2001
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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
-----------------
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, 2001
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 (I.R.S.
jurisdiction Employer Identification
of incorporation or Number)
organization)
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)
-----------------
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Title of Each Class on Which Registered
------------------- -----------------------
Common Stock, without par value (6,792,598,170 shares
outstanding at February 28, 2002) 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 ____
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. ___
The aggregate market value of the voting stock held by non-affiliates of
the registrant on February 28, 2002, based on the closing price on that date of
$41.30 on the New York Stock Exchange composite tape, was in excess of $280
billion.
Documents Incorporated by Reference:
Proxy Statement for the 2002 Annual Meeting of Shareholders (Part III)
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EXXON MOBIL CORPORATION
FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001
TABLE OF CONTENTS
Page
Number
------
PART I
Item 1. Business.................................................................. 1-2
Item 2. Properties................................................................ 2-16
Item 3. Legal Proceedings......................................................... 16
Item 4. Submission of Matters to a Vote of Security Holders....................... 16
Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation S-K,
Item 401(b)]..................................................................... 17
PART II
Item 5. Market for Registrant's Common Stock and Related Shareholder Matters...... 18
Item 6. Selected Financial Data................................................... 18
Item 7. Management's Discussion and Analysis of Financial Condition and Results of
Operations................................................................ 18
Item 7A. Quantitative and Qualitative Disclosures About Market Risk................ 19
Item 8. Financial Statements and Supplementary Data............................... 19
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure................................................................ 19
PART III
Item 10. Directors and Executive Officers of the Registrant........................ 19
Item 11. Executive Compensation.................................................... 19
Item 12. Security Ownership of Certain Beneficial Owners and Management............ 19
Item 13. Certain Relationships and Related Transactions............................ 19
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K........... 19
Financial Section.................................................................. 20-62
Signatures......................................................................... 63-65
Index to Exhibits.................................................................. 66
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 November 30, 1999,
Mobil Corporation ("Mobil") became a wholly-owned subsidiary of Exxon
Corporation ("Exxon") and Exxon changed its name to Exxon Mobil Corporation.
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, manufacture 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 terms like 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 2001, the corporation spent $1,782 million (of which $505 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 $2.5 billion in both 2002 and 2003 (with capital
expenditures representing about 50 percent of the total). The projected
increase is primarily for capital projects to implement refining technology to
manufacture low-sulfur motor fuels in many parts of the world.
Operating data and industry segment information for the corporation are
contained on pages 55, 56 and 62; information on oil and gas reserves is
contained on pages 59 and 60 and information on company-sponsored research and
development activities is contained on page 40 of the Financial Section of this
report.
Factors Affecting Future Results
--------------------------------
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. A key component of the corporation's competitive position,
particularly given the commodity-based nature of many of its products, is its
ability to manage operating expenses successfully, which requires continuous
management focus on reducing unit costs and improving efficiency.
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
assets; restrictions on production, imports and exports; war or other
international conflicts; civil unrest and local security concerns that threaten
the safe operation of company facilities; price controls; tax increases and
retroactive tax claims; expropriation of property; cancellation of
1
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 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, general economic growth rates and the occurrence of economic
recessions; the development of new supply sources; adherence by countries to
OPEC quotas; supply disruptions; weather, including seasonal patterns that
affect energy demand and severe weather events that can disrupt operations;
technological advances, including advances in exploration, production,
refining, and petrochemical manufacturing technology and advances in technology
relating to energy usage; changes in demographics, including population growth
rates and consumer preferences; and the competitiveness of alternative energy
sources or product substitutes.
Project Factors: In addition to the factors cited above, the advancement,
cost and results of particular ExxonMobil projects 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.
Market Risk Factors: See pages 29 and 30 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 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 42, and on pages 57 through 62.
Information with regard to oil and gas producing activities follows:
-------------------------------------------------------------------
1. Net Reserves of Crude Oil and Natural Gas Liquids (millions of barrels) and
Natural Gas (billions of cubic feet) at Year-End 2001
Estimated proved reserves are shown on pages 59 and 60 of the Financial
Section of this report. No major discovery or other favorable or adverse event
has occurred since December 31, 2001, 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 61 of the Financial Section of this report.
2. Estimates of Total Net Proved Oil and Gas Reserves Filed with Other Federal
Agencies
During 2001, ExxonMobil filed proved reserves estimates with the U.S.
Department of Energy on Forms EIA-23 and EIA-28. The information on Form EIA-28
is presented on the same basis as the registrant's Annual Report on Form 10-K
for 2000, which shows ExxonMobil's net interests in all liquids and gas reserve
volumes and changes thereto from both ExxonMobil-operated properties and
properties operated by others. The data on Form EIA-23, although consistent
with the data on
2
Form EIA-28, is presented on a different basis, and includes 100 percent of the
oil and gas volumes from ExxonMobil-operated properties only, regardless of the
company's net interest. In addition, Form EIA-23 information does not include
gas plant liquids. The difference between the oil reserves reported on EIA-23
and those reported in the registrant's Annual Report on Form 10-K for 2000
exceeds five percent. The difference in gas reserves did not exceed five
percent.
3. Average Sales Prices and Production Costs per Unit of Production
Reference is made to page 57 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 59 of the Financial Section of this report. The net
production volumes of natural gas available for sale used in this calculation
are shown on page 62 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 2001 Year-End 2000
-------------------------- --------------------------
Oil Gas Oil Gas
------------- ------------ ------------- ------------
Gross Net Gross Net Gross Net Gross Net
------ ------ ------ ----- ------ ------ ------ -----
United States.... 35,610 14,020 9,905 5,872 35,552 14,067 9,857 5,930
Canada........... 6,551 5,266 5,096 2,548 6,428 5,188 4,926 2,489
Europe........... 1,710 548 1,356 479 1,702 546 1,331 480
Asia-Pacific..... 1,401 527 760 266 1,394 518 718 256
Africa........... 325 139 1 1 362 154 -- --
Other............ 1,086 202 123 39 974 176 137 41
------ ------ ------ ----- ------ ------ ------ -----
Total.......... 46,683 20,702 17,241 9,205 46,412 20,649 16,969 9,196
====== ====== ====== ===== ====== ====== ====== =====
Note: Year-end 2000 well counts for net oil and gas wells in the
United States and gross oil and gas wells in Canada were restated.
5. Gross and Net Developed Acreage
Year-End 2001 Year-End 2000
------------- -------------
Gross Net Gross Net
------ ------ ------ ------
(Thousands of acres)
United States.... 9,528 5,714 9,578 5,993
Canada........... 4,538 2,414 4,577 2,390
Europe........... 11,206 4,819 11,576 4,816
Asia-Pacific..... 5,203 1,640 4,605 1,528
Africa........... 2,108 630 894 387
Other............ 9,223 1,846 9,175 1,821
------ ------ ------ ------
Total.......... 41,806 17,063 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.
3
6. Gross and Net Undeveloped Acreage
Year-End 2001 Year-End 2000
-------------- --------------
Gross Net Gross Net
------- ------ ------- ------
(Thousands of acres)
United States.... 11,801 7,669 11,527 7,399
Canada........... 21,151 9,552 22,136 9,619
Europe........... 13,218 4,624 16,283 6,244
Asia-Pacific..... 28,295 14,161 38,037 19,641
Africa........... 43,660 15,736 47,325 20,111
Other............ 33,190 20,456 51,718 26,363
------- ------ ------- ------
Total.......... 151,315 72,198 187,026 89,377
======= ====== ======= ======
7. Summary of Acreage Terms in Key Areas
UNITED STATES
Oil and gas 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, and are
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.
Italy
Exploration permits are awarded for a period of six years, subject to
specific, minimum work commitments (an exploration well is usually included).
If permit obligations have been fulfilled, the titleholder of the permit is
entitled to two subsequent extensions of three years each. The program of both
the first and second extension period must include the drilling of a further
well. Production licenses are awarded for a period of 20 years upon discovery
of commercial hydrocarbons. After 15 years, the license holder can apply for an
extension of ten years. After seven years of the first extension period, the
license holder can apply for a further extension.
4
Netherlands
Onshore: Permits 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 were 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 were
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 ten 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, 1997 have an initial
period of 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
provided 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 a term of two to
six years (in some states the Petroleum 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 (applying to all of ExxonMobil'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
5
and renewals may be requested. Prior to September 1998, production licenses
were granted initially for 21 years, with a further renewal of 21 years and
thereafter renewals at the discretion of the Joint Authority. Effective
September 1998, new production licenses are to be 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
cooperation contracts, usually in the form of a production sharing contract,
negotiated with the national oil company. However, effective November 23, 2001,
pursuant to the new Oil and Gas Law, the national oil company's role as manager
of upstream activities under existing and future contracts will be transferred
to an upstream regulatory body (still to be established) reporting to the
Minister of Energy and Mineral Resources. Existing cooperation contracts will
be amended to reflect the transfer of authority to the upstream regulatory
body; however, the terms and conditions of the existing contracts will remain
unchanged. Future cooperation contracts will be entered into with the upstream
regulatory body. Regulations are being developed to implement the new law.
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 contract.
Papua New Guinea
Exploration and production activities are governed by the Oil and Gas Act.
Exploration licenses are granted for an initial term of six years with a
five-year extension possible. Generally, a 50 percent relinquishment of the
license area is required at the end of the initial six-year term, if extended.
Production licenses are granted for an initial 25-year period. An extension of
up to 20 years may be granted at the Minister's discretion. Petroleum retention
licenses may be granted for gas resources that are not commercially viable at
the time of application, but that may become commercially viable. These
licenses are granted for five-year terms, and may be extended twice for a
maximum retention time of 15 years.
Thailand
The Petroleum Act of 1972 allows production under ExxonMobil's concession
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
agreements generally provide for a negotiated extension.
6
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, and are 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 ten to 15 years with limited relinquishments in the
absence of commercial discoveries. The production period for crude oil 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) covered by an OPL. Upon
commercial discovery, an OPL may be converted to an OML. Partial relinquishment
is required at the end of the ten-year exploration period, and OMLs have a
20-year production period that may be extended.
Some exploration activities are carried out in deepwater by joint ventures
with indigenous companies holding interests in an OPL. OPLs in deepwater
offshore areas are valid for ten years and are non-renewable, while in all
other areas the licenses 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.
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.
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 extensions on mutual
agreement.
OTHER COUNTRIES
Abu Dhabi
Exploration and production activities are governed by a 75-year oil
concession agreement executed in 1939 and subsequently amended through various
agreements with the government of Abu Dhabi.
7
Argentina
The onshore concession terms 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 offshore concession
terms 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. A 50 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 production 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 area known
as 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 joint-venture
agreements 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 is 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 rights to develop and supply gas from the offshore
North Field development projects. These rights permit the economic development
and production of sufficient gas reserves to satisfy the gas sales obligations
of these projects.
Republic of Yemen
Production sharing agreements (PSAs) negotiated with the government entitle
the company to participate in exploration operations, and if successful,
development and production operations within a designated area, under terms
negotiated prior to executing the PSA. Existing production operations have a
20-year term 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 are awarded for 35 years. Production
licenses are awarded for 20 years under production service agreements.
Heavy oil strategic association agreements (such as the Cerro Negro project)
are typically limited to those projects that require vertical integration of
the production and upgrading of extra heavy crude oil. Contracts are awarded
for 35 years. Significant amendments to the contract terms require Venezuelan
congressional approval.
8
8. Number of Net Productive and Dry Wells Drilled
2001 2000 1999
----- ----- ----
A. Net Productive Exploratory Wells Drilled
United States........................... 4 2 16
Canada.................................. 30 49 4
Europe.................................. 3 3 7
Asia-Pacific............................ 7 5 4
Africa.................................. 4 2 8
Other................................... 3 1 1
----- ----- ----
Total................................. 51 62 40
----- ----- ----
B. Net Dry Exploratory Wells Drilled
United States........................... 4 2 11
Canada.................................. 22 12 2
Europe.................................. 3 3 5
Asia-Pacific............................ 2 3 10
Africa.................................. 4 4 2
Other................................... 6 2 1
----- ----- ----
Total................................. 41 26 31
----- ----- ----
C. Net Productive Development Wells Drilled
United States........................... 733 604 419
Canada.................................. 451 213 308
Europe.................................. 32 40 51
Asia-Pacific............................ 44 30 47
Africa.................................. 23 16 10
Other................................... 30 31 32
----- ----- ----
Total................................. 1,313 934 867
----- ----- ----
D. Net Dry Development Wells Drilled
United States........................... 14 7 16
Canada.................................. 6 -- 12
Europe.................................. 3 5 2
Asia-Pacific............................ 1 1 --
Africa.................................. -- -- --
Other................................... -- -- 1
----- ----- ----
Total................................. 24 13 31
----- ----- ----
Total number of net wells drilled....... 1,429 1,035 969
===== ===== ====
9. Present Activities
A. Wells Drilling
Year-End Year-End
2001 2000
--------- ---------
Gross Net Gross Net
----- --- ----- ---
United States............................ 138 83 151 69
Canada................................... 33 19 63 12
Europe................................... 7 2 26 9
Asia-Pacific............................. 26 14 9 4
Africa................................... 13 4 5 2
Other.................................... 10 3 9 3
--- --- --- --
Total................................ 227 125 263 99
=== === === ==
9
B. Review of Principal Ongoing Activities in Key Areas
During 2001, 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
48.2 percent-owned ExxonMobil 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 set forth below:
UNITED STATES
Exploration and delineation of additional hydrocarbon resources continued in
2001. At year-end 2001, 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 8.4 net exploration and delineation wells were completed
during 2001.
During 2001, 662.6 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 36.2 net development wells were
drilled.
ExxonMobil's net acreage in the Gulf of Mexico at year-end 2001 was 3.5
million acres. A total of 51.0 net exploration and development wells were
completed during the year and development continued on several Gulf of Mexico
projects.
. In April 2001, production began from Nile, a one well subsea development
in 3,500 feet of water, tied back to the Marlin host platform.
. In June 2001, production began from the ExxonMobil-operated Mica field,
a remote deepwater subsea development located in 4,500 feet water depth
tied back to the Pompano host platform.
. The ExxonMobil-operated Marshall and Madison fields, located in 4,300 -
4,900 feet water depth, were tied back to the Hoover-Diana host
facilities. Production started at Marshall in October 2001 and is
projected to start at Madison in 2002.
. Appraisal drilling and development planning continued on the Thunder
Horse discovery, the largest discovery to date in the U.S. offshore Gulf
of Mexico. A floating semi-submersible platform has been selected as the
design concept for the field.
CANADA
ExxonMobil's year-end acreage holdings totaled 12.0 million net acres. A
total of 509.3 net exploration and development wells were completed during the
year.
Gross production from Cold Lake averaged 128 thousand barrels per day during
2001. Field work continued on the next expansion targeted to start up in late
2002. In Eastern Canada, the Terra Nova oil development project, offshore
Newfoundland, underwent final commissioning in 2001 and came on stream in early
2002. Development of the Sable Offshore Energy Project continues, with the
second phase to be completed over the 2003-2006 period. ExxonMobil reached
agreement with co-venturers to assume operatorship of the Sable Offshore Energy
Project in late 2001, and assumed operatorship on February 1, 2002.
10
EUROPE
France
ExxonMobil's acreage at year-end 2001 was 0.8 million net acres, with 0.5
net development wells completed during the year.
Germany
A total of 2.5 million net acres were held by ExxonMobil at year-end 2001,
with 1.6 net development wells drilled during the year.
Italy
ExxonMobil's acreage was 0.3 million net acres at year-end 2001.
Netherlands
ExxonMobil's interest in licenses totaled 2.1 million net acres at year-end
2001. During 2001, 2.9 net exploration and development wells were drilled.
Norway
ExxonMobil's net interest in licenses at year-end 2001 totaled 1.2 million
acres, all offshore. ExxonMobil participated in 11.4 net exploration and
development well completions in 2001. Production was initiated on Ringhorne and
Snorre B in 2001. Field development projects at Sigyn, Mikkel, Grane and Fram
West are in progress.
United Kingdom
ExxonMobil's net interest in licenses at year-end 2001 totaled approximately
2.5 million acres, all offshore. A total of 23.9 net exploration and
development wells were completed during the year. Several projects started up
including Skene, Brigantine, Elgin/Franklin and Kestrel. Several projects were
underway including Penguins, Madoes, Mirren, Maclure and Otter.
ASIA-PACIFIC
Australia
ExxonMobil's net year-end 2001 acreage holdings totaled 6.5 million acres.
ExxonMobil drilled a total of 21.8 net exploration and development wells in
2001, both offshore and onshore. Construction of a gas pipeline in the offshore
Gippsland Basin from the Bream A platform to shore commenced in 2001.
Indonesia
ExxonMobil had acreage of 7.4 million net acres at year-end 2001, with 3.0
exploration wells completed during the year.
Malaysia
ExxonMobil has interests in production sharing contracts covering 1.2
million net acres offshore Malaysia at year-end 2001. During the year, a total
of 27.7 net exploration and development wells were completed. Development and
infill drilling were successfully completed at three platforms, Seligi-E,
11
Bekok-C and Dulang-B. First oil was produced from the Angsi-A platform in
December 2001 and from the Larut field in February 2002. Development projects
are currently in progress at Bintang and Tapis-F. These are scheduled for
installation and start-up in the 2002 to 2003 timeframe.
Papua New Guinea
A total of 0.6 million net acres were held by ExxonMobil at year-end 2001,
with 0.7 net development wells completed during the year. Work continued on the
Moran field development project.
Thailand
ExxonMobil's net acreage in the Khorat concession totaled 15 thousand net
acres at year-end 2001.
AFRICA
Angola
ExxonMobil's year-end 2001 acreage holdings totaled 3.6 million net acres
and 5.5 net exploration and development wells were completed during the year.
The Girassol field in Block 17 started production in late 2001. Construction
has begun on ExxonMobil-operated Kizomba A on Block 15, the first of several
projects planned on this block. In addition, engineering and design work was
initiated on Dalia, a non-operated Block 17 discovery.
Cameroon
ExxonMobil's acreage totaled 0.3 million net acres at year-end 2001, with
1.3 net development wells completed during the year. The D1b field is under
development with first oil planned by early 2002.
Chad
ExxonMobil's net year-end 2001 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 acreage totaled 0.6 million net acres at year-end 2001, with
5.1 net exploration and development wells completed during the year.
Nigeria
ExxonMobil's net acreage totaled 1.4 million acres at year-end 2001, with
18.6 net exploration and development wells completed during the year. Initial
production is expected from the ExxonMobil- operated Yoho project by late 2002.
Development is underway at the Bonga field (OML 118) and development planning
continues for the ExxonMobil-operated Erha (OPL 209) discovery. Expected
start-up is 2004 for Bonga and 2005 for Erha.
OTHER COUNTRIES
Abu Dhabi
ExxonMobil's net acreage in the onshore oil concession was 0.5 million acres
at year-end 2001. During the year, 4.8 net development wells were completed.
12
Argentina
ExxonMobil's acreage totaled 0.4 net million acres at year-end 2001, with
5.2 net exploration and development wells completed during the year.
Azerbaijan
At year-end 2001, ExxonMobil's net acreage totaled 0.2 million acres located
in the Caspian Sea offshore of Azerbaijan. During the year, 0.6 net exploration
and development wells were completed.
At the Megastructure Early Oil project, water injection to support reservoir
pressure is ongoing, with additional producers and injectors planned for 2002.
The next phase of development on the Megastructure was approved in 2001.
Engineering and construction efforts have begun on the Phase I platform, with
production expected by late 2005.
Kazakhstan
ExxonMobil's net acreage totaled 0.4 million acres at year-end 2001, with
1.7 net exploration and development wells completed during 2001. Production
capacity from the Tengiz field has increased with the full year impact of the
fifth processing train and the implementation of gas handling debottlenecking
projects. Development planning to further increase production is ongoing.
The Caspian Pipeline Consortium pipeline for transporting oil from Tengiz,
and other Caspian fields and nearby areas, to the Russian Black Sea port of
Novorossiysk started up in late 2001. The pipeline will mitigate the high cost
of rail and barge transportation.
Appraisal and initial development planning continue for the offshore
Kashagan discovery.
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.). The
Qatargas LNG facilities have three LNG trains with a total combined sales
capacity of 7.4 MTA (million metric tons per annum) of LNG plus associated
condensate. In October 2001, Qatargas awarded Engineering, Procurement and
Construction (EPC) contracts for the debottlenecking of the three LNG trains,
which will increase total sales capacity to 8.9 MTA by 2005. The RasGas LNG
facilities have two LNG trains with a total combined sales capacity of 6.6 MTA
of LNG plus associated condensate. In an ongoing effort to expand LNG sales
capacity from Qatar, in April 2001, RasGas awarded an EPC contract for a third
LNG train with sales capacity of 4.7 MTA of LNG plus associated condensate as
part of the RasGas Expansion Project.
In addition to the two existing LNG projects in Qatar, the Enhanced Gas
Utilization (EGU) project will provide 1.75 billion cubic feet per day of gas
sales plus associated condensate production and liquefied petroleum gases
(LPGs) exports from Qatar's North Field. Engineering and design of the EGU gas
production facilities were completed in 2000 with engineering and design of the
associated natural gas liquids fractionation and LPG export facilities
continuing through 2001. Gas from the EGU project is targeted for domestic use
and inter-regional sales via pipeline. An agreement in principle on key terms
to supply Kuwait with Qatari gas from the EGU project was announced in January
2002. A memorandum of understanding was signed with Bahrain for additional
pipeline sales from the EGU project.
Republic of Yemen
ExxonMobil's net acreage in the Republic of Yemen production sharing areas
totaled 0.9 million acres onshore at year-end 2001. During the year, 4.4 net
development wells were completed.
13
Venezuela
ExxonMobil's net acreage totaled 0.3 million acres at year-end 2001 with
16.0 net exploration and development wells completed during the year. The Cerro
Negro heavy oil project began production in 1999 and the Central Processing
Facility was completed in the fourth quarter 2000. Construction activities on
the Upgrader Facility at the Jose Industrial Complex were completed mid-2001
and the entire project was officially inaugurated in September 2001.
WORLDWIDE EXPLORATION
At year-end 2001 exploration activities were underway in several areas in
which ExxonMobil has no established production operations. A total of 25.8
million net acres were held at year-end 2001, and 6.8 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
Pembina Oil Sands Pipeline Limited Partnership. Since start-up in 1978,
Syncrude has produced about 1.3 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) truck, shovel and
hydrotransport systems are 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
14
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 2001, this
upgrading process yielded 0.845 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 was $750 million
at year end 2001.
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 3,500 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 4,090 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
that its 25 percent net share of proven reserves at year end 2001 was
equivalent to 821 million barrels of synthetic crude oil.
