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2000
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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number 1-2256
EXXON MOBIL CORPORATION
(Exact name of registrant as specified in its charter)
NEW JERSEY 13-5409005
(State or other jurisdiction of (I.R.S. Employer Identification
incorporation or organization) Number)
5959 LAS COLINAS BOULEVARD, IRVING, TEXAS 75039-2298
(Address of principal executive offices) (Zip Code)
(972) 444-1000
(Registrant's telephone number, including area code)
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Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Title of Each Class on Which Registered
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Common Stock, without par value (3,455,409,183 shares
outstanding at February 28, 2001) New York Stock Exchange
Registered securities guaranteed by Registrant:
SeaRiver Maritime Financial Holdings, Inc.
Twenty-Five Year Debt Securities due October 1, 2011 New York Stock Exchange
Exxon Capital Corporation
Twelve Year 6% Notes due July 1, 2005 New York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes X No
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Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K.
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The aggregate market value of the voting stock held by non-affiliates of the
registrant on February 28, 2001, based on the closing price on that date of
$81.05 on the New York Stock Exchange composite tape, was in excess of $280
billion.
Documents Incorporated by Reference:
Proxy Statement for the 2001 Annual Meeting of Shareholders (Part III)
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EXXON MOBIL CORPORATION
FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000
TABLE OF CONTENTS
Page
Number
------
PART I
Item 1. Business..................................................... 1-2
Item 2. Properties................................................... 2-14
Item 3. Legal Proceedings............................................ 15
Item 4. Submission of Matters to a Vote of Security Holders.......... 15
Executive Officers of the Registrant [pursuant to Instruction 3 to
Regulation S-K, Item 401(b)]......................................... 16
PART II
Item 5. Market for Registrant's Common Stock and Related Shareholder
Matters...................................................... 17
Item 6. Selected Financial Data...................................... 17
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations.................................... 17
Item 7A. Quantitative and Qualitative Disclosures About Market Risk... 17-18
Item 8. Financial Statements and Supplementary Data.................. 18
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure..................................... 18
PART III
Item 10. Directors and Executive Officers of the Registrant........... 18
Item 11. Executive Compensation....................................... 18
Item 12. Security Ownership of Certain Beneficial Owners and
Management................................................... 18
Item 13. Certain Relationships and Related Transactions............... 18
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K..................................................... 18
Financial Section...................................................... 19-57
Signatures............................................................. 58-60
Index to Exhibits...................................................... 61
Exhibit 12 -- Computation of Ratio of Earnings to Fixed Charges
PART I
Item 1. Business.
Exxon Mobil Corporation ("ExxonMobil"), formerly named Exxon Corporation,
was incorporated in the State of New Jersey in 1882.
On December 1, 1998, Exxon Corporation ("Exxon") and Mobil Corporation
("Mobil") signed an agreement to merge the two companies subject to
shareholder approval, regulatory reviews and other conditions. On November 30,
1999, pursuant to the agreement, a wholly-owned subsidiary of Exxon was merged
with and into Mobil so that Mobil became a wholly-owned subsidiary of Exxon.
At the same time, Exxon changed its name to Exxon Mobil Corporation.
Coincident with the merger, ExxonMobil announced a new organization
structure built on a concept of eleven separate global businesses designed to
allow the company to compete more effectively in a changing worldwide energy
industry: five upstream businesses--Exploration, Development, Production, Gas
Marketing and Upstream Research; four downstream businesses-- Refining and
Supply, Fuels Marketing, Lubricants and Petroleum Specialties, and Technology;
plus a chemical company and a coal and minerals company.
Divisions and affiliated companies of ExxonMobil operate or market products
in the United States and about 200 other countries and territories. Their
principal business is energy, involving exploration for, and production of,
crude oil and natural gas, manufacturing of petroleum products and
transportation and sale of crude oil, natural gas and petroleum products.
ExxonMobil is a major manufacturer and marketer of basic petrochemicals,
including olefins, aromatics, polyethylene and polypropylene plastics and a
wide variety of specialty products. ExxonMobil is engaged in exploration for,
and mining and sale of coal, copper and other minerals. ExxonMobil also has
interests in electric power generation facilities. Affiliates of ExxonMobil
conduct extensive research programs in support of these businesses.
Exxon Mobil Corporation has several divisions and hundreds of affiliates,
many with names that include ExxonMobil, Exxon, Esso or Mobil. For convenience
and simplicity, in this report the terms ExxonMobil, Exxon, Esso and Mobil, as
well as the terms corporation, company, our, we and its, are sometimes used as
abbreviated references to specific affiliates or groups of affiliates. The
precise meaning depends on the context in question.
In 2000, the corporation spent $1,529 million (of which $393 million were
capital expenditures) on environmental projects and expenses worldwide, mostly
dealing with air and water conservation. Total expenditures for such
activities are expected to be about $1.8 billion in both 2001 and 2002 (with
capital expenditures representing about 25 percent of the total).
Operating data and industry segment information for the corporation are
contained on pages 50, 56 and 57; information on oil and gas reserves is
contained on pages 53 and 54 and information on company-sponsored research and
development activities is contained on page 34 of the Financial Section of
this report.
Factors Affecting Future Results
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Competitive Factors: The energy and petrochemical industries are highly
competitive. There is competition within the industries and also with other
industries in supplying the energy, fuel and chemical needs of industry and
individual consumers. The corporation competes with other firms in the sale or
purchase of various goods or services in many national and international
markets and employs all methods of competition which are lawful and
appropriate for such purposes.
Political Factors: The operations and earnings of the corporation and its
affiliates throughout the world have been, and may in the future be, affected
from time to time in varying degree by political instability and by other
political developments and laws and regulations, such as forced divestiture of
1
assets; restrictions on production, imports and exports; price controls; tax
increases and retroactive tax claims; expropriation of property; cancellation
of contract rights and environmental regulations. Both the likelihood of such
occurrences and their overall effect upon the corporation vary greatly from
country to country and are not predictable.
Industry and Economic Factors: The operations and earnings of the corporation
and its affiliates throughout the world are also affected by local, regional
and global events or conditions that affect supply and demand for oil, natural
gas, petroleum products, petrochemicals and other ExxonMobil products. These
events or conditions are generally not predictable and include, among other
things, the development of new supply sources; supply disruptions; weather;
international political events; technological advances; changes in
demographics and consumer preferences and the competitiveness of alternative
energy sources or product substitutes.
Project Factors: The advancement, cost and results of particular ExxonMobil
projects also depend on the outcome of negotiations with partners,
governments, suppliers, customers or others; changes in operating conditions
or costs and the occurrence of unforeseen technical difficulties.
Merger-Related Factors: Realization of the benefits of the merger will depend,
among other things, upon management's ability to integrate the businesses of
Exxon and Mobil successfully and on schedule. Future results could also be
affected by the diversion of management's focus and resources from other
strategic opportunities during the merger integration process.
Market Risk Factors: See also page 23 and 24 of the Financial Section of this
report for discussion of the impact of market risks, inflation and other
uncertainties.
Projections, estimates and descriptions of ExxonMobil's plans and objectives
included or incorporated in Items 1, 2, 7 and 7A of this report are forward-
looking statements. Actual future results, including merger related expenses,
synergy benefits from the merger (including cost savings, efficiency gains and
revenue enhancements), project completion dates, production rates, capital
expenditures, costs and business plans could differ materially due to, among
other things, the factors discussed above and elsewhere in this report.
Item 2. Properties.
Part of the information in response to this item and to the Securities
Exchange Act Industry Guide 2 is contained in the Financial Section of this
report in Note 10, which note appears on page 36, and on pages 51 through 55
and 57.
Information with regard to oil and gas producing activities follows:
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1. Net Reserves of Crude Oil and Natural Gas Liquids (millions of barrels) and
Natural Gas (billions of cubic feet) at Year-End 2000
Estimated proved reserves are shown on pages 53 and 54 of the Financial
Section of this report. No major discovery or other favorable or adverse event
has occurred since December 31, 2000, that would cause a significant change in
the estimated proved reserves as of that date. For information on the
standardized measure of discounted future net cash flows relating to proved
oil and gas reserves, see page 55 of the Financial Section of this report.
2. Estimates of Total Net Proved Oil and Gas Reserves Filed with Other Federal
Agencies
During 2000, ExxonMobil filed proved reserves estimates with the U.S.
Department of Energy on Forms EIA-23 and EIA-28. The information is consistent
with the ExxonMobil 1999 Annual Report to shareholders with the exception of
EIA-23 which covered total oil and gas reserves from
2
ExxonMobil-operated properties in the United States and does not include gas
plant liquids. The differences between the oil reserves and gas reserves
reported on EIA-23 and those reported in the 1999 Annual Report exceed five
percent.
3. Average Sales Prices and Production Costs per Unit of Production
Reference is made to page 51 of the Financial Section of this report.
Average sales prices have been calculated by using sales quantities from our
own production as the divisor. Average production costs have been computed by
using net production quantities for the divisor. The volumes of crude oil and
natural gas liquids (NGL) production used for this computation are shown in
the reserves table on page 53 of the Financial Section of this report. The net
production volumes of natural gas available for sale by the producing function
used in this calculation are shown on page 57 of the Financial Section of this
report. The volumes of natural gas were converted to oil-equivalent barrels
based on a conversion factor of six thousand cubic feet per barrel.
4. Gross and Net Productive Wells
Year-End 2000
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Oil Gas
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Gross Net Gross Net
------ ------ ------ -----
United States..................................... 35,552 12,455 9,857 4,590
Canada............................................ 6,750 5,188 4,938 2,489
Europe............................................ 1,702 546 1,331 480
Asia-Pacific...................................... 1,394 518 718 256
Africa............................................ 362 154 -- --
Other............................................. 974 176 137 41
------ ------ ------ -----
Total............................................ 46,734 19,037 16,981 7,856
====== ====== ====== =====
5. Gross and Net Developed Acreage
Year-End 2000
---------------------
Gross Net
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(Thousands of acres)
United States.......................................... 9,578 5,993
Canada................................................. 4,577 2,390
Europe................................................. 11,576 4,816
Asia-Pacific........................................... 4,605 1,528
Africa................................................. 894 387
Other.................................................. 9,175 1,821
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Total................................................. 40,405 16,935
========== ==========
Note: Separate acreage data for oil and gas are not maintained because, in
many instances, both are produced from the same acreage.
