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                                      2001

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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, 2001

                         COMMISSION FILE NUMBER 1-14521

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

             DELAWARE                                           51-0370352
   (State or other jurisdiction of                            (I.R.S. employer
   incorporation or organization)                            identification No.)

                          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:

       TITLE OF EACH CLASS             NAME OF EACH EXCHANGE ON WHICH REGISTERED
 -------------------------------       -----------------------------------------
 Common stock ($.01 par value)             New York Stock Exchange, Inc.
 Preferred share purchase rights           New York Stock Exchange, Inc.

        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 common stock held by nonaffiliates of
the registrant (excludes outstanding shares beneficially owned by directors and
officers) as of March 1, 2002, was approximately $17,449 million based on the
closing price on that date of $27.90, on the New York Stock Exchange, Inc. As of
such date, 626,312,581 shares of common stock, $.01 par value, were outstanding.

                       DOCUMENTS INCORPORATED BY REFERENCE
                        (to the extent indicated herein)

<Table>
<Caption>
                                                                     INCORPORATED BY
                                                                 (REFERENCE IN PART NO.)
                                                                 -----------------------
<S>                                                              <C>
  Portions of the registrant's proxy statement for the annual              III
  meeting of stockholders to be held on May 21, 2002
</Table>

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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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                                                                                                     PAGE
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                                                  PART I

Items 1. and 2.  Business and Properties...........................................................    1
Item 3.          Legal Proceedings.................................................................   35
Item 4.          Submission of Matters to a Vote of Security Holders...............................   37
                 Executive Officers of the Registrant..............................................   37

                                                  PART II

Item 5.          Market for Registrant's Common Equity and Related Stockholder Matters.............   39
Item 6.          Selected Financial Data...........................................................   40
Item 7.          Management's Discussion and Analysis of Financial Condition and Results of
                 Operations........................................................................   41
Item 7A.         Quantitative and Qualitative Disclosures About Market Risk........................   66
Item 8.          Financial Statements and Supplementary Data.......................................   70
Item 9.          Changes in and Disagreements with Accountants on Accounting and Financial
                 Disclosure........................................................................  123

                                                  PART III

Item 10.         Directors and Executive Officers of the Registrant................................  123
Item 11.         Executive Compensation............................................................  123
Item 12.         Security Ownership of Certain Beneficial Owners and Management....................  124
Item 13.         Certain Relationships and Related Transactions....................................  124

                                                  PART IV

Item 14.         Exhibits, Financial Statement Schedules, and Reports on Form 8-K..................  124
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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,"
"will," "should" 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 mining, 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, political events, or terrorism;

     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,
          including armed hostilities and terrorism; 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 operating
segment activities include exploring for, developing, producing and selling
crude oil, natural gas and natural gas liquids; and Syncrude mining operations
(Canadian Syncrude). 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. Emerging
businesses is currently involved in carbon fibers (Conoco Cevolution(R));
natural gas refining including gas-to-liquids; and international power. Conoco
operates in over 40 countries worldwide.

     As of December 31, 2001, Conoco had proved worldwide oil and gas reserves
of 3,299 million barrels-of-oil-equivalent (BOE) and proven Canadian Syncrude
reserves of 280 million BOE for a total of 3,579 million BOE, 40 percent of
which were natural gas. In this document, natural gas volumes have been
converted to BOE using a ratio



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of six thousand cubic feet (mcf) of natural gas to one barrel of oil. Based on
2001 annual production of 281 million BOE, excluding natural gas liquids from
gas plant ownership, Conoco had a reserve life of approximately 12 years as of
December 31, 2001. As of December 31, 2001, Conoco owned or had equity interests
in nine refineries worldwide, with a total crude distillation capacity of
approximately 936,000 barrels per day. Conoco had a marketing network of
approximately 7,900 outlets in the United States, Europe and Asia Pacific. In
2001, refined product sales averaged 1,502,000 barrels per day. For the year
ended December 31, 2001, Conoco reported net income of $1,589 million, which
included a net charge of $234 million for special items, on total revenues of
$39,539 million.

RECENT DEVELOPMENTS

     On July 16, 2001, Conoco, through a wholly owned subsidiary, completed the
acquisition of all the ordinary shares of Gulf Canada Resources Limited (Gulf
Canada), now known as Conoco Canada Resources Limited (Conoco Canada) for
approximately $4,571 million in cash plus assumed liabilities and minority
interests. For ease of reference, we will refer to Conoco Canada as Gulf Canada.
Prior to the acquisition, Gulf Canada was a Canadian-based independent
exploration and production company, with primary operations in western Canada,
Indonesia, the Netherlands and Ecuador. Subsequent to the acquisition,
operational responsibilities for Gulf Canada's interests in Indonesia, the
Netherlands and Ecuador were realigned within Conoco's regional organizational
structure and operationally Conoco's existing Canadian operations were merged
with those of Gulf Canada.

     On September 21, 2001, Conoco's shareholders approved the combination of
our Class A and Class B common stock into a single class of new common stock on
a one-for-one basis. The combination was effective on October 8, 2001.

     On November 18, 2001, Conoco and Phillips Petroleum Company (Phillips)
announced that their boards of directors unanimously approved the merger of the
two companies. The new company will be named ConocoPhillips. Under the terms of
the agreement, Phillips shareholders will receive one share of new
ConocoPhillips common stock for each share of Phillips common stock they own and
Conoco shareholders will receive .4677 shares of new ConocoPhillips common stock
for each share of Conoco common stock they own. The merger is conditioned upon,
among other things, the approval of the shareholders of each company and
customary regulatory approvals. Both companies held special meetings of
shareholders on Tuesday, March 12, 2002, and the shareholders of both companies
approved the proposed merger. Completion of the transaction is expected in the
second half of 2002.

BUSINESS STRATEGY

     We are pursuing 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. A top priority for
2002 will be to maintain our focus on operational excellence during the
integration process for the ConocoPhillips merger. We will continue to pursue
profitable production growth through successful exploration, a steady stream of
high-value development projects, and securing new opportunities by providing
innovative commercial solutions to host governments around the globe.

     Downstream is focused on maintaining a balanced suite of assets capable of
generating strong returns even in cyclical markets. We will continue to pursue
innovative growth opportunities that require limited capital investment and
continue to upgrade our business in sustainable ways.

     Our emerging carbon fibers, natural gas refining and international power
businesses are focused on developing commercial capability and building our
customer base. All three of these emerging businesses complement our core
businesses and have the potential to contribute substantially to long-term
growth.

     Conoco's major operations are in four core areas, North America, western
Europe, northern South America and southeast Asia, which was officially
designated as a core area in 2001 subsequent to our purchase of Gulf Canada. We
will continue to improve the profitability, efficiency and effectiveness of
existing operations while pursuing opportunities in the Middle East, the Caspian
Sea region, Russia and West Africa.



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     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 29 to the
consolidated financial statements.

UPSTREAM

   SUMMARY

     Conoco is currently exploring for, developing or producing crude oil,
natural gas and natural gas liquids and mining for Canadian Syncrude in 23
countries around the world. In 2001, production averaged 770,000 BOE per day,
consisting of 422,000 barrels per day of petroleum liquids (excluding natural
gas liquids from gas plant ownership), 2,030 million cubic feet (mmcf) of
natural gas per day and 10,000 barrels of Canadian Syncrude per day. The
majority of this production came from fields located in the U.S., Canada, the
U.K. and Norway, with the remaining production coming from operations in
Indonesia, the United Arab Emirates, the Netherlands, Vietnam, Ecuador, Nigeria,
Russia and Venezuela.

     In 2001, Conoco replaced 432 percent of the oil, natural gas and Canadian
Syncrude produced, adding 1,213 million BOE to its worldwide reserves for a net
increase of 932 million BOE after producing 281 million BOE, excluding natural
gas liquids from gas plant ownership. Excluding the effect of our Gulf Canada
acquisition and other purchases and disposals, we replaced 113 percent of our
oil and natural gas production, with significant reserves in the U.K., U.S.,
Vietnam and Indonesia. On December 31, 2001, we had proved reserves of 3,579
million BOE, consisting of 1,862 million barrels of petroleum liquids, 8,619
billion cubic feet (bcf) of natural gas and 280 million barrels of Canadian
Syncrude.

     Excluding our Gulf Canada purchase, Conoco's capital investment in upstream
activities in 2001 was $2,214 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 additional producing properties and
acreage in the U.K. and Vietnam. These projects will contribute to Conoco's 2002
production.

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

     Conoco is exploring for oil and/or natural gas in 22 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;

     o    the Caspian Sea; and

     o    western Canada and the Mackenzie Delta and Laurentian Basin in
          offshore eastern Canada.

     In 2001, the performance of the Conoco legacy exploration program was
excellent, as in 1998, 1999, and 2000. In 2001, Conoco participated in seven
discoveries and 19 appraisal wells that were potentially commercial, achieving a
37 percent success rate for wildcat wells and a 100 percent success rate for
appraisal drilling. A significant oil find was made in the Cuu Long Basin,
offshore Vietnam, while the high value snuggle exploration program in the North
Sea and Canada yielded a total of five new discoveries close to existing
infrastructure. Through the purchase of Gulf Canada, we also added exploration
discoveries in Canada, Indonesia and the Netherlands to our portfolio.



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     Conoco intends to continue managing our asset portfolio to increase the
proportion of upstream assets relative to downstream assets, the proportion of
gas volumes to liquids volumes, 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; and

     o    the Permian Basin in west Texas.

     In 2001 U.S. operations contributed approximately 17 percent of Conoco's
worldwide petroleum liquids production and 40 percent of its worldwide natural
gas production. U.S. proved reserves as of December 31, 2001, were 600 million
BOE, consisting of 244 million barrels of petroleum liquids and 2,138 bcf 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,
optimize our natural gas processing capabilities, and strategically focus on
natural gas opportunities.

   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 2001, our eight rig drilling program was delivering gross
natural gas production of approximately 550 mmcf per day. Conoco's 2001
development program included the acquisition of new 3D seismic data and the
drilling of 163 wells. We anticipate spending approximately $450 million in 2002
and 2003 to further develop our leases in the Lobo trend.

     Conoco's average working interest in its leases in the Lobo trend is 96
percent. Certain producing wells are subject to volumetric production payments,
the last of which terminate in 2002. These volumetric production payments
averaged approximately 39 mmcf per day in 2001.

     Lobo Pipeline Company, a wholly owned subsidiary of Conoco, owns and
operates an intrastate natural gas pipeline system in south Texas that serves as
a means of 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 two fields operated by Conoco and four 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 15 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 based on estimates of
ultimate recoverable reserves. We hold a 16 percent interest in the field, and
the other owners are Shell, BP 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. Ursa has a platform capacity of 163,000
barrels per day of petroleum liquids and 350 mmcf of gas per day. In January
2002, the field reached a cumulative production of over 100 million BOE.



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     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. The Ursa
unit was expanded to include the Princess field and the resulting alignment of
interests is expediting the development of this discovery.

     Also in 2001, Conoco drilled three appraisal wells further delineating the
extent of the Magnolia discovery. The discovery was confirmed to be commercial
and the project was approved in December of 2001. Conoco operates and holds a 75
percent interest in the Garden Banks 783 and 784 leases that comprise the field.
First oil from Magnolia is scheduled for the fourth quarter of 2004. Peak
production will occur in 2005 with rates of 50,000 barrels per day of petroleum
liquids and 150 mmcf per day of associated natural gas.

     In addition to the Princess and Magnolia successes, Conoco is continuing
its exploration program in the deepwater Gulf of Mexico. We hold interests in
298 leases, 50 of which are owned 100 percent. 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 2002, we expect to
participate in five wildcat exploration wells with working interests averaging
between 35 and 60 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 and the
Permian Basin in west Texas. 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 where our
average daily net production in 2001 was approximately 11,000 barrels of
petroleum liquids and 198 mmcf of natural gas.

     Conoco has an interest in 26 fields in the Permian Basin in west Texas,
which is one of the largest producing areas in the U.S. In the Permian Basin,
our average daily net production in 2001 was approximately 18,000 barrels of
petroleum liquids and 46 mmcf 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.

   Dispositions

     As part of ongoing efforts to rationalize our assets and efficiently manage
our portfolio, Conoco divested several U.S. producing properties in 2001
including:

     o    eight Gulf of Mexico properties as follows: the shelf assets of Ewing
          Bank 305, Main Pass 144, Main Pass 290, Main Pass 311, Mississippi
          Canyon 109, Ship Shoal 176, S. Marsh Island 9, S. Marsh Island 107;

     o    four Lobo fields;

     o    the North Maurice assets in southern Louisiana; and

     o    the Elk Basin field.

     In 2001, Conoco sold its interest in the Pocahontas Gas Partnership, a
50/50 partnership between Conoco and Consol Energy Inc., which produced and
gathered coal bed methane prior to and during coal mining operations in
Virginia.

   Conoco Gas and Power

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



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     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 110,000 barrels per day.

     In November 2001, Conoco acquired various assets from Duke Energy,
including the Zia Gas Plant in Lea County, New Mexico, which has a processing
capacity of 43 mmcf per day.

     In November 2001, Conoco completed the sale of Conoco's 50 percent interest
in Alliance Energy Services Partnership, a gas marketing joint venture, to
Allegheny Energy.

     As of December 31, 2001, Conoco owned interests in 18 natural gas
processing plants, an increase of three from last year, located in Louisiana,
New Mexico and Texas, as well as approximately 5,400 miles of gathering lines.
We operate 14 of the plants.

     Conoco gathers natural gas, extracts natural gas liquids and sells the
remaining residual gas. Most of the gas liquids recovered are supplied to our
fractionation operations, which further separate them into finished products
that are sold as feedstocks to gasoline and chemicals manufacturers, propane
resellers and agricultural end users. Conoco markets over 250,000 barrels per
day of natural gas liquids to more than 500 customers in North America.

     Conoco Gas & Power Marketing (G&PM) was established in 2000 by combining
the marketing activities of our natural gas and power businesses. We offer
sophisticated, customer-driven energy solutions including joint gas and power
procurement, storage, transportation, gas and power price-related risk
management services and ancillary services. Conoco's significant natural gas
assets give G&PM a competitive advantage that enables us to provide reliable
fuel supplies to commercial and industrial customers at attractive prices.
During 2001, Conoco marketed and traded 7 bcf of natural gas per day in North
America.

     In 2001, we combined our G&PM group with our North American power
generating operations to create a new commercial solutions business within
Conoco Gas and Power (CG&P). This move reflects a new business model in which
development activities in both natural gas and power are driven by external
factors to meet market needs. CG&P has interest in three U.S. power-generating
assets, including a new 420-megawatt, joint-venture cogeneration plant near
Orange, Texas; a similar 440-megawatt facility close to Corpus Christi, Texas;
and a 220-megawatt cogeneration plant near Conoco's refinery at Lake Charles,
Louisiana.

     Conoco's share of total natural gas liquids extracted from natural gas
processed averaged 62,500 barrels per day in 2001. Approximately 10,400 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.
Approximately 12,700 barrels per day of additional natural gas liquids were
attributable to the processing of Conoco's natural gas liquids in third
party-operated plants.

   CANADA

     The acquisition of Gulf Canada considerably strengthened Conoco's position
in North America. The transaction increased North American proved oil and gas
reserves by 395 million BOE, and added proven Canadian Syncrude reserves of 281
million BOE.

     Conoco is now the fifth largest oil and gas producer in Canada. The total
net oil and gas production for 2001 was 32 million BOE and net annual Canadian
Syncrude production of 4 million BOE. At year-end, Conoco had proved oil and gas
reserves of 442 million BOE, proven Canadian Syncrude reserves of 280 million
BOE and 8.7 million net undeveloped acres.



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   Conventional Oil and Gas Upstream Operations

     Operations in western Canada encompass properties in Alberta, northeastern
British Columbia and southwestern Saskatchewan. The reserve base in central and
northwestern Alberta and northeastern British Columbia is dominated by
liquids-rich natural gas and light oil fields, as well as large enhanced oil
recovery projects. The reserve base in southern Alberta and southwestern
Saskatchewan is a mix of medium gravity oil and natural gas.

     Conoco is working with three other energy companies, as members of the
Mackenzie Delta Producers' Group, on the possibility of transporting onshore gas
production from the Mackenzie Delta in northern Canada to existing markets. In
October 2001, the Group signed a Memorandum of Understanding (MOU) with the
Aboriginal peoples of the Northwest Territories, as represented by the Mackenzie
Valley Aboriginal Pipeline Corporation (MVAPC). The MOU provides a framework for
the parties to move forward on an economic and timely development of a Mackenzie
Valley pipeline, running some 800 miles to a connection with the North American
gas market. In January 2002, the Group and the MVAPC announced that they would
begin preparing the regulatory applications needed to develop onshore natural
gas resources in the Mackenzie Delta, including the Mackenzie Valley pipeline.

     Off the east coast of Canada, we have a joint venture and operating
agreement with two other companies, covering 8.2 million acres in French (off
the islands of St. Pierre and Miquelon) and Canadian territorial waters.

     In heavy oil properties, Conoco owns approximately 47 percent of Petrovera,
a partnership that combines a substantial portion of Conoco's Canadian heavy oil
assets and certain associated gas assets to reap the benefits of combined
expertise, technology and economies of scale. Net production is approximately
16,000 barrels of petroleum liquids per day.

   Midstream Operations

     Our Canadian natural gas liquids business includes the following assets
acquired from Petro-Canada in 2000:

     o    a 92 percent operating interest in the 2.4 bcf per day Empress natural
          gas processing straddle plant near Medicine Hat, Alberta with a
          natural gas liquids 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    an underground natural gas liquids storage facility with 1 million
          barrels of capacity;

     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.

     During 2001, Conoco acquired the natural gas and gas liquids storage and
distribution facilities of Procor LRP Storage, which includes:

     o    four underground natural gas liquids storage caverns with 2.3 million
          barrels of capacity;

     o    three natural gas storage caverns with 600 mmcf of capacity; and

     o    rail distribution facilities with 20 rail car capacity.

   Oil Sands

     Conoco is piloting a Steam Assisted Gravity Drainage (SAGD) project at
Surmont, about 35 miles south of Fort McMurray, Alberta. This SAGD project will
test the potential of technology to economically develop oil sands that are too
deep to mine.



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     In March 2001, a regulatory application was filed with the Alberta Energy
and Utilities Board (AEUB). A MOU relating to the project has also been signed
with the local Aboriginal bands. A commercial decision on whether to proceed
with the project is expected by September 2002.

   Canadian Syncrude

     Conoco owns a 9.03 percent undivided interest in Syncrude Canada Ltd., a
joint venture created by a number of energy companies for the purpose of mining
shallow deposits of oil sands, extracting the bitumen and upgrading it into a
light sweet crude oil called Syncrude Sweet Blend (SSB). The major facilities
are at a plant site located at Mildred Lake, about 25 miles north of Fort
McMurray, Alberta, together with an auxiliary mining and extraction facility
approximately 20 miles from the Mildred Lake plant. Mining operations in the
auxiliary mine employ a fleet of large shovels and trucks as well as
hydro-transport technology. These technologies are anticipated to eventually
replace the draglines and bucket wheel reclaimers utilized in the original base
mine. During 2001, the oil and sand grade averaged 11.3 percent and overall
extraction recovery of the bitumen was approximately 87 percent. Syncrude Canada
Ltd. holds eight oil sands leases, of which Conoco's share is approximately
23,000 net acres. Several of the leases are held under the Province of Alberta's
80-year provisions for producing and upgrading facilities, which entitle the
Canadian Syncrude project to protect 17.8 billion barrels of bitumen. The
necessary surface rights are also held and the sites are readily accessible. In
December 1999, the AEUB extended the project license term to the year 2035.

     The Crown royalties are subject to a transition agreement with the project
owners under which a blended royalty rate of 50 percent of deemed net profits
from the first 74 million barrels of annual production attributable to the base
mine and a royalty of 25 percent of deemed net profits for incremental annual
volumes and production from the newer leases will apply. Following expiry of the
transition period in December 2001, the Crown royalties will be the greater of 1
percent of gross revenue or 25 percent of net revenue after deduction of all
operating and capital costs.

     The Canadian Syncrude project is a mature project for which exploration
activities are incidental to its current operations. Reclamation of mined areas
has been pursued for several years and in 2001 there were 356 hectares of land
reclaimed. Future reclamation costs for mined areas were estimated in 2001 to be
approximately $800 million, of which Conoco's share is $72 million.

     The owners have completed the first two stages of an expansion plan
intended to more than double production rates from those of the 1990s. The third
stage was conditionally approved in May 2001 and is expected to bring the annual
production to approximately 135 million barrels per year by 2005 at an aggregate
gross cost of approximately $2,700 million.

   WESTERN EUROPE

     Conoco has a significant portfolio of producing properties in the U.K.,
Norway, and the Netherlands. Proved reserves in western Europe as of December
31, 2001, were 943 million BOE, consisting of 426 million barrels of petroleum
liquids and 3.1 trillion cubic feet (tcf) of natural gas. In 2001, operations in
western Europe contributed 40 percent of our worldwide petroleum liquids
production and 41 percent of our natural gas production.

   Britannia Field

     Conoco is the largest equity owner in the Britannia natural gas/condensate
field--the largest in the U.K. sector of the North Sea, based on estimated
recoverable reserves.

     First production from Britannia occurred in August 1998, and we estimate
that the field will have a production life of approximately 30 years. Conoco's
proved reserves in Britannia include 1 tcf of natural gas and 34 million barrels
of petroleum liquids at December 31, 2001. During 2001, Britannia was able to
produce at rates of up to 800 million gross cubic feet of gas per day and 40,000
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 678 million gross cubic feet of gas per day and 31,000 gross
barrels of petroleum liquids per day.



                                       8
<PAGE>
   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 2001, Conoco's net production from the southern North Sea was 353 mmcf of
natural gas per day.

     Our CMS3 project has been sanctioned for development and is well underway,
with production expected in the fourth quarter of 2002. This multi-field
development will be produced via existing Conoco-operated infrastructure.
Another southern North Sea project called Viscount is in the final stages of
project approval with first gas expected in the fourth quarter of 2002.

     The small Venture project, a single well development, is proceeding through
front-end design and commercial negotiations with sanction expected early in
2002. In 2001, additional reservoir work on 48-10, a multi-well development,
confirmed its commercial viability and front-end work is getting under way with
sanction expected near the end of 2002.

   Other United Kingdom Properties and Discoveries

     Conoco also has interests in the following fields and discoveries:

     o    Miller producing field (30 percent);

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

     o    MacCulloch producing field (40 percent);

     o    Banff producing field (32 percent);

     o    Clair field in development stage (24 percent);

     o    Gryphon producing field (25 percent in main field and 18 percent in
          Gryphon South);

     o    Thistle Area producing assets (varying interests averaging
          approximately 18 percent);

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

     o    Kappa exploration discovery (approximately 83 percent).

     Conoco operates the MacCulloch and Banff fields, both of which employ
floating production, storage and offtake (FPSO) technology. Conoco also operates
the 21/3a and Kappa discoveries, both of which are in the greater Britannia
area. Conoco drilled an appraisal well establishing the presence of commercial
hydrocarbons on each of the 21/3a and Kappa discoveries in 2000. BP operates the
Miller field, Thistle Area and the Clair discovery. Clair is one of the largest
undeveloped oil discoveries in western Europe based on estimated ultimate
recoverable oil reserves. The Gryphon field, which is operated by Kerr McGee,
also employs FPSO technology.

   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 mmcf of gas per day to markets in continental Europe. We have
five-to-six-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.

   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) 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),




                                       9
<PAGE>

Sygna, a Statfjord satellite, (6.6 percent), and Heidrun North Flank (18.3
percent), all of which commenced production during 2000. The Huldra development
(23.3 percent) commenced production in December 2001.

     In 2001, Conoco acquired Statoil's 6.4 percent interest in the Grane field.
Grane is located in the Norwegian North Sea and is operated by Norske Hydro. The
field is expected to start production in 2003.

     Norske Conoco AS has executed an agreement with Det Norske Oljeselskap
(DNO) to sell our 3.8 percent interest in Jotun. Pending government approval,
the sale is expected to close at the end of the second quarter of 2002.

     Production from the Heidrun field, in which we own an 18.3 percent
interest, began in 1995 and averaged approximately 177,000 gross barrels of
petroleum liquids per day during 2001. 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 18.3 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 became 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 ultimate
recovery. Additionally, we own a 1.6 percent interest in the Troll gas field,
also operated by Statoil.

   Exploration in the U.K., Norway and Poland

     Exploration activities in the U.K. and Norway 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 plays of the Norwegian Sea.

     Snuggle exploration describes those opportunities near existing
infrastructure, which can be developed quickly, such as the recent Vixen field
development. In 2001, Conoco drilled a total of five snuggle wells on its
existing assets in the U.K. and Norway and had four discoveries, two in the U.K.
southern North Sea and two in the Norwegian North Sea.

     Two wells were drilled in the U.K. Atlantic Margin area and one in the
Atlantic Margin, offshore western Ireland, all of which were written off to dry
hole costs.

     The 2002 drilling program in the U.K. and Norway will focus on snuggle
exploration in the North Sea and exploration growth opportunities in the
Atlantic Margin, offshore Norway.

     During 2001, Norske Conoco acquired a 40 percent interest and was
designated as operator of the PL 268 block. Norske Conoco plans to drill a well
on the Akkar Prospect on this block during the summer of 2002.

     During 2002 Conoco will begin an exploration program in Poland with the
Miloslaw #3 well.

   The Netherlands

     Conoco's subsidiary in the Netherlands focuses on growth using a
concentrated snuggle exploration strategy. Conoco operated four offshore
exploration wells in 2001. The four Conoco operated exploration wells resulted
in one significant new discovery from the Q4-10 wildcat well. Conoco is
preparing appraisal and development plans for this new field, named Q1-B.

     In addition to its exploration activity, Conoco completed two natural gas
developments in the second half of 2001 in the Dutch sector of the North Sea.
Further, Conoco expects to bring on two more developments in 2002 from its Q4-B
and G-17 discoveries.

     Production from the Castricum-Zee field began in July 2001. Extended reach
drilling enabled the field to be brought on production quickly, safely and in an
environmentally responsible manner via Conoco's existing Q8-A platform some
three miles away. Conoco is the operator and has a 50 percent interest in the
field.




                                       10
<PAGE>

     On October 1, 2001, the P6-D natural gas field began production just 19
months after the discovery well was drilled. This quick turnaround was made
possible by the design and reuse of an existing Multi-Purpose Platform, which
was moved successfully from one of Conoco's depleted fields to its new location.
The platform was specifically designed for reuse and relocation as a satellite
facility for offshore production. Conoco operates and has a 29.4 percent
interest in the P6-D field.

   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.

     The project, the first venture of its kind in Venezuela, has 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. 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, 2001 were 687 million
barrels of oil. Drilling began in 1997 and at December 31, 2001, 241 horizontal
wells were completed. The joint venture agreement has a 35-year term, with
royalty terms of 1 percent for the first nine years and 16 2/3 percent
thereafter, which commenced with the first commercial lifting of synthetic crude
in April 2001.

     Petrozuata began early production of extra heavy crude oil in August 1998,
and as of December 2001, 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 blended with lighter oils
and sold on world markets. With the completion of the upgrading facility, the
synthetic crude produced by Petrozuata is now used as a feedstock for Conoco's
Lake Charles refinery and a Venezuelan refinery operated by PDVSA.

     The first commercial sales of synthetic crude from the upgrading facility
occurred in April 2001. Diluted extra heavy crude oil produced from the Orinoco
belt is transported via a 36-inch pipeline from the field to the Jose industrial
complex. An adjacent 20-inch pipeline returns naphtha from the upgrading
facility to the field for use as a diluent. The field processing and support
facilities as well as marine facilities for shipping synthetic crude and
by-products are also complete.

     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 transfer synthetic crude and some of the by-products to ocean vessels for
export. Synthetic crude sales are expected to comprise more than 90 percent of
the project's future 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 exploration wells
in the Gulf of Paria West. The first resulted in 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. In 2001, Conoco and its
partners commenced a four well appraisal program to evaluate the Corocoro
discovery. We drilled three of the four wells in 2001 and completed the fourth
well in the first quarter of 2002. All four wells proved to be successful. We
currently hold a 50 percent working interest in and operate the Gulf of Paria
West block. 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.




                                       11
<PAGE>

     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 and increased its interest to 45 percent in 2001. Following the
acquisition of a 3D seismic survey, Conoco entered into a three-year
exploration-drilling phase in February of 2001. We spudded the first exploration
well in late 2001 and plugged and abandoned it as a dry hole in early 2002.

     Conoco acquired rights to acreage in Trinidad in 1997, drilled a well in
1999, and relinquished the block in 2001.

   Ecuador

     Through the acquisition of Gulf Canada, Conoco obtained a 14 percent
non-operated interest in producing fields in the Oriente basin of Ecuador in the
area collectively referred to as "Block 16". Repsol-YPF is the operator of the
Block 16 area, which currently has gross production of 30,000 barrels of
petroleum liquids per day of 16 degree API crude from over 90 wells in seven
different pools in the block. Sales from the block are prorationed due to
limited export pipeline capacity. A new export pipeline, the Oleoductos Crudos
de Pesados (OCP) was approved in early 2001, and by year-end was almost 20
percent complete. The pipeline is expected to be completed in the first quarter
of 2003. Work is underway in the block to increase production to the shipping
commitment on the OCP of 100,000 barrels of petroleum liquids per day. During
2001, as part of this work, 12 development wells indicating commercial
quantities were drilled in the block. Five of the wells, with total initial
production capacity of 22,500 barrels of petroleum liquids per day, were brought
on production; the rest remain suspended awaiting the OCP, due to an overall
excess of productive capacity on the block.

   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:

     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 7,900 barrels per day in 2001.

   SOUTHEAST ASIA

     The focus areas for Conoco's upstream efforts in southeast Asia are in the
Cuu Long Basin, offshore Vietnam; in the Indonesian sector of the Natuna Sea;
and in its 72 percent ownership of Gulf Indonesia Resources Limited (Gulf
Indonesia), which has both onshore and offshore assets in Indonesia. Conoco also
has interests in exploration blocks in Cambodia and Malaysia.

   Indonesia

     Conoco has a 33-year operating history in Indonesia where it operates the
Block B, Tobong and Northwest Natuna Sea Block II Production Sharing Contracts
(PSCs) and holds an interest in the south Sokang PSC. During 2001, Conoco
significantly grew its business in southeast Asia with the acquisition of a
majority stake in Gulf Indonesia and as a result declared southeast Asia its
fourth core area. In November 2001, the Government of Indonesia formally awarded
the Nila Block PSC to Conoco and its partner Inpex. Conoco will serve as
operator and hold a 65 percent majority interest in the 5,300 square kilometer
block. Extensive seismic and exploration drilling will be conducted under a
three-year work program. The Nila block is located adjacent to the
Conoco-operated south Natuna Sea Block B PSC.




                                       12
<PAGE>



     Singaporean Gas Sale to SembGas

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

     The agreements provide for the supply of 2.5 tcf of natural gas over a
22-year contract period with approximately 1 tcf of natural gas contributed from
fields located in the Block B PSC. After an initial ramp-up period, the WNG will
provide an average gross daily volume of 325 mmcf of natural gas to SembGas, of
which 144 million gross cubic feet per day is attributable to Conoco and the
other Block B participants. Conoco has a 40 percent interest in the Block B PSC.

     In 2001, efforts were focused on installing the Moveable Offshore Gas
Production Unit now named Hang Tuah. Gas sales to Singapore from the
newly-installed platform through the West Natuna Transportation System (WNTS)
commenced in June 2001. The WNTS is a 400 mile sub-sea pipeline and gathering
system, which collects gas from the Block B, Block A and Kakap PSCs in the West
Natuna Sea and transports the gas to Singapore. The WNTS is a joint venture
among Conoco (operator), Premier Oil and Gulf Indonesia.

     In support of the next development phase in Block B, the Engineering
Procurement, Construction and Installation (EPCI) contracts for the Belanak FPSO
vessel and the two wellhead platforms were awarded during the third quarter of
2001 to KBR and McDermott, respectively. It is expected that the EPCI contracts
for the Belanak liquefied petroleum gas (LPG) FSO will be awarded in 2003. The
project is on schedule for its planned 2004 commencement of production.

     Malaysian Gas Sale to Petronas

     In October 2000, Pertamina and Petronas (the Malaysian state-owned oil and
gas company) signed an agreement that provided for the supply of 1.5 tcf of
natural gas from fields governed by the Block B PSC to be delivered over a
20-year period. In March 2001, Pertamina and Petronas signed the final gas sales
agreement. Initial Block B sales are expected to average 100 million gross cubic
feet of natural gas per day, eventually increasing to 250 million gross cubic
feet per day.

     First gas production to Petronas is contracted to begin August 1, 2002 when
gas will be delivered from the Hang Tuah facilities to Petronas' Duyong
receiving facilities. A project is currently in progress to install a 100
kilometer pipeline connecting the Hang Tuah and Duyong facilities. The project
also includes installation of infield pipelines and control facilities to
connect four dry gas wells to the Hang Tuah platform. Drilling and completion of
the four gas source wells is currently in progress. The Keong-3 well has been
drilled, completed and tested. The other three wells, the Keong-2, Keong-1 and
Kijng-3 will be drilled, completed and tested in the first quarter of 2002.

     Two appraisal wells were drilled in the Kerisi field in late 2001. These
wells proved the presence of a commercial oil rim underlying the previously
discovered gas. It is expected that Kerisi will be developed as a tie-in to the
nearby Belanak field and could be brought on-line as early as 2005.

     Belida and Sembilang Oil Fields

     The Belida and Sembilang Fields have been Block B's principal oil assets
since production began in 1992 and 1994, respectively. During 2001 gross
production averaged 49,400 barrels per day. A fourth quarter 2001 program of
workovers and recompletions, combined with an aggressive reservoir management
program, resulted in an average gross production increase to 48,400 barrels per
day for January 2002 from a November 2001 level of approximately 36,000. In
August 2001, Conoco shot 495 square kilometers of 3D seismic over the Belida
area to further define the oil and gas potential of the existing known
accumulations and to evaluate the Belida area outside of the current gas
dedication boundaries. Seismic data quality proved to be excellent, and
interpretation of the 3D to evaluate the prospective area is ongoing.

     Conoco's Block B PSC proved reserves are approximately 1.5 tcf of gross
natural gas and 203 million gross barrels of oil, condensate, and liquid
petroleum gas and are expected to be produced over the next 20-30 years. We





                                       13
<PAGE>
expect to develop more reserves on the Block through additional drilling. The
gas will be sold under the Singaporean and Malasyan contracts, while the liquids
will be available for sale to the open market.

     Gulf Indonesia

     Gulf Indonesia, headquartered in Jakarta, is a 72 percent owned, indirect
subsidiary of Conoco as a result of Conoco's acquisition of Gulf Canada. Since
1997, Gulf Indonesia common shares have been traded publicly on the New York
Stock Exchange under the symbol, "GRL".

     In 2001, Gulf Indonesia celebrated its 40th anniversary of operations in
Indonesia. At December 31, 2001, Gulf Indonesia had interests in 13 contract
areas in Indonesia, covering a total gross acreage of nearly 10 million acres
(6 million net acres). Five of the contract areas have commercial production.
One of the contract areas is in the development phase, and the remaining seven
areas are in the pre-development or exploration phase.

     Gulf Indonesia is a party to four substantial long-term U.S. dollar gas
sales contracts. Three of these contracts are being supplied or will be supplied
from onshore fields in South Sumatra and the gas supply for the fourth is from
the Kakap Block in the Natuna Sea. All reserve numbers for the Gulf Indonesia
gas contracts are stated net to Gulf Indonesia before royalty.

     Gulf Indonesia has agreed to deliver approximately 0.6 tcf of natural gas
over a 15-year period, which commenced in October 1998, from the Corridor Block
PSC area to the Duri Steamflood in central Sumatra. Further, Gulf Indonesia
signed agreements for the delivery of an additional 0.6 tcf of natural gas over
a 19-year period with first gas deliveries targeted for late 2002.

