to a corporation incorporated in Texas in 1902.
When we use the term "Texaco Inc." in this Form 10-K and in the documents we
have incorporated by reference into this Form 10-K, we mean Texaco Inc., a
Delaware corporation. We use terms such as "Texaco," "company," "organization,"
"unit," "we," "us," "our," and "its" for convenience only. These terms may mean
either Texaco Inc. and its consolidated subsidiaries or Texaco Inc.'s
subsidiaries and affiliates, either individually or collectively.
Texaco Inc. and its subsidiary companies, together with affiliates owned
50% or less, represent a vertically integrated enterprise principally engaged in
the worldwide exploration for and production, transportation, refining and
marketing of crude oil, natural gas liquids, natural gas and petroleum products,
power generation, gasification and other energy technologies.
CHEVRON -- TEXACO MERGER
On October 15, 2000, Texaco and Chevron Corporation entered into a merger
agreement. In the proposed merger, Texaco shareholders will receive .77 shares
of Chevron common stock for each share of Texaco common stock they own, and
Chevron shareholders will retain their existing shares. Immediately after
closing, Chevron Corporation will change its name to ChevronTexaco Corporation.
ChevronTexaco Corporation will have significantly enhanced positions in
upstream and downstream operations, a global chemicals business, a growth
platform in power generation, and industry-leading skills in technology
innovation. Annual synergy savings of at least $1.2 billion are expected within
six to nine months of the merger. Though not yet fully quantified, significant
costs will be incurred after the merger for integration-related expenses,
including the elimination of duplicate facilities, operational realignment and
severance payments for workforce reductions.
The merger is conditioned, among other things, on the approval by the
shareholders of both companies, pooling of interests accounting treatment for
the merger, approvals of government agencies, such as the U.S. Federal Trade
Commission (FTC) and completion of the merger on a tax-free basis, such that the
companies themselves, as well as holders of Chevron stock, will not recognize
gain or loss as a result of the merger. Holders of Texaco common stock will not
recognize any gain or loss for federal income tax purposes on the exchange of
their Texaco stock for ChevronTexaco stock in the merger, except for any gain or
loss recognized in connection with the receipt of cash instead of a fractional
share of ChevronTexaco common stock. We anticipate that the FTC will require
certain asset dispositions as a condition of not challenging the merger. While
the scope and method of such dispositions are unknown at this time, we do
anticipate being required to make divestitures of certain United States
refining, marketing and transportation businesses in order to address market
concentration concerns. We believe that we will be able to resolve these
concerns by the disposition of our interests in Equilon and Motiva.
1
The merger agreement provides for the payment of termination fees of up to
$1 billion by either party under certain circumstances. Chevron and Texaco also
were granted options to purchase shares of the other, under the same conditions
as the payments of the termination fees. Texaco granted Chevron an option to
purchase 107 million shares of Texaco's common stock, at $53.71 per share.
Chevron granted Texaco an option to purchase 127 million shares of Chevron's
common stock, at $85.96 per share.
On February 23, 2001, the Board of Directors of Texaco voted to postpone
the Annual Meeting of Stockholders, normally held on the fourth Tuesday in
April, pending further developments relating to the closing of the merger.
INDUSTRY REVIEW OF 2000
Introduction
By most measures, 2000 was an extraordinary year for the international oil
and gas industry. Spot crude oil prices reached their highest average level
since 1982, spot refining margins staged a startling recovery from last year's
lows, and U.S. natural gas prices set new records.
A surging global economy contributed to further growth in energy demand
last year. However, the very favorable price environment was, to a large extent,
the result of a combination of energy market supply-side factors. Low
inventories of crude oil and refined products left oil markets susceptible to
disruption and uncertainty. This helped to support prices and refining margins
at high levels for most of the year.
Low inventory levels also characterized the U.S. natural gas market.
Domestic gas production remained relatively weak in 2000. This made it difficult
both to meet summer demand requirements and to place adequate volumes of gas
into storage for the winter.
Review of 2000
The global economy experienced exceptionally strong growth in 2000. The
U.S. was the world's driving force, enjoying a remarkable 5% increase in Gross
Domestic Product despite a tightening in monetary policy and higher energy
prices. Western Europe also registered a healthy gain, propelled by rising
exports and strong investment spending. However, the large Japanese economy
continued to underperform.
The developing world continued to recover in 2000 from the Asian financial
crisis. Benefiting from both a rise in intra-regional trade and the strength of
the U.S. and European economies, growth in developing Asia accelerated. In
similar fashion, Latin America emerged from its 1999 recession, led by strong
growth in Brazil, Mexico, Peru and Chile. Also, many of the oil producing
nations in the developing world benefited from higher oil prices. Furthermore,
the former Soviet bloc enjoyed its strongest economic performance in 10 years,
led by robust growth in Russia and many of the countries in Eastern Europe.
The increased pace of economic activity contributed to further growth in
world oil demand. Total oil consumption averaged 76.4 million barrels per day
(BPD) during 2000, 1.2% higher than 1999. Virtually all of the increase in
demand occurred in the developing countries, especially those in Asia. The
warmer-than-normal 1999-2000 winter constrained the demand for heating fuels in
the U.S. and Western Europe. Also, sharply higher oil prices limited consumption
in some countries.
In contrast to the deep cutbacks made in 1999, members of the Organization
of Petroleum Exporting Countries (OPEC) raised their production of crude oil
significantly in 2000. OPEC crude oil output averaged 27.9 million BPD, 1.4
million BPD above the prior year and the highest level since 1979. By year end,
many OPEC members were believed to be producing at or near their full capacity.
2
Production in non-OPEC areas also rose substantially in 2000. This largely
reflected the start-up of projects that were delayed from the prior two years,
when low oil prices cut deeply into spending and production plans. However, much
of the increase in world oil production occurred after the spring, and
commercial crude oil inventories remained lean throughout most of the year.
Low crude oil stocks placed continued upward pressure on prices. This was
reinforced by uncertainties regarding export flows from Iraq and the escalation
of violence in the Middle East. For the year overall, the spot price of U.S.
benchmark West Texas Intermediate (WTI) crude oil averaged $30.37 per barrel,
about $11.00 per barrel higher than in 1999.
Early in 2000, refined product inventories were drawn down, especially in
the Atlantic basin, to meet seasonal demand requirements. As the year
progressed, it became difficult to replenish these stocks for a variety of
reasons. These reasons included changes in mandated product specifications in
some areas, scattered worldwide refinery outages and heavy scheduled refinery
maintenance. Consequently, refined product prices rose sharply, and spot
refining margins increased.
U.S. natural gas prices also rose steeply last year, averaging $3.99 per
thousand cubic feet. This increase of about 70% reflected tight supply/demand
conditions. Domestic gas production has recovered slowly from the declines
suffered in 1998-1999 when overall upstream spending was reduced drastically due
to low oil prices. At the same time, however, gas demand has trended upward,
especially for electricity generation during the summer months. During 2000,
natural gas end users competed for available supplies with operators who store
gas for the winter. With low levels of gas in storage heading into the winter,
the onset of severe cold weather in November and December raised concerns about
adequate supplies. This sent gas prices up sharply.
Near-Term Outlook
The global economic expansion is expected to continue through 2001, though
at a slower rate than in 2000. The U.S. economy is showing signs of a sharp
slowdown, responding to the previous interest rate increases by the Federal
Reserve. Recently, the Federal Reserve has reduced interest rates in an effort
to keep the U.S. economy from slipping into a recession. Economic expansions in
Europe and the developing world are also expected to moderate, reflecting the
slowdown in the U.S.
We expect world oil consumption to increase again during 2001. Even with
lower economic growth, oil consumption should rise by about 1.4 million BPD. On
the supply side, non-OPEC production should also rise, but more slowly, as many
delayed projects have been completed.
The major uncertainty facing oil markets in 2001 concerns the level of OPEC
oil output and the future course of prices. OPEC has stated publicly its desire
to maintain crude oil prices in a target range which is roughly equivalent to
$24-$30 per barrel of WTI. Prices were headed down toward the lower end of that
range by the end of 2000 as OPEC's high crude oil production rates ultimately
translated into a worldwide accumulation of crude oil stocks. To avoid a market
oversupply situation which could jeopardize its price goal, OPEC announced
output cuts in January 2001, and prices moved higher. However, renewed concerns
about potential market surplus again drove prices toward the bottom of the
target range, prompting further cuts by OPEC in March.
Worldwide spot refining margins should decline during 2001. High refinery
running rates in many parts of the world during the latter part of last year led
to a partial refilling of refined product stocks. In addition, many of the
unusual factors that prevailed in 2000, such as major changes in product
specifications, should be absent from the market in 2001.
U.S. natural gas markets, on the other hand, have the potential to remain
quite strong in 2001. Under any reasonable expectation, the volume of natural
gas in storage will be very low by the spring. Thus, the need to build supplies
will be intense. Although production and imports will be higher, continued
growth in demand will keep the market balance tight.
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WORLDWIDE OPERATIONS
Our worldwide operations encompass three main businesses: o Upstream
(exploration and production) o Downstream (refining, marketing and distribution)
o Global Gas, Power and Energy Technology.
In the following pages, we discuss each of these businesses and technology.
UPSTREAM
We achieved record upstream earnings through a combination of significantly
higher prices and rigorous cost control. Our worldwide production of crude oil
and natural gas declined by almost 9% due to our continuing strategy of selling
non-core producing properties. In 1999, we decided to divest non-strategic
assets and focus investment on high-return, high-impact opportunities. The
balance of the decrease was due to natural field declines, which exceeded new
production from various fields, and lower production volumes in Indonesia as
higher prices reduced our lifting entitlements for cost recovery under a
production-sharing agreement. Our cash operating expenses increased by less than
5% in 2000 and less than 15% on a per barrel of oil equivalent (BOE) basis. Most
of the increase in operating expenses was due to higher utility and production
taxes directly related to the higher price environment. We made significant
progress in 2000 in executing our strategy to shift our upstream portfolio to
high-margin, high-impact projects. In 2000:
o The deepwater Agbami field appraisal program in Nigeria continued to confirm
a world-class discovery and resulted in the initial field development steps
being taken.
o We drilled the Bilah discovery in the deepwaters of Nigeria.
o We continued construction of the Malampaya natural gas project in the
Philippines, completing the gas export line and installing the concrete
gravity structure for the production platform.
o The Hamaca oil project in Venezuela awarded $1.1 billion in construction
contracts.
o We continued to move forward with our Karachaganak project in Kazakhstan,
where our partners and we awarded the main construction works and drilling
contracts for field expansion.
o First production from the second phase (Area B) of the Captain field in the
U.K. North Sea began in December.
o We made three discoveries in Australia, which add substantial resources
within the greater Gorgon area.
o Our worldwide reserve replacement of 172%, excluding purchases and sales,
enabled us to achieve our highest year-end reserve life in 24 years.
o Our worldwide finding and development costs were a competitive $3.62 per BOE.
o We generated about $600 million in cash from the sale of 74,000 BOE per day
of low-margin, high-cost properties.
Exploration
In the year 2000, we were successful in several of our key focus areas.
Drilling in the deepwater of Nigeria resulted in the Bilah discovery. Within the
U.S. Gulf of Mexico and Louisiana Gulf Coast, we announced four discoveries as a
result of our exploitation drilling. In Australia, we drilled three successful
wells, continuing the expansion of the greater Gorgon area. Plans are underway
to begin the 2001 deepwater drilling campaign in offshore Brazil, as well as
continued exploration in our focus areas.
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West Africa
We drilled a rank wildcat well in 2000. The Bilah #1 on OPL-218 was drilled
in 4,514 feet of water and encountered over 220 net feet of gas condensate pay
in multiple zones. Gas commercialization studies are ongoing and if warranted,
we will undertake further appraisal drilling, both on Bilah and the previous
Nnwa discovery. We plan to drill rank wildcat wells in Blocks 213 and 215 in
2001. We are well positioned to continue to expand resource finds in this
exciting new play.
We hold significant exploration acreage (approximately 2.7 million gross
acres) in the deep waters off Nigeria. We hold interests in five Blocks - 213,
215, 216, 217 and 218 - and we continue to evaluate new blocks, as they become
available.
In Angola, we continue to hold interest in approximately 2.5 million gross
acres. This includes Blocks 9 and 22, where we plan to begin drilling in 2001 or
2002.
Brazil
We received ANP (Brazilian Government oil and gas regulatory agency)
assignment in the first quarter of 2000 for the BC-4, Frade and BS-4 partnership
blocks, which we previously negotiated with Petrobras. We operate BC-4 and Frade
with a 42.5% interest. Shell operates BS-4, where we hold a 20% interest.
In 2000, we acquired a 10% interest in Block BM-C-4 from Agip. The other
partner in the block is YPF. In Block BM-S-2, where we hold a 100% equity stake,
we began acquisition of 5,000 square kilometers of 3D seismic data, one of the
largest 3D programs in our history. The interpretation of seismic data on our
current exploration acreage was a major activity in 2000 and is critical in
building a prospect inventory.
We have a five-well program planned for 2001 including two pre-development
wells on the Frade block.
Gulf of Mexico
The deepwater Gulf of Mexico is one of our exploration focus areas. At
year-end, we held an interest in 383 deepwater leases covering 2.2 million gross
acres. In addition, we hold an interest in 204 Shelf leases covering 1.1 million
gross acres, comprised primarily of producing acreage. In 2001, we plan to
participate in up to five deepwater rank wildcat wells.
In 2000, we drilled the Champlain prospect in Atwater Valley Block 63,
located 160 miles south of New Orleans in 4,384 feet of water. We are the
operator, holding a 75% interest, with Agip holding the remaining 25%. Initial
results have indicated the presence of high-quality reservoir sands with a total
of 140 net feet of pay. We are evaluating this prospect to determine its
commercial viability.
Exploitation drilling yielded four discoveries during 2000, all of which
were announced during the fourth quarter: North Tern Deep in Eugene Island Block
193; Bay St. Elaine Oscar in Terrebonne Parish, Louisiana; Cyrus in High Island
Block 582; and Vermilion Bay B110 in Iberia Parish, Louisiana. These discoveries
are all close to existing infrastructure and capable of delivering significant
near-term production. As of January 2001, the Bay St. Elaine and Vermilion Bay
discoveries are already on production. The North Tern Deep discovery is the
first resulting from a three-year exploration venture agreement with McMoran and
is expected to be on production during the first half of 2001.
5
Australia
We have continued our successful drilling program in Western Australia with
three additional wells, Urania No. 1, and Maenad No. 1 in Block WA-267-P (25%
interest) and Jansz No. 1 in Block WA-268-P (50% interest), adding substantial
new resources in proximity to the Gorgon complex. The drilling campaign will
continue into 2001, with further success already recorded in Blocks WA-25-P
(28.57 % interest) at Iago No. 1 and in WA-267-P at Io No. 1.
In addition, we acquired three new blocks in the Outer Browse Basin adding
3.65 million gross acres, to bring our portfolio in this region to 10.8 million
gross acres. We will continue to seek high-quality opportunities to increase and
upgrade our exploration portfolio.
Development
Our upstream strategy is centered on the development of high-margin,
high-impact reserves. Throughout 2000, we continued to achieve significant
success on each of our major projects.
Agbami
The extension of our OPL Block 216 Agbami discovery was confirmed by an
appraisal well on OPL Block 217. We are a working interest partner in Block 217,
where Statoil is the operator. Consequently, we initiated unitization
discussions with Statoil for a combined Block 216/217 Agbami development. We
spudded the third well on the Block 216 appraisal program, the Agbami-3, in late
2000. The final appraisal well, the Agbami-4, will be drilled immediately
following the Agbami-3 well.
In 2000, we finalized front-end engineering design on the development plan
and have nearly completed the process to bid on construction of the floating
production storage and offloading vessel and gas compression facilities. Current
plans include initial production in 2005 and peak production of 200,000 barrels
of oil per day (100% basis) by 2007.
Malampaya
The construction of the Malampaya Project remains on schedule with first
commercial gas sales slated for early 2002. We achieved several major
construction milestones during the year, including the drilling of five
development wells, the completion of the gas export line and the setting of the
concrete gravity structure. The platform will be placed on the concrete gravity
structure during the first quarter of 2001. Our share of production is expected
to reach a peak of 150 million standard cubic feet (SCF) per day during 2003.
In October 1999, we acquired a 45% interest in the Malampaya Deepwater
Natural Gas Project. The Malampaya field is located northwest of the Philippine
Island of Palawan. Under a 22-year agreement, this integrated natural
gas-to-power project will supply gas to three new power plants on Luzon Island.
Our participation in the project includes the deepwater gas field and the
onshore gas plant.
Hamaca
During 2000, we and our partners awarded a total of $1.1 billion in
engineering, procurement and construction contracts for field production and
crude oil upgrading facilities at the Jose Industrial Complex. Site preparation
has begun for the crude oil upgrading unit at the complex, which is located on
the northern coast of Venezuela. Field drilling operations are underway near El
Tigre. In addition, we finalized the purchase of centralized field production
processing facilities from Petroleos de Venezuela S.A. in 2000.
6
We have a 30% interest in the Hamaca Project. The three working interest
owners formed a joint venture, Petrolera Ameriven, to develop and operate this
project. The plan is to develop and produce the 8(degree) API heavy oil that is
expected to reach peak production rates of 190,000 barrels of oil per day (100%
basis) in 2004. The heavy oil production will be mixed with a diluent and
transported via pipeline to an upgrader located in the Jose Industrial Complex
in Puerto La Cruz. The upgrader will produce 26(degree) API syncrude to sell in
the open market by 2004.
Karachaganak
During 2000, we awarded all major contracts to complete Phase II of the
Karachaganak Development Project. In addition, we focused on maximizing
production and revenues from our existing production facilities. Total field
production for the year (100% basis) was 32.6 million barrels of condensate
(approximately 90,000 barrels per day) and 162.7 billion cubic feet of gas
(approximately 450 million cubic feet per day). These production levels
represent an annual production record for the field.
Our marketing focus is geared toward long-term gas sales arrangements. The
Caspian Pipeline Consortium route for Karachaganak's liquids will allow the
field to reach Phase II full production capacities of 220,000 barrels per day of
condensate and 1.4 billion cubic feet of gas per day (100% basis) in early 2004.
Karachaganak is a world-class gas/condensate field located in northwest
Kazakhstan. The field was discovered in 1979 and contains in excess of 18
billion BOE of hydrocarbons-in-place. In 1996, the Government of the Republic of
Kazakhstan approved our entry into the project. Our working interest is 20%. The
field will be developed in phases to match the capacity of export pipelines as
well as market demand.
North Buzachi
During 2000, we initiated the second phase of appraisal and delineation.
The second phase activities include the completion of a 3D seismic survey, the
drilling of nine wells and the initiation of steam stimulation trials. We
constructed a pump station and 20-mile pipeline to link the field to processing
facilities and the main export pipeline. Test crude sales have been made in
Black Sea and West European markets.
The North Buzachi oil field is located in western Kazakhstan, 120 miles
north of the Caspian port city of Aktau. Significant quantities of recoverable
oil were identified in the license area prior to the Kazakh independence but
remained undeveloped. We acquired a 65% working interest and became operator in
1998. A successful pilot phase of four producing wells was concluded in 1999.
Captain Expansion in the U.K. North Sea
In December 2000, production officially began on the Captain Expansion
Project, following the completion of construction and installation of the
facilities for the project. A new platform, installed during September, linked
up to our existing production platform and connected to a new subsea drilling
and production template via a suite of infield pipelines. This allowed drilling
to commence on the eastern half of the Captain reservoir, which was left
undeveloped during the initial phase of the field development. The first subsea
well was started up via the new facilities during December, only 25 months after
the award of the first contract for design and construction of the facilities.
The project is expected to increase the peak daily production capacity from the
Captain field from 60,000 barrels of oil per day to 85,000 barrels of oil per
day (100% basis). We hold an 85% interest in the Captain field.
7
Gulf of Mexico
In April 2000, we successfully installed a replacement topsides module on
the Petronius project and commissioned for first production in July 2000. The
development phase of the project is currently progressing, with the drilling and
completion of the development wells.
As our first deepwater project, the Petronius field, owned 50% by us,
consists of a compliant tower platform, modular production and water injection
facilities, a gas export pipeline, and the drilling and completion of 14
developmental wells.
Other
In China, the development of the Qinhuangdao 32-6 field in Bohai Bay is in
progress. We hold a 24.5% interest. The construction of all field facilities is
underway, including the floating production storage and offloading vessel,
mooring system, wellhead platforms and topsides equipment. A total of 50 wells
have been drilled and completed on the first two wellhead platforms; another 113
wells will be drilled on the remaining four platforms during the next 18 months.
First oil production is targeted for first quarter 2002. Also in Bohai Bay, the
Bozhong Block CA 11/19 prospect was confirmed through a successful drilling
program. The project team is proceeding with the preparation for an overall
development plan.
In China, we have initiated pilots on three coalbed methane projects to
evaluate their commercial potential. The Huaibei project in Anhui Province, in
which we are the operator and 100% interest owner, has a five-well pilot
underway. The Lin-Xing in Shanxi Province, in which we hold a 47.5% interest,
also has a five-well producing pilot. The San Jiao in Shanxi, in which we have a
30% interest, now has ten wells operating. Marketing activities have also
progressed with the signing of six non-binding Memorandums of Understanding with
ultimate gas consumers. In November 2000, we signed the Production Sharing
Contracts for the fourth project, known as Zhungeer, in which we have a 100%
interest, and preparations are underway for drilling the first set of evaluation
wells.
In Indonesia, we are developing the South Natuna Sea Block B project (our
share is 25%) for the sale of natural gas to both Singapore and Malaysia. The
Singapore project involves the development of six offshore gas fields, including
the associated wells, platforms, floating facilities, pipelines and a 300-mile
gas transmission line to Singapore. During 2000, we completed the initial phase
of the submarine pipeline and made substantial progress on the construction of a
mobile production jack-up barge. First production from Block B will be in the
second quarter of 2001 at a rate of 90 million SCF per day (100% basis), with a
plateau rate of 150 million SCF per day by mid-2002.
As a result of the signing of a non-binding Heads of Agreement between the
governments of Indonesia and Malaysia, in October 2000, negotiations commenced
on a natural gas sales agreement with the government of Malaysia for the sale of
1.5 trillion cubic feet of natural gas from Block B. Block B will be the
exclusive supplier of gas for this deal. The project is scheduled to deliver
first gas in early 2003, ramping up to a gross rate of 250 million SCF per day
(100% basis).
In Brazil, the Frade development project completed 3D seismic acquisition
and conceptual engineering studies in 2000. A pre-development drilling program
planned for 2001 consists of two wells on Frade and one exploration well in the
adjacent BC-4 Block and will assist us in confirming reserve size and optimizing
a field development scenario.
The Frade field lies in approximately 3,700 feet of water, 230 miles
northeast of Rio de Janeiro, in Block BC-4 of the northern Campos Basin. We were
assigned operator of Frade in March of 2000 and we hold an equity stake of
42.5%.
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Production
Our worldwide production of crude oil and natural gas declined by
approximately 9% in 2000 to 1,111 thousand BOE per day. Our U.S. production
accounted for 52% of total worldwide volumes, similar to 1999. Asset sales and
natural field declines contributed equally to a 10% production decline in the
U.S. Internationally, our production declined by 7% as a result of asset sales,
maintenance and repairs to our U.K. North Sea operations and lower lifting
entitlements for cost recovery in Indonesia as a result of higher crude oil
prices. With worldwide crude oil prices and U.S. gas prices increasing almost
70%, we held our operating expenses to less than a 15% increase on a
unit-of-production basis. The majority of this increase is the result of
price-related increases in fuel expense, utility costs and production taxes.
California
In 2000, California production declined 5% to average 160,000 BOE per day.
Aggressive steam management in December reduced high-priced gas consumption,
helping to support California during its power situation. Five thousand barrels
of oil per day were shut in during December as part of the California utility
situation fuel management effort.
Gulf of Mexico
Production from the Petronius field is currently 42,000 barrels of oil per
day and 33.5 million cubic feet of gas per day. Peak production is expected to
range from 45,000 to 50,000 barrels of oil per day and 80 to 100 million cubic
feet of gas per day (100% basis). Our share of the field is 50%.
Central U.S.
Gas production in the Rocky Mountain region continued to increase as we
developed additional coalbed methane production in Utah and New Mexico. The
acquisition of EnerVest San Juan properties at year-end 2000 added a further
21 million cubic feet per day of production and will provide low-risk potential
for further growth.
North Sea
The highlight of the year 2000 in the North Sea was the commissioning of
the Captain Expansion Facility in December. The North Sea provided an average of
156,000 BOE per day in 2000. Production in Denmark was 55,000 BOE per day while
the U.K. sector produced just over 101,000 BOE per day. The Halfdan facility, in
the Danish sector, came on line earlier than anticipated but the Erskine field
in the U.K. was shut in for most of the year for pipeline replacement.
Indonesia
During 2000, production from Indonesia was 122,000 barrels of oil per day,
down almost 20% compared to 1999. Most of our Indonesia production comes from
P.T. Caltex Indonesia (CPI), an exploration and production company owned 50%
each by Texaco and Chevron. CPI operates under production-sharing contracts in
Central Sumatra. We had lower production volumes as higher prices reduced our
lifting entitlements for cost recovery under these production-sharing contracts.
Partitioned Neutral Zone
During 2000, production from the Partitioned Neutral Zone (PNZ) increased
12%, to 139,000 barrels of oil per day -- the ninth consecutive year of
increases of more than 10% in the PNZ. The record level of production was the
result of a combination of infill drilling and horizontal workovers, mainly at
the Wafra and South Umm Gudair fields.
9
Reserves
We replaced 172% of our worldwide combined oil and gas production in 2000,
excluding purchases and sales. When purchases and sales are included, production
replacement drops to 116%, due to the sales of non-strategic assets totaling 285
million BOE. Sales were partially offset by the acquisition of Enervest San Juan
coalbed methane gas reserves of 244 billion cubic feet. Even with these sales,
our overall reserve base grew by 1.4% to 4.9 billion BOE, our highest level
since 1984. This increased the average life of our reserves to 11.4 years, the
longest reserve life in over 24 years.
The significant initial booking for the Hamaca field in Venezuela helped
the international reserves grow by 10.8% and production replacement (excluding
purchases and sales) soared to 267%. Approximately 53% (2.6 billion BOE) of
worldwide reserves are now located in international areas. Our U.S. reserves
dropped by 7.4% to 2.3 billion BOE, due to the sales of non-core producing
properties.
Capital and Exploratory Expenditures
During 2000, our upstream capital and exploratory expenditures were $3.1
billion. We spent approximately $1.1 billion in the U.S. and $2.0 billion
internationally. Our 2000 worldwide finding and development costs were a very
competitive $3.62 per BOE. Our 1998-2000 three-year average finding and
development costs were $3.74 per BOE and our 1996-2000 five-year average was
$3.92 per BOE.
We project our spending for 2001 on upstream projects to be $2.9 billion,
of which approximately 75% will be spent internationally. Our spending profile
continues to reflect high-margin, high-impact projects, with our focus on value
and effectiveness. Spending on major development projects will remain at $1.3
billion. Exploration spending will remain at approximately $600 million for
2001.
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SUPPLEMENTARY EXPLORATION AND PRODUCTION INFORMATION
The following tables provide supplementary information concerning the oil
and gas exploration, development and production activities of Texaco Inc. and
consolidated subsidiaries, as well as our equity in Hamaca Holding LLC, an
affiliate operating in Other Western Hemisphere and CPI, an affiliate operating
in Other Eastern Hemisphere. Supplemental oil and gas information required by
Statement of Financial Accounting Standards No. 69, "Disclosures About Oil and
Gas Producing Activities," is incorporated herein by reference from pages 71
through 78 of our 2000 Annual Report to Stockholders.
Reserves Reported to Other Agencies
We provide information concerning recoverable, proved oil and gas reserve
quantities to the U.S. Department of Energy and to other governmental bodies
annually. Such information is consistent with the reserve quantities presented
in Table I, Net Proved Reserves, beginning on page 71 of our 2000 Annual Report
to Stockholders.
Average Sales Prices and Lifting Costs--Per Unit
Information concerning average sales prices and lifting costs on a per unit
basis is incorporated herein by reference from page 77 of our 2000 Annual Report
to Stockholders.
Delivery Commitments
During 2001, we expect that our net production of natural gas will
approximate 2.0 billion cubic feet per day. This estimate is based upon our past
performance and on our assumption that such gas quantities can be produced under
operating and economic conditions existing at December 31, 2000. We did not
factor in possible future changes in prices or world economic conditions into
this estimate. These expected production volumes, together with the normal
related supply arrangements, are sufficient to meet our anticipated delivery
requirements under contractual arrangements. Over the last three years,
approximately 30% of our proved developed natural gas reserves in the U.S. were
covered by long-term sales contracts. These agreements are primarily priced at
market.
11
Oil and Gas Acreage
As of December 31, 2000
-----------------------------
Thousands of acres Gross Net
------------------ ----- ---
Producing
Texaco Inc. and Subsidiaries
United States................................................ 2,913 1,563
Other Western Hemisphere ................................... 45 22
Europe ..................................................... 400 121
Other Eastern Hemisphere ................................... 714 177
------ ------
Total ................................................... 4,072 1,883
Equity in Affiliate - Other Eastern Hemisphere.................... 225 112
------ ------
Total worldwide .................................. 4,297 1,995
------ ------
Undeveloped
Texaco Inc. and Subsidiaries
United States................................................ 7,649 5,191
Other Western Hemisphere ................................... 18,981 10,632
Europe ..................................................... 5,524 2,071
Other Eastern Hemisphere..................................... 38,926 16,770
------ ------
Total ................................................... 71,080 34,664
Equity in Affiliates..- Other Western Hemisphere*................. 163 49
- Other Eastern Hemisphere.................. 1,731 865
------ ------
Total Equity in Affiliates...................... 1,894 914
------ ------
Total worldwide................................. 72,974 35,578
------ ------
Total oil and gas acreage ...................... 77,271 37,573
====== ======
Number of Wells Capable of Producing**
As of December 31, 2000
-----------------------------
Oil Wells Gross Net
--------- ----- ---
Texaco Inc. and Subsidiaries
United States................................................ 27,900 15,696
Other Western Hemisphere ................................... -- --
Europe ..................................................... 175 44
Other Eastern Hemisphere ................................... 1,916 763
------ ------
Total ................................................... 29,991 16,503
Equity in Affiliate - Other Eastern Hemisphere.................... 8,708 4,354
------ ------
Total worldwide***.............................. 38,699 20,857
====== ======
Gas wells
Texaco Inc. and Subsidiaries
United States................................................ 7,925 3,392
Other Western Hemisphere ................................... 33 17
Europe ..................................................... 66 11
Other Eastern Hemisphere ................................... 62 13
------ ------
Total ................................................... 8,086 3,433
Equity in Affiliate - Other Eastern Hemisphere.................... 58 29
------ ------
Total worldwide*** ............................. 8,144 3,462
====== ======
* Existing acreage was transferred from a consolidated subsidiary to an affiliate at year-end 2000.
** Producible well counts include active wells and wells temporarily shut-in. Consistent with general industry practice,
injection or service wells and wells shut-in that have been identified for plugging and abandonment have been excluded
from the number of wells capable of producing.
*** Includes 98 gross and 23 net multiple completion oil wells and 43 gross and 22 net multiple completion gas wells.
12
Oil, Gas and Dry Wells Completed For the years ended December 31,
-----------------------------------------------------------
2000 1999 1998
--------------- --------------- ---------------
Oil Gas Dry Oil Gas Dry Oil Gas Dry
--- --- --- --- --- --- --- --- ---
Net exploratory wells*
Texaco Inc. and Subsidiaries
United States................................. 3 6 8 3 15 10 14 14 26
Other Western Hemisphere...................... 1 -- 1 -- 1 2 -- 2 2
Europe........................................ -- -- 1 -- -- 1 -- -- 1
Other Eastern Hemisphere...................... 4 2 1 2 2 4 4 4 2
--- --- --- --- --- --- ----- --- --
Total ..................................... 8 8 11 5 18 17 18 20 31
Equity in Affiliate - Other Eastern Hemisphere.. 2 -- -- 2 -- 1 2 -- 2
--- --- --- --- --- --- ----- --- --
Total worldwide........................... 10 8 11 7 18 18 20 20 33
=== === === === === === ===== === ==
Net development wells
Texaco Inc. and Subsidiaries
United States................................. 408 163 7 345 100 7 585 106 14
Other Western Hemisphere...................... -- 1 -- 9 -- -- 109 3 --
Europe........................................ 2 -- -- 2 4 -- 21 2 --
Other Eastern Hemisphere...................... 44 1 1 61 6 1 38 27 --
--- --- --- --- --- --- ----- --- --
Total ...................................... 454 165 8 417 110 8 753 138 14
Equity in Affiliate - Other Eastern Hemisphere.. 218 -- -- 219 -- -- 271 -- --
--- --- --- --- --- --- ----- --- --
Total worldwide........................... 672 165 8 636 110 8 1,024 138 14
=== === === === === === ===== === ==
* Exploratory wells which identify oil and gas reserves, but have not resulted
in recording of proved reserves pending further evaluation, are not
considered completed wells. Reserves which are identified by such wells are
included in Texaco's proved reserves when sufficient information is available
to make that determination. This is particularly applicable to deep water
exploratory areas which may require extended time periods to assess, such as
the U.K. sector of the North Sea and in the deepwater U.S. Gulf of Mexico.
Additional Well Data As of December 31, 2000
-----------------------------------------------------
Wells in the Pressure Maintenance
process of --------------------
drilling
------------------------ Installations
Gross Net in operation
----- --- --------------------
Texaco Inc. and Subsidiaries
United States............................................ 171 90 281
Other Western Hemisphere................................. -- -- --
Europe................................................... 6 1 8
Other Eastern Hemisphere................................. 91 33 269
--- --- ---
Total ................................................. 268 124 558
Equity in Affiliate - Other Eastern Hemisphere.............. 5 3 8
--- --- ---
Total worldwide...................................... 273 127 566
=== === ===
13
DOWNSTREAM
Texaco International Marketing and Manufacturing
Our Texaco International Marketing and Manufacturing (TIMM) unit sells
high-quality fuel, lubricant and convenience products in over 60 countries
throughout Latin America, the Caribbean, Europe and West Africa. TIMM also has
four refineries located in the United Kingdom, the Netherlands, Panama and
Guatemala.
In the Caribbean and Latin America, we are a market leader in fuels and
lubricants. Our fuel market share is strong in all Caribbean and Central
American countries, and one-fourth of our worldwide lubricant sales are in Latin
America. The largest business is in Brazil, where we have some 3,000 service
stations and sales of over 44 million barrels per year. In Brazil, we are also a
market leader in lubricants. Although growth in petroleum consumption in Brazil
was negative in 1999, it rebounded in 2000 and is expected to increase 2.5% in
2001.
In 2000, the economy in Brazil and the Andean Region improved after the
economic recession and currency devaluations in 1999. However, our ability to
take advantage of the economic recovery in the Brazilian market was limited due
to practices, such as tax evasion and adulterated fuels sales, by new
competitors. In the Andean Region, which is composed of Colombia, Ecuador, Peru
and Venezuela, we have over 550 service stations. Excluding Venezuela, our
retail and lubricant market share in the region is over 15%. In Venezuela, we
have 75 stations and are positioned to expand in the retail sector when the
investment climate improves.
In the Caribbean and Central America, our business operates in 34 countries
through a network of 1,400 service stations. In 2000, our refined product sales
volumes in the Caribbean and Central America, including trading operations,
increased by 4%. In this region, our strategy is to build on an excellent market
share by investing in areas with the greatest potential and continuing to seek
infrastructure improvements.
The Latin America refining segment consists of a refinery located in
Escuintla, Guatemala, with a crude capacity of 16,000 barrels per day, and
another in Bahia Las Minas, Panama, with a crude capacity of 60,000 barrels per
day. The Panama refinery manufactures finished products for local sales, canal
sales and export markets, while the Guatemala refinery supplies only internal
country requirements. We wrote down the entire carrying value of the Panama
refinery in the fourth quarter of 2000, when we made a final determination that
the unfavorable operating environment and severe downward pressure on profit
margins would not improve in the foreseeable future.
We continue to maximize returns from our substantial retail properties by
increasing non-fuel retail income. One of the most successful non-fuel retail
initiatives has been the development of the Star Mart(R) convenience store
brand. We have close to 250 convenience stores throughout Latin America and the
Caribbean and over 450 in Europe. The growth of the Star Mart concept has
paralleled the strong growth of the regional economies and the increase in
disposable income, making the convenience store concept more appealing to
consumers. Non-fuel income represents a strategic growth opportunity for the
international areas.
In Europe, our focus is on regional markets, with assets concentrated in
the U.K., Ireland and the Benelux countries. We also have a 50% interest in
Hydro Texaco, a Scandinavian marketing joint venture with Norsk Hydro. In
addition, we market lubricants in all other major European countries. We rank
among the top 10 lubricant marketers on the continent. We are the number one
supplier of lubricants and coolants to original equipment manufacturers in
Europe.
14
Our European refineries reported outstanding results, but the marketing
business faced lower margins as a result of rising product costs that could not
be recovered in the marketplace. In Western Europe, massive protests against
high fuel taxes created a national crisis in some countries, such as the U.K.
and Belgium. As a result of this reaction, the oil industry was unable to fully
recover the increase in crude prices in the marketplace.
In keeping with our focus on improving earnings in North West Europe, we
have worked continually to increase market share, while reducing operating costs
and growing our non-fuel business. In the U.K., we increased our branded retail
market share from about 6% to 10% through acquisitions of dealerships and asset
swaps. In 2000, we successfully integrated 107 Shell sites into the U.K. network
in exchange for our assets in Poland and Greece. During the past three years, we
have also expanded our commercial sales business by more than 50%. Our total
gasoline market share in the U.K. rose to some 16% in 2000, doubling from our
1996 share, while we maintained expenses at 1999 levels.
In other Texaco European retail markets, we have double-digit market share
and a strong presence. In Ireland, we have more than 370 stations and a 16%
market share. In the Benelux countries, we have over 900 stations and an 11%
market share. In our Scandinavian joint venture, Hydro Texaco has over 950
stations and an 18% market share.
In Europe, we have an interest in two refineries with a total capacity for
Texaco of 325,000 barrels per day. We own the Pembroke refinery in Wales, U.K.,
which has the largest Fluid Catalytic Cracker and Alkylation units in Europe. It
is one of the most modern and advanced refineries in Europe, with very high
motor gasoline yields and qualities. This refinery, with a crude capacity of
210,000 barrels per day, supplies our marketing requirements in the U.K. and
Ireland, and also exports its high-quality gasoline to other parts of the world.
It has a highly skilled, talented and innovative workforce, which provides
competitive strength in the areas of health and safety performance and overall
plant reliability and efficiency.
We also own a 31% interest in the 370,000-barrel-per-day Nerefco refinery
in Rotterdam, a joint venture with British Petroleum. This refinery provides the
main supply to our Netherlands marketing operations and, due to its excellent
location in the Rotterdam harbor, is a key supplier to the Rotterdam fuel market
and to the German light products market. Both Pembroke and Nerefco were
configured to comply economically with the European Union's fuel specifications
for the year 2000 and are well positioned for upgrades to meet the 2005
specifications.
U.S. Downstream Alliances
Our U.S. downstream operations include primarily the operations of Equilon
Enterprises LLC and Motiva Enterprises LLC. Equilon and Motiva jointly own
Equiva Trading Company, which functions as the trading unit for both companies.
They also jointly own Equiva Services LLC, which provides common financial,
administrative, technical and other operational support to both companies.
The combination of Equilon and Motiva is the largest retail gasoline
marketer in the U.S., having nearly a 14.5% share of the domestic gasoline
market through about 22,300 retail outlets. The two companies have eight
refineries with a combined capacity of about 1.3 million barrels per day.
Equilon Enterprises LLC
Equilon was formed and began operations in January 1998 as a joint venture
between Texaco and Shell. Equilon, which is headquartered in Houston, Texas,
operates in the western and midwestern United States. We own 44% and Shell owns
56% of the company.
15
Equilon refines and markets gasoline and other petroleum products under
both the Texaco and Shell brand names in all or parts of 32 states. Equilon has
the capacity to refine about 450,000 barrels of crude a day with its four
refineries located in:
o Anacortes, Washington
o Bakersfield, California
o Martinez, California
o Los Angeles, California
Equilon holds interests in about 28,900 miles of pipelines and owns or has
interests in 70 crude oil and product terminals. It is estimated to be the
fourth largest retail gasoline marketer in the U.S., distributing products
through approximately 9,100 service stations. Equilon has an estimated 6.7%
share of the national gasoline market and an estimated 12.9% share of the
gasoline market in its geographic area.
Equilon Lubricants markets two of the top-selling lubricants, Texaco
Havoline(R) brand motor oil and Shell Rotella T(R) brand diesel engine oil,
leading a diverse product line covering an extensive variety of uses. It is a
leading marketer of both commercial lubricants (with a 17% market share) and of
industrial lubricants (with an 11% market share), and fourth in the U.S. in auto
lubricants.
In June 2000, Equilon sold its Wood River Refinery located in Roxana,
Illinois, to Tosco Corporation. The sale continues Equilon's plan to focus on
West Coast refining and its marketing, terminal, pipeline, lubricants and
trading businesses. In conjunction with this plan, Equilon has entered into
long-term crude supply and product off-take agreements with Tosco and, in late
1999, purchased 15 refined product terminals from Clark USA Inc. This will
enable Equilon to meet customer needs in the Midwest markets.
Motiva Enterprises LLC
Motiva was formed and began operations in July 1998 as a joint venture
among Shell, Texaco and Saudi Refining, Inc., a corporate affiliate of Saudi
Aramco. Motiva operates in the eastern and Gulf Coast United States. In
accordance with contractual provisions, our ownership interest in Motiva is
subject to change. From the start of operations through December 31, 1999,
Texaco and Saudi Refining, Inc. each owned 32.5% and Shell owned 35% of Motiva.
For the year 2000, Texaco and Saudi Refining, Inc. each owned just under 31% and
Shell owned just under 39% of Motiva. Texaco's and Saudi Aramco's interests in
these businesses were previously conducted by Star Enterprise, a joint-venture
partnership owned 50% by Texaco and 50% by Saudi Refining, Inc.
Motiva refines and markets gasoline and other petroleum products under the
Shell and Texaco brand names in all or part of 26 states and the District of
Columbia, providing product to almost 13,200 Shell- and Texaco-branded retail
outlets. Motiva has an estimated 7.7% share of the national gasoline market and
an estimated 16.0% market share in its geographic area.
Motiva is the sixth largest refiner in the U.S., capable of refining about
850,000 barrels a day. Motiva's refineries are located in:
o Convent, Louisiana
o Delaware City, Delaware
o Norco, Louisiana
o Port Arthur, Texas.
Motiva also owns or has interests in 53 product terminals.
16
Equiva Trading Company
Equiva Trading provides supply and logistical services for Equilon, Motiva
and other affiliates of Texaco and Shell. In addition, Equiva Trading conducts a
large and growing trading activity on behalf of Equilon. Equiva Trading buys and
sells in excess of 7 million barrels of hydrocarbons per day in the physical
markets, making it one of the largest petroleum supply and trading organizations
in the world. Specific lines of business include acquisition, sales and trades
of domestic and international crude oil and products; lease crude oil
acquisition and marketing; aviation marketing and sales; marine chartering; and
risk management services.
Equiva Services LLC
Equiva Services provides common services to both Equilon and Motiva in
areas such as brand management, retail operations, accounting, tax, treasury,
information technology, safety, health and environment. These common services
have been combined for efficiency, rather than each company having separate
service organizations.
Caltex Corporation
Caltex Corporation (Caltex), is jointly owned 50% each by Texaco and
Chevron. Caltex operates in more than 60 countries in Asia, Africa, the Middle
East, New Zealand and Australia. Caltex refines crude oil and markets petroleum
and convenience products through its subsidiaries and affiliates, and is also
involved in distribution, shipping, storage, supply and trading operations.
Caltex sold 1.4 million barrels per day of crude oil and refined products in
2000.
Caltex maintains a strong marketing presence through 7,800 retail outlets,
of which over 4,600 are Caltex-branded. Caltex also operates over 650 Star Mart
convenience stores.
Caltex has interests in 10 fuel refineries with equity refinery capacity of
nearly 850,000 barrels per day. Additionally, it has interests in two lubricant
refineries, six asphalt plants, 17 lube oil blending plants and more than 500
ocean terminals and depots. Caltex continues to be a major supplier of refined
products through its large refineries in South Korea, Singapore and Thailand.
Caltex is also active in converting lower-value refinery output into products
such as polypropylene, benzene and paraxylene, enabling the company to market a
wider range of higher value products.
Caltex conducts international crude oil and petroleum product logistics and
trading operations from a South East Asia region oil hub in Singapore, providing
24-hour service to the Caltex system and to third parties that require crude
oil, feedstocks, base oils and refined products.
Following its 1999 reorganization along functional business units, the
restructuring of its executive leadership team and the relocation of its
corporate center to Singapore, Caltex closed its Dallas office in 2000. It
continues to streamline its operations and expand use of its Shared Services
Center in the Philippines. Additionally, Caltex is working to maximize the
use of its assets by completing a number of cooperative and joint venture
arrangements.
This reorganization took on added importance in 2000, as Caltex' business
was affected by a number of factors, including the high cost of crude, increased
competition, weaker Asian currencies and a consolidation in the recovery of
Asian economies.
Caltex' business strategy for 2000 and beyond was built around its new
vision of being "outstanding at creating value from our brand and our intellect"
for customers, business partners and employees. The key elements of the vision
include:
o operational excellence and cost reduction
o capital stewardship and profitable growth
17
o building the brands
o organizational capability and motivation
o creative use of technology and innovations to provide more customer-focused
solutions.
Caltex' 2000 accomplishments include:
o Introducing new products - Vortex gasoline, which was launched simultaneously
in nine countries in March, and Delo 400 diesel engine oil, which built on
the international name and reputation of Chevron's Delo Brand lubricant.
o Concluding agreements to blend lubricants for competitors.
o Reaching agreements to share depot and terminal facilities with competitors.
o Controlling operating costs through synergies, efficiencies and initiatives
such as reduced fuel additive costs, supply chain management and strategic
procurement programs.
In 2000, Caltex focused on enhancing revenue through improved productivity
of its existing infrastructure, continued investment in growing markets and
acceleration of its convenience store program.
Caltex continuously seeks new business opportunities in countries such as
China, Vietnam, Cambodia and India, where its strategy is to build a strong
market presence through the sale of LPG, lubricants and asphalt, and eventually
expand into the retail motor fuel sector when permitted.
One significant venture during 2000 involved the expansion of LG-Caltex
(LGC), Caltex' 50% owned joint venture in Korea, which is active in the gas and
power area. Building on its acquisition of Kukdong City Gas in 1999, LGC has
acquired two power plants and three additional city gas companies, all of which
use Liquefied Natural Gas (LNG). These acquisitions propel Caltex into the fast
growing natural gas market and set the stage for the company to enter the LNG
import, transportation, wholesale and retail businesses.
Fuel and Marine Marketing LLC (FAMM)
FAMM is a joint venture between Texaco and Chevron. As a joint venture
company, FAMM has global residual fuels and marine lubricants businesses. We own
69% and Chevron owns 31% of the venture.
FAMM is a global supplier of marine fuels, lubricants, coolants and
industrial fuels, serving customers in over 400 ports and over 100 countries
worldwide. FAMM sells and distributes residual fuel oil for consumption by
waterborne vessels worldwide, as well as for land-based application and to
marine terminals worldwide. FAMM also sells and distributes marine lubricants
and coolants to waterborne vessels and for use in land-based engines using
marine lubricant technology.
For its marine customers, FAMM initiated an Internet company,
"OceanConnect.com," which provides a level market online e-commerce site for the
sale of marine fuels. Major investors include FAMM, BP Marine and Shell Marine
Products. Other shareholders include major shipping companies and other marine
providers.
18
GLOBAL GAS, POWER AND ENERGY TECHNOLOGY
Our Global Gas, Power and Energy Technology operations include the
marketing of natural gas and natural gas liquids, gas processing plants,
pipelines, power generation plants, gasification licensing and equity plants,
fuel processing, hydrocarbons-to-liquids, hydrogen storage systems and fuel cell
technology units.
Global Gas Marketing
Texaco Natural Gas - North America (TNG) is a fully integrated midstream
organization that offers a wide range of services including gas gathering,
processing, transportation, storage, sales and purchases, and risk management
for natural gas and natural gas liquids. TNG's primary objective is to grow
shareholder value by extracting value across the entire energy value chain -
from the wellhead to the burner tip.
The majority of TNG's assets are strategically located in the U.S. Gulf
Coast area. TNG owns and/or operates one of the largest producer-owned gas
pipeline systems in the U.S. consisting of more than 2,150 miles of pipe with
over 50 interconnects to other intrastate and interstate pipelines. The system
is comprised of three pipeline companies: Sabine Pipeline Company, Bridgeline
Holdings, L.P., and Discovery Gas Transmission LLC.
Sabine Pipeline features an open-access interstate natural gas pipeline
that extends from Port Arthur, Texas, to the Henry Hub near Erath, Louisiana.
The Henry Hub is the official delivery mechanism for the New York Mercantile
Exchange's natural gas futures contracts. This is due in large part to Sabine's
reputation for service, flexibility and reliability.
Effective March 1, 2000, Texaco and Enron Corp. formed a joint venture,
Bridgeline Holdings, L. P., that combines their regional marketing services,
intrastate pipelines and gas storage assets in southeast Louisiana. The new
venture, headquartered in Houston, Texas, has combined facilities consisting of
more than 1,000 miles of transmission and distribution pipeline, 7 billion cubic
feet (BCF) of salt dome storage capacity, with an additional 6 BCF in
development and 33,050 horsepower of compression. During 2000, Bridgeline
Holdings sales averaged nearly 1 BCF of natural gas per day. We own 60% and
Enron owns 40% of this venture.
Bridgeline Holdings has physical connections with many of the major
industrial companies, including some of the largest petrochemical, refining,
ammonia and gas-fired electric utility firms in the world. With interconnects to
pipelines from the Gulf of Mexico, customers are presented with access to
abundant offshore supplies. The system also includes excellent delivery access
to several interstate and intrastate pipelines that connect to the Northeast,
Southeast and Mid-continent regions. In addition, the combined capabilities and
interconnections of Bridgeline Holdings' gas storage facilities at Sorrento and
Napoleonville will substantially increase the flexibility and range of services
that will be available to customers. The storage capacity will provide the
flexibility to meet many gas needs, including emergency back-up, needle and
seasonal peaking, winter/summer price hedging and gas future hedging.
Discovery Gas Transmission, a major natural gas gathering and transmission
pipeline in the offshore waters of the Gulf of Mexico, adds significant value
from this key area in the Gulf. The 30-inch pipeline stretches 105 miles into
the Gulf with numerous laterals to deepwater drilling fields and provides
crucial capacity to a currently under-served area. The project also includes a
gas processing plant in Larose, Louisiana, giving Gulf Coast producers a
convenient means for gathering, processing and transporting gas to market. In
addition, Discovery has installed a 42,000-barrel-a-day fractionator at the site
of our Paradis gas processing plant. We hold a one-third ownership interest in
Discovery with partners, Williams Companies and British-Borneo.
19
In addition to the Larose gas processing plant, TNG operates four natural
gas processing plants located in South Louisiana, which have a combined capacity
of 1.2 billion cubic feet a day. TNG also has an ownership interest in two other
plants. These assets strategically position TNG to take advantage of the
significant influx of natural gas, which we expect from deepwater developments
in the Gulf of Mexico.
TNG also has substantial natural gas liquid (NGL) assets in the state of
Louisiana. We recently constructed the Texaco Expanded NGL Distribution System
(TENDS) to further leverage our strategic position in South Louisiana and take
advantage of increasing volumes of gas coming on shore from deepwater
developments. This system integrates newly constructed and purchased pipelines
with our existing assets. The result is an integrated bi-directional natural gas
liquid pipeline, fractionation and underground storage system with a combined
pipeline length of about 500 miles, extending from Lake Charles to Alliance,
Louisiana. The TENDS project has already provided a platform for expansion of
our Louisiana infrastructure through numerous new connections and opportunities.
The NGL Marketing Group transports and markets NGL throughout the world,
although its primary focus is North America. With sales averaging nearly 230,000
barrels a day, TNG is one of the largest marketers of NGL in the industry.
Marketing of propane to wholesale customers in the U.S. has provided a
significant financial contribution for many years.
In Ferndale, Washington, the NGL Marketing Group operates the largest NGL
import/export terminal on the West Coast. This facility includes 750,000 barrels
of storage for butane and propane. Drawing on product from Canada and local
refineries, this terminal provides strategic access to markets including the
Pacific Rim.
The Gas Marketing Group markets 3.6 billion cubic feet per day of equity
and third party gas to major North American utilities, industrial customers and
other marketing/trading companies. TNG ensures that we receive the highest
netback price for its equity production as well as optimizing pipeline capacity.
This unit provides customized and comprehensive risk management and other
financial tools to enable customers and suppliers to structure deals consistent
with their specialized needs. TNG also leases natural gas storage in strategic
locations to take advantage of price arbitrage as well as handle production
fluctuations. Further, TNG provides fuels management services to a number of our
cogeneration partnerships.
Gasification
Our proprietary gasification technology converts a wide variety of
hydrocarbon feedstocks into a clean synthesis gas (syngas) comprised of hydrogen
and carbon monoxide. The syngas can be used as a feedstock for other chemical
processes or as a fuel for use in the most advanced gas turbines to generate
electricity. We license this technology and operate our own gasification
facilities, and develop and invest in projects using this technology.
Recognized as the world leader in gasification technology, our proprietary
Texaco Gasification Process (TGP) has been licensed to more than 70 plants under
development, under construction or in operation in the refining, chemical and
power generation industries worldwide. Syngas production at these facilities
exceeds 5.5 billion standard cubic feet per day. Recent TGP projects include:
o In Louisiana, TECO Power Services licensed our integrated gasification
combined-cycle (IGCC) technology for a 665-megawatt petroleum coke-fired
power plant, which is scheduled for completion in 2005.
20
o In China, there are currently 10 TGP plants in operation and two under
construction, each producing clean syngas primarily for ammonia/urea
fertilizer production from indigenous coal and heavy oil. TGP's success in
China led to the signing of a multi-plant agreement with Sinopec and the
former Ministry of Chemical Industry to retrofit an additional nine plants
that are currently using competitive technology.
o In the year 2000 alone, Texaco personnel assisted our worldwide licensees in
the start-up activities of 12 TGP projects, representing an investment in our
technology of more than $4.5 billion. The $350 million Delaware Clean Power
Project at Motiva's Delaware City Refinery is currently in the start-up phase
and will use TGP in the world's cleanest process for generating clean power
(electricity and steam) from petroleum coke.
o In Italy, two refineries have commissioned large, world-class 500-megawatt
IGCC power plants and a third, in which we have taken a 24% equity interest,
is in the final commissioning and start-up phase.
These TGP units will enable the refineries to convert high-sulfur residues
into clean, higher-value products such as hydrogen, electricity and steam that
are used within the refineries, or sold if surplus to the refineries' needs. TGP
will provide these refineries with wider flexibility with respect to crude
selection, which can provide substantial financial savings, while minimizing
waste streams at these plants.
Power Generation
Our electrical power business includes conventional power generation
projects, as well as cogeneration facilities.
Cogeneration is a process that produces two useful forms of energy from a
single fuel, such as natural gas. The energy products are thermal energy, such
as steam, and electric power. Whether the thermal energy is provided to a
refinery or used to steamflood a heavy oil field, cogeneration boosts
profitability by improving efficiency. In the narrower context of producing oil,
cogeneration is the most efficient way to generate the steam required for
steamflooding.
To date, our largest U.S. cogeneration operations have burned natural gas
to produce heat for steamflooding our Kern River oil field in California while
simultaneously generating electricity. We are now adding to the portfolio of
nine cogeneration facilities we presently operate with our partners in the U.S.
These facilities produce enough electricity to power more than one million
homes. Including projects under construction or development in which we have an
equity share, our cogeneration and conventional power portfolio exceeds 3,000
megawatts.
A major new project is in Indonesia, where subsidiaries of Texaco and
Chevron and a private partner have constructed the largest cogeneration plant of
its kind in that country. The $190 million, 300-megawatt gas-fired plant
supplies power and steam for use in steamflooding the Duri field in Indonesia's
Central Sumatra Province.
A key new combined cycle power project in Thailand began operations in
2000. This $400 million, 740-megawatt gas-fired plant will feed the growing
power needs of Thailand's rapidly expanding economy.
Another 2000 addition to our power portfolio was the acquisition of a 25%
interest in two gas-fired combined cycle power plants in Korea. The $690 million
plants, which together total 951 megawatts, are located in newly constructed
suburban areas of greater Seoul.
Through our electrical power and gasification businesses, we are currently
involved in power projects, either through ownership or licensing, that will
produce over 8,500 megawatts of power.
21
The electric utility deregulation plan adopted by the state of California
in 1996 required utilities to dispose of a portion of their power generation
assets. As a result, utilities that serve California purchase power on the open
market, and, in turn, sell power to the retail customers at capped rates. During
the fourth quarter of 2000, California's power and gas markets experienced
significant price volatility. Increased demand resulted in very high market
prices that California utilities paid for power with no certainty they could
recover these costs from their customers. As both supplier to and purchaser from
the utility companies, Texaco has financial and operational exposure in
California. While the possible outcomes for the California utility situation
remain uncertain, we believe that they will not have a material adverse impact
on our financial condition or results of operations.
Texaco Energy Systems Inc.
Texaco Energy Systems Inc. (TESI) was created in 1999 to explore
opportunities to broaden our energy portfolio. Leveraging the strength of a
global corporation, TESI is developing businesses related to
hydrocarbons-to-liquids (HTL), fuel cells, fuel processing, hydrogen storage and
alternate fuels. As a technology-based company, we are applying energy expertise
and proprietary technologies to make these emerging energy businesses a reality.
HTL technology makes possible the conversion of low-value feedstocks, such
as stranded gas and heavy oil/petroleum coke from producing operations and
refineries into high-quality diesel fuel as well as specialty products. The
technology consists of syngas generation followed by conversion into liquids by
utilizing the Fischer-Tropsch process. Our world-renowned gasification
technology is a leading synthesis gas generating technology especially for
liquid and solid feedstocks.
During 2000, TESI's activities focused on initial development of potential
commercial opportunities related to value creation from natural gas and
petroleum coke. We completed three site-specific pre-feasibility studies for
international opportunities involving natural gas and petroleum coke. Based on
the results, we undertook detailed feasibility studies. Also during the year,
TESI completed the first phase of a three-phase Department of Energy (DOE)
project entitled "Early Entrance Coproduction Plant" (EECP). This phase, largely
funded by the DOE, confirmed that the integration of the HTL technology with
combined cycle power generation into a refinery environment is feasible and has
synergetic benefits.
In June 2000, we purchased 20% of the equity of Energy Conversion Devices,
Inc. (ECD), a publicly traded research and development company located in Troy,
Michigan. Subsequently, TESI formed two joint ventures with ECD to assist them
in commercializing two promising new technologies, metal hydride fuel cells and
hydrogen storage. These two new ventures are:
o Texaco Ovonic Fuel Cells LLC, which is developing a new type of fuel cell
that does not require the use of expensive noble metal catalysts such as
platinum, utilized by most other fuel cell technologies.
o Texaco Ovonic Hydrogen Systems LLC, which is developing a metallic alloy,
which can store hydrogen at ambient temperatures and atmospheric pressure.