6. Gross and Net Undeveloped Acreage
Year-End 2000
--------------------
Gross Net
--------- ----------
(Thousands of acres)
United States........................................... 11,527 7,399
Canada.................................................. 22,136 9,619
Europe.................................................. 16,283 6,244
Asia-Pacific............................................ 38,037 19,641
Africa.................................................. 47,325 20,111
Other................................................... 51,718 26,363
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Total.................................................. 187,026 89,377
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3
7. Summary of Acreage Terms in Key Areas
UNITED STATES
Oil and gas exploration leases have an exploration period ranging from one
to ten years, and a production period that normally remains in effect until
production ceases. In some instances, a "fee interest" is acquired where both
the surface and the underlying mineral interests are owned outright.
CANADA
Exploration permits are granted for varying periods of time with renewals
possible. Production leases are held as long as there is production on the
lease. The majority of Cold Lake leases were taken for an initial 21-year term
in 1968-1969 and renewed for a second 21-year term in 1989-1990. The
exploration acreage in Eastern Canada is currently held by work commitments of
various amounts.
EUROPE
France
Exploration permits are granted for periods of three to five years,
renewable up to two times accompanied by substantial acreage relinquishments:
50 percent of the acreage at first renewal; 25 percent of the remaining
acreage at second renewal. A 1994 law requires a bidding process prior to
granting of an exploration permit. Upon discovery of commercial hydrocarbons,
a production concession is granted for up to 50 years, renewable in periods of
25 years each.
Germany
Exploration concessions are granted for an initial maximum period of five
years with possible extensions of up to three years for an indefinite period.
Extensions are subject to specific, minimum work commitments. Production
licenses are normally granted for 20 to 25 years with multiple possible
extensions as long as there is production on the license.
Netherlands
Onshore: Exploration drilling permits are issued for a period of two to five
years. Permits issued after 1996 are issued for a period of time necessary to
perform the activities for which the permit is issued. Production concessions
are granted after discoveries have been made, under conditions that are
negotiated with the government. Normally, they are field-life concessions
covering an area defined by hydrocarbon occurrences.
Offshore: Prospecting licenses issued prior to March 1976 are for a 15-year
period, with relinquishment of about 50 percent of the original area required
at the end of ten years. Prospecting licenses issued between 1976 and 1996 are
for a ten-year period, with relinquishment of about 50 percent of the original
area required at the end of six years. Current licenses are for a period of
time necessary to perform the activities for which the permit is issued. For
commercial discoveries within a prospecting license, a production license is
normally issued for a 40-year period.
Norway
Licenses issued prior to 1972 were for an initial period of six years and an
extension period of 40 years, with relinquishment of at least one-fourth of
the original area required at the end of the sixth year and another one-fourth
at the end of the ninth year. Licenses issued between 1972 and 1997 were for
an initial period of up to 10 years and an extension period of up to 30 years,
with relinquishment of at least one-half of the original area required at the
end of the sixth year. Licenses issued after July 1,
4
1997 have an initial period of from four to ten years and a normal extension
period of up to 30 years or in special cases of up to 50 years, and with
relinquishment of at least one-half of the original area required at the end
of the initial period.
United Kingdom
Acreage terms are fixed by the government and are periodically changed. For
example, the regulations governing licenses issued between 1996 and 1998
provide for an initial term of three years with possible extensions of six, 15
and 24 years for a license period of 45 more years. After the second
extension, the license must be surrendered in part. In recent licensing
rounds, the initial term has generally been for six years. After possible
surrender of acreage, the license may continue for 30 more years.
ASIA-PACIFIC
Australia
Onshore: Acreage terms are fixed by the individual state and territory
governments. These terms and conditions vary significantly between the states
and territories. Exploration permits are normally granted for two to six years
(in some states the Minister fixes the term) with possible renewals and
relinquishment. Production licenses in South Australia are granted for an
initial term of 21 years, with subsequent renewals, each for 21 years, for the
full area. Production licenses in Queensland are granted for varying periods
consistent with expected field lives, with renewals on a similar basis.
Offshore: Acreage terms are fixed by the federal government beyond the three
nautical mile limit offshore (all of the company's offshore acreage), in most
cases by legislation but in some cases by the Joint Authority (composed of
federal and state ministers) at the time of grant. Exploration permits are
granted for six years with possible renewals of five-year periods. A 50
percent relinquishment of remaining area is mandatory at the end of each
renewal period. Retention leases may be granted for resources that are not
commercially viable at the time of application, but are expected to become
commercially viable within 15 years. These are granted for periods of five
years and renewals may be requested. Production licenses granted prior to
September 1, 1998 were initially for 21 years, with a further renewal of 21
years and thereafter renewals at the discretion of the Joint Authority or
Federal Minister. Effective from September 1, 1998, new production licenses
are granted "indefinitely" i.e., for the life of the field (if no operations
for the recovery of petroleum have been carried on for five years, the license
may be terminated).
Indonesia
Exploration and production activities in Indonesia are generally governed by
production sharing contracts negotiated with the national oil company. Certain
activities may also be subject to joint operating agreements and/or technical
assistance contracts also negotiated with the national oil company. The more
recent contracts have an overall term of up to 30 years with possible
extensions in some contracts. The initial exploration period is from six to
ten years.
Malaysia
Exploration and production activities are governed by production sharing
contracts negotiated with the national oil company. The more recent contracts
have an overall term of 24 to 37 years with possible extensions to the
exploration or development periods. The exploration period is five to seven
years with the possibility of extensions, after which time areas with no
commercial discoveries must be relinquished. The development period is four to
five years from commercial discovery, with the possibility of extensions under
special circumstances. Areas from which commercial production has not started
by the end of the development period must be relinquished if no extension is
granted. The total production period is 15 to 25 years from first commercial
lifting, not to exceed the overall term of the current contract.
5
Papua New Guinea
Exploration and production activities are governed by the Petroleum Act.
Exploration permits are granted for an initial term of six years with renewals
of five years. A 50 percent area relinquishment is mandatory at the end of the
first term. Production licenses are granted for an initial 25-year period.
Renewals of up to 20 years may be granted at the Minister's discretion.
Petroleum retention licenses are granted for five-year terms, renewable twice
for maximum retention time of 15 years.
Thailand
The company's concessions and the Petroleum Act of 1972 allow production for
30 years (through 2021) with a possible ten-year extension at terms generally
prevalent at the time.
AFRICA
Angola
Exploration and production activities are governed by production sharing
agreements with an initial exploration term of four years and an optional
second phase of two to three years. The production period is for 25 years and
a negotiated extension is common.
Cameroon
Exploration and production activities are governed by agreements negotiated
with the national oil company. The concessions have various agreements with
regard to license extension, terms and conditions for the exploration and
production phase.
Chad
Exploration permits are issued for a period of five years, renewable for two
further five-year periods. The production term is for 30 years.
Equatorial Guinea
Exploration and production activities are governed by production sharing
contracts negotiated with the state Ministry of Mines and Energy. The
exploration term is for 10 to 15 years with limited relinquishments in the
absence of commercial discoveries. The production period for crude is 30 years
while the production period for gas is 50 years.
Nigeria
Exploration and production activities in the deepwater offshore areas are
typically governed by production sharing contracts (PSCs) with the national
oil company. The national oil company holds the underlying Oil Prospecting
License (OPL) and any resulting Oil Mining Lease (OML). The terms of the PSCs
are generally 30 years, including a ten-year exploration period (six-year
initial exploration phase plus a four-year optional period) with no required
relinquishment after the initial phase, a 50 percent relinquishment
requirement after the second phase and a 20-year production period that may be
extended.
Some exploration activities are carried out in deepwater by joint ventures
with indigenous companies as direct participants in an OPL. OPLs in deepwater
offshore areas are valid for ten years and are non-renewable, while in all
other areas OPLs are for five years and also are non-renewable. Demonstrating
a commercial discovery is the basis for conversion of an OPL to an OML.
OMLs granted prior to the 1969 Petroleum Act, (i.e., under the Minerals Oils
Act 1914, repealed by the 1969 Petroleum Act) were for 30 years onshore and 40
years in offshore areas and are renewable upon 12 months written notice, for
further periods of 30 and 40 years, respectively.
6
OMLs granted under the 1969 Petroleum Act, which include all deepwater OMLs,
have a maximum term of 20 years without distinction for on- or offshore
location and are renewable, upon 12 months written notice, for another period
of 20 years. OMLs not held by the national oil company are also subject to a
mandatory 50 percent relinquishment, after the first ten years of their
duration.
In all cases, renewal of OMLs is almost certain if lessee satisfies three
conditions, namely, lessee: i) gives the requisite notice within the minimum
stipulated period; ii) has paid up-to-date all rentals, royalties and fees and
iii) has fulfilled all lessee's obligations under the OML.
The MOU (Memorandum of Understanding) defining commercial terms applicable
to existing oil production was renegotiated and executed in 2000 and is
effective for a minimum of three years with possible extension on mutual
agreement. Guidelines for Marginal Field Development were issued by the
Government.
OTHER COUNTRIES
Argentina
The concession terms for onshore in Argentina are two to three years for the
initial exploration period, one to two years for the second exploration period
and zero to one year for the third exploration period. The concession terms
for offshore in Argentina are four years for the initial exploration period,
three years for the second exploration period and three years for the third
exploration period. Fifty percent relinquishment is required after each
exploration period. An extension after the third exploration period is
possible for up to four years. The total exploration and exploitation term is
25 years. A ten-year extension is possible once a field has been developed.
Azerbaijan
The production sharing agreement (PSA) for the development of the
Megastructure is established for an initial period of 30 years starting from
the PSA execution date in 1994.
Other exploration and production activities are governed by PSAs negotiated
with the national oil company. The exploration period consists of three or
four years with the possibility of a one to three-year extension. The
production period, which includes development, is for 25 years or 35 years
with the possibility of one or two five-year extensions.
Kazakhstan
Onshore: Exploration and production activities are governed by a joint-
venture agreement negotiated with the Republic of Kazakhstan. Existing
production operations have a 40-year production period that commenced in 1993.
Offshore: Exploration and production activities are governed by a production
sharing agreement negotiated with the Republic of Kazakhstan. The exploration
period consists of six years with the possibility of a two-year extension. The
production period, which includes development, is for 20 years with the
possibility of two ten-year extensions.
Qatar
The State of Qatar grants concessions to LNG projects within Qatar's
offshore North field to permit the economic development and production of
sufficient gas to satisfy the LNG sales obligations of these projects.
Republic of Yemen
Production sharing agreements (PSAs) negotiated with the government entitle
the company to participate in exploration operations within a designated area
during the exploration period. In the
7
event of a commercial oil discovery, the company is entitled to proceed with
development and production operations during the development period. The
length of these periods and other specific terms are negotiated prior to
executing the PSA. Existing production operations have a development period
extending 20 years from first commercial declaration (made in November 1985
for the Marib PSA and June 1995 for the Jannah PSA).
