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                UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                    FORM 10-K

              ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                         SECURITIES EXCHANGE ACT OF 1934

                   FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000

                         COMMISSION FILE NUMBER 1-14521

                                   CONOCO INC.
             (Exact name of registrant as specified in its charter)

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                     DELAWARE                                                      51-0370352
         (State or other jurisdiction of                                        (I.R.S. employer
         incorporation or organization)                                         identification No.)
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                          600 NORTH DAIRY ASHFORD ROAD
                              HOUSTON, TEXAS 77079
                    (Address of principal executive offices)

        Registrant's telephone number, including area code: 281-293-1000

                                   ----------

           Securities registered pursuant to Section 12(b) of the Act:

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          TITLE OF EACH CLASS                                                 NAME OF EACH EXCHANGE ON WHICH REGISTERED
-------------------------------------                                         -----------------------------------------
Class A common stock ($.01 par value)                                               New York Stock Exchange, Inc.
Class B common stock ($.01 par value)                                               New York Stock Exchange, Inc.
Preferred share purchase rights                                                     New York Stock Exchange, Inc.
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        Securities registered pursuant to Section 12(g) of the Act: NONE

Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes   [X]     No   [ ]

         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. [ ]

         Aggregate market value of voting Class A and Class B common stock held
by nonaffiliates of the registrant (excludes outstanding shares beneficially
owned by directors and officers) as of March 1, 2001, was approximately $5,154
million and $13,099 million based on the closing price on that date of $29.22
and $29.97, on the New York Stock Exchange, Inc. As of such date, 187,057,029
shares of Class A common stock, $.01 par value, and 437,316,095 shares of
Class B common stock, $.01 par value, were outstanding.

                       DOCUMENTS INCORPORATED BY REFERENCE
                        (to the extent indicated herein)

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                                                                                                INCORPORATED BY
                                                                                            (REFERENCE IN PART NO.)
                                                                                            -----------------------
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             Portions of the registrant's proxy statement for the annual meeting                      III
             of stockholders to be held on May 8, 2001
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                                   CONOCO INC.

     Unless the context otherwise indicates, references in this Form 10-K to
"Conoco," "we," or "us" are references to Conoco Inc., its wholly owned and
majority owned subsidiaries, and its ownership interest in equity affiliates
(corporate entities, partnerships, limited liability companies and other
ventures, in which Conoco exerts significant influence by virtue of its
ownership interest, typically between 20 and 50 percent).


                                TABLE OF CONTENTS


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                                                      PART I
                                                                                                               PAGE

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Items 1. and 2.    Business and Properties................................................................       1
Item 3.            Legal Proceedings......................................................................      32
Item 4.            Submission of Matters to a Vote of Security Holders....................................      33
                   Executive Officers of the Registrant...................................................      33

                                                      PART II

Item 5.            Market for Registrant's Common Equity and Related Stockholder Matters..................      35
Item 6.            Selected Financial Data................................................................      36
Item 7.            Management's Discussion and Analysis of Financial Condition and Results of
                   Operations.............................................................................      37
Item 7A.           Quantitative and Qualitative Disclosures About Market Risk.............................      58
Item 8.            Financial Statements and Supplementary Data............................................      60
Item 9.            Changes in and Disagreements with Accountants on Accounting and Financial
                   Disclosure.............................................................................     106

                                                     PART III

Item 10.           Directors and Executive Officers of the Registrant.....................................     106
Item 11.           Executive Compensation.................................................................     106
Item 12.           Security Ownership of Certain Beneficial Owners and Management.........................     106
Item 13.           Certain Relationships and Related Transactions.........................................     106

                                                      PART IV

Item 14.           Exhibits, Financial Statement Schedules, and Reports on Form 8-K.......................     106
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                                     PART I

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

DISCLOSURE REGARDING FORWARD-LOOKING INFORMATION

     This annual report on Form 10-K includes forward-looking statements within
the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934. You can identify our forward-looking statements
by the words "expects," "intends," "plans," "projects," "believes," "estimates"
and similar expressions.

     We have based the forward-looking statements relating to our operations on
our current expectations, estimates and projections about Conoco and the
petroleum industry in general. We caution you that these statements are not
guarantees of future performance and involve risks and uncertainties that we
cannot predict. In addition, we have based many of these forward-looking
statements on assumptions about future events that may prove to be inaccurate.
Accordingly, our actual outcomes and results may differ materially from what we
have expressed or forecasted in the forward-looking statements. Any differences
could result from a variety of factors, including the following:

     o    fluctuations in crude oil and natural gas prices as well as refining
          and marketing margins;

     o    potential failure or delays in achieving expected reserve or
          production levels from existing and future oil and gas development
          projects due to operating hazards, drilling risks and the inherent
          uncertainties in predicting oil and gas reserves and oil and gas
          reservoir performance;

     o    unsuccessful exploratory drilling activities;

     o    failure of new products and services to achieve market acceptance;

     o    unexpected cost increases or technical difficulties in constructing or
          modifying company manufacturing and refining facilities;

     o    unexpected difficulties in manufacturing, transporting or refining
          synthetic crude oil;

     o    ability to meet government regulations;

     o    potential disruption or interruption of our production facilities due
          to accidents or political events;

     o    international monetary conditions and exchange controls;

     o    liability for remedial actions under environmental regulations;

     o    liability resulting from litigation;

     o    general domestic and international economic and political conditions;
          and

     o    changes in tax and other laws applicable to our business.

GENERAL

     Conoco, a major, integrated, global energy company, has three operating
segments: upstream, downstream and emerging businesses. Upstream activities
include exploring for, developing, producing and selling crude oil, natural gas
and natural gas liquids. Downstream activities include refining crude oil and
other feedstocks into petroleum products; buying and selling crude oil and
refined products; and transporting, distributing and marketing petroleum
products. Emerging businesses activities include the development of new
businesses beyond our traditional operations with the potential to contribute
substantially to long-term growth. Conoco operates in over 40 countries
worldwide.

     As of December 31, 2000, Conoco had proved worldwide reserves of 2,647
million barrels-of-oil-equivalent (BOE), 38 percent of which were natural gas.
In this document, natural gas volumes have been converted to BOE using a ratio
of six thousand cubic feet (mcf) of natural gas to one barrel of oil. Based on
2000 annual production of 240 million BOE, excluding natural gas liquids from
gas plant ownership, Conoco had a reserve life of 11 years as of December 31,
2000. Over the last five years, Conoco has replaced an average of 176 percent of
the oil and gas it has produced each year. As of December 31, 2000, Conoco owned





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or had equity interests in nine refineries worldwide, with a total crude
distillation capacity of approximately 904,000 barrels per day. Conoco had a
marketing network of approximately 8,100 outlets in the United States, Europe
and Asia Pacific. For the year ended December 31, 2000, Conoco reported net
income of $1,902 million, which included a net charge of $46 million for special
items, on total revenues of $39,287 million.

BUSINESS STRATEGY

     Our vision is to be recognized around the world as a truly great,
integrated, international, energy company that gets to the future first. To
attain this vision, we will pursue an integrated, growth oriented business
strategy, with our different businesses working together to create a more
economically diverse and value-adding product line to meet the needs of partners
and customers.

     Upstream is focused on maintaining consistent, profitable growth, and is
aggressively pursuing high-potential opportunities worldwide.

     Downstream is focused on generating a competitive return on investment and
surplus cash to support Conoco's global growth initiatives, while selectively
expanding refining and marketing operations in high-growth markets, including
Asia Pacific and central and eastern Europe.

     The three emerging businesses we are developing, carbon fibers, natural gas
refining (which includes our gas-to-liquids technology) and power generation,
will take Conoco beyond our traditional operations and offer tremendous growth
potential. All three of these emerging businesses are built on our core
businesses, which is a compelling strategic advantage.

     Conoco's major operations are in three core areas, North America, western
Europe and northern South America, which was officially designated as a core
area in 2000. We will continue to improve the profitability, efficiency and
effectiveness of existing operations while pursuing opportunities in Asia
Pacific, the Middle East, the Caspian Sea region, Russia and West Africa.

     In all of our activities, we will strive to act in accordance with our core
values of operating safely, protecting the environment, acting ethically and
valuing all people.

FINANCIAL INFORMATION - OPERATING SEGMENT AND GEOGRAPHIC INFORMATION

     For operating segment and geographic information, see note 27 to the
consolidated financial statements.

UPSTREAM

   SUMMARY

     Conoco is currently exploring for, developing or producing crude oil,
natural gas and natural gas liquids in 23 countries around the world. In 2000,
production averaged 654,000 BOE per day, consisting of 370,000 barrels per day
of petroleum liquids, excluding natural gas liquids from gas plant ownership,
and 1,705 million cubic feet of natural gas per day. The majority of this
production came from fields located in the U.S., the U.K. and Norway, with the
remaining production coming from operations in Canada, the United Arab Emirates,
Indonesia, Vietnam, Nigeria, Russia and Venezuela.

     In 2000, Conoco replaced 139 percent of the oil and natural gas it
produced, adding 333 million BOE to its worldwide reserves for a net increase of
93 million BOE after producing 240 million BOE, excluding natural gas liquids
from gas plant ownership. We replaced 179 percent of the oil and 86 percent of
the natural gas we produced. On December 31, 2000, we had proved reserves of
2,647 million BOE, consisting of 1,638 million barrels of petroleum liquids and
6,053 billion cubic feet of natural gas.

     Conoco's capital investment in upstream activities in 2000 was $2,153
million, including the continued development of the South Texas Lobo trend,
several North Sea fields, and properties in Canada, the West Natuna Sea in
Indonesia and Petrozuata in Venezuela, as well as the acquisition of gas
processing facilities in Canada and the U.S. and additional producing properties
and acreage in the U.K. and Vietnam. These projects





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will contribute to Conoco's 2001 production and are expected to increase
Conoco's production rates over current levels in future years.

     The majority of Conoco's producing assets are located in North America,
northern South America and western Europe. Most of these producing properties
will generate cash to fund growth opportunities around the world. Outside of
these areas, Conoco's activities are focused on areas that have the potential to
become major business areas in the future, such as southeast Asia (which is
expected to become Conoco's fourth core area), West Africa, the Caspian Sea
region, the Middle East and Russia.

     Conoco is exploring for oil and/or natural gas in 20 countries. Since 1996,
Conoco has acquired significant acreage positions in the following regions:

     o    the deepwater Gulf of Mexico;

     o    the Atlantic Margin of northwest Europe;

     o    northern South America and the Caribbean;

     o    selected basins in southeast Asia; and

     o    the Caspian Sea.

In 2000, Conoco's exploration performance was excellent, as in 1998 and 1999. In
2000, Conoco participated in nine discoveries and four appraisal wells that were
potentially commercial, achieving a 36 percent success rate for wildcat wells
and an 80 percent success rate for appraisal drilling. Significant gas and oil
finds were made in the deepwater Gulf of Mexico, Vietnam and the North Sea.

     Conoco intends to manage its asset portfolio to increase the proportion of
upstream assets relative to downstream assets and the proportion of large-scale,
long-lived, early-life cycle assets relative to mature assets. In the course of
implementing this strategy, we may from time to time in the future, as we have
in the past, purchase or sell producing upstream assets. We may also consider
forming alliances or joint ventures to hold and operate selected upstream
assets, either to optimize the efficiency of such operations through achieving
economies of scale or, in certain circumstances, to monetize a portion of the
value of such assets.

     UNITED STATES

     Production operations in the U.S. are principally located in the following
     areas:

     o    the Lobo trend in South Texas;

     o    the Gulf of Mexico;

     o    the San Juan Basin in New Mexico;

     o    the Permian Basin in west Texas; and

     o    the central Appalachian Basin in Virginia.

     In 2000, U.S. operations contributed approximately 21 percent of Conoco's
worldwide petroleum liquids production and 48 percent of its worldwide natural
gas production. U.S. proved reserves as of December 31, 2000, were 645 million
BOE, consisting of 249 million barrels of petroleum liquids and 2,378 billion
cubic feet of natural gas.

     Conoco's current objectives in the U.S. are to increase production from the
deepwater Gulf of Mexico, while maintaining production from other U.S. assets
and optimizing our natural gas processing capabilities.

     Lobo Trend in South Texas

     Conoco is the largest natural gas producer in the Lobo trend, and a leading
producer, marketer and transporter of natural gas in South Texas. Conoco has
over 20 years of operating and drilling experience in the Lobo trend and
currently holds approximately 450,000 acres in the area under oil and gas
leases. In December 2000, our gross natural gas production was approximately 625
million cubic feet per day. Conoco's 2000 development program included the
acquisition of new 3D seismic data and the drilling of 164 wells. We anticipate
spending $675 million between 2001 and 2003 to further develop our leases in the
Lobo trend.



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     Conoco's average working interest in its leases in the Lobo trend is 93
percent. Certain producing wells are subject to volumetric production payments,
the last of which terminate in 2002. These volumetric production payments
averaged approximately 53 million cubic feet per day in 2000.

     Lobo Pipeline Company, a wholly owned subsidiary of Conoco, owns a 1,268
mile intrastate natural gas pipeline system in South Texas, which is designed to
provide transportation for our gas production and that of third party producers.

     Gulf of Mexico

     Conoco's current portfolio of producing properties in the Gulf of Mexico
includes six fields operated by Conoco and 12 operated by other companies. The
properties are in various stages of development, ranging from properties that
are fully developed to ones with considerable additional development potential.
We also hold interests in various offshore platforms, pipelines and other
infrastructure.

     Conoco currently has 13 leases in production or under development in the
deepwater Gulf of Mexico. A recent and important development project in the Gulf
of Mexico is our Ursa field. Ursa, operated by Shell, is one of the largest
discoveries to date in the deepwater Gulf of Mexico. We hold a 16 percent
interest in the field, and the other owners are Shell, BP Amoco and ExxonMobil.
The Ursa tension leg platform was installed in late 1998 in approximately 3,900
feet of water, with first production occurring in March 1999. In 2000, the Ursa
field achieved gross daily production of over 110,000 barrels of petroleum
liquids and 225 million cubic feet of gas. Ursa has platform capacity of 150,000
barrels per day of petroleum liquids and 400 million cubic feet of gas per day
and is expected to reach peak production in 2002.

     The Princess field, which is adjacent to the Ursa field, was discovered in
2000. Because of Princess' proximity to Ursa, petroleum liquids and natural gas
produced from Princess may be processed and transported via the Ursa
infrastructure already in place. Conoco owns a 16 percent interest in Princess
with the remainder of the field owned by Conoco's partners in Ursa. Development
should be expedited by the alignment of interests.

     Also in 2000, Conoco drilled several appraisal wells further delineating
the extent and commerciality of the Magnolia discovery. The discovery was
confirmed to be commercial. Conoco operates and holds a 75 percent interest in
the Garden Banks 783 and 784 leases that comprise the field. Additional
appraisal operations will be conducted in 2001 prior to commencement of the
development program for Magnolia.

     In addition to the Princess and Magnolia successes, Conoco is continuing
its exploration program in the deepwater Gulf of Mexico. We hold interests in
291 leases. We have a 100 percent interest in 100 of these leases, and jointly
own 76 of the remaining leases on a 50/50 basis with Shell and 41 of the
remaining leases on a 50/50 basis with ExxonMobil. Since 1996, we have acquired
3D seismic data over large portions of the deepwater Gulf of Mexico to identify
acreage to lease and to select prospects for drilling. In 2001, we expect to
participate in three to five wildcat exploration wells with working interests
averaging between 20 and 50 percent.

     Conoco is carrying out its deepwater Gulf of Mexico drilling program in
large part with the Deepwater Pathfinder, a highly sophisticated drillship,
which is owned by a joint venture between Transocean Sedco Forex Inc. and
Conoco. The vessel, which went into service in January 1999, is capable of
drilling in water depths of up to 10,000 feet and provides us with the ability
to explore in areas that were previously inaccessible.

     Other U.S. Producing Properties

     Outside of South Texas and the Gulf of Mexico, Conoco's largest producing
properties in the U.S. are located in the San Juan Basin in New Mexico, the
Permian Basin in west Texas and the central Appalachian Basin in Virginia. We
also have producing properties in the Williston Basin of North Dakota and the
Hugoton complex in the Oklahoma/Texas Panhandle.

     Conoco has a significant acreage position in the San Juan Basin. Our
average daily net production from the San Juan Basin in 2000 was approximately
11,000 barrels of petroleum liquids and 200 million cubic feet of natural gas.




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     Conoco has an interest in 26 fields in the Permian Basin, which is one of
the largest producing areas in the U.S. In the Permian Basin, our average daily
net production in 2000 was approximately 21,600 barrels of petroleum liquids and
43 million cubic feet of natural gas. We are using 3D seismic technology,
horizontal wells and other innovative extraction technologies in an effort to
extend the productive life of many of the mature fields in the Permian Basin.

     Pocahontas Gas Partnership is a 50/50 partnership between Conoco and Consol
Energy Inc. Pocahontas produces and gathers coal bed methane prior to and during
coal mining operations in Virginia. Pocahontas produced and gathered
approximately 42 million gross cubic feet per day of coal bed methane from the
existing active mining and expansion areas in 2000. Pocahontas drilled more than
80 wells in 2000, with the majority of the wells being drilled in an expansion
area. Pocahontas will continue to focus on developmental drilling in 2001.

     Natural Gas and Gas Products

     As of December 31, 2000, Conoco owned interests in 15 natural gas
processing plants located in Louisiana, New Mexico and Texas, as well as
approximately 6,000 miles of gathering lines. We operate 11 of the plants.

     Conoco gathers natural gas, extracts natural gas liquids and sells the
remaining residual gas. Most of our raw gas liquids are supplied to our
fractionation operations, which further separate them into natural gas liquids
products that are used as feedstocks for gasoline and chemicals production.
Conoco provides service to approximately 430 natural gas producers and sells
more than 470 million cubic feet per day of residue gas to approximately 160
customers.

     Conoco Gas & Power Marketing was established in 2000 by combining the
marketing activities of our natural gas and power businesses. We offer
sophisticated, customer-driven energy solutions, with services including joint
gas and power procurement, as well as storage, transportation, ancillary
services and risk management. The utilization of Conoco's significant natural
gas assets is a competitive advantage that enables us to provide commercial and
industrial customers with reliable fuel supplies at attractive prices. During
2000, Conoco marketed and traded 7.5 billion cubic feet of natural gas per day
in the U.S.

     Conoco's share of total natural gas liquids extracted from natural gas
processed averaged 61,900 barrels per day in 2000. Approximately 10,300 barrels
per day of natural gas liquids were from Conoco owned reserves that were
reported, net of royalties, as U.S. natural gas liquids production. In 2000,
approximately 19,600 barrels per day of additional natural gas liquids were
attributable to the processing of Conoco's natural gas liquids in third
party-operated plants.

     Conoco's natural gas and gas products facilities in the U.S. include:

     o    an 800-mile intrastate natural gas pipeline system in Louisiana
          operated by Conoco's wholly owned subsidiary, Louisiana Gas System,
          Inc.;

     o    natural gas and natural gas liquids pipelines in several states;

     o    an underground gas storage facility in New Mexico;

     o    an underground natural gas liquids storage facility in each of Texas
          and Louisiana;

     o    a natural gas liquids fractionating plant in Gallup, New Mexico with a
          capacity of 25,000 barrels per day; and

     o    a 22.5 percent equity interest in Gulf Coast Fractionators, which owns
          a natural gas liquids fractionating plant in Mt. Belvieu, Texas with a
          capacity of 104,000 barrels per day.

     In March 2000, Conoco completed the sale of its Oklahoma natural gas
gathering and processing assets, consisting of 2,300 miles of natural gas
gathering pipelines and five natural gas processing plants to Duke Energy Field
Services. In October 2000, Conoco sold its 8 percent interest in Dixie Pipeline
Company to Enterprise Products Partners, L.P.




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     In June 2000, Conoco acquired various assets from Range Resources,
including the Conger gas plant in Sterling County, Texas, with a processing
capacity of 25 million cubic feet per day. Also included in the acquisition were
110 miles of pipeline and 15 million cubic feet per day of contracted inlet gas
supply.

     In December 2000, Conoco acquired the assets of LG&E Energy Corp., with
operations located in New Mexico, Oklahoma, Texas and Montana. The acquisition
included three natural gas processing plants in New Mexico and Texas, with a
combined processing capacity of 86 million cubic feet per day. The acquisition
also included a natural gas storage facility and 1,200 miles of natural gas
pipeline.

   CANADA

     In the foothills east of the Canadian Rockies, we have an interest in
approximately 400,000 net acres, much of which is yet to be developed. We began
production from eight discoveries in the foothills during the last half of the
1990s and made two additional discoveries in 2000. We believe additional
hydrocarbons lie beneath the current producing formations and are actively
exploring for new reserves. In addition to the discoveries in the foothills
trend, we have a significant interest in the Peco gas field, located just east
of the foothills. We also own the Peco gas processing plant that processes gas
from the Peco field and five of the foothills discoveries.

     Conoco doubled its Canadian natural gas production with its 1999
acquisition of producing assets and acreage from Renaissance Energy Ltd. Gross
production from the field averaged approximately 70 million cubic feet of
natural gas per day in 2000. Conoco took over field operations in April 2000,
and has since implemented a development drilling program.

     During 2000, Conoco acquired substantially all of Petro-Canada's natural
gas liquids business which included:

     o    a 92 percent operating interest in Petro-Canada's 2.4 billion cubic
          feet per day Empress natural gas processing straddle plant near
          Medicine Hat, Alberta with a NGL production capacity of 48,000 barrels
          per day;

     o    the 580-mile Petroleum Transmission Company pipeline, from Empress to
          Winnipeg and six related pipeline terminals;

     o    a storage facility;

     o    a 10 percent interest in the 1,902-mile Cochin LPG pipeline,
          originating in Edmonton, Alberta and ending in Sarnia, Ontario, and a
          terminal storage system that transports propane, ethane and ethylene;
          and

     o    an 18 percent interest in a 30,000 barrels per day propane-plus
          fractionator and a 5 percent interest in a 65-mile natural gas liquids
          pipeline with storage near Edmonton, Alberta.

For the 10 months of operation in 2000, the Empress plant produced an average of
39,700 barrels per day.

   WESTERN EUROPE

     Conoco has a significant portfolio of producing properties in the U.K. and
Norway. Proved reserves in western Europe as of December 31, 2000, were 938
million BOE, consisting of 465 million barrels of petroleum liquids and 2.8
trillion cubic feet of natural gas. In 2000, operations in western Europe
contributed 46 percent of our worldwide petroleum liquids production and 47
percent of our natural gas production.

     Britannia Field

     Conoco significantly strengthened its position in the Britannia natural gas
field during 2000 with the purchase of Saga U.K. Ltd. from Norske Hydro ASA. The
Saga U.K. acquisition enabled Conoco to increase its interests in the Britannia
gas field and the Alba oil field. Conoco is now the largest equity owner in both
Britannia and Alba with a 51 percent and a 23 percent interest, respectively.

     Britannia is the largest natural gas/condensate field in the U.K. sector of
the North Sea. First production from Britannia occurred in August 1998, and we
estimate that the field will have a production life of approximately 30 years.
Our proved reserves in Britannia include 1.1 trillion cubic feet of natural gas
and 53 million barrels of petroleum liquids at December 31, 2000. During 2000,
Britannia was able to produce at rates





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of up to 815 million gross cubic feet of gas per day and 41,000 gross barrels of
petroleum liquids per day by taking advantage of additional short-term capacity
at the onshore Sage gas terminal. The average annual production rate was 692
million gross cubic feet of gas per day and 37,000 gross barrels of petroleum
liquids per day.

     Southern North Sea Producing Properties

     Conoco has various ownership interests in 15 producing gas fields in the
southern North Sea, a major gas producing area on the U.K. continental shelf.
These fields mostly feed into the Conoco-operated Theddlethorpe gas processing
facility through three Conoco-operated pipeline systems: Viking, LOGGS and CMS.
In 2000, Conoco's net production from the southern North Sea was 402 million
cubic feet of natural gas per day.

     In 2000, we began production from several additional development
opportunities within the southern North Sea. The Vixen and Jupiter II field
developments were completed during 2000. Vixen was brought onstream in the
summer of 2000, less than 20 months after the discovery well was drilled and
only 11 months after project approval. CMS3, a large, multi-field development,
is another source of future production for Conoco in the southern North Sea.
First gas from this field, which will be produced via existing Conoco operated
infrastructure, is expected in 2002.

     Other United Kingdom Properties and Discoveries

     Conoco also has interests in the following fields and discoveries:

     o    Miller (30 percent);

     o    Statfjord (5 percent in the U.K. sector);

     o    MacCulloch (40 percent);

     o    Banff (32 percent);

     o    Clair (24 percent);

     o    Gryphon (25 percent - added through acquisition of Saga U.K.);

     o    Thistle Area (varying interests added through the acquisition of Saga
          U.K. averaging approximately 18 percent);

     o    21/3a (approximately 75 percent); and

     o    Kappa (approximately 83 percent).

     Conoco operates the MacCulloch and Banff fields, both of which employ
floating production, storage and offtake (FPSO) technology. The Banff FPSO is
currently undergoing upgrade work and it is anticipated to return to production
in the second quarter of 2001. Conoco also operates the 21/3a and Kappa
discoveries, both of which are in the greater Britannia area. Conoco drilled an
appraisal well showing potentially commercial hydrocarbons on each of the 21/3a
and Kappa discoveries in 2000. BP Amoco operates the Miller field, Thistle Area
and the Clair discovery, which is one of the largest undeveloped oil discoveries
in western Europe. The Gryphon field, which is operated by Kerr McGee, also
employs an FPSO.

     Interconnector Pipeline and Gas Sales

     The Interconnector pipeline, which connects the U.K. and Belgium,
facilitates the marketing throughout Europe of the natural gas Conoco produces
in the U.K. This pipeline commenced operation in October 1998. Conoco's 10
percent equity share of the Interconnector pipeline allows us to ship
approximately 200 million cubic feet of gas per day to markets in continental
Europe. We have five-to-eight-year contracts to supply natural gas to Gasunie in
the Netherlands and Wingas in Germany, which fully utilize this capacity.
Because the Interconnector pipeline provides flexibility to flow in either
direction, we are able to take advantage of the long-term and short-term market
conditions in both the U.K. and continental Europe.




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     Norway Properties

     Conoco has an ownership interest in three of the largest producing fields
in Norway: Heidrun, Statfjord and Troll. We also have an ownership interest in
the Visund (9.1 percent), Jotun (3.8 percent), Statfjord North Flank (9.4
percent) and Troll C (1.6 percent) developments, all of which began producing in
1999. In addition, we have interests in Oseberg South (7.7 percent), Sygna, a
Statfjord satellite, (6.6 percent), and Heidrun North Flank (18.3 percent), all
of which commenced production during 2000. Huldra (23.3 percent), a new
development in 2000, is scheduled to commence production during 2001.

     In 2000, Conoco agreed to acquire Statoil's 6.4 percent interest in the
Grane field for $60 million. Grane is located in the Norwegian North Sea and is
operated by Norske Hydro. We expect to finalize the acquisition in early 2001
and commence production in 2003.

     Production from the Heidrun field, in which we own an 18.3 percent
interest, began in 1995 and averaged approximately 191,000 gross barrels of
petroleum liquids per day during 2000. We were the operator for the construction
and installation of Heidrun's tension-leg platform. Upon first production,
Statoil assumed operatorship in accordance with a pre-agreed arrangement.
Associated gas from the Heidrun field currently serves as feedstock for a
methanol plant that became operational in Norway in 1997. Statoil operates the
plant, in which we also hold an 18.1 percent equity interest. A new
Statoil-operated pipeline linking the Heidrun platform to the Aasgaard Transport
System for further transport to the European gas market will become operational
in early 2001.

     Conoco holds a 10.3 percent interest in the Norwegian sector of the
Statfjord field. We are supporting work by Statoil, the operator of Statfjord,
to determine ways to slow the natural decline of the field and increase
reserves. We also own a 1.6 percent interest in the Troll gas field, operated by
Statoil.

     Exploration in Europe

     Exploration activities in Europe are focused both on lower risk, high-value
opportunities such as the "snuggle" exploration in the U.K. Southern Gas Basin
and also on higher-risk growth opportunities found in the Atlantic Margin as
represented by our west of Shetlands and Norwegian 16th round license awards.

     Snuggle opportunities are those opportunities near existing infrastructure
which can be developed quickly, such as the recent Vixen field. In 2000, Conoco
spudded six snuggle exploration appraisal wells, of which four were commercial
and two were dry holes. We intend to drill several additional wells in 2001.

     We submitted a highly focused application in the Norwegian 16th licensing
round. We were successful in obtaining significant interests in two prime
licenses, one of which will be drilled during 2001. Both licenses are in deep
water and hold the potential for large gas discoveries.

   NORTHERN SOUTH AMERICA AND THE CARIBBEAN

     Petrozuata

     Petrozuata is a key component of Conoco's strategy to deliver production
and reserves through implementation of long-lived, large development projects
and to utilize our proprietary coking technology in other areas of our business.
Petrozuata is a joint venture between Conoco, which holds a 50.1 percent
non-controlling equity interest, and PDVSA Petroleo y Gas S.A., a subsidiary of
PDVSA, the national oil company of Venezuela, which holds the remaining
interest.

     Petrozuata, the first venture of its kind in Venezuela, had developed an
integrated operation that produces extra heavy crude oil from known reserves in
the Zuata region of the Orinoco Belt, transports it to the Jose industrial
complex on the north coast of Venezuela and upgrades it into synthetic crude,
with associated by-products of liquefied petroleum gas, sulfur, petroleum coke
and heavy gas oil, a product slightly lighter than residual oil. Petrozuata's
synthetic crude is a lighter, partially processed refining feedstock similar to
crude oil. Our recorded proved reserves related to our interest in Petrozuata as
of December 31, 2000 were 750 million barrels of oil. Drilling began in 1997 and
at December 31, 2000, 172 horizontal wells were completed with another 77 wells
planned to be drilled by year-end 2001. The joint venture agreement has a
35-year term,





                                       8
<PAGE>   11
commencing with the first commercial lifting of synthetic crude in 2001, and
requires the approval of both Conoco and PDVSA Petroleo y Gas S.A. for major
Petrozuata decisions.

     The upgrading facility at Jose, which employs Conoco's proprietary delayed
coking technology, is complete. The first commercial sales of synthetic crude
are expected in early 2001. Diluted extra heavy crude oil will be transported
via a 36-inch pipeline from the field to the Jose industrial complex. An
adjacent 20-inch pipeline will return naphtha from the upgrading facility to the
field for use as a diluent. The construction of the field processing and support
facilities and marine facilities for shipping synthetic crude and by-products
are essentially complete. Petrozuata has experienced cost overruns in the
project due to overvaluation of the Bolivar and higher than expected labor
costs; however, these have been partially offset by higher than expected early
production revenues. The expected rate of return on Petrozuata has not been
significantly impacted.

     Petrozuata began early production of extra heavy crude oil in August 1998,
and as of December 2000, was producing approximately 120,000 gross barrels per
day. Prior to the completion of the upgrading facility and commercialized
lifting of synthetic crude, the extra heavy crude was being blended with lighter
oils and sold on world markets. With the completion of the upgrading facility,
the synthetic crude produced by Petrozuata is either used as a feedstock for
Conoco's Lake Charles refinery, a refinery operated by PDVSA, or sold to third
parties.

     In 1999, Petrozuata approved an accelerated drilling program to increase
average well productivity. The drilling program was also modified from single
completion wells to multilateral wells. Preliminary results from the
multilateral wells have been positive.

     Conoco has entered into an agreement to purchase up to 104,000 barrels per
day of the Petrozuata synthetic crude for a formula price over the term of the
joint venture in the event that Petrozuata is unable to sell the production for
higher prices. All synthetic crude sales are denominated in U.S. dollars.
By-products produced by the upgrading facility, principally coke and sulfur, are
sold to a variety of domestic and foreign purchasers. The loading facilities at
Jose are transferring synthetic crude and some of the by-products to ocean
tankers for export. Synthetic crude sales are expected to comprise more than 90
percent of the project's revenues.

     The La Luna Trend

     Exploration activities in northern South America and the Caribbean are
focused on a geologic trend known as La Luna. In Venezuela, we conducted seismic
surveys in 1997 on the shallow water Gulf of Paria West block and on the Guanare
block in the Merida Andes foothills. In 1999, we drilled two wells in the Gulf
of Paria West. The first was the Corocoro discovery that flowed hydrocarbons
from multiple zones in drill stem tests while the second well, in a different
structure, resulted in a dry hole. Conoco and its partners have recently
received approval to proceed with a drilling program in 2001 to appraise the
discovery. We currently hold a 50 percent working interest in the Gulf of Paria
West block, which we operate. Our interest in this block is subject to dilution
to 32.5 percent at the option of a PDVSA affiliate. On the Guanare block,
operated by TotalFinaElf, a dry hole was drilled in 1998. We relinquished the
Guanare block in early 2001.

     In May 1996, Conoco acquired an exclusive deepwater exploration license
offshore Barbados. Following hydrocarbon seep-detection surveys using both sea
bottom sampling and satellite imaging, we acquired 2D seismic data on the block
in 1999. TotalFinaElf farmed in to the license for a 35 percent working interest
in 1999. During 2000, we acquired a 3D seismic survey across the most promising
prospect. We expect to enter a three year exploration drilling phase in May of
2001, and we expect to drill an exploration well in deep water by early 2002.

     Phoenix Park

     Conoco holds a 39 percent equity interest in Phoenix Park Gas Processors
Limited, a joint venture with the National Gas Company of Trinidad and Tobago
Limited, which processes gas in Trinidad and markets natural gas liquids
throughout the Caribbean and into the U.S. Gulf Coast. Phoenix Park's facilities
include:


                                       9
<PAGE>   12
     o    a gas processing plant;

     o    a fractionator producing propane, mixed butane and natural gasoline;

     o    storage tanks; and

     o    two marine loading docks.

     Conoco's share of total natural gas liquids from natural gas processed at
Phoenix Park averaged 7,500 barrels per day in 2000.

   SOUTHEAST ASIA

     The focus areas for Conoco's upstream southeast Asia efforts are in the
Indonesian sector of the Natuna Sea and in the Cuu Long Basin, offshore Vietnam.
Conoco has a 33-year operating history in Indonesia where we are the operator of
the Block B, Tobong and Northwest Natuna Sea Block II production sharing
contracts and have an interest in the South Sokang production sharing contract.
During 2000, Conoco made significant progress expanding its business in Vietnam
by acquiring an interest in one producing field and one new exploration block.
By year-end 2000, Conoco had become the largest foreign acreage holder in
Vietnam with interest in 5.6 million acres. In addition, Conoco has interests in
exploration blocks in Cambodia, Malaysia and New Zealand.

     West Natuna Gas Project

     In 1996, Conoco, as operator of the South Natuna Sea Block B production
sharing contract, along with the other participants in Block B and the interest
holders in the Block A and Kakap production sharing contracts, formed the "West
Natuna Group," with the aim of jointly marketing natural gas from the West
Natuna area to Singapore. In January 1999, the West Natuna Group, Pertamina (the
Indonesian state-owned oil and gas company) and SembGas (a Singapore gas
marketing company owned by SembCorp Industries, Temasek and Tracetebel) signed
agreements to provide for the sale, transportation and purchase of natural gas
from specified fields in the production sharing contracts operated by the West
Natuna Group.

     The agreements provide for supply of 2.5 trillion cubic feet of natural gas
over a 22-year contract period with approximately one trillion cubic feet of
natural gas from fields located in Block B. After an initial ramp-up period, the
West Natuna Group will provide an average daily volume of 325 million cubic feet
of natural gas to SembGas, of which 56 million cubic feet per day is
attributable to Conoco's 40 percent interest in Block B.

     In 2000, efforts were focused on the construction of a 400-mile 28-inch
sub-marine pipeline and associated gathering pipelines collectively known as the
West Natuna Transportation System (WNTS). The West Natuna Group completed the
WNTS and related Singapore onshore facilities in November, and the system was
filled with gas and ready to deliver by year-end. First gas was delivered to
SembGas on January 3, 2001, approximately four months ahead of schedule, and was
supplied from fields governed by the Kakap and Block A production sharing
contracts. Block B's new Movable Offshore Gas Production Unit remains on
schedule for tow out and installation in the second quarter of 2001, with
delivery of first gas from Block B into the WNTS in mid-2001.

     Gas Sales to Malaysia from Conoco's Block B, West Natuna

     Conoco and the other Block B participants, Inpex and Texaco, have been
actively exploring for and appraising natural gas reserves in Block B for the
past two years in anticipation of growing gas markets in Asia, and in 1999,
discovered and certified sufficient gas for further sales.

     In October 2000, Pertamina and Petronas (the Malaysian state-owned oil and
gas company) signed a heads of agreement that provided for the supply of 1.5
trillion cubic feet of natural gas from fields governed by the Block B
production sharing contract to be delivered by WNTS over a 20-year period
beginning in 2002 or 2003. The Block B production is expected to initially have
an average daily volume of 100 million gross cubic feet of natural gas,
eventually increasing to an average daily volume of 250 million gross cubic
feet.

     In addition to the natural gas sales mentioned above, Conoco is expecting
to concurrently develop and produce approximately 280 million gross barrels of
oil, condensate, and liquid petroleum gas over the contract life from the Block
B production sharing contract. These liquids will be available for sale to the
open market.




                                       10
<PAGE>   13
     In anticipation of growing gas demand in Asia, Conoco increased exploratory
drilling in offshore Indonesia in 1999 and 2000, resulting in six new gas and
associated oil discoveries or field extensions in the Block B production sharing
contract area. Based on a report from a third party engineering firm, we believe
these discoveries will yield significant additional reserves. During 2000, we
also drilled four successful gas development wells in preparation for delivering
natural gas to Singapore in 2001.

     Belida and Sembilang Fields, Indonesia

     Conoco holds a 40 percent interest in and serves as operator of the Belida
and Sembilang oil fields in the Block B production sharing contract. During
2000, a program of workovers, recompletions and sidetracks resulted in average
gross production of 48,000 barrels per day.

     Vietnam

     In September 1998, Conoco was awarded a 23.3 percent interest in Block 15-1
in the Cuu Long Basin. 3D seismic was acquired in 1999 and the first exploration
well was drilled during the third quarter of 2000. The well flowed 12,600
barrels of light oil per day, and the discovery will be appraised in early 2001
to determine the commerciality of this find. In addition, another exploratory
well will be drilled during 2001 to test another prospect on the block.

     In February 2000, Conoco acquired a 30 percent interest in Block 15-2 in
the Cuu Long Basin through a farm-in from the Japanese Vietnam Petroleum Company
(JVPC). In December 2000, this ownership interest was increased to 36 percent
through acquisition of an additional 6 percent interest from JVPC. During 2000,
Block 15-2 produced approximately 32,370 gross barrels of oil per day from the
Rang Dong field and this production is expected to gradually increase with the
completion of more production wells. In December 2000, we drilled a step-out
well in the southern part of the Rang Dong structure indicating additional
commercial potential of the field, and we intend to drill additional appraisal
wells in 2001 to assess the reserves. In late 2001, a new platform will be
placed in the eastern part of the Rang Dong structure to produce oil from the
Miocene reservoir.

     In April 2000, Conoco signed an agreement with the Vietnam Oil and Gas
Corporation (Petro Vietnam) and the Korean National Oil Company to acquire
exploration Block 16-2 in the Cuu Long Basin, paving the way for Conoco to
become the operator with a 40 percent interest in the block. A 3D seismic survey
was completed on the block during the third quarter 2000, and processing of the
acquired data will be completed in early 2001. The first exploration well is
scheduled to be drilled in the third quarter of 2001.

     Malaysia

     In November 2000, Conoco acquired one half of Shell's 80 percent interest
in deepwater exploration blocks "G" and "J" offshore the Malaysian state of
Sabah. The two blocks cover more than 1.5 million acres adjacent to acreage with
proven reserves. Conoco and Shell will drill at least four exploration wells on
the blocks over the next two years with the first two wells planned for 2001.

   RUSSIA

     Conoco holds a 50 percent ownership interest in Polar Lights Company, a
Russian limited liability company established in January 1992 to develop the
Ardalin field in the Timan-Pechora basin in Northern Russia. Polar Lights
started producing oil in August 1994. Gross production averaged 35,000 barrels
per day in 2000. Oil is transported through the existing Russian pipeline system
and is then exported or sold on the domestic market. During 2000, Polar Lights
committed to develop the Oshkotin field, the first of four Ardalin satellites,
which is expected to provide production at current levels through 2009.

     Conoco is pursuing a number of significant additional development
opportunities in Russia including the Northern Territories and Shtokman
projects. Since March 1998, Conoco has been working with OAO Lukoil, Russia's
largest oil company, to jointly study the development of petroleum reserves in
the 1.2 million acre block known as the Northern Territories. The block is
located in the Timan-Pechora region and includes the large undeveloped Yuzhno
Khilchuyu oil field. The Shtokman project is a large undeveloped natural gas
field located in the Barents Sea. Both Northern Territories and Shtokman have
been approved by the government for





                                       11
<PAGE>   14

development within a production sharing agreement (PSA) framework. Progress on
negotiating the project-specific PSAs has been slow. However, given the
promising potential, Conoco and its partners remain committed to pursuing these
projects and are taking steps to progress the commercial and financial aspects
of the projects.

   WEST AFRICA

     Conoco, in partnership with a Nigerian company, produces oil from the
shallow water Ukpokiti field located offshore Nigeria. We currently have a 90
percent revenue interest in the field. Gross production from the field is
currently about 20,000 barrels per day of oil, and Conoco's net proved reserves
as of December 31, 2000, were 9 million barrels of oil. Conoco provides
technical and operational assistance in the field's development, which includes
three remote caisson type structures, five wells, and the conversion of the
Conoco tanker Independence into a FPSO. With a 1.7 million barrel storage
capacity, the vessel also serves as an export terminal.

     Conoco also operates and owns a 47.5 percent working interest in the
deepwater block OPL 220 located offshore Nigeria, which encompasses 600,000
acres. Conoco has acquired a 3D seismic survey and drilled two exploratory wells
on this license. The first well, which we drilled in 1997, found only gas and
was not commercial. The Chota well, drilled on the license in 1998, encountered
both oil and gas-filled sands. Evaluation work is ongoing on this discovery and
other potential plays within OPL 220, with an appraisal well on the Chota
structure currently planned for 2001.

   CASPIAN SEA REGION AND MIDDLE EAST

     In Dubai, United Arab Emirates, Conoco has operated four fields since their
discovery between 1966 and 1973. Currently, we are using horizontal drilling
techniques and advanced reservoir drainage technology to enhance the efficiency
of the offshore production operations and improve recovery rates.

     In 1999, Conoco entered into a joint venture service agreement with Syria
to develop its natural gas resources and to build natural gas infrastructure.
Conoco and TotalFinaElf each hold a 50 percent interest in the project service
agreement, with Conoco serving as lead operator. The joint venture is
constructing pipeline and plant facilities to gather and process 450 million
cubic feet per day of natural gas. In addition, about 150 million cubic feet per
day of residue gas from the combined facilities will be transported through a
new 155 mile pipeline that will connect to the existing delivery system, which
serves western Syria including the Damascus area. The gas gathering system is
expected to be operational by mid-year 2001, with the gas processing complex
completed by year-end 2001.

     Conoco also received permission from the U.S. government to travel to Libya
in 1999 to evaluate oil fields and production facilities that we left in 1986,
when the U.S. government imposed sanctions against Libya. We found the assets
operating and in good condition. During 2000, two trips were made to Libya with
permission from the U.S. government.

     One of Conoco's newest initiatives is the 20 percent interest we were
awarded in the Zafar Mashal exploration prospect in the Caspian Sea. The Zafar
Mashal prospect offers promising acreage and is located in the high potential
Volga Delta play in the South Caspian basin. This is an area that includes
previously proved large discoveries. From a strategic perspective, exploration
in the Caspian Sea region fits well with our long-term goal to build Conoco's
portfolio for the future.

   OIL AND NATURAL GAS RESERVES

     Conoco's estimated proved reserves at December 31, 2000 were 2,647 million
BOE, consisting of 1,638 million barrels of oil and 6,053 billion cubic feet of
natural gas.

     Oil and gas proved reserves cannot be measured precisely. The reserve data
set forth in this report is only an estimate. Reservoir engineering is a
subjective and inexact process of estimating underground accumulations of oil
and natural gas. Reserve estimates are based on many factors related to
reservoir performance, which require evaluation by engineers interpreting the
available data, as well as price and other economic factors. The reliability of
these estimates at any point in time depends on both the quality and quantity of
the technical and economic data, the production performance of the reservoirs,
as well as extensive





                                       12
<PAGE>   15

engineering judgment. Consequently, reserve estimates are subject to revision,
as additional data become available during the producing life of a reservoir.
When a commercial reservoir is discovered, proved reserves are initially
determined based on limited data from the first well or wells. Subsequent data
may better define the extent of the reservoir and provide additional production
performance. Well tests and engineering studies will likely improve the
reliability of reserve estimates.

     At lower prices for crude oil and natural gas, it may no longer be economic
to produce certain reserves. Actual production revenues and expenditures with
respect to Conoco's reserves will likely vary from estimates, and such variances
may be material.

     The following table sets forth by region Conoco's proved oil reserves at
year-end for the past five years. Proved oil reserves comprise crude oil,
condensate and natural gas liquids expected to be removed for our account from
our natural gas production.

<TABLE>
<CAPTION>
                                                                    YEAR ENDED DECEMBER 31
                                                          ------------------------------------------
                                                           2000     1999     1998     1997     1996
                                                          ------   ------   ------   ------   ------
                                                                     (MILLIONS OF BARRELS)
<S>                                                       <C>      <C>      <C>      <C>      <C>
PROVED OIL RESERVES
CONSOLIDATED COMPANIES
  United States .......................................      249      238      261      277      299
  Europe ..............................................      405      383      410      421      413
  Other regions .......................................      174      167      192      195      214
                                                          ------   ------   ------   ------   ------
    Worldwide .........................................      828      788      863      893      926
SHARE OF EQUITY AFFILIATES
  Europe ..............................................       60       60       50       51       47
  Other regions(1) ....................................      750      682      678      680       --
                                                          ------   ------   ------   ------   ------
    Total proved oil reserves - equity affiliates .....      810      742      728      731       47
                                                          ------   ------   ------   ------   ------
Total proved oil reserves .............................    1,638    1,530    1,591    1,624      973
                                                          ======   ======   ======   ======   ======
</TABLE>

-----------------

(1)  Represents Conoco's equity share of the Petrozuata joint venture in
     Venezuela.