In 2001, the Syncrude owners endorsed a further development of the Syncrude
resource in the area and expansion of the upgrading facilities. The Syncrude
Aurora 2 and Upgrader Expansion 1 project adds a remote mining development and
expands the central processing and upgrading plant. This expansion increases
proven Syncrude reserves by 230 million barrels and will lead to total
production of about 370 thousand barrels of synthetic crude oil per day (gross)
when completed.
ExxonMobil Share of Net Proven Syncrude Reserves(1)
Synthetic Crude Oil
------------------------------
Base Mine and
North Mine Aurora Mine Total
------------- ----------- -----
(millions of barrels)
January 1, 2001.............. 373 237 610
Revision of previous estimate -- 230 230
Production................... (15) (4) (19)
--- --- ---
December 31, 2001............ 358 463 821
=== === ===
--------
(1) Net reserves are the company's share of reserves after deducting royalties
payable to the Province of Alberta.
15
Syncrude Operating Statistics (total operation)
2001 2000 1999 1998 1997
----- ----- ----- ----- -----
Operating Statistics
Total mined volume (millions of cubic yards)(1)......... 118.3 85.1 100.1 98.4 71.1
Mined volume to tar sands ratio(1)...................... 1.15 0.96 0.99 1.05 0.75
Tar sands mined (million of tons)....................... 181.2 156.4 178.7 165.9 166.7
Average bitumen grade (weight percent).................. 11.0 11.0 10.8 10.7 10.6
----- ----- ----- ----- -----
Crude bitumen in mined tar sands (millions of tons)..... 19.9 17.2 19.3 17.8 17.7
Average extraction recovery (percent)................... 87.0 89.7 91.4 91.6 91.0
----- ----- ----- ----- -----
Crude bitumen production (millions of barrels)(2)....... 97.6 86.8 99.6 92.1 90.3
Average upgrading yield (percent)....................... 84.5 84.3 83.9 84.6 84.5
----- ----- ----- ----- -----
Gross synthetic crude oil produced (millions of barrels) 82.4 73.2 83.6 77.9 76.3
ExxonMobil net share (millions of barrels)(3)........... 19 15 20 19 17
--------
(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.
Item 3. Legal Proceedings.
On December 20, 2001, the U.S. Environmental Protection Agency ("EPA")
issued a Notice of Violation ("NOV") regarding the corporation's Beaumont,
Texas refinery, alleging that the corporation failed to obtain Prevention of
Significant Deterioration permits relating to turnaround projects at the
refinery that allegedly resulted in significant net emission increases of
nitrogen oxides and sulfur oxides.
On December 20, 2001, the EPA issued an NOV for a refinery in Chalmette,
Louisiana that is operated and 50 percent-owned by wholly owned subsidiaries of
the corporation. The EPA alleges several violations of the Clean Air Act at the
refinery, including failure to properly monitor fugitive emissions leaks at the
isomerization and reformer units, failure to maintain air pollution control
equipment on a separator, and burning fuel gas with elevated hydrogen sulfide
concentrations in two heaters.
Although the EPA has not yet made a demand for specific fines or penalties
in either of the NOVs described above, it is possible that the EPA could seek
penalties in excess of $100,000.
The New Mexico Environment Department ("NMED") has issued a compliance order
requiring compliance and assessing a civil penalty with respect to alleged
violations of implementing regulations of the New Mexico Air Quality Control
Act at the Mobil Pipe Line Company's tank battery station in Buckeye, New
Mexico. The alleged violations include a failure to install a control device on
a storage tank, failure to obtain a permit prior to construction of a storage
tank, and failure to test, monitor, report and keep records for a storage tank.
Pursuant to the order, issued on June 13, 2001, the NMED is seeking a civil
penalty of $231,120. Mobil Pipe Line Company has appealed this order, and the
hearing has been postponed indefinitely pending the status of settlement
discussions. Settlement discussions with the NMED to resolve this matter are
ongoing.
Refer to the relevant portions of Note 17 on page 51 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.
-----------------
16
Executive Officers of the Registrant [pursuant to Instruction 3 to Regulation
S-K, Item 401(b)].
Age as of
March 31,
Name 2002 Title (Held Office Since)
---- --------- ---------------------------------------------------
L. R. Raymond........ 63 Chairman of the Board (1993)
R. Dahan............. 60 Executive Vice President (2001)
H. J. Longwell....... 60 Executive Vice President (2001)
E. G. Galante........ 51 Senior Vice President (2001)
R. W. Tillerson...... 50 Senior Vice President (2001)
H. R. Cramer......... 51 Vice President (1999)
M. E. Foster......... 59 President, ExxonMobil Development Company (1999)
D. D. Humphreys...... 54 Vice President and Controller (1997)
G. L. Kohlenberger... 49 Vice President (2002)
K. T. Koonce......... 63 Vice President (1999)
C. W. Matthews....... 57 Vice President and General Counsel (1995)
S. R. McGill......... 59 Vice President (1998)
J. T. McMillan....... 65 Vice President (1997)
P. T. Mulva.......... 50 Vice President -- Investor Relations and Secretary (2002)
F. A. Risch.......... 59 Vice President and Treasurer (1999)
D. S. Sanders........ 62 Vice President (1999)
J. S. Simon.......... 58 Vice President (1999)
P. E. Sullivan....... 58 Vice President and General Tax Counsel (1995)
J. L. Thompson....... 62 Vice President (1991)
For at least the past five years, Messrs. Dahan, Humphreys, Longwell,
Matthews, Raymond, Risch, Sullivan and Thompson 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, 2001.
Esso Italiana S.r.l...................................... Simon
Esso (Thailand) Public Company Limited................... Galante
Exxon Company, International............................. McGill and Simon
Exxon Company, U.S.A..................................... Foster and McMillan
Exxon Upstream Development Company....................... Foster
Exxon Ventures (CIS) Inc................................. Koonce and Tillerson
Exxon Yemen Inc.......................................... Tillerson
ExxonMobil Chemical Company.............................. Sanders and Galante
ExxonMobil Coal and Minerals Company..................... McMillan
ExxonMobil Development Company........................... Tillerson
ExxonMobil Fuels Marketing Company....................... Cramer
ExxonMobil Gas Marketing Company......................... McGill
ExxonMobil Global Services Company....................... Kohlenberger
ExxonMobil Lubricants & Petroleum Specialities Company... Kohlenberger
ExxonMobil Production Company............................ Koonce
ExxonMobil Refining & Supply Company..................... Simon
Imperial Oil Limited..................................... Mulva
Mobil Business Resources Corporation..................... Kohlenberger
Mobil Corporation........................................ Cramer
Mobil Europe and Central Asia Limited.................... Cramer
Officers are generally elected by the Board of Directors at its meeting on
the day of each annual election of directors; with each such officer serving
until a successor has been elected and qualified.
17
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 (10 persons) was
granted 2,400 shares of restricted stock on January 1, 2002. 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,
-----------------------------------------------
2001 2000 1999 1998 1997
-------- -------- -------- -------- --------
(millions of dollars, except per share amounts)
Sales and other operating revenue, including
excise taxes.............................. $209,417 $228,439 $182,529 $165,627 $197,735
Net income
Before extraordinary item and cumulative
effect of accounting change............ $ 15,105 $ 15,990 $ 7,910 $ 8,144 $ 11,732
Extraordinary gain, net of income tax.... $ 215 $ 1,730 $ -- $ -- $ --
Cumulative effect of accounting change... $ -- $ -- $ -- $ (70) $ --
-------- -------- -------- -------- --------
Net income............................... $ 15,320 $ 17,720 $ 7,910 $ 8,074 $ 11,732
Net income per common share
Before extraordinary item and cumulative
effect of accounting change............ $ 2.20 $ 2.30 $ 1.14 $ 1.16 $ 1.66
Extraordinary gain, net of income tax.... $ 0.03 $ 0.25 $ -- $ -- $ --
Cumulative effect of accounting change... $ -- $ -- $ -- $ (0.01) $ --
-------- -------- -------- -------- --------
Net income............................... $ 2.23 $ 2.55 $ 1.14 $ 1.15 $ 1.66
Net income per common share - assuming
dilution
Before extraordinary item and cumulative
effect of accounting change............ $ 2.18 $ 2.27 $ 1.12 $ 1.15 $ 1.64
Extraordinary gain, net of income tax.... $ 0.03 $ 0.25 $ -- $ -- $ --
Cumulative effect of accounting change... $ -- $ -- $ -- $ (0.01) $ --
-------- -------- -------- -------- --------
Net income............................... $ 2.21 $ 2.52 $ 1.12 $ 1.14 $ 1.64
Cash dividends per common share............. $ 0.910 $ 0.880 $ 0.844 $ 0.833 $ 0.810
Total assets................................ $143,174 $149,000 $144,521 $139,335 $143,751
Long-term debt.............................. $ 7,099 $ 7,280 $ 8,402 $ 8,532 $ 10,868
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 23
of the Financial Section of this report.
18
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 29, excluding the part entitled "Inflation and
Other Uncertainties," 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 27, 2002,
appearing on pages 33 to 55; the Quarterly Information appearing on page 56 and
the Supplemental Information on Oil and Gas Exploration and Production
Activities appearing on pages 57 to 61 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 2002 annual meeting of
shareholders (the "2002 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
2002 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 2002 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 20 of the Financial Section of this report.
(a)(3) Exhibits:
See Index to Exhibits on page 66 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 2001.
19
FINANCIAL SECTION
TABLE OF CONTENTS
Business Profile ............................................................................................ 21
Financial Summary ........................................................................................... 22
Management's Discussion and Analysis of Financial Condition and Results of Operations
Functional Earnings ...................................................................................... 23
Review of 2001 and 2000 Results .......................................................................... 24
Liquidity and Capital Resources .......................................................................... 26
Capital and Exploration Expenditures ..................................................................... 28
Merger of Exxon Corporation and Mobil Corporation ........................................................ 28
Merger Expenses and Reorganization Reserves .............................................................. 28
Site Restoration and Other Environmental Costs ........................................................... 29
Taxes .................................................................................................... 29
Market Risks, Inflation and Other Uncertainties .......................................................... 29
Recently Issued Financial Accounting Standards ........................................................... 30
Critical Accounting Policies ............................................................................. 30
Forward Looking Statements ............................................................................... 32
Report of Independent Accountants ........................................................................... 33
Consolidated Financial Statements
Statement of Income ...................................................................................... 34
Balance Sheet ............................................................................................ 35
Statement of Shareholders' Equity ........................................................................ 36
Statement of Cash Flows .................................................................................. 37
Notes to Consolidated Financial Statements
1. Summary of Accounting Policies ...................................................................... 38
2. Extraordinary Item and Accounting Change ............................................................ 39
3. Merger of Exxon Corporation and Mobil Corporation ................................................... 39
4. Merger Expenses and Reorganization Reserves ......................................................... 39
5. Miscellaneous Financial Information ................................................................. 40
6. Cash Flow Information ............................................................................... 40
7. Additional Working Capital Data ..................................................................... 40
8. Equity Company Information .......................................................................... 41
9. Investments and Advances ............................................................................ 41
10. Investment in Property, Plant and Equipment ......................................................... 42
11. Leased Facilities ................................................................................... 42
12. Employee Stock Ownership Plans ...................................................................... 42
13. Capital ............................................................................................. 43
14. Financial Instruments and Derivatives ............................................................... 44
15. Long-Term Debt ...................................................................................... 44
16. Incentive Program ................................................................................... 50
17. Litigation and Other Contingencies .................................................................. 51
18. Annuity Benefits and Other Postretirement Benefits .................................................. 52
19. Income, Excise and Other Taxes ...................................................................... 54
20. Disclosures about Segments and Related Information .................................................. 55
Quarterly Information ....................................................................................... 56
Supplemental Information on Oil and Gas Exploration and Production Activities ............................... 57-61
Operating Summary ........................................................................................... 62
20
BUSINESS PROFILE
Return on Capital and
Earnings After Average Capital Average Capital Exploration
Income Taxes Employed Employed Expenditures
--------------------------------------------------------------------------------------
Financial 2001 2000 2001 2000 2001 2000 2001 2000
-------------------------------------------------------------------------------------------------------------------------------
(millions of dollars) (percent) (millions of dollars)
Petroleum and natural gas
Upstream
United States $ 3,932 $ 4,545 $ 12,900 $ 12,804 30.5 35.5 $ 2,418 $ 1,859
Non-U.S 6,497 7,824 25,037 26,235 25.9 29.8 6,345 5,040
-------------------------------------------- --------------------
Total $ 10,429 $ 12,369 $ 37,937 $ 39,039 27.5 31.7 $ 8,763 $ 6,899
-------------------------------------------- --------------------
Downstream
United States $ 1,924 $ 1,561 $ 7,711 $ 7,976 25.0 19.6 $ 961 $ 1,077
Non-U.S. 2,303 1,857 18,610 19,756 12.4 9.4 1,361 1,541
-------------------------------------------- --------------------
Total $ 4,227 $ 3,418 $ 26,321 $ 27,732 16.1 12.3 $ 2,322 $ 2,618
-------------------------------------------- --------------------
Total petroleum and natural gas $ 14,656 $ 15,787 $ 64,258 $ 66,771 22.8 23.6 $ 11,085 $ 9,517
-------------------------------------------- --------------------
Chemicals
United States $ 398 $ 644 $ 5,506 $ 5,644 7.2 11.4 $ 432 $ 351
Non-U.S. 484 517 8,333 8,170 5.8 6.3 440 1,117
-------------------------------------------- --------------------
Total $ 882 $ 1,161 $ 13,839 $ 13,814 6.4 8.4 $ 872 $ 1,468
Other operations 489 551 3,721 3,992 13.1 13.8 285 163
Corporate and financing (222) (589) 6,182 2,886 -- -- 69 20
Merger expenses (525) (920) -- -- -- -- -- --
Gain from required asset divestitures 40 1,730 -- -- -- -- -- --
-------------------------------------------- --------------------
Net income $ 15,320 $ 17,720 $ 88,000 $ 87,463 17.8 20.6 $ 12,311 $ 11,168
============================================ ====================
Operating 2001 2000
----------------------------------------------------------------------------
(thousands of barrels daily)
Net liquids production
United States 712 733
Non-U.S. 1,830 1,820
--------------
Total 2,542 2,553
(millions of cubic feet daily)
Natural gas production available for sale
United States 2,598 2,856
Non-U.S. 7,681 7,487
--------------
Total 10,279 10,343
(thousands of barrels daily)
Petroleum product sales
United States 2,751 2,669
Non-U.S. 5,220 5,324
--------------
Total 7,971 7,993
(thousands of barrels daily)
Refinery throughput
United States 1,840 1,862
Non-U.S. 3,731 3,780
--------------
Total 5,571 5,642
(thousands of metric tons)
Chemical prime product sales 25,780 25,637
(millions of metric tons)
Coal production
United States 3 2
Non-U.S. 10 15
--------------
Total 13 17
(thousands of metric tons)
Copper production 252 254
21
FINANCIAL SUMMARY
2001 2000 1999 1998 1997
------------------------------------------------------------------------------------------------------------------------------
(millions of dollars, except per share amounts)
Sales and other operating revenue
Petroleum and natural gas $ 192,680 $ 210,006 $ 167,802 $ 151,109 $ 179,137
Chemicals 15,943 17,501 13,777 13,589 16,190
Other 794 932 950 929 2,408
-------------------------------------------------------------
Sales and other operating revenue, including excise taxes $ 209,417 $ 228,439 $ 182,529 $ 165,627 $ 197,735
Earnings from equity interests and other revenue 4,071 4,309 2,998 4,015 4,011
-------------------------------------------------------------
Total revenue $ 213,488 $ 232,748 $ 185,527 $ 169,642 $ 201,746
=============================================================
Earnings
Petroleum and natural gas
Upstream $ 10,429 $ 12,369 $ 5,886 $ 3,352 $ 6,905
Downstream 4,227 3,418 1,227 3,474 3,088
-------------------------------------------------------------
Total petroleum and natural gas $ 14,656 $ 15,787 $ 7,113 $ 6,826 $ 9,993
Chemicals 882 1,161 1,354 1,394 1,771
Other operations 489 551 426 384 434
Corporate and financing (222) (589) (514) (460) (466)
Merger expenses (525) (920) (469) -- --
Gain from required asset divestitures 40 1,730 -- -- --
Accounting change -- -- -- (70) --
-------------------------------------------------------------
Net income $ 15,320 $ 17,720 $ 7,910 $ 8,074 $ 11,732
=============================================================
Net income per common share $ 2.23 $ 2.55 $ 1.14 $ 1.15 $ 1.66
Net income per common share - assuming dilution $ 2.21 $ 2.52 $ 1.12 $ 1.14 $ 1.64
Cash dividends per common share $ 0.910 $ 0.880 $ 0.844 $ 0.833 $ 0.810
Net income to average shareholders' equity (percent) 21.3 26.4 12.6 12.9 18.7
Net income to total revenue (percent) 7.2 7.6 4.3 4.8 5.8
Working capital $ 5,567 $ 2,208 $ (7,592) $ (5,187) $ (377)
Ratio of current assets to current liabilities 1.18 1.06 0.80 0.85 0.99
Total additions to property, plant and equipment $ 9,989 $ 8,446 $ 10,849 $ 12,730 $ 11,652
Property, plant and equipment, less allowances $ 89,602 $ 89,829 $ 94,043 $ 92,583 $ 93,527
Total assets $ 143,174 $ 149,000 $ 144,521 $ 139,335 $ 143,751
Exploration expenses, including dry holes $ 1,175 $ 936 $ 1,246 $ 1,506 $ 1,252
Research and development costs $ 603 $ 564 $ 630 $ 753 $ 763
Long-term debt $ 7,099 $ 7,280 $ 8,402 $ 8,532 $ 10,868
Total debt $ 10,802 $ 13,441 $ 18,972 $ 17,016 $ 17,182
Fixed charge coverage ratio (times) 17.8 15.7 6.6 6.9 9.9
Debt to capital (percent) 12.4 15.4 22.0 20.6 20.3
Shareholders' equity at year-end $ 73,161 $ 70,757 $ 63,466 $ 62,120 $ 63,121
Shareholders' equity per common share $ 10.74 $ 10.21 $ 9.13 $ 8.98 $ 9.04
Average number of common shares outstanding (millions) 6,868 6,953 6,906 6,937 7,022
Number of regular employees at year-end (thousands) 97.9 99.6 106.9 111.6 114.5
Note: Prior period per share amounts restated for the two-for-one stock split
effective June 20, 2001.
22
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
FUNCTIONAL EARNINGS 2001 2000 1999
---------------------------------------------------------------------------------------------------------------------
(millions of dollars, except per share amounts)
Earnings Including Merger Effects and Special Items
Upstream
United States $ 3,932 $ 4,545 $ 1,842
Non-U.S. 6,497 7,824 4,044
Downstream
United States 1,924 1,561 577
Non-U.S. 2,303 1,857 650
Chemicals
United States 398 644 738
Non-U.S. 484 517 616
Other operations 489 551 426
Corporate and financing (222) (589) (514)
Merger expenses (525) (920) (469)
Gain from required asset divestitures 40 1,730 --
------------------------------------------
Net income $ 15,320 $ 17,720 $ 7,910
==========================================
Net income per common share $ 2.23 $ 2.55 $ 1.14
Net income per common share - assuming dilution $ 2.21 $ 2.52 $ 1.12
====================================================================================================================
Merger Effects and Special Items
Upstream
United States $ -- $ -- $ --
Non-U.S. -- -- 119
Downstream
United States -- -- --
Non-U.S. -- -- (120)
Chemicals
United States (extraordinary item) 100 -- --
Non-U.S. (extraordinary item) 75 -- --
Merger expenses (525) (920) (469)
Gain from required asset divestitures (extraordinary item) 40 1,730 --
------------------------------------------
Total $ (310) $ 810 $ (470)
==========================================
====================================================================================================================
Earnings Excluding Merger Effects and Special Items
Upstream
United States $ 3,932 $ 4,545 $ 1,842
Non-U.S. 6,497 7,824 3,925
Downstream
United States 1,924 1,561 577
Non-U.S. 2,303 1,857 770
Chemicals
United States 298 644 738
Non-U.S. 409 517 616
Other operations 489 551 426
Corporate and financing (222) (589) (514)
------------------------------------------
Total $ 15,630 $ 16,910 $ 8,380
==========================================
Earnings per common share $ 2.28 $ 2.43 $ 1.21
Earnings per common share-assuming dilution $ 2.26 $ 2.40 $ 1.19
====================================================================================================================
Note: Prior period per share amounts restated for the two-for-one stock split
effective June 20, 2001.
23
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
The following discussion and analysis of ExxonMobil's financial results, as well
as the accompanying financial statements and related notes to consolidated
financial statements to which they refer, are the responsibility of the
management of Exxon Mobil Corporation. The corporation's accounting and
financial reporting fairly reflect its straightforward business model involving
the extracting, refining and marketing of hydrocarbons and hydrocarbon-based
products. The corporation's business model involves the production (or
purchase), manufacture and sale of physical products, and all commercial
activities are directly in support of the underlying physical movement of goods.
This straightforward approach extends to the financing of the business. In
evaluating business or investment opportunities, the corporation views as
economically equivalent any debt obligation, whether disclosed on the face of
the consolidated balance sheet, or disclosed as other debt-like obligations in
notes to the financial statements, such as those summarized in the table on page
26. This consistent, conservative approach to financing the capital-intensive
needs of the corporation has helped ExxonMobil to sustain the "triple-A" status
of its long-term debt securities for more than eighty years.
REVIEW OF 2001 RESULTS
Earnings excluding merger effects and special items were $15,630 million, a
decrease of $1,280 million from 2000. Net income in 2001 was $15,320 million,
including $215 million of extraordinary gains and $525 million of merger costs,
a decrease of $2,400 million from 2000, which benefited from $810 million in net
favorable merger effects including gains from divestments required as a
condition of regulatory approval of the merger. Upstream (Exploration and
Production) earnings in 2001 declined, following lower crude oil realizations,
which on average were down 18 percent versus 2000. Upstream volumes in 2001, on
an oil equivalent basis, were up 1 percent excluding the effect of reduced
natural gas production operations in Indonesia due to security concerns.
Downstream (Refining and Marketing) earnings improved from 2000, reflecting
stronger U.S. refining margins and improved marketing results outside of the
U.S. Chemicals earnings declined versus 2000, as lower product realizations and
weakening demand conditions put significant pressure on commodity margins and
more than offset the $175 million of extraordinary gains associated with asset
management activities. Prime product sales volumes were 1 percent higher than
2000, reflecting capacity additions in Singapore and Saudi Arabia. Merger
implementation activities in 2001 reduced earnings by a net $485 million. Gains
from asset divestitures that were a condition of regulatory approval of the
merger added $40 million to earnings, partly offsetting merger implementation
expenses of $525 million. Revenue for 2001 totaled $213 billion, down 8 percent
from 2000.