Venezuela
Exploration and production activities are governed by contracts negotiated
with the national oil company. Exploration activity is covered by risk/profit
sharing contracts where exploration blocks were awarded for 35 years.
Production licenses are awarded for 20 years under production service
agreements.
Strategic association agreements (such as the Cerro Negro project) are
limited to those projects that require vertical integration. Licenses are
awarded for 35 years. Significant amendments to the contract terms require
Venezuelan congressional approval.
8. Number of Net Productive and Dry Wells Drilled
2000 1999 1998
----- ----- -----
A. Net Productive Exploratory Wells Drilled
United States............................................... 2 16 23
Canada...................................................... 49 4 18
Europe...................................................... 3 7 8
Asia-Pacific................................................ 5 4 19
Africa...................................................... 2 8 6
Other....................................................... 1 1 8
----- ----- -----
Total...................................................... 62 40 82
----- ----- -----
B. Net Dry Exploratory Wells Drilled
United States............................................... 2 11 20
Canada...................................................... 12 2 9
Europe...................................................... 3 5 11
Asia-Pacific................................................ 3 10 15
Africa...................................................... 4 2 8
Other....................................................... 2 1 1
----- ----- -----
Total...................................................... 26 31 64
----- ----- -----
C. Net Productive Development Wells Drilled
United States............................................... 604 419 629
Canada...................................................... 213 308 149
Europe...................................................... 40 51 54
Asia-Pacific................................................ 30 47 69
Africa...................................................... 16 10 15
Other....................................................... 31 32 17
----- ----- -----
Total...................................................... 934 867 933
----- ----- -----
D. Net Dry Development Wells Drilled
United States............................................... 7 16 21
Canada...................................................... -- 12 8
Europe...................................................... 5 2 4
Asia-Pacific................................................ 1 -- 3
Africa...................................................... -- -- --
Other....................................................... -- 1 2
----- ----- -----
Total...................................................... 13 31 38
----- ----- -----
Total number of net wells drilled........................... 1,035 969 1,117
===== ===== =====
8
9. Present Activities
A. Wells Drilling -- Year-End 2000
Gross Net
----- ---
United States....................................................... 151 69
Canada.............................................................. 63 12
Europe.............................................................. 26 9
Asia-Pacific........................................................ 9 4
Africa.............................................................. 5 2
Other............................................................... 9 3
--- ---
Total............................................................. 263 99
=== ===
B. Review of Principal Ongoing Activities in Key Areas
During 2000, ExxonMobil's activities were conducted, either directly or
through affiliated companies, for exploration by ExxonMobil Exploration
Company, for large development activities by ExxonMobil Development Company,
for producing and smaller development activities by ExxonMobil Production
Company and for gas marketing by ExxonMobil Gas Marketing Company. During this
same period, some of ExxonMobil's exploration, development, production and gas
marketing activities were also conducted in California by Aera Energy, LLC, a
joint venture with Shell Oil Company and in Canada by the Resources Division
of Imperial Oil Limited, which is 69.6 percent owned by ExxonMobil.
Some of the more significant ongoing activities are:
UNITED STATES
Exploration and delineation of additional hydrocarbon resources continued.
At year-end 2000, ExxonMobil's acreage totaled 13.4 million net acres.
ExxonMobil was active in areas onshore and offshore in the lower 48 states and
in Alaska. A total of 3.9 net exploration and delineation wells were completed
during 2000.
During 2000, 539.1 net development wells were completed within and around
mature fields in the inland lower 48 states.
Participation in Alaska production and development continued and a total of
21.0 net development wells were drilled in 2000. Equity realignment in the
Prudhoe Bay field increased the company's net production by 30 thousand
barrels per day.
ExxonMobil's net acreage in the Gulf of Mexico at year-end 2000 was 3.5
million acres. A total of 47.1 net exploration and development wells were
completed during the year and development continued on several Gulf of Mexico
projects in 2000.
. In May 2000, production began from the ExxonMobil-operated Hoover and
Diana fields in the deepwater Gulf of Mexico using a Deep-Draft Caisson
Vessel (DDCV). This DDCV, installed in 4,800 feet of water, set a world
water-depth record for a combined drilling and production platform.
. Activities to tie-in Nile, a one well subsea development in 3,500 feet
of water, to the Marlin host platform are underway. First production is
planned for second quarter 2001.
. Construction and drilling activities advanced in the ExxonMobil-operated
Mica field, a remote deepwater subsea development located in 4,500 feet
water depth tied back to the Pompano host platform. First production is
scheduled for mid-year 2001.
9
. Activities to tie-in the ExxonMobil-operated Marshall and Madison
discoveries, located in 4,800 feet water depth, to the Hoover host
facilities are underway. First production is planned for early 2002.
CANADA
ExxonMobil's year-end acreage holdings totaled 12.0 million net acres. A
total of 273.7 net exploration and development wells were completed during the
year.
Gross production from Cold Lake averaged 119 thousand barrels per day during
2000. Field work began on the next expansion targeted to start up in 2003. In
Eastern Canada, 2000 marked the first full year of gas production of the Sable
Offshore Energy Project. The Terra Nova oil development project offshore
Newfoundland is under construction.
EUROPE
France
ExxonMobil's acreage at year-end 2000 was 0.8 million net acres, with 2.5
net exploration and development wells completed during the year.
Germany
A total of 2.8 million net acres were held by ExxonMobil at year-end 2000,
with 4.8 net exploration and development wells drilled during the year. The
offshore A6/B4 gas project in the North Sea came on stream in the third
quarter of 2000.
Netherlands
ExxonMobil's interest in licenses totaled 2.5 million net acres at year-end
2000. During 2000, 2.7 net exploration and development wells were drilled.
Significant, but smaller fields, are continuously being discovered, developed
and brought on stream.
Norway
ExxonMobil's net interest in licenses at year-end 2000 totaled 1.4 million
acres, all offshore. ExxonMobil participated in 12.7 net exploration and
development well completions in 2000. Production was initiated on three
developments: Aasgard B/C, Sygna and Oseberg South. Field development projects
for Snorre B, Ringhorne and Grane fields are in progress.
United Kingdom
ExxonMobil's net interest in licenses at year-end 2000 totaled approximately
3.2 million acres, all offshore. A total of 28.2 net exploration and
development wells were completed during the year. Several projects started up,
including Shearwater, Triton, Cook and Skiff. Several major projects were
underway including Skene, Brigantine and Elgin/Franklin.
ASIA-PACIFIC
Australia
ExxonMobil's net year-end 2000 acreage holdings totaled 7.6 million acres.
ExxonMobil drilled a total of 24.4 net exploration and development wells in
2000. A development drilling program was completed offshore Australia.
10
Indonesia
ExxonMobil had acreage of 8.0 million net acres at year-end 2000. During the
year ExxonMobil acquired an additional 51 percent interest in the Cepu block,
bringing its total interest to 100 percent.
Malaysia
ExxonMobil has interests in production sharing contracts covering 4.5
million net acres offshore Malaysia. During the year, a total of 13.3 net
exploration and development wells were completed. Development and infill
drilling were successfully completed at Tapis-E, Pulai-A and Jerneh-A
platforms. Major development projects currently in progress are Angsi, Larut
and five satellite field developments. These are scheduled for installation
and start-up in the 2001 to 2003 time frame.
Papua New Guinea
ExxonMobil's 2000 year-end acreage was 0.6 million net acres, with 0.5 net
exploration and development wells completed in 2000. An extended well test
commenced in the Moran field.
Thailand
ExxonMobil's acreage in the Khorat concession totaled 15 thousand net acres
at year-end.
AFRICA
Angola
ExxonMobil's year-end 2000 acreage holdings totaled 3.7 million net acres
and 3.6 net exploration and development wells were completed during the year.
Development continued on the Girassol field in Block 17 with first production
scheduled in late 2001. Development planning is progressing on ExxonMobil-
operated discoveries in Block 15 and non-operated Block 17 discoveries.
Cameroon
ExxonMobil's acreage totaled 0.3 million net acres at year-end, with 0.9 net
exploration and development wells completed during the year. The D1b field is
under development with first oil planned by year-end 2001.
Chad
ExxonMobil's net year-end 2000 acreage holdings consisted of 4.1 million
acres. Construction has commenced on the Chad-Cameroon Oil Development and
Pipeline project which will develop discovered oil fields in landlocked
southern Chad and transport produced oil to the coast of Cameroon.
Equatorial Guinea
ExxonMobil's net acreage totaled 0.6 million acres at year-end, with 4.4 net
exploration and development wells completed during the year. Production from
the Jade platform started in June 2000.
Nigeria
ExxonMobil's net acreage totaled 1.4 million acres at year-end, with 10.8
net exploration and development wells completed during the year. Development
plans are being progressed for the Bonga discovery (OPL 212) and for the
ExxonMobil-operated Erha (OPL 209) discovery. Expected start-up is 2004 for
Bonga and 2005 for Ehra.
11
OTHER COUNTRIES
Argentina
ExxonMobil's acreage totaled 0.6 net million acres at year-end, with 4.0 net
exploration and development wells completed during the year.
Azerbaijan
At year-end 2000, ExxonMobil's net acreage totaled 0.2 million acres located
in the Caspian Sea offshore of Azerbaijan.
At the Megastructure Early Oil project, water injection to support reservoir
pressure was started in mid-2000. Engineering design of the next platform
continues.
Kazakhstan
ExxonMobil's net acreage totaled 0.4 million acres at year-end 2000, with
1.2 net exploration and development wells completed during 2000. Production
capacity from the Tengiz field has increased with the completion of a fifth
processing train and the implementation of gas handling de-bottlenecking
projects. Development planning to further increase production is ongoing.
Substantial progress was made on construction of the Caspian Pipeline
Consortium (CPC) project for transporting oil from Tengiz, and other Caspian
fields and nearby areas, to the Russian Black Sea port of Novorossiysk. Start-
up is projected in 2001. The pipeline will displace the high cost rail and
barge transportation now being used.
Qatar
Production and development activities continued on two major liquefied
natural gas (LNG) projects in Qatar -- Qatargas (Qatar Liquefied Gas Company
Limited) and RasGas (Ras Laffan Liquefied Natural Gas Company Ltd.). Initial
RasGas operations commenced in 1999 from the first LNG train. A second train
started up in March 2000, bringing total production capacity to 6.6 MTA
(million metric tons per year) of LNG. Engineering and design was completed in
2000 for two new LNG trains as part of the RasGas Expansion project.