     The following table sets forth by region Conoco's proved natural gas
reserves at year-end for the past five years:

<TABLE>
<CAPTION>
                                                                    YEAR ENDED DECEMBER 31
                                                          ------------------------------------------
                                                           2000     1999     1998     1997     1996
                                                          ------   ------   ------   ------   ------
                                                                  (BILLIONS OF CUBIC FEET)
<S>                                                        <C>      <C>      <C>      <C>      <C>
PROVED NATURAL GAS RESERVES
CONSOLIDATED COMPANIES
  United States .......................................    2,061    2,166    2,319    2,235    1,822
  Europe ..............................................    2,837    2,884    3,053    3,060    3,068
  Other regions .......................................      838      749      430      196      173
                                                          ------   ------   ------   ------   ------
     Worldwide ........................................    5,736    5,799    5,802    5,491    5,063
SHARE OF EQUITY AFFILIATES
  United States .......................................      317      343      381      370      333
                                                          ------   ------   ------   ------   ------
Total proved natural gas reserves .....................    6,053    6,142    6,183    5,861    5,396
                                                          ======   ======   ======   ======   ======
</TABLE>

   PRODUCTION DATA

     Conoco's oil and natural gas production, excluding natural gas liquids from
gas plant ownership, averaged 654,000 BOE per day in 2000, compared with 636,000
BOE per day in 1999. As a percentage of total production, natural gas production
was 44 percent in 2000 and 1999.

     The table below shows Conoco's interests in average daily oil production
and natural gas production for the past three years. Oil production comprises
crude oil and condensate produced for our account, plus our share of natural gas
liquids removed from natural gas production from our owned leases. Natural gas
production




                                       13
<PAGE>   16
represents our share of production from leases in which we have an ownership
interest. Natural gas liquids processed represents our share of natural gas
liquids acquired through gas plant ownership.

<TABLE>
<CAPTION>
                                                            2000       1999       1998
                                                          --------   --------   --------
                                                                   (THOUSANDS OF
                                                                  BARRELS PER DAY)
<S>                                                       <C>        <C>        <C>
NET AVERAGE DAILY OIL PRODUCTION
CONSOLIDATED COMPANIES
  United States .......................................         80         74         79
  Europe ..............................................        155        161        152
  Other regions .......................................         79         84         95
                                                          --------   --------   --------
     Total net production - consolidated companies ....        314        319        326

SHARE OF EQUITY AFFILIATES
  Europe ..............................................         17         18         17
  Other regions .......................................         39         22          5
                                                          --------   --------   --------
     Total net production - equity affiliates .........         56         40         22
                                                          --------   --------   --------
Total net oil production per day ......................        370        359        348
                                                          ========   ========   ========
</TABLE>

<TABLE>
<CAPTION>
                                                            2000       1999       1998
                                                          --------   --------   --------
                                                             (MILLIONS OF CUBIC FEET
                                                                      PER DAY)
<S>                                                       <C>        <C>        <C>
NET AVERAGE DAILY NATURAL GAS PRODUCTION
CONSOLIDATED COMPANIES
  United States .......................................        796        865        873
  Europe ..............................................        800        728        470
  Other regions .......................................         91         52         53
                                                          --------   --------   --------
     Total net production - consolidated companies ....      1,687      1,645      1,396

SHARE OF EQUITY AFFILIATES
  United States .......................................         18         15         15
                                                          --------   --------   --------
Total net natural gas production per day ..............      1,705      1,660      1,411
                                                          ========   ========   ========
</TABLE>

<TABLE>
<CAPTION>
                                                            2000       1999       1998
                                                           ------     ------    -------
                                                              (THOUSANDS OF BARRELS
                                                                     PER DAY)
<S>                                                       <C>      <C>      <C>
NET AVERAGE DAILY NATURAL GAS LIQUIDS PROCESSED
CONSOLIDATED COMPANIES
  United States .......................................         50         51         55
  Other regions .......................................         33         --         --
                                                            ------     ------     ------
    Total net processed - consolidated companies ......         83         51         55

SHARE OF EQUITY AFFILIATES
  United States .......................................          1          7          8
  Other regions .......................................          8          6          4
                                                            ------     ------     ------
    Total net processed - equity affiliates ...........          9         13         12
                                                            ------     ------     ------
Total net natural gas liquids processed per day .......         92         64         67
                                                            ======     ======     ======
</TABLE>

     See the supplemental petroleum data in Item 8 for the annual production
volumes of oil (crude oil, condensate and natural gas liquids) and natural gas
from proved reserves. Proved oil production volumes exclude natural gas liquids
from plant ownership.

     The following tables set forth for Conoco (including equity affiliates),
Conoco (excluding equity affiliates) and its equity affiliates, the average
production costs per BOE produced, average sales prices per barrel of crude oil
and condensate sold, and average sales prices per mcf of natural gas sold for
the three-year period ended December 31, 2000. Average sales prices exclude
proceeds from sales of interests in oil and gas properties.



                                       14
<PAGE>   17
<TABLE>
<CAPTION>
                                                                      TOTAL        UNITED                    OTHER
                                                                    WORLDWIDE      STATES       EUROPE      REGIONS
                                                                    ---------    ----------   ----------   ----------
                                                                                    (UNITED STATES DOLLARS)
<S>                                                                 <C>          <C>          <C>          <C>
TOTAL CONOCO
  For the year ended December 31, 2000
   Average production costs per barrel of oil
     equivalent of petroleum produced(1) ........................   $    4.13     $    4.27   $     3.61   $     5.09
   Average sales prices of produced petroleum
     Per barrel of crude oil and condensate sold ................       26.08         27.72        27.13        23.91
     Per mcf of natural gas sold ................................        3.07          3.42         2.68         3.33
  For the year ended December 31, 1999
   Average production costs per barrel of oil equivalent of
     petroleum produced(1) ......................................        4.04          3.67         4.22         4.28
   Average sales prices of produced petroleum
     Per barrel of crude oil and condensate sold ................       17.09         17.33        17.33        16.55
     Per mcf of natural gas sold ................................        2.12          1.99         2.30         1.92
  For the year ended December 31, 1998
   Average production costs per barrel of oil equivalent of
     petroleum produced(1) ......................................        4.17          3.76         4.65         3.93
   Average sales prices of produced petroleum
     Per barrel of crude oil and condensate sold ................       12.14         12.17        12.31        11.86
     Per mcf of natural gas sold ................................        2.24          1.97         2.86         1.42

CONSOLIDATED COMPANIES
  For the year ended December 31, 2000
   Average production costs per barrel of oil
     equivalent of petroleum produced(1) ........................   $    4.00     $    4.17   $     3.49   $     5.14
   Average sales prices of produced petroleum
     Per barrel of crude oil and condensate sold ................       27.67         27.72        27.96        27.07
     Per mcf of natural gas sold ................................        3.06          3.42         2.68         3.33
  For the year ended December 31, 1999
   Average production costs per barrel of oil equivalent of
     petroleum produced(1) ......................................        3.93          3.60         4.20         3.91
   Average sales prices of produced petroleum
     Per barrel of crude oil and condensate sold ................       17.51         17.33        17.80        17.07
     Per mcf of natural gas sold ................................        2.12          1.98         2.30         1.92
  For the year ended December 31, 1998
   Average production costs per barrel of oil equivalent of
     petroleum produced(1) ......................................        3.95          3.69         4.54         3.21
   Average sales prices of produced petroleum
     Per barrel of crude oil and condensate sold ................       12.37         12.17        12.61        12.12
     Per mcf of natural gas sold ................................        2.24          1.96         2.86         1.42

EQUITY AFFILIATES
  For the year ended December 31, 2000
   Average production costs per barrel of oil
     equivalent of petroleum produced(1) ........................   $    5.43     $   10.69   $     5.58   $     4.96
   Average sales prices of produced petroleum
     Per barrel of crude oil and condensate sold ................       18.21            --        19.63        17.62
     Per mcf of natural gas sold ................................        3.77          3.77           --           --
  For the year ended December 31, 1999
   Average production costs per barrel of oil equivalent of
     petroleum produced(1) ......................................        5.53         10.02         4.51         5.84
   Average sales prices of produced petroleum
     Per barrel of crude oil and condensate sold ................       13.86            --        13.03        14.55
     Per mcf of natural gas sold ................................        2.35          2.35           --           --
</TABLE>




                                       15
<PAGE>   18
<TABLE>
<CAPTION>
                                                                      TOTAL        UNITED                    OTHER
                                                                    WORLDWIDE      STATES       EUROPE      REGIONS
                                                                    ---------    ----------   ----------   ----------
                                                                                   (UNITED STATES DOLLARS)

<S>                                                                 <C>          <C>          <C>          <C>
EQUITY AFFILIATES (CONT'D.)
  For the year ended December 31, 1998
   Average production costs per barrel of oil equivalent of
     petroleum produced(1) ......................................        9.10         10.11         6.16        18.64
   Average sales prices of produced petroleum
     Per barrel of crude oil and condensate sold ................        8.90            --         9.85         3.76
     Per mcf of natural gas sold ................................        2.39          2.39           --           --
</TABLE>

----------

(1)  Average production costs per barrel of equivalent liquids, with
     natural gas converted to liquids at a ratio of 6,000 cubic feet of
     natural gas to one barrel of liquid.

   DRILLING AND PRODUCTIVE WELLS

     The following table sets forth Conoco's drilling wells and productive wells
by region as of December 31, 2000. The table excludes our share of equity
affiliates.

<TABLE>
<CAPTION>
                                                                      TOTAL        UNITED                    OTHER
                                                                    WORLDWIDE      STATES       EUROPE      REGIONS
                                                                    ----------   ----------   ----------   ----------
                                                                                     (NUMBER OF WELLS)
<S>                                                                 <C>          <C>          <C>          <C>
Number of wells drilling(1)
   Gross ........................................................           67           42           17            8
   Net ..........................................................           37           30            3            4
Number of productive wells(2)
   Oil wells - gross ............................................        7,268        6,534          381          353
             - net ..............................................        2,381        2,216           41          124
   Gas wells - gross ............................................        8,887        8,263          206          418
             - net ..............................................        4,535        4,104           54          377
</TABLE>

----------

(1)  Includes wells being completed.

(2)  Approximately 65 gross (24 net) oil wells and 741 gross (260 net) gas
     wells have multiple completions.

   DRILLING ACTIVITY

     The following table sets forth Conoco's net exploratory and development
wells drilled by region for the three-year period ended December 31, 2000. The
table excludes our share of equity affiliates.

<TABLE>
<CAPTION>
                                                                      TOTAL        UNITED                    OTHER
                                                                    WORLDWIDE      STATES       EUROPE      REGIONS
                                                                    ----------   ----------   ----------   ----------
                                                                               (NUMBER OF NET WELLS COMPLETED)
<S>                                                                 <C>          <C>          <C>          <C>
For the year ended December 31, 2000
   Exploratory -- productive ....................................          4.1          1.0          1.6          1.5
               -- dry ...........................................          4.3          2.6           .2          1.5
   Development -- productive ....................................        304.8        267.2         12.0         25.6
               -- dry ...........................................         45.7         20.1           --         25.6
For the year ended December 31, 1999
   Exploratory -- productive ....................................          6.8          1.7          1.3          3.8
               -- dry ...........................................          3.3          0.0          0.8          2.5
   Development -- productive ....................................        179.1        165.2          8.7          5.2
               -- dry ...........................................         19.1         18.3          0.0          0.8
For the year ended December 31, 1998
   Exploratory -- productive ....................................          7.3          2.2          1.1          4.0
               -- dry ...........................................         14.0          5.4          1.9          6.7
   Development -- productive ....................................        234.8        215.9          2.8         16.1
               -- dry ...........................................         13.0         13.0          0.0          0.0
</TABLE>




                                       16
<PAGE>   19
   DEVELOPED AND UNDEVELOPED PETROLEUM ACREAGE

     The following table sets forth Conoco's developed and undeveloped petroleum
acreage by region as of December 31, 2000. The table excludes our share of
equity affiliates.

<TABLE>
<CAPTION>
                                                                      TOTAL        UNITED                    OTHER
                                                                    WORLDWIDE      STATES       EUROPE      REGIONS
                                                                    ----------   ----------   ----------   ----------
                                                                                    (THOUSANDS OF ACRES)
<S>                                                                 <C>          <C>          <C>          <C>
Developed acreage
   Gross ........................................................        8,816        3,000        1,608        4,208
   Net ..........................................................        3,807        1,565          417        1,825
Undeveloped acreage
   Gross ........................................................       82,587        2,963        6,111       73,513
   Net ..........................................................       44,263        1,857        1,765       40,641
</TABLE>

     Conoco is not required to file, and has not filed on a recurring basis,
estimates of its total proved net oil and gas reserves with any U.S. or non U.S.
governmental regulatory authority or agency other than the Department of Energy
(DOE) and the Securities and Exchange Commission (SEC). The estimates furnished
to the DOE have been consistent with those furnished to the SEC. They are not
necessarily directly comparable, however, due to special DOE reporting
requirements, such as requirements to report in some instances on a gross, net
or total operator basis, and requirements to report in terms of smaller units.
In no instance have the estimates for the DOE differed by more than 5 percent
from the corresponding estimates reflected in total reserves reported to the
SEC.

DOWNSTREAM

   SUMMARY

     Downstream operations encompass refining crude oil and other feedstocks
into petroleum products, buying and selling crude oil and refined products and
transporting, distributing and marketing petroleum products. Downstream
operations are organized regionally with operations in the U.S., Europe and the
Asia Pacific region.

     Downstream's objective is to continue to generate a competitive return on
investment and surplus cash to support Conoco's global growth initiatives, while
selectively expanding refining and marketing operations in high-growth markets,
including Asia Pacific and central and eastern Europe. Consistent with this
objective, Conoco has in the past, and may from time to time in the future,
purchase or sell downstream assets. We may also consider forming alliances or
joint ventures to hold and operate all or a selected part of our downstream
assets either to optimize the efficiency of such operations through achieving
economies of scale or, in certain circumstances, to monetize a portion of the
value of such assets.

     Conoco has made capital investments in downstream activities averaging
approximately $513 million per year for the last three years. Capital
investments for 2000 in downstream activities were approximately $545 million.

     Conoco's downstream strengths are in the following areas:

     o    continually improving the operating and cost efficiency of our
          refineries;

     o    processing heavy, high sulfur and acidic crudes;

     o    upgrading bottom-of-the-barrel feedstocks via coking technology;

     o    maintaining low cost, high volume retail operations in selected
          markets;

     o    developing and marketing specialty products; and

     o    integrating our refining and marketing infrastructure.

These strengths are enhanced by the integration that exists with our upstream
operations.



                                       17
<PAGE>   20

     Conoco produces and markets a full range of refined petroleum products,
including gasolines, diesel fuels, heating oils, aviation fuels, heavy fuel
oils, asphalts, lubricants, petroleum coke and specialty products and
petrochemical feedstocks. We own and operate, or are a partner in the operation
of, nine refineries worldwide with a total crude distillation capacity of about
904,000 barrels per day. Refining capacity is distributed 61 percent in the
U.S., 34 percent in Europe and 5 percent in the Asia Pacific region.

     Approximately 50 percent of Conoco's worldwide refining capacity is
designed to process heavy, high sulfur crude. In addition, the crude slate for
the Humber refinery in the U.K. comprises about 45 percent acidic crudes. In
2000, acidic crude processing capacity was installed at our Lake Charles,
Louisiana refinery in the U.S. to allow us to process synthetic crude from
Petrozuata. Refining capacity has risen by about 133,000 barrels per day, or 17
percent, since year-end 1996, primarily as a result of:

     o    the expansion of the Lake Charles refinery;

     o    the upgrade of the Humber refinery;

     o    the addition of the Melaka refinery in Malaysia; and

     o    low cost incremental expansion of existing refining units.

     Conoco has applied its coking technology to nearly all of its refining
operations throughout the world. This has enabled us to become a world leader in
producing petroleum coke products, such as high value graphite and anode cokes,
which are used in the production of electrodes and anodes for the steel and
aluminum industries, respectively. We have also licensed our fuel coking
technology around the world, which has in turn created other business
development opportunities.

     In the U.S., Conoco primarily markets through low cost wholesale
operations. We have a growing marketing presence in Europe and Asia Pacific,
where we are a leader in operating low cost, high volume retail stations. In
2000, refined product sales averaged 1,485,000 barrels per day.

   UNITED STATES

     Conoco's four U.S. refineries are high conversion facilities with capacity
designed to process over 50 percent high sulfur crude oils, much of which is
also heavy crude. In addition, acidic crude capacity was installed in 2000 at
our Lake Charles refinery, in preparation for receiving synthetic crude from
Petrozuata. A principal factor affecting the profitability of our U.S.
operations is the price of refined products in relation to the cost of crude
oils and other feedstocks processed. Because we are able to process a relatively
large proportion of heavy, high sulfur and, beginning in 2001, acidic crude, the
cost advantage of these crude oils, such as those from Mexico, Venezuela and
Canada, over lighter, low sulfur crude oils, such as West Texas Intermediate, is
particularly significant. Over half of our U.S. refining capacity is located in
inland markets and therefore benefits from the price differential for products
produced and sold inland versus those produced and sold on the Gulf Coast.

     Integration of refining, transportation and marketing and continuous
improvement initiatives have provided increased profitability through
improvements in refinery reliability, utilization, product yield and energy
usage. Since the end of 1996, Conoco has increased refining input at its four
U.S. refineries by approximately 18 percent, contributing to increased
utilization and lower average operating expenses per barrel. We have also
improved market share through geographic concentration of markets.

     Conoco intends to limit future capital investments in downstream U.S.,
excluding capital investments in large, non-discretionary, regulatory-driven
projects and selected growth projects, to a level that is less than half of
downstream U.S. operating cash flow. Capital expenditures increased by
approximately $130 million to $344 million in 2000, compared to $214 million in
1999, primarily as a result of the installation of our new acidic crude unit at
our Lake Charles refinery and the expansion of our pipeline infrastructure in
the Rocky Mountain region. We are positioned to make the necessary clean fuels
investments at our refineries over the next five years in support of changing
motor fuel specifications.



                                       18
<PAGE>   21


     Refining

     Conoco operates four wholly owned refineries in the U.S. The following
tables outline the rated crude distillation capacity as of December 31 for each
of the past five years, and the average daily inputs to crude distillation units
and other feedstocks for each of the past five years.

<TABLE>
<CAPTION>
                                                                                    YEAR ENDED DECEMBER 31
                                                                    ----------------------------------------------------
                                                                      2000       1999       1998       1997      1996
                                                                    --------   --------   --------   --------   --------
                                                                                (THOUSANDS OF BARRELS PER DAY)
<S>                                                                 <C>        <C>        <C>        <C>        <C>
CRUDE DISTILLATION CAPACITY(1)
Lake Charles, Louisiana .........................................        248        248        241        226        226
Ponca City, Oklahoma ............................................        184        174        168        155        155
Denver, Colorado ................................................         58         58         58         58         58
Billings, Montana ...............................................         56         54         52         52         52
                                                                    --------   --------   --------   --------   --------
Total crude distillation capacity ...............................        546        534        519        491        491
                                                                    ========   ========   ========   ========   ========

REFINERY INPUTS(2)
Lake Charles, Louisiana
    Inputs to crude distillation units(3) .......................        208        234        216        211        176
    Other inputs ................................................         25         20         24         22         21
Ponca City, Oklahoma
    Inputs to crude distillation units(3) .......................        181        173        167        161        150
    Other inputs ................................................          1          3          4          2          2
Denver, Colorado
    Inputs to crude distillation units(3) .......................         58         56         50         53         49
    Other inputs ................................................          0          0          0          0          0
Billings, Montana
    Inputs to crude distillation units(3) .......................         57         49         52         51         51
    Other inputs ................................................          3          3          3          3          3

Total inputs to crude distillation units ........................        504        512        485        476        426
                                                                    ========   ========   ========   ========   ========
Total other inputs ..............................................         29         26         31         27         26
                                                                    ========   ========   ========   ========   ========
</TABLE>

----------

(1)  Reflects all inputs to crude distillation units. In prior years, this table
     only reflected crude and condensate inputs to crude distillation units.

(2)  Reflects all inputs to crude distillation units and all other inputs
     (excluding internal recycles). In prior years, this table reflected crude
     and condensate inputs to crude distillation units and all other feedstocks.

(3)  Actual inputs to crude distillation units may exceed rated capacity.

     Conoco's U.S. consolidated refined product yields by volume in 2000 were 47
percent motor gasoline, 38 percent middle distillates, including jet and diesel
fuel, and 15 percent residual fuel oil and asphalt and other products, including
petroleum coke, lubricants and liquefied petroleum gases.

     Lake Charles Refinery and Related Facilities

     Conoco's Lake Charles refinery, located in Westlake, Louisiana, is a fully
integrated, high conversion facility, which has a crude distillation capacity of
248,000 barrels per day. The refinery processes heavy, high sulfur, low sulfur
and, beginning in 2001, acidic crude oil. The refinery's Gulf Coast location
provides access to numerous cost effective domestic and international crude oil
sources. The crude design capacity is approximately 188,000 barrels per day of
heavy, high sulfur and acidic crudes with the remaining 60,000 barrels per day
of domestic sourced low sulfur crudes. While the types and origins of these
lower priced heavy, high sulfur and acidic crudes can vary, the majority
consists of Venezuelan and Mexican crudes delivered via tanker. Lake Charles
refinery products can be delivered by truck, rail or major common carrier
product pipelines, partially owned by Conoco, which serve the eastern and
mid-continent U.S. In addition, refinery products can be sold into export
markets through the refinery's marine terminal.




                                       19
<PAGE>   22

     The ability to refine low sulfur, heavy, high sulfur and acidic crudes at
the Lake Charles refinery provides a competitive advantage by enabling the
refinery to produce a full range of products including gasolines, jet fuel,
diesel fuel, LPG, fuel grade petroleum coke and specialty coke from relatively
low-cost feedstocks. The refinery facilities include fluid catalytic cracking,
delayed coking and hydrodesulfurization units, which enable it to maximize the
upgrade of heavier crude oil.

     Integration of fuels and specialty products plays an important role in
maximizing product value at the refinery. The refinery supplies high sulfur gas
oil to Excel Paralubes, a 50/50 joint venture between Conoco and Pennzoil-Quaker
State, which owns a hydrocracked lubricating base oil facility. Excel Paralubes'
state-of-the-art lube oil facility produces approximately 21,000 barrels per day
of high quality clear hydrocracked base oils, representing approximately 13
percent of U.S. lubricating base oil production. Hydrocracked base oils are
second in quality only to synthetic base oils, but are produced at a much lower
cost. The refinery produces other specialty intermediates for making solvents to
supply Penreco, which manufactures and markets highly refined specialty
petroleum products for global markets. Conoco has a 50 percent interest in
Penreco. Conoco also maintains a 35 percent interest in the Cit-Con lubes plant,
which produces base oils and waxes.

     The Lake Charles facilities also include a specialty coker and calciner
that manufacture the more highly valued graphite and anode petroleum cokes for
the steel and aluminum industries, and provide a substantial increase in light
oils production by breaking down the heaviest part of the crude barrel to allow
additional production of diesel fuel and gasoline. In addition, green petroleum
coke is supplied to a nearby coke calcining venture.

     Ponca City Refinery

     Conoco's refinery located in Ponca City, Oklahoma has a crude distillation
capacity of 184,000 barrels per day of light, high sulfur crude, light, low
sulfur crude and Canadian heavy, high sulfur crude. Both foreign and domestic
crudes are delivered by pipeline from offshore, Oklahoma, Kansas, north and west
Texas and Canada. Finished products are shipped by truck, rail and company-owned
and common carrier pipelines to markets throughout the mid-continent region.

     The Ponca City refinery is a high conversion facility that produces a full
range of products, including gasoline, jet fuel, diesel, LPG and anode and fuel
grade petroleum cokes. The refinery's facilities include fluid catalytic
cracking, delayed coking and hydrodesulfurization units, which enable it to
produce high ratios of gasoline and diesel fuel from crude oil.

     Denver Refinery

     Conoco's Denver refinery, located in Commerce City, Colorado, has a crude
distillation capacity of 58,000 barrels per day, processing a mixture of
Canadian heavy, high sulfur crudes, and domestic heavy, high sulfur and low
sulfur crudes. Almost all crude oil processed at the refinery is transported via
pipeline. Products are delivered predominantly through a local truck loading
terminal to the east side of the Rockies, but also by rail and pipelines to
other Colorado markets. The refined gasoline products from the Denver refinery
help supply our marketing operations in the Rocky Mountain states.

     The Denver refinery is a high conversion refinery that produces a full
range of products including gasolines, jet fuels, diesel and asphalt. The
refinery's upgrading units enable it to process a crude slate containing nearly
50 percent heavy, high sulfur crude. We have a processing agreement with a
refinery located in Cheyenne, Wyoming, that has coking capabilities, from which
the refinery receives intermediate feedstocks for processing into finished
products. The Denver refinery also supplies KC Asphalt, a 50/50 joint venture
with Koch Industries, which markets high quality asphalt products. Both of these
ventures enable us to turn relatively low value intermediates into higher margin
products.

     Billings Refinery

     Conoco's Billings, Montana refinery has a crude distillation capacity of
56,000 barrels per day, processing a mixture of about 95 percent Canadian heavy,
high sulfur crude plus domestic high sulfur and low sulfur crudes, all delivered
by pipeline. Products from the refinery are delivered via company-owned
pipelines, rail, and trucks, supplying Conoco's extensive branded marketing
operations in eastern Washington and the northern





                                       20
<PAGE>   23

Rocky Mountain states. The refinery's proximity to its primary source of crude
and its ability to refine both low sulfur and heavy, high sulfur crudes provides
us with significant competitive advantages.

     The Billings refinery is a high conversion refinery that produces a full
range of products including gasolines, jet fuels, diesel and fuel grade
petroleum coke. A delayed coker converts heavy, high sulfur residue into higher
value light oils.

     Marketing

     In the U.S., Conoco markets gasoline, utilizing the Conoco brand, in 39
states, 23 of which represent primary markets, in the southeast, mid-continent
and Rocky Mountain regions. Market growth continues to be targeted to those
areas where we can obtain a strong market share and areas that leverage supply
from our U.S. refineries and those distribution systems in which we have an
ownership position. Increasing market share has resulted in particularly strong
brand recognition in the Rocky Mountain and mid-continent markets.

     Conoco gasoline is sold through approximately 5,000 branded stations in the
U.S., 90 percent of the gasoline through retail outlets owned by independent
wholesale marketers and 10 percent through 150 company-owned stores at year-end
2000. We market gasoline primarily through the wholesale channel in the U.S.
because it requires a lower capital investment than company-owned retail
stations, but still provides a secure branded outlet for Conoco's products.
Conoco operates retail stations to establish brand standards and image, as well
as to better understand the independent distributors in order to provide better
programs and services to them and the consumer.

     In 2000, we continued to develop "breakplace(R)," Conoco's upscale
convenience store design. This format is designed to increase the frequency and
transaction size of customer visits by catering to the needs of our targeted
customer, the "convenience connoisseur." There were 37 "breakplace(R)" locations
as of December 31, 2000. Most of our "breakplace(R)" convenience stores are
company-owned. While we are not currently offering new "breakplace(R)" licenses
to Conoco marketers, they are encouraged to share in the concept by adopting the
comprehensive offerings patterned after the format. Complementing the
"breakplace(R)" image, we continued the upgrade of company and marketer owned
retail outlets to the enhanced "Conoco Red" image, which employs brighter
exterior lighting and improved signage to attract customers.

     At year-end 2000, CFJ Properties, a 50/50 joint venture between Conoco and
Flying J, owned and operated 92 truck travel plazas that carry the Conoco and/or
Flying J brands and provide a secure outlet for our low sulfur diesel
production.

     In addition, bulk sales of all refined petroleum products are made to
commercial, industrial and spot market customers.

     Transportation

     Conoco has approximately 7,200 miles of crude and product mainline
pipelines in the U.S., including those partially owned and/or operated by
affiliates. We also own and operate 36 finished product terminals, five
liquefied petroleum gas terminals, two crude terminals and one coke-exporting
facility. Our crude pipeline interests and terminals provide integral logistical
links between crude sources and refineries to lower crude costs. The product
pipelines serve as secure links between refineries and key product markets. Our
U.S. pipeline system transported an average of 952,000 barrels per day in 2000.
Our equity share of shipments on affiliate pipelines was an additional 419,000
barrels per day.

     Conoco currently operates a fleet of seven seagoing double-hulled crude oil
tankers. Six of the ships typically travel to Mexico, Central America and South
America to load crude oil and discharge at a Gulf Coast location. The vessels
are used to provide secure transportation to the Lake Charles refinery, but when
not in service for Conoco, are available for charter to third parties. The
seventh double-hulled tanker, the Rangrid, is on lease to a third party for use
as a shuttle tanker for the Heidrun field in the North Sea, in which Conoco has
an interest. The Independence, operated by Conoco Energy Nigeria Ltd., is a VLCC
class ship that has been converted for use as a FPSO vessel off the coast of
Nigeria.



                                       21
<PAGE>   24
     Conoco also operates a domestic fleet of seven boats and 14 double-hulled
barges, providing the Gulf Coast Regional Business Unit with inland waterway
transportation services. The fleet operates along the Gulf Coast from Corpus
Christi, Texas to Mobile, Alabama transporting crude oil and refined products.

   EUROPE

     Conoco's European refining and marketing activities are conducted in 17
countries and are generally organized into two regional clusters to facilitate
operational synergies and best practices. In addition, the regional clusters
centralize and leverage certain support activities, which allows the individual
country organizations to focus on serving customers and developing our business
within and across European borders.

     The northern cluster is based in the U.K. and includes marketing operations
in Sweden, Norway, Finland and Denmark, in addition to refining and marketing
activities in the U.K. The Continental cluster is based in Germany and includes
marketing operations in Austria, Switzerland, Belgium, Luxembourg, Hungary,
Slovakia, France, Poland and the Czech Republic. The Continental cluster also
includes refining joint ventures in Germany and the Czech Republic and a
marketing joint venture in Spain. In addition, although it is not part of either
cluster, a marketing joint venture in Turkey is also included in Conoco's
European operations.

     Together, our refining and marketing operations in the U.K. and Germany
accounted for 94 percent of our European downstream after-tax earnings in 2000.

     Conoco's European downstream strategy has been to operate low cost, high
volume retail outlets in selected key markets where we have a competitive
advantage, pursue opportunities in growth regions, and maintain our Humber
refinery and the Mineraloel Raffinerie Oberrhein GmbH (MiRO) joint venture
refinery, in the U.K. and Germany, respectively, as top quartile performers in
Europe.

     Conoco invested approximately $175 million in its European downstream
operations in 2000, and $172 million in 1999. A significant portion of these
expenditures went towards meeting current and expected future clean fuels
regulations. Our European refineries are on schedule to produce motor fuels that
meet the more stringent European Union specifications expected to come into
force in 2005. The majority of our diesel production is scheduled to be in full
compliance during 2003, with the majority of our gasoline production expected to
be in compliance the following year. Duty incentives are in place to promote
this early compliance.

     We continue to implement relatively low-cost projects in our refining
operations designed to increase production and improve yields, while reducing
feedstock costs and operating expenses. Conoco plans to continue to direct
capital expenditures for marketing operations toward construction of new
stations in growth markets. These markets are primarily in central and eastern
Europe, and also in our areas of competitive strength in Germany, Austria and
the Nordic countries.

     Conoco's European downstream profitability is affected by several factors.
As with all refining operations, the difference between the market price of
refined products and the cost of crude oil is the major factor. Our European
refineries are able to process lower cost crudes or upgrade other feedstocks
into higher value finished products. In addition, since the U.K. refinery also
processes fuel oil as a feedstock, the price difference between low sulfur fuel
oil and finished product is important to earnings. European operations also
include significant retail marketing volumes, and therefore earnings are driven
by retail margins, fuel and convenience product sales and operating expenses in
the various countries where we operate.

     Refining

     Conoco's principal European refining operations are located in the U.K.,
Germany and the Czech Republic. The expansion of Conoco's Humber refinery in the
U.K. and the formation of the MiRO joint venture through consolidation with a
neighboring German refinery have increased our European refining capacity by
approximately 11 percent, or 30,000 barrels per day since 1996. We have
continuously upgraded our refineries in Europe since the early 1990s and their
configuration and output are two of Conoco's primary sources of competitive
advantage. In 1998, the U.K. and Germany refineries ranked in the first quartile
of western European refineries by Solomon Associates, an independent
benchmarking company for financial and operating performance, as measured by net
margin and return on investment categories. In addition, Wood Mackenzie, a
recognized petroleum industry consultant, rated Conoco's European refining
operations best in Europe in a 1999 study, as measured by net cash margin per
barrel.




                                       22
<PAGE>   25

     Conoco has undertaken a major capital investment program, totaling
approximately $521 million from 1994 through 2000, to process lower cost
feedstocks and increase conversion capacity, product quality and energy
efficiency at the Humber refinery. During 2000 and 1999, we spent about $117
million at the Humber refinery, and in 2001 we plan to spend another $30 million
to meet current and expected future clean fuel specifications and to fund other
environmental projects. We are also participating in upgrading projects at our
MiRO joint venture refinery and our joint venture Czech Refining Company (CRC)
refineries in the Czech Republic.

     The following tables outline the rated crude distillation capacity as of
December 31 for each of the past five years and the average daily inputs to
crude distillation units and other feedstocks for each of the past five years.

<TABLE>
<CAPTION>
                                                                                    YEAR ENDED DECEMBER 31
                                                                    ----------------------------------------------------
                                                                      2000       1999       1998       1997       1996
                                                                    --------   --------   --------   --------   --------
                                                                               (THOUSANDS OF BARRELS PER DAY)
<S>                                                                 <C>        <C>        <C>        <C>        <C>
CRUDE DISTILLATION CAPACITY(1)
Humber, United Kingdom ..........................................        230        218        218        210        210
MiRO, Germany(2) ................................................         53         53         53         53         43
CRC, Czech Republic(3) ..........................................         27         27         27         27         27
                                                                    --------   --------   --------   --------   --------
Total crude distillation capacity(4) ............................        310        298        298        290        280
                                                                    ========   ========   ========   ========   ========

REFINERY INPUTS(5)
Humber, United Kingdom(6)
  Inputs to crude distillation units(7) .........................        203        213        214        174        162
  Other inputs ..................................................         21         13          8         19         35
MiRO, Germany(2)
  Inputs to crude distillation units(7) .........................         54         56         54         51         47
  Other inputs ..................................................          3          4          3         11         13
CRC, Czech Republic(3)
  Inputs to crude distillation units(7) .........................         17         17         20         21         22
  Other inputs ..................................................          1          1          1          1          1

Total inputs to crude distillation units(4) .....................        274        286        288        246        231
                                                                    ========   ========   ========   ========   ========
Total other inputs ..............................................         25         18         12         31         49
                                                                    ========   ========   ========   ========   ========
</TABLE>

----------

(1)  Reflects all inputs to crude distillation units. In prior years, this table
     only reflected crude and condensate inputs to crude distillation units.

(2)  The 2000, 1999, 1998, and 1997 figures represent Conoco's 18.75 percent
     interest in the MiRO refinery complex at Karlsruhe, Germany. For 1996
     Conoco's interest was 25 percent in the OMW refinery.

(3)  Represents Conoco's 16.33 percent interest in two refineries in the Czech
     Republic.

(4)  Does not include Conoco's 1.4 percent interest in a 95,000 barrel per day
     refinery in Mersin, Turkey.

(5)  Reflects all inputs to crude distillation units and all other inputs
     (excluding internal recycles). In prior years, this table reflected crude
     and condensate inputs to crude distillation units and all other feedstocks.

(6)  The tie-in of a major expansion project and a major refinery maintenance
     turnaround significantly affected the Humber refinery's utilization in 1997
     and 1996, respectively.

(7)  Actual inputs to crude distillation units may exceed rated capacity.




                                       23
<PAGE>   26


     The yield of Conoco's European refineries by product and country for the
year ended December 31, 2000, was as follows:


<TABLE>
<CAPTION>
                                                            UNITED                     CZECH
                                                           KINGDOM      GERMANY      REPUBLIC
                                                          ----------   ----------   ----------
<S>                                                       <C>          <C>          <C>
PERCENT OF TOTAL YIELD(1)
Motor gasoline ........................................           36           35           19
Middle distillate .....................................           45           42           38
Residual fuel oil and asphalt .........................            6            9           18
Other(2) ..............................................           13           14           25
</TABLE>

----------

(1)  Percentages are volume based, not weight based.

(2)  Other products primarily include petroleum coke, lubricants and liquefied
     petroleum gases.

     United Kingdom Refinery

     Conoco's wholly owned Humber refinery is located in North Lincolnshire,
U.K., and has a crude distillation capacity of 230,000 barrels per day. Crude
processed at the refinery is exclusively low or medium sulfur, supplied
primarily from the North Sea and includes lower cost, acidic crudes. The
refinery also processes other intermediate feedstocks, mostly vacuum gas oils
and residual fuel oil, which many other European refineries are not able to
process. The refinery's location on the east coast of England provides for
cost-effective North Sea crude imports and product exports to European and world
markets.

     The Humber refinery, one of the most sophisticated refineries in Europe, is
a fully integrated, high conversion refinery that produces a full slate of light
products and minimal fuel oil. The refinery also has two coking units with
associated calcining plants, which upgrade the heavy "bottoms" and imported
feedstocks into light oil products and high value graphite and anode petroleum
cokes. Approximately 48 percent of the light oils produced in the refinery are
marketed in the U.K., while the other products are exported to the rest of
Europe and the U.S. This gives the refinery the flexibility to take full
advantage of inland and global export market opportunities.

     Germany Refinery

     The MiRO refinery in Karlsruhe, Germany, is a joint venture refinery with a
crude distillation capacity of 283,000 barrels per day. The MiRO joint venture
arose from the combination in 1996 of the existing OMW refinery, in which Conoco
had a 25 percent share, with an adjacent Esso refinery. Conoco has an 18.75
percent interest in MiRO and Conoco's capacity share is 53,000 barrels per day.
The other owners of MiRO are DEA Mineraloel AG, Esso AG and Ruhr Oel GmbH, a
50/50 joint venture between Veba and PDVSA. Approximately 55 percent of the
refinery's crude feedstock is low cost, high sulfur crude. The MiRO complex is a
fully integrated, high conversion refinery producing gasoline, middle
distillates, and specialty products along with a small amount of residual fuel
oil. The refinery has a high capacity to convert lower cost feedstocks into
higher value products, primarily with a fluid catalytic cracker and delayed
coker. The coker produces both fuel grade and specialty calcined cokes.

     The creation of the MiRO joint venture improved the refinery's
competitiveness and was driven by the process synergy that existed between the
two facilities. Integrated operations have yielded improved product slates,
which better match local demand, and increased processing efficiency, while
retaining operational flexibility for the partners. The refinery processes crude
and other feedstock supplied by each of the partners in proportion to their
respective ownership interests. Streamlining the two operations has allowed less
efficient processing units in both refineries to be eliminated, resulting in
lower operating costs.

     Czech Republic Refineries

     Conoco, through participation in CRC, has an interest in two refineries in
the Czech Republic: one in Kralupy and the other in Litvinov. The other owners
of CRC are Unipetrol A.S., Agip Petroli, and Shell Overseas Investment B.V. The
refinery at Litvinov has a crude distillation capacity of 103,000 barrels per
day, and the Kralupy refinery has a crude distillation capacity of 63,000
barrels per day. Conoco's 16.33 percent ownership share of the combined capacity
is 27,000 barrels per day. Both refineries process mostly high sulfur




                                       24
<PAGE>   27

crude, with a large portion being Russian export blend delivered by pipeline at
an advantageous cost. The refineries have an alternative crude supply via a
pipeline from the Mediterranean.

     The commissioning of a visbreaker unit at the Litvinov refinery in 2000
increased conversion rates and significantly reduced fuel oil production.
Completion of a fluid catalytic cracking unit at the Kralupy refinery in early
2001 will also significantly increase light oil yields and reduce the production
of less valuable heavy fuel oil. The two Czech refineries are operated as a
single entity, with certain intermediate streams moving between the two
facilities. CRC markets finished products both inland and abroad. We are using
our share of the light oil production to support an expanding retail marketing
network in central and eastern Europe.

     Marketing

     Conoco has marketing operations in 17 European countries. Our European
marketing strategy is to sell primarily through owned, leased or joint venture
retail sites using a low cost, high volume, low price strategy. Conoco has a
strong reputation in the European marketing area, as evidenced by Wood
Mackenzie's 2000 study that ranked our retail marketing operations in the top
quartile in marketing efficiency (measured as average sales per station relative
to industry average sales per station in countries where Conoco operates). We
intend to expand into identified growing markets, while concurrently
strengthening our market share in core markets such as Germany, Austria and the
Nordic countries. Conoco is standardizing its European retail operations in
order to capture cost savings and prepare for a more integrated Europe. We are
continuing to reduce our cost structure for marketing activities while also
optimizing activities to grow income in the non-fuels sector. We also market
aviation fuels, liquid petroleum gases, heating oils, transportation fuels and
marine bunkers to commercial customers and into the bulk or spot market.

     Conoco uses the "JET" brand name to market its retail products in its
wholly owned operations in Austria, the Czech Republic, Denmark, Finland,
Germany, Hungary, Norway, Poland, Slovakia, Sweden and the U.K. In Belgium and
Luxembourg, we market under the "SECA" brand. Stations throughout Europe also
display the "Conoco" logo next to the brand, indicating Conoco corporate
ownership. In addition, various joint ventures, in which Conoco has an equity
interest, market products in Spain, Switzerland and Turkey under the "JET,"
"Coop" and "Tabas" or "Turkpetrol" brand names, respectively.

     As of December 31, 2000, Conoco had 1,996 marketing outlets in its wholly
owned European operations, of which 1,313 were company-owned. Through our joint
venture operations in Turkey, Spain and Switzerland, we also have an interest in
another 964 retail sites. Our largest branded site networks are in Germany and
the U.K., which account for 64 percent of the total branded units. In Germany
and Austria, 24 outlets were added during 2000, most of which were newly
constructed sites. In the Nordic countries, we have expanded our base of
unattended sites in Sweden, Denmark, Norway and Finland, with seven new stations
in the region. In response to weak fuel margins in the U.K. over the past
several years, we have restructured our operations, focusing on locations where
we have a competitive advantage, which has reduced our unit breakeven cost
structure.

     Conoco has been expanding and upgrading its station portfolio in the
targeted growth markets of central and eastern Europe in the Czech Republic,
Poland, Hungary and Slovakia, resulting in a total of 130 stations as of
December 31, 2000. We expect to continue building high quality new stores,
retrofitting current stations and rationalizing our network in 2001. Our
marketing position should allow us to capture demand growth and expected rising
margins in these inland markets and to obtain further integration with products
produced at the Czech refineries. Similarly, Conoco has retail marketing
operations in Spain and Turkey, where at the end of 2000, we had an interest
through our joint ventures in 121 and 750 sites, respectively. The joint venture
marketing operation in Turkey also provides us with a strategic position and
opportunity for upstream ventures in this region.

     In the third quarter of 1999, our Turkish affiliate, Tabas, merged with an
affiliated Turkish company, Turcas. Conoco's ownership interest in the larger
combined company amounts to 27.6 percent versus 28.9 percent of the pre-merger
company. The resulting entity structure provides significant financial
advantages to our Turkish operations.




                                       25
<PAGE>   28
   ASIA PACIFIC

     Despite the economic downturn in the late 1990s, Conoco views the Asian
market as a source for potential long-term growth. We intend to grow our equity
refining capacity in the region, as well as expand our marketing operations to
integrate with the refining supply and capitalize on market deregulation and
long-term regional demand growth.

     Refining

     The refinery in Melaka, Malaysia was built by a joint venture, which is 40
percent owned by Conoco with partners Petronas, the Malaysian state oil company,
and Statoil. The Melaka refinery became operational in August 1998. The refinery
has a rated crude distillation capacity of about 120,000 barrels per day, of
which Conoco's share is about 48,000 barrels per day. Conoco's share of refinery
inputs, sourced mostly from the Middle East, was about 14 million barrels for
2000. This volume accounts for approximately 39,000 barrels per day of Conoco's
total refinery inputs for 2000.

     In February 2001, Conoco and Petronas announced they had signed a
memorandum of understanding with Statoil to acquire the Norwegian state oil
company's 15 percent share of the Melaka refinery. Conoco and Petronas expect
the Share Purchase Agreement to be signed by the end of March 2001.

     The following tables outline the rated crude distillation capacity as of
December 31 for each of the past three years and the average daily inputs to
crude distillation units and other feedstocks.

<TABLE>
<CAPTION>
                                                              YEAR ENDED DECEMBER 31
                                                          ------------------------------
                                                            2000       1999       1998
                                                          --------   --------   --------
                                                           (THOUSANDS OF BARRELS OF DAY)
<S>                                                       <C>        <C>        <C>
CRUDE DISTILLATION CAPACITY(1)(2)
Melaka, Malaysia ......................................         48         45         45

REFINERY INPUTS(1)(3)
Melaka, Malaysia
  Inputs to crude distillation units(4) ...............         39         32          7
  Other inputs ........................................         --         --         --
</TABLE>

----------

(1)  Represents Conoco's 40 percent interest in the Melaka refinery.

(2)  Reflects all inputs to crude distillation units. In prior years, only crude
     and condensate inputs to crude distillation units were reported.

(3)  Reflects all inputs to crude distillation units and all other inputs
     (excluding internal recycles). In prior years, only crude and condensate
     inputs to crude distillation units and all other feedstocks were reported.

(4)  Actual inputs to crude distillation units may exceed rated capacity.

     The refinery is a high conversion facility that produces a full range of
refined petroleum products. The refinery capitalizes on Conoco's proprietary
coking technology to upgrade low-cost feedstocks to higher-margin products.

     The feedstocks for Conoco's capacity in the refinery typically consist of
between 70 and 90 percent high sulfur crude with the remainder being local heavy
sweet crude, depending on processing economics. The joint venture has a
five-year tax holiday commencing with initial operation.

     Conoco intends to utilize some of its share of refined products from the
refinery to continue growing its retail marketing operations in the Asia Pacific
region. The balance of Conoco's share of production will be sold primarily in
the spot market. Our regional crude and product supply and disposition
operations are centrally located in Singapore.




                                       26
<PAGE>   29


     Marketing

     Conoco has established a significant presence in the Thailand retail
market. At the end of 2000, Conoco had 115 stores in operation and continued
expansion is anticipated in 2001.

     Conoco has launched a retail marketing joint venture in Malaysia with Sime
Darby Bhd., a company that has a major presence in the Malaysian business
sector. Capitalizing on the cost benefits of direct supply, the benefits of
being the first licensees since 1969 to establish retail marketing operations in
Malaysia, and the currently depressed prices of premium Malaysian real estate,
we are initially targeting major markets within 125 miles of the Melaka
refinery. The fourth quarter of 1999 witnessed the opening of the first ProJET
station and "destina(R)" store in Malaysia, and three more stores were opened in
2000.

SPECIALTY PRODUCTS

     Conoco sells a variety of high value lubricants and specialty products
including petroleum coke, lubes, such as automotive and industrial lubricants
and waxes, solvents and pipeline flow improvers, to commercial, industrial and
wholesale accounts worldwide.

     Conoco's technical expertise in carbon upgrading positions it as a leader
in manufacturing and marketing specialty coke and coke products. We manufacture
high quality graphite coke, at our Lake Charles and Humber refineries, for use
in the global steel industry. We also globally market anode and fuel coke
produced at our Lake Charles, Ponca City, Billings, Humber and joint venture
MiRO refineries, as well as fuel coke produced at our joint venture Melaka
refinery. In addition, we participate in the Asia Pacific coke market by
providing technical and marketing expertise to our PetroCokes joint venture with
Sumitomo and Japan Energy. Today our technology is used by more than two dozen
coking facilities--a third of the world's delayed coking capacity.

