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2001
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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 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 U