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 2001 was $44.0 billion, up $400
million from 2000. Cost increases associated with new operations, higher energy
costs and higher pension-related expenses were substantially offset by the
favorable impact of continuing efficiency initiatives carried out in all
business lines. The impact of these initiatives, including the capture of merger
synergies, reduced operating costs by $1.2 billion in 2001, and cumulatively by
$4 billion since 1998. Interest expense in 2001 was $293 million compared to
$589 million in 2000 reflecting lower debt levels and interest rates.
Upstream
Upstream earnings of $10,429 million decreased $1,940 million, or 16 percent
from last year's record level, primarily due to lower crude oil prices. The
impacts of lower crude realizations and higher exploration expenses in future
growth areas were partly offset by higher average natural gas realizations,
principally in North America and Europe. U.S. and Canadian natural gas prices
reached historical highs early in 2001 but dropped through the remainder of the
year. Liquids production in 2001 of 2,542 kbd (thousands of barrels daily) was
down slightly from 2000, as natural field declines in mature areas were largely
offset by new volumes from work programs and new developments in the North Sea,
U.S., Equatorial Guinea and Kazakhstan, some of which have not yet reached full
capacity. Absent the effect of reduced Arun operations in Indonesia due to
security concerns, worldwide gas production was up about 2 percent, with
increases in Europe, Australia, Canada and Qatar. Including the impact of lower
Indonesia volumes, full-year 2001 worldwide natural gas production of 10,279
mcfd (millions of cubic feet daily) compared with 10,343 mcfd in 2000. Combined
liquids and gas volumes, on an oil equivalent basis, were up 1 percent excluding
the effect of reduced natural gas production operations in Indonesia. Earnings
from U.S. upstream operations were $3,932 million, a decrease of $613 million.
Earnings outside the U.S. were $6,497 million, $1,327 million lower than 2000.
Downstream
Downstream earnings of $4,227 million were a record and improved 24 percent over
2000. Results benefited from higher refining margins early in the year,
particularly in the U.S., improved worldwide refining operations and higher
marketing margins outside the U.S. Refining margins in most areas peaked in the
second quarter and declined during the second half of 2001. Earnings also
benefited from a planned reduction in inventories as a result of optimizing
operations around the world. Petroleum product sales of 7,971 kbd compared with
7,993 kbd in the prior year. Excluding the effect of the required merger related
divestments in 2000, volumes were up slightly. Refinery throughput was 5,571 kbd
compared with 5,642 kbd in 2000. U.S. downstream earnings were $1,924 million,
up $363 million, reflecting stronger refining margins and improved operations.
Earnings outside the U.S. of $2,303 million were $446 million higher than 2000.
The improvement was driven by stronger marketing margins, partly offset by
weaker European refining margins.
Chemicals
Chemicals earnings totaled $882 million, including $175 million of net gains on
asset management activities. Absent this special item, chemicals earnings were
$707 million, a decrease of $454 million from 2000. Most of the reduction
occurred in the U.S. as lower product realizations and weakening demand
conditions put significant pressure on
24
commodity margins. Record prime product sales volumes of 25,780 kt (thousands of
metric tons) were 1 percent above the prior year's record level as higher sales
outside the U.S., reflecting capacity additions in Singapore and Saudi Arabia,
were partly offset by lower sales in the U.S. reflecting weaker industrial
demand.
Other Operations
Earnings from other operating segments totaled $489 million, a decrease of $62
million from 2000, reflecting lower copper prices.
Corporate and Financing
Corporate and financing expenses decreased $367 million to $222 million,
reflecting lower net interest costs due to lower debt levels and higher cash
balances, along with favorable foreign exchange and tax effects.
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 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 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 extraordinary 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 was $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 were a record and increased due to higher
crude oil and natural gas realizations, up about 60 percent and 45 percent,
respectively. Liquids production of 2,553 kbd 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 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.
Prime product sales volumes of 25,637 kt 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 and coal 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 exchange effects and lower
tax-related benefits, partly offset by 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.
25
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
LIQUIDITY AND CAPITAL RESOURCES
In 2001, cash provided by operating activities totaled $22.9 billion, the same
level as 2000. Major sources of funds were net income of $15.3 billion and
non-cash provisions of $7.9 billion for depreciation and depletion.
Cash used in investing activities totaled $8.2 billion, up $4.9 billion
from 2000 due to lower proceeds from sales of subsidiaries, investments and
property, plant and equipment resulting from the absence of the asset
divestitures in 2000 that were required as a condition of the regulatory
approval of the merger, and due to higher additions to property, plant and
equipment.
Cash used in financing activities was $15.0 billion, up $0.9 billion,
driven by higher purchases of common shares, offset by lower debt reductions.
Dividend payments on common shares increased from $0.88 per share to $0.91 per
share and totaled $6.3 billion, a payout of 41 percent. Total consolidated
short-term and long-term debt declined by $2.6 billion to $10.8 billion.
Shareholders' equity increased by $2.4 billion to $73.2 billion.
During 2001, Exxon Mobil Corporation purchased 139 million shares of its
common stock for the treasury at a gross cost of $5,721 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 6,930 million at the end of 2000 to 6,809 million at the end of
2001. Purchases were made in both the open market and through negotiated
transactions, and may be discontinued at any time.
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 $0.844 per share to $0.880 per share and totaled $6.1 billion, a
payout of 35 percent. Total consolidated short-term and long-term debt declined
by $5.6 billion to $13.4 billion. Shareholders' equity increased by $7.3 billion
to $70.8 billion.
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 54 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 6,955 million at the
end of 1999 to 6,930 million at the end of 2000. Purchases were made in both the
open market and through negotiated transactions.
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. The management of cash that may be
temporarily available as surplus to the corporations immediate needs is
carefully controlled, both to optimize returns on cash balances, and to ensure
its secure, ready availability to meet the corporations' cash requirements as
they arise.
Long-Term Contractual Obligations and
Other Commercial Commitments
Set forth below is information about the corporations' long-term contractual
obligations and other commercial commitments outstanding at December 31, 2001.
It brings together data for easy reference from the consolidated balance sheet
and from individual notes to consolidated financial statements. This information
is important in understanding the financial position of the corporation. In
considering the economic viablity of investment opportunities, the corporation
views any source of financing, whether it be operating leases, third party
guarantees or equity company debt, as being economically equivalent to
consolidated debt of the corporation.
Payments due by Period
----------------------------
Long-Term Contractual Footnote 2003- 2007 and Total
Obligations Reference 2002 2006 Beyond Amount
----------------------------------------------------------------------------------------
(millions of dollars)
Long-term debt (1) Note 15 $ -- $3,498 $ 3,601 $ 7,099
- Due in one year (2) 339 -- -- 339
ExxonMobil share
of equity company
long-term debt (3) Note 8 -- 1,922 2,028 3,950
- Due in one year (2) 590 -- -- 590
Operating leases (4) Note 11 1,327 2,910 2,687 6,924
Unconditional purchase
obligations (5) Note 17 156 544 1,329 2,029
Firm capital
commitments (6) 1,996 911 978 3,885
--------------------------------------
Total $4,408 $9,785 $10,623 $24,816
=======================================
Notes:
(1) Includes capitalized lease obligations of $266 million.
(2) The amounts due in one year are included in notes and loans payable of
$3,703 million (note 7) for consolidated companies and in short-term debt of
$1,232 million (note 8) for equity companies.
(3) The corporation includes its share of equity company debt in its calculation
of return on average capital employed.
(4) Minimum commitments for operating leases, shown on an undiscounted basis,
cover drilling equipment, tankers, service stations and other properties.
26
(5) Unconditional purchase obligations, shown on an undiscounted basis, mainly
pertain to pipeline throughput agreements. The present value of these
commitments, excluding imputed interest of $733 million, totaled $1,296 million.
(6) Firm commitments related to capital projects, shown on an undiscounted
basis, totaled approximately $3.9 billion at the end of 2001, compared with $4.6
billion at year-end 2000. The largest single commitment outstanding at year-end
2001 was $2.1 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 internal cash flow.
Other Commercial Commitments
The corporation and certain of its consolidated subsidiaries were contingently
liable at December 31, 2001, for $3,921 million, primarily relating to
guarantees for notes, loans and performance under contracts (note 17). This
included $672 million representing guarantees of non-U.S. excise taxes and
customs duties of other companies, entered into as a normal business practice,
under reciprocal arrangements. Also included in this amount were guarantees by
consolidated affiliates of $1,641 million, representing ExxonMobil's share of
obligations of certain equity companies.
On December 31, 2001, unused credit lines for short-term financing totaled
approximately $5.3 billion (note 7).
The table below shows the corporation's fixed charge coverage and
consolidated debt to capital ratios. The data demonstrate the corporations
creditworthiness. Throughout this period, the corporations long-term debt
securities maintained the top credit rating from both Standard and Poor's (AAA)
and Moody's (Aaa), a rating it has sustained for 83 years.
2001 2000 1999
---------------------------------
Fixed charge coverage ratio (times) 17.8 15.7 6.6
Debt to capital (percent) 12.4 15.4 22.0
Net debt to capital (percent) (1) 5.3 7.9 20.4
Credit rating AAA/Aaa AAA/Aaa AAA/Aaa
(1) Debt net of all cash
Management views the corporation's financial strength, as evidenced by the
above financial ratios and other similar measures, to be a competitive advantage
of strategic importance. The corporation's sound financial position gives it the
opportunity to access the world's capital markets in the full range of market
conditions, and enables the corporation to take on large, long-term capital
commitments in the pursuit of maximizing shareholder value.
In addition to the above commitments, the corporation makes limited use of
derivative instruments, which are discussed in Risk Management on page 29 and
note 14 on page 44.
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. The vast majority of
the claims have been resolved leaving a few compensatory damages cases to be
tried. All of the punitive damage claims were consolidated in the civil trial
that began in May 1994.
In that trial, on September 24, 1996, the United States District Court for
the District of Alaska entered a judgment in the amount of $5.058 billion. 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 appealed the judgment. On
November 7, 2001, the United States Court of Appeals for the Ninth Circuit
vacated the punitive damage award as being excessive under the Constitution and
remanded the case to the District Court for it to determine the amount of the
punitive damage award consistent with the Ninth Circuit's holding. The Ninth
Circuit upheld the compensatory damage award which has been paid. The letter of
credit was terminated on February 1, 2002. 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. The verdict
was upheld by the trial court on May 4, 2001. ExxonMobil has appealed the
judgment and believes it should be set aside or substantially reduced on factual
and constitutional grounds. The ultimate outcome is not expected to have a
materially adverse effect upon the corporation's operations or financial
condition.
On May 22, 2001, a state court jury in New Orleans, Louisiana, returned a
verdict against the corporation and three other entities in a case brought by a
landowner claiming damage to his property. The property had been leased by the
landowner to a company that performed pipe cleaning and storage services for
customers, including the corporation. The jury awarded the plaintiff $56 million
in compensatory damages (90 percent to be paid by the corporation) and $1
billion in punitive damages (all to be paid by the corporation). The damage
related to the presence of naturally occurring radioactive material (NORM) on
the site resulting from pipe cleaning operations. The award has been upheld at
the trial court. ExxonMobil will appeal the judgment to the Louisiana Fourth
Circuit Court of Appeals and believes that the judgment should be set aside or
substantially reduced on factual and constitutional grounds. 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. The ultimate resolution of
these issues and several other tax and legal issues, including resolution of tax
issues related to the gas lifting imbalance along the German/Dutch border, is
not expected to have a materially adverse effect upon the corporation's
operations or financial condition.
27
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
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.
CAPITAL AND EXPLORATION EXPENDITURES
Capital and exploration expenditures in 2001 were $12.3 billion, up from $11.2
billion in 2000, reflecting the corporation's active investment program.
Upstream spending was up 27 percent to $8.8 billion in 2001, from $6.9
billion in 2000, as a result of higher spending on major projects in Africa, the
North Sea, and Canada, and increased drilling activity. Capital investments in
the downstream totaled $2.3 billion in 2001, down $0.3 billion from 2000,
primarily reflecting timing of investments in China partly offset by increased
spending in the retail businesses. Chemicals capital expenditures were $0.9
billion in 2001, down from $1.5 billion in 2000, due to the completion of major
projects in Singapore and Saudi Arabia, and timing of investment in China.
Capital and exploration expenditures in the U.S. totaled $3.9 billion in
2001, an increase of $0.6 billion from 2000, reflecting higher spending in both
the upstream and chemicals, partly offset by lower spending in the downstream.
Spending outside the U.S. of $8.4 billion in 2001 was up $0.5 billion from 2000,
reflecting higher expenditures in the upstream, partly offset by lower
expenditures in the downstream and chemicals.
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.
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. The
carrying value of these assets was approximately $3 billion and before-tax
proceeds were approximately $5 billion. Net after-tax gains of $40 million and
$1,730 million were reported in 2001 and 2000, respectively, as extraordinary
items consistent with pooling of interests accounting requirements. The divested
properties historically earned approximately $200 million per year.
MERGER EXPENSES AND REORGANIZATION RESERVES
In association with the merger between Exxon and Mobil, $748 million pre-tax
($525 million after-tax), $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 2001, 2000 and 1999, respectively. Charges included
separation expenses related to workforce reductions (approximately 8,000
employees at year-end 2001), plus implementation and merger closing costs. The
separation reserve balance at year-end 2001 of approximately $197 million is
expected to be expended in 2002. Merger-related expenses are expected to grow to
approximately $2.9 billion pre-tax on a cumulative basis by the end of 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 approximately $7 billion per year by 2002.
In the first quarter of 1999, the corporation recorded a $120 million
after-tax charge for the non-merger related 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 were paid in 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. Workforce reduction savings
associated with this reorganization are approximately $50 million per year
after-tax.
The following table summarizes the activity in the reorganization reserves.
The 1999 opening balance represents accruals for provisions taken in prior
years.
Opening Balance at
Balance Additions Deductions Year End
--------------------------------------------------------------------------------
(millions of dollars)
1999 $169 $563 $351 $381
2000 381 738 780 339
2001 339 187 329 197
28
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 ExxonMobils 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 $371 million in 2001, $311 million in 2000 and $219 million in
1999. At the end of 2001, 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.
ExxonMobil's worldwide environmental costs in 2001 totaled $1,782 million
of which $505 million were capital expenditures and $1,277 million were
operating costs (including the $371 million of site restoration and
environmental provisions noted above). These costs were mostly associated with
air and water conservation. Total costs for such activities are expected to
increase to about $2.5 billion in both 2002 and 2003 (with capital expenditures
representing about 50 percent of the total). The projected increase is primarily
for capital projects to implement refining technology to manufacture low-sulfur
motor fuels in many parts of the world.
TAXES
Income, excise and all other taxes and duties totaled $66.6 billion in 2001, a
decrease of $1.8 billion or 3 percent from 2000. Income tax expense, both
current and deferred, was $9.0 billion compared to $11.1 billion in 2000,
reflecting lower pre-tax income in 2001. The effective tax rate of 39.3 percent
in 2001 compared to 42.4 percent in 2000, benefiting from a higher level of
favorably resolved tax-related issues. Excise and all other taxes and duties
were $57.6 billion.
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.
MARKET RISKS, INFLATION AND OTHER UNCERTAINTIES
In the past, crude, natural gas, petroleum 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 chemicals operations have been varied, tending at times to be offsetting.
Nonetheless, the global energy markets can give rise to extended periods in
which market conditions are adverse to one or more of the corporation's
businesses. Such conditions, along with the capital intensive nature of the
industry and very long lead times associated with many of our projects,
underscore the importance of maintaining a strong financial position. Management
views the corporation's financial strength, including the AAA and Aaa ratings of
its long-term debt securities by Standard and Poor's and Moody's, as a
competitive advantage.
Although price levels of crude oil and natural gas will occasionally spike
upwards or 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
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.
The corporation has had an active 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 and has meant that the corporation has seldom been required to
write-down the carrying value of assets, even during periods of low commodity
prices.
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. The
corporation relies on these operating attributes and strengths to reduce
enterprise-wide risk. As a result, the corporation makes limited use of
derivatives to offset exposures arising from existing transactions.
The corporation does not trade in derivatives nor does it use derivatives
with leverage 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. Interest rate, foreign exchange rate and commodity price exposures
arising from derivative contracts undertaken in accordance with the
corporation's policies have not been significant.
29
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
The fair value of derivatives outstanding and recorded on the balance sheet
at December 31, 2001 was $50 million before-tax. This is the amount that the
corporation would have had to pay to third parties if these derivatives had been
settled at year-end. These derivative fair values were substantially offset by
the fair values of the underlying exposures being hedged. During 2001, the
corporation recognized a before-tax gain of $23 million related to derivative
activity. This gain included the offsetting amounts from the changes in fair
value of the items being hedged by the derivatives. The fair value of
derivatives outstanding at year-end and gains recognized during the year are
immaterial in relation to the corporation's year-end cash balance of $6.5
billion, total assets of $143.2 billion, or net income for the year of $15.3
billion.
Debt-Related Instruments
The corporation is exposed to changes in interest rates, primarily as a result
of its short-term debt and long-term debt carrying 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 2001, the Financial Accounting Standards Board issued Statements of
Financial Accounting Standards No. 141 (FAS 141), "Business Combinations", and
No. 142 (FAS 142), "Goodwill and Other Intangible Assets". Under FAS 141, the
pooling of interests method of accounting is no longer permitted and the
purchase method must be used for business combinations initiated after June 30,
2001. Under FAS 142, which will be effective for the corporation beginning
January 1, 2002, goodwill and certain intangibles will no longer be amortized
but will be subject to annual impairment tests. The effect of adoption of the
new standards on the corporation's financial statements will be negligible.
In August 2001, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 143 (FAS 143), "Accounting for Asset
Retirement Obligations". FAS 143 is required to be adopted by the corporation no
later than January 1, 2003 and its primary impact will be to change the method
of accruing for upstream site restoration costs. These costs are currently
accrued ratably over the productive lives of the assets. At the end of 2001 the
cumulative amount accrued under this policy was approximately $3.2 billion.
Under FAS 143, the fair value of asset retirement obligations will be recorded
as liabilities when they are incurred, which are typically at the time the
assets are installed. Amounts recorded for the related assets will be increased
by the amount of these obligations. Over time the liabilities will be accrued
for the change in their present value and the initial capitalized costs will be
depreciated over the useful lives of the related assets. The corporation is
evaluating the impact of adopting FAS 143.
In August 2001, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 144 (FAS 144), "Accounting for the
Impairment or Disposal of Long-Lived Assets". FAS 144 is required to be adopted
prospectively by the corporation no later than January 1, 2002. FAS 144
supercedes previous guidance related to the impairment or disposal of long-lived
assets. For long-lived assets to be held and used, it resolves certain
implementation issues of the former standards, but retains the basic
requirements of recognition and measurement of impairment losses. For long-lived
assets to be disposed of by sale, it broadens the definition of those disposals
that should be reported separately as discontinued operations. There is no
impact on the corporation of adopting FAS 144, except that future sales of
long-lived assets may be required to be presented as discontinued operations,
which would be a different presentation than under previous accounting
standards.
CRITICAL ACCOUNTING POLICIES
The corporation's accounting and financial reporting fairly reflect its
straightforward business model involving the extracting, refining and marketing
of hydrocarbons and hydrocarbon-based products. The preparation of financial
statements in conformity with U.S. Generally Accepted Accounting Principles
(GAAP) requires management to make estimates and judgments that affect the
reported amounts of assets, liabilities, revenues and expenses and the
disclosure of contingent assets and liabilities. The following summary provides
further information about the critical accounting policies and should be read in
conjunction with note 1 on page 38.
30
Principles of Consolidation
The consolidated financial statements include the accounts of those significant
subsidiaries that the corporation controls. They also include the corporation's
undivided interests in upstream assets and liabilities. Amounts representing the
corporation's percentage interest in the underlying net assets of other
significant affiliates that it does not control, but exercises significant
influence, are included in "Investments and advances"; the corporation's share
of the net income of these companies is included in the consolidated statement
of income caption "Earnings from equity interests and other revenue". The
accounting for these non-consolidated companies is referred to as the equity
method of accounting.
Additional disclosures of summary balance sheet and income information for
those subsidiaries accounted for under the equity method of accounting can be
found in note 8 on page 41. The corporation believes this to be important
information necessary to a full understanding of the corporation's financial
statements.
Investments in companies that are partially owned by the corporation are
integral to the corporation's operation's. In some cases they serve to balance
worldwide risks and in others they provide the only available means of entry
into a particular market or area of interest. The other parties who also have an
equity interest in these companies are either independent third parties or host
governments that share in the business results according to their percentage
ownership. The corporation does not invest in these companies in order to remove
liabilities from its balance sheet. In fact, the corporation has long been on
record supporting an alternative accounting method that would require each
investor to consolidate its percentage share of all assets and liabilities in
these partially owned companies rather than only the percentage in the net
equity. This method of accounting for investments in partially owned companies
is not permitted by GAAP except where the investments are in the undivided
interests in upstream assets and liabilities. However, for purposes of
calculating return on average capital employed, which is not covered by GAAP
standards, the corporation includes its share of debt of these partially owned
companies in the determination of average capital employed.
Revenue Recognition
Revenues associated with sales of crude oil, natural gas, petroleum and chemical
products and all other items are recorded when title passes to the customer.
The corporation does not engage in arrangements whereby the corporation has
ongoing relationships with its buyers that require it to repurchase its products
or provide buyers with the right of return. As a result, the recognition of
revenues is straightforward.
Derivative Instruments
As discussed on page 29, the corporation makes limited use of derivatives.
Derivative instruments are not held for trading purposes nor do they have
leverage features. 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, reducing the corporation's need for derivatives to manage
business risk.
Because of their limited use, accounting policies for derivatives do not
impact information that is significant or critical to an understanding of the
corporation's financial condition and results of operations.
Inventories
Crude oil, products and merchandise are carried at the lower of current market
value or cost (generally determined under the last-in, first-out method - LIFO).
There are other acceptable methods of accounting for inventory such as
first-in, first-out or average cost. The corporation uses the LIFO method
because it charges each sale with the cost of the most recently purchased
inventory. As such, the profit recognized on these sales is based on the latest
cost structure and generally results in a better matching of costs and revenues.
Property, Plant and Equipment
The corporation's exploration and production activities are accounted for under
the "successful efforts" method. Depreciation, depletion and amortization, based
on cost less estimated salvage value of the asset, are primarily determined
under either the unit-of-production method or the straight-line method.
Unit-of-production rates are based on oil, gas and mineral reserves estimated to
be recoverable from existing facilities. The straight-line method is based on
estimated asset service life taking obsolescence into consideration. The service
lives of refinery and chemicals components generally extend to 25 and 20 years,
respectively, and reflect the corporation's long-term commitment to effective
asset optimization.