     Conoco began marketing the HYDROCLEAR(R) brand of lubricants with the
start-up of Excel Paralubes in 1997. The HYDROCLEAR(R) lubricants, which are
non-toxic, were designed to compete with synthetics for a range of applications
with difficult operating conditions. We also have a 50 percent interest in
Penreco, a fully integrated specialties company providing high quality products
for use in the global cosmetic, pharmaceutical, industrial and home markets.

     Conoco is a leader in the worldwide market for pipeline flow improvers. Our
"LiquidPower(TM) Flow Improver" product is used for increasing petroleum
pipeline capacity by reducing frictional pressure drop or used for energy
savings. We also use "LiquidPower(TM) Flow Improver" in our own pipeline
systems. In 1999, we introduced "RefinedPower(R) Flow Improver," an innovative
new generation product designed for petroleum product pipelines.

EMERGING BUSINESSES

   SUMMARY

     Emerging businesses encompass the development of new businesses that will
take us beyond our traditional operations. These are built on our core
businesses and have the potential to contribute substantially to long-term
growth. At present, these new businesses include our carbon fibers, natural gas
refining and power businesses.

   CARBON FIBERS

     Conoco has introduced a new petroleum-based carbon fiber that we expect
will have applications in the electronics, composite materials, plastics,
automotive, construction, transportation and other niche markets. The material,
produced utilizing Conoco's carbon upgrading expertise, is different from
existing carbon-based fibers, with properties that can enhance existing products
and allow us to participate in new markets. The manufacturing process uses
low-cost refinery product streams, instead of the high-cost chemical feedstocks
utilized in making traditional carbon fibers, resulting in a significant
reduction in manufacturing costs. This process is protected with 38 issued U.S.
patents. The patents include protection for the composition of matter having to
do with Conoco's fundamental breakthrough in mass-production technology.

     We are currently manufacturing small quantities of carbon fiber at a pilot
plant located at our Ponca City, Oklahoma research facility. In the second
quarter of 2000, we began construction of an 8-million-pound-per-




                                       27
<PAGE>   30
year manufacturing plant adjacent to our Ponca City refinery. We expect the new
plant to be completed in late 2001 with commercial production and sales of
carbon fiber starting in 2002.

     Conoco recently opened a sales office in Tokyo, Japan to establish the
contacts necessary for the sale of carbon fibers in Japan.

   NATURAL GAS REFINING

     In 1997, Conoco initiated a natural gas refining program, with the goal to
develop the best technology solution for stranded gas reserves around the world.
Stranded gas reserves are those gas reserves that are located in areas from
which they may not be currently economically transported to market. The volume
of stranded gas reserves is thought to be significant, and Conoco believes that
this large volume of stranded gas reserves presents an opportunity to develop
new competitive gas technologies that can create future value.

     The natural gas refining program includes research into several alternative
gas technologies, but gas-to-liquids (GTL) is the main emphasis. The GTL process
refines natural gas into a wide range of transportable products, from light
naphtha, kerosene and diesel to heavier waxes, high-quality lubricants and white
oils.

     Developing our natural gas refining technologies is a technology group of
approximately 80 people working at our natural gas refining research facility in
Ponca City, Oklahoma. The research facility includes state-of-the-art
laboratories and pilot plants to facilitate technology advancements. A GTL plant
consists of three major processes: synthesis gas production, synthesis gas
conversion and product refining. We have developed proprietary technology for
both synthesis gas production and synthesis gas conversion. Our GTL technology
is being developed with a focus on reducing costs and increasing product yields
to a level where commercial plants can be built.

     A successful program would give us a technology that could result in
significant new business opportunities. There are several different ways of
commercializing this technology, and also many integration opportunities exist
for our upstream and downstream businesses.

   POWER

     Conoco Global Power was founded in 1995 to leverage the economic advantages
of Conoco's energy production activities. By utilizing strengths in managing
major projects, market risk, and industrial operations, Conoco Global Power
offers integrated energy solutions to customers.

     Conoco Global Power owns a 50 percent interest in a natural gas-fired
cogeneration plant near Corpus Christi, Texas. The plant, which commenced
commercial operation in November 1999, is located adjacent to chemical complexes
owned by DuPont and OxyChem. OxyChem, Occidental Petroleum Corporation's
chemicals division, is our partner in this joint venture. OxyChem operates the
plant under a long-term contract and purchases electricity and steam production
from the plant. The plant is designed to produce 440 megawatts of power and 1.1
million pounds per hour of process steam. The plant is a qualifying facility
under the Public Utility Regulatory Policies Act and sells excess electricity in
the Texas power markets.

     Conoco Global Power commenced construction of a natural gas-fired
cogeneration facility near Orange, Texas in October 1999. The facility, which is
located at DuPont's chemical complex, has received project financing and is
owned 50 percent each by Conoco and NRG Energy, Inc. The facility will provide
electricity and process steam to the chemical complex and will sell excess power
to Entergy. The plant is designed to produce 420 megawatts of power and 810,000
pounds per hour of process steam. Commercial operation is scheduled for the
third quarter of 2001.

     During 2000, Conoco Global Power decided to divest of its 37.5 percent
interest in a Colombian power venture. The divestiture is expected to be
completed in the first half of 2001.

     Conoco Global Power is developing a 700 megawatt combined heat and power
cogeneration plant in North Lincolnshire, U.K. The facility will provide steam
and electricity to the Conoco and TotalFinaElf refineries in the area, as well
as market power into the U.K. market. Construction is scheduled to begin in 2001
with commercial operation anticipated in 2004.




                                       28
<PAGE>   31
     In 2000, Conoco had equity ownership of 300 megawatts of power. Conoco Gas
& Power Marketing markets Conoco's merchant power.

ELECTRONIC COMMERCE

     During 2000, Conoco announced its participation in a number of electronic
business-to-business (B2B) initiatives. We expect these initiatives to further
Conoco's vision of becoming a globally connected company that successfully
utilizes technology to conduct business. These initiatives include Internet
marketplaces for procurement of goods and services as well as wholesale energy
trading. Additionally, Conoco announced its participation in a joint venture to
provide heavy equipment condition monitoring systems via the Internet.

CORE VALUES

     Conoco is committed to four core values: operating safely, protecting the
environment, behaving ethically and valuing all people. Over the past four
years, Conoco achieved and maintained its lowest level of recordable injury
rates in the company's history for both employees and contractors. The American
Petroleum Institute ranked Conoco's U.S. employees as the safest among their
peers in the petroleum industry, with the lowest 1999 recordable injury rate, an
achievement that has been matched for 15 out of the last 21 years. In 2000, the
U.S. Mineral Management Service and the Offshore Operator's Committee selected
Conoco as a pacesetter company in the category of safety. Additionally, Conoco
received the distinction of being named to the Dow Jones Sustainability Group
Index. The index represents the top 10 percent of sustainability companies
worldwide that exhibit strength in balancing environmental protection, social
and cultural responsibility, and economic performance. Moreover, Conoco was top
rated among 23 global energy companies in corporate responsibility by Oekom, AG,
an independent rating agency that examines sustainability performance. Conoco's
four core values are credited with creating a business culture where respect for
people and the environment are moral imperatives for operating safely and
ethically.

     Operating responsibly requires diligence in carrying out the company's
operations safely, in a manner that not only manages risks, but also employs the
use of comprehensive incident and crisis management systems to effectively
mitigate the impact of any unplanned event. In 2000, significant progress was
made in furthering Conoco's crisis management and emergency response capability
at both the corporate and the business levels. The company's ability to
effectively respond to a crisis is extensively drilled.

     Conoco is also an innovator both at recycling materials and at operating in
environmentally sensitive areas. In the U.K., for example, Conoco recycled over
99 percent of four Viking gas platforms, which it decommissioned in the North
Sea. We have also operated for 60 years in the Aransas National Wildlife Refuge,
a natural habitat for the endangered Whooping Crane in South Texas. In 1990,
Conoco took a major step toward oil spill prevention by being the first
petroleum company to voluntarily commit to build only double-hulled tankers--a
decision made before U.S. law mandated such technology. During 1998, Conoco
began operating fleets of 100 percent double-hulled crude oil tankers and tank
barges in U.S. waters, more than a year ahead of its target date of 2000. In
2000, Conoco marked the 32nd anniversary of implementing one of the industry's
first environmental policies, which predates both the World Environmental Day
and Earth Day in the U.S.

     Recently, Conoco's environmental leadership and innovation were recognized
by external parties. During 2000, Conoco won the first annual Environment Award
from the U.K. Institute of Petroleum for its natural gas project (DEZ Gas) in
Syria that will gather, process and transport 175 million cubic feet per day of
natural gas that is currently being flared. The project will displace some
26,000 barrels per day of heavy fuel oil currently used to generate electric
power in Syria. Conoco received the Gulf Guardian Award from the Gulf of Mexico
Program for the company's operation in Aransas National Wildlife Refuge. Our
U.S. Natural Gas and Gas Products division has taken a leadership role and is
participating in the U.S. Environmental Protection Agency Natural Gas Star
program to reduce methane emissions in the oil and gas industry.

     In order to maintain the highest ethical standards, Conoco established
clear guidelines on business ethics, which every employee agrees to follow.
Conoco has historically granted annual President's Awards to recognize
exceptional examples of performance in safety, environmental protection and
valuing all people. A President's Award for ethical behavior was added in 1999.

     The valuing all people core value is based on our commitment to maximize
the contribution and motivation of our 17,600 workforce in service to being a
great company to work for and to achieve business success.




                                       29
<PAGE>   32
     We believe these core values result in a motivated workforce with values
and goals firmly aligned with the strategic aims of the business. This belief is
reinforced through our 1999 Employee Opinion Survey results, which reached a
6-year high, indicating employees were quite pleased with the company and their
jobs. Core values guide employees in working to meet the expectations of
customers, partners and host governments, and in respecting the communities in
which we do business. In addition, we believe our commitment to core values
helps to reduce liabilities, manage risks and improve business performance. The
financial success of Conoco -- which is influenced by performance in our core
values -- is shared with substantially all employees through the "Conoco
Challenge" and "Global Variable Compensation" programs.

ENVIRONMENTAL REGULATION

     As with other companies and industries, Conoco's operations are subject to
numerous federal, state, local, European Union and other foreign environmental
laws and regulations, including legislation that implements international
conventions or protocols, concerning its oil and gas operations, products and
other activities, including:

o    the federal Clean Air Act, as amended (CAA), which subjects Conoco
     operations to regulations controlling emissions of air pollutants;

o    the Comprehensive Environmental Response, Compensation, and Liability Act
     of 1980, as amended (CERCLA), and comparable state statutes, which impose
     strict, joint and several liability on owners and operators of sites and on
     persons who disposed of or arranged for the disposal of "hazardous
     substances" found at such sites. Although CERCLA currently excludes
     petroleum operations from cleanup liability, many state laws affecting
     Conoco's operations impose clean-up liability regarding petroleum-related
     products;

o    the Resource Conservation and Recovery Act of 1976, as amended (RCRA), and
     comparable state statutes that govern the management and disposal of
     wastes;

o    the federal Oil Pollution Act of 1990, as amended, under which (a) owners
     and operators of onshore facilities and pipelines, (b) lessees or
     permittees of an area in which an offshore facility is located and (c)
     owners and operators of tank vessels, are strictly liable on a joint and
     several basis for removal costs and damages that result from a discharge of
     oil into navigable waters of the U.S.; and

o    regulations of the United States Department of the Interior related to
     offshore oil and gas operations in U.S. waters, which currently impose
     strict liability upon the lessee under a federal lease for the cost of
     clean-up of pollution resulting from the lessee's operations, and possible
     liability for pollution damages.

     Governmental approvals and permits are currently, and may in the future be,
required in connection with Conoco's operations. The duration and success of
obtaining such approvals are contingent upon numerous variables, many of which
are not within our control. To the extent such approvals are required and not
obtained, operations may be delayed or curtailed, or Conoco may be prohibited
from proceeding with planned exploration or operation of facilities.

     Environmental laws and regulations are expected to have an increasing
impact on Conoco's operations in most of the countries in which it operates,
although it is impossible to predict accurately the effect of future
developments in such laws and regulations on Conoco's future earnings and
operations. Some risk of environmental costs and liabilities is inherent in
particular operations and products of Conoco, as it is with other companies
engaged in similar businesses, and there can be no assurance that material costs
and liabilities will not be incurred. However, Conoco does not currently expect
any material adverse effect upon its results of operations or financial position
as a result of compliance with such laws and regulations.

     Under the CAA, the U.S. Environmental Protection Agency (EPA) has
promulgated a number of regulatory standards that mandate a variety of
specifications for motor fuels designed to reduce emissions of certain air
pollutants from vehicles burning such fuels. These regulated fuels include
gasoline and diesel fuels produced and marketed by Conoco. In addition, many
other countries in which Conoco produces or markets motor fuels regulate the
composition of such products. Conoco has already incurred the costs of complying
with such requirements that are currently in effect.




                                       30
<PAGE>   33
     The European Parliament enacted legislation in October 1998 that, among
other things, required phased reductions of sulfur and aromatics content in
gasoline and diesel fuel and of benzene in gasoline. Through the end of 2000, we
have spent about $110 million to modify and/or replace existing equipment to
comply with the new sulfur standards. The remaining cost to complete the
modification is expected to be about $28 million, with completion scheduled for
no later than 2001.

     In late 1999, the EPA published final rules, referred to as Tier 2, for
controlling future vehicle emissions and the sulfur content of gasoline. Conoco
is positioning itself to be able to supply the low sulfur gasoline as required
by the new Tier 2 regulations by the required date of 2004. The company is
currently assessing the compliance costs that will be incurred, so it is
premature to accurately estimate these costs. However, costs are expected to be
in line with the estimate of two to three cents per gallon included in the Tier
2 regulations.

     Early in 2001, the EPA published final rules controlling the future sulfur
content of on-road diesel fuel emissions. Conoco will be assessing the
requirements to comply with the new rules that will take effect in June 2006. It
is too early to fully assess the compliance costs that may be incurred to meet
the on-road diesel requirements. Similar rules controlling the future sulfur
content of off-road diesel fuel emissions have not yet been finalized, and
therefore it is too early to be able to estimate the costs to comply with those
standards, should they be finalized.

     In 1997, an international conference on global warming concluded an
agreement, known as the Kyoto Protocol, which called for reductions of certain
emissions that contribute to increases in atmospheric greenhouse gas
concentrations. The U.S. has not ratified the treaty codifying the Kyoto
Protocol, but it may in the future. In addition, other countries where Conoco
has interests, or may have interests in the future, have made commitments to the
Kyoto Protocol and are in various stages of formulating applicable regulations.
Although it is not yet possible to estimate accurately the total actual
expenditures that may be incurred by Conoco as a result of the Kyoto Protocol,
such expenditures could be substantial.

     For a discussion of our operating expenses and capital expenditures with
respect to environmental protection, see Item 7 -- Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Environmental
Matters. Although future environmental obligations are not expected to have a
material adverse effect on the results of operations or financial condition of
Conoco, there can be no assurance that future developments, such as increasingly
stringent environment laws or enforcement thereof, will not cause us to incur
substantial environmental liabilities or costs.

SOURCES OF SUPPLY

     During 2000, Conoco supplemented its own crude oil production to meet its
refining requirements by the purchase of crude oil from both domestic and
international sources. Approximately 51 percent of the crude oil processed in
our U.S. refineries in 2000 came from U.S. sources. The remainder of crude oil
processed came principally from Venezuela, Mexico and Canada. During 2000,
Conoco's Humber refinery processed principally North Sea crude oils. In the MiRO
joint venture refinery, Conoco processed primarily Mediterranean crude oils,
while Conoco's joint venture CRC refineries processed primarily Russian crude
oils.

RESEARCH AND DEVELOPMENT

     The objectives of Conoco's research and development programs are to
discover new products, processes and business opportunities in relevant fields,
and to improve existing products and processes. Research and development also
focuses on optimizing existing assets and improving efficiency, safety and
environmental protection. Worldwide expenditures for research and development
amounted to approximately $58 million in 2000, $54 million in 1999 and $51
million in 1998.

PATENTS AND TRADEMARKS

     Conoco owns and is the licensee under various patents, which expire from
time to time, covering many products, processes and product uses. No individual
patent is of material importance to Conoco's business as a whole. During 2000,
we were granted two U.S. and 41 non-U.S. patents. We also have individual
trademarks and brands for our products and services, which are registered in
various countries throughout the world. None of these trademarks and brands is
considered material other than the "Conoco" and "JET" brands.




                                       31
<PAGE>   34

OPERATING HAZARDS AND INSURANCE

     Conoco's operations are subject to certain operating hazards, such as well
blowouts, collapsed wells, explosions, uncontrolled flows of oil, natural gas or
well fluids, fires, formations with abnormal pressures, pipeline ruptures or
spills, refinery explosions, surface or marine transportation incidents,
pollution, releases of toxic gas and other environmental hazards and risks. In
accordance with customary industry practices, Conoco maintains insurance against
some, but not all, of such risks and losses. Given our risk profile, and in
accordance with the practices of a number of major, integrated, international
energy companies, Conoco does not carry business interruption insurance on all
operations. Conoco's decision to carry business interruption insurance only on
selected operations is based on several factors, including its spread of risks,
a favorable loss history and loss prevention and safety programs. Conoco has
elected to retain the risk where management believes the cost of insurance,
although available, is excessive relative to the risks presented. In addition,
pollution and environmental risks are generally not fully insurable.

PROPERTIES

     Conoco's corporate headquarters, consisting of 16 three-story buildings on
a 62-acre site, is located in Houston, Texas. We own and lease petroleum
properties and operate production processing, refining, marketing, power
generating and research and development facilities worldwide. In addition, we
operate sales offices, regional purchasing offices, distribution centers and
various other specialized service locations throughout the world.

EMPLOYEES

     Conoco had about 17,600 employees at December 31, 2000, approximately 900
more employees than last year. Approximately, 1,400 employees at our four U.S.
refineries are primarily represented by the Paper, Allied-Industrial, Chemical
and Energy Workers International Union, under separate bargaining agreements for
each refinery. These agreements cover wages, certain benefits matters, grievance
procedures and various employment conditions, and we believe they are typical of
the refining industry in the U.S.

ITEM 3.  LEGAL PROCEEDINGS

     In June of 1997, Conoco experienced pipeline spills on its Seminoe pipeline
at Banner, Wyoming and Lodge Grass, Montana. In response to these spills, the
U.S. Department of Justice advised Conoco in August 2000 that the U.S.
Government is contemplating a legal proceeding under the Clean Water Act against
Conoco. Governmental monetary sanctions resulting from this matter could be in
excess of $100,000.

     In June 1998, the United States Environmental Protection Agency (USEPA) and
the Louisiana Department of Environmental Quality (LDEQ) conducted a multi-media
environmental inspection of Conoco's Lake Charles refinery. The U.S. and the
State of Louisiana, in response to the inspection findings, filed an enforcement
action under the Clean Water Act and Clean Air Act. The parties have negotiated
a settlement requiring Conoco to pay a civil penalty of $240,000.

     On August 31, 1998, the LDEQ issued a notice of violation against Conoco
for alleged failure to maintain control equipment to control emissions from the
sulfur pits at the Lake Charles refinery. Conoco is awaiting final State of
Louisiana approval of a settlement for this matter. Under the settlement, Conoco
has agreed to pay a civil penalty of $75,000 and complete a supplemental
environmental project.

     On November 17, 1999, Conoco received a notice of violation from the New
Mexico Environmental Department (NMED). NMED alleged that Conoco did not
complete two initial compliance tests at the Kemnitz NG&GP Compressor Station by
the permitted deadline, and that it did not submit the test reports to the state
within the regulatory time frame after the tests were completed. The notice of
violation contained a draft penalty calculation of $160,656. Settlement
negotiations are ongoing.

     In February 2000, Conoco voluntarily disclosed the results of a
self-initiated environmental audit of its Ponca City refinery to the Oklahoma
Department of Environmental Quality (ODEQ). In response to the audit findings,
Conoco and the ODEQ entered into cooperative negotiations to address compliance
issues identified by the audit. As a result, Conoco and the ODEQ have entered
into a consent order to resolve these issues. The





                                       32
<PAGE>   35

consent order assessed monetary sanctions against Conoco in the amount of
$462,000, $363,000 of which is intended to be satisfied by the timely
implementation of a supplemental environmental project.

     On March 27, 2000, the Montana Department of Environmental Quality (MDEQ)
issued a notice of violation to Conoco for alleged exceedences of Montana's
3-hour SO2 limit at the Billings refinery. On March 5, 2001, the MDEQ reported
that it intended to seek a civil penalty in the amount of $2.96 million against
Conoco for this violation. At the same time, the MDEQ also reported that Conoco
may be allowed to mitigate the penalty by undertaking a project beneficial to
the environment.

     Between August and November 2000, Conoco voluntarily disclosed the results
of self-initiated environmental audits of each of its Ponca City, Denver and
Billings refineries to the USEPA and the ODEQ, Colorado Department of Public
Health and the Environment (CDPHE) and the MDEQ, respectively. In response to
the audit findings, Conoco has entered into cooperative negotiations with each
of the USEPA, ODEQ, CDPHE and MDEQ to address compliance issues identified by
these audits. These negotiations are ongoing, but are expected to be resolved in
separate consent orders. Governmental monetary sanctions resulting from each of
these matters could be in excess of $100,000.

     The USEPA has advised Conoco that it is contemplating the filing of a civil
enforcement action against Conoco for alleged violations of the Federal Clear
Air Act at each of Conoco's Billings, Denver, Lake Charles and Ponca City
refineries. Governmental monetary sanctions resulting from each of these matters
could be in excess of $100,000.

     Conoco is subject to various lawsuits and claims involving a variety of
matters including, along with other oil companies, actions challenging oil and
gas royalty and severance tax payments, actions related to gas measurement and
valuation methods, actions related to joint interest billings to operating
agreement partners, and claims for damages resulting from leaking underground
storage tanks. As a result of the separation agreement with DuPont, Conoco has
also assumed responsibility for current and future claims related to certain
discontinued chemicals and agricultural chemicals businesses operated by Conoco
in the past. In general, the effect on future financial results is not subject
to reasonable estimation because considerable uncertainty exists. Conoco
believes the ultimate liabilities resulting from such lawsuits and claims may be
significant to results of operations in the period in which they are recognized
but will not materially affect the consolidated financial position of Conoco.

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     No matter was submitted during the fourth quarter of 2000 to a vote of
security holders through the solicitation of proxies or otherwise.

EXECUTIVE OFFICERS OF THE REGISTRANT

<TABLE>
<CAPTION>
NAME                                        AGE(1)             POSITION WITH THE COMPANY
----                                        -------            -------------------------
<S>                                         <C>        <C>
Archie W. Dunham......................         62      Chairman, President and Chief Executive Officer

Gary W. Edwards.......................         59      Senior Executive Vice President,
                                                           Corporate Strategy and Development

Robert E. McKee III...................         54      Executive Vice President, Exploration Production

Jim W. Nokes..........................         54      Executive Vice President, Refining, Marketing,
                                                           Supply and Transportation

Robert W. Goldman.....................         58      Senior Vice President, Finance, and
                                                           Chief Financial Officer

Rick A. Harrington....................         56      Senior Vice President, Legal, and General Counsel
</TABLE>

----------

(1)  As of March 12, 2001.

     Set forth below is information concerning the current executive officers.

     Archie W. Dunham has been Chairman of the Board of Conoco since August 12,
1999 and a director since July 1998. He has been President and Chief Executive
Officer of Conoco since 1996. He joined Conoco in





                                       33
<PAGE>   36

1966 and subsequently held a number of commercial and managerial positions
within Conoco and DuPont. Mr. Dunham is also a member of the boards of directors
of Louisiana-Pacific Corporation, Phelps Dodge Corporation and Union Pacific
Corporation. Mr. Dunham is a former Executive Vice President, Exploration
Production and Executive Vice President, Refining, Marketing, Supply and
Transportation for Conoco. He was also a Senior Vice President, Polymers and
Senior Vice President, Chemicals and Pigments for DuPont. He is a director of
the American Petroleum Institute, the U.S.-Russia Business Council and the
Greater Houston Partnership. He is a past Chairman of the United States Energy
Association, Chairman of the National Petroleum Council and a member of The
Business Council. Mr. Dunham is also a member of the Board of Visitors and the
Energy Center board of directors at the University of Oklahoma. He also serves
on the board of the Memorial Hermann Healthcare System in Houston and the board
of trustees of the Houston Symphony, the George Bush Presidential Library and
the Smithsonian Institution. Mr. Dunham is also President and a trustee of the
Houston Grand Opera.

     Gary W. Edwards was appointed Senior Executive Vice President, Corporate
Strategy and Development of Conoco in November 1999. Prior to his appointment,
he had been Executive Vice President of Conoco since 1991, with responsibility
for worldwide refining, marketing, supply and transportation and was a Senior
Vice President of DuPont until October 27, 1998. He joined Conoco in 1963,
working at various locations throughout the U.S. and in the U.K., and was
formerly Conoco's Vice President, Refining Marketing Europe; Vice President
North American Refining, Marketing and Transportation; and Vice President North
American Marketing. Mr. Edwards has held a number of managerial positions in
Conoco Pipe Line, Transportation, Natural Gas and Gas Products, Logistics and
Marketing. He is a director of the American Petroleum Institute and National
Association of Manufacturers and a previous director and Vice President of the
European Petroleum Industry Association in Brussels, Belgium. Mr. Edwards is a
member of the Kansas State University Engineering advisory council and serves on
the boards of the Yellowstone Park Foundation, Theatre Under the Stars, Junior
Achievement, Inc. (National), as well as Junior Achievement of Southeast Texas
and the Houston Music Hall Foundation.

     Robert E. McKee III has been an Executive Vice President for Conoco since
1992, and was a Senior Vice President of DuPont until October 27, 1998 with
responsibility for worldwide exploration and production. He was formerly
Conoco's Executive Vice President for Corporate Strategy and Development, Senior
Vice President for Administration, Vice President of North American Refining and
Marketing and Vice President, Chairman and Managing Director of Conoco (U.K.)
Limited. Since he joined Conoco in 1967, Mr. McKee has worked at various
locations and held numerous managerial, operating, administrative and technology
positions both in the U.S. and overseas. He currently serves on the board of
directors of the American Petroleum Institute and is a former director of Consol
Energy Inc. and Consol Inc. In addition, he is a past Chairman of the Southern
Regional Advisory Board of the Institute of International Education and a member
of the advisory committee of the University of Texas Engineering Department. Mr.
McKee also serves as Chairman of the President's Council of the Colorado School
of Mines.

     Jim W. Nokes has been Executive Vice President for Conoco since November
1999, with responsibility for worldwide refining, marketing, supply and
transportation, and was President of North American Refining and Marketing from
1998 until 1999. Mr. Nokes was Vice President of North American Refining and
Marketing from 1994 until 1998. Since he joined Conoco in 1970, Mr. Nokes has
held various administrative, planning and operating management positions with
Conoco's gas and natural gas processing departments and pipe line subsidiary. In
1989, he transferred to London to serve as Director and General Manager of
Business Development for Conoco's exploration and production affiliate,
returning to the U.S. in 1991 to become Vice President and General Manager for
North American Marketing.

     Robert W. Goldman has been Senior Vice President, Finance, and Chief
Financial Officer of Conoco since 1998 and was its Vice President, Finance from
1991 to 1998. Mr. Goldman began his career with DuPont in 1965 and subsequently
held many technical and managerial positions within the finance, tax and
treasury functions. He is the former Vice President-Finance of DuPont (Mexico),
Vice President, Remington Arms Company and served as Director and Comptroller of
several operating departments of DuPont in Wilmington, Delaware. Mr. Goldman
transferred to Conoco in 1988 as Vice President and Controller. He is
co-chairman of Conoco's Risk Management Committee and is a member of the
American Petroleum Institute, a former chairman of its Accounting Committee and
currently serves on its Executive Committee of the General Committee on Finance.
He is also a member of the Financial Executives Institute and the Executive
Committee of the Board of Directors of the Alley Theatre in Houston, Texas.




                                       34
<PAGE>   37
     Rick A. Harrington has been Senior Vice President, Legal, and General
Counsel of Conoco since 1998 and was Vice President and General Counsel of
Conoco and Vice President and Assistant General Counsel of DuPont from 1994
until October 27, 1998. He joined DuPont in 1979 as a Senior Attorney, and
subsequently held the positions of Managing Counsel, Special Litigation, and
Vice President and General Counsel of Consolidation Coal Company. Prior to
joining DuPont, he was a partner in the firm of Arent, Fox, Kintner, Plotkin and
Kahn in Washington, D.C. where he specialized in antitrust litigation. Mr.
Harrington is a member of the bar of the District of Columbia, the District of
Columbia Court of Appeals and the Fifth Circuit Court of Appeals. He is
co-chairman of Conoco's Risk Management Committee. He is on the boards of
directors of the American Corporate Counsel Association and the Minority
Corporate Counsel Association and Chairman of the American Petroleum Institute
General Committee on Law. He is also a member of the Association of General
Counsel.

                                     PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

MARKET, STOCK AND DIVIDEND INFORMATION

     Conoco's Class A common stock (symbol: COC.A) and Class B common stock
(symbol: COC.B) are listed on the New York Stock Exchange, Inc. The number of
record holders of Class A common stock was 2,162, and Class B common stock was
6,077 at March 1, 2001.

QUARTERLY COMMON STOCK PRICES AND DIVIDENDS

<TABLE>
<CAPTION>
                                               COMMON STOCK PRICE RANGE
                                      -----------------------------------------
                                             2000                   1999
                                      -------------------   -------------------
                                        HIGH       LOW        HIGH       LOW
                                      --------   --------   --------   --------
<S>                                   <C>        <C>        <C>        <C>
CLASS A COMMON STOCK
First quarter .....................   $  27.88   $  18.81   $  25.44   $  19.38
Second quarter ....................      27.06      22.00      31.25      22.94
Third quarter .....................      27.63      21.38      29.25      25.31
Fourth quarter ....................      29.56      24.00      29.06      20.94

CLASS B COMMON STOCK
First quarter .....................      28.75      19.00         --         --
Second quarter ....................      29.00      23.25         --         --
Third quarter .....................      28.75      22.31      29.38      24.50
Fourth quarter ....................      29.69      24.69      28.94      20.75

DIVIDENDS PER SHARE ...............     2000                  1999
                                      --------              --------
First quarter .....................   $    .19              $    .14
Second quarter ....................        .19                   .19
Third quarter .....................        .19                   .19
Fourth quarter ....................        .19                   .19
                                      --------              --------
Total Dividends per Share .........   $    .76              $    .71
                                      ========              ========
</TABLE>

     Conoco's Class B common stock began trading on the New York Stock Exchange
on August 16, 1999. There are no stock prices for Class B common stock for any
quarters prior to the third quarter of 1999. Quarterly market prices are as
reported by the New York Stock Exchange, Inc.

     Dividends were declared on a quarterly basis throughout 2000 and 1999. The
first quarter dividend of 1999 of $.14 per share was determined on a pro rata
basis covering the period from October 27, 1998, the date of Conoco's initial
public offering, to December 31, 1998, and is equivalent to $.19 per share for a
full quarter. Conoco declared a first quarter cash dividend on January 22, 2001,
of $.19 per share on each outstanding share of Class A common stock and Class B
common stock, payable March 10, 2001, to shareholders of record as of February
10, 2001.


                                       35
<PAGE>   38
     Conoco's Board of Directors will determine the amount of future cash
dividends to be declared and paid based upon Conoco's financial condition,
results of operations, cash flow, the level of its capital and exploration
expenditures, its future business prospects and such other matters as the Board
of Directors deems relevant.

ITEM 6. SELECTED FINANCIAL DATA

<TABLE>
<CAPTION>
                                                                      YEAR ENDED DECEMBER 31
                                                     --------------------------------------------------------
                                                       2000        1999        1998        1997        1996
                                                     --------    --------    --------    --------    --------
                                                                  (IN MILLIONS, EXCEPT PER SHARE)
<S>                                                  <C>         <C>         <C>         <C>         <C>
STATEMENT OF INCOME DATA
Sales and other operating revenues ...............   $ 38,737    $ 27,039    $ 22,796    $ 25,796    $ 24,230
Equity in earnings of affiliates .................        277         150          22          40         (25)
Other income .....................................        273         120         350         427         211
                                                     --------    --------    --------    --------    --------
Total revenues(1) ................................     39,287      27,309      23,168      26,263      24,416
Cost of goods sold ...............................     23,921      14,781      11,751      14,333      12,847
Operating expenses ...............................      2,215       2,060       2,089       1,893       1,713
Selling, general and administrative
     expenses(2) .................................        794         809         972         726         755
Exploration expenses(3) ..........................        279         270         380         457         404
Depreciation, depletion and amortization
     (DD&A) ......................................      1,301       1,193       1,113       1,179       1,085
Taxes other than on income(1) ....................      6,981       6,668       5,970       5,532       5,637
Interest and debt expense ........................        338         311         199          36          74
                                                     --------    --------    --------    --------    --------
Income before income taxes .......................      3,458       1,217         694       2,107       1,901
Provision for income taxes .......................      1,556         473         244       1,010       1,038
                                                     --------    --------    --------    --------    --------
Net income(4) ....................................   $  1,902    $    744    $    450    $  1,097    $    863
                                                     ========    ========    ========    ========    ========
SEGMENT NET INCOME
Upstream
   United States .................................   $    719    $    322    $    223    $    447    $    314
   International .................................      1,148         534         283         439         367
Downstream
   United States .................................        182         119         141         223         186
   International .................................        230         129         156          91         117
Emerging businesses ..............................        (69)        (35)        (31)        (24)        (16)
Corporate(4) .....................................       (308)       (325)       (322)        (79)       (105)
                                                     --------    --------    --------    --------    --------
Net income(4) ....................................   $  1,902    $    744    $    450    $  1,097    $    863
                                                     ========    ========    ========    ========    ========
Earnings per share(5)
   Basic .........................................   $   3.05    $   1.19    $    .95    $   2.51    $   1.98
   Diluted .......................................   $   3.00    $   1.17    $    .95    $   2.51    $   1.98
Weighted-average shares outstanding(5)
   Basic .........................................        624         627         474         437         437
   Diluted .......................................        633         636         475         437         437
Dividends per common share .......................   $    .76    $    .71    $     --    $     --    $     --

OTHER DATA
Cash provided by operations ......................   $  3,438    $  2,216    $  1,373    $  2,876    $  2,396
Capital expenditures and investments .............      2,796       1,787       2,516       3,114       1,944
Cash exploration expense .........................        191         139         217         286         262
</TABLE>

----------

(1)  Includes petroleum excise taxes of $6,774, $6,492, $5,801, $5,349 and
     $5,461 for 2000, 1999, 1998, 1997 and 1996, respectively.

(2)  Includes a non-cash stock option provision of $236 for 1998.

(3)  Includes cash exploration overhead and operating expense, dry hole costs
     and impairments of unproved properties.


                                       36
<PAGE>   39
(4) Includes after-tax exchange gains (losses) of $38, $6, $32, $21 and $(7)
    for 2000, 1999, 1998, 1997 and 1996, respectively.

(5) Conoco's capital structure was established at the time of the initial public
    offering. Earnings per share for the periods prior to the initial public
    offering was calculated using only Class B common stock, as required by SFAS
    No. 128. See note 8 to the consolidated financial statements.

<TABLE>
<CAPTION>
                                                                                DECEMBER 31
                                                          ------------------------------------------------------
                                                            2000        1999        1998       1997       1996
                                                          --------    --------    --------   --------   --------
<S>                                                       <C>         <C>         <C>        <C>        <C>
BALANCE SHEET DATA
Cash and cash equivalents .............................   $    342    $    317    $    394   $  1,147   $    846
Working capital .......................................       (776)       (690)         45        567        862
Net property, plant and equipment .....................     12,207      11,235      11,413     10,828     10,082
Total assets ..........................................     18,127      16,375      16,075     17,062     15,226
Long-term borrowings-related parties ..................         --          --       4,596      1,450      2,287
Long-term borrowings and capital lease obligations ....      4,138       4,080          93        106        101
Total stockholders' equity/owner's net investment .....      5,628       4,555       4,438      7,896      6,579
</TABLE>


ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

GENERAL

     References to "Conoco," "we" or "us" are references to Conoco Inc. and its
consolidated subsidiaries.

     This annual report includes forward-looking statements within the meaning
of Section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934. You can identify our forward-looking statements by the
words "expects," "intends," "plans," "projects," "believes," "estimates" and
similar expressions.

     We have based the forward-looking statements relating to our operations on
our current expectations and on estimates and projections about Conoco and the
petroleum industry in general. We caution you that these statements are not
guarantees of future performance and involve risks, uncertainties and
assumptions that we cannot predict with certainty. Accordingly, our actual
outcomes and results may differ materially from what we have expressed or
forecasted in the forward-looking statements. Any differences could result from
a variety of factors, including the following:

     o    fluctuations in crude oil and natural gas prices and refining and
          marketing margins;

     o    potential failure or delays in achieving expected reserve or
          production levels from existing and future oil and gas development
          projects due to operating hazards, drilling risks and the inherent
          uncertainties in predicting oil and gas reserves and oil and gas
          reservoir performance;

     o    unsuccessful exploratory drilling activities;

     o    failure of new products and services to achieve market acceptance;

     o    unexpected cost increases or technical difficulties in constructing or
          modifying company manufacturing and refining facilities;

     o    unexpected difficulties in manufacturing, transporting or refining
          synthetic crude oil;

     o    ability to meet government regulations;

     o    potential disruption or interruption of our production facilities due
          to accidents or political events;

     o    international monetary conditions and exchange controls;

     o    liability for remedial actions under environmental regulations;

     o    liability resulting from litigation;

     o    general domestic and international economic and political conditions;
          and

     o    changes in tax and other laws applicable to our business.



                                       37
<PAGE>   40

     The discussion and analysis of Conoco's financial condition and results of
operations should be read in conjunction with Conoco's consolidated financial
statements included in this report.

     The initial public offering of the Class A common stock of Conoco commenced
on October 21, 1998. The initial public offering consisted of approximately 191
million shares of Class A common stock issued at a price of $23 per share, and
represented E.I. du Pont de Nemours and Company's (DuPont) first step in the
planned divestiture of Conoco. After the initial public offering, DuPont owned
100 percent of Conoco's Class B common stock (approximately 437 million shares),
representing approximately 70 percent of Conoco's outstanding common stock and
approximately 92 percent of the combined voting power of all classes of voting
stock of Conoco. On August 6, 1999, DuPont concluded an exchange offer to its
stockholders, which resulted in all 437 million shares of Class B common stock
being distributed to DuPont stockholders. The exchange offer was the final step
in DuPont's planned divestiture of Conoco.

     Prior to the date of the initial public offering, operations were conducted
by Conoco and, in some cases, subsidiaries of DuPont. The consolidated financial
statements for 1998 are presented on a carve-out basis prepared from DuPont's
historical accounting records, and include the historical operations of both
entities owned by Conoco and operations transferred to Conoco by DuPont at the
time of the initial public offering. In this context, no direct ownership
relationship existed among all the various units comprising Conoco. Accordingly,
net cash distribution to owner prior to the initial public offering included
funds transferred between Conoco and DuPont for operating needs, cash dividends
paid and other equity transactions.

     Effective at the time of the initial public offering, Conoco's capital
structure was established and the transfer to Conoco of certain subsidiaries
previously owned by DuPont was substantially complete, resulting in direct
ownership of those subsidiaries. Accordingly, for periods subsequent to the
initial public offering, financial information is presented on a consolidated
basis.

     The consolidated statement of income includes all revenues and costs
directly attributable to Conoco. These costs include costs for facilities,
functions and services used by Conoco at shared sites and costs for certain
functions and services performed by centralized DuPont organizations and
directly charged to Conoco based on usage. In addition, services performed by
Conoco on DuPont's behalf are directly charged to DuPont. The results of
operations also include allocations of DuPont's general corporate expenses
through the date of the initial public offering.

     Prior to the date of the initial public offering, all charges and
allocations of cost for facilities, functions and services performed by DuPont
organizations for Conoco are deemed paid by Conoco to DuPont, in cash, in the
period in which the cost was recorded in the consolidated financial statements.
Allocations of current income taxes receivable or payable are similarly
considered remitted, in cash, by or to DuPont in the period the related income
taxes were recorded. Subsequent to the initial public offering, such costs are
billed directly under transitional service agreements, and income taxes are paid
directly to the taxing authorities, or to DuPont, as appropriate.

     All of the allocations and estimates in the consolidated financial
statements are based on assumptions that management believes are reasonable
under the circumstances. However, these allocations and estimates are not
necessarily indicative of the costs and expenses that would have resulted if
Conoco had been operated as a separate entity for periods prior to the initial
public offering.

     Conoco has three operating segments -- upstream, downstream and emerging
businesses. Upstream operating segment activities include exploring for,
developing, producing and selling crude oil, natural gas and natural gas
liquids. Downstream operating segment activities include refining crude oil and
other feedstocks into petroleum products; buying and selling crude oil and
refined products; and transporting, distributing and marketing petroleum
products. Emerging businesses operating segment activities include the
development of new businesses beyond our traditional operations with the
potential to contribute substantially to long-term growth. Conoco has five
reporting segments. Four reporting segments reflect the geographic division
between the U.S. and international operations for its upstream and downstream
businesses. One reporting segment is for emerging businesses. Corporate includes
general corporate expenses, financing costs and other non-operating items, and
captive insurance operations.


                                       38
<PAGE>   41
     Conoco considers portfolio optimization to be an ongoing business strategy
and continuously seeks to rationalize its investment portfolio in order to
maximize profitability. Over the past five years, Conoco has generated proceeds
of approximately $2 billion, averaging about $400 million a year, through the
disposal of marginal and non-strategic producing properties, while upgrading and
redirecting its exploration portfolio and increasing its ownership in
large-scale properties. As a result, we have increased production by 23 percent
on a barrel-of-oil-equivalent (BOE) basis while undergoing this rationalization.
Our policy is to report material gains and losses from individual asset sales as
special items when reporting consolidated net income.

     Conoco conducts its activities through wholly and majority owned
subsidiaries and, increasingly, through equity affiliates. This trend of
conducting business in the petroleum industry through equity affiliates is
expected to increase in the future as Conoco attempts to minimize either the
capital or political risks associated with new large-scale, high-impact projects
and capture synergies leading to growth opportunities.

     Conoco's profitability is largely determined by the difference between
prices received for crude oil, natural gas, natural gas liquids and refined
products produced and the costs of finding, developing, producing, refining and
marketing these resources. Conoco has no control over many factors affecting
prices for its products. Prices for crude oil, natural gas and refined products
may fluctuate widely in response to changes in global and regional supply,
political developments and the ability of the Organization of Petroleum
Exporting Countries (OPEC) and other producing nations to set and maintain
production levels and prices.

     Crude oil and natural gas prices in 2000 increased substantially from the
prices experienced during 1999. West Texas Intermediate crude oil averaged
$30.15 per barrel for 2000, an increase of $10.91 from $19.24 per barrel in
1999. In addition, NYMEX natural gas spot prices averaged $3.71 per thousand
cubic feet (mcf) in 2000, up $1.44 from $2.27 per mcf in 1999. Conoco generated
record-setting results for the year, largely due to these dramatic price
increases. Also contributing to the higher earnings for 2000 were healthy
refining margins in the U.S. and Europe.

     Prices for crude oil, natural gas and refined products also are affected by
changes in demand for these products. Changes may result from global events, as
well as supply and demand in industrial markets, such as the steel and aluminum
markets. Even small decreases in crude oil and natural gas prices and refined
product margins may adversely affect Conoco. Lower crude oil and natural gas
prices may reduce the amount of oil and natural gas reserves Conoco can produce
economically, and existing contracts that Conoco has entered into may become
uneconomic.

     Local political and economic factors in international markets may have a
material adverse effect on Conoco. There are many risks associated with
operations in international markets, including changes in foreign governmental
policies relating to crude oil, natural gas or refined product pricing and
taxation; other political, economic or diplomatic developments; changing
political conditions; and international monetary fluctuations. Recent turmoil in
regions such as Russia, Asia Pacific and South America has subjected Conoco's
operations in these regions to increased risks. These risks include:

     o    the risk of political and economic instability;

     o    the risk of war;

     o    the risk that Conoco's property will be seized by a foreign government
          with or without compensation;

     o    the risk of confiscatory taxation;

     o    the risk that foreign governments will attempt to renegotiate or
          revoke existing contractual arrangements;

     o    increased risks of fluctuating currency values, hard currency
          shortages and currency controls; and

     o    civil unrest and changes in government.

     Actions of the U.S. government also can expose Conoco's operations to risk.
The U.S. government can use tax and other legislation, executive orders and
commercial restrictions to prevent or restrict Conoco from doing business in
foreign countries. These restrictions and those of foreign governments have in
the past limited Conoco's ability to operate in, or gain attractive
opportunities in, various countries. Actions by both the U.S. and host
governments have affected operations significantly in the past and will continue
to do so in the future.




                                       39
<PAGE>   42


LIQUIDITY AND CAPITAL RESOURCES

   CASH PROVIDED BY OPERATIONS

     Cash provided by operations in 2000 increased $1,222 million to $3,438
million versus $2,216 million in 1999. Cash provided by operations before
changes in operating assets and liabilities increased $1,376 million compared to
1999, primarily due to higher crude oil, natural gas and natural gas liquids
prices, along with stronger refining margins and higher dividends from equity
affiliates. Negative changes to net operating assets and liabilities of $154
million were due to increased inventories and funds required for the recent
commencement of a service contract in Syria, partially offset by decreases in
accounts receivable and higher taxes payable.

     Cash provided by operations in 1999 increased $843 million to $2,216
million versus $1,373 million in 1998. Cash provided by operations before
changes in operating assets and liabilities decreased $40 million compared to
1998, primarily due to significantly weaker refined product margins, lower net
realized natural gas prices and increased interest expense, partially offset by
higher crude oil prices and higher volumes. Positive changes to net operating
assets and liabilities of $883 million were due to lower tax payments in 1999, a
decrease in disposition trust fund balances and a decrease in inventories. In
addition, the rise in crude oil prices during 1999 resulted in an increase in
accounts payable, partially offset by an increase in accounts receivable.