This storage system has the potential to facilitate the use of fuel cells in
automobiles and other portable power applications.
TESI is also continuing the in-house development of our proprietary fuel
processing expertise to develop an economical means of converting common
hydrocarbons such as natural gas into hydrogen to power fuel cell devices.
Results to date have been very promising.
Additionally, in 2000, we acquired a 5% interest in Acumentrics
Corporation, a developer of solid oxide fuel cells. The $10 million purchase
will complement Texaco's alternative energy activities, including the
commercialization of fuel cell technologies.
22
Texaco Technology Ventures
Texaco Technology Ventures (TTV) was established as a division of Texaco in
August 2000 to focus on three business activities: the representation of our
shareholder interest in ECD, the strategic management of our interest in all
activities between Texaco and ECD and the execution of additional equity
investments in advanced energy technologies. In addition, Texaco, through TTV,
provides marketing assistance to ECD in photovoltaics and other business
segments.
On October 10, 2000, TTV announced its intention to purchase General
Motors' interest in its joint venture with ECD, GM Ovonic LLC, which was formed
in 1994 to commercialize ECD's nickel-metal hydride battery technologies. The
purchase is expected to be finalized during the second quarter of 2001, and it
is anticipated that the company will be renamed Texaco Ovonic LLC. The company
will be the third joint venture between Texaco and ECD-related companies. The
new venture will supply the emerging hybrid-electric and 42-volt automotive
battery markets and will also broaden marketing efforts to include segments
outside the automotive industry.
In the future, TTV will continue to invest in energy technologies where, as
an equity partner, we provide more to the business than capital and/or receive
more from the business venture than capital appreciation. The potentials of
energy technology companies are judged by the financial markets on two criteria:
the size of the market that their technology targets and their access to that
market. In the area of market access, we provide many benefits as a partner to
promising technology companies, including a highly regarded brand image,
government and industry contacts, technological expertise, global distribution
and strong marketing skills. Furthermore, we have proprietary technologies under
internal development that could benefit from investments in related companies.
TECHNOLOGY
Technology drives growth in our industry - and we are generating new
technology and capturing greater value through fast, effective applications of
technology. Below are a few key examples of how we are applying our technologies
to create increased value.
Heavy Oil Upgrading
We have a comprehensive oil-upgrading technology program aimed at
developing and applying methods to enhance the value of our oil assets. The
program targets oils that are heavy and contain significant amounts of sulfur,
metals and acid, or that have lower value with respect to benchmark light
crudes. We enhanced this program by acquiring an equity ownership of Unipure
Corporation in late 2000. Unipure Corporation has developed technology that is
being fully tested and commercialized through a joint venture with Texaco.
Our strategy is to develop and apply upgrading technologies at the
producing site to capture extra value from heavy crude production. For example,
we have developed Heavy Oil Upgrading technology for effective sulfur removal
and to increase the API gravity of heavy crude oil. This technology has proven
to be particularly effective in pilot testing with Middle Eastern crudes such as
Arab Heavy, Ratawi and Eocene. In the case of the Eocene crude, the technology
was effective in reducing sulfur content from 4.5% to 0.3%, while upgrading the
crude oil from 20(degree) API to 35(degree) API.
We are also focusing on the development of radical new technologies for
sulfur and metals removal and for API upgrading. This includes Low-Pressure and
Temperature Oxidation technology and Bio-desulfurization. When commercialized,
these new technologies will result in significant additional hydrocarbon value.
23
Thermal Heavy Oil Recovery
We have continued to focus on thermal technologies that have the best
opportunity to maximize the value of our heavy oil assets by reducing capital
and operating costs and improving steam heat management. One area in which we
have made progress is in new down-hole heating technologies. We are testing two
technologies, one that proves a brand new concept and the other that uses
off-the-shelf technology. These are Down-hole Steam Generation and Down-hole
Induction Heating, respectively. During the year, we conducted field tests for
both technologies in our California operations. The successful completion of
these tests moves these technologies one step closer toward commercial
viability.
The commercial development of Down-hole Steam Generation could expand
steamflooding to offshore assets, deeper zones and ecologically sensitive areas.
At the same time, these new technologies will substantially reduce capital and
operating costs over those of conventional steam generation.
Prototype of Glycol-free Coolant Technology
We have developed a new proprietary glycol-free coolant technology, which
provides the necessary freezing protection and synergistic corrosion protection
for automobile, truck and marine engines. It improves heat transfer and fluidity
characteristics. The technology also has the clear advantage of being non-toxic
and 100% biodegradable. A prototype coolant, ETX2010 was presented to Renault,
Ford Europe, Ford USA and GM. Today, our extended-life coolants are in new cars
built by General Motors in the U.S. and by Opel, Vauxhaul, Landrover, Ford,
Jaguar, Volkswagen and Renault in Europe and in Caterpillar heavy-duty engines
worldwide. In addition, Havoline extended-life coolant will be used as fuel cell
coolant in GM's concept car.
Fuel Additive Technology
New and improved technology has allowed Texaco Additives International to
enter new markets and to improve profitability. We have introduced a new
additive that improves gasoline engine fuel economy into the Asian market, and
there is significant interest in the product within North America. The additive
works by reducing friction inside automotive engines. In Europe, fuel additives
have been introduced with considerable success into the service station and
workshop markets. In North America, we have been able to win new customers. In
both cases, having sound technical data to support claims differentiates us from
the competition. Also in Europe, technical qualifications of new additive
sources has led to major reductions in gasoline additive cost, thereby improving
profits and giving us a competitive edge.
Leading Lubricant Technology
During 2000, our lubricant technology resources and expertise have been
expanded and utilized in support of several new ventures. Our technology has
demonstrated its value on new joint ventures and enabled us to establish new
partnerships. In particular, our product and technology support programs have
strengthened our business ventures with TNK-Texaco in Russia, with Prista in
Bulgaria and with Somepi SA in Morocco. In addition, our recent advances in
lubricant technology and our ability to work co-operatively proved to be
critical elements in the AB Volvo Group's selection of Texaco as its global
preferred supplier.
24
Hydrocarbons/Gas-to-Liquids Technology
Texaco established a "technology portfolio" approach to developing
conversion technologies for both natural gas and low-value hydrocarbon products.
The primary objective of this program is to develop Hydrocarbons/ Gas-to-Liquids
technologies to convert remote natural gas resources to valuable middle
distillates and increase the commercial value of these assets. The technology
portfolio approach includes in-house research and outside partnerships with
various corporations and universities. During the year 2000, we participated in
a U.S. Department of Energy project to pilot test a catalyst-based
gas-to-liquids technology at Laporte, Texas, working in partnership with Rentech
Inc. The coupling of our proprietary Gasification Process technology with the
new gas-to-liquids technology should provide an integral process that will
improve the economics of the project and make more effective use of the total
energy resources.
Technology Leadership
During the last two years, we have implemented a new model for technology
development, commercialization and value growth. This model continues our focus
on extracting value from technology through its application to Texaco's
resources. It also provides for added value from further development and
application of these technologies beyond the scope of our current business
focus.
We have now formed two new companies that will help to promote the broader
development of two of Texaco's outstanding technologies.
The first of these companies is Alto Technology, a wholly-owned subsidiary
that will further develop and commercialize the Texaco Energy and Environmental
Multispectral Imaging Spectrometer (TEEMS) remote sensing technology. The market
opportunities for this unique technology extend beyond the business focus of
Texaco operations and include agriculture, land management and ecological
activities. Alto Technology will continue to provide us with remote sensing
capability to help us identify potential oil deposits in environmentally
sensitive areas, as we have previously done in the United States, Colombia, the
Partitioned Neutral Zone and Indonesia.
Similarly, we formed Magic Earth, LLC to further develop and expand the
applications of our 3-D Visualization technology. We will continue to use this
technology to help discover large reserves and improve recovery from existing
fields. We hold a substantial interest in Magic Earth and will participate in
defining the future direction of this revolutionary technology. Through the
formation of Magic Earth, our 3-D visualization efforts will be expanded into
other industries, and will lead to new technology products and applications from
which our company can benefit.
25
ADDITIONAL INFORMATION CONCERNING OUR BUSINESS
Research Expenditures
Worldwide expenditures of Texaco Inc. and subsidiary companies for
research, development and technical support amounted to approximately $108
million in 2000, $96 million in 1999 and $138 million in 1998.
Environmental Expenditures
Information regarding capital environmental expenditures of Texaco Inc. and
subsidiary companies, including equity in affiliates, during 2000, and
projections for 2001 and 2002, for air, water and solid waste pollution
abatement, and related environmental projects and facilities, is incorporated
herein by reference from page 42 of Texaco Inc.'s 2000 Annual Report to
Stockholders.
Employees
The number of employees of Texaco Inc. and subsidiary companies as of
December 31, 2000 totaled 19,011 and as of December 31, 1999 totaled 18,443.
Sales to Significant Affiliates
Sales by Texaco Inc. and subsidiary companies to significant affiliates
totaled $7,811 million in 2000, $4,839 million in 1999 and $4,169 million in
1998.
Geographical Financial Data
Information regarding geographical financial data of Texaco Inc. and
subsidiary companies appears in Note 1, Segment Information, on pages 52 through
54 of Texaco Inc.'s 2000 Annual Report to Stockholders.
Incorporation by Reference
We have incorporated some data and information appearing in our 2000 Annual
Report to Stockholders into Items 1, 2, 3, 5, 6, 7, 8 and 14 of this Form 10-K.
No other data and information in our Annual Report to Stockholders is
incorporated by reference into, or filed as part of, this Annual Report on Form
10-K.
26
FORWARD-LOOKING STATEMENTS AND
FACTORS THAT MAY AFFECT OUR BUSINESS
This Form 10-K may contain or incorporate by reference to other documents
"forward- looking statements" that are based on our current expectations,
estimates, projections, beliefs and assumptions about our company and the
industries in which we operate. We use words such as "expects," "anticipates,"
"intends," "plans," "believes," "estimates," "potential," and similar
expressions to identify such forward-looking statements. Section 27A of the
Securities Act of 1933 protects us from liability in private actions under the
Securities Act based on "forward-looking statements" which later prove to be
inaccurate. We have based our forward-looking statements on a number of
assumptions, any or all of which could ultimately prove to be inaccurate. We
cannot predict with any certainty the overall effect of changes in these
assumptions on our business. Following are some of the important factors that
could change these assumptions and that could adversely affect our business and
cause actual results to differ materially from those projected in the
forward-looking statements:
Business Risks
o incorrect estimation of reserves
o inaccurate seismic data
o mechanical failures
o decreased demand for motor fuels, natural gas and other products
o above-average temperatures
o pipeline failures
o oil spills
o worldwide and industry economic conditions
o inaccurate forecasts of crude oil, natural gas and petroleum product prices
o increasing price and product competition
o higher costs, expenses and interest rates
o the outcome of pending and future litigation and governmental proceedings
o continued availability of financing
o strikes and other industrial disputes.
Laws, Regulations and Legislation. In the U.S. and other countries in which
we operate, various laws and regulations that affect the petroleum industry are
either now in force, in standby status or under consideration, dealing with such
matters as:
o production restrictions
o import and export controls
o price controls
o crude oil and refined product allocations
o refined product specifications
o environmental, health and safety regulations
o retroactive and prospective tax increases
o cancellation of contract rights and concessions by host governments
o expropriation of property
o divestiture of operations
o foreign exchange rate changes and restrictions as to convertibility of
currencies
o tariffs and other international trade restrictions.
Proposed Chevron-Texaco Merger. Factors that could impact the proposed
Chevron-Texaco merger include:
o the possibility that the merger will not be consummated
o the process of, or conditions imposed in connection with, obtaining
regulatory approvals for the merger
o the possibility that the anticipated benefits from the merger cannot be
fully realized
o the possibility that costs or difficulties related to the integration
of our business with Chevron will be greater than we expected.
27
Euro Conversion. Factors that could alter the financial impact of our euro
conversion include:
o changes in current governmental regulations and interpretations of such
regulations
o unanticipated implementation costs
o the effect of the euro conversion on product prices and margins.
The forward-looking statements included in this report are only made as of
the date of this report, and we do not intend to update such forward-looking
statements to reflect subsequent events or circumstances, unless required by law
or such statements are hereafter referenced or incorporated into a subsequent
written statement.
Item 3. Legal Proceedings
Litigation--We have provided information about legal proceedings pending
against Texaco Inc. and subsidiary companies in Note 15, "Other Financial
Information, Commitments and Contingencies - Litigation" on page 69 of our 2000
Annual Report to Stockholders. Note 15 is incorporated here by reference.
As of December 31, 2000, three purported stockholder derivative suits were
pending in state court in Delaware against Texaco Inc. and its directors. The
suits allege, among other things, that the directors breached their fiduciary
duties to the corporation and its stockholders by failing to ensure that
stockholders receive appropriate consideration in the proposed merger with
Chevron. The cases, titled Zucker v. Texaco Inc., et al., Ursula Desimone Trust
v. Texaco Inc., et al. and Priven v. Texaco Inc., et al., seek money damages on
behalf of Texaco Inc. and its stockholders, attorneys fees and injunctive
relief.
The Securities and Exchange Commission (SEC) requires us to report
proceedings that were instituted or contemplated by governmental authorities
against us under laws or regulations relating to the protection of the
environment. None of these proceedings is material to our business or financial
condition. Following is a brief description of those proceedings that were
either pending as of December 31, 2000, or settled during the fourth quarter of
2000.
o On June 9, 1992, the U.S. Environmental Protection Agency (EPA), Region VI,
served an administrative complaint on Texaco Chemical Company (TCC). The
complaint alleges that TCC violated the State Implementation Plan at its
Port Neches, Texas chemical plant. We sold TCC to Huntsman Corporation on
April 21, 1994, and, by agreement, we retained obligations applicable to
events occurring at the plant prior to the closing date. The EPA is seeking
civil penalties of $149,000.We are contesting liability.
o On December 28, 1992, the EPA, Region VI served an administrative complaint
on TCC. The complaint alleged hazardous waste, PCB, release notification
and reporting violations at TCC's Port Neches chemical plant. The EPA is
seeking civil penalties of $3.8 million and corrective action. We are
contesting liability and agreed with the EPA to consolidate this complaint
with the June 9, 1992 complaint, described above. The consolidated matter
is pending before an EPA administrative law judge.
o In March 1998 the U.S. Department of Justice (DOJ) filed a complaint
against us regarding spills of oil and produced water at the Aneth
Producing Field in Utah in violation of the Clean Water Act. The DOJ is
seeking a penalty of approximately $2.3 million. We are contesting
liability.
o Commencing in December 1999, the San Joaquin Valley Unified Air Pollution
Control District issued a series of 59 Notices of Violation to Texaco
California Inc. (TCI) and Texaco Exploration and Production Inc. (TEPI)
alleging various permit violations in the Midway-Sunset fields and Kern
River fields in Kern County, California, primarily in connection with a
project to refurbish, replace and expand the number of steam generators
used in the Midway-Sunset fields. Effective September 1, 2000, TCI and TEPI
settled these Notices of Violation by paying a civil penalty of $100,000.
28
o In December 1999, the DOJ notified us that it would file a complaint
alleging that the Aneth gas plant, located near Montezuma Creek, Utah,
violated Clean Air Act regulations when renovation work was done on the
plant in 1991 and when asbestos-containing debris was cleaned up after an
explosion in December 1997. The notice also alleged the Aneth Producing
Field in Utah violated section 304 of the Emergency Planning and Community
Right-to-Know Act for failing to provide proper notice to emergency
response authorities about releases of sulfur dioxide in December 1997. The
DOJ is expected to seek more than $100,000 in penalties. We are contesting
liability.
o Texaco Refining and Marketing Inc. (TRMI) has tentatively negotiated a
settlement with the DOJ to resolve violations of the Clean Water Act at two
former facilities in California: the Los Angeles refinery and a service
station in San Luis Obispo. Under the terms of the tentative settlement,
TRMI would pay more than the reporting threshold in penalties and plead
guilty to two violations of the Clean Water Act. Further details of the
settlement will be reported when it is finalized.
Item 4. Submission of Matters to a Vote of Security Holders
Not applicable.
29
PART II
The following information, contained in Texaco Inc.'s 2000 Annual Report to
Stockholders, is incorporated herein by reference. Page references are to the
paper document version of Texaco Inc.'s 2000 Annual Report to Stockholders, as
provided to stockholders:
Texaco Inc.
2000
Annual Report
to Stockholders
Form 10-K Item Page Reference
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters 84 (a)
Item 6. Selected Financial Data
Five-Year Comparison of Selected Financial Data 81
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 27-43
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Supplemental Market Risk Disclosures 79
Item 8. Financial Statements and Supplementary Data
Description of Significant Accounting Policies 44-45
Consolidated Statement of Income 46
Consolidated Balance Sheet 47
Consolidated Statement of Stockholders' Equity 48-49
Consolidated Statement of Comprehensive Income 50
Consolidated Statement of Cash Flows 51
Notes to Consolidated Financial Statements 52-69
Report of Independent Public Accountants 70
Supplemental Oil and Gas Information 71-78
Selected Quarterly Financial Data 80
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure Not applicable.
(a) Only the data and information provided under the caption "Common
Stock-Market and Dividend Information" is deemed to be filed as part of
this Annual Report on Form 10-K.
30
PART III
Item 10. Directors and Executive Officers of the Registrant
DIRECTORS OF TEXACO INC.
Following is certain biographical information concerning the directors of
Texaco Inc.
Glenn F. Tilton, 52, has been Chairman of the Board and Chief Executive Officer
of Texaco Inc. since February 4, 2001. He joined Texaco in 1970 and after
serving in various domestic marketing, corporate planning, and European
downstream assignments of increasing responsibility, in 1989, while serving as
President of U.S. Refining and Marketing, he was elected a Vice President of
Texaco Inc. He was elected Chairman of Texaco Ltd. in 1991 and was named
President of Texaco Europe in 1992. He became President of Texaco USA in January
1995 and was elected a Senior Vice President of Texaco Inc. in April 1995. In
January 1997, he was appointed President of Texaco's Global Business Unit. He
also serves on the President's Advisory Board at the University of South
Carolina, on the Board of Directors of the American Petroleum Institute, and on
the Board and Executive Committee of the British American Chamber of Commerce.
A. Charles Baillie, 61, Chairman and Chief Executive Officer of the
Toronto-Dominion Bank, became a Director in December 1998. He was elected Vice
Chairman of Toronto-Dominion Bank in 1992, President in February 1995, Chief
Executive Officer in February 1997 and Chairman of the Board in February 1998.
He joined the Bank in 1964 and progressed through a variety of assignments both
in the United States and Toronto. Baillie serves as a director of Dana
Corporation and is Chairman and a director of TD Waterhouse.
Mary K. Bush, 52, President of Bush International, Inc. (formerly Bush &
Company), an international financial consulting firm, joined the Board in July
1997. Prior to founding Bush & Company in 1991, she served from 1989 to 1991 as
Managing Director of the U.S. Federal Housing Board. Prior to that position, she
was Vice President - International Finance at the Federal National Mortgage
Associate (Fannie Mae). From 1984 to 1988, she served as U.S. Alternate
Executive Director of the International Monetary Fund (IMF). She serves on a
number of boards and advisory boards, including Mortgage Guaranty Insurance
Corporation, Brady Corporation, R.J. Reynolds Tobacco Holdings, Inc., a number
of Pioneer mutual funds, Washington Mutual Investors Fund, March of Dimes,
Hoover Institution and the University of Maryland Foundation.
Edmund M. Carpenter, 59, President and Chief Executive Officer of Barnes Group
Inc. since December 1998, became a Director in September 1991. He was Sr.
Managing Director of Clayton, Dubilier & Rice, Inc. from May 1996 through
November 1998, and Chairman and Chief Executive Officer of General Signal
Corporation from 1988 to 1995. Prior to serving with General Signal, he was
President, Chief Operating Officer and a director of ITT Corporation. He is a
director of Campbell Soup Company and Dana Corporation.
Robert J. Eaton, 61, Chairman of the Board of Management of DaimlerChrysler AG
from November 1998 through March 31, 2000, and Chairman and Chief Executive
Officer of Chrysler from 1993 to November 1998, became a Director of Texaco in
October 2000. He is a fellow of the Society of Automotive Engineers and the
Engineering Society of Detroit and a member of the National Academy of
Engineering. He is a director of International Paper Company and a member of the
Business Council.
31
Michael C. Hawley, 63, retired Chairman and Chief Executive Officer of The
Gillette Company, has been a Director since July 1995. After joining Gillette in
1961, he held management positions of increasing responsibility in a variety of
countries and in 1985 was appointed Vice President, Operations Services, and
elected a corporate Vice President. In 1989, he was elected President of Oral-B
Laboratories, a Gillette subsidiary, and in 1993 was elected Executive Vice
President, International Group. In April 1995, he was named President and Chief
Operating Officer of The Gillette Company and a member of its Board of
Directors. Mr. Hawley was named Chief Executive Officer in April 1999 and served
as Chairman and Chief Executive Officer of The Gillette Company through his
retirement in October 2000. He is also a director of the John Hancock Financial
Services Co.
Franklyn G. Jenifer, 61, President of The University of Texas at Dallas since
July 1994, has been a Director since November 1993. Following an academic career
as a professor of biology, he was President of Howard University from 1990 to
1994. Prior to that he was Chancellor of the Massachusetts Board of Regents of
Higher Education, and from 1979 to 1986, Vice Chancellor of the New Jersey
Department of Higher Education. He serves on the Board of Trustees of the Texas
Health Research Institute, the Board of Directors of the United Way of
Metropolitan Dallas, the Executive Committee of the Alliance for Higher
Education, the Monitoring Committee for the Louisiana Desegregation Settlement
Agreement, and the Texas Science and Technology Council.
Sam Nunn, 62, former U.S. Senator from Georgia, joined the Board in September
1997. He was a member of the U.S. Senate from 1972 to January 1997, where he
served as chairman of the Senate Armed Services Committee. He is a senior
partner in the Atlanta law firm of King & Spalding with which he has been
associated since January 1997 and where his practice focuses on international
and corporate matters. Mr. Nunn is co-chairman and chief executive officer of
the Nuclear Threat Initiative, a Washington-based organization working to reduce
the global threat of weapons of mass destruction. He is also a distinguished
professor in the Sam Nunn School of International Affairs at Georgia Tech. Among
the non-profit boards on which he serves are the Center for Strategic and
International Studies, the Aspen Strategy Group and the Carnegie Corporation of
New York. He also serves on the boards of The Coca-Cola Company, Community
Health Systems, Inc., Dell Computer Corporation, General Electric Company,
Internet Securities Systems, Inc., National Service Industries, Inc., Total
System Services, Inc. and Scientific- Atlanta, Inc.
Charles H. Price II, 69, was Chairman of Mercantile Bank of Kansas City from May
1992 to April 1996 and has continued his long-standing service on the boards of
various corporations and charitable foundations begun before that time. He is a
former United States Ambassador to the United Kingdom (1983-1989) and Belgium
(1981-1983) and became a Director in March 1989. He is a director of The New
York Times Company and U.S. Industries, Inc. Prior to service as a United States
Ambassador, he had been Chairman of the Board of the Price Candy Company,
American Bancorporation and American Bank and Trust Company.
Charles R. Shoemate, 61, retired Chairman, President and Chief Executive Officer
of Bestfoods, joined the Board in October 1998. He joined Bestfoods, formerly
CPC International, in 1962 and progressed through a variety of positions in
manufacturing, finance and business management within the consumer foods and
corn refining businesses. He was elected President and a member of its Board of
Directors in 1988, Chief Executive Officer in August 1990 and Chairman in
September 1990, serving until October 2000. In February 2001, he was named an
Advisory Director of Unilever. He is a director of CIGNA Corporation,
International Paper and a Trustee of the Conference Board.
32
Robin B. Smith, 61, Chairman and Chief Executive Officer of Publishers Clearing
House since August 1996 and President and Chief Executive Officer since January
1988, became a Director in January 1992. Prior to joining Publishers Clearing
House in 1981 as President and Chief Operating Officer, she concluded her
sixteen year career with Doubleday & Co., Inc. as President and General Manager
of its Dell Publishing subsidiary. She is a director of Springs Industries,
Inc., BellSouth Corporation, Kmart Corporation and a number of Prudential mutual
funds.
William C. Steere, Jr., 64, Chairman of Pfizer, became a Director in September
1992. Mr. Steere began his career with Pfizer, a diversified pharmaceutical
company with global operations, and attained the positions of President of
Pfizer Pharmaceuticals Group and President and Chief Executive Officer before
elevation to Chairman of the Board in 1992. He served as President until March
1992 and Chief Executive Officer through December 2000. He is a director of
Metropolitan Life Insurance Company, Dow Jones & Company, Inc., the New York
Botanical Garden, Minerals Technologies Inc. and the New York University Medical
Center.
Thomas A. Vanderslice, 69, a private investor, has been a Director since April
1980. He has been President of TAV Associates since May 1993, and formerly was
Chairman of the Board, President and Chief Executive Officer of M/A-COM, Inc.,
Chairman and Chief Executive Officer of Apollo Computer, Inc., President and
Chief Operating Officer of GTE Corporation and an officer of General Electric
Company. He is a member of the Board of Trustees of Boston College and the
National Academy of Engineering, the American Chemical Society and the American
Institute of Physics.
33
EXECUTIVE OFFICERS OF TEXACO INC.
The executive and other elected officers of Texaco Inc. as of March 12, 2001
are:
Name and Age Position Major Area of Responsibility
------------------------------ ---------------------------- ----------------------------
Glenn F. Tilton 52 Chairman and Chief Executive Chief Executive Officer
Officer since February 2001
Patrick J. Lynch 63 Senior Vice President and Chief Chief Financial Officer
Financial Officer since January 1997
John J. O'Connor 55 Senior Vice President since Worldwide Exploration
January 1998 & Production
William M. Wicker 51 Senior Vice President since Global Businesses
August 1997
Bruce S. Appelbaum 53 Vice President since Worldwide Exploration
March 2000 & New Ventures
John E. Bethancourt 49 Vice President since Worldwide Production
May 2000 Operations
Eugene G. Celentano 62 Vice President since International Marketing
July 1995 & Manufacturing
James F. Link 56 Vice President since October 1999 Finance & Risk Management
James R. Metzger 53 Vice President since June 1997 Chief Technology Officer
Rosemary Moore 50 Vice President since Corporate Communications
June 2000 and Government Affairs
Robert C. Oelkers 56 Vice President since Worldwide Supply &
December 1996 Trading Operations
Elizabeth P. Smith 51 Vice President since Investor Relations &
February 1992 Shareholder Services
Robert A. Solberg 55 Vice President since Worldwide Upstream
September 1992 Commercial Development
Janet L. Stoner 52 Vice President since October 1997 Human Resources
Michael N. Ambler 64 General Tax Counsel since Tax
December 1990
George J. Batavick 53 Comptroller since April 1999 Chief Accounting Officer
Ira D. Hall 56 Treasurer since October 1999 Finance
Michael H. Rudy 57 Secretary since January 2000 Corporate Secretary
34
There are no family relationships among any of the officers of Texaco Inc.
Except as noted below, each of the company's executive and other elected
officers have held the positions listed on the previous page for more than five
years.
Name Position and Date Position Assumed
--------------------------------------------------------------------------------
G.F. Tilton - President of Global Businesses - January 1997
- President of Texaco USA - January 1995
P.J. Lynch - President of Texaco Europe - January 1995
J.J. O'Connor - Chief Executive Officer of BHP Petroleum - August 1994
W.M. Wicker - President of Global Businesses - February 2000
- Senior Vice President of Corporate Development - August
1997
- Managing Director and Co-Head of the Global Energy Group
for Credit Suisse First Boston - March 1995
B.S. Appelbaum - Vice President of Worldwide Exploration - June 1999
- President of Exploration - January 1997
- President of International Exploration - May 1996
- Division Manager of Exploration - January 1991
J.E. Bethancourt - Vice President of Business Development - January 1997
- Managing Director of Business Development - April 1993
J.F. Link - Treasurer - March 1995
J.R. Metzger - Vice President of Corporate Planning & Economics -
December 1996
- General Manager of Information Technology - December
1988
R. Moore - Independent Communications Consultant - June 1996
- Corporate Vice President, Corporate Communications of
the Seagram Company Ltd. - August 1990
R.C. Oelkers - Vice President and Comptroller - December 1996
- Comptroller - March 1994
J.L. Stoner - Vice President of Producing - January 1997
- Vice President of Exploration and Producing - Latin
America/West Africa - May 1995
G.J. Batavick - Deputy Comptroller - October 1998
- Assistant Comptroller - December 1994
I.D. Hall - General Manager of Alliance Management - June 1998
- Director of Business Development of IBM Global
Services - March 1996
M.H. Rudy - Senior Counsel - August 1999
- Senior Attorney - July 1986
The rules of the Securities and Exchange Commission require that we
disclose late filings of reports of stock ownership and changes in stock
ownership by our directors and executive officers. To the best of our knowledge,
based on a review of the relevant forms and written representations from the
directors and officers, there were no late filings during 2000.
Item 11. Executive Compensation
COMPENSATION OF EXECUTIVE OFFICERS
Summary Compensation Table
Long-Term
Annual Compensation Compensation Awards(1)
----------------------------------- ----------------------
Securities
Other Restricted Underlying All
Name and Principal Annual Stock Options/ Other
Position Year Salary($) Bonus($) Compensation($)(2) Awards($)(3) SARs(#) Compensation($)(4)
-------- ---- --------- -------- ------------------ ------------ ---------- ------------------
G.F. Tilton 2000 421,225 434,494 3,931 744,928 65,850 25,274
Chairman of the 1999 406,000 284,021 3,805 497,855 214,485 24,360
Board/CEO(5) 1998 400,250 189,918 12,709 419,248 186,053 24,015
P.I. Bijur 2000 987,500 -- 6,521 4,086,641 361,250 59,250
Retired Chairman 1999 950,000 1,015,059 4,420 2,169,092 677,553 57,000
of the Board/ 1998 925,000 597,749 5,407 1,853,438 546,797 55,500
CEO(5)
P.J. Lynch 2000 454,575 489,616 5,330 744,928 65,850 27,275
Senior Vice 1999 435,000 338,634 5,124 497,855 214,427 26,100
President/CFO 1998 428,750 182,245 5,573 501,911 174,560 25,725
J.J. O'Connor 2000 473,625 489,616 -- 744,928 84,089 28,418
Senior Vice 1999 450,000 373,855 -- 497,855 80,877 27,000
President 1998 450,000 182,245 49,515 710,324 85,498 63,989
W.M. Wicker 2000 427,450 489,616 41,269 744,928 81,033 25,647
Senior Vice 1999 412,000 284,021 3,810 497,855 67,171 24,720
President 1998 409,000 182,245 4,533 419,248 52,026 8,240
(1) Upon closing of the merger with Chevron, restricted stock awards and
securities underlying options will be converted, to the extent practicable,
into ChevronTexaco common stock equivalents pursuant to the terms of the
merger agreement dated October 15, 2000.
(2) This column includes our aggregate incremental cost of providing various
perquisites and personal benefits in excess of reporting thresholds
including, for Mr. Wicker in 2000, $41,269 for reimbursement of taxes
applicable to club initiation fees and dues, and for Mr. O'Connor in 1998,
$49,515 for reimbursement of taxes applicable to moving expenses.
(3) Messrs. Tilton, Bijur, Lynch, O'Connor and Wicker had restricted
stockholdings of 150,483; 388,793; 119,174; 33,314; and 34,132 shares,
respectively, as of December 31, 2000. The shares had a market value of
$9,349,509; $24,155,709; $7,404,281; $2,069,799; and $2,120,621
respectively, at December 31, 2000, based on a value of $62.13 per share.
These share numbers and values include the awards since the last proxy
statement dated March 14, 2000, which are reported in the "Restricted Stock
Awards" column above. Dividends are paid on the restricted stock at the
same time and rate as dividends paid to holders of unrestricted stock.
(4) Matching contributions to the qualified and nonqualified Employees Thrift
Plan and relocation expenses.
(5) On February 4, 2001, Mr. Tilton became Chairman of the Board and Chief
Executive Officer of Texaco Inc., following the retirement of Mr. Bijur.
36
Individual Grants of Options in 2000
Number
of
Securities
Underlying % of Total Exercise or Grant Date
Options Options Base Expiration Present
Name Date Granted(#) Granted Price($/Sh.) Date Value $*
---- ---- ---------- ------- ------------ ---------- ----------
G.F. Tilton 06/23/00 65,850 2.055% 56.56250 06/23/2010 754,641
P.I. Bijur 06/23/00 361,250 11.275% 56.56250 06/23/2010 4,139,925
P.J. Lynch 06/23/00 65,850 2.055% 56.56250 06/23/2010 754,641
J.J. O'Connor 05/16/00** 18,239 0.569% 57.21875 01/02/2008 214,491
06/23/00 65,850 2.055% 56.56250 06/23/2010 754,641
W.M. Wicker 06/23/00 65,850 2.055% 56.56250 06/23/2010 754,641
11/29/00** 15,183 0.474% 61.47000 08/04/2007 185,536
* Valuation. All options are granted at an exercise price equal to the market
value of the Company's Common Stock on the date of grant. Therefore, if
there is no appreciation in that market value, no value will be realizable.
In accordance with Securities and Exchange Commission rules, we chose the
Black-Scholes option pricing model to estimate the grant date present value
of the options set forth in this table. Our use of this model should not be
construed as an endorsement of its accuracy at valuing options. All stock
option valuation models, including the Black-Scholes model, require a
prediction about the future movement of the stock price. We made the
following assumptions for purposes of calculating the Grant Date Present
Value: the option term is assumed to be two years, volatility at 33.80%,
dividend yield of 3.0% per share and interest rate of 6.4%. The real value
of the options in this table depends solely upon the actual performance of
the Company's Common Stock during the applicable period.
** Restored Options. All options include a restoration feature, by which
participants receive options to replace shares that they are using to either
(1) pay the Company for shares they are acquiring when they exercise a stock
option or (2) satisfy their tax withholding obligations. Since restored
options are granted at an exercise price which is equal to the market price
of the Company's Common Stock on the day of grant, they are issued at an
exercise price which is at a higher price than the exercise price of the
original grant. Options vest 50% after one year and become fully exercisable
after two years. Restored options are fully exercisable after six months and
expire at the date of the original grant. Restoration of options originally
granted and reported for Mr. O'Connor on January 2, 1998 and for Mr. Wicker
on August 4, 1997.
Aggregated Option Exercises in 2000 and Year-End Option Values
Shares Number of Securities Value of Unexercised
Acquired Underlying Unexercised In-the-Money Options
on Value Options at Year-End(#)* at Year-End($) **
Name Exercise(#) Realized($) Exercisable Unexercisable ExercisableUnexercisable
---- ----------- ----------- ----------- ------------- ------------------------
G.F. Tilton -- -- 192,194 93,605 8,283 366,620
P.I. Bijur -- -- 637,103 482,175 36,619 2,011,259
P.J. Lynch -- -- 196,242 93,605 9,916 366,620
J.J. O'Connor 1,193 68,262 110,852 93,605 123,519 366,620
W.M. Wicker 1,022 62,822 89,369 108,788 16,962 376,641
* Includes options reported in the chart entitled "Individual Grants of
Options in 2000".
** Based on the 2000 year-end price of $62.13.
37
RETIREMENT PLAN
Retirement Plan
Approximately 7,000 employees, including the 18 elected officers, are
eligible to participate in the Retirement Plan. The plan is a qualified plan
under the Internal Revenue Code and provides benefits funded by Company
contributions. In addition, participants have the option of making contributions
to the plan and receiving greater retirement benefits. Contributions are paid to
a Master Trustee and to insurance companies for investment.
For purposes of calculating pension benefits for the executive officers
named on page 33, the plan recognizes salary only and does not take into account
other forms of compensation. For the executive officers, salary and bonus for
the last three years are shown in the salary and bonus columns of the Summary
Compensation Table. The Internal Revenue Code provides that qualified plans may
not consider remuneration exceeding $170,000 per year (as indexed for inflation)
for purposes of calculating benefits under the Retirement Plan. The amount of an
employee's retirement benefit is the greater of a benefit based upon a final pay
formula (applicable in most cases), a career average formula or a minimum
retirement benefit. In addition to the qualified Retirement Plan, we sponsor
supplemental plans which take into account bonuses paid to a participant and
salary in excess of the Internal Revenue Code limitations.
Retirement Plan Table
YEARS OF BENEFIT SERVICE
-------------------------------------------------------------------
COVERED REMUNERATION* 15 20 25 30 35 40
---------------------- --------- -------- --------- -------- ---------- ----------
$ 100,000 $ 22,500 $ 30,000 $ 37,500 $ 44,700 $ 51,700 $ 58,700
200,000 45,000 60,000 75,000 89,400 103,400 117,400
400,000 90,000 120,000 150,000 178,800 206,800 234,800
600,000 135,000 180,000 225,000 268,200 310,200 352,200
800,000 180,000 240,000 300,000 357,600 413,600 469,600
1,000,000 225,000 300,000 375,000 447,000 517,000 587,000
1,200,000 270,000 360,000 450,000 536,400 620,400 704,400
1,400,000 315,000 420,000 525,000 625,800 723,800 821,800
1,600,000 360,000 480,000 600,000 715,200 827,200 939,200
1,800,000 405,000 540,000 675,000 804,600 930,600 1,056,600
2,000,000 450,000 600,000 750,000 894,000 1,034,000 1,174,000
* "Covered Remuneration" means the highest three-year average salary and
highest three-year average bonus, if any, during the last ten years of
employment. The company recognizes the following years of benefit service
for the following individuals as of December 31, 2000: Mr. Tilton, 31; Mr.
Bijur, 34; Mr. Lynch, 40; Mr. O'Connor, 3; and Mr. Wicker, 11. With respect
to the plans, annual pension benefits are based on the non-contributory
final pay formula (up to 1.5% of final average covered remuneration times
benefit service) and assume the participant retires at age 65 and has been a
non-contributory member of the plan throughout the period of service. These
amounts, however, do not reflect a reduction for Social Security benefits
pursuant to the provisions of the Retirement Plan. They do include those
additional sums, if any, payable under a Supplemental Retirement Plan to
compensate those employees who have earned annual retirement benefits
payable under the Retirement Plan but which are limited by the Internal
Revenue Code.
38
COMPENSATION OF BOARD OF DIRECTORS
Employee directors receive no compensation for service on the Board or its
committees. Non-employee directors receive an annual retainer of $40,000, and
$1,500 for each Board and committee meeting they attend, as well as an annual
fee of 900 restricted stock-equivalent units which have significant vesting and
transferability restrictions. Committee Chairs receive annual retainers of
$7,000. We pay one-half of each annual retainer in Common Stock or restricted
stock-equivalent units. Directors may elect to receive all or any part of the
remaining retainers and fees in Common Stock and to defer payment of fees, in
cash, in Common Stock or in restricted stock-equivalent units.
Directors may participate in a group personal liability and property damage
insurance program, which we administer and partially fund.
As part of our corporate-wide effort to encourage charitable giving, we
have established a directors' gift program. Only institutions that are qualified
recipients of grants from the Texaco Foundation may receive gifts under the
directors' program. Upon the death of a director, we will donate up to a total
of one million dollars to one or more qualifying charitable organizations
designated by the director. The directors' program is funded entirely by
insurance policies on the life of each director. We own the policies, pay the
premiums for such insurance ($40,306 paid for all directors in 2000) and are
entitled to all tax deductions resulting from any contributions made to the
qualifying charitable organizations. Individual directors derive no financial
benefit from this program.
39
Item 12. Security Ownership of Certain Beneficial Owners and Management
SECURITY OWNERSHIP OF DIRECTORS AND MANAGEMENT
The table below sets forth, as of February 1, 2001, information on Texaco
stock and units owned by our directors and executive officers. Except as noted
below, each person has sole voting and investment power over the shares listed.
Directors and executive officers as a group own less than 1% of our outstanding
Common Stock.
Number of Shares or Units
------------------------------------------------------------------------
Shares Underlying Stock-Equivalent
Total Stock Common Options Exercisable Restricted
Beneficial Owners Interest Stock Within 60 Days of 2/1/01 Units
----------------- ----------- ------ ------------------------ ----------------
A. Charles Baillie 6,171 3,000 -- 3,171
Peter I. Bijur* 1,047,744 410,641 637,103 --
Mary K. Bush 5,012 341 -- 4,671
Edmund M. Carpenter 12,256 827 -- 11,429
Robert J. Eaton 2,727 2,000 -- 727
Michael C. Hawley 12,188 400** -- 11,788
Franklyn G. Jenifer 8,499 200 -- 8,299
Patrick J. Lynch 354,388 158,146 196,242 --
Sam Nunn 7,216 423 -- 6,793
John J. O'Connor 147,647 36,795 110,852 --
Charles H. Price, II 16,149 2,497 -- 13,652
Charles R. Shoemate 7,225 2,500 -- 4,725
Robin B. Smith 9,861 600 -- 9,261
William C. Steere, Jr. 19,205 1,400 -- 17,805
Glenn F. Tilton* 360,554 168,360 192,194 --
Thomas A. Vanderslice 47,925 23,283 -- 24,642
William M. Wicker 125,257 35,888 89,369 --
All Directors and Executive
Officers as a group
(32 persons) 3,766,048 1,546,478 2,102,607 116,963
* On February 4, 2001, Mr. Tilton became Chairman of the Board and Chief
Executive Officer of Texaco Inc., following the retirement of Mr. Bijur.
** Mr. Hawley shares voting power over 400 shares of Texaco Common Stock with
his spouse.
CHANGE IN CONTROL
Upon the successful consummation of the merger of Texaco and Chevron,
Texaco will become a wholly-owned subsidiary of ChevronTexaco Corporation.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
State Street Bank and Trust Company, 225 Franklin Street, Boston,
Massachusetts 02110, filed a Schedule 13G with the Securities and Exchange
Commission disclosing that, as of December 31, 2000, it had sole voting power
over 39,241,349 shares, shared voting power over 254,046 shares, sole
dispositive power over 9,786,299 shares and shared dispositive power over
30,627,545 shares as Trustee of our Employee Stock Ownership Plan (ESOP) and a
similar plan maintained for our affiliates (as well as various collective
investment funds and personal trust accounts). Shares for which it had sole or
shared dispositive power represent approximately 7.4% of the Company's
outstanding Common Stock. Under the terms of the ESOPs, State Street is required
to vote shares it holds for the plan participants in accordance with
confidential instructions received from the participants and to vote all shares
for which it shall not have received instructions in the same ratio as the
shares with respect to which it received instructions.
40
Capital Research and Management Company, 333 South Hope Street, Los
Angeles, CA 90071, also filed a Schedule 13G, disclosing that as of December 31,
2000, it had sole dispositive power over 39,684,600 shares, or approximately
7.2% of our outstanding Common Stock.
We have established a grantor trust and contributed to such trust 9,200,000
shares of Common Stock. These shares are held by the Trustee to ensure that we
satisfy our obligations under our non-qualified deferred compensation plans and
arrangements. The Trustee votes the shares in the trust as the beneficiaries of
the trust instruct it. The Trustee votes shares for which no instructions are
received in the same ratio as the shares for which instructions have been
received.
Item 13. Certain Relationships and Related Transactions
TRANSACTIONS WITH DIRECTORS AND OFFICERS
Sen. Nunn is a member of the law firm of King & Spalding, which has
provided legal services to us for many years.
Messrs. O'Connor and Wicker each has an employment agreement that is
terminable at will. The agreements provide for salaries and benefits in
accordance with their respective positions and grades, awards of stock options
and performance restricted shares and additional service credits for welfare
benefit plan purposes. In addition, Mr. Wicker has an additional eight years of
service for supplemental pension credit.
On May 31, 2000, the company extended an interest free loan of $146,500 to
Mr. Bethancourt to fund a portion of his employment relocation expenses. The
loan was fully repaid to the company by Mr. Bethancourt on August 30, 2000.
SEVERANCE AGREEMENTS
Executive Officer Severance Agreements
As of March 12, 2001, twenty Texaco executives have severance agreements
with Texaco, which expire as of the first day of the month immediately following
the executive's 65th birthday. An executive will be entitled to the severance
benefits set forth in the severance agreements if, after the date of first
contact by a party, or a party's representative, with Texaco which results in a
"change of control" (as defined in the severance agreements) involving that
party or its affiliate and up to 36 months after a change of control, either the
executive's employment is terminated without "just cause" (as defined in the
severance agreements) or the executive resigns for "good reason." Under the
severance agreements, an executive will be deemed to resign for good reason if
he or she resigns within 60 days after:
o a reduction in the executive's base pay;
o a reduction in the executive's cash bonus in excess of 20% of the prior
year's award (unless the reduction is due to Texaco's performance under the
objective measurements of Texaco's Incentive Bonus Plan effective immediately
before the change of control or under the objective measurements of an
incentive compensation program with target bonuses and performance goals
comparable to and not materially less favorable to the executive than the
targets and goals described in the Incentive Bonus Plan in existence prior to
the change of control);
o the assignment of any duties inconsistent with the position in Texaco that
the executive held immediately prior to the change of control or a
significant adverse alteration in the nature or status of the executive's
responsibilities or condition of employment from those in effect immediately
prior to such change of control;
41
o the failure of Texaco to continue in effect any material compensation or
benefit plan in which the executive participated immediately prior to the
change of control, unless an equitable arrangement (embodied in an ongoing
substitute or alternate plan) has been made with respect to such plan, or the
failure by Texaco to continue the executive's participation in such material
compensation or benefit plan (or in such substitute or alternative plan) on a
basis not materially less favorable, both in terms of the amount of benefits
provided and the level of the executive's participation relative to other
participants, as that which existed at the time of the change of control,
unless any such change is independently justified based on peer group
practices; or
o the requirement to relocate to a work location which is 50 or more miles from
the executive's former work location, without the executive's consent.
If there is a change of control and the executive is terminated without
just cause or resigns for good reason within three years thereafter, a typical
executive will be entitled to receive a cash payment, except as otherwise
provided below, equal to the following (although benefits may vary slightly on a
case by case basis):
o "base pay severance" equal to thirty-six months' base pay, which means the
monthly base salary in effect immediately before the change of control or, if
greater, the base salary during the year immediately before the executive's
termination without just cause or resignation for good reason; plus
o "bonus severance" equal to three times the highest cash bonus earned by the
executive in any of the five years preceding the executive's termination date
(if the executive has not yet earned a company bonus prior to the change of
control, then the executive's target bonus will be used in this regard); plus
o three times the annual value of benefits earned or accrued by the executive
as a result of the executive's participation in the following plans
immediately preceding the change of control or immediately preceding the
executive's resignation, whichever is greater:
o in lieu of additional service credit under the retirement and supplemental
plans, a cash payment equal to 10% of the amount of the total of base pay
severance and bonus severance; plus
o in lieu of additional contributions to the thrift and supplemental plans,
a cash payment equal to 6% of the amount of base pay severance; plus
o if the executive is not eligible for retiree medical coverage under the
bullet immediately below, a cash payment equal to three times the annual
company contribution to the Texaco comprehensive medical plan (or
alternate sponsored medical plan or HMO) for the executive's elected
coverage option.
o executives who are age 45 or older with at least ten years of service will
receive retiree medical coverage pursuant to the terms and conditions that
existed immediately prior to the change of control with the full company
portion of the premium paid by the company. In order to qualify, the
executive must have been covered under a company-sponsored medical plan
immediately prior to the change of control or immediately prior to
termination of employment;
o executives who are age 45 or older with at least ten years of service will
receive full retiree life insurance coverage pursuant to the terms and
conditions that existed immediately prior to the change of control with the
full amount of insurance paid by the company. In order to qualify for retiree
life insurance, the executive must have participated in contributory life
insurance coverage immediately prior to the date of the change of control or
immediately prior to termination of employment;
o outplacement services with a nationally recognized outplacement firm, with a
cost not to exceed $15,000; plus
42
o continued participation under the terms and practices of the company's tax
assistance plan for the year of termination or resignation and three calendar
years immediately following.
Notwithstanding the above, if the executive is within 36 months of
attaining age 65 at the time of termination of employment or resignation, the
benefits described in the first three bullets above will be reduced by
multiplying such benefit amounts by a fraction the numerator of which is the
number of full and partial months from the date the executive terminates
employment to the last day of the month he or she turns age 65, and the
denominator of which is 36 months.
Under the severance agreements, Texaco is required, if necessary, to make
an additional gross-up payment to any executive to offset fully the effect of
any excise tax imposed by Section 4999 of the Internal Revenue Code on any
excess parachute payment, whether made to that executive under the severance
agreements or otherwise. In general, Section 4999 imposes an excise tax on the
recipient of any excess parachute payment equal to 20% of that payment. A
parachute payment is any payment contingent on a change of control that equals
or exceeds three times the executive's "base amount", which is defined as
average taxable compensation received by the executive from the employer during
the five taxable years preceding the year in which the change of control occurs.
Excess parachute payments consist of the excess of parachute payments over an
individual's base amount. If the individual has been employed for fewer than
five taxable years, the individual's entire period of employment will be used to
calculate the excess parachute payment. Severance benefits received by the
executive under the severance agreements will be made in lieu of and will
replace any benefit entitlements under the U.S. Separation Pay Plan.
The merger, as described on page 1, will constitute a change of control
under the severance agreements. If all the conditions to the closing are met and
the closing occurs on July 1, 2001, and if all of the Texaco executives who are
party to the severance agreements are terminated without just cause or resign
for good reason immediately following that date, the amount of the cash
severance payments payable to all of the Texaco executive officers who are party
to the severance agreements would be approximately $50 million and the gross-up
payment payable would not be expected to exceed approximately $40 million.
Employee Severance Benefits
Texaco maintains severance pay programs in most locations around the world.
In general, all regular, full-time Texaco employees on the U.S. payroll are
eligible to participate in the U.S. Separation Pay Plan. Under the terms of the
U.S. Separation Pay Plan, benefits will be provided to all eligible employees if
their employment is terminated or the conditions of their employment are changed
adversely within two years following a change of control. The severance pay
programs maintained outside the United States are designed to be competitive
locally and do not provide special change of control benefits.
Under the U.S. Separation Pay Plan, an eligible Texaco employee will
receive change of control benefits if any of the following occurs within two (2)
years after a change of control of Texaco:
o the employee's employment is terminated without "just cause" (as defined in
the U.S. Separation Pay Plan);
o the employee resigns within 60 days after:
o a reduction in the employee's base pay; or
o a reduction in approved overtime (other than an across-the-board cut for
operational reasons); or
43
o a reduction in the employee's cash bonus or cash stipend bonus in excess
of 20% of the employee's prior year award (unless the reduction is due to
Texaco's performance under the objective measurements of its incentive
bonus plan effective immediately before the change of control or under the
objective measurements of an incentive compensation program with target
bonuses and performance goals comparable to and not materially less
favorable to the employee than the targets and goals described in Texaco's
incentive bonus plan in existence prior to the change of control); or
o a reduction in the employee's position or position grade or any equivalent
action; or
o the benefits under one or more of the benefit plans or perquisites in
which the employee may participate at the time of the change of control
are reduced or terminated (except as required by law) unless any such
change is independently justified based on peer group practices; or
o being required to relocate to a work location which is 50 or more miles
from the employee's former work location, without the employee's consent.
The change of control benefits consist of an amount equal to the following:
o "base pay benefit" - one month's base pay (which means the greater of the
monthly rate of pay in effect immediately prior to the change of control or
during the highest paid month in the year immediately prior to the employee's
termination or resignation) for each completed or partial year of service up
to a maximum of 24 months' base pay (minimum of 3 months' base pay if the
employee has at least one year of service); plus
o "bonus and overtime benefit" - 1/12th of the employee's highest cash bonus,
PCP award, cash stipend bonus, merit stipend or annual overtime pay received
in any of the five years immediately preceding the employee's termination and
qualifying resignation, multiplied by the same number of months used to
calculate the employee's base pay benefit; plus
o the benefit plans make-up payment equal to the sum of:
o retirement plan - 10% of the sum of the base pay benefit and the bonus and
overtime benefit;
o thrift plan - 6% of the base pay benefit; and
o medical plan - company's monthly contribution to the Texaco comprehensive
medical plan (or alternate company-sponsored medical plan or HMO), for the
employee's elected coverage option either immediately preceding a change
of control or immediately preceding the employee's termination or
qualifying resignation, whichever is greater, multiplied by the number of
years of service determined in calculating the base pay benefit;
o "retiree medical coverage" - employees who are age 45 with at least 10 years
of service will receive retiree medical coverage. Employees with 20 or more
years of service will receive 100% of Texaco's contribution. Texaco's
contribution will be pro-rated downward 5% per year for years of service less
than 20. In order to qualify for retiree coverage, the employee must have
been covered under a Texaco-sponsored medical plan immediately prior to the
change of control or immediately prior to termination or qualifying
resignation. Employees who are not eligible for retiree medical can
participate in the Texaco-sponsored medical plan at their own expense for
three years following termination (inclusive of COBRA coverage); and
o "retiree life insurance coverage" - employees age 45 or older with at least
10 years of service will be eligible for Texaco-provided retiree life
insurance coverage. Employees with 20 or more years of service will receive
100% retiree life insurance coverage. Coverage is reduced 5% per year for
each year of service below 20 years. The amount of coverage will be
determined based on the employee's level of participation in Texaco's term
life insurance plan immediately prior to the date of the change of control or
immediately prior to termination or qualifying resignation; and
44
o "retirement plan"- more favorable early commencement discount factors will
apply when an employee starts his or her pension at age 50 or older, even if
the employee leaves Texaco before age 50. Social security offset in the final
average pay formula will not apply until age 62, if the employee starts
pension before age 62.
Also, employees in Grade 20 or higher qualifying for benefits under the
U.S. Separation Pay Plan will be entitled to the following supplemental
benefits. In determining years of company service under the first bullets above
setting forth certain benefits to be provided to eligible participants in the
separation pay plan upon a change of control, such employee will be credited
with a minimum of twelve years of deemed service plus (a) for employees in Grade
20, one additional year for each actual completed or partial year of company
service; (b) for employees in Grade 21, one and one-half additional years for
each actual completed or partial year of company service; or (c) for employees
in Grades 22 and above, two additional years for each actual completed or
partial year of company service. In no event will the aggregate years of
service, actual and deemed, used in determining benefits under the U.S.
Separation Pay Plan exceed 24 years of service.
Under the U.S. Separation Pay Plan, Texaco is required, if necessary, to
make an additional gross-up payment to any employee to offset fully the effect
of any excise tax imposed by Section 4999 of the Internal Revenue Code on any
excess parachute payment.
The merger, as described on page 1, will constitute a change of control
under the U.S. Separation Pay Plan. If all the conditions to the closing are met
and the closing occurs on July 1, 2001, and if all of the eligible Texaco
employees are terminated without just cause or resign for the specified reasons
immediately following that date, the amount of the cash severance payment
payable to all of the U.S. Texaco employees would be approximately $1.2 billion
and the gross-up payment payable would not be expected to exceed approximately
$25 million.
45
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
The following information, contained in Texaco Inc.'s 2000 Annual Report to
Stockholders, is incorporated herein by reference. Page references are to the
paper document version of Texaco Inc.'s 2000 Annual Report to Stockholders, as
provided to stockholders:
(a) The following documents are filed as part of this report:
Texaco Inc.
2000
Annual Report
1. Financial Statements (incorporated by reference from the indicated to Stockholders
pages of Texaco Inc.'s 2000 Annual Report to Stockholders): Page Reference
---------------
Description of Significant Accounting Policies................................ 44-45
Consolidated Statement of Income for the three years
ended December 31, 2000 ................................................. 46
Consolidated Balance Sheet at December 31, 2000 and 1999...................... 47
Consolidated Statement of Stockholders' Equity
for the three years ended December 31, 2000 ................................ 48-49
Consolidated Statement of Comprehensive Income
for the three years ended December 31, 2000 ............................. 50
Consolidated Statement of Cash Flows for the three years
ended December 31, 2000 .................................................... 51
Notes to Consolidated Financial Statements.................................... 52-69
Report of Independent Public Accountants...................................... 70
2. Financial Statement Schedules
We have included on page 50 of this Annual Report on Form 10-K Financial
Statement Schedule II, Valuation and Qualifying Accounts.
We have filed as part of this Annual Report on Form 10-K the following sets
of financial statements, for which we use the equity method of accounting:
o Caltex Group of Companies Combined Financial Statements
o Equilon Enterprises LLC Consolidated Financial Statements
o Motiva Enterprises LLC Financial Statements.
Financial statements and schedules of certain affiliated companies have
been omitted in accordance with the provisions of Rule 3.09 of Regulation S-X.
Financial Statement Schedules I, III, IV and V are omitted as permitted
under Rule 4.03 and Rule 5.04 of Regulation S-X.
3. Exhibits
-- (2.1) Agreement and Plan of Merger dated as of October 15,
2000 among Chevron Corporation, Texaco Inc. and Keepep
Inc. (Schedules and Exhibits omitted), filed as Exhibit
2.1 to Texaco Inc.'s Current Report on Form 8-K, dated
October 16, 2000, incorporated herein by reference, SEC
File No. 1-27.
-- (2.2) Stock Option Agreement dated as of October 15, 2000
between Chevron Corporation and Texaco Inc., filed as
Exhibit 2.2 to Texaco Inc.'s Current Report on Form 8-K,
dated October 16, 2000, incorporated herein by reference,
SEC File No. 1-27.
-- (2.3) Stock Option Agreement dated as of October 15, 2000
between Chevron Corporation and Texaco Inc., filed as
Exhibit 2.3 to Texaco Inc.'s Current Report on Form 8-K,
dated October 16, 2000, incorporated herein by reference,
SEC File No. 1-27.
46
-- (3.1) Copy of Restated Certificate of Incorporation of
Texaco Inc., as amended to and including August 4, 1999,
including Certificate of Designations, Preferences and
Rights of Series D Junior Participating Preferred Stock
and Series G, H, I and J Market Auction Preferred Shares,
filed as Exhibit 3.1 to Texaco Inc.'s Quarterly Report on
Form 10-Q for the quarterly period ended June 30, 1999,
dated August 12, 1999, incorporated herein by reference,
SEC File No. 1-27.
-- (3.2) Copy of By-Laws of Texaco Inc., as amended to and
including October 15, 2000, filed as Exhibit 3.2 to Texaco
Inc.'s Quarterly Report on Form 10-Q for the quarterly
period ended September 30, 2000, dated November 9, 2000,
incorporated herein by reference, SEC File No. 1-27.
-- (4.1(a)) Form of Amended Rights Agreement, dated as of March 16,
1989, as amended as of April 28, 1998, between Texaco Inc.
and ChaseMellon Shareholder Services, L.L.C., as Rights
Agent, filed as Exhibit I, pages 40 through 78, of Texaco
Inc.'s proxy statement dated March 17, 1998, incorporated
herein by reference, SEC File No. 1-27.
-- (4.1(b)) Form of Amendment No. 1, dated as of October 15, 2000 to
the Amended Rights Agreement, dated as of March 16, 1989,
as amended as of April 28, 1998, between Texaco Inc. and
ChaseMellon Shareholder Services, L.L.C., as Rights Agent,
filed as Exhibit 2 of Texaco Inc.'s Amendment No. 1 to
Form 8-A, dated October 25, 2000, incorporated herein by
reference, SEC File No. 1-27.