In May 2000, a development and production sharing agreement was executed for
the Enhanced Gas Utilization (EGU) project, which provides for up to 1.75
billion cubic feet per day of gas production, along with associated condensate
and natural gas liquids, from Qatar's North field. Engineering and design of
the EGU gas production facilities were completed in 2000. Gas from EGU is
targeted for domestic use and regional sales via pipeline.
Republic of Yemen
ExxonMobil's net acreage in the Republic of Yemen production sharing areas
totaled 0.9 million acres onshore at year-end. During the year, 5.7 net
exploration and development wells were drilled and completed.
Venezuela
ExxonMobil's net acreage totaled 0.5 million acres at year-end with 19.3 net
exploration and development wells completed during the year. The Cerro Negro
heavy oil project began production in November 1999, and the Central
Processing facility was completed in the fourth quarter of 2000. Construction
activities on the Upgrader Facility at the Jose Industrial Complex are on
schedule for a 2001 start-up.
12
WORLDWIDE EXPLORATION
Exploration activities were underway in several areas in which ExxonMobil
has no established production operations. A total of 35.2 million net acres
were held at year-end, and 3.6 net exploration wells were completed during the
year.
Information with regard to mining activities follows:
- - - - - - -----------------------------------------------------
Syncrude Operations
Syncrude is a joint-venture established to recover shallow deposits of tar
sands using open-pit mining methods, to extract the crude bitumen, and to
produce a high-quality, light (32 degree API), sweet, synthetic crude oil. The
Syncrude operation, located near Fort McMurray, Alberta, Canada, exploits a
portion of the Athabasca Oil Sands Deposit. The location is readily accessible
by public road. The produced synthetic crude oil is shipped from the Syncrude
site to Edmonton, Alberta in the Alberta Oil Sands Pipeline owned by the
Alberta Energy Company Ltd. Since startup in 1978, Syncrude has produced 1.2
billion barrels of synthetic crude oil. Imperial Oil Limited is the owner of a
25 percent interest in the joint-venture. Exxon Mobil Corporation has a 69.6
percent interest in Imperial Oil Limited.
Operating License and Leases
Syncrude has an operating license issued by the Province of Alberta which is
effective until 2035. This license permits Syncrude to mine tar sands and
produce synthetic crude oil from approved development areas on tar sands
leases. Syncrude holds eight tar sands leases covering approximately 255,000
acres in the Athabasca Oil Sands Deposit. Issued by the Province of Alberta,
the leases are automatically renewable as long as tar sands operations are
ongoing or the leases are part of an approved development plan. Syncrude
leases 10, 12, 17, 22 and 34 (containing proven reserves) and leases 29, 30
and 31 (containing no proven reserves) are included within a development plan
approved by the Province of Alberta's Department of Resource Development.
There were no known previous commercial operations on these leases prior to
the start-up of operations in 1978.
Operations, Plant and Equipment
Operations at Syncrude involve three main processes: open pit mining,
extraction of crude bitumen and upgrading of crude bitumen into synthetic
crude oil. In the Base mine (lease 17), the mining and transportation system
uses draglines, bucketwheel reclaimers and belt conveyors. In the North mine
(leases 17 and 22) and in the Aurora mine (leases 10, 12 and 34), a truck,
shovel and hydrotransport system is used. Production from the Aurora mine
commenced in 2000. The extraction facilities, which separate crude bitumen
from sand, are capable of processing approximately 545,000 tons of tar sands a
day, producing 110 million barrels of crude bitumen a year. This represents
recovery capability of about 92 percent of the crude bitumen contained in the
mined tar sands.
Crude bitumen extracted from tar sands is refined to a marketable
hydrocarbon product through a combination of carbon removal in two large,
high-temperature, fluid-coking vessels and by hydrogen addition in high-
temperature, high-pressure, hydrocracking vessels. These processes remove
carbon and sulfur and reformulate the crude into a low viscosity, low sulfur,
high-quality synthetic crude oil product. In 2000 this upgrading process
yielded 0.843 barrels of synthetic crude oil per barrel of crude bitumen.
About two-thirds of the synthetic crude oil is processed by Edmonton area
refineries and the remaining one-third is pipelined to refineries in eastern
Canada and the mid-western United States. Electricity is provided to Syncrude
by a 270 megawatt electricity generating plant and an 80 megawatt electricity
generating plant, both located at Syncrude. The generating plants are owned by
the Syncrude participants. Imperial Oil Limited's 25 percent share of net
investment in plant, property and equipment, including surface mining
facilities, transportation equipment and upgrading facilities is $690 million.
13
Synthetic Crude Oil Reserves
The crude bitumen is contained within the unconsolidated sands of the
McMurray Formation. Ore bodies are buried beneath 50 to 150 feet of
overburden, have bitumen grades ranging from 4 to 14 weight percent and ore
thickness of 115 to 160 feet. Estimates of synthetic crude oil reserves are
based on detailed geological and engineering assessments of in-place crude
bitumen volume, the mining plan, historical extraction recovery and upgrading
yield factors, installed plant operating capacity and operating approval
limits. The in-place volume, depth and grade are established through extensive
and closely spaced core drilling. Proven reserves include the operating Base
and North mines and the Aurora mine. In accordance with the approved mining
plan, there are an estimated 3,535 million tons of extractable tar sands in
the Base and North mines, with an average bitumen grade of 10.4 weight
percent. In addition, at the Aurora mine, there are an estimated 1,645 million
tons of extractable tar sands at an average bitumen grade of 11.3 weight
percent. After deducting royalties payable to the Province of Alberta,
Imperial Oil Limited estimates its 25 percent net share of proven reserves is
equivalent to 610 million barrels of synthetic crude oil.
ExxonMobil Share of Net Proven Syncrude Reserves(1)
Synthetic Crude Oil
-------------------------------
Base Mine and
North Mine Aurora Mine Total
------------- ----------- -----
(millions of barrels)
January 1, 2000................................. 387 190 577
Revision of previous estimate................... -- 48 48
Production...................................... (14) (1) (15)
--- --- ---
December 31, 2000............................... 373 237 610
=== === ===
- - - - - - --------
(1) Net reserves are the company's share of reserves after deducting royalties
payable to the Province of Alberta.
Syncrude Operating Statistics (total operation)
2000 1999 1998 1997 1996
----- ----- ----- ----- -----
Operating Statistics
Total mined volume (millions of cubic yards)(1).. 85.1 100.1 98.4 71.1 63.4
Mined volume to tar sands ratio(1)............... 0.96 0.99 1.05 0.75 0.68
Tar sands mined (million of tons)................ 156.4 178.7 165.9 166.7 163.7
Average bitumen grade (weight percent)........... 11.0 10.8 10.7 10.6 10.4
----- ----- ----- ----- -----
Crude bitumen in mined tar sands (millions of
tons)........................................... 17.2 19.3 17.8 17.7 17.0
Average extraction recovery (percent)............ 89.7 91.4 91.6 91.0 90.0
----- ----- ----- ----- -----
Crude bitumen production (millions of
barrels)(2)..................................... 86.8 99.6 92.1 90.3 86.4
Average upgrading yield (percent)................ 84.3 83.9 84.6 84.5 84.2
----- ----- ----- ----- -----
Gross synthetic crude oil produced (millions of
barrels)........................................ 73.2 83.6 77.9 76.3 72.9
ExxonMobil net share (millions of barrels)(3).... 15 20 19 17 15
- - - - - - --------
(1) Includes pre-stripping of mine areas and reclamation volumes.
(2) Crude bitumen production is equal to crude bitumen in mined tar sands
multiplied by the average extraction recovery and the appropriate
conversion factor.
(3) Reflects ExxonMobil's 25 percent interest in production less applicable
royalties payable to the Province of Alberta.
14
Item 3. Legal Proceedings.
A previously reported matter, involving a proceeding by the Texas Natural
Resource Conservation Commission captioned "In the Matter of an Enforcement
Action Concerning Exxon Mobil Corporation, Air Account No. JE-0067-I" and
alleging that the corporation failed to timely install NOx RACT and meet other
related requirements at the Mobil Oil Corporation Beaumont, Texas refinery in
violation of the Texas Health and Safety Code and various Commission rules,
was settled and a Final Agreed Order prepared during the fourth quarter of
2000. The Agreed Order requires payment of an administrative penalty of
$64,800 in addition to a Supplemental Environmental Project (SEP). The SEP
involves the purchase by the corporation of $64,800 worth of communications
equipment for the Jefferson County Local Emergency Planning Commission to
improve their ability to respond to local emergencies, including air pollution
incidents. The Commission had initially sought an administrative penalty of
$234,900. The Final Order will be executed during the first half of 2001.
In November, 2000, the Illinois Attorney General's office made a demand for
$275,000 in civil penalties in connection with a previously reported matter
involving a suit commenced by the Attorney General of the State of Illinois
and the State's Attorney for Will County, Illinois and alleging that a July 2,
1999 release of water and gas from the coker unit of Mobil Oil Corporation's
Joliet, Illinois refinery violated several provisions of the Illinois
Environmental Protection Act, created a public nuisance and violated a 1998
Consent Order. Penalties were previously unspecified. The corporation is
reviewing the demand.
The corporation, the U.S. Environmental Protection Agency and the California
Regional Water Quality Control Board have reached an agreement in principle to
settle penalty claims arising from a 1991 oil spill by Mobil Oil Corporation
into the Santa Clara River upon payment of $1,250,000 in civil penalties. The
agencies allege the spill resulted in violations of the Federal Clean Water
Act, the California Water Code and the Federal Oil Pollution Act. The
settlement, as well as an associated consent decree still to be negotiated,
will ultimately require approval by the court and publication in the Federal
Register to become effective.
Refer to the relevant portions of Note 17 on page 46 of the Financial
Section of this report for additional information on legal proceedings.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
----------------
15
Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation
S-K, Item 401(b)].