     Gulf Indonesia is also a participant in the West Natuna Group consortium,
as a participant in the Kakap Block PSC in the Natuna Sea. Gulf Indonesia's
share of the Kakap Block PSC will be a part of the total 2.5 tcf to be supplied
under the Sembgas contract.

     In February 2001, Gulf Indonesia signed agreements for the supply of
approximately 0.7 tcf of natural gas from Sumatra to Singapore over a 20-year
period. First gas deliveries for this contract are targeted for late 2003.

     In 2001, Gulf Indonesia completed a seven-well offshore exploration program
that began in 2000. Four of the seven wells were discoveries with a fifth
containing untested gas. Delineation programs for these discoveries are
currently being planned for 2002.

   Vietnam

     In September 1998, Conoco was awarded a 23.25 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. In August 2001, Conoco and its partners in
Block 15-1 declared the Sutu Den (Black Lion) field commercial after a
successful appraisal program. A wildcat discovery was also made on the nearby
Sutu Vang (Golden Lion) prospect in the third quarter of 2001. The Sutu Den
Phase I development project was approved by Conoco in December 2001. A FPSO
vessel and a wellhead platform will be utilized and initial development will
start in the southwest portion of the field. Because of the low gas to oil ratio
in the reservoir, water injection and gas lift equipment will be installed in
the first phase. The field is scheduled to begin production in 2004.

     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, our ownership interest was increased to 36 percent
through acquisition of an additional 6 percent interest from JVPC. During 2001,
Block 15-2 production increased to over 50,000 (gross) barrels of petroleum
liquids per day from the Rang Dong field. This production is expected to
increase with an expansion of the facilities through a gas lift, water injection
and gas export project that was approved in 2001. In late 2002, two new
platforms will be placed in the eastern (E-1) and southern (S-1) part of the
Rang Dong field to bring the oil production capacity up within the range of
65,000 to 70,000 barrels of petroleum liquids per day. A successful appraisal
step-out well, RD-12X, was drilled in the central part of the field in late 2001
and tested at a rate of 9,300 barrels of petroleum liquids per day. A
development plan for this area of the field is being evaluated.




                                       14
<PAGE>

     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. Conoco became the operator with a
40 percent interest in the block. The first exploration well was drilled in the
fourth quarter of 2001 and was written off to dry hole cost at the end of the
year.

     In December 2001, Conoco purchased Statoil's 50 percent interest in Block
5-3, which covers approximately 462,000 acres. Exploration and appraisal efforts
are ongoing. We also acquired all shares of a Statoil subsidiary, Statoil
Vietnam AS, which owned a 16.33 percent stake in the Nam Con Son pipeline, a
240-mile delivery system that will transport natural gas from Nam Con Son fields
to the Phu My industrial complex near Ho Chi Minh City. Gas delivery is
scheduled to begin in late 2002. The purchase supports Conoco's strategic growth
plans for southeast Asia and its objective of building a sustainable natural gas
business in Vietnam. We are currently the largest acreage holder of any foreign
energy company in Vietnam.

   Malaysia

     In November 2000, Conoco acquired 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 proved
reserves. Two exploration wells were drilled on the blocks during 2001 and both
were determined not to be commercially viable and there is a commitment to drill
at least two additional wells over the next two years.

   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 30,872 barrels
of petroleum liquids per day in 2001. Oil is transported through the existing
Russian pipeline system and is then exported or sold on the domestic market.
During 2001, Polar Lights committed to three Ardalin satellites fields:
Oshkotin; Vostochnaya Kolva (VK); and Dyusushev (DY). First oil at the Oshkotin
field is planned for 2002. VK and DY fields are expected to start producing in
2003.

     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. The Russian government has approved both the
Northern Territories and Shtokman projects for 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 an 80
percent revenue interest in the field. Gross production from the field is
currently about 21,000 barrels per day of oil, and Conoco's net proved reserves
as of December 31, 2001, were 7.2 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 acquired a 3D seismic survey and drilled two exploratory wells on
this license. The first well, drilled in 1997, was not commercial. Conoco's
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. An appraisal well of the Chota structure was completed on the
neighboring block, OPL 219, at the end of 2001.




                                       15
<PAGE>



   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 completed
construction of pipelines and plant facilities to gather and process 450 mmcf
per day of natural gas. In addition, about 150 mmcf 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 that serves western Syria including
the Damascus area. The Deir Ez Zor gas processing plant began operation in
September 2001 with the shut down of flares and the processing of associated
gas. The project was fully completed prior to year-end. It was finished almost
six months ahead of schedule and was built under budget.

     Conoco was one of three companies chosen to participate in Core Venture 3,
a large natural gas opportunity in Saudi Arabia, which will span the value chain
from wellhead to market. We were awarded a 30 percent interest in the Core
Venture 3 consortium and will have the lead role in gas processing, as well as
transmission operations of both gas and natural gas liquids. Other segments of
the venture include a petrochemical plant, a power/water desalination facility
and gas exploration and development over a 74,000 square-mile area. Commercial
negotiations for the project are ongoing.

     Conoco continues to be active in efforts to re-enter Libya where our
partners and we were forced to suspend active participation in the Oasis
concession in 1986 because of U.S. government sanctions. In 2001, the U.S.
government authorized our partners and us to travel to Libya to evaluate the
concession area, where the assets were found to be operating and in good
condition. The Oasis partners are meeting with Libyan officials and preparing
for a future return to the concession area when political conditions permit.

     One of Conoco's newest initiatives is its 20 percent interest in the Zafar
Mashal exploration prospect in the Caspian Sea. The Zafar Mashal prospect is
located in the Volga Delta play in the South Caspian basin, an area that
includes previously proved large discoveries.

   OIL, NATURAL GAS AND CANADIAN SYNCRUDE RESERVES

     Conoco's estimated proved reserves at December 31, 2001 were 3,579 million
BOE, consisting of 1,862 million barrels of oil, 8,619 bcf of natural gas and
280 million barrels of Canadian Syncrude.

     In addition to conventional liquids and natural gas proved reserves defined
by the Securities and Exchange Commission (SEC), Conoco has significant
interests in proven oil sands in Canada associated with the Canadian Syncrude
project. Management views the oil sands reserves related to the Canadian
Syncrude project and their development as an integral part of the oil and gas
operations of the company. However, generally accepted accounting principles
define these reserves as mining related and exclude these reserves from the
conventional definition of oil and gas reserves. As a result, oil sands
information identified as Canadian Syncrude is presented separately.

     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 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.

     Canadian Syncrude proven reserves cannot be measured precisely. The reserve
data set forth in this report is only an estimate. Reserve estimates of Canadian
Syncrude are based on detailed geological and engineering





                                       16
<PAGE>

assessments of in-place crude bitumen volume, the mining plan, historical
extraction recovery and upgrading yield factors, installed plant operating
capacity and operating approval limits. The in-place volume, depth and grade are
established through extensive and closely spaced core drilling. The reliability
of these estimates at any point in time depends on both the quality and quantity
of the technical and economic data and the efficiency of extracting the bitumen
and upgrading it into a light sweet crude oil. Consequently, Canadian Syncrude
reserve estimates are subject to revision as additional data become available.

     At lower prices for crude oil, natural gas and Canadian Syncrude, 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 Conoco's proved oil and Canadian Syncrude
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
                                               ----------------------------------------------------------
                                                  2001        2000        1999        1998        1997
                                               ----------  ----------  ----------  ----------  ----------
                                                                  (MILLIONS OF BARRELS)
<S>                                            <C>         <C>         <C>         <C>         <C>
PROVED OIL AND CANADIAN SYNCRUDE RESERVES
Consolidated Companies
   United States ............................         244         249         238         261         277
   Canada ...................................         164           7           8          11           8
   Europe ...................................         426         405         383         410         421
   Other regions ............................         248         167         159         181         187
                                               ----------  ----------  ----------  ----------  ----------
     Total consolidated companies ...........       1,082         828         788         863         893
Equity companies ............................         780         810         742         728         731
Canadian Syncrude ...........................         280          --          --          --          --
                                               ----------  ----------  ----------  ----------  ----------
Total worldwide .............................       2,142       1,638       1,530       1,591       1,624
                                               ==========  ==========  ==========  ==========  ==========
</Table>

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

<Table>
<Caption>
                                                                  YEAR ENDED DECEMBER 31
                                               ----------------------------------------------------------
                                                  2001        2000        1999        1998        1997
                                               ----------  ----------  ----------  ----------  ----------
                                                                (BILLIONS OF CUBIC FEET)
<S>                                            <C>         <C>         <C>         <C>         <C>
PROVED NATURAL GAS RESERVES
Consolidated Companies
   United States ............................       2,138       2,061       2,166       2,319       2,235
   Canada ...................................       1,420         327         385         234         196
   Europe ...................................       3,103       2,837       2,884       3,053       3,060
   Other regions ............................       1,939         511         364         196          --
                                               ----------  ----------  ----------  ----------  ----------
     Total consolidated companies ...........       8,600       5,736       5,799       5,802       5,491
Equity companies ............................          19         317         343         381         370
                                               ----------  ----------  ----------  ----------  ----------
Total worldwide .............................       8,619       6,053       6,142       6,183       5,861
                                               ==========  ==========  ==========  ==========  ==========
</Table>

   PRODUCTION DATA

     Conoco's oil, natural gas and Canadian Syncrude production, excluding
natural gas liquids from gas plant ownership, averaged 770,000 BOE per day in
2001, compared with 654,000 BOE per day in 2000. As a percentage of total
production, natural gas production was 44 percent in 2001 and 2000.

     The following table shows Conoco's interests in average daily oil and
Canadian Syncrude production and average 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. Canadian Syncrude production represents our
share of the production from our Canadian Syncrude joint venture in Canada.
Natural gas production represents our share of production from leases in which
we have an ownership interest. Natural gas liquids processed represent our share
of natural gas liquids acquired through gas plant ownership.




                                       17
<PAGE>


<Table>
<Caption>
                                                                 2001        2000        1999
                                                              ----------  ----------  ----------
                                                                 (THOUSANDS OF BARRELS PER DAY)
<S>                                                           <C>         <C>         <C>
NET AVERAGE DAILY OIL AND CANADIAN SYNCRUDE PRODUCTION
Consolidated Companies
   United States ...........................................          73          80          74
   Canada ..................................................          30           1           1
   Europe ..................................................         155         155         161
   Other regions ...........................................          91          78          83
                                                              ----------  ----------  ----------
     Total net production - consolidated companies .........         349         314         319
Equity companies ...........................................          73          56          40
Canadian Syncrude ..........................................          10          --          --
                                                              ----------  ----------  ----------
Total worldwide ............................................         432         370         359
                                                              ==========  ==========  ==========
</Table>


<Table>
<Caption>
                                                            2001        2000        1999
                                                         ----------  ----------  ----------
                                                          (MILLIONS OF CUBIC FEET PER DAY)
<S>                                                      <C>         <C>         <C>
NET AVERAGE DAILY NATURAL GAS PRODUCTION
Consolidated Companies
   United States ......................................         797         796         865
   Canada .............................................         303          91          53
   Europe .............................................         825         800         727
   Other regions ......................................          86          --          --
                                                         ----------  ----------  ----------
     Total net production - consolidated companies ....       2,011       1,687       1,645
Equity companies ......................................          19          18          15
                                                         ----------  ----------  ----------
Total worldwide .......................................       2,030       1,705       1,660
                                                         ==========  ==========  ==========
</Table>

<Table>
<Caption>
                                                            2001        2000        1999
                                                         ----------  ----------  ----------
                                                           (THOUSANDS OF BARRELS PER DAY)
<S>                                                      <C>         <C>         <C>
NET AVERAGE DAILY NATURAL GAS LIQUIDS PROCESSED
Consolidated Companies
   United States ......................................          52          50          51
   Canada .............................................          36          33          --
                                                         ----------  ----------  ----------
     Total net processed - consolidated companies .....          88          83          51
Equity companies ......................................           8           9          13
                                                         ----------  ----------  ----------
Total worldwide .......................................          96          92          64
                                                         ==========  ==========  ==========
</Table>

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

     The following table sets forth for Conoco, including 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, 2001. Average sales prices
exclude proceeds from sales of interests in oil and gas properties.



                                       18
<PAGE>
<Table>
<Caption>
                                                     UNITED                          OTHER    CONSOLIDATED     EQUITY        TOTAL
                                                     STATES     CANADA    EUROPE    REGIONS     COMPANIES     COMPANIES    WORLDWIDE
                                                     ------     ------    ------    -------   ------------    ---------    ---------
                                                                                 (UNITED STATES DOLLARS)
<S>                                                  <C>        <C>       <C>       <C>       <C>             <C>          <C>
FOR THE YEAR ENDED DECEMBER 31, 2001
 Average production costs per barrel of oil
   equivalent of petroleum produced (1) ..........   $ 5.23     $ 5.61    $ 4.34     $ 6.48      $ 5.08        $ 6.71        $ 5.25
 Average sales prices of produced petroleum
   Per barrel of crude oil and condensate sold ...    23.95(2)   17.74     23.07      23.44       22.89         13.16         21.14
   Per mcf of natural gas sold ...................     4.13(2)    2.40      3.32       3.31        3.51          4.61          3.52
FOR THE YEAR ENDED DECEMBER 31, 2000
 Average production costs per barrel of oil
   equivalent of petroleum produced (1) ..........   $ 4.17     $ 5.49    $ 3.49     $ 5.07      $ 4.00        $ 5.43        $ 4.13
 Average sales prices of produced petroleum
   Per barrel of crude oil and condensate sold ...    27.72      27.78     27.96      27.06       27.67         18.21         26.08
   Per mcf of natural gas sold ...................     3.42       3.33      2.68         --        3.06          3.77          3.07
FOR THE YEAR ENDED DECEMBER 31, 1999
 Average production costs per barrel of oil
   equivalent of petroleum produced (1) ..........   $ 3.60     $ 3.10    $ 4.20     $ 4.01      $ 3.93        $ 5.53        $ 4.04
 Average sales prices of produced petroleum
   Per barrel of crude oil and condensate sold ...    17.33      18.20     17.80      17.05       17.51         13.86         17.09
   Per mcf of natural gas sold ...................     1.98       1.92      2.30         --        2.12          2.35          2.12
</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.

(2)  Includes favorable U.S. hedging effect of $38 million or $1.29 per barrel
     for crude oil and condensate sold and $.05 per mcf for natural gas sold.

          The following table sets forth for Conoco the average production cost
     per barrel of Canadian Syncrude produced and average sales price per barrel
     of Canadian Syncrude sold from the Canadian Syncrude project in Canada.

<Table>
<Caption>
                                                                                     AMOUNT
                                                                                   ----------
                                                                                    (UNITED
                                                                                     STATES
                                                                                    DOLLARS)
<S>                                                                                <C>
CANADIAN SYNCRUDE
FOR THE SIX MONTHS ENDED DECEMBER 31, 2001
    Average production costs per barrel of Canadian Syncrude produced...........   $    11.34
    Average sales price per barrel of Canadian Syncrude sold....................        21.98
</Table>

   DRILLING AND PRODUCTIVE WELLS

     The following table sets forth Conoco's drilling wells and productive wells
by region as of December 31, 2001. The table excludes our share of equity
affiliates.

<Table>
<Caption>
                                            UNITED                              OTHER       TOTAL
                                            STATES     CANADA(3)    EUROPE     REGIONS    WORLDWIDE
                                          ----------  ----------  ----------  ----------  ----------
                                                               (NUMBER OF WELLS)
<S>                                       <C>         <C>         <C>         <C>         <C>
Number of wells drilling(1)
   Gross ...............................          47         261          20           3         331
   Net .................................          31         135           4           2         172
Number of productive wells(2)
   Oil wells -- gross ..................       5,709       3,651         441         868      10,669
             -- net ....................       1,517       2,495          51         380       4,443
   Gas wells -- gross ..................       7,735       5,302         282          44      13,363
             -- net ....................       3,659       3,624          68          20       7,371
</Table>


----------
(1)  Includes wells being completed.

(2)  Approximately 337 gross (226 net) oil wells and 1,538 gross (825 net) gas
     wells have multiple completions.

(3)  Includes Gulf Canada acquisition in 2001.




                                       19
<PAGE>

   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, 2001. The
table excludes our share of equity affiliates.

<Table>
<Caption>
                                            UNITED                              OTHER        TOTAL
                                            STATES      CANADA      EUROPE     REGIONS     WORLDWIDE
                                          ----------  ----------  ----------  ----------  ----------
                                                         (NUMBER OF NET WELLS COMPLETED)
<S>                                       <C>         <C>         <C>         <C>         <C>
FOR THE YEAR ENDED DECEMBER 31, 2001
   Exploratory  -- productive ..........         4.3        27.6         2.9         8.5        43.3
                -- dry .................         1.3        20.3         2.9         3.6        28.1
   Development  -- productive ..........       286.8        73.5        12.8        10.0       383.1
                -- dry .................        18.6        36.4          --         4.2        59.2
FOR THE YEAR ENDED DECEMBER 31, 2000
   Exploratory  -- productive ..........         1.0         0.5         1.6         1.0         4.1
                -- dry .................         2.6          --         0.2         1.5         4.3
   Development  -- productive ..........       267.2        20.7        12.0         4.9       304.8
                -- dry .................        20.1        25.6          --          --        45.7
FOR THE YEAR ENDED DECEMBER 31, 1999
   Exploratory  -- productive ..........         1.7         0.5         1.3         3.3         6.8
                -- dry .................          --          --         0.8         2.5         3.3
   Development  -- productive ..........       165.2         4.3         8.7         0.9       179.1
                -- dry .................        18.3          --          --         0.8        19.1
</Table>

   DEVELOPED AND UNDEVELOPED PETROLEUM ACREAGE

     The following table sets forth Conoco's developed and undeveloped petroleum
acreage by region as of December 31, 2001. The table excludes our share of
equity affiliates.

<Table>
<Caption>
                                       UNITED                               OTHER      TOTAL
                                       STATES      CANADA      EUROPE      REGIONS   WORLDWIDE
                                     ----------  ----------  ----------  ----------  ----------
                                                         (THOUSAND OF ACRES)
<S>                                  <C>         <C>         <C>         <C>         <C>
Developed acreage
   Gross ..........................       2,940       4,224       3,848       3,825      14,837
   Net ............................       1,508       3,041         844       1,495       6,888
Undeveloped acreage
   Gross ..........................       2,765      14,497       8,109      81,141     106,512
   Net ............................       1,568       8,704       2,767      45,775      58,814
</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 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






                                       20
<PAGE>

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 $465 million per year for the last three years. Capital
investments for 2001 in downstream activities were approximately $389 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.

     Conoco produces and markets a full range of refined petroleum products,
including gasoline, 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 936,000
barrels per day. Refining capacity is distributed 61 percent in the U.S., 33
percent in Europe and 6 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. and the Lake Charles refinery in the U.S.
comprises about 45 percent and 25 percent acidic crudes respectively. Refining
capacity has risen by about 155,000 barrels per day, or 20 percent, since
year-end 1997, 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
2001, downstream refined product sales volumes averaged 1,304,000 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. 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 acidic crudes, 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.




                                       21
<PAGE>

     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 1997, Conoco has increased refining input at its four
U.S. refineries by approximately 7 percent. 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 decreased by
approximately $180 million to $164 million in 2001, compared to $344 million in
2000, primarily as a result of the installation of an acidic crude unit at our
Lake Charles refinery in 2000. We are positioned to make the necessary clean
fuels investments, starting in 2002, at our refineries over the next five years
in support of changing motor fuel specifications.

   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
                                                    ----------------------------------------------------------
                                                       2001        2000        1999        1998        1997
                                                    ----------  ----------  ----------  ----------  ----------
                                                                   (THOUSANDS OF BARRELS PER DAY)
<S>                                                 <C>         <C>         <C>         <C>         <C>
CRUDE DISTILLATION CAPACITY (1)
Lake Charles, Louisiana ..........................         252         248         248         241         226
Ponca City, Oklahoma .............................         194         184         174         168         155
Denver, Colorado .................................          62          58          58          58          58
Billings, Montana ................................          60          56          54          52          52
                                                    ----------  ----------  ----------  ----------  ----------
Total crude distillation capacity ................         568         546         534         519         491
REFINERY INPUTS (2)
Lake Charles, Louisiana
    Inputs to crude distillation units (3) .......         228         208         234         216         211
    Other inputs .................................          27          25          20          24          22
Ponca City, Oklahoma
    Inputs to crude distillation units (3) .......         174         181         173         167         161
    Other inputs .................................           1           1           3           4           2
Denver, Colorado
    Inputs to crude distillation units (3) .......          54          58          56          50          53
Billings, Montana
    Inputs to crude distillation units (3) .......          53          57          49          52          51
    Other inputs .................................           3           3           3           3           3

Total inputs to crude distillation units .........         509         504         512         485         476
                                                    ==========  ==========  ==========  ==========  ==========
Total other inputs ...............................          31          29          26          31          27
                                                    ==========  ==========  ==========  ==========  ==========
</Table>


----------
(1)  Reflects all inputs to crude distillation units.

(2)  Reflects all inputs to crude distillation units and all other inputs
     (excluding internal recycles).

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

     Conoco's U.S. consolidated refined product sales by volume in 2001 were 50
percent motor gasoline, 34 percent middle distillates, including jet and diesel
fuel, and 16 percent residual fuel oil and asphalt and other products, including
petroleum coke, lubricants and liquefied petroleum gases.




                                       22
<PAGE>



     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
252,000 barrels per day. The refinery processes heavy, high sulfur, low sulfur
and acidic crude oil. The refinery's Gulf Coast location provides access to
numerous cost effective domestic and international crude oil sources. The crude
capacity is approximately 192,000 barrels per day of heavy, high sulfur crudes
including 75,000 barrels per day of acidic crude. The remaining 60,000 barrels
per day is comprised 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.

     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 gasoline, 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, a fully integrated specialties company, which manufactures and
markets highly refined specialty petroleum products for global markets. Conoco
has a 50 percent interest in Penreco.

     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.

     In 2001, Conoco reached agreement to divest its 35 percent interest in
Cit-Con, a paraffinic lubricants refinery. The sale closed in January 2002.

     Ponca City Refinery

     Conoco's refinery located in Ponca City, Oklahoma has a crude distillation
capacity of 194,000 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 62,000 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 to other Colorado
markets. The refined gasoline products from the Denver refinery help supply our
marketing operations in the Rocky Mountain states.





                                       23
<PAGE>

     The Denver refinery is a high conversion refinery that produces a full
range of products including gasoline, 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
60,000 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 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 gasoline, 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.

     Conoco gasoline is sold through approximately 4,900 branded stations in the
U.S., 88 percent of the gasoline through retail outlets owned by independent
wholesale marketers and 12 percent through 120 company-owned stores at year-end
2001. 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 2001, we realigned our marketing department to provide best in class
service to our branded marketer network, which comprises nearly 400 independent
businesses. We continue to build and enhance ConocoNet, a paperless platform to
deliver key operating information and best-practice sharing to our marketers.
Emphasis on reducing break-even operating costs, improving convenience product
margins, and building consumer loyalty anchored our effort.

     At year-end 2001, CFJ Properties, a 50/50 joint venture between Conoco and
Flying J, owned and operated 95 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 7,400 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 933,000 barrels per day in 2001.
Our equity share of shipments on affiliate pipelines was an additional 446,000
barrels per day.




                                       24
<PAGE>

     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.

     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 15
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 allow 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, Poland and the Czech Republic. The Continental cluster also includes
refining joint ventures in Germany and the Czech Republic. 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 91 percent of our European downstream after-tax earnings before
special items in 2001.

     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 $182 million in its European downstream
operations in 2001, and $175 million in 2000. 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 currently in full
compliance, with the majority of our gasoline production expected to be in
compliance during 2003. Tax 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. has increased our European refining capacity by approximately 8 percent, or
22,000 barrels per day since 1997. 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






                                       25
<PAGE>
advantage. In 2000, 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. In addition, Wood Mackenzie, a recognized petroleum industry consultant,
rated Conoco's European refining operations number two in Europe in a 2001
study, as measured by net cash margin per barrel.

     Conoco has undertaken a major capital investment program, totaling
approximately $597 million from 1994 through 2001, to process lower cost
feedstocks and increase conversion capacity, product quality and energy
efficiency at the Humber refinery. From 1999 through 2001, we have spent about
$132 million at the Humber refinery, and in 2002 we plan to spend another $16
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 Ceska
rafinerska, a.s. (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
                                                    ------------------------------------------------
                                                      2001      2000      1999      1998      1997
                                                    --------  --------  --------  --------  --------
                                                              (THOUSANDS OF BARRELS PER DAY)
<S>                                                 <C>       <C>       <C>       <C>       <C>
CRUDE DISTILLATION CAPACITY(1)
Humber, United Kingdom ...........................       232       230       218       218       210
MiRO, Germany(2) .................................        53        53        53        53        53
CRC, Czech Republic(3) ...........................        27        27        27        27        27
                                                    --------  --------  --------  --------  --------
Total crude distillation capacity(4) .............       312       310       298       298       290
                                                    ========  ========  ========  ========  ========
REFINERY INPUTS(5)
Humber, United Kingdom(6)
  Inputs to crude distillation units(7) ..........       166       203       213       214       174
  Other inputs ...................................        20        21        13         8        19
MiRO, Germany(2)
  Inputs to crude distillation units(7) ..........        54        54        56        54        51
  Other inputs ...................................         2         3         4         3        11
CRC, Czech Republic (3)
  Inputs to crude distillation units (7) .........        18        17        17        20        21
  Other inputs ...................................         1         1         1         1         1

Total inputs to crude distillation units(4) ......       238       274       286       288       246
                                                    ========  ========  ========  ========  ========
Total other inputs ...............................        23        25        18        12        31
                                                    ========  ========  ========  ========  ========
</Table>

----------

(1)  Reflects all inputs to crude distillation units.

(2)  Represents Conoco's 18.75 percent interest in the MiRO refinery complex at
     Karlsruhe, Germany.

(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).

(6)  The 2001 utilization was significantly impacted by the fire and major
     turnaround at the Humber refinery in the second quarter. The tie-in of a
     major expansion project significantly affected the Humber refinery's
     utilization in 1997.

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

     The yields of Conoco's European refineries by product and country for the
year ended December 31, 2001, were as follows:

<Table>
<Caption>
                                                             UNITED                       CZECH
                                                           KINGDOM(1)      GERMANY     REPUBLIC(2)
                                                          -----------   -------------  -----------
<S>                                                       <C>            <C>            <C>
PERCENT OF TOTAL YIELD (3)
Motor gasoline...........................................       28             36            29
Middle distillate........................................       44             46            46
Residual fuel oil and asphalt............................       10             10            13
Other (4)................................................       18              8            12
</Table>

----------




                                       26
<PAGE>

(1)  Significant changes in motor gasoline, resid and other resulted from plant
     downtime associated with the fire and major turnaround in the second
     quarter of 2001.

(2)  Increased production of gasoline and distillate resulted from the FCC unit
     coming on stream at the Kralupy refinery in 2001.

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

(4)  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 232,000 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 58 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.

     The Humber refinery sustained damage in a localized area of the plant in
the second quarter of 2001 as the result of a fire. There were no serious
injuries as a result of the incident and a majority of the refinery units were
not damaged. Most of the units were back in operation by the end of the third
quarter of the year, although repair work continued on certain units. The fire
and a major turnaround in the second quarter significantly impacted refinery
utilization and yields in the second and third quarters, but operations resumed
to near normal levels by the fourth quarter.

     Germany Refinery

     The MiRO refinery in Karlsruhe, Germany, is a joint venture refinery with a
crude distillation capacity of 283,000 barrels per day. 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 60 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
refinery processes crude and other feedstocks supplied by each of the partners
in proportion to their respective ownership interests.

     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 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 significantly increased light oil yields and reduced 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.




                                       27
<PAGE>

   Marketing

     Conoco has marketing operations in 15 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, where we historically marketed under the "SECA" brand, we have now
moved to a standardized European offering under the "JET" 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 Switzerland and Turkey under the
"Coop" and "Tabas" or "Turkpetrol" brand names, respectively.

     As of December 31, 2001, Conoco had 2,033 marketing outlets in its wholly
owned European operations, of which 1,154 were company-owned. Through our joint
venture operations in Turkey and Switzerland, we also have an interest in
another 819 retail sites. Our largest branded site networks are in Germany and
the U.K., which account for 61 percent of the total branded units. In Germany
and Austria, 24 outlets were added during 2001, 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 12 new stations in
the region. Conoco sold its U.K. network of company-owned retail sites in the
fourth quarter of 2001 to Fuelforce Limited. Under terms of the sale, we will
supply petroleum products to the outlets that Fuelforce will continue to operate
under the "JET" brand. The transaction allows Conoco to maximize the sale of
quality products from the Humber refinery through "JET" branded outlets and
optimizes overhead and operating and capital costs.

     Conoco has 130 stations in central and eastern Europe in the Czech
Republic, Poland, Hungary and Slovakia as of December 31, 2001. We expect to
continue building high quality new stores, retrofitting current stations and
rationalizing our network in 2002. 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. In
Turkey, Conoco has retail marketing operations through a 28.5 percent joint
venture, Turcas, where at the end of 2001, we had an interest in 718 sites.
Conoco sold its 50 percent interest in CONSA, a retail marketing joint venture
in Spain, in the second quarter of 2001.

   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 continue the
expansion of our marketing operations to integrate with our refining supply and
capitalize on market deregulation and long-term regional demand growth.

   Refining

     The refinery in Melaka, Malaysia is a joint venture with Petronas, the
Malaysian state oil company. We now own a 47 percent interest in the joint
venture. The refinery became operational in August 1998, and has a rated crude
distillation capacity of about 120,000 barrels per day, of which Conoco's share
is 56,400 barrels per day. Conoco's share of refinery inputs, sourced mostly
from the Middle East, was 19.5 million barrels for 2001. This volume is
equivalent to approximately 53,000 barrels per day.

     In 2001, Conoco and Petronas completed the acquisition of a 15 percent
share in the Melaka refinery from Statoil, the Norwegian state oil company,
increasing Conoco's interest to 47 percent from 40 percent.




                                       28
<PAGE>
     The following tables outline the rated crude distillation capacity as of
December 31 for each of the past four years and the average daily inputs to
crude distillation units and other feedstocks.

<Table>
<Caption>
                                                             YEAR ENDED DECEMBER 31
                                                    --------------------------------------
                                                      2001      2000      1999      1998
                                                    --------  --------  --------  --------
                                                         (THOUSANDS OF BARRELS PER DAY)
<S>                                                 <C>       <C>       <C>       <C>
CRUDE DISTILLATION CAPACITY(1)(2)
Melaka, Malaysia .................................        56        48        45        45

REFINERY INPUTS(1)(3)
Melaka, Malaysia
  Inputs to crude distillation units(4) ..........        53        39        32         7
</Table>


----------
(1)  Represents Conoco's 47 percent interest in the Melaka refinery for 2001 and
     Conoco's 40 percent interest for 2000, 1999 and 1998.

(2)  Reflects all inputs to crude distillation units.

(3)  Reflects all inputs to crude distillation units and all other inputs
     (excluding internal recycles).

(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 regional
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 supply and product disposition operations
are centrally located in Singapore.

   Marketing

     Conoco has established a significant presence in the Thailand retail
market. At the end of 2001, Conoco had 132 stores in operation and continued
expansion is anticipated in 2002.

     Conoco has a retail marketing joint venture in Malaysia with Sime Darby
Bhd., a company that has a major presence in the Malaysian business sector,
initially targeting major markets within 125 miles of the Melaka refinery. A
total of 11 stores were in operation at the end of 2001.

   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. In 2001, Conoco continued its expansion of
marketing the HYDROCLEAR(R) brand of lubricants into Asia Pacific. This growth
has been achieved with minimal capital investment as blending and supply chain
management activities have been outsourced to established vendors in the region.
The HYDROCLEAR(R) lubricants, which are





                                       29
<PAGE>

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 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 (Conoco
Cevolution(R)), natural gas refining and international power businesses.

   CARBON FIBERS

     In January 2000, Conoco announced its entry into the carbon fiber industry
with the formation of Conoco Carbon Fibers, a new business solely dedicated to
the manufacture, marketing, and sale of the company's new mesophase pitch-based
carbon fiber technology, which was also introduced at that time.

     In June 2001, we changed the name of Conoco Carbon Fibers to Conoco
Cevolution to reflect our new rapidly expanding market scope. This initiative
included building upon Conoco's leadership position in carbon customization with
the development and integration of several new carbon technologies into Conoco
Cevolution's growing portfolio of products.

     Conoco Cevolution now offers customers a variety of advanced carbon
technology solutions, targeting a broad range of potential applications in
several key global industries. These include plastics, composites, automotive,
electrical/electronics, telecommunications, data storage and entertainment
devices, computers and business machines, building and construction,
infrastructure, and portable power, as well as a number of high-end, niche
market segments.

     We expect to complete the construction of our first commercial-scale carbon
fibers manufacturing plant located in Ponca City, Oklahoma with first production
expected in mid-2002. The plant has an initial capacity of 4 million pounds per
year and is designed to allow expansion up to 8 million pounds per year.

     Conoco Cevolution is headquartered in Houston, with technical facilities
located in Ponca City. In December 2000, we opened a new office in Tokyo to
serve our growing Asian customer base, and in September 2001, we opened a second
regional office in Amsterdam, the Netherlands, to benefit our European
customers.

   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 140 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





                                       30
<PAGE>
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 400-barrel per
day demonstration plant is under construction in Ponca City and is scheduled for
completion during the fourth quarter of 2002.

     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.

   INTERNATIONAL POWER

     Conoco Global Power was restructured in mid 2001, to accomplish two primary
objectives:

     o    capitalize on the gas/power convergence in North America by merging
          the remaining natural gas and power development groups into our Gas
          and Power Marketing organization; and

     o    develop new markets outside North America for stranded/undervalued gas
          reserves via power generation.

     The focus will be on developing integrated projects in support of our
upstream and downstream strategies and business objectives, with a goal of
monetizing natural gas reserves and strengthening the downstream portfolio. We
hope to accomplish this by bringing together people with project development
skills, commercial skills, engineering skills, water desalination skills, and
economic evaluation skills.

     During 2001, Conoco Global Power completed the divesture of its 37.5
percent interest in a Colombian power venture. The divestiture was completed in
the first quarter of 2001.

     Conoco Global Power is developing a 730-megawatt combined heat and power
cogeneration plant in North Lincolnshire, U.K. The facility will provide steam
and electricity to the Conoco refinery and a neighboring refinery, as well as
market power into the U.K. market. Construction is scheduled to begin in 2002
with commercial operation anticipated in 2004.

ELECTRONIC COMMERCE

     During 2000, Conoco participated in a number of electronic
business-to-business (B2B) initiatives. These initiatives included Internet
marketplaces for procurement of goods and services, as well as wholesale energy
trading. Additionally, in 2001, we participated in a joint venture to provide
heavy equipment condition monitoring systems via the Internet.

     Because some of these investments in B2B initiatives are in new or unproven
technologies and business processes, ultimate success is not always certain.
Although not all initiatives may prove to be economically viable, our overall
investment in this area is not significant to our consolidated financial
position.

CORE VALUES

     Conoco is committed to four core values: operating safely, protecting the
environment, behaving ethically, and valuing all people. Each year, Conoco
President's Awards honor individuals and teams of employees for advancing these
core values. Conoco's core values provide the foundation for the company's
commitment to sustainable growth and support the basic tenets of sustainability
-- financial excellence, environmental responsibility, and social progress.
Sustainability integrates Conoco's core values with business excellence.

     Conoco issued its first sustainable growth report to show how the company
creates value for shareholders while maintaining respect for environmental and
social considerations. The report, "Conoco Sustainable Growth Report -- a Look
at Our Progress, May 2001," documents Conoco's successes, takes a look at areas
in need of improvement, and outlines the company's commitment to sustainable
growth. The document is a major step in Conoco's journey toward transparency and
includes a record of the company's global environmental and safety performance
and sustainable development goals for 2001. The report received worldwide
recognition, including coverage on CNN. At the local level, two U.S. downstream
businesses issued their own sustainability reports, further driving stakeholder
engagement in their communities.