-- (4.2) Instruments defining the rights of holders of long-term
debt of Texaco Inc. and its subsidiary companies are not
being filed, since the total amount of securities
authorized under each of such instruments does not exceed
10 percent of the total assets of Texaco Inc. and its
subsidiary companies on a consolidated basis. Texaco Inc.
agrees to furnish a copy of any instrument to the
Securities and Exchange Commission upon request.
-- (10(iii)(a)) Form of severance agreement between Texaco Inc. and
elected officers of Texaco Inc., filed as Exhibit
10(iii)(a) to Texaco Inc.'s Annual Report on Form 10-K for
the year ended December 31, 1998, dated March 25, 1999,
incorporated herein by reference, SEC File No. 1-27.
-- (10(iii)(b)) Employment agreement dated December 30, 1997, between
Texaco Inc. and Mr. John J. O'Connor, Senior Vice
President of Texaco Inc., filed as Exhibit 10(iii)(b) to
Texaco Inc.'s Annual Report on Form 10-K for the year
ended December 31, 1998, dated March 25, 1999,
incorporated herein by reference, SEC File No. 1-27.
-- (10(iii)(c)) Employment agreements dated July 18, 1997, between Texaco
Inc. and Mr. William M. Wicker, Senior Vice President of
Texaco Inc., filed as Exhibit 10(iii)(c) to Texaco Inc.'s
Annual Report on Form 10-K for the year ended December 31,
1998, dated March 25, 1999, incorporated herein by
reference, SEC File No. 1-27.
-- (10(iii)(d)) Texaco Inc.'s 1997 Stock Incentive Plan, incorporated
herein by reference to Appendix A, pages 39 through 44
of Texaco Inc.'s proxy statement dated March 27, 1997,
SEC File No. 1-27.
-- (10(iii)(e)) Texaco Inc.'s 1997 Incentive Bonus Plan, incorporated
herein by reference to Appendix A, pages 45 and 46 of
Texaco Inc.'s proxy statement dated March 27, 1997,
SEC File No. 1-27.
-- (10(iii)(f)) Texaco Inc.'s Stock Incentive Plan, incorporated herein
by reference to pages A-1 through A-8 of Texaco Inc.'s
proxy statement dated April 5, 1993, SEC File No. 1-27.
47
-- (10(iii)(g)) Texaco Inc.'s Stock Incentive Plan, incorporated herein
by reference to pages IV-1 through IV-5 of Texaco Inc.'s
proxy statement dated April 10, 1989 and to Exhibit A of
Texaco Inc.'s proxy statement dated March 29, 1991,
SEC File No. 1-27.
-- (10(iii)(h)) Description of Texaco Inc.'s Supplemental Pension Benefits
Plan, incorporated herein by reference to pages 8 and 9 of
Texaco Inc.'s proxy statement dated March 17, 1981,
SEC File No. 1-27.
-- (10(iii)(i)) Description of Texaco Inc.'s Revised Supplemental Pension
Benefits Plan, incorporated herein by reference to pages
24 through 27 of Texaco Inc.'s proxy statement dated March
9, 1978, SEC File No. 1-27.
-- (10(iii)(j)) Description of Texaco Inc.'s Revised Incentive
Compensation Plan, incorporated herein by reference to
pages 10 and 11 of Texaco Inc.'s proxy statement dated
March 13, 1969, SEC File No. 1-27.
-- (12.1) Computation of Ratio of Earnings to Fixed Charges
of Texaco on a Total Enterprise Basis.
-- (12.2) Definitions of Selected Financial Ratios.
-- (13) Copy of those portions of Texaco Inc.'s 2000 Annual
Report to Stockholders that are incorporated herein by
reference into this Annual Report on Form 10-K.
-- (21) Listing of significant Texaco Inc. subsidiary companies
and the name of the state or other jurisdiction in which
each subsidiary was organized.
-- (23.1) Consent of Arthur Andersen LLP.
-- (23.2) Consent of KPMG (regarding its report on the combined
financial statements of the Caltex Group of Companies).
-- (23.3) Consent of Arthur Andersen LLP and PricewaterhouseCoopers
LLP (regarding their report on the consolidated financial
statements of Equilon Enterprises LLC).
-- (23.4) Consent of Arthur Andersen LLP, PricewaterhouseCoopers LLP
and Deloitte & Touche LLP (regarding their report on the
financial statements of Motiva Enterprises LLC).
-- (24.1) Power of Attorney. Powers of Attorney for certain
directors and officers of Texaco Inc. authorizing, among
other things, the signing of Texaco Inc.'s Annual Report
on Form 10-K on their behalf, filed as Exhibit 24 to
Texaco Inc.'s Annual Report on Form 10-K for the year
ended December 31, 1999, dated March 24, 2000,
incorporated herein by reference, SEC File No. 1-17.
-- (24.2) Power of Attorney. Power of Attorney for Glenn F. Tilton,
Chairman of the Board and Chief Executive Officer of
Texaco Inc., authorizing, among other things, the signing
of Texaco Inc.'s Annual Report on Form 10-K on his behalf.
-- (24.3) Power of Attorney. Power of Attorney for Robert J. Eaton,
a director of Texaco Inc., authorizing, among other
things, the signing of Texaco Inc.'s Annual Report on
Form 10-K on his behalf.
(b) Reports on Form 8-K
During the fourth quarter of 2000, Texaco Inc. filed Current Reports on
Form 8-K relating to the following events:
1. October 16, 2000
Item 5. Other Events -- reported that Texaco and Chevron
Corporation announced a merger that will create a new
company, ChevronTexaco Corporation.
2. October 24, 2000
Item 5. Other Events -- reported that Texaco issued an
Earnings Press Release for the third quarter and first
nine months of 2000.
48
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders, Texaco Inc.:
We have audited in accordance with auditing standards generally accepted in
the United States, the financial statements included in Texaco Inc. and
subsidiary companies' annual report to stockholders incorporated by reference in
this Form 10-K, and have issued our report thereon dated February 22, 2001. Our
audit was made for the purpose of forming an opinion on those statements taken
as a whole. The schedule listed in Item 14 is the responsibility of the
Company's management and is presented for purposes of complying with the
Securities and Exchange Commission's rules and is not part of the basic
financial statements. This schedule has been subjected to the auditing
procedures applied in the audit of the basic financial statements and, in our
opinion, fairly states in all material respects the financial data required to
be set forth therein in relation to the basic financial statements taken as a
whole.
Arthur Andersen LLP
New York, N.Y.
February 22, 2001
49
Schedule II
Texaco Inc. and Subsidiary Companies
Schedule II - Valuation and Qualifying Accounts
For the Years Ended December 31, 2000, 1999 and 1998
(In Millions of Dollars)
Balance at Additions-Charged Balance at
Beginning to Costs and End
Description of Year Expenses Deductions of Year
----------- ---------- ----------------- ---------- ----------
Year ended December 31, 2000
Allowance for doubtful accounts $ 27 $ 26 $ 26 $ 27
==== ==== ==== ====
Maintenance and Repairs -
Major Facilities $ 26 $ 42 $ 45 $ 23
==== ==== ==== ====
2000 Employee Termination Benefits $ -- $ 17 $ 16* $ 1
==== ==== ==== ====
1998 Employee Termination Benefits $ 27 $ -- $ 27 $ --
==== ==== ==== ====
1996 Employee Termination Benefits $ 8 $ -- $ 8 $ --
==== ==== ==== ====
Year ended December 31, 1999
Allowance for doubtful accounts $ 28 $ 16 $ 17 $ 27
==== ==== ==== ====
Inventory valuation allowance $ 99 $ -- $ 99 $ --
==== ==== ==== ====
Maintenance and Repairs -
Major Facilities $ 40 $ 45 $ 59 $ 26
==== ==== ==== ====
1998 Employee Termination Benefits $100 $ 48 $121** $ 27
==== ==== ==== ====
1996 Employee Termination Benefits $ 12 $ -- $ 4 $ 8
==== ==== ==== ====
Year ended December 31, 1998
Allowance for doubtful accounts $ 22 $ 26 $ 20 $ 28
==== ==== ==== ====
Inventory valuation allowance $ -- $ 99 $ -- $ 99
==== ==== ==== ====
Maintenance and Repairs -
Major Facilities $120 $ 36 $116 $ 40
==== ==== ==== ====
1998 Employee Termination Benefits $ -- $115 $ 15 $100
==== ==== ==== ====
1996 Employee Termination Benefits $ 20 $ -- $ 8 $ 12
==== ==== ==== ====
* Includes cash payments of $8 million and transfers to long-term obligations
of $8 million.
** Includes cash payments of $109 million and transfers to long-term obligations
of $12 million.
50
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, in the Town of
Harrison, State of New York, on the 26th day of March, 2001.
Texaco Inc.
(Registrant)
Michael H. Rudy
By ........................................
(Michael H. Rudy)
Secretary
Attest:
Calli P. Checki
By .......................................
(Calli P. Checki)
Assistant Secretary
Pursuant to the requirements of the Securities Exchange Act of 1934,
this Annual Report has been signed below by the following persons on behalf of
the Registrant and in the capacities and on the date indicated.
Glenn F. Tilton ...........Chairman of the Board and Chief Executive Officer
(Principal Executive Officer)
Patrick J. Lynch ...........Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
George J. Batavick .........Comptroller
(Principal Accounting Officer)
Directors:
A. Charles Baillie Charles H. Price II
Mary K. Bush Charles R. Shoemate
Edmund M. Carpenter Robin B. Smith
Robert J. Eaton William C. Steere, Jr.
Michael C. Hawley Glenn F. Tilton
Franklyn G. Jenifer Thomas A. Vanderslice
Sam Nunn
Michael H. Rudy
By .......................................
(Michael H. Rudy)
Attorney-in-fact for the above-named
officers and directors
March 26, 2001
51
CALTEX GROUP OF COMPANIES
COMBINED FINANCIAL STATEMENTS
December 31, 2000
CALTEX GROUP OF COMPANIES
COMBINED FINANCIAL STATEMENTS
DECEMBER 31, 2000
INDEX
Page
----
General Information 1-2
Independent Auditors' Report 3
Combined Statement of Income 4
Combined Statement of Comprehensive Income 4
Combined Balance Sheet 5
Combined Statement of Stockholders' Equity 6
Combined Statement of Cash Flows 7
Notes to Combined Financial Statements 8-18
Note: Financial statement schedules are omitted as permitted by Rule 4.03 and
Rule 5.04 of Regulation S-X.
CALTEX GROUP OF COMPANIES
GENERAL INFORMATION
The Caltex Group of Companies (Group) is jointly owned 50% each by Chevron
Corporation and Texaco Inc. (collectively, the Stockholders) and was created in
1936 by its two owners to explore for, produce, transport, refine and market
crude oil and petroleum products. The Group is comprised of the following
companies:
Caltex Corporation, a company incorporated in Delaware with its corporate
headquarters in Singapore, that, through its many subsidiaries and
affiliates, conducts refining, transporting, trading, and marketing
activities in the Eastern Hemisphere;
P. T. Caltex Pacific Indonesia, an exploration and production company
incorporated and operating in Indonesia; and,
American Overseas Petroleum Limited, a company incorporated in the
Bahamas.
A brief description of each company's operations and other items follows. All
reported amounts are in U.S. dollars.
Caltex Corporation (Caltex)
Through its subsidiaries and affiliates, Caltex operates in approximately 57
countries, principally in Africa, Asia, the Middle East, New Zealand and
Australia. These geographic areas comprise a broad diversity of mature,
developing, and emerging markets. At the end of 2000, it had total assets of
$7.7 billion, sales of 1.4 million barrels of crude oil and petroleum products
per day, and total revenues of $18.4 billion for the year. Caltex is involved in
all aspects of the downstream business: marketing, refining, distribution,
transportation, storage, supply and trading operations; the corporation is also
active in the petrochemical business through its affiliate in Korea. At year-end
2000, Caltex had more than 7,200 employees.
The majority of refining and certain marketing operations are conducted through
joint ventures. Caltex has equity interests in 10 refineries with equity
refining capacity of approximately 846,000 barrels per day. Additionally, it has
interests in two lubricant refineries, 17 lubricant blending plants, and a
network of ocean terminals and depots. Caltex also has an interest in a fleet of
vessels, and owns or has equity interests in numerous pipelines. Caltex conducts
international crude oil and petroleum product logistics and trading operations
from a subsidiary in Singapore.
P. T. Caltex Pacific Indonesia (CPI)
CPI holds a Production Sharing Contract (PSC) in Central Sumatra through the
year 2021. CPI also acts as operator in Sumatra for eight other petroleum
contract areas, with 33 fields, which are jointly held by Chevron and Texaco. At
the end of 2000, CPI had total assets of $2.5 billion, which generated total
revenues of $2.0 billion for the year. Exploration is pursued over an area
comprising 18.3 million acres with production established in the giant Minas and
Duri fields, along with smaller fields. Gross production from fields operated by
CPI for 2000 was over 707,000 barrels of crude oil per day. CPI entitlements are
sold to its Stockholders, who use them in their systems or sell them to third
parties. At year-end 2000, CPI had approximately 5,800 employees, all located in
Indonesia.
American Overseas Petroleum Limited (AOPL)
AOPL and its subsidiary, Amoseas Indonesia, Inc, provide services for CPI and
manage certain geothermal steam operations and geothermal power generation
projects in Indonesia in which Chevron and Texaco have interests. At year-end
2000, AOPL had approximately 186 employees, of which 9% were located in the
United States.
1
CALTEX GROUP OF COMPANIES
GENERAL INFORMATION
Supplemental Market Risk Disclosures
------------------------------------
The Group uses various derivative financial instruments for hedging and trading
purposes. These instruments principally include interest rate and/or currency
swap contracts, forward and option contracts to buy and sell foreign currencies,
and commodity futures, options, swaps and other derivative instruments. Hedged
market risk exposures include certain portions of assets, liabilities, future
commitments and anticipated sales. Positions are adjusted for changes in the
exposures being hedged. Since the Group hedges only a portion of its market risk
exposures, exposure remains on the unhedged portion. The Notes to the Combined
Financial Statements provide additional data relating to derivatives and
applicable accounting policies.
Debt and debt-related derivatives - The Group is exposed to interest rate risk
on its short-term and long-term debt with variable interest rates (approximately
$1.9 billion and $2.2 billion, before the effects of related net interest rate
swaps of $0.3 billion and $0.4 billion, at December 31, 2000 and 1999,
respectively). The Group seeks to balance the benefit of lower cost variable
rate debt, having inherent increased risk, with more expensive, but lower risk
fixed rate debt. This is accomplished through adjusting the mix of fixed and
variable rate debt, as well as the use of derivative financial instruments,
principally interest rate swaps.
Based on the overall interest rate exposure on variable rate debt and interest
rate swaps at December 31, 2000 and 1999, a hypothetical change in the interest
rates of 2% would change net income by approximately $23 million and $25 million
in 2000 and 1999, respectively.
Crude oil and petroleum product derivatives - The Group uses established
petroleum futures exchanges, as well as "over-the-counter" instruments,
including futures, options, swaps, and other derivative products to hedge a
portion of the market risks associated with its crude oil and petroleum product
purchases and sales. The Group also enters into derivative contracts as part of
its crude oil and petroleum product trading activities.
The Group had net open petroleum derivative purchase contracts of approximately
$146 million and $127 million at December 31, 2000 and 1999, respectively. As a
sensitivity for these contracts, a hypothetical 10% change in crude oil and
petroleum product prices would change net income by approximately $10 million
and $9 million in 2000 and 1999, respectively.
Currency-related derivatives - The Group is exposed to foreign currency exchange
risk in the countries in which it operates. To hedge against adverse changes in
foreign currency exchange rates against the U.S. dollar, the Group sometimes
enters into forward exchange and options contracts. Depending on the exposure
being hedged, the Group either purchases or sells selected foreign currencies.
The Group had net foreign currency purchase contracts of approximately $191
million and $279 million at December 31, 2000 and 1999, respectively, to hedge
certain specific transactions or net exposures including foreign currency
denominated debt. A hypothetical 10% change in exchange rates against the U.S.
dollar would not result in a net material change in the Group's operating
results or cash flows from the derivatives and their related underlying hedged
positions in 2000 or 1999.
New Accounting Standard
Statement of Financial Accounting Standards No. 133 (SFAS No. 133), "Accounting
for Derivative Instruments and Hedging Activities", as amended by SFAS No. 137
and No. 138, will be adopted by the Group beginning January 1, 2001. SFAS No.
133/138 require companies to record derivatives on the balance sheet as assets
or liabilities and measure those derivatives at fair value. Changes in the fair
values of derivatives are to be recorded each period in current earnings or
other comprehensive income, depending on whether a derivative is designated as
part of a hedge transaction and the type of exposure being hedged.
Based on its current level of activity with derivative instruments, the Group
does not expect the adoption of SFAS No. 133/138 to have significant impact on
results of operations, other comprehensive income or financial position.
2
Independent Auditors' Report
To the Stockholders
The Caltex Group of Companies:
We have audited the accompanying combined balance sheets of the Caltex Group of
Companies as of December 31, 2000 and 1999, and the related combined statements
of income, comprehensive income, stockholders' equity, and cash flows for each
of the years in the three-year period ended December 31, 2000, all expressed in
United States of America dollars. These combined financial statements are the
responsibility of the Group's management. Our responsibility is to express an
opinion on these combined financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. 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, the combined financial statements referred to above present
fairly, in all material respects, the financial position of the Caltex Group of
Companies as of December 31, 2000 and 1999 and the results of its operations and
its cash flows for each of the years in the three-year period ended December 31,
2000, in conformity with accounting principles generally accepted in the United
States of America.
As discussed in Note 2 to the combined financial statements, the Group
changed its method of accounting for start-up costs in 1998 to comply with the
provisions of the AICPA's Statement of Position 98-5 - "Reporting on the Costs
of Start-up Activities".
KPMG
Singapore
February 8, 2001
3
CALTEX GROUP OF COMPANIES
COMBINED STATEMENT OF INCOME
Year ended December 31,
------------------------------------------
(Millions of U.S. dollars)
2000 1999 1998
---- ---- ----
Revenues:
Sales and other operating revenues(1) $ 20,239 $ 14,942 $ 11,522
Gain on sale of investment in affiliate - 18 -
Income in equity affiliates 71 252 108
Dividends, interest and other income 62 62 97
--------- --------- ---------
Total revenues 20,372 15,274 11,727
Costs and deductions:
Cost of sales and operating expenses(2) 17,991 13,134 9,763
Selling, general and administrative expenses 515 582 676
Depreciation, depletion and amortization 494 459 431
Maintenance and repairs 129 154 147
Foreign exchange - net (37) 11 16
Interest expense 192 152 172
Minority interest - 2 3
--------- --------- ---------
Total costs and deductions 19,284 14,494 11,208
--------- --------- ---------
Income before income taxes 1,088 780 519
Provision for income taxes 569 390 326
--------- --------- ---------
Income before cumulative effect of accounting change 519 390 193
Cumulative effect of accounting change (no tax benefit) - - (50)
--------- --------- ----------
Net income $ 519 $ 390 $ 143
========= ========= ==========
(1) Includes sales to:
Stockholders $2,924 $2,275 $1,555
Affiliates 5,454 3,970 2,121
(2) Includes purchases from:
Stockholders $2,970 $1,491 $1,455
Affiliates 1,888 1,121 1,353
CALTEX GROUP OF COMPANIES
COMBINED STATEMENT OF COMPREHENSIVE INCOME
Year ended December 31,
------------------------------------------
(Millions of U.S. dollars)
2000 1999 1998
---- ---- ----
Net income $ 519 $ 390 $ 143
Other comprehensive income:
Currency translation adjustments:
Change during the year (14) (5) (10)
Reclassification to net income for sale of investment in affiliate - (63) -
Unrealized gains/(losses) on investments:
Change during the year 3 32 8
Reclassification of gains included in net income (1) (64) -
Related income tax benefit (expense) - 11 (1)
--------- --------- ---------
Total other comprehensive loss (12) (89) (3)
--------- --------- ---------
Comprehensive income $ 507 $ 301 $ 140
========= ========= =========
See accompanying notes to combined financial statements.
4
CALTEX GROUP OF COMPANIES
COMBINED BALANCE SHEET
As of December 31,
---------------------------
(Millions of U.S. dollars)
ASSETS 2000 1999
---- ----
Current assets:
Cash and cash equivalents, including time deposits of
$13 in 2000 and $12 in 1999 $ 219 $ 225
Marketable securities 11 117
Accounts and notes receivable, less allowance for doubtful
accounts of $58 in 2000 and $43 in 1999:
Trade 1,047 1,048
Affiliates 432 541
Other 224 132
--------- -------
1,703 1,721
Inventories 557 623
Deferred income taxes 54 19
--------- -------
Total current assets 2,544 2,705
Equity in affiliates 2,192 2,127
Miscellaneous investments and long-term receivables,
less allowance of $23 in 2000 and $24 in 1999 106 96
Property, plant, and equipment, at cost:
Producing 5,085 4,732
Refining 1,352 1,350
Marketing 3,241 3,194
Other 15 14
--------- -------
9,693 9,290
Accumulated depreciation, depletion and amortization (4,552) (4,120)
--------- -------
Net property, plant and equipment 5,141 5,170
Deferred income taxes 13 28
Prepaid and deferred charges 226 211
--------- -------
Total assets $ 10,222 $10,337
========= =======
LIABILITIES
Current liabilities:
Short-term debt $ 1,639 $ 1,588
Accounts payable:
Trade and other 1,297 1,440
Stockholders 134 44
Affiliates 55 61
--------- -------
1,486 1,545
Accrued liabilities 193 163
Estimated income taxes 67 99
--------- -------
Total current liabilities 3,385 3,395
Long-term debt 853 1,054
Employee benefit plans 87 85
Deferred credits and other non-current liabilities 1,344 1,271
Deferred income taxes 232 234
Minority interest in subsidiary companies 27 23
--------- -------
Total 5,928 6,062
STOCKHOLDERS' EQUITY
Common stock 355 355
Capital in excess of par value 2 2
Retained Earnings 4,148 4,117
Accumulated other comprehensive loss (211) (199)
--------- -------
Total stockholders' equity 4,294 4,275
--------- -------
Total liabilities and stockholders' equity $ 10,222 $10,337
========= =======
See accompanying notes to combined financial statements.
5
CALTEX GROUP OF COMPANIES
COMBINED STATEMENT OF STOCKHOLDERS' EQUITY
Year ended December 31,
------------------------------------------
(Millions of U.S. dollars)
2000 1999 1998
---- ---- ----
Common stock $ 355 $ 355 $ 355
========= ========= =========
Capital in excess of par value $ 2 $ 2 $ 2
========= ========= ========
Retained earnings:
Balance at beginning of year $ 4,117 $ 4,151 $ 4,342
Net income 519 390 143
Cash dividends (488) (424) (334)
--------- --------- ---------
Balance at end of year $ 4,148 $ 4,117 $ 4,151
========= ========= ========
Accumulated other comprehensive loss:
Cumulative translation adjustments:
Balance at beginning of year $ (198) $ (130) $ (120)
Change during the year (14) (5) (10)
Reclassification to net income for sale of investment
in affiliate - (63) -
-------- --------- ---------
Balance at end of year $ (212) $ (198) $ (130)
========= ========= =========
Unrealized holding gain/(loss) on investments, net of tax:
Balance at beginning of year $ (1) $ 20 $ 13
Change during the year 3 19 7
Reclassification of gains included in net income (1) (40) -
--------- --------- ---------
Balance at end of year $ 1 $ (1) $ 20
========= ========= =========
Accumulated other comprehensive loss - end of year $ (211) $ (199) $ (110)
========= ========= =========
Total stockholders' equity - end of year $ 4,294 $ 4,275 $ 4,398
========= ========= =========
See accompanying notes to combined financial statements.
6
CALTEX GROUP OF COMPANIES
COMBINED STATEMENT OF CASH FLOWS
Year ended December 31,
------------------------------------------
(Millions of U.S. dollars)
2000 1999 1998
---- ---- ----
Operating activities:
Net income $ 519 $ 390 $ 143
Reconciliation to net cash provided by operating activities:
Depreciation, depletion and amortization 494 459 431
Dividends more (less) than income in equity affiliates 12 (181) (8)
Net losses on asset disposals/write-downs 6 34 50
Deferred income taxes (13) (58) 92
Prepaid charges and deferred credits 58 154 59
Changes in operating working capital:
Accounts and notes receivable (51) (653) 404
Inventories 66 (12) (28)
Accounts payable (10) 484 (105)
Accrued liabilities 40 (23) 41
Estimated income taxes (27) 14 4
Gain on sale of investment in affiliate - (18) -
Other (6) (25) 35
------- ------- -------
Net cash provided by operating activities 1,088 565 1,118
Investing activities:
Capital expenditures (509) (580) (761)
Investments in and advances to affiliates (87) (1) (211)
Purchase of investment instruments (108) (11) (114)
Sale of investment instruments 214 - 90
Proceeds from sale of investments in affiliates - 249 -
Proceeds from asset sales 21 16 9
------- ------- -------
Net cash used for investing activities (469) (327) (987)
Financing activities:
Debt with terms in excess of three months:
Borrowings 996 959 849
Repayments (727) (824) (701)
Net (decrease) increase in other debt (351) 118 (22)
Funding provided by minority interest - - 17
Dividends paid (488) (424) (334)
------- ------- -------
Net cash used for financing activities (570) (171) (191)
Effect of exchange rate changes on cash and cash equivalents (55) (20) (44)
------- ------- -------
Cash and cash equivalents:
Net change during the year (6) 47 (104)
Beginning of year balance 225 178 282
------- ------- -------
End of year balance $ 219 $ 225 $ 178
======= ======= =======
Net cash provided by operating activities includes the following cash payments
for interest and income taxes:
Interest paid (net of capitalized interest) $ 189 $ 142 $ 182
Income taxes paid 601 404 237
See accompanying notes to combined financial statements.
7
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of combination The combined financial statements of the Caltex Group
of Companies (Group) include the accounts of Caltex Corporation and
subsidiaries, American Overseas Petroleum Limited and subsidiary, and P.T.Caltex
Pacific Indonesia. Intercompany transactions and balances have been eliminated.
Subsidiaries include companies owned directly or indirectly more than 50% except
cases in which control does not rest with the Group. The Group's accounting
policies are in accordance with U.S. generally accepted accounting principles,
and the Group's reporting currency is the U.S. dollar.
Translation of foreign currencies The U.S. dollar is the functional currency for
all principal subsidiary and affiliate operations.
Estimates The preparation of financial statements in conformity with U.S.
generally accepted accounting principles requires estimates and assumptions that
affect the reported amounts of assets and liabilities, the disclosure of
contingent assets and liabilities at the date of the financial statements, and
the reported amounts of revenues and expenses during the reporting period.
Actual results may differ from those estimates.
Short-term investments All highly liquid investments are classified as available
for sale. Those with a maturity of three months or less when purchased are
considered as "Cash equivalents" and those with longer maturities are classified
as "Marketable securities".
Inventories Inventories are valued at the lower of cost or current market,
except as noted below. Crude oil and petroleum product inventory costs are
primarily determined using the last-in, first-out (LIFO) method, and include
applicable acquisition and refining costs, duties, import taxes, freight, etc.
Materials and supplies are stated at average cost. Certain trading-related
inventory, which is highly transitory in nature, is marked-to-market.
Investments and advances Investments in affiliates in which the Group has an
ownership interest of 20% to 50% or majority-owned investments where control
does not rest with the Group, are accounted for by the equity method. The
Group's share of earnings or losses of these companies is included in current
results, and the recorded investments reflect the underlying equity in each
company. Investments in other affiliates are carried at cost and dividends are
reported as income.
Property, plant and equipment Exploration and production activities are
accounted for under the successful efforts method. All costs for development
wells, related plant and equipment, and proved mineral interests in oil and gas
properties are capitalized. Costs of exploratory wells are capitalized pending
determination of whether the wells found proved reserves. Costs of wells that
are assigned proved reserves remain capitalized. Costs are also capitalized for
wells that find commercially producible reserves that cannot be classified as
proved, pending one or more of the following: (1) decisions on additional major
capital expenditures, (2) the results of additional exploratory wells that are
under way or firmly planned, and (3) securing final regulatory approvals for
development. Otherwise, well costs are expensed if a determination cannot be
made within one year following completion of drilling as to whether proved
reserves were found. All other exploratory wells and costs are expensed.
Long-lived assets, including proved developed oil and gas properties, are
assessed for possible impairment by comparing their carrying values to the
undiscounted-future-net-before-tax cash flows. Impaired assets are written down
to their fair values, generally their discounted cash flows. Impaired assets
held for sale are recorded at their fair value less cost to sell. For proved oil
and gas properties, the reviews are performed on a concession basis. Impairment
amounts are recorded as incremental depreciation expense in the period in which
the event occurs.
Depreciation, depletion and amortization expenses for capitalized costs relating
to producing properties, including intangible development costs, are determined
using the unit-of-production method by individual fields as the proved developed
reserves are produced. Depletion expenses for capitalized costs of proved
mineral interests are recognized using the unit-of-production method by
individual fields as the related proved reserves are produced. Periodic
valuation provisions for impairment of capitalized costs of unproved mineral
interests are expensed. All other assets are depreciated by class on a
straight-line basis using rates based upon the estimated useful life of each
class.
8
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (continued)
Maintenance and repairs necessary to maintain facilities in operating condition
are charged to income as incurred. Additions and improvements that materially
extend the life of assets are capitalized. Upon disposal of assets, any net gain
or loss is included in income.
Deferred credits Deferred credits primarily represent the Indonesian
government's interest in specific property, plant and equipment balances. Under
the Production Sharing Contract (PSC), the Indonesian government retains a
majority equity share of current production profits. Intangible development
costs (IDC) are capitalized for U.S. generally accepted accounting principles
under the successful efforts method, but are treated as period expenses for PSC
reporting. Other capitalized amounts are depreciated at an accelerated rate for
PSC reporting. The deferred credit balances recognize the government's share of
IDC and other reported capital costs that over the life of the PSC will be
included in income as depreciation, depletion and amortization and will be
applied against future production related profits.
Derivative financial instruments and energy trading contracts The Group uses
various derivative financial instruments for hedging purposes. These instruments
include interest rate and/or currency swap contracts, forward and options
contracts to buy and sell foreign currencies, and commodity futures, options,
swaps and other derivative instruments. Hedged market risk exposures include
certain portions of assets, liabilities, future commitments and anticipated
sales. Prior realized gains and losses on hedges of existing non-monetary assets
are included in the carrying value of those assets. Gains and losses related to
qualifying hedges of firm commitments or anticipated transactions are deferred
and recognized in income when the underlying hedged transaction is recognized in
income. If the derivative instrument ceases to be a hedge, the related gains and
losses are recognized currently in income. Gains and losses on derivative
instruments that do not qualify as hedges are recognized currently in income.
The Group also enters into energy contracts as a part of its crude oil and
petroleum product trading activities. Trading contracts are recorded at market
value and related gains and losses are recorded on a net basis in cost of sales
and operating expenses as the market values change. The net gains and losses
from trading contracts were not material to the Group's results of operations
for 2000, 1999 and 1998.
Accounting for contingencies Certain conditions may exist as of the date
financial statements are issued which may result in a loss to the Group, but
which will only be resolved when one or more future events occur or fail to
occur. Assessing contingencies necessarily involves an exercise of judgment. In
assessing loss contingencies related to legal proceedings that are pending
against the Group or unasserted claims that may result in such proceedings, the
Group evaluates the perceived merits of any legal proceedings or unasserted
claims as well as the perceived merits of the amount of relief sought or
expected to be sought therein.
If the assessment of a contingency indicates that it is probable that a material
liability had been incurred and the amount of the loss can be estimated, then
the estimated liability is accrued in the Group's financial statements. If the
assessment indicates that a potentially material liability is not probable, but
is reasonably possible, or is probable but cannot be estimated, then the nature
of the contingent liability, together with an estimate of the range of possible
loss, if determinable, is disclosed.
Loss contingencies considered remote are generally not disclosed unless they
involve guarantees, in which case the nature and amount of the guarantee would
be disclosed. However, in some instances in which disclosure is not otherwise
required, the Group may disclose contingent liabilities of an unusual nature
which, in the judgment of management and its legal counsel, may be of interest
to Stockholders or others.
Environmental matters The Group's environmental policies encompass the existing
laws in each country in which the Group operates, and the Group's own internal
standards. Expenditures that create future benefits or contribute to future
revenue generation are capitalized. Future remediation costs are accrued based
on estimates of known environmental exposure even if uncertainties exist about
the ultimate cost of the remediation. Such accruals are based on the best
available undiscounted estimates using data primarily developed by third party
experts. Costs of environmental compliance for past and ongoing operations,
including maintenance and monitoring, are expensed as incurred. Recoveries from
third parties are recorded as assets when realizable.
9
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (continued)
Revenue recognition In general, revenue is recognized for crude oil, natural gas
and refined product sales when title passes as specified in the sales contract.
Reclassifications Certain reclassifications have been made to the prior year
amounts to conform to the 2000 presentation.
NOTE 2 - ACCOUNTING CHANGE
An affiliate of the Group capitalized certain start-up costs, primarily
organizational and training, over the period 1992-1996 related to a grassroots
refinery construction project in Thailand. These costs were considered part of
the effort required to prepare the refinery for operations. With the issuance of
the AICPA's Statement of Position 98-5, "Reporting on the Costs of Start-up
Activities," these costs would be accounted for as period expenses. The Group
elected early adoption of this pronouncement effective January 1, 1998 and
accordingly, recorded a cumulative effect charge to income as of January 1, 1998
of $50 million representing the Group's share of the applicable start-up costs.
Excluding the cumulative effect, the change in accounting for start-up costs did
not materially affect net income for 1998.
NOTE 3 - RESTRUCTURING/REORGANIZATION
Caltex recorded a charge to selling, general and administrative expenses of $37
million and $86 million in 1999 and 1998, respectively, for various
restructuring and reorganization activities undertaken to realign its downstream
operations along functional lines and reduce redundant operating activities. The
charges included severance and other termination benefits of $23 million and $60
million for approximately 200 employees and 500 employees in 1999 and 1998,
respectively. All affected employees had left Caltex by December 2000. The
following table summarizes the restructuring/reorganization costs for 2000, 1999
and 1998 (millions of U.S. dollars):
The $9 million liability as of December 31, 2000 primarily relates to future
lease commitments on vacated office space over the remaining lease term ending
in 2002. Adjustments made in 2000 and 1999 to recorded liabilities were
insignificant.
In addition to the above, 1999 net income included a $27 million after tax
charge for restructuring activities of affiliates.
NOTE 4 - ASSETS HELD FOR DISPOSAL
The Group continually reviews its asset portfolio and periodically sells or
otherwise disposes of various assets that no longer fit into the Group's
strategic direction. The Group recorded a charge to earnings of approximately $4
million in 2000 and $30 million in both 1999 and 1998 related to various
marketing assets (primarily service station land and buildings) which have been
removed from operation and are awaiting disposal or sale as buyers are located.
Carrying value of these assets, which is based on appraisals or estimated
selling prices, as of December 31, 2000 is approximately $25 million. The effect
of suspending depreciation on assets held for sale in 2000, 1999 and 1998 was
not material.
10
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
NOTE 5 - OPERATING LEASES
The Group has operating leases involving various marketing assets for which net
rental expense was $92 million, $112 million, and $103 million in 2000, 1999,
and 1998, respectively.
Future net minimum rental commitments under operating leases having
non-cancelable terms in excess of one year are as follows (in millions of U.S.
dollars): 2001 - $42; 2002 - $16; 2003 - $7; 2004 - $6; 2005 - $6; and 2006 and
thereafter - $23.
NOTE 6 - TAXES
Taxes charged to income consist of the following:
Year ended December 31,
---------------------------------------
(Millions of U.S. dollars)
2000 1999 1998
---- ---- ----
Taxes other than income taxes:
Duties, import and excise taxes $ 1,389 $ 1,077 $ 1,218
Other 16 16 17
-------- -------- -------
Total taxes other than income taxes $ 1,405 $ 1,093 $ 1,235
======== ======== =======
Income taxes:
U.S. taxes :
Current $ 3 $ 72 $ 6
Deferred - - 23
-------- -------- -------
Total U.S. 3 72 29
-------- -------- -------
International taxes:
Current 579 376 228
Deferred (13) (58) 69
-------- -------- -------
Total International 566 318 297
-------- -------- -------
Total provision for income taxes $ 569 $ 390 $ 326
======== ======== =======
Income taxes have been computed on an individual company basis at rates in
effect in the various countries of operation. The effective tax rate differs
from the "expected" tax rate (U.S. Federal corporate tax rate) as follows:
Year ended December 31,
------------------------------------
2000 1999 1998
---- ---- ----
Computed "expected" tax rate 35.0% 35.0% 35.0%
Effect of recording equity in net income
of affiliates on an after tax basis (2.4) (11.3) (7.3)
Effect of dividends received from
subsidiaries and affiliates 0.6 0.4 (0.3)
Income subject to foreign taxes at other
than U.S. statutory tax rate 16.1 18.4 26.0
Effect of sale of investment in an affiliate - 6.6 -
Deferred income tax valuation allowance 4.2 2.4 8.7
Other (1.2) (1.5) 0.7
---- ---- ----
Effective tax rate 52.3% 50.0% 62.8%
==== ==== ====
For 2000, the increase in effective tax rate is primarily due to the larger
proportion of earnings from higher tax rate foreign jurisdictions. For 1999, the
increase in the effective tax rate resulting from the sale of investment in an
affiliate is net of the effect of previously unrecorded foreign tax credit
carry-forwards of $29 million.
11
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
NOTE 6 - TAXES - (continued)
Deferred income taxes are provided in each tax jurisdiction for temporary
differences between the financial reporting and the tax basis of assets and
liabilities. Temporary differences and tax loss carry-forwards which give rise
to deferred tax liabilities (assets) are as follows:
A valuation allowance has been established to reduce deferred income tax assets
to amounts which, in the Group's judgement are more likely than not (more than
50%) to be utilized against current and future taxable income when those
temporary differences become deductible.
Undistributed earnings of subsidiaries and affiliates, for which no U.S.
deferred income tax provision has been made, approximated $3.3 billion and $3.4
billion as of December 31, 2000 and December 31, 1999, respectively. Such
earnings have been or are intended to be indefinitely reinvested, and become
taxable in the U.S. only upon remittance as dividends. It is not practical to
estimate the amount of tax that may be payable on the eventual remittance of
such earnings. Upon remittance, certain foreign countries impose withholding
taxes which, subject to certain limitations, are available for use as tax
credits against the U.S. tax liability. Excess U.S. foreign income tax credits
are not recorded until realized.
NOTE 7 - INVENTORIES
As of December 31,
-------------------------
(Millions of U.S. dollars)
2000 1999
---- ----
Inventories
Crude oil $ 169 $ 170
Petroleum products 364 427
Materials and supplies 24 26
----- ------
$ 557 $ 623
===== ======
The reported value of inventory at December 31, 2000 and 1999 was less than its
current cost by approximately $152 million and $104 million, respectively. In
2000 and 1998, certain inventories were recorded at market, which was lower than
the LIFO carrying value. Adjustments to market reduced net income $4 million in
2000 and $18 million in 1998. In 1999, the market valuation adjustment reserves
established in prior years were eliminated as market prices improved and the
physical units of inventory were sold. Elimination of these reserves increased
net income in 1999 by $71 million. At December 31, 2000, inventories were
primarily reported at LIFO carrying cost except for approximately $39 million of
trading inventory recorded at market.
Inventory quantities valued on the LIFO basis were reduced at certain locations
during the periods presented. Such inventory reductions increased net income in
2000 and 1999 by $41 million each year and decreased net income by $4 million
(net of a related market valuation adjustment of $1 million) in 1998.
12
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
NOTE 8 - EQUITY IN AFFILIATES
Investments in affiliates at equity include the following:
As of December 31,
---------------------------
(Millions of U.S. dollars)
Equity % 2000 1999
-------- ---- ----
Caltex Australia Limited 50% $ 253 $ 260
LG-Caltex Oil Corporation 50% 1,468 1,441
Star Petroleum Refining Company, Ltd. 64% 337 269
All other Various 134 157
--------- ---------
$ 2,192 $ 2,127
========= =========
The carrying value of the Group's investment in its affiliates in excess of its
proportionate share of affiliate net equity is being amortized over
approximately 20 years.
In 1999, Caltex Corporation sold its 50% interest in Koa Oil Company, Limited
(Koa) with a net book value of approximately $219 million, to Nippon Mitsubishi
Oil Corp, for approximately $237 million in cash. As a result of the sale,
Caltex incurred additional U.S. tax liabilities of approximately $81 million.
The remaining interest in Star Petroleum Refining Company, Ltd. (SPRC) is owned
by a governmental entity of the Kingdom of Thailand. Provisions in the SPRC
shareholders agreement limit the Group's control and provide for active
participation of the minority shareholder in routine business operating
decisions. The agreement also mandates reduction in Group ownership to a
minority position before the year 2001; however, this requirement has been
delayed in view of the current economic difficulties in the region.
Shown below is summarized combined financial information for affiliates at
equity (in millions of U.S. dollars):
Cash dividends received from these affiliates were $83 million, $71 million, and
$50 million in 2000, 1999, and 1998, respectively.
The summarized combined financial information shown above includes the
cumulative effect of the accounting change in 1998 as described in Note 2.
Retained earnings as of December 31, 2000 and 1999 includes $1.4 billion which
represents the Group's share of undistributed earnings of affiliates at equity.
13
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
NOTE 9 - SHORT-TERM DEBT
Short-term debt consists primarily of demand and promissory notes, acceptance
credits, overdrafts and the current portion of long-term debt. The weighted
average interest rates on short-term financing as of December 31, 2000 and 1999
were 6.9% and 6.5%, respectively. Unutilized lines of credit available for
short-term financing totaled $1.0 billion as of December 31, 2000.
NOTE 10 - LONG-TERM DEBT
Long-term debt, with related interest rates for 2000 and 1999 consists of the
following:
As of December 31,
--------------------------
(Millions of U.S. dollars)
2000 1999
U.S. dollar debt:
Variable interest rate loans with average rates
of 6.9% and 6.4%, due 2002-2009 $ 482 $ 481
Fixed interest rate term loans with average rates of 6.4%
and 6.2%, due 2002-2005 174 171
Australian dollar debt:
Fixed interest rate loan with 12.4% rate due 2001 - 205
Hong Kong dollar debt:
Variable interest rate loans with average rates
of 6.32% and 6.07%, due 2002 75 75
New Zealand dollar debt:
Variable interest rate loans with average rates
of 7.0% and 5.6%, due 2002-2005 70 70
Malaysian ringgit debt:
Variable interest rate loans with average rate of 3.8%
due 2005 7 -
Fixed interest rate loans with average rates of 6.95%
and 7.81%, due 2005 13 24
South African rand debt:
Fixed interest rate loan with 17.8% rate due 2007 6 8
Other - variable interest rate loans with average rates
of 12.1% and 15.3%, due 2003-2007 26 20
------ ------
$ 853 $1,054
====== ======
Aggregate maturities of long-term debt by year are as follows (in millions of
U.S. dollars): 2001 - $469 (included in short-term debt); 2002 - $590; 2003 -
$118; 2004 - $56; 2005 - $70; and thereafter - $19.
14
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
NOTE 11 - FINANCIAL INSTRUMENTS
Certain Group companies are parties to financial instruments with off-balance
sheet credit and market risk, principally interest rate risk. The Group's
outstanding commitments for interest rate swaps and foreign currency contractual
amounts are:
As of December 31,
------------------------
(Millions of U.S. dollars)
2000 1999
---- ----
Interest rate swaps - Pay Fixed, Receive Floating $ 507 $ 632
Interest rate swaps - Pay Floating, Receive Fixed 188 245
Commitments to purchase foreign currencies 275 360
Commitments to sell foreign currencies 84 81
The Group enters into interest rate swaps in managing its interest risk, and
their effects are recognized in the statement of income at the same time as the
interest expense on the debt to which they relate. The swap contracts have
remaining maturities of up to six years. Net unrealized (losses) and gains on
contracts outstanding at December 31, 2000 and 1999 were ($1 million) and $4
million, respectively.
The Group enters into forward exchange contracts to hedge against some of its
foreign currency exposure stemming from existing liabilities and firm
commitments. Contracts to purchase foreign currencies (principally Australian
and Singapore dollars) to hedge existing liabilities have maturities of up to
two years. Net unrealized losses applicable to outstanding forward exchange
contracts at December 31, 2000 and 1999 were $37 million and $5 million,
respectively.
The Group hedges a portion of the market risks associated with its crude oil and
petroleum product purchases and sales. Established petroleum futures exchanges
are used, as well as "over-the-counter" hedge instruments, including futures,
options, swaps, and other derivative products. Gains and losses on hedges are
deferred and recognized concurrently with the underlying commodity transactions.
Deferred (losses) and gains on hedging contracts outstanding at year-end were
($4 million) in 2000 and $4 million in 1999.
The Group's recorded value of fixed interest rate debt exceeded the fair value
by $27 million and $22 million as of December 31, 2000 and 1999, respectively.
The fair value estimates were based on the present value of expected cash flows
discounted at current market rates for similar obligations. The reported amounts
of financial instruments such as cash and cash equivalents, marketable
securities, notes and accounts receivable, and all other current liabilities
approximate fair value because of their short maturities.
The Group had investments in debt securities available-for-sale at amortized
costs of $11 million and $120 million at December 31, 2000 and 1999,
respectively. The fair value of these securities at December 31, 2000 and 1999
approximated amortized costs. As of December 31, 2000 and 1999, investments in
debt securities available-for-sale had maturities of less than ten years. The
Group's carrying amount for investments in affiliates accounted for at equity
included $1 million and $2 million, as of December 31, 2000 and 1999,
respectively, for after-tax unrealized net gains on investments held by these
companies.
The Group is exposed to credit risks in the event of non-performance by
counter-parties to financial instruments. For financial instruments with
institutions, the Group does not expect any counter-party to fail to meet its
obligations given their high credit ratings. Other financial instruments exposed
to credit risk consist primarily of trade receivables. These receivables are
dispersed among the countries in which the Group operates, thus limiting
concentration of such risk. The Group performs ongoing credit evaluations of its
customers and generally does not require collateral. Letters of credit are the
principal security obtained to support lines of credit when the financial
strength of a customer is not considered sufficient. Credit losses have
historically been within management's expectations.
15
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
NOTE 12 - EMPLOYEE BENEFIT PLANS
The Group has various retirement plans, including defined benefit pension plans,
covering substantially all of its employees. The benefit levels, vesting terms
and funding practices vary among plans. The following provides a reconciliation
of benefit obligations, plan assets, and funded status of the various plans,
primarily foreign.
As of December 31,
-------------------------------------------
(Millions of U.S. dollars)
Other Post-retirement
Pension Benefits Benefits
------------------- -------------------
2000 1999 2000 1999
---- ---- ---- ----
Change in benefit obligations:
Benefit obligation at January 1, $ 186 $ 231 $ 78 $ 79
Service cost 13 10 1 1
Interest cost 21 18 8 8
Actuarial loss (gain) 57 7 3 (5)
Benefits paid (22) (25) (6) (4)
Settlements and curtailments (7) (57) - -
Foreign exchange rate changes (24) 2 (7) (1)
Benefit obligation at December 31, $ 224 $ 186 $ 77 $ 78
Change in plan assets:
Fair value at January 1, $ 210 $ 220 $ - $ -
Actual return on plan assets 10 32 - -
Group contribution 26 32 6 4
Benefits paid (22) (25) (6) (4)
Settlements (7) (57) - -
Foreign exchange rate changes (36) 8 - -
Fair value at December 31, $ 181 $ 210 $ - $ -
Accrued benefit costs:
Funded status $ (43) $ 24 $ (77) $ 78)
Unrecognized net actuarial loss (gain) 16 (26) 17 17
Unrecognized prior service cost 26 6 - -
(Accrued) prepaid benefit cost recognized $ (1) $ 4 $ (60) $(61)
Amounts recognized in the Combined Balance Sheet:
Prepaid benefit cost $ 27 $ 32 $ - $ -
Accrued benefit liability (28) (28) (60) (61)
(Accrued) prepaid benefit cost recognized $ (1) $ 4 $ (60) $(61)
Weighted average rate assumptions:
Discount rate 9.7% 9.3% 9.9% 10.9%
Rate of increase in compensation 7.4% 7.0% 6.8% 4.0%
Expected return on plan assets 10.3% 11.5% n/a n/a
As of December 31,
-------------------------
(Millions of U.S. dollars)
2000 1999
---- ----
Pension plans with accumulated benefit obligations in excess of assets:
Projected benefit obligation $ 24 $ 25
Accumulated benefit obligation 13 13
Fair value of assets - -
16
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
NOTE 12 - EMPLOYEE BENEFIT PLANS - (continued)
Year ended December 31,
-----------------------
(Millions of U.S. dollars)
2000 1999 1998
---- ---- ----
Components of Pension Expense
Service cost $ 13 $ 10 $ 10
Interest cost 21 18 20
Expected return on plan assets (20) (22) (21)
Amortization of prior service cost 3 3 1
Recognized net actuarial loss (gain) 1 (2) 3
Curtailment/settlement loss 1 17 13
----- ------ ------
Total $ 19 $ 24 $ 26
===== ====== ======
Components of Other Post-retirement Benefits
Service cost $ 1 $ 1 $ 2
Interest cost 8 8 6
Special termination benefit recognition - - 3
Curtailment recognition - - 3
----- ------ ------
Total $ 9 $ 9 $ 14
===== ====== ======
Other post-retirement benefits are comprised of contributory healthcare and life
insurance plans. A one percentage point change in the assumed health care cost
trend rate of 10% would change the post-retirement benefit obligation by $9
million and would not have a material effect on aggregate service and interest
components.
NOTE 13 - COMMITMENTS AND CONTINGENCIES
Caltex is involved in tax audits in the United States and in certain other
jurisdictions. The Internal Revenue Service's audit for the years 1987-1993 has
been administratively settled and Caltex will receive a refund of tax and
interest for these years. In jurisdictions outside the United States, the tax
authorities' audits are in various stages of completion. In the opinion of
management, adequate provision has been made for income taxes for all years
under examination or subject to future examination.
Caltex and certain of its subsidiaries are named as defendants, along with
privately held Philippine ferry and shipping companies and the shipping
company's insurer, in various lawsuits filed in the U.S. and the Philippines on
behalf of at least 3,350 parties, who were either survivors of, or relatives of
persons who allegedly died in a collision in Philippine waters on December 20,
1987. One vessel involved in the collision was carrying products for Caltex
(Philippines) Inc. (a subsidiary of Caltex) in connection with a contract of
affreightment. Although Caltex had no direct or indirect ownership in or
operational responsibility for either vessel, various theories of liability have
been alleged against Caltex. The major suit filed in the U.S. (Louisiana State
Court) was dismissed in December 2000 on forum non conveniens grounds and is
currently under appeal by the plaintiffs. Caltex will vigorously contest this
appeal. Caltex is actively pursuing dismissal of all Philippine litigation on
the strength of a Philippine Supreme Court decision absolving it of any
responsibility for the collision. No reasonable estimate of damages involved or
being sought can be made at this time.
The Group may be subject to loss contingencies pursuant to environmental laws
and regulations in each of the countries in which it operates that, in the
future, may require the Group to take action to correct or remediate the effects
on the environment of prior disposal or release of petroleum substances by the
Group. The amount of such future cost is indeterminable due to such factors as
the nature of the new regulations, the unknown magnitude of any possible
contamination, the unknown timing and extent of the corrective actions that may
be required, and the extent to which such costs are recoverable from third
parties.
17
CALTEX GROUP OF COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
NOTE 13 - COMMITMENTS AND CONTINGENCIES - (continued)
In the Group's opinion, while it is impossible to ascertain the ultimate legal
and financial liability, if any, with respect to the above mentioned and other
contingent liabilities, the aggregate amount that may arise from such
liabilities is not anticipated to be material in relation to the Group's
combined financial position or liquidity, or results of operations over a
reasonable period of time.
A Caltex subsidiary has a contractual commitment until 2007 to purchase
petroleum products in conjunction with the financing of a refinery owned by an
affiliate. Total future estimated commitments under this contract, based on
current pricing and projected growth rates, are approximately $0.8 billion per
year. Purchases (in billions of U.S. dollars) under this and other similar
contracts were $1.0, $0.7 and $0.8 in 2000, 1999, and 1998 respectively.
Caltex is contingently liable for sponsor support funding for a maximum of $193
million in connection with an affiliate's project finance obligations. The
project has been operational since 1996 and has successfully completed all
mechanical, technical and reliability tests associated with the plant physical
completion covenant. However, the affiliate has been unable to satisfy a
covenant relating to a working capital requirement. As a result, a technical
event of default exists which has not been waived by the lenders. The lenders
have not enforced their rights and remedies under the finance agreements and
they have not indicated an intention to do so. The affiliate is current on these
financial obligations and anticipates resolving the issue with its secured
creditors during further restructuring discussions. During 2000, Caltex and the
other sponsor provided temporary short-term extended trade credit related to
crude oil supply with an outstanding balance owing to Caltex at December 31,
2000 of $124 million.
NOTE 14 - OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCING ACTIVITIES
The financial statements of Chevron Corporation and Texaco Inc. contain required
supplementary information on oil and gas producing activities, including
disclosures on affiliates at equity. Accordingly, such disclosures are not
presented herein.
EQUILON
ENTERPRISES LLC
Shell & Texaco Working Together
Page
----
Report of Management ....................................................................... 1
Report of Independent Accountants .......................................................... 2
Statement of Consolidated Income ........................................................... 3
Consolidated Balance Sheet ................................................................. 4
Statement of Consolidated Cash Flows ....................................................... 5
Statement of Owners' Equity ................................................................ 6
Notes to the Consolidated Financial Statements ............................................. 7-23
REPORT OF MANAGEMENT
EQUILON ENTERPRISES LLC
The management of Equilon Enterprises LLC ("Equilon") is responsible for
preparing the consolidated financial statements of Equilon in accordance with
generally accepted accounting principles. In doing so, management must make
estimates and judgments when the outcome of events and transactions is not
certain.
In preparing these financial statements from the accounting records, management
relies on an effective internal control system in meeting its responsibility.
The objective of this system of internal controls is to provide reasonable
assurance that assets are safeguarded and that the financial records are
accurately and objectively maintained. Equilon's internal auditors conduct
regular and extensive internal audits throughout the company. During these
audits they review and report on the effectiveness of the internal controls and
make recommendations for improvement.
The independent accounting firms of PricewaterhouseCoopers LLP and Arthur
Andersen LLP are engaged to provide an objective, independent audit of Equilon's
financial statements. Their accompanying report is based on an audit conducted
in accordance with generally accepted auditing standards, which includes a
review and evaluation of the effectiveness of the company's internal controls.
This review establishes a basis for their reliance thereon in determining the
nature, timing and scope of their audit.
The Audit Committee of the Board of Directors is comprised of two directors who
review and evaluate Equilon's accounting policies and reporting, internal
controls, internal audit program and other matters as deemed appropriate. The
Audit Committee also reviews the performance of PricewaterhouseCoopers LLP and
Arthur Andersen LLP and evaluates their independence and professional
competence, as well as the results and scope of their audit.
Rob J. Routs Ronald B. Blakely David C. Cable
President and Chief Executive Officer Chief Financial Officer Controller
1
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors of Equilon Enterprises LLC:
We have audited the accompanying consolidated balance sheets of Equilon
Enterprises LLC ("Equilon") and its subsidiaries as of December 31, 2000 and
1999, and the related statements of consolidated income, owners' equity, and
cash flows for each of the years in the three-year period ended December 31,
2000. These combined financial statements are the responsibility of Equilon's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. 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, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Equilon Enterprises
LLC and its subsidiaries as of December 31, 2000 and 1999, and the results of
their operations and their cash flows for each of the years in the three year
period ended December 31, 2000, in conformity with accounting principles
generally accepted in the United States.
PricewaterhouseCoopers LLP Arthur Andersen LLP
Houston, Texas Houston, Texas
March 1, 2000 March 1, 2000
2
EQUILON ENTERPRISES LLC
STATEMENT OF CONSOLIDATED INCOME
For the years ended December 31,
------------------------------------------
2000 1999 1998
--------- --------- ---------
(Millions of dollars)
REVENUES
Sales and services $ 49,973 $ 29,174 $ 22,006
Equity in income of affiliates 166 154 109
Gain (loss) on asset sales (166) 12 118
Other revenue 37 58 13
---------- ---------- ----------
Total revenues 50,010 29,398 22,246
---------- ---------- ----------
COSTS AND EXPENSES
Purchases and other costs 45,579 24,714 17,540
Operating expenses 2,050 2,033 2,274
Selling, general and administrative expenses 1,563 1,308 1,251
Depreciation, amortization and impairment expenses 472 878 543
Interest expense 118 115 134
Minority interest - 3 2
---------- ---------- ----------
Total costs and expenses 49,782 29,051 21,744
---------- ---------- ----------
NET INCOME $ 228 $ 347 $ 502
========== ========== ==========
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
As of December 31,
----------------------------
2000 1999
---------- ----------
(Millions of dollars)
ASSETS
Current Assets
Cash and cash equivalents $ 68 $ 161
Accounts and notes receivable (less allowance for doubtful
accounts of $9 million in 2000 and $7 million in 1999) 2,262 2,456
Accounts receivable from affiliates 185 161
Inventories 610 620
Other current assets 9 28
--------- --------
Total Current Assets 3,134 3,426
Investments and Advances 547 529
Property, Plant and Equipment, Net 5,892 6,312
Deferred Charges and Other Noncurrent Assets 391 367
--------- --------
Total Assets $ 9,964 $ 10,634
========= ========
LIABILITIES AND OWNERS' EQUITY
Current Liabilities
Commercial paper and current portion
of long-term debt $ 2,149 $ 2,157
Accounts payable - trade 1,430 1,698
Accounts payable to affiliates 543 589
Accrued liabilities and other payables 465 409
--------- --------
Total Current Liabilities 4,587 4,853
Long-term Debt 8 5
Long-term Payables to Affiliates 365 466
Long-term Liabilities, Deferred Credits and Minority Interest 524 264
--------- --------
Total Liabilities 5,484 5,588
Owners' Equity 4,480 5,046
--------- --------
Total Liabilities and Owners' Equity $ 9,964 $ 10,634
========= ========
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
4
EQUILON ENTERPRISES LLC
STATEMENT OF CONSOLIDATED CASH FLOWS
For the years ended December 31,
------------------------------------------
2000 1999 1998
--------- --------- ---------
(Millions of dollars)
Operating activities:
Net Income $ 228 $ 347 $ 502
Reconciliation to net cash provided by operating activities
Depreciation, amortization and impairment expenses 472 878 543
Dividends from affiliates less than equity in income (1) (10) (41)
(Gain) loss on asset sales 166 (12) (118)
Changes in working capital
Accounts and notes receivable 194 (1,051) 247
Accounts receivable from affiliates (24) (4) (157)
Inventories (10) 23 26
Accounts payable - trade (268) 1,269 (800)
Accounts payable to affiliates (46) (6) 307
Accrued liabilities and other payables 32 (235) 246
Other, net 149 88 (29)
---------- ---------- ----------
Net cash provided by operating activities 892 1,287 726
---------- ---------- ----------
Investing activities:
Capital expenditures (579) (582) (651)
Proceeds from asset sales 464 371 409
---------- ---------- ----------
Net cash used in investing activities (115) (211) (242)
---------- ---------- ----------
Financing activities:
Net increase (decrease) in borrowings having original
terms in excess of three months 3 (155) (9)
Repayment of formation costs - - (1,613)
Net increase (decrease) in other short-term borrowings (8) 2 1,846
Distributions paid to owners (865) (773) (698)
---------- ---------- ----------
Net cash used in financing activities (870) (926) (474)
---------- ---------- ----------
Cash and Cash Equivalents:
Increase (decrease) in cash during year (93) 150 10
Balance at beginning of year 161 11 1
---------- ---------- ----------
Balance at end of year $ 68 $ 161 $ 11
========== ========== ==========
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
5
EQUILON ENTERPRISES LLC
STATEMENT OF OWNERS' EQUITY
2000 1999 1998
--------- --------- ---------
(Millions of dollars)
Owners' Equity balance at January 1 $ 5,046 $ 5,966 $ 6,122
Net income 228 347 502
Distributions paid (865) (773) (698)
Contribution adjustments:
Employee benefit obligations from owners (Note 8) 59 (543) -
Other 12 49 40
---------- ---------- ----------
Owners' Equity balance at December 31 $ 4,480 $ 5,046 $ 5,966
========== ========== ==========
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
6
EQUILON ENTERPRISES LLC
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - ORGANIZATION
Equilon Enterprises LLC ("Equilon") is a limited liability company formed by
Shell Oil Company ("Shell") and Texaco Inc. ("Texaco") effective January 1, 1998
under the Delaware Limited Liability Act, with equity interests of 56 percent
and 44 percent, respectively. The joint venture combined the major elements of
Shell and Texaco's Western and Midwestern U.S. refining and marketing businesses
and their nationwide trading, transportation and lubricants businesses. Despite
the ownership interests, Shell and Texaco jointly control Equilon, as many
significant governance decisions require unanimous approval.