Age as of
March 31,
Name 2001 Title (Held Office Since)
---- --------- ------------------------------------------------
L. R. Raymond.... 62 Chairman of the Board (1993)
R. Dahan......... 59 Senior Vice President (1995)
H. J. Longwell... 59 Senior Vice President (1995)
E. A. Renna...... 56 Senior Vice President (1999)
H. R. Cramer..... 50 Vice President (1999)
M. E. Foster..... 58 President, ExxonMobil Development Company (1999)
D. D. Humphreys.. 53 Vice President and Controller (1997)
K. T. Koonce..... 62 Vice President (1999)
C. W. Matthews... 56 Vice President and General Counsel (1995)
S. R. McGill..... 58 Vice President (1998)
J. T. McMillan... 64 Vice President (1997)
S. D. Pryor...... 51 Vice President (1999)
F. A. Risch...... 58 Vice President and Treasurer (1999)
D. S. Sanders.... 61 Vice President (1999)
J. S. Simon...... 57 Vice President (1999)
P. E. Sullivan... 57 Vice President and General Tax Counsel (1995)
J. L. Thompson... 61 Vice President (1991)
T. P. Townsend... 64 Vice President -- Investor Relations (1990)
and Secretary (1995)
For at least the past five years, Messrs. Longwell, Matthews, Raymond,
Risch, Sullivan, Thompson and Townsend have been employed as executives of the
registrant. Mr. Raymond also holds the title of president.
The following executive officers of the registrant have also served as
executives of the subsidiaries, affiliates or divisions of the registrant
shown opposite their names during the five years preceding December 31, 2000.
Esso Italiana S.p.A. ............................... Simon
Esso Malaysia Berhad................................ Humphreys
Esso Production Malaysia Inc. ...................... Humphreys
Exxon Chemical Company.............................. Sanders
Exxon Coal and Minerals Company..................... McMillan
Exxon Company, International........................ Dahan, McGill and Simon
Exxon Company, U.S.A................................ Foster and McMillan
Exxon Upstream Development Company.................. Foster
Exxon Ventures (CIS) Inc. .......................... Koonce
ExxonMobil Chemical Company......................... Sanders
ExxonMobil Coal and Minerals Company................ McMillan
ExxonMobil Fuels Marketing Company.................. Cramer
ExxonMobil Gas Marketing Company.................... McGill
ExxonMobil Lubricants & Petroleum Specialties
Company............................................ Pryor
ExxonMobil Production Company....................... Koonce
ExxonMobil Refining & Supply Company................ Simon
Mobil Asia Pacific Pty. Ltd. ....................... Pryor
Mobil Chemical Company.............................. Pryor
Mobil Corporation................................... Cramer and Renna
Mobil Europe and Central Asia Limited............... Cramer
Mobil Europe Limited................................ Cramer
Mobil Oil Corporation............................... Pryor and Renna
Mobil South, Inc. .................................. Cramer
Officers are generally elected by the Board of Directors at its meeting on
the day of each annual election of directors, each such officer to serve until
his or her successor has been elected and qualified.
16
PART II
Item 5. Market for Registrant's Common Stock and Related Shareholder Matters.
Reference is made to the quarterly information which appears on page 56 of
the Financial Section of this report.
In accordance with the registrant's 1997 Nonemployee Director Restricted
Stock Plan, as amended, each incumbent nonemployee director (13 persons) was
granted 1,200 shares of restricted stock on January 1, 2001. These grants are
exempt from registration under bonus stock interpretations such as the "no-
action" letter to Pacific Telesis Group (June 30, 1992).
Item 6. Selected Financial Data.
Years Ended December 31,
---------------------------------------------
2000 1999 1998 1997 1996
-------- -------- -------- -------- --------
(millions of dollars, except per share
amounts)
Sales and other operating
revenue, including excise taxes. $228,439 $182,529 $165,627 $197,732 $210,038
Net income
Before extraordinary item and
cumulative effect of
accounting change............. $ 15,990 $ 7,910 $ 8,144 $ 11,732 $ 10,474
Extraordinary gain from
required asset divestitures,
net of income tax............. $ 1,730 $ -- $ -- $ -- $ --
Cumulative effect of accounting
change........................ $ -- $ -- $ (70) $ -- $ --
-------- -------- -------- -------- --------
Net income..................... $ 17,720 $ 7,910 $ 8,074 $ 11,732 $ 10,474
Net income per common share
Before extraordinary item and
cumulative effect of
accounting change............. $ 4.60 $ 2.28 $ 2.33 $ 3.32 $ 2.95
Extraordinary gain, net of
income tax.................... $ 0.50 $ -- $ -- $ -- $ --
Cumulative effect of accounting
change........................ $ -- $ -- $ (0.02) $ -- $ --
-------- -------- -------- -------- --------
Net income..................... $ 5.10 $ 2.28 $ 2.31 $ 3.32 $ 2.95
Net income per common share -
assuming dilution
Before extraordinary item and
cumulative effect of
accounting change............. $ 4.55 $ 2.25 $ 2.30 $ 3.28 $ 2.91
Extraordinary gain, net of
income tax.................... $ 0.49 $ -- $ -- $ -- $ --
Cumulative effect of accounting
change........................ $ -- $ -- $ (0.02) $ -- $ --
-------- -------- -------- -------- --------
Net income..................... $ 5.04 $ 2.25 $ 2.28 $ 3.28 $ 2.91
Cash dividends per common share . $ 1.760 $ 1.687 $ 1.666 $ 1.619 $ 1.538
Total assets..................... $149,000 $144,521 $139,335 $143,751 $146,939
Long-term debt................... $ 7,280 $ 8,402 $ 8,532 $ 10,868 $ 11,986
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
Reference is made to the section entitled "Management's Discussion and
Analysis of Financial Condition and Results of Operations" beginning on page
20 of the Financial Section of this report.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Reference is made to the section entitled "Market Risks, Inflation and Other
Uncertainties" beginning on page 23 excluding the part entitled "Inflation and
Other Uncertainties" and to the
17
eleventh paragraph of the section entitled "Liquidity and Capital Resources"
on page 25 of the Financial Section of this report. All statements other than
historical information incorporated in this Item 7A are forward looking
statements. The actual impact of future market changes could differ materially
due to, among other things, factors discussed in this report.
Item 8. Financial Statements and Supplementary Data.
Reference is made to the consolidated financial statements, together with
the report thereon of PricewaterhouseCoopers LLP dated February 28, 2001,
appearing on pages 27 to 50; the Quarterly Information appearing on page 56
and the Supplemental Information on Oil and Gas Exploration and Production
Activities appearing on pages 51 to 55 of the Financial Section of this
report. Consolidated Financial Statement Schedules have been omitted because
they are not applicable or the required information is shown in the
consolidated financial statements or notes thereto.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
PART III
Item 10. Directors and Executive Officers of the Registrant.
Incorporated by reference to the sections entitled "Election of Directors"
and "Section 16(a) Beneficial Ownership Reporting Compliance" of the
registrant's definitive proxy statement for the 2001 annual meeting of
shareholders (the "2001 Proxy Statement").
Item 11. Executive Compensation.
Incorporated by reference to the section entitled "Director Compensation"
and the section entitled "Executive Compensation Tables" of the registrant's
2001 Proxy Statement.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
Incorporated by reference to the section entitled "Director and Executive
Officer Stock Ownership" of the registrant's 2001 Proxy Statement.
Item 13. Certain Relationships and Related Transactions.
None.
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.
(a) (1) and (a) (2) Financial Statements:
See Table of Contents on page 19 of the Financial Section of this
report.
(a) (3) Exhibits:
See Index to Exhibits on page 61 of this report.
(b) Reports on Form 8-K.
The Registrant did not file any reports on Form 8-K during the last
quarter of 2000.
18
FINANCIAL SECTION
TABLE OF CONTENTS
Management's Discussion and Analysis of Financial Condition and Results
of Operations........................................................... 20-26
Report of Independent Accountants........................................ 27
Consolidated Financial Statements
Statement of Income.................................................... 28
Balance Sheet.......................................................... 29
Statement of Shareholders' Equity...................................... 30
Statement of Cash Flows................................................ 31
Notes to Consolidated Financial Statements
1. Summary of Accounting Policies..................................... 32
2. Extraordinary Item and Accounting Change........................... 33
3. Merger of Exxon Corporation and Mobil Corporation.................. 33
4. Reorganization Costs............................................... 33
5. Miscellaneous Financial Information ............................... 34
6. Cash Flow Information.............................................. 34
7. Additional Working Capital Data ................................... 34
8. Equity Company Information ........................................ 35
9. Investments and Advances........................................... 35
10. Investment in Property, Plant and Equipment........................ 36
11. Leased Facilities ................................................. 36
12. Capital............................................................ 36
13. Employee Stock Ownership Plans .................................... 38
14. Financial Instruments ............................................. 38
15. Long-Term Debt..................................................... 39
16. Incentive Program.................................................. 45
17. Litigation and Other Contingencies ................................ 46
18. Annuity Benefits and Other Postretirement Benefits ................ 47
19. Income, Excise and Other Taxes .................................... 49
20. Disclosures about Segments and Related Information ................ 50
Supplemental Information on Oil and Gas Exploration and Production
Activities ............................................................. 51-55
Quarterly Information ................................................... 56
Operating Summary ....................................................... 57
19
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
FUNCTIONAL EARNINGS 2000 1999 1998
____________________________________________________________________________________________________________
(millions of dollars)
Earnings Including Merger Effects and Special Items
Upstream
United States $ 4,545 $1,842 $ 850
Non-U.S. 7,824 4,044 2,502
Downstream
United States 1,561 577 1,199
Non-U.S. 1,857 650 2,275
Chemicals
United States 644 738 792
Non-U.S. 517 616 602
Other operations 551 426 384
Corporate and financing (589) (514) (460)
Merger expenses (920) (469) --
Gain from required asset divestitures 1,730 -- --
Accounting change -- -- (70)
-----------------------
Net income $17,720 $7,910 $8,074
=======================
Net income per common share (dollars) $ 5.10 $ 2.28 $ 2.31
Net income per common share -- assuming dilution (dollars) $ 5.04 $ 2.25 $ 2.28
============================================================================================================
Merger Effects and Special Items
Upstream
United States $ -- $ -- $ (185)
Non-U.S. -- 119 (176)
Downstream
United States -- -- 8
Non-U.S. -- (120) (412)
Chemicals
United States -- -- (8)
Non-U.S. -- -- (1)
Corporate and financing -- -- 112
Merger expenses (920) (469) --
Gain from required asset divestitures 1,730 -- --
Accounting change -- -- (70)
-----------------------
Total $ 810 $ (470) $ (732)
=======================
============================================================================================================
Earnings Excluding Merger Effects and Special Items
Upstream
United States $ 4,545 $1,842 $1,035
Non-U.S. 7,824 3,925 2,678
Downstream
United States 1,561 577 1,191
Non-U.S. 1,857 770 2,687
Chemicals
United States 644 738 800
Non-U.S. 517 616 603
Other operations 551 426 384
Corporate and financing (589) (514) (572)
-----------------------
Total $16,910 $8,380 $8,806
=======================
Earnings per common share (dollars) $ 4.87 $ 2.41 $ 2.52
Earnings per common share -- assuming dilution (dollars) $ 4.81 $ 2.38 $ 2.49
============================================================================================================
20
REVIEW OF 2000 RESULTS
Earnings excluding merger effects and special items were $16,910 million, an
increase of $8,530 million from 1999. Net income in 2000 of $17,720 million,
including net favorable merger effects of $810 million, increased $9,810 million
from 1999. Upstream (Exploration and Production) earnings benefited from higher
crude oil and natural gas realizations, which on average were up about 60
percent and 45 percent, respectively, versus 1999. Excluding the effects of
lower entitlements caused by higher crude prices, liquids production was 3
percent higher than 1999. Downstream (Refining and Marketing) earnings improved
from the very depressed results in 1999, driven by stronger worldwide refining
margins and better refining operations. However, downstream profitability was
restrained by difficulties in recovering the significant increases in raw
material costs that occurred over much of the year. Merger implementation
activities in 2000 added a net $810 million to net income, reflecting $1,730
million of gains from asset divestitures that were a condition of regulatory
approval of the merger. These gains more than offset merger implementation
expenses of $920 million. Results in 1999 included $470 million of net charges
for special items, primarily merger expenses with other special items
essentially offsetting. Revenue for 2000 totaled $233 billion, up 25 percent
from 1999, and the cost of crude oil and product purchases increased by 41
percent, both influenced by higher prices.