Under the "successful efforts" method, costs are accumulated on a
field-by-field basis with certain exploratory expenditures and exploratory dry
holes being expensed as incurred. Exploratory wells that find oil and gas in an
area requiring a major capital expenditure before production can begin are
evaluated annually to ensure that commercial quantities of reserves have been
found or that additional exploration work is underway or planned. Costs of
productive wells and development dry holes are capitalized and amortized on the
unit-of-production method for each field. The corporation uses this accounting
policy instead of the "full cost" method because it provides a more timely
accounting of the success or failure of the corporation's exploration and
production activities. If the full cost method were used, all costs would be
capitalized and depreciated on a country-by-country basis. The capitalized costs
would be subject to an impairment test by country. The full cost method would
tend to delay the expense recognition of unsuccessful projects.
Oil, gas and other properties held and used by the corporation are reviewed
for impairment whenever events or changes in circumstances indicate that the
carrying amounts may not be recoverable. The corporation estimates the future
undiscounted cash flows of the affected properties to judge the recoverability
of carrying amounts. In general, analyses are based on proved reserves, except
in circumstances where it is probable that additional resources will be
developed and contribute to cash flows in the future.
Evaluations of oil and gas reserves are important to the effective
management of upstream assets. They are integral to making investment decisions
about oil and gas properties such as whether develop-
31
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
ment should proceed or enhanced recovery methods should be undertaken. Proved
oil and gas reserve quantities are also used as the basis of calculating the
unit-of-production rates for depreciation and evaluating for impairment. These
reserves are the estimated quantities of crude oil, natural gas and natural gas
liquids that geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions, i.e., prices and costs as of the date the
estimate is made. The estimation of reserves is an ongoing process based on
rigorous technical evaluations and extrapolations of well information such as
flow rates and reservoir pressure declines.
Supplemental information on oil and gas exploration and production
activities can be found on pages 57 to 61. Included in that section on page 60
is information on Canadian tar sands proven reserves. This information is shown
separately from the conventional liquids and natural gas proved reserves. For
internal management purposes, the corporation does not view these reserves
separately, but instead considers them and their development as an integral part
of total upstream operations. Refining tar sands reserves produces the same
petroleum products that are produced from refining conventional oil and gas
reserves. However, U.S. Securities and Exchange Commission regulations define
these tar sands reserves as mining reserves and not a part of conventional oil
and gas reserves.
Site Restoration and Environmental Conservation Costs
Site restoration costs that may be incurred by the corporation at the end of the
operating life of certain of its facilities and properties are accrued ratably
over the asset's productive life. Liabilities for environmental conservation are
recorded when it is probable that obligations have been incurred and the amounts
can be reasonably estimated.
The necessity of recording liabilities for these costs is prescribed by
GAAP. Estimating the probability of whether obligations have been incurred and
the amounts that should be recorded requires significant management judgment.
This judgment is based on extensive cost and engineering studies using the
latest available technology.
Foreign Currency Translation
The "functional currency" for translating the accounts of the majority of
downstream and chemicals operations outside the U.S. is the local currency.
Local currency is also used for upstream operations that are relatively
self-contained and integrated within a particular country. The U.S. dollar is
used for operations in highly inflationary economies and certain other
countries.
The method of translating the foreign currency financial statements of the
corporations international subsidiaries into U.S. dollars is prescribed by GAAP.
Under these principles, it is necessary to select the functional currency of
these subsidiaries. The functional currency is the currency of the primary
economic environment in which the subsidiary operates. Management selects the
functional currency after evaluating this economic environment. Downstream and
chemicals operations normally use the local currency, except in highly
inflationary countries, primarily Latin America, as well as in Singapore, which
uses the U.S. dollar, because it predominantly sells into the U.S. dollar export
market. Upstream operations also use the local currency as the functional
currency, except where crude and natural gas production is predominantly sold in
the export market in U.S. dollars. These operations, which use the U.S. dollar
as their functional currency, are in Malaysia, Indonesia, Nigeria, Equatorial
Guinea and the Middle East countries.
Litigation and Other Contingencies
Claims for substantial amounts have been made against ExxonMobil and certain of
its consolidated subsidiaries in pending lawsuits and tax disputes. These are
summarized on page 27, with a more extensive discussion included in note 17 on
page 51.
The general guidance provided by GAAP requires that liabilities for
contingencies should be recorded when it is probable that a liability has been
incurred before the date of the balance sheet and that the amount can be
reasonably estimated. Significant management judgment is required to comply with
this guidance, and it includes management reviews with the corporation's
attorneys, taking into consideration all of the relevant facts and
circumstances.
FORWARD-LOOKING STATEMENTS
Statements in this discussion regarding expectations, plans and future events or
conditions are forward-looking statements. Actual future results, including
merger expenses and synergies; 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, such as the outcome of commercial
negotiations; changes in the supply of and demand for crude oil, natural gas,
and petroleum and petrochemical products; and other factors discussed above and
under the caption "Factors Affecting Future Results" in Item 1 of ExxonMobil's
2001 Form 10-K.
32
REPORT OF INDEPENDENT ACCOUNTANTS
PricewaterhouseCoopers [LOGO]
Dallas, Texas
February 27, 2002
To the Shareholders of Exxon Mobil Corporation
In our opinion, the consolidated financial statements appearing on pages 34
through 55 present fairly, in all material respects, the financial position of
Exxon Mobil Corporation and its subsidiary companies at December 31, 2001 and
2000, and the results of their operations and their cash flows for each of the
three years in the period ended December 31, 2001, 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. 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 provide a
reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
33
CONSOLIDATED STATEMENT OF INCOME
2001 2000 1999
---------------------------------------------------------------------------------------------------------
(millions of dollars)
Revenue
Sales and other operating revenue, including excise taxes $ 209,417 $ 228,439 $ 182,529
Earnings from equity interests and other revenue 4,071 4,309 2,998
-------------------------------------
Total revenue $ 213,488 $ 232,748 $ 185,527
-------------------------------------
Costs and other deductions
Crude oil and product purchases $ 92,286 $ 108,951 $ 77,011
Operating expenses 18,170 18,135 16,806
Selling, general and administrative expenses 12,900 12,044 13,134
Depreciation and depletion 7,944 8,130 8,304
Exploration expenses, including dry holes 1,175 936 1,246
Merger related expenses 748 1,406 625
Interest expense 293 589 695
Excise taxes 21,907 22,356 21,646
Other taxes and duties 33,377 32,708 34,765
Income applicable to minority and preferred interests 569 412 145
-------------------------------------
Total costs and other deductions $ 189,369 $ 205,667 $ 174,377
-------------------------------------
Income before income taxes $ 24,119 $ 27,081 $ 11,150
Income taxes 9,014 11,091 3,240
-------------------------------------
Income before extraordinary item $ 15,105 $ 15,990 $ 7,910
Extraordinary gain, net of income tax 215 1,730 --
-------------------------------------
Net income $ 15,320 $ 17,720 $ 7,910
=====================================
Net income per common share (dollars)
Before extraordinary item $ 2.20 $ 2.30 $ 1.14
Extraordinary gain, net of income tax 0.03 0.25 --
-------------------------------------
Net income $ 2.23 $ 2.55 $ 1.14
=====================================
Net income per common share - assuming dilution (dollars)
Before extraordinary item $ 2.18 $ 2.27 $ 1.12
Extraordinary gain, net of income tax 0.03 0.25 --
-------------------------------------
Net income $ 2.21 $ 2.52 $ 1.12
=====================================
The information on pages 38 through 55 is an integral part of these statements.
34
CONSOLIDATED BALANCE SHEET
Dec. 31 Dec. 31
2001 2000
------------------------------------------------------------------------------------------------------------------------------
(millions of dollars)
Assets
Current assets
Cash and cash equivalents $ 6,547 $ 7,080
Notes and accounts receivable, less estimated doubtful amounts 19,549 22,996
Inventories
Crude oil, products and merchandise 6,743 7,244
Materials and supplies 1,161 1,060
Prepaid taxes and expenses 1,681 2,019
---------------------
Total current assets $ 35,681 $ 40,399
Investments and advances 10,768 12,618
Property, plant and equipment, at cost, less accumulated depreciation and depletion 89,602 89,829
Other assets, including intangibles, net 7,123 6,154
---------------------
Total assets $ 143,174 $ 149,000
=====================
Liabilities
Current liabilities
Notes and loans payable $ 3,703 $ 6,161
Accounts payable and accrued liabilities 22,862 26,755
Income taxes payable 3,549 5,275
---------------------
Total current liabilities $ 30,114 $ 38,191
Long-term debt 7,099 7,280
Annuity reserves and accrued liabilities 12,475 11,934
Deferred income tax liabilities 16,359 16,442
Deferred credits 1,141 1,166
Equity of minority and preferred shareholders in affiliated companies 2,825 3,230
---------------------
Total liabilities $ 70,013 $ 78,243
---------------------
Shareholders' equity
Benefit plan related balances $ (159) $ (235)
Common stock without par value (9,000 million shares authorized) 3,789 3,661
Earnings reinvested 95,718 86,652
Accumulated other nonowner changes in equity
Cumulative foreign exchange translation adjustment (5,947) (4,862)
Minimum pension liability adjustment (535) (310)
Unrealized gains/(losses) on stock investments (108) (17)
Common stock held in treasury (1,210 million shares in 2001 and 1,089 million shares in 2000) (19,597) (14,132)
---------------------
Total shareholders' equity $ 73,161 $ 70,757
---------------------
Total liabilities and shareholders' equity $ 143,174 $ 149,000
=====================
The information on pages 38 through 55 is an integral part of these statements.
35
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
2001 2000 1999
-------------------------------------------------------------------------------
Nonowner Nonowner Nonowner
Shareholders' Changes in Shareholders' Changes in Shareholders' Changes in
Equity Equity Equity Equity Equity Equity
-------------------------------------------------------------------------------
(millions of dollars)
Benefit plan related balances $ (159) $ (235) $ (298)
Common stock (see note 13)
At beginning of year 3,661 3,403 4,870
Issued -- -- 92
Other 128 258 303
Cancellation of common stock held in treasury -- -- (1,862)
----------- ---------- --------------
At end of year $ 3,789 $ 3,661 $ 3,403
----------- ---------- --------------
Earnings reinvested
At beginning of year 86,652 75,055 75,109
Net income for the year 15,320 $ 15,320 17,720 $ 17,720 7,910 $ 7,910
Dividends - common and preferred shares (6,254) (6,123) (5,872)
Cancellation of common stock held in treasury -- -- (2,092)
----------- ---------- ----------
At end of year $ 95,718 $ 86,652 $ 75,055
----------- ---------- ----------
Accumulated other nonowner changes in equity
At beginning of year (5,189) (2,568) (1,981)
Foreign exchange translation adjustment (1,085) (1,085) (2,562) (2,562) (727) (727)
Minimum pension liability adjustment (225) (225) (11) (11) 109 109
Unrealized gains/(losses) on stock investments (91) (91) (48) (48) 31 31
----------- --------- ----------
At end of year $ (6,590) $ (5,189) $ (2,568)
----------- ---------- --------- -------- ---------- ----------
Total $ 13,919 $ 15,099 $ 7,323
========== ======== ==========
Common stock held in treasury
At beginning of year (14,132) (12,126) (15,831)
Acquisitions, at cost (5,721) (2,352) (976)
Dispositions 256 346 727
Cancellation, returned to unissued -- -- 3,954
----------- --------- ----------
At end of year $ (19,597) $ (14,132) $ (12,126)
----------- --------- ----------
Shareholders' equity at end of year $ 73,161 $ 70,757 $ 63,466
=========== ========= ==========
Share Activity
--------------------------------------------------------------
2001 2000 1999
--------------------------------------------------------------
(millions of shares)
Common stock
Issued (see note 13)
At beginning of year 8,019 8,019 8,338
Issued -- -- 8
Cancelled -- -- (327)
----------- --------- ----------
At end of year 8,019 8,019 8,019
----------- --------- ----------
Held in treasury (see note 13)
At beginning of year (1,089) (1,064) (1,422)
Acquisitions, at cost (139) (54) (33)
Dispositions 18 29 64
Cancellation, returned to unissued -- -- 327
----------- --------- ----------
At end of year (1,210) (1,089) (1,064)
----------- --------- ----------
Common shares outstanding at end of year 6,809 6,930 6,955
=========== ========= ==========
The information on pages 38 through 55 is an integral part of these statements.
36
CONSOLIDATED STATEMENT OF CASH FLOWS
2001 2000 1999
-------------------------------------------------------------------------------------------------------------------
(millions of dollars)
Cash flows from operating activities
Net income
Accruing to ExxonMobil shareholders $ 15,320 $ 17,720 $ 7,910
Accruing to minority and preferred interests 569 412 145
Adjustments for non-cash transactions
Depreciation and depletion 7,944 8,130 8,304
Deferred income tax charges/(credits) 650 10 (1,439)
Annuity and accrued liability provisions 498 (662) 412
Dividends received greater than/(less than) equity in
current earnings of equity companies 78 (387) 146
Extraordinary gain, before income tax (194) (2,038) --
Changes in operational working capital, excluding cash and debt
Reduction/(increase) - Notes and accounts receivable 3,062 (4,832) (3,478)
- Inventories 154 (297) 50
- Prepaid taxes and expenses 118 (204) 177
Increase/(reduction) - Accounts and other payables (5,103) 5,411 3,046
All other items - net (207) (326) (260)
----------------------------------
Net cash provided by operating activities $ 22,889 $ 22,937 $ 15,013
----------------------------------
Cash flows from investing activities
Additions to property, plant and equipment $ (9,989) $ (8,446) $ (10,849)
Sales of subsidiaries, investments and property, plant and equipment 1,078 5,770 972
Additional investments and advances (1,035) (1,648) (1,476)
Collection of advances 1,735 985 387
Additions to other marketable securities -- (41) (61)
Sales of other marketable securities -- 82 42
----------------------------------
Net cash used in investing activities $ (8,211) $ (3,298) $ (10,985)
----------------------------------
Net cash generation before financing activities $ 14,678 $ 19,639 $ 4,028
----------------------------------
Cash flows from financing activities
Additions to long-term debt $ 547 $ 238 $ 454
Reductions in long-term debt (506) (901) (341)
Additions to short-term debt 705 500 1,870
Reductions in short-term debt (1,212) (2,413) (2,359)
Additions/(reductions) in debt with less than 90 day maturity (2,306) (3,129) 2,210
Cash dividends to ExxonMobil shareholders (6,254) (6,123) (5,872)
Cash dividends to minority interests (194) (251) (219)
Changes in minority interests and sales/(purchases) of affiliate stock (401) (227) (200)
Common stock acquired (5,721) (2,352) (670)
Common stock sold 301 493 348
----------------------------------
Net cash used in financing activities $(15,041) $ (14,165) $ (4,779)
----------------------------------
Effects of exchange rate changes on cash $ (170) $ (82) $ 53
----------------------------------
Increase/(decrease) in cash and cash equivalents $ (533) $ 5,392 $ (698)
Cash and cash equivalents at beginning of year 7,080 1,688 2,386
----------------------------------
Cash and cash equivalents at end of year $ 6,547 $ 7,080 $ 1,688
==================================
The information on pages 38 through 55 is an integral part of these statements.
37
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The accompanying consolidated financial statements and the supporting and
supplemental material are the responsibility of the management of Exxon Mobil
Corporation.
The corporation's principal business is energy, involving the worldwide
exploration, production, transportation and sale of crude oil and natural gas
(upstream) and the manufacture, transportation and sale of petroleum products
(downstream). The corporation is also a major worldwide manufacturer and
marketer of petrochemicals and participates in coal and minerals mining and
electric power generation.
The preparation of financial statements in conformity with Generally
Accepted Accounting Principles requires management to make estimates that affect
the reported amounts of assets, liabilities, revenues and expenses and the
disclosure of contingent assets and liabilities. Actual results could differ
from these estimates.
1. Summary of Accounting Policies
Principles of Consolidation. The consolidated financial statements include the
accounts of those significant subsidiaries owned directly or indirectly with
more than 50 percent of the voting rights held by the corporation, and for which
other shareholders do not possess the right to participate in significant
management decisions. They also include the corporation's share of the undivided
interest in upstream assets and liabilities. Amounts representing the
corporation's percentage interest in the underlying net assets of other
significant subsidiaries and less than majority owned companies in which a
significant equity ownership interest is held, are included in "Investments and
advances"; the corporation's share of the net income of these companies is
included in the consolidated statement of income caption "Earnings from equity
interests and other revenue."
Investments in other companies, none of which is significant, are generally
included in "Investments and advances" at cost or less. Dividends from these
companies are included in income as received.
Revenue Recognition. Revenues associated with sales of crude oil, natural gas,
petroleum and chemical products and all other items are recorded when title
passes to the customer.
Revenues from the production of natural gas properties in which the
corporation has an interest with the other producers are recognized on the basis
of the company's net working interest. Differences between actual production and
net working interest volumes are not significant.
Derivative Instruments. The corporation makes limited use of derivatives.
Derivative instruments are not held for trading purposes nor do they have
leverage features. When the corporation does enter into derivative transactions,
it is to offset exposures associated with interest rates, foreign currency
exchange rates and hydrocarbon prices. The gains and losses resulting from the
changes in fair value of these instruments are recorded in income, except when
the instruments are designated as hedging the currency exposure of net
investments in foreign subsidiaries, in which case they are recorded in the
cumulative foreign exchange translation account, as part of shareholders equity.
The gains and losses on derivative instruments that are designated as fair
value hedges (i.e., those hedging the exposure to changes in the fair value of
an asset or a liability or the changes in the fair value of a firm commitment),
are offset by the gains and losses from the changes in fair value of the hedged
items, which are also recognized in income. Most of these designated hedges are
entered into at the same time that the hedged items are transacted, they are
fully effective and in combination with the offsetting hedged items, they result
in no net impact on income. In some situations, the corporation has chosen not
to designate certain immaterial derivatives used for hedging economic exposure
as hedges for accounting purposes due to the excessive administrative effort
that would be required to account for these items as hedging transactions. These
derivatives are recorded on the balance sheet at fair value and the gains and
losses arising from changes in fair value are recognized in income. All
derivatives activity is immaterial.
Inventories. Crude oil, products and merchandise inventories are carried at the
lower of current market value or cost (generally determined under the last-in,
first-out method - LIFO). Costs include applicable purchase costs and operating
expenses but not general and administrative expenses or research and development
costs. Inventories of materials and supplies are valued at cost or less.
Property, Plant and Equipment. Depreciation, depletion and amortization, based
on cost less estimated salvage value of the asset, are primarily determined
under either the unit-of-production method or the straight-line method.
Unit-of-production rates are based on oil, gas and other mineral reserves
estimated to be recoverable from existing facilities. The straight-line method
of depreciation is based on estimated asset service life taking obsolescence
into consideration.
Maintenance and repairs are expensed as incurred. Major renewals and
improvements are capitalized and the assets replaced are retired.
The corporation's upstream activities are accounted for under the
"successful efforts" method. Under this method, costs of productive wells and
development dry holes, both tangible and intangible, as well as productive
acreage are capitalized and amortized on the unit-of-production method. Costs of
that portion of undeveloped acreage likely to be unproductive, based largely on
historical experience, are amortized over the period of exploration. Other
exploratory expenditures, including geophysical costs, other dry hole costs and
annual lease rentals, are expensed as incurred. Exploratory wells that find oil
and gas in an area requiring a major capital expenditure before production can
begin are evaluated annually to assure that commercial quantities of reserves
have been found or that additional exploration work is underway or planned.
Exploratory well costs not meeting either of these tests are charged to expense.
Oil, gas and other properties held and used by the corporation are reviewed
for impairment whenever events or changes in circumstances indicate that the
carrying amounts may not be recoverable. The corporation estimates the future
undiscounted cash flows of the affected properties to judge the recoverability
of carrying amounts. In general, analyses are based on proved reserves, except
in circumstances where it is probable that additional resources will be
developed and contribute to cash flows in the future.
Site Restoration and Environmental Conservation Costs. Site restoration costs
that may be incurred by the corporation at the end of the operating life of
certain of its facilities and properties are reserved ratably over the asset's
productive life.
38
Liabilities for environmental conservation are recorded when it is probable
that obligations have been incurred and the amounts can be reasonably estimated.
These liabilities are not reduced by possible recoveries from third parties, and
projected cash expenditures are not discounted.
Foreign Currency Translation. The "functional currency" for translating the
accounts of the majority of downstream and chemical operations outside the U.S.
is the local currency. Local currency is also used for upstream operations that
are relatively self-contained and integrated within a particular country, such
as in Canada, the United Kingdom, Norway and Continental Europe. The U.S. dollar
is used for operations in highly inflationary economies, in Singapore which is
predominantly export oriented and for some upstream operations, primarily in
Malaysia, Indonesia, Nigeria, Equatorial Guinea and the Middle East countries.
For all operations, gains or losses on remeasuring foreign currency transactions
into functional currency are included in income.
2. Extraordinary Item and Accounting Change
Net income for 2001 included net after-tax gains from asset management
activities in the chemicals segment and regulatory required asset divestitures
in the amount of $215 million (including an income tax credit of $21 million),
or $0.03 per common share. Net income for 2000 included net after-tax gains from
regulatory required asset divestitures in the amount of $1,730 million (net $308
million of income taxes), or $0.25 per common share. These net after-tax gains
were reported as extraordinary items according to accounting requirements for
business combinations accounted for as pooling of interests.
As of January 1, 2001, ExxonMobil adopted Financial Accounting Standards
Board Statement No. 133 (FAS 133), "Accounting for Derivative Instruments and
Hedging Activities" as amended by Statements No. 137 and 138. This statement
requires that all derivatives be recognized as either assets or liabilities in
the financial statements and be measured at fair value. Since the corporation
makes limited use of derivatives, the effect of adoption of FAS 133 on the
corporation's operations or financial condition was negligible.
3. 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.
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. Certain
reclassifications have been made to conform the presentation of Exxon and Mobil.
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. The carrying value of these assets was approximately $3 billion and
net after-tax gains of $40 million and $1,730 million were reported as
extraordinary items in 2001 and 2000, respectively. The divested properties
historically earned approximately $200 million per year.
4. Merger Expenses and Reorganization Reserves
In association with the Merger, $748 million pre-tax ($525 million
after-tax), $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 2001, 2000 and 1999, respectively. These cumulative charges of
$2,779 million included separation expenses of approximately $1,345 million
related to workforce reductions (approximately 8,000 employees at year-end
2001), plus implementation costs and merger closing costs. The separation
reserve balance at year-end 2001 of approximately $197 million, is expected to
be expended in 2002.