A second joint venture company, Motiva Enterprises LLC ("Motiva"), was formed on
July 1, 1998, combining the major elements of the Eastern and Gulf Coast U.S.
refining and marketing businesses of Shell, Texaco and Saudi Refining, Inc.
("SRI"). Equiva Trading Company and Equiva Services LLC were also formed on July
1, 1998 and are owned equally by Equilon and Motiva. Equiva Trading Company, a
general partnership, functions as the trading unit for both Equilon and Motiva.
Equiva Services LLC provides common financial, administrative, technical, and
other operational support to Equilon and Motiva. Equiva Trading Company and
Equiva Services LLC bill their services at cost.
Equilon refines, distributes and markets petroleum products under both the Shell
and Texaco brands through wholesalers and its network of company owned and
contractor operated service stations. Products are manufactured at four
refineries located in Puget Sound, Washington; and in Bakersfield, Los Angeles,
and Martinez, California. As part of its strategic initiative to strengthen its
portfolio of assets, Equilon sold its refinery in El Dorado, Kansas in November
of 1999, and sold its Wood River, Illinois refinery in June of 2000.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Financial Statements
The accompanying financial statements are presented using Shell and Texaco's
historical basis of the assets and liabilities contributed to Equilon on January
1, 1998. The consolidated financial statements generally include the accounts of
Equilon and subsidiaries in which Equilon directly or indirectly owns more than
a 50 percent voting interest. Intercompany accounts and transactions are
eliminated. Investments in entities in which Equilon has a significant ownership
interest, generally 20 to 50 percent, and entities where Equilon has greater
than 50 percent ownership but, as a result of contractual agreement or
otherwise, does not exercise control, are accounted for using the equity method.
Other investments are carried at cost. Equilon's investments in Equiva Services
LLC and Equiva Trading Company are accounted for using the equity method.
Transactions by Equiva Trading Company that are made on behalf of Equilon are
recorded directly to Equilon's records.
7
EQUILON ENTERPRISES LLC
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
Use of Estimates
These financial statements were prepared in conformity with generally accepted
accounting principles, which require management to make estimates and
assumptions. These assumptions affect the reported amounts of assets and
liabilities and the disclosure of contingent assets and liabilities at the date
of the financial statements and the reported amounts of revenues and expenses
during the reporting period.
Significant estimates include the recoverability of assets, environmental
remediation, employee benefit liabilities, litigation, claims and assessments.
Amounts are recognized when it is probable that an asset has been impaired or a
liability has been incurred, and the cost can be reasonably estimated. Actual
results could differ from those estimates.
New Accounting Standards
In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement
of Financial Accounting Standards 133, "Accounting for Derivative Instruments
and Hedging Activities" ("SFAS 133"). SFAS 133 establishes new accounting rules
and disclosure requirements for most derivative instruments and hedge
transactions. In June 1999, the FASB issued SFAS 137 that deferred the effective
date of adoption of SFAS 133 for one year. This was followed in June 2000 by the
issuance of SFAS 138, "Accounting for Certain Derivative Instruments and Certain
Hedging Activities", which amended SFAS 133.
SFAS 133, as amended by SFAS 137 and SFAS 138, requires Equilon to record all
derivative financial instruments in the Consolidated Balance Sheets at fair
value. For derivatives accounted for as hedges, fair value adjustments are
recorded to earnings or other comprehensive income, a component of owners'
equity, depending upon the type of hedge and the degree of hedge effectiveness.
For hedges classified as fair value hedges, adjustments are also recorded to the
carrying amount of the hedged item through earnings. For derivatives not
accounted for as hedges, fair value adjustments are recorded to earnings.
Equilon adopted these standards effective January 1, 2001. As such, Equilon's
results of operations and financial position will reflect the impact of the new
standard commencing January 1, 2001. The cumulative effect of adoption at that
date on net income and other comprehensive income, a component of owners'
equity, was not material.
Revenues
Revenues for refined products and crude oil sales are recognized at the point of
passage of title specified in the contract. Revenues on forward sales where cash
has been received are recorded to deferred income until title passes.
Cash Equivalents
Highly liquid investments with maturity when purchased of three months or less
are considered to be cash equivalents.
Inventories
Inventories are valued at the lower of cost or market. Hydrocarbon inventory
cost is determined on the last-in, first-out (LIFO) method. The cost of other
merchandise inventories is determined on the first-in, first-out (FIFO) method.
Weighted average cost is utilized for inventories of materials and supplies.
8
EQUILON ENTERPRISES LLC
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
Investments and Advances
The equity method of accounting is generally used for investments in certain
affiliates owned 50 percent or less, including corporate joint ventures, limited
liability companies and partnerships. Under this method, equity in pre-tax
income or losses of limited liability companies and partnerships, and the net
income or losses of corporate joint venture companies are reflected in revenues
as they are generated, rather than when realized through dividends or
distributions.
The cost method is generally used to account for affiliates in which Equilon's
ownership interest is less than 20 percent. Income from these investments is
recognized as dividends or distributions are declared.
Property, Plant and Equipment
Depreciation of property, plant and equipment is generally provided on composite
groups, using the straight-line method, with depreciation rates based upon the
estimated useful lives of the groups.
Under the composite depreciation method, the cost of partial retirements of a
group is charged to accumulated depreciation. However, when there is a
disposition of a complete group, or when the retirement is due to an
extraordinary loss, the cost and related depreciation are retired, and any gain
or loss is reflected in income.
Capitalized leases are amortized over the estimated useful life of the asset or
the lease term, as appropriate, using the straight-line method.
All maintenance and repairs, including major refinery maintenance, are charged
to expense as incurred. Renewals, betterments and major repairs that materially
extend the life of the properties are capitalized. Interest incurred during the
construction period of major additions is capitalized.
The evaluation of impairment for property, plant and equipment is based on
comparisons of carrying values against undiscounted future net pre-tax cash
flows. If impairment is identified, the asset's carrying amount is adjusted to
fair value. Assets to be disposed of are generally valued at the lower of net
book value or fair value less cost to sell.
Derivatives
Equilon utilizes futures, purchased options and swaps to manage the price risk
of crude oil and refined products. These transactions meet the requirements for
hedge accounting, including designation and correlation. Gains and losses on
closed positions are deferred until corresponding physical transactions occur.
At that time, any gain or loss is accounted for as part of the transactions
being hedged. Deferred gains and losses are included in current assets and
liabilities on the balance sheet. Equilon also uses written options to manage
price risk. Unrealized gains and losses on these transactions are recognized in
current earnings.
Equilon conducts petroleum-related trading activities. As of January 1, 1999,
Equilon adopted mark-to-market accounting in compliance with Emerging Issues
Task Force Issue 98-10, "Accounting for Energy Trading and Risk Management
Activities." Under mark-to-market accounting, gains and losses resulting from
changes in market prices on contracts entered into for trading purposes are
reflected in current earnings.
9
EQUILON ENTERPRISES LLC
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
Fair Market Value of Financial Instruments
The estimated fair value of long-term debt is disclosed in Note 7 to the
financial statements. The carrying amount of long-term debt with variable rates
of interest approximates fair value at December 31, 2000 and 1999, as borrowing
terms equivalent to the stated rates were available in the marketplace. Fair
value for long-term debt with a fixed rate of interest is determined based on
discounted cash flows using estimated prevailing interest rates.
Other financial instruments are included in current assets and liabilities on
the balance sheet and approximate fair value because of the short maturity of
such instruments. These include cash, short-term investments, notes and accounts
receivable, accounts payable and short-term debt.
Contingencies
Certain conditions may exist as of the date financial statements are issued,
which may result in a loss to the company, but which will be resolved only when
one or more future events occur or fail to occur. Equilon's management and legal
counsel assess such contingent liabilities. The assessment of loss contingencies
necessarily involves an exercise of judgment and is a matter of opinion. In
assessing loss contingencies related to legal proceedings that are pending
against the company or unasserted claims that may result in such proceedings,
Equilon's legal counsel evaluates the perceived merits of any legal proceedings
or unasserted claims as well as the perceived merits of the amount of relief
sought or expected to be sought therein.
If the assessment of a contingency indicates that it is probable that a material
liability has been incurred and the amount of the loss can be estimated, then
the estimated liability is accrued in the company's financial statements. If the
assessment indicates that a potentially material liability is not probable, but
is reasonably possible, or is probable but cannot be estimated, then the nature
of the contingent liability, together with an estimate of the range of possible
loss is disclosed if determinable and material. Loss contingencies considered
remote are generally not disclosed unless they involve guarantees, in which case
the nature of the guarantee is disclosed.
Environmental Expenditures
Equilon accrues for environmental remediation liabilities when it is probable
that such liabilities exist, based on past events or known conditions, and the
amount of such liability can be reasonably estimated. If Equilon can only
estimate a range of probable liabilities, the minimum future undiscounted
expenditure necessary to satisfy Equilon's future obligation is accrued.
Equilon determines the appropriate amount of each obligation by considering all
of the available data, including technical evaluations of the currently
available facts, interpretation of existing laws and regulations, prior
experience with similar sites and the estimated reliability of financial
projections.
Equilon adjusts the environmental liabilities, as required, based on the latest
experience with similar sites, changes in environmental laws and regulations or
their interpretation, development of new technology, or new information related
to the extent of Equilon's obligation. Other environmental expenditures,
principally maintenance or preventive in nature, are expensed or capitalized as
appropriate.
10
EQUILON ENTERPRISES LLC
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
Reclassifications
Certain 1999 and 1998 amounts have been reclassified to conform to current year
presentation, including netting of certain trade payables and receivables where
a legal right of offset exists.
NOTE 3 - INVENTORIES
As of December 31,
-------------------------
2000 1999
---- ----
(Millions of dollars)
Crude oil $ 175 $ 211
Petroleum products 359 316
Other merchandise 24 21
Materials and supplies 52 72
--------- -------
Total $ 610 $ 620
========= =======
The excess of estimated market value over the book value of inventories carried
at cost on the LIFO basis of accounting was approximately $861 million at
December 31, 2000 and $771 million at December 31, 1999.
Partial liquidation of inventories valued on a LIFO basis increased net income
by $11 million in 2000 and $13 million in 1999.
NOTE 4 - PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment, including capitalized lease assets, were as
follows:
As of December 31,
------------------------------------------------------
2000 1999
------------------------- ------------------------
Gross Net Gross Net
----- --- ----- ---
(Millions of dollars)
Refining $ 5,310 $ 2,654 $ 6,510 $ 3,148
Marketing 2,480 1,858 2,478 1,856
Transportation 2,489 1,322 2,280 1,203
Other 130 58 186 105
--------- ---------- -------- ---------
Total $ 10,409 $ 5,892 $ 11,454 $ 6,312
========= ========== ======== =========
Capital lease amounts included above $ 2 $ - $ 2 $ -
Accumulated depreciation and amortization totaled $4,517 million at December 31,
2000 and $5,142 million at December 31, 1999. Interest capitalized as part of
property, plant and equipment was $2 million in each year, 2000 and 1999.
11
EQUILON ENTERPRISES LLC
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 4 - PROPERTY, PLANT AND EQUIPMENT (continued)
Long-Lived Assets
Under the provisions of SFAS 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to Be Disposed Of," Equilon recorded a charge
of $397 million, during the second quarter 1999, for the impairment of the El
Dorado refinery and the Wood River refinery and lubricants plant. These
impairments, which were recognized in anticipation of the sale of these
refineries and for the write-off of abandoned lubricants base oil assets at Wood
River, were reflected as increased depreciation, amortization and impairment
expenses on the Statement of Consolidated Income.
On June 1, 2000, Equilon recognized a loss of $161 million to complete the sale
of the Wood River refinery. Included in this loss was a charge of $100 million
for tank upgrades and environmental compliance and remediation issues. The
carrying value of the Wood River refinery was $410 million at the date of sale.
The Wood River refinery had operating income of $18 million in 2000, and $10
million in 1998, and an operating loss of $20 million in 1999.
On November 17, 1999, Equilon recorded an additional charge of $11 million to
complete the sale of the El Dorado refinery. This included the recognition of a
liability for wastewater treatment. The carrying amount of the El Dorado
refinery at the time of sale was $170 million. Operating income for the El
Dorado refinery was $20 million in 1999 and $24 million in 1998.
During 1998, Equilon recognized the impairment of surplus assets resulting from
the consolidation and optimization of assets contributed by Shell and Texaco.
Impairments from this activity totaled over $77 million, including the write-off
of abandoned assets at the Odessa refinery, shut down in October 1998, and the
write-down to estimated realizable value of three lubricant blending plants
either closed in 1998 or sold in 1999. The impairments were primarily reflected
in increased depreciation, amortization and impairment expenses on the Statement
of Consolidated Income.
NOTE 5 - INVESTMENTS AND ADVANCES
Investments in affiliates, including corporate joint ventures and partnerships,
owned 50% or less are generally accounted for on the equity method. Equilon's
total investments and advances are summarized as follows:
As of December 31,
--------------------------
2000 1999
---- ----
(Millions of dollars)
Investments in affiliates accounted for on the equity method
Pipeline affiliates $ 395 $ 415
Other affiliates 98 82
--------- -------
Total equity method affiliates 493 497
Other investments and advances 54 32
--------- -------
Total investments and advances $ 547 $ 529
========= =======
12
EQUILON ENTERPRISES LLC
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 5 - INVESTMENTS AND ADVANCES (continued)
Undistributed earnings of equity companies included in Equilon's accumulated
earnings as of December 31, 2000 and 1999 were $52 million and $51 million,
respectively. Summarized financial information for these investments and
Equilon's equity share thereof is as follows in millions of dollars:
100% Equity Share
----------------------------- ------------------------------
2000 1999 1998 2000 1999 1998
---- ---- ---- ---- ---- ----
Revenues $ 2,380 $ 2,002 $ 1,500 $ 817 $ 615 $ 430
Income before income taxes 638 664 519 186 176 123
Net income 505 494 362 166 154 109
Dividends received 165 144 68
NOTE 6 - LEASE COMMITMENTS AND RENTAL EXPENSE
Equilon has leasing arrangements involving service stations and other
facilities. Renewal and purchase options are available on certain of these
leases in which Equilon is lessee.
Equilon has a one year lease agreement for a cogeneration plant at the El Dorado
refinery. This lease may be renewed each year until 2016 at Equilon's option.
The lease has been renewed with a minimum lease rental of $4 million for 2001.
Equilon has guaranteed a minimum recoverable residual value to the lessor of $72
million, if the lease is not renewed for the year 2002. In connection with the
sale of the El Dorado refinery in 1999, Equilon entered into a long-term
sublease arrangement with a subsidiary of Frontier Oil Corporation (Frontier)
for Frontier's use of the cogeneration facility at the refinery. While the
sublease payments from the sublessee fully cover Equilon's lease obligation,
Equilon remains primarily liable with regard to payment of its original
obligation. The original term of the sublease is 17 years, although it is
subject to early termination upon the occurrence of certain events specified in
the sublease. Upon expiration of the initial term of the sublease, Frontier has
the option of purchasing the cogeneration facility, from Equilon, at a price not
less than the fair market value of the facility at the time the option is
exercised.
13
EQUILON ENTERPRISES LLC
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 6 - LEASE COMMITMENTS AND RENTAL EXPENSE (continued)
Rental expense relative to operating leases, including contingent rentals, is
provided in the table below:
For the years ended December 31,
------------------------------------------
2000 1999 1998
---- ---- ----
(Millions of dollars)
Rental Expense:
Minimum lease rentals $ 96 $ 121 $ 178
Contingent rentals 15 3 7
--------- --------- ---------
Total 111 124 185
Less rental income on properties subleased to others 52 59 54
--------- --------- ---------
Net rental expense $ 59 $ 65 $ 131
========= ========= =========
As of December 31, 2000 Equilon had estimated minimum commitments for payment of
rentals under leases that, at inception, had a non-cancelable term of more than
one year, as follows:
Operating leases
(Millions of dollars)
2001 $ 104
2002 91
2003 89
2004 83
2005 75
After 2005 929
---------
Total 1,371
Less sublease rental income 119
Total lease commitments $ 1,252
=========
14
EQUILON ENTERPRISES LLC
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 7 - DEBT
Equilon has revolving credit facilities with commitments of $1,874 million, as
support for the company's commercial paper program, as well as for working
capital and other general purposes. Equilon pays a nominal quarterly facility
fee for the $1,874 million availability. No amounts were outstanding during 2000
and 1999.
Commercial Paper and Current Portion of Long-term Debt
As of December 31,
----------------------
2000 1999
---- ----
(Millions of dollars)
Commercial Paper $ 1,854 $ 1,850
Anacortes Pollution Control Bonds due 2019 34 34
Butler County Industrial Revenue Bonds due 2024 30 30
California Pollution Control Bonds due 2011 through 2024 172 185
Southwestern Illinois Industrial Revenue Bonds due 2021 through 2025 58 58
Current portion of long-term debt 1 -
--------- -------
Total $ 2,149 $ 2,157
========= =======
Average interest rate of short term debt 6.27% 5.12%
Long-term Debt
As of December 31,
----------------------
2000 1999
---- ----
(Millions of dollars)
Variable notes, currently 9.125% , due 2006 through 2009 $ 6 $ 5
7.000% note due 2013 2 -
6.000% note due 2020 1 -
--------- -------
Total 9 5
Less current portion of long-term debt 1 -
--------- -------
Total $ 8 $ 5
--------- -------
Fair market value of long-term debt $ 8 $ 5
========= =======
The Pollution Control Bonds outstanding at December 31, 2000 and 1999 shown
above consisted of four issues assumed from Shell and one from Texaco. The
Industrial Revenue Bonds outstanding at December 31, 2000 and 1999 consisted of
three issues from Shell and one from Texaco. Interest rates are currently reset
daily for these issues and the bonds may be converted from time to time to other
modes. Bondholders have the right to tender their bonds under certain
conditions, including on interest rate resets. Pursuant to the terms of the
underlying indentures, Shell and Texaco retain liability for debt service on the
issues assumed by Equilon in the event that Equilon fails to perform on its
obligations. All other Equilon borrowings are unsecured general obligations of
Equilon and not guaranteed by any other entity.
Interest paid during 2000, 1999 and 1998 was $133 million, $128 million and $95
million, respectively.
15
EQUILON ENTERPRISES LLC
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 8 - LONG-TERM PAYABLES TO AFFILIATES, OWNERS' EQUITY CONTRIBUTION
ADJUSTMENTS AND FORMATION PAYABLES
Long-term Payables
On April 1, 1999, Shell and Texaco employees designated as performing duties
supporting Equilon, were transferred to Equiva Services LLC. At that time
certain benefit liabilities were transferred to Equiva Services LLC from Shell
and Texaco through their interests in Equilon and Motiva. Such obligations
transferred from Shell and Texaco, applicable to Equilon, were recorded as
reductions to Equilon's investment in Equiva Services LLC. A related party
obligation of $520 million at December 31, 1999 represents Equilon's obligation
to Equiva Services LLC for all employee benefit liabilities. Of this amount,
$466 million was classified as long-term at December 31, 1999. On January 1,
2000, Equiva Services employees supporting Equilon and Equiva Trading Company
became employees of the respective companies they support. Employee related
benefit liabilities were transferred to Equilon and through Equilon to Equiva
Trading Company, at the same time. As a result of the transfer, Equilon's
related party obligation to Equiva Services LLC was reduced by $480 million. As
of December 31, 2000, Equilon has affiliate payables to Equiva Services LLC and
Equiva Trading Company totaling $56 million representing its obligation for
employee benefit liabilities of these entities. Of this amount $48 million was
classified as long term.
Additional information is disclosed in Note 11 - Employee Benefits.
Owners' Equity Contribution Adjustments
The foregoing contribution of liabilities that were transferred from Shell and
Texaco through Equilon to Equiva Services LLC for employee benefit liabilities
at April 1, 1999 reduced Equilon's owners' equity by $543 million and included
$357 million for pension related affiliate obligations, $147 million of
post-employment medical benefits and $39 million for vacation benefits. Other
contribution adjustments in 1999 related primarily to certain environmental
remediation obligations transferred to Equilon at formation, which were
reassumed by Shell in 1999, increased owners' equity by $49 million. The sale of
Wood River refinery in 2000 reduced pension related affiliate obligations to
Shell by $59 million and resulted in an increase in Shell's owners' equity in
Equilon by the same amount.
Formation Payables
In accordance with the joint venture agreements, Equilon owed Shell $1,001
million and Texaco $612 million at formation. These amounts were separate from
normal trade payables and reflect amounts to reimburse Shell and Texaco for
certain capital expenditures incurred prior to the formation of the venture and
certain other items specified in the formation documents. Equilon paid these
amounts to Shell and Texaco prior to December 31, 1998. Interest was accrued on
these amounts until paid.
In addition to the foregoing payable amounts, Texaco retained $240 million of
receivables related to the contributed business as part of these arrangements.
16
EQUILON ENTERPRISES LLC
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 9 - TRANSACTIONS WITH RELATED PARTIES
Equilon has entered into transactions with Shell, Texaco, Motiva, Equiva Trading
Company, and Equiva Services LLC, including the affiliates of these companies.
Such transactions are in the ordinary course of business and include the
purchase, sale and transportation of crude oil and petroleum products, and
numerous service agreements.
The aggregate amounts of such transactions were as follows:
For the years ended December 31,
-------------------------------------
2000 1999 1998
---- ---- ----
(Millions of dollars)
Sales and other operating revenue $ 5,950 $ 3,409 $ 1,368
Purchases and transportation costs 11,846 6,961 4,900
Service and technology expense 319 1,057 794
NOTE 10 - TAXES
Equilon, as a limited liability company, is not liable for income taxes. Income
taxes are the responsibility of the owners. Equilon's pre-tax earnings are
included in the owners' earnings for the determination of income tax liability.
Under the joint venture agreements with its owners, Equilon is required to make
cash distributions to its owners reflecting their share of estimated income
taxes for the year based on Equilon's estimated taxable income.
Direct taxes other than income taxes, which are included in operating expenses,
were as follows:
For the years ended December 31,
--------------------------------------
2000 1999 1998
---- ---- ----
(Millions of dollars)
Direct taxes
Property $ 82 $ 78 $ 41
Licenses and permits 10 7 5
Other 15 12 26
-------- --------- ---------
Total direct taxes $ 107 $ 97 $ 72
======== ========= =========
Other taxes collected from consumers for governmental agencies that are not
included in revenues or expenses were $3,499 million for 2000, $3,405 million
for 1999 and $3,646 million for 1998.
17
EQUILON ENTERPRISES LLC
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 11 - EMPLOYEE BENEFITS
In accordance with certain joint venture agreements related to human resources
matters, employees performing duties supporting Equilon remained employees of
the owner companies and their affiliates until April 1, 1999. Beginning April 1,
1999 Equilon's affiliate, Equiva Services LLC, employed personnel necessary for
ongoing operations. Obligations and accrued liabilities for certain employee
benefits, including pension and other post-employment benefits, were transferred
to Equiva Services LLC at that time. On January 1, 2000, employees directly
supporting Equilon became employees of Equilon. Employees providing common crude
and product logistical and trading support for both Equilon and Motiva became
employees of Equiva Trading Company. Employees providing common financial,
administrative, technical and other operational support to both Equilon and
Motiva remain employees of Equiva Services LLC. Employee related obligations,
including liabilities for pension and other post-employment benefits for
employees transferred to Equilon, were recorded as Equilon liabilities on
January 1, 2000 with a corresponding reduction in the affiliate payable to
Equiva Services LLC. Employee related liabilities for employees transferred from
Equiva Services LLC to Equiva Trading Company were transferred to Equiva Trading
Company through Equilon and Motiva. Equilon's share of these liabilities was
recorded as a long-term affiliate payable to Equiva Trading Company.
Pension Related Affiliate Obligations
Concurrently with their transfer from the owner companies, employees retained
certain pension benefits for future pay increases under the owner company
pension plans. Under agreements with Shell and Texaco, the owner companies will
be reimbursed for past service pension benefits attributable to these future pay
benefits at April 1, 1999, as well as ongoing increases in the related projected
benefit obligation under the owner companies' qualified pension plans. These
reimbursements will be made at the time these employees receive benefits from
owner company plans. The following summarizes the reimbursement owed to the
owner companies and components of accrual expense:
2000 1999 (a)
---- --------
(Millions of dollars)
Projected benefit obligation at January 1, 2000 and April 1, 1999 $ 276 $ 327
Interest cost 22 16
Actuarial gain (13) (55)
Acquisition/divestiture (23) (12)
--------- -------
Projected benefit obligation at December 31 262 276
Unrecognized net gain 67 67
--------- -------
Accrued past services pension liability at December 31 $ 329 $ 343
========= =======
Weighted-average assumptions at December 31
Discount rate 7.5% 8.0%
Rate of compensation increase 4.0% 4.5%
Components of net accrual expense
Interest cost $ 22 $ 16
Recognized net actuarial gain (3) -
--------- -------
Net accrual expense $ 19 $ 16
========= =======
(a) Represents amounts applicable to Equiva Services employees working on
behalf of Equilon for the 9 month period from April 1, 1999 to December 31,
1999.
18
EQUILON ENTERPRISES LLC
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 11 - EMPLOYEE BENEFITS (continued)
Other Post-Employment Benefits
Equilon and Equiva Services LLC currently provide health care benefits for
retired employees and their dependents through a common plan. Eligibility for
such benefits requires that a retired employee be at least 50 years of age, with
at least 10 years of service and the sum of age and service of at least 70
years. Past service with the owner companies is credited for determining benefit
eligibility.
The company's obligation is a percentage of the total premiums required. This
percentage varies from 60% to 80% of total cost depending on the sum of the
employee's total years of age plus service at the time of retirement. The
assumed annual health care cost trend rate used in measuring the accumulated
post-employment benefit obligation (APBO) was 7.0% in 1999, and 9.0% in 2000,
decreasing to 5.0% by 2008 and remaining at that level thereafter. Assuming a 1%
increase in the annual rate of increase of required medical premiums, the APBO
and annual expense would increase by approximately $35 million and $2 million,
respectively.
In addition to medical benefits, Equilon and Equiva Services LLC are providing
retiree life insurance benefits to certain former owner employees from Texaco
and Star Enterprise (Star). These employees were to have reached age 50 by April
1, 1999, with 5 years of service at the time of transfer, and must retire at a
minimum age of 55 with at least 10 years of service in order to be eligible.
Net post-employment benefit costs for 2000 and for the period of April 1, 1999
to December 31, 1999 were as follows:
2000 1999 (b)
---- --------
(Millions of dollars)
Service cost $ 6 $ 5
Interest cost 9 7
Amortization of prior service cost (1) (1)
Recognized net actuarial gain (1) -
Curtailment gain (6) -
--------- -------
Accrued expense $ 7 $ 11
========= =======
(b) Represents amounts applicable to Equiva Services employees working on
behalf of Equilon for the 9 month period from April 1, 1999 to December 31,
1999.
19
EQUILON ENTERPRISES LLC
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 11 - EMPLOYEE BENEFITS (continued)
Other Post-Employment Benefits (continued)
The status of other post-employment plans as of December 31, 2000 and 1999, was
as follows:
2000 1999 (c)
---- --------
(Millions of dollars)
Benefit obligation at January 1, 2000 and April 1, 1999 $ 118 $ 131
Service cost 6 5
Interest cost 9 7
Actuarial (gain)/loss 53 (19)
Acquisition/divestiture 6 (6)
Benefit paid (1) -
Curtailments (6) -
--------- -------
Benefit obligation at December 31 185 118
Unrecognized prior service cost 8 8
Unrecognized gain/(loss) (28) 24
--------- -------
Accrued post-employment benefit obligation at December 31 $ 165 $ 150
========= =======
(c) Represents amounts applicable to Equiva Services employees working on
behalf of Equilon for the 9 month period from April 1, 1999 to December 31,
1999.
Pension Plans
Effective April 1, 1999, Equiva Services LLC established a cash balance defined
benefit pension plan covering substantially all of its employees. Company
contributions under the plan are between 3% and 7% of compensation based on
years of service, age, and covered compensation. Individual employee accounts
are credited each month with employer contributions and interest on the account
balance at an interest rate adjusted quarterly. Currently the interest rate is
5.8% per annum. Assets of the plan are comprised of equity securities and fixed
income securities. Equilon and Equiva Services LLC's funding policy is to
contribute all pension costs accrued to the extent required by federal tax
regulations. The following table sets forth information related to changes in
the benefit obligations, change in plan assets, a reconciliation of the funded
status of the plans and components of the expense recognized related to
Equilon's pension plan.
20
EQUILON ENTERPRISES LLC
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 11 - EMPLOYEE BENEFITS (continued)
Pension Plans (continued)
2000 1999 (d)
---- --------
(Millions of dollars)
Change in benefit obligation
Projected benefit obligation at January 1, 2000 and April 1, 1999 $ 20 $ -
Service cost 29 23
Interest cost 3 -
Actuarial gain (1) (2)
Acquisition/divestiture/plan merger 9 (1)
Benefit paid (5) -
Curtailments (1) -
--------- --------
Projected benefit obligation at December 31 $ 54 $ 20
========= ========
Change in plan assets
Fair value of plan assets at January 1, 2000 and April 1, 1999 $ - $ -
Actual return on plan assets, net of expenses (1) (1)
Employer contributions 25 1
Benefit paid (5) -
Plan merger 15 -
--------- --------
Fair value of plan assets at December 31 $ 34 $ -
========= ========
Funded status at December 31
Obligation greater than assets $ 20 $ 20
Unrecognized net gain 2 2
--------- --------
Accrued pension liability at December 31 $ 22 $ 22
========= ========
Weighted-average assumptions at December 31
Discount rate 7.5% 8.0%
Expected return on plan assets 9.0% 9.0%
Rate of compensation increase 4.0% 4.5%
Components of net periodic benefit costs
Service cost $ 29 $ 23
Interest cost 3 -
Expected return on plan assets (2) -
Curtailment gain (1) -
--------- --------
Net periodic benefit costs $ 29 $ 23
========= ========
(d) Represents amounts applicable to Equiva Services employees working on
behalf of Equilon for the 9 month period from April 1, 1999 to December 31,
1999.
21
EQUILON ENTERPRISES LLC
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 11 - EMPLOYEE BENEFITS (continued)
Employee Termination Benefits
The joint venture agreements provide for Equilon and Motiva to determine the
appropriate staffing levels for their businesses. To the extent those staffing
needs resulted in the elimination of positions from the ranks of Shell, Texaco
and Star, affected employees were entitled to termination benefits provided for
under the benefit plans of the applicable companies. Shell, Texaco and Star, as
the employer companies, are responsible for administering the payment of
benefits under their respective benefit plans. Equilon and Motiva have
reimbursed the employer companies for substantially all costs resulting from the
elimination of positions in accordance with a formula included in the joint
venture agreements.
The formation of Equilon and Motiva resulted in the termination of 1,658
employees. The separations were substantially complete as of December 31, 1999.
In 1998, Equilon recorded a charge of $61 million for its share of reimbursable
severance and other benefit costs as selling, general and administrative
expenses in the Statement of Consolidated Income. An additional provision of $2
million was recorded to selling, general and administrative expenses in 1999.
Equilon reimbursed the employer companies $4 million in 2000, $52 million in
1999, and $7 million in 1998 for the termination benefits.
NOTE 12 - DERIVATIVES
On January 1, 2001, Equilon adopted Statement of Financial Accounting Standards
No. 133 (SFAS 133) Accounting for Derivative Instruments and Hedging Activities
as amended by SFAS 137 and SFAS 138. Equilon's results of operations and
financial position will reflect the impact of the new standard commencing
January 1, 2001. The cumulative effect of adoption at that date on net income
and other comprehensive income, a component of owners' equity, is not material.
At December 31, 2000, open derivative instruments held for hedging purposes
consisted mostly of futures. Notional contract amounts were $33 million and $31
million at year-end 2000 and 1999, respectively. These amounts principally
represent future values of contract volumes over the remaining duration of the
outstanding futures contracts at the respective dates. These contracts hedge a
small fraction of the company's business activities, generally for periods
within the next twelve months.
Equilon entered into a relatively small number of petroleum-related derivative
transactions for trading purposes. The results of derivative trading activities
are marked to market, with gains and losses recorded in operating revenue. All
derivative instruments are straightforward futures, swaps and options, with no
leverage or multiplier features. At December 31, 2000, the open derivative
instruments held for trading purposes consisted primarily of futures and
options. The notional contract amounts of derivative instruments were $903
million and $813 million at year-end 2000 and 1999, respectively.
22
EQUILON ENTERPRISES LLC
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 12 - DERIVATIVES (continued)
The earnings impact of hedging and trading activities in 2000 and 1999 was a
charge to revenues of $20 million and $92 million, respectively, and was not
material in 1998. The unrealized gains and losses on open positions at December
31, 2000 and 1999 were losses of $36 million and $3 million, respectively.
The adoption, including the cumulative effect, of mark-to-market accounting in
compliance with Emerging Issues Task Force Issue 98-10 "Accounting for Energy
Trading and Risk Management Activities" has had no material impact on the
consolidated financial position or results of operation of Equilon.
NOTE 13 - CONTINGENT LIABILITIES
Equilon is subject to possible loss contingencies including actions or claims
based on environmental laws, federal regulations, and other matters. While it is
impossible to ascertain the ultimate legal and financial liability with respect
to many such contingent liabilities and commitments, Equilon has accrued amounts
(undiscounted) related to certain such liabilities where the outcome is deemed
both probable and reasonably measurable.
Equilon has been named as a defendant or a potentially responsible party in
several contamination matters and has certain obligations for remediation of
adverse environmental conditions related to certain of its operating assets
under existing laws and regulations.
On June 10, 1999, there was a rupture and resulting fire in the Olympic Pipe
Line Company pipeline at Bellingham, Washington, in which there were three
civilian fatalities. Equilon Pipeline Company LLC holds a 37.5 percent interest
in Olympic Pipe Line Company. Regulatory and governmental investigations are
ongoing and wrongful death lawsuits were filed.
On November 25, 1998, a fire occurred at the Equilon Puget Sound Refinery in
Anacortes, Washington, which resulted in six fatalities - four employees of a
contractor and two Texaco employees working on behalf of Equilon. Regulatory and
governmental investigations and the subsequent wrongful death lawsuits were
settled in May 1999 and January 2001, respectively. Settlement obligations were
previously accrued or covered by third party insurance.
Equilon has assumed crude and refined product throughput commitments previously
made by Shell and Texaco to ship through affiliated pipeline companies and an
offshore oil port, some of which relate to financing arrangements. As of
December 31, 2000 and 1999, the maximum exposure was estimated to be $248
million and $297 million, respectively. In addition, Equilon is contingently
liable for potential contractual obligations related to the sale of electricity
by a cogeneration facility in which it has a general partnership interest.
Equilon's maximum exposure under this arrangement was $159 million and $173
million as of December 31, 2000 and December 31, 1999, respectively. No advances
have resulted from these obligations.
In management's opinion, the aggregate amount of liability for contingent
liabilities, in excess of financial liabilities already accrued or anticipated
insurance recoveries, is not anticipated to be material in relation to the
consolidated financial position or results of operations of Equilon.
23
MOTIVA
ENTERPRISES LLC
Shell, Texaco & Saudi Aramco Working Together
2000 FINANCIAL STATEMENTS
MOTIVA ENTERPRISES LLC
2000 FINANCIAL STATEMENTS
INDEX
Page
----
Report of Management................................................................. 1
Report of Independent Accountants.................................................... 2
Statements of Income................................................................. 3
Balance Sheets....................................................................... 4
Statements of Cash Flows............................................................. 5
Statements of Owners' Equity......................................................... 6
Notes to Financial Statements........................................................ 7-22
REPORT OF MANAGEMENT
MOTIVA ENTERPRISES LLC
The management of Motiva Enterprises LLC (Motiva) is responsible for preparing
the financial statements of Motiva in accordance with accounting principles
generally accepted in the United States. In doing so, management must make
estimates and judgments when the outcome of events and transactions is not
certain.
In preparing these financial statements from the accounting records, management
relies on an effective internal control system in meeting its responsibility.
The objective of this system of internal controls is to provide reasonable
assurance that assets are safeguarded and that the financial records are
accurately and objectively maintained. Motiva's internal auditors conduct
regular and extensive internal audits. During these audits they review and
report on the effectiveness of the internal controls and make recommendations
for improvement.
The independent accounting firms of PricewaterhouseCoopers LLP, Deloitte &
Touche LLP and Arthur Andersen LLP are engaged to provide an objective,
independent audit of Motiva's financial statements. Their accompanying report is
based on an audit conducted in accordance with auditing standards generally
accepted in the United States, which includes obtaining an understanding of
Motiva's internal controls sufficient to plan the audit and determine the
nature, timing and extent of their audit tests.
The Audit Committee of the Board of Directors is comprised of three non-employee
directors who review and evaluate Motiva's accounting policies and reporting,
internal controls, internal audit program and other matters as deemed
appropriate. The Audit Committee also reviews the performance of
PricewaterhouseCoopers LLP, Deloitte & Touche LLP and Arthur Andersen LLP and
evaluates their independence and professional competence, as well as the results
and scope of their audit.
R. L. Ebert W. M. Kaparich Randy J. Braud
President and Chief Executive Officer Chief Financial Officer Controller
1
REPORT OF INDEPENDENT ACCOUNTANTS
The Board of Directors of Motiva Enterprises LLC:
We have audited the accompanying balance sheets of Motiva Enterprises LLC
("Motiva") as of December 31, 2000 and 1999, and the related statements of
income, owners' equity and cash flows for the years ended December 31, 2000 and
1999 and the six months ended December 31, 1998. These financial statements are
the responsibility of Motiva's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. 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, the financial statements referred to above present fairly, in
all material respects, the financial position of Motiva Enterprises LLC as of
December 31, 2000 and 1999, and the results of its operations and its cash flows
for the years ended December 31, 2000 and 1999 and the six months ended December
31, 1998 in conformity with accounting principles generally accepted in the
United States.
Arthur Andersen LLP
Deloitte & Touche LLP
PricewaterhouseCoopers LLP
Houston, Texas
March 1, 2001
2
MOTIVA ENTERPRISES LLC
STATEMENTS OF INCOME
For the
For the Six Months
Years Ended Ended
December 31, December 31,
----------------------------
2000 1999 1998
------------- ------------- ----------------
(Millions of dollars)
REVENUES
Sales and other revenue $ 19,446 $ 12,196 $ 5,371
COSTS AND EXPENSES
Purchases and other costs 15,965 9,809 4,079
Operating expenses 1,483 1,108 512
Selling, general and administrative expenses 969 805 464
Depreciation and amortization 372 378 174
Interest expense 115 94 43
Taxes other than income taxes 81 71 21
--------- --------- --------
Total costs and expenses 18,985 12,265 5,293
NET INCOME (LOSS) $ 461 $ (69) $ 78
========= ========== ========
The accompanying Notes to Financial Statements are an integral part of these
statements.
3
MOTIVA ENTERPRISES LLC
BALANCE SHEETS
As of December 31,
----------------------------
2000 1999
---------- ----------
(Millions of dollars)
ASSETS
Current Assets
Cash and cash equivalents $ 9 $ 23
Accounts receivable, less allowance for doubtful
accounts of $3 million at December 31, 2000 and 1999 729 574
Accounts receivable from affiliates 48 -
Inventories 560 651
Other current assets 35 23
--------- -------
Total current assets 1,381 1,271
--------- -------
Investments and Advances 68 180
Property, Plant and Equipment
At cost 7,517 7,335
Less accumulated depreciation 2,613 2,361
--------- -------
Net property, plant and equipment 4,904 4,974
--------- -------
Deferred Charges and Other Noncurrent Assets 138 153
--------- -------
Total Assets $ 6,491 $ 6,578
========= =======
LIABILITIES AND OWNERS' EQUITY
Current Liabilities
Commercial paper and current portion of long-term debt $ 352 $ 363
Accounts payable and accrued liabilities 518 377
Accounts payable to affiliates 101 301
Accrued taxes 179 237
--------- -------
Total current liabilities 1,150 1,278
Long-Term Debt and Capital Lease Obligation 1,429 1,451
Long-Term Payables to Affiliates 230 408
Accrued Environmental Remediation Liability 233 221
Deferred Credits and Other Noncurrent Liabilities 125 15
--------- -------
Total Liabilities 3,167 3,373
--------- -------
Owners' Equity 3,324 3,205
--------- -------
Total Liabilities and Owners' Equity $ 6,491 $ 6,578
========= =======
The accompanying Notes to Financial Statements are an integral part
of these statements.
4
MOTIVA ENTERPRISES LLC
STATEMENTS OF CASH FLOWS
For the
For the Six Months
Years Ended Ended
December 31, December 31,
----------------------------
2000 1999 1998
------------- ------------- ----------------
(Millions of dollars)
OPERATING ACTIVITIES
Net income (loss) $ 461 $ (69) $ 78
Reconciliation to net cash provided by operating activities:
Depreciation and amortization 372 378 174
(Gain) loss on sale of assets (26) (13) 1
Changes in operating working capital
Accounts receivable (203) 92 (42)
Inventories 91 41 (39)
Other current assets (12) 60 (35)
Accounts payable and accrued liabilities (177) 72 (71)
Other - net 103 (16) 4
------- -------- ------
Net cash provided by operating activities 609 545 70
------- ------- ------
INVESTING ACTIVITIES
Capital expenditures (376) (310) (182)
Proceeds from sale of assets 114 41 13
------- ------- ------
Net cash used in investing activities (262) (269) (169)
-------- -------- -------
FINANCING ACTIVITIES
Proceeds from borrowings 762 417 1,278
Repayment of debt (795) (495) (911)
Distributions to owners (328) (200) (243)
-------- -------- -------
Net cash provided by (used in) financing activities (361) (278) 124
-------- -------- ------
CASH AND CASH EQUIVALENTS
Increase (decrease) during the period (14) (2) 25
Beginning of period 23 25 -
------- ------- ------
End of period $ 9 $ 23 $ 25
======= ======= ======
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid during the period $ 131 $ 84 $ 43
======= ======= ======
The accompanying Notes to Financial Statements are an integral part of
these statements.
5
MOTIVA ENTERPRISES LLC
STATEMENTS OF OWNERS' EQUITY
(Millions of dollars)
INITIAL OWNERS' CAPITAL CONTRIBUTION, JULY 1, 1998 $ 3,993
Net income 78
Distributions (243)
--------------
BALANCE AT DECEMBER 31, 1998 3,828
Contributed liabilities:
Employee benefit obligation from owners (Note 10) (337)
Other (17)
Net loss (69)
Distributions (200)
--------------
BALANCE AT DECEMBER 31, 1999 3,205
Net income 461
Distributions:
Cash (328)
Property (14)
--------------
BALANCE AT DECEMBER 31, 2000 $ 3,324
=============
The accompanying Notes to Financial Statements are an integral part
of these statements.
6
MOTIVA ENTERPRISES LLC
NOTES TO FINANCIAL STATEMENTS
NOTE 1 - ORGANIZATION
Motiva Enterprises LLC (Motiva) is a joint venture combining the major elements
of Shell Oil Company (Shell), Texaco Inc. (Texaco) and Saudi Aramco's Gulf and
East Coast U.S. refining and marketing businesses. Motiva is a limited liability
company established by Shell Norco Refining Company (Shell Norco), Shell, Texaco
Refining and Marketing (East) Inc. (TRMI East) and Saudi Refining Inc. (SRI)
effective July 1, 1998 under the Delaware Limited Liability Company Act. On
December 7, 1998, the ownership in Motiva attributable to Shell Norco and Shell
was transferred to SOPC Holdings East LLC, a wholly owned subsidiary of Shell.
In accordance with the Limited Liability Company Agreement (the "Agreement"),
initial provisional ownership percentages were 35% for Shell Norco and Shell
together and 32.5% for each of TRMI East and SRI, effective through the first
full fiscal year. Also in accordance with the Agreement, subsequent provisional
ownership percentages will be determined for Motiva's second through seventh
full fiscal years and final ownership percentages will be determined for
Motiva's eighth full fiscal year. The calculation of provisional ownership
percentages for Motiva's second full fiscal year resulted in ownership
percentages of 38.812 % for SOPC Holdings East LLC and 30.594% for each of TRMI
East and SRI.
A second joint venture company, Equilon Enterprises LLC (Equilon), was formed on
January 1, 1998, combining the major elements of Shell and Texaco's Western and
Midwestern U.S. refining and marketing businesses and their nationwide trading,
transportation and lubricants businesses. Equiva Trading Company (Equiva
Trading) and Equiva Services LLC (Equiva Services) were formed on July 1, 1998
and are owned equally by Motiva and Equilon. Equiva Trading functions as the
trading unit for both Motiva and Equilon. Equiva Services provides common
financial, administrative, technical and other operational support to both
Motiva and Equilon. Equiva Trading and Equiva Services bill their services at
cost.
Motiva refines, distributes and markets petroleum products under both the Shell
and Texaco brands through its network of wholesalers, retailers and company
owned and contractor operated service stations in all or part of 26 states and
the District of Columbia. Products are manufactured at four refineries located
in Delaware City, Delaware; Convent, Louisiana; Norco, Louisiana; and Port
Arthur, Texas.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis Of Presentation
Effective July 1, 1998, Shell Norco, Shell, TRMI East and SRI contributed assets
and liabilities to Motiva pursuant to the terms of the Asset Transfer and
Liability Assumption Agreement, one of the joint venture agreements establishing
Motiva. TRMI East and SRI contributed the assets and liabilities of Star
Enterprise (Star). The accompanying financial statements are presented using the
historical basis of the assets and liabilities contributed to Motiva on July 1,
1998.
7
MOTIVA ENTERPRISES LLC
NOTES TO FINANCIAL STATEMENTS
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
Use Of Estimates
These financial statements are prepared in conformity with accounting principles
generally accepted in the United States, which require management to make
estimates and assumptions. These assumptions affect the reported amounts of
assets and liabilities and the disclosure of contingent assets and liabilities
at the date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Significant estimates include the
recoverability of assets, environmental remediation, litigation and claims and
assessments. Amounts are recognized when it is probable that an asset has been
impaired or a liability has been incurred and the cost can be reasonably
estimated. Actual results could differ from those estimates.
Revenues
Revenues for refined products and crude oil sales are recognized at the point of
passage of title specified in the contract.
Cash Equivalents
Cash equivalents consist of highly liquid investments with a maturity of three
months or less when purchased.
Inventories
All inventories are valued at the lower of cost or market, after initial
recording at cost. The cost of inventories of crude oil and petroleum products
is determined on the last-in, first-out (LIFO) method, while the cost of other
merchandise inventories is determined on the first-in, first-out (FIFO) method,
and materials and supplies are stated at average cost.
Property, Plant And Equipment
Depreciation of property, plant and equipment is provided generally on composite
groups, using the straight-line method, with depreciation rates based upon the
estimated useful lives of the groups.
Under the composite depreciation method, the cost of partial retirements of a
group is charged to accumulated depreciation. However, when there is a
disposition of a complete group, the cost and related depreciation are retired,
and any gain or loss is reflected in earnings.
Capitalized leases are amortized over the estimated useful life of the asset or
the lease term, as appropriate, using the straight-line method.
Maintenance and repairs, including major refinery maintenance, are charged to
expense as incurred. Renewals, betterments and major repairs that materially
extend the life of the properties are capitalized.
Interest incurred during the construction period of major additions is
capitalized.
The evaluation of impairment for property, plant and equipment is based on a
comparison of carrying value against undiscounted future net pre-tax cash flows.
If an impairment is identified, the asset's carrying amount is adjusted to fair
value. Assets to be disposed of are generally valued at the lower of net book
value or fair value less cost to sell.
8
MOTIVA ENTERPRISES LLC
NOTES TO FINANCIAL STATEMENTS
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
Investments
Entities where Motiva has greater than 50 percent ownership but as a result of
contractual agreement or otherwise does not exercise control, are accounted for
using the equity method. The equity method of accounting is generally used for
investments in certain affiliates owned 50 percent or less, including corporate
joint ventures, limited liability companies and partnerships. Under this method,
equity in pre-tax income or losses of limited liability companies and
partnerships, and the net income or losses of corporate joint venture companies
is reflected in income, rather than when realized through dividends or
distributions. Other investments are carried at cost.
Environmental Expenditures
Motiva accrues for environmental remediation liabilities when it is probable
that such liability exists, based on past events or known conditions, and the
amount of such loss can be reasonably estimated. If Motiva can only estimate a
range of probable liabilities, the minimum undiscounted expenditure necessary to
satisfy Motiva's future obligation is accrued.
Motiva determines the appropriate amount of each obligation considering all of
the available data, including technical evaluations of the currently available
facts, interpretation of existing laws and regulations, prior experience with
similar sites and the estimated reliability of financial projections.
Motiva adjusts financial liabilities, as required, based on the latest
experience with similar sites, changes in environmental laws and regulations or
their interpretation, development of new technology or new information related
to the extent of Motiva's obligation.
New Accounting Standards
In June 1998, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 133). SFAS 133 establishes new
accounting rules and disclosure requirements for most derivative instruments and
hedging activities. In June 1999, the FASB issued SFAS 137 that deferred the
effective date of adoption of SFAS 133 for one year. This was followed in June
2000 by the issuance of SFAS 138, "Accounting for Certain Derivative Instruments
and Certain Hedging Activities," which amended SFAS 133.
SFAS 133, as amended by SFAS 137 and SFAS 138, requires Motiva to record all
derivative financial instruments in the Balance Sheets at fair value. For
derivatives accounted for as hedges, fair value adjustments are recorded to
earnings or to other comprehensive income, depending upon the type of hedge and
the degree of hedge effectiveness. For hedges classified as fair value hedges,
adjustments are also recorded to the carrying amount of the hedged item through
earnings. For derivatives not accounted for as hedges, fair value adjustments
are recorded to earnings.
Motiva adopted these standards effective January 1, 2001. As such, Motiva's
results of operations and financial position will reflect the impact of the new
standards commencing January 1, 2001. The cumulative effect of adoption at that
date on net income and other comprehensive income, a component of owners'
equity, was not material.
9
MOTIVA ENTERPRISES LLC
NOTES TO FINANCIAL STATEMENTS
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
New Accounting Standards (continued)
In September 2000, the FASB issued Statement of Financial Accounting Standards
No. 140, "Accounting for Transfers and Servicing of Financial Assets and
Extinguishments of Liabilities - a replacement of FASB 125" (SFAS 140). For
Motiva, SFAS 140 is effective for transfers and servicing of financial assets
and extinguishment of liabilities occurring after March 31, 2001. Certain
disclosure requirements under SFAS 140 are effective for financial statements
for fiscal years ended after December 15, 2000 and have been included in Note 4.
Motiva does not believe the effects of the adoption of SFAS 140 will be material
to its financial position or the results of operations.
Derivatives
Motiva uses interest rate swap derivative financial transactions to manage its
exposure to changes in interest rates. Amounts receivable or payable based on
the interest rate differentials of interest rate swaps are accrued monthly and
are reflected in interest expense.
Motiva uses futures, purchased options and swaps to hedge the effects of
fluctuations in the prices of crude oil and refined products. Unrealized gains
and losses on such transactions are deferred and recognized in income when the
transactions and cash are settled. Motiva also uses written options. The
unrealized gains and losses on these transactions are recognized in current
earnings.
Fair Value Of Financial Instruments
The estimated fair value of long-term debt is disclosed in Note 7 to the
financial statements. The carrying amount of long-term debt with variable rates
of interest approximates fair value at December 31, 2000 and 1999 as borrowing
terms equivalent to the stated rates were available in the marketplace. Fair
value for long-term debt with a fixed rate of interest and interest rate swaps
is determined based on discounted cash flows using estimated prevailing interest
rates.
Other financial instruments are included in current assets and liabilities on
the balance sheet and approximate fair value because of the short maturity of
such instruments. These include cash, short-term investments, notes and accounts
receivable, accounts payable and short-term debt.
Contingencies
Certain conditions may exist as of the date financial statements are issued,
which may result in a loss to Motiva, but which will be resolved only when one
or more future events occur or fail to occur. Motiva's management and legal
counsel assess such contingent liabilities. The assessment of loss contingencies
necessarily involves an exercise of judgment and is a matter of opinion. In
assessing loss contingencies related to legal proceedings that are pending
against Motiva or unasserted claims that may result in such proceedings,
Motiva's legal counsel evaluates the perceived merits of any legal proceeding or
unasserted claims as well as the perceived merits of the amount of relief sought
or expected to be sought therein.
10
MOTIVA ENTERPRISES LLC
NOTES TO FINANCIAL STATEMENTS
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
Contingencies (continued)
If the assessment of a contingency indicates that it is probable that a material
liability has been incurred and the amount of the loss can be estimated, then
the estimated liability would be accrued in Motiva's financial statements. If
the assessment indicates that a potentially material liability is not probable,
but is reasonably possible, or is probable but cannot be estimated, then the
nature of the contingent liability, together with an estimate of the range of
possible loss if determinable and material would be disclosed.
Loss contingencies considered remote are generally not disclosed unless they
involve guarantees, in which case the nature of the guarantee would be
disclosed. However, in some instances in which disclosure is not otherwise
required, Motiva may disclose contingent liabilities of an unusual nature which,
in the judgment of management and its legal counsel, may be of interest to the
owners or others.
NOTE 3 - TRANSACTIONS WITH RELATED PARTIES
Motiva has entered into transactions with Shell, Texaco, SRI, Equilon, Equiva
Services, and Equiva Trading, including the affiliates of these companies. Such
transactions are in the ordinary course of business and include the purchase,
sale and transportation of crude oil and petroleum products and numerous service
agreements.
The aggregate amounts of such transactions were as follows:
For the
For the Six Months
Years Ended Ended
December 31, December 31,
----------------------------
2000 1999 1998
------------- ------------- ----------------
(Millions of dollars)
Sales and other revenue $ 3,195 $ 1,701 $ 857
Purchases and transportation 9,548 5,602 2,642
Service and technology expense 402 659 297
NOTE 4 - SALE OF RECEIVABLES
Motiva has a third-party accounts receivable agreement under which it has the
right to sell up to $200 million of trade accounts receivable on a continuing
basis subject to limited recourse. Receivables sold under this facility totaled
$1,066 million in 2000 and $403 million in 1999. The discount recorded on sales
of trade receivables amounted to $3 million in 2000, $1 million in 1999 and $1
million for the six months ended December 31, 1998.
11
MOTIVA ENTERPRISES LLC
NOTES TO FINANCIAL STATEMENTS
NOTE 5 - INVENTORIES
As of December 31,
----------------------------
2000 1999
---------- ----------
(Millions of dollars)
Crude oil and petroleum products $ 473 $ 558
Other merchandise 15 13
Materials and supplies 72 80
--------- -------
Total $ 560 $ 651
========== ========
At December 31, 2000 and 1999, the excess of market value over the LIFO carrying
value of crude oil and petroleum products inventories was approximately $638
million and $147 million, respectively.
Partial liquidation of inventories valued on a LIFO basis improved net income by
$8 million in 2000 and $23 million in 1999.
NOTE 6 - PROPERTY, PLANT AND EQUIPMENT
As of December 31,
------------------------------------------------------
2000 1999
------------------------- ------------------------
Gross Net Gross Net
--------- ---------- ---------- ---------
(Millions of dollars)
Refining $ 4,760 $ 2,936 $ 4,583 $ 2,967
Marketing 2,757 1,968 2,752 2,007
---------- ----------- ----------- ---------
Total $ 7,517 $ 4,904 $ 7,335 $ 4,974
========== =========== =========== =========
Capital lease amounts included above $ 24 $ 10 $ 24 $ 11
========== =========== =========== =========
Interest expense capitalized as part of property, plant and equipment amounted
to $8 million in 2000, $6 million in 1999 and $4 million for the six months
ended December 31, 1998.
12
MOTIVA ENTERPRISES LLC
NOTES TO FINANCIAL STATEMENTS
NOTE 7 - DEBT
Short-Term
Debt due within one year consisted of the following:
As of December 31,
----------------------------
2000 1999
---------- ----------
(Millions of dollars)
Commercial paper and extendible commercial notes $ 1,076 $ 1,133
Pollution control revenue bonds 329 304
--------- -------
1,405 1,437
Current maturities of long-term debt and capital lease obligation 47 1
--------- -------
1,452 1,438
Less: Short-term obligations intended to be refinanced:
Commercial paper 900 900
Pollution control revenue bonds 200 175
--------- -------
Total $ 352 $ 363
========= =======
The weighted average interest rates for the commercial paper and extendible
commercial notes outstanding at December 31, 2000 and 1999 were 6.63% and 5.99%,
respectively.
The pollution control revenue bonds outstanding at December 31, 2000 and 1999
include five individual issues assumed from Shell totaling $129 million.
Interest rates are currently reset on a daily basis for four of those issues and
on a weekly basis for the remaining issue; the bonds may be converted from time
to time to other modes. The weighted average interest rates for those issues at
December 31, 2000 and 1999 were 5.07% and 5.29%, respectively. The bonds mature
between 2005 and 2023, although bondholders have the right to tender their bonds
under certain conditions, including on interest rate resets. Pursuant to the
terms of the underlying indentures, Shell retains liability for debt service on
the issues Motiva assumed from Shell in the event that Motiva fails to perform
its obligations.