Excluding merger expenses, the combined total of operating costs (including
operating, selling, general, administrative, exploration, depreciation and
depletion expenses from the consolidated statement of income and ExxonMobil's
share of similar costs for equity companies) in 2000 were $43.6 billion, down
about $700 million from 1999. The impact of efficiency initiatives, including
the capture of merger synergies, reduced operating costs by $1.6 billion.
Interest expense in 2000 was $589 million compared to $695 million in 1999 as
the effect of lower debt levels was partly offset by higher interest rates.
Upstream
Upstream earnings of $12,369 million increased due to higher crude oil and
natural gas realizations, up about 60 percent and 45 percent, respectively.
Liquids production of 2,553 kbd (thousands of barrels daily) increased from
2,517 kbd in 1999. Excluding the effects of lower entitlements caused by higher
crude prices, liquids production was 3 percent higher than 1999, mainly
reflecting new production from fields in the North Sea and Venezuela and
increased production from eastern Canada and Alaska. These increases more than
offset the effects of natural field declines. Natural gas production of 10,343
mcfd (millions of cubic feet daily) was about the same as 1999 reflecting higher
production in eastern Canada, Europe and Qatar, offset by lower production in
Indonesia. Excluding entitlement impacts, natural gas production increased about
1 percent. Lower exploration expenses also benefited 2000 upstream earnings.
Earnings from U.S. upstream operations were $4,545 million, an increase of
$2,703 million from 1999. Earnings outside the U.S. were $7,824 million, $3,899
million higher than last year, excluding a $141 million deferred tax benefit and
a $22 million property write-off in 1999.
Downstream
Downstream earnings of $3,418 million improved over $2 billion from the very
depressed results in 1999, driven by stronger worldwide refining margins and
better refining operations. Earnings also benefited from a planned reduction in
inventories as a result of merging Exxon and Mobil operations around the world.
Petroleum product sales of 7,993 kbd compared with 8,887 kbd in 1999. The
decrease reflected the effects of the required divestiture of Mobil's European
fuels joint venture and of U.S. marketing and refining assets, as well as lower
supply sales in Asia-Pacific resulting from the low margin environment. Refinery
throughput was 5,642 kbd compared with 5,977 kbd in 1999. Excluding the effects
of the divestments, refinery throughput in 2000 was at the same level as 1999
and petroleum product sales were down about 4 percent. Earnings from U.S.
downstream operations were $1,561 million, up $984 million from the depressed
results of 1999, reflecting stronger refining margins and improved operations,
partly offset by weaker marketing margins. Earnings outside the U.S. of $1,857
million were $1,087 million higher than 1999 after excluding special charges in
1999 in Japan of $80 million for non-merger related restructuring of downstream
operations and a $40 million write-off associated with the cancellation of a
power project. The improvement was driven by stronger European and to a much
lesser extent Southeast Asian refining margins and improved refining operations,
partly offset by weaker marketing margins.
Chemicals
Chemicals earnings totaled $1,161 million compared with $1,354 million in 1999.
Record prime product sales volumes of 25,637 kt (thousands of metric tons) were
up 354 kt. The decline in earnings was driven by higher feedstock and energy
costs and unfavorable foreign exchange effects.
Other Operations
Earnings from other operating segments totaled $551 million, an increase of $125
million from 1999, reflecting record copper, coal and electricity sales, higher
copper prices, lower operating expenses and favorable foreign exchange effects,
partly offset by lower coal prices.
Corporate and Financing
Corporate and financing expenses of $589 million compared with $514 million in
1999. The increase resulted from unfavorable foreign
21
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
exchange effects and lower tax-related benefits. Partly offsetting was a
reduction in administrative expenses as a result of combining Exxon and Mobil
headquarters operations. The effect of lower debt levels was partly offset by
higher interest rates during the year.
REVIEW OF 1999 RESULTS
Earnings excluding merger expenses and special items were $8,380 million, down
$426 million or 5 percent from 1998. Net income was $7,910 million, down from
$8,074 million in 1998. The decline was primarily in the downstream where
steeply rising crude oil costs could not be recovered in the marketplace. Crude
oil prices rose about $14 per barrel from January to December 1999, depressing
downstream margins in all geographic areas. Weaker chemicals margins and lower
coal prices also adversely affected earnings. However, upstream results
benefited from the increase in crude oil prices and partly offset the weakness
in downstream business conditions. Record chemicals, coal and copper volumes and
reduced expenses in every operating segment also benefited earnings. Results in
1999 included $470 million of net charges for special items -- $469 million of
merger expenses with other special items essentially offsetting. Results in 1998
included $732 million of net special charges. Revenue for 1999 totaled $186
billion, up 9 percent from 1998, and the cost of crude oil and product purchases
increased 24 percent.
Excluding merger expenses, the combined total of operating costs (including
operating, selling, general, administrative, exploration, depreciation and
depletion expenses from the consolidated statement of income and ExxonMobil's
share of similar costs for equity companies) in 1999 was $44.3 billion, down
about $400 million from 1998. The impact of efficiency initiatives, including
the capture of early merger synergies, reduced operating costs by $1.2 billion.
Interest expense in 1999 was $695 million, $127 million higher than 1998,
mainly due to a higher debt level and unfavorable foreign exchange effects.
Upstream
Upstream earnings of $5,886 million increased significantly from 1998 reflecting
higher average crude oil prices, up over $5 per barrel from 1998. Average U.S.
natural gas prices were 9 percent higher than the prior year, while European gas
prices, which are tied to petroleum product prices on a lagged basis, were about
17 percent lower. Liquids production of 2,517 kbd was up 1 percent from 2,502
kbd in 1998 as production from new developments in the North Sea, the Gulf of
Mexico, West Africa and the Caspian offset natural field declines in North
America and lower liftings in Indonesia and Malaysia. Natural gas production of
10,308 mcfd compared with 10,617 mcfd in 1998. Upstream expenses were reduced
from 1998 levels. Earnings from the U.S. upstream were $1,842 million, up $807
million after excluding $185 million of special charges related mainly to
property write-downs in 1998. Outside the U.S. upstream earnings were $3,925
million, up $1,247 million after excluding a $141 million deferred tax benefit
and a $22 million property write-off in 1999 and $176 million of other net
special charges in 1998.
Downstream
Downstream earnings of $1,227 million declined from 1998's strong results
primarily reflecting escalating crude oil costs and weaker downstream margins in
all geographic areas. Unfavorable foreign exchange and inventory effects also
reduced earnings. Higher volumes, mainly in the U.S., and lower operating
expenses provided a partial offset. Petroleum product sales were 8,887 kbd
compared with 8,873 kbd in 1998. Refinery throughput was 5,977 kbd compared with
6,093 kbd in 1998. In the U.S., downstream earnings were $577 million, down $614
million from 1998 after excluding $8 million of special credits related to
inventory adjustments in 1998. Downstream operations outside of the U.S. earned
$770 million, down $1,917 million from 1998 after excluding special charges from
both years. Results in 1999 included $80 million of charges for non-merger
related restructuring of Japanese downstream operations and a $40 million write-
off associated with the cancellation of a power project in Japan, while 1998
results included $412 million of special charges largely related to the impact
of lower prices on inventories and Mobil-British Petroleum (BP) alliance
implementation costs.
Chemicals
Earnings from chemicals operations totaled $1,354 million, down $40 million or 3
percent from 1998. Industry margins declined due to lower product prices and
higher feedstock costs. Prime product sales volumes of 25,283 kt were a record.
Earnings also benefited from lower operating expenses. Chemicals' results
included $9 million of special charges related to the impact of lower prices on
inventories in 1998.
Other Operations
Earnings from other operating segments totaled $426 million, an increase of $42
million from 1998. The increase reflects record copper and coal production,
lower operating expenses and favorable foreign exchange effects, partly offset
by depressed coal prices.
Corporate and Financing
Corporate and financing expenses were $514 million, $54 million higher than 1998
which included a net special credit of $112 million related to settlement of
prior years' tax disputes. Excluding special items, expenses were $58 million
lower reflecting lower tax-related charges.
MERGER OF EXXON CORPORATION AND MOBIL CORPORATION
On November 30, 1999, a wholly-owned subsidiary of Exxon Corporation (Exxon)
merged with Mobil Corporation (Mobil) so that Mobil became a wholly-owned
subsidiary of Exxon (the "Merger"). At the same time, Exxon changed its name to
Exxon Mobil Corporation (ExxonMobil). Under the terms of the agreement,
approximately 1.0 billion shares of ExxonMobil common stock were issued in
exchange for all the outstanding shares of Mobil common stock based upon an
exchange ratio of 1.32015. Following the exchange, former shareholders of Exxon
owned approximately 70 percent of the corporation, while former Mobil
shareholders owned approximately 30 percent of the corporation. Each outstanding
share of Mobil preferred stock was converted into one share of a new class of
ExxonMobil preferred stock.
As a result of the Merger, the accounts of certain downstream and chemicals
operations jointly controlled by the combining companies have been included in
the consolidated financial statements. These operations were previously
accounted for by Exxon and Mobil as separate companies using the equity method
of accounting.