INVESTING ACTIVITIES

   CAPITAL EXPENDITURES AND INVESTMENTS

<TABLE>
<CAPTION>
                                                              YEAR ENDED DECEMBER 31
                                                          ------------------------------
                                                            2000       1999       1998
                                                          --------   --------   --------
                                                                   (IN MILLIONS)
<S>                                                       <C>        <C>        <C>
Upstream
    United States .....................................   $    667   $    413   $    788
    International .....................................      1,486        839      1,177
                                                          --------   --------   --------
       Total upstream .................................      2,153      1,252      1,965
Downstream
    United States .....................................        344        214        201
    International .....................................        201        248        332
                                                          --------   --------   --------
       Total downstream ...............................        545        462        533
Emerging businesses ...................................         72         69          1
Corporate .............................................         26          4         17
                                                          --------   --------   --------
Total capital expenditures and investments ............   $  2,796   $  1,787   $  2,516
                                                          ========   ========   ========

United States .........................................   $  1,101   $    700   $  1,007
International .........................................      1,695      1,087      1,509
                                                          --------   --------   --------
Total .................................................   $  2,796   $  1,787   $  2,516
                                                          ========   ========   ========
</TABLE>

     Total capital expenditures and investments in 2000, including investments
in affiliates and acquisitions, were $2,796 million, an increase of 56 percent
versus 1999 capital expenditures and investments of $1,787 million. The increase
was primarily due to significant acquisitions in the U.K. and U.S., as well as
increased capital spending in Indonesia, Vietnam, the Caspian Sea and the Gulf
of Mexico. During 2000, 77 percent of total capital expenditures and investments
were upstream-related, with a majority devoted to the acquisition of producing
acreage in the North Sea, gas processing plants in Canada and the U.S. and in
our Petrozuata joint venture in Venezuela. Worldwide, approximately $204 million
was spent on exploratory drilling and leasing. The increase in 2000 downstream
capital expenditures and investments primarily resulted from the upgrade to our
Lake Charles refinery to enable it to process Petrozuata synthetic crude.
Emerging businesses capital expenditures and investments were essentially
unchanged versus 1999, as our initial capital expenditures and investments in
our carbon fibers business were offset by a decrease in capital spending in our
power business. The increase in corporate capital expenditures and investments
was primarily due to investments in several e-commerce initiatives and computer
hardware and software costs.

     Total capital expenditures and investments in 1999, including investments
in affiliates and acquisitions, were $1,787 million, a decrease of 29 percent
versus 1998 capital expenditures and investments of $2,516




                                       40
<PAGE>   43
million. The decline was primarily due to lower worldwide spending on upstream
capital projects. During 1999, 70 percent of total capital expenditures and
investments were upstream-related, with a majority devoted to further
development of the Lobo field, completion of the Ursa field, drilling in the
deepwater Gulf of Mexico, acquisition of producing acreage in Canada and our
Petrozuata joint venture, as well as continued development of various fields in
the U.K. and the Norwegian sectors of the North Sea. Worldwide, approximately
$156 million was spent on exploratory drilling and leasing. The reduction in
1999 downstream capital expenditures and investments primarily resulted from the
late 1998 completion of the Melaka refinery, a joint venture with Petronas and
Statoil, in Malaysia. The increase in emerging businesses capital expenditures
and investments was primarily due to project costs associated with construction
of power-generating facilities. Corporate capital expenditures and investments
decreased due to the absence of software costs incurred in 1998.

     In 2001, Conoco expects its capital expenditures and investments, including
investments in affiliates and acquisitions, to be about $2,400 million. We
expect about $1,800 million will be spent on upstream projects for worldwide
exploration, production and natural gas activities, while about $400 million
will be spent on downstream projects and about $200 million on emerging
businesses projects.

   Upstream

     Upstream capital expenditures and investments totaled $2,153 million in
2000. The increase of $901 million, or approximately 72 percent, compared to
$1,252 million in 1999, was primarily the result of the acquisitions of Saga
U.K. Ltd. from Norske Hydro ASA of Norway and gas processing plants in the U.S.
Additionally, we increased our capital spending in the Caspian Sea, Indonesia
and the U.S.

     Upstream capital expenditures and investments, excluding amounts paid in
the first quarter of 1999 for the completion of 1998 acquisitions, totaled
$1,252 million in 1999. The decrease of $713 million, or approximately 36
percent, compared to $1,965 million in 1998, was primarily the result of an
overall reduction in the capital expenditure program driven by lower prices in
late 1998 and early 1999 and the completion of major projects, such as Britannia
in the U.K. North Sea and Ursa in the Gulf of Mexico.

     United States

     U.S. capital expenditures and investments were $667 million in 2000, an
increase of $254 million, or 62 percent, compared to 1999 capital expenditures
and investments of $413 million. Expenditures during 2000 were focused on
continued development of the Lobo field in South Texas and the San Juan field in
New Mexico, as well as the acquisition of gas processing plants in the U.S.
Expenditures were also centered on the deepwater Gulf of Mexico with the
drilling of the Princess discovery near the Ursa field and the drilling of an
appraisal well in the Magnolia discovery to confirm the field's commerciality.

     U.S. capital expenditures and investments were $413 million in 1999, a
decrease of $375 million, or 48 percent, compared to 1998 capital expenditures
and investments of $788 million. Expenditures during 1999 focused on continued
development of the South Texas Lobo field and, in the deepwater Gulf of Mexico,
completion of the Ursa field and drilling of the Magnolia and K2 discoveries.

     International

     International capital expenditures and investments were $1,486 million in
2000, an increase of $647 million, or 77 percent, compared to $839 million in
1999. The 2000 expenditures were focused on the acquisition of Saga U.K. Ltd.
and natural gas processing and gathering assets in Canada, continued
developmental spending in the North Sea, exploratory drilling in the North Sea
and Indonesia, development of Petrozuata and construction of a natural gas
pipeline system offshore Indonesia.

     International capital expenditures and investments were $839 million in
1999, a decrease of $338 million, or 29 percent, compared to $1,177 million in
1998. The 1999 expenditures focused on additional capital investments in
exploratory drilling and development of the Petrozuata joint venture,
acquisition of producing acreage in Canada and continued developmental spending
on the Visund field in the Norwegian North Sea and the Britannia and the Viking
Phoenix gas fields in the U.K. North Sea.

     During 2000, Conoco agreed to acquire an equity interest in the Grane oil
field located in the Norwegian North Sea. We will purchase a 6.4 percent
interest from Statoil for $60 million and expect to invest an





                                       41
<PAGE>   44

additional $120 million in development costs over the next two to three years.
The field, which is expected to produce for 30 years, is planned to begin
production in 2003, and at plateau, is expected to add more than 13,000 barrels
of oil per day to Conoco's Norwegian production. The acquisition is expected to
close in early 2001, subject to Norwegian government approval.

   Downstream

     Downstream capital expenditures and investments for 2000 totaled $545
million, an increase of $83 million, or 18 percent, versus $462 million in 1999,
primarily reflecting increased expenditures in the U.S.

     For 1999, downstream capital expenditures and investments totaled $462
million, a decrease of $71 million, or 13 percent, versus $533 million in 1998.
The difference in 1999 versus 1998 expenditures was primarily attributable to
the completion of the Melaka refinery in late 1998.

     United States

     For 2000, U.S. capital expenditures and investments totaled $344 million,
an increase of $130 million, or 61 percent, versus 1999 capital expenditures and
investments of $214 million. Expenditures in 2000 were focused on the new units
being installed at our Lake Charles, Louisiana, refinery to process acidic
synthetic crude from Petrozuata and expansion of pipeline assets in the Rocky
Mountain region, as well as our ongoing refining and marketing operations.

     For 1999, U.S. capital expenditures and investments totaled $214 million,
an increase of $13 million, or 6 percent, versus 1998 capital expenditures and
investments of $201 million. As in 1998, 1999 expenditures were primarily
attributable to both ongoing continued enhancement of operations and the
optimization of retail marketing operations.

     International

     Conoco made international capital expenditures and investments of $201
million during 2000, a decrease of $47 million, or 19 percent, from the $248
million spent in 1999. Expenditures in 2000 were focused on supporting our
refining operations, including upgrades to meet future clean fuels
specifications in Europe, as well as growth in selected retail markets.

     Conoco made international capital expenditures and investments of $248
million during 1999, down $84 million, or 25 percent, from the $332 million
spent in 1998. Expenditures in 1999 continued to focus on strengthening Conoco's
retail marketing position, as well as additional investment in the Melaka
refinery in Malaysia and the Humber refinery in the U.K.

     In February 2001, Conoco and Petronas announced they had signed a
memorandum of understanding with Statoil to acquire the Norwegian state oil
company's 15 percent share of the Melaka refinery. Conoco and Petronas expect
the Share Purchase Agreement to be signed by the end of March 2001.

   Emerging Businesses

     During 2000, emerging businesses capital expenditures and investments
totaled $72 million, compared to $69 million in 1999. Investments in 2000 were
focused on the construction of the 8 million-pound-per-year carbon fibers
manufacturing plant in Ponca City, Oklahoma. Construction began during 2000 and
mechanical completion of the plant is expected late in 2001. There was an
offsetting decrease in the capital expenditures associated with our power
business.

     During 1999, emerging businesses capital expenditures and investments
totaled $69 million, an increase of $68 million from 1998 capital expenditures
and investments of $1 million, primarily related to project costs associated
with the construction of power-generating facilities.

   Corporate

     During 2000, corporate capital expenditures and investments totaled $26
million, an increase of $22 million from 1999 capital expenditures and
investments of $4 million. The increased expenditures during 2000 were




                                       42
<PAGE>   45
primarily related to investments in e-commerce initiatives and
technology-related investments in hardware and software.

     During 1999, corporate capital expenditures and investments totaled $4
million, a decrease of $13 million, or 76 percent, from 1998 capital
expenditures and investments of $17 million. During 1998, the company invested
$17 million for computer software.

   PROCEEDS FROM SALES OF ASSETS AND SUBSIDIARIES

     Conoco's 2000 disposition proceeds were $222 million, up $60 million, or 37
percent, from $162 million in 1999, due to a greater number of large asset
dispositions in 2000, including the sale of gas processing plants in Oklahoma,
retail outlets in the Dallas-Fort Worth area and Gulf Coast region, and our
interest in a pipeline in the southeastern U.S.

     Conoco's 1999 disposition proceeds were $162 million, down $559 million, or
78 percent, from $721 million in 1998, due to a smaller number of large asset
dispositions in 1999. There were no significant proceeds from any one asset sale
in 1999.

FINANCING ACTIVITIES

     Conoco's ability to maintain and grow its operating income and cash flow is
dependent upon continued capital spending to replace depleting assets. Conoco
believes its future cash flow from operations and borrowing capacity should be
sufficient to fund dividends, capital expenditures and working capital
requirements, and to service debt.

     In connection with the separation from DuPont, Conoco incurred indebtedness
to DuPont consisting of a $7,500 million dividend promissory note, other
intercompany notes and borrowings under a revolving credit agreement. In October
1998, Conoco raised net proceeds of $4,228 million in its initial public
offering, which were used to repay a portion of the $7,500 million note and
certain other intercompany notes with DuPont.

     In April 1999, Conoco issued and sold in a public offering $4,000 million
in senior fixed-rate debt securities with a weighted-average interest rate of
6.49 percent. The $3,970 million net proceeds of this offering were used to
repay a portion of Conoco's separation-related indebtedness to DuPont. The
remaining debt owed to DuPont was repaid in May 1999 with proceeds from a U.S.
commercial paper program that is fully supported by an unsecured $2,000 million
revolving credit facility with a syndicate of U.S. and international banks. The
U.S. commercial paper program provides Conoco with up to $2,000 million of
borrowing capacity and gives Conoco the ability to issue commercial paper at any
time with various maturities not to exceed 270 days.

     During 2000, Conoco initiated a euro 500 million European commercial paper
program, which gives Conoco the ability to issue commercial paper in the
European market at any time with maturities not to exceed 183 days. The program
is an alternative to the use of U.S. commercial paper and is not expected to
increase Conoco's current debt level. This program will complement the $2,000
million U.S. commercial paper program and is fully supported by our existing
revolving credit facility. At December 31, 2000, there was $187 million of
commercial paper outstanding, with a weighted-average interest rate of 6.8
percent, of which $85 million was denominated in foreign currencies. At December
31, 1999, U.S. commercial paper outstanding was $628 million with a
weighted-average interest rate of 6.6 percent.

     In 1996, various upstream subsidiaries contributed assets to Conoco Oil &
Gas Associates L.P. for a general partnership interest of 67 percent. Vanguard
Energy Investors L.P. then purchased the remaining 33 percent as a limited
partner. In December 1999, Conoco elected to retire Vanguard's $302 million
minority interest and terminate the Conoco Oil & Gas Associates partnership.

     In November 1999, Conoco and Armadillo Investors L.L.C. formed Conoco Gas
Holdings L.L.C. Conoco contributed certain domestic upstream assets for a 75
percent common member interest and cash, and Armadillo contributed cash for a 25
percent preferred member interest. As a result of the formation, Conoco received
cash proceeds of $185 million, with a corresponding increase in minority
interest.




                                       43
<PAGE>   46
     In December 1999, Conoco formed Conoco Corporate Holdings L.P. by
contributing certain corporate assets. The limited partner interest was sold to
Highlander Investors L.L.C. for $141 million, or an initial 47 percent interest.
The net minority interest in Conoco Corporate Holdings held by Highlander was
$141 million on December 31, 1999.

     The net effect of these 1999 transactions resulted in a minority interest
balance of $335 million at December 31, 1999. Minority interest at December 31,
2000 was $337 million.

     In early 2001, Conoco's management approved plans to acquire the minority
interest in Conoco Gas Holdings L.L.C. from Armadillo L.L.C. This acquisition is
expected to result in a reduction of $185 million in minority interest with an
increase in long-term debt of $171 million and a reduction in cash of $14
million.

     Total Conoco debt was $4,394 million at December 31, 2000, down $349
million versus $4,743 million at year-end 1999. The total debt-to-capitalization
ratio was 43.8 percent at December 31, 2000, and 51.0 percent at December 31,
1999.

     In February 2001, Conoco announced a new $1,000 million stock buyback
program over a three-year period. Conoco Class A and B share repurchases will be
made from time to time in the open market or possibly, under certain
circumstances, through private transactions, as our financial condition and
market conditions warrant. The new program replaces an existing buyback program
intended solely to offset the dilution associated with employee compensation
plans.

RESULTS OF OPERATIONS

   CONSOLIDATED RESULTS

<TABLE>
<CAPTION>
                                                                YEAR ENDED DECEMBER 31
                                                          --------------------------------
                                                            2000        1999        1998
                                                          --------    --------    --------
                                                                   (IN MILLIONS)
<S>                                                       <C>         <C>         <C>
SALES AND OTHER OPERATING REVENUES
   Upstream
      United States ...................................   $  5,531    $  3,309    $  3,200
      International ...................................      3,666       2,247       1,601
                                                          --------    --------    --------
       Total upstream .................................      9,197       5,556       4,801
   Downstream
      United States ...................................     17,379      11,191       8,949
      International ...................................     12,157      10,264       8,297
                                                          --------    --------    --------
       Total downstream ...............................     29,536      21,455      17,246
   Emerging businesses ................................          4          28         729
   Corporate ..........................................         --          --          20
                                                          --------    --------    --------
Total sales and other operating revenues ..............   $ 38,737    $ 27,039    $ 22,796
                                                          ========    ========    ========

AFTER-TAX OPERATING INCOME
   Upstream
      United States ...................................   $    719    $    322    $    223
      International ...................................      1,148         534         283
                                                          --------    --------    --------
       Total upstream .................................      1,867         856         506
   Downstream
      United States ...................................        182         119         141
      International ...................................        230         129         156
                                                          --------    --------    --------
       Total downstream ...............................        412         248         297
   Emerging businesses ................................        (69)        (35)        (31)
   Corporate ..........................................       (104)        (98)       (250)
                                                          --------    --------    --------
       Total after-tax operating income ...............   $  2,106    $    971    $    522
Interest and other non-operating expenses
       net of tax .....................................       (204)       (227)        (72)
                                                          --------    --------    --------
Net income ............................................   $  1,902    $    744    $    450
                                                          ========    ========    ========
</TABLE>




                                       44
<PAGE>   47
   SPECIAL ITEMS

     Net income includes the following non-recurring items (special items) on an
after-tax basis:


<TABLE>
<CAPTION>
                                                                YEAR ENDED DECEMBER 31
                                                          --------------------------------
                                                            2000        1999        1998
                                                          --------    --------    --------
                                                                    (IN MILLIONS)

<S>                                                       <C>         <C>         <C>
UPSTREAM
   Asset sales ........................................   $     27    $     --    $     95
   Property impairments ...............................         --          --         (38)
   Employee separation costs ..........................         --          --         (42)
   Inventory write-downs ..............................         --          --          (4)
                                                          --------    --------    --------
        Total upstream ................................         27          --          11

DOWNSTREAM
   Asset sales ........................................         --          --          12
   Property impairments ...............................         (3)         --          --
   Employee separation costs ..........................         --          --         (10)
   Inventory write-downs ..............................        (24)         --         (59)
   Litigation .........................................        (16)        (18)        (28)
                                                          --------    --------    --------
        Total downstream ..............................        (43)        (18)        (85)

EMERGING BUSINESSES
   Property impairments ...............................        (26)         --          --
                                                          --------    --------    --------
        Total emerging businesses .....................        (26)         --          --

CORPORATE
   Stock option provision .............................         --          --        (183)
   Discontinued businesses ............................         (4)        (20)         --
   Litigation .........................................         --          --         (14)
                                                          --------    --------    --------
        Total corporate ...............................         (4)        (20)       (197)
                                                          --------    --------    --------

Total special items ...................................   $    (46)   $    (38)   $   (271)
                                                          ========    ========    ========
</TABLE>

     Special items in 2000 included a $27 million gain from the sale of U.S.
natural gas processing assets. This asset sale was part of Conoco's effort to
move away from a midstream business of scattered assets in mature areas toward a
more profitable business built on centralized, large-scale gas processing
systems.

     The following charges also were recorded during the year:

     o    property impairments of $29 million;

     o    $24 million write-down of inventories to market value;

     o    $16 million from U.S. downstream litigation charges; and

     o    $4 million from discontinued businesses.

     The after-tax property impairments were as a result of our write-off of $26
million related to our 37.5 percent interest in a Colombian power venture, due
to a combination of continuing weak demand and unsatisfactory rate regulations,
and a $3 million write-off of U.S. refinery assets. The $24 million write-down
of inventories at year-end was the result of significant declines in crude oil
and finished product prices during December. The write-down occurred at our
Melaka refinery joint venture as Dubai crude oil prices fell from $33 per barrel
to $23 per barrel during December. The $4 million loss was for settlement costs
associated with the separation agreement from DuPont related to a discontinued
business.

     Special items in 1999 included charges for $18 million related to the
settlement of certain posted price litigation and $20 million for the resolution
of certain liabilities associated with the separation from DuPont related to
discontinued businesses operated by Conoco in the past.




                                       45
<PAGE>   48

     Special items in 1998 included $107 million in gains from several unrelated
asset sales. The gains consisted of:

     o    $54 million from the sale of producing and non-producing international
          upstream properties;

     o    $41 million from the sale of U.S. upstream producing properties and
          assets; and

     o    $12 million in downstream from the sale of an office building in
          Europe.

     The upstream sales were a part of Conoco's ongoing strategic portfolio
management program designed to improve profitability by disposing of marginal
properties and concentrating operations in core properties.

     Offsetting the gains were:

     o    property impairments of $38 million;

     o    inventory write-downs of $63 million to market prices;

     o    restructuring and employee separation costs of $52 million;

     o    other losses of $42 million for litigation settlements; and

     o    a one-time stock option provision of $183 million.

     The after-tax property impairments of $38 million were made in accordance
with Conoco's policy on impairment of long-lived assets and relate to a $32
million after-tax write-down of U.S. upstream properties and a $6 million
after-tax write-down of an international upstream property.

     The $63 million write-down of inventories at year-end 1998 was the result
of significant declines in crude oil and petroleum product prices occurring
primarily in the fourth quarter of 1998.

     The $42 million relates to the settlement in 1998 of lawsuits and a number
of group and individual claims. In each of these settlements, Conoco was and is
bound to confidentiality agreements with the settling parties, most of which
involved court approval.

     The $183 million stock option provision is a one-time non-cash charge for
stock option employee compensation expenses related to the replacement of
outstanding DuPont stock options held by Conoco employees with Conoco stock
options in connection with the initial public offering.

     Net income before special items (earnings before special items) totaled
$1,948 million in 2000, $782 million in 1999 and $721 million in 1998.

   2000 VERSUS 1999

     Conoco's 2000 net income of $1,902 million was up 156 percent from $744
million in 1999. Earnings before special items of $1,948 million in 2000 were
149 percent higher than the $782 million in 1999. The increase in earnings
before special items was primarily the result of higher crude oil, natural gas
and natural gas liquids prices, increased volumes, lower dry hole costs and
stronger refining margins. Partly offsetting these improvements were weaker
co-product margins, lower European marketing earnings and higher operating costs
associated with increased volumes and higher energy costs.

     Sales and other operating revenues of $38,737 million in 2000 increased 43
percent compared to $27,039 million in 1999, primarily driven by higher crude
oil and natural gas prices and improved refined product prices and volumes.
Downstream sales and other operating revenues were $29,536 million, up 38
percent compared to $21,455 million in 1999. Crude oil and refined product
buy/sell and natural gas and electric power resale activities in 2000 totaled
$9,044 million, up 71 percent compared to $5,299 million in 1999. The increase
was primarily due to higher crude oil, natural gas and refined product prices,
slightly offset by reduced power trading activities.

     Income from equity affiliates for 2000 was $277 million, up $127 million,
or 85 percent, compared to $150 million in 1999. Additional crude oil volumes
from our Petrozuata joint venture and higher crude oil and natural gas prices
primarily drove this increase.



                                       46
<PAGE>   49


     Other income for 2000 was $273 million, up 128 percent from $120 million in
1999, primarily due to the gain on the sale of natural gas processing assets in
the U.S., revenue from our Syrian service contract, foreign exchange gains and
additional interest income. These improvements were partly offset by the $26
million write-off of our 37.5 percent interest in a Colombian power venture.

     Cost of goods sold totaled $23,921 million in 2000, an increase of 62
percent compared to $14,781 million in 1999. The increase is primarily
attributable to higher feedstock costs associated with higher crude oil prices.

     Operating expenses were $2,215 million in 2000, up 8 percent from the
$2,060 million for 1999, primarily due to higher energy costs and higher overall
compensation charges due to variable compensation based on higher earnings in
2000.

     Selling, general and administrative expenses for 2000 amounted to $794
million, down 2 percent compared to $809 million in 1999.

     During 2000, exploration expenses totaled $279 million, an increase of $9
million, or 3 percent, compared to $270 million in 1999. The higher expenses
were primarily driven by deepwater Gulf of Mexico seismic purchases, partially
offset by lower dry hole costs.

     Depreciation, depletion and amortization (DD&A) for 2000 totaled $1,301
million, an increase of $108 million, or 9 percent, compared to $1,193 million
in 1999 due to higher production volumes and the write-down of a non-operating
natural gas processing plant.

     Provision for income taxes for 2000 was $1,556 million, an increase of 229
percent compared to $473 million for 1999. This increase was primarily the
result of higher pretax income in 2000. The effective tax rate in 2000 was
approximately 45 percent versus 39 percent in 1999. The higher effective tax
rate was due to a greater portion of 2000 earnings being generated by operations
in countries with higher tax rates and the reduced impact of U.S. alternative
fuels tax credits on higher pretax income in 2000.

   1999 VERSUS 1998

     Conoco's 1999 net income of $744 million was up 65 percent from $450
million in 1998. Earnings before special items of $782 million in 1999 were 8
percent higher than the $721 million in 1998. The increase in earnings before
special items was primarily the result of higher crude oil prices, increased
natural gas volumes, improved earnings from international upstream equity
companies, higher sales volumes of lower-cost inventories and lower exploration
expenses. Partly offsetting these improvements were weaker refinery margins,
higher operating costs associated with higher volumes, lower net realized
natural gas prices, higher corporate expenses and increased interest expense.

     Sales and other operating revenues of $27,039 million in 1999 increased 19
percent compared to $22,796 million in 1998, primarily driven by higher prices
and a 7 percent increase in refined product sales volumes worldwide, partly
offset by reduced power-trading revenues reported in the emerging businesses
segment and lower natural gas prices. Downstream sales and other operating
revenues were $21,455 million, up 24 percent compared to $17,246 million. Crude
oil and refined product buy/sell and natural gas and electric power resale
activities in 1999 totaled $5,299 million, up 6 percent compared to $5,004
million in 1998. The increase was primarily due to higher crude oil prices
partly offset by reduced power-trading activities.

     Income from equity affiliates for 1999 was $150 million, up $128 million
compared to $22 million in 1998. Earnings improvements associated with increased
crude oil volumes and higher crude oil prices from our Petrozuata and Polar
Lights joint ventures primarily drove this increase.

     Other income for 1999 was $120 million, down 66 percent from $350 million
in 1998, primarily due to lower gains on the sale of assets and reduced interest
income.

     Cost of goods sold totaled $14,781 million in 1999, an increase of 26
percent compared to $11,751 million in 1998. The increase is primarily
attributable to higher feedstock costs associated with higher crude oil prices
and slightly higher refined product volumes partly offset by the reduction in
power-trading activities.

     Operating expenses were $2,060 million in 1999, down 1 percent from the
$2,089 million for 1998.




                                       47
<PAGE>   50
     Selling, general and administrative expenses for 1999 amounted to $809
million, up 10 percent compared to $736 million in 1998. The $73 million
increase was primarily attributable to the incremental administrative costs
associated with becoming an independent company.

     During 1999, exploration expenses totaled $270 million, a decline of $110
million, or 29 percent, compared to $380 million in 1998. The lower expenses
primarily resulted from the implementation of a more focused exploration
program. This, plus a higher exploration success rate, also resulted in lower
dry hole costs.

     DD&A for 1999 totaled $1,193 million, an increase of $80 million, or 7
percent, compared to $1,113 million in 1998 due to higher production volumes,
DD&A rate changes and field mix.

     Provision for income taxes for 1999 was $473 million, an increase of 94
percent compared to $244 million for 1998. This increase was primarily the
result of higher pretax income in 1999. The effective tax rate in 1999 was
approximately 39 percent versus 35 percent in 1998. The higher effective tax
rate was due to the reduced impact of the U.S. alternative fuels credit and a
greater percentage of income from upstream operations in countries with higher
tax rates.

UPSTREAM SEGMENT RESULTS

<TABLE>
<CAPTION>
                                                     YEAR ENDED DECEMBER 31
                                                -------------------------------
                                                  2000        1999       1998
                                                --------    --------   --------
                                                         (IN MILLIONS)
<S>                                             <C>         <C>        <C>
After-tax operating income
   United States ............................   $    719    $    322   $    223
   International ............................      1,148         534        283
                                                --------    --------   --------
     After-tax operating income .............      1,867         856        506
Special items
   United States ............................        (27)         --         14
   International ............................         --          --        (25)
                                                --------    --------   --------
     Special items ..........................        (27)         --        (11)
Earnings before special items
   United States ............................        692         322        237
   International ............................      1,148         534        258
                                                --------    --------   --------
Earnings before special items ...............   $  1,840    $    856   $    495
                                                ========    ========   ========
</TABLE>

     The following tables set forth for Conoco (including equity affiliates),
Conoco (excluding equity affiliates) and its equity affiliates, the average
production costs per BOE produced, average sales prices per barrel of crude oil
and condensate sold, and average sales prices per mcf of natural gas sold for
the three-year period ended December 31, 2000. Average sales prices exclude
proceeds from sales of interests in oil and gas properties.

<TABLE>
<CAPTION>
                                                                      TOTAL        UNITED
                                                                    WORLDWIDE      STATES       INT'L.
                                                                    ----------   ----------   ----------
                                                                            (UNITED STATES DOLLARS)
<S>                                                                 <C>          <C>          <C>
TOTAL CONOCO
  For the year ended December 31, 2000
   Average production costs per barrel of oil
     equivalent of petroleum produced(1) ........................   $     4.13   $     4.27   $     4.06
   Average sales prices of produced petroleum
     Per barrel of crude oil and condensate sold ................        26.08        27.72        25.77
     Per mcf of natural gas sold ................................         3.07         3.42         2.75
  For the year ended December 31, 1999
   Average production costs per barrel of oil
     equivalent of petroleum produced(1) ........................         4.04         3.67         4.24
   Average sales prices of produced petroleum
     Per barrel of crude oil and condensate sold ................        17.09        17.33        17.04
     Per mcf of natural gas sold ................................         2.12         1.99         2.27
</TABLE>





                                       48
<PAGE>   51

<TABLE>
<CAPTION>
                                                                      TOTAL        UNITED
                                                                    WORLDWIDE      STATES       INT'L.
                                                                    ----------   ----------   ----------
                                                                            (UNITED STATES DOLLARS)
<S>                                                                 <C>          <C>          <C>
TOTAL CONOCO (CONT'D.)
  For the year ended December 31, 1998
   Average production costs per barrel of oil
     equivalent of petroleum produced(1) ........................         4.17         3.76         4.43
   Average sales prices of produced petroleum
     Per barrel of crude oil and condensate sold ................        12.14        12.17        12.14
     Per mcf of natural gas sold ................................         2.24         1.97         2.72
CONSOLIDATED COMPANIES
  For the year ended December 31, 2000
   Average production costs per barrel of oil
     equivalent of petroleum produced(1) ........................   $     4.00   $     4.17   $     3.90
   Average sales prices of produced petroleum
     Per barrel of crude oil and condensate sold ................        27.67        27.72        27.65
     Per mcf of natural gas sold ................................         3.06         3.42         2.75
  For the year ended December 31, 1999
   Average production costs per barrel of oil
     equivalent of petroleum produced(1) ........................         3.93         3.60         4.13
   Average sales prices of produced petroleum
     Per barrel of crude oil and condensate sold ................        17.51        17.33        17.55
     Per mcf of natural gas sold ................................         2.12         1.98         2.27
  For the year ended December 31, 1998
   Average production costs per barrel of oil
     equivalent of petroleum produced(1) ........................         3.95         3.69         4.13
   Average sales prices of produced petroleum
     Per barrel of crude oil and condensate sold ................        12.37        12.17        12.40
     Per mcf of natural gas sold ................................         2.24         1.96         2.72
EQUITY AFFILIATES
  For the year ended December 31, 2000
   Average production costs per barrel of oil
     equivalent of petroleum produced(1) ........................   $     5.43   $    10.69   $     5.15
   Average sales prices of produced petroleum
     Per barrel of crude oil and condensate sold ................        18.21           --        18.21
     Per mcf of natural gas sold ................................         3.77         3.77           --
  For the year ended December 31, 1999
   Average production costs per barrel of oil
     equivalent of petroleum produced(1) ........................         5.53        10.02         5.24
   Average sales prices of produced petroleum
     Per barrel of crude oil and condensate sold ................        13.86           --        13.86
     Per mcf of natural gas sold ................................         2.35         2.35           --
  For the year ended December 31, 1998
   Average production costs per barrel of oil
     equivalent of petroleum produced(1) ........................         9.10        10.11         8.98
   Average sales prices of produced petroleum
     Per barrel of crude oil and condensate sold ................         8.90           --         8.90
     Per mcf of natural gas sold ................................         2.39         2.39           --
</TABLE>

----------
(1)  Average production costs per barrel of equivalent liquids, with natural gas
     converted to liquids at a ratio of 6,000 cubic feet of gas to one barrel of
     liquid.

   2000 VERSUS 1999

     Upstream after-tax operating income was $1,867 million in 2000, up 118
percent from $856 million in 1999, principally due to higher crude oil, natural
gas and natural gas liquids prices, increased U.S. petroleum liquids production,
increased international natural gas production and lower dry hole costs. These
improvements were partly offset by a drop in U.S. natural gas volumes due to the
disposition of our Grand Isle




                                       49
<PAGE>   52
assets and natural field decline. Upstream earnings before special items were
$1,840 million in 2000, an increase of 115 percent from $856 million in 1999.

     Including equity affiliates, Conoco's worldwide net realized crude oil
price was $26.08 per barrel for 2000, an improvement of $8.99 per barrel, or 53
percent, versus $17.09 per barrel for 1999, primarily driven by strong demand,
as well as by members of OPEC adhering to production quotas implemented in early
1999. Worldwide net realized natural gas prices averaged $3.07 per mcf for 2000,
compared to $2.12 per mcf for 1999, an improvement of 45 percent. U.S. natural
gas prices increased from $1.99 per mcf in 1999 to $3.42 per mcf in 2000, up 72
percent, while international natural gas prices averaged $2.75 per mcf in 2000,
up $.48 from $2.27 per mcf in 1999. The increase in U.S. gas prices was largely
due to increased demand during an extended and severe winter season. Worldwide
petroleum liquids production in 2000, including Conoco's share from its equity
affiliates, was 370,000 barrels per day versus 359,000 barrels per day in 1999,
a 3 percent increase. Conoco's 2000 worldwide natural gas production, including
its share from equity affiliates, was up 3 percent to 1,705 million cubic feet
per day from 1999 production of 1,660 million cubic feet per day. Conoco's total
net hydrocarbon production, including its share from equity affiliates, was
654,000 BOE per day, an increase of 3 percent over 1999.

     U.S. upstream earnings before special items totaled $692 million in 2000, a
115 percent increase from $322 million in 1999. The increase was largely due to
higher crude oil, natural gas and natural gas liquids prices and increased
petroleum liquids production. These improvements were partly offset by higher
exploration expenses, higher DD&A associated with field mix and lower natural
gas production. U.S. petroleum liquids production, including Conoco's share from
its equity affiliates, was up 6,000 barrels per day to 80,000 barrels per day,
as a result of additional volumes from the Ursa field, partially offset by the
disposition of our Grand Isle assets and natural field decline. U.S. natural gas
production, including Conoco's share from its equity affiliates, was 814 million
cubic feet per day, 66 million less than in 1999, due primarily to the
disposition of our Grand Isle assets and natural field decline. U.S. production
costs were $4.27 per BOE, up $.60 per BOE, compared to $3.67 per BOE in 1999,
due to an increase in price-driven production taxes.

     International upstream earnings before special items were $1,148 million,
an improvement of 115 percent, from $534 million in 1999. This was due primarily
to higher crude oil, natural gas and natural gas liquids prices; improved
earnings from equity affiliates; lower dry hole costs; and increased natural gas
volumes. These improvements were partly offset by lower petroleum liquids
production and higher DD&A associated with field mix. International petroleum
liquids production, including our share from equity affiliates, increased 2
percent, or 5,000 barrels per day, to 290,000 barrels per day in 2000. The
increase is primarily attributable to higher production in Norway and Venezuela,
and the acquisition of Saga U.K. Ltd. This increase was partly offset by
downtime at the U.K. Banff field and natural decline in other U.K. fields. In
2000, the 891 million cubic feet per day of international natural gas
production, including our share from equity affiliates, was up 14 percent, or
111 million cubic feet per day, over 1999, due primarily to our acquisitions in
Canada and our Saga acquisition in the U.K., and higher production from the
Britannia, Vampire and V-fields in the North Sea. International production costs
were $4.06 per BOE, down 4 percent from $4.24 per BOE in 1999, due to higher
production volumes in Norway and the U.K.

   1999 VERSUS 1998

     Upstream after-tax operating income was $856 million in 1999, up 69 percent
from $506 million in 1998, principally due to higher crude oil prices, increased
volumes, improved equity earnings and lower exploration expenses. These
improvements were partly offset by higher production costs associated with the
increased volumes and lower gains from asset dispositions. Upstream earnings
before special items were $856 million in 1999, an increase of 73 percent from
$495 million in 1998.

     Including equity affiliates, Conoco's worldwide net realized crude oil
price was $17.09 per barrel for 1999, an improvement of $4.95 per barrel, or 41
percent, versus $12.14 per barrel for 1998, primarily driven by the OPEC
producing countries' adherence to the quota agreement implemented in early 1999.
Worldwide net realized natural gas prices averaged $2.12 per mcf for 1999,
compared to $2.24 per mcf for 1998, a reduction of 5 percent. U.S. natural gas
prices increased slightly from $1.97 per mcf to $1.99 per mcf, while
international natural gas prices averaged $2.27 per mcf, a 17 percent decline
from $2.72 per mcf in 1998. The reduction in international gas prices was
largely due to contractual terms renegotiated in 1998 and weaker demand.
Worldwide petroleum liquids production in 1999, including Conoco's share from
its equity affiliates, was 359,000 barrels per day versus 348,000 barrels per
day in 1998, a 3 percent increase. Conoco's 1999 worldwide




                                       50
<PAGE>   53
natural gas production, including its share of equity affiliates, was up 18
percent to 1,660 million cubic feet per day from 1998 production of 1,411
million cubic feet per day. Conoco's total net hydrocarbon production, including
its share from equity affiliates, was 636,000 BOE per day, an increase of 9
percent over 1998.

     U.S. upstream earnings before special items totaled $322 million in 1999, a
36 percent increase from $237 million in 1998. The increase was largely due to
higher crude oil prices and lower exploration expenses. These improvements were
partly offset by lower gains from non-strategic asset dispositions, higher DD&A
associated with rate changes and field mix, lower petroleum liquids and natural
gas production, and higher incentive compensation expenses. U.S. petroleum
liquids production, including Conoco's share from its equity affiliates, was
down 5,000 barrels per day to 74,000 barrels per day, as a result of natural
decline and the disposition of non-strategic assets, partly offset by additional
volumes from the Ursa field. U.S. natural gas production, including Conoco's
share from its equity affiliates, was 880 million cubic feet per day, 8 million
less than in 1998 due primarily to the disposition of non-strategic assets and
reduced development drilling in the South Texas Lobo gas field, reflecting a
more capital efficient program. U.S. production costs were $3.67 per BOE, down
$.09 per BOE, compared to $3.76 per BOE in 1998, due to reduced operating
expenses.

     International upstream earnings before special items were $534 million, an
improvement of 107 percent from $258 million in 1998. This was due primarily to
higher crude oil prices, increased natural gas and petroleum liquids production,
improved earnings from equity affiliates and lower exploration costs. These
improvements were partly offset by lower natural gas prices, higher production
costs associated with increased volumes and fewer gains from non-strategic asset
dispositions. International petroleum liquids production, including Conoco's
share from its equity affiliates, increased 6 percent, or 16,000 barrels per
day, to 285,000 barrels per day. The increase is primarily attributable to
higher production in the Britannia and Banff fields in the North Sea and at
Petrozuata, and was partly offset by lower-cost recovery volumes in Indonesia.
In 1999, the 780 million cubic feet per day of international natural gas
production, including Conoco's share from its equity affiliates, was 49 percent,
or 257 million cubic feet per day, higher than 1998 due primarily to higher
production from the Britannia and Viking Phoenix fields in the North Sea.
International production costs were $4.24 per BOE, down 4 percent from $4.43 per
BOE in 1998, due to higher production volumes at our Petrozuata joint venture.

DOWNSTREAM SEGMENT RESULTS

<TABLE>
<CAPTION>
                                                              YEAR ENDED DECEMBER 31
                                                          ------------------------------
                                                            2000       1999       1998
                                                          --------   --------   --------
                                                                   (IN MILLIONS)
<S>                                                       <C>        <C>        <C>
After-tax operating income
   United States ......................................   $    182   $    119   $    141
   International ......................................        230        129        156
                                                          --------   --------   --------
     After-tax operating income .......................        412        248        297
Special items
   United States ......................................         19         18         73
   International ......................................         24         --         12
                                                          --------   --------   --------
     Special items ....................................         43         18         85
Earnings before special items
   United States ......................................        201        137        214
   International ......................................        254        129        168
                                                          --------   --------   --------
Earnings before special items .........................   $    455   $    266   $    382
                                                          ========   ========   ========
</TABLE>

   2000 VERSUS 1999

     Downstream after-tax operating income was $412 million in 2000, up 66
percent compared to $248 million in 1999. Downstream earnings before special
items totaled $455 million in 2000, an increase of 71 percent from $266 million
in 1999.

     In 2000, U.S. downstream earnings before special items totaled $201
million, which was $64 million, or 47 percent, higher than $137 million in 1999.
The increase was attributable to significantly improved refining margins, offset
partly by weaker margins for co-products, such as petroleum coke and asphalt,
lower marketing margins and reduced earnings in our lubricants and specialty
products business, as a result of higher feedstock




                                       51
<PAGE>   54

costs. Additionally, earnings were reduced due to higher operating costs,
including energy and variable compensation charges.

     International downstream earnings before special items were $254 million in
2000, an increase of 97 percent from $129 million in 1999, reflecting stronger
refinery margins, partly offset by weaker co-product margins as a result of
higher crude oil costs and lower European marketing earnings.

     Conoco's refineries operated at 93 percent capacity in 2000 versus 96
percent in 1999. The decrease is primarily due to downtime in connection with
the major modifications at our Lake Charles refinery to enable it to process
Petrozuata synthetic crude.

   1999 VERSUS 1998

     Downstream after-tax operating income was $248 million in 1999, down 16
percent compared to $297 million in 1998. Downstream earnings before special
items totaled $266 million in 1999, a decline of 30 percent from $382 million in
1998.

     In 1999, U.S. downstream earnings before special items totaled $137
million, $77 million, or 36 percent, lower than $214 million in 1998. The
decline was mainly attributable to weaker refinery margins, partly offset by
higher sales volumes of lower-cost inventories.

     International downstream earnings before special items were $129 million in
1999, a reduction of 23 percent from $168 million in 1998, reflecting weaker
refinery margins, partly offset by higher sales volumes of lower-cost
inventories.

     Excluding the Melaka refinery, which came online in August of 1998,
Conoco's refineries operated at 98 percent capacity in 1999 versus 99 percent in
1998. Including the Melaka refinery, Conoco's refineries operated at 96 percent
capacity in 1999.

EMERGING BUSINESSES SEGMENT RESULTS

<TABLE>
<CAPTION>
                                                      YEAR ENDED DECEMBER 31
                                                --------------------------------
                                                  2000        1999        1998
                                                --------    --------    --------
                                                          (IN MILLIONS)
<S>                                             <C>         <C>         <C>
After-tax operating losses ..................   $    (69)   $    (35)   $    (31)
Special items ...............................         26          --          --
                                                --------    --------    --------
Losses before special items .................   $    (43)   $    (35)   $    (31)
                                                ========    ========    ========
</TABLE>

   2000 VERSUS 1999

     Emerging businesses after-tax operating losses were $69 million in 2000, an
impairment of $34 million from losses of $35 million in 1999, primarily
resulting from the $26 million write-off of Conoco's 37.5 percent interest in a
Colombian power venture, and from higher operating expenses required to grow
these new businesses. Emerging businesses operating losses before special items
for 2000 were $43 million, up $8 million from the $35 million loss in 1999.

   1999 VERSUS 1998

     Emerging businesses after-tax operating losses were $35 million in 1999,
essentially unchanged as compared to losses of $31 million in 1998. There were
no special items for 1999 and 1998 in emerging businesses.

CORPORATE SEGMENT RESULTS

<TABLE>
<CAPTION>
                                                           YEAR ENDED DECEMBER 31
                                                     --------------------------------
                                                       2000        1999        1998
                                                     --------    --------    --------
                                                               (IN MILLIONS)
<S>                                                  <C>         <C>         <C>
After-tax losses .................................   $   (104)   $    (98)   $   (250)
Special items ....................................          4          20         197
                                                     --------    --------    --------
Losses before special items ......................   $   (100)   $    (78)   $    (53)
                                                     ========    ========    ========
</TABLE>




                                       52
<PAGE>   55

   2000 VERSUS 1999

     Corporate after-tax losses were $104 million in 2000, an impairment of $6
million from losses of $98 million in 1999. Corporate losses before special
items for 2000 were $100 million, an impairment of $22 million from $78 million
in 1999, reflecting larger advertising and compensation costs and an increase in
other administrative costs associated with becoming an independent company.

   1999 VERSUS 1998

     Corporate after-tax losses were $98 million in 1999, an improvement of $152
million from losses of $250 million in 1998, primarily resulting from the
recording in 1998 of the $183 million one-time, after-tax, non-cash stock option
provision. Corporate losses before special items for 1999 were $78 million, an
impairment of $25 million from $53 million in 1998, due to increased
administrative costs associated with becoming an independent company.

INTEREST AND OTHER NON-OPERATING EXPENSES NET OF TAX

<TABLE>
<CAPTION>
                                                               YEAR ENDED DECEMBER 31
                                                          --------------------------------
                                                            2000        1999        1998
                                                          --------    --------    --------
                                                                   (IN MILLIONS)
<S>                                                       <C>         <C>         <C>
Interest expense on debt ..............................   $   (277)   $   (243)   $   (177)
Interest income .......................................         35          10          73
Exchange gains ........................................         38           6          32
                                                          --------    --------    --------
Total .................................................   $   (204)   $   (227)   $    (72)
                                                          ========    ========    ========
</TABLE>

   2000 VERSUS 1999

     Interest and other non-operating expenses of $204 million for 2000 were
down $23 million, or 10 percent, versus $227 million in 1999, primarily the
result of foreign currency exchange gains and higher interest income due to
higher average cash balances as a result of increased crude oil and natural gas
prices. These benefits were partially offset by higher interest expense on debt
due to higher interest rates.

   1999 VERSUS 1998

     Interest and other non-operating expenses of $227 million for 1999 were
$155 million higher than the previous year, primarily reflecting an increase in
interest expense, as debt was only outstanding for half of 1998. In addition,
interest income was reduced in 1999 on lower bank balances and 1998 included
significant exchange gains tied to DuPont intercompany loans eliminated as part
of the separation. Year-end 1999 results do not include comparable gains.

ENVIRONMENTAL EXPENDITURES

     The costs to comply with complex environmental laws and regulations, as
well as the cost of internal voluntary programs, are significant and will
continue to be so in the foreseeable future. Conoco anticipates substantial
expenditures will be necessary to comply with Maximum Achievable Control
Technology II (MACT II) standards to be promulgated by the U.S. Environmental
Protection Agency (EPA) under the Clean Air Act (CAA), and with specifications
for motor fuels designed to reduce emissions of certain pollutants from vehicles
using such fuels. These costs may increase in the future, but are not expected
to have a material adverse effect on our financial condition, results of
operations or liquidity.

     Estimated pretax environmental expenses charged to current operations
totaled about $165 million in 2000, compared to approximately $127 million in
1999 and $131 million in 1998. These expenses include remediation accruals;
operating, maintenance and depreciation costs for solid waste; air and water
pollution control facilities; and the costs of certain other environmental
activities. The largest of these expenses resulted from the operation of
wastewater treatment facilities, solid waste management facilities and
facilities for the control and abatement of air emissions. Approximately 78
percent of total annual environmental expenses in 2000 resulted from our U.S.
operations.




                                       53
<PAGE>   56

     Capital expenditures for environmental control facilities totaled
approximately $115 million in 2000, compared to about $81 million in 1999 and
$53 million in 1998. The 2000 increase is primarily attributable to a capital
spending increase of $15 million in European downstream operations to comply
with regulations requiring cleaner-burning fuels and $11 million largely
associated with the construction of a new acidic crude unit installed at our
Lake Charles refinery. Conoco estimates that capital expenditures will be about
$101 million in 2001, including about $28 million for complying with European
clean fuel regulations.

     In late 1999, the EPA published final rules, referred to as Tier 2, for
controlling future vehicle emissions and the sulfur content of gasoline. We are
positioning ourselves to be able to supply the low-sulfur gasoline as mandated
by the new Tier 2 regulations by the required date of 2004. We currently are
assessing the compliance costs that will be incurred. While it is premature to
accurately estimate these costs, they are expected to be in line with the
estimate of two to three cents per gallon included in the Tier 2 regulations.