Of the remaining $200 million in pollution control revenue bonds at December 31,
2000, $158 million have interest rates currently reset on a weekly basis and the
other $42 million are marketed in a commercial paper mode. Any or all of these
bonds may also be converted from time to time to other modes. Weighted average
interest rates for the bonds reset weekly at December 31, 2000 and 1999 were
5.22% and 5.46%, respectively. For the issue marketed in a commercial paper
mode, the weighted average interest rates at December 31, 2000 and 1999 were
6.72% and 6.03%, respectively. The bonds mature between 2014 and 2029, although
bondholders have the right to tender their bonds under certain conditions,
including on interest rate resets or commercial paper maturity. These bonds, as
well as $900 million of Motiva's commercial paper and extendible commercial note
obligations scheduled to mature in 2001, are reclassified to long-term debt at
December 31, 2000, recognizing Motiva's intent and ability to refinance those
issues on a long-term basis, if necessary, through the use of its $1.5 billion
revolving credit facility.
Motiva has entered into borrowing agreements with a number of financial
institutions to obtain funds on an "as available" basis at negotiated rates. The
maximum amounts outstanding under these agreements during 2000 and 1999 were
$100 million and $84 million, respectively. These facilities were unused as of
December 31, 2000 and 1999.
13
MOTIVA ENTERPRISES LLC
NOTES TO FINANCIAL STATEMENTS
NOTE 7 - DEBT (continued)
Long-Term
Long-term debt consisted of the following:
As of December 31,
----------------------------
2000 1999
---------- ----------
(Millions of dollars)
Private placements $ 360 $ 360
Capital lease obligation 16 17
--------- -------
376 377
Less: Amounts due within one year 47 1
--------- -------
329 376
Add: Short-term obligations intended to be refinanced:
Commercial paper 900 900
Pollution control revenue bonds 200 175
--------- -------
Total $ 1,429 $ 1,451
========= =======
At December 31, 2000 and 1999, Motiva was party to a $1.5 billion extendible
364-day revolving credit facility with a syndicate of major U.S. and
international banks. This facility, originally established in 1998 and renewed
most recently in October 2000, is available as support for the issuance of
Motiva's commercial paper and certain of its pollution control revenue bonds, as
well as for working capital and for other general corporate purposes. Motiva had
no amounts outstanding under this facility during 2000 or 1999. Motiva pays a
facility fee based on its total amount. Under this agreement, interest on any
amounts borrowed would be based on short-term rates at the time of borrowing.
Private placements of $360 million at December 31, 2000 and 1999 were assumed
from Star, and consist of $110 million and $250 million issued to various
insurance companies in 1991 and 1992, respectively. All of the notes carry fixed
interest rates; the weighted average interest rates were 8.6% for the 1991 issue
and 7.6% for the 1992 issue. These notes have varying maturities lasting until
the year 2009.
All of Motiva's borrowings are unsecured and with the exception of the pollution
control revenue bonds assumed from Shell, are non-recourse to the owners.
Long-term debt borrowing agreements include financial covenants regarding net
worth, leverage and liens.
The amounts of long-term debt maturities during each of the next five years are
$45 million, $63 million, $65 million, $35 million and $0 million, respectively.
The preceding maturities are before consideration of short-term obligations
intended to be refinanced and also exclude the capital lease obligation.
14
MOTIVA ENTERPRISES LLC
NOTES TO FINANCIAL STATEMENTS
NOTE 7 - DEBT (continued)
Fair Value Of Financial Instruments
The estimated fair values of Motiva's long-term debt and related derivative
financial instruments were as follows:
As of December 31,
------------------------------------------------------
2000 1999
------------------------- ------------------------
Carrying Fair Carrying Fair
Value Value Value Value
--------- ---------- ---------- ---------
(Millions of dollars)
Long-term debt $ 1,429 $ 1,448 $ 1,451 $ 1,460
Interest rate swaps - - - (1)
NOTE 8 - DERIVATIVES
Debt-Related Derivatives
Many of Motiva's interest-bearing liabilities reflected on its balance sheets
are floating rate instruments. To reduce the impact of changes in interest rates
on this floating rate debt, Motiva assumed certain interest rate swap agreements
in the notional amount of $100 million previously entered into by Star. All such
interest rate swaps required the counterparty of the swap to pay to Motiva a
floating rate of interest on notional amounts of principal, and for Motiva to
pay to the counterparty a fixed rate of interest on the same amounts of notional
principal. In all cases, Motiva remains obligated to pay the variable rate owing
to the holder of the underlying obligations. One swap with a notional amount of
$20 million remained outstanding at December 31, 2000, and matured on February
5, 2001.
Each party to any interest rate swap agreement is exposed to credit risk for
nonperformance of the other party. Motiva had such exposure prior to the
maturity of the final swap agreement, but did not experience nonperformance by
counterparties.
Commodity Derivatives
Motiva utilizes futures, purchased options and swaps to hedge the effects of
fluctuations in the prices of crude oil and refined products. These transactions
meet the requirements for hedge accounting. The resulting gains or losses,
measured by quoted market prices, are accounted for as part of the transactions
being hedged. On the balance sheet, deferred gains and losses are included in
current assets and liabilities. Motiva also uses written options to manage its
price risk. Written options do not meet the requirement for hedge accounting.
Accordingly, these transactions are marked to market and recognized in income
monthly.
At December 31, 2000 and 1999, Motiva had open derivative commodity contracts
required to be settled in cash, consisting mostly of futures. Notional contract
amounts were $200 million and $192 million at December 31, 2000 and 1999,
respectively. These amounts principally represent future values of contract
volumes over the remaining duration of outstanding futures contracts at the
respective dates. These contracts hedge a small fraction of Motiva's business
activities, generally for periods within the next twelve months.
15
MOTIVA ENTERPRISES LLC
NOTES TO FINANCIAL STATEMENTS
NOTE 8 - DERIVATIVES (continued)
Commodity Derivatives (continued)
A significant factor impacting earnings during both 2000 and 1999 was the rapid
increase in crude oil prices and market volatility. As a result, Motiva realized
positive impacts to earnings through increased refining margins associated with
the holding period for inventory.
Unrealized gains on open hedging positions at December 31, 2000 and 1999 were
not significant. The earnings impact of closed hedging positions along with open
and closed written options was a loss of $132 million and $89 million for the
years ended December 31, 2000 and 1999, respectively, and was not significant
for the six months ended December 31, 1998. The favorable impact of refining
margins in 2000 and 1999 associated with the holding period for inventory was
offset by the impact of hedging.
On January 1, 2001, Motiva adopted SFAS 133 as amended by SFAS 137 and SFAS 138.
Motiva's results of operations and financial position will reflect the impact of
the new standard commencing January 1, 2001. The cumulative effect of adoption
at that date on net income and other comprehensive income, a component of
owners' equity, was not material.
NOTE 9 - LEASE COMMITMENTS AND RENTAL EXPENSE
Motiva has leasing arrangements involving service stations and other facilities.
Renewal and purchase options are available on certain of these leases in which
Motiva is lessee.
Motiva has a one-year lease agreement, which began in April 2000 for a
cogeneration plant constructed in proximity to Motiva's Delaware City refinery.
The lease may be renewed at Motiva's option for seventeen consecutive one-year
terms. Motiva has renewed the lease for the second one-year term beginning in
April 2001. The minimum lease commitment for any twelve-month period is
approximately $20 million (not included in the table below). Total project
expenditures are approximately $352 million. At the end of any one-year lease
term, if not renewed, Motiva has guaranteed a minimum recoverable residual value
to the lessor of approximately 89 percent of the total project construction
cost.
16
MOTIVA ENTERPRISES LLC
NOTES TO FINANCIAL STATEMENTS
NOTE 9 - LEASE COMMITMENTS AND RENTAL EXPENSE (continued)
As of December 31, 2000, Motiva had estimated minimum commitments for payment of
rentals under leases, which, at inception, had a noncancelable term of more than
one year, as follows:
Operating Capital
Leases Leases
-------------- ---------------
(Millions of dollars)
2001 $ 50 $ 4
2002 48 4
2003 45 4
2004 43 4
2005 38 4
After 2005 408 6
---------- ----------
Total lease commitments $ 632 26
==========
Less amounts representing interest 10
----------
Present value of total capital lease obligation 16
Less current portion of capital lease obligation 2
----------
Present value of long-term portion of capital lease obligation $ 14
==========
Rental expense relative to operating leases, including contingent rentals, is
provided in the table below:
For the
For the Six Months
Years Ended Ended
December 31, December 31,
----------------------------
2000 1999 1998
------------- ------------- ----------------
(Millions of dollars)
Rental expense:
Minimum lease rentals $ 95 $ 74 $ 52
Contingent rentals 1 2 5
--------- --------- ----------
Total 96 76 57
Less rental income on properties subleased to others 47 48 25
--------- --------- ----------
Net rental expense $ 49 $ 28 $ 32
========= ======== ==========
17
MOTIVA ENTERPRISES LLC
NOTES TO FINANCIAL STATEMENTS
NOTE 10 - AFFILIATE OBLIGATIONS AND CONTRIBUTED LIABILITIES
On April 1, 1999, Shell, Texaco and Star employees designated as performing
duties supporting Motiva were transferred to Equiva Services. At that time
certain benefit liabilities were transferred to Equiva Services from Shell,
Texaco and Star through their interests in Motiva and Equilon. Equiva Services'
obligations transferred from Shell, Texaco and Star applicable to Motiva were
recorded as reductions to Motiva's investment in Equiva Services. A related
party obligation of $440 million at December 31, 1999 represented Motiva's
obligation to Equiva Services for these employee benefit liabilities. Of this
amount, $408 million was classified as long-term at December 31, 1999. On
January 1, 2000, Equiva Services employees supporting Motiva and Equiva Trading
became employees of the respective companies they support. Employee related
benefit liabilities were transferred to Motiva, and through Motiva to Equiva
Trading, at the same time. As a result of the transfer, Motiva's related party
obligation to Equiva Services was reduced by $401 million. As a result of this
transfer, the post-employment benefits and vacation obligations became direct
liabilities of Motiva, and at December 31, 2000 were in the amounts of $98
million and $25 million respectively. Further, the pension liability became
payable to the owners on January 1, 2000 and at December 31, 2000 was $230
million. As of December 31, 2000, Motiva had affiliate payables to Equiva
Services and Equiva Trading totaling $56 million, representing its obligation
for employee benefit liabilities of these entities. Of this amount, $48 million
was classified as long-term.
The foregoing contribution of liabilities that were transferred from Shell,
Texaco, and Star through Motiva to Equiva Services for employee benefit
liabilities at April 1, 1999 was $337 million and included $202 million for
pension related affiliate obligations, $110 million of post employment medical
benefits and $25 million for vacation benefits. Additional information is
disclosed in Note 11.
NOTE 11 - EMPLOYEE BENEFIT PLANS
In accordance with certain joint venture agreements related to human resources
matters, employees performing duties supporting Motiva remained employees of the
owner companies and their affiliates until April 1, 1999. Beginning April 1,
1999, Motiva's affiliate, Equiva Services, employed personnel necessary for
ongoing operations. Obligations and accrued liabilities for certain employee
benefits, including pension and other post-employment benefits, were transferred
to Equiva Services at that time.
On January 1, 2000, employees directly supporting Motiva became employees of
Motiva. Employees providing common crude and product logistical and trading
support for both Motiva and Equilon became employees of Equiva Trading.
Employees providing common financial, administrative, technical and other
operational support to both Motiva and Equilon remain employees of Equiva
Services. Employee related obligations, including liabilities for pension and
other post-employment benefits for employees transferred to Motiva, were
recorded as Motiva liabilities on January 1, 2000 with a corresponding reduction
in the affiliate payable to Equiva Services. Employee related liabilities for
employees transferred from Equiva Services to Equiva Trading were transferred to
Equiva Trading through Motiva and Equilon. Motiva's share of these liabilities
was recorded as a long-term affiliate payable to Equiva Trading.
18
MOTIVA ENTERPRISES LLC
NOTES TO FINANCIAL STATEMENTS
NOTE 11 - EMPLOYEE BENEFIT PLANS (continued)
Pension Related Affiliate Obligations
Concurrently with their transfer from the owner companies, employees retained
certain pension benefits for future pay increases under the owner company
pension plans. Under agreements with Shell, Texaco and SRI, the owner companies
will be reimbursed for past service pension benefits attributable to these
future pay benefits at April 1, 1999, as well as future increases in the related
projected benefit obligation under the owner companies' qualified pension plans.
These reimbursements will be made at the time employees receive benefits from
owner company plans. The following summarizes the reimbursement owed to the
owner companies and components of accrual expense:
2000 1999 (a)
-------------- ---------------
(Millions of dollars)
Projected benefit obligation at January 1, 2000 and April 1, 1999 $ 143 $ 148
Interest cost 12 8
Actuarial gain (6) (13)
-------- -------
Projected benefit obligation at December 31 149 143
Unrecognized net gain 18 13
-------- -------
Accrued past service pension liability at December 31 $ 167 $ 156
======== =======
Weighted average assumptions at December 31
Discount rate 7.5% 8.0%
Rate of compensation increase 4.0% 4.5%
Components of net accrual expense
Interest cost $ 11 $ 8
======== =======
(a) Represents amounts applicable to Equiva Services employees working on
behalf of Motiva for the nine-month period from April 1, 1999 to December
31, 1999.
Post-Employment Benefits
Motiva and Equiva Services currently provide health care benefits for retired
employees and their dependents through a common plan. Eligibility for such
benefits requires that a retired employee be at least 50 years of age, with at
least 10 years of service and the sum of age and service of at least 70 years.
Past service with the owner companies is credited for determining benefit
eligibility.
Motiva's obligation is a percentage of the total premiums required. This
percentage varies from 60% to 80% of total cost depending on the sum of the
employee's total years of age plus service at the time of retirement. The
assumed annual health care cost trend rate used in measuring the accumulated
post-employment benefit obligation (APBO) was 9.0% in 2000, decreasing to 5.0%
by 2008 and remaining at that level thereafter. Assuming a 1% increase in the
annual rate of increase of required medical premiums, the APBO and annual
expense would increase by approximately $19 million and $1 million,
respectively.
19
MOTIVA ENTERPRISES LLC
NOTES TO FINANCIAL STATEMENTS
NOTE 11 - EMPLOYEE BENEFIT PLANS (continued)
Post-Employment Benefits (continued)
In addition to medical benefits, Motiva and Equiva Services provide retiree life
insurance benefits to certain employees who transferred from Texaco and Star.
These employees must be of age 50 at April 1, 1999 with 5 years of service at
the time of transfer and retire at a minimum age of 55 with at least 10 years of
service in order to be eligible. Net post-employment benefit costs for 2000 and
for the period of April 1, 1999 to December 31, 1999 were as follows:
2000 1999 (b)
-------------- ---------------
(Millions of dollars)
Service cost $ 2 $ 2
Interest cost 6 5
Amortization of prior service cost (2) (2)
--------- -------
Accrued expense $ 6 $ 5
======== ======
(b) Represents amounts applicable to Equiva Services employees working on
behalf of Motiva for the nine-month period from April 1, 1999 to December
31, 1999.
The status of other post-employment plans as of December 31, 2000 and 1999 was
as follows:
2000 1999 (c)
-------------- ---------------
(Millions of dollars)
Benefit obligation at January 1, 2000 and April 1, 1999 $ 71 $ 75
Service cost 2 2
Interest cost 6 4
Actuarial (gain)/loss 22 (10)
--------- -------
Benefit obligation at December 31 101 71
Unrecognized prior service cost 20 22
Unrecognized gain/(loss) (23) -
--------- -------
Accrued post-employment benefit obligation at December 31 $ 98 $ 93
========= =======
(c) Represents amounts applicable to Equiva Services employees working on
behalf of Motiva for the nine-month period from April 1, 1999 to December
31, 1999.
Pension Plans
Effective April 1, 1999, Equiva Services established a cash balance defined
benefit pension plan covering substantially all of its employees. Company
contributions under the plan are between 3% and 7% of compensation based on
years of service, age, and covered compensation. Individual employee accounts
are credited each month with employer contributions and interest on the account
balance at an interest rate adjusted quarterly. Currently the interest rate is
5.80% per annum. Assets of the plan are comprised of equity securities and fixed
income securities. Motiva and Equiva Services' funding policy is to contribute
all pension costs accrued to the extent required by federal tax regulations.
20
MOTIVA ENTERPRISES LLC
NOTES TO FINANCIAL STATEMENTS
NOTE 11 - EMPLOYEE BENEFIT PLANS (continued)
Pension Plans (continued)
The following table sets forth information related to changes in the benefit
obligations, change in plans assets, a reconciliation of the funded status of
the plans and components of the expense recognized related to Motiva's pension
plan.
As of December 31,
-------------------------------
2000 1999 (d)
-------------- ---------------
(Millions of dollars)
Change in benefit obligation
Projected benefit obligation at January 1, 2000 and April 1, 1999 $ 10 $ -
Service cost 14 11
Interest cost 1 -
Actuarial gain - (1)
Benefits paid (1) -
---------- ----------
Projected benefit obligation at December 31 $ 24 $ 10
=========== ==========
Change in plan assets
Fair value of plan assets at January 1, 2000 and April 1, 1999 $ - $ -
Actual return on plan assets, net of expenses (1) (1)
Employer contributions 12 1
Benefits paid (1) -
---------- ----------
Fair value of plan assets at December 31 $ 10 $ -
========== ==========
Funded status at December 31
Obligation greater than assets $ 14 $ 10
Unrecognized net gain/(loss) (1) -
----------- ----------
Accrued pension liability at December 31 $ 13 $ 10
========== ==========
Weighted average assumptions at December 31
Discount rate 7.5% 8.0%
Expected return on plan assets 9.0% 9.0%
Rate of compensation increase 4.0% 4.5%
Components of net periodic benefit costs
Service cost $ 14 $ 11
Interest cost 1 -
---------- ----------
Net periodic benefit costs $ 15 $ 11
========== ==========
(d) Represents amounts applicable to Equiva Services employees working on
behalf of Motiva for the nine-month period from April 1, 1999 to December
31, 1999.
21
MOTIVA ENTERPRISES LLC
NOTES TO FINANCIAL STATEMENTS
NOTE 11 - EMPLOYEE BENEFIT PLANS (continued)
Employee Termination Benefits
The joint venture agreements provide for Motiva and Equilon to determine the
appropriate staffing levels for their businesses. To the extent those staffing
needs resulted in the elimination of positions from the ranks of Shell, Texaco
and Star, affected employees were entitled to termination benefits provided for
under the benefit plans of the applicable companies. Shell, Texaco and Star, as
the employer companies, are responsible for administering the payment of
benefits under their respective benefit plans. Motiva and Equilon have
reimbursed the employer companies for all costs resulting from the elimination
of positions in accordance with a formula included in the joint venture
agreements.
The formation of Motiva and Equilon resulted in the termination of 1,658
employees. The separations were substantially complete as of December 31, 1999.
In 1998, Motiva recorded a charge of $28 million for its share of reimbursable
severance and other benefit costs as selling, general and administrative
expenses in the Statement of Income. An additional provision of $3 million was
recorded to selling, general and administrative expenses in 1999. Motiva
reimbursed the employer companies $2 million in 2000, $26 million in 1999 and $3
million in 1998 for the termination benefits.
NOTE 12 - CONTINGENT LIABILITIES
Except for environmental obligations, Motiva generally did not assume any
contingent liabilities with respect to events occurring before July 1, 1998.
While it is impossible to ascertain the ultimate legal and financial liability
with respect to many contingent liabilities and commitments (including lawsuits,
claims, guarantees, federal regulations, environmental issues, etc.), Motiva has
accrued amounts related to certain such liabilities. Motiva does not expect that
the aggregate amount of commitments and contingent liabilities in excess of
amounts accrued at December 31, 2000 and 1999, if any, will have a material
effect on the financial position or results of operations of Motiva.
NOTE 13 - TAXES
Motiva, as a limited liability company, is not liable for income taxes. Income
taxes are the responsibility of the owners, with earnings of Motiva included in
the owners' earnings for the determination of income tax liability.
Excise taxes collected from consumers for governmental agencies that are not
included in revenues or expenses were $4,200 million in 2000, $3,527 million in
1999 and $2,062 million for the six months ended December 31, 1998.
22
APPENDIX
DESCRIPTION OF GRAPHIC/IMAGE/ILLUSTRATION MATERIAL INCLUDED IN
EXHIBIT 13 - TEXACO INC.'S 2000 ANNUAL REPORT TO STOCKHOLDERS
The following information is depicted in graphic/image/illustration form in
Texaco Inc.'s 2000 Annual Report to Stockholders filed as Exhibit 13 to Texaco
Inc.'s 2000 Annual Report on Form 10-K and all page references included in the
following descriptions are to the actual and complete paper format version of
Texaco Inc.'s 2000 Annual Report to Stockholders as provided to Texaco Inc.'s
stockholders:
This Appendix describes the graphic material contained in the portion of Texaco
Inc.'s 2000 Annual Report to Stockholders which is incorporated by reference
into Texaco Inc.'s 2000 Annual Report on Form 10-K, in response to Form 10-K,
Item 7 - Management's Discussion and Analysis of Financial Condition and Results
of Operations.
1. The first graph is located on Page 28. The bar graph is entitled
"Average Price Per Barrel of West Texas Intermediate (WTI) Crude Oil"
and is reflected in dollars. The average price per barrel of West Texas
Intermediate crude oil, in dollars, for each year are depicted as
follows:
1998 $14.39
1999 $19.31
2000 $30.37
Below the graph a footnote appears which states, "Prices in 2000
reached their highest average level since 1982."
2. The second graph is located on Page 28. The bar graph is entitled
"Average Price Per MCF of U. S. Natural Gas at Henry Hub" and is
reflected in dollars. The average price per MCF of U. S. natural gas
at Henry Hub, in dollars, for each year are depicted as follows:
1998 $2.17
1999 $2.35
2000 $3.99
Below the graph a footnote appears which states, "Prices in 2000
reached record highs."
3. The third graph is located on Page 28. The bar graph is entitled
"Average OPEC Crude Oil Production" and is reflected in millions of
barrels a day. The average OPEC crude oil production, in millions of
barrels a day, for each year are depicted as follows:
1998 27.8
1999 26.5
2000 27.9
Below the graph a footnote appears which states, "OPEC increased
production in 2000 to stabilize prices."
4. The fourth graph is located on Page 29. The bar graph is entitled
"Worldwide Revenues from Sales and Services" and is reflected in
billions of dollars. The worldwide revenues from sales and services, in
billions of dollars, for each year are depicted as follows:
1998 $30.9
1999 $35.0
2000 $50.1
Below the graph a footnote appears which states, "Our revenues in 2000
reflect the run-up in crude oil, refined product and natural gas
prices."
5. The fifth graph is located on Page 31. The bar graph is entitled
"Worldwide Finding and Development Costs Per Barrel of Oil Equivalent"
and is reflected in dollars. The worldwide finding and development
costs per barrel of oil equivalent, in dollars, for each year are
depicted as follows:
1998 $3.45
1999 $4.37
2000 $3.62
Below the graph a footnote appears which states, "Our finding and
development costs remain at competitive levels."
6. The sixth graph is located on Page 32. The bar graph is entitled
"U. S. Lifting Costs Per BOE" and is reflected in dollars. The U.S.
lifting costs per BOE, in dollars, for each year are depicted as
follows:
1998 $4.07
1999 $4.01
2000 $5.05
Below the graph a footnote appears which states, "The increase in our
lifting costs in 2000 reflects the effect of sharply higher oil and gas
prices on utility expenses and production taxes."
7. The seventh graph is located on Page 34. The bar graph is entitled
"International Net Proved Reserves" and is reflected in millions of
barrels of oil equivalent. The
International net proved reserves, in millions of barrels of oil
equivalent, for each year are depicted as follows:
Crude Oil Natural Gas Total
--------- ----------- -----
1998 1,749 402 2,151
1999 1,698 650 2,348
2000 1,958 644 2,602
Below the graph a footnote appears which states, "Net proved reserves
increased in 2000 due to the Hamaca project in Venezuela."
8. The eighth graph is located on Page 34. The bar graph is entitled
"International Upstream Capital and Exploratory Expenditures" and is
reflected in billions of dollars. The International upstream capital
and exploratory expenditures, in billions of dollars, for each year are
depicted as follows:
1998 $1.219
1999 $1.823
2000 $1.967
Below the graph a footnote appears which states, "The growth in
international upstream investments shows our focus on high-impact
projects."
9. The ninth graph is located on Page 37. The bar graph is entitled
"International Refined Product Sales" and is reflected in thousands of
barrels a day. The International refined product sales, in thousands of
barrels a day, for each year and geographical location are depicted as
follows:
Caltex Europe Other LA/WA Total
------ ------ ----- ----- -----
1998 593 571 59 462 1,685
1999 614 606 76 493 1,789
2000 540 636 92 484 1,752
Below the graph a footnote appears which states, "International sales
volumes held steady in 2000."
10. The tenth graph is located on Page 41. The bar graph is entitled
"Capital and Exploratory Expenditures - Geographical" and is reflected
in billions of dollars. Capital and exploratory expenditures, in
billions of dollars, for each year and geographical location are
depicted as follows:
United States International Total
------------- ------------- -----
1998 $2.020 $1.999 $4.019
1999 $1.400 $2.493 $3.893
2000 $1.718 $2.516 $4.234
Below the graph a footnote appears which states, "Our U. S.
expenditures increased by almost 23% in 2000."
11. The eleventh graph is located on Page 41. The bar graph is entitled
"Capital and Exploratory Expenditures - Functional" and is reflected in
billions of dollars. Capital and exploratory expenditures, in billions
of dollars, for each year and function are depicted as follows:
Global gas, power Refining, marketing,
Exploration and and energy distribution
production technology and other Total
---------- ---------- --------- -----
1998 $2.655 $0.185 $1.179 $4.019
1999 $2.723 $0.279 $0.891 $3.893
2000 $3.055 $0.333 $0.846 $4.234
Below the graph a footnote appears which states, "We continued our
emphasis on exploration and production projects, which was 72% of our
spending."
BGM
APPENDIX.doc
INDEX TO EXHIBITS
The exhibits designated by an asterisk are incorporated herein by reference
to documents previously filed by Texaco Inc. with the Securities and Exchange
Commission, SEC File No. 1-27.
Exhibits
(2.1) Agreement and Plan of Merger dated as of October 15, 2000 among Chevron
Corporation, Texaco Inc. and Keepep Inc. (Schedules and Exhibits omitted),
filed as Exhibit 2.1 to Texaco Inc.'s Current Report on Form 8-K, dated
October 16, 2000, incorporated herein by reference, SEC File No. 1-27. *
(2.2) Stock Option Agreement dated as of October 15, 2000 between Chevron
Corporation and Texaco Inc., filed as Exhibit 2.2 to Texaco Inc.'s Current
Report on Form 8-K, dated October 16, 2000, incorporated herein by reference,
SEC File No. 1-27. *
(2.3) Stock Option Agreement dated as of October 15, 2000 between Chevron
Corporation and Texaco Inc., filed as Exhibit 2.3 to Texaco Inc.'s Current
Report on Form 8-K, dated October 16, 2000, incorporated herein by reference,
SEC File No. 1-27. *
(3.1) Copy of Restated Certificate of Incorporation of Texaco Inc., as
amended to and including August 4, 1999, including Certificate of
Designations, Preferences and Rights of Series D Junior
Participating Preferred Stock and Series G, H, I and J Market
Auction Preferred Shares, filed as Exhibit 3.1 to Texaco Inc.'s
Quarterly Report on Form 10-Q for the quarterly period ended June
30, 1999, dated August 12, 1999, incorporated
herein by reference, SEC File No. 1-27. *
(3.2) Copy of By-Laws of Texaco Inc., as amended to and including October
15, 2000, filed as Exhibit 3.2 to Texaco Inc.'s Quarterly Report
on Form 10-Q for the quarterly period ended September 30, 2000,
dated November 9, 2000, incorporated herein by reference, SEC
File No. 1-27. *
(4.1(a)) Form of Amended Rights Agreement, dated as of March 16, 1989, as amended
as of April 28, 1998, between Texaco Inc. and ChaseMellon Shareholder Services, L.L.C.,
as Rights Agent, filed as Exhibit I, pages 40 through 78, of Texaco Inc.'s
proxy statement dated March 17, 1998, incorporated herein by reference, SEC
File No. 1-27. *
(4.1(b)) Form of Amendment No. 1, dated as of October 15, 2000 to the Amended Rights Agreement,
dated as of March 16, 1989, as amended as of April 28, 1998, between Texaco Inc. and
ChaseMellon Shareholder Services, L.L.C., as Rights Agent, filed as Exhibit 2 of Texaco
Inc.'s Amendment No. 1 to Form 8-A, dated October 25, 2000, incorporated herein by
reference, SEC File No. 1-27. *
(10(iii)(a)) Form of severance agreement between Texaco Inc. and elected officers of
Texaco Inc., filed as Exhibit 10(iii)(a) to Texaco Inc.'s Annual Report on
Form 10-K for the year ended December 31, 1998, dated March 25, 1999,
incorporated herein by reference, SEC File No. 1-27. *
(10(iii)(b)) Employment agreement dated December 30, 1997, between Texaco Inc.
and Mr. John J. O'Connor, Senior Vice President of Texaco Inc., filed as
Exhibit 10(iii)(b) to Texaco Inc.'s Annual Report on Form 10-K for the
year ended December 31, 1998, dated March 25, 1999, incorporated herein
by reference, SEC File No. 1-27. *
(10(iii)(c)) Employment agreements dated July 18, 1997, between Texaco Inc. and
Mr. William M. Wicker, Senior Vice President of Texaco Inc., filed as
Exhibit 10(iii)(c) to Texaco Inc.'s Annual Report on Form 10-K
for the year ended December 31, 1998, dated March 25, 1999,
incorporated herein
by reference, SEC File No. 1-27. *
(10(iii)(d)) Texaco Inc.'s 1997 Stock Incentive Plan, incorporated herein by reference
to Appendix A, pages 39 through 44 of Texaco Inc.'s proxy statement
dated March 27, 1997. *
(10(iii)(e)) Texaco Inc.'s 1997 Incentive Bonus Plan, incorporated herein by reference
to Appendix A, pages 45 and 46 of Texaco Inc.'s proxy statement dated
March 27, 1997. *
(10(iii)(f)) Texaco Inc.'s Stock Incentive Plan, incorporated herein by reference to
pages A-1 through A-8 of Texaco Inc.'s proxy statement dated
April 5, 1993. *
(10(iii)(g)) Texaco Inc.'s Stock Incentive Plan, incorporated herein by reference to pages
IV-1 through IV-5 of Texaco Inc.'s proxy statement dated April 10, 1989
and to Exhibit A of Texaco Inc.'s proxy statement dated March 29, 1991. *
(10(iii)(h)) Description of Texaco Inc.'s Supplemental Pension Benefits Plan, incorporated
herein by reference to pages 8 and 9 of Texaco Inc.'s proxy statement dated
March 17, 1981. *
(10(iii)(i)) Description of Texaco Inc.'s Revised Supplemental Pension
Benefits Plan, incorporated herein by reference to pages 24
through 27 of Texaco Inc.'s proxy statement dated March 9, 1978. *
(10(iii)(j)) Description of Texaco Inc.'s Revised Incentive Compensation Plan,
incorporated herein by reference to pages 10 and 11 of Texaco Inc.'s proxy
statement dated March 13, 1969. *
(12.1) Computation of Ratio of Earnings to Fixed Charges of Texaco on a
Total Enterprise Basis.
(12.2) Definitions of Selected Financial Ratios.
(13) Copy of those portions of Texaco Inc.'s 2000 Annual Report to
Stockholders that are incorporated herein by reference into this
Annual Report on Form 10-K.
(21) Listing of significant Texaco Inc. subsidiary companies and the
name of the state or other jurisdiction in which each subsidiary
was organized.
(23.1) Consent of Arthur Andersen LLP.
(23.2) Consent of KPMG (regarding its report on the combined financial
statements of the Caltex Group of Companies).
(23.3) Consent of Arthur Andersen LLP and PricewaterhouseCoopers LLP
(regarding their report on the consolidated financial statements
of Equilon Enterprises LLC).
(23.4) Consent of Arthur Andersen LLP, PricewaterhouseCoopers LLP and
Deloitte & Touche LLP (regarding their report on the financial
statements of Motiva Enterprises LLC).
(24.1) Power of Attorney. Powers of Attorney for certain directors and officers
of Texaco Inc. authorizing, among other things, the signing of Texaco Inc.'s
Annual Report on Form 10-K on their behalf, filed as Exhibit 24
to Texaco Inc.'s Annual Report on Form 10-K for the year ended
December 31, 1999, dated March 24, 2000, incorporated herein by reference,
SEC File No. 1-17. *
(24.2) Power of Attorney. Power of Attorney for Glenn F. Tilton, Chairman of
the Board and Chief Executive Officer of Texaco Inc., authorizing, among
other things, the signing of Texaco Inc.'s Annual Report on Form 10-K
on his behalf.
(24.3) Power of Attorney. Power of Attorney for Robert J. Eaton, a director of
Texaco Inc., authorizing, among other things, the signing of Texaco Inc.'s
Annual Report on Form 10-K on his behalf.
EXHIBIT 12.1
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
OF TEXACO ON A TOTAL ENTERPRISE BASIS (UNAUDITED)
FOR EACH OF THE FIVE YEARS ENDED DECEMBER 31, 2000
(In Millions of Dollars)
Years Ended December 31,
-------------------------------------------------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
Income from continuing operations, before provision or
benefit for income taxes and cumulative effect of
accounting changes effective 1-1-98................... $4,457 $1,955 $ 892 $3,514 $3,450
Dividends from less than 50% owned companies
more or (less) than equity in net income.............. 145 189 -- (11) (4)
Minority interest in net income.......................... 125 83 56 68 72
Previously capitalized interest charged to
income during the period.............................. 22 14 22 25 27
------ ------ ------ ------ ------
Total earnings................................... 4,749 2,241 970 3,596 3,545
------ ------ ------ ------ ------
Fixed charges:
Items charged to income:
Interest charges.................................... 561 587 664 528 551
Interest factor attributable to operating
lease rentals.................................. 82 90 120 112 129
------ ------ ------ ------ ------
Total items charged to income.................... 643 677 784 640 680
Preferred stock dividends of subsidiaries
guaranteed by Texaco Inc........................ 50 55 33 33 35
Interest capitalized.................................. 76 28 26 27 16
Interest on ESOP debt guaranteed by Texaco Inc........ -- -- 3 7 10
------ ------ ------ ------ ------
Total fixed charges.............................. 769 760 846 707 741
------ ------ ------ ------ ------
Earnings available for payment of fixed charges.......... $5,392 $2,918 $1,754 $4,236 $4,225
(Total earnings + Total items charged to income) ====== ====== ====== ====== ======
Ratio of earnings to fixed charges of Texaco
on a total enterprise basis........................... 7.01 3.84 2.07 5.99 5.70
====== ====== ====== ====== ======
EXHIBIT 12.2
DEFINITIONS OF SELECTED FINANCIAL RATIOS
CURRENT RATIO
Current assets divided by current liabilities.
RETURN ON AVERAGE STOCKHOLDERS' EQUITY
Net income divided by average stockholders' equity. Average
stockholders' equity is computed using the average of the monthly
stockholders' equity balances.
RETURN ON AVERAGE CAPITAL EMPLOYED
Net income plus minority interest plus after-tax interest expense
divided by average capital employed. Capital employed consists of
stockholders' equity, total debt and minority interest. Average capital
employed is computed on a four-quarter average basis.
TOTAL DEBT TO TOTAL BORROWED AND INVESTED CAPITAL
Total debt, including capital lease obligations, divided by total debt
plus minority interest liability and stockholders' equity.
RXHIBIT 13
> TEXACO 2000 ANNUAL REPORT 27
MANAGEMENT'S DISCUSSION AND ANALYSIS
INTRODUCTION
We use the Management's Discussion and Analysis (MD&A) to explain Texaco's
operating results and general financial condition. A table of financial
highlights that provides a financial picture of the company is followed by four
main sections: Industry Review, Results of Operations, Analysis of Income by
Operating Segments and Other Items. Earnings information is presented on an
after-tax basis, unless otherwise noted.
Industry Review -- We discuss the economic factors that affected our
industry in 2000. We also provide our near-term outlook for the industry.
Results of Operations -- We explain changes in revenues, costs, expenses
and income taxes. Summary schedules, showing results before and after special
items, complete this section. Special items are significant benefits or charges
outside the scope of normal operations.
Analysis of Income by Operating Segments -- We discuss the performance of
our operating segments: Exploration and Production (upstream), Refining,
Marketing and Distribution (downstream) and Global Gas, Power and Energy
Technology. We also discuss Other Business Units and our Corporate/Non-operating
results.
Other Items -- We discuss the following items in this section:
> Liquidity and Capital Resources: How we manage cash, working capital and
debt and other actions to provide financial flexibility
> Reorganizations, Restructurings and Employee Separation Programs: A
discussion of our reorganizations and other cost-cutting initiatives
> Capital and Exploratory Expenditures: Our program to invest in the
business, especially in projects aimed at future growth
> Environmental Matters: A discussion about our expenditures relating to
protection of the environment
> New Accounting Standards: A description of new accounting standards to be
adopted
> Euro Conversion: The status of our program to adapt to the euro currency
> California Power Situation: A discussion of the current power problems
facing California
> Chevron-Texaco Merger: The status of our proposed merger with Chevron
Our discussions in the MD&A and other sections of this Annual Report contain
forward-looking statements that are based upon our best estimate of the trends
we know about or anticipate. Actual results may be different from our estimates.
We have described in our 2000 Annual Report on Form 10-K the factors that could
change these forward-looking statements.
---------------------------------------------------------------------------------------------------------------------------------
Financial Highlights
(Millions of dollars, except per share and ratio data) 2000 1999 1998
=================================================================================================================================
Revenues $ 51,130 $ 35,691 $ 31,707
Income before special items and cumulative effect of accounting change $ 2,898 $ 1,214 $ 894
Special items (356) (37) (291)
Cumulative effect of accounting change -- -- (25)
--------------------------------------------------
Net income $ 2,542 $ 1,177 $ 578
Diluted income per common share (dollars)
Income before special items and cumulative effect
of accounting change $ 5.31 $ 2.21 $ 1.59
Special items (.66) (.07) (.55)
Cumulative effect of accounting change -- -- (.05)
--------------------------------------------------
Net income $ 4.65 $ 2.14 $ .99
Cash dividends per common share (dollars) $ 1.80 $ 1.80 $ 1.80
Total assets $ 30,867 $ 28,972 $ 28,570
Total debt $ 7,191 $ 7,647 $ 7,291
Stockholders' equity $ 13,444 $ 12,042 $ 11,833
Current ratio 1.18 1.05 1.07
Return on average stockholders' equity* 20.1% 10.0% 4.9%
Return on average capital employed before special items* 16.2% 8.3% 6.5%
Return on average capital employed* 14.5% 8.1% 5.0%
Total debt to total borrowed and invested capital 33.7% 37.5% 36.8%
=================================================================================================================================
* Returns for 1998 exclude the cumulative effect of accounting change (see
Note 2 to the financial statements).
28 > TEXACO 2000 ANNUAL REPORT
INDUSTRY REVIEW
Introduction
By most measures, 2000 was an extraordinary year for the international oil and
gas industry. Spot crude oil prices reached their highest average level since
1982, spot refining margins staged a startling recovery from last year's lows
and U.S. natural gas prices set new records.
ITEM 1. AVERAGE PRICE PER BARREL OF WEST TEXAS INTERMEDIATE (WTI) CRUDE OIL
[GRAPHIC/IMAGE/ILLUSTRATION MATERIAL APPEARS HERE. SEE APPENDIX, ITEM #1]
ITEM 2. AVERAGE PRICE PER MCF OF U.S. NATURAL GAS AT HENRY HUB
[GRAPHIC/IMAGE/ILLUSTRATION MATERIAL APPEARS HERE. SEE APPENDIX, ITEM #2]
A surging global economy contributed to further growth in energy demand
last year. However, the very favorable price environment was, to a large extent,
the result of a combination of energy market supply-side factors. Low
inventories of crude oil and refined products left oil markets susceptible to
disruption and uncertainty. This helped to support prices and refining margins
at high levels for most of the year.
Low inventory levels also characterized the U.S. natural gas market.
Domestic gas production remained relatively weak in 2000. This made it difficult
both to meet summer demand requirements and to place adequate volumes of gas
into storage for the winter.
Review of 2000
The global economy experienced exceptionally strong growth in 2000. The U.S. was
the world's driving force, enjoying a remarkable 5% increase in Gross Domestic
Product despite a tightening in monetary policy and higher energy prices.
Western Europe also registered a healthy gain, propelled by rising exports and
strong investment spending. However, the large Japanese economy continued to
underperform.
The developing world continued to recover in 2000 from the Asian financial
crisis. Benefiting from both a rise in intra-regional trade and the strength of
the U.S. and European economies, growth in developing Asia accelerated. In
similar fashion, Latin America emerged from its 1999 recession, led by strong
growth in Brazil, Mexico, Peru and Chile. Also, many of the oil producing
nations in the developing world benefited from higher oil prices. Furthermore,
the former Soviet bloc enjoyed its strongest economic performance in 10 years,
led by robust growth in Russia and many of the countries in Eastern Europe.
The increased pace of economic activity contributed to further growth in
world oil demand. Total oil consumption averaged 76.4 million barrels per day
(BPD) during 2000, 1.2% higher than 1999. Virtually all of the increase in
demand occurred in the developing countries, especially those in Asia. The
warmer-than-normal 1999-2000 winter constrained the demand for heating fuels in
the U.S. and Western Europe. Also, sharply higher oil prices limited consumption
in some countries.
In contrast to the deep cutbacks made in 1999, members of the Organization
of Petroleum Exporting Countries (OPEC) raised their production of crude oil
significantly in 2000. OPEC crude oil output averaged 27.9 million BPD, 1.4
million BPD above the prior year and the highest level since 1979. By year end,
many OPEC members were believed to be producing at or near their full capacity.
ITEM 3. AVERAGE OPEC CRUDE OIL PRODUCTION
[GRAPHIC/IMAGE/ILLUSTRATION MATERIAL APPEARS HERE. SEE APPENDIX, ITEM #3]
Production in non-OPEC areas also rose substantially in 2000. This largely
reflected the start-up of projects that were delayed from the prior two years,
when low oil prices cut deeply into spending and production plans. However, much
of the increase in world oil production occurred after the spring, and
commercial crude oil inventories remained lean throughout most of the year.
Low crude oil stocks placed continued upward pressure on prices. This was
reinforced by uncertainties regarding export flows from Iraq and the escalation
of violence in the Middle East. For the year overall, the spot price of U.S.
benchmark West Texas Intermediate (WTI) crude oil averaged $30.37 per barrel,
about $11.00 per barrel higher than in 1999. For 2000, WTI crude oil prices
averaged $30.37 per barrel, or 57% above the 1999 average.
Early in 2000, refined product inventories were drawn down, especially in
the Atlantic basin, to meet seasonal demand requirements. As the year
progressed, it became difficult to replenish these stocks for a variety of
reasons. These reasons included changes
> TEXACO 2000 ANNUAL REPORT 29
in mandated product specifications in some areas, scattered worldwide refinery
outages and heavy scheduled refinery maintenance. Consequently, refined product
prices rose sharply, and spot refining margins increased.
U.S. natural gas prices also rose steeply last year, averaging $3.99 per
thousand cubic feet. This increase of about 70% reflected tight supply/demand
conditions. Domestic gas production has recovered slowly from the declines
suffered in 1998-1999 when overall upstream spending was reduced drastically due
to low oil prices. At the same time, however, gas demand has trended upward,
especially for electricity generation during the summer months. During 2000,
natural gas end users competed for available supplies with operators who store
gas for the winter. With low levels of gas in storage heading into the winter,
the onset of severe cold weather in November and December raised concerns about
adequate supplies. This sent prices up sharply.
Near-Term Outlook
The global economic expansion is expected to continue through 2001, though at a
slower rate than in 2000. The U.S. economy is showing signs of a sharp slowdown,
responding to the previous interest rate increases by the Federal Reserve.
Economic expansions in Europe and the developing world are also expected to
moderate, reflecting the slowdown in the U.S.
World oil consumption will increase again during 2001. Even with lower
economic growth, oil consumption should rise by about 1.4 million BPD. On the
supply side, non-OPEC production will also rise, but more slowly, as many
delayed projects have been completed.
The major uncertainty facing oil markets in 2001 concerns the level of OPEC
oil output and the future course of prices. OPEC has stated publicly its desire
to maintain crude oil prices in a target range which is roughly equivalent to
$24-$30 per barrel of WTI. Prices were headed down toward the lower end of that
range by the end of 2000 as OPEC's high crude oil production rates ultimately
translated into a worldwide accumulation of crude oil stocks. To avoid a market
oversupply situation which could jeopardize its price goal, OPEC implemented
output restraints early in 2001.
Worldwide spot refining margins should decline during 2001. High refinery
running rates in many parts of the world during the latter part of last year led
to a partial refilling of refined product stocks. In addition, many of the
unusual factors that prevailed in 2000, such as major changes in product
specifications, should be absent from the market in 2001.
U.S. natural gas markets, on the other hand, have the potential to remain
quite strong in 2001. Under any reasonable expectation, the volume of natural
gas in storage will be very low by the spring. Thus, the need to build supplies
will be intense. Although production and imports will be higher, continued
growth in demand will keep the market balance tight.
RESULTS OF OPERATIONS
Revenues
Our consolidated worldwide revenues were $51.1 billion in 2000, $35.7 billion in
1999 and $31.7 billion in 1998.
ITEM 4. WORLDWIDE REVENUES FROM SALES AND SERVICES
[GRAPHIC/IMAGE/ILLUSTRATION MATERIAL APPEARS HERE. SEE APPENDIX, ITEM #4]
Sales Revenues -- Price/Volume Effects
Our sales revenues were higher in 2000 due to an increase of over 60% in our
realized crude oil prices. However, our crude oil and natural gas liquids
production was 10% lower due to sales of non-core producing properties in the
U.S. and U.K. and natural field declines.
Sales revenues from petroleum products increased in 2000 led by higher
prices in all markets. Volumes increased slightly as higher sales in the U.S.
and Europe were offset by decreases in Latin America and West Africa and lower
natural gas liquids (NGL) trading activity in our international areas.
U.S. natural gas revenues also improved in 2000 due to a significant
increase in our realized natural gas price, as well as higher sales of purchased
gas. Results for our international operations were consistent with 1999.
Our sales revenues were higher in 1999 due to our increased realized crude
oil prices which began to rise during the second half of the year. However,
crude oil and NGL production declined due to natural field declines and asset
sales in the U.S., as well as temporary operating problems in the U.K.
Sales revenues from petroleum products increased in 1999 due to higher
prices and increased international and marine fuels volumes. Our 1999 natural
gas volumes decreased in the U.S. due to lower production and reduced sales of
purchased gas. Internationally, our results were impacted by our withdrawal from
the U.K. retail gas market.
Other Revenues
Other revenues include our equity in the income of affiliates, gains from
asset sales and interest income. Results for 2000 were higher due to increased
equity in income of affiliates. These results benefited from improved refining
margins for Motiva in the U.S. East and Gulf Coast areas and higher crude oil
prices in our Indonesian producing affiliate. Adversely impacting results were
lower marketing and lubricant margins realized by Equilon and lower Caltex
marketing results.
Results for 1999 were lower due to reduced interest income on notes and
marketable securities and lower asset sales. Equity in income of affiliates in
1999 was consistent with 1998. Lower downstream margins in the Caltex
Asia-Pacific region and in Motiva's East and
30 > TEXACO 2000 ANNUAL REPORT
Gulf Coast areas depressed results. However, we realized higher refining margins
in Equilon's West Coast operating areas. We also benefited from stronger crude
oil prices in our Indonesian producing affiliate during the second half of 1999.
Our share of special charges by our affiliates included in other revenues
amounted to $104 million in 2000, $153 million in 1999 and $159 million in 1998.
In 2000, these major special charges included a loss on the sale of a U.S.
refinery and asset write-downs, as well as patent litigation and environmental
issues. Also included was a special gain for an employee benefits revision. The
1999 special charges included refinery asset write-downs in the U.S. and a loss
on the sale of an interest in a Japanese affiliate. These charges were reduced
by inventory valuation benefits in the U.S. and abroad, as well as tax
revaluation benefits in Korea.
In 1998, special charges included inventory valuation adjustments, net U.S.
alliance formation costs and Caltex restructuring charges.
Costs and Expenses
Costs and expenses from operations were $46.3 billion in 2000, $33.3 billion in
1999 and $30.5 billion in 1998. Significantly higher worldwide crude oil,
petroleum products and U.S. natural gas prices increased our purchases and other
costs in 2000. Operating expenses also increased due to the impact of higher
fuel and gas prices on utility expenses and production taxes. In 1999, our
purchases and other costs increased due to higher prices and product volumes.
Special items recorded by our subsidiaries increased costs and operating
expenses by $819 million in 2000, $121 million in 1999 and $382 million in 1998.
Major special items in 2000 included asset write-downs, losses on asset sales
and environmental and litigation issues. The asset write-downs and losses on
asset sales in 2000, which increased depreciation, depletion and amortization
expense by $569 million, resulted mainly from impairments of certain producing
properties and refinery assets in Panama, as well as sales of producing assets.
In 1999 and 1998, write-downs and losses on asset sales were recorded that
increased depreciation, depletion and amortization expense by $87 million and
$150 million. Asset impairments we have recognized are based on the provisions
of SFAS 121, as well as other applicable accounting pronouncements. These
impairments are driven by specific events, including the sale of properties or
downward revisions in underground reserve quantities. In performing our reviews
of assets not held for sale, we use our best judgment in estimating future cash
flows. This includes our outlook for commodity prices based on our review of
supply and demand forecasts and other economic indicators.
Special items in 1999 also included inventory valuation benefits in
subsidiaries, which reversed charges recorded in 1998 when commodity prices were
very depressed. The year 1998 also included employee separation costs.
Interest expense for 2000 was lower due to lower debt levels and higher
capitalized interest on major upstream projects. The amount recorded for 1999
reflects the impact of higher average debt levels.
Income Taxes
Income tax expense was $1,676 million in 2000, $602 million in 1999 and $98
million in 1998. The increases in 2000 and 1999 are the result of higher income
from producing operations due to higher prices.
Income Summary Schedules
The following schedules show after-tax results before and after special items
and before the cumulative effect of accounting change. A full discussion of
special items is included in our Analysis of Income by Operating Segments.
Income (Loss)
(Millions of dollars) 2000 1999 1998
==================================================================
Income before special items
and cumulative effect of
accounting change $ 2,898 $ 1,214 $ 894
-----------------------------------------------------------------
Special items:
Write-downs of assets (272) (157) (93)
Environmental, litigation
and royalty issues (138) (42) --
Gains (losses) on major asset sales (94) (62) 20
Reorganization, restructuring,
employee related and other costs (8) (74) (144)
Tax issues 96 106 25
Tax benefits on asset sales 70 40 43
Inventory valuation adjustments -- 152 (142)
Merger costs (10) -- --
---------------------------
Total special items (356) (37) (291)
-----------------------------------------------------------------
Income before cumulative effect
of accounting change $ 2,542 $ 1,177 $ 603
=================================================================
> TEXACO 2000 ANNUAL REPORT 31
The following schedule further details our results:
Income (Loss)
Before Special Items After Special Items
---------------------------- ---------------------------
(Millions of dollars) 2000 1999 1998 2000 1999 1998
=============================================================================================================================
Exploration and production (upstream)
United States $ 1,788 $ 666 $ 381 $1,518 $ 652 $ 301
International 1,058 386 181 1,077 360 129
----------------------------------------------------------
Total 2,846 1,052 562 2,595 1,012 430
-----------------------------------------------------------------------------------------------------------------------------
Refining, marketing and distribution (downstream)
United States 243 287 276 158 208 221
International 272 338 503 143 370 332
----------------------------------------------------------
Total 515 625 779 301 578 553
-----------------------------------------------------------------------------------------------------------------------------
Global gas, power and energy technology 50 21 (33) 50 (14) (16)
-----------------------------------------------------------------------------------------------------------------------------
Total 3,411 1,698 1,308 2,946 1,576 967
-----------------------------------------------------------------------------------------------------------------------------
Other business units (11) (3) (2) (11) (3) (2)
Corporate/Non-operating (502) (481) (412) (393) (396) (362)
----------------------------------------------------------
Income before cumulative effect of accounting change $ 2,898 $ 1,214 $ 894 $2,542 $ 1,177 $ 603
=============================================================================================================================
ANALYSIS OF INCOME BY OPERATING SEGMENTS
Upstream
In our upstream business, we explore for, find, develop, produce and sell crude
oil, NGL and natural gas.
Our upstream operations benefited from sharply higher crude oil and natural
gas prices during 2000. The following discussion focuses on how the price
environment and other business factors affected our earnings. The U.S. results
for 1998 include some minor Canadian operations which were sold at the end of
1998.
ITEM 5. WORLDWIDE FINDING AND DEVELOPMENT COSTS PER BARREL OF OIL EQUIVALENT
[GRAPHIC/IMAGE/ILLUSTRATION MATERIAL APPEARS HERE. SEE APPENDIX, ITEM #5]
32 > TEXACO 2000 ANNUAL REPORT
United States Upstream
(Millions of dollars, except as indicated) 2000 1999 1998
==================================================================================================================
Operating income before special items $ 1,788 $ 666 $ 381
------------------------------------------------------------------------------------------------------------------
Special items:
Write-downs of assets (126) -- (51)
Environmental, litigation and royalty issues (15) (30) --
Gains (losses) on major asset sales (129) 18 --
Reorganization, restructuring, employee related and other costs -- (11) (29)
Tax issues -- 9 --
-----------------------------------------
Total special items (270) (14) (80)
------------------------------------------------------------------------------------------------------------------
Operating income $ 1,518 $ 652 $ 301
------------------------------------------------------------------------------------------------------------------
Selected operating data:
Net production
Crude oil and NGL (thousands of barrels a day) 356 395 433
Natural gas available for sale (millions of cubic feet a day) 1,310 1,462 1,679
Average realized crude price (dollars per barrel) $ 26.00 $ 14.70 $ 10.60
Average realized natural gas price (dollars per MCF) $ 3.69 $ 2.18 $ 2.00
Exploratory expenses (millions of dollars) $ 120 $ 234 $ 257
Lifting costs (dollars per barrel of oil equivalent) $ 5.05 $ 4.01 $ 4.07
Return on average capital employed before special items 29.0% 10.5% 6.0%
Return on average capital employed 24.6% 10.3% 4.7%
==================================================================================================================
WHAT HAPPENED IN THE UNITED STATES?
Business Factors
PRICES We benefited from higher prices in 2000, which improved earnings by
$1,368 million. Our average realized crude oil price increased by 77% to $26.00
per barrel. This follows a 39% increase in 1999. Despite production increases in
2000 by OPEC members, concerns over low global inventories of crude oil and
refined products helped push prices up to their highest levels since the Gulf
War in 1991. Concerns over low U.S. natural gas storage levels and strong demand
helped push U.S. natural gas prices to record levels. Our average realized
natural gas price in 2000 increased 69% to $3.69 per thousand cubic feet (MCF).
This follows a 9% increase in 1999.
PRODUCTION Our production decreased by 10% in 2000. Half of this expected
reduction was due to our continuing strategy of selling non-core producing
properties. In 1999, we decided to divest non-strategic assets and focus
investment on high-return, high-impact opportunities. The balance of the
decrease was due to natural field declines, which exceeded new production from
various fields. In 1999, our production also decreased by 10% due to natural
field declines, asset sales and reduced investment in mature properties.
EXPLORATORY EXPENSES We expensed $120 million on exploratory activity in 2000.
Our exploratory expenses in 1999 were $234 million, 9% lower than in 1998. The
year 1999 included a $100 million write-off of investments in prospects in the
Gulf of Mexico. These prospects, initially drilled between 1995 and 1998, were
determined to be non-commercial in the fourth quarter of 1999 after further
appraisal drilling.
Other Factors
Our operating expenses increased by 7% in 2000. This was the result of higher
crude oil and natural gas prices causing a significant increase in utilities
expense and production taxes. Our lifting costs per barrel of oil equivalent
(BOE) increased in 2000 due to these factors. In 1999, our lifting costs per BOE
benefited from cost savings offset partly by lower production.
ITEM 6. U.S. LIFTING COSTS PER BOE
[GRAPHIC/IMAGE/ILLUSTRATION MATERIAL APPEARS HERE. SEE APPENDIX, ITEM #6]
> TEXACO 2000 ANNUAL REPORT 33
Special Items
In 2000, our results included a $129 million charge for net losses on the sales
of non-core producing properties and related disposal costs. These sales were a
significant part of our continuing strategy to upgrade our portfolio in the
upstream by divesting non-strategic assets and focusing investment on
high-return, high-impact opportunities. Our results also included a special
charge of $15 million for crude oil and gas royalty settlements and $126 million
for the write-downs of assets, mostly in the Gulf of Mexico and Gulf Coast.
These impairments were caused by downward revisions in the fourth quarter of
2000 of the estimated volume of the fields' proved reserves and changes in our
outlook of future production. We determined that the carrying values of these
properties exceeded future undiscounted cash flows. Fair value was determined by
discounting expected future cash flows.
Our results for 1999 included a $30 million charge for the settlement of
crude oil royalty valuation issues on federal lands and an $11 million charge
for employee separation costs. The employee separation costs result from the
expansion of our 1998 program. Results for 1998 included a charge for employee
separation costs of $29 million. See the section entitled Reorganizations,
Restructurings and Employee Separation Programs on page 40 for additional
information. During 1999, we also recorded an $18 million gain on asset sales in
California and a $9 million production tax refund.
Results for 1998 also included asset write-downs of $51 million for
impaired properties in Louisiana and Canada. The impaired Louisiana property
represents an unsuccessful enhanced recovery project, which we determined to be
impaired in the fourth quarter of 1998. The Canadian properties were impaired
following our decision in October 1998 to exit the upstream business in Canada.
These properties were written down to their sales price with the sale closing in
December 1998.
-----------------------------------------------------------------------------------------------
International Upstream
(Millions of dollars, except as indicated) 2000 1999 1998
===============================================================================================
Operating income before special items $ 1,058 $ 386 $ 181
-----------------------------------------------------------------------------------------------
Special items:
Write-downs of assets (20) -- (42)
Gains on major asset sales 90 -- --
Reorganization, restructuring, employee related and other costs (14) (2) (10)
Tax issues (37) (24) --
---------------------------
Total special items 19 (26) (52)
-----------------------------------------------------------------------------------------------
Operating income $ 1,077 $ 360 $ 129
-----------------------------------------------------------------------------------------------
Selected operating data:
Net production
Crude oil and NGL (thousands of barrels a day) 444 490 497
Natural gas available for sale (millions of cubic feet a day) 557 537 548
Average realized crude price (dollars per barrel) $ 24.83 $15.23 $11.20
Average realized natural gas price (dollars per MCF) $ 1.58 $ 1.34 $ 1.63
Exploratory expenses (millions of dollars) $ 238 $ 267 $ 204
Lifting costs (dollars per barrel of oil equivalent) $ 4.09 $ 4.37 $ 3.74
Return on average capital employed before special items 23.2% 10.3% 5.8%
Return on average capital employed 23.6% 9.6% 4.1%
===============================================================================================
WHAT HAPPENED IN THE INTERNATIONAL AREAS?