                                       31
<PAGE>

     For the second consecutive year, in 2001 Conoco was selected as a component
of the Dow Jones Sustainability World Index (DJSI), formerly known as the Dow
Jones Sustainability Group Index. The DJSI represents the top 10 percent of
sustainability companies worldwide that exhibit strength in balancing
environmental protection, social and cultural responsibility, and economic
performance. Conoco also was named to the FTSE4Good U.S. 100 Index, a stock
index representing the 100 largest U.S. companies with high standards of
corporate social responsibility. Conoco was the only oil and gas company to make
the list. In 2001, the Houston Business Journal named Conoco as the "Best Place
to Work" in Houston among companies with more than 500 employees.

     In 2001, Conoco maintained its record level of employee safety performance.
Conoco is the safest integrated global energy company in the United States,
according to data published in the American Petroleum Institute (API) annual
survey of Occupational Injuries and Illnesses in the Petroleum Industry for
performance in 2001. This was the fifth consecutive year, as well as the 17th
time in the past 23 years, that Conoco topped the safety list among its industry
peers. Conoco also ranked No. 1 for the third consecutive year in API's third
survey of the industry's safety performance outside the United States.

     Operating responsibly requires diligence in carrying out the company's
operations safely - in a manner that not only manages risks, but also uses
comprehensive incident and crisis management systems to effectively mitigate the
impact of any unplanned event. In 2001, 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 respond
effectively to a crisis is drilled extensively.

      In 2001, Conoco received external recognition for its environmental
leadership and innovation. Conoco was awarded the European Bank for
Reconstruction and Development's Corporate Environmental Award, recognizing the
environmental excellence of Conoco's Polar Lights joint venture in Russia. The
company was honored by the Canadian Council of Ministers of the Environment for
outstanding efforts showing innovation and leadership in pollution prevention
for significant reductions in greenhouse gas emissions. In addition, our
Canadian operations again were recognized as a Gold Champion Level Reporter by
the Canadian Voluntary Challenge and Registry, a not-for-profit organization
commissioned by the Canadian Federal Government to promote voluntary reduction
of greenhouse gas emissions. Conoco's Indonesian operations received a first
place award for Safety, Health and Environment from Pertamina, Indonesia's
national oil company.

     Conoco (U.K.) Limited, Conoco's upstream business unit in the United
Kingdom, received full company ISO 14001 certification in 2001. One of our
upstream operations in the Middle East and a downstream lubricants facility in
the U.S. also received ISO 14001 certification. Our U.S. CG&P division continues
its leadership role by participating in the United States Environmental
Protection Agency (USEPA) Natural Gas Star program to reduce methane emissions
in the oil and gas industry. Conoco began operating only double-hulled tankers
in U.S. waters in 1998. Today, Conoco operates a fleet of 100 percent
double-hulled crude oil tankers globally and a 100 percent double-hulled tank
barge fleet in U.S. waters. Conoco's international fleet of tankers is required
to maintain American Bureau of Shipping International Safety Management System
(ISM) certification. ISM certification verifies that the company has met the
rigorous International Maritime Organization standard requirements for a marine
safety and pollution prevention management system. In 2001, Conoco's U.S. marine
operations proactively pursued voluntary certification of the inland tank barge
fleet and received certification following rigorous audits of each vessel and
the overall management system.

     In order to maintain high ethical standards, Conoco has a formal ethics
policy and established procedures for conducting business with integrity and in
compliance with all applicable laws. At Conoco, adherence to Conoco's published
ethics policy is a condition of employment. Employees are required to review the
policy and procedures regularly and complete an annual certificate of
compliance. We also have a 24-hour telephone hotline that provides employees an
avenue for seeking guidance on ethics issues or reporting possible problems.

     As an international energy company, Conoco has an extremely diverse global
workforce. By drawing on the different perspectives and cultures of our 20,000
employees, along with their combined knowledge and creativity, Conoco has a
powerful business advantage around the world. At Conoco, we strive to create an
inclusive work environment that treats all people with dignity and respect, and
encourages employees to express their ideas and develop to their maximum
ability. This helps employees reach their personal career goals, while
increasing their contributions toward achieving the company's objectives. Conoco
in 2001 awarded employees globally a "Learning is Timeless" gift. Employees were
able to select from several choices of high-tech learning tools for their
personal use. Such investments in our employees contribute to their personal
development and motivation and results in a highly motivated, innovative work
force.




                                       32
<PAGE>
     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 2001 Employee Opinion Survey results, which reached an
eight-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
reduces liabilities, helps to manage risks and improves 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 ISSUES

     Conoco adheres to a comprehensive published environmental policy. Conoco's
environmental policy, originally adopted in 1968, has guided the company for
more than 30 years. The policy statement is "Our company will conduct business
with respect and care for the environments in which we operate." More
specifically, the policy addresses minimizing the environmental impact of our
operations, fostering open communication of company environmental performance,
systematically managing environmental performance, and continually improving the
total environmental performance of the company. The Board of Directors' Audit
and Compliance Committee provides oversight of performance as set forth in
environmental policy, standards, and goals. Conoco's Management Committee
provides strategic direction for environmental policy and reviews performance.
Corporate staff oversees the governance, implements standards, conducts safety
and environmental audits, and tracks company performance. Environmental
professionals within Conoco's global business units support local management in
managing environmental affairs and performance. The Vice President, Safety,
Health and Environment provides overall coordination and reports to the
President and Chief Executive Officer.

     Conoco and each of its various businesses are subject to numerous
international, federal, state, and local laws and regulations relating to the
protection of the environment. These environmental laws and regulations include,
among others, the:

     o    federal Clean Air Act (CAA), which governs air emissions;

     o    federal Clean Water Act (CWA), which governs discharges to water
          bodies;

     o    federal Comprehensive Environmental Response, Compensation and
          Liability Act (CERCLA), which imposes liability on generators,
          transporters, and arrangers of hazardous substances at sites where
          hazardous substance releases have occurred or are threatened to occur;

     o    federal Resource Conservation and Recovery Act (RCRA), which governs
          the treatment, storage, and disposal of solid waste;

     o    federal Oil Pollution Act of 1990 (OPA) under which owners and
          operators of onshore facilities and pipelines, lessees or permittees
          of an area in which an offshore facility is located, and owners and
          operators of vessels are liable for removal costs and damages that
          result from a discharge of oil into navigable waters of the United
          States;

     o    federal Emergency Planning and Community Right-to-Know Act (EPCRA)
          which requires facilities to report toxic chemical inventories with
          local emergency planning committees and responses departments;

     o    federal Safe Drinking Water Act (SDWA) which governs the disposal of
          wastewater in underground injections wells; and

     o    U.S. Department of the Interior regulations, which relate to offshore
          oil and gas operations in U.S. waters and impose liability for the
          cost of pollution cleanup resulting from the lessee's operations and
          potential liability for pollution damages.

     Moreover, many states and foreign countries where Conoco operates have
similar environmental laws and regulations covering the same types of matters.

     The ultimate financial impact arising from these environmental laws and
regulations is neither clearly known nor easily determined as new standards,
such as new air emission standards, water quality standards and stricter fuel
regulations, continue to evolve. Notwithstanding, environmental laws and
regulations are expected to have an increasing impact on Conoco's operations
here in the United States and in most of the countries in which the






                                       33
<PAGE>

company operates. Notable areas of potential impacts include air emission
compliance and remediation obligations. Under the CAA, the USEPA has promulgated
a number of stringent limits on air emissions and established a federally
mandated operating permit program. Violations of the CAA are enforceable with
civil and criminal sanctions.

     Moreover, the new CAA Tier II Fuels regulations pertaining to gasoline
fuels, finalized by the USEPA in early 2000, and the regulations pertaining to
on-road diesel fuels, finalized by the USEPA in early 2001, require
substantially reduced sulfur levels. Conoco is positioning itself to be able to
supply the low-sulfur gasoline according to the phase-in schedule. While the
on-road diesel regulations have been finalized, the regulations controlling the
future sulfur content of off-road diesel fuel emissions have not been issued
which has complicated estimating diesel compliance costs because those two
products are inherently tied in the refining process. New technologies are also
being developed in the industry that may lower the capital costs of compliance
with these regulations. Conoco continues to assess the compliance costs
associated with the Tier II Fuels regulations, and while it is premature to
estimate these costs accurately, Conoco expects to average less than 20 percent
to 25 percent of its yearly downstream capital spending over the next six years
to install the appropriate equipment. Similarly, the European Parliament enacted
legislation in October 1998 that, among other things, required phased reductions
of the sulfur and aromatics content in gasoline and diesel fuel and of benzene
in gasoline. Our European refineries already are in compliance with the first
level of sulfur reduction and we already have the ability to produce some of the
2005 specification gasoline and diesel at both the Humber and MiRO refineries.
The costs to comply with the 2005 specifications will not be significant. We
also are studying the possibility of producing 2011 specification products well
in advance of that required date.

     Additional areas of potential air-related impacts to Conoco are the
proposed revisions to the National Ambient Air Quality Standards (NAAQS) and the
Kyoto Protocol. In July 1997, the USEPA promulgated more stringent revisions to
the NAAQS for ozone and particulate matter. Since that time, final adoption of
these revisions has been the subject of litigation (American Trucking
Association, Inc. et al. v. United States Environmental Protection Agency) that
eventually reached the U. S. Supreme Court during fall 2000. In February 2001,
the U. S. Supreme Court remanded this matter in part to the USEPA to address the
implementation provisions relating to the revised ozone NAAQS. If adopted, the
impact of the revised NAAQS could result in substantial future environmental
expenditures for Conoco. 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 United States has not ratified the treaty codifying the
Kyoto Protocol but 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.

     Conoco also is subject to certain laws and regulations relating to
environmental remediation obligations associated with current and past
operations. Such laws and regulations include CERCLA and RCRA and their state
equivalents. Conoco's estimated remediation expenditures related to its CERCLA
and RCRA matters are discussed in Item 7 -- Management's Discussion and Analysis
of Financial Condition and Results of Operations -- Environmental Expenditures.
Remediation obligations include clean-up responsibility arising from petroleum
releases from underground storage tanks (UST) located at numerous past and
present Conoco owned and/or operated petroleum-marketing outlets throughout the
United States. Federal and state laws require that contamination caused by such
UST releases be assessed and remediated to meet applicable standards. In
addition to other clean-up standards, many states have adopted clean-up criteria
for methyl tertiary butyl ether (MTBE) for both soil and groundwater. MTBE
standards continue to evolve, and future environmental expenditures associated
with the remediation of MTBE contaminated UST sites could be substantial.

     Notwithstanding any of the foregoing and as with other companies engaged in
similar businesses, environmental costs and liabilities are inherent in Conoco's
operations and products and there can be no assurance that material costs and
liabilities will not be incurred. However, Conoco currently does not expect any
material adverse affect upon its results of operations or financial position as
a result of compliance with environmental laws and regulations. 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 Expenditures, and Item 3 --
Legal Proceedings.




                                       34
<PAGE>



SOURCES OF SUPPLY

     During 2001, 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 46 percent of the crude oil processed in
our U.S. refineries in 2001 came from U.S. sources. The remainder of crude oil
processed came principally from Venezuela, Mexico and Canada. During 2001,
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. The majority of the crude oil processed in our Melaka joint venture
refinery was from the Middle East.

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 $96 million in 2001, $58 million in 2000 and $54
million in 1999.

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 2001,
we were granted 10 U.S. and 38 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.

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. Conoco
discontinued its limited business interruption insurance in late 2001 because of
several factors including the high cost of such insurance relative to Conoco's
spread of risks, a favorable long-term loss history, and loss prevention and
safety programs. Conoco has elected to retain risks where management believes
the cost of insurance, although available, is excessive for 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 20,000 employees at December 31, 2001, approximately 2,400
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 (DOJ) advised Conoco in August 2000





                                       35
<PAGE>

that the U.S. Government is contemplating a legal proceeding under the Clean
Water Act against Conoco. Conoco and DOJ are currently in negotiations to
resolve these matters.

     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. In 2001, Conoco, LDEQ and
USEPA entered into a Consent Decree to resolve this matter. Under this Consent
Decree, Conoco agreed to pay a civil penalty of $240,000.

     On March 27, 2000, the Montana Department of Environmental Quality (MDEQ)
issued a Notice of Violation (NOV) to Conoco for alleged exceedences of
Montana's 3-hour SO2 limit at the Billings refinery. On March 1, 2001, Conoco
received an Enforcement Action Letter indicating Montana's proposed penalty of
$3 million for these alleged violations. Subsequently, the parties negotiated a
tentative settlement in which Conoco will pay a cash penalty of $207,300 and
perform a supplemental environmental project valued at $3 million to $5 million.

     During June 2001, the New Mexico Environmental Department (NMED) issued two
Compliance Orders to Conoco, one related to the Maljamar Gas Plant and the other
related to the San Juan Basin Gas Plant. The NMED alleges that the Maljamar Gas
Plant exceeded air quality emission limits and failed to complete compliance
tests within the specified time period. The NMED further alleges that the San
Juan Basin Gas Plant failed to design and operate a flare with no visible
emissions. In December 2001, the parties agreed to settle both matters by paying
$200,000 to the State of New Mexico and making a commitment to redesign flare
operations at the San Juan Basin Gas Plant.

     During August 2001, the USEPA issued a NOV to Conoco for certain alleged
violations of the federal fuels regulations of the Clear Air Act. The NOV arises
from a June 1998 USEPA audit of each of Conoco's Billings, Denver, Lake Charles
and Ponca City refineries and its Conoco Center complex in Houston, Texas. The
NOV seeks a penalty of $190,000.

     During August 2001, the USEPA and the U.S. DOJ notified Conoco of their
intent to seek sanctions for alleged violations of the Clean Air Act arising
from a 1998 Maximum Achievable Control Technology (MACT) compliance test of a
flare at Conoco's Denver refinery. The USEPA and DOJ seek a cash penalty of
$38,775 and the performance of a Supplemental Environmental Project (SEP) valued
at $130,000.

     In 2000, Conoco conducted an audit of its air compliance systems at the
Denver refinery. Conoco then self reported the results of this audit. Beginning
in August 2001, Conoco and the State of Colorado began negotiating a resolution
associated with the self-reported items. In December 2001, Conoco agreed to pay
a civil penalty of $139,800 and perform a supplemental environmental project
valued at $630,000 to resolve this matter.

     Conoco conducted negotiations with the USEPA and the states of Colorado,
Louisiana, Montana, and Oklahoma throughout 2001 as part of USEPA's nationwide
initiative to enforce federal air regulations at petroleum refineries. In
December 2001, Conoco entered into a Consent Decree with the United States,
Colorado, Louisiana, Montana and Oklahoma to reduce emissions from Conoco's
Billings, Denver, Lake Charles and Ponca City refineries by a total of 7,500
tons per year over the next seven years. Conoco will spend an estimated $95
million to $110 million over the next seven years to install control technology
and equipment to reduce emissions from stacks, vents, valves, heaters, boilers
and flares. The Consent Decree requires Conoco to pay a civil penalty of $1.5
million, in addition to $5.1 million to be spent on supplemental environmental
projects in Colorado, Louisiana, Montana and Oklahoma. This Consent Decree also
resolves certain refinery air compliance issues previously self-disclosed to the
state environmental agencies for Colorado, Montana and Oklahoma. Other
self-disclosed air compliance issues that were outside the scope of the Consent
Decree have been or will be resolved by consent orders entered directly with the
appropriate state agency.

     An accrual of $112 million was recorded during the fourth quarter of 2001
for a litigation settlement related to certain discontinued chemicals businesses
for which Conoco assumed responsibility for claims as a result of the separation
agreement with DuPont.

     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 flow improver products. The amount awarded as damages
was $55 million. The Federal Circuit Court of Appeals handed down a decision on
September 19, 2001 without a written opinion, affirming the trial court's
verdict. On November 9, 2001, we paid approximately $60





                                       36
<PAGE>

million that included interest to the settlement date, in partial satisfaction
of the judgment. The parties entered into settlement negotiations and in
December 2001 reached a confidential settlement of all disputes between the
parties.

     Conoco is subject to various lawsuits and claims including but not limited
to: 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; claims for damages resulting
from leaking underground storage tanks; and related toxic tort claims. 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.

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

     No matter was submitted during the fourth quarter of 2001 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......................         63      Chairman, President and Chief Executive Officer

Robert E. McKee III...................         55      Executive Vice President, Exploration Production

Jimmy W. Nokes........................         55      Executive Vice President, Refining, Marketing,
                                                           Supply and Transportation

Robert W. Goldman.....................         59      Senior Vice President, Finance, and
                                                           Chief Financial Officer

Rick A. Harrington....................         57      Senior Vice President, Legal, and General Counsel

Phillip L. Frederickson...............         45      Senior Vice President, Corporate Strategy and Business
                                                           Development

Thomas C. Knudson.....................         55      Senior Vice President, Human Resources, Information
                                                           Management and Corporate Communications

J. Michael Stinson....................         58      Senior Vice President, Government Affairs
</Table>


----------
(1)  As of March 12, 2002.

     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 the President and Chief Executive Officer of Conoco since 1996. He
joined Conoco in 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 an Executive Vice President of 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 both the United States
Energy Association and the National Petroleum Council and a member of The
Business Council and The Business Roundtable. Mr. Dunham is also a member of the
board of visitors at the University of Oklahoma. He serves on the board of the
Memorial Hermann Healthcare System in Houston, the board of visitors of M.D.
Anderson Cancer Center and the board of trustees of the Houston Symphony, the
George Bush Presidential Library and the Smithsonian Institution. Mr. Dunham is
the Chairman and a trustee of the Houston Grand Opera.

     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







                                       37
<PAGE>

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.

     Jimmy 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 a pipeline 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 both in the United States and internationally. He is the
former Treasurer, DuPont (Puerto Rico, Inc.), Vice President-Finance of DuPont
(Mexico), and 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
currently serves on the Board of Directors and Audit Committees of Conoco Canada
Resources Limited and Gulf Indonesia Resources Limited. 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. Mr. Goldman is on
the Advisory Board of the Center for Finance Education and Research of the
McCombs School of Business at the University of Texas at Austin. 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.

     Rick A. Harrington has been Senior Vice President, Legal and General
Counsel of Conoco since 1998. He was named Vice President and General Counsel
for Conoco in 1994. Mr. Harrington joined DuPont in 1979 as a senior litigation
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 past Chairman of the American Petroleum Institute General
Committee on Law and served on the American Corporate Counsel Board of
Directors. Currently, Mr. Harrington serves on the Conoco Executive Committee
and the Conoco Management Committee. He is also a Director of Gulf Indonesia
Resources Limited and the Minority Corporate Counsel Association.

     Philip L. Frederickson has been Senior Vice President of Corporate Strategy
and Business Development since November 2001. He joined Conoco in 1978 and held
a series of positions supporting the company's U.S. transportation operations
and its natural gas business. In 1987 he was named Manager of Planning and
Administration for the company's North American Petroleum Products Department.
Mr. Frederickson transferred to London in 1989 as General Manager for the
European refining and marketing operations. He then became President and
Managing Director of Conoco Ireland, headquartered in Dublin. He returned to
Houston in 1990 and served in assignments in U.S. retail and global downstream
operations. In 1994 he was named General Manager of Refining and Marketing
Operations in the Rocky Mountain region. He returned to Houston in 1997 to
become General Manager of Strategy and Portfolio Management for Conoco's
upstream segment and became Vice president of Business Development in 1998. Mr.
Frederickson is a member of the Texas Tech University Industrial Engineering
Academy. He serves on the Board of Directors of Theatre Under the Stars.

     Thomas C. Knudson has been Senior Vice President, Human Resources,
Information Management and Corporate Communications since November 2001. Prior
to his current position, he was Vice President, Human Resources since July 2000.
He is a graduate of the U.S. Naval Academy and served as a naval aviator before
joining Conoco's natural gas and gas products division in Houston in 1975. His
career includes assignments as Chief Executive Officer of DuPont Scandinavia,
General Manager of External Affairs and Communications, General Manager of
Business Development for Conoco's upstream business. He was Vice President and
General Manager






                                       38
<PAGE>

for Natural Gas and Gas Products from June 1995 to June 1997. From June 1997 to
July 2000, he was Chairman of Conoco Exploration Production Europe Limited,
based in London, where he was responsible for developing and executing the
company's upstream strategy throughout Europe and the former Soviet Union.
Knudson was the founding president of the Business Council for Sustainable
Development (BCSD) in the Gulf of Mexico and most recently was the founding
Chairman of the BCSD in the North Sea Region. He currently serves on the boards
of the Houston Museum of Natural Science, Covenant House Texas, and Alpha
Houston.

     J. Michael Stinson has been Senior Vice President, Government Affairs since
November 2001. He joined Conoco in 1965. He held a number of positions in the
U.S. before being named a Director and General Manager for Conoco (U.K.) Limited
in 1982. He has served as President of Conoco Norway Inc. and as the Chairman
and Managing Director of Conoco (U.K.) Limited. He became Vice President of
Business development in 1993. In 1998 he was named Senior Vice President,
Government Affairs, Corporate Strategy and Communications. Mr. Stinson is a
fellow of the Institute of Petroleum and a member of the American Petroleum
Institute, the Society of Petroleum Engineers and the American Association of
Petroleum Geologists. He is past Chairman of the American Heart Association's
Houston Division.

                                     PART II

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

MARKET, STOCK AND DIVIDEND INFORMATION

     Conoco's common stock (symbol: COC) is listed on the New York Stock
Exchange, Inc. The number of record holders of common stock was 8,685 at March
1, 2002.

     On September 21, 2001, Conoco's shareholders approved the combination of
Conoco's Class A and Class B common stock into a single class of new common
stock on a one-for-one basis. The combination was effective on October 8, 2001.

QUARTERLY COMMON STOCK PRICES AND DIVIDENDS

<Table>
<Caption>
                                               COMMON STOCK PRICE RANGE(1)
                                     ----------------------------------------------
                                              2001                    2000
                                     ----------------------  ----------------------
                                        HIGH        LOW         HIGH        LOW
                                     ----------  ----------  ----------  ----------
<S>                                  <C>         <C>         <C>         <C>
CLASS A COMMON STOCK
First quarter .....................  $    30.79  $    25.75  $    27.88  $    18.81
Second quarter ....................       32.99       26.30       27.06       22.00
Third quarter .....................       31.60       23.65       27.63       21.38
Fourth quarter ....................       26.58       24.60       29.56       24.00
CLASS B COMMON STOCK
First quarter .....................  $    31.10  $    26.00  $    28.75  $    19.00
Second quarter ....................       33.35       26.75       29.00       23.25
Third quarter .....................       32.00       23.77       28.75       22.31
Fourth quarter ....................       26.57       24.61       29.69       24.69
COMMON STOCK
Fourth quarter ....................  $    28.80  $    23.97         n/a         n/a
</Table>

----------
(1)  Quarterly market prices are as reported by the New York Stock Exchange,
     Inc.

<Table>
<Caption>
DIVIDENDS PER SHARE                          2001        2000
                                          ----------  ----------
<S>                                       <C>         <C>
First quarter ..........................  $      .19  $      .19
Second quarter .........................         .19         .19
Third quarter ..........................         .19         .19
Fourth quarter .........................         .19         .19
                                          ----------  ----------
Total Dividends per Share ..............  $      .76  $      .76
                                          ==========  ==========
</Table>






                                       39
<PAGE>

     Dividends were declared on a quarterly basis throughout 2001 and 2000.
Conoco declared a first quarter cash dividend on January 24, 2002, of $.19 per
share on each outstanding share of common stock, payable March 10, 2002, to
shareholders of record as of February 10, 2002.

     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
                                                         --------------------------------------------------------------
                                                            2001         2000         1999         1998        1997
                                                         ----------   ----------   ----------   ----------   ----------
                                                                          (IN MILLIONS, EXCEPT PER SHARE)
<S>                                                      <C>          <C>          <C>          <C>          <C>
STATEMENT OF INCOME DATA
Sales and other operating revenues ....................  $   38,737   $   38,737   $   27,039   $   22,796   $   25,796
Equity in earnings of affiliates ......................         181          277          150           22           40
Other income ..........................................         621          273          120          350          427
                                                         ----------   ----------   ----------   ----------   ----------
Total revenues (1) ....................................      39,539       39,287       27,309       23,168       26,263
Cost of goods sold ....................................      23,043       23,921       14,781       11,751       14,333
Operating expenses ....................................       3,053        2,215        2,060        2,089        1,893
Selling, general and administrative
   expenses (2) .......................................         888          794          809          972          726
Exploration expenses (3) ..............................         378          279          270          380          457
Depreciation, depletion and amortization
   (DD&A) .............................................       1,811        1,301        1,193        1,113        1,179
Taxes other than on income (1) ........................       6,983        6,981        6,668        5,970        5,532
Interest and debt expense .............................         396          338          311          199           36
                                                         ----------   ----------   ----------   ----------   ----------
Income before income taxes ............................       2,987        3,458        1,217          694        2,107
Income tax expense ....................................       1,391        1,556          473          244        1,010
                                                         ----------   ----------   ----------   ----------   ----------
Income before extraordinary item and
   accounting change ..................................       1,596        1,902          744          450        1,097
Extraordinary item, net of income taxes ...............         (44)          --           --           --           --
Cumulative effect of accounting change, net of
   income taxes .......................................          37           --           --           --           --
                                                         ----------   ----------   ----------   ----------   ----------
Net income (4) ........................................  $    1,589   $    1,902   $      744   $      450   $    1,097
                                                         ==========   ==========   ==========   ==========   ==========
SEGMENT NET INCOME
Upstream
   United States ......................................  $      987   $      719   $      322   $      223   $      447
   International ......................................         824        1,148          534          283          439
Downstream
   United States ......................................         329          182          119          141          223
   International ......................................          86          230          129          156           91
Emerging businesses ...................................         (90)         (69)         (35)         (31)         (24)
Corporate (4) .........................................        (547)        (308)        (325)        (322)         (79)
                                                         ----------   ----------   ----------   ----------   ----------
Net income (4) ........................................  $    1,589   $    1,902   $      744   $      450   $    1,097
                                                         ==========   ==========   ==========   ==========   ==========
EARNINGS PER SHARE (5)
   Basic ..............................................  $     2.54   $     3.05   $     1.19   $      .95   $     2.51
   Diluted ............................................  $     2.50   $     3.00   $     1.17   $      .95   $     2.51
Weighted-average shares outstanding (5)
   Basic ..............................................         626          624          627          474          437
   Diluted ............................................         635          633          636          475          437
Dividends per common share ............................  $      .76   $      .76   $      .71   $       --   $       --
OTHER DATA
Cash provided by operations ...........................  $    3,141   $    3,438   $    2,216   $    1,373   $    2,876
Capital expenditures and investments (6) ..............       2,835        2,796        1,787        2,516        3,114
Cash exploration expense ..............................         262          191          139          217          286
</Table>





                                       40
<PAGE>
----------
(1)  Includes petroleum excise taxes of $6,744, $6,774, $6,492, $5,801 and
     $5,349 for 2001, 2000, 1999, 1998 and 1997, 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.

(4)  Includes after-tax exchange gains (losses) of $(33), $38, $6, $32 and $21
     for 2001, 2000, 1999, 1998 and 1997, 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.

(6)  Excludes acquisition of Gulf Canada of $4,571 cash plus assumed liabilities
     and minority interests.

<Table>
<Caption>
                                                                                   DECEMBER 31
                                                         -------------------------------------------------------------
                                                            2001         2000         1999         1998        1997
                                                         ----------   ----------   ----------   ----------  ----------
<S>                                                      <C>          <C>          <C>          <C>         <C>
BALANCE SHEET DATA
Cash and cash equivalents .............................  $      388   $      342   $      317   $      394  $    1,147
Working capital .......................................      (1,159)        (776)        (690)          45         567
Net property, plant and equipment .....................      17,918       12,207       11,235       11,413      10,828
Total assets ..........................................      27,904       18,127       16,375       16,075      17,062
Long-term borrowings -- related parties ...............          --           --           --        4,596       1,450
Long-term borrowings and capital lease obligations ....       8,267        4,138        4,080           93         106
Minority interests ....................................       1,204          337          335          309         309
Total stockholders' equity/owner's net investment .....       6,610        5,628        4,555        4,438       7,896
</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,"
"will," "should" 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 mining, 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, political events or terrorism;

     o    international monetary conditions and exchange controls;





                                       41
<PAGE>
     o    liability for remedial actions under environmental regulations;

     o    liability resulting from litigation;

     o    general domestic and international economic and political conditions,
          including armed hostilities and terrorism; and

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

     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 Conoco's Class A common stock 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 $23.00 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.

     On September 21, 2001, Conoco's shareholders approved the combination of
our Class A and Class B common stock into a single class of new common stock on
a one-for-one basis. The combination was effective on October 8, 2001. The
number of shares of common stock issued and outstanding as of December 31, 2000,
has been restated to give effect to the combination. There was no effect on
previously reported earnings per share amounts.

     On November 18, 2001, Conoco and Phillips Petroleum Company (Phillips)
announced that their boards of directors unanimously approved the merger of the
two companies. The new company will be named ConocoPhillips. Under the terms of
the agreement, Phillips shareholders will receive one share of new
ConocoPhillips common stock for each share of Phillips common stock they own and
Conoco shareholders will receive .4677 shares of new ConocoPhillips common stock
for each share of Conoco common stock they own. The merger is conditioned upon,
among other things, the approval of the shareholders of each company and
customary regulatory approvals. Both companies held special meetings of
shareholders on Tuesday, March 12, 2002, and the shareholders of both companies
approved the proposed merger. Completion of the transaction is expected in the
second half of 2002.

     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; and Syncrude mining operations (Canadian Syncrude). 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. Currently, we are involved in the carbon fibers
(Conoco Cevolution(R)); natural gas refining, including gas-to-liquids; and
international power businesses. We have five reporting segments. Four reporting
segments reflect the geographic division between the U.S. and international
operations for our 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.

     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 $2,465 million, averaging about $493 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 34 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





                                       42
<PAGE>
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, Canadian
Syncrude and refined products produced, and the costs of finding, mining,
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, Canadian Syncrude 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 2001 decreased from the prices
experienced during 2000. West Texas Intermediate crude oil averaged $25.97 per
barrel for 2001, a decrease of $4.18 from $30.15 per barrel in 2000. In
addition, NYMEX natural gas spot prices averaged $4.38 per thousand cubic feet
(mcf) in 2001, up $.67 from $3.71 per mcf in 2000. Conoco had lower earnings for
the year, largely due to lower crude oil prices, partially offset by higher gas
prices and healthy refining margins in the U.S.

     Prices for crude oil, natural gas, Canadian Syncrude 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, natural gas
and Canadian Syncrude prices and refined product margins may adversely affect
Conoco. Lower crude oil, natural gas and Canadian Syncrude prices may reduce the
amount of oil, natural gas and Canadian Syncrude 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, the Middle East 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 and terrorism;

     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    the risk of 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.

CRITICAL ACCOUNTING POLICIES

     In preparing financial statements, management is required to select
appropriate accounting policies and make estimates and assumptions that affect
the reported amounts of assets, liabilities, revenues and expenses. Certain of
those accounting policies involve judgments and uncertainties and there is
reasonable likelihood that materially different amounts could have been reported
had different assumptions and judgments been made.

   OIL AND GAS ACTIVITIES

     The accounting for our upstream oil and gas activities is subject to
special accounting rules that are unique to the oil and gas business. There are
two methods to account for oil and gas business activities, the successful
efforts






                                       43
<PAGE>
method and the full cost method. Conoco has elected to use the successful
efforts method. A description of our policies for oil and gas properties,
impairment, maintenance and repair activities is located in note 2 to our
consolidated financial statements.

     The successful efforts method reflects the volatility that is inherent in
exploring for mineral resources in that costs of unsuccessful exploratory
efforts are charged to expense as they are incurred. These costs primarily
include dry hole costs, seismic costs and other exploratory costs. Under the
full cost method, these costs are capitalized and written-off (depreciated) over
time.

   OIL AND GAS RESERVES

     Engineering estimates of Conoco's oil and gas reserves are inherently
imprecise and represent only approximate amounts because of the subjective
judgments involved in developing such information. There are authoritative
guidelines regarding the engineering criteria that have to be met before
estimated oil and gas reserves can be designated as "proved." Proved reserve
estimates are updated at least annually and take into account recent production
and technical information about each field. In addition, as prices and cost
levels change from year to year, the estimate of proved reserves also changes.
This change is considered a change in estimate for accounting purposes and is
reflected on a prospective basis in related depreciation rates.

     Despite the inherent imprecision in these engineering estimates, these
estimates are used in determining depreciation expense and impairment expense,
and in disclosing the supplemental standardized measure of discounted future net
cash flows relating to proved oil and gas properties. Depreciation rates are
determined based on estimated proved reserve quantities (the denominator) and
capitalized costs of producing properties (the numerator). Producing properties'
capitalized costs are amortized based on the units of oil or gas produced.
Therefore, assuming all other variables are held constant, an increase in
estimated proved reserves decreases our depreciation, depletion and amortization
expense. Also, estimated reserves are often used to calculate future cash flows
from our oil and gas operations, which serve as an indicator of fair value in
determining whether a property is impaired or not. The larger the estimated
reserves, the less likely the property is impaired.

   CANADIAN SYNCRUDE RESERVES

     Canadian Syncrude proven reserves cannot be measured precisely. Reserve
estimates of Canadian Syncrude are based on subjective judgments involving
geological and engineering assessments of in-place crude bitumen volume, the
mining plan, historical extraction recovery and upgrading yield factors,
installed plant operating capacity and operating approval limits. The
reliability of these estimates at any point in time depends on both the quality
and quantity of the technical and economic data and the efficiency of extracting
the bitumen and upgrading it into a light sweet crude oil.

     Despite the inherent imprecision in these engineering estimates, these
estimates are used in determining such amounts as depreciation expense,
impairment expense and estimated future cash flows relating to mining
operations.

   IMPAIRMENTS

     If circumstances indicate that the net book value of an asset or
investment, including oil and gas properties, may not be recoverable, this asset
may be considered "impaired," and an impairment loss may be recognized in
accordance with Statement of Financial Accounting Standards (SFAS) Nos. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of" and 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets" or Accounting Principles Board (APB) Opinion No. 18, "The
Equity Method of Accounting for Investments in Common Stock." The amount of
impairment loss is the difference between the carrying amount of the asset or
investment and its fair market value. It is difficult to precisely estimate fair
value because quoted market prices for our assets and investments are not easily
available. We will use all readily available information in determining an
amount that is a reasonable approximation of fair value, including the net
present value of future net cash flows based on reserve quantities as indicated
above.

     In recording the purchase of Gulf Canada Resources Limited (Gulf Canada),
we recorded a material amount of goodwill. Under current accounting rules,
goodwill is not amortized; instead, it is subject to annual impairment testing.
Effective January 1, 2002, impairment testing will use the fair market value of
individual reporting units to which goodwill has been allocated to determine
whether an impairment exists. Management will use all reasonably





                                       44
<PAGE>
available information to make these fair value determinations and may hire an
outside firm to help in determining reporting unit fair values.

   ASSET RETIREMENT OBLIGATIONS

     Conoco has significant obligations to remove tangible equipment and restore
land or seabed at the end of operations. Our removal and restoration obligations
are primarily associated with plugging and abandoning wells and removal and
disposal of offshore oil and gas platforms around the world. The estimated
undiscounted costs, net of salvage value, of dismantling and removing these
facilities are accrued over the productive life of the asset. Estimating the
future asset removal costs is difficult and requires management to make
estimates and judgments because most of the removal obligations are many years
in the future and contracts and regulations often have vague descriptions of
what constitutes removal. Asset removal technologies and costs are constantly
changing, as well as political, environmental, safety and public relations
considerations. In addition, the Financial Accounting Standards Board (FASB) has
recently issued SFAS No. 143, "Accounting for Asset Retirement Obligations,"
which significantly changes the method of accruing for costs, associated with
the retirement of fixed assets, that an entity is legally obligated to incur. We
are evaluating the impact and timing of implementing SFAS No. 143.