     Early in 2001, the EPA published final rules controlling the future sulfur
content of on-road diesel fuel emissions. Conoco will be assessing the
requirements to comply with the new rules, which will take effect in June 2006.
It is too early to fully assess the compliance costs that may be incurred to
meet the on-road diesel requirements. Similar rules controlling the future
sulfur content of off-road diesel fuel emissions have not yet been finalized,
and therefore it is too early to estimate the costs to comply with those
standards.

   REMEDIATION EXPENDITURES

     The Resource Conservation and Recovery Act, as amended (RCRA), extensively
regulates the treatment, storage and disposal of hazardous waste and requires a
permit to conduct such activities. RCRA requires permitted facilities to
undertake an assessment of environmental conditions at the facility. If
conditions warrant, Conoco may be required to remediate contamination caused by
prior operations. In contrast to the Comprehensive Environmental Response,
Compensation and Liability Act, as amended (CERCLA), often referred to as
"Superfund," the cost of corrective action activities under the RCRA corrective
action program is typically borne solely by Conoco. Over the next decade, Conoco
anticipates that significant ongoing expenditures for RCRA remediation
activities may be required. However, annual expenditures for the near term are
not expected to vary significantly from the range of such expenditures over the
past few years. Conoco's expenditures associated with RCRA and similar
remediation activities conducted voluntarily or pursuant to state and foreign
laws were approximately $34 million in 2000, $33 million in 1999 and $27 million
in 1998. In the long term, expenditures are subject to considerable uncertainty
and may fluctuate significantly.

     Conoco from time to time receives requests for information or notices of
potential liability from EPA and state environmental agencies alleging that we
are a potentially responsible party under CERCLA or an equivalent state statute.
On occasion, Conoco also has been made a party to cost recovery litigation by
those agencies or by private parties. These requests, notices and lawsuits
assert potential liability for remediation costs at various sites that typically
are not owned by Conoco but allegedly contain wastes attributable to Conoco's
past operations. As of December 31, 2000, Conoco had been notified of potential
liability under CERCLA or comparable state law at about 17 sites around the
U.S., with active remediation under way at seven of those sites. Conoco received
notice of potential liability at two new sites during 2000, compared with four
similar notices in 1999 and one in 1998. Expenditures associated with CERCLA and
similar state remediation activities were not significant for Conoco in 2000,
1999 or 1998.

     For most Superfund sites, Conoco's potential liability will be
significantly less than the total site remediation costs because the percentage
of waste attributable to Conoco versus that attributable to all other
potentially responsible parties is relatively low. Other potentially responsible
parties at sites where Conoco is a party typically have had the financial
strength to meet their obligations, and where they have not, or where
potentially responsible parties could not be located, Conoco's own share of
liability has not materially increased. There are relatively few sites where
Conoco is a major participant, and neither the cost to Conoco of remediation at
those sites, nor such cost at all CERCLA sites in the aggregate, is expected to
have a material adverse effect on the competitive or financial condition of
Conoco.

     Cash expenditures not charged against income for previously accrued
remediation activities under CERCLA, RCRA and similar state and foreign laws
were $25 million in 2000, $26 million in 1999 and $17 million in 1998. Although
future remediation expenditures in excess of current reserves are possible, the
effect of any such excess on future financial results is not subject to
reasonable estimation because of the considerable uncertainty regarding the cost
and timing of expenditures.




                                       54
<PAGE>   57

   REMEDIATION ACCRUALS

     Conoco accrues for remediation activities when it is probable that a
liability has been incurred and reasonable estimates of the liability can be
made. These accrued liabilities exclude claims against Conoco's insurers or
other third parties and are not discounted. Many of these liabilities result
from CERCLA, RCRA and similar state laws that require Conoco to undertake
certain investigative and remedial activities at sites where we conduct, or once
conducted, operations or at sites where Conoco-generated waste was disposed. The
accrual also includes a number of sites identified by Conoco that may require
environmental remediation, but which are not currently the subject of CERCLA,
RCRA or state enforcement activities. Over the next decade, Conoco may incur
significant costs under both CERCLA and RCRA. Considerable uncertainty exists
with respect to these costs, and under adverse changes in circumstances,
potential liability may exceed amounts accrued as of December 31, 2000.

     Remediation activities vary substantially in duration and cost from site to
site depending on the mix of unique site characteristics, evolving remediation
technologies, diverse regulatory agencies and enforcement policies, and the
presence or absence of potentially liable third parties. Therefore, it is
difficult to develop reasonable estimates of future site remediation costs. At
December 31, 2000, Conoco's balance sheet included an accrued liability of $119
million, compared to $109 million at year-end 1999, for future site
remediation costs. Approximately 88 percent of Conoco's environmental reserve at
December 31, 2000, was attributable to RCRA and similar remediation liabilities
(excluding voluntary remediations) and 12 percent to CERCLA liabilities. During
2000, remediation accruals resulted in a $35 million charge, compared to a $6
million charge in 1999 and a $2 million charge in 1998.

TAX MATTERS

     In connection with the separation from DuPont and the initial public
offering, Conoco and DuPont entered into a tax sharing agreement. Several
matters under the tax sharing agreement remain in dispute between Conoco and
DuPont and currently are being arbitrated. Conoco currently expects that
DuPont's obligations to Conoco could total up to approximately $250 million,
plus interest. DuPont also has made claims related to the dispute, to which
Conoco has taken exception. The amount of such claims is not material. The
effect of the dispute currently is not reflected in Conoco's financial
statements, and regardless of the outcome of this dispute, Conoco believes the
result will not be material to its financial position or results of operations.

EUROPEAN MONETARY UNION

     Within Europe, the European Economic and Monetary Union (EMU) introduced a
new currency, the euro, on January 1, 1999. The new currency was in response to
the EMU's policy of economic convergence to harmonize trade policy, eliminate
business costs associated with currency exchange, and to promote the free flow
of capital goods and services.

     The euro has been adopted by 12 EMU countries as their local currency. The
most recent country was Greece, which joined the EMU and adopted the euro in
January 2001. The euro is initially available for currency trading on currency
exchanges and non-cash (banking) transactions. The existing local currencies, or
legacy currencies, will remain legal tender through January 1, 2002. Beginning
on January 1, 2002, euro-denominated notes and coins will be issued for cash
transactions. For a period of two months from this date, both legacy currencies
and the euro will be legal tender. However, when legacy currencies are offered,
any change returned will be in euro. For some countries, the legacy currency
will be withdrawn at the end of this two-month period. For other countries, the
legacy currency cannot be used for commerce after the two-month period, but can
be exchanged for euro at banks until the legacy currency is withdrawn on July 1,
2002.

     Conoco recognized the introduction of the euro as a significant event with
potential implications for existing operations. Currently, Conoco operates in a
number of countries that are participating in the EMU, including Austria,
Belgium, Finland, Germany and Spain (via a joint venture).

     In preparation for the introduction of the euro, Conoco reviewed the impact
of the euro's introduction on areas such as operations, finance, treasury,
legal, information management, procurement and others, both in participating and
nonparticipating European Union countries where Conoco currently operates.
Existing legacy accounting and business systems and other business assets were
reviewed for euro compliance, including





                                       55
<PAGE>   58

assessment of risks from third parties. Euro implementation progress within
Conoco is reported periodically to management. Amounts spent to date, and
anticipated future expenditures, for Conoco's conversion to the euro are not
material.

     Because of the staggered introduction of the euro regarding non-cash and
cash transactions, Conoco developed plans to address its accounting and business
systems first and its business assets second. Conoco undertook steps to be euro
compliant, within its accounting and business systems, by the end of 1998 to
meet conversion rules when performing translations between EMU currencies. The
accounting systems were modified so that EMU currencies were converted to other
EMU currencies via the euro rather than directly. Conoco had the capability to
conduct electronic transfers in euro commencing January 1, 1999. Conoco has an
implementation plan to convert its accounting and reporting systems from legacy
currency to the euro before January 1, 2002, for those operations that are in
EMU countries. This primarily will be accomplished via a significant upgrade to
Conoco's computer systems. The plan also incorporates steps to ensure the
corresponding business assets are fully compliant by that date, in preparation
for being able to utilize euro notes and coins to conduct business.

     Consistent with regulations and steps the industry is taking to familiarize
the public with the euro, conversion at our retail outlets is under way. The
conversion program varies between countries. Examples of the conversion program
include:

     o    conversion tables between EMU legacy currencies and the euro displayed
          at gasoline stations;

     o    stickers placed on the gasoline pumps with the equivalent euro price
          per liter;

     o    "Euro corners" installed in the shop part of stations with calculators
          and examples so the customers can practice converting from their EMU
          legacy currency to the euro; and

     o    the euro equivalent total printed at the bottom of receipts issued
          from cash registers.

     The business assets conversion program will continue throughout the
transition period and, in its final stages, will include new or modified pole
price signs, electronic euro price displays at the pump, new or modified
automatic cash machines and receipts that give a detailed itemized breakdown in
euros.

     Compliance in participating and nonparticipating countries will be achieved
primarily through the upgrading and modification of systems. Conoco does not
expect to experience any significant operational disruptions or to incur any
significant costs, including any currency risk, that could materially affect its
liquidity or capital resources. Conoco is preparing plans to address issues
within the transitional period when both legacy and euro currencies may be
tendered.

     Because of the competitive business environment within the petroleum
industry, Conoco does not anticipate any long-term competitive implications or
the need to materially change its mode of conducting business as a result of
increased price transparency.

RESTRUCTURING

     In December 1998, Conoco announced that as a result of a comprehensive
review of its assets and long-term strategy, Conoco would make organizational
realignments consistent with furthering the efficiency of operations and taking
advantage of synergies created by upgrading its asset portfolio. Associated with
the announcement, Conoco recorded an $82 million pretax ($52 million after-tax)
charge to operating expense in the fourth quarter of 1998. Nearly all of this
charge represented termination payments and related employee benefits to be made
to the estimated 975 persons in both upstream and downstream businesses affected
by the restructuring. Payments were made under existing company severance
policies, generally based on years of service up to a maximum amount that varied
by country.

     During 1999, 704 employees left Conoco as part of the implementation of the
realignment plans, with related charges against the restructuring reserve of $68
million. In the fourth quarter 1999, estimates of the number of severances were
revised due to changes in operational requirements. The original number of
estimated severances was reduced by 137 positions, primarily in our upstream
business, to 838 positions. The reduction of positions eliminated resulted in a
corresponding reduction in the restructuring reserve of $3 million that was
recorded in the fourth quarter 1999. Total charges and adjustments to the
reserve during 1999 were $71 million, resulting in a December 31, 1999 reserve
balance of $11 million.




                                       56
<PAGE>   59
     During the first half of 2000, 79 employees left Conoco as part of the
realignment plans. Related charges against the reserve totaled $6 million. The
remaining reserve balance of $5 million was reversed into earnings in the second
quarter of 2000.

NEW ACCOUNTING STANDARDS

     In June 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for
Derivative Instruments and Hedging Activities." In June 2000, the FASB issued
SFAS No. 138, "Accounting for Certain Derivative Instruments and Hedging
Activities," which made certain amendments to SFAS No. 133. These Standards,
which were required to be adopted by Conoco on January 1, 2001, modify the
criteria for identifying derivative instruments and require that derivatives,
whether in stand-alone contracts or, in certain cases, those embedded into other
contracts, be recorded at their fair value as assets or liabilities on the
balance sheet. In addition, the Standards prescribe the accounting for the gain
or loss resulting from changes in the fair value of derivatives designated as
hedging instruments as follows:

     o    the gain or loss on a fair value hedge (a hedge of the exposure to
          changes in the fair value of a recognized asset or liability or an
          unrecognized firm commitment) is recognized in earnings in the period
          of change together with the offsetting gain or loss on the hedged
          item;

     o    the gain or loss on a cash flow hedge (a hedge of the exposure to
          variable cash flow of a forecasted transaction) is initially reported
          as a component of other comprehensive income and subsequently
          reclassified into earnings when the forecasted transaction affects
          earnings;

     o    the gain or loss on a foreign currency hedge (a hedge of an exposure
          to risk of changes in foreign currency exchange rates) is initially
          reported as a component of other comprehensive income and subsequently
          reclassified into earnings when the foreign currency transaction
          affects earnings; and

     o    the ineffective portion of the gain or loss on derivatives designated
          as hedging instruments is recognized in earnings in the period of
          change.

     Conoco adopted SFAS No. 133 and SFAS No. 138 on January 1, 2001. As part of
the preparation for adoption of these Standards, Conoco completed an evaluation
of its Risk Management Policy and a review of its underlying business activities
in order to identify contractual arrangements that qualify as derivative
financial instruments pursuant to the requirements of the Standards. Consistent
with its Risk Management Policy, which was not changed as a result of this
evaluation, Conoco intends to use stand-alone derivative financial instruments
to manage its commodity price, foreign currency rate and interest rate risks. In
addition, Conoco intends to continue to conduct limited amounts of trading for
profit unrelated to its underlying physical business using stand-alone commodity
derivative financial instruments. Pursuant to these Standards, such trading for
profit contracts will continue to be reported on the balance sheet at fair value
consistent with the current treatment afforded such contracts under existing
generally accepted accounting principles.

     Upon initial adoption of the Standards on January 1, 2001, Conoco recorded
a cumulative transition gain of $37 million after-tax into net income, which was
mainly the result of certain derivative instruments that did not meet the
conditions for hedge accounting pursuant to the Standards, and $1 million into
other comprehensive income to reflect the fair value of derivatives as cash flow
hedges. In addition, $297 million was recorded as assets and $259 million was
recorded as liabilities.

     SFAS No. 133 and SFAS No. 138 are complex and subject to a potentially wide
range of interpretations in their application. As such, in 1998 the FASB
established the Derivative Implementation Group (DIG) task force specifically to
consider and to publish official interpretations of issues arising from the
implementation of these Standards. The DIG currently is considering several
issues, and the potential exists for additional issues to be brought under its
review. Therefore, if subsequent DIG interpretations of these Standards are
different than Conoco's initial application, it is possible that the impact of
Conoco's implementation, as stated above, will be modified.

     Conoco's Risk Management Policy is further explained in note 25 to the
consolidated financial statements.




                                       57
<PAGE>   60


ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

MARKET RISKS

     Conoco operates in the worldwide crude oil, refined product, natural gas,
natural gas liquids and electric power markets and is exposed to fluctuations in
hydrocarbon prices, foreign currency rates and interest rates. These
fluctuations can affect the revenues and cost of operating, investing and
financing. Conoco's management has used and intends to use financial and
commodity-based derivative contracts to reduce the risk in overall earnings and
cash flow when the benefits provided are anticipated to more than offset the
risk management costs involved.

     Conoco has established a Risk Management Policy that provides guidelines
for entering into contractual arrangements (derivatives) to manage its commodity
price, foreign currency rate and interest rate risks. The Conoco Risk Management
Committee has:

     o    an ongoing responsibility for the content of this policy;

     o    principal oversight responsibility to ensure Conoco is in compliance
          with the policy; and

     o    responsibility to ensure that procedures and controls are in place for
          the use of commodity, foreign currency and interest rate instruments.

     These procedures clearly establish derivative control and valuation
processes, routine monitoring and reporting requirements, and counterparty
credit approval procedures. Additionally, to assess the adequacy of internal
controls, Conoco's internal audit group reviews these risk management
activities. The audit results are then reviewed by both the Conoco Risk
Management Committee and by management.

     The counterparties to these contractual arrangements are limited to major
financial institutions and other established companies in the petroleum
industry. Although Conoco, in the event of nonperformance by these
counterparties, is exposed to credit loss, this exposure is managed through
credit approvals, limits and monitoring procedures and limits to the period over
which unpaid balances are allowed to accumulate. Conoco has not experienced
nonperformance by counterparties to these contracts, and no material loss would
be expected from any such nonperformance.

   COMMODITY PRICE RISK

     Conoco enters into energy-related futures, forwards, swaps and options in
various markets:

     o    to balance its physical systems;

     o    to meet customer needs; and

     o    to manage its price exposure on anticipated crude oil, natural gas,
          refined product and electric power transactions.

     These instruments provide a natural extension of the underlying cash market
and are used to physically acquire a portion of supply requirements. The
commodity futures market has greater liquidity and longer trading periods than
the cash market, and is one method of managing price risk in the energy
business.

     Conoco's policy is generally to be exposed to market pricing for commodity
purchases and sales. From time to time, management may use derivatives to
establish longer-term positions to hedge the price risk for Conoco's equity
crude oil and natural gas production, as well as its refinery margins.
Specifically, we have taken action to mitigate our exposure to volatile crude
oil prices through the purchase of crude oil put options, which reduce our
downside risk while maintaining our upside potential.

     Conoco does limited amounts of trading for profit unrelated to its
underlying physical business. After-tax gain or loss from trading for profit
activities has not been material.

     The fair value gain or loss of outstanding derivative commodity instruments
and the change in fair value that would be expected from a 10 percent adverse
price change are shown in the following table.



                                       58
<PAGE>   61
<TABLE>
<CAPTION>
                                                                                                    CHANGE IN FAIR
                                                                                                        VALUE
                                                                                                   FROM 10% ADVERSE
                                                                             FAIR VALUE              PRICE CHANGE
                                                                           ---------------          ---------------

<S>                                                                        <C>                      <C>
COMMODITY DERIVATIVES(1)
AT DECEMBER 31, 2000
Crude oil and refined products
   Trading ......................................................          $             1          $             1
   Non-trading(2) ...............................................                       92                      (29)
                                                                           ---------------          ---------------
Combined ........................................................          $            93          $           (28)
                                                                           ===============          ===============

Natural gas
   Trading ......................................................          $             3          $             2
   Non-trading ..................................................                      103                      (33)
                                                                           ---------------          ---------------
Combined ........................................................          $           106          $           (31)
                                                                           ===============          ===============

AT DECEMBER 31, 1999
Crude oil and refined products
   Trading ......................................................          $            10          $             2
   Non-trading ..................................................                       10                       (4)
                                                                           ---------------          ---------------
Combined ........................................................          $            20          $            (2)
                                                                           ===============          ===============

Natural gas
   Trading ......................................................          $            --          $            --
   Non-trading ..................................................                       --                       (8)
                                                                           ---------------          ---------------
Combined ........................................................          $            --          $            (8)
                                                                           ===============          ===============
</TABLE>

---------
(1)  Includes derivative instruments that can be settled in cash or by physical
     delivery of the commodity.

(2)  Includes purchased crude oil put options with a strike price of $22.00
     (West Texas Intermediate equivalent) per barrel on 63 million barrels
     during the period of April through December 2001.

     The fair values of the futures contracts are based on quoted market prices
obtained from the New York Mercantile Exchange or the International Petroleum
Exchange of London. The fair values of swaps and other over-the-counter
instruments are estimated based on quoted market prices of comparable contracts
and approximate the gain or loss that would have been realized if the contracts
had been closed out at year-end.

     Price-risk sensitivities were calculated by assuming an across-the-board 10
percent adverse change in prices regardless of term or historical relationships
between the contractual price of the instrument and the underlying commodity
price. In the event of an actual 10 percent change in prompt month crude oil or
natural gas prices, the fair value of Conoco's derivative portfolio would
typically change less than that shown in the table due to lower volatility in
out-month prices.

     Additional details regarding accounting policy for these financial
instruments are set forth in note 2 to the consolidated financial statements.

   FOREIGN CURRENCY RISK

     Conoco has foreign currency exchange rate risk resulting from operations in
over 40 countries around the world. Conoco does not comprehensively hedge its
exposure to currency rate changes, although it may choose to selectively hedge
exposures to foreign currency rate risk. Examples include firm commitments for
capital projects, certain local currency tax payments and dividends, and cash
returns from net investments in foreign affiliates to be remitted within the
coming year.

     In conjunction with our European commercial paper program, initiated in
2000, Conoco entered into foreign currency swaps for all non-U.S. dollar notes
issued in order to receive the U.S. dollar equivalent proceeds upon note
issuance and to lock in the forward foreign currency rate on note maturity. At
December 31, 2000, the U.S. dollar equivalent of all non-U.S. dollar notes
outstanding was $85 million, all of which were


                                       59
<PAGE>   62





swapped to the U.S. dollar. The notional amount of the forward portion of these
swaps was $81 million, and the estimated fair value was $86 million.

     At December 31, 2000, Conoco had open foreign currency exchange derivative
instruments of $45 million, related to anticipated foreign currency capital
investments, with an estimated fair value of $42 million. Conoco had no open
foreign currency exchange derivative instruments at December 31, 1999. A 10
percent adverse change in foreign currency exchange rates would change the fair
value of the derivative instruments by $4 million.

   INTEREST RATE RISK

     Conoco manages any material risk arising from exposure to interest rates by
using a combination of financial derivative instruments. This program was
developed to manage the fixed and floating interest rate mix of Conoco's total
debt portfolio and related overall cost of borrowing.

     At December 31, 2000, and at December 31, 1999, Conoco had no significant
open interest rate financial derivative instruments.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                                      INDEX

<TABLE>
<CAPTION>
                                                                                                              PAGE

<S>                                                                                                          <C>
Report of Management......................................................................................      61

Audited Consolidated Financial Statements

   Report of Independent Accountants......................................................................      62

   Consolidated Statement of Income - Years Ended December 31, 2000, 1999 and 1998........................      63

   Consolidated Balance Sheet - at December 31, 2000 and 1999.............................................      64

   Consolidated Statement of Stockholders' Equity/Owner's Net Investment and Accumulated
     Other Comprehensive Loss - Years Ended December 31, 2000, 1999 and 1998..............................      65

   Consolidated Statement of Cash Flows - Years Ended December 31, 2000, 1999 and 1998....................      66

   Notes to Consolidated Financial Statements.............................................................      67

Unaudited Financial Information

   Supplemental Petroleum Data - 2000, 1999 and 1998......................................................      99

   Consolidated Quarterly Financial Data - 2000 and 1999..................................................     105
</TABLE>




                                       60

<PAGE>   63

                              REPORT OF MANAGEMENT

     Management of Conoco Inc. is responsible for preparing the accompanying
consolidated financial statements and other information. The consolidated
financial statements have been prepared in accordance with generally accepted
accounting principles considered by management to present fairly Conoco's
financial position, results of operations and cash flows. The consolidated
financial statements include some amounts that are based on management's best
estimates and judgments.

     Conoco's system of internal controls is designed to provide reasonable
assurance as to the protection of assets against loss from unauthorized use or
disposition, and the reliability of financial records for preparing financial
statements and maintaining accountability for assets. Conoco's business ethics
policy is the cornerstone of our internal control system. This policy sets forth
management's commitment to conduct business worldwide with the highest ethical
standards and in conformity with applicable laws. The business ethics policy
also requires that all documents supporting transactions clearly describe their
true nature and that all transactions be properly reported and classified in the
financial records. An extensive internal audit program monitors Conoco's system
of internal controls. Management believes Conoco's system of internal controls
meets the objective noted above.

     Conoco's independent accountants, PricewaterhouseCoopers LLP, have audited
the consolidated financial statements. The purpose of their audit is to
independently affirm the fairness of management's reporting of financial
position, results of operations and cash flows. Management has made available to
PricewaterhouseCoopers LLP all of Conoco's financial records and related data,
as well as the minutes of the stockholders' and directors' meetings. To express
the opinion set forth in their report, PricewaterhouseCoopers LLP studies and
evaluates the internal controls to the extent they deem necessary. The adequacy
of Conoco's internal control systems and the accounting principles employed in
financial reporting are under the general oversight of the Audit and Compliance
Committee of the Board of Directors. This committee also has responsibility for
employing the independent accountants, subject to stockholder ratification. All
members of this committee are independent of Conoco, in compliance with the
rules of the New York Stock Exchange. The independent accountants and the
internal auditors have direct access to the Audit and Compliance Committee, and
they meet with the Audit and Compliance Committee from time to time, with and
without management present, to discuss accounting, auditing and financial
reporting matters.

<TABLE>
<S>                                      <C>                                    <C>
        /s/ ARCHIE W. DUNHAM                   /s/ ROBERT W. GOLDMAN                   /s/ W. DAVID WELCH
-----------------------------------      --------------------------------       --------------------------------
          Archie W. Dunham                       Robert W. Goldman                       W. David Welch
      Chairman, President and             Senior Vice President, Finance,               Controller and
      Chief Executive Officer               and Chief Financial Officer          Principal Accounting Officer
</TABLE>




                                       61
<PAGE>   64
                        REPORT OF INDEPENDENT ACCOUNTANTS


To the Stockholders and the Board of Directors of Conoco Inc.

     In our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of income, of stockholders' equity/owner's net
investment and accumulated other comprehensive loss, and of cash flows present
fairly, in all material respects, the financial position of Conoco Inc. and its
subsidiaries at December 31, 2000 and 1999, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 2000, in conformity with accounting principles generally accepted in the
United States of America. These financial statements are the responsibility of
the Company's management; our responsibility is to express an opinion on these
financial statements based on our audits. We conducted our audits of these
statements in accordance with auditing standards generally accepted in the
United States of America, which require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.



PRICEWATERHOUSECOOPERS LLP


Houston, Texas
February 19, 2001




                                       62
<PAGE>   65
                                   CONOCO INC.


                        CONSOLIDATED STATEMENT OF INCOME


<TABLE>
<CAPTION>
                                                                    YEAR ENDED DECEMBER 31
                                                            ---------------------------------------
                                                               2000          1999          1998
                                                            -----------   -----------   -----------
                                                                (IN MILLIONS, EXCEPT PER SHARE)
<S>                                                         <C>           <C>           <C>
Revenues
   Sales and other operating revenues* ..................   $    38,737   $    27,039   $    22,796
   Equity in earnings of affiliates (note 12) ...........           277           150            22
   Other income (note 4) ................................           273           120           350
                                                            -----------   -----------   -----------
         Total revenues .................................        39,287        27,309        23,168
                                                            -----------   -----------   -----------

Costs and expenses
   Cost of goods sold ...................................        23,921        14,781        11,751
   Operating expenses ...................................         2,215         2,060         2,089
   Selling, general and administrative expenses .........           794           809           736
   Stock option provision (note 22) .....................            --            --           236
   Exploration expenses .................................           279           270           380
   Depreciation, depletion and amortization .............         1,301         1,193         1,113
   Taxes other than on income* (note 5) .................         6,981         6,668         5,970
   Interest and debt expense (note 6) ...................           338           311           199
                                                            -----------   -----------   -----------
          Total costs and expenses ......................        35,829        26,092        22,474
                                                            -----------   -----------   -----------
Income before income taxes ..............................         3,458         1,217           694
Provision for income taxes (note 7) .....................         1,556           473           244
                                                            -----------   -----------   -----------
Net income ..............................................   $     1,902   $       744   $       450
                                                            ===========   ===========   ===========

Earnings per share** (note 8)
   Basic ................................................   $      3.05   $      1.19   $       .95
   Diluted ..............................................   $      3.00   $      1.17   $       .95

Weighted-average number of shares outstanding (note 8)
   Basic ................................................           624           627           474
   Diluted ..............................................           633           636           475

----------
*    Includes petroleum excise taxes ....................   $     6,774   $     6,492   $     5,801

**   Earnings per share for 1998, prior to Conoco's initial public offering, was calculated by using
     only Class B common stock, as required by SFAS No. 128 (see note 8).
</TABLE>


          See accompanying notes to consolidated financial statements.



                                       63
<PAGE>   66
                                   CONOCO INC.

                           CONSOLIDATED BALANCE SHEET



<TABLE>
<CAPTION>

                                                                                            DECEMBER 31
                                                                                      ------------------------
                                                                                         2000          1999
                                                                                      ----------    ----------
                                                                                            (IN MILLIONS)
<S>                                                                                   <C>           <C>
                                                   ASSETS

Current assets
   Cash and cash equivalents ......................................................   $      342    $      317
   Accounts and notes receivable (note 9) .........................................        1,837         1,735
   Inventories (note 10) ..........................................................          791           703
   Prepaid expenses and other current assets ......................................          441           313
                                                                                      ----------    ----------
         Total current assets .....................................................        3,411         3,068
Property, plant and equipment (note 11) ...........................................       23,890        22,476

Less: accumulated depreciation, depletion and amortization ........................      (11,683)      (11,241)
                                                                                      ----------    ----------
Net property, plant and equipment .................................................       12,207        11,235
Investment in affiliates (note 12) ................................................        1,831         1,604
Other assets (note 13) ............................................................          678           468
                                                                                      ----------    ----------
Total assets ......................................................................   $   18,127    $   16,375
                                                                                      ==========    ==========


                                    LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities
   Accounts payable (note 14) .....................................................   $    1,723    $    1,489
   Short-term borrowings and capital lease obligations (note 15) ..................          256           663
   Income taxes (note 7) ..........................................................          665           303
   Other accrued liabilities (note 16) ............................................        1,543         1,303
                                                                                      ----------    ----------
         Total current liabilities ................................................        4,187         3,758
Long-term borrowings and capital lease obligations (note 17) ......................        4,138         4,080
Deferred income taxes (note 7) ....................................................        1,911         1,689
Other liabilities and deferred credits (note 18) ..................................        1,926         1,958
                                                                                      ----------    ----------
         Total liabilities ........................................................       12,162        11,485
                                                                                      ----------    ----------

Commitments and contingent liabilities (note 26)
Minority interests (note 19) ......................................................          337           335
Stockholders' equity (note 20)
   Preferred stock, $.01 par value
     250,000,000 shares authorized; none issued ...................................           --            --
   Class A common stock, $.01 par value
     3,000,000,000 shares authorized; 191,497,821 shares issued with 186,646,358
       shares outstanding at December 31, 2000 and 189,039,861 shares
       outstanding at December 31, 1999 ...........................................            2             2
   Class B common stock, $.01 par value
     1,599,776,271 shares authorized, 436,786,482 shares issued and
       outstanding at December 31, 2000; 1,600,000,000 shares authorized,
       436,543,573 shares issued and outstanding at December 31, 1999 .............            4             4
   Additional paid-in capital .....................................................        4,932         4,941
   Retained earnings ..............................................................        1,460            44
   Accumulated other comprehensive loss (note 21) .................................         (653)         (372)
   Treasury stock, at cost
     4,851,463 and 2,457,960 Class A shares at December 31, 2000 and
       December 31, 1999, respectively ............................................         (117)          (64)
                                                                                      ----------    ----------

         Total stockholders' equity ...............................................        5,628         4,555
                                                                                      ----------    ----------
Total liabilities and stockholders' equity ........................................   $   18,127    $   16,375
                                                                                      ==========    ==========
</TABLE>

          See accompanying notes to consolidated financial statements.



                                       64
<PAGE>   67
                                   CONOCO INC.

    CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY/OWNER'S NET INVESTMENT AND
                      ACCUMULATED OTHER COMPREHENSIVE LOSS

                                (NOTES 20 AND 21)

<TABLE>
<CAPTION>
                                                                          RETAINED                    ACCUMULATED
                                                             ADDITIONAL   EARNINGS                       OTHER
                                      OWNER'S NET  COMMON     PAID-IN   (ACCUMULATED   COMPREHENSIVE COMPREHENSIVE   TREASURY
                                      INVESTMENT    STOCK     CAPITAL      DEFICIT)       INCOME         LOSS         STOCK
                                      ----------- ---------  ---------   ------------  -------------   ---------    ---------
                                                                         (IN MILLIONS)
<S>                                   <C>         <C>        <C>         <C>             <C>           <C>          <C>
Balance January 1, 1998 .............  $   8,087  $      --  $      --   $      --                     $    (191)   $      --
Comprehensive income
  Net income (loss) .................        694                              (244)      $     450
  Other comprehensive income (loss)
     Foreign currency translation
       adjustment ...................                                                          (25)
     Minimum pension liability
       adjustment ...................                                                          (58)
                                                                                         ---------
       Other comprehensive loss .....                                                          (83)          (83)
                                                                                         ---------
Comprehensive income ................                                                    $     367
                                                                                         =========

Cash distribution to owner ..........       (512)
Dividends to owner ..................     (8,200)
Other transfers from owner ..........        433
Capitalization from owner at initial
  public offering ...................       (502)         4        498
Initial public offering .............                     2      4,226
Compensation plans ..................                               (5)
Treasury stock purchases ............                                                                                      (5)
Stock option provision (note 22) ....                              236
                                       ---------  ---------  ---------   ---------                        ------    ---------
Balance December 31, 1998 ...........         --          6      4,955        (244)                         (274)          (5)
Comprehensive income
  Net income ........................                                          744       $     744
  Other comprehensive income (loss)
     Foreign currency translation
       adjustment ...................                                                         (162)
     Minimum pension liability
       adjustment ...................                                                           64
                                                                                         ---------
       Other comprehensive loss .....                                                          (98)          (98)
                                                                                         ---------
Comprehensive income ................                                                    $     646
                                                                                         =========
Adjustment to capitalization from
  owner at initial public
  offering (note 20) ................                              (26)
Dividends ...........................                                         (445)
Compensation plans ..................                               12
Treasury stock - purchases ..........                                                                                     (87)
               - issuances ..........                                          (11)                                        28
                                       ---------  ---------  ---------   ---------                     ---------    ---------
Balance December 31, 1999 ...........         --          6      4,941          44                          (372)         (64)
Comprehensive income
  Net income ........................                                        1,902       $   1,902
  Other comprehensive income (loss)..
     Foreign currency translation
       adjustment ...................                                                         (272)
     Minimum pension liability
       adjustment ...................                                                           (9)
                                                                                         ---------
       Other comprehensive loss .....                                                         (281)         (281)
                                                                                         ---------
Comprehensive income ................                                                    $   1,621
                                                                                         =========
Dividends ...........................                                        (474)
Compensation plans ..................                                           5
Redemption of minority interests ....                               (9)
Treasury stock - purchases ..........                                                                                     (90)
               - issuances ..........                                          (17)                                        37
                                       ---------  ---------  ---------   ---------                     ---------    ---------
Balance December 31, 2000 ...........  $      --  $       6  $   4,932   $   1,460                     $    (653)   $    (117)
                                       =========  =========  =========   =========                     =========    =========
</TABLE>



          See accompanying notes to consolidated financial statements.






                                       65
<PAGE>   68
                                   CONOCO INC.

                      CONSOLIDATED STATEMENT OF CASH FLOWS

<TABLE>
<CAPTION>
                                                                                     YEAR ENDED DECEMBER 31
                                                                           --------------------------------------
                                                                              2000          1999          1998
                                                                           ----------    ----------    ----------
                                                                                        (IN MILLIONS)
<S>                                                                        <C>           <C>           <C>
Cash provided by operations
   Net income ..........................................................   $    1,902    $      744    $      450
   Adjustments to reconcile net income to cash provided by operations
      Depreciation, depletion and amortization .........................        1,301         1,193         1,113
      Dry hole costs and impairment of unproved properties .............           88           131           163
      Stock option provision (note 22) .................................           --            --           236
      Inventory write-down to market (note 10) .........................           --            --            97
      Deferred income taxes (note 7) ...................................          236          (111)          (32)
      Income applicable to minority interests ..........................           24            25            21
      Gain on asset dispositions .......................................          (72)          (20)         (206)
      Undistributed equity earnings ....................................         (145)          (73)           83
      Other non-cash charges and credits - net .........................          (87)          (18)          (14)
      Decrease (increase) in operating assets
        Accounts and notes receivable ..................................         (153)         (573)          125
        Inventories ....................................................         (119)           80           (62)
        Other operating assets .........................................         (313)          107          (172)
      Increase (decrease) in operating liabilities
        Accounts and other operating payables ..........................          567           639           (69)
        Income and other taxes payable (notes 5 and 7) .................          209            92          (360)
                                                                           ----------    ----------    ----------
           Cash provided by operations .................................        3,438         2,216         1,373
                                                                           ----------    ----------    ----------
Investing activities (note 24)
    Purchases of property, plant and equipment .........................       (1,921)       (1,675)       (1,965)
    Purchases of businesses - net of cash acquired .....................         (661)           --            --
    Investments in affiliates - additions ..............................         (173)         (272)         (391)
                              - repayment of loans and advances ........           64            45             6
    Proceeds from sales of assets and subsidiaries .....................          222           162           721
    Net (increase) decrease in short-term financial instruments ........           (3)           34            31
                                                                           ----------    ----------    ----------
           Cash used in investing activities ...........................       (2,472)       (1,706)       (1,598)
                                                                           ----------    ----------    ----------
Financing activities
    Short-term borrowings (note 15) - receipts .........................       28,091        12,778            --
                                    - payments .........................      (28,498)      (12,156)          (26)
    Long-term borrowings - receipts ....................................           65         3,970            --
                         - payments ....................................           --           (20)           (4)
    Related party borrowings - receipts ................................           --           865           927
                             - payments ................................           --        (5,461)       (5,434)
    Related party notes receivable - receipts ..........................           --            --           444
                                   - payments ..........................           --            --          (152)
    Treasury stock - purchases .........................................          (90)          (87)           (5)
                   - proceeds from issuances ...........................           12            13            --
    Cash dividends .....................................................         (474)         (445)           --
    Proceeds from initial public offering ..............................           --            --         4,228
    Cash distribution to owner .........................................           --           (11)         (512)
    Minority interests (note 19) - receipts ............................           --           326            --
                                 - payments ............................          (26)         (324)          (21)
                                                                           ----------    ----------    ----------
           Cash used in financing activities ...........................         (920)         (552)         (555)
                                                                           ----------    ----------    ----------
Effect of exchange rate changes on cash ................................          (21)          (35)           27
                                                                           ----------    ----------    ----------
Increase (decrease) in cash and cash equivalents .......................           25           (77)         (753)
Cash and cash equivalents at beginning of year .........................          317           394         1,147
                                                                           ----------    ----------    ----------
Cash and cash equivalents at end of year ...............................   $      342    $      317    $      394
                                                                           ==========    ==========    ==========
SUPPLEMENTAL SCHEDULE OF NON-CASH FINANCING ACTIVITIES
Transactions with DuPont
    Dividends to owner .................................................   $       --    $       --    $   (8,200)
    Promissory note issued .............................................           --            --         7,500
    Notes receivable reduced ...........................................           --            --           700
    Borrowings contributed to capital ..................................           --            --          (544)
                                                                           ----------    ----------    ----------
Total non-cash financing activities ....................................   $       --    $       --    $     (544)
                                                                           ==========    ==========    ==========
</TABLE>

          See accompanying notes to consolidated financial statements.



                                       66
<PAGE>   69
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)

1. BASIS OF PRESENTATION

     Conoco is an integrated, global energy company that has three operating
segments--upstream, downstream and emerging businesses. Activities of the
upstream operating segment include exploring for, developing, producing and
selling crude oil, natural gas and natural gas liquids. Downstream operating
segment activities include refining crude oil and other feedstocks into
petroleum products; buying and selling crude oil and refined products; and
transporting, distributing and marketing petroleum products. Emerging businesses
operating segment activities include the development of new businesses beyond
our traditional operations with the potential to contribute substantially to
long-term growth. Conoco has five reporting segments. Four of these reporting
segments reflect geographic division between U.S. and international
operations in upstream and downstream businesses, and one segment is for
emerging businesses. Corporate includes general corporate expenses, financing
costs and other non-operating items and captive insurance operations.

     The initial public offering of the Class A common stock of Conoco commenced
on October 21, 1998. The initial public offering consisted of approximately 191
million shares of Class A common stock issued at a price of $23 per share and
represented E.I. du Pont de Nemours and Company's (DuPont) first step in the
planned divestiture of Conoco. After the initial public offering, DuPont owned
100 percent of Conoco's Class B common stock (approximately 437 million shares),
representing approximately 70 percent of Conoco's outstanding common stock and
approximately 92 percent of the combined voting power of all classes of voting
stock of Conoco. On August 6, 1999, DuPont concluded an exchange offer to its
stockholders, which resulted in all 437 million shares of Class B common stock
being distributed to DuPont stockholders. The exchange offer was the final step
in DuPont's planned divestiture of Conoco.

     Prior to the date of the initial public offering, operations were conducted
by Conoco and, in some cases, subsidiaries of DuPont. The accompanying
consolidated financial statements for 1998 are presented on a carve-out basis
prepared from DuPont's historical accounting records and include the historical
operations of both entities owned by Conoco and operations transferred to Conoco
by DuPont at the time of the initial public offering. In this context, no direct
ownership relationship existed among all the various units comprising Conoco.
Accordingly, cash distribution to owner prior to the initial public offering
included funds transferred between Conoco and DuPont for operating needs, cash
dividends paid and other equity transactions.

     Effective at the time of the initial public offering, Conoco's capital
structure was established and the transfer to Conoco of certain subsidiaries
previously owned by DuPont was substantially complete, resulting in direct
ownership of those subsidiaries. Accordingly, for periods subsequent to the
initial public offering, financial information is presented on a consolidated
basis.

     The consolidated statement of income includes all revenues and costs
directly attributable to Conoco. These costs include costs for facilities,
functions and services used by Conoco at shared sites and costs for certain
functions and services performed by centralized DuPont organizations and
directly charged to Conoco based on usage. In addition, services performed by
Conoco on DuPont's behalf are directly charged to DuPont. The results of
operations also include allocations of DuPont's general corporate expenses
through the date of the initial public offering.

     Prior to the date of the initial public offering, all charges and
allocations of cost for facilities, functions and services performed by DuPont
organizations for Conoco are deemed paid by Conoco to DuPont, in cash, in the
period in which the cost was recorded in the consolidated financial statements.
Allocations of current income taxes receivable or payable are similarly
considered remitted, in cash, by or to DuPont in the period the related income
taxes were recorded. Subsequent to the initial public offering, such costs are
billed directly under transitional service agreements, and income taxes are paid
directly to the taxing authorities, or to DuPont, as appropriate.

     All of the allocations and estimates in the consolidated financial
statements are based on assumptions that management believes are reasonable
under the circumstances. However, these allocations and estimates are not
necessarily indicative of the costs and expenses that would have resulted if
Conoco had been operated as a separate entity for periods prior to the initial
public offering.



                                       67
<PAGE>   70
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Consolidation

     The accounts of wholly owned and majority owned subsidiaries are included
in the consolidated financial statements. All intercompany balances have been
eliminated. The equity method is used to account for investments in corporate
entities, partnerships and limited liability companies in which Conoco exerts
significant influence, generally having a 20 percent to 50 percent ownership
interest. Conoco's 50.1 percent noncontrolling interest in Petrozuata C.A.,
located in Venezuela, is accounted for using the equity method. The equity
method is used because the minority shareholder, a subsidiary of PDVSA, the
national oil company of the Bolivarian Republic of Venezuela, has substantive
participating rights. Undivided interests in oil and gas properties under joint
operating agreements and in transportation assets are combined on a
proportionate gross basis. Other investments, excluding marketable securities,
are carried at cost.

Use of Estimates

     The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets, liabilities, revenues
and expenses, and the disclosure of contingent assets and liabilities. Actual
results may differ from those estimates and assumptions.

Revenue Recognition

     Revenues are recorded when title passes to the customer. Revenues from the
production of oil and gas properties in which Conoco has interests with other
companies are recorded on the basis of sales to customers. Differences between
these sales and our share of production are not significant. Revenues from
construction service contracts are recorded on a percentage-of-completion
method.

Cash Equivalents

     Cash equivalents represent investments with maturities of three months or
less from the time of purchase. They are carried at cost plus accrued interest,
which approximates fair value.

Inventories

     Inventories are carried at the lower of cost or market. Cost is determined
under the last-in, first-out (LIFO) method for inventories of crude oil and
petroleum products. Cost for remaining inventories, principally materials and
supplies, is generally determined by the average cost method. Market is
determined on a regional basis and any lower of cost or market write-down is
recorded as a permanent adjustment to the cost of inventory.

Property, Plant and Equipment (PP&E)

     PP&E is carried at cost, including interest capitalized on construction
projects. Depreciation of PP&E, other than oil and gas properties, is generally
computed on a straight-line basis over the estimated economic lives of the
facilities, which for major assets range from 14 to 25 years. When assets that
are part of a composite group are retired, sold, abandoned or otherwise disposed
of, the cost, net of sales proceeds or salvage value, is charged against the
accumulated reserve for depreciation, depletion and amortization (DD&A). Where
depreciation is accumulated for specific assets, gains or losses on disposal are
included in period income.

     Minor maintenance and repairs are charged to expense; replacements and
improvements are capitalized.




                                       68
<PAGE>   71
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)

Major Maintenance

     Conoco accrues in advance for planned major maintenance. Costs accrued,
which are classified as liabilities on the balance sheet, are primarily related
to work to be done as part of refinery turnarounds and drydock maintenance for
tankers, barges and boats.

Oil and Gas Properties

     Conoco follows the successful efforts method of accounting. Under
successful efforts, the costs of property acquisitions, successful exploratory
wells, development wells and related support equipment and facilities are
capitalized. The costs of producing properties are amortized at the field level
on a unit-of-production method.

     Unproved properties, which are individually significant, are periodically
assessed for impairment. The impairment of individually insignificant properties
is recorded by amortizing the costs based on past experience and the estimated
holding period. Exploratory well costs are expensed in the period a well is
determined to be unsuccessful. All other exploration costs, including geological
and geophysical costs, production costs and overhead costs, are expensed in the
period incurred.

     The estimated costs of dismantlement and removal of oil and gas related
facilities are accrued over the properties' productive lives using the
unit-of-production method and recognized as a liability as the amortization
expense is recorded.

Impairment of Long-lived Assets

     Long-lived assets, with recorded values that are not expected to be
recovered through future cash flows, are written down to current fair value
through additional amortization or depreciation provisions. Fair value is
generally determined from estimated discounted future net cash flows. Upstream
properties are evaluated at the field level.

Environmental Costs

     Environmental expenditures are expensed or capitalized, as appropriate,
depending on their future economic benefit. Expenditures that relate to an
existing condition caused by past operations, and that do not have future
economic benefit, are expensed. Liabilities related to future costs are recorded
on an undiscounted basis when environmental assessments and/or remediation
activities are probable and the costs can be reasonably estimated.

Stock Compensation

     Conoco applies the intrinsic value method of accounting for stock options
as prescribed by Accounting Principles Board (APB) Opinion No. 25, "Accounting
for Stock Issued to Employees," and related interpretations. Pro forma
information regarding changes in net income and earnings per share data, if the
accounting prescribed by Statement of Financial Accounting Standards (SFAS) No.
123, "Accounting for Stock-Based Compensation," had been applied, is presented
in note 22.

Income Taxes

     The provision for income taxes has been determined using the asset and
liability approach of accounting for income taxes. Under this approach, deferred
taxes represent the future tax consequences expected to occur when the reported
amounts of assets and liabilities are recovered or paid. The provision for
income taxes represents income taxes paid or payable for the current year plus
the change in deferred taxes during the year. Deferred taxes result from
differences between the financial and tax basis of Conoco's assets and
liabilities and are adjusted for changes in tax rates and tax laws when changes
are enacted. Valuation allowances are recorded to reduce deferred tax assets
when it is more likely than not that some or all of the deferred tax asset will
not be realized.