Business Factors
PRICES Our earnings increased by $720 million in 2000 due to sharply higher
crude oil and natural gas prices. Our average crude oil price increased by 63%
to $24.83 per barrel. Market conditions kept crude oil prices strong throughout
2000 despite OPEC actions to boost production. Crude oil prices began to improve
in 1999, increasing by 36% to $15.23 per barrel. This was due to worldwide
production cutbacks and improved demand. Our average realized natural gas price
increased by 18% in 2000 to $1.58 per MCF. This follows a decrease of 18% in
1999.
PRODUCTION Our production in 2000 declined by 7%. We experienced some declines
due to scheduled maintenance and repairs in our U.K. North Sea operations. In
Indonesia, we had lower production volumes as higher prices reduced our lifting
entitlements for cost
34 > TEXACO 2000 ANNUAL REPORT
recovery under a production sharing agreement. In addition, the planned sale of
non-core producing properties caused 40% of the production decline. These
declines were partially offset by increased production in the Partitioned
Neutral Zone and the Karachaganak field in the Republic of Kazakhstan. Our
production decreased slightly in 1999 due to operating problems in the U.K.
North Sea and reduced lifting entitlements in Indonesia. We also experienced
lower natural gas production in Latin America. These declines were partially
offset by increased production in the Partitioned Neutral Zone as a result of
increased drilling activity and development of the Karachaganak field in
Kazakhstan.
EXPLORATORY EXPENSES Our exploratory expenses for 2000 were $238 million. We
expensed $267 million on exploratory activity in 1999, an increase of 31%. This
included about $50 million for an unsuccessful exploratory well offshore
Trinidad and $30 million for prior year drilling expenditures in Thailand, which
we wrote off in 1999 after we determined the prospect to be non-commercial.
ITEM 7. INTERNATIONAL NET PROVED RESERVES
[GRAPHIC/IMAGE/ILLUSTRATION MATERIAL APPEARS HERE. SEE APPENDIX, ITEM #7]
Other Factors
Our operating expenses decreased 7% in 2000 in line with production declines.
Our lifting costs in 2000 were $4.09 per BOE, a decrease of 6%. This decrease
was due in part to lower U.K. lifting costs. Lifting costs per BOE increased in
1999 by 17%, primarily resulting from lower Indonesian lifting entitlements.
ITEM 8. INTERNATIONAL UPSTREAM CAPITAL AND EXPLORATORY EXPENDITURES
[GRAPHIC/IMAGE/ILLUSTRATION MATERIAL APPEARS HERE. SEE APPENDIX, ITEM #8]
Special Items
Our results for 2000 included a special benefit of $90 million for net gains on
the sales of non-core producing properties. These sales are part of our
continuing strategy to divest non-strategic assets and focus investment on
high-return, high-impact opportunities. Results for 2000 also included a special
charge of $14 million for net losses resulting from the Erskine pipeline
interruption in the U.K. North Sea, charges of $37 million for prior years' tax
adjustments and a fourth quarter charge of $20 million for an asset write-down
associated with a project in the U.K. North Sea, which we do not plan to
develop.
Our results for 1999 included a $24 million charge for prior years' tax
issues in the U.K. and a $2 million charge for employee separation costs. The
employee separation costs result from the expansion of our 1998 program. Results
for 1998 included a charge for employee separation costs of $10 million. See the
section entitled Reorganizations, Restructurings and Employee Separation
Programs on page 40 for additional information.
Results for 1998 also included a write-down of $42 million for the
impairment of our investment in the Strathspey field in the U.K. North Sea. The
Strathspey impairment was caused by a downward revision in the fourth quarter of
1998 of the estimated volume of the field's proved reserves.
LOOKING FORWARD IN THE WORLDWIDE UPSTREAM
We intend to continue to cost-effectively explore for, develop and produce crude
oil and natural gas reserves by focusing on high-margin, high-impact projects.
We will continue to review our assets for profitability and strategic fit and
make selective dispositions, as appropriate. We expect worldwide production to
grow an average of two to three percent annually over the next five years. Our
growth areas of focus include:
> Philippines -- where we hold a 45% interest in the Malampaya Deep Water
Natural Gas Project, with first production expected by early 2002
> West Africa -- where we will develop the major Agbami oil field offshore
Nigeria
> U.S. Gulf of Mexico -- where we hold both exploration and production
acreage and saw the July 2000 start-up of our Petronius Project
> U.K. North Sea -- where first production from the second phase (Area B) of
the Captain field began in December 2000
> Venezuela -- where we have a 30% interest in the Hamaca Oil Project, which
is under development
> Kazakhstan -- where we hold interests in the Karachaganak and North Buzachi
projects
> Brazil-- where we have interests in both exploration and development areas
> TEXACO 2000 ANNUAL REPORT 35
Downstream
In our downstream business, we refine, transport and sell crude oil and
products, such as gasoline, fuel oil and lubricants.
Our U.S. downstream includes our share of operations in Equilon and Motiva.
Equilon is our joint venture with Shell Oil Company in which we have a 44%
interest. The Equilon area includes western and midwestern refining and
marketing operations and nationwide trading, transportation and lubricants
activities. The Motiva area includes East and Gulf Coast refining and
marketing operations. Our results for 2000, 1999 and the last half of 1998 are
our share of the earnings of Motiva, our joint venture with Shell and Saudi
Refining, Inc., which began operations on July 1, 1998. In accordance with
contractual provisions, our ownership interest in Motiva is subject to change.
From the start of operations through December 31, 1999 our ownership interest
was 32.5%. For the year 2000, our interest was just under 31%. Results for the
first half of 1998 are for our 50% share of Star, our joint venture with Saudi
Refining, Inc.
Internationally, our wholly-owned downstream operations are reported
separately as Latin America and West Africa and Europe. We also have a 50%
interest in Caltex, a joint venture with Chevron, which operates in Africa,
Asia, Australia, the Middle East and New Zealand.
In the U.S. and international operations, we also have other businesses,
which include aviation and marine product sales, lubricants marketing and other
refined product trading activity.
-----------------------------------------------------------------------------------------------------------------------------
United States Downstream
(Millions of dollars, except as indicated) 2000 1999 1998
=============================================================================================================================
Operating income before special items $ 243 $ 287 $ 276
-----------------------------------------------------------------------------------------------------------------------------
Special items:
Write-downs of assets (10) (76) --
Environmental, litigation and royalty issues (45) -- --
Losses on major asset sales (48) -- --
Reorganization, restructuring, employee related and other costs 18 (11) (21)
Inventory valuation adjustments -- 8 (34)
-------------------------------------
Total special items (85) (79) (55)
-----------------------------------------------------------------------------------------------------------------------------
Operating income $ 158 $ 208 $ 221
-----------------------------------------------------------------------------------------------------------------------------
Selected operating data:
Refinery input (thousands of barrels a day) 524 671 698
Refined product sales (thousands of barrels a day) 1,373 1,347 1,203
Return on average capital employed before special items 9.9% 11.3% 9.6%
Return on average capital employed 6.4% 8.2% 7.7%
=============================================================================================================================
WHAT HAPPENED IN THE UNITED STATES?
Equilon Area
These operations contributed $151 million to our 2000 operating earnings before
special items. Our earnings were lower in 2000 as a result of depressed
marketing margins as pump prices lagged increases in supply costs in a highly
competitive market. Additionally, weak lubricant margins resulting from higher
base oil costs negatively impacted earnings. Maintenance activity at the Puget
Sound, Martinez and Wood River refineries also contributed to these lower
results. These negative factors were partly offset by higher refining margins.
We achieved higher earnings in 1999 from improved West Coast refining
margins as a result of industry refinery outages earlier in the year. We also
benefited from improved utilization of the Martinez refinery, transportation
results and higher trading activity volumes. These improved results were partly
offset by operating problems at the Puget Sound refinery early in the year and
weak marketing margins.
Motiva Area
These operations contributed $102 million of our 2000 operating income before
special items. Our earnings were higher in 2000 due to improved East and Gulf
Coast refining margins stemming from lower industry inventory levels. The year
began with low inventory stocks and tight supplies continued throughout the year
due to increased demand, industry refinery downtime and unusually cold weather.
These improved results were negatively impacted by maintenance activity early in
2000 at the Delaware City and Port Arthur refineries.
Results for 1999 were lower due to weak refining and marketing margins on
the East and Gulf Coasts. This weakness resulted from the inability to pass
along rising supply costs and from high industry-wide refined product inventory
levels. These negative factors were partly offset by improved refinery
reliability.
36 > TEXACO 2000 ANNUAL REPORT
Special Items
Results for 2000, 1999 and 1998 included net special charges of $85 million, $79
million and $55 million, representing our share of special items recorded by our
U.S. alliances.
The 2000 charge included $48 million for the loss on the sale of the Wood
River refinery. This sale was completed in June to Tosco Corporation. Our 2000
results also included charges of $10 million for asset write-downs and $45
million for environmental, litigation and royalty issues, as well as a benefit
of $18 million for an employee benefits revision.
The 1999 charge included $76 million for the write-downs of assets to their
estimated sales values by Equilon for the intended sales of its El Dorado and
Wood River refineries. Equilon completed the sale of the El Dorado refinery to
Frontier Oil Corporation in November 1999.
Our 1999 results also included an inventory valuation benefit of $8 million
due to higher 1999 inventory values. This follows a 1998 charge of $34 million
to reflect lower market prices on December 31, 1998 for inventories of crude oil
and refined products. We value inventories at the lower of cost or market after
initially recording at cost. Inventory valuation adjustments are reversed when
prices recover and the associated physical units of inventory are sold.
Our 1999 and 1998 results included net charges of $11 million and $21
million for reorganizations, restructurings and employee separation costs. The
1999 charge represents dismantling expenses at a closed refinery, an adjustment
to the Anacortes refinery sale and employee separation costs from the expansion
of Equilon's and Motiva's 1998 separation programs. The 1998 net charge was for
U.S. alliance formation issues. This net charge included $52 million for
employee separation costs and $45 million for write-downs of closed facilities
and surplus equipment to their net realizable value. These facilities included a
refinery in Texas, lubricant plants in various states, a sales terminal in
Louisiana, and research facilities and equipment in Texas and New York. Also
included in net charges were gains of $76 million from the Federal Trade
Commission mandated sale of the Anacortes refinery and Plantation pipeline.
------------------------------------------------------------------------------------------------------------
International Downstream
(Millions of dollars, except as indicated) 2000 1999 1998
============================================================================================================
Operating income before special items $ 272 $ 338 $ 503
------------------------------------------------------------------------------------------------------------
Special items:
Write-downs of assets (112) (23) --
Environmental, litigation and royalty issues (5) -- --
Losses on major asset sales -- (80) --
Reorganization, restructuring, employee related and other costs (12) (41) (63)
Tax issues -- 32 --
Inventory valuation adjustments -- 144 (108)
-------------------------------------
Total special items (129) 32 (171)
------------------------------------------------------------------------------------------------------------
Operating income $ 143 $ 370 $ 332
------------------------------------------------------------------------------------------------------------
Selected operating data:
Refinery input (thousands of barrels a day) 794 820 832
Refined product sales (thousands of barrels a day) 1,752 1,789 1,685
Return on average capital employed before special items 4.4% 5.6% 8.2%
Return on average capital employed 2.3% 6.1% 5.4%
============================================================================================================
WHAT HAPPENED IN THE INTERNATIONAL AREAS?
Latin America and West Africa
Our operations in Latin America and West Africa contributed $141 million to our
2000 operating income before special items. Results for 2000 decreased due to
lower refining margins as escalating crude costs continued to outpace product
price increases in Panama and Guatemala. Rising utility costs and downtime also
negatively impacted refining results. Contributing to the decrease were lower
marketing margins and volumes in South America and lower margins in Central
America and West Africa.
Our 1999 earnings declined due to lower refining margins arising from
higher crude costs. Lower marketing margins and lower volumes in Brazil also
depressed earnings, but were partially offset by higher refined product sales in
our Caribbean and Central American operations.
> TEXACO 2000 ANNUAL REPORT 37
Europe
Our European operations contributed $161 million to our 2000 operating income
before special items. We achieved higher earnings in 2000 from improved refining
margins in the U.K. and the Netherlands. These improvements were partially
offset by higher utility costs. Also, results were negatively impacted by lower
marketing margins in Europe, as well as higher expenses in the U.K.
Our 1999 results were lower due to poor refining margins as product price
increases failed to keep pace with escalating crude costs. Increased refined
product sales helped to offset the squeeze on margins.
Caltex
We recognized a loss of $24 million before special items in 2000 from our Caltex
operations. Earnings declined in 2000 due to depressed marketing margins. This
reflected the inability to recover rapidly increasing crude oil costs in highly
competitive markets. Lower refined product volumes also contributed to the
decrease. Although marketing results declined, refining margins improved for the
year.
In 1999, our results were adversely impacted by lower refining and
marketing margins. These declines were partially offset by an inventory drawdown
benefit, lower currency losses and gains on the sales of marketable securities.
ITEM 9. INTERNATIONAL REFINED PRODUCT SALES
[GRAPHIC/IMAGE/ILLUSTRATION MATERIAL APPEARS HERE. SEE APPENDIX, ITEM #9]
Special Items
Results for 2000 included net special charges of $112 million, primarily related
to the write-down of the Panama refinery. We determined that the carrying value
of the refinery exceeded undiscounted future cash flows. The impairment of the
entire carrying value of the refinery was caused by a final determination in the
fourth quarter of 2000 that the unfavorable operating environment and severe
downward pressure on profit margins would not improve in the foreseeable future.
Our 2000 results also included special charges of $12 million related to
employee separation costs and $5 million for environmental issues. See the
section entitled Reorganizations, Restructurings and Employee Separation
Programs on page 40 for additional information. Results for 1999 included net
special benefits of $32 million, while 1998 included net special charges of $171
million. Special items relating to Caltex represent our 50% share.
Results for 1999 included inventory valuation benefits of $144 million due
to higher 1999 inventory values. This follows a 1998 charge of $108 million to
reflect lower market prices on December 31, 1998 for inventories of crude oil
and refined products, as well as additional charges recorded in prior years. We
value inventories at the lower of cost or market, after initially recording at
cost. Inventory valuation adjustments are reversed when prices recover and the
associated physical units of inventory are sold.
Results for 1999 included a charge of $23 million for the write-downs of
assets. These write-downs on properties to be disposed of include $10 million
for marketing assets in our subsidiary in Poland and $13 million for assets in
our Caltex operations.
Our 1999 results included a $9 million charge for employee separation costs
for our subsidiaries operating in Europe and Latin America. These costs resulted
from the expansion of our 1998 program. Results for 1998 included a charge for
employee separation costs of $20 million. See the section entitled
Reorganizations, Restructurings and Employee Separation Programs on page 40 for
additional information.
Results for 1999 also included charges of $80 million related to our share
of the Caltex loss on the sale of its equity interest in Koa Oil Company,
Limited, including deferred currency translation net losses. Additionally, our
results for 1999 included a Caltex Korean tax benefit of $54 million due to
asset revaluation and $22 million for prior year tax charges in the U.K.
Results for 1999 and 1998 included other charges of $32 million and $43
million, representing our share of a Caltex reorganization program. The 1999
charge represented continued expenses related to the 1998 program. The 1998
charge resulted from its decision to structure the organization along functional
lines and to reduce costs by establishing a shared service center in the
Philippines. In implementing this change, Caltex also relocated its headquarters
from Dallas to Singapore. About $35 million of the 1998 charge relates to
severance and other retirement benefits for about 200 employees not relocating,
write-downs of surplus furniture and equipment, and other costs. The balance of
the charge is for severance costs in other affected areas and amounts spent in
relocating employees to the new shared service center.
LOOKING FORWARD IN THE WORLDWIDE DOWNSTREAM
We intend to do the following in our worldwide downstream:
> Pursue marketing growth opportunities in selected areas
> Continue to focus on lowering costs
> Focus on business opportunities in areas of trading, transportation and
lubricants
38 > TEXACO 2000 ANNUAL REPORT
Global Gas, Power and Energy Technology
(Millions of dollars,
except as indicated) 2000 1999 1998
=============================================================
Operating income (loss)
before special items $ 50 $ 21 $(33)
-------------------------------------------------------------
Special items:
Write-downs of assets -- (32) --
Gain on major asset sale -- -- 20
Reorganization, restructuring,
employee related and other costs -- (3) (3)
-------------------------
Total special items -- (35) 17
-------------------------------------------------------------
Operating income (loss) $ 50 $ (14) $(16)
-------------------------------------------------------------
Natural gas sales (millions
of cubic feet per day) 3,476 3,134 3,764
-------------------------------------------------------------
Net power sales (gigawatt hours) 5,644 4,353 4,395
=============================================================
Global gas, power and energy technology includes marketing of natural gas
and natural gas liquids, gas processing plants, pipelines, power generation
plants, gasification licensing and equity plants, fuel processing,
hydrocarbons-to-liquids, hydrogen storage systems and fuel cell technology
units. Gasification is a proprietary technology that converts low-value
hydrocarbons into useful synthesis gas for the chemical, refining and power
industries. In 2000, we purchased a 20% interest in Energy Conversion Devices,
Inc. (ECD). ECD develops and commercializes enabling technologies for use in the
fields of energy storage and information technology. We formed two joint
ventures with ECD, to further develop and commercialize fuel cells and hydrogen
storage products. We also formed a joint venture with a subsidiary of Enron
Corp. that combined the companies' intrastate pipeline and storage businesses in
south Louisiana.
Our gas marketing and trading results in 2000 benefited from improved
natural gas liquids and natural gas margins.
Our gas marketing operating results in 1999 benefited from improved natural
gas liquids margins. Also included in our 1999 results are gains on normal asset
sales and lower operating expenses. The asset sales included our interest in a
U.K. retail gas marketing operation and the sale of a U.S. gas gathering
pipeline.
Our operating results for the power and gasification business in 2000 were
slightly higher than 1999.
Our 1999 results benefited from higher gasification licensing revenues,
cogeneration income and the start-up of new plants in Thailand and Indonesia.
This was partially offset by the non-recurring recoupment of development costs
in 1998.
Special Items
Results for both 1999 and 1998 included charges of $3 million for employee
separation costs. The 1999 charge resulted from the expansion of our 1998
program. See the section entitled Reorganizations, Restructurings and Employee
Separation Programs on page 40 for additional information.
Our 1999 results also included charges of $32 million for asset write-downs
from the impairment of certain gas plants in Louisiana. We determined in the
fourth quarter of 1999 that as a result of declining gas volumes available for
processing, the carrying value of these plants exceeded future undiscounted cash
flows. Fair value was determined by discounting expected future cash flows. Our
1998 results also included a gain of $20 million on the sale of an interest in
our Discovery pipeline affiliate.
LOOKING FORWARD IN GLOBAL GAS, POWER AND ENERGY TECHNOLOGY
We believe there is great promise with emerging energy technologies.
Accordingly, we are pursuing opportunities utilizing gasification,
hydrocarbons-to-liquids and fuel cell technologies. We continue to develop power
projects in conjunction with our exploration, production and refining needs. Our
future plans include:
> Developing power projects where significant reserves of natural gas require
commercialization
> Expanding our gasification technology to commercialize this environmentally
friendly technology
> Using our technology to develop opportunities in the fuel cell, fuel
processing, hydrogen storage and hydrocarbons-to-liquids businesses
Other Business Units
(Millions of dollars) 2000 1999 1998
=============================================================
Operating loss $ (11) $(3) $(2)
=============================================================
Our other business units mainly include our insurance operations. There
were no significant items in our three-year results.
Corporate/Non-operating
(Millions of dollars) 2000 1999 1998
=============================================================
Results before special items $ (502) $ (481) $ (412)
-------------------------------------------------------------
Special items:
Write-downs of assets (4) (26) --
Environmental, litigation
and royalty issues (73) (12) --
Loss on major asset sales (7) -- --
Reorganization, restructuring,
employee related and other costs -- (6) (18)
Tax issues 133 89 25
Tax benefits on asset sales 70 40 43
Merger costs (10) -- --
--------------------------
Total special items 109 85 50
-------------------------------------------------------------
Total Corporate/Non-operating $ (393) $ (396) $ (362)
=============================================================
> TEXACO 2000 ANNUAL REPORT 39
Corporate/Non-operating includes our corporate center and financing
activities. Our 2000 results included lower interest and higher corporate
expenses. The increase in corporate expenses included spending for our Olympic
sponsorship program and increased incentive compensation for employees
associated with the higher level of earnings. Results for 1999 included higher
interest expense resulting from increases in debt levels.
Special Items
Results for 2000 included a tax benefit of $133 million for favorable income tax
settlements and adjustments to prior years' tax liabilities and tax benefits of
$70 million on the sale of an interest in a subsidiary. Also included are
charges of $73 million for environmental and litigation issues, $10 million for
merger costs, $7 million for early extinguishment of debt associated with the
sale of a U.K. North Sea offshore producing field and $4 million for write-downs
of assets.
Results for 1999 included tax benefits of $89 million. These are associated
with favorable determinations in the fourth quarter on prior years' tax issues.
Results for 1999 and 1998 included tax benefits of $40 million and $43 million
from the sales of interests in a subsidiary. Additionally, results for 1998
included a benefit of $25 million to adjust for prior years' federal tax
liabilities.
Our 1999 results also included a $6 million charge for employee separation
costs. These costs resulted from the expansion of our 1998 program. Results for
1998 included a charge for employee separations of $18 million. See the section
entitled Reorganizations, Restructurings and Employee Separation Programs on
page 40 for additional information.
We also recorded in 1999 charges of $12 million for environmental issues
and $26 million for the impairment of assets and related disposal costs. The
assets write-downs resulted from our joint plan with state and local agencies to
convert for third-party industrial use idle facilities formerly used in
research activities. The facilities and equipment were written down to their
appraised values.
OTHER ITEMS
Liquidity and Capital Resources
INTRODUCTION The Consolidated Statement of Cash Flows on page 51 reports the
changes in cash balances for the last three years, and summarizes the inflows
and outflows of cash between operating, investing and financing activities. Our
cash requirements are met by cash from operations and the proceeds from the sale
of non-strategic assets, supplemented by outside borrowings and sales of
investment instruments, if needed.
INFLOWS Cash from operating activities represents net income adjusted for
non-cash charges or credits, such as depreciation, depletion and amortization,
and changes in working capital and other balances. Operating cash flows for 2000
of $3,864 million benefited mainly from higher crude oil and natural gas prices
partially offset by lower crude oil and natural gas production. For more
detailed insight into our financial and operational results, see Analysis of
Income by Operating Segments on the preceding pages.
Other cash inflows in 2000 represent the proceeds from asset sales of $684
million, mainly of non-strategic assets. As discussed earlier, these assets are
producing properties that no longer fit our business strategy of focusing on
high-margin, high-impact projects.
OUTFLOWS Capital expenditures were $2,974 million in 2000. The section on page
41 describes in more detail our capital and exploratory spending.
Net borrowings in 2000 decreased by $444 million compared to a net increase
of $290 million in 1999. This year's decrease reflects debt repayments of $2,167
million and increased borrowings of $1,723 million which includes the issuance
of $530 million of medium-term notes. During the year, we increased commercial
paper by $340 million to $1,439 million. See Note 9 to the financial statements
for total outstanding debt, including 2000 borrowings. We maintain strong credit
ratings and access to global financial markets providing us flexibility to
borrow funds at low capital costs.
Our senior debt is rated A+ by Standard & Poor's Corporation and A1 by
Moody's Investors Services. Our U.S. commercial paper is rated A-1 by Standard &
Poor's and Prime-1 by Moody's. These ratings denote high-quality investment
grade securities. Our debt has an average maturity of 10 years and a weighted
average interest rate of 6.9%. We increased our revolving credit facilities to
$2.575 billion at December 31, 2000 from $2.05 billion at years ended 1999 and
1998. These facilities remain unused and provide liquidity and support our
commercial paper program.
Payments of dividends were $1,116 million in 2000: $976 million to common,
$15 million to preferred and $125 million to shareholders who hold a minority
interest in Texaco subsidiary companies.
Purchases of common stock were $169 million in 2000. In March of 2000, we
resumed purchasing common stock under the $1 billion common stock repurchase
program we initiated in early 1998. Including the purchases of $169 million in
2000, this brings our total purchases under this program, including $474 million
purchased in 1998, to $643 million. No shares were repurchased in 1999. We
suspended the repurchase program following the October 2000 announcement of the
proposed merger with Chevron Corporation.
40 > TEXACO 2000 ANNUAL REPORT
Other cash outflows in 2000 reflect the net purchases of investment
instruments of $61 million. The following year-end table reflects our key
financial indicators:
(Millions of dollars, except as indicated) 2000 1999 1998
==========================================================================
Current ratio 1.18 1.05 1.07
Total debt $ 7,191 $ 7,647 $ 7,291
Average years debt maturity 10 10 10
Average interest rates 6.9% 7.0% 7.0%
Minority interest in
subsidiary companies $ 713 $ 710 $ 679
Stockholders' equity $13,444 $12,042 $11,833
Total debt to total borrowed
and invested capital 33.7% 37.5% 36.8%
==========================================================================
OUTLOOK We consider our financial position to be sufficiently strong to meet our
anticipated future requirements. Our financial policies and procedures afford us
flexibility to meet the changing landscape of our financial environment. Cash
required to service debt maturities in 2001 is projected to be $585 million.
However, we intend to refinance these maturities.
In 2001, we feel our cash from operating activities, coupled with our
borrowing capacity, will allow us to meet our Capex program and the payment of
dividends.
MANAGING MARKET RISK We are exposed to the following types of market risks:
> The price of crude oil, natural gas and petroleum products
> The value of foreign currencies in relation to the U.S. dollar
> Interest rates
We use contracts, such as futures, options and swaps, in managing our exposure
to these risks. We have written policies that govern our use of these
instruments and limit our exposure to market and counterparty risks. These
arrangements do not expose us to material adverse effects. See Notes 9, 14 and
15 to the financial statements and Supplemental Market Risk Disclosures on page
79 for additional information.
Reorganizations, Restructurings and Employee Separation Programs
In the fourth quarter of 1998, we announced that we were reorganizing several of
our operations and implementing other cost-cutting initiatives. The principal
units affected were our worldwide upstream; our international downstream,
principally our marketing operations in the United Kingdom and Brazil and our
refining operations in Panama; global gas marketing, now included as part of our
global gas, power and energy technology operating segment; and our corporate
center. We accrued $115 million ($80 million, net of tax) for employee
separations, curtailment costs and special termination benefits associated with
these announced restructurings in the fourth quarter of 1998. During the second
quarter of 1999, we expanded the employee separation programs and recorded an
additional provision of $48 million ($31 million, net of tax). For the most
part, separation accruals are shown as operating expenses in the Consolidated
Statement of Income.
The following table identifies each of our four restructuring initiatives.
It provides the provision recorded in the fourth quarter of 1998 and the
additional provision recorded in the second quarter of 1999. By the end of the
third quarter of 2000, we had satisfied all remaining obligations in accordance
with the plan provisions. Cash payments totaled $151 million, and transfers to
long-term obligations totaled $12 million.
Provision Recorded in
---------------------
(Millions of dollars) 1998 1999
=============================================================
Worldwide upstream $ 56 $ 20
International downstream 25 13
Global gas, power and energy technology 5 4
Corporate center 29 11
---------------
Total $ 115 $ 48
=============================================================
At the time we initially announced these programs, we estimated that over
1,400 employee reductions would result. Employee reductions of 800 in worldwide
upstream, 300 in international downstream, 100 in global gas, power and energy
technology and 200 in our corporate center were expected. During the second
quarter of 1999, we expanded the program by about 1,200 employees, made up of
600 employees in worldwide upstream, 250 employees in international downstream,
130 employees in global gas, power and energy technology and 200 employees in
our corporate center. By the end of the third quarter of 2000, the estimated
employee reductions were met.
During the first quarter of 2000, we announced an additional employee
separation program for our international downstream, primarily our marketing
operations in Brazil and Ireland. We accrued $17 million ($12 million, net of
tax) for employee separations, curtailment costs and special termination
benefits for about 200 employees. These separation accruals are included in
selling, general and administrative expenses in the Consolidated Statement of
Income. Through December 31, 2000, employee reductions totaled 159. The
remaining reductions will occur by the end of the first quarter of 2001. During
the year 2000, we made cash payments of $8 million and transfers to long-term
obligations of $8 million. We will pay the remaining obligations of $1 million
in future periods in accordance with plan provisions.
> TEXACO 2000 ANNUAL REPORT 41
Capital and Exploratory Expenditures
2000 ACTIVITY Worldwide capital and exploratory expenditures, including our
share of affiliates, were $4.2 billion for the year 2000, $3.9 billion for 1999
and $4.0 billion for 1998. Expenditures in 2000 included increased development
work in upstream projects. Expenditures were geographically and functionally
split as follows:
ITEM 10. CAPITAL AND EXPLORATORY EXPENDITURES -- GEOGRAPHICAL
[GRAPHIC/IMAGE/ILLUSTRATION MATERIAL APPEARS HERE. SEE APPENDIX, ITEM #10]
ITEM 11. CAPITAL AND EXPLORATORY EXPENDITURES -- FUNCTIONAL
[GRAPHIC/IMAGE/ILLUSTRATION MATERIAL APPEARS HERE. SEE APPENDIX, ITEM #11]
EXPLORATION AND PRODUCTION Significant areas of investment included:
> Exploration and development work in West Africa where we announced the
major Agbami oil discovery offshore Nigeria in 1999
> Development of the Malampaya Deep Water Natural Gas Project in the
Philippines
> Development work in Kazakhstan on the Karachaganak and North Buzachi fields
> Development work on the Captain B project in the U.K. North Sea
> Acquisition of EnerVest San Juan Acquisition Partnership in December 2000
OTHER Significant areas of investment included:
> Acquisition of a 20% interest in Energy Conversion Devices, Inc. in June
2000
> Development of the Thailand power project in which we have a 37.5% interest
The following table details our capital and exploratory expenditures:
2000 1999 1998
--------------------------- --------------------------- ---------------------------
Inter- Inter- Inter-
(Millions of dollars) U.S. national Total U.S. national Total U.S. national Total
=============================================================================================================================
Exploration and production
Exploratory expenses $ 120 $ 238 $ 358 $ 234 $ 267 $ 501 $ 257 $ 204 $ 461
Capital expenditures 968 1,729 2,697 666 1,556 2,222 1,179 1,015 2,194
-----------------------------------------------------------------------------------------------------------------------------
Total exploration and
production 1,088 1,967 3,055 900 1,823 2,723 1,436 1,219 2,655
Refining, marketing
and distribution 405 380 785 379 487 866 431 717 1,148
Global gas, power and
energy technology 164 169 333 103 176 279 124 61 185
Other 61 -- 61 18 7 25 29 2 31
-----------------------------------------------------------------------------------------------------------------------------
Total $ 1,718 $ 2,516 $4,234 $ 1,400 $ 2,493 $ 3,893 $2,020 $ 1,999 $ 4,019
-----------------------------------------------------------------------------------------------------------------------------
Total, excluding affiliates $ 1,279 $ 2,210 $3,489 $ 1,012 $ 2,051 $ 3,063 $1,528 $ 1,496 $ 3,024
=============================================================================================================================
42 > TEXACO 2000 ANNUAL REPORT
2001
Spending for the year 2001 is expected to be $4.5 billion. In the upstream,
spending continues to be allocated to our large-impact projects in West Africa,
Venezuela, Kazakhstan, the Philippines and the North Sea. Major exploration
programs are under way in our key focus areas of Nigeria, Brazil and the
deepwater Gulf of Mexico. International marketing will increase spending in the
U.K., Latin America and West Africa. Increases in spending are also anticipated
for our international refinery system, particularly the Pembroke refinery in
Wales. Our global gas, power and energy technology business continues to grow
and has identified additional power generation and gasification projects and
natural gas business opportunities. In addition, increased spending for our fuel
cell and hydrogen storage joint ventures is anticipated.
Environmental Matters
The cost of compliance with federal, state and local environmental laws in the
U.S. and international countries continues to be substantial. Using definitions
and guidelines established by the American Petroleum Institute, our 2000
environmental spending was $686 million. This includes our equity share in the
environmental expenditures of our major affiliates, Equilon, Motiva and the
Caltex Group of Companies. The following table provides our environmental
expenditures for the past three years:
Our spending for capital projects in 2000 was $110 million. These expenditures
were made to comply with clean air and water regulations as well as waste
management requirements. Worldwide capital expenditures projected for 2001 and
2002 are $178 million and $154 million.
ONGOING OPERATIONS
In 2000, environmental expenses charged to current operations were $436 million.
These expenses related largely to the production of cleaner-burning gasoline and
the execution of our environmental programs.
REMEDIATION
Remediation Costs and Liabilities
Our worldwide remediation expenditures in 2000 were $109 million. This included
$12 million spent on the remediation of Superfund waste sites. At the end of
2000, we had liabilities of $428 million for the estimated cost of our known
environmental liabilities. This includes $41 million for the cleanup of
Superfund waste sites. We have accrued for these remediation liabilities based
on currently available facts, existing technology and presently enacted laws and
regulations. It is not possible to project overall costs beyond amounts
disclosed due to the uncertainty surrounding future developments in regulations
or until new information becomes available.
Superfund Sites
Under the Comprehensive Environmental Response, Compensation and Liability Act,
the U.S. Environmental Protection Agency (EPA) and other regulatory agencies
have identified us as a potentially responsible party (PRP) for cleanup of
Superfund waste sites. We have determined that we may have potential exposure,
though limited in most cases, at 183 Superfund waste sites. Of these sites, 106
are on the EPA's National Priority List. Under Superfund, liability is joint and
several. That is, each PRP at a site can be held liable individually for the
entire cleanup cost of the site. We are, however, actively pursuing the sharing
of Superfund costs with other identified PRPs. The sharing of these costs is on
the basis of weight, volume and toxicity of the materials contributed by the
PRP.
RESTORATION AND ABANDONMENT COSTS AND LIABILITIES
Expenditures in 2000 for restoration and abandonment of our oil and gas
producing properties amounted to $31 million. At year-end 2000, accruals to
cover the cost of restoration and abandonment were $749 million.
We make every reasonable effort to fully comply with applicable governmental
regulations. Changes in these regulations, as well as our continuous
re-evaluation of our environmental programs, may result in additional future
costs. We believe that any mandated future costs would be recoverable in the
marketplace since all companies within our industry would be facing similar
requirements. However, we do not believe that such future costs would be
material to our financial position or to our operating results over any
reasonable period of time.
> TEXACO 2000 ANNUAL REPORT 43
New Accounting Standards
In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS 133,
"Accounting for Derivative Instruments and Hedging Activities." SFAS 133
establishes new accounting rules and disclosure requirements for most derivative
instruments and hedge transactions. In June 1999, the FASB issued SFAS 137,
which deferred the effective date of SFAS 133. This was followed in June 2000 by
the issuance of SFAS 138, "Accounting for Certain Derivative Instruments and
Certain Hedging Activities," which amended SFAS 133.
These standards require that all applicable derivative financial
instruments be recorded in the Consolidated Balance Sheet at fair value. For
derivatives accounted for as hedges, fair value adjustments are recorded to
earnings or directly to equity, depending upon the type of hedge and the degree
of hedge effectiveness. For hedges classified as fair value hedges, adjustments
are also recorded to the carrying amount of the hedged item through earnings.
For derivatives not accounted for as hedges, fair value adjustments are recorded
to earnings.
We are adopting these standards effective January 1, 2001. The cumulative
effects of adoption at that date on net income and other comprehensive income
are not material to net income and stockholders' equity.
Euro Conversion
On January 1, 1999, 11 of the 15 member countries of the European Union
established fixed conversion rates between their existing currencies and one
common currency -- the euro. The euro began trading on world currency exchanges
at that time and may be used in business transactions. On January 1, 2002, new
euro-denominated bills and coins will be issued, and legacy currencies will be
completely withdrawn from circulation by June 30 of that year.
Prior to introduction of the euro, our operating subsidiaries affected by
the euro conversion completed computer systems upgrades and fiscal and legal due
diligence to ensure our euro readiness. Computer systems have been adapted to
ensure that all our operating subsidiaries have the capability to comply with
necessary business requirements and customer/supplier preferences. Legal due
diligence was conducted to ensure post-euro continuity of contracts, and fiscal
reviews were completed to ensure compatibility with our banking relationships.
We, therefore, experienced no major impact on our current business operations as
a result of the introduction of the euro. Our operating subsidiaries affected by
the euro conversion are formulating plans to accommodate all euro-denominated
transactions and triangulation conventions by January 1, 2002, and some of these
operations have already implemented the utilization of the euro as a
transactional currency.
We continue to review our marketing and operational policies and procedures
to ensure our ability to continue to successfully conduct all aspects of our
business in this new, price-transparent market. We believe that the euro
conversion will not have a material adverse impact on our financial condition or
results of operations.
California Power Situation
The electric utility deregulation plan adopted by the state of California in
1996 required utilities to dispose of a portion of their power generation
assets. As a result, utilities that serve California purchase power on the open
market and, in turn, sell power to the retail customers at capped rates. During
the fourth quarter of 2000, California's power and gas markets experienced
significant price volatility. Increased demand resulted in very high market
prices that California utilities paid for power with no certainty they could
recover these costs from their customers. As both supplier to and purchaser from
the utility companies, Texaco has financial and operational exposure in
California. While the possible outcomes for the California utility situation
remain uncertain, we believe that they will not have a material adverse impact
on our financial condition or results of operations.
Chevron-Texaco Merger
On October 15, 2000, Texaco and Chevron Corporation entered into a merger
agreement. In the merger, Texaco shareholders will receive .77 shares of Chevron
common stock for each share of Texaco common stock they own, and Chevron
shareholders will retain their existing shares.
The new company -- ChevronTexaco Corporation -- will have significantly
enhanced positions in upstream and downstream operations, a global chemicals
business, a growth platform in power generation, and industry-leading skills in
technology innovation. Annual synergy savings of at least $1.2 billion are
expected within six to nine months of the merger. Though not yet fully
quantified, significant costs will also be incurred after the merger for
integration-related expenses, including the elimination of duplicate facilities,
operational realignment and severance payments for workforce reductions.
The merger is conditioned, among other things, on the approval by the
shareholders of both companies, pooling of interests accounting treatment for
the merger and approvals of government agencies, such as the U.S. Federal Trade
Commission (FTC). Texaco and Chevron anticipate that the FTC will require
certain divestitures in the U.S. downstream in order to address market
concentration issues, and the companies intend to cooperate with the FTC in this
process. In that regard, Texaco is in discussions with our partners in the U.S.
downstream.
44 > TEXACO 2000 ANNUAL REPORT
DESCRIPTION OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements consist of the accounts of Texaco Inc. and
subsidiary companies in which we hold direct or indirect voting interest of more
than 50%. Intercompany accounts and transactions are eliminated.
The U.S. dollar is the functional currency of all our operations and
substantially all of the operations of affiliates accounted for on the equity
method. For these operations, translation effects and all gains and losses from
transactions not denominated in the functional currency are included in income
currently, except for certain hedging transactions. The cumulative translation
effects for the equity affiliates using functional currencies other than the
U.S. dollar are included in the currency translation adjustment in stockholders'
equity.
USE OF ESTIMATES
In preparing Texaco's consolidated financial statements in accordance with
generally accepted accounting principles, management is required to use
estimates and judgment. While we have considered all available information,
actual amounts could differ from those reported as assets and liabilities and
related revenues, costs and expenses and the disclosed amounts of contingencies.
REVENUES
We recognize revenues for crude oil, natural gas and refined product sales at
the point of passage of title specified in the contract. We record revenues on
forward sales where cash has been received to deferred income until title
passes.
CASH EQUIVALENTS
We generally classify highly liquid investments with a maturity of three months
or less when purchased as cash equivalents.
INVENTORIES
We value inventories at the lower of cost or market, after initially recording
at cost. For virtually all inventories of crude oil, petroleum products and
petrochemicals, cost is determined on the last-in, first-out (LIFO) method. For
other merchandise inventories, cost is generally on the first-in, first-out
(FIFO) method. For materials and supplies, cost is at average cost.
INVESTMENTS AND ADVANCES
We use the equity method of accounting for investments in certain affiliates
owned 50% or less, including corporate joint ventures, limited liability
companies and partnerships. Under this method, we record equity in the pre-tax
income or losses of limited liability companies and partnerships, and equity in
the net income or losses of corporate joint-venture companies currently in
Texaco's revenues, rather than when realized through dividends or distributions.
We record the net income of affiliates accounted for at cost in net income
when realized through dividends.
We account for investments in debt securities and in equity securities with
readily determinable fair values at fair value if classified as
available-for-sale.
PROPERTIES, PLANT AND EQUIPMENT AND DEPRECIATION, DEPLETION AND AMORTIZATION
We follow the "successful efforts" method of accounting for our oil and gas
exploration and producing operations.
We capitalize as incurred the lease acquisition costs of properties held
for oil, gas and mineral production. We expense as incurred exploratory costs
other than wells. We initially capitalize exploratory wells, including
stratigraphic test wells, pending further evaluation of whether economically
recoverable proved reserves have been found. If such reserves are not found, we
charge the well costs to exploratory expenses. For locations not requiring major
capital expenditures, we record the charge within one year of well completion.
We capitalize intangible drilling costs of productive wells and of development
dry holes, and tangible equipment costs. Also capitalized are costs of injected
carbon dioxide related to development of oil and gas reserves.
We base our evaluation of impairment for properties, plant and equipment
intended to be held on comparison of carrying value against undiscounted future
net pre-tax cash flows, generally based on proved developed reserves. If an
impairment is identified, we adjust the asset's carrying amount to fair value.
We generally account for assets to be disposed of at the lower of net book value
or fair value less cost to sell.
We amortize unproved oil and gas properties, when individually significant,
by property using a valuation assessment. We generally amortize other unproved
oil and gas properties on an aggregate basis over the average holding period
for the portion expected to be nonproductive. We amortize productive properties
and other tangible and intangible costs of producing activities principally by
field. Amortization is based on the unit-of-production basis by applying the
ratio of produced oil and gas to estimated recoverable proved oil and gas
reserves. We include estimated future restoration and abandonment costs in
determining amortization and depreciation rates of productive properties.
> TEXACO 2000 ANNUAL REPORT 45
We apply depreciation of facilities other than producing properties
generally on the group plan, using the straight-line method, with composite
rates reflecting the estimated useful life and cost of each class of property.
We depreciate facilities not on the group plan individually by estimated useful
life using the straight-line method. We exclude estimated salvage value from
amounts subject to depreciation. We amortize capitalized non-mineral leases over
the estimated useful life of the asset or the lease term, as appropriate, using
the straight-line method.
We record periodic maintenance and repairs at manufacturing facilities on
the accrual basis. We charge to expense normal maintenance and repairs of all
other properties, plant and equipment as incurred. We capitalize renewals,
betterments and major repairs that materially extend the useful life of
properties and record a retirement of the assets replaced, if any.
When capital assets representing complete units of property are disposed
of, we credit or charge to income the difference between the disposal proceeds
and net book value.
ENVIRONMENTAL EXPENDITURES
When remediation of a property is probable and the related costs can be
reasonably estimated, we accrue the expenses of environmental remediation costs
and record them as liabilities. Recoveries or reimbursements are recorded as an
asset when receipt is assured. We expense or capitalize other environmental
expenditures, principally maintenance or preventive in nature, as appropriate.
DEFERRED INCOME TAXES
We determine deferred income taxes utilizing a liability approach. The income
statement effect is derived from changes in deferred income taxes on the balance
sheet. This approach gives consideration to the future tax consequences
associated with differences between financial accounting and tax bases of assets
and liabilities. These differences relate to items such as depreciable and
depletable properties, exploratory and intangible drilling costs, non-productive
leases, merchandise inventories and certain liabilities. This approach gives
immediate effect to changes in income tax laws upon enactment.
We reduce deferred income tax assets by a valuation allowance when it is
more likely than not (more than 50%) that a portion will not be realized.
Deferred income tax assets are assessed individually by type for this purpose.
This process requires the use of estimates and judgment, as many deferred income
tax assets have a long potential realization period.
We do not make provision for possible income taxes payable upon
distribution of accumulated earnings of foreign subsidiary companies and
affiliated corporate joint-venture companies when such earnings are deemed to be
permanently reinvested.
ACCOUNTING FOR CONTINGENCIES
Certain conditions may exist as of the date financial statements are issued,
which may result in a loss to the company, but which will only be resolved when
one or more future events occur or fail to occur. Such contingent liabilities
are assessed by the company's management and legal counsel. The assessment of
loss contingencies necessarily involves an exercise of judgment and is a matter
of opinion. In assessing loss contingencies related to legal proceedings that
are pending against the company or unasserted claims that may result in such
proceedings, the company's legal counsel evaluates the perceived merits of any
legal proceedings or unasserted claims as well as the perceived merits of the
amount of relief sought or expected to be sought therein.
If the assessment of a contingency indicates that it is probable that a
material liability had been incurred and the amount of the loss can be
estimated, then the estimated liability would be accrued in the company's
financial statements. If the assessment indicates that a potentially material
liability is not probable, but is reasonably possible, or is probable but cannot
be estimated, then the nature of the contingent liability, together with an
estimate of the range of possible loss if determinable and material, would be
disclosed.
Loss contingencies considered remote are generally not disclosed unless
they involve guarantees, in which case the nature of the guarantee would be
disclosed. However, in some instances in which disclosure is not otherwise
required, the company may disclose contingent liabilities of an unusual nature
which, in the judgment of management and its legal counsel, may be of interest
to stockholders or others.
CONSOLIDATED STATEMENT OF CASH FLOWS
We present cash flows from operating activities using the indirect method and
reflect our capital expenditures as investing activities.
46 > TEXACO 2000 ANNUAL REPORT
CONSOLIDATED STATEMENT OF INCOME
(Millions of dollars) For the years ended December 31 2000 1999 1998
===============================================================================================================
Revenues
Sales and services (includes transactions with significant
affiliates of $7,811 million in 2000, $4,839 million
in 1999 and $4,169 million in 1998) $ 50,100 $ 34,975 $ 30,910
Equity in income of affiliates, interest, asset sales and other 1,030 716 797
----------------------------------------
Total revenues 51,130 35,691 31,707
---------------------------------------------------------------------------------------------------------------
Deductions
Purchases and other costs (includes transactions with significant
affiliates of $3,266 million in 2000, $1,691 million in 1999
and $1,669 million in 1998) 39,576 27,442 24,179
Operating expenses 2,808 2,319 2,508
Selling, general and administrative expenses 1,291 1,186 1,224
Exploratory expenses 358 501 461
Depreciation, depletion and amortization 1,917 1,543 1,675
Interest expense 458 504 480
Taxes other than income taxes 379 334 423
Minority interest 125 83 56
----------------------------------------
46,912 33,912 31,006
---------------------------------------------------------------------------------------------------------------
Income before income taxes and cumulative effect of
accounting change 4,218 1,779 701
Provision for income taxes 1,676 602 98
----------------------------------------
Income before cumulative effect of accounting change 2,542 1,177 603
Cumulative effect of accounting change -- -- (25)
----------------------------------------
Net income $ 2,542 $ 1,177 $ 578
===============================================================================================================
Net Income Per Common Share (dollars)
Basic:
Income before cumulative effect of accounting change $ 4.66 $ 2.14 $ 1.04
Cumulative effect of accounting change -- -- (.05)
----------------------------------------
Net income $ 4.66 $ 2.14 $ .99
===============================================================================================================
Diluted:
Income before cumulative effect of accounting change $ 4.65 $ 2.14 $ 1.04
Cumulative effect of accounting change -- -- (.05)
----------------------------------------
Net income $ 4.65 $ 2.14 $ .99
===============================================================================================================
Average Number of Common Shares Outstanding (for computation
of earnings per share) (thousands)
Basic 542,322 535,369 528,416
Diluted 543,952 537,860 528,965
===============================================================================================================
See accompanying notes to consolidated financial statements.
> TEXACO 2000 ANNUAL REPORT 47
CONSOLIDATED BALANCE SHEET
(Millions of dollars) As of December 31 2000 1999
==============================================================================================================
Assets
Current Assets
Cash and cash equivalents $ 207 $ 419
Short-term investments - at fair value 46 29
Accounts and notes receivable (includes receivables from significant affiliates
of $667 million in 2000 and $585 million in 1999), less allowance for
doubtful accounts of $27 million in 2000 and 1999 5,583 4,060
Inventories 1,023 1,182
Deferred income taxes and other current assets 194 273
--------------------
Total current assets 7,053 5,963
Investments and Advances 6,889 6,426
Net Properties, Plant and Equipment 15,681 15,560
Deferred Charges 1,244 1,023
--------------------
Total $ 30,867 $ 28,972
==============================================================================================================
Liabilities and Stockholders' Equity
Current Liabilities
Notes payable, commercial paper and current portion of long-term debt $ 376 $ 1,041
Accounts payable and accrued liabilities (includes payables to significant affiliates
of $146 million in 2000 and $61 million in 1999)
Trade liabilities 3,314 2,585
Accrued liabilities 1,347 1,203
Estimated income and other taxes 947 839
--------------------
Total current liabilities 5,984 5,668
Long-Term Debt and Capital Lease Obligations 6,815 6,606
Deferred Income Taxes 1,547 1,468
Employee Retirement Benefits 1,118 1,184
Deferred Credits and Other Non-Current Liabilities 1,246 1,294
Minority Interest in Subsidiary Companies 713 710
--------------------
Total 17,423 16,930
Stockholders' Equity
Market auction preferred shares 300 300
Unearned employee compensation and benefit plan trust (310) (306)
Common stock - shares issued: 567,576,504 in 2000 and 1999 1,774 1,774
Paid-in capital in excess of par value 1,301 1,287
Retained earnings 11,297 9,748
Other comprehensive income (130) (119)
--------------------
14,232 12,684
Less - Common stock held in treasury, at cost 788 642
--------------------
Total stockholders' equity 13,444 12,042
--------------------------------------------------------------------------------------------------------------
Total $ 30,867 $ 28,972
==============================================================================================================
See accompanying notes to consolidated financial statements.
48 > TEXACO 2000 ANNUAL REPORT
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
Shares Amount Shares Amount Shares Amount
----------------- ----------------- -----------------
(Shares in thousands; amounts in millions of dollars) 2000 1999 1998
=============================================================================================================================
Preferred Stock
par value $1; shares authorized - 30,000,000
Market Auction Preferred Shares (Series G, H, I and J) --
liquidation preference of $250,000 per share
Beginning and end of year 1 $ 300 1 $ 300 1 $ 300
-----------------------------------------------------------------------------------------------------------------------------
Series B ESOP Convertible Preferred Stock
Beginning of year -- -- 649 389 693 416
Redemptions -- -- (587) (352) -- --
Retirements -- -- (62) (37) (44) (27)
----------------------------------------------------------
End of year -- -- -- -- 649 389
-----------------------------------------------------------------------------------------------------------------------------
Series F ESOP Convertible Preferred Stock
Beginning of year -- -- 53 39 56 41
Redemptions -- -- (53) (39) -- --
Retirements -- -- -- -- (3) (2)
----------------------------------------------------------
End of year -- -- -- -- 53 39
-----------------------------------------------------------------------------------------------------------------------------
Unearned Employee Compensation
(related to ESOP and restricted stock awards)
Beginning of year (66) (94) (149)
Awards (30) (18) (36)
Amortization and other 26 46 91
----------------------------------------------------------
End of year (70) (66) (94)
-----------------------------------------------------------------------------------------------------------------------------
Benefit Plan Trust
(common stock)
Beginning and end of year 9,200 (240) 9,200 (240) 9,200 (240)
-----------------------------------------------------------------------------------------------------------------------------
Common Stock
par value $3.125; shares authorized -- 850,000,000
Beginning of year 567,577 1,774 567,606 1,774 567,606 1,774
Monterey acquisition adjustment -- -- (29) -- -- --
----------------------------------------------------------
End of year 567,577 1,774 567,577 1,774 567,606 1,774
-----------------------------------------------------------------------------------------------------------------------------
Common Stock Held in Treasury, at Cost
Beginning of year 14,469 (642) 32,976 (1,435) 25,467 (956)
Redemption of Series B and
Series F ESOP Convertible
Preferred Stock -- -- (16,180) 699 -- --
Purchases of common stock 3,331 (169) -- -- 9,572 (551)
Other - mainly employee benefit plans (386) 23 (2,327) 94 (2,063) 72
----------------------------------------------------------
End of year 17,414 $ (788) 14,469 $ (642) 32,976 $ (1,435)
=============================================================================================================================
See accompanying notes to consolidated financial statements. (Continued on next page.)
> TEXACO 2000 ANNUAL REPORT 49
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(Millions of dollars) 2000 1999 1998
=============================================================================================================================
Paid-in Capital in Excess of Par Value
Beginning of year $ 1,287 $ 1,640 $ 1,688
Redemption of Series B and Series F ESOP
Convertible Preferred Stock -- (308) --
Monterey acquisition adjustment -- (2) --
Treasury stock transactions relating to investor services plan
and employee compensation plans 14 (43) (48)
----------------------------------------
End of year 1,301 1,287 1,640
-----------------------------------------------------------------------------------------------------------------------------
Retained Earnings
Balance at beginning of year 9,748 9,561 9,987
Add:
Net income 2,542 1,177 578
Tax benefit associated with dividends on unallocated
ESOP Convertible Preferred Stock and Common Stock -- 2 3
Deduct: Dividends declared on
Common stock
($1.80 per share in 2000, 1999 and 1998) 976 964 952
Preferred stock
Series B ESOP Convertible Preferred Stock -- 17 38
Series F ESOP Convertible Preferred Stock -- 2 4
Market Auction Preferred Shares (Series G, H, I and J) 17 9 13
----------------------------------------
Balance at end of year 11,297 9,748 9,561
-----------------------------------------------------------------------------------------------------------------------------
Other Comprehensive Income
Currency translation adjustment
Beginning of year (99) (107) (105)
Change during year (7) 8 (2)
----------------------------------------
End of year (106) (99) (107)
----------------------------------------
Minimum pension liability adjustment
Beginning of year (23) (24) (16)
Change during year (4) 1 (8)
----------------------------------------
End of year (27) (23) (24)
----------------------------------------
Unrealized net gain on investments
Beginning of year 3 30 26
Change during year -- (27) 4
----------------------------------------
End of year 3 3 30
----------------------------------------
Total other comprehensive income (130) (119) (101)
-----------------------------------------------------------------------------------------------------------------------------
Stockholders' Equity
End of year (including preceding page) $ 13,444 $ 12,042 $ 11,833
=============================================================================================================================
See accompanying notes to consolidated financial statements.
50 > TEXACO 2000 ANNUAL REPORT
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(Millions of dollars) For the years ended December 31 2000 1999 1998
====================================================================================================================
Net Income $ 2,542 $ 1,177 $ 578
--------------------------------------------------------------------------------------------------------------------
Other Comprehensive Income:
Currency translation adjustment
Reclassification to net income of realized loss on sale of affiliate -- 17 --
Other unrealized net change during period (7) (9) (2)
-------------------------------------
Total (7) 8 (2)
-------------------------------------
Minimum pension liability adjustment
Before income taxes (5) 1 (16)
Income taxes 1 -- 8
-------------------------------------
Total (4) 1 (8)
-------------------------------------
Unrealized net gain on investments
Net gain (loss) arising during period
Before income taxes 1 12 35
Income taxes -- (2) (11)
Reclassification to net income of net realized (gain) or loss
Before income taxes (1) (48) (31)
Income taxes -- 11 11
-------------------------------------
Total -- (27) 4
--------------------------------------------------------------------------------------------------------------------
Total other comprehensive income (11) (18) (6)
--------------------------------------------------------------------------------------------------------------------
Total comprehensive income $ 2,531 $ 1,159 $ 572
--------------------------------------------------------------------------------------------------------------------
See accompanying notes to consolidated financial statements.
> TEXACO 2000 ANNUAL REPORT 51
CONSOLIDATED STATEMENT OF CASH FLOWS
(Millions of dollars) For the years ended December 31 2000 1999 1998
=============================================================================================================================
Operating Activities
Net income $ 2,542 $ 1,177 $ 578
Reconciliation to net cash provided by (used in) operating activities
Cumulative effect of accounting change -- -- 25
Depreciation, depletion and amortization 1,917 1,543 1,675
Deferred income taxes 134 (140) (152)
Minority interest in net income 125 83 56
Dividends from affiliates, greater than equity in income 77 233 224
Gains on asset sales (141) (87) (109)
Changes in operating working capital
Accounts and notes receivable (1,549) (637) 125
Inventories 131 (28) (51)
Accounts payable and accrued liabilities 621 382 16
Other - mainly estimated income and other taxes 50 130 (205)
Other - net (43) 29 (89)
----------------------------------------
Net cash provided by operating activities 3,864 2,685 2,093
----------------------------------------
Investing Activities
Capital expenditures (2,974) (2,473) (2,650)
Proceeds from asset sales 684 321 282
Sales (purchases) of leasehold interests -- (23) 25
Purchases of investment instruments (340) (432) (947)
Sales/maturities of investment instruments 279 778 1,118
Collection of note/formation payments from U.S. affiliate -- 101 612
----------------------------------------
Net cash used in investing activities (2,351) (1,728) (1,560)
----------------------------------------
Financing Activities
Borrowings having original terms in excess of three months
Proceeds 808 2,353 1,300
Repayments (2,167) (1,080) (741)
Net increase (decrease) in other borrowings 915 (983) 493
Purchases of common stock (169) -- (579)
Dividends paid to the company's stockholders
Common (976) (964) (952)
Preferred (15) (28) (53)
Dividends paid to minority stockholders (125) (55) (52)
----------------------------------------
Net cash used in financing activities (1,729) (757) (584)
----------------------------------------
Cash and Cash Equivalents
Effect of exchange rate changes 4 (30) (11)
----------------------------------------
Increase (decrease) during year (212) 170 (62)
Beginning of year 419 249 311
----------------------------------------
End of year $ 207 $ 419 $ 249
=============================================================================================================================
See accompanying notes to consolidated financial statements.
52 > TEXACO 2000 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 SEGMENT INFORMATION
Operating segments are based on differences in the nature of their operations,
geographic location and internal management reporting. The composition of
segments and measure of segment profit are consistent with that used by our
Executive Council in making strategic decisions. The Executive Council is headed
by the Chairman and Chief Executive Officer and includes, among others, the
Senior Vice Presidents having oversight responsibility for our business units.