In the first quarter of 1999, the corporation recorded a $120 million
after-tax charge for the non-merger related 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.
The following table summarizes the activity in the reorganization reserves.
The 1999 opening balance represents accruals for provisions taken in prior
years.
Opening Balance at
Balance Additions Deductions Year End
------------------------------------------------------------------
(millions of dollars)
1999 $169 $563 $351 $381
2000 381 738 780 339
2001 339 187 329 197
39
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
5. Miscellaneous Financial Information
Research and development costs totaled $603 million in 2001, $564 million in
2000 and $630 million in 1999.
Net income included aggregate foreign exchange transaction losses of $142
million in 2001, $236 million in 2000 and $5 million in 1999.
In 2001, 2000, and 1999, net income included gains of $238 million, and
$175 million, and losses of $7 million, respectively, attributable to the
combined effects of LIFO inventory accumulations and draw-downs. The aggregate
replacement cost of inventories was estimated to exceed their LIFO carrying
values by $4.2 billion and $6.7 billion at December 31, 2001 and 2000,
respectively.
6. Cash Flow Information
The consolidated statement of cash flows provides information about changes in
cash and cash equivalents. Highly liquid investments with maturities of three
months or less when acquired are classified as cash equivalents.
Cash payments for interest were: 2001 - $562 million, 2000 - $729 million
and 1999 - $882 million. Cash payments for income taxes were: 2001 - $9,855
million, 2000 - $8,671 million and 1999 - $3,805 million.
7. Additional Working Capital Data Dec. 31 Dec. 31
2001 2000
--------------------------------------------------------------------------------
(millions of dollars)
Notes and accounts receivable
Trade, less reserves of $279 million
and $258 million $ 13,597 $ 17,568
Other, less reserves of $62 million
and $48 million 5,952 5,428
------------------------
$ 19,549 $ 22,996
========================
Notes and loans payable
Bank loans $ 1,063 $ 1,244
Commercial paper 1,804 3,761
Long-term debt due within one year 339 650
Other 497 506
------------------------
$ 3,703 $ 6,161
========================
Accounts payable and accrued liabilities
Trade payables $ 12,696 $ 15,357
Obligations to equity companies 632 586
Accrued taxes other than income taxes 4,768 5,423
Other 4,766 5,389
------------------------
$ 22,862 $ 26,755
========================
On December 31, 2001, unused credit lines for short-term financing totaled
approximately $5.3 billion. Of this total, $2.1 billion support commercial paper
programs under terms negotiated when drawn. The weighted average interest rate
on short-term borrowings outstanding at December 31, 2001 and 2000 was 3.8
percent and 6.4 percent, respectively.
40
8. Equity Company Information
The summarized financial information below includes amounts related to certain
less than majority owned companies and majority owned subsidiaries where
minority shareholders possess the right to participate in significant management
decisions (see note 1). These companies are primarily engaged in crude
production, natural gas marketing and refining operations in North America;
natural gas production, natural gas distribution, and downstream operations in
Europe and crude production in Kazakhstan and the Middle East. Also included are
several power generation, petrochemical/lubes manufacturing and chemical
ventures; 1999 included amounts related to Mobil's European Fuels joint venture
which was divested as a condition of the Merger approval.
2001 2000 1999
-----------------------------------------------------------------
ExxonMobil ExxonMobil ExxonMobil
Equity Company Financial Summary Total Share Total Share Total Share
------------------------------------------------------------------------------------------------------------------------------------
(millions of dollars)
Total revenues
Percent of revenues from companies included in the ExxonMobil
consolidation was 9% in 2001, 11% in 2000 and 8% in 1999 $ 95,009 $ 36,695 $ 81,371 $32,452 $94,534 $32,124
----------------------------------------------------------------
Income before income taxes $ 6,952 $ 2,922 $ 7,632 $ 3,092 $ 4,100 $ 2,095
Less: Related income taxes (1,562) (748) (1,382) (658) (734) (449)
----------------------------------------------------------------
Net income $ 5,390 $ 2,174 $ 6,250 $ 2,434 $ 3,366 $ 1,646
================================================================
Current assets $ 18,992 $ 7,369 $ 28,784 $11,479 $21,518 $ 7,739
Property, plant and equipment, less accumulated depreciation 36,565 13,135 36,553 13,733 44,213 15,509
Other long-term assets 5,127 2,284 6,656 2,979 4,806 2,106
----------------------------------------------------------------
Total assets $ 60,684 $ 22,788 $ 71,993 $28,191 $70,537 $25,354
----------------------------------------------------------------
Short-term debt $ 3,142 $ 1,232 $ 2,636 $ 1,093 $ 2,856 $ 1,129
Other current liabilities 16,218 6,349 25,377 10,357 18,129 6,324
Long-term debt 10,496 3,950 11,116 4,094 13,486 3,978
Other long-term liabilities 6,253 2,862 7,054 3,273 5,372 2,598
Advances from shareholders 8,443 2,179 8,485 2,510 3,636 1,919
----------------------------------------------------------------
Net assets $ 16,132 $ 6,216 $ 17,325 $ 6,864 $27,058 $ 9,406
================================================================
9. Investments and Advances Dec. 31 Dec. 31
2001 2000
------------------------------------------------------------------------------------------------------------------------------------
(millions of dollars)
Companies carried at equity in underlying assets
Investments $ 6,216 $ 6,864
Advances 2,179 2,510
----------------------
$ 8,395 $ 9,374
Companies carried at cost or less and stock investments carried at fair value 1,060 1,230
----------------------
$ 9,455 $10,604
Long-term receivables and miscellaneous investments at cost or less 1,313 2,014
----------------------
Total $10,768 $12,618
======================
41
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
10. Investment in Property, Plant and Equipment Dec. 31, 2001 Dec. 31, 2000
------------------------------------------------
Cost Net Cost Net
---------------------------------------------------------------------------------------------------------
(millions of dollars)
Petroleum and natural gas
Upstream $ 109,616 $ 46,597 $ 106,287 $ 45,731
Downstream 50,691 25,560 51,862 26,730
------------------------------------------------
Total petroleum and natural gas $ 160,307 $ 72,157 $ 158,149 $ 72,461
Chemicals 17,973 9,690 17,860 9,935
Other 12,223 7,755 11,737 7,433
------------------------------------------------
Total $ 190,503 $ 89,602 $ 187,746 $ 89,829
================================================
Accumulated depreciation and depletion totaled $100,901 million at the end of
2001 and $97,917 million at the end of 2000. Interest capitalized in 2001, 2000
and 1999 was $518 million, $641 million and $595 million, respectively.
--------------------------------------------------------------------------------
11. Leased Facilities
At December 31, 2001, the corporation and its consolidated subsidiaries held
non-cancelable operating charters and leases covering drilling equipment,
tankers, service stations and other properties with minimum lease commitments as
indicated in the table.
Net rental expenditures for 2001, 2000 and 1999 totaled $2,454 million,
$1,935 million and $2,172 million, respectively, after being reduced by related
rental income of $199 million, $195 million and $317 million, respectively.
Minimum rental expenditures totaled $2,562 million in 2001, $1,992 million in
2000 and $2,311 million in 1999.
Minimum Related
Commitment Rental income
--------------------------------------------------------------------------------
(millions of dollars)
2002 $ 1,327 $ 110
2003 1,107 103
2004 801 95
2005 569 87
2006 433 48
2007 and beyond 2,687 103
---------------------------
Total $ 6,924 $ 546
===========================
--------------------------------------------------------------------------------
12. Employee Stock Ownership Plans
In 1989, the Exxon leveraged employee stock ownership plan (Exxon LESOP) trust
borrowed $1,000 million under the terms of notes guaranteed by Exxon. The Exxon
LESOP trust used the proceeds of the borrowing to purchase shares of Exxon's
convertible Class A Preferred Stock. The final Exxon LESOP note was repaid in
1999. By year-end 1999, all remaining shares of Exxon Class A Preferred Stock
were converted to ExxonMobil common shares.
In 1989, the Mobil Oil Corporation employee stock ownership plan (Mobil
LESOP) trust borrowed $800 million under the terms of notes and debentures
guaranteed by Mobil. The trust used the proceeds of the borrowing to purchase
shares of Mobil's Series B Convertible Preferred Stock which upon the merger
were converted into shares of ExxonMobil Class B Preferred Stock with similar
terms. By year-end 1999, all remaining shares of Class B Preferred Stock were
converted to ExxonMobil common shares.
The Exxon LESOP and Mobil LESOP were merged in late 1999 to create the
ExxonMobil LESOP. The ExxonMobil LESOP is a constituent part of the ExxonMobil
Savings Plan which, effective February 8, 2002, is an employee stock ownership
plan in its entirety. Employees eligible to participate in the ExxonMobil
Savings Plan may elect to participate in the ExxonMobil LESOP. Corporate
contributions to the plan and dividends are used to make principal and interest
payments on the ExxonMobil LESOP trust notes. As corporate contributions and
dividends are credited, common shares are allocated to participants' plan
accounts. The corporation's contribution to the ExxonMobil LESOP, representing
the amount by which debt service exceeded dividends on shares held by the
ExxonMobil LESOP, was $58 million, $15 million, and $19 million in 2001, 2000
and 1999, respectively.
Accounting for the plans has followed the principles that were in effect
for the respective plans when they were established. The amount of compensation
expense related to the plans and recorded by the corporation during the periods
was $83 million in 2001, $13 million in 2000, and $5 million in 1999. The
ExxonMobil LESOP trust held 104.2 million shares of ExxonMobil common stock at
the end of 2001 and 109.2 million shares at the end of 2000.
42
13. Capital
On May 30, 2001, the company's Board of Directors approved a two-for-one stock
split of common stock for shareholders of record on June 20, 2001. The
authorized common stock was increased from 4.5 billion shares without par value
to 9 billion shares without par value, and the issued shares were split on a
two-for-one basis on June 20, 2001.
At the effective time of the merger of Exxon and Mobil, the authorized
common stock of ExxonMobil was increased from 3 billion shares to 4.5 billion
shares. Under the terms of the merger agreement, approximately 1.0 billion
shares of ExxonMobil common stock were issued in exchange for all of the
outstanding shares of Mobil's common stock based upon an exchange ratio of
1.32015 ExxonMobil shares for each Mobil share. Mobil's common stock accounted
for as treasury stock was cancelled at the effective time of the merger.
In 1989, $1,800 million of benefit related balances were recorded as debt
and as a reduction to shareholders' equity, representing Exxon and Mobil
guaranteed borrowings by the Exxon LESOP to purchase Exxon Class A Preferred
Stock and the Mobil LESOP to purchase Mobil Class B Preferred Stock. As common
shares are earned by employees and the debt is repaid, the benefit plan related
balances are being reduced. Preferred dividends of $36 million were paid during
1999 on preferred shares described in note 12, all of which were converted to
ExxonMobil common stock by year-end 1999. The table below summarizes the
earnings per share calculations.
2001 2000 1999
-------------------------------
Net income per common share
---------------------------
Income before extraordinary item (millions of dollars) $ 15,105 $ 15,990 $ 7,910
Less: Preferred stock dividends -- -- (36)
-------------------------------
Income available to common shares $ 15,105 $ 15,990 $ 7,874
===============================
Weighted average number of common shares outstanding (millions of shares) 6,868 6,953 6,906
Net income per common share
Before extraordinary item $ 2.20 $ 2.30 $ 1.14
Extraordinary gain, net of income tax 0.03 0.25 --
-------------------------------
Net income $ 2.23 $ 2.55 $ 1.14
===============================
Net income per common share - assuming dilution
-----------------------------------------------
Income before extraordinary item (millions of dollars) $ 15,105 $ 15,990 $ 7,910
Adjustment for assumed dilution (4) (8) 1
-------------------------------
Income available to common shares $ 15,101 $ 15,982 $ 7,911
===============================
Weighted average number of common shares outstanding (millions of shares) 6,868 6,953 6,906
Plus: Issued on assumed exercise of stock options 73 80 88
Plus: Assumed conversion of preferred stock -- -- 42
-------------------------------
Weighted average number of common shares outstanding 6,941 7,033 7,036
===============================
Net income per common share
Before extraordinary item $ 2.18 $ 2.27 $ 1.12
Extraordinary gain, net of income tax 0.03 0.25 --
-------------------------------
Net income $ 2.21 $ 2.52 $ 1.12
===============================
Dividends paid per common share $ 0.910 $ 0.880 $ 0.844
43
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
14. Financial Instruments and Derivatives
The fair value of financial instruments is determined by reference to various
market data and other valuation techniques as appropriate. Long-term debt is the
only category of financial instruments whose fair value differs materially from
the recorded book value. The estimated fair value of total long-term debt,
including capitalized lease obligations, at December 31, 2001 and 2000, was $7.9
billion and $8.0 billion, respectively, as compared to recorded book values of
$7.1 billion and $7.3 billion.
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. The
corporation relies on these operating attributes and strengths to reduce
enterprise-wide risk. As a result, the corporation makes limited use of
derivatives to offset exposures arising from existing transactions.
The corporation does not trade in derivatives nor does it use 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. Interest rate, foreign exchange rate and commodity price exposures
arising from derivative contracts undertaken in accordance with the
corporation's policies have not been significant.
The fair value of derivatives outstanding and recorded on the balance sheet
at December 31, 2001 was $50 million before-tax. This is the amount that the
corporation would have had to pay to third parties if these derivatives had been
settled at year-end. These derivative fair values were substantially offset by
the fair values of the underlying exposures being hedged. During 2001, the
corporation recognized a before-tax gain of $23 million related to derivative
activity. This gain included the offsetting amounts from the changes in fair
value of the items being hedged by the derivatives.
15. Long-Term Debt
At December 31, 2001, long-term debt consisted of $6,465 million due in U.S.
dollars and $634 million representing the U.S. dollar equivalent at year-end
exchange rates of amounts payable in foreign currencies. These amounts exclude
that portion of long-term debt, totaling $339 million, which matures within one
year and is included in current liabilities. The amounts of long-term debt
maturing, together with sinking fund payments required, in each of the four
years after December 31, 2002, in millions of dollars, are: 2003 - $880, 2004 -
$2,176, 2005 - $328 and 2006 - $114. Certain of the borrowings described may
from time to time be assigned to other ExxonMobil affiliates. At December 31,
2001, the corporation's unused long-term credit lines were not material.
The total outstanding balance of defeased debt at year-end 2001 was $408
million. Summarized long-term borrowings at year-end 2001 and 2000 were as shown
in the adjacent table:
2001 2000
--------------------------------------------------------------------------------
(millions of dollars)
Exxon Mobil Corporation
Guaranteed zero coupon notes due 2004
- Face value ($1,146) net of
unamortized discount $ 836 $ 749
Exxon Capital Corporation
6.0% Guaranteed notes due 2005 106 106
6.125% Guaranteed notes due 2008 160 175
SeaRiver Maritime Financial Holdings, Inc.
Guaranteed debt securities due 2003-2011 (1) 105 115
Guaranteed deferred interest
debentures due 2012
- Face value ($771) net of unamortized
discount plus accrued interest 903 811
Imperial Oil Limited
Variable rate notes due 2004 (2) 600 600
ExxonMobil Canada Ltd.
3.0% Swiss franc debentures due 2003 (3) 328 331
5.0% U.S. dollar Eurobonds due 2004 (4) 262 274
Mobil Producing Nigeria Unlimited
8.625% notes due 2003-2006 146 188
Mobil Corporation
8.625% debentures due 2021 247 247
7.625% debentures due 2033 204 203
Industrial revenue bonds due 2003-2033 (5) 1,535 1,469
ESOP Trust notes due 2003 65 100
Other U.S. dollar obligations (6) 751 1,062
Other foreign currency obligations 585 598
Capitalized lease obligations (7) 266 252
-------------------
Total long-term debt $7,099 $7,280
===================
(1) Average effective interest rate of 4.1% in 2001 and 6.4% in 2000.
(2) Average effective interest rate of 4.2% in 2001 and 6.6% in 2000.
(3) Swapped into floating rate U.S. dollar debt.
(4) Swapped into floating rate debt.
(5) Average effective interest rate of 3.0% in 2001 and 4.5% in 2000.
(6) Average effective interest rate of 8.0% in 2001 and 7.8% in 2000.
(7) Average imputed interest rate of 6.4% in 2001 and 7.2% in 2000.
44
Condensed consolidating financial information related to guaranteed securities
issued by subsidiaries
Exxon Mobil Corporation has fully and unconditionally guaranteed the 6.0% notes
due 2005 ($106 million of long-term debt at year-end 2001) and the 6.125% notes
due 2008 ($160 million) of Exxon Capital Corporation and the deferred interest
debentures due 2012 ($903 million) and the debt securities due 2003-2011 ($105
million long-term and $10 million short-term) of SeaRiver Maritime Financial
Holdings, Inc. Exxon Capital Corporation and SeaRiver Maritime Financial
Holdings, Inc. are 100 percent owned subsidiaries of Exxon Mobil Corporation.
The following condensed consolidating financial information is provided for
Exxon Mobil Corporation, as guarantor, and for Exxon Capital Corporation and
SeaRiver Maritime Financial Holdings, Inc., as issuers, as an alternative to
providing separate financial statements for the issuers. The accounts of Exxon
Mobil Corporation, Exxon Capital Corporation and SeaRiver Maritime Financial
Holdings, Inc. are presented utilizing the equity method of accounting for
investments in subsidiaries.