   ENVIRONMENTAL LIABILITIES

     Conoco incurs costs to comply with complex environmental laws and
regulations, and internal voluntary programs. These costs are significant and
will continue to be so in the foreseeable future. We accrue for these costs when
it is probable that a liability has been incurred and reasonable estimates of
the liability can be made. It is difficult to develop reasonable estimates of
future site remediation costs due to changing regulations, changing technologies
and their associated costs, as well as changing economic and political
environments. Also, it is difficult to determine our liability in proportion to
that of other responsible parties. As a result, from time to time significant
charges to income may be recorded to properly accrue for such liabilities. For
additional information, see note 28 to the consolidated financial statements.

   CONTINGENCIES

     In addition to accruing the estimated costs for asset retirement
obligations and environmental liabilities, Conoco accrues for all known and
estimable contingencies. These other contingencies are primarily related to
litigation and tax issues. Determining appropriate amounts for accrual is a
complex estimation process that includes subjective judgments. We review these
contingencies on at least a quarterly basis to determine if new accruals need to
be recorded or if adjustments to existing accruals need to be made. In
accordance with SFAS No. 5, "Accounting for Contingencies," accruals are
recorded when an adverse outcome is probable and the amount can be reasonably
estimated. For additional information, see note 28 to the consolidated financial
statements.

   INVENTORIES

     Conoco uses the last-in, first-out (LIFO) method for determining the value
of crude oil and petroleum products and Canadian Syncrude inventories. Under the
LIFO method, cost of goods sold more closely reflects current prices and
inventory value more closely reflects prior period costs. As a result, the
valuation of inventory is more likely to experience lower-of-cost-or-market
impairments, as compared to other methods, when price levels decline. In
addition, current period earnings could be impacted when inventory is drawn down
into prior LIFO cost inventory layers. In determining how to price the LIFO
layers each period, we use objective evidence based on internally developed
criteria that are consistently applied.

   FOREIGN CURRENCY

     Conoco has operations in numerous countries and conducts business
transactions in several foreign currencies. In accounting and reporting for
these foreign operations, U.S. generally accepted accounting principles require
that an entity designate a "reporting currency" in which its financial
statements are presented and designate the "functional currency" of each of its
foreign operations. Selection of the functional currency involves management
judgment regarding the economic environments in which foreign entities conduct
business. The selection of a functional currency affects our income statement as
foreign currency gains and losses from re-measurements into the functional
currency are reported in current period income and gains and losses from
translation from the functional currency into the "reporting currency" are not
reported in current income, but instead are recorded in other comprehensive
income in the Stockholders' Equity section of the balance sheet. The U.S. dollar
is Conoco's





                                       45
<PAGE>

reporting currency, as well as the functional currency of all foreign operations
except Europe and Canada. The local currency is the functional currency of
Conoco's European and Canadian operations.

   BASIS OF CONSOLIDATION

     The decision of the appropriate method of reporting financial results of
investments in activities of affiliates (full consolidation, equity or cost
method) is based on:

     o    the extent of influence Conoco can exert on the affiliate; and

     o    the structure of the investor agreements.

     In assessing the degree of influence, management takes into account the
legal structure (corporation, partnership, joint venture, etc.), as well as
Conoco's and other investors' voting percentage. The percentage guidelines set
forth in the accounting literature are not absolutes, but merely guidelines for
making an initial assessment of Conoco's level of control. Other items (e.g.,
veto rights) also influence whether control exists in actuality. It is necessary
to consider all relevant facts and circumstances and apply judgment to ensure
that the reporting methods reflect the substance, not just the form, of the
relationship between Conoco and its affiliates. Refer to notes 2, 15 and 22 in
the consolidated financial statements and Other Liquidity Matters.

   DERIVATIVE FINANCIAL INSTRUMENTS

     The current accounting rules require that derivative instruments be
recorded at fair value. Quoted market prices are the best evidence of fair
value. If quoted market prices are not available, management's best estimate of
fair value is based on the quoted market price of financial instruments with
similar characteristics or on valuation techniques (e.g., option pricing
models).

     As discussed in further detail in Item 7A -- Quantitative and Qualitative
Disclosures About Market Risk, Conoco's fair values of exchange traded futures
contracts are based on publicly quoted prices. The fair value non-exchange
traded contracts (swaps and other over-the-counter instruments) are estimated
based on quoted market prices of comparable contracts.

     SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities," as amended by SFAS No. 138, "Accounting for Certain Derivative
Instruments and Certain Hedging Activities," (SFAS 133) requires that gains and
losses from the change in fair value of derivative instruments that do not
qualify for hedge accounting be reported in current period income, rather than
in the period in which the hedged transaction is settled. This may result in
significant volatility to current period income.

     SFAS 133 is complex and subject to a potentially wide range of
interpretations in its 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
SFAS 133. The DIG is still active, and the potential exists for additional
issues to be brought under its review. Therefore, if subsequent DIG
interpretations of SFAS 133 are different than our current policy, it is
possible that our policy, as stated above, would be modified.

LIQUIDITY AND CAPITAL RESOURCES

   CASH PROVIDED BY OPERATIONS

     Cash provided by operations in 2001 decreased $297 million to $3,141
million versus $3,438 million in 2000. Cash provided by operations before
changes in operating assets and liabilities increased $434 million compared to
2000, primarily due to higher natural gas prices and strong U.S. refining
margins in the first six months of the year, increased crude oil and natural gas
volumes and higher dividends from equity affiliates, partially offset by lower
crude oil prices. Negative changes to net operating assets and liabilities of
$731 million were due to decreases in payables, partially offset by a decrease
in accounts receivable.

     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




                                       46
<PAGE>
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.

   INVESTING ACTIVITIES

     PURCHASE OF BUSINESSES

     On July 16, 2001, Conoco, through a wholly owned subsidiary, completed the
acquisition of all the ordinary shares of Gulf Canada, now known as Conoco
Canada Resources Limited (Conoco Canada) for approximately $4,571 million in
cash plus assumed liabilities and minority interests. For ease of reference, we
will refer to Conoco Canada as Gulf Canada. Prior to the acquisition, Gulf
Canada was a Canadian-based independent exploration and production company, with
primary operations in western Canada, Indonesia, the Netherlands and Ecuador.
Subsequent to the acquisition, operational responsibilities for Gulf Canada's
interests in Indonesia, the Netherlands and Ecuador were realigned within
Conoco's regional organizational structure, and operationally Conoco's existing
Canadian operations were merged with those of Gulf Canada.

     CAPITAL EXPENDITURES AND INVESTMENTS

<Table>
<Caption>
                                                                 YEAR ENDED DECEMBER 31
                                                         -------------------------------------
                                                            2001           2000        1999
                                                         ----------     ----------  ----------
                                                                     (IN MILLIONS)
<S>                                                      <C>            <C>         <C>
Upstream
    United States .....................................  $      856     $      667  $      413
    International .....................................       1,358(1)       1,486         839
                                                         ----------     ----------  ----------
       Total upstream .................................       2,214          2,153       1,252
Downstream
    United States .....................................         164            344         214
    International .....................................         225            201         248
                                                         ----------     ----------  ----------
       Total downstream ...............................         389            545         462
Emerging businesses ...................................         196             72          69
Corporate .............................................          36             26           4
                                                         ----------     ----------  ----------
Total capital expenditures and investments ............  $    2,835     $    2,796  $    1,787
                                                         ==========     ==========  ==========
United States
                                                         $    1,218     $    1,101  $      700
International .........................................       1,617          1,695       1,087
                                                         ----------     ----------  ----------
Total .................................................  $    2,835     $    2,796  $    1,787
                                                         ==========     ==========  ==========
</Table>


----------
(1)  Excludes acquisition of Gulf Canada for $4,571 million cash plus assumed
     liabilities and minority interests.

     Total capital expenditures and investments in 2001, including investments
in affiliates and acquisitions other than Gulf Canada, were $2,835 million, an
increase of 1 percent versus 2000 capital expenditures and investments of $2,796
million. The increase was due primarily to higher spending on emerging
businesses partially offset by lower expenditures on U.S. refining operations.
During 2001, 78 percent of total capital expenditures and investments were
upstream-related, with a majority devoted to the acquisition of coalbed methane
properties in the San Juan Basin and drilling in deepwater Gulf of Mexico,
Vietnam, Venezuela and Indonesia, as well as continued development of various
fields. Worldwide, approximately $324 million was spent on exploratory drilling
and leasing. The decrease in 2001 downstream capital expenditures and
investments primarily resulted from decreased expenditures on U.S. refining
operations. Emerging businesses capital expenditures and investments increased
versus 2000, as a result of continued construction of our first commercial-scale
carbon fibers manufacturing plant, in Ponca City, Oklahoma, and project costs
associated with our U.S. power business. The increase in corporate capital
expenditures and investments was due primarily to computer infrastructure
additions.

     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 due primarily 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 and gas processing plants in Canada and the U.S., and
to our Petrozuata joint venture in Venezuela. Worldwide,



                                       47
<PAGE>

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, Louisiana, 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 due primarily to investments in several
e-commerce initiatives and to computer hardware and software costs.

     In 2002, Conoco expects its capital budget, including investments in
affiliates and acquisitions, to be about $2,800 million. We expect about $2,300
million will be spent on upstream projects for worldwide exploration, production
and natural gas activities, while about $500 million will be spent on downstream
projects. These expenditures will be funded primarily through cash flow from
operations, augmented as necessary by asset dispositions and existing borrowing
capacity.

     Upstream

     Upstream capital expenditures and investments totaled $2,214 million in
2001. The increase of $61 million, or approximately 3 percent, compared to
$2,153 million in 2000, was primarily the result of increased drilling
operations. Expenditures in 2001 included the purchase of coalbed methane
properties in the San Juan Basin and drilling in deepwater Gulf of Mexico,
Vietnam, Venezuela and Indonesia, as well as continued development of various
fields.

     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. and gas processing plants in the U.S. Additionally, we increased our
capital spending in the Caspian Sea, Indonesia and the U.S.

     We also have spent approximately $892 million, $705 million and $587
million to develop our proved undeveloped reserves in 2001, 2000 and 1999 and
expect to spend an estimated $1,100 million, $1,000 million and $600 million in
2002, 2003 and 2004.

     United States

     U.S. capital expenditures and investments were $856 million in 2001, an
increase of $189 million, or 28 percent, compared to 2000 capital expenditures
and investments of $667 million. Expenditures during 2001 were focused on
continued development of the Lobo field in south Texas and the acquisition of
coalbed methane properties in the San Juan Basin of New Mexico. Expenditures
also were centered on the deepwater Gulf of Mexico with the drilling of the
appraisal wells in the Magnolia discovery.

     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 also were 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.

     International

     International capital expenditures and investments were $1,358 million in
2001, a decrease of $128 million, or 9 percent, compared to $1,486 million in
2000. The decrease was primarily the result of lower spending on acquisitions.
Expenditures in 2000 included the acquisition of Saga U.K. Ltd. and Canadian
natural gas gathering and processing assets.

     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 gathering and processing 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.




                                       48
<PAGE>

   Downstream

     Downstream capital expenditures and investments for 2001 totaled $389
million, a decrease of $156 million, or 29 percent, versus $545 million in 2000,
primarily reflecting decreased expenditures on U.S. refining operations.

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

     United States

     For 2001, U.S. capital expenditures and investments totaled $164 million, a
decrease of $180 million, or 52 percent, versus 2000 capital expenditures and
investments of $344 million. Expenditures in 2001 were principally related to
pipeline and refining operations.

     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
installation of new units at our Lake Charles refinery to process acidic
synthetic crude from Petrozuata and expansion of pipeline assets in the Rocky
Mountain region, as well as on our refining and marketing operations.

     International

     Conoco made international capital expenditures and investments of $225
million during 2001, an increase of $24 million, or 12 percent, from the $201
million spent in 2000. The majority of the funds in 2001 were directed toward
our ongoing refining and marketing operations, as well as continuing investments
relating to upgrades to meet future clean fuels specifications in Europe.

     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.

   Emerging Businesses

     During 2001, emerging businesses capital expenditures and investments
totaled $196 million, compared to $72 million in 2000. The increased
expenditures in 2001 were primarily related to the construction of our first
commercial-scale carbon fibers manufacturing plant, in Ponca City, Oklahoma, and
project costs associated with our U.S. power business. Completion of the carbon
fibers plant is expected soon, with first production expected in mid-2002.

     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 our carbon fibers manufacturing plant in Ponca
City, Oklahoma, which began during 2000. There was an offsetting decrease in the
capital expenditures associated with our power business.

   Corporate

     During 2001, corporate capital expenditures and investments totaled $36
million, an increase of $10 million from 2000 capital expenditures and
investments of $26 million. The increased expenditures during 2001 were largely
for computer infrastructure.

     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 primarily
related to investments in e-commerce initiatives and technology-related
investments in hardware and software.




                                       49
<PAGE>



     PROCEEDS FROM SALES OF ASSETS AND SUBSIDIARIES

     Conoco's 2001 disposition proceeds were $795 million, up $573 million, or
258 percent, from $222 million in 2000, due to more asset dispositions in 2001
resulting from our asset disposition program implemented in 2001. Our asset
dispositions included the sale of our interest in the Pocahontas Gas
Partnership; the sale of our interest in Arkhangelskgeoldobycha, a Russian oil
company; the sale of retail units and natural gas facilities in the United
States; exiting our downstream operation in Spain; the sale of oil and gas
properties in shallow waters in the Gulf of Mexico; the sale of oil and gas
properties in Texas and Wyoming; and the sale of retail units in the U.K.

     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 the Gulf Coast region, and our
interest in a pipeline in the southeastern U.S.

   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. We
believe our future cash flow from operations and our borrowing capacity should
be sufficient to fund our payments of dividends, if any, capital expenditures
and working capital requirements and to service debt.

     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. In May of
1999, we repaid the remaining debt owed to DuPont with proceeds from a $2,000
million U.S. commercial paper program.

     On October 18, 2001, we amended and increased our unsecured $2,000 million
revolving credit facility with a syndicate of U.S. and international banks by
$1,000 million to facilitate an increase in our commercial paper program. The
terms consist of a 364-day committed facility in the amount of $2,350 million
and a five-year committed facility, with over two years remaining, in the amount
of $650 million. At December 31, 2001, and at December 31, 2000, we had no
outstanding borrowings under the credit facility.

     Also, during October, we increased our U.S. commercial paper program to
$3,000 million and increased our European commercial paper program to euro 1,000
million. Both programs are fully supported by the credit facility. We have the
ability to issue commercial paper at any time with maturities not to exceed 270
days. At December 31, 2001, we had $558 million of commercial paper outstanding,
with a weighted-average interest rate of 2.16 percent, of which $29 million was
denominated in foreign currencies. 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 the time of the Gulf Canada acquisition, Gulf Canada had a $500 million
unsecured credit facility. This facility was subsequently cancelled in October
2001.

     In connection with the July 2001 Gulf Canada acquisition, we arranged a
$4,500 million senior unsecured 364-day bridge credit facility to finance the
transaction and assumed approximately $2,000 million of net debt and minority
interests. The borrowings under the bridge facility were repaid on October 11,
2001, primarily with the net proceeds of $4,469 million from the $4,500 million
debt offering by Conoco and Conoco Funding Company, a wholly owned Nova Scotia
finance subsidiary, described in the subsequent paragraphs. The bridge facility
was subsequently cancelled on October 16, 2001. Subsequent to the Gulf Canada
acquisition, Gulf Indonesia Resources Limited (Gulf Indonesia), a consolidated
subsidiary of Gulf Canada, repaid $116 million of its outstanding debt and Gulf
Canada repaid $1,015 million of its $1,048 million in outstanding U.S. dollar
debt securities. In addition, Gulf Canada repaid $207 million of its
subordinated debt and an additional $234 million of outstanding private
placement debt. In association with the debt securities repaid in 2001, we
incurred an extraordinary loss of $77 million ($44 million after-tax) for a
premium charged on the early repayment of this debt. We funded these repayments
and the repayment of the balance of the bridge facility through a combination of
cash on hand, our issuance of commercial paper and borrowings under other
available credit lines.

     On October 11, 2001, Conoco Funding Company issued $3,500 million of senior
debt securities, fully and unconditionally guaranteed by Conoco, as follows:




                                       50
<PAGE>

     o    $1,250 million of 5.45 percent notes due 2006;

     o    $1,750 million of 6.35 percent notes due 2011; and

     o    $500 million of 7.25 percent notes due 2031.

Conoco also issued $1,000 million of floating rate notes as follows:

     o    $500 million notes due October 15, 2002, with a floating rate based on
          the three-month LIBOR rate plus .77 percent; and

     o    $500 million notes due April 15, 2003, with a floating rate based on
          the three-month LIBOR rate plus .85 percent.

     In 1996, various upstream subsidiaries contributed oil and gas 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
interest and terminate the Conoco Oil & Gas Associates partnership, reducing
minority interest by $302 million. As a result of this transaction, Vanguard
received from Conoco Oil & Gas Associates $310 million cash, which represented
its mark-to-market adjusted capital account value plus a priority return for the
period of October 1, 1999, through December 31, 1999.

     In 1999, Conoco formed Conoco Corporate Holdings L.P. by contributing an
office building and four aircraft. The limited partner interest was sold to
Highlander Investors L.L.C. for $141 million, or an initial net 47 percent
interest. Highlander is entitled to a cumulative annual priority return on its
investment of 7.86 percent. The net minority interest in Conoco Corporate
Holdings held by Highlander was $141 million at December 31, 2001 and December
31, 2000.

     In 1999, Conoco and Armadillo Investors L.L.C. formed Conoco Gas Holdings
L.L.C. We 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. The net minority interest
in Conoco Gas Holdings held by Armadillo was $185 million at December 31, 2000.
In March 2001, we acquired the minority interest in Conoco Gas Holdings L.L.C.
from Armadillo L.L.C. The acquisition resulted in a reduction of minority
interest of $185 million, an increase in debt of $171 million and a reduction in
cash of $14 million. We assumed the $171 million debt from Armadillo L.L.C.

     In December 2001, Conoco and Cold Spring Finance S.a.r.l. formed Ashford
Energy Capital S.A. through the contribution of cash and a Conoco subsidiary
promissory note. Ashford Energy issued $498 million in equity certificates to
Cold Spring, and they are entitled to a cumulative annual preferred return based
upon current short-term interest rates. The initial return will be 3.18 percent
and will adjust quarterly. As a result, Cold Spring held a $500 million net
minority interest in Ashford Energy at December 31, 2001.

     Total Conoco debt was $9,392 million at December 31, 2001, up $4,998
million versus $4,394 million at December 31, 2000. The total
debt-to-capitalization ratio was 54.6 percent at December 31, 2001, and 42.4
percent at December 31, 2000. Effective with the third quarter of 2001, the
debt-to-capitalization ratio calculation was changed to include minority
interest in the denominator. The December 31, 2000, debt-to-capitalization ratio
has been restated to reflect this change.

     In February 2001, we commenced a new three-year $1,000 million common stock
buyback program. The stock buyback program allowed us to repurchase shares from
time to time in the open market or possibly, under certain circumstances,
through private transactions, as our financial condition and market conditions
warranted. The stock buyback program was suspended in May 2001 with our purchase
of Gulf Canada. During 2001, we purchased 1.3 million shares of our common stock
at a total cost of $37 million.

     On February 14, 2002, Gulf Canada announced that its board of directors
approved the redemption of its Series I and Series II preferred stock and its
6.45 percent senior unsecured Canadian dollar notes due 2007. The Series II
preferred shares will be redeemed on April 10, 2002, at a cost of Canadian $150
million; while both the Series I preferred shares and the 6.45 percent senior
unsecured notes will be redeemed on April 22, 2002, at a cost of Canadian $472
million and Canadian $106 million, respectively.




                                       51
<PAGE>
     In January 2002, Immingham CHP, L.L.P., a subsidiary of Conoco, executed a
British pound 257 million bank facility for the planned construction of a
730-megawatt combined heat and power cogeneration plant near our Humber refinery
in the U.K. The bank facility is designed to provide 65 percent of the
construction costs of the project with the remaining 35 percent of the funds
coming in the form of equity from certain Conoco subsidiaries. Borrowing under
the bank facility is not projected to begin until September 2002. In addition,
we have issued a construction support guarantee that indirectly guarantees up to
approximately 25 percent of the debt, depending upon the initial operating
performance of the plant. This guarantee will be released upon meeting the
various completion tests as required by the lenders. Subsequent to closing the
facility and as required by the lender to mitigate certain risks, Immingham CHP
entered into related foreign currency and interest rate derivative hedging
instruments.

   OTHER LIQUIDITY MATTERS

     LIQUIDITY AVAILABILITY

     Conoco's debt securities have current investment grade ratings of BBB+,
Baa1, and BBB+ from Standard & Poor's, Moody's Investor Services, and Fitch
Ratings Services, respectively. As a result of the proposed merger with
Phillips, all three agencies have put Conoco's ratings on Creditwatch positive
for a potential upgrade pending the completion of the merger.

     As a result of Conoco's investment grade ratings, Conoco has access to the
money markets, which include the commercial paper markets and bank loan market.
As a component of the debt refinancing activities in connection with the Gulf
Canada acquisition, Conoco increased its U.S. commercial paper program by $1,000
million in October (see the discussion in financing activities above). During
2001, Conoco had a total daily average of unused capacity of approximately
$1,300 million under its commercial paper programs available to support any
unforeseen capital needs.

     Conoco does not have any ratings triggers on any of its corporate debt that
would cause an automatic event of default in the event of a downgrade of
Conoco's debt rating, thereby impacting Conoco's access to liquidity. In the
highly unlikely event that Conoco's credit deteriorates to a level that
prohibits Conoco from accessing the commercial paper market, Conoco would still
be able to access funds under its $3,000 million revolving credit facility.
Based on Conoco's year-end commercial paper balance of $558 million, Conoco
would still have access to over $2,400 million in borrowing capacity, after
repaying all outstanding commercial paper, to provide ample liquidity to cover
any needs that its business may require to cover daily operations.

     COMMITMENT AND GUARANTEES OF JOINT-VENTURE DEBT

     At December 31, 2001, Conoco had guarantees outstanding of about $1,014
million for its portion of joint-venture debt totaling $1,955 million. The most
significant guarantee was a completion guarantee, guaranteed by DuPont on behalf
of and indemnified by Conoco, supporting our share of Petrozuata's debt ($707
million). Petrozuata has now successfully met all of the operational, financial
and legal requirements of the completion test associated with this guarantee. On
March 14, 2002, Conoco was notified that DuPont was released from its guarantee
and the debt became non-recourse to both of the sponsors. Substantially all of
the joint ventures whose debt we guarantee are appropriately capitalized and
have sufficient cash flow to service their debt. Management believes our current
exposure could be up to $50 million for joint ventures that may have
insufficient sources of cash to service their debt.

     OFF-BALANCE SHEET ARRANGEMENTS AND MINORITY INTERESTS

     Conoco uses various leased facilities and equipment in its operations, some
of which are structured in off-balance sheet entities. These structures are
principally used to reduce the after-tax cost of leasing such assets. Should the
accounting rules concerning consolidation or leasing entities change such that
these arrangements would be consolidated by Conoco, we would be required to
record the outstanding debt and assets of these arrangements. At December 31,
2001, this amount approximated $400 million. The impact on earnings would not be
significant, since current lease payments approximate any resulting depreciation
and interest costs from such a reclassification.

     Conoco also consolidates several entities that have issued equity interests
to third parties and provides for a preferred return to those parties. Those
entities, which are described in note 22 to the consolidated financial
statements, are consolidated with the preferred equity interests accounted for
as minority interests. If the accounting rules for consolidations or for
classification of debt and equity were to change, the amounts recorded as
minority




                                       52
<PAGE>

interest might have to be reclassified to long-term debt, with the returns
included in interest expense. There would be no effect on cash flow or earnings
available to common shareholders for such a reclassification.

     Conoco has not pledged its stock directly or on a contingency basis as a
guarantee or support to any financing transactions.

     DISCLOSURES ABOUT CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

<Table>
<Caption>
                                                                 PAYMENTS DUE BY PERIOD
                                               ----------------------------------------------------------
                                                                      (IN MILLIONS)
                                                              UP TO       2 - 3      4 - 5       AFTER 5
                                                  TOTAL      1 YEAR       YEARS      YEARS        YEARS
                                               ----------  ----------  ----------  ----------  ----------
<S>                                            <C>         <C>         <C>         <C>         <C>
CONTRACTUAL OBLIGATIONS
Long-term debt ..............................  $    8,862  $      506  $    2,033  $    1,276  $    5,047
Capital lease obligations ...................          22           2          --           3          17
Operating leases ............................       1,674         329         439         357         549
Unconditional purchase obligations (1) ......       1,264         222         315         197         530
                                               ----------  ----------  ----------  ----------  ----------
Total contractual cash obligations ..........  $   11,822  $    1,059  $    2,787  $    1,833  $    6,143
                                               ==========  ==========  ==========  ==========  ==========
</Table>


----------
(1)  Includes only non-market based purchase commitments; does not include
     purchase commitments for materials, supplies, services and items of
     permanent investment incident to the ordinary conduct of business.

     EXCHANGE AND NON-EXCHANGE TRADED CONTRACTS ACCOUNTED FOR AT FAIR VALUE

     See Item 7A.  Quantitative and Qualitative Disclosures About Market Risk.

     RELATED PARTY AND OTHER TRANSACTIONS

     Conoco has transactions with many unconsolidated affiliates. Equity
affiliate sales to Conoco amounted to $1,023 million in 2001, $804 million in
2000 and $720 million in 1999. Equity affiliate purchases from Conoco totaled
$1,690 million in 2001, $2,200 million in 2000 and $1,519 million in 1999. These
agreements were not the result of arms-length negotiations. However, Conoco
believes that these contracts are generally at values that are similar to those
that could be negotiated with independent third parties.

     Conoco does have employees of the company that serve as management
committee members of all of our joint ventures. However, neither Conoco's
management nor employees have any personal financial ownership in any of these
ventures.

RESULTS OF OPERATIONS

   CONSOLIDATED RESULTS

<Table>
<Caption>
                                                                              YEAR ENDED DECEMBER 31
                                                                   ------------------------------------------
                                                                       2001           2000           1999
                                                                   ------------   ------------   ------------
                                                                                (IN MILLIONS)
<S>                                                                <C>            <C>            <C>
SALES AND OTHER OPERATING REVENUES
   Upstream
      United States .............................................  $      7,028   $      5,531   $      3,309
      International .............................................         5,120          3,666          2,247
                                                                   ------------   ------------   ------------
       Total upstream ...........................................        12,148          9,197          5,556
   Downstream
      United States .............................................        15,288         17,379         11,191
      International .............................................        11,296         12,157         10,264
                                                                   ------------   ------------   ------------
       Total downstream .........................................        26,584         29,536         21,455
    Emerging businesses .........................................             5              4             28
    Corporate ...................................................            --             --             --
                                                                   ------------   ------------   ------------
Total sales and other operating revenues ........................  $     38,737   $     38,737   $     27,039
                                                                   ============   ============   ============
</Table>






                                       53
<PAGE>

<Table>
<Caption>
                                                                              YEAR ENDED DECEMBER 31
                                                                   ------------------------------------------
                                                                       2001           2000           1999
                                                                   ------------   ------------   ------------
                                                                                (IN MILLIONS)
<S>                                                                <C>            <C>            <C>
AFTER-TAX OPERATING INCOME
   Upstream
      United States .............................................  $        987   $        719   $        322
      International .............................................           824          1,148            534
                                                                   ------------   ------------   ------------
       Total upstream ...........................................         1,811          1,867            856
   Downstream
      United States .............................................           329            182            119
      International .............................................            86            230            129
                                                                   ------------   ------------   ------------
       Total downstream .........................................           415            412            248
    Emerging businesses .........................................           (90)           (69)           (35)
    Corporate ...................................................          (201)          (104)           (98)
                                                                   ------------   ------------   ------------
       Total after-tax operating income .........................         1,935          2,106            971
   Interest and other non-operating expenses net of tax .........          (346)          (204)          (227)
                                                                   ------------   ------------   ------------
Net income ......................................................  $      1,589   $      1,902   $        744
                                                                   ============   ============   ============
</Table>



   SPECIAL ITEMS

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

<Table>
<Caption>
                                                                                    YEAR ENDED DECEMBER 31
                                                                             ------------------------------------
                                                                                2001         2000         1999
                                                                             ----------   ----------   ----------
                                                                                        (IN MILLIONS)
<S>                                                                          <C>          <C>          <C>
UPSTREAM
   Asset sales ............................................................  $      134   $       27   $       --
   Affiliate sales and write-downs ........................................          23           --           --
   Cumulative effect of accounting change .................................          40           --           --
   Assets held for sale and other write-downs .............................        (131)          --           --
                                                                             ----------   ----------   ----------
        Total upstream ....................................................          66           27           --
DOWNSTREAM
   Affiliate sales and write-downs ........................................         (46)          --           --
   Inventory write-downs ..................................................          --          (24)          --
   Cumulative effect of accounting change .................................          (3)          --           --
   Assets held for sale and other write-downs .............................          --           (3)          --
   Humber fire repairs ....................................................         (54)          --           --
   Litigation .............................................................         (41)         (16)         (18)
                                                                             ----------   ----------   ----------
        Total downstream ..................................................        (144)         (43)         (18)
EMERGING BUSINESSES
   Affiliate sales and write-downs ........................................          --          (26)          --
                                                                             ----------   ----------   ----------
        Total emerging businesses .........................................          --          (26)          --
CORPORATE
   Discontinued businesses ................................................         (70)          (4)         (20)
   Other ..................................................................          (4)          --           --
                                                                             ----------   ----------   ----------
        Total corporate ...................................................         (74)          (4)         (20)
INTEREST AND OTHER NON-OPERATING EXPENSES NET OF TAX
   Foreign currency exchange loss .........................................         (38)          --           --
   Premium on debt retirement .............................................         (44)          --           --
                                                                             ----------   ----------   ----------
        Total interest and other non-operating expenses net of tax ........         (82)          --           --
                                                                             ----------   ----------   ----------
Total special items .......................................................  $     (234)  $      (46)  $      (38)
                                                                             ==========   ==========   ==========
</Table>

     Special items in 2001 included gains of $194 million, consisting of:




                                       54
<PAGE>

     o    $134 million from the sale of several shallow Gulf of Mexico
          properties;

     o    $23 million from the sale of our interest in the Pocahontas Gas
          Partnership; and

     o    $37 million from a cumulative transition gain recorded on January 1,
          2001, upon initial adoption of SFAS No. 133, as amended.

     The cumulative transition gain of $37 million included a $40 million gain
in upstream related to changes in the fair value of certain crude oil put
options from their purchase date to the January 1, 2001, adoption of the
aforementioned standards and a $3 million charge in U.S. downstream associated
with various derivatives. The $40 million upstream transition gain consisted of
$8 million that was U.S. related and $32 million that was related to
international operations. Offsetting this transition gain and included in net
income for upstream was a $53 million expense for 2001 related to changes in the
fair value of these same crude oil put options. The $53 million expense for 2001
consisted of $10 million for U.S. operations and $43 million for international
operations.

     Offsetting these gains were:

     o    upstream assets held for sale and other write-downs of $131 million,
          consisting of a $44 million write-down of certain U.S. producing
          assets held for sale and an $87 million write-down of Canadian legacy
          assets held for sale;

     o    downstream affiliate sales and write-downs of $46 million, consisting
          of a $23 million write-down of a U.S. joint-venture investment held
          for sale and a $23 million write-down of an international
          joint-venture investment held for sale;

     o    a $54 million charge to record repairs and other costs associated with
          the April 16, 2001, explosion and fire at our Humber refinery in North
          Lincolnshire, U.K.;

     o    a $41 million charge related to an adverse ruling on the patent
          dispute with General Technology Applications (GTA);

     o    an accrual of $70 million for a litigation settlement for a
          discontinued business related to the separation agreement from DuPont;

     o    $4 million in costs associated with the ConocoPhillips merger;

     o    a $38 million foreign currency exchange loss from changes in the fair
          value of Canadian dollar forward exchange contracts related to the
          acquisition of Gulf Canada; and

     o    $44 million for extraordinary item charges for premiums on the early
          repayment of high-cost Gulf Canada debt.

     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
business built on centralized, large-scale gas processing systems.

     The following charges also were recorded during 2000:

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

     o    assets held for sale and other write-downs of $3 million for U.S.
          refinery assets;

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

     o    affiliate sales and write-downs of $26 million; and

     o    $4 million from discontinued businesses.

     The $24 million write-down of inventories at year-end 2000 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 $33.00 per barrel to $23.00 per barrel during
December.

     The after-tax affiliate sales and other write-downs were the result of our
write-off of $26 million related to our 37.5 percent interest in a Colombian
power venture. The Colombian power venture write-off was due to






                                       55
<PAGE>
unfavorable business conditions in Colombia. In October 1996, Conoco Global
Energy purchased shares in a Colombian power venture that was formed to generate
and market electric power by means of a gas-fired electrical generating facility
near Barrancabermeja, Colombia. The gas-fired plant became operational in August
1998 and received capacity payments for idle periods. With the deterioration of
the Colombian economy, the plant suffered small losses in 1998 and 1999. The
continued weak demand for electricity created a large surplus in generating
capacity, prompting a reduction in the capacity payment rate for 2000. A
combination of lower capacity payment revenue, continued weak demand for
electricity, onerous gas supply contract provisions, safety and security
concerns from continued guerrilla activity and forecasted losses for 2000
prompted management's decision in the third quarter of 2000 to exit the venture,
resulting in a revaluation of the investment. After pursuing various options,
Conoco's interest was sold in February 2001 for a nominal amount.

     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.

     Net income before special items (earnings before special items) totaled
$1,823 million in 2001, $1,948 million in 2000 and $782 million in 1999.

   2001 VERSUS 2000

     Conoco's 2001 net income of $1,589 million was down 16 percent from $1,902
million in 2000. Earnings before special items of $1,823 million in 2001 were 6
percent lower than the $1,948 million in 2000. The decrease in earnings before
special items was predominantly the result of lower worldwide crude oil prices,
higher operating and overhead costs and higher depreciation, depletion and
amortization (DD&A), partly offset by higher worldwide natural gas prices and
strong U.S. refining margins in the first six months of 2001 and increased
production.

     Sales and other operating revenues of $38,737 million in 2001 were
unchanged from 2000. Downstream sales and other operating revenues were $26,584
million, down 10 percent compared to $29,536 million in 2000. Crude oil and
refined product buy/sell and natural gas resale activities in 2001 totaled
$9,509 million, up 5 percent compared to $9,044 million in 2000. The increase
was primarily due to higher natural gas prices in the first six months of 2001
and increased natural gas volumes.

     Income from equity affiliates for 2001 was $181 million, down $96 million,
or 35 percent, compared to $277 million in 2000. Lower prices for heavy crude
reduced our earnings from Petrozuata by $95 million and from Polar Lights, our
Russian joint venture, by $35 million in 2001 compared to 2000. This was
partially offset by an increase in our earnings from the Pocahontas Gas
Partnership in the first nine months of the year due to strong natural gas
prices; reduced losses from the Melaka, Malaysia, refinery; and increased
earnings from Excel Paralubes.

     Other income for 2001 was $621 million, up 127 percent from $273 million in
2000. The increase in other income was primarily due to a gain of $283 million
on natural gas and crude oil hedges (that were not afforded hedge accounting
treatment) associated with the Gulf Canada acquisition and a gain of $214
million from the sale of shallow-water Gulf of Mexico properties, partially
offset by an $84 million charge related to changes in the fair value of certain
crude oil options from January 1, 2001, to December 31, 2001, and a $59 million
foreign currency loss associated with the Gulf Canada acquisition.