-----------------------------------------------------------------------------------------------------------------------------------
Operating Segments 2000
Sales and Services After- Income
-------------------------------- Tax Tax Other Capital Assets at
Inter- Profit Expense DD&A Non-Cash Expen- Year-
(Millions of dollars) Outside segment Total (Loss) (Benefit) Expense Items ditures End
===================================================================================================================================
Exploration and production
United States $ 3,693 $2,127 $ 5,820 $ 1,518 $ 806 $1,148 $ 203 $ 975 $ 8,442
International 3,578 1,504 5,082 1,077 1,149 406 161 1,367 6,343
Refining, marketing
and distribution
United States 6,027 21 6,048 158 119 2 149 8 3,495
International 29,099 393 29,492 143 80 328 182 294 8,865
Global gas, power and
energy technology 7,693 223 7,916 50 28 11 10 269 2,580
-----------------------------------------------------------------------------------------------------
Segment totals $50,090 $4,268 54,358 2,946 2,182 1,895 705 2,913 29,725
================== -------
Other business units 30 (11) (5) -- (6) -- 341
Corporate/Non-operating 6 (393) (501) 22 228 61 1,185
Intersegment eliminations (4,294) -- -- -- -- -- (384)
-----------------------------------------------------------------------------
Consolidated $ 50,100 $ 2,542 $ 1,676 $1,917 $ 927 $2,974 $30,867
=============================================================================
Operating Segments 1999
Sales and Services After- Income
-------------------------------- Tax Tax Other Capital Assets at
Inter- Profit Expense DD&A Non-Cash Expen- Year-
(Millions of dollars) Outside segment Total (Loss) (Benefit) Expense Items ditures End
-----------------------------------------------------------------------------------------------------------------------------------
Exploration and production
United States $ 2,166 $1,547 $ 3,713 $ 652 $ 299 $ 758 $ 167 $ 660 $ 8,696
International 2,684 924 3,608 360 545 451 30 1,267 5,333
Refining, marketing
and distribution
United States 3,579 18 3,597 208 73 3 78 3 3,714
International 22,114 75 22,189 370 101 220 132 361 8,542
Global gas, power and
energy technology 4,422 117 4,539 (14) (8) 65 10 161 1,297
--------------------------------------------------------------------------------------------------
Segment totals $34,965 $2,681 37,646 1,576 1,010 1,497 417 2,452 27,582
==================
Other business units 32 (3) (2) 1 -- -- 365
Corporate/Non-operating 6 (396) (406) 45 (1) 21 1,430
Intersegment eliminations (2,709) -- -- -- -- -- (405)
-------------------------------------------------------------------------
Consolidated $34,975 $1,177 $ 602 $1,543 $ 416 $2,473 $28,972
=========================================================================
> TEXACO 2000 ANNUAL REPORT 53
Operating Segments 1998
Sales and Services After- Income
---------------------------- Tax Tax Other Capital Assets at
Inter- Profit Expense DD&A Non-Cash Expen- Year-
(Millions of dollars) Outside segment Total (Loss) (Benefit) Expense Items ditures End
----------------------------------------------------------------------------------------------------------------------------------
Exploration and production
United States $ 1,712 $1,659 $ 3,371 $ 301 $ 34 $ 892 $ 1 $1,200 $ 8,699
International 2,020 695 2,715 129 132 513 18 901 4,345
Refining, marketing
and distribution
United States 2,612 29 2,641 221 88 29 230 1 4,066
International 19,805 106 19,911 332 130 204 135 396 8,214
Global gas, power and
energy technology 4,748 76 4,824 (16) 4 15 45 122 1,119
----------------------------------------------------------------------------------------------
Segment totals $30,897 $2,565 33,462 967 388 1,653 429 2,620 26,443
=================
Other business units 50 (2) -- 1 3 -- 381
Corporate/Non-operating 5 (362) (290) 21 (67) 30 1,945
Intersegment eliminations (2,607) -- -- -- -- -- (199)
--------------------------------------------------------------------------
Consolidated, before cumulative
effect of accounting change $ 30,910 $ 603 $ 98 $1,675 $ 365 $2,650 $ 28,570
==========================================================================
Our exploration and production segments explore for, find, develop and
produce crude oil and natural gas. The United States segment in 1998 included
minor operations in Canada. Our refining, marketing and distribution segments
process crude oil and other feedstocks into refined products and purchase, sell
and transport crude oil and refined petroleum products. The global gas, power
and energy technology segment includes the U.S. natural gas operations which
purchases natural gas and natural gas products from our exploration and
production operations and third parties for resale. It also operates natural gas
processing plants and pipelines in the United States. Also included in this
segment are our power generation, gasification, hydrocarbons-to-liquids, battery
and fuel cell technology operations. This segment sold its U.K. wholesale gas
business in 1998 and its U.K. retail gas marketing business in 1999. Other
business units include our insurance operations and investments in undeveloped
mineral properties. None of these units is individually significant in terms of
revenue, income or assets.
You are encouraged to read Note 5 which includes information about our
affiliates and the formation of the Equilon and Motiva alliances in 1998.
Corporate and non-operating includes the assets, income and expenses
relating to cash management and financing activities, our corporate center and
other items not directly attributable to the operating segments.
We apply the same accounting policies to each of the segments as we do in
preparing the consolidated financial statements. Intersegment sales and services
are generally representative of market prices or arms-length negotiated
transactions. Intersegment receivables are representative of normal trade
balances. Other non-cash items principally include deferred income taxes, the
difference between cash distributions and equity in income of affiliates, and
non-cash charges and credits associated with asset sales. Capital expenditures
are presented on a cash basis, excluding exploratory expenses.
54 > TEXACO 2000 ANNUAL REPORT
The countries in which we have significant sales and services and
long-lived assets are listed below. Sales and services are based on the origin
of the sale. Long-lived assets include properties, plant and equipment and
investments in foreign operations where the host governments own the physical
assets under terms of the operating agreements.
-----------------------------------------------------------------------------------------------------------------------------
Sales and Services Long-lived assets at December 31
---------------------------- --------------------------------
(Millions of dollars) 2000 1999 1998 2000 1999 1998
=============================================================================================================================
United States $ 17,074 $ 9,733 $ 8,184 $8,018 $ 8,630 $ 8,757
=============================================================================================================================
International - Total $ 33,026 $ 25,242 $ 22,726 $7,879 $ 7,109 $ 6,250
Significant countries included above:
Brazil 3,023 2,404 3,175 336 326 301
Netherlands 2,570 1,955 1,636 232 246 257
Philippines -- -- -- 1,132 554 --
United Kingdom 11,472 9,211 7,529 2,460 2,275 2,257
=============================================================================================================================
NOTE 2 ADOPTION OF NEW ACCOUNTING STANDARDS
Effective January 1, 1998, Caltex, our affiliate, adopted Statement of Position
98-5, "Reporting on the Costs of Start-Up Activities," issued by the American
Institute of Certified Public Accountants. This Statement requires that the
costs of start-up activities and organization costs, as defined, be expensed as
incurred. The cumulative effect of adoption on Texaco's net income for 1998 was
a net loss of $25 million. This Statement was adopted by Texaco and our other
affiliates effective January 1, 1999. The effect was not significant.
In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS
133, "Accounting for Derivative Instruments and Hedging Activities." SFAS 133
establishes new accounting rules and disclosure requirements for most derivative
instruments and hedge transactions. In June 1999, the FASB issued SFAS 137,
which deferred the effective date of SFAS 133. This was followed in June 2000 by
the issuance of SFAS 138, "Accounting for Certain Derivative Instruments and
Certain Hedging Activities," which amended SFAS 133.
We are adopting these standards effective January 1, 2001. The cumulative
effects of adoption at that date on net income and other comprehensive income
are not material to net income and stockholders' equity.
NOTE 3 INCOME PER COMMON SHARE
Basic net income per common share is net income less preferred stock dividend
requirements divided by the average number of common shares outstanding. Diluted
net income per common share assumes issuance of the net incremental shares from
stock options and full conversion of all dilutive convertible securities at the
later of the beginning of the year or date of issuance. Common shares held by
the benefit plan trust are not considered outstanding for purposes of net income
per common share.
------------------------------------------------------------------------------------------------------------------------------------
2000 1999 1998
(Millions, except per share amounts) --------------------------- ----------------------------- -----------------------------
For the years ended December 31 Income Shares Per Share Income Shares Per Share Income Shares Per Share
====================================================================================================================================
Basic net income:
Income before cumulative
effect of accounting change $ 2,542 $ 1,177 $ 603
Less: Preferred stock dividends (15) (29) (54)
-------------------------------------------------------------------------------------------
Income before cumulative
effect of accounting change,
for basic income per share $ 2,527 542.3 $4.66 $1,148 535.4 $ 2.14 $549 528.4 $ 1.04
Effect of dilutive securities:
Stock options and restricted stock 3 1.7 3 2.5 -- .4
Convertible debentures -- -- -- -- 1 .2
Income before cumulative -------------------------------------------------------------------------------------------
effect of accounting change, for
diluted income per share $ 2,530 544.0 $4.65 $1,151 537.9 $ 2.14 $550 529.0 $ 1.04
===================================================================================================================================
> TEXACO 2000 ANNUAL REPORT 55
NOTE 4 INVENTORIES
(Millions of dollars)
As of December 31 2000 1999
=============================================================
Crude oil $ 127 $ 141
Petroleum products and other 732 857
Materials and supplies 164 184
-----------------
Total $ 1,023 $1,182
=============================================================
At December 31, 2000 and 1999, the excess of estimated market value over
the carrying value of inventories was $210 million and $194 million.
NOTE 5 INVESTMENTS AND ADVANCES
We account for our investments in affiliates, including corporate joint ventures
and partnerships owned 50% or less, on the equity method. Our total investments
and advances are summarized as follows:
(Millions of dollars)
As of December 31 2000 1999
=============================================================
Affiliates accounted for on the
equity method
Exploration and production
United States $ 269 $ 243
International
CPI 465 454
Other 145 14
-----------------
879 711
Refining, marketing
and distribution
United States
Equilon 1,724 1,953
Motiva 743 686
Other 5 8
International
Caltex 1,682 1,685
Other 238 234
-----------------
4,392 4,566
Global gas, power and
energy technology 630 286
-----------------
Total 5,901 5,563
-----------------
Miscellaneous investments, long-term
receivables, etc., accounted for at:
Fair value 122 138
Cost, less reserve 866 725
-----------------
Total $ 6,889 $6,426
=============================================================
Our equity in the net income of affiliates is adjusted to reflect income
taxes for limited liability companies and partnerships whose income is directly
taxable to us:
(Millions of dollars)
For the years ended December 31 2000 1999 1998
=============================================================
Equity in net income (loss)
Exploration and production
United States $ 83 $ 53 $ 37
International
CPI 255 139 107
Other 1 -- (12)
-------------------------
339 192 132
Refining, marketing
and distribution
United States
Equilon 98 142 199
Motiva 100 (3) 22
Other 27 -- (3)
International
Caltex 5 11 (36)
Other 8 27 15
-------------------------
238 177 197
Global gas, power and
energy technology 36 6 (11)
-------------------------
Total $ 613 $ 375 $ 318
-------------------------------------------------------------
Dividends received $ 863 $ 716 $ 709
=============================================================
The undistributed earnings of these affiliates included in our retained
earnings were $2,536 million, $2,613 million and $2,846 million as of December
31, 2000, 1999 and 1998.
Caltex Group
We have investments in the Caltex Group of Companies, owned 50% by Texaco and
50% by Chevron Corporation. The Caltex Group consists of P.T. Caltex Pacific
Indonesia (CPI), American Overseas Petroleum Limited and subsidiary and Caltex
Corporation and subsidiaries (Caltex). This group of companies is engaged in the
exploration for and production, transportation, refining and marketing of crude
oil and products in Africa, Asia, Australia, the Middle East and New Zealand.
Results for the Caltex Group in 1998 include an after-tax charge of $50
million (Texaco's share $25 million) for the cumulative effect of an accounting
change. See Note 2 for additional information.
Equilon Enterprises LLC
Effective January 1, 1998, Texaco and Shell Oil Company formed Equilon
Enterprises LLC (Equilon), a Delaware limited liability company. Equilon is a
joint venture that combined major elements of the companies' western and
midwestern U.S. refining and marketing businesses and their nationwide trading,
transportation and lubricants businesses. We own 44% and Shell Oil Company owns
56% of Equilon.
56 > TEXACO 2000 ANNUAL REPORT
The carrying amounts at January 1, 1998, of the principal assets and
liabilities of the businesses we contributed to Equilon were $.2 billion of net
working capital assets, $2.8 billion of net properties, plant and equipment and
$.2 billion of debt. These amounts were reclassified to investment in affiliates
accounted for by the equity method.
In April 1998, we received $463 million from Equilon, representing
reimbursement of certain capital expenditures incurred prior to the formation of
the joint venture. In July 1998, we received $149 million from Equilon for
certain specifically identified assets transferred for value to Equilon. In
February 1999, we received $101 million from Equilon for the payment of notes
receivable.
Motiva Enterprises LLC
Effective July 1, 1998, Texaco, Shell and Saudi Aramco formed Motiva Enterprises
LLC (Motiva), a Delaware limited liability company. Motiva is a joint venture
that combined Texaco's and Saudi Aramco's interests and major elements of
Shell's East and Gulf Coast U.S. refining and marketing businesses. Texaco's
and Saudi Aramco's interests in these businesses were previously conducted by
Star Enterprise (Star), a joint-venture partnership owned 50% by Texaco and 50%
by Saudi Refining, Inc., a corporate affiliate of Saudi Aramco.
From July 1, 1998, through December 31, 1999, Texaco and Saudi Refining,
Inc. each owned 32.5% and Shell owned 35% of Motiva. Under the terms of the
Limited Liability Agreement for Motiva, the ownership in Motiva is subject to
annual adjustment through year-end 2005, based on the performance of the assets
contributed to Motiva. Accordingly, the initial ownership in Motiva was adjusted
effective as of January 1, 2000, so that for the year 2000, Texaco and Saudi
Refining, Inc. each owned just under 31% and Shell owned just under 39% of
Motiva. The Agreement provides that a final ownership percentage will be
calculated at the end of 2005.
The investment in Motiva at date of formation approximated the previous
investment in Star. The Motiva investment and previous Star investment are
recorded as investment in affiliates accounted for on the equity method.
The following table provides summarized financial information on a 100% basis
for the Caltex Group, Equilon, Motiva, Star and all other affiliates that we
account for on the equity method, as well as Texaco's total share of the
information. The net income of all limited liability companies and partnerships
is net of estimated income taxes. The actual income tax liability is reflected
in the accounts of the respective members or partners and is not shown in the
following table.
-----------------------------------------------------------------------------------------------------------------------------
Total
Caltex Other Texaco's
(Millions of dollars) Equilon Motiva Group Affiliates Share
=============================================================================================================================
2000
Gross revenues $ 50,010 $ 19,446 $20,239 $ 4,163 $ 39,913
Income before income taxes $ 228 $ 461 $ 1,088 $ 408 $ 993
Net income $ 148 $ 300 $ 519 $ 283 $ 613
-----------------------------------------------------------------------------------------------------------------------------
As of December 31:
Current assets $ 3,134 $ 1,381 $ 2,544 $ 1,652 $ 3,782
Non-current assets 6,830 5,110 7,678 4,318 9,656
Current liabilities (4,587) (1,150) (3,385) (1,280) (4,650)
Non-current liabilities (897) (2,017) (2,543) (1,816) (2,887)
-------------------------------------------------
Net equity $ 4,480 $ 3,324 $ 4,294 $ 2,874 $ 5,901
=============================================================================================================================
Total
Caltex Other Texaco's
(Millions of dollars) Equilon Motiva Group Affiliates Share
=============================================================================================================================
1999
Gross revenues $ 29,398 $ 12,196 $14,942 $ 2,895 $ 25,663
Income (loss) before income taxes $ 347 $ (69) $ 780 $ 348 $ 679
Net income (loss) $ 226 $ (45) $ 390 $ 232 $ 375
-----------------------------------------------------------------------------------------------------------------------------
As of December 31:
Current assets $ 3,426 $ 1,271 $ 2,705 $ 801 $ 3,452
Non-current assets 7,208 5,307 7,632 2,230 9,335
Current liabilities (4,853) (1,278) (3,395) (736) (4,572)
Non-current liabilities (735) (2,095) (2,667) (792) (2,652)
-------------------------------------------------
Net equity $ 5,046 $ 3,205 $ 4,275 $ 1,503 $ 5,563
-----------------------------------------------------------------------------------------------------------------------------
> TEXACO 2000 ANNUAL REPORT 57
Total
Caltex Other Texaco's
(Millions of dollars) Equilon Motiva Star Group Affiliates Share
-----------------------------------------------------------------------------------------------------------------------------------
1998
Gross revenues $ 22,246 $ 5,371 $ 3,190 $11,522 $ 2,541 $ 20,030
Income (loss) before income taxes and cumulative
effect of accounting change $ 502 $ 78 $ (128) $ 519 $ 170 $ 662
Net income (loss) $ 326 $ 51 $ (83) $ 143 $ 84 $ 318
-----------------------------------------------------------------------------------------------------------------------------------
As of December 31:
Current assets $ 2,640 $ 1,481 $ 1,974 $ 687 $ 2,769
Non-current assets 7,752 5,257 7,684 2,021 9,313
Current liabilities (4,044) (1,243) (2,839) (727) (3,924)
Non-current liabilities (382) (1,667) (2,421) (672) (2,142)
----------------------------------------------------------------------
Net equity $ 5,966 $ 3,828 $ 4,398 $ 1,309 $ 6,016
-----------------------------------------------------------------------------------------------------------------------------------
NOTE 6 PROPERTIES, PLANT AND EQUIPMENT
Gross Net
-----------------------------------------------------
(Millions of dollars) As of December 31 2000 1999 2000 1999
---------------------------------------------------------------------------------------------------
Exploration and production
United States $19,301 $21,565 $ 7,258 $ 7,822
International 7,418 8,835 4,612 3,804
----------------------------------------------------
Total 26,719 30,400 11,870 11,626
---------------------------------------------------------------------------------------------------
Refining, marketing and distribution
United States 37 33 23 22
International 4,684 4,575 3,031 3,107
----------------------------------------------------
Total 4,721 4,608 3,054 3,129
---------------------------------------------------------------------------------------------------
Global gas, power and energy technology 615 748 280 317
Other 766 771 477 488
---------------------------------------------------------------------------------------------------
Total $32,821 $36,527 $15,681 $15,560
===================================================================================================
Capital lease amounts included above $ 212 $ 152 $ 57 $ 3
---------------------------------------------------------------------------------------------------
Accumulated depreciation, depletion and amortization totaled $17,140 million and
$20,967 million at December 31, 2000 and 1999. Interest capitalized as part of
properties, plant and equipment was $76 million in 2000, $28 million in 1999 and
$21 million in 1998.
In 2000, 1999 and 1998, we recorded pre-tax charges of $337 million, $87
million and $150 million for the write-downs of impaired assets. These charges
were recorded to depreciation, depletion and amortization expense.
2000
In the U.S. exploration and production operating segment, pre-tax asset
write-downs for impaired properties mostly in the Gulf of Mexico and Gulf Coast
were $203 million. These impairments were caused by downward revisions of the
estimated volume of the fields' proved reserves and changes in our outlook of
future production. We determined in the fourth quarter of 2000 that the carrying
values of these properties exceeded future undiscounted cash flows. Fair value
was determined by discounting expected future cash flows.
In the international exploration and production operating segment, the
pre-tax asset write-down for the impairment of a project in the U.K. North Sea
was $29 million. The impairment was caused by a determination made in the fourth
quarter of 2000 that we do not plan to develop this property.
In the international downstream operating segment, the pre-tax asset
write-down for the impairment of the Panama refinery was $105 million. We
determined that the carrying value of the refinery exceeded undiscounted future
cash flows. The impairment of the entire carrying value of the refinery was
caused by a final determination in the fourth quarter of 2000 that the
unfavorable operating environment and downward pressure on profit margins would
not improve in the foreseeable future.
58 > TEXACO 2000 ANNUAL REPORT
1999
In our global gas, power and energy technology operating segment, pre-tax asset
write-downs from the impairment of certain gas plants in Louisiana were $49
million. We determined in the fourth quarter that, as a result of declining gas
volumes available for processing, the carrying value of these plants exceeded
future undiscounted cash flows. Fair value was determined by discounting
expected future cash flows.
Pre-tax asset write-downs of $28 million included in corporate resulted
from our joint plan with state and local agencies to convert for third-party
industrial use idle facilities, formerly used in research activities. The
facilities and equipment were written down to their appraised values. An
additional $10 million was recorded to bring certain marketing assets of our
subsidiary in Poland to be disposed of to their appraised value.
1998
In the U.S. exploration and production operating segment, pre-tax asset
write-downs for impaired properties in Louisiana and Canada were $64 million.
The Louisiana property represents an unsuccessful enhanced recovery project. We
determined in the fourth quarter of 1998 that the carrying value of this
property exceeded future undiscounted cash flows. Fair value was determined by
discounting expected future cash flows. Canadian properties were impaired
following our decision in October 1998 to exit the upstream business in Canada.
These properties were written down to their sales price with the sale closing in
December 1998.
In the international exploration and production operating segment, the
pre-tax asset write-down for the impairment of our investment in the Strathspey
field in the U.K. North Sea was $58 million. The Strathspey impairment was
caused by a downward revision in the fourth quarter of the estimated volume of
the field's proved reserves. Fair value was determined by discounting expected
future cash flows.
In the U.S. downstream operating segment, the pre-tax asset write-downs for
the impairment of surplus facilities and equipment held for sale and not
transferred to the Equilon joint venture was $28 million. Fair value was
determined by an independent appraisal.
NOTE 7 FOREIGN CURRENCY
Currency translation effects and currency transactions resulted in pre-tax
losses of $88 million in 2000, $47 million in 1999 and $80 million in 1998.
After applicable taxes, 2000 included a gain of $37 million and 1999 included a
gain of $25 million as compared to a loss of $94 million in 1998.
The after-tax currency gain in 2000 and 1999 related principally to balance
sheet translation. After-tax currency impacts for year 1998 were largely due to
currency volatility in Asia. In 1998, our Caltex affiliate incurred significant
currency-related losses due to the strengthening of the Korean won and Japanese
yen against the U.S. dollar.
Results for 1998 through 2000 were also impacted by the effect of currency
rate changes on deferred income taxes denominated in British pounds. This
results in gains from strengthening of the U.S. dollar and losses from weakening
of the U.S. dollar. These effects were gains of $12 million in 2000 and $8
million in 1999 and losses of $5 million in 1998.
Currency translation adjustments shown in the separate stockholders' equity
account result from translation items pertaining to certain affiliates of
Caltex. For 2000, we recorded unrealized losses of $7 million from these
adjustments. In 1999, we recorded unrealized losses of $9 million and in
addition, we reversed an existing $17 million deferred loss due to the sale by
Caltex of its investment in Koa Oil Company, Limited. As a result, a $17 million
loss was recorded in Texaco's net income as part of the loss on this sale. For
the year 1998, currency translation losses recorded to stockholders' equity
amounted to $2 million.
NOTE 8 TAXES
(Millions of dollars) 2000 1999 1998
=============================================================
Federal and other income taxes
Current
U.S. Federal $ 278 $ 100 $ (45)
Foreign 1,265 678 283
State and local (1) (36) 12
----------------------------
Total 1,542 742 250
Deferred
U.S. 87 (120) (104)
Foreign 47 (20) (48)
----------------------------
Total 134 (140) (152)
----------------------------
Total income taxes 1,676 602 98
Taxes other than income taxes
Oil and gas production 117 64 70
Property 90 69 108
Payroll 81 91 119
Other 91 110 126
----------------------------
Total 379 334 423
Import duties and other levies
U.S. 25 34 36
Foreign 6,928 6,937 6,843
----------------------------
Total 6,953 6,971 6,879
----------------------------
Total direct taxes 9,008 7,907 7,400
Taxes collected from consumers 2,519 2,097 2,148
----------------------------
Total all taxes $ 11,527 $ 10,004 $9,548
=============================================================
The deferred income tax assets and liabilities included in the Consolidated
Balance Sheet as of December 31, 2000 and 1999 amounted to $154 million and $198
million, as net current assets and $1,547 million and $1,468 million, as net
non-current liabilities.
> TEXACO 2000 ANNUAL REPORT 59
The table that follows shows deferred income tax assets and liabilities by
category:
(Liability) Asset
-------------------------
(Millions of dollars) As of December 31 2000 1999
================================================================================
Depreciation $ (831) $ (991)
Depletion (416) (383)
Intangible drilling costs (888) (881)
Other deferred tax liabilities (788) (691)
-------------------------
Total (2,923) (2,946)
Employee benefit plans 565 548
Tax loss carryforwards 405 599
Tax credit carryforwards 273 495
Environmental liabilities 130 123
Other deferred tax assets 984 711
-------------------------
Total 2,357 2,476
-------------------------
Total before valuation allowance (566) (470)
Valuation allowance (827) (800)
-------------------------
Total $(1,393) $(1,270)
================================================================================
The preceding table excludes certain potential deferred income tax asset
amounts for which possibility of realization is extremely remote.
The valuation allowance relates principally to upstream operations in
Denmark. The related deferred income tax assets result from tax loss
carryforwards and book versus tax asset basis differences for a hydrocarbon tax.
Loss carryforwards from this tax are generally determined by individual field
and, in that case, are not usable against other fields' taxable income.
The following schedule reconciles the differences between the U.S. Federal
income tax rate and the effective income tax rate excluding the cumulative
effect of accounting change in 1998:
2000 1999 1998
========================================================================
U.S. Federal income tax rate
assumed to be applicable 35.0% 35.0% 35.0%
Net earnings and dividends
attributable to affiliated
corporations accounted
for on the equity method (2.4) (3.8) (7.0)
Aggregate earnings and
losses from international
operations 12.9 14.4 10.4
U.S. tax adjustments (3.3) (5.0) (8.7)
Sales of stock of subsidiaries (1.7) (2.2) (6.1)
Energy credits (1.5) (3.8) (11.7)
Other .7 (.8) 2.1
--------------------------------
Effective income tax rate 39.7% 33.8% 14.0%
========================================================================
For companies operating in the United States, pre-tax earnings before the
cumulative effect of an accounting change aggregated $1,899 million in 2000,
$484 million in 1999 and $194 million in 1998. For companies with operations
located outside the United States, pre-tax earnings on that basis aggregated
$2,319 million in 2000, $1,295 million in 1999 and $507 million in 1998.
Income taxes paid, net of refunds, amounted to $1,374 million, $600 million
and $430 million in 2000, 1999 and 1998.
The undistributed earnings of subsidiary companies and of affiliated
corporate joint-venture companies accounted for on the equity method, for which
deferred U.S. income taxes have not been provided at December 31, 2000, amounted
to $1,995 million and $2,206 million. The corresponding amounts at December 31,
1999 were $1,708 million and $2,187 million. Determination of the unrecognized
U.S. deferred income taxes on these amounts is not practicable.
For the years 2000, 1999 and 1998, no loss carryforward benefits were
recorded for U.S. Federal income taxes. For the years 2000, 1999 and 1998, the
tax benefits recorded for loss carryforwards were $89 million, $54 million and
$30 million in foreign income taxes.
At December 31, 2000, we had worldwide tax basis loss carryforwards of
approximately $1,299 million, including $753 million which do not have an
expiration date. The remainder expire at various dates through 2019.
Foreign tax credit carryforwards available for U.S. Federal income tax
purposes amounted to approximately $295 million at December 31, 2000, expiring
at various dates through 2005. Alternative minimum tax credit carryforwards for
U.S. Federal income tax purposes were $258 million at December 31, 2000. For the
year 2000, we utilized tax credit carryforwards of $189 million for U.S. Federal
income tax purposes.
NOTE 9 SHORT-TERM DEBT, LONG-TERM DEBT, CAPITAL LEASE OBLIGATIONS AND RELATED
DERIVATIVES
Notes Payable, Commercial Paper and Current Portion of Long-Term Debt
(Millions of dollars) As of December 31 2000 1999
================================================================================
Notes payable to banks and others with
originating terms of one year or less $ 362 $1,251
Commercial paper 1,439 1,099
Current portion of long-term debt
and capital lease obligations
Indebtedness 986 734
Capital lease obligations 7 7
--------------------
2,794 3,091
Less short-term obligations
intended to be refinanced 2,418 2,050
--------------------
Total $ 376 $1,041
================================================================================
60 > TEXACO 2000 ANNUAL REPORT
The weighted average interest rates of commercial paper and notes payable
to banks at December 31, 2000 and 1999 were 6.6% and 5.9%.
Long-Term Debt and Capital Lease Obligations
(Millions of dollars) As of December 31 2000 1999
================================================================================
Long-Term Debt
3-1/2% convertible notes due 2004 $ 203 $ 203
5.5% note due 2009 392 397
5.7% notes due 2008 201 201
6% notes due 2005 299 299
6-7/8% debentures due 2023 196 196
7.09% notes due 2007 150 150
7-1/2% debentures due 2043 198 198
7-3/4% debentures due 2033 199 199
8% debentures due 2032 148 148
8-1/4% debentures due 2006 150 150
8-3/8% debentures due 2022 198 198
8-1/2% notes due 2003 200 200
8-5/8% debentures due 2010 150 150
8-5/8% debentures due 2031 199 199
8-5/8% debentures due 2032 199 199
8-7/8% debentures due 2021 150 150
9-3/4% debentures due 2020 250 250
Medium-term notes, maturing
from 2001 to 2043 (7.1%) 1,081 757
Pollution Control Revenue Bonds,
due 2012 - variable rate (4.3%) 166 166
Other long-term debt:
U.S. dollars (6.6%) 248 369
Other currencies (6.4%) 367 472
--------------------
Total 5,344 5,251
Capital Lease Obligations (see Note 10) 46 46
--------------------
5,390 5,297
Less current portion of long-term
debt and capital lease obligations 993 741
--------------------
4,397 4,556
Short-term obligations intended
to be refinanced 2,418 2,050
--------------------
Total long-term debt and
capital lease obligations $6,815 $6,606
================================================================================
The percentages shown for variable-rate debt are the interest rates at
December 31, 2000. The percentages shown for the categories "Medium-term notes"
and "Other long-term debt" are the weighted average interest rates at year-end
2000. Where applicable, principal amounts shown in the preceding schedule
include unamortized premium or discount. Texaco Inc. or Texaco Capital Inc., a
wholly-owned finance subsidiary of Texaco Inc., has issued all of our publicly
traded long-term debt. Texaco Inc. has fully and unconditionally guaranteed all
of Texaco Capital Inc.'s outstanding debt. Interest paid, net of amounts
capitalized, amounted to $440 million in 2000, $480 million in 1999 and $474
million in 1998.
At December 31, 2000, we had revolving credit facilities with commitments
of $2.575 billion with syndicates of major U.S. and international banks. These
facilities are available as support for our issuance of commercial paper as well
as for working capital and other general corporate purposes. We had no amounts
outstanding under these facilities at year-end 2000. We pay commitment fees on
these facilities. The banks reserve the right to terminate the credit facilities
upon the occurrence of certain specific events, including a change in control.
However, the banks have waived these change in control provisions with respect
to the proposed Chevron-Texaco merger.
At December 31, 2000, our long-term debt included $2.418 billion of
short-term obligations scheduled to mature during 2001, which we have both the
intent and the ability to refinance on a long-term basis through the use of our
$2.575 billion revolving credit facilities.
Contractual annual maturities of long-term debt, including sinking fund
payments and potential repayments resulting from options that debtholders might
exercise, for the five years subsequent to December 31, 2000 are as follows (in
millions):
We seek to maintain a balanced capital structure that provides financial
flexibility and supports our strategic objectives while achieving a low cost of
capital. This is achieved by balancing our liquidity and interest rate
exposures. We manage these exposures primarily through long-term and short-term
debt on the balance sheet. In managing our exposure to interest rates, we seek
to balance the benefit of lower cost floating rate debt, having refinancing
risk, with fixed rate debt not having this risk. To achieve this objective, we
also use off-balance sheet derivative instruments, primarily non-leveraged
interest rate swaps, to manage identifiable exposures on a non-speculative
basis.
Summarized below are the carrying amounts and fair values of our debt and
debt-related derivatives at December 31, 2000 and 1999. Our use of derivatives
during the periods presented was limited to interest rate swaps, where we either
paid or received the net effect of a fixed rate versus a floating rate
(commercial paper or
> TEXACO 2000 ANNUAL REPORT 61
LIBOR) index at specified intervals, calculated by reference to an agreed
notional principal amount.
(Millions of dollars) As of December 31 2000 1999
================================================================================
Notes Payable and Commercial Paper:
Carrying amount $ 1,801 $ 2,350
Fair value 1,801 2,348
Related Derivatives -
Payable (Receivable):
Carrying amount $ -- $ --
Fair value -- (13)
Notional principal amount $ -- $ 300
Weighted average maturity (years) -- 7.3
Weighted average fixed pay rate -- 6.42%
Weighted average floating
receive rate -- 6.42%
Long-Term Debt, including
current maturities:
Carrying amount $ 5,344 $ 5,251
Fair value 5,465 5,225
Related Derivatives -
Payable (Receivable):
Carrying amount $ (35) $ (19)
Fair value (7) 55
Notional principal amount $ 1,275 $ 1,294
Weighted average maturity (years) 5.3 5.8
Weighted average fixed receive rate 6.18% 5.69%
Weighted average floating pay rate 6.36% 6.10%
Unamortized net gain on
terminated swaps
Carrying amount $ 17 $ 4
================================================================================
Excluded from this table is an interest rate and equity swap with a
notional principal amount of $200 million entered into in 1997, related to the
3-1/2% notes due 2004. We pay a floating rate and receive a fixed rate and the
counterparty assumes all exposure for the potential equity-based cash redemption
premium on the notes. The fair value of this swap was not significant at
year-end 2000 and 1999.
During 2000, floating rate pay swaps aggregating $549 million notional and
fixed rate pay swaps of $300 million notional were terminated or matured. We
initiated $530 million notional of new floating rate pay swaps in connection
with year 2000 debt issues.
Fair values of debt are based upon quoted market prices, where available
and, where not, on interest rates currently available to us for borrowings with
similar terms and maturities. We estimate the fair value of swaps as the amount
that would be received or paid to terminate the agreements at year end, taking
into account current interest rates and the current creditworthiness of the swap
counterparties. The notional amounts of derivative contracts do not represent
cash flow and are not subject to credit risk.
Amounts receivable or payable based on the interest rate differentials of
derivatives are accrued monthly and are reflected in interest expense as a hedge
of interest on outstanding debt. Gains and losses on terminated swaps are
deferred and amortized over the life of the associated debt or the original term
of the swap, whichever is shorter.
NOTE 10 LEASE COMMITMENTS AND RENTAL EXPENSE
We have leasing arrangements involving service stations, tanker charters, crude
oil production and processing equipment and other facilities. We reflect amounts
due under capital leases in our balance sheet as obligations, while we reflect
our interest in the related assets as properties, plant and equipment. The
remaining lease commitments are operating leases, and we record payments on such
leases as rental expense.
As of December 31, 2000, we had estimated minimum commitments for payment
of rentals (net of non-cancelable sublease rentals) under leases which, at
inception, had a non-cancelable term of more than one year, as follows:
Operating Capital
(Millions of dollars) Leases Leases
==========================================================
2001 $ 130 $ 10
2002 421 10
2003 56 9
2004 51 9
2005 40 8
After 2005 287 11
----------------
Total lease commitments $ 985 $ 57
=====
Less interest 11
-----
Present value of total capital
lease obligations $ 46
==========================================================
Operating lease commitments for 2002 include a $304 million residual value
guarantee of leased production facilities if we do not renew the lease.
Rental expense relative to operating leases, including contingent rentals
based on factors such as gallons sold, is provided in the table below. Such
payments do not include rentals on leases covering oil and gas mineral rights.
(Millions of dollars) 2000 1999 1998
================================================================================
Rental expense
Minimum lease rentals $229 $218 $208
Contingent rentals 10 6 --
--------------------------------
Total 239 224 208
Less rental income on
properties subleased
to others 48 54 50
--------------------------------
Net rental expense $191 $170 $158
================================================================================
62 > TEXACO 2000 ANNUAL REPORT
NOTE 11 EMPLOYEE BENEFIT PLANS
Texaco Inc. and certain of its non-U.S. subsidiaries sponsor various benefit
plans for active employees and retirees. The costs of the savings, health care
and life insurance plans relative to employees' active service are shared by the
company and its employees, with Texaco's costs for these plans charged to
expense as incurred. In addition, accruals for employee benefit plans are
provided principally for the unfunded costs of various pension plans, retiree
health and life insurance benefits, incentive compensation plans and for
separation benefits payable to employees.
Employee Stock Ownership Plans (ESOP)
Effective March 1, 2000, the Employees Savings Plan of Texaco Inc. merged into
the Employees Thrift Plan of Texaco Inc. Participants of the Employees Savings
Plan became participants in the Employees Thrift Plan, and the Savings Plan
assets were transferred to the Thrift Plan on May 31, 2000.
We recorded ESOP expense of $1 million in 2000, $3 million in 1999 and $1
million in 1998. Our contributions to the Employees Thrift Plan and the
Employees Savings Plan amounted to $1 million in 2000, $3 million in 1999 and $1
million in 1998. These plans were designed to provide participants with a
benefit of approximately 6% of base pay, as well as any benefits earned under
the current employee Performance Compensation Program. In December 2000, we made
a $14 million advanced company ESOP allocation for the period December 2000
through May 2001 to entitled participants of the Employees Thrift Plan.
During 2000, we paid $20 million in dividends. Dividends on the common ESOP
shares used to service debt of the plans are tax deductible to the company.
The trustee applied the dividends to fund interest payments which amounted
to $1 million, $2 million and $5 million for 2000, 1999 and 1998, as well as to
reduce principal on the Thrift Plan ESOP loan. In November 1998 and December
1997, a portion of the original loan was refinanced through a company loan. The
Thrift Plan ESOP loan was satisfied in December 2000.
Benefit Plan Trust
We have established a benefit plan trust for funding company obligations under
some of our benefit plans. At year-end 2000, the trust contained 9.2 million
shares of treasury stock. We intend to continue to pay our obligations under our
benefit plans. The trust will use the shares, proceeds from the sale of such
shares and dividends on such shares to pay benefits only to the extent that we
do not pay such benefits. The trustee will vote the shares held in the trust as
instructed by the trust's beneficiaries. The shares held by the trust are not
considered outstanding for earnings per share purposes until distributed or sold
by the trust in payment of benefit obligations.
Termination Benefits
In the fourth quarter of 1998, we announced we were restructuring several of our
operations. The principal units affected were our worldwide upstream; our
international downstream, principally our marketing operations in the United
Kingdom and Brazil and our refining operations in Panama; our global gas
marketing operations, now included as part of our global gas, power and energy
technology segment; and our corporate center. In 1998, we recorded an after-tax
charge of $80 million for employee separations, curtailment costs and special
termination benefits associated with our restructuring. The charge was comprised
of $88 million of operating expenses, $27 million of selling, general and
administrative expenses and $35 million in related income tax benefits. We
initially estimated that over 1,400 employee reductions worldwide would occur.
In the second quarter of 1999, we expanded the employee separation programs and
recorded an after-tax charge of $31 million to cover an additional 1,200
employee reductions. The charge was comprised of $36 million of operating
expenses, $12 million of selling, general and administrative expenses and $17
million in related income tax benefits. By the end of the third quarter of 2000,
we had satisfied all remaining obligations in accordance with plan provisions.
Cash payments totaled $151 million and transfers to long-term obligations
totaled $12 million. Employee reductions approximated the original estimates.
During the first quarter of 2000, we announced an additional employee
separation program for our international downstream, primarily our marketing
operations in Brazil and Ireland. We recorded an after-tax charge of $12 million
for employee separations, curtailment costs and special termination benefits for
about 200 employees. The charge was comprised of $17 million of selling, general
and administrative expenses and $5 million in related income tax benefits.
Through December 31, 2000, employee reductions totaled 159. The remaining
reductions will occur by the end of the first quarter of 2001. During the year
2000, we made cash payments of $8 million and transfers to long-term obligations
of $8 million. We will pay the remaining obligations of $1 million in future
periods in accordance with plan provisions.
Pension Plans
We sponsor pension plans that cover the majority of our employees. Generally,
these plans provide defined pension benefits based on years of service, age and
final average pay. Pension plan assets are principally invested in equity and
fixed income securities and deposits with insurance companies.
Total worldwide expense for all employee pension plans of Texaco, including
pension supplementations and smaller non-U.S. plans, was $42 million in 2000,
$41 million in 1999 and $92 million in 1998.
> TEXACO 2000 ANNUAL REPORT 63
The following data are provided for principal U.S. and non-U.S. plans:
Pension Benefits
-----------------------------------------------
2000 1999 Other U.S. Benefits
--------------------- --------------------- ---------------------
(Millions of dollars) As of December 31 U.S. Int'l U.S. Int'l 2000 1999
==================================================================================================================================
Changes in Benefit (Obligations)
Benefit (obligations) at January 1 $(1,664) $ (980) $(1,884) $ (979) $ (633) $ (773)
Service cost (35) (24) (46) (25) (5) (6)
Interest cost (120) (75) (113) (82) (48) (49)
Amendments (2) (3) (29) (23) -- 12
Actuarial gain (loss) (21) (10) (16) (26) (104) 59
Employee contributions (2) -- (3) (1) (18) (14)
Benefits paid 66 64 63 62 71 66
Curtailments/settlements 76 3 364 (2) -- 12
Special termination benefits -- (6) -- -- -- --
Currency adjustments -- 80 -- 96 -- --
Acquisitions/joint ventures -- -- -- -- -- 60
------------------------------------------------------------------------
Benefit (obligations) at December 31 $(1,702) $ (951) $(1,664) $ (980) $ (737) $ (633)
Changes in Plan Assets
Fair value of plan assets at January 1 $ 1,646 $ 1,070 $ 1,826 $ 1,028 $ -- $ --
Actual return on plan assets (41) 19 236 151 -- --
Company contributions 18 22 15 26 53 52
Employee contributions 2 -- 3 1 18 14
Expenses (8) -- (7) -- -- --
Benefits paid (66) (64) (63) (62) (71) (66)
Currency adjustments -- (73) -- (74) -- --
Curtailments/settlements (76) -- (364) -- -- --
------------------------------------------------------------------------
Fair value of plan assets at December 31 $ 1,475 $ 974 $ 1,646 $ 1,070 $ -- $ --
==================================================================================================================================
Funded Status of the Plans
Obligation (greater than) less than assets $ (227) $ 23 $ (18) $ 90 $ (737) $ (633)
Unrecognized net transition asset (2) -- (7) (1) -- --
Unrecognized prior service cost 73 48 85 63 (7) (7)
Unrecognized actuarial (gain) loss 68 85 (161) (17) (32) (143)
------------------------------------------------------------------------
Net (liability) asset recorded in
Texaco's Consolidated Balance Sheet $ (88) $ 156 $ (101) $ 135 $ (776) $ (783)
Net (liability) asset recorded in Texaco's
Consolidated Balance Sheet consists of:
Prepaid benefit asset $ 27 $ 392 $ 84 $ 373 $ -- $ --
Accrued benefit liability (158) (248) (231) (246) (776) (783)
Intangible asset 16 12 23 8 -- --
Other comprehensive income 27 -- 23 -- -- --
------------------------------------------------------------------------
Net (liability) asset recorded in
Texaco's Consolidated Balance Sheet $ (88) $ 156 $ (101) $ 135 $ (776) $ (783)
==================================================================================================================================
Assumptions as of December 31
Discount rate 7.5% 7.8% 8.0% 8.1% 7.5% 8.0%
Expected return on plan assets 10.0% 8.8% 10.0% 8.8% -- --
Rate of compensation increase 4.0% 4.5% 4.0% 5.2% 4.0% 4.0%
Health care cost trend rate -- -- -- -- 4.0% 4.0%
==================================================================================================================================
64 > TEXACO 2000 ANNUAL REPORT
Pension Benefits
---------------------------------------------------
2000 1999 1998 Other U.S. Benefits
--------------- --------------- --------------- ----------------------
(Millions of dollars) As of December 31 U.S. Int'l U.S. Int'l U.S. Int'l 2000 1999 1998
===================================================================================================================================
Components of Net Periodic
Benefit Expenses
Service cost $ 35 $ 24 $ 46 $ 25 $ 60 $ 21 $ 5 $ 6 $ 9
Interest cost 120 75 113 82 117 86 48 49 50
Expected return on plan assets (136) (96) (140) (81) (136) (79) -- -- --
Amortization of transition asset (5) (1) (6) (12) (4) (10) -- -- --
Amortization of prior
service cost 14 9 11 13 11 7 (1) -- --
Amortization of (gain) loss 1 (3) 4 (2) 6 (2) (7) (1) (4)
Curtailments/settlements (7) 8 (15) 2 6 -- -- (12) 1
Special termination charges -- -- -- -- 8 -- -- -- 2
-----------------------------------------------------------------------------
Net periodic benefit expenses $ 22 $ 16 $ 13 $ 27 $ 68 $ 23 $ 45 $ 42 $ 58
===================================================================================================================================
For pension plans with accumulated obligations in excess of plan assets,
the projected benefit obligation and the accumulated benefit obligation were
$410 million and $390 million as of December 31, 2000, and $410 million and $379
million as of December 31, 1999. The fair value of plan assets for both years
was $0.
Other U.S. Benefits
We sponsor postretirement plans in the U.S. that provide health care and life
insurance for retirees and eligible dependents based on an age and service point
schedule for eligible participants. Our U.S. health insurance obligation is our
fixed dollar contribution. The plans are unfunded, and the costs are shared by
us and our employees and retirees. Certain of the company's non-U.S.
subsidiaries have postretirement benefit plans, the cost of which is not
significant to the company.
For measurement purposes, the fixed dollar contribution is expected to
increase by 4% per annum for all future years. A change in our fixed dollar
contribution has a significant effect on the amounts we report. A 1% change in
our contributions would have the following effects:
1-Percentage 1-Percentage
(Millions of dollars) Point Increase Point Decrease
================================================================================
Effect on annual total of service
and interest cost components $ 4 $ (4)
Effect on postretirement
benefit obligation $46 $(41)
================================================================================
NOTE 12 STOCK INCENTIVE PLAN
Under our Stock Incentive Plan, stock options, restricted stock and other
incentive award forms may be granted to executives, directors and key employees
to provide motivation to enhance the company's success and increase shareholder
value. The maximum number of shares that may be awarded as stock options or
restricted stock under the plan is 1% of the common stock outstanding on
December 31 of the previous year. The following table summarizes the number of
shares at December 31, 2000, 1999 and 1998 available for awards during the
subsequent year:
(Shares) As of December 31 2000 1999 1998
================================================================================
To all participants 19,803,026 15,646,336 12,677,325
To those participants not
officers or directors 229,229 2,020,621 1,967,715
------------------------------------------
Total 20,032,255 17,666,957 14,645,040
================================================================================
Restricted shares granted under the plan contain a performance element
which must be satisfied in order for all or a specified portion of the shares to
vest. Restricted performance shares awarded in each year under the plan were as
follows:
2000 1999 1998
================================================================================
Shares 530,878 278,402 334,798
Weighted average fair value $ 56.52 $ 62.78 $ 61.59
================================================================================
Stock options granted under the plan extend for 10 years from the date of
grant and vest over a two-year period at a rate of 50% in the first year and 50%
in the second year. The exercise price cannot be less than the fair market value
of the underlying shares of common stock on the date of the grant. The plan
provides for restored options. This feature enables a participant who exercises
a stock option by exchanging previously acquired common stock or who has shares
withheld by us to satisfy tax withholding obligations, to receive new options
equal to the number of shares exchanged or withheld. The restored options are
fully exercisable six months after the date of grant and the exercise price is
the fair market value of the common stock on the day the restored option is
granted.
We apply APB Opinion 25 in accounting for our stock-based compensation
programs. Stock-based compensation expense recognized in connection with the
plan was $25 million in 2000, $19 million in 1999 and $17 million in 1998. Had
we accounted for our plan using
> TEXACO 2000 ANNUAL REPORT 65
the accounting method recommended by SFAS 123, net income and earnings per share
would have been the pro forma amounts below:
2000 1999 1998
================================================================================
Net income (millions of dollars)
As reported $ 2,542 $ 1,177 $ 578
Pro forma $ 2,525 $ 1,107 $ 524
Earnings per share (dollars)
Basic -- as reported $ 4.66 $ 2.14 $ .99
-- pro forma $ 4.63 $ 2.01 $ .89
Diluted -- as reported $ 4.65 $ 2.14 $ .99
-- pro forma $ 4.62 $ 2.01 $ .89
================================================================================
We used the Black-Scholes model with the following assumptions to estimate
the fair market value of options at date of grant:
On June 30, 1999, after we called the Series B for redemption, each share of
Series B was converted into 25.736 shares, or 15.1 million shares in total, of
common stock.
Series D Junior Participating Preferred Stock and Rights
In 1989, we declared a dividend distribution of one Right for each outstanding
share of common stock. This was adjusted to one-half Right when we declared a
two-for-one stock split in 1997. In 1998, our shareholders approved the
extension of the Rights until May 1, 2004. Unless we redeem the Rights, the
Rights will be exercisable only after a person(s) acquires, obtains the right to
acquire or commences a tender offer that would result in that person(s)
acquiring 20% or more of the outstanding common stock other than pursuant to a
Qualifying Offer. A Qualifying Offer is an all-cash, fully financed tender offer
for all outstanding shares of common stock which remains open for 45 days, which
results in the acquiror owning a majority of the company's voting stock, and in
which the
66 > TEXACO 2000 ANNUAL REPORT
acquiror agrees to purchase for cash all remaining shares of common stock. The
Rights entitle holders to purchase from the company units of Series D Junior
Participating Preferred Stock (Series D). In general, each Right entitles the
holder to acquire shares of Series D, or in certain cases common stock, property
or other securities, at a formula value equal to two times the exercise price of
the Right.
We can redeem the Rights at one cent per Right at any time prior to 10 days
after the Rights become exercisable. Until a Right becomes exercisable, the
holder has no additional voting or dividend rights and it will not have any
dilutive effect on the company's earnings. We have reserved and designated 3
million shares as Series D for issuance upon exercise of the Rights. At December
31, 2000, the Rights were not exercisable. The Rights will not become
exercisable if the proposed merger between Chevron and Texaco is completed in
accordance with the terms and conditions of the Merger Agreement dated October
15, 2000.
Series F ESOP Convertible Preferred Stock
On February 16, 1999, after we called the Series F for redemption, each share of
Series F was converted into 20 shares, or 1.1 million shares in total, of common
stock.
Market Auction Preferred Shares
There are 1,200 shares of cumulative variable rate preferred stock, called
Market Auction Preferred Shares (MAPS) outstanding. The MAPS are grouped into
four series (300 shares each of Series G, H, I and J) of $75 million each, with
an aggregate value of $300 million.
The dividend rates for each series are determined by Dutch auctions
conducted at seven-week or longer intervals.
During 2000, the annual dividend rate for the MAPS ranged between 4.22% and
5.15% and dividends totaled $17 million ($14,189, $14,307, $14,301 and $12,823
per share for series G, H, I and J).
For 1999, the annual dividend rate for the MAPS ranged between 3.59% and
4.36% and dividends totaled $9 million ($7,713, $7,772, $7,989 and $7,935 per
share for Series G, H, I and J).
For 1998, the annual dividend rate for the MAPS ranged between 3.96% and
4.50% and dividends totaled $13 million ($11,280, $11,296, $11,227 and $11,218
per share for Series G, H, I and J).
We may redeem the MAPS, in whole or in part, at any time at a liquidation
preference of $250,000 per share, plus premium, if any, and accrued and unpaid
dividends thereon.
The MAPS are non-voting, except under limited circumstances.
NOTE 14 FINANCIAL INSTRUMENTS
We utilize various types of financial instruments in conducting our business.
Financial instruments encompass assets and liabilities included in the balance
sheet, as well as derivatives which are principally off-balance sheet.
Derivatives are contracts whose value is derived from changes in an
underlying commodity price, interest rate or other item. We use derivatives to
reduce our exposure to changes in foreign exchange rates, interest rates and
crude oil, petroleum products and natural gas prices. Our written policies
restrict our use of derivatives to primarily protecting existing positions and
committed or anticipated transactions. On a limited basis, we may use
commodity-based derivatives to establish a position in anticipation of future
movements in prices or margins. Derivative transactions expose us to
counterparty credit risk. We place contracts only with parties whose
credit-worthiness has been pre-determined under credit policies and limit the
dollar exposure to any counterparty. Therefore, risk of counterparty
non-performance and exposure to concentrations of credit risk are limited.
Cash and Cash Equivalents
Fair value approximates cost as reflected in the Consolidated Balance Sheet at
December 31, 2000 and 1999 because of the short-term maturities of these
instruments. Cash equivalents are classified as held-to-maturity. The amortized
cost of cash equivalents at December 31, 2000 includes $34 million of time
deposits and $16 million of commercial paper. Comparable amounts at year-end
1999 were $67 million and $165 million.
Short-Term and Long-Term Investments
Fair value is primarily based on quoted market prices and valuation statements
obtained from major financial institutions. At December 31, 2000, our
available-for-sale securities had an estimated fair value of $168 million,
including gross unrealized gains of $9 million and losses of $5 million. At
December 31, 1999, our available-for-sale securities had an estimated fair value
of $167 million, including gross unrealized gains of $11 million and losses of
$6 million. The available-for-sale securities consist primarily of debt
securities issued by U.S. and foreign governments and corporations. The majority
of these investments mature within five years.
Proceeds from sales of available-for-sale securities were $224 million in
2000, $750 million in 1999 and $1,011 million in 1998. These sales resulted in
gross realized gains of $8 million in 2000, $45 million in 1999 and $53 million
in 1998, and gross realized losses of $7 million, $13 million and $22 million.
The estimated fair value of other long-term investments qualifying as
financial instruments but not included above, for which it is practicable to
estimate fair value, approximated the December 31, 2000 and 1999 carrying values
of $549 million and $465 million.
Short-Term Debt, Long-Term Debt and Related Derivatives
Refer to Note 9 for additional information about debt and related derivatives
outstanding at December 31, 2000 and 1999.
> TEXACO 2000 ANNUAL REPORT 67
Forward Exchange and Option Contracts
As an international company, we are exposed to currency exchange risk. To hedge
against adverse changes in foreign currency exchange rates, we will enter into
forward and option contracts to buy and sell foreign currencies. Shown below in
U.S. dollars are the notional amounts of outstanding forward exchange contracts
to buy and sell foreign currencies.
(Millions of dollars) Buy Sell
================================================================================
Australian dollars $ 230 $ 31
British pounds 856 365
Danish kroner 215 90
Euro 293 92
New Zealand dollars 117 26
Other currencies 59 26
---------------------
Total at December 31, 2000 $1,770 $630
Total at December 31, 1999 $2,122 $272
================================================================================
Market risk exposure on these contracts is essentially limited to currency
rate movements. At year-end 2000, there were $58 million of unrealized gains and
$2 million of unrealized losses related to these contracts. At year-end 1999,
there were $10 million of unrealized gains and $30 million of unrealized losses.
We use forward exchange contracts to buy foreign currencies primarily to
hedge the net monetary liability position of our European, Australian and New
Zealand operations and to hedge portions of significant foreign currency capital
expenditures and lease commitments. These contracts generally have terms of 60
days or less. Contracts that hedge foreign currency monetary positions are
marked-to-market monthly. Any resultant gains and losses are included in the
Consolidated Statement of Income as other costs. At year-end 2000 and 1999,
hedges of foreign currency commitments principally involved capital projects
requiring expenditure of British pounds and Danish kroner. The percentages of
planned capital expenditures hedged at year end were: British pounds -- 72% in
2000 and 90% in 1999; Danish kroner -- 87% in 2000 and 94% in 1999. Realized
gains and losses on hedges of foreign currency commitments are initially
recorded to deferred charges. Subsequently, the amounts are applied to the
capitalized project cost on a percentage-of-completion basis, and are then
amortized over the lives of the applicable projects. At year-end 2000 and 1999,
net hedging losses of $18 million and net hedging gains of $17 million had yet
to be amortized.
We sell foreign currencies under a separately managed program to hedge the
value of our investment portfolio denominated in foreign currencies. Our
strategy is to hedge the full value of this portion of our investment portfolio
and to close out forward contracts upon the sale or maturity of the
corresponding investments. We value these contracts at market based on the
foreign exchange rates in effect on the balance sheet dates. We record changes
in the value of these contracts as part of the carrying amount of the related
investments. We record related gains and losses, net of applicable income taxes,
to stockholders' equity until the underlying investments are sold or mature.
Preferred Shares of Subsidiaries
Refer to Note 15 regarding derivatives related to subsidiary preferred shares.
Petroleum and Natural Gas Hedging
We hedge a portion of the market risks associated with our crude oil, natural
gas and petroleum product purchases, sales and exchange activities to reduce
price exposure. All hedge transactions are subject to the company's corporate
risk management policy which sets out dollar, volumetric and term limits, as
well as to management approvals as set forth in our delegations of authorities.
We use established petroleum futures exchanges, as well as
"over-the-counter" hedge instruments, including futures, options, swaps and
other derivative products. In carrying out our hedging programs, we analyze our
major commodity streams for fixed cost, fixed revenue and margin exposure to
market price changes. Based on this corporate risk profile, forecasted trends
and overall business objectives, we determine an appropriate strategy for risk
reduction.
Hedge positions are marked-to-market for valuation purposes. Gains and
losses on hedge transactions, which offset losses and gains on the underlying
"cash market" transactions, are recorded to deferred income or charges until the
hedged transaction is closed, or until the anticipated future purchases, sales
or production occur. At that time, any gain or loss on the hedging contract is
recorded to operating revenues as an increase or decrease in margins, or to
inventory, as appropriate. Derivative transactions not designated as hedging a
specific position or transaction are adjusted to market at each balance sheet
date. Gains and losses are included in operating income.
At December 31, 2000 and 1999, there were open derivative commodity
contracts required to be settled in cash, consisting mostly of basis swaps
related to location differences in prices. Notional contract amounts, excluding
unrealized gains and losses, were $9,077 million and $6,604 million at year-end
2000 and 1999. These amounts principally represent future values of contract
volumes over the remaining duration of outstanding swap contracts at the
respective dates. These contracts hedge a small fraction of our business
activities, generally for the next 12 months. Unrealized gains and losses on
contracts outstanding at year-end 2000 were $641 million and $423 million.
At year-end 1999, unrealized gains and losses were $195 million and $132
million.
68 > TEXACO 2000 ANNUAL REPORT
NOTE 15 OTHER FINANCIAL INFORMATION, COMMITMENTS AND CONTINGENCIES
Environmental Liabilities
Texaco Inc. and subsidiary companies have financial liabilities relating to
environmental remediation programs which we believe are sufficient for known
requirements. At December 31, 2000, the balance sheet includes liabilities of
$260 million for future environmental remediation costs. Also, we have accrued
$665 million for the future cost of restoring and abandoning existing oil and
gas properties.
We have accrued for our probable environmental remediation liabilities to
the extent reasonably measurable. We based our accruals for these obligations on
technical evaluations of the currently available facts, interpretation of the
regulations and our experience with similar sites. Additional accrual
requirements for existing and new remediation sites may be necessary in the
future when more facts are known. The potential also exists for further
legislation which may provide limitations on liability. It is not possible to
project the overall costs or a range of costs for environmental items beyond
that disclosed above. This is due to uncertainty surrounding future
developments, both in relation to remediation exposure and to regulatory
initiatives. We believe that such future costs will not be material to our
financial position or to our operating results over any reasonable period of
time.
Preferred Shares of Subsidiaries
Minority holders own $602 million of preferred shares of our subsidiary
companies, which is reflected as minority interest in subsidiary companies in
the Consolidated Balance Sheet.
MVP Production Inc., a subsidiary, has variable rate cumulative preferred
shares of $75 million owned by one minority holder. The shares have voting
rights and are redeemable in 2003. Dividends on these shares were $4 million in
2000, 1999 and 1998.