SeaRiver
Exxon Mobil Maritime Consolidating
Corporation Exxon Financial and
Parent Capital Holdings, All Other Eliminating
Guarantor Corporation Inc. Subsidiaries Adjustments Consolidated
------------------------------------------------------------------------
(millions of dollars)
Condensed consolidated statement of income for twelve months ended December 31, 2001
------------------------------------------------------------------------------------
Revenue
Sales and other operating revenue, including excise taxes $ 28,800 $ -- $ -- $ 180,617 $ -- $ 209,417
Earnings from equity interests and other revenue 13,535 -- 32 3,709 (13,205) 4,071
Intercompany revenue 6,252 584 62 106,498 (113,396) --
-----------------------------------------------------------------------
Total revenue 48,587 584 94 290,824 (126,601) 213,488
-----------------------------------------------------------------------
Costs and other deductions
Crude oil and product purchases 19,483 -- -- 174,484 (101,681) 92,286
Operating expenses 5,702 3 1 17,613 (5,149) 18,170
Selling, general and administrative expenses 2,158 2 -- 10,802 (62) 12,900
Depreciation and depletion 1,584 5 3 6,352 -- 7,944
Exploration expenses, including dry holes 125 -- -- 1,050 -- 1,175
Merger related expenses 89 -- -- 771 (112) 748
Interest expense 1,043 531 114 4,924 (6,319) 293
Excise taxes 1,957 -- -- 19,950 -- 21,907
Other taxes and duties 14 -- -- 33,363 -- 33,377
Income applicable to minority and preferred interests -- -- -- 569 -- 569
-----------------------------------------------------------------------
Total costs and other deductions 32,155 541 118 269,878 (113,323) 189,369
-----------------------------------------------------------------------
Income before income taxes 16,432 43 (24) 20,946 (13,278) 24,119
Income taxes 1,327 15 (20) 7,692 -- 9,014
-----------------------------------------------------------------------
Income before extraordinary item 15,105 28 (4) 13,254 (13,278) 15,105
Extraordinary gain, net of income tax 215 -- -- -- -- 215
-----------------------------------------------------------------------
Net income $ 15,320 $ 28 $ (4) $ 13,254 $ (13,278) $ 15,320
=======================================================================
45
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Condensed consolidating financial information related to guaranteed securities
issued by subsidaries
SeaRiver
Exxon Mobil Maritime Consolidating
Corporation Exxon Financial and
Parent Capital Holdings, All Other Eliminating
Guarantor Corporation Inc. Subsidiaries Adjustments Consolidated
-------------------------------------------------------------------------
(millions of dollars)
Condensed consolidated statement of income for twelve months ended December 31, 2000
------------------------------------------------------------------------------------
Revenue
Sales and other operating revenue, including excise taxes $ 36,211 $ -- $ -- $ 192,228 $ -- $ 228,439
Earnings from equity interests and other revenue 14,399 -- 35 3,577 (13,702) 4,309
Intercompany revenue 4,148 997 90 92,832 (98,067) --
------------------------------------------------------------------------
Total revenue 54,758 997 125 288,637 (111,769) 232,748
------------------------------------------------------------------------
Costs and other deductions
Crude oil and product purchases 22,790 -- -- 173,012 (86,851) 108,951
Operating expenses 5,787 3 1 17,051 (4,707) 18,135
Selling, general and administrative expenses 1,978 -- -- 10,203 (137) 12,044
Depreciation and depletion 1,510 5 3 6,612 -- 8,130
Exploration expenses, including dry holes 115 -- -- 821 -- 936
Merger related expenses 402 -- -- 1,171 (167) 1,406
Interest expense 1,449 916 116 4,313 (6,205) 589
Excise taxes 2,614 -- -- 19,742 -- 22,356
Other taxes and duties 15 -- -- 32,693 -- 32,708
Income applicable to minority and preferred interests -- -- -- 412 -- 412
------------------------------------------------------------------------
Total costs and other deductions 36,660 924 120 266,030 (98,067) 205,667
------------------------------------------------------------------------
Income before income taxes 18,098 73 5 22,607 (13,702) 27,081
Income taxes 2,108 20 (10) 8,973 -- 11,091
------------------------------------------------------------------------
Income before extraordinary item 15,990 53 15 13,634 (13,702) 15,990
Extraordinary gain, net of income tax 1,730 -- -- 962 (962) 1,730
------------------------------------------------------------------------
Net income $ 17,720 $ 53 $ 15 $ 14,596 $ (14,664) $ 17,720
========================================================================
Condensed consolidated statement of income for twelve months ended December 31, 1999
------------------------------------------------------------------------------------
Revenue
Sales and other operating revenue, including excise taxes $ 25,758 $ -- $ -- $ 156,771 $ -- $ 182,529
Earnings from equity interests and other revenue 7,585 37 31 2,102 (6,757) 2,998
Intercompany revenue 1,585 660 61 35,825 (38,131) --
------------------------------------------------------------------------
Total revenue 34,928 697 92 194,698 (44,888) 185,527
------------------------------------------------------------------------
Costs and other deductions
Crude oil and product purchases 13,926 -- -- 97,296 (34,211) 77,011
Operating expenses 4,669 3 1 13,285 (1,152) 16,806
Selling, general and administrative expenses 2,230 -- -- 10,908 (4) 13,134
Depreciation and depletion 1,396 5 3 6,900 -- 8,304
Exploration expenses, including dry holes 110 -- -- 1,136 -- 1,246
Merger related expenses 479 -- -- 146 -- 625
Interest expense 1,150 561 95 1,653 (2,764) 695
Excise taxes 2,846 -- -- 18,800 -- 21,646
Other taxes and duties 14 -- -- 34,751 -- 34,765
Income applicable to minority and preferred interests -- -- -- 145 -- 145
------------------------------------------------------------------------
Total costs and other deductions 26,820 569 99 185,020 (38,131) 174,377
------------------------------------------------------------------------
Income before income taxes 8,108 128 (7) 9,678 (6,757) 11,150
Income taxes 198 28 (13) 3,027 -- 3,240
------------------------------------------------------------------------
Income before extraordinary item 7,910 100 6 6,651 (6,757) 7,910
Extraordinary gain, net of income tax -- -- -- -- -- --
------------------------------------------------------------------------
Net income $ 7,910 $ 100 $ 6 $ 6,651 $ (6,757) $ 7,910
========================================================================
46
Exxon Mobil SeaRiver Consolidating
Corporation Exxon Maritime and
Parent Capital Financial All Other Eliminating
Guarantor Corporation Holdings, Inc. Subsidiaries Adjustments Consolidated
--------------------------------------------------------------------------------
(millions of dollars)
Condensed consolidated balance sheet for year ended December 31, 2001
---------------------------------------------------------------------
Cash and cash equivalents $ 1,375 $ -- $ -- $ 5,172 $ -- $ 6,547
Notes and accounts receivable - net 2,458 -- -- 17,091 -- 19,549
Inventories 996 -- -- 6,908 -- 7,904
Prepaid taxes and expenses 155 5 8 1,513 -- 1,681
--------------------------------------------------------------------------------
Total current assets 4,984 5 8 30,684 -- 35,681
Investments and advances 92,091 -- 415 317,456 (399,194) 10,768
Property, plant and equipment - net 16,843 108 6 72,645 -- 89,602
Other long-term assets 753 -- 137 6,233 -- 7,123
Intercompany receivables 8,466 1,365 1,431 266,527 (277,789) --
--------------------------------------------------------------------------------
Total assets $123,137 $ 1,478 $1,997 $693,545 $(676,983) $143,174
================================================================================
Notes and loans payable $ -- $ 35 $ 10 $ 3,658 $ -- $ 3,703
Accounts payable and accrued liabilities 2,735 6 1 20,120 -- 22,862
Income taxes payable 767 -- -- 2,782 -- 3,549
--------------------------------------------------------------------------------
Total current liabilities 3,502 41 11 26,560 -- 30,114
Long-term debt 1,258 266 1,008 4,567 -- 7,099
Deferred income tax liabilities 2,989 33 302 13,035 -- 16,359
Other long-term liabilities 4,373 -- -- 12,068 -- 16,441
Intercompany payables 37,854 248 382 239,305 (277,789) --
-------------------------------------------------------------------------------
Total liabilities 49,976 588 1,703 295,535 (277,789) 70,013
Earnings reinvested 95,718 84 (100) 48,907 (48,891) 95,718
Other shareholders' equity (22,557) 806 394 349,103 (350,303) (22,557)
--------------------------------------------------------------------------------
Total shareholders' equity 73,161 890 294 398,010 (399,194) 73,161
--------------------------------------------------------------------------------
Total liabilities and shareholders' equity $123,137 $ 1,478 $1,997 $693,545 $(676,983) $143,174
================================================================================
Condensed consolidated balance sheet for year ended December 31, 2000
---------------------------------------------------------------------
Cash and cash equivalents $ 4,235 $ -- $ -- $ 2,845 $ -- $ 7,080
Notes and accounts receivable - net 4,427 -- -- 18,569 -- 22,996
Inventories 1,102 -- -- 7,202 -- 8,304
Prepaid taxes and expenses 262 -- 14 1,743 -- 2,019
--------------------------------------------------------------------------------
Total current assets 10,026 -- 14 30,359 -- 40,399
Investments and advances 79,589 -- 408 303,090 (370,469) 12,618
Property, plant and equipment - net 18,559 113 9 71,148 -- 89,829
Other long-term assets 508 2 150 5,494 -- 6,154
Intercompany receivables 9,339 19,124 1,355 212,790 (242,608) --
--------------------------------------------------------------------------------
Total assets $118,021 $ 19,239 $1,936 $622,881 $(613,077) $149,000
================================================================================
Notes and loans payable $ 60 $ 74 $ 7 $ 6,020 $ -- $ 6,161
Accounts payable and accrued liabilities 3,918 8 2 22,827 -- 26,755
Income taxes payable 902 9 -- 4,364 -- 5,275
--------------------------------------------------------------------------------
Total current liabilities 4,880 91 9 33,211 -- 38,191
Long-term debt 1,209 281 925 4,865 -- 7,280
Deferred income tax liabilities 3,334 31 292 12,785 -- 16,442
Other long-term liabilities 4,428 9 -- 11,893 -- 16,330
Intercompany payables 33,413 17,965 412 190,818 (242,608) --
--------------------------------------------------------------------------------
Total liabilities 47,264 18,377 1,638 253,572 (242,608) 78,243
Earnings reinvested 86,652 56 (96) 36,946 (36,906) 86,652
Other shareholders' equity (15,895) 806 394 332,363 (333,563) (15,895)
--------------------------------------------------------------------------------
Total shareholders' equity 70,757 862 298 369,309 (370,469) 70,757
--------------------------------------------------------------------------------
Total liabilities and shareholders' equity $118,021 $ 19,239 $1,936 $622,881 $(613,077) $149,000
================================================================================
47
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Condensed consolidating financial information related to guaranteed securities
issued by subsidiaries
Exxon Mobil SeaRiver Consolidating
Corporation Exxon Maritime and
Parent Capital Financial All Other Eliminating
Guarantor Corporation Holdings, Inc. Subsidiaries Adjustments Consolidated
-------------------------------------------------------------------------------
(millions of dollars)
Condensed consolidated statement of cash flows for twelve months ended December 31, 2001
----------------------------------------------------------------------------------------
Cash provided by/(used in) operating activities $ 7,277 $ 12 $ 113 $ 16,239 $ (752) $ 22,889
-------------------------------------------------------------------------------
Cash flows from investing activities
Additions to property, plant and equipment (2,058) -- -- (7,931) -- (9,989)
Sales of long-term assets 536 -- -- 542 -- 1,078
Net intercompany investing 3,152 17,759 (76) (1,345) (19,490) --
All other investing, net (31) -- -- 731 -- 700
-------------------------------------------------------------------------------
Net cash provided by/(used in) investing
activities 1,599 17,759 (76) (8,003) (19,490) (8,211)
-------------------------------------------------------------------------------
Cash flows from financing activities
Additions to short- and long-term debt -- -- -- 1,252 -- 1,252
Reductions in short- and long-term debt (62) (15) (7) (1,634) -- (1,718)
Additions/(reductions) in debt with less than
90 day maturity -- (39) -- (2,267) -- (2,306)
Cash dividends (6,254) -- -- (752) 752 (6,254)
Common stock acquired (5,721) -- -- -- -- (5,721)
Net intercompany financing activity -- (17,717) (30) (1,743) 19,490 --
All other financing, net 301 -- -- (595) -- (294)
-------------------------------------------------------------------------------
Net cash provided by/(used in) financing
activities (11,736) (17,771) (37) (5,739) 20,242 (15,041)
-------------------------------------------------------------------------------
Effects of exchange rate changes on cash -- -- -- (170) -- (170)
-------------------------------------------------------------------------------
Increase/(decrease) in cash and cash equivalents $ (2,860) $ -- $ -- $ 2,327 $ -- $ (533)
===============================================================================
Condensed consolidated statement of cash flows for twelve months ended December 31, 2000
----------------------------------------------------------------------------------------
Cash provided by/(used in) operating activities $ 7,704 $ 61 $ 94 $ 16,063 $ (985) $ 22,937
-------------------------------------------------------------------------------
Cash flows from investing activities
Additions to property, plant and equipment (1,832) -- -- (6,614) -- (8,446)
Sales of long-term assets 1,088 -- -- 4,682 -- 5,770
Net intercompany investing 6,386 (7,143) (114) (6,285) 7,156 --
All other investing, net (26) -- -- (596) -- (622)
-------------------------------------------------------------------------------
Net cash provided by/(used in) investing
activities 5,616 (7,143) (114) (8,813) 7,156 (3,298)
-------------------------------------------------------------------------------
Cash flows from financing activities
Additions to short- and long-term debt 23 -- -- 715 -- 738
Reductions in short- and long-term debt (247) (214) (7) (2,846) -- (3,314)
Additions/(reductions) in debt with less than
90 day maturity (990) 16 -- (2,155) -- (3,129)
Cash dividends (6,123) -- -- (985) 985 (6,123)
Common stock acquired (2,352) -- -- -- -- (2,352)
Net intercompany financing activity -- 7,280 27 (151) (7,156) --
All other financing, net 493 -- -- (478) -- 15
-------------------------------------------------------------------------------
Net cash provided by/(used in) financing
activities (9,196) 7,082 20 (5,900) (6,171) (14,165)
-------------------------------------------------------------------------------
Effects of exchange rate changes on cash -- -- -- (82) -- (82)
-------------------------------------------------------------------------------
Increase/(decrease) in cash and cash equivalents $ 4,124 $ -- $ -- $ 1,268 $ -- $ 5,392
===============================================================================
48
Exxon Mobil SeaRiver Consolidating
Corporation Exxon Maritime and
Parent Capital Financial All Other Eliminating
Guarantor Corporation Holdings, Inc. Subsidiaries Adjustments Consolidated
---------------------------------------------------------------------------------
(millions of dollars)
Condensed consolidated statement of cash flows for twelve months ended December 31, 1999
----------------------------------------------------------------------------------------
Cash provided by/(used in) operating activities $ 5,056 $ 78 $ 104 $ 12,916 $ (3,141) $ 15,013
---------------------------------------------------------------------------------
Cash flows from investing activities
Additions to property, plant and equipment (1,968) -- -- (8,881) -- (10,849)
Sales of long-term assets 294 -- -- 678 -- 972
Net intercompany investing 2,982 (751) (95) (6,468) 4,332 --
All other investing, net (31) -- -- (1,077) -- (1,108)
---------------------------------------------------------------------------------
Net cash provided by/(used in) investing
activities 1,277 (751) (95) (15,748) 4,332 (10,985)
---------------------------------------------------------------------------------
Cash flows from financing activities
Additions to short- and long-term debt 2 -- -- 2,322 -- 2,324
Reductions in short- and long-term debt (2) -- (7) (2,691) -- (2,700)
Additions/(reductions) in debt with less than
90 day maturity (117) 10 -- 2,317 -- 2,210
Cash dividends (5,872) (2,000) -- (1,141) 3,141 (5,872)
Common stock acquired (670) -- -- -- -- (670)
Net intercompany financing activity -- 2,663 (2) 1,671 (4,332) --
All other financing, net 348 -- -- (419) -- (71)
---------------------------------------------------------------------------------
Net cash provided by/(used in) financing
activities (6,311) 673 (9) 2,059 (1,191) (4,779)
---------------------------------------------------------------------------------
Effects of exchange rate changes on cash -- -- -- 53 -- 53
---------------------------------------------------------------------------------
Increase/(decrease) in cash and cash equivalents $ 22 $ -- $ -- $ (720) $ -- $ (698)
=================================================================================
49
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
16. Incentive Program
The 1993 Incentive Program provides for grants of stock options, stock
appreciation rights (SARs), restricted stock and other forms of award. Awards
may be granted over a 10-year period to eligible employees of the corporation
and those affiliates at least 50 percent owned. The number of shares of stock
which may be awarded each year under the 1993 Incentive Program may not exceed
seven tenths of one percent (0.7%) of the total number of shares of common stock
of the corporation outstanding (excluding shares held by the corporation) on
December 31 of the preceding year. If the total number of shares effectively
granted in any year is less than the maximum number of shares allowable, the
balance may be carried over thereafter. Outstanding awards are subject to
certain forfeiture provisions contained in the program or award instrument.
Options and SARs may be granted at prices not less than 100 percent of
market value on the date of grant and have a maximum life of 10 years. Most of
the options and SARs normally first become exercisable one year following the
date of grant.
On the closing of the merger on November 30, 1999, outstanding options and
SARs granted by Mobil under its 1995 Incentive Compensation and Stock Ownership
Plan and prior plans were assumed by ExxonMobil and converted into rights to
acquire ExxonMobil common stock with adjustments to reflect the exchange ratio.
No further awards may be granted under the former Mobil plans.
Shares available for granting under the 1993 Incentive Program were 133,115
thousand at the beginning of 2001 and 98,668 thousand at the end of 2001. At
December 31, 2000 and 2001, respectively, 2,438 thousand and 2,559 thousand
shares of restricted common stock were outstanding.
Statement of Financial Accounting Standards No. 123, "Accounting for
Stock-Based Compensation," was implemented in January 1996. As permitted by the
Standard, ExxonMobil retained its prior method of accounting for stock
compensation. If the provisions of Statement No. 123 had been adopted, net
income and earnings per share (on both a basic and diluted basis) would have
been reduced by $285 million, or $0.04 per share in 2001; $296 million, or $0.04
per share in 2000 and $149 million, or $0.02 per share in 1999. For the
ExxonMobil plan, the average fair value of each option granted during 2001, 2000
and 1999 was $6.89, $10.18 and $9.85, respectively. The fair value was estimated
at the grant date using an option-pricing model with the following weighted
average assumptions for 2001, 2000 and 1999, respectively: risk-free interest
rates of 4.6 percent, 5.5 percent and 6.2 percent; expected life of 6 years for
all years; volatility of 16 percent, 16 percent and 15 percent and a dividend
yield of 2.5 percent, 2.0 percent and 2.1 percent. For the Mobil plans, the
average fair value of each Mobil option granted during 1999 was $8.51. The fair
value was estimated at the grant date using an option-pricing model with the
following weighted average assumptions for 1999: risk-free interest rate of 5.2
percent; expected life of 5 years; volatility of 20 percent and a dividend yield
of 2.7 percent.
Changes that occurred in options outstanding in 2001, 2000 and 1999,
including the former Mobil plans, are summarized below (shares in thousands):
2001 2000 1999
-----------------------------------------------------------------------------
Avg. Exercise Avg. Exercise Avg. Exercise
Shares Price Shares Price Shares Price
-----------------------------------------------------------------------------
Outstanding at beginning of year 248,680 $28.70 242,232 $24.81 221,218 $21.02
Granted 34,717 37.12 36,224 45.19 44,198 39.00
Exercised (16,949) 16.63 (28,714) 16.35 (22,500) 15.16
Expired/Canceled (753) 39.44 (1,062) 37.13 (684) 33.09
------- ------- -------
Outstanding at end of year 265,695 30.54 248,680 28.70 242,232 24.81
Exercisable at end of year 221,405 29.29 195,144 25.95 174,944 21.08
The following table summarizes information about stock options outstanding,
including those from former Mobil plans, at December 31, 2001 (shares in
thousands):
Options Outstanding Options Exercisable
--------------------------------------------------------------- ------------------------
Exercise Price Avg. Remaining Avg. Exercise Avg. Exercise
Range Shares Contractual Life Price Shares Price
--------------------------------------------------------------- ------------------------
$11.64-16.54 48,548 2.5 years $15.08 48,548 $15.08
19.06-27.71 63,525 5.1 years 22.92 63,525 22.92
29.18-45.22 153,622 8.2 years 38.58 109,332 39.30
------- -------
Total 265,695 6.4 years 30.54 221,405 29.29
50
17. Litigation and Other Contingencies
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. The vast
majority of the claims have been resolved leaving a few compensatory damages
cases to be tried. All of the punitive damage claims were consolidated in the
civil trial that began in May 1994.
In that trial, on September 24, 1996, the United States District Court for
the District of Alaska entered a judgment in the amount of $5.058 billion. 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 appealed the judgment. On
November 7, 2001, the United States Court of Appeals for the Ninth Circuit
vacated the punitive damage award as being excessive under the Constitution and
remanded the case to the District Court for it to determine the amount of the
punitive damage award consistent with the Ninth Circuit's holding. The Ninth
Circuit upheld the compensatory damage award which has been paid. The letter of
credit was terminated on February 1, 2002.
On January 29, 1997, a settlement agreement was concluded resolving all
remaining matters between the corporation and various insurers arising from the
Valdez accident. Under terms of this settlement, ExxonMobil received $480
million. Final income statement recognition of this settlement continues to be
deferred in view of uncertainty regarding the ultimate cost to the corporation
of the Valdez accident.
The ultimate cost to ExxonMobil from the lawsuits arising from the Exxon
Valdez grounding is not possible to predict and may not be resolved for a number
of years.
Under the October 8, 1991, civil agreement and consent decrees with the
U.S. and Alaska governments, the corporation made the final payment of $70
million in the third quarter of 2001. This payment, along with prior payments,
was charged against the provision that was previously established to cover the
costs of the settlement.
A dispute with a Dutch affiliate concerning an overlift of natural gas by a
German affiliate was resolved by payments by the German affiliate pursuant to an
arbitration award. The German affiliate had paid royalties on the excess gas and
recovered the royalties in 2001. The only substantive issue remaining is the
taxes payable on the final compensation for the overlift. Resolution of this
issue will not have a materially adverse effect upon the corporation's
operations or financial condition.
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. The verdict
was upheld by the trial court on May 4, 2001. ExxonMobil has appealed the
judgment and believes that it should be set aside or substantially reduced on
factual and constitutional grounds. The ultimate outcome is not expected to have
a materially adverse effect upon the corporation's operations or financial
condition.
On May 22, 2001, a state court jury in New Orleans, Louisiana, returned a
verdict against the corporation and three other entities in a case brought by a
landowner claiming damage to his property. The property had been leased by the
landowner to a company that performed pipe cleaning and storage services for
customers, including the corporation. The jury awarded the plaintiff $56 million
in compensatory damages (90 percent to be paid by the corporation) and $1
billion in punitive damages (all to be paid by the corporation). The damage
related to the presence of naturally occurring radioactive material (NORM) on
the site resulting from pipe cleaning operations. The award has been upheld at
the trial court. ExxonMobil will appeal the judgment to the Louisiana Fourth
Circuit Court of Appeals and believes that the judgment should be set aside or
substantially reduced on factual and constitutional grounds. 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. The ultimate resolution of
these issues is not expected to have a materially adverse effect upon the
corporation's operations or financial condition.
Claims for substantial amounts have been made against ExxonMobil and
certain of its consolidated subsidiaries in other pending lawsuits, the outcome
of which is not expected to have a materially adverse effect upon the
corporation's operations or financial condition.
The corporation and certain of its consolidated subsidiaries were
contingently liable at December 31, 2001, for $3,921 million, primarily relating
to guarantees for notes, loans and performance under contracts. This included
$672 million representing guarantees of non-U.S. excise taxes and customs duties
of other companies, entered into as a normal business practice, under reciprocal
arrangements. Also included in this amount were guarantees by consolidated
affiliates of $1,641 million, representing ExxonMobil's share of obligations of
certain equity companies.
Additionally, the corporation and its affiliates have numerous long-term
sales and purchase commitments in their various business activities, all of
which are expected to be fulfilled with no adverse consequences material to the
corporation's operations or financial condition. The present value of
unconditional purchase obligations was $1,296 million at December 31, 2001. On
an undiscounted basis, including imputed interest of $733 million, these
commitments totaled $2,029 million. Unconditional purchase obligations as
defined by accounting standards are those long-term commitments that are
noncancelable or cancelable only under certain conditions, and that third
parties have used to secure financing for the facilities that will provide the
contracted goods or services.
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.
51
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
18. Annuity Benefits and Other Postretirement Benefits
Annuity Benefits
--------------------------------------------------- Other Postretirement
U.S. Non-U.S. Benefits
----------------------- ------------------------ ------------------------
2001 2000 1999 2001 2000 1999 2001 2000 1999
------------------------------------------------------------------------------
Components of net benefit cost (millions of dollars)
Service cost $ 200 $ 214 $ 249 $ 232 $ 245 $ 312 $ 27 $ 24 $ 36
Interest cost 579 592 555 598 603 608 205 201 190
Expected return on plan assets (623) (726) (601) (629) (641) (599) (43) (51) (48)
Amortization of actuarial loss/(gain)
and prior service cost (25) (168) (36) 78 55 167 4 -- 14
Net pension enhancement and
curtailment/settlement expense 14 (175) 1 27 77 50 -- (5) --
-----------------------------------------------------------------------------
Net benefit cost $ 145 $(263) $ 168 $ 306 $ 339 $ 538 $ 193 $ 169 $ 192
=============================================================================
Costs for defined contribution plans were $132 million, $67 million and $69
million in 2001, 2000 and 1999, respectively.
Annuity Benefits
-------------------------------------------- Other Postretirement
U.S. Non-U.S. Benefits
-------------------- -------------------- --------------------
2001 2000 2001 2000 2001 2000
--------------------------------------------------------------------
Change in benefit obligation (millions of dollars)
Benefit obligation at January 1 $ 7,651 $ 8,032 $ 11,063 $ 11,628 $ 2,942 $ 2,620
Service cost 200 214 232 245 27 24
Interest cost 579 592 598 603 205 201
Actuarial loss/(gain) 638 179 540 429 7 144
Benefits paid (868) (1,534) (710) (815) (258) (233)
Foreign exchange rate changes -- -- (678) (811) (12) (8)
Other 13 168 161 (216) 220 194
--------------------------------------------------------------------
Benefit obligation at December 31 $ 8,213 $ 7,651 $ 11,206 $ 11,063 $ 3,131 $ 2,942
====================================================================
Change in plan assets
Fair value at January 1 $ 6,795 $ 7,965 $ 7,780 $ 8,689 $ 446 $ 568
Actual return on plan assets (647) 208 (424) (12) (34) (30)
Foreign exchange rate changes -- -- (422) (612) -- --
Payments directly to participants 135 156 225 311 187 166
Company contribution -- -- 299 232 32 38
Benefits paid (868) (1,534) (710) (815) (258) (233)
Other -- -- 7 (13) 22 (63)
---------------------------------------------------------------------
Fair value at December 31 $ 5,415 $ 6,795 $ 6,755 $ 7,780 $ 395 $ 446
=====================================================================
Assets in excess of/(less than) benefit obligation
Balance at December 31 $ (2,798) $ (856) $ (4,451) $ (3,283) $ (2,736) $ (2,496)
Unrecognized net transition liability/(asset) (2) (31) 34 49 -- --
Unrecognized net actuarial loss/(gain) 1,142 (788) 2,002 507 108 35
Unrecognized prior service cost 248 281 308 297 381 180
Intangible asset (226) (12) (135) (82) -- --
Equity of minority shareholders -- -- (82) (36) -- --
Minimum pension liability adjustment (144) (163) (805) (422) -- --
---------------------------------------------------------------------
Prepaid/(accrued) benefit cost $ (1,780) $ (1,569) $ (3,129) $ (2,970) $ (2,247) $ (2,281)
=====================================================================
Assumptions as of December 31 (percent)
Discount rate 7.25 7.5 2.6-6.8 3.0-7.0 7.25 7.5
Long-term rate of compensation increase 3.50 3.5 2.8-4.3 3.0-5.0 3.50 3.5
Long-term rate of return on funded assets 9.50 9.5 6.5-10.0 6.5-10.0 9.50 9.5
52
Annuity Benefits
-------------------------------
U.S. Non-U.S.