     Cost of goods sold totaled $23,043 million in 2001, a decrease of 4 percent
compared to $23,921 million in 2000. The decrease was primarily due to lower
feedstock costs associated with lower crude oil prices for the last six months
of 2001.

     Operating expenses were $3,053 million in 2001, up 38 percent from $2,215
million for 2000, primarily attributable to our Gulf Canada acquisition, higher
energy costs experienced by our downstream operations, higher volume-related and
price-related operating costs, and higher transportation and tariff charges
experienced by our upstream operations.

     Selling, general and administrative expenses for 2001 amounted to $888
million, up 12 percent compared to $794 million in 2000. The increase was
related to our Gulf Canada acquisition and higher computer services expenses.




                                       56
<PAGE>

     In 2001, exploration expenses totaled $378 million, an increase of $99
million, or 35 percent, compared to $279 million in 2000. The higher expenses
were primarily a result of our Gulf Canada acquisition.

     DD&A for 2001 totaled $1,811 million, an increase of $510 million, or 39
percent, compared to $1,301 million in 2000, principally due to our Gulf Canada
acquisition. The remainder of the increase was due to write-downs of $197
million related to certain North American upstream producing assets held for
sale and changes in rates and field mix.

     Provision for income taxes for 2001 was $1,391 million, a decrease of 11
percent compared to $1,556 million for 2000. This decrease was primarily the
result of lower pretax income in 2001. The effective tax rate in 2001 was
approximately 47 percent versus 45 percent in 2000. The higher effective tax
rate was due to a greater portion of 2001 earnings being generated by operations
in countries with higher effective tax rates.

   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.

     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.

     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




                                       57
<PAGE>

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.

UPSTREAM SEGMENT RESULTS

<Table>
<Caption>
                                                      YEAR ENDED DECEMBER 31
                                          ------------------------------------------
                                              2001           2000           1999
                                          ------------   ------------   ------------
                                                       (IN MILLIONS)
<S>                                       <C>            <C>            <C>
After-tax operating income
   United States .......................  $        987   $        719   $        322
   International .......................           824          1,148            534
                                          ------------   ------------   ------------
     After-tax operating income ........         1,811          1,867            856
Special items
   United States .......................          (121)           (27)            --
   International .......................            55             --             --
                                          ------------   ------------   ------------
     Special items .....................           (66)           (27)            --
Earnings before special items
   United States .......................           866            692            322
   International .......................           879          1,148            534
                                          ------------   ------------   ------------
Earnings before special items ..........  $      1,745   $      1,840   $        856
                                          ============   ============   ============
</Table>

     The following table sets forth for Conoco, including 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, 2001. Average sales prices
exclude proceeds from sales of interests in oil and gas properties.

<Table>
<Caption>
                                                           UNITED                  CONSOLIDATED   EQUITY      TOTAL
                                                           STATES         INT'L.     COMPANIES   COMPANIES  WORLDWIDE
                                                         ----------     ---------- ------------ ----------  ----------
                                                                              (UNITED STATES DOLLARS)
<S>                                                      <C>            <C>         <C>         <C>         <C>
FOR THE YEAR ENDED DECEMBER 31, 2001
 Average production costs per barrel of oil
   equivalent of petroleum produced (1) ...............  $     5.23     $     5.02  $     5.08  $     6.71  $     5.25
 Average sales prices of produced petroleum
   Per barrel of crude oil and condensate sold ........       23.95(2)       22.69       22.89       13.16       21.14
   Per mcf of natural gas sold ........................        4.13(2)        3.09        3.51        4.61        3.52
FOR THE YEAR ENDED DECEMBER 31, 2000
 Average production costs per barrel of oil
   equivalent of petroleum produced (1) ...............  $     4.17     $     3.90  $     4.00  $     5.43  $     4.13
 Average sales prices of produced petroleum
   Per barrel of crude oil and condensate sold ........       27.72          27.65       27.67       18.21       26.08
   Per mcf of natural gas sold ........................        3.42           2.75        3.06        3.77        3.07
FOR THE YEAR ENDED DECEMBER 31, 1999
 Average production costs per barrel of oil
   equivalent of petroleum produced (1) ...............  $     3.60     $     4.13  $     3.93  $     5.53  $     4.04
 Average sales prices of produced petroleum
   Per barrel of crude oil and condensate sold ........       17.33          17.55       17.51       13.86       17.09
   Per mcf of natural gas sold ........................        1.98           2.27        2.12        2.35        2.12
</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.

(2)  Includes favorable U.S. hedging effect of $38 million or $1.29 per barrel
     for crude oil and condensate sold and $.05 per mcf for natural gas sold.

     The following table sets forth for Conoco the average production cost per
barrel of Canadian Syncrude produced and average sales price per barrel of
Canadian Syncrude sold from the Canadian Syncrude project in Canada.



                                       58
<PAGE>




<Table>
<Caption>
                                                                                    AMOUNT
                                                                                   ----------
                                                                                    (UNITED
                                                                                     STATES
                                                                                    DOLLARS)
<S>                                                                                <C>
CANADIAN SYNCRUDE
FOR THE SIX MONTHS ENDED DECEMBER 31, 2001
    Average production costs per barrel of Canadian Syncrude produced...........   $    11.34
    Average sales price per barrel of Canadian Syncrude sold....................        21.98
</Table>

   2001 VERSUS 2000

     Upstream after-tax operating income was $1,811 million in 2001, down 3
percent from $1,867 million in 2000, principally due to lower crude oil prices
and higher operating and overhead costs and DD&A resulting from the Gulf Canada
acquisition. These factors were partly offset by stronger gas prices in the
first six months of 2001, increased production volumes and gains from natural
gas and crude oil hedges associated with the Gulf Canada acquisition. Upstream
earnings before special items were $1,745 million in 2001, a decrease of 5
percent from $1,840 million in 2000.

     Including equity affiliates, Conoco's worldwide net realized crude oil
price was $21.14 per barrel for 2001, a reduction of $4.94 per barrel, or 19
percent, versus $26.08 per barrel for 2000, primarily driven by a decrease in
demand for oil and an increase in inventory levels. Worldwide net realized
natural gas prices, including equity affiliates, averaged $3.52 per mcf for
2001, compared to $3.07 per mcf for 2000, an improvement of 15 percent. U.S.
natural gas prices increased from $3.42 per mcf in 2000 to $4.13 per mcf in
2001, up 21 percent, while international natural gas prices averaged $3.09 per
mcf in 2001, up 12 percent from $2.75 per mcf in 2000. The increase in U.S. gas
prices was largely due to increased demand during the first quarter of 2001.
Worldwide petroleum liquids production in 2001, including Conoco's share from
its equity affiliates, but excluding Canadian Syncrude, was 422,000 barrels per
day versus 370,000 barrels per day in 2000, a 14 percent increase. Canadian
Syncrude production for the last six months of 2001 averaged 20,000 barrels per
day. Conoco's 2001 worldwide natural gas production, including its share from
equity affiliates, was up 19 percent to 2,030 million cubic feet (mmcf) per day
from 2000 production of 1,705 mmcf per day. Conoco's total net hydrocarbon
production, including its share from equity affiliates and including Canadian
Syncrude, was 770,000 BOE per day, an increase of 18 percent over 2000.

     U.S. upstream earnings before special items totaled $866 million in 2001,
an increase of 25 percent, from $692 million in 2000. The increase was largely
due to higher natural gas prices and natural gas and crude oil hedging gains.
These improvements were partly offset by lower crude oil prices, higher
production operating and overhead costs and higher DD&A associated with field
mix. U.S. petroleum liquids production, including Conoco's share from its equity
affiliates, was down 7,000 barrels per day to 73,000 barrels per day, due to
natural field decline in the Gulf Coast and Mid-Continent regions. U.S. natural
gas production, including Conoco's share from its equity affiliates, was 811
mmcf per day, 3 mmcf less than in 2000, due primarily to natural field decline.
U.S. production costs were $5.23 per BOE, up $1.06 per BOE, compared to $4.17
per BOE in 2000, primarily due to a reclassification of transportation charges
from sales and other operating revenues to operating costs.

     International upstream earnings before special items were $879 million, an
impairment of 23 percent, from $1,148 million in 2000. This was primarily due to
lower crude oil prices, higher production operating and overhead costs related
to the Gulf Canada acquisition, higher DD&A due to the Gulf Canada acquisition
and higher exploration expenses and dry hole costs. These factors were partly
offset by higher petroleum liquids production. International petroleum liquids
production, including our share from equity affiliates and including Canadian
Syncrude, increased 24 percent, or 69,000 barrels per day, to 359,000 barrels
per day in 2001. The increase is primarily attributable to the acquisition of
Gulf Canada. In addition, there was increased production from both Vietnam,
where there were additional wells producing, and Petrozuata, where the upgrader
is operational. These increases were partly offset by decreases in Russia. In
2001, the 1,219 mmcf per day of international natural gas production, including
our share from equity affiliates, was up 37 percent, or 328 mmcf per day, over
2000, due primarily to our Gulf Canada acquisition, offset by lower production
from the Murdoch field, Miller field and V fields in the North Sea.
International production costs were $5.02 per BOE, up 29 percent from $3.90 per
BOE in 2000, due to our Gulf Canada acquisition and increased pipeline charges
in the U.K.

   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


                                       59
<PAGE>
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, Louisiana, 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, including equity affiliates,
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 $1.98 per mcf
in 1999 to $3.42 per mcf in 2000, up 73 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 mmcf per day from 1999 production of 1,660
mmcf 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 mmcf
per day, 66 mmcf per day less than in 1999, due primarily to the disposition of
our Grand Isle assets and natural field decline. U.S. production costs were
$4.17 per BOE, up $.57 per BOE, compared to $3.60 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 mmcf per day of international natural gas production, including
our share from equity affiliates, was up 14 percent, or 111 mmcf 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 field, Vampire field and V
fields in the North Sea. International production costs were $3.90 per BOE, down
6 percent from $4.13 per BOE in 1999, due to higher production volumes in Norway
and the U.K.

DOWNSTREAM SEGMENT RESULTS

<Table>
<Caption>
                                                  YEAR ENDED DECEMBER 31
                                               ----------------------------
                                                 2001      2000      1999
                                               --------  --------  --------
                                                       (IN MILLIONS)
<S>                                            <C>       <C>       <C>
After-tax operating income
   United States ............................  $    329  $    182  $    119
   International ............................        86       230       129
                                               --------  --------  --------
   After-tax operating income ...............       415       412       248
Special items
   United States ............................        67        19        18
   International ............................        77        24        --
                                               --------  --------  --------
   Special items ............................       144        43        18
Earnings before special items
   United States ............................       396       201       137
   International ............................       163       254       129
                                               --------  --------  --------
Earnings before special items ...............  $    559  $    455  $    266
                                               ========  ========  ========
</Table>





                                       60
<PAGE>

   2001 VERSUS 2000

     Downstream after-tax operating income was $415 million in 2001, up 1
percent compared to $412 million in 2000. Downstream earnings before special
items totaled $559 million in 2001, an increase of 23 percent from $455 million
in 2000.

     In 2001, U.S. downstream earnings before special items totaled $396
million, which was $195 million, or 97 percent, higher than $201 million in
2000. The increase was attributable to significantly improved inland refining
margins, wider price differentials between light and heavy crude oil and
stronger margins for co-products, such as petroleum coke and asphalt. This was
partly offset by higher operating and overhead costs, including increased energy
costs in the first half of 2001.

     International downstream earnings before special items were $163 million in
2001, a decrease of 36 percent from $254 million in 2000, reflecting lower
refining margins.

     Conoco's refineries operated at 88 percent capacity in 2001 versus 93
percent in 2000. The decrease is primarily due to downtime resulting from the
April explosion and fire at our U.K. Humber refinery.

   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 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.

EMERGING BUSINESSES SEGMENT RESULTS

<Table>
<Caption>
                                           YEAR ENDED DECEMBER 31
                                     ------------------------------------
                                        2001         2000        1999
                                     ----------   ----------   ----------
                                                (IN MILLIONS)
<S>                                  <C>          <C>          <C>
After-tax operating losses ........  $      (90)  $      (69)  $      (35)
Special items .....................          --           26           --
                                     ----------   ----------   ----------
Losses before special items .......  $      (90)  $      (43)  $      (35)
                                     ==========   ==========   ==========
</Table>

   2001 VERSUS 2000

     Emerging businesses after-tax operating losses were $90 million in 2001, an
impairment of $21 million from losses of $69 million in 2000, primarily
resulting from increased research and development costs and operating expenses
required to grow these new businesses. Emerging businesses operating losses
before special items for 2001 were $90 million, up $47 million from the $43
million loss in 2000.

   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




                                       61
<PAGE>

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.

CORPORATE SEGMENT RESULTS


<Table>
<Caption>
                                             YEAR ENDED DECEMBER 31
                                     ------------------------------------
                                        2001         2000        1999
                                     ----------   ----------   ----------
                                                (IN MILLIONS)
<S>                                  <C>          <C>          <C>
After-tax losses ..................  $     (201)  $     (104)  $      (98)
Special items .....................          74            4           20
                                     ----------   ----------   ----------
Losses before special items .......  $     (127)  $     (100)  $      (78)
                                     ==========   ==========   ==========
</Table>

   2001 VERSUS 2000

     Corporate after-tax losses were $201 million in 2001, an impairment of $97
million from losses of $104 million in 2000. Corporate losses before special
items for 2001 were $127 million, an impairment of $27 million from $100 million
in 2000, reflecting higher information technology costs, increased compensation
and increased legal fees.

   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.

INTEREST AND OTHER NON-OPERATING EXPENSES NET OF TAX

<Table>
<Caption>
                                                      YEAR ENDED DECEMBER 31
                                               ------------------------------------
                                                  2001         2000         1999
                                               ----------   ----------   ----------
                                                          (IN MILLIONS)
<S>                                            <C>          <C>          <C>
Interest expense on debt ....................  $     (365)  $     (277)  $     (243)
Interest income .............................          63           35           10
Exchange gains (losses) .....................         (33)          38            6
Other .......................................         (11)          --           --
                                               ----------   ----------   ----------
Expenses net of tax .........................        (346)        (204)        (227)
Special items ...............................          82           --           --
                                               ----------   ----------   ----------
Expenses net of tax before special items ....  $     (264)  $     (204)  $     (227)
                                               ==========   ==========   ==========
</Table>

   2001 VERSUS 2000

     Interest and other non-operating expenses before special items of $264
million for 2001 were up $60 million, or 29 percent, versus $204 million in
2000, primarily due to an increase in interest expense brought on by additional
debt incurred to acquire Gulf Canada, and lower foreign currency exchange gains,
partially offset by higher interest income.

   2000 VERSUS 1999

     Interest and other non-operating expenses before special items 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.

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. Estimated pretax environmental
expenses charged to current operations totaled about $253 million in 2001,
compared to approximately $165 million in 2000 and $127 million in 1999. These
expenses include remediation accruals; operating, maintenance and






                                       62
<PAGE>

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 66 percent of total annual environmental expenses in
2001 resulted from our U.S. operations. The 2001 increase in pretax
environmental expenses was attributable partly to additions from the Gulf Canada
acquisition.

     Capital expenditures for environmental control facilities totaled
approximately $79 million in 2001, compared to approximately $115 million in
2000 and $81 million in 1999. The 2001 decrease was attributable primarily to a
capital spending decrease in European downstream operations as capital projects
have been completed to comply with regulations requiring cleaner-burning fuels.
We estimate that worldwide capital expenditures will be about $137 million in
2002, including initial expenditures to comply with the new Clean Air Act (CAA)
Tier II Fuels regulations and planned expenditures to lower emissions of
pollutants from our four U.S. refineries. Over the next seven years, we also
will spend an estimated $95 million to $100 million for capital improvements at
our U.S. refineries to install control technology and equipment to reduce
emissions from stacks, vents, valves, heaters, boilers and flares.

     The new CAA Tier II Fuels regulations pertaining to gasoline fuels,
finalized by the United States Environmental Protection Agency (USEPA) in early
2000, and the regulations pertaining to on-road diesel fuels, finalized by the
USEPA in early 2001, require substantially reduced sulfur levels. Conoco is
positioning itself to be able to supply the low-sulfur gasoline according to the
phase-in schedule. While the on-road diesel regulations have been finalized, the
regulations controlling the future sulfur content of off-road diesel fuel
emissions have not been issued. This has complicated estimating diesel
compliance costs because those two products are inherently tied in the refining
process. New technologies also are being developed in the industry that may
lower the capital costs. Conoco continues to assess the compliance costs
associated with the Tier II Fuels regulations, and while it may be premature to
estimate these costs accurately, we expect to average less than 20 percent to 25
percent of our yearly downstream capital spending over the next six years to
install the appropriate equipment. Similarly, the European Parliament enacted
legislation in October 1998 that, among other things, required phased reductions
of the sulfur and aromatics content in gasoline and diesel fuel and of benzene
in gasoline. Our European refineries already are in compliance with the first
level of sulfur reduction and we already have the ability to produce some of the
2005 specification gasoline and diesel at both the Humber and MiRO refineries.
The costs to comply with the 2005 specifications will not be significant. We
also are studying the possibility of producing 2011 specification products well
in advance of that required date.

     Conoco does not anticipate substantial additional expenditures to comply
with Maximum Achievable Control Technology II (MACT II) standards expected to be
promulgated by the USEPA under the CAA in 2002.

   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), and often referred to as
"Superfund," the cost of corrective action activities under the RCRA corrective
action program typically is 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 $63 million in 2001, $34 million in 2000 and $33 million
in 1999. 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 the USEPA 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, 2001, Conoco had been notified of
potential liability under CERCLA or comparable state law at about 22 sites
around the U.S., with active remediation under way at six of those sites. Conoco
received notice of







                                       63
<PAGE>

potential liability at five new sites during 2001, compared with two similar
notices in 2000 and four in 1999. Expenditures associated with CERCLA and
similar state remediation activities were not significant for Conoco in 2001,
2000 or 1999.

     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 increased materially. 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 $33 million in 2001, $25 million in 2000 and $26 million in 1999. 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 such expenditures.

   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, 2001.

     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, 2001, Conoco's balance sheet included an accrued liability of $157
million, compared to $119 million at year-end 2000, for future site remediation
costs. These expenditures are expected to be incurred over the next 10 years.
Approximately 90 percent of Conoco's environmental reserve at December 31, 2001,
was attributable to RCRA and similar remediation liabilities (including
voluntary remediation) and 10 percent to CERCLA liabilities. During 2001,
remediation accruals resulted in a $44 million charge, compared to a $35 million
charge in 2000 and a $6 million charge in 1999. Conoco also assumed
environmental remediation liabilities with the purchase of Gulf Canada in the
third quarter of 2001. These liabilities totaled $27 million at December 31,
2001, and were discounted at 5 percent.

TAX MATTERS

     In connection with the separation from DuPont and the initial public
offering, Conoco and DuPont entered into a Tax Sharing Agreement and a
Restructuring, Transfer and Separation Agreement. Certain disputes arose under
these agreements and on November 8, 2001, these matters were settled. The $93
million net effect of this settlement is included in additional paid-in capital
as an adjustment to capitalization from DuPont in our consolidated financial
statements.

EUROPEAN MONETARY UNION

     The European Economic and Monetary Union (EMU) introduced a new currency,
the euro, on January 1, 1999. The new currency was established 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.




                                       64
<PAGE>

     The euro was initially available for currency trading on currency exchanges
and non-cash (banking) transactions for the 12 EMU countries that adopted it as
their local currency. On January 1, 2002, euro-denominated notes and coins were
issued for cash transactions. The existing local currencies, or legacy
currencies, remain legal tender during a "dual-circulation" period. During the
dual-circulation period, both legacy currencies and the euro can be used for
transactions. However, when legacy currencies are offered, any change returned
is in euro. At the end of the dual-circulation period, the legacy currencies
will be withdrawn from circulation, but can be exchanged for euros at specified
banks.

     Generally the dual-circulation period is from January 1, 2002, until
February 28, 2002. Exceptions to this general rule are listed below:

     o    Germany - no official dual-circulation period;

     o    France - February 17, 2002;

     o    Ireland - February 9, 2002; and

     o    the Netherlands - January 28, 2002.

     Conoco operates in a number of countries that are participating in the EMU,
including Austria, Belgium, Finland and Germany, and uses the euro in business
transactions with other EMU countries.

     Conoco prepared for the impact of the euro's introduction on areas such as
operations, finance, treasury, legal, information management, procurement and
others, both in participating and non-participating European Union (EU)
countries where Conoco currently operates. Existing legacy accounting and
business systems and other business assets were upgraded or replaced as
necessary for euro compliance. Out of the three non-participating EU countries,
Conoco has a significant presence only in the U.K., where the British pound
continues to be the local currency.

     Because of the staged introduction of the euro regarding non-cash and cash
transactions, we addressed our accounting and business systems first and our
business assets second. During 2001, we implemented a new converged SAP system
for our Refining & Marketing Europe organization that is euro compliant. As of
October 2001, all operations in EMU countries were using the new system for
accounting and reporting. By December 31, 2001, corresponding business assets
were compliant and capable of conducting business with euro notes and coins.
Amounts spent for our conversion to the euro were not material.

     Conoco has not experienced any operational disruptions as the result of the
introduction of the euro. 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

     During 1999, 704 employees left Conoco as part of the implementation of our
1998 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 of 1999. Total charges and adjustments
to the reserve during 1999 were $71 million, resulting in a December 31, 1999,
reserve balance of $11 million.

     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.

RECENT ACCOUNTING STANDARDS


     In early July 2001, the FASB issued SFAS No. 141, "Business Combinations,"
and SFAS No. 142, "Goodwill and Other Intangible Assets," which revise the
accounting for business combinations by requiring that the purchase method of
accounting be used on all business combinations initiated after June 30, 2001,
and that separately





                                       65
<PAGE>

identified intangible assets be recorded as assets. In addition, goodwill must
be tested at least annually for impairment and is no longer amortized.

     SFAS No. 141 was applicable to our 2001 acquisition of Gulf Canada. SFAS
No. 142 was adopted on January 1, 2002. The goodwill we recorded with the
acquisition of Gulf Canada, which occurred prior to our adoption of SFAS No.
142, was subject to review for impairment under the provisions of APB Opinion
No. 17, "Intangible Assets," and SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." No impairment
was recognized on goodwill at December 31, 2001. The impact of these standards
on existing goodwill from previous acquisitions is not material.

     The FASB also recently issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." This statement significantly changes the method of
accruing for costs, associated with the retirement of fixed assets (e.g., oil
and gas production facilities and oil and gas properties, etc.), that an entity
is legally obligated to incur. We will further evaluate the impact and timing of
implementing SFAS No. 143. Implementation of this standard is required no later
than January 1, 2003, with earlier adoption encouraged.

     In October 2001, the FASB approved SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," which clarified certain
implementation issues arising from SFAS No. 121. This standard was adopted on
January 1, 2002, and there was no impact upon adoption.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

GENERAL

     We operate in the worldwide crude oil, refined product, natural gas,
natural gas liquids and electric power markets and are exposed to fluctuations
in hydrocarbon and power prices, foreign currency rates and interest rates.
These fluctuations can affect revenues and the cost of operating, investing and
financing. Our 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.

     We have established a Risk Management Policy that provides guidelines for
entering into contractual arrangements (derivatives) to manage our commodity
price, foreign currency rate and interest rate risks. The Conoco Risk Management
Committee, composed of certain senior officers of the company, has:

     o    an ongoing responsibility for the content of this policy;

     o    principal oversight responsibility to ensure that we are 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. We have not experienced any
material nonperformance by counterparties to these contracts, and no material
loss would be expected from any such nonperformance. Our exposure to the recent
Enron Corp. bankruptcy is not material.

COMMODITY PRICE RISK

     We enter into energy-related futures, forwards, swaps and options in
various markets:




                                       66
<PAGE>
     o    to balance our physical systems -- In addition to being able to settle
          exchange traded futures contracts in cash prior to contract expiry,
          they also can be settled by physical delivery of the commodity. These
          barrels can provide another source of supply to our physical or "wet
          barrel" pool to meet refinery requirements or marketing demand;

     o    to meet customer needs -- Consistent with our policy to generally
          remain exposed to market prices, we use swap contracts to convert
          fixed price sales contracts (often requested by natural gas and
          refined product consumers) to a floating market basis; and

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

     Our 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 our equity crude oil
and natural gas production, as well as our refinery margins. Specifically, in
conjunction with the Gulf Canada acquisition, we initiated an extensive hedging
program to mitigate volatile crude oil and natural gas prices through the
purchase of derivative instruments.

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

<Table>
<Caption>
                                                       CHANGE IN FAIR
                                                            VALUE
                                                      FROM 10% ADVERSE
                                        FAIR VALUE      PRICE CHANGE
                                     ---------------  ----------------
                                               (IN MILLIONS)

<S>                                  <C>              <C>
COMMODITY DERIVATIVES (1)
AT DECEMBER 31, 2001
Crude oil and refined products
   Trading ........................  $            --  $            (3)
   Non-trading  (2) ...............              264             (105)
                                     ---------------  ---------------
Combined ..........................  $           264  $          (108)
                                     ===============  ===============
Natural gas and electricity
   Trading ........................  $            --  $            (1)
   Non-trading  (3) ...............               74               (8)
                                     ---------------  ---------------
Combined ..........................  $            74  $            (9)
                                     ===============  ===============
AT DECEMBER 31, 2000
Crude oil and refined products
   Trading ........................  $             1  $             1
   Non-trading (4) ................               92              (29)
                                     ---------------  ---------------
Combined ..........................  $            93  $           (28)
                                     ===============  ===============
Natural gas and electricity
   Trading ........................  $             3  $             2
   Non-trading ....................              103              (33)
                                     ---------------  ---------------
Combined ..........................  $           106  $           (31)
                                     ===============  ===============
</Table>

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

(2)  Includes collars with a $24.04 floor price and a $26.54 cap price (West
     Texas Intermediate equivalent) on 54.5 million barrels for the period
     October 2001 through December 2002.

     Includes swaps at $25.30 on 18.3 million barrels for the period October
     2001 through December 2002.

(3)  Includes collars with a $4.00 floor price and a $4.60 cap price (NYMEX
     equivalent) on approximately 120,000 mmbtu per day for the period October
     2001 through December 2002.

     Includes swaps at $4.02 on approximately 100,000 mmbtu per day for the
     period October 2001 through December 2002.

(4)  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 publicly quoted
market prices obtained from the New York Mercantile Exchange (NYMEX) or the
International Petroleum Exchange of London. The fair values of swaps and


                                       67
<PAGE>

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.

EXCHANGE AND NON-EXCHANGE TRADED CONTRACTS ACCOUNTED FOR AT FAIR VALUE

<Table>
<Caption>
                                                                         EXCHANGE   NON-EXCHANGE
                                                                          TRADED       TRADED       TOTAL
                                                                        ----------   ----------   ----------
                                                                                   (IN MILLIONS)
<S>                                                                     <C>          <C>          <C>
Fair value of contracts outstanding at the beginning of the period ...  $        8   $      191   $      199
Contracts realized or otherwise settled during the period ............         (28)        (108)        (136)
Fair value of new contracts when entered into during the period ......          --          (28)         (28)
Changes in fair value values attributable to changes in valuation
   techniques ........................................................          --           --           --
Other changes in fair values .........................................          16          287          303
                                                                        ----------   ----------   ----------
Fair value of contracts outstanding at the end of the period .........  $       (4)  $      342   $      338
                                                                        ==========   ==========   ==========
</Table>

<Table>
<Caption>
                                                      FAIR VALUE OF CONTRACTS AT PERIOD-END
                                          -------------------------------------------------------------
                                                                                 MATURITY IN
                                         MATURITY UP    MATURITY     MATURITY     EXCESS OF   TOTAL FAIR
                                          TO 1 YEAR    2 - 3 YEARS  4 - 5 YEARS    5 YEARS       VALUE
                                          ----------   -----------  -----------  ----------   ----------
                                                                           (IN MILLIONS)
<S>                                       <C>          <C>          <C>          <C>          <C>
SOURCE OF FAIR VALUE
Prices actively quoted
  Exchange .............................  $       (4)  $        --  $        --   $       --  $       (4)
  Non-exchange .........................         350            (7)          (1)          --         342
                                          ----------   -----------  -----------   ----------  ----------
     Total .............................  $      346   $        (7) $        (1)  $       --  $      338
                                          ==========   ===========  ===========   ==========  ==========
Prices provided by other external
   sources .............................          --            --           --           --          --
Prices based on models and other
   valuation methods ...................          --            --           --           --          --
</Table>

     We do a limited amount of trading unrelated to our underlying physical
business, for which after-tax gains or losses have not been material.

FOREIGN CURRENCY RISK

     Conoco has foreign currency exchange rate risk resulting from operations in
over 40 countries around the world. We do not comprehensively hedge our exposure
to currency rate changes, although we may choose to selectively hedge exposures
to foreign currency rate risk. Examples include firm commitments for future
capital projects and operating costs, 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, we enter 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, 2001, the U.S.
dollar equivalent of all non-U.S. dollar notes outstanding was $29 million, all
of which were swapped to the U.S. dollar. At December 31, 2000, the U.S. dollar
equivalent of all non-U.S. dollar notes outstanding was $81 million, all of
which were swapped for the U.S. dollar.

     At December 31, 2001, we had open foreign currency exchange derivative
instruments with a notional value of $9 million related to forward currency
sales. At December 31, 2000, we had open foreign currency exchange





                                       68
<PAGE>

derivative instruments with a notional value of $45 million related to
anticipated foreign currency capital investments.

     The fair value of outstanding foreign currency hedges and the change in the
fair value that would be expected from a 10 percent adverse foreign currency
rate change are shown in the following table:

<Table>
<Caption>
                                                                                  CHANGE IN FAIR VALUE
                                                                                    FROM 10% ADVERSE
                                                                         FAIR       FOREIGN CURRENCY
                                                                         VALUE        RATE CHANGE
                                                                         -----        -----------
                                                                              (IN MILLIONS)
<S>                                                                      <C>          <C>
FOREIGN CURRENCY DERIVATIVES
AT DECEMBER 31, 2001
   Non-trading......................................................     $  --        $       (4)

AT DECEMBER 31, 2000
   Non-trading......................................................     $   2        $       (4)
</Table>

     Price-risk sensitivities were calculated by assuming an across-the-board 10
percent adverse change in foreign currency rates.

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 our total debt
portfolio and related overall cost of borrowing. Beginning in the fourth quarter
2001, we executed several interest rate swaps to increase our overall debt
portfolio's exposure to floating interest rates. These transactions included
swapping $1,650 million of fixed rate debt to floating rate debt, as well as
swapping $900 million of floating rate debt to fixed rate debt. Through these
transactions, we effectively increased our exposure to floating interest rates
on $750 million of debt. In addition to increasing our floating rate exposure,
we effectively swapped $900 million of debt to a lower fixed rate, reducing the
pretax interest rate by approximately 250 basis points.

     The fair value gain or loss of outstanding interest rate swaps and the
change in fair value that would be expected from a 10 percent adverse interest
rate change are shown in the following table:

<Table>
<Caption>
                                                            CHANGE IN FAIR
                                                                VALUE
                                                           FROM 10% ADVERSE
                                                            INTEREST RATE
                                          FAIR VALUE            CHANGE
                                       ---------------     ---------------
                                                 (IN MILLIONS)
<S>                                                        <C>
INTEREST RATE DERIVATIVES
AT DECEMBER 31, 2001
 Fixed rate to floating rate
  Notes due 2009 ..................    $           (35)    $           (52)
  Notes due 2029 ..................                (74)               (134)
                                       ---------------     ---------------
Fixed rate to floating rate .......               (109)               (186)
Floating rate to fixed rate .......                 (8)                 (1)
                                       ---------------     ---------------
Total .............................    $          (117)    $          (187)
                                       ===============     ===============
</Table>

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


                                       69
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA

                                      INDEX

<Table>
<Caption>
                                                                                                               PAGE

<S>                                                                                                           <C>
Report of Management......................................................................................      71

Audited Consolidated Financial Statements

   Report of Independent Accountants......................................................................      72

   Consolidated Statement of Income - Year Ended December 31, 2001, 2000 and 1999.........................      73

   Consolidated Balance Sheet - at December 31, 2001 and 2000.............................................      74

   Consolidated Statement of Stockholders' Equity and Accumulated Other Comprehensive
     Loss - Years Ended December 31, 2001, 2000 and 1999..................................................      75

   Consolidated Statement of Cash Flows - Year Ended December 31, 2001, 2000 and 1999.....................      76

   Notes to Consolidated Financial Statements.............................................................      77

Unaudited Financial Information

   Supplemental Petroleum Data - 2001, 2000 and 1999......................................................     113

   Consolidated Quarterly Financial Data - 2001 and 2000..................................................     122
</Table>

                                       70
<PAGE>

                              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 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, pursuant to 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,       Vice President, Controller and
      Chief Executive Officer               and Chief Financial Officer          Principal Accounting Officer
</Table>



                                       71
<PAGE>

                        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 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, 2001
and 2000, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 2001 in conformity with
accounting principles generally accepted in the United States of America. These
financial statements are the responsibility of the 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.

     As discussed in note 9 to the consolidated financial statements, in
accordance with the requirements of Statement of Financial Accounting Standards
No. 133, "Accounting for Derivative Instruments and Hedging Activities," the
Company changed its method of accounting for derivative instruments and hedging
activities effective January 1, 2001.


PRICEWATERHOUSECOOPERS LLP


Houston, Texas
February 19, 2002



                                       72
<PAGE>

                                   CONOCO INC.

                        CONSOLIDATED STATEMENT OF INCOME


<Table>
<Caption>
                                                                                    YEAR ENDED DECEMBER 31
                                                                           -----------------------------------------
                                                                              2001            2000           1999
                                                                           ----------      ----------     ----------
                                                                                (IN MILLIONS, EXCEPT PER SHARE)
<S>                                                                        <C>             <C>            <C>
Revenues
   Sales and other operating revenues* ...............................     $   38,737      $   38,737     $   27,039
   Equity in earnings of affiliates (note 15) ........................            181             277            150
   Other income (note 4) .............................................            621             273            120
                                                                           ----------      ----------     ----------
         Total revenues ..............................................         39,539          39,287         27,309
                                                                           ----------      ----------     ----------

Costs and expenses
   Cost of goods sold** ..............................................         23,043          23,921         14,781
   Operating expenses ................................................          3,053           2,215          2,060
   Selling, general and administrative expenses ......................            888             794            809
   Exploration expenses ..............................................            378             279            270
   Depreciation, depletion and amortization ..........................          1,811           1,301          1,193
   Taxes other than on income* (note 5) ..............................          6,983           6,981          6,668
   Interest and debt expense (note 6) ................................            396             338            311
                                                                           ----------      ----------     ----------
          Total costs and expenses ...................................         36,552          35,829         26,092
                                                                           ----------      ----------     ----------
Income before income taxes ...........................................          2,987           3,458          1,217
Income tax expense (note 7) ..........................................          1,391           1,556            473
                                                                           ----------      ----------     ----------
Income before extraordinary item and accounting change ...............          1,596           1,902            744
Extraordinary item, charge for the early extinguishment of debt,
    net of income taxes of $33 (note 8) ..............................            (44)             --             --
Cumulative effect of accounting change, net of income taxes of $22
    (note 9) .........................................................             37              --             --
                                                                           ----------      ----------     ----------
Net income ...........................................................     $    1,589      $    1,902     $      744
                                                                           ==========      ==========     ==========

Earnings per share (note 10)
  Basic
    Before extraordinary item and accounting change ..................     $     2.55      $     3.05     $     1.19
    Extraordinary item ...............................................           (.07)             --             --
    Cumulative effect of accounting change ...........................            .06              --             --
                                                                           ----------      ----------     ----------
                                                                           $     2.54      $     3.05     $     1.19
                                                                           ==========      ==========     ==========

  Diluted
    Before extraordinary item and accounting change ..................     $     2.51      $     3.00     $     1.17
    Extraordinary item ...............................................           (.07)             --             --
    Cumulative effect of accounting change ...........................            .06              --             --
                                                                           ----------      ----------     ----------
                                                                           $     2.50      $     3.00     $     1.17
                                                                           ==========      ==========     ==========

Weighted-average shares outstanding (note 10)
    Basic ............................................................            626             624            627
    Diluted ..........................................................            635             633            636

----------

*  Includes petroleum excise taxes ...................................     $    6,744      $    6,774     $    6,492
** Excludes refining depreciation ....................................     $      127      $      122     $      116
</Table>

          See accompanying notes to consolidated financial statements.