22
The Merger was accounted for as a pooling of interests. Accordingly, the
consolidated financial statements give retroactive effect to the merger, with
all periods presented as if Exxon and Mobil had always been combined.
As a condition of the approval of the Merger, the U.S. Federal Trade
Commission and the European Commission required that certain property --
primarily downstream, pipeline and natural gas distribution assets -- be
divested. These assets, with a carrying value of approximately $3 billion, were
sold in the year 2000. Before-tax proceeds for these assets were approximately
$5 billion. The net after-tax gain of $1,730 million was reported as an
extraordinary item consistent with pooling of interests accounting
requirements. The properties have historically earned approximately $200
million per year.
REORGANIZATION COSTS
In association with the merger between Exxon and Mobil, $1,406 million pre-tax
($920 million after-tax) and $625 million pre-tax ($469 million after-tax) of
costs were recorded as merger related expenses in 2000 and 1999, respectively.
Cumulative charges included separation expenses related to workforce reductions
(approximately 6,000 employees at year-end 2000) and merger closing and
implementation costs. The separation reserve balance at year-end 2000 of
approximately $320 million is expected to be expended in 2001. Merger related
expenses are expected to grow to approximately $2.5 billion pre-tax on a
cumulative basis by 2002. Pre-tax operating synergies associated with the
Merger, which are on track with expectations, including cost savings, efficiency
gains, and revenue enhancements, are expected to reach $4.6 billion per year by
2002.
In the first quarter of 1999 the corporation recorded a $120 million after-
tax charge for the reorganization of Japanese downstream operations in its
wholly-owned Esso Sekiyu K.K. and 50.1 percent owned General Sekiyu K.K.
affiliates. The reorganization resulted in the reduction of approximately 700
administrative, financial, logistics and marketing service employee positions.
The Japanese affiliates recorded a combined charge of $216 million (before-tax)
to selling, general and administrative expenses for the employee related costs.
Substantially all cash expenditures anticipated in the restructuring provision
have been paid as of the end of 1999. General Sekiyu also recorded a $211
million (before-tax) charge to depreciation and depletion for the write-off of
costs associated with the cancellation of a power plant project at the Kawasaki
terminal. Manpower reduction savings associated with this reorganization are
approximately $50 million per year after-tax in 2000.
As indicated in note 4, during 1998 Mobil implemented reorganization programs
in Australia, New Zealand and Latin America to integrate regional fuels and
lubes operations. In 1997, Mobil and BP announced that their European
downstream alliance would implement a major reorganization of its lubricant
base oil refining business. Also in 1997, Mobil commenced two major cost
savings initiatives in Asia-Pacific: one in Japan in response to the
deregulated business environment and the other in Australia. After-tax costs
for programs initiated in 1998 were $41 million and for the 1997 programs were
$189 million. Benefits associated with these undertakings are estimated at $140
million per year after-tax.
The following table summarizes the activity in the reorganization reserves.
The 1998 opening balance represents accruals for provisions taken in prior
years.
Opening Balance at
Balance Additions Deductions Year End
___________________________________________________________________________
(millions of dollars)
1998 $300 $ 50 $181 $169
1999 169 563 351 381
2000 381 738 780 339
CAPITAL AND EXPLORATION EXPENDITURES
Capital and exploration expenditures in 2000 were $11.2 billion, down from $13.3
billion in 1999, primarily reflecting timing of completion of major project
expenditures.
Upstream spending was down 18 percent to $6.9 billion in 2000, from $8.4
billion in 1999, as a result of the completion of major projects in the North
Sea, Canada and South America, and lower exploration expenses. Capital
investments in the downstream totaled $2.6 billion in 2000, up $0.2 billion
from 1999, primarily reflecting increased investments in China and higher
spending at U.S. refineries. The increase was largely offset by lower spending
in the European Fuels Joint Venture with BP which was divested in 2000 as a
condition of regulatory approval of the merger, and lower spending in the
retail businesses. Chemicals capital expenditures were $1.5 billion in 2000,
down from $2.2 billion in 1999, due to the completion of major projects in the
United States, Singapore, Saudi Arabia, and Thailand.
Capital and exploration expenditures in the U.S. totaled $3.3 billion in
2000, a decrease of $0.1 billion from 1999, reflecting higher spending in both
the upstream and downstream, offset by lower spending in chemicals. Spending
outside the U.S. of $7.9 billion in 2000 compared with $9.9 billion in 1999,
reflecting lower expenditures in the upstream and chemicals.
Firm commitments related to capital projects totaled approximately $4.6
billion at the end of 2000, the same as at year-end 1999. The largest single
commitment in 2000 was $2.3 billion associated with the development of crude
oil and natural gas resources in Malaysia. The corporation expects to fund the
majority of these commitments through internally generated funds.
MARKET RISKS, INFLATION AND OTHER UNCERTAINTIES
In the past, crude, product and chemical prices have fluctuated widely in
response to changing market forces. The impacts of these price fluctuations on
earnings from upstream operations, downstream operations and chemical operations
have been varied, tending at times to be offsetting.
The markets for crude oil and natural gas have a history of significant price
volatility. Although prices will occasionally drop precipitously, industry
prices over the long term will continue to be driven by market supply and
demand fundamentals. Accordingly, the corporation tests the viability of its
oil and gas operations based on long-term price projections. The corporation's
assessment is that its operations will
23
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
continue to be successful in a variety of market conditions. This is the
outcome of disciplined investment and asset management programs.
Investment opportunities are tested against a variety of market conditions,
including low price scenarios. As a result, investments that would succeed only
in highly favorable price environments are screened out of the investment plan.
In addition, the corporation has had an aggressive asset management program in
which under-performing assets are either improved to acceptable levels or
considered for divestment. The asset management program involves a disciplined,
regular review to ensure that all assets are contributing to the corporation's
strategic and financial objectives. The result has been the creation of a very
efficient capital base.
Risk Management
The corporation's size, geographic diversity and the complementary nature of the
upstream, downstream and chemicals businesses mitigate the corporation's risk
from changes in interest rates, currency rates and commodity prices. As a
result, the corporation makes limited use of derivatives to offset exposures
arising from existing transactions.
Interest rate, foreign exchange rate and commodity price exposures from the
contracts undertaken in accordance with the corporation's policies have not
been significant. Derivative instruments are not held for trading purposes nor
do they have leveraged features.
Debt-Related Instruments
The corporation is exposed to changes in interest rates, primarily as a result
of its short-term and long-term debt with both fixed and floating interest
rates. The corporation makes limited use of interest rate swap agreements to
adjust the ratio of fixed and floating rates in the debt portfolio. The impact
of a 100 basis point change in interest rates affecting the corporation's debt
would not be material to earnings, cash flow or fair value.
Foreign Currency Exchange Rate Instruments
The corporation conducts business in many foreign currencies and is subject to
foreign currency exchange rate risk on cash flows related to sales, expenses,
financing and investment transactions. The impacts of fluctuations in foreign
currency exchange rates on ExxonMobil's geographically diverse operations are
varied and often offsetting in amount. The corporation makes limited use of
currency exchange contracts to reduce the risk of adverse foreign currency
movements related to certain foreign currency debt obligations. Exposure from
market rate fluctuations related to these contracts is not material. Aggregate
foreign exchange transaction gains and losses included in net income are
discussed in note 5 to the consolidated financial statements.
Commodity Instruments
The corporation makes limited use of commodity forwards, swaps and futures
contracts of short duration to mitigate the risk of unfavorable price movements
on certain crude, natural gas and petroleum product purchases and sales.
Commodity price exposure related to these contracts is not material.
Inflation and Other Uncertainties
The general rate of inflation in most major countries of operation has been
relatively low in recent years, and the associated impact on operating costs has
been countered by cost reductions from efficiency and productivity improvements.
The operations and earnings of the corporation and its affiliates throughout
the world have been, and may in the future be, affected from time to time in
varying degree by political developments and laws and regulations, such as
forced divestiture of assets; restrictions on production, imports and exports;
price controls; tax increases and retroactive tax claims; expropriation of
property; cancellation of contract rights and environmental regulations. Both
the likelihood of such occurrences and their overall effect upon the
corporation vary greatly from country to country and are not predictable.
RECENTLY ISSUED STATEMENTS
OF FINANCIAL ACCOUNTING STANDARDS
In June 1998, the Financial Accounting Standards Board released Statement No.
133, "Accounting for Derivative Instruments and Hedging Activities." Statement
No. 133, as amended by Statements No. 137 and 138, must be adopted by the
corporation no later than January 1, 2001. The statement establishes accounting
and reporting standards for derivative instruments. It requires that all
derivatives be recognized as either assets or liabilities in the financial
statements and measured at fair value. It establishes the accounting for changes
in the fair value of the derivatives depending on their intended use. Since the
corporation makes very limited use of derivatives, the effect of adoption on the
corporation's operations or financial condition will be negligible.
SITE RESTORATION AND OTHER ENVIRONMENTAL COSTS
Over the years the corporation has accrued provisions for estimated site
restoration costs to be incurred at the end of the operating life of certain of
its facilities and properties. In addition, the corporation accrues provisions
for environmental liabilities in the many countries in which it does business
when it is probable that obligations have been incurred and the amounts can be
reasonably estimated. This policy applies to assets or businesses currently
owned or previously disposed.
The corporation has accrued provisions for probable environmental remediation
obligations at various sites, including multi-party sites where ExxonMobil has
been identified as one of the potentially responsible parties by the U.S.
Environmental Protection Agency. The involvement of other financially
responsible companies at these multi-party sites mitigates ExxonMobil's actual
joint and several liability exposure. At present, no individual site is
expected to have losses material to ExxonMobil's operations, financial
condition or liquidity.
Charges made against income for site restoration and environmental
liabilities were $311 million in 2000, $219 million in 1999 and $240 million in
1998. At the end of 2000, accumulated site restoration and environmental
provisions, after reduction for amounts paid, amounted to $3.7 billion.
ExxonMobil believes that any cost in excess of the amounts already provided for
in the financial statements would not have a materially adverse effect upon the
corporation's operations, financial condition or liquidity.
24
In 2000, the corporation spent $1,529 million (of which $393 million were
capital expenditures) on environmental projects and expenses worldwide, mostly
dealing with air and water conservation. Total expenditures for such activities
are expected to be about $1.8 billion in both 2001 and 2002 (with capital
expenditures representing about 25 percent of the total).