-------------------------------
2001 2000 2001 2000
-------------------------------
(millions of dollars)
For funded pension plans with accumulated
------
benefit obligations in excess of plan
assets:
Projected benefit obligation $7,140 $ -- $4,142 $2,234
Accumulated benefit obligation 6,226 -- 3,828 2,089
Fair value of plan assets 5,247 -- 2,855 1,333
For unfunded plans covered by book reserves:
--------
Projected benefit obligation $ 963 $ 885 $3,197 $2,918
Accumulated benefit obligation 859 799 2,854 2,587
The preceding data conform with current accounting standards that specify use of
a discount rate at which postretirement liabilities could be effectively
settled. The discount rate for calculating year-end postretirement liabilities
is based on the year-end rate of interest on high quality bonds. The return on
the annuity fund's actual portfolio of assets has historically been higher than
bonds as the majority of pension assets are invested in equities. The actual
rate earned in the U.S. over the past decade has been 12 percent. All funded
U.S. plans are fully funded in 2001 under the standards set by the Department of
Labor and the Internal Revenue Service. The corporation will continue to make
contributions as necessary to maintain the fully funded status of these plans
according to those standards. Certain smaller U.S. plans and a number of
non-U.S. plans are not funded because local tax conventions and regulatory
practices do not encourage funding of these plans. Book reserves have been
established for these plans to provide for future benefit payments. All defined
benefit pension obligations, regardless of the funding status of the underlying
plans, are fully supported by the financial strength of the corporation or the
respective sponsoring affiliate.
53
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
19. Income, Excise and Other Taxes
2001 2000 1999
---------------------------------------------------------------------------------------------------------------------------------
United Non- United Non- United Non-
States U.S. Total States U.S. Total States U.S. Total
---------------------------------------------------------------------------------------------------------------------------------
(millions of dollars)
Income taxes
Federal or non-U.S.
Current $ 1,729 $ 6,084 $ 7,813 $ 2,635 $ 7,972 $10,607 $ 369 $ 3,973 $ 4,342
Deferred - net 712 169 881 433 (322) 111 214 (1,489) (1,275)
U.S. tax on non-U.S. operations 91 -- 91 64 -- 64 25 -- 25
--------------------------------------------------------------------------------------------
$ 2,532 $ 6,253 $ 8,785 $ 3,132 $ 7,650 $10,782 $ 608 $ 2,484 $ 3,092
State 229 -- 229 309 -- 309 148 -- 148
--------------------------------------------------------------------------------------------
Total income taxes $ 2,761 $ 6,253 $ 9,014 $ 3,441 $ 7,650 $11,091 $ 756 $ 2,484 $ 3,240
Excise taxes 7,030 14,877 21,907 6,997 15,359 22,356 7,795 13,851 21,646
All other taxes and duties 1,177 34,485 35,662 1,253 33,685 34,938 1,021 35,616 36,637
--------------------------------------------------------------------------------------------
Total $ 10,968 $ 55,615 $ 66,583 $ 11,691 $56,694 $68,385 $ 9,572 $ 51,951 $ 61,523
============================================================================================
All other taxes and duties include taxes reported in operating and
selling, general and administrative expenses. The above provisions for deferred
income taxes include net credits for the effect of changes in tax laws and rates
of $31 million in 2001, $84 million in 2000 and $205 million in 1999. Income
taxes (charged)/credited directly to shareholders' equity were:
2001 2000 1999
--------------------------------------------------------------------------------
(millions of dollars)
Cumulative foreign exchange
translation adjustment $ 102 $ 221 $ (84)
Minimum pension liability
adjustment 139 27 (127)
Unrealized gains and losses on stock
investments 40 57 (45)
Other components of
shareholders' equity 83 111 50
The reconciliation between income tax expense and a theoretical U.S. tax
computed by applying a rate of 35 percent for 2001, 2000 and 1999, is as
follows:
2001 2000 1999
--------------------------------------------------------------------------------
(millions of dollars)
Earnings before Federal and
non-U.S. income taxes
United States $ 8,310 $ 9,016 $ 3,187
Non-U.S. 15,580 17,756 7,815
--------------------------------
Total $ 23,890 $ 26,772 $ 11,002
--------------------------------
Theoretical tax $ 8,362 $ 9,370 $ 3,851
Effect of equity method accounting (761) (852) (576)
Non-U.S. taxes in excess of
theoretical U.S. tax 1,354 1,986 201
U.S. tax on non-U.S. operations 91 64 25
Other U.S. (261) 214 (409)
--------------------------------
Federal and non-U.S. income
tax expense $ 8,785 $ 10,782 $ 3,092
================================
Total effective tax rate 39.3% 42.4% 31.8%
The effective income tax rate includes state income taxes and the
corporation's share of income taxes of equity companies. Equity company taxes
totaled $748 million in 2001, $658 million in 2000 and $449 million in 1999,
primarily all outside the U.S.
Deferred income taxes reflect the impact of temporary differences between
the amount of assets and liabilities recognized for financial reporting purposes
and such amounts recognized for tax purposes.
Deferred tax liabilities/(assets) are comprised of the following at
December 31:
Tax effects of temporary differences for: 2001 2000
-----------------------------------------------------------------------------
(millions of dollars)
Depreciation $12,738 $13,358
Intangible development costs 3,445 3,282
Capitalized interest 1,989 1,891
Other liabilities 3,165 2,935
---------------------
Total deferred tax liabilities $21,337 $21,466
---------------------
Pension and other postretirement benefits $(1,911) $(1,923)
Tax loss carryforwards (2,057) (1,763)
Other assets (2,803) (3,465)
---------------------
Total deferred tax assets $(6,771) $(7,151)
---------------------
Asset valuation allowances 209 380
---------------------
Net deferred tax liabilities $14,775 $14,695
=====================
The corporation had $17 billion of indefinitely reinvested, undistributed
earnings from subsidiary companies outside the U.S. Unrecognized deferred taxes
on remittance of these funds are not expected to be material.
54
20. Disclosures about Segments and Related Information
The functional segmentation of operations reflected below is consistent with
ExxonMobil's internal reporting. Earnings include special items and transfers
are at estimated market prices. The interest revenue amount relates to interest
earned on cash deposits and marketable securities. Interest expense includes
non-debt related interest expense of $105 million, $142 million and $123 million
in 2001, 2000 and 1999, respectively.
All Other includes smaller operating segments, corporate and financing
activities, merger expenses, and extraordinary gains from required asset
divestitures of $40 million and $1,730 million in 2001 and 2000, respectively.
U.S. chemicals and non-U.S. chemicals after-tax earnings in 2001 include net
gains on asset management activities totaling $100 million and $75 million,
respectively.
Upstream Downstream Chemicals
------------------- ------------------- --------------------- All Corporate
U.S. Non-U.S. U.S. Non-U.S. U.S. Non-U.S. Other Total
--------------------------------------------------------------------------------------
(millions of dollars)
As of December 31, 2001
Earnings after income tax $ 3,932 $ 6,497 $ 1,924 $ 2,303 $ 398 $ 484 $ (218) $ 15,320
Earnings of equity companies included above 482 1,477 89 12 19 118 (23) 2,174
Sales and other operating revenue 5,606 12,889 50,988 123,197 6,918 9,025 794 209,417
Intersegment revenue 5,408 12,322 4,115 16,880 2,186 2,284 178 --
Depreciation and depletion expense 1,436 3,221 598 1,476 408 289 516 7,944
Interest revenue -- -- -- -- -- -- 380 380
Interest expense -- -- -- -- -- -- 293 293
Income taxes 2,093 5,547 1,075 744 82 149 (676) 9,014
Additions to property, plant and equipment 1,980 4,518 827 1,239 390 243 792 9,989
Investments in equity companies 1,371 2,043 329 831 333 1,291 18 6,216
Total assets 18,809 40,018 12,850 37,617 7,495 9,524 16,861 143,174
======================================================================================
As of December 31, 2000
Earnings after income tax $ 4,545 $ 7,824 $ 1,561 $ 1,857 $ 644 $ 517 $ 772 $ 17,720
Earnings of equity companies included above 753 1,400 71 74 35 139 (38) 2,434
Sales and other operating revenue 5,669 15,774 56,080 132,483 8,198 9,303 932 228,439
Intersegment revenue 6,557 15,654 8,631 11,684 2,905 2,398 181 --
Depreciation and depletion expense 1,417 3,469 594 1,489 397 281 483 8,130
Interest revenue -- -- -- -- -- -- 258 258
Interest expense -- -- -- -- -- -- 589 589
Income taxes 2,489 7,137 889 850 344 210 (828) 11,091
Additions to property, plant and equipment 1,513 3,501 966 926 288 458 794 8,446
Investments in equity companies 1,261 1,971 264 1,456 492 1,395 25 6,864
Total assets 18,825 39,626 13,516 42,422 8,047 10,234 16,330 149,000
======================================================================================
As of December 31, 1999
Earnings after income tax $ 1,842 $ 4,044 $ 577 $ 650 $ 738 $ 616 $ (557) $ 7,910
Earnings of equity companies included above 299 881 8 148 49 83 178 1,646
Sales and other operating revenue 3,104 11,353 43,376 109,969 6,554 7,223 950 182,529
Intersegment revenue 3,925 9,093 2,867 5,387 1,624 1,317 796 --
Depreciation and depletion expense 1,330 3,497 697 1,670 402 274 434 8,304
Interest revenue -- -- -- -- -- -- 153 153
Interest expense -- -- -- -- -- -- 695 695
Income taxes 1,008 2,703 343 (22) 338 63 (1,193) 3,240
Additions to property, plant and equipment 1,440 5,025 830 1,201 600 1,093 660 10,849
Investments in equity companies 1,171 2,647 280 3,304 429 1,537 38 9,406
Total assets 18,211 40,906 13,699 43,718 7,605 9,831 10,551 144,521
======================================================================================
Geographic
Sales and other operating revenue 2001 2000 1999
----------------------------------------------------------------------------------------------------------------
(millions of dollars)
United States $ 63,603 $ 70,036 $ 53,214
Non-U.S. 145,814 158,403 129,315
-------------------------------------------
Total $ 209,417 $ 228,439 $ 182,529
Significant non-U.S. revenue sources include:
Japan $ 21,788 $ 24,520 $ 19,727
United Kingdom 18,628 19,904 16,305
Canada 14,912 16,059 11,576
Long-lived assets 2001 2000 1999
----------------------------------------------------------------------------------------------------------------
(millions of dollars)
United States $ 33,637 $ 33,087 $ 33,913
Non-U.S. 55,965 56,742 60,130
-------------------------------------------
Total $ 89,602 $ 89,829 $ 94,043
Significant non-U.S. long-lived assets include:
United Kingdom $ 8,390 $ 9,024 $ 10,293
Canada 7,862 7,922 8,404
Norway 4,627 4,383 4,802
55
QUARTERLY INFORMATION
2001 2000
----------------------------------------------------------------------------------------------------
First Second Third Fourth First Second Third Fourth
Quarter Quarter Quarter Quarter Year Quarter Quarter Quarter Quarter Year
----------------------------------------------------------------------------------------------------------------------------------
Volumes
Production of crude oil (thousands of barrels daily)
and natural gas liquids 2,620 2,539 2,484 2,527 2,542 2,602 2,514 2,497 2,600 2,553
Refinery throughput 5,687 5,406 5,605 5,587 5,571 5,528 5,572 5,736 5,732 5,642
Petroleum product sales 7,985 7,933 7,951 8,016 7,971 7,796 8,035 8,069 8,068 7,993
Natural gas production (millions of cubic feet daily)
available for sale 12,119 9,090 8,561 11,373 10,279 12,146 9,247 8,735 11,252 10,343
(thousands of metric tons)
Chemical prime product sales 6,533 6,418 6,457 6,372 25,780 6,519 6,596 6,038 6,484 25,637
Summarized financial data
Sales and other operating (millions of dollars)
revenue $56,076 55,101 51,132 47,108 209,417 $53,273 54,936 57,497 62,733 228,439
Gross profit* $24,233 22,873 21,855 22,056 91,017 $21,896 22,201 23,620 25,506 93,223
Net income before
extraordinary item $ 4,960 4,285 3,180 2,680 15,105 $ 3,025 4,000 4,060 4,905 15,990
Extraordinary gain
net of income tax $ 40 175 -- -- 215 $ 455 530 430 315 1,730
Net income $ 5,000 4,460 3,180 2,680 15,320 $ 3,480 4,530 4,490 5,220 17,720
Per share data
Net income per common share (dollars per share)
before extraordinary item $ 0.71 0.64 0.46 0.39 2.20 $ 0.44 0.58 0.57 0.71 2.30
Extraordinary gain
net of income tax $ 0.01 0.02 -- -- 0.03 $ 0.06 0.08 0.06 0.05 0.25
Net income per common share $ 0.72 0.66 0.46 0.39 2.23 $ 0.50 0.66 0.63 0.76 2.55
Net income per common share
- assuming dilution $ 0.71 0.65 0.46 0.39 2.21 $ 0.49 0.65 0.63 0.75 2.52
Dividends per common share $ 0.22 0.23 0.23 0.23 0.91 $ 0.22 0.22 0.22 0.22 0.88
Common stock prices
High $44.875 45.835 44.400 42.700 45.835 $43.156 42.375 45.375 47.719 47.719
Low $37.600 38.500 35.010 36.410 35.010 $34.938 37.500 37.563 42.031 34.938
* Gross profit equals sales and other operating revenue less estimated costs
associated with products sold.
Note: Prior period per share amounts restated for the two-for-one stock split
effective June 20, 2001.
The price range of ExxonMobil common stock is as reported on the composite tape
of the several U.S. exchanges where ExxonMobil common stock is traded. The
principal market where ExxonMobil common stock (XOM) is traded is the New York
Stock Exchange, although the stock is traded on other exchanges in and outside
the United States.
There were 698,770 registered shareholders of ExxonMobil common stock at
December 31, 2001. At January 31, 2002, the registered shareholders of
ExxonMobil common stock numbered 697,972.
On January 30, 2002, the corporation declared a $0.23 dividend per common
share, payable March 11, 2002.
56
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
Consolidated Subsidiaries
-----------------------------------------------------------------
Non-
United Consolidated Total
Results of Operations States Canada Europe Asia-Pacific Africa Other Total Interests Worldwide
------------------------------------------------------------------------------------------------------------------------------------
(millions of dollars)
2001 - Revenue
Sales to third parties $ 4,045 $ 1,784 $ 5,017 $1,269 $ 17 $ 342 $ 12,474 $ 3,326 $ 15,800
Transfers 4,547 1,203 3,927 1,917 2,894 250 14,738 1,306 16,044
------------------------------------------------------------------------------------------
$ 8,592 $ 2,987 $ 8,944 $3,186 $2,911 $ ,592 $ 27,212 $ 4,632 $ 31,844
Production costs excluding taxes 1,389 633 1,425 549 414 210 4,620 580 5,200
Exploration expenses 215 109 117 103 217 412 1,173 18 1,191
Depreciation and depletion 1,392 570 1,644 557 318 148 4,629 354 4,983
Taxes other than income 545 54 484 410 375 5 1,873 1,160 3,033
Related income tax 1,957 543 2,567 622 1,023 (98) 6,614 1,037 7,651
------------------------------------------------------------------------------------------
Results of producing activities $ 3,094 $ 1,078 $ 2,707 $ 945 $ 564 $ (85) $ 8,303 $ 1,483 $ 9,786
Other earnings* 354 (37) 132 (36) 33 (58) 388 255 643
------------------------------------------------------------------------------------------
Total earnings $ 3,448 $ 1,041 $ 2,839 $ 909 $ 597 $ (143) $ 8,691 $ 1,738 $ 10,429
==========================================================================================
2000 - Revenue
Sales to third parties $ 4,060 $ 2,423 $ 4,387 $2,167 $ 20 $ 366 $ 13,423 $ 3,055 $ 16,478
Transfers 5,420 771 5,491 2,130 3,212 324 17,348 1,532 18,880
------------------------------------------------------------------------------------------
$ 9,480 $ 3,194 $ 9,878 $4,297 $3,232 $ 690 $ 30,771 $ 4,587 $ 35,358
Production costs excluding taxes 1,231 595 1,627 543 400 181 4,577 621 5,198
Exploration expenses 145 81 135 164 196 211 932 22 954
Depreciation and depletion 1,373 586 1,906 556 340 141 4,902 399 5,301
Taxes other than income 637 33 358 506 446 4 1,984 997 2,981
Related income tax 2,419 736 3,274 1,005 1,093 97 8,624 975 9,599
------------------------------------------------------------------------------------------
Results of producing activities $ 3,675 $ 1,163 $ 2,578 $1,523 $ 757 $ 56 $ 9,752 $ 1,573 $ 11,325
Other earnings* 117 (36) 521 144 31 (31) 746 298 1,044
------------------------------------------------------------------------------------------
Total earnings $ 3,792 $ 1,127 $ 3,099 $1,667 $ 788 $ 25 $ 10,498 $ 1,871 $ 12,369
==========================================================================================
1999 - Revenue
Sales to third parties $ 2,419 $ 925 $ 3,287 $2,160 $ 13 $ 178 $ 8,982 $ 2,123 $ 11,105
Transfers 3,237 848 2,965 1,250 1,986 204 10,490 867 11,357
------------------------------------------------------------------------------------------
$ 5,656 $ 1,773 $ 6,252 $3,410 $1,999 $ 382 $ 19,472 $ 2,990 $ 22,462
Production costs excluding taxes 1,347 504 1,499 566 394 157 4,467 617 5,084
Exploration expenses 232 93 280 144 236 261 1,246 29 1,275
Depreciation and depletion 1,260 486 1,932 678 318 173 4,847 443 5,290
Taxes other than income 425 31 246 288 309 2 1,301 591 1,892
Related income tax 893 252 929 521 534 (5) 3,124 546 3,670
------------------------------------------------------------------------------------------
Results of producing activities $ 1,499 $ 407 $ 1,366 $1,213 $ 208 $ (206) $ 4,487 $ 764 $ 5,251
Other earnings* 42 32 391 6 17 (36) 452 183 635
------------------------------------------------------------------------------------------
Total earnings $ 1,541 $ 439 $ 1,757 $1,219 $ 225 $ (242) $ 4,939 $ 947 $ 5,886
==========================================================================================
Average sales prices and production costs per unit of production
------------------------------------------------------------------------------------------------------------------------------------
During 2001
Average sales prices
Crude oil and NGL, per barrel $ 19.92 $ 15.95 $ 22.79 $24.36 $23.34 $20.21 $ 21.30 $ 19.64 $ 21.10
Natural gas, per thousand cubic feet 4.36 3.71 3.28 1.80 -- 1.44 3.37 3.48 3.39
Average production costs, per barrel** 3.68 3.88 3.40 2.98 3.32 5.85 3.54 2.53 3.39
During 2000
Average sales prices
Crude oil and NGL, per barrel $ 23.94 $ 21.60 $ 26.96 $28.74 $28.17 $24.57 $ 25.77 $ 24.17 $ 25.59
Natural gas, per thousand cubic feet 3.85 3.58 2.69 2.59 -- 1.29 3.12 3.11 3.12
Average production costs, per barrel** 3.08 4.04 3.72 2.72 3.39 5.50 3.43 2.90 3.35
During 1999
Average sales prices
Crude oil and NGL, per barrel $ 14.96 $ 14.47 $ 16.59 $17.96 $16.81 $18.57 $ 16.16 $ 14.52 $ 15.97
Natural gas, per thousand cubic feet 2.21 1.61 2.25 1.88 -- 1.21 2.08 2.47 2.15
Average production costs, per barrel** 3.42 3.69 3.64 2.40 3.31 6.20 3.38 3.02 3.33
* Includes earnings from transportation operations, tar sands operations, LNG
operations, technical services agreements, other non-operating activities
and adjustments for minority interests.
** Production costs exclude depreciation and depletion and all taxes. Natural
gas included by conversion to crude oil equivalent.
57
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
Oil and Gas Exploration and Production Costs
The amounts shown for net capitalized costs of consolidated subsidiaries are
$5,212 million less at year-end 2001 and $4,852 million less at year-end 2000
than the amounts reported as investments in property, plant and equipment for
the upstream in note 10. This is due to the exclusion from capitalized costs of
certain transportation and research assets and assets relating to the tar sands
and LNG operations, and to the inclusion of accumulated provisions for site
restoration costs, all as required in Statement of Financial Accounting
Standards No. 19.
The amounts reported as costs incurred include both capitalized costs and
costs charged to expense during the year. Total worldwide costs incurred in 2001
were $7,803 million, up $1,740 million from 2000, due primarily to higher
development costs. 2000 costs were $6,063 million, down $1,696 million from
1999, due primarily to lower development costs.