                                       73
<PAGE>

                                   CONOCO INC.

                           CONSOLIDATED BALANCE SHEET

<Table>
<Caption>
                                                                                            DECEMBER 31
                                                                                     --------------------------
                                                                                        2001            2000
                                                                                     ----------      ----------
                                                                                           (IN MILLIONS)
<S>                                                                                  <C>             <C>

                                                     ASSETS

Current assets
   Cash and cash equivalents ...................................................     $      388      $      342
   Accounts and notes receivable (note 11) .....................................          1,894           1,837
   Inventories (note 12) .......................................................            995             791
   Other current assets (note 13) ..............................................          1,066             441
                                                                                     ----------      ----------
         Total current assets ..................................................          4,343           3,411
Property, plant and equipment (note 14) ........................................         30,224          23,890
Less: accumulated depreciation, depletion and amortization .....................        (12,306)        (11,683)
                                                                                     ----------      ----------
Net property, plant and equipment ..............................................         17,918          12,207
Investment in affiliates (note 15) .............................................          1,894           1,831
Goodwill (note 3) ..............................................................          2,933              10
Other assets (note 16) .........................................................            816             668
                                                                                     ----------      ----------
Total assets ...................................................................     $   27,904      $   18,127
                                                                                     ==========      ==========

                                      LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities
   Accounts payable (note 17) ..................................................     $    1,950      $    1,723
   Short-term borrowings and capital lease obligations (note 18) ...............          1,125             256
   Income taxes (note 7) .......................................................            530             665
   Other accrued liabilities (note 19) .........................................          1,897           1,543
                                                                                     ----------      ----------
         Total current liabilities .............................................          5,502           4,187
Long-term borrowings and capital lease obligations (note 20) ...................          8,267           4,138
Deferred income taxes (note 7) .................................................          3,975           1,911
Other liabilities and deferred credits (note 21) ...............................          2,346           1,926
                                                                                     ----------      ----------
         Total liabilities .....................................................         20,090          12,162
                                                                                     ----------      ----------

Commitments and contingent liabilities (note 28)
Minority interests (note 22) ...................................................          1,204             337
Stockholders' equity (note 23)
   Preferred stock, $.01 par value
     250,000,000 shares authorized; none issued ................................             --              --
   Common stock, $.01 par value (note 23)
     4,600,000,000 shares authorized, 628,938,046 shares issued with
       625,658,528 shares outstanding at December 31, 2001; 4,599,776,271
       shares authorized, 628,284,303 shares issued with 623,432,840 shares
       outstanding at December 31, 2000 ........................................              6               6
   Additional paid-in capital ..................................................          5,044           4,932
   Retained earnings ...........................................................          2,537           1,460
   Accumulated other comprehensive loss (note 24) ..............................           (894)           (653)
   Treasury stock, at cost
     3,279,518 and 4,851,463 shares at December 31, 2001, and
       December 31, 2000, respectively .........................................            (83)           (117)
                                                                                     ----------      ----------
         Total stockholders' equity ............................................          6,610           5,628
                                                                                     ----------      ----------
Total liabilities and stockholders' equity .....................................     $   27,904      $   18,127
                                                                                     ==========      ==========
</Table>


          See accompanying notes to consolidated financial statements.


                                       74
<PAGE>

                                   CONOCO INC.

      CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY AND ACCUMULATED OTHER
                               COMPREHENSIVE LOSS

                                (NOTES 23 AND 24)

<Table>
<Caption>
                                                                           RETAINED
                                                           ADDITIONAL      EARNINGS                    ACCUMULATED OTHER
                                                  COMMON    PAID-IN     (ACCUMULATED   COMPREHENSIVE     COMPREHENSIVE     TREASURY
                                                   STOCK    CAPITAL        DEFICIT)        INCOME             LOSS           STOCK
                                                  ------   ----------   ------------   -------------   -----------------   --------
                                                                                    (IN MILLIONS)
<S>                                               <C>      <C>          <C>            <C>             <C>                 <C>

Balance January 1, 1999 ........................  $    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 DuPont .......                  (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)
Comprehensive income
   Net income ..................................                               1,589   $       1,589
   Other comprehensive income (loss)
     Foreign currency translation adjustment ...                                                (309)
     Minimum pension liability adjustment ......                                                 (19)
     Unrealized gains on derivatives ...........                                                  86
     Unrealized gain on derivatives from
      adoption of SFAS No. 133 .................                                                   1
                                                                                       -------------
       Other comprehensive loss ................                                                (241)               (241)
                                                                                       -------------
Comprehensive income ...........................                                       $       1,348
                                                                                       =============
Adjustment to capitalization from DuPont .......                   93
Dividends ......................................                                (474)
Compensation plans .............................                   24
Redemption of minority interests ...............                   (3)
Costs related to the combination of Class
 A and B stock .................................                   (2)
Treasury stock - purchases .....................                                                                                (37)
               - issuances .....................                                 (38)                                            71
                                                  ------   ----------   ------------                   -----------------   --------
Balance December 31, 2001 ......................  $    6   $    5,044   $      2,537                   $            (894)  $    (83)
                                                  ======   ==========   ============                   =================   ========
</Table>


          See accompanying notes to consolidated financial statements.


                                       75
<PAGE>

                                   CONOCO INC.

                      CONSOLIDATED STATEMENT OF CASH FLOWS

<Table>
<Caption>
                                                                                                  YEAR ENDED DECEMBER 31
                                                                                            ----------------------------------
                                                                                              2001         2000         1999
                                                                                            --------     --------     --------
                                                                                                      (IN MILLIONS)
<S>                                                                                         <C>          <C>          <C>
Cash provided by operations
    Net income .........................................................................    $  1,589     $  1,902     $    744
    Adjustments to reconcile net income to cash provided by operations
      Extraordinary item, charge for the early extinguishment of debt (note 8) .........          77           --           --
      Cumulative effect of accounting change (note 9) ..................................         (59)          --           --
      Depreciation, depletion and amortization .........................................       1,811        1,301        1,193
      Dry hole costs and impairment of unproved properties .............................         116           88          131
      Deferred tax expense (note 7) ....................................................         282          236         (111)
      Income applicable to minority interests ..........................................          23           24           25
      Gain on asset dispositions .......................................................        (311)         (72)         (20)
      Dividends received greater than (less than) equity in earnings from affiliates ...          17         (145)         (73)
      Other non-cash charges and (credits) - net .......................................         136          (87)         (18)
      Decrease (increase) in operating assets
        Accounts and notes receivable ..................................................         521         (153)        (573)
        Inventories ....................................................................        (159)        (119)          80
        Other operating assets .........................................................        (724)        (313)         107
      Increase (decrease) in operating liabilities
        Accounts and other operating payables ..........................................         132          567          639
        Income and other taxes payable .................................................        (310)         209           92
                                                                                            --------     --------     --------
           Cash provided by operations .................................................       3,141        3,438        2,216
                                                                                            --------     --------     --------
Investing activities
    Purchases of property, plant and equipment .........................................      (2,702)      (1,921)      (1,675)
    Purchase of Gulf Canada - net of cash acquired (note 3) ............................      (4,318)          --           --
    Purchases of businesses - net of cash acquired .....................................          --         (661)          --
    Investments in affiliates - additions ..............................................        (133)        (173)        (272)
                              - repayment of loans and advances ........................          14           64           45
    Proceeds from sales of assets and subsidiaries .....................................         795          222          162
    Net (increase) decrease in short-term financial instruments ........................          (3)          (3)          34
                                                                                            --------     --------     --------
           Cash used in investing activities ...........................................      (6,347)      (2,472)      (1,706)
                                                                                            --------     --------     --------
Financing activities
    Short-term borrowings (note 18) - receipts .........................................      27,048       28,091       12,778
                                    - payments .........................................     (24,147)     (28,498)     (12,156)
    Long-term borrowings (note 20) - receipts ..........................................       6,195           65        3,970
                                   - payments ..........................................      (5,802)          --          (20)
    Related-party borrowings - receipts ................................................          --           --          865
                             - payments ................................................          --           --       (5,461)
    Treasury stock - purchases .........................................................         (37)         (90)         (87)
                   - proceeds from issuances ...........................................          31           12           13
    Cash dividends .....................................................................        (474)        (474)        (445)
    Cash distribution (to) from DuPont (note 32) .......................................          93           --          (11)
    Minority interests (note 22) - receipts ............................................         488           --          326
                                 - payments ............................................         (33)         (26)        (324)
                                                                                            --------     --------     --------
           Cash provided by (used in) financing activities .............................       3,362         (920)        (552)
                                                                                            --------     --------     --------
Effect of exchange rate changes on cash ................................................        (110)         (21)         (35)
                                                                                            --------     --------     --------
Increase (decrease) in cash and cash equivalents .......................................          46           25          (77)
Cash and cash equivalents at beginning of year .........................................         342          317          394
                                                                                            --------     --------     --------
Cash and cash equivalents at end of year ...............................................    $    388     $    342     $    317
                                                                                            ========     ========     ========
</Table>


          See accompanying notes to consolidated financial statements.


                                       76
<PAGE>

                   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, and Syncrude mining
operations (Canadian Syncrude). 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.
Emerging businesses currently is involved in carbon fibers (Conoco
Cevolution(R)); natural gas refining, including gas-to-liquids; and
international power. We have five reporting segments. Four of these segments
reflect the geographic division between U.S. and international operations in our
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 Conoco's Class A common stock 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 $23.00 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.

     On September 21, 2001, Conoco's shareholders approved the combination of
Conoco's Class A and Class B common stock into a single class of new common
stock on a one-for-one basis. The combination was effective on October 8, 2001.
See note 23 for further details.

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 we exert
significant influence, generally having a 20 percent to 50 percent ownership
interest. Our 50.1 percent non-controlling 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, under which all substantive operating decisions (e.g., annual budgets,
major financings, selection of senior operating management, etc.) require joint
approvals, and therefore Conoco does not effectively control Petrozuata C.A.
Undivided interests in oil and gas properties, certain transportation assets and
Canadian Syncrude mining operations are accounted for 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; the disclosure of contingent assets and liabilities; and the
reported amounts of proved oil, gas and Canadian Syncrude reserves. 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 we have 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.



                                       77
<PAGE>

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


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 and Canadian Syncrude. 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 and Canadian Syncrude
properties, is generally computed on a straight-line basis over the estimated
economic lives (of 14 to 25 years for major assets) of the facilities. 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.

     Oil and Gas Properties

     We follow 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 that 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, well plugging and abandonment, and other site restoration costs are
accrued over the properties' productive lives using the unit-of-production
method and recognized as a liability as the amortization expense is recorded.
See note 21 for further details.

     Syncrude Mining Operations

     Capitalized costs, including support facilities, include the cost of the
acquisition and other capital costs incurred. Capital costs are depreciated
using the unit-of-production method based on the applicable portion of proven
reserves associated with each mine location and its facilities.

     Impairment of Long-lived Assets

     Long-lived assets, including oil and gas properties with recorded values
that are not expected to be recovered through future cash flows, are fully
written down to current fair value through additional amortization or
depreciation provisions in the periods in which the determination of impairments
are made. Fair value is generally determined from estimated discounted future
net cash flows.

     Capitalized Interest

     Interest from external borrowings is capitalized on major projects with an
expected construction period of one year or longer. Capitalized interest is
added to the cost of the underlying asset and is amortized over the useful lives
of the assets in the same manner as the underlying assets.



                                       78
<PAGE>

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


Maintenance and Repair Activities

     We accrue in advance for planned major maintenance. Through December 31,
2001, costs primarily related to work to be done as part of refinery turnarounds
and drydock maintenance for tankers, barges and boats are accrued and are
classified as liabilities on the balance sheet. However, effective January 1,
2002, we changed to a preferable method of accounting as recommended by the
American Institute of Certified Public Accountants' proposed Statement of
Position (SOP), "Accounting for Certain Costs and Activities Related to
Property, Plant and Equipment" and the Financial Accounting Standards Board's
(FASB) Exposure Draft, "Accounting in Interim and Annual Financial Statements
for Certain Costs and Activities Related to Property, Plant and Equipment."
Effective with this change, we began expensing all major maintenance costs as
incurred. The effect of implementation of this change is a reversal of amounts
previously accrued through December 31, 2001, of $47, which will be reported in
the first quarter of 2002 as a change in accounting principle. Minor maintenance
and repairs are charged to expense as incurred and improvements are capitalized.

Shipping and Handling Costs

     We include shipping and handling costs in cost of goods sold if they are a
component of manufacturing of refined products; otherwise they are reported as
either operating expense or cost of goods sold, depending on the nature of the
cost.

Environmental Costs

     Environmental expenditures are expensed or capitalized, as appropriate,
depending on their future economic benefit. Expenditures, which 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

     We apply 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 (as 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 25.

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.

     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 our integrated European
and Canadian petroleum operations because it is the currency of the primary
economic environment in which those entities operate. 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 resulting translation adjustment is a component of accumulated other
comprehensive loss (see note 24). 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 resulting exchange gains or losses,
together with their related tax effects, are included in income in the period in



                                       79
<PAGE>

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


which they occur. Revenues and expenses are translated into U.S. dollars at the
average exchange rates in effect during the period.

     For all other subsidiaries, 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 revenues 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.

Derivative Instruments

     Effective January 1, 2001, we follow the methods prescribed by SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities," as amended
by SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain
Hedging Activities," to account for derivative instruments. Under SFAS No. 133,
as amended (SFAS 133), all derivative instruments are recorded on the balance
sheet at their fair value. See note 9 for details on the accounting change
generated from implementing SFAS 133; note 24 for the impact of implementing
SFAS 133 on "Other comprehensive loss;" and note 27 for additional details of
the accounting for the gain or loss resulting from changes in the fair value of
derivatives designated as hedging instruments.

     Prior to the adoption of SFAS 133, derivative instruments that were
designated and qualified as hedges were recognized in income in the period in
which the underlying transaction affected earnings. Neither the hedging
contracts nor the unrealized gains or losses on these contracts were recognized
in the financial statements. All other derivative contracts were reflected at
their fair market value on the balance sheet. Changes in market values of all
other derivative contracts were reflected in income in the period in which the
change occurred.

Reclassifications

     Certain data in the prior years' financial statements have been
reclassified to conform to the 2001 presentation.

Recent Accounting Standards

     In early July 2001, the FASB issued SFAS No. 141, "Business Combinations,"
and SFAS No. 142, "Goodwill and Other Intangible Assets," which revise the
accounting for business combinations by requiring that the purchase method of
accounting be used on all business combinations initiated after June 30, 2001,
and that separately identified intangible assets be recorded as assets. In
addition, goodwill must be tested at least annually for impairment and is no
longer amortized.

     SFAS No. 141 was applicable to our 2001 acquisition of Gulf Canada
Resources Limited (Gulf Canada). SFAS No. 142 was adopted on January 1, 2002.
The goodwill we recorded with the acquisition of Gulf Canada, which occurred
prior to our adoption of SFAS No. 142, was subject to review for impairment
under the provisions of APB Opinion No. 17, "Intangible Assets," and SFAS No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of." No impairment was recognized on goodwill at December
31, 2001. The impact of these standards on existing goodwill from previous
acquisitions is not material.

     The FASB also recently issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." This statement significantly changes the method of
accruing for costs, associated with the retirement of fixed assets (e.g., oil
and gas production facilities and oil and gas properties, etc.), that an entity
is legally obligated to incur. We will further evaluate the impact and timing of
implementing SFAS No. 143. Implementation of this standard is required no later
than January 1, 2003, with earlier adoption encouraged.

     In October 2001, the FASB approved SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," which clarified certain
implementation issues arising from SFAS No. 121. This standard was adopted on
January 1, 2002, and there was no impact upon adoption.



                                       80
<PAGE>

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


3.   GULF CANADA ACQUISITION

     On July 16, 2001, Conoco, through a wholly owned subsidiary, completed the
acquisition of all the ordinary shares of Gulf Canada, now known as Conoco
Canada Resources Limited (Conoco Canada) for approximately $4,571 in cash plus
assumed liabilities and minority interests. For ease of reference, we will refer
to Conoco Canada as Gulf Canada. Prior to the acquisition, Gulf Canada was a
Canadian-based independent exploration and production company, with primary
operations in western Canada, Indonesia, the Netherlands and Ecuador. Subsequent
to the acquisition, operational responsibilities for Gulf Canada's interests in
Indonesia, the Netherlands and Ecuador were realigned within Conoco's regional
organizational structure, and operationally Conoco's existing Canadian
operations were merged with those of Gulf Canada.

     We acquired Gulf Canada to strengthen our oil and gas position in North
America, to enhance our competitive position in key regions of the world, to add
to our inventory of near- and long-term growth opportunities, to increase our
exposure to North American and European markets, and to establish southeast Asia
as our fourth core area.

     The following is a table of the calculation and allocation of the purchase
price to the assets acquired and liabilities assumed based on their relative
fair market values:

<Table>
<S>                                                                               <C>
CALCULATION OF THE PURCHASE PRICE FOR ASSETS ACQUIRED(1)
   Cash paid for stock purchased ............................................     $  4,551
   Other purchase price costs (e.g., fees, etc.) ............................           20
                                                                                  --------
     Total purchase price for common equity .................................        4,571

Plus fair market value of liabilities assumed and minority interest
   Current and other liabilities ............................................          776
   Debt .....................................................................        1,691
   Deferred tax .............................................................        1,824
   Minority interest ........................................................          552
                                                                                  --------
     Total liabilities and minority interests ...............................        4,843
                                                                                  --------

Total purchase price for assets acquired ....................................     $  9,414
                                                                                  ========

ALLOCATION OF PURCHASE PRICE FOR ASSETS ACQUIRED(1)
   Property, plant and equipment(2) .........................................     $  5,396
   Goodwill(3) ..............................................................        3,066
   All other assets, including working capital and intangibles(4) ...........          952
                                                                                  --------

Total .......................................................................     $  9,414
                                                                                  ========
</Table>

----------

(1)  The purchase price was converted from Canadian dollars to U.S. dollars at
     the July 1, 2001, exchange rate of .66. Amounts shown on the December 31,
     2001, balance sheet were converted to U.S. dollars using a .63 exchange
     rate.

(2)  Proved properties were valued at $3,549, unproved properties at $1,788 and
     other properties and equipment at $59.

(3)  None of the goodwill is deductible for tax purposes. Due to foreign
     currency translation adjustments, goodwill at December 31, 2001 was $2,933,
     of which $2,927 was attributable to Gulf Canada.

(4)  Includes the fair value of identifiable intangible assets of $6. These
     intangible assets have indefinite useful lives and will be tested for
     impairment.

     The purchase price allocation is subject to changes as additional
information becomes available for certain accounts and properties. Management
does not believe the final purchase price allocation will differ materially from
the current purchase price allocation. Upon full implementation of SFAS No. 142
in 2002, the goodwill from this transaction will be disclosed in the reporting
segments that include the "reporting units" to which this goodwill must be
allocated in accordance with the requirements of this standard.

     Conoco's unaudited pro forma results are presented below for the years
ended December 31, 2001, and December 31, 2000 (collectively the unaudited pro
forma results). The unaudited pro forma results have been prepared to illustrate
the estimated effect of the acquisition of Gulf Canada on Conoco under the
purchase method of accounting as if Conoco's acquisition of Gulf Canada had
occurred on January 1, 2000. The unaudited pro forma



                                       81
<PAGE>

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


results also give effect to the acquisition (that closed effective November 6,
2000) of Crestar Energy Inc. (Crestar) by Gulf Canada as if the acquisition had
occurred on January 1, 2000. For these unaudited pro forma results, the
historical income statement information of Gulf Canada has been converted to
U.S. Generally Accepted Accounting Principles (GAAP) and converted to U.S.
dollars using the average exchange rates of .64 for the six months ended
December 31, 2001, .65 for the six months ended June 30, 2001, and .67 for the
year ended December 31, 2000. The unaudited results do not purport to represent
what the results of operations would actually have been if the acquisition had
in fact occurred on such dates or to project Conoco's results of operations for
any future date or period.

<Table>
<Caption>
                                                                                          PRO FORMA
                                                                                   YEAR ENDED DECEMBER 31
                                                                                  -------------------------
                                                                                     2001           2000
                                                                                  ----------     ----------
                                                                                         (UNAUDITED)
<S>                                                                               <C>            <C>
Total revenues ..............................................................     $   40,736     $   41,265
Income before extraordinary item and accounting change ......................          1,711          1,890
Net income ..................................................................          1,704          1,890

Earnings per share before extraordinary item and accounting change
     Basic ..................................................................           2.73           3.03
     Diluted ................................................................           2.69           2.99
Earnings per share
     Basic ..................................................................           2.72           3.03
     Diluted ................................................................           2.68           2.99
</Table>

4.   OTHER INCOME

<Table>
<Caption>
                                                                          2001            2000            1999
                                                                       ----------      ----------      ----------
<S>                                                                    <C>             <C>             <C>
Interest income ..................................................     $       21      $       39      $       25
Gain on sales of assets and subsidiaries .........................            310              72              26
Gain (loss) on derivative activities .............................            212             (15)             --
Syrian service contract ..........................................            118             110               3
Write-down of various affiliates .................................            (50)            (26)             --
Exchange gain (loss) and other ...................................             10              93              66
                                                                       ----------      ----------      ----------
Other income .....................................................     $      621      $      273      $      120
                                                                       ==========      ==========      ==========
</Table>

5.   TAXES OTHER THAN ON INCOME

<Table>
<Caption>
                                                                          2001            2000            1999
                                                                       ----------      ----------      ----------
<S>                                                                    <C>             <C>             <C>
Petroleum excise taxes
  U.S. ...........................................................     $    1,463      $    1,572      $    1,495
  Non-U.S. .......................................................          5,281           5,202           4,997
                                                                       ----------      ----------      ----------
     Total .......................................................          6,744           6,774           6,492
Payroll taxes ....................................................             54              45              44
Property taxes ...................................................             67              65              64
Production and other taxes .......................................            118              97              68
                                                                       ----------      ----------      ----------
Taxes other than on income .......................................     $    6,983      $    6,981      $    6,668
                                                                       ==========      ==========      ==========
</Table>

6.   INTEREST AND DEBT EXPENSE

<Table>
<Caption>
                                                                          2001            2000            1999
                                                                       ----------      ----------      ----------
<S>                                                                    <C>             <C>             <C>
Interest and debt cost incurred ..................................     $      429      $      354      $      317
Less: interest and debt cost capitalized .........................             33              16               6
                                                                       ----------      ----------      ----------
Interest and debt expense(1) .....................................     $      396      $      338      $      311
                                                                       ==========      ==========      ==========
</Table>

----------

(1)  Cash interest paid, net of amounts capitalized, was $363 in 2001, $331 in
     2000 and $297 in 1999.



                                       82
<PAGE>

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


7.   PROVISION FOR INCOME TAXES

<Table>
<Caption>
                                                                          2001            2000            1999
                                                                       ----------      ----------      ----------
<S>                                                                    <C>             <C>             <C>
Current tax expense
    U.S. federal .................................................     $      102      $      126      $       26
    U.S. state and local .........................................             (5)             11               4
    Non-U.S. .....................................................          1,001           1,183             554
                                                                       ----------      ----------      ----------
      Current tax expense ........................................          1,098           1,320             584
                                                                       ----------      ----------      ----------

Deferred tax expense
    U.S. federal .................................................            290             125             (84)
    U.S. state and local .........................................             14               3              (5)
    Non-U.S. .....................................................            (11)            108             (22)
                                                                       ----------      ----------      ----------
      Deferred tax expense .......................................            293             236            (111)
                                                                       ----------      ----------      ----------

Income tax expense ...............................................          1,391           1,556             473
    Extraordinary item (see note 8) ..............................            (33)             --              --
    Cumulative effect of accounting change (see note 9) ..........             22              --              --
    Foreign currency translation (see note 24) ...................            (20)            (83)            (29)
    Minimum pension liability (see note 24) ......................             (8)             (5)             29
    Unrealized gains on derivatives (see note 24) ................             54              --              --
                                                                       ----------      ----------      ----------
Total provision for income taxes .................................     $    1,406      $    1,468      $      473
                                                                       ==========      ==========      ==========
</Table>

     Total income taxes paid worldwide were $1,379 in 2001, $1,030 in 2000 and
$493 in 1999.

     At December 31, 2001 and 2000, the current and non-current deferred taxes
were classified in the consolidated balance sheet as follows:

<Table>
<Caption>
                                                                          2001            2000
                                                                       ----------      ----------
<S>                                                                    <C>             <C>
Other current assets (see note 13) ...............................     $      (13)     $      (43)
Other assets (see note 16) .......................................            (28)            (39)
Income taxes .....................................................            208              66
Deferred income taxes ............................................          3,975           1,911
                                                                       ----------      ----------
Net deferred tax liabilities .....................................     $    4,142      $    1,895
                                                                       ==========      ==========
</Table>

     The significant components of deferred tax liabilities/(assets) at December
31, 2001 and 2000 were as follows:

<Table>
<Caption>
                                                                          2001            2000
                                                                       ----------      ----------
<S>                                                                    <C>             <C>
Deferred tax liabilities
  PP&E ...........................................................     $    4,681      $    2,452
  Inventories ....................................................             42              15
  Other ..........................................................            415             181
                                                                       ----------      ----------
    Deferred tax liabilities .....................................          5,138           2,648

Deferred tax assets
  PP&E ...........................................................            (33)            (35)
  Employee benefits ..............................................           (281)           (252)
  Other accrued expenses .........................................           (403)           (275)
  Tax loss/tax credit carryforwards ..............................           (724)           (442)
  Other ..........................................................           (174)           (158)
                                                                       ----------      ----------
    Deferred tax assets ..........................................         (1,615)         (1,162)
Valuation allowance ..............................................            619             409
                                                                       ----------      ----------
    Net deferred tax assets ......................................           (996)           (753)
                                                                       ----------      ----------
Net deferred tax liabilities .....................................     $    4,142      $    1,895
                                                                       ==========      ==========
</Table>

     Valuation allowances, which reduce deferred tax assets to an amount that
will more likely than not be realized, increased $210 in 2001. This reflects a
$201 increase to offset tax assets representing operating and tax losses
incurred in exploration, production, and start-up operations and a $66 increase
due to the Gulf Canada acquisition.



                                       83
<PAGE>

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


This increase is partially offset by a decrease of $57 related to tax loss
carryforwards, which have been utilized or have expired, and to tax assets
representing operating losses that we determined will more likely than not be
realized in future years. In 2000, valuation allowances decreased $43, primarily
reflecting a $123 decrease related to tax assets representing operating losses,
which we determined will more likely than not be realized in future years and
tax loss carryforwards that have been relinquished or expired. This decrease was
partially offset by an $80 increase in the valuation allowance used to offset
tax assets representing operating and tax losses incurred in exploration,
production and start-up operations.

     Under the tax laws of various jurisdictions in which we operate, deductions
or credits that cannot be fully utilized for tax purposes during the current
year may be carried forward. These loss carryforwards, subject to statutory
limitations, can reduce taxable income or taxes payable in a future year. At
December 31, 2001, the tax effect of such loss carryforwards approximated $724.
Of this amount, $271 has no expiration date, $22 expires in 2002, $45 expires in
2003, $47 expires in 2004, $72 expires in 2005, $185 expires in 2006, $1 expires
in 2007, $71 expires in 2008 and $10 expires in 2011 and later years.

     As a result of the Gulf Canada acquisition, gross deferred tax assets of
$137 were recorded, representing tax loss and tax credit carryforwards.
Valuation allowances of $66 reduce the gross asset to the amount we believe will
more likely than not be realized. Also as a result of the acquisition, net
deferred tax liabilities of $1,895 were recorded, reflecting the temporary
differences between book value and carryover tax basis in the assets acquired.

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

<Table>
<Caption>
                                                                          2001            2000            1999
                                                                       ----------      ----------      ----------
<S>                                                                    <C>             <C>             <C>
Statutory U.S. federal income tax rate ...........................           35.0%           35.0%           35.0%
Higher tax rate on international operations ......................           13.4            11.3            10.0
Alternative fuels credit .........................................           (1.3)           (1.2)           (4.0)
Other - net ......................................................           (0.2)            0.2            (1.3)
                                                                       ----------      ----------      ----------
     Consolidated companies ......................................           46.9            45.3            39.7
Effect of recording equity in income of certain affiliated
     companies on an after-tax basis .............................           (0.3)           (0.3)           (0.8)
                                                                       ----------      ----------      ----------
Effective income tax rate(1) .....................................           46.6%           45.0%           38.9%
                                                                       ==========      ==========      ==========
</Table>

----------

(1)  Effective income tax rate based on income and income taxes before
     extraordinary item and cumulative effect of accounting change.

     Income before income taxes was based on the location of the corporate unit
to which such earnings are attributable. However, since such earnings are 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>
                                                                          2001            2000            1999
                                                                       ----------      ----------      ----------
<S>                                                                    <C>             <C>             <C>
U.S. .............................................................     $    1,122      $      735      $       93
Non-U.S. .........................................................          1,865           2,723           1,124
                                                                       ----------      ----------      ----------
Income before income taxes .......................................     $    2,987      $    3,458      $    1,217
                                                                       ==========      ==========      ==========
</Table>

     Unremitted earnings of certain international subsidiaries totaling $1,687
at December 31, 2001, and $1,661 at December 31, 2000, are 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.   EXTRAORDINARY CHARGE FOR THE EARLY EXTINGUISHMENT OF DEBT

     Subsequent to the Gulf Canada acquisition, Conoco repaid various high-cost
Gulf Canada outstanding notes with an aggregate principal value of $1,572. The
extraordinary charge of $44, net of a tax benefit of $33, principally represents
the premium associated with the early repayment of these notes. See note 20.



                                       84
<PAGE>

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


9.   CUMULATIVE EFFECT OF ACCOUNTING CHANGE

     In June 2000, the FASB issued SFAS No. 138, which made amendments to SFAS
No. 133. We adopted SFAS No. 133, as amended (SFAS 133), on January 1, 2001. It
modified the criteria for identifying derivative instruments and required 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. Upon initial adoption of SFAS 133, we 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 SFAS 133, and $1 into other comprehensive
income to reflect the fair value of derivatives qualifying as cash flow hedges.
In addition, $297 was recorded as assets and $259 was recorded as liabilities.
Note 27 provides additional details of the accounting for the gain or loss
resulting from changes in the fair value of derivatives designated as hedging
instruments, as prescribed by SFAS 133.

     In accordance with the transition provisions of SFAS 133, we recorded the
following after-tax cumulative adjustments into earnings on January 1, 2001:

<Table>
<S>                                                                                          <C>
Previously designated fair value hedging relationships(1):
   Fair value of hedging instruments ...................................................     $     27
   Offsetting changes in fair value of hedged items ....................................          (25)
Hedging instruments not designated for hedge accounting under the standard(2) ..........           36
Contracts previously not designated as derivative instruments prior to the standard ....           (1)
                                                                                             --------
Total cumulative effect of adoption on earnings, after-tax .............................     $     37
                                                                                             ========
</Table>

The total cumulative effect is shown on the consolidated statement of income as
"Cumulative effect of accounting change."

----------

(1)  These fair value hedging relationships reflect conversions of certain
     commodity contracts from fixed prices to market prices, in accordance with
     Conoco's Risk Management Policy. For the year ended December 31, 2001, the
     ineffective portions of these hedges were immaterial.

(2)  Primarily reflects a pretax gain of $64 ($40 after-tax) related to changes
     in the fair value of certain crude oil put options from their purchase date
     to the January 1, 2001, adoption date of SFAS 133. Included in income
     before extraordinary item and accounting change on the consolidated
     statement of income is an $84 pretax expense ($53 after-tax) related to
     changes in the fair value of these same crude oil put options for the year
     ended December 31, 2001.

10.  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 vested Conoco employee and director awards and fee deferrals
that are invested in Conoco stock units (the denominator). Diluted EPS is
similarly computed using the treasury stock method, except the denominator is
increased to include the dilutive effect of outstanding stock options and
unvested shares of restricted stock awarded under Conoco's compensation plans
(see note 25). Fixed options and restricted stock grants that are contingent
upon continued service to the company are included in the diluted earnings per
share calculation and are excluded in the basic earnings per share calculation.
Issuance of these shares is contingent only upon a continued specified service
period of the grantees, and there are no other contingency provisions in these
fixed options and restricted stock grants.

     Diluted EPS includes the dilutive effect of an additional 9,591,024 shares
for 2001, 8,405,998 shares for 2000 and 9,241,896 shares for 1999.

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

<Table>
<Caption>
                                                                          2001            2000            1999
                                                                       -----------     -----------     -----------
<S>                                                                    <C>             <C>             <C>
Basic ............................................................     625,503,098     624,354,441     627,233,229
Diluted ..........................................................     635,094,122     632,760,439     636,475,125
</Table>

     At December 31, 2001, variable stock options for 1,331,300 shares of common
stock were outstanding, and at December 31, 2000 and 1999, variable stock
options for 3,124,146 shares of common stock were outstanding.



                                       85
<PAGE>

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


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.

     Fixed stock options for 7,691,426; 89,530; and 30,972 shares of common
stock were not included in the diluted earnings per share calculation for 2001,
2000 and 1999, respectively, because the exercise price was greater than the
average market price.

     The weighted-average number of common shares held as treasury stock is
deducted in determining the weighted-average number of shares outstanding.

11.  ACCOUNTS AND NOTES RECEIVABLE

<Table>
<Caption>
                                                                              DECEMBER 31
                                                                       -------------------------
                                                                          2001           2000
                                                                       ----------     ----------
<S>                                                                    <C>            <C>
Trade ............................................................     $    1,415     $    1,506
Notes and other ..................................................            479            331
                                                                       ----------     ----------
Accounts and notes receivable ....................................     $    1,894     $    1,837
                                                                       ==========     ==========
</Table>

     Included in the preceding table are accounts and notes receivable from
affiliated companies (see note 15) of $685 at December 31, 2001, and $548 at
December 31, 2000.

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

     See note 29 for a description of operating segment markets and associated
concentrations of credit risk.

12.  INVENTORIES

<Table>
<Caption>
                                                                              DECEMBER 31
                                                                       -------------------------
                                                                          2001           2000
                                                                       ----------     ----------
<S>                                                                    <C>            <C>
Crude oil and petroleum products .................................     $      773     $      643
Canadian Syncrude (from mining operations) .......................             10             --
Other merchandise ................................................             26             27
Materials and supplies ...........................................            186            121
                                                                       ----------     ----------
Inventories ......................................................     $      995     $      791
                                                                       ==========     ==========
</Table>

     The excess of market over book value of inventories valued under the LIFO
method was $268 and $643 at December 31, 2001 and 2000, respectively.
Inventories valued at LIFO represented 79 percent and 81 percent of consolidated
inventories at December 31, 2001 and 2000, 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.