     Prior to the date of the initial public offering, Conoco was included in
the DuPont consolidated tax return, and the provision for income taxes was
determined using the loss benefit method. Under the loss benefit method, the
current tax provision or benefit is allocated based on the expected amount to be
paid or received from the




                                       69
<PAGE>   72

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)


consolidated group. Benefits of losses and credit carry forwards are recorded
when members of the consolidated group expect to realize such benefits. The pro
forma effect on the consolidated statement of income, reflecting the provision
for income taxes on a separate return basis prior to the initial public
offering, is not material. For periods ending after the initial public offering,
Conoco has filed separate tax returns. Accordingly, for periods subsequent to
the initial public offering, the provision for income taxes has been determined
on a separate tax return basis.

     Provision has been made for income taxes on unremitted earnings of
subsidiaries and affiliates, except in cases in which earnings are deemed to be
permanently invested.

Foreign Currency Translation

     The local currency is the functional currency for Conoco's integrated
western European and some eastern European petroleum operations. The euro has
been adopted as the local currency by the 12 countries participating in the
European Economic and Monetary Union. For those participating countries in which
Conoco operates, the euro concurrently became Conoco's functional currency. For
subsidiaries whose functional currency is the local currency, assets and
liabilities denominated in local currency are translated into U.S. dollars at
end-of-period exchange rates. The resultant translation adjustment is a
component of accumulated other comprehensive loss (see note 21). Monetary assets
and liabilities denominated in currencies other than the local currency are
remeasured into the local currency prior to translation into U.S. dollars. The
resultant exchange gains or losses, together with their related tax effects, are
included in income in the period in which they occur. Revenue and expenses are
translated into U.S. dollars at the average exchange rates in effect during the
period.

     For subsidiaries where the U.S. dollar is the functional currency, all
foreign currency asset and liability amounts are remeasured into U.S. dollars at
end-of-period exchange rates. Inventories, prepaid expenses and PP&E are
exceptions to this policy and are remeasured at historical rates. Foreign
currency revenue and expenses are remeasured at average exchange rates in effect
during the year. Exceptions to this policy include all expenses related to
balance sheet amounts that are remeasured at historical exchange rates. Exchange
gains and losses arising from remeasured foreign-currency-denominated monetary
assets and liabilities are included in current period income.

Commodity Hedging and Trading Activities

     Conoco enters into energy-related futures, forwards, swaps and options in
various markets:

     o    to balance its physical systems;

     o    to meet customer needs; and

     o    to manage its price exposure on anticipated crude oil, natural gas,
          refined product and electric power transactions.

     Gains and losses on non-trading contracts that are designated as hedges are
deferred and included in the measurement of the related transaction. Changes in
market values of all other derivative contracts are reflected in income in the
period the change occurs.

     In the event a derivative designated as a hedge is terminated prior to the
maturity of the hedged transaction, gains or losses at termination are deferred
and included in the measurement of the hedged transaction. If a hedged
transaction matures, is sold, extinguished or terminated prior to the maturity
of a derivative designated as a hedge of such transaction, then the gains or
losses associated with the derivative, through the maturity date of the
transaction, are included in the measurement of the hedged transaction. The
derivative also is reclassified as for trading purposes. Derivatives designated
as a hedge of an anticipated transaction are reclassified as for trading
purposes if the anticipated transaction is no longer expected to occur.

     In the consolidated statement of cash flows, Conoco reports the cash flows
resulting from its hedging activities in the same category as the related item
that is being hedged.



                                       70
<PAGE>   73
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)


Reclassifications

     Certain data in the prior years' financial statements have been
reclassified to conform to the 2000 presentation.

Recent Accounting Standards

     In June 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for
Derivative Instruments and Hedging Activities." In June 2000, the FASB issued
SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging
Activities," which made certain amendments to SFAS No. 133. These Standards,
which were required to be adopted by Conoco on January 1, 2001, modify the
criteria for identifying derivative instruments and require that derivatives,
whether in stand-alone contracts or, in certain cases, those embedded into other
contracts, be recorded at their fair value as assets or liabilities in the
balance sheet. In addition, the Standards prescribe the accounting for the gain
or loss resulting from changes in the fair value of derivatives designated as
hedging instruments as follows:

o    the gain or loss on a fair value hedge (a hedge of the exposure to changes
     in the fair value of a recognized asset or liability or an unrecognized
     firm commitment) is recognized in earnings in the period of change together
     with the offsetting gain or loss on the hedged item;

o    the gain or loss on a cash flow hedge (a hedge of the exposure to variable
     cash flow of a forecasted transaction) is initially reported as a component
     of other comprehensive income and subsequently reclassified into earnings
     when the forecasted transaction affects earnings;

o    the gain or loss on a foreign currency hedge (a hedge of an exposure to
     risk of changes in foreign currency exchange rates) is initially reported
     as a component of other comprehensive income and subsequently reclassified
     into earnings when the foreign currency transaction affects earnings; and

o    the ineffective portion of the gain or loss on derivatives designated as
     hedging instruments is recognized in earnings in the period of change.

     Conoco adopted SFAS No. 133 and SFAS No. 138 on January 1, 2001. As part of
the preparation for adoption of these Standards, Conoco completed an evaluation
of its Risk Management Policy and a review of its underlying business activities
in order to identify contractual arrangements that qualify as derivative
instruments pursuant to the requirements of the Standards. Consistent with its
Risk Management Policy, which was not changed as a result of this evaluation,
Conoco intends to use stand-alone derivative instruments to manage its commodity
price, foreign currency rate and interest rate risks. In addition, Conoco
intends to continue to conduct limited amounts of trading for profit unrelated
to its underlying physical business using stand-alone commodity derivative
instruments. Pursuant to these Standards, such trading for profit contracts will
continue to be reported on the balance sheet at fair value consistent with the
current treatment afforded such contracts under existing generally accepted
accounting principles.

     Upon initial adoption of the Standards on January 1, 2001, Conoco recorded
a cumulative transition gain of $37 after-tax into net income, which was mainly
the result of certain derivative instruments that did not meet the conditions
for hedge accounting pursuant to the Standards, and $1 into other comprehensive
income to reflect the fair value of derivatives intended as cash flow hedges. In
addition, $297 was recorded as assets and $259 was recorded as liabilities.

     SFAS No. 133 and SFAS No. 138 are complex and subject to a potentially wide
range of interpretations in their application. As such, in 1998 the FASB
established the Derivative Implementation Group (DIG) task force specifically to
consider and to publish official interpretations of issues arising from the
implementation of these Standards. The DIG currently is considering several
issues, and the potential exists for additional issues to be brought under its
review. Therefore, if subsequent DIG interpretations of these Standards are
different than Conoco's initial application, it is possible that the impact of
Conoco's implementation, as stated above, will be modified.

     Conoco's Risk Management Policy is further explained in note 25 to these
financial statements.




                                       71
<PAGE>   74
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)

3. TRANSACTIONS WITH DUPONT

     As disclosed in note 1, DuPont ceased to be a related party effective
August 6, 1999. However, the 1999 and 1998 consolidated financial statements
included related party transactions with DuPont involving services such as cash
management, other financial services, purchasing, legal, computer, corporate
aviation and general corporate expenses that were provided between Conoco and
DuPont organizations. For periods prior to the initial public offering, the
costs of services were directly charged or allocated between Conoco and DuPont
using methods management believes were reasonable. These methods included
negotiated usage rates, dedicated asset assignment and proportionate corporate
formulas involving assets, revenues and employees. Such charges and allocations
were not necessarily indicative of what would have been incurred if Conoco had
been a separate entity.

     Amounts charged to Conoco for these services were $21 for 1999 and $121 for
1998. These amounts were principally included in selling, general and
administrative expenses. Conoco provided DuPont services such as computer, legal
and purchasing, as well as certain technical and plant operating services.
Charges for these services amounted to $15 for 1999 and $61 for 1998. These
charges to DuPont were treated as reductions, as appropriate, of cost of goods
sold, operating expenses or selling, general and administrative expenses.

     Interest expense charged by DuPont was $91 for 1999 and $264 for 1998.
Interest charged by DuPont reflected market-based interest rates. A portion of
historical related party interest cost and other interest expense was
capitalized as cost associated with major construction projects. Interest income
from DuPont was $43 for 1998, and also reflected market-based interest rates.

     Sales and other operating revenues included sales of products from Conoco
to DuPont, principally natural gas and gas liquids supplied to several DuPont
plant sites. These sales totaled $211 for 1999 and $427 for 1998. Also included
for 1998 was $20 in revenues from insurance premiums charged to DuPont for
property and casualty coverage outside the U.S. Purchases of products from
DuPont during these periods were not material. Subsequent to the initial public
offering, these intercompany arrangements between DuPont and Conoco, excluding
insurance coverage provided to DuPont, were provided under transition service
agreements or other long-term agreements.

     In April 1999, Conoco issued and sold in a public offering $4,000 in senior
fixed-rate debt securities with a weighted-average interest rate of 6.49
percent. The $3,970 net proceeds of this offering were used to repay a portion
of Conoco's separation-related indebtedness to DuPont that was incurred in 1998.
The remaining debt owed to DuPont was repaid in May 1999 with proceeds from a
commercial paper program (see note 15).

4. OTHER INCOME

<TABLE>
<CAPTION>
                                                    2000         1999        1998
                                                  ---------    ---------   ---------
<S>                                               <C>          <C>         <C>
Interest income
   DuPont (see note 3) ........................   $      --    $      --   $      43
   Other ......................................          39           25          46
                                                  ---------    ---------   ---------
   Total ......................................          39           25          89
Gain on sales of assets and subsidiaries (1) ..          72           26         207
Write-off of Colombia power venture ...........         (26)          --          --
Syrian service contract .......................         110            3          --
Exchange gain (loss) and other ................          78           66          54
                                                  ---------    ---------   ---------
Other income ..................................   $     273    $     120   $     350
                                                  =========    =========   =========
</TABLE>

----------

(1)  2000 includes a gain of $42 from the sale of Oklahoma gas properties. 1998
     includes a gain of $89 from the sale of certain upstream properties in the
     North Sea and the U.S.


                                       72
<PAGE>   75
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)


5. TAXES OTHER THAN ON INCOME

<TABLE>
<CAPTION>
                                                                                 2000         1999         1998
                                                                               ---------    ---------    ---------
<S>                                                                            <C>          <C>          <C>
Petroleum excise taxes
   U.S. ....................................................................   $   1,572    $   1,495    $   1,286
   Non-U.S. ................................................................       5,202        4,997        4,515
                                                                               ---------    ---------    ---------
      Total ................................................................       6,774        6,492        5,801
Payroll taxes ..............................................................          45           44           42
Property taxes .............................................................          65           64           64
Production and other taxes .................................................          97           68           63
                                                                               ---------    ---------    ---------
Taxes other than on income..................................................   $   6,981    $   6,668    $   5,970
                                                                               =========    =========    =========
</TABLE>

6. INTEREST AND DEBT EXPENSE

<TABLE>
<CAPTION>
                                                                                 2000         1999         1998
                                                                               ---------    ---------    ---------
<S>                                                                            <C>          <C>          <C>
Interest and debt cost incurred
   DuPont (see note 3) .....................................................   $      --    $      91    $     264
   Other debt and capital leases ...........................................         354          226            7
                                                                               ---------    ---------    ---------
      Total ................................................................         354          317          271
Less: Interest and debt cost capitalized ...................................          16            6           72
                                                                               ---------    ---------    ---------
Interest and debt expense (1) ..............................................   $     338    $     311    $     199
                                                                               =========    =========    =========
</TABLE>

----------

(1) Interest paid, net of amounts capitalized, was $331 in 2000, $297 in 1999
and $145 in 1998.

7. PROVISION FOR INCOME TAXES

<TABLE>
<CAPTION>
                                                                                 2000         1999         1998
                                                                               ---------    ---------    ---------
<S>                                                                            <C>          <C>          <C>
Current tax expense
    U.S. federal ...........................................................   $     126    $      26    $     (57)
    U.S. state and local ...................................................          11            4           10
    Non-U.S. ...............................................................       1,183          554          323
                                                                               ---------    ---------    ---------
      Current tax expense ..................................................       1,320          584          276
                                                                               ---------    ---------    ---------

Deferred tax expense
    U.S. federal ...........................................................         125          (84)         (51)
    U.S. state and local ...................................................           3           (5)          (5)
    Non-U.S. ...............................................................         108          (22)          24
                                                                               ---------    ---------    ---------
      Deferred tax expense .................................................         236         (111)         (32)
                                                                               ---------    ---------    ---------

Provision for income taxes .................................................       1,556          473          244
    Foreign currency translation (see note 21) .............................         (83)         (29)         (22)
    Minimum pension liability (see note 21) ................................          (5)          29          (26)
                                                                               ---------    ---------    ---------
Total provision ............................................................   $   1,468    $     473    $     196
                                                                               =========    =========    =========
</TABLE>

     Total income taxes paid worldwide were $1,030 in 2000, $493 in 1999 and
$714 in 1998.




                                       73
<PAGE>   76
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)


    At December 31, 2000 and 1999, deferred taxes were classified in the
consolidated balance sheet as follows:

<TABLE>
<CAPTION>
                                                    2000          1999
                                                 ----------    ----------
<S>                                              <C>           <C>
Prepaid expenses and other current assets ....   $      (43)   $      (15)
Other assets (see note 13) ...................          (39)          (61)
Income taxes .................................           66            27
Deferred income taxes ........................        1,911         1,689
                                                 ----------    ----------

Net deferred tax liabilities .................   $    1,895    $    1,640
                                                 ==========    ==========
</TABLE>

     The significant components of deferred tax liabilities/(assets) at December
31, 2000 and 1999 were as follows:

<TABLE>
<CAPTION>
                                                    2000          1999
                                                 ----------    ----------
<S>                                              <C>           <C>
Deferred tax liabilities
  PP&E .......................................   $    2,452    $    2,349
  Inventories ................................           15            46
  Other ......................................          181            85
                                                 ----------    ----------
      Deferred tax liabilities ...............        2,648         2,480

Deferred tax assets
  PP&E .......................................          (35)         (244)
  Employee benefits ..........................         (252)         (241)
  Other accrued expenses .....................         (275)         (236)
  Tax loss/tax credit carry forwards .........         (442)         (512)
  Other ......................................         (158)          (59)
                                                 ----------    ----------
      Deferred tax assets ....................       (1,162)       (1,292)
Valuation allowance ..........................          409           452
                                                 ----------    ----------
      Net deferred tax assets ................         (753)         (840)
                                                 ----------    ----------

Net deferred tax liabilities .................   $    1,895    $    1,640
                                                 ==========    ==========
</TABLE>

     Valuation allowances, which reduce deferred tax assets to an amount that
will more likely than not be realized, decreased $43 in 2000. This reflects a
$123 decrease related to tax assets representing operating losses, which Conoco
determined will more likely than not be realized in future years and tax loss
carry forwards that have been relinquished or expired. This decrease is
partially offset by an $80 increase used to offset tax assets representing
operating and tax losses incurred in exploration, production and start-up
operations. Valuation allowances increased $29 in 1999 primarily reflecting an
$80 increase in the valuation allowance used to offset operating losses incurred
in exploration, production and start-up operations, partially offset by a $51
decrease related to tax assets representing operating losses.

     Under the tax laws of various jurisdictions in which Conoco operates,
deductions or credits that cannot be fully utilized for tax purposes during the
current year may be carried forward. These loss carry forwards, subject to
statutory limitations, can reduce taxable income or taxes payable in a future
year. At December 31, 2000, the tax effect of such loss carry forwards
approximated $442. Of this amount, $166 has no expiration date, $76 expires in
2001, $6 expires in 2002, $39 expires in 2003, $71 expires in 2004 and $84
expires in 2005 and later years.

     In connection with the separation from DuPont and the initial public
offering, Conoco and DuPont entered into a tax sharing agreement. Several
matters under the tax sharing agreement remain in dispute between Conoco and
DuPont and are currently being arbitrated. Conoco currently expects that
DuPont's obligations to Conoco could total up to approximately $250, plus
interest. DuPont also has made claims related to the dispute, to which Conoco
has taken exception. The amount of such claims is not material. The effect of
the dispute currently is not reflected in Conoco's financial statements and,
regardless of the outcome of this dispute, Conoco believes the result will not
be material to its financial position or results of operations.




                                       74
<PAGE>   77
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)


     An analysis of Conoco's effective income tax rate follows:

<TABLE>
<CAPTION>
                                                              2000          1999          1998
                                                            ---------     ---------     ---------
<S>                                                         <C>           <C>           <C>
Statutory U.S. federal income tax rate ..................        35.0%         35.0%         35.0%
Higher tax rate on international operations .............        11.3          10.0           7.8
Alternative fuels credit ................................        (1.2)         (4.0)         (8.2)
Reduced tax benefit from stock option provision .........          --            --           4.9
Realization of unbenefited loss from sale of subsidiary .          --            --          (4.6)
Other - net .............................................        (0.1)         (2.1)          0.3
                                                            ---------     ---------     ---------
Effective income tax rate ...............................        45.0%         38.9%         35.2%
                                                            =========     =========     =========
</TABLE>

     Income before income taxes was based on the location of the corporate unit
to which such earnings are attributable. However, since such earnings were often
subject to taxation in more than one country, the income tax provision shown
above, as U.S. or non-U.S., does not correspond to the earnings as set forth in
the following table.

<TABLE>
<CAPTION>
                                                               2000        1999        1998
                                                            ---------   ---------   ---------
<S>                                                         <C>         <C>         <C>
U.S. ....................................................   $     735   $      93   $    (173)
Non-U.S. ................................................       2,723       1,124         867
                                                            ---------   ---------   ---------
Income before income taxes ..............................   $   3,458   $   1,217   $     694
                                                            =========   =========   =========
</TABLE>

     Unremitted earnings of international subsidiaries totaling $1,661 at
December 31, 2000, and $1,488 at December 31, 1999, were deemed to be
permanently invested. No deferred tax liability was recognized for the
remittance of such earnings. It is not practicable to estimate the income tax
liability that might be incurred if such earnings were remitted to the U.S.

8. EARNINGS PER SHARE

     Basic earnings per share (EPS) is computed by dividing net income (the
numerator) by the weighted-average number of common shares outstanding plus the
effects of certain Conoco employee and director awards and fee deferrals that
are invested in Conoco stock units (the denominator). Diluted EPS is similarly
computed, except that the denominator is increased to include the dilutive
effect of outstanding stock options awarded under Conoco's compensation plans
(see note 22).

     As described in note 1, Conoco's capital structure was established at the
time of the initial public offering. In accordance with SEC Staff Accounting
Bulletin No. 98, the capitalization of Class B common stock has been
retroactively reflected for the purpose of presenting earnings per share for
periods prior to the initial public offering. For the periods subsequent to the
initial public offering, basic EPS reflects the weighted-average number of
shares of Class A and Class B common stock and deferred award units outstanding.
Corresponding diluted EPS includes the dilutive effect of an additional
8,405,998 shares for 2000, an additional 9,241,896 shares for 1999 and an
additional 1,659,816 shares for 1998. These additional shares for 1998 represent
the weighted-average dilutive effect of outstanding stock options that resulted
from the concurrent cancellation of DuPont stock options at the date of the
initial public offering and the issuance of options with respect to Class A
common stock.

     The denominator is based on the following weighted-average number of common
shares outstanding:

<TABLE>
<CAPTION>
                                                                 2000                1999                 1998
                                                        ------------------   -----------------    -----------------
<S>                                                     <C>                  <C>                  <C>
Basic..................................................       624,354,441         627,233,229          473,826,632
Diluted................................................       632,760,439         636,475,125          475,486,448
</TABLE>

     Variable stock options for 3,124,146 shares of Class A and Class B common
stock were outstanding at December 31, 2000 and 1999. At December 31, 1998,
variable stock options for 1,724,146 shares of Class A and


                                       75
<PAGE>   78
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)

Class B common stock were outstanding. These options were not included in the
computation of diluted EPS because the threshold price required for these
options to be vested had not been reached.

     Common shares held as treasury stock are deducted in determining the number
of shares outstanding.

     Fixed stock options for 89,530; 30,972; and 28,796 shares of Class A common
stock were not included in the diluted earnings per share calculation for 2000,
1999 and 1998, respectively, because the exercise price was greater than the
average market price.

9. ACCOUNTS AND NOTES RECEIVABLE

<TABLE>
<CAPTION>
                                                         DECEMBER 31
                                                  -----------------------
                                                    2000         1999
                                                  ----------   ----------
<S>                                               <C>          <C>
Trade .........................................   $    1,506   $    1,394
Notes and other ...............................          331          341
                                                  ----------   ----------
Accounts and notes receivable .................   $    1,837   $    1,735
                                                  ==========   ==========
</TABLE>

     Included in the preceding table are accounts and notes receivable from
affiliated companies (see note 12) of $548 at December 31, 2000, and $115 at
December 31, 1999.

     The carrying value of accounts and notes receivable approximates fair value
because of their short maturity.

     See note 27 for a description of operating segment markets and associated
concentrations of credit risk.

10. INVENTORIES

<TABLE>
<CAPTION>
                                                       DECEMBER 31
                                                  ---------------------
                                                    2000        1999
                                                  ---------   ---------
<S>                                               <C>         <C>
Crude oil and petroleum products ..............   $     643   $     554
Other merchandise .............................          27          33
Materials and supplies ........................         121         116
                                                  ---------   ---------
Inventories ...................................   $     791   $     703
                                                  =========   =========
</TABLE>

     The excess of market over book value of inventories valued under the LIFO
method was $643 and $430 at December 31, 2000 and 1999, respectively. In the
fourth quarter of 1998, a write-down to market of $97 was made in accordance
with Conoco's inventory valuation policy (see note 2). Inventories valued at
LIFO represented 81 percent and 78 percent of consolidated inventories at
December 31, 2000 and 1999, respectively.

     During 2000, certain inventory quantities were reduced, resulting in a
partial liquidation of the LIFO basis. The 2000 liquidation of inventories,
carried at lower costs prevailing in prior years, as compared with the
replacement costs of these inventories, had no material effect on net income.
The effect of a liquidation of the LIFO basis during 1999 decreased cost of
goods sold by approximately $67 and increased net income by approximately $42,
or $.07 per diluted share. There was no material effect on net income in 1998
for LIFO reductions.



                                       76
<PAGE>   79
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)

11. PROPERTY, PLANT AND EQUIPMENT

<TABLE>
<CAPTION>
                                                 DECEMBER 31
                                ---------------------------------------------
                                        COST                     NET
                                ---------------------   ---------------------
                                  2000        1999        2000        1999
                                ---------   ---------   ---------   ---------
<S>                             <C>         <C>         <C>         <C>
Oil and gas properties
   Unproved .................   $   1,106   $   1,201   $     920   $     985
   Proved ...................      14,730      13,661       6,719       5,990
Other .......................       1,449       1,222       1,009         792
                                ---------   ---------   ---------   ---------
       Total upstream .......      17,285      16,084       8,648       7,767
Refining ....................       4,264       4,082       2,161       2,072
Marketing and distribution ..       2,202       2,214       1,292       1,309
                                ---------   ---------   ---------   ---------
       Total downstream .....       6,466       6,296       3,453       3,381
Emerging businesses .........          58          60          58          60
Corporate ...................          81          36          48          27
                                ---------   ---------   ---------   ---------

PP&E ........................   $  23,890   $  22,476   $  12,207   $  11,235
                                =========   =========   =========   =========
</TABLE>

     PP&E includes downstream assets acquired under capital leases of $36 at
December 31, 2000, and December 31, 1999. Related amounts included in
accumulated DD&A were $16 at December 31, 2000, and $15 at December 31, 1999.

12. SUMMARIZED FINANCIAL INFORMATION FOR AFFILIATED COMPANIES

     Summarized consolidated financial information for Petrozuata C.A. (50.1
percent noncontrolling interest) and other affiliated companies for which
Conoco uses the equity method of accounting (see note 2, "Basis of
Consolidation") is shown below. "Other Affiliates" includes the financial
information of, among others, the following: Ceska Rafinerska, a.s. (16.33
percent), CFJ Properties (50 percent), Excel Paralubes (50 percent), Malaysian
Refining Company Sdn. Bhd. (40 percent), Pocahontas Gas Partnership (50 percent)
and Polar Lights Company (50 percent).

<TABLE>
<CAPTION>
                                                                             100%
                                                        -------------------------------------------------
                                                                             OTHER                              CONOCO'S
                                                          PETROZUATA       AFFILIATES         TOTAL               SHARE
                                                        --------------   ---------------  ---------------    -------------
<S>                                                     <C>              <C>              <C>                <C>
2000
RESULTS OF OPERATIONS
Sales..............................................     $          512   $        10,836  $        11,348    $       4,368
Cost of goods sold.................................     $           17   $         8,031  $         8,048    $       3,287
Operating expenses.................................     $          125   $         1,349  $         1,474    $         493
DD&A...............................................     $           26   $           380  $           406    $         133
Interest...........................................     $           40   $           165  $           205    $          86
Earnings before income taxes.......................     $          307   $           744  $         1,051    $         387
Net income (1).....................................     $          294   $           545  $           839    $         277
FINANCIAL POSITION
Current assets.....................................     $          324   $         2,238  $         2,562    $         874
Non-current assets.................................              2,799             7,423           10,222            3,638
                                                        --------------   ---------------  ---------------    -------------
Total assets.......................................     $        3,123   $         9,661  $        12,784    $       4,512
                                                        ==============   ===============  ===============    =============
Short-term borrowings (2)..........................     $           --   $           564  $           564    $         163
Other current liabilities..........................                218             1,604            1,822              603
Long-term borrowings (2)...........................              1,373             3,938            5,311            1,787
Other long-term liabilities........................              1,174               721            1,895              793
                                                        --------------   ---------------  ---------------    -------------
Total liabilities..................................     $        2,765   $         6,827  $         9,592    $       3,346
                                                        ==============   ===============  ===============    =============
Conoco's net investment in affiliates (includes
  advances)........................................     $          693   $         1,138                     $       1,831
                                                        ==============   ===============                     =============
</TABLE>




                                       77
<PAGE>   80
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)


<TABLE>
<CAPTION>
                                                                             100%
                                                        -------------------------------------------------
                                                                             OTHER                              CONOCO'S
                                                          PETROZUATA       AFFILIATES         TOTAL               SHARE
                                                        --------------   ---------------  ---------------    -------------
<S>                                                     <C>              <C>              <C>                <C>
1999
RESULTS OF OPERATIONS
Sales..............................................     $          228   $         8,304  $         8,532    $       3,208
Cost of goods sold.................................     $           --   $         5,665  $         5,665    $       2,361
Operating expenses.................................     $           84   $         1,340  $         1,424    $         452
DD&A...............................................     $           26   $           314  $           340    $         127
Interest...........................................     $           24   $           208  $           232    $          80
Earnings before income taxes.......................     $           92   $           665  $           757    $         163
Net income.........................................     $          109   $           490  $           599    $         150
FINANCIAL POSITION
Current assets.....................................     $          190   $         2,662  $         2,852    $         776
Non-current assets.................................              2,202             6,702            8,904            3,223
                                                        --------------   ---------------  ---------------    -------------
Total assets.......................................     $        2,392   $         9,364  $        11,756    $       3,999
                                                        ==============   ===============  ===============    =============
Short-term borrowings (2)..........................     $           --   $           581  $           581    $         182
Other current liabilities..........................                149             1,525            1,674              588
Long-term borrowings (2)...........................              1,282             3,719            5,001            1,677
Other long-term borrowings.........................                896               422            1,318              522
                                                        --------------   ---------------  ---------------    -------------
Total liabilities..................................     $        2,327   $         6,247  $         8,574    $       2,969
                                                        ==============   ===============  ===============    =============
Conoco's net investment in affiliates (includes
  advances)........................................     $          445   $         1,159                     $       1,604
                                                        ==============   ===============                     =============
1998
RESULTS OF OPERATIONS
Sales..............................................     $            9   $         6,735  $         6,744    $       2,386
Cost of goods sold.................................     $           --   $         4,195  $         4,195    $       1,679
Operating expenses.................................     $           46   $         1,438  $         1,484    $         488
DD&A...............................................     $            7   $           276  $           283    $          97
Interest...........................................     $           21   $           323  $           344    $          55
Earnings before income taxes.......................     $          (54)  $           412  $           358    $          43
Net income.........................................     $          (16)  $           268  $           252    $          22
</TABLE>

----------

(1)  For 2000, Conoco's equity in Petrozuata's earnings totaled $147.

(2)  Equity affiliate borrowings of $979 in 2000 and $1,005 in 1999 were
     guaranteed by Conoco or DuPont, on behalf of and indemnified by Conoco.
     These amounts are included in the guarantees disclosed in note 26. In
     addition, Conoco owns 2.0 billion shares of Turcas Petrol A.S., of which
     909 million shares at December 31, 2000, and 1.3 billion shares at December
     31, 1999, were pledged to a group of Turkish banks that issued letters of
     credit in support of a $70 long-term debt instrument.

     Equity affiliate sales to Conoco amounted to $804 in 2000, $720 in 1999 and
$412 in 1998. Equity affiliate purchases from Conoco totaled $2,200 in 2000,
$1,519 in 1999 and $1,219 in 1998.

     Dividends received from equity affiliates were $132 in 2000, $77 in 1999
and $105 in 1998. Conoco's equity in undistributed earnings of its affiliated
companies was $446 at December 31, 2000, and $366 at December 31, 1999.




                                       78
<PAGE>   81
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)


13. OTHER ASSETS

<TABLE>
<CAPTION>
                                                                                                DECEMBER 31
                                                                                        ---------------------------
                                                                                           2000            1999
                                                                                        -----------    ------------
<S>                                                                                     <C>            <C>
Prepaid pension cost (see note 23)..................................................... $        5     $        13
Long-term receivables (1)..............................................................        280              69
Other securities and investments.......................................................        105              87
Leveraged lease on Deepwater Pathfinder................................................         61              55
Deferred tax assets (see note 7).......................................................         39              61
Deferred pension transition obligation (see note 23)...................................         33              54
Other (2)..............................................................................        155             129
                                                                                        ----------     -----------
Other assets........................................................................... $      678     $       468
                                                                                        ==========     ===========
</TABLE>

----------

(1)  Includes $223 at December 31, 2000, and $10 at December 31, 1999,
     attributable to a long-term service contract to develop gas and condensate
     infrastructure in Syria. Once the infrastructure is in place, this amount
     is recoverable from the gas and condensate revenue stream generated over a
     period up to five years commencing in late 2001.

(2)  Includes intangible assets of $10 at December 31, 2000, and $14 at December
     31, 1999.

14. ACCOUNTS PAYABLE

<TABLE>
<CAPTION>
                                                                                                DECEMBER 31
                                                                                        ---------------------------
                                                                                           2000            1999
                                                                                        -----------    ------------
<S>                                                                                     <C>            <C>
Trade.................................................................................. $    1,287     $       959
Payables to banks......................................................................        130              81
Product exchanges......................................................................        217             210
Other..................................................................................         89             239
                                                                                        ----------     -----------
Accounts payable....................................................................... $    1,723     $     1,489
                                                                                        ==========     ===========
</TABLE>

     Included in the preceding table are accounts payable to affiliated
companies (see note 12) of $573 at December 31, 2000, and $100 at December 31,
1999.

     Payables to banks represent checks issued on certain disbursement accounts
but not presented to the banks for payment. The amounts above are carried at
historical cost, which approximate fair value because of their short maturity.

15. SHORT-TERM BORROWINGS AND CAPITAL LEASE OBLIGATIONS

<TABLE>
<CAPTION>
                                                                                                DECEMBER 31
                                                                                        ---------------------------
                                                                                           2000            1999
                                                                                        -----------    ------------
<S>                                                                                     <C>            <C>
Commercial paper....................................................................... $      187     $       628
Industrial development bonds...........................................................         59              24
Long-term borrowings payable within one year...........................................          8               9
Capital lease obligations..............................................................          2               2
                                                                                        ----------     -----------
Short-term borrowings and capital lease obligations.................................... $      256     $       663
                                                                                        ==========     ===========
</TABLE>

     These amounts are carried at historical cost, which approximate fair value
because of their short maturity.

     At December 31, 2000 and December 31, 1999, Conoco had an unsecured $2,000
revolving credit facility with a syndicate of U.S. and international banks. The
terms consist of a 364-day committed facility in the amount of $1,350 and a
five-year committed facility in the amount of $650. At December 31, 2000 and at
December 31, 1999, Conoco had no outstanding borrowings under the credit
facility. The five-year committed facility had over three years remaining at
December 31, 2000.



                                       79
<PAGE>   82
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)


     Conoco maintains a $2,000 U.S. commercial paper program that is fully
supported by the credit facility. The program gives Conoco the ability to issue
commercial paper at any time with various maturities not to exceed 270 days.

     During 2000, Conoco initiated a euro 500 million European commercial paper
program, which gives Conoco the ability to issue commercial paper in the
European market at any time with maturities not to exceed 183 days. The program
is an alternative to the use of U.S. commercial paper and is not expected to
increase Conoco's current debt level. This program will complement the $2,000
U.S. commercial paper program and is fully supported by our existing revolving
credit facility.

     At December 31, 2000, there was $187 of commercial paper outstanding, with
a weighted-average interest rate of 6.8 percent, of which $85 was denominated in
foreign currencies. At December 31, 1999, U.S. commercial paper of $628, with a
weighted-average interest rate of 6.6 percent, was outstanding.

     The weighted-average interest rate on short-term borrowings and capital
lease obligations outstanding was 6.3 percent at December 31, 2000, and 6.4
percent at December 31, 1999.

16. OTHER ACCRUED LIABILITIES

<TABLE>
<CAPTION>
                                                                                              DECEMBER 31
                                                                                        ---------------------------
                                                                                           2000           1999
                                                                                        -----------    ------------
<S>                                                                                     <C>            <C>
Taxes other than on income............................................................. $      384     $       371
Operating expenses.....................................................................        469             347
Payroll and other employee-related costs...............................................        206             153
Royalties..............................................................................        134              99
Restructuring costs (1)................................................................         --              11
Accrued post-retirement benefits cost (see note 23)....................................         18              18
Other..................................................................................        332             304
                                                                                        ----------     -----------
Other accrued liabilities.............................................................. $    1,543     $     1,303
                                                                                        ==========     ===========
</TABLE>

----------

(1)  In December 1998, Conoco announced that as a result of a comprehensive
     review of its assets and long-term strategy, Conoco would make
     organizational realignments consistent with furthering the efficiency of
     operations and taking advantage of synergies created by upgrading its asset
     portfolio. Associated with the announcement, Conoco recorded an $82 pretax
     ($52 after-tax) charge to operating expense in the fourth quarter of 1998.
     Nearly all of this charge represented termination payments and related
     employee benefits to be made to the estimated 975 persons in both upstream
     and downstream businesses affected by the restructuring. Payments were made
     under existing company severance policies, generally based on years of
     service up to a maximum amount that varied by country.

     During 1999, 704 employees left Conoco as part of the implementation of the
     realignment plans, with related charges against the restructuring reserve
     of $68. In the fourth quarter 1999, estimates of the number of severances
     were revised due to changes in operational requirements. The original
     number of estimated severances was reduced by 137 positions, primarily in
     our upstream business, to 838 positions. The reduction of positions
     eliminated resulted in a reduction in the restructuring reserve of $3 that
     was recorded in the fourth quarter 1999. Total charges and adjustments to
     the reserve during 1999 were $71, resulting in a December 31, 1999 reserve
     balance of $11.

     During the first half of 2000, 79 employees left Conoco as part of the
     realignment plans. Related charges against the reserve totaled $6. The
     remaining reserve balance of $5 was reversed into earnings in the second
     quarter of 2000.



                                       80
<PAGE>   83
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)

17.  LONG-TERM BORROWINGS AND CAPITAL LEASE OBLIGATIONS

<TABLE>
<CAPTION>
                                                                                                DECEMBER 31
                                                                                        ---------------------------
                                                                                           2000           1999
                                                                                        -----------    ------------
<S>                                                                                     <C>            <C>
5.90% senior unsecured notes due 2004.................................................. $    1,348     $     1,348
6.50% senior unsecured notes due 2008..................................................          7               7
6.35% senior unsecured notes due 2009..................................................        750             750
7.68% senior unsecured notes due 2012..................................................         65              --
5.75% senior unsecured notes due 2026..................................................         16              16
6.95% senior unsecured notes due 2029..................................................      1,900           1,900
Other loans (various currencies) due 2002-2008 (1).....................................         20              24
Capitalization obligation to affiliate due 2008........................................          9               8
Capital lease obligations..............................................................         23              27
                                                                                        ----------     -----------
Long-term borrowings and capital lease obligations..................................... $    4,138     $     4,080
                                                                                        ==========     ===========
</TABLE>

----------

(1)  Weighted-average interest rate was 7.5 percent at December 31, 2000, and
     7.4 percent at December 31, 1999.

     Maturities of long-term borrowings, together with sinking fund requirements
for years ending after December 31, 2001, are $3 for 2002, $3 for 2003, $1,353
for 2004, $3 for 2005 and $4 for 2006. Long-term borrowings and capital lease
obligations outstanding at December 31, 2000 approximate fair value. At December
31, 1999, these outstanding obligations had an estimated fair value of $3,839.
These estimates were based on quoted market prices for the same or similar
issues.

18.  OTHER LIABILITIES AND DEFERRED CREDITS

<TABLE>
<CAPTION>
                                                                                                DECEMBER 31
                                                                                        ---------------------------
                                                                                           2000           1999
                                                                                        -----------    ------------
<S>                                                                                     <C>            <C>
Deferred gas revenue................................................................... $      280     $       361
Accrued post-retirement benefits cost (see note 23)....................................        335             335
Accrued pension liability (see note 23)................................................        184             200
Abandonment costs......................................................................        397             289
Environmental remediation costs (see note 26)..........................................        107              97
Other..................................................................................        623             676
                                                                                        ----------     -----------
Other liabilities and deferred credits................................................. $    1,926     $     1,958
                                                                                        ==========     ===========
</TABLE>

19.  MINORITY INTERESTS

     In 1996, various upstream subsidiaries contributed assets to Conoco Oil &
Gas Associates L.P. for a general partnership interest of 67 percent. Vanguard
Energy Investors L.P. then purchased the remaining 33 percent as a limited
partner. In December 1999, Conoco elected to retire Vanguard's $302 minority
interest and terminate the Conoco Oil & Gas Associates partnership.

     In November 1999, Conoco and Armadillo Investors L.L.C. formed Conoco Gas
Holdings L.L.C. Conoco contributed certain domestic upstream assets for a 75
percent common member interest and cash, and Armadillo contributed cash for a 25
percent preferred member interest. Armadillo is entitled to a cumulative annual
preferred dividend on its investment of 7.16 percent. Armadillo's share of
Conoco Gas Holdings' 2000 earnings was $15, while its share of 1999 earnings was
$2. The net minority interest in Conoco Gas Holdings held by Armadillo was $185
at December 31, 2000 and December 31, 1999.

     In December 1999, Conoco formed Conoco Corporate Holdings L.P. by
contributing certain corporate assets. The limited partner interest was sold to
Highlander Investors L.L.C. for $141, or an initial net 47 percent interest.
Highlander is entitled to a cumulative annual priority return on its investment
of 7.86 percent. Highlander's share of




                                       81
<PAGE>   84
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)

Conoco Corporate Holdings' 2000 earnings was $11, while its share of 1999
earnings was $1. The net minority interest in Conoco Corporate Holdings held by
Highlander was $141 at December 31, 2000 and December 31, 1999.

     The net effect of these 1999 transactions resulted in a minority interest
balance of $335 at December 31, 1999. Minority interest at December 31, 2000 was
$337.

20.  STOCKHOLDERS' EQUITY

     As described in note 1, Conoco's capital structure was established at the
time of the initial public offering in October 1998. A summary of the activity
in common shares outstanding for 1998, 1999 and 2000 is presented as follows:

<TABLE>
<CAPTION>
                                                                        CLASS A          CLASS B           TOTAL
                                                                      -----------      -----------      -----------
<S>                                                                  <C>               <C>              <C>
Issued in connection with the initial public offering of Class
  A shares and recapitalization of DuPont ownership
  (Class B shares)..........................................          191,456,427      436,543,573      628,000,000
Purchase of shares for treasury (1).........................             (250,000)              --         (250,000)
Issued on exercise of stock options (including 137 from
  treasury).................................................               41,531               --           41,531
                                                                      -----------      -----------      -----------

Common shares outstanding - December 31, 1998...............          191,247,958      436,543,573      627,791,531

Purchase of shares for treasury (1).........................           (3,494,616)              --       (3,494,616)
Issued on exercise of stock options and compensation
  awards from treasury (see note 22)........................            1,286,519               --        1,286,519
                                                                      -----------      -----------      -----------

Common shares outstanding - December 31, 1999...............          189,039,861      436,543,573      625,583,434
                                                                      -----------      -----------      -----------

Purchase of shares for treasury (1).........................           (3,634,400)              --       (3,634,400)

Additional shares issued....................................                   --          466,638          466,638

Shares purchased and retired (1) (2)........................                   --         (223,729)        (223,729)
Issued on exercise of stock options and compensation awards
  from treasury (see note 22)...............................            1,240,897               --        1,240,897
                                                                      -----------      -----------      -----------
Common shares outstanding - December 31, 2000...............          186,646,358      436,786,482      623,432,840
                                                                      ===========      ===========      ===========
</TABLE>

----------

(1)  To offset dilution from issuances under compensation plans.

(2)  Purchased Class B shares must be retired in accordance with Conoco's
     certificate of incorporation.

     At December 31, 2000 and 1999, 250,000,000 shares of preferred stock were
authorized. Of this amount, 1,000,000 shares were designated as Series A Junior
Participating Preferred Stock and reserved for issuance on the exercise of
preferred stock purchase rights under Conoco's Share Purchase Rights Plan. Each
issued share of Class A and Class B common stock has one preferred stock
purchase right attached to it. No preferred shares have been issued, and the
rights currently are not exercisable.

     During 1999, Conoco recorded a $26 reduction of additional paid-in capital
to reflect an adjustment to capitalization from owner at the initial public
offering. This reduction was primarily related to tax adjustments of $52,
partially offset by a $31 adjustment in book value for various subsidiaries
transferred from DuPont to Conoco as part of the separation.



                                       82
<PAGE>   85
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)

     Dividends declared and paid on Class A and Class B common stock for 2000
and 1999 are shown as follows:

<TABLE>
<CAPTION>
                                                                                                 2000         1999
                                                                                              ---------    ----------
<S>                                                                                           <C>          <C>
First quarter (1).........................................................................      $.19         $.14
Second quarter............................................................................       .19          .19
Third quarter.............................................................................       .19          .19
Fourth quarter............................................................................       .19          .19
                                                                                                ----         ----
Dividends per share.......................................................................      $.76         $.71
                                                                                                ====         ====
</TABLE>

----------

(1)  The first quarter 1999 dividend was determined on a pro rata basis covering
     the period from October 27, 1998 to December 31, 1998, and is equivalent to
     $.19 per share for a full quarter.

     Conoco declared a first quarter cash dividend on January 22, 2001, of $.19
per share on each outstanding share of Class A and Class B common stock. This
quarterly dividend will be paid on March 10, 2001, to all shareholders of record
as of February 10, 2001.

21.  ACCUMULATED OTHER COMPREHENSIVE LOSS

     Balances of related after-tax components comprising accumulated other
comprehensive loss are summarized in the following table:

<TABLE>
<CAPTION>
                                                                                                DECEMBER 31
                                                                                        --------------------------
                                                                                            2000            1999
                                                                                        ----------       ---------
<S>                                                                                     <C>              <C>
Foreign currency translation adjustment................................................ $     (619)      $    (347)
Minimum pension liability adjustment (see note 23).....................................        (34)            (25)
                                                                                        ----------       ---------
Accumulated other comprehensive loss................................................... $     (653)      $    (372)
                                                                                        ==========       =========
</TABLE>

     The following table summarizes the changes in the related components of
other comprehensive loss, which are reported net of associated income tax
effects:

<TABLE>
<CAPTION>
                                                                   YEAR ENDED DECEMBER 31
                                -------------------------------------------------------------------------------------------------
                                             2000                             1999                            1998
                                -------------------------------  -------------------------------  -------------------------------
                                 PRETAX   INCOME TAX  AFTER-TAX   PRETAX   INCOME TAX  AFTER-TAX  PRETAX    INCOME TAX  AFTER-TAX
                                 ------   ----------  ---------   ------   ----------  ---------  ------    ----------  ---------
<S>                             <C>        <C>        <C>        <C>        <C>        <C>        <C>        <C>        <C>
Foreign currency translation
  adjustment .................  $   (355)  $    (83)  $   (272)  $   (191)  $    (29)  $   (162)  $    (47)  $    (22)  $    (25)
Minimum pension liability
  adjustment .................       (14)        (5)        (9)        93         29         64        (84)       (26)       (58)
                                --------   --------   --------   --------   --------   --------   --------   --------   --------

Other comprehensive loss .....  $   (369)  $    (88)  $   (281)  $    (98)  $     --   $    (98)  $   (131)  $    (48)  $    (83)
                                ========   ========   ========   ========   ========   ========   ========   ========   ========
</TABLE>

22.  COMPENSATION PLANS

TRANSITION FROM DUPONT PLANS TO CONOCO PLANS

     Until the date of the initial public offering, employees of Conoco
participated in stock-based compensation plans administered through DuPont and
involving options to acquire DuPont common stock. At the time of the initial
public offering, Conoco employees held a total of 10,964,917 stock options for
DuPont common stock and 1,333,135 stock appreciation rights (SARs) with respect
to DuPont common stock.

     At the time of the initial public offering, Conoco gave those persons the
option, subject to specific country tax and legal requirements, to participate
in a program involving the cancellation of all or part of their DuPont stock
options or SARs. Upon such cancellation, Conoco issued comparable options to
acquire Conoco Class A common stock or SARs with respect to Conoco Class A
common stock. The substitute stock options and other awards had the same vesting
provisions, option periods and other terms and conditions as the DuPont options
and awards they replaced. Further, these substitute stock options had the same
ratio of the exercise price per share to the market value per share, and the
same aggregated difference between market value and exercise price as the DuPont
stock




                                       83
<PAGE>   86
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)


options. A total of 8,921,508 DuPont stock options and 745,358 DuPont SARs were
cancelled. Conoco then issued 24,275,690 stock options for Conoco Class A common
stock and 2,279,834 SARs with respect to Conoco Class A common stock. The Conoco
stock options and SARs had comparable terms and conditions to the previous
DuPont options and SARs. The new program was deemed a change in the terms of
certain awards granted to Conoco employees. As a result, Conoco incurred a
non-cash charge to compensation expense of $236 in the fourth quarter of 1998,
with a corresponding increase in additional paid-in capital. DuPont retained
responsibility for delivery of DuPont common stock to Conoco employees when
retained DuPont stock options are exercised.

AWARDS UNDER DUPONT PLANS

     Stock option awards under the DuPont Stock Performance Plan were granted to
key employees of Conoco prior to the initial public offering and were "fixed"
and/or "variable" as defined by APB Opinion No. 25. The purchase price of shares
subject to option is the market price of DuPont stock at the date of grant.