Consolidated Subsidiaries
------------------------------------------------------------------
Non-
United Consolidated Total
Capitalized costs States Canada Europe Asia-Pacific Africa Other Total Interests Worldwide
-----------------------------------------------------------------------------------------------------------------------------------
As of December 31, 2001
Property (acreage) costs - Proved $ 4,543 $ 2,656 $ 178 $ 689 $ 107 $ 957 $ 9,130 $ 11 $ 9,141
- Unproved 674 196 49 850 630 530 2,929 2 2,931
-----------------------------------------------------------------------------------------
Total property costs $ 5,217 $ 2,852 $ 227 $ 1,539 $ 737 $ 1,487 $ 12,059 $ 13 $ 12,072
Producing assets 33,379 6,662 27,628 11,764 4,300 1,992 85,725 5,710 91,435
Support facilities 488 83 449 925 208 159 2,312 257 2,569
Incomplete construction 1,050 334 1,306 684 1,433 346 5,153 495 5,648
-----------------------------------------------------------------------------------------
Total capitalized costs $ 40,134 $ 9,931 $ 29,610 $14,912 $ 6,678 $ 3,984 $105,249 $ 6,475 $111,724
Accumulated depreciation and depletion 25,754 4,888 19,398 9,705 2,323 1,796 63,864 3,127 66,991
-----------------------------------------------------------------------------------------
Net capitalized costs $ 14,380 $ 5,043 $ 10,212 $ 5,207 $ 4,355 $ 2,188 $ 41,385 $ 3,348 $ 44,733
=========================================================================================
As of December 31, 2000
Property (acreage) costs - Proved $ 4,686 $ 2,784 $ 161 $ 729 $ 54 $ 1,187 $ 9,601 $ 11 $ 9,612
- Unproved 700 236 50 1,044 641 314 2,985 3 2,988
-----------------------------------------------------------------------------------------
Total property costs $ 5,386 $ 3,020 $ 211 $ 1,773 $ 695 $ 1,501 $ 12,586 $ 14 $ 12,600
Producing assets 31,843 5,958 27,794 11,359 3,920 1,592 82,466 5,528 87,994
Support facilities 860 105 447 950 41 119 2,522 260 2,782
Incomplete construction 877 682 1,050 678 1,001 497 4,785 430 5,215
-----------------------------------------------------------------------------------------
Total capitalized costs $ 38,966 $ 9,765 $ 29,502 $14,760 $ 5,657 $ 3,709 $102,359 $ 6,232 $108,591
Accumulated depreciation and depletion 25,129 4,607 18,666 9,486 1,946 1,646 61,480 2,858 64,338
-----------------------------------------------------------------------------------------
Net capitalized costs $ 13,837 $ 5,158 $ 10,836 $ 5,274 $ 3,711 $ 2,063 $ 40,879 $ 3,374 $ 44,253
=========================================================================================
Costs incurred in property acquisitions, exploration and development activities
-----------------------------------------------------------------------------------------------------------------------------------
During 2001
Property acquisition costs - Proved $ -- $ -- $ -- $ -- $ 2 $ -- $ 2 $ -- $ 2
- Unproved 95 17 1 (1) -- 10 122 -- 122
Exploration costs 352 141 144 148 281 459 1,525 35 1,560
Development costs 1,648 664 1,498 666 995 219 5,690 429 6,119
-----------------------------------------------------------------------------------------
Total $ 2,095 $ 822 $ 1,643 $ 813 $ 1,278 $ 688 $ 7,339 $ 464 $ 7,803
=========================================================================================
During 2000
Property acquisition costs - Proved $ 1 $ 1 $ -- $ 1 $ -- $ -- $ 3 $ -- $ 3
- Unproved 72 15 4 96 2 49 238 -- 238
Exploration costs 219 145 187 145 272 297 1,265 23 1,288
Development costs 1,236 525 1,262 502 402 224 4,151 383 4,534
-----------------------------------------------------------------------------------------
Total $ 1,528 $ 686 $ 1,453 $ 744 $ 676 $ 570 $ 5,657 $ 406 $ 6,063
=========================================================================================
During 1999
Property acquisition costs - Proved $ -- $ -- $ 1 $ 18 $ -- $ -- $ 19 $ -- $ 19
- Unproved 8 5 8 -- 459 70 550 -- 550
Exploration costs 263 106 248 152 304 267 1,340 38 1,378
Development costs 1,263 787 1,822 576 547 408 5,403 409 5,812
-----------------------------------------------------------------------------------------
Total $ 1,534 $ 898 $ 2,079 $ 746 $ 1,310 $ 745 $ 7,312 $ 447 $ 7,759
=========================================================================================
58
Oil and Gas Reserves
The following information describes changes during the years and balances of
proved oil and gas reserves at year-end 1999, 2000 and 2001.
The definitions used are in accordance with applicable Securities and
Exchange Commission regulations.
Proved oil and gas reserves are the estimated quantities of crude oil,
natural gas and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions, i.e., prices
and costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions. In some cases, substantial new
investments in additional wells and related facilities will be required to
recover these proved reserves.
Proved reserves include 100 percent of each majority owned affiliate's
participation in proved reserves and ExxonMobil's ownership percentage of the
proved reserves of equity companies, but exclude royalties and quantities due
others. Gas reserves exclude the gaseous equivalent of liquids expected to be
removed from the gas on leases, at field facilities and at gas processing
plants. These liquids are included in net proved reserves of crude oil and
natural gas liquids.
Consolidated Subsidiaries
---------------------------------------------------------------
Non-
United Consolidated Total
Crude Oil and Natural Gas Liquids States Canada Europe Asia-Pacific Africa Other Total Interests Worldwide
------------------------------------------------------------------------------------------------------------------------------------
Net proved developed and undeveloped reserves (millions of barrels)
January 1, 1999 2,804 1,154 1,708 786 1,821 710 8,983 1,970 10,953
Revisions 96 19 96 23 128 6 368 25 393
Purchases -- -- -- -- -- -- -- -- --
Sales (3) -- -- -- -- -- (3) (9) (12)
Improved recovery 7 1 15 -- 3 -- 26 72 98
Extensions and discoveries 58 277 174 18 191 2 720 -- 720
Production (213) (96) (232) (112) (119) (18) (790) (102) (892)
--------------------------------------------------------------------------------------
December 31, 1999 2,749 1,355 1,761 715 2,024 700 9,304 1,956 11,260
Revisions 410 9 25 29 50 24 547 33 580
Purchases -- -- -- -- -- -- -- -- --
Sales (1) (5) -- -- -- -- (6) -- (6)
Improved recovery 40 34 20 -- 3 -- 97 26 123
Extensions and discoveries 8 33 5 39 425 4 514 3 517
Production (220) (96) (253) (93) (118) (26) (806) (107) (913)
--------------------------------------------------------------------------------------
December 31, 2000 2,986 1,330 1,558 690 2,384 702 9,650 1,911 11,561
Revisions 89 (9) 68 (1) 94 15 256 8 264
Purchases -- -- -- -- -- -- -- -- --
Sales (6) -- -- -- -- -- (6) (3) (9)
Improved recovery 57 5 5 -- 34 -- 101 20 121
Extensions and discoveries 112 53 79 23 74 -- 341 112 453
Production (210) (102) (234) (90) (125) (29) (790) (109) (899)
--------------------------------------------------------------------------------------
December 31, 2001 3,028 1,277 1,476 622 2,461 688 9,552 1,939 11,491
Developed reserves, included above
At December 31, 1999 2,383 608 1,086 615 1,048 186 5,926 1,333 7,259
At December 31, 2000 2,661 630 978 504 989 245 6,007 1,331 7,338
At December 31, 2001 2,567 593 881 477 1,022 232 5,772 1,440 7,212
59
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
Net proved developed reserves are those volumes which are expected to be
recovered through existing wells with existing equipment and operating methods.
Undeveloped reserves are those volumes which are expected to be recovered as a
result of future investments to drill new wells, to recomplete existing wells
and/or to install facilities to collect and deliver the production from existing
and future wells.
Reserves attributable to certain oil and gas discoveries were not
considered proved as of year-end 2001 due to geological, technological or
economic uncertainties and therefore are not included in the tabulation.
Crude oil and natural gas liquids and natural gas production quantities
shown are the net volumes withdrawn from ExxonMobil's oil and gas reserves. The
natural gas quantities differ from the quantities of gas delivered for sale by
the producing function as reported on page 62 due to volumes consumed or flared
and inventory changes. Such quantities amounted to approximately 391 billion
cubic feet in 1999, 392 billion cubic feet in 2000 and 406 billion cubic feet in
2001.
Consolidated Subsidiaries
-------------------------------------------------------------
Non-
United Consolidated Total
Natural Gas States Canada Europe Asia-Pacific Africa Other Total Interests Worldwide
------------------------------------------------------------------------------------------------------------------------------------
(billions of cubic feet)
Net proved developed and undeveloped reserves
January 1, 1999 13,057 3,489 11,401 9,998 113 615 38,673 19,333 58,006
Revisions 781 31 680 131 -- 42 1,665 142 1,807
Purchases -- -- -- -- -- -- -- -- --
Sales (18) (1) -- -- -- -- (19) -- (19)
Improved recovery 2 14 105 -- -- -- 121 161 282
Extensions and discoveries 305 207 192 44 58 6 812 61 873
Production (1,126) (353) (1,150) (815) -- (55) (3,499) (654) (4,153)
--------------------------------------------------------------------------------------
December 31, 1999 13,001 3,387 11,228 9,358 171 608 37,753 19,043 56,796
Revisions 987 69 970 (113) 147 62 2,122 85 2,207
Purchases -- 10 -- -- -- -- 10 -- 10
Sales (3) (5) -- -- -- -- (8) -- (8)
Improved recovery 22 24 46 -- -- 24 116 50 166
Extensions and discoveries 195 430 96 11 70 26 828 45 873
Production (1,157) (399) (1,170) (710) (13) (53) (3,502) (676) (4,178)
--------------------------------------------------------------------------------------
December 31, 2000 13,045 3,516 11,170 8,546 375 667 37,319 18,547 55,866
Revisions 612 (51) 564 (198) 8 (5) 930 (94) 836
Purchases -- 1 -- -- -- -- 1 -- 1
Sales (57) -- (2) (8) -- -- (67) (2) (69)
Improved recovery 4 15 11 -- 2 -- 32 7 39
Extensions and discoveries 242 120 360 590 8 120 1,440 1,991 3,431
Production (1,114) (418) (1,172) (629) (14) (54) (3,401) (757) (4,158)
--------------------------------------------------------------------------------------
December 31, 2001 12,732 3,183 10,931 8,301 379 728 36,254 19,692 55,946
Developed reserves, included above
At December 31, 1999 10,820 2,475 7,764 6,471 2 426 27,958 8,643 36,601
At December 31, 2000 10,956 2,850 8,222 6,300 125 477 28,930 9,087 38,017
At December 31, 2001 10,366 2,517 7,824 6,005 122 404 27,238 8,784 36,022
====================================================================================================================================
INFORMATION ON CANADIAN TAR SANDS PROVEN RESERVES NOT INCLUDED ABOVE
In addition to conventional liquids and natural gas proved reserves, ExxonMobil
has significant interests in proven tar sands reserves in Canada associated with
the Syncrude project. For internal management purposes, ExxonMobil views these
reserves and their development as an integral part of total Upstream operations.
However, U.S. Securities and Exchange Commission regulations define these
reserves as mining related and not a part of conventional oil and gas reserves.
The tar sands reserves are not considered in the standardized measure of
discounted future cash flows for conventional oil and gas reserves, which is
found on page 61.
Tar Sands Reserves Canada
--------------------------------------------------------
(millions of barrels)
At December 31, 1999 577
At December 31, 2000 610
At December 31, 2001 821
60
Standardized Measure of Discounted Future Cash Flows
As required by the Financial Accounting Standards Board, the standardized
measure of discounted future net cash flows is computed by applying year-end
prices, costs and legislated tax rates and a discount factor of 10 percent to
net proved reserves. The corporation believes the standardized measure is not
meaningful and may be misleading, due to a number of factors, including
significant variability in cash flows due to changes in year-end prices.
Consolidated Subsidiaries
-------------------------------------------------------------
Non-
United Asia- Consolidated Total
States Canada Europe Pacific Africa Other Total Interests Worldwide
------------------------------------------------------------------------------------------------------------------------------------
(millions of dollars)
As of December 31, 1999
Future cash inflows from sales of oil and gas $ 82,674 $29,360 $64,192 $34,771 $49,247 $13,780 $274,024 $94,767 $368,791
Future production costs 21,219 6,618 13,660 9,754 11,784 2,548 65,583 33,006 98,589
Future development costs 4,131 2,116 4,904 3,516 4,779 605 20,051 3,104 23,155
Future income tax expenses 20,103 8,096 23,396 7,680 20,405 2,493 82,173 26,573 108,746
-----------------------------------------------------------------------------------
Future net cash flows $ 37,221 $12,530 $22,232 $13,821 $12,279 $ 8,134 $106,217 $32,084 $138,301
Effect of discounting net cash flows at 10% 20,139 5,884 7,351 5,918 6,275 4,694 50,261 19,473 69,734
-----------------------------------------------------------------------------------
Discounted future net cash flows $ 17,082 $ 6,646 $14,881 $ 7,903 $ 6,004 $ 3,440 $ 55,956 $12,611 $ 68,567
===================================================================================
As of December 31, 2000
Future cash inflows from sales of oil and gas $177,178 $41,275 $70,208 $34,658 $52,651 $10,317 $386,287 $93,597 $479,884
Future production costs 26,417 7,857 15,979 9,977 10,953 3,467 74,650 38,011 112,661
Future development costs 3,977 2,806 5,552 3,405 7,516 798 24,054 3,901 27,955
Future income tax expenses 55,192 12,731 26,078 7,382 18,949 1,830 122,162 21,333 143,495
-----------------------------------------------------------------------------------
Future net cash flows $ 91,592 $17,881 $22,599 $13,894 $15,233 $ 4,222 $165,421 $30,352 $195,773
Effect of discounting net cash flows at 10% 48,876 6,795 7,779 5,638 8,158 2,450 79,696 18,825 98,521
-----------------------------------------------------------------------------------
Discounted future net cash flows $ 42,716 $11,086 $14,820 $ 8,256 $ 7,075 $ 1,772 $ 85,725 $11,527 $ 97,252
===================================================================================
As of December 31, 2001
Future cash inflows from sales of oil and gas $ 68,713 $19,573 $58,394 $24,452 $42,806 $10,370 $224,308 $87,828 $312,136
Future production costs 20,008 6,711 15,807 7,801 10,341 3,217 63,885 31,839 95,724
Future development costs 4,613 2,695 5,252 3,262 7,839 831 24,492 3,043 27,535
Future income tax expenses 16,620 3,908 17,416 4,325 13,485 2,091 57,845 22,046 79,891
-----------------------------------------------------------------------------------
Future net cash flows $ 27,472 $ 6,259 $19,919 $ 9,064 $11,141 $ 4,231 $ 78,086 $30,900 $108,986
Effect of discounting net cash flows at 10% 15,065 2,377 7,338 3,552 6,087 2,553 36,972 18,766 55,738
-----------------------------------------------------------------------------------
Discounted future net cash flows $ 12,407 $ 3,882 $12,581 $ 5,512 $ 5,054 $ 1,678 $ 41,114 $12,134 $ 53,248
===================================================================================
Change in Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil and Gas Reserves
Consolidated Subsidiaries 2001 2000 1999
------------------------------------------------------------------------------------------------------------------------------------
(millions of dollars)
Value of reserves added during the year due to extensions, discoveries, improved recovery
and net purchases less related costs $ 2,660 $ 6,029 $ 4,245
Changes in value of previous-year reserves due to:
Sales and transfers of oil and gas produced during the year, net of production (lifting) costs (20,748) (24,498) (13,395)
Development costs incurred during the year 5,577 4,194 5,313
Net change in prices, lifting and development costs (79,693) 44,702 59,466
Revisions of previous reserves estimates 2,520 12,537 3,106
Accretion of discount 12,293 7,694 3,056
Net change in income taxes 32,780 (20,889) (30,833)
--------------------------------
Total change in the standardized measure during the year $ (44,611) $ 29,769 $ 30,958
================================
61
OPERATING SUMMARY
2001 2000 1999 1998 1997
-------------------------------------------------------------------------------------------------------------------------------
(thousands of barrels daily)
Production of crude oil and natural gas liquids
Net production
United States 712 733 729 745 803
Canada 331 304 315 322 287
Europe 653 704 650 635 641
Asia-Pacific 247 253 307 322 347
Africa 342 323 326 301 294
Other Non-U.S. 257 236 190 177 155
------------------------------------------------------------------
Worldwide 2,542 2,553 2,517 2,502 2,527
==================================================================
(millions of cubic feet daily)
Natural gas production available for sale
Net production
United States 2,598 2,856 2,871 3,140 3,223
Canada 1,006 844 683 667 600
Europe 4,595 4,463 4,438 4,245 4,283
Asia-Pacific 1,547 1,755 2,027 2,352 2,632
Other Non-U.S. 533 425 289 213 156
------------------------------------------------------------------
Worldwide 10,279 10,343 10,308 10,617 10,894
==================================================================
(thousands of barrels daily)
Refinery throughput
United States 1,840 1,862 1,930 1,919 2,026
Canada 449 451 441 445 448
Europe 1,563 1,578 1,782 1,888 1,899
Asia-Pacific 1,436 1,462 1,537 1,554 1,559
Other Non-U.S. 283 289 287 287 302
------------------------------------------------------------------
Worldwide 5,571 5,642 5,977 6,093 6,234
==================================================================
Petroleum product sales
United States 2,751 2,669 2,918 2,804 2,777
Canada 585 577 587 579 574
Europe 2,079 2,129 2,597 2,646 2,609
Asia-Pacific and other Eastern Hemisphere 2,024 2,090 2,223 2,266 2,249
Latin America 532 528 562 578 564
------------------------------------------------------------------
Worldwide 7,971 7,993 8,887 8,873 8,773
==================================================================
Gasoline, naphthas 3,165 3,122 3,428 3,417 3,317
Heating oils, kerosene, diesel oils 2,389 2,373 2,658 2,689 2,725
Aviation fuels 721 749 813 774 753
Heavy fuels 668 694 706 765 744
Specialty petroleum products 1,028 1,055 1,282 1,228 1,234
------------------------------------------------------------------
Worldwide 7,971 7,993 8,887 8,873 8,773
==================================================================
(thousands of metric tons)
Chemical prime product sales 25,780 25,637 25,283 23,628 23,838
==================================================================
(millions of metric tons)
Coal production 13 17 17 15 15
==================================================================
(thousands of metric tons)
Copper production 252 254 248 216 205
==================================================================
Operating statistics include 100 percent of operations of majority owned
subsidiaries; for other companies, crude production, gas, petroleum product and
chemical prime product sales include ExxonMobil's ownership percentage, and
refining throughput includes quantities processed for ExxonMobil. Net production
excludes royalties and quantities due others when produced, whether payment is
made in kind or cash.
62
SIGNATURES
Pursuant to the requirements of Section 13 of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its behalf by
the undersigned, thereunto duly authorized.
EXXON MOBIL CORPORATION
By: /s/ LEE R. RAYMOND
----------------------------------
(Lee R. Raymond,
Chairman of the Board)
Dated March 27, 2002
-----------------
POWER OF ATTORNEY
Each person whose signature appears below constitutes and appoints Richard
E. Gutman, Paul A. Hanson and Brian A. Maher, and each of them, his or her true
and lawful attorneys-in-fact and agents, with full power of substitution and
resubstitution, for him or her and in his or her name, place and stead, in any
and all capacities, to sign any and all amendments to this Annual Report on
Form 10-K, and to file the same, with all exhibits thereto, and other documents
in connection therewith, with the Securities and Exchange Commission, granting
unto said attorneys-in-fact and agents, and each of them, full power and
authority to do and perform each and every act and thing requisite and
necessary to be done, as fully to all intents and purposes as he or she might
or could do in person, hereby ratifying and confirming all that said
attorneys-in-fact and agents or any of them, or their or his or her substitute
or substitutes, may lawfully do or cause to be done by virtue hereof.
-----------------
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
/s/ LEE R. RAYMOND Chairman of the Board March 27, 2002
_____________________________ (Principal Executive Officer)
(Lee R. Raymond)
/s/ MICHAEL J. BOSKIN Director March 27, 2002
___________________________
(Michael J. Boskin)
/s/ RENE DAHAN Director March 27, 2002
_____________________________
(Rene Dahan)
63
/s/ WILLIAM T. ESREY Director March 27, 2002
_____________________________
(William T. Esrey)
/s/ DONALD V. FITES Director March 27, 2002
_____________________________
(Donald V. Fites)
/s/ JAMES R. HOUGHTON Director March 27, 2002
_____________________________
(James R. Houghton)
/s/ WILLIAM R. HOWELL Director March 27, 2002
_____________________________
(William R. Howell)
/s/ HELENE L. KAPLAN Director March 27, 2002
_____________________________
(Helene L. Kaplan)
/s/ REATHA CLARK KING Director March 27, 2002
_____________________________
(Reatha Clark King)
/s/ PHILIP E. LIPPINCOTT Director March 27, 2002
_____________________________
(Philip E. Lippincott)
/s/ HARRY J. LONGWELL Director March 27, 2002
_____________________________
(Harry J. Longwell)
/s/ MARILYN CARLSON NELSON Director March 27, 2002
_____________________________
(Marilyn Carlson Nelson)
64
/s/ WALTER V. SHIPLEY Director March 27, 2002
_____________________________
(Walter V. Shipley)
/s/ DONALD D. HUMPHREYS Controller March 27, 2002
_____________________________ (Principal Accounting Officer)
(Donald D. Humphreys)
/s/ FRANK A. RISCH Treasurer March 27, 2002
_____________________________ (Principal Financial Officer)
(Frank A. Risch)
65
INDEX TO EXHIBITS
3(i). Restated Certificate of Incorporation, as restated November 30, 1999, and as further
amended effective June 20, 2001 (incorporated by reference to Exhibit 3(i) to the
registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001).
3(ii). By-Laws, as revised to November 30, 1999 (incorporated by reference to Exhibit 3(ii) to
the registrant's Annual Report on Form 10-K for 1999).
10(iii)(a). 1993 Incentive Program, as amended (incorporated by reference to Exhibit 10(iii)(a) of
the registrant's Annual Report on Form 10-K for 1999).*
10(iii)(b). 2001 Nonemployee Directors' Deferred Compensation Plan (incorporated by reference to
Exhibit 10(iii)(b) to the registrant's Annual Report on Form 10-K for 2000).*
10(iii)(c). Restricted Stock Plan for Nonemployee Directors, as amended.*
10(iii)(d). ExxonMobil Executive Life Insurance and Death Benefit Plan (incorporated by reference
to Exhibit 10(iii)(d) to the registrant's Annual Report on Form 10-K for 1999).*
10(iii)(e). Short Term Incentive Program, as amended (incorporated by reference to Exhibit
10(iii)(e) to the registrant's Annual Report on Form 10-K for 1999).*
10(iii)(f). 1997 Nonemployee Director Restricted Stock Plan (incorporated by reference to Exhibit
10(iii)(f) to the registrant's Quarterly Report on Form 10-Q for the quarter ended
September 30, 2000).*
10(iii)(g). 1995 Mobil Incentive Compensation and Stock Ownership Plan (incorporated by
reference to Exhibit 10(iii)(g) to the registrant's Annual Report on Form 10-K for
2000).*
10(iii)(i). Supplemental Employees Savings Plan of Mobil Oil Corporation (incorporated by
reference to Exhibit 10.5 to the Annual Report on Form 10-K of Mobil Corporation
filed March 31, 1999).*
12. Computation of ratio of earnings to fixed charges.
21. Subsidiaries of the registrant.
23. Consent of PricewaterhouseCoopers LLP, Independent Accountants.
--------
* Compensatory plan or arrangement required to be identified pursuant to Item
14(a)(3) of this Annual Report on Form 10-K.
The registrant has not filed with this report copies of the instruments
defining the rights of holders of long-term debt of the registrant and its
subsidiaries for which consolidated or unconsolidated financial statements are
required to be filed. The registrant agrees to furnish a copy of any such
instrument to the Securities and Exchange Commission upon request.
66