13.  OTHER CURRENT ASSETS

<Table>
<Caption>
                                                                              DECEMBER 31
                                                                       -------------------------
                                                                          2001           2000
                                                                       ----------     ----------
<S>                                                                    <C>            <C>
Fair value of derivative instruments (see note 27) ...............     $      574     $       36
Prepaid expenses .................................................             18             20
Deferred taxes (see note 7) ......................................             13             43
Other ............................................................            461            342
                                                                       ----------     ----------
Other current assets .............................................     $    1,066     $      441
                                                                       ==========     ==========
</Table>



                                       86
<PAGE>

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


14.  PROPERTY, PLANT AND EQUIPMENT

<Table>
<Caption>
                                                                                             DECEMBER 31
                                                                       -------------------------------------------------------
                                                                                 COST                          NET
                                                                       -------------------------     -------------------------
                                                                          2001           2000           2001           2000
                                                                       ----------     ----------     ----------     ----------
<S>                                                                    <C>            <C>            <C>            <C>
Oil and gas properties
   Unproved ......................................................     $    2,524     $    1,106     $    2,310     $      920
   Proved ........................................................         18,541         14,730         10,093          6,719
Canadian Syncrude ................................................            802             --            797             --
Other ............................................................          1,537          1,449          1,044          1,009
                                                                       ----------     ----------     ----------     ----------
   Total upstream ................................................         23,404         17,285         14,244          8,648
Refining, marketing and distribution .............................          6,497          6,466          3,392          3,453
Emerging businesses ..............................................            229             58            228             58
Corporate ........................................................             94             81             54             48
                                                                       ----------     ----------     ----------     ----------
PP&E .............................................................     $   30,224     $   23,890     $   17,918     $   12,207
                                                                       ==========     ==========     ==========     ==========
</Table>

     PP&E includes downstream assets acquired under capital leases of $44 at
December 31, 2001, and $36 at December 31, 2000. DD&A expense associated with
these assets was $18 at December 31, 2001, $16 at December 31, 2000, and $15 at
December 31, 1999.

15.  SUMMARIZED FINANCIAL INFORMATION FOR AFFILIATED COMPANIES

     Summarized consolidated financial information for Petrozuata C.A. (50.1
percent non-controlling interest) and other affiliated companies for which
Conoco uses the equity method of accounting (see note 2) 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. (47 percent),
Petrovera (46.7 percent), Pocahontas Gas Partnership (50 percent) and Polar
Lights Company (50 percent). During the third quarter 2001, Conoco sold its 50
percent interest in the Pocahontas Gas Partnership.

<Table>
<Caption>
                                                                                         100%
                                                                       ----------------------------------------
                                                                                        OTHER                        CONOCO'S
                                                                       PETROZUATA     AFFILIATES        TOTAL         SHARE
                                                                       ----------     ----------     ----------     ----------
<S>                                                                    <C>            <C>            <C>            <C>
2001
RESULTS OF OPERATIONS
Sales ............................................................     $      577     $   11,079     $   11,656     $    4,719
Cost of goods sold ...............................................     $      115     $    8,458     $    8,573     $    3,678
Operating expenses ...............................................     $      233     $    1,201     $    1,434     $      529
DD&A .............................................................     $       74     $      414     $      488     $      180
Interest .........................................................     $      101     $       52     $      153     $       77
Earnings before income taxes .....................................     $       37     $      597     $      634     $      153
Net income(1) ....................................................     $      105     $      394     $      499     $      181
Dividends received ...............................................                                                  $      198

FINANCIAL POSITION
Current assets ...................................................     $      323     $    2,229     $    2,552     $      956
Non-current assets ...............................................          3,047          7,585         10,632          3,843
                                                                       ----------     ----------     ----------     ----------
Total assets .....................................................     $    3,370     $    9,814     $   13,184     $    4,799
                                                                       ==========     ==========     ==========     ==========
Short-term borrowings(2) .........................................     $       64     $      974     $    1,038     $      256
Other current liabilities ........................................            113          1,872          1,985            764
Long-term borrowings(2) ..........................................          1,364          3,626          4,990          1,699
Other long-term liabilities ......................................          1,365            812          2,177            934
                                                                       ----------     ----------     ----------     ----------
Total liabilities ................................................     $    2,906     $    7,284     $   10,190     $    3,653
                                                                       ==========     ==========     ==========     ==========
Conoco's net investment in affiliates (includes advances) ........     $      822     $    1,072                    $    1,894
                                                                       ==========     ==========                    ==========
</Table>



                                       87
<PAGE>

                   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>
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
Dividends received ...............................................                                                  $      132

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
                                                                       ==========     ==========                    ==========

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(1) ....................................................     $      109     $      490     $      599     $      150
Dividends received ...............................................                                                  $       77
</Table>

----------

(1)  Conoco's equity in Petrozuata's earnings totaled $52 in 2001, $147 in 2000
     and $50 in 1999.

(2)  Equity affiliate borrowings of $1,014 in 2001 and $979 in 2000 were
     guaranteed by Conoco or DuPont, on behalf of and indemnified by Conoco.
     These amounts are included in the guarantees disclosed in note 28.

     Equity affiliate sales to Conoco amounted to $1,023 in 2001, $804 in 2000
and $720 in 1999. Equity affiliate purchases from Conoco totaled $1,690 in 2001,
$2,200 in 2000 and $1,519 in 1999. Conoco's equity in undistributed earnings of
its affiliated companies was $585 at December 31, 2001, $446 at December 31,
2000 and $366 at December 31, 1999.

16.  OTHER ASSETS

<Table>
<Caption>
                                                                              DECEMBER 31
                                                                       -------------------------
                                                                          2001           2000
                                                                       ----------     ----------
<S>                                                                    <C>            <C>
Long-term receivables(1) .........................................     $      359     $      280
Other securities and investments .................................             85            105
Leveraged lease on Deepwater Pathfinder ..........................             63             61
Deferred taxes (see note 7) ......................................             28             39
Deferred pension transition obligation (see note 26) .............             70             33
Prepaid pension cost (see note 26) ...............................             --              5
Fair value of derivative instruments (see note 27) ...............             27             --
Other ............................................................            184            145
                                                                       ----------     ----------
Other assets .....................................................     $      816     $      668
                                                                       ==========     ==========
</Table>



                                       88
<PAGE>

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


----------

(1)  Includes $277 at December 31, 2001, and $223 at December 31, 2000,
     attributable to a long-term service contract for the development of a gas
     and condensate infrastructure in Syria. This amount is recoverable from the
     gas and condensate revenue stream generated over a period up to five years
     commencing in early 2002.

17.  ACCOUNTS PAYABLE

<Table>
<Caption>
                                                                              DECEMBER 31
                                                                       -------------------------
                                                                          2001           2000
                                                                       ----------     ----------
<S>                                                                    <C>            <C>
Trade ............................................................     $    1,439     $    1,287
Payables to banks ................................................            146            130
Product exchanges ................................................            250            217
Other ............................................................            115             89
                                                                       ----------     ----------
Accounts payable .................................................     $    1,950     $    1,723
                                                                       ==========     ==========
</Table>

     Included in the preceding table are accounts payable to affiliated
companies (see note 15) of $195 at December 31, 2001, and $573 at December 31,
2000.

     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.

18.  SHORT-TERM BORROWINGS AND CAPITAL LEASE OBLIGATIONS

<Table>
<Caption>
                                                                              DECEMBER 31
                                                                       -------------------------
                                                                          2001           2000
                                                                       ----------     ----------
<S>                                                                    <C>            <C>
Commercial paper .................................................     $      558     $      187
Industrial development bonds .....................................             59             59
Floating rate notes due 2002(1) ..................................            500             --
Long-term borrowings payable within one year .....................              6              8
Capital lease obligations ........................................              2              2
                                                                       ----------     ----------
Short-term borrowings and capital lease obligations ..............     $    1,125     $      256
                                                                       ==========     ==========
</Table>

----------

(1)  At December 31, 2001, the effective interest rate was 3.2 percent.

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

     During October 2001, we amended and increased our unsecured $2,000
revolving credit facility by $1,000 to facilitate an increase in our U.S.
commercial paper program. Also effective in October, the European commercial
paper program was increased from euro 500 to euro 1,000. We have the ability to
issue commercial paper at any time with maturities not to exceed 270 days. At
December 31, 2001, we had $558 of commercial paper outstanding, of which $29 was
denominated in foreign currencies. The weighted-average interest rate was 2.16
percent. 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.

     Supporting the commercial paper programs, we have an unsecured $3,000
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 $2,350 and a
five-year committed facility, with over two years remaining, in the amount of
$650. At December 31, 2001, and at December 31, 2000, we had no outstanding
borrowings under this credit facility.

     The weighted-average interest rate on short-term borrowings and capital
lease obligations outstanding was 2.7 percent at December 31, 2001, and 6.3
percent at December 31, 2000.



                                       89
<PAGE>

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


19.  OTHER ACCRUED LIABILITIES

<Table>
<Caption>
                                                                              DECEMBER 31
                                                                       -------------------------
                                                                          2001           2000
                                                                       ----------     ----------
<S>                                                                    <C>            <C>
Taxes other than on income .......................................     $      402     $      384
Operating expenses and other related costs .......................            402            537
Payroll and other employee-related costs .........................            185            206
Royalties ........................................................             70            134
Interest payable .................................................            112             66
Fair value of derivative instruments (see note 27) ...............            222             --
Accrual for litigation settlement (see note 28) ..................            112             --
Accrued post-retirement benefits cost (see note 26) ..............             30             18
Environmental remediation costs (see note 28) ....................             23             12
Other ............................................................            339            186
                                                                       ----------     ----------
Other accrued liabilities ........................................     $    1,897     $    1,543
                                                                       ==========     ==========
</Table>

20.  LONG-TERM BORROWINGS AND CAPITAL LEASE OBLIGATIONS

<Table>
<Caption>
                                                                                         DECEMBER 31
                                                                                  --------------------------
                                                                                     2001            2000
                                                                                  ----------      ----------
<S>                                                                               <C>            <C>
Floating rate notes due 2003 ................................................     $      500      $       --
7.443% senior unsecured notes due 2004 ......................................            171              --
5.90% senior unsecured notes due 2004 .......................................          1,349           1,348
8.375% senior unsecured notes due 2005(1) ...................................              9              --
5.45% senior unsecured notes due 2006 .......................................          1,248              --
8.35% senior unsecured notes due 2006(1) ....................................              4              --
6.45% senior unsecured notes due 2007(1)(2) .................................             62              --
6.50% senior unsecured notes due 2008 .......................................              7               7
6.35% senior unsecured notes due 2009 .......................................            750             750
6.35% senior unsecured notes due 2011 .......................................          1,747              --
7.125% senior unsecured notes due 2011(1) ...................................              5              --
7.68% senior unsecured notes due 2012 .......................................             63              65
8.25% senior unsecured notes due 2017(1) ....................................              9              --
5.75% senior unsecured notes due 2026 .......................................             16              16
6.95% senior unsecured notes due 2029 .......................................          1,900           1,900
7.25% senior unsecured notes due 2031 .......................................            494              --
Other loans (various currencies) due 2003-2008(3) ...........................              9              20
Capitalization obligation to affiliate due 2008 .............................             13               9
Capital lease obligations ...................................................             20              23
                                                                                  ----------      ----------
   Total long-term borrowings and capital lease obligations before hedges ...          8,376           4,138
Fair market value adjustment on notes subject to hedging (see note 27)
   Notes due 2009(4) ........................................................            (35)             --
   Notes due 2029(5) ........................................................            (74)             --
                                                                                  ----------      ----------
Long-term borrowings and capital lease obligations ..........................     $    8,267      $    4,138
                                                                                  ==========      ==========
</Table>

----------

(1)  Outstanding notes originally issued by Crestar and Gulf Canada reflect a $2
     fair value adjustment as a result of the acquisition.

(2)  The principal amount of these notes is Canadian $100. The obligation is
     converted based on the year-end exchange rate of .63.

(3)  Weighted-average interest rate was 6 percent at December 31, 2001, and 7.5
     percent at December 31, 2000.

(4)  Fair market value of the $750 executed interest rate swaps.

(5)  Fair market value of the $900 executed interest rate swaps.

     In connection with the July 2001 Gulf Canada acquisition, we arranged a
$4,500 senior unsecured 364-day bridge credit facility to finance the
transaction and assumed approximately $2,000 of net debt and minority interests.
The borrowings under the bridge facility were repaid on October 11, 2001,
primarily with the net proceeds of $4,469 from the $4,500 debt offerings by
Conoco and Conoco Funding Company, a wholly owned Nova Scotia finance
subsidiary, described in the subsequent paragraphs. The bridge was subsequently
cancelled on October 16, 2001.



                                       90
<PAGE>

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


Subsequent to the Gulf Canada acquisition, Gulf Indonesia Resources Limited
(Gulf Indonesia), a consolidated subsidiary of Gulf Canada, repaid $116 of its
outstanding debt, and Gulf Canada repaid $1,015 of its $1,048 in outstanding
public debt securities. In addition, Gulf Canada repaid $207 of its subordinated
debt and an additional $234 of outstanding private placement debt. We funded
these repayments and the repayment of the balance of the bridge facility through
a combination of cash on hand, our issuance of commercial paper and borrowings
under other available credit lines.

     On October 11, 2001, Conoco Funding Company issued $3,500 of senior
unsecured debt securities, fully and unconditionally guaranteed by Conoco, as
follows:

     o    $1,250 of 5.45 percent notes due 2006;

     o    $1,750 of 6.35 percent notes due 2011; and

     o    $500 of 7.25 percent notes due 2031.

Conoco also issued $1,000 of floating rate notes as follows:

     o    $500 notes due October 15, 2002, with a floating rate based on the
          three-month LIBOR rate plus .77 percent. The effective interest rate
          for the floating rate notes was 3.20 percent at December 31, 2001; and

     o    $500 notes due April 15, 2003, with a floating rate based on the
          three-month LIBOR rate plus .85 percent. The effective interest rate
          for the floating rate notes was 3.28 percent at December 31, 2001.

     Maturities of long-term borrowings, together with sinking fund requirements
for years ending after December 31, 2002, are $506 for 2003, $1,527 for 2004,
$19 for 2005, $1,260 for 2006 and $5,064 for 2007 and thereafter. Long-term
borrowings and capital lease obligations outstanding at December 31, 2001,
before interest rate hedges, had an estimated fair value of $8,557. At December
31, 2000, these outstanding obligations approximate fair value. These estimates
were based on quoted market prices for the same or similar issues.

21.  OTHER LIABILITIES AND DEFERRED CREDITS

<Table>
<Caption>
                                                                                         DECEMBER 31
                                                                                  --------------------------
                                                                                     2001            2000
                                                                                  ----------      ----------
<S>                                                                               <C>            <C>
Deferred gas revenue ........................................................     $      231      $      280
Accrued post-retirement benefits cost (see note 26) .........................            363             335
Accrued pension liability (see note 26) .....................................            266             184
Abandonment costs(1) ........................................................            432             397
Environmental remediation costs (see note 28) ...............................            134             107
Fair value of derivative instruments (see note 27) ..........................            158              --
Other .......................................................................            762             623
                                                                                  ----------      ----------
Other liabilities and deferred credits ......................................     $    2,346      $    1,926
                                                                                  ==========      ==========
</Table>

----------

(1)  Total future abandonment costs are currently estimated to be $1,062.

22.  MINORITY INTERESTS

     In 1996, various upstream subsidiaries contributed oil and gas 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
interest and terminate the Conoco Oil & Gas Associates partnership, reducing
minority interest by $302. As a result of this transaction, Vanguard received
from Conoco Oil & Gas Associates $310 cash, which represented its mark-to-market
adjusted capital account value plus a priority return for the period of October
1, 1999, through December 31, 1999.

     In 1999, Conoco formed Conoco Corporate Holdings L.P. by contributing an
office building and four aircraft. 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. The net minority interest in Conoco Corporate Holdings held by
Highlander was $141 at December 31, 2001, and December 31, 2000.



                                       91
<PAGE>

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


     In 1999, Conoco and Armadillo Investors L.L.C. formed Conoco Gas Holdings
L.L.C. We 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. The net minority interest
in Conoco Gas Holdings held by Armadillo was $185 at December 31, 2000. In March
2001, we acquired the minority interest in Conoco Gas Holdings L.L.C. from
Armadillo L.L.C. The acquisition resulted in a reduction of minority interest of
$185, an increase in debt of $171 and a reduction in cash of $14. Conoco assumed
the $171 debt from Armadillo L.L.C.

     In July 2001, Conoco assumed minority interests of $552 as part of the Gulf
Canada acquisition. The minority interests included $381 of two classes (Series
I and II) preferred stock of Gulf Canada that remained outstanding after the
acquisition and $171 representing 28 percent of the outside ownership of the
common shares outstanding of its subsidiary, Gulf Indonesia. Both Series I
preferred stock of Gulf Canada and common shares of Gulf Indonesia are publicly
traded.

     In December 2001, Conoco and Cold Spring Finance S.a.r.l. formed Ashford
Energy Capital S.A. through the contribution of cash and a Conoco subsidiary
promissory note. Cold Spring is entitled to a cumulative annual preferred return
based upon current short-term interest rates. A small portion of our return is a
preferred return based on short-term interest rates, while the remainder of our
return is based on the residual earnings of Ashford Energy. Cold Spring held a
$500 net minority interest in Ashford Energy at December 31, 2001.

     There was no consolidated gain or loss recognized on the formation of
Conoco Oil & Gas Associates, Conoco Corporate Holdings, Conoco Gas Holdings or
Ashford Energy. Conoco's net income was reduced by minority interest earnings of
$23 for 2001, $24 for 2000 and $25 for 1999. Minority interest at December 31,
2001, and December 31, 2000, was $1,204 and $337, respectively.

23.  STOCKHOLDERS' EQUITY

     As described in note 1, Conoco's capital structure was established at the
time of the initial public offering in October 1998. On September 21, 2001,
Conoco's shareholders approved the combination of our Class A and Class B common
stock into a single class of new common stock on a one-for-one basis. As a
result of the combination, each outstanding share of Class A and Class B common
stock was converted into one share of a new class of common stock. Each
shareholder has the same economic ownership of Conoco stock that they had prior
to the combination, and each share of the new common stock is entitled to one
vote. Prior to the combination, Class B shareholders had five votes per share.
The combination was effective on October 8, 2001.

     The number of shares of common stock issued and outstanding as of December
31, 2000, has been restated to give effect to the combination of the Class A and
Class B common stock. There was no effect on previously reported earnings per
share amounts.

     A summary of the activity in common shares outstanding for 1999, 2000 and
2001 is presented as follows:

<Table>
<Caption>
                                                                                                           TOTAL
                                                                                                        ------------

<S>                                                                                                     <C>
Common shares outstanding - December 31, 1998 .....................................................      627,791,531
Purchase of shares for treasury(1) ................................................................       (3,494,616)
Issued on exercise of stock options and compensation awards from treasury (see note 25) ...........        1,286,519
                                                                                                        ------------
Common shares outstanding - December 31, 1999 .....................................................      625,583,434
Purchase of shares for treasury(1) ................................................................       (3,634,400)
Additional shares issued ..........................................................................          466,638
Shares purchased and retired(1) ...................................................................         (223,729)
Issued on exercise of stock options and compensation awards from treasury (see note 25) ...........        1,240,897
                                                                                                        ------------
Common shares outstanding - December 31, 2000 .....................................................      623,432,840
Purchase of shares for treasury(1) ................................................................       (1,258,070)
Additional shares issued ..........................................................................          684,443
Shares purchased and retired(1) ...................................................................          (30,700)
Issued on exercise of stock options and compensation awards from treasury (see note 25) ...........        2,830,015
                                                                                                        ------------
Common shares outstanding - December 31, 2001 .....................................................      625,658,528
                                                                                                        ============
</Table>


----------

                                       92
<PAGE>

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


(1)  To offset dilution from issuances under compensation plans. Additionally,
     in February 2001, we commenced a new three-year $1,000 common stock buyback
     program. The stock buyback program allowed us to repurchase shares from
     time to time in the open market or possibly, under certain circumstances,
     through private transactions, as our financial condition and market
     conditions warranted. The stock buyback program was suspended in May 2001,
     with our purchase of Gulf Canada. During 2001, we purchased 1,288,770
     shares of our common stock at a total cost of $37.

     At December 31, 2001 and 2000, 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 common stock has one preferred stock purchase right attached to
it. No preferred shares have been issued, and the rights currently are not
exercisable. The purchase rights would generally become exercisable under the
direction of our board of directors, if a person or group acquires 15 percent or
more of the company's common stock or announces a tender offer that would result
in a person becoming an acquiring person.

     In connection with the separation from DuPont, Conoco recorded in
additional paid-in capital a net increase of $93 and a $26 charge in 2001 and
1999, respectively. These are included in additional paid-in capital as an
adjustment to capitalization from DuPont (see note 32).

     Dividends declared and paid on common stock for 2001 and 2000 are shown as
follows:

<Table>
<Caption>
                                                                                     2001            2000
                                                                                  ----------      ----------
<S>                                                                               <C>             <C>
First quarter ...............................................................     $      .19      $      .19
Second quarter ..............................................................            .19             .19
Third quarter ...............................................................            .19             .19
Fourth quarter ..............................................................            .19             .19
                                                                                  ----------      ----------
Dividends per share .........................................................     $      .76      $      .76
                                                                                  ==========      ==========
</Table>

     Conoco declared a first quarter cash dividend on January 24, 2002, of $.19
per share on each outstanding share of common stock. This quarterly dividend
will be paid on March 10, 2002, to all shareholders of record as of February 10,
2002.

24.  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
                                                                                  --------------------------
                                                                                     2001            2000
                                                                                  ----------      ----------
<S>                                                                               <C>            <C>
Foreign currency translation adjustment .....................................     $     (928)     $     (619)
Minimum pension liability adjustment (see note 26) ..........................            (53)            (34)
Unrealized gains on derivatives (see note 9) ................................             87              --
                                                                                  ----------      ----------
Accumulated other comprehensive loss ........................................     $     (894)     $     (653)
                                                                                  ==========      ==========
</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
                                      ----------------------------------------------------------------------------------------
                                                 2001                          2000                           1999
                                      ---------------------------   ---------------------------   ----------------------------
                                               INCOME                        INCOME                        INCOME
                                      PRETAX     TAX    AFTER-TAX   PRETAX     TAX    AFTER-TAX   PRETAX     TAX    AFTER-TAX
                                      ------   ------   ---------   ------   ------   ---------   ------   ------   ---------
<S>                                   <C>      <C>       <C>        <C>      <C>     <C>          <C>      <C>      <C>
Foreign currency translation
   adjustment .....................   $ (329)  $  (20)  $    (309)  $ (355)  $  (83)  $    (272)  $ (191)  $  (29)  $    (162)
Minimum pension liability
   adjustment .....................      (27)      (8)        (19)     (14)      (5)         (9)      93       29          64
Unrealized gains on derivatives ...      141       54          87       --       --          --       --       --          --
                                      ------   ------   ---------   ------   ------   ---------   ------   ------   ---------
Other comprehensive loss ..........   $ (215)  $   26   $    (241)  $ (369)  $  (88)  $    (281)  $  (98)  $   --   $     (98)
                                      ======   ======   =========   ======   ======   =========   ======   ======   =========
</Table>

     Conoco recorded an after-tax gain of $87 into other comprehensive income
from derivatives during 2001. This gain includes an after-tax gain of $92
related to derivative instruments designated as cash flow hedges of certain
forecasted sales of crude oil and natural gas and a net after-tax charge of $5
due to changes in the fair values of



                                       93
<PAGE>

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


derivative instruments designated as cash flow hedges of variable interest rate
obligations. During the next 12-month period, all of the $92 after-tax gain
associated with the forecasted sales of crude oil and natural gas, as well as an
immaterial portion of the $5 net after-tax charge related to variable interest
rate obligations, is expected to be reclassified into income.

25.  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.
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 and replacement with Conoco options or SARs. The
substitute stock options and other awards had the same total intrinsic value,
vesting provisions, option periods and other terms and conditions as the DuPont
options and awards they replaced. A total of 8,921,508 DuPont stock options and
745,358 DuPont SARs were cancelled and replaced by 24,275,690 stock options for
Conoco common stock and 2,279,834 SARs with respect to Conoco common stock.
DuPont retained responsibility for delivery of DuPont common stock to Conoco
employees for DuPont stock options not cancelled.

     Of the converted options, 1,724,146 were variable options for which a
threshold price of $32.88 (closing price for five consecutive days) had to be
reached within five years of the grant date in order to become exercisable. In
2001, the time deadline to reach the threshold price was extended by two years.
Of these options, 392,846 were granted to the Chief Executive Officer (CEO). Due
to an application of a vesting provision in the CEO's employment contract, these
392,846 options have been reclassified as fixed options.

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.
Awards may be in the form of cash, stock, stock options or SARs with respect to
Conoco 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:

     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 some senior management, certain shares can be deferred as stock units for a
designated future delivery.

     In 1999, a variable option grant to acquire 1,400,000 shares of common
stock was made to Conoco's Chairman, President and CEO. Of this grant, 50
percent was subject to forfeiture if, within three years from the date of grant,
the market price of Conoco common stock did not achieve a price of $35.00 per
share for five consecutive days. The remaining 50 percent of the grant was
subject to forfeiture if, within five years from the date of grant, the market
price of Conoco common stock did not achieve a price of $42.00 per share for
five consecutive days. The exercise price was $26.50, which was the market price
on the grant date. In 2001, due to an extension of the time deadline to reach
the threshold price for 700,000 options and application of a vesting provision
in the CEO's employment contract, all 1,400,000 options were reclassified as
fixed options.

     Prior to 2001, the maximum number of shares of common stock and stock
options granted under the plan was limited to the highest of 20,000,000 or 3.3
percent of outstanding shares of common stock. In September 2001, the plan was
amended to increase the number of shares that may be granted. The maximum number
of shares of



                                       94
<PAGE>

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


common stock and stock options granted under the plan is now limited to
31,397,830. At December 31, 2001, 19,953,208 shares and at December 31, 2000,
12,028,155 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 in the form of Conoco stock options or SARs, both with respect
to common stock. Such awards granted under this plan are awarded under the same
terms and conditions of the 1998 Stock and Performance Incentive Plan as
described above. Prior to 2001, the maximum number of shares of common stock and
stock options granted under the plan was limited to the higher of 18,000,000 or
3 percent of outstanding shares of common stock. In September 2001, the plan was
amended to increase the number of shares that may be granted. The maximum number
of shares of common stock and stock options granted under the plan is now
limited to 37,580,628. At December 31, 2001, 24,879,789 shares of common stock
were available for issuance under the plan, while at December 31, 2000,
10,556,261 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 for certain
managers upon the exercise of stock options. Reload provisions associated with
options considered to be fixed were contained in the original terms of the plans
and have not been modified. 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 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:

     o    were awarded at the price of the initial public offering
          ($23.00 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.

     The 2001 Global Performance Sharing Plan is a broad-based plan under which
grants of stock options and SARs with respect to 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:

     o    were awarded at the market price of stock at the award date
          ($29.15 per share);

     o    have a 10-year life; and

     o    become exercisable at the earliest of when Conoco stock closing price
          is $36.25 or above for five consecutive days, or six months before the
          expiration date of the options.

     Most stock options granted under Conoco plans are fixed and have no
intrinsic value at grant date. The exceptions to this fixed status are the
1,724,146 options granted to substitute for cancelled DuPont options granted in
1997 and the 1,400,000 options granted on August 17, 1999.


                                       95


<PAGE>
                   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>

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
   Granted .......................       7,840,895            29.44              --               --
   Issued in exchange for Gulf
      Canada options .............         132,571            19.07              --               --
   Reclassified ..................       1,792,846            24.90      (1,792,846)           24.90
   Exercised .....................      (3,460,154)           12.14              --               --
   Forfeited .....................        (144,528)           24.66              --               --
                                       -----------                       ----------
December 31, 2001 ................      41,852,763            21.15       1,331,300            19.18
</Table>

     The following table summarizes information concerning outstanding and
exercisable fixed Conoco options at December 31, 2001. For total variable
options outstanding at December 31, 2001, the weighted-average remaining
contractual life was 5.1 years.

<Table>
<Caption>
                                                           EXERCISE PRICE
                                 ---------------------------------------------------------------------
                                     $8.40 -         $12.78 -           $19.17 -          $29.15 -
                                     $10.42           $18.31             $28.55            $31.21
                                 --------------   --------------    ---------------    ---------------
<S>                              <C>              <C>               <C>                <C>
Options outstanding ........         5,517,691         2,644,842         25,968,804         7,721,426
Weighted-average remaining
  contractual life (years)..              2.61              4.23               6.65              9.08
Weighted-average price .....     $        9.84    $        14.35    $         21.77    $        29.46
Options exercisable ........         5,517,691         2,644,842         23,690,960            29,099
Weighted-average price .....     $        9.84    $        14.35    $         21.51    $        30.03
</Table>

     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>
                                                                    2001              2000               1999
                                                              --------------    ---------------    ----------------
<S>                                                           <C>               <C>                <C>
Options exercisable at year-end
   Number of shares .....................................         31,882,592         25,443,830         22,481,408
   Weighted-average price ...............................     $        18.90    $         16.85    $         15.31
Weighted-average fair value of options granted during
   the year .............................................     $         8.64    $          6.14    $          6.85
</Table>

     The incremental fair value of Conoco variable options with a hurdle price
of $32.88 per share was assumed to be zero. Except for the $2 related to the
conversion of the CEO's variable options to fixed, no compensation expense has
been recognized for fixed options.



                                       96
<PAGE>

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

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

<Table>
<Caption>
                                      CONOCO OPTIONS(1)
                                ----------------------------
                                  2001     2000      1999
                                -------   -------   -------
                                  NEW       NEW       NEW
                                -------   -------   -------
<S>                             <C>       <C>       <C>
Dividend yield ...........        3.3%      3.3%      3.3%
Volatility ...............       30.0%     30.0%     25.0%
Risk-free interest rate...        5.3%      5.1%      5.8%
Expected life (years) ....        6.0       6.0       6.0
</Table>

----------

(1)  For 2001 and 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. 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 we had adopted
the optional recognition provisions of SFAS No. 123 (see note 2):

<Table>
<Caption>
                                   2001         2000        1999
                                ----------   ----------  ----------
<S>                             <C>          <C>         <C>
Increase (decrease) in
     Net income ...........     $     (46)   $     (28)  $     (18)
     Earnings per share
         Basic ............     $    (.07)   $    (.04)  $    (.03)
         Diluted ..........     $    (.07)   $    (.04)  $    (.03)
</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 $6 for 2001, $4 for 2000 and $24 for 1999.

     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 common stock under
Conoco's 1998 Key Employee Stock Performance Plan. Effective with the initial
public offering, no new grants were made or are planned out of the Conoco Unit
Option Plan. At December 31, 2001, outstanding unit options based on common
stock were 1,150,975, and at December 31, 2000, outstanding unit options based
on common stock were 1,330,485. For these same time periods, outstanding unit
options based on DuPont common stock were 346,724 and 403,115, respectively. The
related liability provisions totaled $16 at December 31, 2001, and $21 at
December 31, 2000.

     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 were 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 2001 in
anticipation of awards to be made in 2002 were $49, while amounts charged
against earnings during 2000 in anticipation of awards to be made in 2001 were
$62.

     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



                                       97
<PAGE>
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)

common stock for designated future delivery. At December 31, 2001, 54,421 shares
of DuPont stock and 329,572 shares of Conoco common stock were awaiting
delivery. Conoco recognized a liability of $2 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 our 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 $47 for 2001, $63 in
2000 and $40 in 1999.

GULF CANADA FIXED OPTIONS

     At the time of the acquisition offer, Gulf Canada employees holding Gulf
Canada options were given the opportunity to convert those options to Conoco
options with comparable intrinsic value, terms and conditions. Accordingly,
473,112 Gulf Canada options were converted to 132,571 Conoco options. All Gulf
Canada options not converted (approximately 21 million) were exercised
immediately prior to the acquisition and the resulting shares were included as
part of the purchase price.

26.  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. In 2000, DuPont
transferred cash and assets valued at $858 to fund the plan.

     The Conoco plan covers substantially all U.S. non-retail employees, as well
as about half of all U.S. retail 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 employee's
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, we 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 our general creditors in preference to the claims of
plan participants and beneficiaries. The trust is currently not active and is
funded with $2 cash that is consolidated in our financial statements.

     Pension coverage is provided to the extent appropriate for employees of our
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, we reserve the right to change, modify or discontinue
the plans. We have communicated to plan participants that any increase in the
annual health care escalation rate above 4.5 percent will be borne by the
participants. However, for 2002 we approved a one-year increase to Conoco's
contributions to 9.0 percent. Because cost increases for years prior to 2002
were less than 4.5 percent, the overall average through 2002 does not exceed 4.5
percent. As a result, we do not expect a material increase to the accumulated
post-retirement benefit obligation or the other post-retirement benefit cost.



                                       98
<PAGE>
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)

<Table>
<Caption>
                                                       PENSION BENEFITS                             OTHER POST-RETIREMENT BENEFITS
                                 ---------------------------------------------------------------    ------------------------------
                                        2001                 2000                    1999             2001       2000        1999
                                 ------------------   -------------------    -------------------    --------   --------    -------
                                   U.S.      INT'L.     U.S.      INT'L.       U.S.      INT'L.
                                 --------   -------   --------   --------    --------   --------

<S>                              <C>        <C>       <C>        <C>         <C>        <C>         <C>        <C>         <C>
 Service cost..................  $     39   $    26   $     35   $     27    $     44   $     42    $      6   $      7    $     9
 Interest cost.................        61        41         62         37          58         41          28         25         22
 Expected return on plan
   assets......................       (76)      (37)       (76)       (33)        (79)       (36)         --         --         --
 Amortization of prior
   service cost (credit).......        (7)        5         (6)         5          (7)         5          (4)        (4)        (4)
 Recognized actuarial
   loss (gain).................         5        --          4         --           4          5           2         (1)         2
                                 --------   -------   --------   --------    --------   --------    --------   --------    -------
 Net periodic benefit cost.....  $     22   $    35   $     19   $     36   $      20   $     57    $     32   $     27    $    29
                                 ========   =======   ========   ========   =========   ========    ========   ========    =======
</Table>


         The following table reflects information concerning benefit
obligations, plan assets, funded status and recorded values:

<Table>
<Caption>
                                                                                                               OTHER
                                                                       PENSION BENEFITS               POST-RETIREMENT BENEFITS
                                                         ------------------------------------------   ------------------------
                                                               2001                     2000             2001          2000
                                                         ------------------      ------------------   ----------    ----------
                                                          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 ..........     $  855      $  698      $  834      $  679   $      374    $      323
  Service cost .....................................         39          26          35          27            6             7
  Interest cost ....................................         61          41          62          37           28            25
  Exchange gain ....................................         --         (20)         --         (58)          (2)           --
  Participant contributions ........................         --          --          --          --           --             4
  Amendment(1) .....................................         27          --          --          --            6            --
  Actuarial (gain) loss ............................         53         (17)         (2)         17           38            46
  Acquisitions, divestitures and other .............         --          25          --          18           32            --
  Benefits paid ....................................        (50)        (23)        (74)        (22)         (29)          (31)
                                                         ------      ------      ------      ------   ----------    ----------
  Benefit obligation at end of year ................     $  985      $  730      $  855      $  698   $      453    $      374
                                                         ======      ======      ======      ======   ==========    ==========

  CHANGE IN PLAN ASSETS
  Fair value of plan assets at beginning of year ...     $  798      $  524      $  884      $  494   $       --    $       --
  Actual return on plan assets .....................        (45)        (68)        (29)         49           --            --
  Employer contribution ............................          7          32          17          29           24            26
  Participant contributions ........................         --          --          --          --            5             5
  Exchange gain ....................................         --         (15)         --         (40)          --            --
  Acquisitions, divestitures and other .............         --          23          --          10           --            --
  Benefits paid ....................................        (50)        (21)        (74)        (18)         (29)          (31)
                                                         ------      ------      ------      ------   ----------    ----------
  Fair value of plan assets at end of year .........     $  710      $  475      $  798      $  524   $       --    $       --
                                                         ======      ======      ======      ======   ==========    ==========

  Funded status of plans at end of year ............     $ (275)     $ (254)     $  (57)     $ (174)  $     (453)   $     (374)
  Transition asset .................................         (7)         (5)        (15)         (6)          --            --
  Unrecognized actuarial loss ......................        225          95          55          12           99            62
  Exchange gain ....................................         --          --          --          --           (2)           --
  Unrecognized prior service cost (credit) .........         37          68          11          81          (37)          (41)
                                                         ------      ------      ------      ------   ----------    ----------
  Net amount recognized at end of year .............     $  (20)     $  (96)     $   (6)     $  (87)  $     (393)   $     (353)
                                                         ======      ======      ======      ======   ==========    ==========

  AMOUNTS RECOGNIZED IN CONSOLIDATED BALANCE SHEET
     AT END OF YEAR
  Prepaid benefit (see note 16) ....................     $   --      $   --      $    5      $   --   $       --    $       --
  Accrued benefit liability
    Short-term (see note 19) .......................         --          --          --          --          (30)          (18)
    Long-term (see note 21) ........................        (70)       (196)        (69)       (115)        (363)         (335)
  Deferred pension transition obligation (see note
     16) ...........................................         --          70           5          28           --            --
  Accumulated other comprehensive loss(2) ..........         50          30          53          --           --            --
                                                         ------      ------      ------      ------   ----------    ----------
   Net amount recognized ............................    $  (20)     $  (96)     $   (6)     $  (87)  $     (393)   $     (353)
                                                         ======      ======      ======      ======   ==========    ==========
</Table>
----------



                                       99
<PAGE>
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)



(1)   Represents a change in the U.S. pension plan for the survivors' benefit
      provisions.