     During 1997, variable stock option grants were made to certain senior
management and are subject to forfeiture. The forfeiture would occur if, within
five years from the date of grant, the market price of DuPont common stock did
not achieve a price of $75 per share for 50 percent of the options and $90 per
share for the remaining 50 percent. During 1998, before the initial public
offering, the $75 price was reached and options with that hurdle price became
fixed and exercisable. All of the outstanding variable DuPont options with a $90
per share hurdle price at the time of the initial public offering were cancelled
and substituted with options for Conoco Class A common stock with a hurdle price
of $32.88 per share.

AWARDS UNDER CONOCO PLANS

     The 1998 Stock and Performance Incentive Plan provides incentives to
certain corporate officers and non-employee directors who can contribute
materially to the success and profitability of Conoco and its subsidiaries, and
provides for substitution of certain existing DuPont awards in connection with
the initial public offering. Awards may be in the form of cash, stock, stock
options or SARs with respect to Class A and Class B common stock (further
reference to common stock in this note refers to Conoco Class A and B common
stock). This plan also provides for the Conoco Global Variable Compensation
Plan. The Conoco Global Variable Compensation Plan is an annual management
incentive program for officers and certain non-officer employees with awards
made in cash and stock. Stock options and SARs granted under the 1998 Stock and
Performance Incentive Plan (except those granted to substitute for DuPont
awards):

     o    are awarded at market price on the date of grant;

     o    have a 10-year life;

     o    generally vest one year from date of grant; and

     o    may be subject to exercise restrictions, such as the attainment of
          specific stock price targets or the passage of time.

     For certain senior management, certain shares can be deferred as stock
units for a designated future delivery. These shares include both:

     o    shares receivable from the exercise of nonqualified options, with
          respect to Class A common stock granted under the 1998 Stock and
          Performance Incentive Plan of Conoco to substitute for cancelled 1998
          DuPont stock options; and

     o    incremental new Conoco stock options granted from the date of the
          initial public offering.

     In 1999, a variable option grant to acquire 1,400,000 shares of Class B
 common stock was made to Conoco's Chairman, President and Chief Executive
 Officer. Of this grant, 50 percent is subject to forfeiture if, within three
 years from the date of grant, the market price of Conoco Class B common stock
 does not achieve a price of $35 per share for five consecutive days. The
 remaining 50 percent of the grant is subject to forfeiture if, within five
 years




                                       84
<PAGE>   87
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)


from the date of grant, the market price of Conoco Class B common stock does not
achieve a price of $42 per share for five consecutive days. The exercise price
is $26.50, which was the market price on the grant date.

     The maximum number of shares of common stock and stock options granted
under the plan is limited to the highest of 20,000,000 or 3.3 percent of
outstanding shares of common stock. Awards made in substitution for DuPont
awards do not count against the number of shares available under the plan. At
December 31, 2000, and December 31, 1999, respectively, 12,028,155 shares and
15,078,195 shares of common stock were available for issuance under the plan.

     Conoco adopted the 1998 Key Employee Stock Performance Plan to attract and
retain employees. The plan will accomplish this by enhancing the proprietary and
personal interests of employees in Conoco's success and profitability. Awards to
employees may be made in the form of Conoco stock options or SARs, both with
respect to common stock. Such awards granted under this plan (except to
substitute for DuPont awards) are awarded under the same terms and conditions of
the 1998 Stock and Performance Incentive Plan as described above. The maximum
number of shares of common stock and stock options granted under the plan is
limited to the higher of 18,000,000 or 3 percent of outstanding shares of common
stock. Awards made in substitution for DuPont awards do not count against the
number of shares available under the plan. At December 31, 2000 and 1999,
respectively, 10,556,261 and 14,615,564 shares of common stock were available
for issuance under the plan.

     Under both the 1998 Stock and Performance Incentive Plan and the 1998 Key
Employee Stock Performance Plan, reload options are available upon the exercise
of stock options. These reload options include a condition that shares received
from the exercise of the original option may not be sold for at least two years.
Under a reload option, the number of new options granted is equal to the number
of shares required to satisfy the total exercise price of the original option.
Reload options are granted at the market price of the stock on the reload grant
date.

     The 1998 Global Performance Sharing Plan is a broad-based plan under which,
on the date of the initial public offering, grants of stock options and SARs
with respect to Class A common stock were made to certain non-officer employees.
This was done to encourage a sense of proprietorship and an active interest in
the financial success of Conoco and its subsidiaries. The stock options and SARs
were awarded:

     o    at the price of the initial public offering ($23 per share);

     o    have a 10-year life; and

     o    become exercisable in one-third increments on the first, second and
          third anniversaries of the grant date.

     Currently, there are no additional shares available for issuance under this
plan.

     Most stock options granted under Conoco plans are fixed and have no
intrinsic value at grant date. The 1,724,146 options granted to substitute for
cancelled DuPont options granted in 1997 and the 1,400,000 variable options
granted on August 17, 1999, are the exceptions to this fixed status. Except for
the fourth quarter 1998 charge related to the one-time offer to cancel DuPont
options and substitute Conoco options, no compensation expense has been
recognized for fixed options.



                                       85
<PAGE>   88
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)


     The following table summarizes activity for fixed and variable options for
the last three years:

<TABLE>
<CAPTION>
                                                        FIXED                               VARIABLE
                                          -----------------------------------    -------------------------------
                                                NUMBER           WEIGHTED-           NUMBER          WEIGHTED-
                                                  OF              AVERAGE              OF             AVERAGE
                                                SHARES             PRICE             SHARES            PRICE
                                          -------------------  --------------    ----------------   ------------
<S>                                       <C>                  <C>               <C>                <C>
DUPONT OPTIONS
January 1, 1998...........................      8,990,428      $     35.14            1,259,600     $     52.50
   Granted................................      1,241,055            59.53                   --              --
   Reclassified...........................        629,800            52.50             (629,800)          52.50
   Exercised..............................       (460,314)           24.64                   --              --
   Forfeited..............................        (65,852)           50.68                   --              --
                                          ---------------                        --------------
October 21, 1998 (at initial public
   offering)..............................     10,335,117            39.50              629,800           52.50
   Cancelled for Conoco options...........     (8,291,708)              --             (629,800)             --
                                          ---------------                        --------------
   Options retained by DuPont ............      2,043,409               --                   --              --

CONOCO OPTIONS
Granted at initial public offering date
   for cancelled DuPont options...........     22,551,544      $     14.62            1,724,146     $     19.18
   New awards.............................      9,721,750            23.00                   --              --
   Exercised..............................        (41,531)           14.18                   --              --
   Forfeited..............................        (53,840)           23.00                   --              --
                                          ---------------                        --------------
December 31, 1998.........................     32,177,923            17.14            1,724,146           19.18
   Granted................................         30,689            27.46            1,400,000           26.50
   Exercised..............................     (1,225,424)           12.37                   --              --
   Forfeited..............................       (133,929)           22.28                   --              --
                                          ---------------                        --------------
December 31, 1999.........................     30,849,259            17.31            3,124,146           22.46
   Granted................................      6,419,256            21.31                   --              --
   Exercised..............................     (1,406,597)           10.47                   --              --
   Forfeited..............................       (170,785)           20.54                   --              --
                                          ---------------                        --------------
December 31, 2000.........................     35,691,133            18.29            3,124,146           22.46
</TABLE>

     The following table summarizes information concerning outstanding and
exercisable fixed Conoco options at December 31, 2000. For total variable
options outstanding at December 31, 2000, the weighted-average remaining
contractual life was 7.1 years.

<TABLE>
<CAPTION>
                                                                       EXERCISE PRICE
                                         ---------------------------------------------------------------------------
                                             $6.57 -             $10.13 -             $19.17 -           $28.00 -
                                             $9.59               $14.47               $27.20             $29.72
                                         ---------------     ----------------    ----------------    ---------------
<S>                                      <C>                 <C>                 <C>                 <C>
Options outstanding.....................       3,987,574           6,676,845          24,988,871             37,843
Weighted-average remaining
    contractual life (years)............             2.0                 4.5                 7.6                8.6
Weighted-average price..................  $         8.79      $        11.92       $       21.49       $      28.03
Options exercisable.....................       3,987,574           6,676,845          14,764,448             14,963
Weighted-average price..................  $         8.79      $        11.92       $       21.24       $      28.09
</TABLE>




                                       86
<PAGE>   89
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)


     Fixed options exercisable at the end of the last three years and the
weighted-average fair value of fixed options granted are as follows:

<TABLE>
<CAPTION>
                                                                     2000             1999             1998
                                                               ----------------- ---------------- ----------------
<S>                                                            <C>               <C>              <C>
OPTIONS EXERCISABLE AT YEAR-END
    Number of shares..........................................       25,443,830       22,481,408       19,425,900
    Weighted-average price....................................     $      16.85     $      15.31     $      13.49
WEIGHTED-AVERAGE FAIR VALUE OF OPTIONS GRANTED DURING THE YEAR
    New options...............................................     $       6.14     $       6.85     $       4.15
    Options substituted for DuPont options....................     $         --     $         --     $       9.22
</TABLE>

     The incremental fair value of Conoco variable options with a hurdle price
of $32.88 per share, granted as substitutes for DuPont variable options, was
assumed to be zero.

     The fair value of options is calculated using the Black-Scholes
option-pricing model. Assumptions used were as follows:

<TABLE>
<CAPTION>
                                                                                                         DUPONT
                                                                    CONOCO OPTIONS (1)                  OPTIONS
                                                       ---------------------------------------------- -----------
                                                          2000        1999             1998              1998
                                                       ------------ ---------- ---------------------- -----------
                                                           NEW         NEW        NEW     SUBSTITUTES   FIXED
                                                       ------------ ---------- ---------- ----------- -----------
<S>                                                    <C>          <C>        <C>        <C>         <C>
Dividend yield.........................................      3.3%       3.3%       3.3%        3.3%        2.1%
Volatility.............................................     30.0%      25.0%      20.0%       20.0%       19.9%
Risk-free interest rate................................      5.1%       5.8%       4.6%        4.4%        5.5%
Expected life (years)..................................      6.0        6.0        5.8         3.9         5.8
</TABLE>

----------

(1)  For 2000, Conoco's historical volatility is used. However, due to
     insufficient history, the volatility of Conoco stock was estimated by
     referencing oil industry experience trends in 1999 and DuPont experience
     trends in 1998. The expected life for exercise of Conoco stock options was
     estimated by using DuPont experience trends.

     The following table sets forth pro forma information as if Conoco had
adopted the optional recognition provisions of SFAS No. 123 (see note 1):

<TABLE>
<CAPTION>
                                                                               2000         1999         1998
                                                                            ------------ -----------  ------------
<S>                                                                           <C>         <C>         <C>
 Increase (decrease) in
     Net income............................................................   $   (28)    $   (18)    $     157
     Earnings per share
         Basic.............................................................   $  (.04)    $  (.03)    $     .33
         Diluted...........................................................   $  (.04)    $  (.03)    $     .33
</TABLE>

     The incremental fair value for cancellation and substitution of stock
 options originally granted before adoption of SFAS No. 123 was zero because
 intrinsic value exceeds fair value.

     Compensation expense recognized in income for stock-based employee
compensation awards was $4 for 2000, $24 for 1999 and $229 for 1998. The year
1998 includes a one-time charge of $236 for the cancellation of DuPont stock
options described above.

     Prior to the initial public offering, the Conoco Unit Option Plan awarded
SARs with respect to DuPont common stock to key salaried employees in certain
grade levels who showed early evidence of the ability to assume significant
responsibility and leadership. At the time of the initial public offering,
1,131,494 unit options were outstanding, of which 593,722 were cancelled and
substituted with comparable SARs with respect to Conoco Class A common stock
under Conoco's 1998 Key Employee Stock Performance Plan. Effective with the
initial public


                                       87
<PAGE>   90
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)


offering, no new grants were made or are planned out of the Conoco Unit Option
Plan. At December 31, 2000, outstanding unit options based on Conoco Class A
common stock were 1,330,485, and at December 31, 1999, outstanding unit options
based on Conoco Class A common stock were 1,469,287. For these same time
periods, outstanding unit options based on DuPont common stock were 403,115 and
466,436, respectively. The related liability provisions totaled $21 at December
31, 2000, and $23 at December 31, 1999.

     Through the date of the initial public offering, certain Conoco employees
who participated in the DuPont Variable Compensation Plan received grants of
stock and cash. Overall amounts were dependent on financial performance of
DuPont and Conoco and other factors, and were subject to maximum limits as
defined by the plan. Amounts charged against earnings in anticipation of awards
to be made later were $39 in 1998. Actual cash and stock awards made in 1999 for
the 1998 plan year totaled $24. These awards were made out of the Conoco 1998
Stock and Performance Incentive Plan based on performance standards set
previously in the DuPont Variable Compensation Plan. Both the DuPont Variable
Compensation Plan and the Conoco 1998 Stock and Performance Incentive Plan allow
future delivery of stock awards.

     Beginning with the 1999 plan year, grants of stock and cash are made from
the Conoco 1998 Stock and Performance Incentive Plan according to the financial
performance of Conoco and its business units. Awards are subject to maximum
limits as defined by the plan. Amounts charged against earnings during 2000 in
anticipation of awards to be made in 2001 were $62, while amounts charged
against earnings during 1999 in anticipation of awards to be made in 2000 were
$52. Awards actually distributed in 2001 for the 2000 plan year amounted to $65.
Awards actually distributed in 2000 for the 1999 plan year amounted to $49.

     Under the Conoco 1998 Stock and Performance Incentive Plan, employees were
offered the opportunity to cancel DuPont shares, which were granted under
previous awards, and receive substitute shares of Conoco Class A common stock
for designated future delivery. At December 31, 2000, 60,072 shares of DuPont
stock and 282,576 shares of Conoco Class A common stock were awaiting delivery.
Conoco recognized a liability of $3 for the delivery of DuPont shares.

     Awards under the separate Conoco Challenge Program may be granted in cash
to employees not covered by the Variable Compensation Plan. This plan provides
awards based on meeting financial goals and upholding Conoco's core values.
Overall amounts are dependent on Conoco's earnings and cash provided by
operations. Beginning with the 1999 plan year, awards also are adjusted up or
down based on a measure of Conoco's shareholder return as compared to a group of
selected benchmark competitors. All payout amounts are subject to maximum limits
as defined by the plan. Amounts charged against earnings for the current year
and to adjust for over/under accruals in prior years totaled $63 for 2000, $40
in 1999, and $22 in 1998. Awards made for plan years were $56 for 2000, $40 for
1999, and $19 for 1998.

23.  PENSIONS AND OTHER POST-RETIREMENT BENEFITS

     Prior to the split-off, Conoco participated in the DuPont U.S. tax
qualified defined benefit pension plan. In 1999, Conoco established a U.S. tax
qualified defined benefit pension plan (Conoco plan) which was spun off from the
DuPont U.S. tax qualified defined benefit pension plan. The Conoco plan covers
substantially all U.S. non-retail employees, as well as about half of all U.S.
retail employees, and provides essentially the same benefits to Conoco employees
as the DuPont plan provided to these employees. In addition, Conoco has separate
U.S. non-tax qualified defined benefit pension plans covering certain U.S. and
international employees. The benefits for the plans mentioned in this paragraph
are based primarily on years of service and the average of the employees'
highest 36 consecutive months' pay. Conoco's funding policy for the U.S. tax
qualified plan is consistent with the funding requirements of federal laws and
regulations. The nonqualified plans are not funded. In 1999, however, Conoco set
up a "Rabbi Trust," which may be funded in the future. A Rabbi Trust sets aside
assets to pay for benefits under a nonqualified pension plan, but those assets
remain subject to claims of Conoco's general creditors in preference to the
claims of plan participants and beneficiaries.

     With respect to the DuPont U.S. tax qualified defined benefit pension plan,
Conoco and DuPont agreed upon an amount of approximately $820 at the date of the
initial public offering to be transferred to a separate trust for Conoco's
pension plan. The transfer value was adjusted for benefit payments and
investment returns from the date of the initial public offering to the transfer
date. The adjusted value transferred in July and September 2000 totaled


                                       88
<PAGE>   91
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)


$858. At December 31, 1999, prior to the transfer, the estimated value of the
amount to be transferred was $884.

     DuPont allocated the pension obligations based on Conoco's individual
employees covered by the plan. The unrecognized prior service cost and
unrecognized net gain were allocated in proportion to Conoco's projected benefit
obligation to the total projected benefit obligation of the DuPont plan. The net
periodic pension cost components included in the following table also are based
on the foregoing allocation factors.

     Pension coverage is provided to the extent appropriate for employees of
Conoco's international subsidiaries through separate plans. Obligations under
such plans are systematically provided for by depositing funds with trustees,
under insurance policies or by book reserves.

     Conoco and certain subsidiaries also provide medical and life insurance
benefits to U.S. retirees and survivors. The associated plans, principally
health, are not funded, and approved claims are paid from Conoco's funds. Under
the terms of these plans, Conoco reserves the right to change, modify or
discontinue the plans. Conoco has communicated to plan participants that any
increase in the annual health care escalation rate above 4.5 percent will be
borne by the participants. Therefore, Conoco does not expect an increase to the
accumulated post-retirement benefit obligation or the other post-retirement
benefit cost.

<TABLE>
<CAPTION>
                                                                                                                OTHER
                                                                                                            POST-RETIREMENT
                                                                PENSION BENEFITS                               BENEFITS
                                             ----------------------------------------------------   ------------------------------
                                                    2000                   1999            1998       2000       1999      1998
                                             -------------------   -------------------   --------   --------   --------   --------
                                              U.S.       INT'L.      U.S.      INT'L.
                                             --------   --------   --------   --------
<S>                                          <C>        <C>        <C>        <C>        <C>        <C>        <C>        <C>
 Service cost ...........................    $     35   $     27   $     44   $     42   $     65   $      7   $      9   $      7
 Interest cost ..........................          62         37         58         41         94         25         22         21
 Expected return on plan assets .........         (76)       (33)       (79)       (36)      (105)        --         --         --
 Amortization of prior service
   cost (credit) ........................          (6)         5         (7)         5          9         (4)        (4)        (4)
 Recognized actuarial loss (gain) .......           4         --          4          5         (4)        (1)         2         --
                                             --------   --------   --------   --------   --------   --------   --------   --------
 Net periodic benefit cost ..............    $     19   $     36   $     20   $     57   $     59   $     27   $     29   $     24
                                             ========   ========   ========   ========   ========   ========   ========   ========
</TABLE>


                                       89
<PAGE>   92
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)


     The following table reflects information concerning benefit obligations,
plan assets, funded status and recorded values. Pension benefits for 1999
include amounts associated with Conoco's portion of what was previously the
DuPont U.S. tax qualified defined benefit pension plan.

<TABLE>
<CAPTION>
                                                                                                                   OTHER
                                                                                                              POST-RETIREMENT
                                                                           PENSION BENEFITS                       BENEFITS
                                                            --------------------------------------------    --------------------
                                                                    2000                    1999              2000        1999
                                                            --------------------    --------------------    --------    --------
                                                             U.S.        INT'L.      U.S.        INT'L.
                                                            --------    --------    --------    --------
<S>                                                         <C>         <C>         <C>         <C>         <C>         <C>
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year .................   $    834    $    679    $    113    $    753    $    323    $    350
Adjustment to include U.S. qualified plan balance .......         --          --         871          --          --          --
                                                            --------    --------    --------    --------    --------    --------
Adjusted benefit obligation at beginning of year.........        834         679         984         753         323         350
Service cost ............................................         35          27          44          42           7           9
Interest cost ...........................................         62          37          58          41          25          22
Exchange gain ...........................................         --         (58)         --         (24)         --          --
Participant contributions ...............................         --          --          --          --           4           4
Actuarial (gain) loss ...................................         (2)         17        (151)       (104)         46         (32)
Divestitures and other ..................................         --          18          13          --          --          (5)
Benefits paid ...........................................        (74)        (22)       (114)        (29)        (31)        (25)
                                                            --------    --------    --------    --------    --------    --------
Benefit obligation at end of year .......................   $    855    $    698    $    834    $    679    $    374    $    323
                                                            ========    ========    ========    ========    ========    ========

CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year ..........   $    884    $    494    $     --    $    438    $     --    $     --
Adjustment for fair value of U.S. qualified plan assets..         --          --         878          --          --          --
                                                            --------    --------    --------    --------    --------    --------
Adjusted fair value of plan assets at beginning of
   year .................................................        884         494         878         438          --          --
Actual return on plan assets ............................        (29)         49         130          59          --          --
Employer contribution ...................................         17          29           6          32          26          21
Participant contributions ...............................         --          --          --          --           5           4
Exchange gain ...........................................         --         (40)         --         (14)         --          --
Divestitures and other ..................................         --          10         (16)         --          --          --
Benefits paid ...........................................        (74)        (18)       (114)        (21)        (31)        (25)
                                                            --------    --------    --------    --------    --------    --------
Fair value of plan assets at end of year ................   $    798    $    524    $    884    $    494    $     --    $     --
                                                            ========    ========    ========    ========    ========    ========

Funded status of plans at end of year ...................   $    (57)   $   (174)   $     50    $   (185)   $   (374)   $   (323)
Transition asset ........................................        (15)         (6)        (23)        (14)         --          --
Unrecognized actuarial (gain) loss ......................         55          12         (41)         12          62          15
Unrecognized prior service cost (credit) ................         11          81          13          94         (41)        (45)
                                                            --------    --------    --------    --------    --------    --------
Net amount recognized at end of year ....................   $     (6)   $    (87)   $     (1)   $    (93)   $   (353)   $   (353)
                                                            ========    ========    ========    ========    ========    ========

AMOUNTS RECOGNIZED IN CONSOLIDATED BALANCE SHEET
   AT END OF YEAR
Prepaid benefit (see note 13) ...........................   $      5    $     --    $     13    $     --    $     --    $     --
Accrued benefit liability
  Short-term (see note 16) ..............................         --          --          --          --         (18)        (18)
  Long-term (see note 18) ...............................        (69)       (115)        (58)       (142)       (335)       (335)
Deferred pension transition obligation (see note 13).....          5          28           5          49          --          --
Accumulated other comprehensive loss (1) ................         53          --          39          --          --          --
                                                            --------    --------    --------    --------    --------    --------
Net amount recognized ...................................   $     (6)   $    (87)   $     (1)   $    (93)   $   (353)   $   (353)
                                                            ========    ========    ========    ========    ========    ========
</TABLE>

----------

(1)  Before reduction for associated deferred tax savings of $19 at December 31,
     2000, and $14 at December 31, 1999 (see note 21).




                                       90
<PAGE>   93
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)

<TABLE>
<CAPTION>
                                                                                                            OTHER
                                                                                                       POST-RETIREMENT
                                                                  PENSION BENEFITS                        BENEFITS
                                                   -----------------------------------------------  --------------------
                                                            2000                      1999            2000       1999
                                                   -----------------------      ------------------  ---------  ---------
                                                    U.S.            INT'L.       U.S.       INT'L.
                                                   ------          -------      ------     -------
<S>                                                <C>             <C>          <C>        <C>      <C>        <C>
WEIGHTED-AVERAGE ASSUMPTIONS AT END OF YEAR
Discount rate..................................... 7.50%            6.00%        7.75%      6.00%     7.50%      8.00%
Rate of compensation increase..................... 4.60%            4.50%        5.20%      4.50%     4.60%      5.15%
Expected return on plan assets.................... 9.00%            7.00%        9.00%      7.00%       --         --
Health care escalation rate.......................   --               --           --         --      4.50%      4.50%
</TABLE>

     At December 31, 2000, U.S. defined benefit plan assets consisted primarily
of common stocks. No Conoco common stock was included in the holdings. At
December 31, 1999, the U.S. defined benefit plan assets consisted principally of
common stocks, including 34,809 shares of Conoco common stock.

24.  INVESTING ACTIVITIES

     Purchases of businesses in 2000 included $545 for Saga U.K. Ltd. There were
no significant purchases in 1999. Purchases in 1998 included $929 for upstream
natural gas properties in South Texas.

     Non-cash additions to PP&E were $41 for 2000, zero for 1999 and $162 for
1998.

     For 2000, total proceeds from sales of assets of $222 included the sale of
Oklahoma gas plants and the sale of retail assets in the Dallas-Fort Worth area
and the Gulf Coast region. There were no significant proceeds from any one asset
sale in 1999. Proceeds in 1998 included $245 from the sale of certain U.S. and
North Sea upstream properties, $156 from various U.S. downstream asset sales and
$54 from the sale of a downstream office building in Europe.

25.  FINANCIAL INSTRUMENTS AND OTHER RISK MANAGEMENT ACTIVITIES

     Conoco operates in the worldwide crude oil, refined product, natural gas,
natural gas liquids and electric power markets and is exposed to fluctuations in
hydrocarbon prices, foreign currency rates and interest rates. These
fluctuations can affect revenues and the cost of operating, investing and
financing. Conoco's management has used and intends to continue to use financial
and commodity-based derivative contracts to reduce the risk in overall earnings
and cash flow when the benefits provided are anticipated to more than offset the
risk management costs involved.

     Conoco has established a Risk Management Policy that provides guidelines
for entering into contractual arrangements (derivatives) to manage its commodity
price, foreign currency rate and interest rate risks. The Conoco Risk Management
Committee has:

     o    an ongoing responsibility for the content of this policy;

     o    principal oversight responsibility to ensure that Conoco is in
          compliance with the policy; and

     o    responsibility to ensure that procedures and controls are in place for
          the use of commodity, foreign currency and interest rate instruments.

     These procedures clearly establish derivative control and valuation
processes, routine monitoring and reporting requirements, and counterparty
credit approval procedures. Additionally, to assess the adequacy of internal
controls, Conoco's internal audit group reviews these risk management
activities. The audit results are then reviewed by both the Conoco Risk
Management Committee and by management.



                                       91
<PAGE>   94
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)


     The counterparties to these contractual arrangements are limited to major
financial institutions and other established companies in the petroleum
industry. Although Conoco, in the event of nonperformance by these
counterparties, is exposed to credit loss, this exposure is managed through
credit approvals, limits and monitoring procedures and limits to the period over
which unpaid balances are allowed to accumulate. Conoco has not experienced
nonperformance by counterparties to these contracts, and no material loss would
be expected from any such nonperformance.

COMMODITY PRICE RISK

     Conoco enters into energy-related futures, forwards, swaps and options in
various markets:

     o    to balance its physical systems;

     o    to meet customer needs; and

     o    to manage its price exposure on anticipated crude oil, natural gas,
          refined product and electric power transactions.

     These instruments provide a natural extension of the underlying cash market
and are used to physically acquire a portion of supply requirements. The
commodity futures market has greater liquidity and longer trading periods than
the cash market, and is one method of managing price risk in the energy
business.

     Conoco's policy is generally to be exposed to market pricing for commodity
purchases and sales. From time to time, management may use derivatives to
establish longer-term positions to hedge the price risk for Conoco's equity
crude oil and natural gas production, as well as its refinery margins.
Specifically, we have taken action to mitigate our exposure to volatile crude
oil prices through the purchase of crude oil put options, which reduce our
downside risk while maintaining our upside potential.

     Conoco does limited amounts of trading for profit unrelated to its
underlying physical business. After-tax gain or loss from trading for profit
activities has not been material.

FOREIGN CURRENCY RISK

     Conoco has foreign currency exchange rate risk resulting from operations in
over 40 countries around the world. Conoco does not comprehensively hedge its
exposure to currency rate changes, although it may choose to selectively hedge
exposures to foreign currency rate risk. Examples include firm commitments for
capital projects, certain local currency tax payments and dividends, and cash
returns from net investments in foreign affiliates to be remitted within the
coming year.

     In conjunction with our European commercial paper program, initiated in
2000, Conoco enters into foreign currency swaps for all non-U.S. dollar notes
issued in order to receive the U.S. dollar equivalent proceeds upon note
issuance and to lock in the forward foreign currency rate on note maturity. At
December 31, 2000, the U.S. dollar equivalent of all non-U.S. dollar notes
outstanding was $85, all of which were swapped to the U.S. dollar. The notional
amount of the forward portion of these swaps was $81, and the estimated fair
value was $86.

     At December 31, 2000, Conoco had open foreign currency exchange derivative
instruments of $45, related to anticipated foreign currency capital investments,
with an estimated fair value of $42. Conoco had no open foreign currency
exchange derivative instruments at December 31, 1999.

INTEREST RATE RISK

     Conoco manages any material risk arising from exposure to interest rates by
using a combination of financial derivative instruments. This program was
developed to manage the fixed and floating interest rate mix of Conoco's total
debt portfolio and related overall cost of borrowing.



                                       92
<PAGE>   95
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)


     At December 31, 2000 and at December 31, 1999, Conoco had no significant
open interest rate financial derivative instruments.

FAIR VALUES OF FINANCIAL INSTRUMENTS

     The carrying values of most financial instruments are based on historical
costs. The carrying values of marketable securities, receivables, payables and
short-term obligations approximate their fair value because of their short
maturity.

     Long-term borrowings and capital lease obligations outstanding at December
31, 2000, of $4,138 approximate fair value. Obligations outstanding at December
31, 1999, of $4,080 had an estimated fair value of $3,839. These estimates were
based on quoted market prices for the same or similar issues, or the current
rates offered to Conoco for issues with the same remaining maturities.

SUMMARY OF OUTSTANDING COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS

     The following table provides a summary of the fair values, carrying amounts
and notional values of outstanding commodity financial instruments at December
31, 2000 and 1999.

     Notional amounts represent the face amount of the contractual arrangements
and are not a measure of market or credit exposure. The fair value of swaps and
other over-the-counter instruments are estimated based on quoted market prices
of comparable contracts. These estimated values approximate the gain or (loss)
that would have been realized if the contracts had been closed out at the
balance sheet date. Carrying amounts represent the receivable (payable) position
recorded in the consolidated balance sheet.

<TABLE>
<CAPTION>
                                                    FAIR      CARRYING    NOTIONAL
                                                    VALUE      AMOUNT      VALUE
                                                   --------   --------   --------
<S>                                                <C>        <C>        <C>
COMMODITY DERIVATIVES (1)
December 31, 2000
    Trading.....................................   $      6   $      6   $    811
    Non-trading (2).............................   $    185   $    125   $  1,606
December 31, 1999
    Trading.....................................   $     10   $     10   $    529
    Non-trading.................................   $      6   $      5   $    464
</TABLE>

----------

(1)  Includes derivative instruments that can only be settled in cash.

(2)  Includes purchased crude oil put options with a strike price of $22.00
     (West Texas Intermediate equivalent) per barrel on 63 million barrels
     during the period of April through December 2001.

26.  COMMITMENTS AND CONTINGENT LIABILITIES

     Conoco uses various leased facilities and equipment in its operations.
Future minimum lease payments under noncancelable operating leases are $231 for
2001, $276 for 2002, $251 for 2003, $124 for 2004, $112 for 2005 and $585 for
subsequent years. Future minimum lease payments are not reduced by $46 of
noncancelable minimum sublease rentals, where Conoco continues to be the primary
obligator under the original leases. Rental expense under operating leases was
$274 in 2000, $301 in 1999 and $214 in 1998. Rental revenue under operating
subleases was $11 in 2000, $15 in 1999 and $16 in 1998.

     Conoco has various purchase commitments for materials, supplies, services
and items of permanent investment incident to the ordinary conduct of business.
Such commitments are not at prices in excess of current market. Additionally,
Conoco has obligations under international contracts to purchase natural gas
over periods up to 19 years. Due to the significant strengthening of market
prices, these long-term purchase obligations are at prices lower than December
31, 2000 quoted market prices. However, at December 31, 1999, these obligations
were at prices in




                                       93
<PAGE>   96
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)


excess of year-end 1999 quoted market prices. No material annual gain or loss is
expected from these long-term commitments.

     Conoco is subject to various lawsuits and claims involving a variety of
matters including, along with other oil companies, actions challenging oil and
gas royalty and severance tax payments, actions related to gas measurement and
valuation methods, actions related to joint interest billings to operating
agreement partners, and claims for damages resulting from leaking underground
storage tanks. As a result of the separation agreement with DuPont, Conoco also
has assumed responsibility for current and future claims related to certain
discontinued chemicals and agricultural chemicals businesses operated by Conoco
in the past. In general, the effect on future financial results is not subject
to reasonable estimation because considerable uncertainty exists. The ultimate
liabilities resulting from such lawsuits and claims may be material to results
of operations in the period in which they are recognized.

     On May 2, 2000, a jury in federal court in Virginia found that Conoco
infringed patents of General Technology Applications (GTA) involving part of a
process for manufacturing a flow improver product. The amount awarded as damages
was $55. We have appealed the verdict. Conoco remains convinced that the
evidence clearly demonstrates that Conoco's process does not infringe the GTA
patents, and that the trial court decision will be reversed.

     Conoco also is subject to contingencies pursuant to environmental laws and
regulations that in the future may require further action to correct the effects
on the environment of prior disposal practices or releases of petroleum
substances by Conoco or other parties. Conoco has accrued for certain
environmental remediation activities consistent with the policy set forth in
note 2. Conoco assumed environmental remediation liabilities from DuPont related
to certain discontinued chemicals and agricultural chemicals businesses operated
by Conoco in the past that are included in the environmental accrual. The
accrual amounted to $119 at December 31, 2000, and $109 at December 31, 1999. In
management's opinion, this accrual was appropriate based on existing facts and
circumstances. Under adverse changes in circumstances, potential liability may
exceed amounts accrued. In the event future monitoring and remediation
expenditures are in excess of amounts accrued, they may be significant to
results of operations in the period recognized. However, management does not
anticipate they will have a material adverse effect on the consolidated
financial position of Conoco.

     Conoco or DuPont, on behalf of and indemnified by Conoco, has directly
guaranteed obligations of certain affiliated companies and others. These
guarantees totaled $1,090 at December 31, 2000, and $1,138 at December 31, 1999.
The balance at December 31, 2000, included $706 and $167 associated with
Petrozuata and Polar Lights, respectively. Conoco had no indirect guarantees as
of December 31, 2000. At December 31, 1999, Conoco had indirectly guaranteed
various debt obligations under agreements with certain affiliated and other
companies to provide specified minimum revenues from shipments or purchases of
products. These indirect guarantees totaled $7. No material loss is anticipated
by reason of such agreements and guarantees.

     Conoco's operations, particularly oil and gas exploration and production,
can be affected by changing economic, regulatory and political environments in
the various countries in which Conoco operates, including the U.S. In certain
locations, host governments have imposed restrictions, controls and taxes. In
others, political conditions have existed that may threaten the safety of
employees and Conoco's continued presence in those countries. Internal unrest or
strained relations between a host government and Conoco or other governments may
affect Conoco's operations. Those developments have, at times, significantly
affected Conoco's operations and related results and are carefully considered by
management when evaluating the level of current and future activity in such
countries. Conoco does take various steps to minimize its financial exposure to
loss including, in certain cases, obtaining risk insurance coverage. Areas in
which Conoco has a significant active presence include Canada, the Czech
Republic, Germany, Indonesia, Malaysia, Nigeria, Norway, Russia, Syria, the
United Arab Emirates, the U.K., the U.S., Venezuela and Vietnam.

27.  OPERATING SEGMENT AND GEOGRAPHIC INFORMATION

     Conoco has three operating segments that comprise the structure used by
senior management to make key operating decisions and assess performance. These
are the upstream, downstream and emerging businesses segments. Upstream
operating segment activities include exploring for, developing, producing and
selling crude oil, natural gas and natural gas liquids. Activities of the
downstream operating segment include refining crude oil and other feedstocks
into petroleum products; buying and selling crude oil and refined products; and
transporting,




                                       94
<PAGE>   97

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)


distributing and marketing petroleum products. Activities of the emerging
businesses operating segment include the development of new businesses beyond
our traditional operations. Conoco has five reporting segments. Four reporting
segments reflect the geographic division between the U.S. and international
operations of its upstream and downstream businesses. One reporting segment is
for emerging businesses. Corporate includes general corporate expenses,
financing costs and other non-operating items and captive insurance operations.

     There were several factors driving Conoco's revised segment reporting and
the subsequent creation of the emerging businesses operating segment in the
fourth quarter of 2000. The most important of these factors was the desire to
differentiate new businesses from our traditional operations. These businesses
have the potential to contribute substantially to our long-term growth and are
built on our core businesses. This segment includes Conoco's emerging power,
carbon fibers and natural gas refining businesses.

     Conoco sells its products worldwide. In 2000, about 59 percent of sales
were made in the U.S. and 36 percent of sales were made in Europe. In 1999,
about 54 percent of sales were made in the U.S. and 41 percent of sales were
made in Europe. Major products include crude oil, natural gas and refined
products that are sold primarily in the energy and transportation markets.
Conoco's sales are not materially dependent on any single customer or small
group of customers. Transfers between segments are on the basis of estimated
market values.

<TABLE>
<CAPTION>
                                           UPSTREAM               DOWNSTREAM
                                     --------------------    --------------------
                                                                                     EMERGING                ELIMINA-   CONSOLI-
SEGMENT INFORMATION                    U.S.       INT'L.       U.S.       INT'L.    BUSINESSES  CORPORATE     TIONS      DATED
                                    --------    --------    --------    --------    ----------  ---------  -----------  --------
<S>                                  <C>         <C>         <C>         <C>        <C>         <C>        <C>          <C>
2000
Sales and other operating
  revenues (2)
   Refined products ...............  $     --    $     --    $ 12,343    $ 11,284    $     --   $     --   $        --  $ 23,627
   Crude oil ......................        16       1,627       4,754         497          --         --            --     6,894
   Natural gas ....................     4,099       1,686          --          --          --         --            --     5,785
   Other ..........................     1,416         353         282         376           4         --            --     2,431
                                     --------    --------    --------    --------    --------   --------   -----------  --------
        Total .....................     5,531       3,666      17,379      12,157           4         --            --    38,737
Transfers between segments ........       740         831         177         644          --         --        (2,392)       --
                                     --------    --------    --------    --------    --------   --------   -----------  --------
Total operating revenues ..........  $  6,271    $  4,497    $ 17,556    $ 12,801    $      4   $     --   $    (2,392) $ 38,737
                                     ========    ========    ========    ========    ========   ========   ===========  ========
Operating profit ..................  $  1,051    $  2,103    $    208    $    344    $    (89)  $   (159)  $        --  $  3,458
Equity in earnings of affiliates ..        20         230          53         (26)         --         --            --       277
Corporate non-operating items
   Interest and debt expense ......        --          --          --          --          --       (338)           --      (338)
   Interest income (net of misc.
    interest expense) .............        --          --          --          --          --         39            --        39
   Other ..........................        --          --          --          --          --         22            --        22
                                     --------    --------    --------    --------    --------   --------   -----------  --------
Income before income taxes ........     1,071       2,333         261         318         (89)      (436)           --     3,458
Provision for income taxes ........      (352)     (1,185)        (79)        (88)         20        128            --    (1,556)
                                     --------    --------    --------    --------    --------   --------   -----------  --------
Net income (loss) (1) .............  $    719    $  1,148    $    182    $    230    $    (69)  $   (308)  $        --  $  1,902
                                     ========    ========    ========    ========    ========   ========   ===========  ========
Capital employed at December 31 (3)
   Excluding investment in
    affiliates ....................  $  2,501    $  3,278    $  1,265    $    918    $     27   $    202   $        --  $  8,191
   Investment in affiliates (4) ...       162         865         285         490          29         --            --     1,831
                                     --------    --------    --------    --------    --------   --------   -----------  --------
Total capital employed ............  $  2,663    $  4,143    $  1,550    $  1,408    $     56   $    202   $        --  $ 10,022
                                     ========    ========    ========    ========    ========   ========   ===========  ========

Return on capital employed
  (ROCE) (5) ......................      25.9%       30.2%       12.9%       18.0%        N/A        N/A            --      23.1%
Significant non-cash items
  DD&A ............................  $    412    $    611    $    136    $    138    $     --   $      4   $        --  $  1,301
  Dry hole costs and impairment of
    unproved properties ...........  $     44    $     44    $     --    $     --    $     --   $     --   $        --  $     88
  Inventory write-down to market ..  $     --    $     --    $     --    $     24    $     --   $     --   $        --  $     24
Capital expenditures and
  investments (6) .................  $    667    $  1,486    $    344    $    201    $     72   $     26   $        --  $  2,796
Total assets ......................  $  3,733    $  7,195    $  3,461    $  2,925    $     88   $    725   $        --  $ 18,127
</TABLE>



                                       95

<PAGE>   98

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)


<TABLE>
<CAPTION>
                                          UPSTREAM               DOWNSTREAM
                                     --------------------    --------------------

SEGMENT INFORMATION                                                                   EMERGING                 ELIMINA-    CONSOLI-
                                       U.S.       INT'L.       U.S.       INT'L.     BUSINESSES   CORPORATE     TIONS       DATED
                                     --------    --------    --------    --------    ----------   ---------   ----------   --------
<S>                                  <C>         <C>         <C>         <C>           <C>         <C>        <C>          <C>
1999
Sales and other operating
  revenues (2)
   Refined products ...............  $     --    $     --    $  7,771    $  9,253      $     --    $     --   $       --   $ 17,024
   Crude oil ......................        10       1,101       3,165         621            --          --           --      4,897
   Natural gas ....................     2,436       1,033          --          --            --          --           --      3,469
   Other ..........................       863         113         255         390            28          --           --      1,649
                                     --------    --------    --------    --------      --------    --------   ----------   --------
        Total .....................     3,309       2,247      11,191      10,264            28          --           --     27,039
Transfers between segments ........       435         476         106         325            --          --       (1,342)        --
                                     --------    --------    --------    --------      --------    --------   ----------   --------
Total operating revenues ..........  $  3,744    $  2,723    $ 11,297    $ 10,589      $     28    $     --   $   (1,342)  $ 27,039
                                     ========    ========    ========    ========      ========    ========   ==========   ========

Operating profit ..................  $    381    $    891    $    110    $    192      $    (54)   $   (154)  $       --   $  1,366
Equity in earnings of affiliates ..         8          94          55          (7)           --          --           --        150
Corporate non-operating items
   Interest and debt expense ......        --          --          --          --            --        (311)          --       (311)
   Interest income (net of misc.
    interest expense) .............        --          --          --          --            --          25           --         25
   Other ..........................        --          --          --          --            --         (13)          --        (13)
                                     --------    --------    --------    --------      --------    --------   ----------   --------
Income before income taxes ........       389         985         165         185           (54)       (453)          --      1,217
Provision for income taxes ........       (67)       (451)        (46)        (56)           19         128           --       (473)
                                     --------    --------    --------    --------      --------    --------   ----------   --------
Net income (loss) (1) .............  $    322    $    534    $    119    $    129      $    (35)   $   (325)  $       --   $    744
                                     ========    ========    ========    ========      ========    ========   ==========   ========
Capital employed at December 31 (3)
   Excluding investment in
    affiliates ....................  $  2,509    $  2,840    $  1,311    $    890      $     50    $     94   $       --   $  7,694
   Investment in affiliates (4) ...       166         620         260         526            32          --           --      1,604
                                     --------    --------    --------    --------      --------    --------   ----------   --------
Total capital employed ............  $  2,675    $  3,460    $  1,571    $  1,416      $     82    $     94   $       --   $  9,298
                                     ========    ========    ========    ========      ========    ========   ==========   ========
Return on capital employed
  (ROCE) (5) ......................      12.3%       16.0%        8.9%        8.8%          N/A         N/A           --       11.1%
Significant non-cash items
   DD&A ...........................  $    374    $    547    $    126    $    142      $     --    $      4   $       --   $  1,193
   Dry hole costs and impairment of
    unproved properties ...........  $     16    $    115    $     --    $     --      $     --    $     --   $       --   $    131
Capital expenditures and
  investments(6) ..................  $    413    $    839    $    214    $    248      $     69    $      4   $       --   $  1,787
Total assets ......................  $  3,502    $  5,949    $  3,287    $  2,835      $     91    $    711   $       --   $ 16,375

1998
Sales and other operating
  revenues (2)
   Refined products ...............  $     --    $     --    $  6,082    $  7,647      $     --    $     --   $       --   $ 13,729
   Crude oil ......................        14         774       2,650         299            --          --           --      3,737
   Natural gas ....................     2,416         723          --          --            --          --           --      3,139
   Other ..........................       770         104         217         351           729          20           --      2,191
                                     --------    --------    --------    --------      --------    --------   ----------   --------
        Total .....................     3,200       1,601       8,949       8,297           729          20           --     22,796
Transfers between segments ........       308         378          89         181            --          --         (956)        --
                                     --------    --------    --------    --------      --------    --------   ----------   --------
Total operating revenues ..........  $  3,508    $  1,979    $  9,038    $  8,478      $    729    $     20   $     (956)  $ 22,796
                                     ========    ========    ========    ========      ========    ========   ==========   ========

Operating profit ..................  $    229    $    482    $    157    $    256      $    (47)   $   (346)  $       --   $    731
Equity in earnings of affiliates ..         1         (14)         56         (20)           (1)         --           --         22
Corporate non-operating items
   Interest and debt expense ......        --          --          --          --            --        (199)          --       (199)
   Interest income (net of misc.
    interest expense) .............        --          --          --          --            --          89           --         89
   Other ..........................        --          --          --          --            --          51           --         51
                                     --------    --------    --------    --------      --------    --------   ----------   --------

Income before income taxes ........       230         468         213         236           (48)       (405)          --        694
Provision for income taxes ........        (7)       (185)        (72)        (80)           17          83           --       (244)
                                     --------    --------    --------    --------      --------    --------   ----------   --------
Net income (loss) (1) .............  $    223    $    283    $    141    $    156      $    (31)   $   (322)  $       --   $    450
                                     ========    ========    ========    ========      ========    ========   ==========   ========
Capital employed at December 31 (3)
   Excluding investment in
    affiliates ....................  $  2,349    $  2,849    $  1,245    $    989      $      2    $    382   $       --   $  7,816
   Investment in affiliates (4) ...       191         371         248         531            22          --           --      1,363
                                     --------    --------    --------    --------      --------    --------   ----------   --------
Total capital employed ............  $  2,540    $  3,220    $  1,493    $  1,520      $     24    $    382   $       --   $  9,179
                                     ========    ========    ========    ========      ========    ========   ==========   ========

Return on capital employed
  (ROCE) (5) ......................       9.3%        8.9%       13.6%       10.9%          N/A         N/A           --       10.3%
</TABLE>



                                       96

<PAGE>   99

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)

<TABLE>
<CAPTION>
                                         UPSTREAM              DOWNSTREAM
                                    -------------------    -------------------    EMERGING                 ELIMINA-    CONSOLI-
SEGMENT INFORMATION                   U.S.       INT'L.      U.S.      INT'L.    BUSINESSES   CORPORATE     TIONS        DATED
                                    --------    -------    --------    -------   ----------   ---------    --------    --------
<S>                                     <C>         <C>         <C>         <C>         <C>          <C>         <C>       <C>
1998 (CONTINUED)

Significant non-cash items
   DD&A ......................      $    383    $    457   $    139    $    133  $    --      $      1     $    --     $   1,113
   Dry hole costs and
     impairment of unproved
     properties ..............      $     59    $    104   $     --    $     --  $    --      $     --     $    --     $     163
   Stock option provision ....      $     --    $     --   $     --    $     --  $    --      $    236     $    --     $     236
   Inventory write-down to
     market ..................      $      6    $     --   $     63    $     28  $    --      $     --     $    --     $      97
Capital expenditures and
  investments (6).............      $    788    $  1,177   $    201    $    332  $     1      $     17     $    --     $   2,516
Total assets .................      $  3,653    $  5,693   $  2,805    $  2,815  $    14      $  1,095     $    --     $  16,075
</TABLE>

----------

(1)  Includes after-tax benefits (charges) from special items:

<TABLE>
<S>                                 <C>         <C>        <C>         <C>       <C>          <C>          <C>         <C>
 2000
 Asset sales .................      $     27    $    --    $     --    $    --   $     --     $     --     $     --    $     27
 Discontinued businesses .....            --         --          --         --         --           (4)          --          (4)
 Property impairments ........            --         --          (3)        --        (26)          --           --         (29)
 Inventory write-downs .......            --         --          --        (24)        --           --           --         (24)
 Litigation ..................            --         --         (16)        --         --           --           --         (16)
                                    --------    -------    --------    -------   --------     --------     --------    --------
 Total special items .........      $     27    $    --    $    (19)   $   (24)  $    (26)    $     (4)    $     --    $    (46)
                                    ========    =======    ========    =======   ========     ========     ========    ========
 1999
 Discontinued businesses .....      $     --    $    --    $     --    $    --   $     --     $    (20)    $     --    $    (20)
 Litigation ..................            --         --         (18)        --         --           --           --         (18)
                                    --------    -------    --------    -------   --------     --------     --------    --------
 Total special items .........      $     --    $    --    $    (18)   $    --   $     --     $    (20)    $     --    $    (38)
                                    ========    =======    ========    =======   ========     ========     ========    ========

 1998
 Asset sales .................      $     41    $    54    $     --    $    12   $     --     $     --     $     --    $    107
 Property impairments ........           (32)        (6)         --         --         --           --           --         (38)
 Inventory write-downs .......            (4)        --         (40)       (19)        --           --           --         (63)
 Employee separation costs ...           (19)       (23)         (5)        (5)        --           --           --         (52)
 Litigation ..................            --         --         (28)        --         --          (14)          --         (42)
 Stock option provision ......            --         --          --         --         --         (183)          --        (183)
                                    --------    -------    --------    -------   --------     --------     --------    --------
 Total special items .........      $    (14)   $    25    $    (73)   $   (12)  $     --     $   (197)    $     --    $   (271)
                                    ========    =======    ========    =======   ========     ========     ========    ========
</TABLE>

(2)  Includes sales of purchased products substantially at cost:

<TABLE>
<CAPTION>
                                                      2000       1999       1998
                                                    ---------- ---------- ----------
<S>                                                 <C>         <C>        <C>
   Buy/sell supply transactions settled in cash
       Crude oil..................................  $   4,786   $  3,282   $  2,728
       Refined products...........................  $   1,703   $    747   $    438
   Natural gas resales............................  $   2,551   $  1,242   $  1,109
   Electric power resales.........................  $       4   $     28   $    729
</TABLE>

     Sales to equity affiliates totaled $2,200 for 2000, $1,519 for 1999 and
     $1,219 for 1998. The majority of these sales was in downstream and
     represented refined products.