Texaco Capital LLC, a wholly-owned finance subsidiary of Texaco Inc., has
three classes of preferred shares, all held by minority holders. The first class
is 14 million shares totaling $350 million of Cumulative Guaranteed Monthly
Income Preferred Shares, Series A (Series A). The second class is 4.5 million
shares totaling $112 million of Cumulative Adjustable Rate Monthly Income
Preferred Shares, Series B (Series B). The third class, issued in Canadian
dollars, is 3.6 million shares totaling $65 million of Deferred Preferred
Shares, Series C (Series C). Texaco Capital LLC's sole assets are notes
receivable from Texaco Inc. The payment of dividends and payments on liquidation
or redemption with respect to Series A, Series B and Series C are fully and
unconditionally guaranteed by Texaco Inc.
The fixed dividend rate for Series A is 6-7/8% per annum. The annual
dividend rate for Series B averaged 5.4% for 2000, 5.0% for 1999 and 5.1% for
1998. The dividend rate on Series B is reset quarterly per contractual formula.
Dividends on Series A and Series B are paid monthly. Dividends on Series A for
2000, 1999 and 1998 totaled $24 million for each year. Annual dividends on
Series B totaled $6 million for 2000, 1999 and 1998.
Series A and Series B are redeemable under certain circumstances at the
option of Texaco Capital LLC (with Texaco Inc.'s consent) in whole or in part at
$25 per share plus accrued and unpaid dividends to the date fixed for
redemption.
Dividends on Series C at a rate of 7.17% per annum, compounded annually,
will be paid at the redemption date of February 28, 2005, unless earlier
redemption occurs. Early redemption may result upon the occurrence of certain
specific events.
We have entered into an interest rate and currency swap related to Series C
preferred shares. The swap matures in the year 2005. Over the life of the
interest rate swap component of the contract, we will make LIBOR-based floating
rate interest payments based on a notional principal amount of $65 million.
Canadian dollar interest will accrue to us at a fixed rate applied to the
accreted notional principal amount, which was Cdn. $87 million at the inception
of the swap.
The currency swap component of the transaction calls for us to exchange at
contract maturity date $65 million for Cdn. $170 million, representing Cdn. $87
million plus accrued interest. The carrying amount of this contract represents
the Canadian dollar accrued interest receivable by us. At year-end 2000 and
1999, the carrying amounts of this swap, which approximated fair value, were $27
million and $20 million.
Series A, Series B and Series C preferred shares are non-voting, except
under limited circumstances.
The above preferred stock issues currently require annual dividend payments
of approximately $34 million. We are required to redeem $75 million of this
preferred stock in 2003, $65 million (plus accreted dividends of $59 million) in
2005, $112 million in 2024 and $350 million in 2043. We have the ability to
extend the required redemption dates for the $112 million and $350 million of
preferred stock beyond 2024 and 2043.
Pending Award
In July 1999, the Governing Council of the United Nations Compensation
Commission (UNCC) approved an award to Saudi Arabian Texaco Inc. (SAT), a
wholly-owned subsidiary of Texaco Inc., of about $505 million, plus unspecified
interest, for damages sustained as a result of Iraq's invasion of Kuwait in
1990. Payments to SAT are subject to income tax in Saudi Arabia at an applicable
tax rate of 85%. SAT is party to a concession agreement with the Kingdom of
Saudi Arabia covering the Partitioned Neutral Zone in Southern Kuwait and
Northern Saudi Arabia.
> TEXACO 2000 ANNUAL REPORT 69
UNCC funds compensation awards by retaining 30% of Iraqi oil sales revenue
under an agreement with Iraq. In January 2001, SAT was paid $5 million and
expects to be paid an additional $40 million in the near future. We do not know
when we will receive the balance of this award since the timing of payments by
UNCC depends on several factors, including the total amount of all compensation
awards, the ability of Iraq to produce and sell oil, the price of Iraqi oil and
the duration of U.N. trade sanctions on Iraq. This award will be recognized in
income when collection is assured.
Financial Guarantees
We have guaranteed the payment of certain debt, lease commitments and other
obligations of third parties and affiliate companies. These guarantees totaled
$792 million and $804 million at December 31, 2000 and 1999. The year-end 2000
and 1999 amounts include $399 million and $424 million of operating lease
commitments of Equilon, our affiliate.
Exposure to credit risk in the event of non-payment by the obligors is
represented by the contractual amount of these instruments. No loss is
anticipated under these guarantees.
Throughput Agreements
Texaco Inc. and certain of its subsidiary companies previously entered into
certain long-term agreements wherein we committed to ship through affiliated
pipeline companies and an offshore oil port sufficient volume of crude oil or
petroleum products to enable these affiliated companies to meet a specified
portion of their individual debt obligations, or, in lieu thereof, to advance
sufficient funds to enable these affiliated companies to meet these obligations.
In 1998, we assigned the shipping obligations to Equilon, our affiliate, but
Texaco remains responsible for deficiency payments on virtually all of these
agreements. Additionally, Texaco has entered into long-term purchase commitments
with third parties for take or pay gas transportation. At December 31, 2000 and
1999, our maximum exposure to loss was estimated to be $388 million and $445
million.
However, based on our right of counterclaim against Equilon and
unaffiliated third parties in the event of non-performance, our net exposure was
estimated to be $148 million and $173 million at December 31, 2000 and 1999.
No significant losses are anticipated as a result of these obligations.
Litigation
Texaco and approximately 50 other oil companies are defendants in 17 purported
class actions. The actions are pending in Texas, New Mexico, Oklahoma,
Louisiana, Utah, Mississippi and Alabama. The plaintiffs allege that the
defendants undervalued oil produced from properties leased from the plaintiffs
by establishing artificially low selling prices. They allege that these low
selling prices resulted in the defendants underpaying royalties or severance
taxes to them. Plaintiffs seek to recover royalty underpayments and interest. In
some cases plaintiffs also seek to recover severance taxes and treble and
punitive damages. Texaco and 24 other defendants have executed a settlement
agreement with most of the plaintiffs that will resolve many of these disputes.
The federal court in Texas gave final approval to the settlement in April 1999
and the matter is now pending before the U.S. Fifth Circuit Court of Appeal.
Texaco has reached an agreement with the federal government to resolve
similar claims. The claims of various state governments remain unresolved.
It is impossible for us to ascertain the ultimate legal and financial liability
with respect to contingencies and commitments. However, we do not anticipate
that the aggregate amount of such liability in excess of accrued liabilities
will be materially important in relation to our consolidated financial position
or results of operations.
NOTE 16 CHEVRON-TEXACO MERGER
On October 15, 2000, Texaco and Chevron Corporation entered into a merger
agreement. In the merger, Texaco shareholders will receive .77 shares of Chevron
common stock for each share of Texaco common stock they own, and Chevron
shareholders will retain their existing shares.
The merger is conditioned, among other things, on the approval of the
shareholders of both companies, pooling of interests accounting treatment for
the merger and approvals of government agencies, such as the U.S. Federal Trade
Commission (FTC). Texaco and Chevron anticipate that the FTC will require
certain divestitures in the U.S. downstream in order to address market
concentration issues, and the companies intend to cooperate with the FTC in this
process. In that regard, Texaco is in discussions with our partners in the U.S.
downstream.
The merger agreement provides for the payment of termination fees of as
much as $1 billion by either party under certain circumstances. Chevron and
Texaco also were granted options to purchase shares of the other, under the same
conditions as the payments of the termination fees. Texaco granted Chevron an
option to purchase 107 million shares of Texaco's common stock, at $53.71 per
share. Chevron granted Texaco an option to purchase 127 million shares of
Chevron's common stock, at $85.96 per share.
70 > TEXACO 2000 ANNUAL REPORT
REPORT OF MANAGEMENT
We are responsible for preparing Texaco's consolidated financial statements in
accordance with generally accepted accounting principles. In doing so, we must
use judgment and estimates when the outcome of events and transactions is not
certain. Information appearing in other sections of this Annual Report is
consistent with the financial statements.
Texaco's financial statements are based on its financial records. We rely
on Texaco's internal control system to provide us reasonable assurance these
financial records are being accurately and objectively maintained and the
company's assets are being protected. The internal control system comprises:
> Corporate Conduct Guidelines requiring all employees to obey all applicable
laws, comply with company policies and maintain the highest ethical
standards in conducting company business,
> An organizational structure in which responsibilities are defined and
divided, and
> Written policies and procedures that cover initiating, reviewing, approving
and recording transactions.
We require members of our management team to formally certify each year that the
internal controls for their business units are operating effectively.
Texaco's internal auditors review and report on the effectiveness of
internal controls during the course of their audits. Arthur Andersen LLP,
selected by the Audit Committee and approved by stockholders, independently
audits Texaco's financial statements. Arthur Andersen LLP assesses the adequacy
and effectiveness of Texaco's internal controls when determining the nature,
timing and scope of their audit. We seriously consider all suggestions for
improving Texaco's internal controls that are made by the internal and
independent auditors.
The Audit Committee is comprised of six directors who are not employees of
Texaco. This Committee reviews and evaluates Texaco's accounting policies and
reporting practices, internal auditing, internal controls, security and other
matters. The Committee also evaluates the independence and professional
competence of Arthur Andersen LLP and reviews the results and scope of their
audit. The internal and independent auditors have free access to the Committee
to discuss financial reporting and internal control issues.
/s/ Glenn F. Tilton
Glenn F. Tilton
Chairman of the Board and Chief Executive Officer
/s/ Patrick J. Lynch
Patrick J. Lynch
Senior Vice President and Chief Financial Officer
/s/ George J. Batavick
George J. Batavick
Comptroller
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders, Texaco Inc.:
We have audited the accompanying consolidated balance sheet of Texaco Inc. (a
Delaware corporation) and subsidiary companies as of December 31, 2000 and 1999,
and the related consolidated statements of income, stockholders' equity,
comprehensive income and cash flows for each of the three years in the period
ended December 31, 2000. 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 auditing standards generally
accepted in the United States. 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, the financial statements referred to above present fairly,
in all material respects, the financial position of Texaco Inc. and subsidiary
companies as of December 31, 2000 and 1999, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 2000 in conformity with accounting principles generally accepted in the
United States.
/s/ Arthur Andersen LLP
Arthur Andersen LLP
February 22, 2001
New York, N.Y.
> TEXACO 2000 ANNUAL REPORT 71
SUPPLEMENTAL OIL AND GAS INFORMATION
The following pages provide information required by Statement of Financial
Accounting Standards No. 69, "Disclosures about Oil and Gas Producing
Activities."
Table I -- Net Proved Reserves
The reserve quantities include only those quantities that are recoverable based
upon reasonable estimates from sound geological and engineering principles. As
additional information becomes available, these estimates may be revised. Also,
we have a large inventory of potential hydrocarbon resources that we expect will
increase our reserve base as future investments are made in exploration and
development programs.
> Proved developed reserves are reserves that we expect to be recovered
through existing wells with existing equipment and operating methods.
> Proved undeveloped reserves are reserves that we expect to be recovered
from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for completion of development.
---------------------------------------------------------------------------------------------------------------------------------
Table I -- Net Proved Reserves
Net Proved Reserves of Crude Oil and Natural Gas Liquids (Millions of barrels)
Consolidated Subsidiaries Equity
----------------------------------------------- --------------------------------
Affiliate Affiliate
United Other Other -- Other -- Other World-
States West Europe East Total West East Total wide
=================================================================================================================================
Developed reserves 1,374 54 210 463 2,101 -- 354 354 2,455
Undeveloped reserves 393 11 221 90 715 -- 97 97 812
-------------------------------------------------------------------------------------------
As of December 31, 1997 1,767 65 431 553 2,816 -- 451 451 3,267
Discoveries & extensions 70 2 8 32 112 -- 1 1 113
Improved recovery 136 -- 16 3 155 -- 156 156 311
Revisions 46 (15) 22 55 108 -- 137 137 245
Net purchases (sales) (38) -- -- 26 (12) -- -- -- (12)
Production (157) (4) (58) (71) (290) -- (61) (61) (351)
-------------------------------------------------------------------------------------------
Total changes 57 (17) (12) 45 73 -- 233 233 306
Developed reserves 1,415 39 246 490 2,190 -- 456 456 2,646
Undeveloped reserves 409 9 173 108 699 -- 228 228 927
-------------------------------------------------------------------------------------------
As of December 31, 1998* 1,824 48 419 598 2,889 -- 684 684 3,573
Discoveries & extensions 66 11 23 23 123 -- 2 2 125
Improved recovery 34 -- 2 29 65 -- 52 52 117
Revisions 11 -- 36 72 119 -- (132) (132) (13)
Net purchases (sales) (9) -- -- 23 14 -- -- -- 14
Production (144) (4) (53) (75) (276) -- (60) (60) (336)
-------------------------------------------------------------------------------------------
Total changes (42) 7 8 72 45 -- (138) (138) (93)
Developed reserves 1,361 39 261 545 2,206 -- 316 316 2,522
Undeveloped reserves 421 16 166 125 728 -- 230 230 958
-------------------------------------------------------------------------------------------
As of December 31, 1999* 1,782 55 427 670 2,934 -- 546 546 3,480
Discoveries & extensions 39 -- 21 9 69 374 -- 374 443
Improved recovery 25 -- -- 39 64 -- 14 14 78
Revisions (21) -- 9 30 18 -- 37 37 55
Net purchases (sales) (135) (52) (44) -- (231) -- -- -- (231)
Production (130) (3) (44) (78) (255) -- (52) (52) (307)
-------------------------------------------------------------------------------------------
Total changes (222) (55) (58) -- (335) 374 (1) 373 38
Developed reserves 1,202 -- 219 559 1,980 -- 282 282 2,262
Undeveloped reserves 358 -- 150 111 619 374 263 637 1,256
-------------------------------------------------------------------------------------------
As of December 31, 2000* 1,560 -- 369 670 2,599 374 545 919 3,518
-------------------------------------------------------------------------------------------
*Includes net proved
NGL reserves
As of December 31, 1998 250 -- 68 22 340 -- 6 6 346
As of December 31, 1999 250 -- 74 134 458 -- 1 1 459
As of December 31, 2000 219 -- 67 162 448 -- 1 1 449
=================================================================================================================================
72 > TEXACO 2000 ANNUAL REPORT
Table I -- Net Proved Reserves (continued)
Net Proved Reserves of Natural Gas (Billions of cubic feet)
Consolidated Subsidiaries Equity
----------------------------------------------- --------------------------------
Affiliate Affiliate
United Other Other -- Other -- Other World-
States West Europe East Total West East Total wide
=================================================================================================================================
Developed reserves 3,379 792 576 110 4,857 -- 145 145 5,002
Undeveloped reserves 643 126 452 2 1,223 -- 17 17 1,240
-------------------------------------------------------------------------------------------
As of December 31, 1997 4,022 918 1,028 112 6,080 -- 162 162 6,242
Discoveries & extensions 599 6 47 98 750 -- 1 1 751
Improved recovery 4 -- 7 -- 11 -- 3 3 14
Revisions 152 (12) (6) 34 168 -- 10 10 178
Net purchases (sales) (39) -- -- 250 211 -- -- -- 211
Production (633) (92) (112) (17) (854) -- (25) (25) (879)
-------------------------------------------------------------------------------------------
Total changes 83 (98) (64) 365 286 -- (11) (11) 275
Developed reserves 3,345 688 615 374 5,022 -- 135 135 5,157
Undeveloped reserves 760 132 349 103 1,344 -- 16 16 1,360
-------------------------------------------------------------------------------------------
As of December 31, 1998 4,105 820 964 477 6,366 -- 151 151 6,517
Discoveries & extensions 442 7 93 42 584 -- 5 5 589
Improved recovery 4 -- 2 235 241 -- 1 1 242
Revisions 285 193 7 427 912 -- 3 3 915
Net purchases (sales) (81) -- -- 712 631 -- -- -- 631
Production (550) (79) (104) (27) (760) -- (26) (26) (786)
-------------------------------------------------------------------------------------------
Total changes 100 121 (2) 1,389 1,608 -- (17) (17) 1,591
Developed reserves 3,388 865 557 787 5,597 -- 131 131 5,728
Undeveloped reserves 817 76 405 1,079 2,377 -- 3 3 2,380
-------------------------------------------------------------------------------------------
As of December 31, 1999 4,205 941 962 1,866 7,974 -- 134 134 8,108
Discoveries & extensions 585 -- -- -- 585 33 4 37 622
Improved recovery 5 -- -- -- 5 -- -- -- 5
Revisions 121 12 43 164 340 -- 8 8 348
Net purchases (sales) 8 (58) (11) -- (61) -- -- -- (61)
Production (494) (95) (81) (36) (706) -- (24) (24) (730)
-------------------------------------------------------------------------------------------
Total changes 225 (141) (49) 128 163 33 (12) 21 184
Developed reserves 3,299 738 573 977 5,587 -- 121 121 5,708
Undeveloped reserves 1,131 62 340 1,017 2,550 33 1 34 2,584
-------------------------------------------------------------------------------------------
As of December 31, 2000 4,430 800* 913 1,994 8,137* 33 122 155 8,292*
=================================================================================================================================
* Additionally, there are approximately 302 BCF of natural gas in Other West
which will be available from production during the period 2005-2016 under a
long-term purchase associated with a service agreement.
The following chart summarizes our experience in finding new quantities of
oil and gas to replace our production. Our reserve replacement performance is
calculated by dividing our reserve additions by our production. Our additions
relate to new discoveries, existing reserve extensions, improved recoveries and
revisions to previous reserve estimates. The chart excludes oil and gas
quantities from purchases and sales.
Worldwide United States International
=========================================================================
Year 2000 172% 76% 267%
Year 1999 111% 99% 124%
Year 1998 166% 144% 191%
3-year average 150% 109% 192%
5-year average 146% 108% 189%
> TEXACO 2000 ANNUAL REPORT 73
Table II -- Standardized Measure
The standardized measure provides a common benchmark among those companies that
have exploration and producing activities. This measure may not necessarily
match our view of the future cash flows from our proved reserves.
The standardized measure is calculated at a 10% discount. Future revenues
are based on year-end prices for oil and gas. Future production and development
costs are based on current year costs. Extensive judgment is used to estimate
the timing of production and future costs over the remaining life of the
reserves. Future income taxes are calculated using each country's statutory tax
rate.
Our inventory of potential hydrocarbon resources, which may become proved
in the future, are excluded. This could significantly impact our standardized
measure in the future.
-----------------------------------------------------------------------------------------------
Table II -- Standardized Measure of Discounted Future Net Cash Flows
Consolidated Subsidiaries
-------------------------------------------------------
United Other Other
(Millions of dollars) States West Europe East Total
===============================================================================================
As of December 31, 2000
Future cash inflows from sale of
oil & gas, and service fee revenue $ 67,115 $ 1,559 $ 10,549 $ 15,512 $ 94,735
Future production costs (13,107) (252) (2,074) (2,768) (18,201)
Future development costs (3,588) (30) (1,244) (1,280) (6,142)
Future income tax expense (17,024) (612) (2,238) (6,681) (26,555)
-------------------------------------------------------
Net future cash flows
before discount 33,396 665 4,993 4,783 43,837
10% discount for timing of
future cash flows (15,407) (259) (1,778) (2,239) (19,683)
-------------------------------------------------------
Standardized measure of
discounted future net cash flows $ 17,989 $ 406 $ 3,215 $ 2,544 $ 24,154
===============================================================================================
As of December 31, 1999
Future cash inflows from sale of
oil & gas, and service fee revenue $ 45,281 $ 2,668 $ 11,875 $ 16,890 $ 76,714
Future production costs (10,956) (913) (2,264) (2,946) (17,079)
Future development costs (3,853) (239) (1,749) (1,956) (7,797)
Future income tax expense (8,304) (758) (2,428) (7,665) (19,155)
-------------------------------------------------------
Net future cash flows
before discount 22,168 758 5,434 4,323 32,683
10% discount for timing of
future cash flows (10,816) (327) (1,985) (2,243) (15,371)
-------------------------------------------------------
Standardized measure of
discounted future net cash flows $ 11,352 $ 431 $ 3,449 $ 2,080 $ 17,312
===============================================================================================
As of December 31, 1998
Future cash inflows from sale of
oil & gas, and service fee revenue $ 23,147 $ 1,657 $ 6,581 $ 4,816 $ 36,201
Future production costs (10,465) (605) (2,574) (2,551) (16,195)
Future development costs (4,055) (142) (1,695) (761) (6,653)
Future income tax expense (2,583) (419) (715) (1,023) (4,740)
-------------------------------------------------------
Net future cash flows
before discount 6,044 491 1,597 481 8,613
10% discount for timing of
future cash flows (2,626) (244) (644) (167) (3,681)
-------------------------------------------------------
Standardized measure of
discounted future net cash flows $ 3,418 $ 247 $ 953 $ 314 $ 4,932
===============================================================================================
---------------------------------------------------------------------------------------
Table II -- Standardized Measure of Discounted Future Net Cash Flows
Equity
---------------------------------
Affiliate Affiliate
-- Other -- Other World-
(Millions of dollars) West East Total wide
=======================================================================================
As of December 31, 2000
Future cash inflows from sale of
oil & gas, and service fee revenue $ 3,917 $ 7,873 $ 11,790 $ 106,525
Future production costs (273) (2,853) (3,126) (21,327)
Future development costs (406) (694) (1,100) (7,242)
Future income tax expense (1,101) (2,189) (3,290) (29,845)
-----------------------------------------------
Net future cash flows
before discount 2,137 2,137 4,274 48,111
10% discount for timing of
future cash flows (1,431) (809) (2,240) (21,923)
-----------------------------------------------
Standardized measure of
discounted future net cash flows $ 706 $ 1,328 $ 2,034 $ 26,188
=======================================================================================
As of December 31, 1999
Future cash inflows from sale of
oil & gas, and service fee revenue $ -- $ 7,646 $ 7,646 $ 84,360
Future production costs -- (2,254) (2,254) (19,333)
Future development costs -- (767) (767) (8,564)
Future income tax expense -- (2,340) (2,340) (21,495)
-----------------------------------------------
Net future cash flows
before discount -- 2,285 2,285 34,968
10% discount for timing of
future cash flows -- (887) (887) (16,258)
-----------------------------------------------
Standardized measure of
discounted future net cash flows $ -- $ 1,398 $ 1,398 $ 18,710
=======================================================================================
As of December 31, 1998
Future cash inflows from sale of
oil & gas, and service fee revenue $ -- $ 4,708 $ 4,708 $ 40,909
Future production costs -- (1,992) (1,992) (18,187)
Future development costs -- (803) (803) (7,456)
Future income tax expense -- (967) (967) (5,707)
-----------------------------------------------
Net future cash flows
before discount -- 946 946 9,559
10% discount for timing of
future cash flows -- (391) (391) (4,072)
-----------------------------------------------
Standardized measure of
discounted future net cash flows $ -- $ 555 $ 555 $ 5,487
=======================================================================================
74 > TEXACO 2000 ANNUAL REPORT
Table III -- Changes in the Standardized Measure
The annual change in the standardized measure is explained in this table by the
major sources of change, discounted at 10%.
> Sales & transfers, net of production costs capture the current year's
revenues less the associated producing expenses. The net amount reflected
here correlates to Table VII for revenues less production costs.
> Net changes in prices, production & development costs are computed before
the effects of changes in quantities. The beginning-of-the-year production
forecast is multiplied by the net annual change in the unit sales price and
production cost.
> Discoveries & extensions indicate the value of the new reserves at year-end
prices, less related costs.
> Development costs incurred during the period capture the current year's
development costs that are shown in Table V. These costs will reduce the
previously estimated future development costs.
> Accretion of discount represents 10% of the beginning discounted future net
cash flows before income tax effects.
> Net change in income taxes is computed as the change in present value of
future income taxes.
-----------------------------------------------------------------------------------------------------------------------------
Table III -- Changes in the Standardized Measure
Worldwide Including
Equity in Affiliates
----------------------------------------
(Millions of dollars) 2000 1999 1998
=============================================================================================================================
Standardized measure - beginning of year $ 18,710 $ 5,487 $ 12,057
Sales of minerals-in-place (3,990) (352) (160)
----------------------------------------
14,720 5,135 11,897
Changes in ongoing oil and gas operations:
Sales and transfers of produced oil and gas,
net of production costs during the period (7,345) (4,276) (3,129)
Net changes in prices, production and development costs 11,389 22,036 (11,205)
Discoveries and extensions and improved recovery, less related costs 4,543 1,821 728
Development costs incurred during the period 2,043 1,598 1,770
Timing of production and other changes 670 (517) (1,170)
Revisions of previous quantity estimates 668 301 852
Purchases of minerals-in-place 901 895 48
Accretion of discount 3,120 881 1,916
Net change in discounted future income taxes (4,521) (9,164) 3,780
----------------------------------------
Standardized measure -- end of year $ 26,188 $ 18,710 $ 5,487
=============================================================================================================================
> TEXACO 2000 ANNUAL REPORT 75
Table IV - Capitalized Costs
Costs of the following assets are capitalized under the "successful efforts"
method of accounting. These costs include the activities of Texaco's upstream
operations but exclude the crude oil marketing and other non-producing
activities. As a result, this table will not correlate to information in Note 6
to the financial statements.
> Proved properties include mineral properties with proved reserves,
development wells and uncompleted development well costs.
> Unproved properties include leaseholds under exploration (even where
hydrocarbons were found but not in sufficient quantities to be considered
proved reserves) and uncompleted exploratory well costs.
> Support equipment and facilities include costs for seismic and drilling
equipment, construction and grading equipment, repair shops, warehouses and
other supporting assets involved in oil and gas producing activities.
> The accumulated depreciation, depletion and amortization represents the
portion of the assets that have been charged to expense in prior periods.
It also includes provisions for future restoration and abandonment
activity.
-----------------------------------------------------------------------------------------------------------------------------------
Table IV -- Capitalized Costs
Consolidated Subsidiaries Equity
-------------------------------------------------- -------------------------------
Affiliate Affiliate
United Other Other -- Other -- Other World-
(Millions of dollars) States West Europe East Total West* East Total wide
===================================================================================================================================
As of December 31, 2000
Proved properties $ 18,213 $ 137 $ 3,295 $ 3,699 $ 25,344 $ 66 $ 1,370 $ 1,436 $ 26,780
Unproved properties 1,026 98 58 655 1,837 68 265 333 2,170
Support equipment and facilities 257 81 28 135 501 42 906 948 1,449
----------------------------------------------------------------------------------------------
Gross capitalized costs 19,496 316 3,381 4,489 27,682 176 2,541 2,717 30,399
Accumulated depreciation,
depletion and amortization (12,084) (92) (1,821) (1,508) (15,505) (1) (1,349) (1,350) (16,855)
----------------------------------------------------------------------------------------------
Net capitalized costs $ 7,412 $ 224 $ 1,560 $ 2,981 $ 12,177 $ 175 $ 1,192 $ 1,367 $ 13,544
===================================================================================================================================
As of December 31, 1999
Proved properties $ 20,364 $ 304 $ 5,327 $ 2,525 $ 28,520 $ -- $ 1,158 $ 1,158 $ 29,678
Unproved properties 983 139 50 619 1,791 -- 335 335 2,126
Support equipment and facilities 441 267 37 277 1,022 -- 902 902 1,924
----------------------------------------------------------------------------------------------
Gross capitalized costs 21,788 710 5,414 3,421 31,333 -- 2,395 2,395 33,728
Accumulated depreciation,
depletion and amortization (13,855) (298) (3,955) (1,365) (19,473) -- (1,217) (1,217) (20,690)
----------------------------------------------------------------------------------------------
Net capitalized costs $ 7,933 $ 412 $ 1,459 $ 2,056 $ 11,860 $ -- $ 1,178 $ 1,178 $ 13,038
===================================================================================================================================
* Existing costs were transferred from a consolidated subsidiary to an
affiliate at year-end 2000.
76 > TEXACO 2000 ANNUAL REPORT
Table V -- Costs Incurred
This table summarizes how much we spent to explore and develop our existing
reserve base, and how much we spent to acquire mineral rights from others
(classified as proved or unproved).
> Exploration costs include geological and geophysical costs, the cost of
carrying and retaining undeveloped properties and exploratory drilling
costs.
> Development costs include the cost of drilling and equipping development
wells and constructing related production facilities for extracting,
treating, gathering and storing oil and gas from proved reserves.
> Exploration and development costs may be capitalized or expensed, as
applicable. Such costs also include administrative expenses and
depreciation applicable to support equipment associated with these
activities. As a result, the costs incurred will not correlate to Capital
and Exploratory Expenditures.
On a worldwide basis, in 2000 we spent $3.62 for each BOE we added. Finding and
development costs averaged $3.74 for the three-year period 1998-2000 and $3.92
per BOE for the five-year period 1996-2000.
-----------------------------------------------------------------------------------------------------------------------------------
Table V -- Costs Incurred
Consolidated Subsidiaries Equity
----------------------------------------------- ------------------------------
Affiliate Affiliate
United Other Other -- Other -- Other World-
(Millions of dollars) States West Europe East Total West East Total wide
===================================================================================================================================
For the year ended December 31, 2000
Proved property acquisition $ 138 $ -- $ -- $ 276 $ 414 $ -- $ -- $ -- $ 414
Unproved property acquisition 5 12 -- -- 17 -- -- -- 17
Exploration 227 62 18 287 594 -- 19 19 613
Development 716 121 334 677 1,848 -- 169 169 2,017
-------------------------------------------------------------------------------------------
Total $1,086 $195 $352 $1,240 $2,873 $ -- $188 $188 $3,061
===================================================================================================================================
For the year ended December 31, 1999
Proved property acquisition $ 4 $ -- $ -- $ 481 $ 485 $ -- $ -- $ -- $ 485
Unproved property acquisition 39 25 -- 27 91 -- -- -- 91
Exploration 204 92 23 224 543 -- 19 19 562
Development 698 97 319 301 1,415 -- 183 183 1,598
-------------------------------------------------------------------------------------------
Total $ 945 $214 $342 $1,033 $2,534 $ -- $202 $202 $2,736
===================================================================================================================================
For the year ended December 31, 1998
Proved property acquisition $ 27 $ -- $ -- $ 199 $ 226 $ -- $ -- $ -- $ 226
Unproved property acquisition 85 1 -- 32 118 -- -- -- 118
Exploration 417 92 65 277 851 -- 19 19 870
Development 1,073 25 308 204 1,610 -- 160 160 1,770
-------------------------------------------------------------------------------------------
Total $1,602 $118 $373 $ 712 $2,805 $ -- $179 $179 $2,984
===================================================================================================================================
> TEXACO 2000 ANNUAL REPORT 77
Table VI -- Unit Prices
Average sales prices are calculated using the gross revenues in Table VII.
Average lifting costs equal production costs and the depreciation, depletion and
amortization of support equipment and facilities, adjusted for inventory
changes.
Average sales prices
------------------------------------------------------------------------
Affiliate Affiliate
United Other Other -- Other -- Other
States West Europe East West East
====================================================================================================================
Crude oil (per barrel)
2000 $ 26.20 $ 22.74 $ 26.86 $ 22.81 $ -- $ 21.52
1999 14.97 14.12 17.15 15.33 -- 13.24
1998 10.40 9.65 11.73 9.61 -- 9.81
Natural gas liquids (per barrel)
2000 18.73 -- 17.93 -- -- --
1999 10.86 -- 12.53 -- -- --
1998 8.99 -- 11.89 -- -- --
Natural gas (per thousand cubic feet)
2000 3.67 1.13 2.49 1.23 -- --
1999 2.07 .77 1.99 .18 -- --
1998 1.93 .92 2.42 .38 -- --
Average lifting costs (per barrel of oil equivalent)
------------------------------------------------------------------------
Affiliate Affiliate
United Other Other -- Other -- Other
States West Europe East West East
====================================================================================================================
2000 $ 5.05 $ 2.94 $ 5.08 $ 3.03 $ -- $ 5.06
1999 4.01 2.87 6.15 3.45 -- 3.95
1998 4.07 1.86 5.24 3.65 -- 2.68
====================================================================================================================
Table VII - Results of Operations
Results of operations for exploration and production activities consist of all
the activities within our upstream operations, except for crude oil marketing
and other non-producing activities. As a result, this table will not correlate
to the Analysis of Income by Operating Segments.
> Revenues are based upon our production that is available for sale and
excludes revenues from resale of third-party volumes, equity earnings of
certain smaller affiliates, trading activity and miscellaneous operating
income. Expenses are associated with current year operations, but do not
include general overhead and special items.
> Production costs consist of costs incurred to operate and maintain wells
and related equipment and facilities. These costs also include taxes other
than income taxes and administrative expenses.
> Exploration costs include dry hole, leasehold impairment, geological and
geophysical expenses, the cost of retaining undeveloped leaseholds and
administrative expenses. Also included are taxes other than income taxes.
> Depreciation, depletion and amortization includes the amount for support
equipment and facilities.
> Estimated income taxes are computed by adjusting each country's income
before income taxes for permanent differences related to the oil and gas
producing activities, then multiplying the result by the country's
statutory tax rate and adjusting for applicable tax credits.
78 > TEXACO 2000 ANNUAL REPORT
Table VII -- Results of Operations
Consolidated Subsidiaries
---------------------------------------------------------------
United Other Other
(Millions of dollars) States West Europe East Total
===========================================================================================================
For the year ended December 31, 2000
Gross revenues from:
Sales and transfers, including
affiliate sales $ 4,460 $ -- $ 869 $ 1,440 $ 6,769
Sales to unaffiliated entities 545 190 591 315 1,641
Production costs (1,070) (46) (375) (232) (1,723)
Exploration costs (130) (62) (18) (152) (362)
Depreciation, depletion
and amortization (723) (18) (221) (147) (1,109)
Other expenses (190) (27) (2) (88) (307)
---------------------------------------------------------------
Results before estimated income taxes 2,892 37 844 1,136 4,909
Estimated income taxes (972) (48) (269) (945) (2,234)
---------------------------------------------------------------
Net results $ 1,920 $ (11) $ 575 $ 191 $ 2,675
===========================================================================================================
For the year ended December 31, 1999
Gross revenues from:
Sales and transfers, including
affiliate sales $ 2,936 $ -- $ 617 $ 935 $ 4,488
Sales to unaffiliated entities 230 116 498 202 1,046
Production costs (943) (39) (435) (252) (1,669)
Exploration costs (243) (97) (21) (154) (515)
Depreciation, depletion
and amortization (794) (22) (336) (134) (1,286)
Other expenses (138) (15) (1) (53) (207)
---------------------------------------------------------------
Results before estimated income taxes 1,048 (57) 322 544 1,857
Estimated income taxes (322) (8) (114) (457) (901)
---------------------------------------------------------------
Net results $ 726 $ (65) $ 208 $ 87 $ 956
===========================================================================================================
For the year ended December 31, 1998
Gross revenues from:
Sales and transfers, including
affiliate sales $ 2,570 $ -- $ 438 $ 571 $ 3,579
Sales to unaffiliated entities 218 120 509 122 969
Production costs (1,066) (35) (400) (250) (1,751)
Exploration costs (286) (31) (53) (137) (507)
Depreciation, depletion
and amortization (832) (22) (422) (113) (1,389)
Other expenses (198) -- (4) (10) (212)
---------------------------------------------------------------
Results before estimated income taxes 406 32 68 183 689
Estimated income taxes (49) (14) (27) (166) (256)
---------------------------------------------------------------
Net results $ 357 $ 18 $ 41 $ 17 $ 433
===========================================================================================================
Equity
----------------------------------
Affiliate Affiliate
-- Other -- Other World-
(Millions of dollars) West East Total wide
========================================================================================
For the year ended December 31, 2000
Gross revenues from:
Sales and transfers, including
affiliate sales $ -- $ 831 $ 831 $ 7,600
Sales to unaffiliated entities -- 50 50 1,691
Production costs -- (223) (223) (1,946)
Exploration costs -- (14) (14) (376)
Depreciation, depletion
and amortization -- (129) (129) (1,238)
Other expenses -- (2) (2) (309)
-------------------------------------------------
Results before estimated income taxes -- 513 513 5,422
Estimated income taxes -- (258) (258) (2,492)
-------------------------------------------------
Net results $ -- $ 255 $ 255 $ 2,930
========================================================================================
For the year ended December 31, 1999
Gross revenues from:
Sales and transfers, including
affiliate sales $ -- $ 592 $ 592 $ 5,080
Sales to unaffiliated entities -- 24 24 1,070
Production costs -- (205) (205) (1,874)
Exploration costs -- (17) (17) (532)
Depreciation, depletion
and amortization -- (109) (109) (1,395)
Other expenses -- (3) (3) (210)
-------------------------------------------------
Results before estimated income taxes -- 282 282 2,139
Estimated income taxes -- (143) (143) (1,044)
-------------------------------------------------
Net results $ -- $ 139 $ 139 $ 1,095
========================================================================================
For the year ended December 31, 1998
Gross revenues from:
Sales and transfers, including
affiliate sales $ -- $ 454 $ 454 $ 4,033
Sales to unaffiliated entities -- 28 28 997
Production costs -- (150) (150) (1,901)
Exploration costs -- (16) (16) (523)
Depreciation, depletion
and amortization -- (106) (106) (1,495)
Other expenses -- (1) (1) (213)
-------------------------------------------------
Results before estimated income taxes -- 209 209 898
Estimated income taxes -- (102) (102) (358)
-------------------------------------------------
Net results $ -- $ 107 $ 107 $ 540
========================================================================================
> TEXACO 2000 ANNUAL REPORT 79
SUPPLEMENTAL MARKET RISK DISCLOSURES
We use derivative financial instruments to hedge interest rate, foreign currency
exchange and commodity market risks. Derivatives principally include interest
rate and/or currency swap contracts, forward and option contracts to buy and to
sell foreign currencies, and commodity futures, options, swaps and other
instruments. We hedge only a portion of our risk exposures for assets,
liabilities, commitments and future production, purchases and sales. We remain
exposed on the unhedged portion of such risks.
The estimated sensitivity effects below assume that valuations of all items
within a risk category will move in tandem. This cannot be assured for exposures
involving interest rates, currency exchange rates, petroleum and natural gas.
Users should realize that actual impacts from future interest rate, currency
exchange and petroleum and natural gas price movements will likely differ from
the disclosed impacts due to ongoing changes in risk exposure levels and
concurrent adjustments of hedging derivative positions. Additionally, the range
of variability in prices and rates is representative only of past fluctuations
for each risk category. Past fluctuations in rates and prices may not
necessarily be an indicator of probable future fluctuations.
Notes 9, 14 and 15 to the financial statements include details of our
hedging activities, fair values of financial instruments, related derivatives
exposures and accounting policies.
DEBT AND DEBT-RELATED DERIVATIVES
We had variable rate debt of approximately $2.4 billion and $2.8 billion at
year-end 2000 and 1999, before effects of related interest rate swaps. Interest
rate swap notional amounts at year-end 2000 were virtually unchanged from
year-end 1999.
Based on our overall interest rate exposure on variable rate debt and
interest rate swaps at December 31, 2000 (including the interest rate and equity
swap), a hypothetical two percentage point increase or decrease in interest
rates would decrease or increase net income approximately $50 million.
CURRENCY FORWARD EXCHANGE AND OPTION CONTRACTS
During 2000, the net notional amount of open forward contracts decreased $710
million. This related to decreases in balance sheet monetary exposures and
foreign currency capital projects.
The effect on fair value of our forward exchange contracts at year-end 2000
from a hypothetical 10% change in currency exchange rates would be an increase
or decrease of approximately $114 million. This would be offset by an opposite
effect on the related hedged exposures.
PETROLEUM AND NATURAL GAS HEDGING
The notional amount of commodity derivatives outstanding at year-end 2000 that
are permitted to be settled in cash or another financial instrument declined
about 20% from year-end 1999. The aggregate effect of a hypothetical 20% change
in natural gas prices, a 15% change in crude oil prices and a 20% change in
petroleum product prices would not be material to our consolidated financial
position, net income or cash flows.
INVESTMENTS IN DEBT AND PUBLICLY TRADED EQUITY SECURITIES
We are subject to price risk on this unhedged portfolio of available-for-sale
securities. Our investments in available-for-sale securities were approximately
the same at year-end 2000 and 1999. At year-end 2000, a 10% appreciation or
depreciation in debt and equity prices would not have a material effect on
consolidated financial position, net income or cash flows. This assumes no
fluctuations in currency exchange rates.
PREFERRED SHARES OF SUBSIDIARIES
We are exposed to interest rate risk on dividend requirements of Series B
preferred shares of Texaco Capital LLC.
We are exposed to currency exchange risk on the Canadian dollar denominated
Series C preferred shares of Texaco Capital LLC. We are exposed to offsetting
currency exchange risk as well as interest rate risk on a swap contract used to
hedge the Series C.
Based on the above exposures, a hypothetical two percentage point increase
or decrease in the applicable variable interest rates and a hypothetical 10%
appreciation or depreciation in the Canadian dollar exchange rate would not
materially affect our consolidated financial position, net income or cash flows.
MARKET AUCTION PREFERRED SHARES (MAPS)
We are exposed to interest rate risk on dividend requirements of MAPS. A
hypothetical two percentage point increase or decrease in interest rates would
not materially affect our consolidated financial position or cash flows. There
are no derivatives related to MAPS.
80 > TEXACO 2000 ANNUAL REPORT
SELECTED FINANCIAL DATA
Selected Quarterly Financial Data
First Second Third Fourth First Second Third Fourth
Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter
---------------------------------------- ----------------------------------------
(Millions of dollars) 2000 1999
=================================================================================================================================
Revenues
Sales and services $11,086 $11,776 $13,027 $14,211 $ 6,914 $8,116 $ 9,472 $10,473
Equity in income of affiliates, interest,
asset sales and other 185 293 332 220 276 153 205 82
------------------------------------------------------------------------------------
11,271 12,069 13,359 14,431 7,190 8,269 9,677 10,555
------------------------------------------------------------------------------------
Deductions
Purchases and other costs 8,630 9,425 10,251 11,270 5,450 6,356 7,448 8,188
Operating expenses 590 678 667 873 559 550 544 666
Selling, general and
administrative expenses 325 256 323 387 290 311 270 315
Exploratory expenses 53 60 106 139 130 80 72 219
Depreciation, depletion and amortization 484 391 356 686 361 365 356 461
Interest expense, taxes other than
income taxes and minority interest 252 230 236 244 216 212 214 279
------------------------------------------------------------------------------------
10,334 11,040 11,939 13,599 7,006 7,874 8,904 10,128
------------------------------------------------------------------------------------
Income before income taxes 937 1,029 1,420 832 184 395 773 427
Provision for (benefit from) income taxes 363 404 622 287 (15) 122 386 109
------------------------------------------------------------------------------------
Net income $ 574 $ 625 $ 798 $ 545 $ 199 $ 273 $ 387 $ 318
---------------------------------------------------------------------------------------------------------------------------------
Comprehensive income $ 576 $ 620 $ 801 $ 534 $ 179 $ 271 $ 393 $ 316
=================================================================================================================================
Net income per common share (dollars)
Basic $ 1.05 $ 1.14 $ 1.47 $ 1.00 $ .35 $ .50 $ .71 $ .58
Diluted $ 1.05 $ 1.14 $ 1.46 $ 1.00 $ .35 $ .50 $ .71 $ .58
=================================================================================================================================
See accompanying notes to consolidated financial statements.
> TEXACO 2000 ANNUAL REPORT 81
Five-Year Comparison of Selected Financial Data
(Millions of dollars) 2000 1999 1998 1997 1996
============================================================================================================
For the year:
Revenues $51,130 $35,691 $ 31,707 $46,667 $45,500
Net income before cumulative effect of accounting change $ 2,542 $ 1,177 $ 603 $ 2,664 $ 2,018
Cumulative effect of accounting change -- -- (25) -- --
-------------------------------------------------
Net income $ 2,542 $ 1,177 $ 578 $ 2,664 $ 2,018
-------------------------------------------------
Comprehensive income $ 2,531 $ 1,159 $ 572 $ 2,601 $ 1,863
-------------------------------------------------
Net income per common share* (dollars)
Basic
Income before cumulative effect of accounting change $ 4.66 $ 2.14 $ 1.04 $ 4.99 $ 3.77
Cumulative effect of accounting change -- -- (.05) -- --
-------------------------------------------------
Net income $ 4.66 $ 2.14 $ .99 $ 4.99 $ 3.77
Diluted
Income before cumulative effect of accounting change $ 4.65 $ 2.14 $ 1.04 $ 4.87 $ 3.68
Cumulative effect of accounting change -- -- (.05) -- --
-------------------------------------------------
Net income $ 4.65 $ 2.14 $ .99 $ 4.87 $ 3.68
-------------------------------------------------
Cash dividends per common share* (dollars) $ 1.80 $ 1.80 $ 1.80 $ 1.75 $ 1.65
Total cash dividends paid on common stock $ 976 $ 964 $ 952 $ 918 $ 859
At end of year:
Total assets $30,867 $28,972 $ 28,570 $29,600 $26,963
Debt and capital lease obligations
Short-term $ 376 $ 1,041 $ 939 $ 885 $ 465
Long-term 6,815 6,606 6,352 5,507 5,125
-------------------------------------------------
Total debt and capital lease obligations $ 7,191 $ 7,647 $ 7,291 $ 6,392 $ 5,590
============================================================================================================
* Reflects two-for-one stock split effective September 29, 1997.
See accompanying notes to consolidated financial statements.
84
TEXACO 2000 ANNUAL REPORT
INVESTOR INFORMATION
COMMON STOCK - MARKET
AND DIVIDEND INFORMATION:
Texaco Inc. common stock (symbol TX) is traded principally on the New York Stock Exchange. As of February 22, 2001, there were
184,958 shareholders of record. In 2000, Texaco's common stock price reached a high of $63 3/4, and closed December 21, 2000, at
$62 1/8.
------------------------------------------------------------------------------------------------------------------------------------
Common Stock Price Range
----------------------------------------------------------
High Low High Low Dividends
------------------- -------------------- ---------
2000 1999 2000 1999
------------------------------------------------------------------------------------------------------------------------------------
First Quarter $ 61 7/16 $ 44 1/4 $ 59 3/16 $ 44 9/16 $ .45 $ .45
Second Quarter 59 11/16 48 9/16 70 1/16 55 1/8 .45 .45
Third Quarter 56 1/8 48 1/4 68 1/2 60 5/16 .45 .45
Fourth Quarter 63 3/4 50 13/16 67 3/16 52 3/8 .45 .45
------------------------------------------------------------------------------------------------------------------------------------
STOCK TRANSFER AGENT AND
SHAREHOLDER COMMUNICATIONS
FOR INFORMATION ABOUT TEXACO
OR ASSISTANCE WITH YOUR ACCOUNT,
PLEASE CONTACT:
Texaco Inc.
Investor Services
2000 Westchester Avenue
White Plains, NY 10650-0001
Phone: 1-800-283-9785
Fax: (914) 253-6286
E-mail: invest@texaco.com
NY DROP AGENT
Mellon Investor Services LLC
120 Broadway - 13th Floor
New York, NY 10271
Phone: (212) 374-2500
Fax: (212) 571-0871
SECURITY ANALYSTS AND INSTITUTIONAL
INVESTORS SHOULD CONTACT:
Elizabeth P. Smith
Vice President, Texaco Inc.
Phone: (914) 253-4478
Fax: (914) 253-6269
E-mail: smithep@texaco.com
ANNUAL MEETING
We have not scheduled an Annual Meeting of Stockholders for 2001, because of the
pending merger with Chevron Corporation. A formal notice of a special meeting of
stockholders to approve the merger, together with proxy materials will be mailed
to stockholders after we have obtained regulatory approvals of the merger.
INVESTOR SERVICES PLAN
The company's Investor Services Plan offers a variety of benefits to individuals
seeking an easy way to invest in Texaco Inc. common stock. Enrollment in the
Plan is open to anyone, and investors may make initial investments directly
through the company. The Plan features dividend reinvestment, optional cash
investments and custodial service for stock certificates. Open an account or
access your registered shareholder account on the Internet through our new
TexLink connection at www.texaco.com. Texaco's Investor Services Plan is an
excellent way to start an investment program for family or friends. For a
complete informational package, including a Plan prospectus, call
1-800-283-9785, e-mail at invest@texaco.com, or visit Texaco's Internet home
page at www.texaco.com.
EXHIBIT 21
Subsidiaries of Registrant
2000
Parents of Registrant
None
Registrant
Texaco Inc.
The significant subsidiaries included in the consolidated financial statements
of the Registrant are as follows:
Organized
under
the laws of
-----------
Fuel and Marine Marketing LLC Delaware
Fuel and Marine Marketing Limited England
Four Star Oil and Gas Company Delaware
Heddington Insurance Ltd. Bermuda
MVP Production Inc. Delaware
S.A. Texaco Belgium N.V. Belgium
Saudi Arabian Texaco Inc. Delaware
Star Deep Water Petroleum Limited Nigeria
TEPI Holdings Inc. Delaware
TRMI Holdings Inc. Delaware
Texaco Australia Pty. Limited Australia
Texaco Aviation Products LLC Delaware
Texaco Block B South Natuna Sea Inc. Liberia
Texaco Brazil S.A. - Produtos de Petroleo Brazil
Texaco Britain Limited England
Texaco California Inc. Delaware
Texaco Captain Holdings Inc. Delaware
Texaco Caribbean Inc. Delaware
Texaco China B.V. Netherlands
Texaco Denmark Inc. Delaware
Texaco Exploration and Production Inc. Delaware
Texaco Group Inc. Delaware
Texaco International Trader Inc. Delaware
Texaco International Petroleum Co. Delaware
Texaco Investments (Netherlands), Inc. Delaware
Texaco (Ireland) Limited Ireland
Texaco Limited England
Texaco Natural Gas Inc. Delaware
Texaco Nederland B.V. Netherlands
Texaco North Sea U.K. Company Delaware
Texaco Overseas (Nigeria) Petroleum Company Unlimited Nigeria
Texaco Overseas Holdings Inc. Delaware
Texaco Panama Inc. Panama
Texaco Philippines Inc. Liberia
Texaco Pipeline International LLC Delaware
Texaco Puerto Rico Inc. Puerto Rico
Texaco Raffinaderij Pernis B.V. Netherlands
Texaco Refining and Marketing Inc. Delaware
Texaco Refining and Marketing (East) Inc. Delaware
Texaco Trinidad, Inc. Delaware
Texaco Venezuela Holdings (I) Company Delaware
Texas Petroleum Company New Jersey
Names of certain subsidiary companies are omitted because, considered in the
aggregate as a single subsidiary company, they do not constitute a significant
subsidiary company.
EXHIBIT 23.1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our
reports dated February 22, 2001 included or incorporated by reference in Texaco
Inc.'s Form 10-K for the year ended December 31, 2000, into the following
previously filed Registration Statements:
1. Form S-3 File Number 33-31148
2. Form S-8 File Number 2-67125
3. Form S-8 File Number 2-76755
4. Form S-8 File Number 2-90255
5. Form S-8 File Number 33-34043
6. Form S-3 File Number 33-50553 and 33-50553-01
7. Form S-8 File Number 333-11019
8. Form S-3 File Number 333-82893 and 333-82893-01
9. Form S-8 File Number 333-73329
ARTHUR ANDERSEN LLP
New York, N.Y.
March 20, 2001
EXHIBIT 23.2
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
Texaco Inc.:
We hereby consent to the incorporation by reference of our report dated February
8, 2001 relating to the combined balance sheets of the Caltex Group of Companies
as of December 31, 2000 and 1999, and the related combined statements of income,
comprehensive income, stockholders' equity and cash flows for each of the years
in the three-year period ended December 31, 2000, which report appears in the
December 31, 2000 Annual Report on Form 10-K of Texaco Inc., into the following
previously filed Registration Statements:
1. Form S-3 File Number 33-31148
2. Form S-8 File Number 2-67125
3. Form S-8 File Number 2-76755
4. Form S-8 File Number 2-90255
5. Form S-8 File Number 33-34043
6. Form S-3 File Number 33-50553 and 33-50553-01
7. Form S-8 File Number 333-11019
8. Form S-3 File Number 333-82893 and 333-82893-01
9. Form S-8 File Number 333-73329
KPMG
Singapore
March 23, 2001
EXHIBIT 23.3
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference of our report dated March 1,
2001, on our audits of the consolidated balance sheets of Equilon Enterprises
LLC as of December 31, 2000 and 1999, and the related statements of consolidated
income, owners' equity and cash flows for each of the years in the three-year
period ended December 31,2000, included in the Annual Report on Form 10-K of
Texaco Inc. for the year ended December 31, 2000, into the following previously
filed Registration Statements:
1. Form S-3 File Number 33-31148
2. Form S-8 File Number 2-67125
3. Form S-8 File Number 2-76755
4. Form S-8 File Number 2-90255
5. Form S-8 File Number 33-34043
6. Form S-3 File Number 33-50553 and 33-50553-01
7. Form S-8 File Number 333-11019
8. Form S-3 File Number 333-82893 and 333-82893-01
9. Form S-8 File Number 333-73329
PricewaterhouseCoopers LLP Arthur Andersen LLP
Houston, Texas Houston, Texas
March 22, 2001 March 22, 2001
EXHIBIT 23.4
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference of our report dated March 1,
2001, on our audits of the balance sheets of Motiva Enterprises LLC as of
December 31, 2000 and 1999, and the related statements of income, owners' equity
and cash flows for the years ended December 31, 2000 and 1999 and the six months
ended December 31, 1998, included in the Annual Report on Form 10-K of Texaco
Inc. for the year ended December 31, 2000, into the following previously filed
Registration Statements:
1. Form S-3 File Number 33-31148
2. Form S-8 File Number 2-67125
3. Form S-8 File Number 2-76755
4. Form S-8 File Number 2-90255
5. Form S-8 File Number 33-34043
6. Form S-3 File Number 33-50553 and 33-50553-01
7. Form S-8 File Number 333-11019
8. Form S-3 File Number 333-82893 and 333-82893-01
9. Form S-8 File Number 333-73329
Arthur Andersen LLP
Deloitte & Touche LLP
PricewaterhouseCoopers LLP
Houston, Texas
March 22, 2001
EXHIBIT 24.2
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that the undersigned, Chairman of the
Board and Chief Executive Officer of TEXACO INC., a Delaware corporation (the
"Company"), hereby appoints MICHAEL H. RUDY and CALLI P. CHECKI, and either of
them (with full power to act without the other) as the undersigned's
attorneys-in-fact and agents, with full power and authority to act in any and
all capacities for and in the name, place and stead of the undersigned in
connection with the filing of: (i) any and all registration statements and all
amendments and post-effective amendments thereto (collectively, "Registration
Statements") under the Securities Act of 1933, as amended, with the Securities
and Exchange Commission, and any and all registrations, qualifications or
notifications under the applicable securities laws of any and all states and
other jurisdictions, with respect to the securities of the Company of whatever
class, including without limitation thereon the Company's Common Stock,
preferred stock and debt securities, however offered, sold, issued, distributed,
placed or resold by the Company, by any of its subsidiary companies, or by any
other person or entity, that may be required to effect: (a) any such filing, (b)
any primary or secondary offering, sale, distribution, exchange, or conversion
of the Company's securities, (c) any acquisition, merger, reorganization or
consolidation involving the issuance of the Company's securities, (d) any stock
option, restricted stock grant, incentive, investment, thrift, profit sharing,
or other employee benefit plan relating to the Company's securities, or (e) any
dividend reinvestment or stock purchase plan relating to the Company's
securities; (ii) the Company's Annual Report to the Securities and Exchange
Commission on Form 10-K, and any and all amendments thereto on Form 8 or
otherwise, under the Securities Exchange Act of 1934, as amended ("Exchange
Act"), and (iii) Statements of Changes of Beneficial Ownership of Securities on
Form 4 or Form 5 (or such other forms as may be designated from time to time for
such purposes), pursuant to Section 16(a) of the Exchange Act.
Without limiting the generality of the foregoing grant of authority,
such attorneys-in-fact and agents, or either of them, are hereby granted full
power and authority, on behalf of and in the name, place and stead of the
undersigned, to execute and deliver all such Registration Statements,
registrations, qualifications, or notifications, the Company's Form 10-K, any
and all amendments thereto, statements of changes, and any and all other
documents in connection with the foregoing, and take such other and further
action as such attorneys-in-fact and agents, or either of them, deem necessary
or appropriate. The powers and authorities granted herein to such
attorneys-in-fact and agents, and either of them, also include the full right,
power and authority to effect necessary or appropriate substitutions or
revocations. The undersigned hereby ratifies, confirms, and adopts, as the
undersigned's own act and deed, all action lawfully taken pursuant to the powers
and authorities herein granted by such attorneys-in-fact and agents, or either
of them, or by their respective substitutes. This Power of Attorney expires by
its terms and shall be of no further force and effect on December 31, 2002.
IN WITNESS WHEREOF, the undersigned has hereunto set his name as of
the 4th day of February, 2001.
/S/Glenn F. Tilton
------------------
Glenn F. Tilton
Chairman of the Board
and Chief Executive Officer
EXHIBIT 24.3
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that the undersigned, a director of
TEXACO INC., a Delaware corporation (the "Company"), hereby appoints MICHAEL H.
RUDY and DEVAL L. PATRICK, and either of them (with full power to act without
the other) as the undersigned's attorneys-in-fact and agents, with full power
and authority to act in any and all capacities for and in the name, place and
stead of the undersigned in connection with the filing of: (i) any and all
registration statements and all amendments and post-effective amendments thereto
(collectively, "Registration Statements") under the Securities Act of 1933, as
amended, with the Securities and Exchange Commission, and any and all
registrations, qualifications or notifications under the applicable securities
laws of any and all states and other jurisdictions, with respect to the
securities of the Company of whatever class, including without limitation
thereon the Company's Common Stock, preferred stock and debt securities, however
offered, sold, issued, distributed, placed or resold by the Company, by any of
its subsidiary companies, or by any other person or entity, that may be required
to effect: (a) any such filing, (b) any primary or secondary offering, sale,
distribution, exchange, or conversion of the Company's securities, (c) any
acquisition, merger, reorganization or consolidation involving the issuance of
the Company's securities, (d) any stock option, restricted stock grant,
incentive, investment, thrift, profit sharing, or other employee benefit plan
relating to the Company's securities, or (e) any dividend reinvestment or stock
purchase plan relating to the Company's securities; (ii) the Company's Annual
Report to the Securities and Exchange Commission on Form 10-K, and any and all
amendments thereto on Form 8 or otherwise, under the Securities Exchange Act of
1934, as amended ("Exchange Act"), and (iii) Statements of Changes of Beneficial
Ownership of Securities on Form 4 or Form 5 (or such other forms as may be
designated from time to time for such purposes), pursuant to Section 16(a) of
the Exchange Act.
Without limiting the generality of the foregoing grant of authority,
such attorneys-in-fact and agents, or either of them, are hereby granted full
power and authority, on behalf of and in the name, place and stead of the
undersigned, to execute and deliver all such Registration Statements,
registrations, qualifications, or notifications, the Company's Form 10-K, any
and all amendments thereto, statements of changes, and any and all other
documents in connection with the foregoing, and take such other and further
action as such attorneys-in-fact and agents, or either of them, deem necessary
or appropriate. The powers and authorities granted herein to such
attorneys-in-fact and agents, and either of them, also include the full right,
power and authority to effect necessary or appropriate substitutions or
revocations. The undersigned hereby ratifies, confirms, and adopts, as the
undersigned's own act and deed, all action lawfully taken pursuant to the powers
and authorities herein granted by such attorneys-in-fact and agents, or either
of them, or by their respective substitutes. This Power of Attorney expires by
its terms and shall be of no further force and effect on March 31, 2001.
IN WITNESS WHEREOF, the undersigned has hereunto set his name as of
the 27th day of October, 2000.
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