TAXES
Income, excise and all other taxes and duties totaled $68.4 billion in 2000, an
increase of $6.9 billion or 11 percent from 1999. Income tax expense, both
current and deferred, was $11.1 billion compared to $3.2 billion in 1999,
reflecting higher pre-tax income in 2000. The effective tax rate increased from
31.8 percent in 1999 to 42.4 percent in 2000 as a result of a larger share of
total earnings coming from the more highly taxed non-U.S. upstream segment and
lower benefits from resolution of tax-related issues. Excise and all other taxes
and duties decreased $1.0 billion to $57.3 billion.
Income, excise and all other taxes and duties totaled $61.5 billion in 1999,
an increase of $1.6 billion or 3 percent from 1998. Income tax expense, both
current and deferred, was $3.2 billion compared to $3.9 billion in 1998,
reflecting lower pre-tax income in 1999, the impact of lower foreign tax rates
and favorable resolution of tax-related issues. The effective tax rate was 31.8
percent in 1999 versus 35.2 percent in 1998. Excise and all other taxes and
duties increased $2.3 billion to $58.3 billion, reflecting higher prices.
LIQUIDITY AND CAPITAL RESOURCES
In 2000, cash provided by operating activities totaled $22.9 billion, up $7.9
billion from 1999. Major sources of funds were net income of $17.7 billion and
non-cash provisions of $8.1 billion for depreciation and depletion.
Cash used in investing activities totaled $3.3 billion, down $7.7 billion
from 1999 due to higher proceeds from sales of subsidiaries, investments and
property, plant and equipment resulting from asset divestitures that were
required as a condition of the regulatory approval of the merger, and due to
lower additions to property, plant and equipment.
Cash used in financing activities was $14.2 billion, up $9.4 billion, driven
by debt reductions in the current year versus debt increases in 1999, along
with higher purchases of common shares. Dividend payments on common shares
increased from $1.687 per share to $1.760 per share and totaled $6.1 billion, a
payout of 35 percent. Total consolidated debt declined by $5.6 billion to $13.4
billion.
Shareholders' equity increased by $7.3 billion to $70.8 billion. The ratio of
debt to capital decreased to 15 percent, reflecting lower debt levels and the
higher shareholders' equity balance.
Prior to the merger, the corporation purchased shares of its common stock for
the treasury. Consistent with pooling accounting requirements, this repurchase
program was terminated effective with the close of the ExxonMobil merger on
November 30, 1999. On August 1, 2000, the corporation announced its intention
to purchase shares of its common stock. During 2000, Exxon Mobil Corporation
purchased 27.0 million shares of its common stock for the treasury at a gross
cost of $2,352 million. These purchases were to offset shares issued in
conjunction with company benefit plans and programs and to reduce the number of
shares outstanding. Shares outstanding were reduced from 3,477 million at the
end of 1999 to 3,465 million at the end of 2000. Purchases were made in both
the open market and through negotiated transactions, and may be discontinued at
any time.
In 1999, cash provided by operating activities totaled $15.0 billion, down
$1.4 billion from 1998. Major sources of funds were net income of $7.9 billion
and non-cash provisions of $8.3 billion for depreciation and depletion.
Cash used in investing activities totaled $11.0 billion, down $1.0 billion
from 1998 primarily as a result of lower additions to property, plant and
equipment, partly offset by lower sales of subsidiaries and property, plant and
equipment.
Cash used in financing activities was $4.8 billion, down $2.4 billion,
primarily due to fewer common share purchases. Dividend payments on common
shares increased from $1.666 per share to $1.687 per share and totaled $5.8
billion, a payout of 74 percent. Total consolidated debt increased by $2.0
billion to $19.0 billion.
Shareholders' equity increased by $1.3 billion to $63.5 billion. The ratio of
debt to capital increased to 22 percent, reflecting higher debt levels. During
1999, Exxon purchased 8.3 million shares of its common stock for the treasury
at a cost of $648 million. These purchases were used to offset shares issued in
conjunction with the company's benefit plans and programs. Purchases were made
both in the open market and through negotiated transactions. Consistent with
pooling of interest accounting requirements, these repurchases were terminated
effective with the close of the ExxonMobil merger on November 30, 1999.
Previously, as a consequence of the then proposed merger of Exxon and Mobil
announced on December 1, 1998, both companies' repurchase programs to reduce
the number of shares outstanding were discontinued.
Although the corporation issues long-term debt from time to time and
maintains a revolving commercial paper program, internally generated funds
cover the majority of its financial requirements.
As discussed in note 14 to the consolidated financial statements, the
corporation's financial derivative activities are limited to simple risk
management strategies. The corporation does not trade in financial derivatives
nor does it use financial derivatives with leveraged features. The corporation
maintains a system of controls that includes a policy covering the
authorization, reporting, and monitoring of derivative activity. The
corporation's derivative activities pose no material credit or market risks to
ExxonMobil's operations, financial condition or liquidity.
Litigation and Other Contingencies
As discussed in note 17 to the consolidated financial statements, a number of
lawsuits, including class actions, were brought in various courts against Exxon
Mobil Corporation and certain of its subsidiaries relating to the accidental
release of crude oil from the tanker Exxon Valdez in 1989. Essentially all of
these lawsuits have now been resolved or are subject to appeal.
25
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
On September 24, 1996, the United States District Court for the District of
Alaska entered a judgment in the amount of $5.058 billion in the Exxon Valdez
civil trial that began in May 1994. The District Court awarded approximately
$19.6 million in compensatory damages to fisher plaintiffs, $38 million in
prejudgment interest on the compensatory damages and $5 billion in punitive
damages to a class composed of all persons and entities who asserted claims for
punitive damages from the corporation as a result of the Exxon Valdez grounding.
The District Court also ordered that these awards shall bear interest from and
after entry of the judgment. The District Court stayed execution on the judgment
pending appeal based on a $6.75 billion letter of credit posted by the
corporation. ExxonMobil has appealed the judgment. The United States Court of
Appeals for the Ninth Circuit heard oral arguments on the appeal on May 3, 1999.
The corporation continues to believe that the punitive damages in this case are
unwarranted and that the judgment should be set aside or substantially reduced
by the appellate courts. The ultimate cost to the corporation from the lawsuits
arising from the Exxon Valdez grounding is not possible to predict and may not
be resolved for a number of years.
On December 19, 2000, a jury in Montgomery County, Alabama, returned a
verdict against the corporation in a contract dispute over royalties in the
amount of $87.69 million in compensatory damages and $3.42 billion in punitive
damages in the case of Exxon Corporation v. State of Alabama, et al. ExxonMobil
will challenge the verdict and believes that the verdict is unwarranted and
that the judgment should be set aside or substantially reduced. The ultimate
outcome is not expected to have a materially adverse effect upon the
corporation's operations or financial condition.
The U.S. Tax Court has decided the issue with respect to the pricing of crude
oil purchased from Saudi Arabia for the years 1979-1981 in favor of the
corporation. This decision is subject to appeal. Certain other issues for the
years 1979-1993 remain pending before the Tax Court. Ultimate resolution of
these issues and several other tax and legal issues, notably final resolution
of royalty recovery and tax issues related to the gas lifting imbalance in the
Common Area (along the German/Dutch border), is not expected to have a
materially adverse effect upon the corporation's operations, financial
condition or liquidity.
There are no events or uncertainties known to management beyond those already
included in reported financial information that would indicate a material
change in future operating results or financial condition.
THE EURO
On January 1, 1999, eleven European countries established fixed conversion rates
between their existing sovereign currencies ("legacy currencies") and adopted
the euro as their common legal currency. The euro and the legacy currencies are
each legal tender for transactions now. Beginning January 1, 2002, the
participating countries will issue euro-denominated bills and coins. By July 1,
2002 each country will withdraw its sovereign currency and transactions
thereafter will be conducted solely in euros. Based on work to date, the
conversion to the euro is not expected to have a material effect on the
corporation's operations, financial condition or liquidity.
FORWARD-LOOKING STATEMENTS
Statements in this discussion regarding expectations, plans and future events or
conditions are forward-looking statements. Actual future results, including
merger related expenses; synergy benefits from the merger (including cost
savings, efficiency gains and revenue enhancements); financing sources; the
resolution of contingencies; the effect of changes in prices, interest rates and
other market conditions; and environmental and capital expenditures could differ
materially depending on a number of factors. These factors include management's
ability to implement merger plans successfully and on schedule; the outcome of
commercial negotiations; changes in the supply of and demand for crude oil,
natural gas, and petroleum and petro-chemical products; and other factors
discussed above and under the caption "Factors Affecting Future Results" in
Item 1 of ExxonMobil's 2000 Form 10-K.
26
REPORT OF INDEPENDENT ACCOUNTANTS
[LOGO OF PRICEWATERHOUSECOOPERS LLC]
Dallas, Texas
February 28, 2001
To the Shareholders of Exxon Mobil Corporation
In our opinion, based on our audits and the report of other auditors, the
consolidated financial statements appearing on pages 28 through 50 present
fairly, in all material respects, the financial position of Exxon Mobil
Corporation and its subsidiary companies at 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 of America. These financial
statements are the responsibility of the corporation's management; our
responsibility is to express an opinion on these financial statements based on
our audits. The consolidated financial statements give retroactive effect to
the merger of Mobil Corporation on November 30, 1999 in a transaction
accounted for as a pooling of interests, as described in note 3 to the
consolidated financial statements. We did not audit the financial statements
of Mobil Corporation, which statements reflect total revenues of $53,531
million for the year ended December 31, 1998. Those statements were audited by
other auditors whose report thereon has been furnished to us, and our opinion
expressed herein, insofar as it relates to the amounts included for Mobil
Corporation, is based solely on the report of the other auditors. We conducted
our audits of these statements in accordance with auditing standards generally
accepted in the United States of America, which 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, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement
presentation. We believe that our audits and the report of the other auditors
provide a reasonable basis for our opinion.
As discussed in note 2 to the consolidated financial statements, the
corporation changed its method of accounting for the cost of start-up
activities in 1998.
/s/ PRICEWATERHOUSECOOPERS LLP
27
CONSOLIDATED STATEMENT OF INCOME
2000 1999 1998
______________________________________________________________________________________________________________________
(millions of dollars)
Revenue
Sales and other operating revenue, including excise taxes $228,439 $182,529 $165,627
Earnings from equity interests and other revenue 4,309 2,998 4,015
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Total revenue $232,748 $185,527 $169,642
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Costs and other deductions
Crude oil and product purchases $108,951 $ 77,011 $ 62,145
Operating expenses 18,135 16,806 17,666
Selling, general and administrative expenses 12,044 13,134 12,925
Depreciation and depletion 8,130 8,304 8,355
Exploration expenses, including dry holes 936 1,246 1,506
Merger related expenses 1,406 625 --
Interest expense 589 695