(3)  Capital employed is equivalent to the sum of stockholders' equity/owner's
     net investment and borrowings (both short-term and long-term). Borrowings
     include amounts due to related parties, net of associated notes receivable.
     Amounts identified for operating segments comprise those assets and
     liabilities not deemed to be of a general corporate nature, including cash
     and cash equivalents, financing-oriented items and aviation investment.

(4)  Investment in affiliates (including advances) for Petrozuata was $693 and
     $445 for 2000 and 1999, respectively.



                                       97
<PAGE>   100
(5)  ROCE is a measure of annual net income before special items, excluding
     after-tax debt cost incurred, generated as a percentage of the two-year
     average capital employed.

(6)  Includes investments in affiliates.

<TABLE>
<CAPTION>
                                                                                                         OTHER
 GEOGRAPHIC INFORMATION                                U.S.          U.K.      GERMANY       NORWAY    COUNTRIES   CONSOLIDATED
                                                     -------       --------    -------       -------   ---------   ------------
 2000
<S>                                                  <C>            <C>         <C>             <C>      <C>           <C>
 Sales and other operating revenues (1).........     $22,914        $7,851      $3,606        $  474     $3,892        $38,737
 Long-lived assets at December 31 (2)...........     $ 5,492        $3,662      $  143        $1,473     $1,437        $12,207
 1999
 Sales and other operating revenues (1).........     $14,528        $5,950      $3,150        $  330     $3,081        $27,039
 Long-lived assets at December 31 (2)...........     $ 5,192        $3,265      $  154        $1,574     $1,050        $11,235
 1998
 Sales and other operating revenues (1).........     $12,878        $4,305      $2,881        $  289     $2,443        $22,796
 Long-lived assets at December 31 (2)...........     $ 5,122        $3,577      $  195        $1,547     $  972        $11,413
</TABLE>

----------

(1)  Revenues are attributed to countries based on location of the selling
     entity.

(2)  Represents net PP&E.

28.  OTHER FINANCIAL INFORMATION


     Research and development expenses were $58 for 2000, $54 for 1999 and $51
for 1998.


                                       98
<PAGE>   101
                           SUPPLEMENTAL PETROLEUM DATA
                                   (UNAUDITED)
                              (DOLLARS IN MILLIONS)

OIL AND GAS PRODUCING ACTIVITIES

         Supplemental Petroleum Data disclosures are presented in accordance
with the provisions of SFAS No. 69, "Disclosures about Oil and Gas Producing
Activities."

         Accordingly, volumes of reserves and production exclude royalty
interests of others, and royalty payments are reflected as reductions in
revenues.

RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES

<TABLE>
<CAPTION>
                              TOTAL WORLDWIDE             UNITED STATES              EUROPE                 OTHER REGIONS
                         -----------------------   ------------------------   ----------------------  ---------------------------
                          2000     1999    1998     2000     1999     1998     2000    1999    1998     2000      1999     1998
                         ------   ------  ------   ------   ------   ------   ------  ------  ------  -------   -------   -------
<S>                      <C>      <C>     <C>      <C>      <C>      <C>      <C>     <C>     <C>     <C>       <C>       <C>
CONSOLIDATED COMPANIES
Revenues
    Sales ............   $3,494   $2,389  $1,938   $1,022   $  646   $  643   $1,573  $1,192  $  831  $   899   $   551   $   464
    Transfers ........    1,420      862     646      688      384      272      731     478     374        1        --        --
Exploration (1) ......     (279)    (270)   (380)    (121)     (64)    (128)     (59)    (62)   (108)     (99)     (144)     (144)
Production ...........     (872)    (851)   (806)    (324)    (287)    (303)    (369)   (433)   (382)    (179)     (131)     (121)
DD&A .................     (973)    (887)   (799)    (366)    (338)    (345)    (526)   (491)   (372)     (81)      (58)      (82)
Other (2) ............       63       18     148      (27)      13      104       73       6      48       17        (1)       (4)
Income taxes .........   (1,390)    (501)   (201)    (293)     (87)     (36)    (698)   (272)   (100)    (399)     (142)      (65)
                         ------   ------  ------   ------   ------   ------   ------  ------  ------  -------   -------   -------
    Results of
      Operations .....    1,463      760     546      579      267      207      725     418     291      159        75        48
                         ------   ------  ------   ------   ------   ------   ------  ------  ------  -------   -------   -------

EQUITY AFFILIATES (3)
 Revenues ............      399      212      78       25       14       14      118      84      60      256       114         4
 Production ..........     (118)     (81)    (67)     (12)      (9)      (6)     (35)    (30)    (38)     (71)      (42)      (23)
 DD&A ................      (31)     (33)    (23)      (6)      (4)      (4)     (12)    (16)    (16)     (13)      (13)       (3)
 Other (2) ...........        5       --      --        3       --       --       (2)     --      --        4        --        --
 Income taxes ........      (38)       8      18       --       --       --      (13)     (1)     (1)     (25)        9        19
                         ------   ------  ------   ------   ------   ------   ------  ------  ------  -------   -------   -------
    Results of
      Operations .....      217      106       6       10        1        4       56      37       5      151        68        (3)
                         ------   ------  ------   ------   ------   ------   ------  ------  ------  -------   -------   -------
Total Results of
   Operations ........   $1,680   $  866  $  552   $  589   $  268   $  211   $  781  $  455  $  296  $   310   $   143   $    45
                         ======   ======  ======   ======   ======   ======   ======  ======  ======  =======   =======   =======
</TABLE>

---------

(1)  Includes exploration operating expenses, dry hole costs and impairment of
     unproved properties.

(2)  Includes gain/(loss) on disposal of fixed assets and other miscellaneous
     revenues and expenses.

(3)  Includes Conoco's net share of equity affiliate information.

                                       99
<PAGE>   102




                           SUPPLEMENTAL PETROLEUM DATA
                                   (UNAUDITED)
                              (DOLLARS IN MILLIONS)

COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION,
     EXPLORATION AND DEVELOPMENT ACTIVITIES (1)

<TABLE>
<CAPTION>
                               TOTAL WORLDWIDE         UNITED STATES               EUROPE              OTHER REGIONS
                           ----------------------  ----------------------  ----------------------  ----------------------
                            2000    1999    1998    2000    1999    1998    2000    1999    1998    2000    1999    1998
                           ------  ------  ------  ------  ------  ------  ------  ------  ------  ------  ------  ------
<S>                        <C>     <C>     <C>     <C>     <C>     <C>     <C>     <C>     <C>     <C>     <C>     <C>
CONSOLIDATED
COMPANIES
Property acquisitions
    Proved (2) (3) (4) ..  $  621  $  138  $  199  $   24  $    6  $   24  $  572  $   --  $  175  $   25  $  132  $   --
    Unproved ............      92      19      93       6       1      55      11      12      25      75       6      13
Exploration .............     299     276     436     125      97     119      61      72     114     113     107     203
Development .............     908     737   1,019     398     304     542     335     342     403     175      91      74
                           ------  ------  ------  ------  ------  ------  ------  ------  ------  ------  ------  ------

     Total ..............   1,920   1,170   1,747     553     408     740     979     426     717     388     336     290

EQUITY AFFILIATES (5)
Development .............     320     337     564      18      15      30       8       1       2     294     321     532
                           ------  ------  ------  ------  ------  ------  ------  ------  ------  ------  ------  ------

Total ...................  $2,240  $1,507  $2,311  $  571  $  423  $  770  $  987  $  427  $  719  $  682  $  657  $  822
                           ======  ======  ======  ======  ======  ======  ======  ======  ======  ======  ======  ======
</TABLE>

----------

(1)  These data comprise all costs incurred in the activities shown, whether
     capitalized or charged to expense at the time they were incurred.

(2)  Does not include properties acquired through property trades.

(3)  Acquisition costs of properties are shown before a gross up for SFAS No.
     109 "Accounting For Income Taxes" of $204 in 2000, $48 in 1999 and $55
     in 1998.

(4)  Includes acquisition costs associated with petroleum reserves acquired in
     the North Sea in 2000 and 1998.

(5)  Includes Conoco's net share of equity affiliate information.


CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES

<TABLE>
<CAPTION>
                                  TOTAL WORLDWIDE           UNITED STATES               EUROPE              OTHER REGIONS
                             -------------------------  ----------------------  ----------------------  ----------------------
                               2000    1999     1998     2000    1999    1998    2000    1999    1998    2000    1999    1998
                             -------  -------  -------  ------  ------  ------  ------  ------  ------  ------  ------  ------
<S>                          <C>      <C>      <C>      <C>     <C>     <C>     <C>     <C>     <C>     <C>     <C>     <C>
CONSOLIDATED
 COMPANIES

Gross costs
   Proved properties (1) ..  $14,730  $13,661  $13,488  $5,266  $4,968  $5,013  $7,461  $6,939  $6,942  $2,003  $1,754  $1,533
   Unproved properties ....    1,106    1,201    1,159     497     651     634     322     331     262     287     219     263
Less
   Accumulated DD&A .......    8,197    7,887    7,469   3,099   3,024   2,983   3,668   3,507   3,182   1,430   1,356   1,304
                             -------  -------  -------  ------  ------  ------  ------  ------  ------  ------  ------  ------
     Total net costs ......    7,639    6,975    7,178   2,664   2,595   2,664   4,115   3,763   4,022     860     617     492

EQUITY AFFILIATES (2)
Gross costs
   Proved properties ......    1,728    1,411    1,075     119     102      87     213     207     207   1,396   1,102     781
Less
   Accumulated DD&A .......      164      134       99      29      25      21     101      90      75      34      19       3
                             -------  -------  -------  ------  ------  ------  ------  ------  ------  ------  ------  ------
     Total net costs ......    1,564    1,277      976      90      77      66     112     117     132   1,362   1,083     778
                             -------  -------  -------  ------  ------  ------  ------  ------  ------  ------  ------  ------

Total .....................  $ 9,203  $ 8,252  $ 8,154  $2,754  $2,672  $2,730  $4,227  $3,880  $4,154  $2,222  $1,700  $1,270
                             =======  =======  =======  ======  ======  ======  ======  ======  ======  ======  ======  ======
</TABLE>

----------

(1)  Includes acquisition costs associated with petroleum reserves acquired in
     the North Sea in 2000 and 1998.

(2)  Includes Conoco's net share of equity affiliate information.




                                       100
<PAGE>   103
                          SUPPLEMENTAL PETROLEUM DATA
                                  (UNAUDITED)
                            (IN MILLIONS OF BARRELS)

ESTIMATED PROVED RESERVES OF OIL (1)

<TABLE>
<CAPTION>
                                        TOTAL WORLDWIDE           UNITED STATES              EUROPE               OTHER REGIONS
                                    ----------------------   ----------------------  ----------------------  ----------------------
                                     2000    1999    1998     2000    1999    1998    2000    1999    1998    2000    1999    1998
                                    ------  ------  ------   ------  ------  ------  ------  ------  ------  ------  ------  ------
<S>                                 <C>     <C>     <C>      <C>     <C>     <C>     <C>     <C>     <C>     <C>     <C>     <C>
PROVED RESERVES OF
   CONSOLIDATED COMPANIES

Beginning of year ...............      788     863     893      238     261     277     383     410     421     167     192     195
Revisions and other changes .....       46      (6)     42       23       4      14      16      (5)     20       7      (5)      8
Extensions and discoveries ......       56      54      41       19       7      15      18      37       6      19      10      20
Improved recovery ...............       --      --      14       --      --      --      --      --      11      --      --       3
Purchase of reserves (2) (3) ....       55       1       8       --       1      --      45      --       8      10      --      --
Sale of reserves (4) ............       (2)     (8)    (16)      (2)     (8)    (16)     --      --      --      --      --      --
Production ......................     (115)   (116)   (119)     (29)    (27)    (29)    (57)    (59)    (56)    (29)    (30)    (34)
                                    ------  ------  ------   ------  ------  ------  ------  ------  ------  ------  ------  ------
   End of year ..................      828     788     863      249     238     261     405     383     410     174     167     192
                                    ------  ------  ------   ------  ------  ------  ------  ------  ------  ------  ------  ------

PROVED RESERVES OF EQUITY
    AFFILIATES (5)

Beginning of year ...............      742     728     731       --      --      --      60      50      51     682     678     680
Revisions and other changes .....        2       8       5       --      --      --       3       8       5      (1)     --      --
Extensions and discoveries ......       87      21      --       --      --      --       4       9      --      83      12      --
Production ......................      (21)    (15)     (8)      --      --      --      (7)     (7)     (6)    (14)     (8)     (2)
                                    ------  ------  ------   ------  ------  ------  ------  ------  ------  ------  ------  ------
   End of year ..................      810     742     728       --      --      --      60      60      50     750     682     678
                                    ------  ------  ------   ------  ------  ------  ------  ------  ------  ------  ------  ------
Total ...........................    1,638   1,530   1,591      249     238     261     465     443     460     924     849     870
                                    ======  ======  ======   ======  ======  ======  ======  ======  ======  ======  ======  ======

PROVED DEVELOPED RESERVES OF
    CONSOLIDATED COMPANIES
Beginning of year ...............      565     622     600      202     222     242     217     228     174     146     172     184
End of year .....................      607     565     622      215     202     222     256     217     228     136     146     172

PROVED DEVELOPED RESERVES OF
    EQUITY AFFILIATES (5)
Beginning of year ...............      129      92      43       --      --      --      43      42      43      86      50      --
End of year .....................      193     129      92       --      --      --      39      43      42     154      86      50
</TABLE>

---------

(1)  Oil reserves comprise crude oil and condensate, and natural gas liquids
     expected to be removed for Conoco's account from its natural gas
     deliveries.

(2)  Includes reserves acquired through property trades.

(3)  Includes reserves acquired in the North Sea in 2000 and 1998.

(4)  Includes reserves disposed of through property trades.

(5)  Includes Conoco's net share of equity affiliate information.

                                       101

<PAGE>   104
                          SUPPLEMENTAL PETROLEUM DATA
                                  (UNAUDITED)
                            (IN BILLION CUBIC FEET)

ESTIMATED PROVED RESERVES OF GAS

<TABLE>
<CAPTION>
                                       TOTAL WORLDWIDE           UNITED STATES              EUROPE                OTHER REGIONS
                                  ----------------------   ----------------------   ----------------------   ----------------------
                                   2000    1999    1998     2000    1999    1998     2000    1999    1998     2000    1999    1998
                                  ------  ------  ------   ------  ------  ------   ------  ------  ------   ------  ------  ------
<S>                               <C>     <C>     <C>      <C>     <C>     <C>      <C>     <C>     <C>      <C>     <C>     <C>
PROVED RESERVES OF
   CONSOLIDATED COMPANIES

Beginning of year ..............   5,799   5,802   5,491    2,166   2,319   2,235    2,884   3,053   3,060      749     430     196
Revisions and other changes
    (1) (2) ....................    (176)      7      25     (110)    (34)     18       42      31     (20)    (108)     10      27
Extensions and discoveries .....     515     446     961      284     219     624        1      65     111      230     162     226
Purchase of reserves (3) (4) ...     222     174     116       19       8       4      203      --     112       --     166      --
Sale of reserves (5) ...........      (7)    (30)   (281)      (7)    (30)   (243)      --      --     (38)      --      --      --
Production .....................    (617)   (600)   (510)    (291)   (316)   (319)    (293)   (265)   (172)     (33)    (19)    (19)
                                  ------  ------  ------   ------  ------  ------   ------  ------  ------   ------  ------  ------
   End of year .................   5,736   5,799   5,802    2,061   2,166   2,319    2,837   2,884   3,053      838     749     430
                                  ------  ------  ------   ------  ------  ------   ------  ------  ------   ------  ------  ------

PROVED RESERVES OF EQUITY
    AFFILIATES (6)

Beginning of year ..............     343     381     370      343     381     370       --      --      --       --      --      --
Revisions and other changes ....     (19)    (35)    (12)     (19)    (35)    (12)      --      --      --       --      --      --
Extensions and discoveries .....      --      --       1       --      --       1       --      --      --       --      --      --
Purchase of reserves ...........      --       3      27       --       3      27       --      --      --       --      --      --
Production .....................      (7)     (6)     (5)      (7)     (6)     (5)      --      --      --       --      --      --
                                  ------  ------  ------   ------  ------  ------   ------  ------  ------   ------  ------  ------
   End of year .................     317     343     381      317     343     381       --      --      --       --      --      --
                                  ------  ------  ------   ------  ------  ------   ------  ------  ------   ------  ------  ------
Total ..........................   6,053   6,142   6,183    2,378   2,509   2,700    2,837   2,884   3,053      838     749     430
                                  ======  ======  ======   ======  ======  ======   ======  ======  ======   ======  ======  ======

PROVED DEVELOPED RESERVES OF
    CONSOLIDATED COMPANIES
Beginning of year ..............   4,164   3,991   3,061    1,792   1,828   1,801    2,017   1,954   1,091      355     209     169
End of year ....................   4,375   4,164   3,991    1,788   1,792   1,828    2,295   2,017   1,954      292     355     209

PROVED DEVELOPED RESERVES OF
    EQUITY AFFILIATES (6)
Beginning of year ..............      72      66      40       72      66      40       --      --      --       --      --      --

End of year ....................      74      72      66       74      72      66       --      --      --       --      --      --
</TABLE>

---------
(1)  Includes revisions due to wet gas and NGL accounting realignment in the
     U.S. This resulted in net additional reserves of 11 MMBOE in 2000.

(2)  Includes other regions' price-driven revisions to gas reserve entitlements
     under production sharing contracts and similar arrangements.

(3)  Includes reserves acquired through property trades.

(4)  Includes reserves acquired in the North Sea in 2000 and 1998.

(5)  Includes reserves disposed of through property trades.

(6)  Includes Conoco's net share of equity affiliate information.

                                       102

<PAGE>   105



                           SUPPLEMENTAL PETROLEUM DATA
                                   (UNAUDITED)

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
     AND GAS RESERVES

     The following information has been prepared in accordance with SFAS No. 69,
which requires the standardized measure of discounted future net cash flows to
be based on year-end prices, costs and statutory income tax rates and a 10
percent annual discount rate. Specifically, the per-barrel oil prices used to
calculate the December 31, 2000 data averaged $25.29 for the U.S., $21.75 for
Europe and $21.23 for other regions. The gas prices per thousand cubic feet
averaged $9.79 for the U.S., $3.15 for Europe and $5.43 for other regions.
Because prices used in the calculation are as of December 31, the standardized
measure could vary significantly from year to year based on market conditions at
that specific date.

     The projections should not be viewed as realistic estimates of future cash
flows nor should the "standardized measure" be interpreted as representing
current value to Conoco. Material revisions to estimates of proved reserves may
occur in the future; development and production of the reserves may not occur in
the periods assumed; actual prices realized are expected to vary significantly
from those used; and actual costs also may vary. Conoco's investment and
operating decisions are not based on the following information, but on a wide
range of reserve estimates that include probable as well as proved reserves,
and on different price and cost assumptions from those reflected in this
information.

                                       103

<PAGE>   106
                           SUPPLEMENTAL PETROLEUM DATA
                                   (UNAUDITED)
                              (DOLLARS IN MILLIONS)

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
      AND GAS RESERVES

<TABLE>
<CAPTION>
                             TOTAL WORLDWIDE              UNITED STATES                EUROPE                  OTHER REGIONS
                       ---------------------------  -------------------------  -------------------------  -------------------------
                         2000      1999     1998     2000     1999     1998     2000     1999     1998     2000     1999     1998
                       --------  --------  -------  -------  -------  -------  -------  -------  -------  -------  -------  -------
<S>                    <C>       <C>       <C>      <C>      <C>      <C>      <C>      <C>      <C>      <C>      <C>      <C>
CONSOLIDATED COMPANIES
Future cash flows

  Revenues............ $ 52,174  $ 31,682  $20,340  $25,990  $ 9,824  $ 6,148  $17,664  $15,724  $11,376  $ 8,520  $ 6,134  $ 2,816
  Production costs....   (9,698)   (8,295)  (8,271)  (3,342)  (2,604)  (2,665)  (4,794)  (4,460)  (4,742)  (1,562)  (1,231)    (864)
  Development costs...   (1,904)   (1,573)  (1,548)    (304)    (347)    (370)    (627)    (665)    (823)    (973)    (561)    (355)
  Income tax expense..  (16,892)  (10,212)  (3,904)  (7,505)  (1,805)    (546)  (6,515)  (5,581)  (2,239)  (2,872)  (2,826)  (1,119)
                       --------  --------  -------  -------  -------  -------  -------  -------  -------  -------  -------  -------
Future net cash
  flows...............   23,680    11,602    6,617   14,839    5,068    2,567    5,728    5,018    3,572    3,113    1,516      478
Discounted to present
  value at a 10%
  annual rate.........   (9,341)   (4,373)  (2,414)  (6,350)  (2,157)  (1,055)  (1,699)  (1,468)  (1,151)  (1,292)    (748)    (208)
                       --------  --------  -------  -------  -------  -------  -------  -------  -------  -------  -------  -------
      Total (1).......   14,339     7,229    4,203    8,489    2,911    1,512    4,029    3,550    2,421    1,821      768      270
                       --------  --------  -------  -------  -------  -------  -------  -------  -------  -------  -------  -------

EQUITY AFFILIATES (2)
Future cash flows

  Revenues............   15,366    13,524    5,327    3,158      839    1,001    1,015      976      427   11,193   11,709    3,899
  Production costs....   (1,578)   (2,489)  (2,228)    (514)    (334)    (346)    (417)    (492)    (266)    (647)  (1,663)  (1,616)
  Development costs...   (1,239)   (1,168)  (1,086)    (288)    (181)    (191)     (39)     (38)     (28)    (912)    (949)    (867)
  Income tax expense..   (3,341)   (2,522)    (425)    (867)    (115)    (166)    (161)     (78)     (63)  (2,313)  (2,329)    (196)
                       --------  --------  -------  -------  -------  -------  -------  -------  -------  -------  -------  -------
Future net cash
  flows...............    9,208     7,345    1,588    1,489      209      298      398      368       70    7,321    6,768    1,220
Discounted to present
  value at a 10%
  annual rate.........   (5,771)   (5,039)  (1,327)    (833)    (155)    (220)    (139)    (106)      (9)  (4,799)  (4,778)  (1,098)
                       --------  --------  -------  -------  -------  -------  -------  -------  -------  -------  -------  -------
      Total...........    3,437     2,306      261      656       54       78      259      262       61    2,522    1,990      122
                       --------  --------  -------  -------  -------  -------  -------  -------  -------  -------  -------  -------
Total................. $ 17,776  $  9,535  $ 4,464  $ 9,145  $ 2,965  $ 1,590  $ 4,288  $ 3,812  $ 2,482  $ 4,343  $ 2,758  $   392
                       ========  ========  =======  =======  =======  =======  =======  =======  =======  =======  =======  =======
</TABLE>

---------

(1)  Includes $263 at year-end 1998 attributable to Conoco Oil & Gas Associates
     L.P., in which there was a minority interest with an approximate 20 percent
     average revenue share.

(2)  Includes Conoco's net share of equity affiliate information.

SUMMARY OF CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
     RELATING TO PROVED OIL AND GAS RESERVES

<TABLE>
<CAPTION>
                                                                          CONSOLIDATED COMPANIES         EQUITY AFFILIATES(1)
                                                                       ----------------------------   ---------------------------
                                                                         2000      1999      1998      2000      1999      1998
                                                                       --------   -------   -------   -------   -------   -------
<S>                                                                    <C>        <C>       <C>       <C>       <C>       <C>
Balance at January 1 ................................................. $  7,229   $ 4,203   $ 5,623   $ 2,306   $   261   $   604

Sales and transfers of oil and gas produced, net of production
  costs ..............................................................   (4,041)   (2,400)   (1,778)     (281)     (124)       (2)

Development costs incurred during the period .........................      908       737     1,019       320       337       555

Net changes in prices and in development and production costs ........    9,150     6,650    (3,948)      541     2,112    (1,155)

Extensions, discoveries and improved recovery, less related costs ....    2,241     1,023       838       423        80         1

Revisions of previous quantity estimates .............................       77       (24)      189       (39)       25         2

Purchases (sales) of reserves in place - net .........................      869        99       (92)       --         2        18

Accretion of discount ................................................    1,321       620       916       294        36        84

Net change in income taxes ...........................................   (3,450)   (3,978)    1,541      (444)     (530)      128

Other ................................................................       35       299      (105)      317       107        26
                                                                       --------   -------   -------   -------   -------   -------

Balance at December 31 ............................................... $ 14,339   $ 7,229   $ 4,203   $ 3,437   $ 2,306   $   261
                                                                       ========   =======   =======   =======   =======   =======
</TABLE>

---------

(1)  Includes Conoco's net share of equity affiliate information.


                                       104

<PAGE>   107



                      CONSOLIDATED QUARTERLY FINANCIAL DATA
                                   (UNAUDITED)
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)

<TABLE>
<CAPTION>
                                                                     QUARTER ENDED
                                               ---------------------------------------------------------------
                                                MARCH 31        JUNE 30       SEPTEMBER 30       DECEMBER 31
                                               ----------     ----------     --------------     --------------
<S>                                            <C>            <C>            <C>                <C>
2000
Sales and other operating revenues (1) ......  $    8,524     $    9,357     $       10,587     $       10,269
Cost of goods sold and other expenses (2) ...  $    7,896     $    8,643     $        9,654     $        9,298
Interest and debt expense ...................  $       83     $       89     $           78     $           88
Net income before special items .............  $      391     $      460     $          523     $          574
Net income ..................................  $      399(3)  $      456(4)  $          497(5)  $          550(6)
Earnings per share
   Basic (7) ................................  $      .64     $      .73     $          .80     $          .88
   Diluted (7) ..............................  $      .63     $      .72     $          .79     $          .87
Dividends per common share ..................  $      .19     $      .19     $          .19     $          .19
Market price of Class A common stock (8)
   High .....................................  $    27.88     $    27.06     $        27.63     $        29.56
   Low ......................................  $    18.81     $    22.00     $        21.38     $        24.00
Market price of Class B common stock (8)
   High .....................................  $    28.75     $    29.00     $        28.75     $        29.69
   Low ......................................  $    19.00     $    23.25     $        22.31     $        24.69

1999
Sales and other operating revenues (1) ......  $    5,311     $    6,252     $        7,409     $        8,067
Cost of goods sold and other expenses (2) ...  $    5,130     $    6,090     $        7,020     $        7,541
Interest and debt expense ...................  $       71     $       79     $           80     $           81
Net income before special items .............  $       83     $      114     $          261     $          324
Net income ..................................  $       83     $      114     $          223(9)  $          324
Earnings per share
   Basic (7) ................................  $      .13     $      .18     $          .36     $          .52
   Diluted (7) ..............................  $      .13     $      .18     $          .35     $          .51
Dividends per common share ..................  $      .14     $      .19     $          .19     $          .19
Market price of Class A common stock (8)
   High .....................................  $    25.44     $    31.25     $        29.25     $        29.06
   Low ......................................  $    19.38     $    22.94     $        25.31     $        20.94
Market price of Class B common stock (8)
   High .....................................  $       --     $       --     $        29.38     $        28.94
   Low ......................................  $       --     $       --     $        24.50     $        20.75
</TABLE>

---------

(1)  Excludes other income and equity in earnings of affiliates of $167, $149,
     $110 and $124 in each of the quarters in 2000 and $24, $77, $76 and $93 in
     each of the quarters in 1999.

(2)  Excludes provision for income taxes.

(3)  Includes $8 ($.01 per share - diluted) reflecting a $27 gain from the sale
     of natural gas processing assets in the U.S. partially offset by a $16 loss
     for litigation provisions and $3 for the write-off of related refinery
     assets.

(4)  Includes $4 ($.01 per share - diluted) for settlement costs associated with
     the separation agreement from DuPont related to a discontinued business.

(5)  Includes $26 ($.04 per share - diluted) for the write-off of our share of a
     Colombian power venture.

(6)  Includes $24 ($.04 per share - diluted) related to the write-down of an
     international refinery venture's inventories to market value.

(7)  Earnings per share for the year may not equal the sum of the quarterly
     earnings per share due to changes in average shares outstanding (see note 8
     to the consolidated financial statements).

(8)  Conoco's Class A common stock and Class B common stock are listed on the
     New York Stock Exchange (trading symbols: COC.A and COC.B). Class A common
     stock commenced trading on October 22, 1998, subsequent to Conoco's initial
     public offering. Class B common stock commenced trading on August 16, 1999,
     subsequent to the conclusion of DuPont's exchange offer, which resulted in
     100 percent of Class B common stock being distributed to DuPont
     shareholders. Prices are reported by the New York Stock Exchange.

(9)  Includes $38 ($.06 per share - diluted) related to U.S. downstream
     litigation and corporate settlement charges.

                                       105
<PAGE>   108
ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
          FINANCIAL DISCLOSURE

     None.

                                    PART III

    Except as indicated below, information with respect to the following items
is incorporated by reference to Conoco's 2001 annual meeting proxy statement
filed in connection with the annual meeting of stockholders to be held on May 8,
2001.

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

    The information required by this item will be set forth under the captions
"Proposal I -- Election of Directors" and "Stock Ownership of Directors and
Executive Officers -- Section 16(a) Beneficial Ownership Reporting Compliance"
in Conoco's definitive proxy statement (the "2001 Proxy Statement") for its
annual meeting of stockholders to be held on May 8, 2001, which sections are
incorporated herein by reference.

    Pursuant to general instruction G to Form 10-K, the information required by
Item 401 of Regulation S-K with respect to executive officers of Conoco is set
forth in Part I of this report (page 33).

ITEM 11.  EXECUTIVE COMPENSATION

    The information required by this item will be set forth in the sections
entitled "Proposal I -- Election of Directors -- Board Compensation" and
"Compensation of Executive Officers" in the 2001 proxy statement, which sections
are incorporated herein by reference.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

    The information required by this item is set forth in the sections entitled
"Principal Stockholders" and "Stock Ownership of Directors and Executive
Officers" in the 2001 proxy statement, which sections are incorporated herein by
reference.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

    The information required by this item is set forth in the section entitled
"Compensation of Executive Officers -- Certain Relationships and Related
Transactions" in the 2001 proxy statement, which section is incorporated herein
by reference.

                                     PART IV

ITEM 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(a) Financial statements, financial statement schedules and exhibits

    1. Financial statements (see Part II, Item 8 of this report regarding
       financial statements).

    2. Financial statement schedules.

    The following should be read in conjunction with the previously referenced
    financial statements --

       Financial statement schedules listed under SEC rules but not included in
    this report are omitted because they are not applicable or the required
    information is shown in the financial statements or notes.

       Condensed financial information of the parent company is omitted because
    restricted net assets of consolidated subsidiaries do not exceed 25 percent
    of consolidated net assets. Footnote disclosure of restrictions on the
    ability of subsidiaries and affiliates to transfer funds is omitted because
    the restricted net assets of subsidiaries combined with Conoco's equity in
    the undistributed earnings of affiliated companies does not exceed 25
    percent of consolidated net assets at December 31, 2000.


                                      106
<PAGE>   109


       Separate financial statements of affiliated companies accounted for by
    the equity method are omitted because no such affiliate individually
    constitutes a 20 percent significant subsidiary.

       Included on page 110 of this annual report on Form 10-K is financial
    statement schedule II -- Valuation and qualifying accounts.

    3. Exhibits

       The following list of exhibits includes both exhibits submitted with this
    Form 10-K as filed with the SEC and those incorporated by reference to other
    filings:

    EXHIBIT NUMBER                 DESCRIPTION

        3.1         --   Second Amended and Restated Certificate of
                         Incorporation of Conoco Inc.(1)
        3.2         --   By-Laws of Conoco Inc., as amended October 28, 1999(2)
        4.1         --   Specimen Certificate for shares of Class A Common Stock
                         of the Registrant(3)
        4.2         --   Specimen Certificate for shares of Class B Common Stock
                         of the Registrant(3)
        4.3         --   Preferred Share Purchase Rights Agreement(3)
        4.4         --   Amendment to Preferred Share Purchase Rights Agreement
                         (4)
        4.5         --   Second Amendment to Preferred Share Purchase Rights
                         Agreement(5)
        4.6         --   Indenture between Conoco and the Trustee relating to
                         the Debt Securities(6)
       10.1#        --   Employment Agreement, dated October 19, 2000 between
                         Conoco and Archie W. Dunham(7)
       10.2#        --   Conoco Inc. Key Employee Severance Plan, as amended(8)
       10.3#        --   Conoco Inc. Key Employee Temporary Severance Plan, as
                         amended(9)
       10.4#        --   Conoco Inc. Salary Deferral and Savings Restoration
                         Plan, as amended(10)
       10.5#        --   Directors' Charitable Gift Plan, as amended(10)
       10.6#        --   Deferred Compensation Plan for Nonemployee Directors,
                         as amended May 12, 1999(11)
       10.7#        --   Form Indemnity Agreement with Directors(12)
       10.8#        --   1998 Stock and Performance Incentive Plan, as amended
                         October 28, 1999(13)
       10.9#        --   1998 Key Employee Stock Performance Plan, as amended
                         October 28, 1999(14)
       10.11#       --   Rabbi Trust Agreement dated December 17, 1999(15)
       11           --   Statement re: Computation of Per Share Earnings(7)
       12           --   Computation of Ratio of Earnings to Fixed Charges(7)
       21.1         --   List of Principal Subsidiaries of the Registrant(7)
       23.1         --   Consent of PricewaterhouseCoopers LLP(7)
       24           --   Power of Attorney(16)
       99.1         --   Consent of Solomon Associates(7)

----------

(1)   Incorporated by reference to exhibit 3.1 of Conoco's Form 10-Q for the
      quarter ended September 30, 1998.

(2)   Incorporated by reference to exhibit 3.2 of Conoco's registration
      statement on Form S-3/A, Registration No. 333-88573.

(3)   Incorporated by reference to the exhibit of the same number filed as part
      of Conoco's registration statement on Form S-1, Registration No.
      333-60119.

(4)   Incorporated by reference to exhibit 4.6 of Conoco's registration
      statement on Form S-8, Registration No. 333-65977.

(5)   Incorporated by reference to exhibit 4.1 of Conoco's Form 10-Q for the
      quarter ended June 30, 1999.

(6)   Incorporated by reference to exhibit 4.1 of Conoco's registration
      statement on Form S-3, Registration No. 333-72291.

(7)   Filed herein.


                                      107
<PAGE>   110


(8)   Incorporated by reference to exhibit 10.1 of Conoco's Form 10-Q for the
      quarter ended June 30, 2000.

(9)   Incorporated by reference to exhibit 10.2 of Conoco's Form 10-Q for the
      quarter ended June 30, 2000.

(10)  Incorporated by reference to exhibit of the same number of Conoco's
      registration statement on Form S-1, Registration No. 333-88573.

(11)  Incorporated by reference to exhibit 10.1 of Conoco's Form 10-Q for the
      quarter ended March 31, 1999.

(12)  Incorporated by reference to exhibit 10.19 of Conoco's registration
      statement on Form S-1, Registration No. 333-60119.

(13)  Incorporated by reference to exhibit 10.6 of Conoco's Form 10-Q for the
      quarter ended September 30, 1999.

(14)  Incorporated by reference to exhibit 10.7 of Conoco's Form 10-Q for the
      quarter ended September 30, 1999.

(15)  Incorporated by reference to exhibit of the same number of Conoco's Form
      10-K for the fiscal year ended December 31, 1999.

 #    Management contract or compensatory plan or arrangement required to be
      filed as an exhibit to this Form 10-K.

(b)   Reports on Form 8-K

      1. A current report on Form 8-K, dated February 22, 2001 was filed by
         Conoco on February 22, 2001. In this report, we filed our 2000 audited
         financial statements.


                                      108
<PAGE>   111


                      REPORT OF INDEPENDENT ACCOUNTANTS ON
                          FINANCIAL STATEMENT SCHEDULE


To the Stockholders and the Board of Directors of Conoco Inc.:

Our audit of the consolidated financial statements referred to in our report
dated February 19, 2001 appearing in the 2000 Annual Report to Shareholders of
Conoco Inc. (which report and consolidated financial statements are included in
this Annual Report on Form 10-K) also included an audit of the financial
statement schedule listed in Item 14(a)(2) of this Form 10-K. In our opinion,
this financial statement schedule presents fairly, in all material respects, the
information set forth therein when read in conjunction with the related
consolidated financial statements.



PRICEWATERHOUSECOOPERS LLP

Houston, Texas
March 9, 2001


                                      109
<PAGE>   112


                                   CONOCO INC.
                SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
              FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
                            (IN MILLIONS OF DOLLARS)


<TABLE>
<CAPTION>

                                                                                  MILLIONS OF DOLLARS
                                                     -----------------------------------------------------------------------
                                                     BALANCE AT                                                  BALANCE AT
DESCRIPTION                                          JANUARY 1      ADDITIONS     DEDUCTIONS       OTHER         DECEMBER 31
                                                     ----------     ---------     ----------      --------       -----------
<S>                                                  <C>            <C>           <C>             <C>            <C>
2000
Deducted from asset accounts:
    Deferred tax asset valuation allowance .......     $   452        $   80        $   123       $     --        $   409
Included in other accrued liabilities:
    Restructuring ................................          11            --              6              5             --
    Reserve for maintenance turnarounds ..........          62            55             46             (2)            69
1999
Deducted from asset accounts:
    Deferred tax asset valuation allowance .......         423            80             51             --            452
Included in other accrued liabilities:
    Restructuring ................................          82            --             71             --             11
    Reserve for maintenance turnarounds ..........          55            62             54             (1)            62
1998
Deducted from asset accounts:
    Deferred tax asset valuation allowance .......         392            54             23             --            423
Included in other accrued liabilities:
    Restructuring ................................          --            82             --             --             82
    Reserve for maintenance turnarounds ..........          41            53             39             --             55
</TABLE>



                                      110
<PAGE>   113


                                   SIGNATURES

    Pursuant to the requirements of Section 13 of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its behalf by
the undersigned, thereunto duly authorized and in the capacities indicated, as
of the 12th day of March 2001.

                                       CONOCO INC.
                                       (REGISTRANT)

                                       By:  /s/ ROBERT W. GOLDMAN
                                          --------------------------------------
                                                      Robert W. Goldman
                                             Senior Vice President, Finance, and
                                                   Chief Financial Officer


                                       By:  /s/ W. DAVID WELCH
                                          --------------------------------------
                                                    W. David Welch
                                                    Controller and
                                             Principal Accounting Officer



    Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed, as of the 12th day of March, 2001, by the following
persons on behalf of the registrant in the capacities indicated:


<TABLE>

<S>                                     <C>
     /s/ ARCHIE W. DUNHAM               Chairman, President and Chief Executive Officer
------------------------------
       Archie W. Dunham


     /s/ ROBERT W. GOLDMAN              Senior Vice President, Finance, and Chief Financial
------------------------------            Officer
       Robert W. Goldman


     /s/ W. DAVID WELCH                 Controller and Principal Accounting Officer
------------------------------
        W. David Welch


               *                        Director
------------------------------
    Kenneth M. Duberstein


      /s/ RUTH R. HARKIN                Director
------------------------------
        Ruth R. Harkin


    /s/ CHARLES C. KRULAK               Director
------------------------------
      Charles C. Krulak


   /s/ FRANK A. McPHERSON               Director
------------------------------
      Frank A. McPherson


               *                        Director
------------------------------
      William K. Reilly


               *                        Director
------------------------------
      William R. Rhodes


   /s/ FRANKLIN A. THOMAS               Director
------------------------------
      Franklin A. Thomas


    /s/ A. R. SANCHEZ, JR.              Director
------------------------------
      A. R. Sanchez, Jr.
</TABLE>


*BY:  /s/ MICHAEL A. GIST
   ---------------------------
       Michael A. Gist
      Attorney-in-Fact




                                       111
<PAGE>   114
                               INDEX TO EXHIBITS

<TABLE>
<CAPTION>

      EXHIBIT
      NUMBER             DESCRIPTION
      -------            -----------
<S>                 <C>  <C>
        3.1         --   Second Amended and Restated Certificate of
                         Incorporation of Conoco Inc.(1)
        3.2         --   By-Laws of Conoco Inc., as amended October 28, 1999(2)
        4.1         --   Specimen Certificate for shares of Class A Common Stock
                         of the Registrant(3)
        4.2         --   Specimen Certificate for shares of Class B Common Stock
                         of the Registrant(3)
        4.3         --   Preferred Share Purchase Rights Agreement(3)
        4.4         --   Amendment to Preferred Share Purchase Rights
                         Agreement(4)
        4.5         --   Second Amendment to Preferred Share Purchase Rights
                         Agreement(5)
        4.6         --   Indenture between Conoco and the Trustee relating to
                         the Debt Securities(6)
       10.1#        --   Employment Agreement, dated October 19, 2000 between
                         Conoco and Archie W. Dunham(7)
       10.2#        --   Conoco Inc. Key Employee Severance Plan, as amended(8)
       10.3#        --   Conoco Inc. Key Employee Temporary Severance Plan, as
                         amended(9)
       10.4#        --   Conoco Inc. Salary Deferral and Savings Restoration
                         Plan, as amended(10)
       10.5#        --   Directors' Charitable Gift Plan, as amended(10)
       10.6#        --   Deferred Compensation Plan for Nonemployee Directors,
                         as amended May 12, 1999(11)
       10.7#        --   Form Indemnity Agreement with Directors(12)
       10.8#        --   1998 Stock and Performance Incentive Plan, as amended
                         October 28, 1999(13)
       10.9#        --   1998 Key Employee Stock Performance Plan, as amended
                         October 28, 1999(14)
       10.11#       --   Rabbi Trust Agreement dated December 17, 1999(15)
       11           --   Statement re: Computation of Per Share Earnings(7)
       12           --   Computation of Ratio of Earnings to Fixed Charges(7)
       21.1         --   List of Principal Subsidiaries of the Registrant(7)
       23.1         --   Consent of PricewaterhouseCoopers LLP(7)
       24           --   Power of Attorney(7)
       99.1         --   Consent of Solomon Associates(7)
</TABLE>
----------

(1)   Incorporated by reference to exhibit 3.1 of Conoco's Form 10-Q for the
      quarter ended September 30, 1998.

(2)   Incorporated by reference to exhibit 3.2 of Conoco's registration
      statement on Form S-3/A, Registration No. 333-88573.

(3)   Incorporated by reference to the exhibit of the same number filed as part
      of Conoco's registration statement on Form S-1, Registration No.
      333-60119.

(4)   Incorporated by reference to exhibit 4.6 of Conoco's registration
      statement on Form S-8, Registration No. 333-65977.

(5)   Incorporated by reference to exhibit 4.1 of Conoco's Form 10-Q for the
      quarter ended June 30, 1999.

(6)   Incorporated by reference to exhibit 4.1 of Conoco's registration
      statement on Form S-3, Registration No. 333-72291.

(7)   Filed herein.

(8)   Incorporated by reference to exhibit 10.1 of Conoco's Form 10-Q for the
      quarter ended June 30, 2000.

(9)   Incorporated by reference to exhibit 10.2 of Conoco's Form 10-Q for the
      quarter ended June 30, 2000.

(10)  Incorporated by reference to exhibit of the same number of Conoco's
      registration statement on Form S-1, Registration No. 333-88573.

(11)  Incorporated by reference to exhibit 10.1 of Conoco's Form 10-Q for the
      quarter ended March 31, 1999.


                                       112
<PAGE>   115



(12)  Incorporated by reference to exhibit 10.19 of Conoco's registration
      statement on Form S-1, Registration No. 333-60119.

(13)  Incorporated by reference to exhibit 10.6 of Conoco's Form 10-Q for the
      quarter ended September 30, 1999.

(14)  Incorporated by reference to exhibit 10.7 of Conoco's Form 10-Q for the
      quarter ended September 30, 1999.

(15)  Incorporated by reference to exhibit of the same number of Conoco's Form
      10-K for the fiscal year ended December 31, 1999.

 #    Management contract or compensatory plan or arrangement required to be
      filed as an exhibit to this Form 10-K.


                                      113