(2)   Before reduction for associated deferred tax benefit of $27 at
      December 31, 2001, and $19 at December 31, 2000 (see note 24).

<Table>
<Caption>
                                                                                              OTHER
                                                                                         POST-RETIREMENT
                                                             PENSION BENEFITS                BENEFITS
                                               --------------------------------------   -----------------
                                                       2001                2000          2001       2000
                                               ----------------     ----------------    ------     ------
                                                U.S.     INT'L.      U.S.     INT'L.
                                               ------    ------     ------    ------
<S>                                            <C>       <C>        <C>       <C>       <C>       <C>
WEIGHTED-AVERAGE ASSUMPTIONS AT END OF
 YEAR
Discount rate ..........................        7.00%     6.00%      7.50%     6.00%     7.00%     7.50%
Rate of compensation increase ..........        4.60%     4.05%      4.60%     4.50%     4.60%     4.60%
Expected return on plan assets .........        9.25%     7.00%      9.00%     7.00%       --        --
Health care escalation rate ............          --        --         --        --      4.50%     4.50%
</Table>

     U.S. defined benefit plan assets consisted primarily of common stock and
fixed income securities at December 31, 2001. The assets included 1,100 shares
of Conoco stock. At December 31, 2000, U.S. defined benefit plan assets
consisted primarily of common stocks. No Conoco common stock was included in the
2000 holdings.

27.  FINANCIAL INSTRUMENTS AND OTHER RISK MANAGEMENT ACTIVITIES

GENERAL

     We operate in the worldwide crude oil, refined product, natural gas,
natural gas liquids and electric power markets and are exposed to fluctuations
in hydrocarbon and power prices, foreign currency rates and interest rates.
These fluctuations can affect revenues and the cost of operating, investing and
financing. Our 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.

     We have established a Risk Management Policy that provides guidelines for
entering into contractual arrangements (derivatives) to manage our commodity
price, foreign currency rate and interest rate risks. The Conoco Risk Management
Committee, composed of certain senior officers, has:

     o   an ongoing responsibility for the content of this policy;

     o   principal oversight responsibility to ensure that we are 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, our 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. We have not experienced any
material nonperformance by counterparties to these contracts, and no material
loss would be expected from any such nonperformance. Our exposure to the recent
Enron Corp. bankruptcy is not material.



                                       100
<PAGE>
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)


ADOPTION OF NEW ACCOUNTING STANDARD

     Effective January 1, 2001, we adopted SFAS No. 133, as amended by SFAS No.
138 (SFAS 133). Upon initial adoption of SFAS 133, we 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 SFAS 133, and $1 into other comprehensive income to
reflect the fair value of derivatives qualifying as cash flow hedges. In
addition, $297 was recorded as assets, and $259 was recorded as liabilities.

     See note 9 for details on the accounting change generated from implementing
SFAS 133 and note 24 for the impact of implementing SFAS 133 to "Other
Comprehensive Income."

ACCOUNTING POLICY

     All derivatives are recognized on the balance sheet at their fair value. At
the time Conoco enters into a derivative commodity instrument, the derivative is
designated as a fair value hedge, a cash flow hedge or a non-hedging instrument.

     At December 31, 2001, the fair value of all derivative instruments was
recorded in the balance sheet captions as follows:

     o   other current assets $574;

     o   other assets $27;

     o   other accrued liabilities $222; and

     o   other liabilities and deferred credits $158.

     For those derivatives designated as fair value or cash flow hedges, we
formally document the hedging relationship and our risk management objective and
strategy prior to undertaking the hedge. Hedge accounting is adopted for
reporting gains and losses from changes in the fair value of cash flow and fair
value hedges when the impact is material and the hedging instruments meet the
criteria for hedge accounting, as defined in SFAS 133. Gains or losses from
derivative instruments for which hedge accounting is applied are reported at the
same time and in the same income statement caption as the hedged item. Gains or
losses from derivative instruments for which hedge accounting is not applied are
reported in other income.

     Conoco formally assesses, both at inception of the hedge and on an ongoing
basis, the effectiveness of the hedging instrument. If it is determined that a
hedging instrument has not been highly effective in offsetting gains or losses
on the hedged transaction, hedge accounting will be discontinued on a
prospective basis. Hedge accounting was not discontinued during 2001 for any
hedging instruments.

     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 a non-hedging instrument. If the anticipated
transaction is no longer expected to occur, derivatives designated as a hedge
are reclassified to non-hedging instruments and gains (losses) are recognized in
earnings in the current period.

     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 SFAS 133. The DIG is still active, and the potential exists
for additional issues to be brought under its review. Therefore, if subsequent
DIG interpretations of SFAS 133 are different than our current policy, it is
possible that our policy, as stated above, would be modified.



                                       101
<PAGE>

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

COMMODITY PRICE RISK

     We enter into energy-related futures, forwards, swaps and options in
various markets:

     o   to balance our physical systems -- In addition to being able to settle
         exchange traded futures contracts in cash prior to contract expiry,
         they also can be settled by physical delivery of the commodity. These
         barrels can provide another source of supply to our physical or "wet
         barrel" pool to meet refinery requirements or marketing demand;

     o   to meet customer needs -- Consistent with our policy to generally
         remain exposed to market prices, we use swap contracts to convert fixed
         price sales contracts (often requested by natural gas and refined
         product consumers) to a floating market basis; and

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

     Our 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 our equity crude oil
and natural gas production, as well as our refinery margins. Specifically, in
conjunction with the Gulf Canada acquisition, we initiated an extensive hedging
program to mitigate volatile crude oil and natural gas prices through the
purchase of derivative instruments.

     The fair value gain or loss of outstanding derivative commodity instruments
is shown in the following table:

<Table>
<Caption>
                                     FAIR VALUE AT DECEMBER 31
                                     -------------------------
                                      2001              2000
                                     -------         ---------
<S>                                  <C>             <C>
COMMODITY DERIVATIVES(1)
Crude oil and refined products
   Trading ......................    $    --         $       1
   Non-trading ..................        264(2)             92(3)
                                     -------         ---------
Combined ........................    $   264         $      93
                                     =======         =========

Natural gas and electricity
   Trading ......................    $    --         $       3
   Non-trading ..................         74(4)            103
                                     -------         ---------
Combined ........................    $    74         $     106
                                     =======         =========
</Table>


----------

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

(2)  Includes collars with a $24.04 floor price and a $26.54 cap price (West
     Texas Intermediate equivalent) on 54.5 million barrels for the period
     October 2001 through December 2002.

     Includes swaps at $25.30 on 18.3 million barrels for the period October
     2001 through December 2002.

(3)  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.

(4)  Includes collars with a $4.00 floor price and a $4.60 cap price (NYMEX
     equivalent) on approximately 120,000 mmbtu per day for the period October
     2001 through December 2002.

     Includes swaps at $4.02 on approximately 100,000 mmbtu per day for the
     period October 2001 through December 2002.


     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.

     We do a limited amount of trading unrelated to our underlying physical
business for which after-tax gains or losses have not been material.



                                       102
<PAGE>
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)

     The amount of hedge accounting ineffectiveness related to commodity
derivatives for the year 2001 was not material.

FOREIGN CURRENCY RISK

     Conoco has foreign currency exchange rate risk resulting from operations in
over 40 countries around the world. We do not comprehensively hedge our exposure
to currency rate changes, although we 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, we enter 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, 2001, the U.S.
dollar equivalent of all non-U.S. dollar notes outstanding was $29, all of which
were swapped to the U.S. dollar. At December 31, 2000, the U.S. dollar
equivalent of all non-U.S. dollar notes outstanding was $81, all of which were
swapped for the U.S. dollar.

     At December 31, 2001, we had open foreign currency exchange derivative
instruments with a notional value of $9 related to forward currency sales. At
December 31, 2000, we had open foreign currency exchange derivative instruments
with a notional value of $45 related to anticipated foreign currency capital
investments.

     The fair value of outstanding foreign currency hedges is shown in the
following table:

<Table>
<Caption>
                                 FAIR VALUE AT DECEMBER 31
                                 -------------------------
                                    2001           2000
                                 ---------       ---------
<S>                              <C>             <C>
FOREIGN CURRENCY DERIVATIVES
   Non-trading .............     $      --       $       2
                                 ---------       ---------
Total ......................     $      --       $       2
                                 =========       =========
</Table>

     There was no amount of hedge accounting ineffectiveness recognized in
earnings related to foreign currency derivatives for the year 2001.

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 our total debt
portfolio and related overall cost of borrowing. Beginning in the fourth quarter
2001, we executed several interest rate swaps to increase our overall debt
portfolio's exposure to floating interest rates. These transactions included
swapping $1,650 of fixed rate debt to floating rate debt, as well as swapping
$900 of floating rate debt to fixed rate debt. These instruments qualify for the
short-cut method of hedge accounting and had no ineffectiveness. Through these
transactions, we effectively increased our exposure to floating interest rates
by $750. In addition to increasing our floating rate exposure, we effectively
swapped $900 of debt to a lower fixed rate, reducing the pretax interest rate
by approximately 250 basis points.

     The fair value gain or loss of outstanding interest rate swaps is shown in
the following table:

<Table>
<Caption>
                                            FAIR VALUE AT DECEMBER 31
                                            -------------------------
                                               2001           2000
                                            ---------       ---------
<S>                                         <C>             <C>

INTEREST RATE DERIVATIVES
   Fixed rate to floating rate hedges
    Notes due 2009 .....................    $     (35)      $      --
    Notes due 2029 .....................          (74)             --
                                            ---------       ---------
   Fixed rate to floating rate hedges
    (see note 20) ......................         (109)             --
   Floating rate to fixed rate hedges...           (8)             --
                                            ---------       ---------
Total ..................................    $    (117)      $      --
                                            =========       =========
</Table>
     At December 31, 2000, Conoco had no significant open interest rate
financial derivative instruments.



                                       103
<PAGE>
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)

FAIR VALUES OF NON-DERIVATIVE FINANCIAL INSTRUMENTS

     The carrying values of most non-derivative 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, 2001, before interest rate hedges, of $8,376, had an estimated fair value of
$8,557. Obligations outstanding at December 31, 2000, of $4,138 approximate fair
value. 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.

28.  COMMITMENTS AND CONTINGENT LIABILITIES

     We use various leased facilities and equipment in our operations. Future
minimum lease payments under noncancelable operating leases are $329 for 2002,
$285 for 2003, $154 for 2004, $136 for 2005, $221 for 2006 and $549 for
subsequent years. Future minimum lease payments are not reduced by $66 of
noncancelable minimum sublease rentals, where we continue to be the primary
obligator under the original leases. Rental expense under operating leases was
$322 in 2001, $274 in 2000 and $301 in 1999. Rental revenue under operating
subleases was $15 in 2001, $11 in 2000 and $15 in 1999.

     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, we
have obligations under international contracts to purchase natural gas over
periods up to 18 years. At December 31, 2001, these long-term purchase
obligations were at prices approximating year-end quoted market prices. However,
at December 31, 2000, these obligations were at prices lower than year-end 2000
market prices. No material annual loss is expected from these long-term
commitments.

     We are subject to various lawsuits and claims including but not limited to:
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; claims for damages resulting
from leaking underground storage tanks; and related toxic tort claims. As a
result of the separation agreement with DuPont, we also have 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.

     An accrual of $112 was recorded during the fourth quarter of 2001 for a
litigation settlement related to certain discontinued chemicals businesses for
which we assumed responsibility for claims as a result of the separation
agreement with DuPont.

     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 flow improver products. The amount awarded as damages
was $55. The Federal Circuit Court of Appeals handed down a decision on
September 19, 2001, without a written opinion, affirming the trial court's
verdict. On November 9, 2001, we paid approximately $60 that included interest
to the settlement date, in partial satisfaction of the judgment. The parties
entered into settlement negotiations and in December 2001 reached a confidential
settlement of all disputes between the parties.

     Over the next seven years, we will spend an estimated $95 to $100 for
capital improvements at our U.S. refineries to install control technology and
equipment to reduce emissions from stacks, vents, valves, heaters, boilers and
flares.

     We also are 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. We have accrued for certain environmental
remediation activities consistent with our policy set forth in note 2. These
accrued liabilities exclude claims against Conoco's insurers or other third
parties and are not discounted. Many of these liabilities result from the
Comprehensive Environmental Response, Compensation and Liability Act, as amended
and often referred to as "Superfund" (CERCLA); the Resource Conservation and
Recovery Act, as amended (RCRA); and similar state laws that require us to
undertake certain



                                       104
<PAGE>

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

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, we 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, 2001.

     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. We also
assumed environmental remediation liabilities with the purchase of Gulf Canada
in the third quarter 2001. These liabilities totaled $27 at December 31, 2001,
and were discounted at 5 percent. The total environmental liability accrual
amounted to $157 at December 31, 2001, and $119 at December 31, 2000. These
expenditures are expected to be incurred over the next 10 years.

     Approximately 90 percent of Conoco's environmental reserve at December 31,
2001, was attributable to RCRA and similar remediation liabilities (including
voluntary remediations) and 10 percent to CERCLA liabilities. 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. In management's
opinion, this accrual was appropriate based on existing facts and circumstances.
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. During 2001,
remediation accruals resulted in a $44 charge, compared to a $35 charge in 2000
and a $6 charge in 1999.

     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, we may be required to remediate contamination
caused by prior operations. In contrast to the CERCLA, the cost of corrective
action activities under the RCRA corrective action program typically is borne
solely by Conoco. Over the next decade, we anticipate 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 $63 in 2001, $34 in 2000
and $33 in 1999. 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 the United States Environmental Protection Agency
(USEPA) 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, 2001, we had been notified of potential liability under CERCLA
or comparable state law at about 22 sites around the U.S., with active
remediation under way at six of those sites. We received notice of potential
liability at five new sites during 2001, compared with two similar notices in
2000 and four in 1999. Expenditures associated with CERCLA and similar state
remediation activities were not significant for Conoco in 2001, 2000 or 1999.

     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 increased materially. 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 $33 in 2001, $25 in 2000 and $26 in 1999. Although future



                                       105
<PAGE>
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)

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 such expenditures.

     Conoco or DuPont, on behalf of and indemnified by Conoco, has directly
guaranteed borrowings and other obligations of certain affiliated companies and
others. These guarantees totaled $1,097 at December 31, 2001, and $1,090 at
December 31, 2000. The balance at December 31, 2001, included $719 and $150
associated with Petrozuata and Polar Lights, respectively, while the balance at
December 31, 2000, included $706 and $167. Petrozuata has successfully met the
operational requirements of the completion test associated with this guarantee,
and upon acceptance of the financial certificate by the trustee, Conoco will be
released from its guarantee and the debt will become non-recourse to the
sponsors. We expect this release to occur no later than April 2002. In addition,
Conoco owned 7.5 billion shares at December 31, 2001, and 2.0 billion shares at
December 31, 2000, of Turcas Petrol A.S., of which 1,304 million shares at
December 31, 2001, and 909 million shares at December 31, 2000, were pledged to
a group of Turkish banks that issued letters of credit in support of a $70
borrowing. Conoco had no indirect guarantees as of December 31, 2001, and
December 31, 2000.

     Our operations, particularly oil and gas exploration and production, can be
affected by changing economic, regulatory and political environments in the
various countries in which we operate, 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
our continued presence in those countries. Internal unrest or strained relations
between a host government and Conoco or other governments may affect our
operations. Those developments have, at times, significantly affected our
operations and related results and are carefully considered by management when
evaluating the level of current and future activity in such countries. We do
take various steps to minimize our financial exposure to loss including, in
certain cases, obtaining risk insurance coverage. Areas in which we have a
significant active presence include Canada, the Czech Republic, Ecuador,
Germany, Indonesia, Malaysia, the Netherlands, Nigeria, Norway, Russia, Syria,
the United Arab Emirates, the U.K., the U.S., Venezuela and Vietnam.

29.  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; and Canadian Syncrude.
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, distributing and marketing petroleum
products. Emerging businesses operating segment activities include the
development of new businesses beyond our traditional operations. Emerging
businesses currently is involved in carbon fibers (Conoco Cevolution(R));
natural gas refining, including gas-to-liquids; and international power.

     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.

     We sell our products worldwide. In 2001, about 58 percent of sales were
made in the U.S. and 36 percent of sales were made in Europe. In 2000, about 59
percent of sales were made in the U.S. and 36 percent of sales were made in
Europe. Major products include crude oil, natural gas, Canadian Syncrude and
refined products that are sold primarily in the energy and transportation
markets. Our 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.



                                       106
<PAGE>
                   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>
2001
Sales and other operating
 revenues(1)
   Refined products .................  $     --    $     22    $ 11,425    $ 10,696    $     --   $     --   $     --   $ 22,143
   Crude oil ........................        40       1,905       3,674         250          --         --         --      5,869
   Natural gas ......................     5,615       2,509          --          --          --         --         --      8,124
   Canadian Syncrude ................        --          79          --          --          --         --         --         79
   Other ............................     1,373         605         189         350           5         --         --      2,522
                                       --------    --------    --------    --------    --------   --------   --------   --------
        Total .......................     7,028       5,120      15,288      11,296           5         --         --     38,737
Transfers between segments ..........       764         624         173         490          24         --     (2,075)        --
                                       --------    --------    --------    --------    --------   --------   --------   --------
Total operating revenues ............  $  7,792    $  5,744    $ 15,461    $ 11,786    $     29   $     --   $ (2,075)  $ 38,737
                                       ========    ========    ========    ========    ========   ========   ========   ========
Operating profit ....................  $  1,451    $  1,642    $    447    $    159    $   (131)  $   (305)  $     --   $  3,263
Equity in earnings of affiliates ....        33         106          71         (22)         (7)        --         --        181
Corporate non-operating items
   Interest and debt expense ........        --          --          --          --          --       (396)        --       (396)
   Interest income (net of misc.
     interest expense) ..............        --          --          --          --          --         21         --         21
   Other ............................        --          --          --          --          --        (82)        --        (82)
                                       --------    --------    --------    --------    --------   --------   --------   --------
Income before income taxes ..........     1,484       1,748         518         137        (138)      (762)        --      2,987
Income tax expense ..................      (505)       (956)       (186)        (51)         48        259         --     (1,391)
                                       --------    --------    --------    --------    --------   --------   --------   --------
Income before extraordinary
   item and accounting change .......       979         792         332          86         (90)      (503)        --      1,596
Extraordinary item, charge for the
   early extinguishment of debt,
   net of income taxes ..............        --          --          --          --          --        (44)        --        (44)
Cumulative effect of accounting
   change, net of income taxes ......         8          32          (3)         --          --         --         --         37
                                       --------    --------    --------    --------    --------   --------   --------   --------
Net income (loss)(2) ................  $    987    $    824    $    329    $     86    $    (90)  $   (547)  $     --   $  1,589
                                       ========    ========    ========    ========    ========   ========   ========   ========
Capital employed at December 31(3)
   Excluding investment
     in affiliates ..................  $  2,854    $  6,886    $  1,308    $    933    $    194   $    203   $     --   $ 12,378
   Investment in affiliates(4) ......        92       1,129         253         420          --         --         --      1,894
                                       --------    --------    --------    --------    --------   --------   --------   --------
Total capital employed ..............  $  2,946    $  8,015    $  1,561    $  1,353    $    194   $    203   $     --   $ 14,272
                                       ========    ========    ========    ========    ========   ========   ========   ========
  Return on capital employed
     (ROCE)(5) ......................      30.0%       14.5%       25.6%       11.8%        N/A        N/A         --       17.7%
  Significant non-cash items
     DD&A ...........................  $    508    $  1,014    $    140    $    141    $     --   $      8   $     --   $  1,811
     Dry hole costs and impairment of
       unproved properties ..........  $     18    $     98    $     --    $     --    $     --   $     --   $     --   $    116
  Capital expenditures and
     investments(6) .................  $    856    $  1,358    $    164    $    225    $    196   $     36   $     --   $  2,835
  Purchase of Gulf Canada,
     net of cash acquired ...........  $     --    $  4,318    $     --    $     --    $     --   $     --   $     --   $  4,318
Total assets(7) .....................  $  4,378    $ 16,607    $  3,411    $  2,786    $    234   $    488   $     --   $ 27,904

2000
Sales and other operating
 revenues(1)
   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
</Table>

                                       107

<PAGE>
                   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>
2000 (CONT'D.)
   Other .................................        --         --         --         --           --          22         --        22
                                            --------   --------   --------   --------   ----------   ---------   --------  --------
Income before income taxes ...............     1,071      2,333        261        318          (89)       (436)        --     3,458
Income tax expense .......................      (352)    (1,185)       (79)       (88)          20         128         --    (1,556)
                                            --------   --------   --------   --------   ----------   ---------   --------  --------
Net income (loss)(2) .....................  $    719   $  1,148   $    182   $    230   $      (69)  $    (308)  $     --  $  1,902
                                            ========   ========   ========   ========   ==========   =========   ========  ========
Capital employed at December 31(3)
   Excluding investment in affiliates ....  $  2,684   $  3,278   $  1,266   $    918   $       27   $     346   $     --  $  8,519
   Investment in affiliates(4) ...........       162        865        285        490           29          --         --     1,831
                                            --------   --------   --------   --------   ----------   ---------   --------  --------
Total capital employed ...................  $  2,846   $  4,143   $  1,551   $  1,408   $       56   $     346   $     --  $ 10,350
                                            ========   ========   ========   ========   ==========   =========   ========  ========
Return on capital employed (ROCE)(5) .....      24.7%      30.2%      12.8%      18.0%         N/A         N/A         --      22.6%
Significant 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

1999
Sales and other operating revenues(1)
   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
Income tax expense .......................       (67)      (451)       (46)       (56)          19         128         --      (473)
                                            --------   --------   --------   --------   ----------   ---------   --------  --------
Net income (loss)(2) .....................  $    322   $    534   $    119   $    129   $      (35)  $    (325)  $     --  $    744
                                            ========   ========   ========   ========   ==========   =========   ========  ========
Capital employed at December 31(3)
   Excluding investment in affiliates ....  $  2,694   $  2,842   $  1,313   $    884   $       50   $     232   $     --  $  8,015
   Investment in affiliates(4) ...........       166        620        260        526           32          --         --     1,604
                                            --------   --------   --------   --------   ----------   ---------   --------  --------
Total capital employed ...................  $  2,860   $  3,462   $  1,573   $  1,410   $       82   $     232   $     --  $  9,619
                                            ========   ========   ========   ========   ==========   =========   ========  ========

Return on capital employed (ROCE)(5)......      12.1%      16.0%       9.0%       8.8%         N/A         N/A         --      11.0%
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

</Table>

----------
(1)  Includes sales of purchased products substantially at cost:


<Table>
<Caption>

                                                                2001       2000        1999
                                                             ----------- ---------- -----------
<S>                                                          <C>         <C>        <C>
Buy/sell supply transactions settled in cash
    Crude oil..............................................  $    3,770  $   4,786  $    3,282
    Refined products.......................................  $    1,803  $   1,703  $      747
Natural gas resales........................................  $    3,931  $   2,551  $    1,242
Electric power resales.....................................  $        5  $       4  $       28
</Table>


                                       108
<PAGE>
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)


    Sales to equity affiliates totaled $1,690 for 2001, $2,200 for 2000 and
    $1,519 for 1999. The majority of these sales was in downstream and
    represented refined products.

(2) Includes after-tax benefits (charges) from the following items:

<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>
2001
Asset sales ...............................  $    134   $    --    $     --   $     --    $        --  $     --   $    --  $   134
Affiliate sales and write-downs ...........        23        --         (23)       (23)            --        --        --      (23)
Foreign currency exchange loss ............        --        --          --         --             --       (38)       --      (38)
Cumulative effect of accounting change ....         8        32          (3)        --             --        --        --       37
Assets held for sale and
  other write-downs .......................       (44)      (87)         --         --             --        --        --     (131)
Premium on debt retirement ................        --        --          --         --             --       (44)       --      (44)
Humber fire repairs .......................        --        --          --        (54)            --        --        --      (54)
Discontinued businesses ...................        --        --          --         --             --       (70)       --      (70)
Litigation ................................        --        --         (41)        --             --        --        --      (41)
Other .....................................        --        --          --         --             --        (4)       --       (4)
                                             --------   -------    --------   --------    -----------  --------   -------  -------
Total special items .......................  $    121   $   (55)   $    (67)  $    (77)   $        --  $   (156)  $    --  $  (234)
                                             ========   =======    ========   ========    ===========  ========   =======  =======

2000
Asset sales ...............................  $     27   $    --    $     --   $     --      $      --  $     --   $    --  $    27
Affiliate sales and write-downs ...........        --        --          --         --            (26)       --        --      (26)
Inventory write-downs .....................        --        --          --        (24)            --        --        --      (24)
Assets held for sale and
  other write-downs .......................        --        --          (3)        --             --        --        --       (3)
Discontinued businesses ...................        --        --          --         --             --        (4)       --       (4)
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)
                                             ========   =======    ========   ========    ===========  ========   =======  =======
</Table>

    Special items in 2001 included gains of $194, consisting of:

     o     $134 from the sale of several shallow Gulf of Mexico properties;

     o     $23 from the sale of our interest in the Pocahontas Gas Partnership;
           and

     o     $37 from a cumulative transition gain recorded on January 1, 2001,
           upon initial adoption of SFAS No. 133, as amended.

     The cumulative transition gain of $37 included a $40 gain in upstream
related to changes in the fair value of certain crude oil put options from their
purchase date to the January 1, 2001, adoption of the aforementioned standards
and a $3 charge in U.S. downstream associated with various derivatives. The $40
upstream transition gain consisted of $8 that was U.S. related and $32 that was
related to international operations. Offsetting this transition gain and
included in net income for upstream was a $53 expense for 2001 related to
changes in the fair value of these same crude oil put options. The $53 expense
for 2001 consisted of $10 for U.S. operations and $43 for international
operations.

     Offsetting these gains were:

     o     downstream affiliate sales and write-downs of $46, consisting of a
           $23 write-down of a U.S. joint-venture investment held for sale and
           a $23 write-down of an international joint-venture investment held
           for sale;

     o     a $38 foreign currency exchange loss from changes in the fair value
           of Canadian dollar forward exchange contracts related to the
           acquisition of Gulf Canada;

     o     upstream assets held for sale and other write-downs of $131,
           consisting of a $44 write-down of certain U.S. producing assets held
           for sale and an $87 write-down of Canadian legacy assets held for
           sale;

     o     $44 for extraordinary item charges for premiums on the early
           repayment of high-cost Gulf Canada debt;

     o     a $54 charge to record repairs and other costs associated with the
           April 16, 2001, explosion and fire at our Humber refinery in North
           Lincolnshire, U.K.;

     o     an accrual of $70 for a litigation settlement for a discontinued
           business related to the separation agreement from DuPont;

     o     a $41 charge related to an adverse ruling on the patent dispute with
           GTA; and

                                       109
<PAGE>
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)


     o     $4 in costs associated with the ConocoPhillips merger.

     Special items in 2000 included a $27 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 business built
on centralized, large-scale gas processing systems.

     The following charges also were recorded during 2000:

     o     affiliate sales and write-downs of $26;

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

     o     assets held for sale and other write-downs of $3 for U.S. refinery
           assets;

     o     $4 from discontinued businesses; and

     o     $16 from U.S. downstream litigation charges.

     The after-tax affiliate sales and write-downs were the result of our
write-off of $26 related to our 37.5 percent interest in a Colombian power
venture. The Colombian power venture write-off was due to unfavorable business
conditions in Colombia. In October 1996, Conoco Global Energy purchased shares
in a Colombian power venture that was formed to generate and market electric
power by means of a gas-fired electrical generating facility near
Barrancabermeja, Colombia. The gas-fired plant became operational in August 1998
and received capacity payments for idle periods. With the deterioration of the
Colombian economy, the plant suffered small losses in 1998 and 1999. The
continued weak demand for electricity created a large surplus in generating
capacity, prompting a reduction in the capacity payment rate for 2000. A
combination of lower capacity payment revenue, continued weak demand for
electricity, onerous gas supply contract provisions, safety and security
concerns from continued guerrilla activity, and forecasted losses for 2000
prompted management's decision in the third quarter of 2000 to exit the venture,
resulting in a revaluation of the investment. After pursuing various options,
Conoco's interest was sold in February 2001 for a nominal amount.

     The $24 write-down of inventories at year-end 2000 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 $33.00 per barrel to $23.00 per barrel during December. The $4
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 related to the settlement of
certain posted price litigation and $20 for the resolution of certain
liabilities associated with the separation from DuPont related to discontinued
businesses operated by Conoco in the past.

     Net income before special items (earnings before special items) totaled
$1,823 in 2001, $1,948 in 2000 and $782 in 1999.

(3)  Capital employed is equivalent to the sum of stockholders' equity,
     minority interests and borrowings (both short-term and long-term) and
     excludes goodwill. 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 $822,
     $693 and $445 for 2001, 2000 and 1999, respectively.

(5)  ROCE is a measure of annual net income before special items, excluding
     after-tax debt cost incurred and minority interests incurred, generated as
     a percentage of the two-year average capital employed as defined above.

(6)  Includes investments in affiliates.

(7)  Includes goodwill arising from the third quarter 2001 acquisition of
     Gulf Canada. Upon full implementation in 2002 of SFAS No. 142, this amount
     will be disclosed in the reporting segments that include the "Reporting
     Units" to which this goodwill must be allocated in accordance with the
     requirement of this standard.


<Table>
<Caption>

                                                                                                            OTHER
GEOGRAPHIC INFORMATION                           U.S.       CANADA       U.K.      GERMANY     NORWAY     COUNTRIES   CONSOLIDATED
                                              ---------   ---------   ---------   ---------   ---------   ---------   ------------

<S>                                           <C>         <C>         <C>         <C>         <C>         <C>           <C>
2001
Sales and other operating revenues(1) .....   $  22,321   $   1,112   $   7,732   $   3,518   $     577   $   3,477     $  38,737
Long-lived assets at December 31(2)  ......   $   5,792   $   4,514   $   3,292   $     145   $   1,711   $   2,464     $  17,918

2000
Sales and other operating revenues(1)  ....   $  22,914   $     372   $   7,851   $   3,606   $     474   $   3,520     $  38,737
Long-lived assets at December 31(2)  ......   $   5,492   $     515   $   3,662   $     143   $   1,473   $     922     $  12,207

1999
Sales and other operating revenues(1) .....   $  14,528   $      46   $   5,950   $   3,150   $     330   $   3,035     $  27,039
Long-lived assets at December 31(2)  ......   $   5,192   $     300   $   3,265   $     154   $   1,574   $     750     $  11,235
</Table>


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

(1)  Revenues are attributed to countries based on location of the selling
     entity.

(2)  Represents net PP&E.


                                       110
<PAGE>

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


30.  INVESTING ACTIVITIES

     In 2001, purchases of businesses included $4,571 cash paid for Gulf Canada.
See note 3 for details of the acquisition. Purchases of businesses in 2000
included a third quarter cash purchase of Saga U.K. Ltd. for $545, which was
allocated $796 to fixed assets, $92 to other assets and $343 to liabilities
assumed. In 1999, Conoco purchased substantially all of Petro-Canada's natural
gas liquids business for $176 cash, which was allocated $189 to fixed assets, $9
to working capital and $22 to deferred taxes and liabilities assumed. The pro
forma effect on prior period revenue, net income and earnings per share was not
material.

     Non-cash additions to PP&E were $61 for 2001, $41 for 2000 and zero for
1999.

     Total proceeds in 2001 from the sales of assets of $795 included the
shallow Gulf of Mexico properties for $294; the third quarter sale of our 50
percent interest in the Pocahontas Gas Partnership for $152; Lobo natural gas
properties for $69; and the disposition of various U.K. retail assets for $98.
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 single
asset sale in 1999. The after-tax earnings impact of such asset sales was a gain
of $197 in 2001, $47 in 2000 and $10 in 1999.

     The carrying value of assets held for sale, primarily upstream property,
plant and equipment, totaled $42 at December 31, 2001, and zero at December 31,
2000.

31.  OTHER FINANCIAL INFORMATION

     Research and development expenses were $96 for 2001, $58 for 2000, and $54
for 1999.

32.  TRANSACTIONS WITH DUPONT

     As disclosed in note 1, DuPont ceased to be a related party effective
August 6, 1999. However, the 1999 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.

     Amounts charged to Conoco for these services were $21 for 1999. These
amounts were principally included in selling, general and administrative
expenses. We 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. 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 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.

     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.

     In connection with the separation from DuPont and the initial public
offering, Conoco and DuPont entered into a Tax Sharing Agreement and a
Restructuring, Transfer and Separation Agreement. Certain disputes arose under
these agreements and on November 8, 2001, these matters were settled. The $93
net effect of this settlement is included in additional paid-in capital as an
adjustment to capitalization from DuPont.

33.  SUBSEQUENT AND OTHER EVENTS

     On November 18, 2001, Conoco and Phillips Petroleum Company (Phillips)
announced that their boards of directors unanimously approved the merger of the
two companies. The new company will be named ConocoPhillips. Under the terms of
the agreement, Phillips shareholders will receive one share of new
ConocoPhillips common stock for each share of Phillips stock they own, and
Conoco shareholders will receive .4677 shares of new ConocoPhillips common stock
for each share they own. The merger is conditioned upon, among other things, the
approvals of the shareholders of each company and customary regulatory
approvals. Both



                                       111
<PAGE>

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


companies intend to hold special meetings of stockholders on Tuesday, March 12,
2002, to seek approval of the proposed merger. Completion of the transaction is
expected in the second half of 2002.

     On February 14, 2002, Gulf Canada announced that its board of directors
approved the redemption of its Series I and Series II preferred stock and its
6.45 percent senior unsecured Canadian $100 notes due 2007. The Series II
preferred shares will be redeemed on April 10, 2002, at a cost of Canadian $150;
while both the Series I preferred shares and the 6.45 percent senior unsecured
notes will be redeemed on April 22, 2002, at a cost of Canadian $472 and
Canadian $106, respectively. See notes 20 and 22 for further details.

     In January 2002, Immingham CHP, L.L.P., a subsidiary of Conoco, executed a
British pound 257 million bank facility for the planned construction of a 730-
megawatt combined heat and power cogeneration plant near our Humber refinery in
the U.K. The bank facility is designed to provide 65 percent of the construction
costs of the project with the remaining 35 percent of the funds coming in the
form of equity from certain Conoco subsidiaries. Borrowing under the bank
facility is not projected to begin until September 2002. In addition, we have
issued a construction support guarantee that indirectly guarantees up to
approximately 25 percent of the debt depending upon the initial operating
performance of the plant. This guarantee will be released upon meeting the
various completion tests as required by the lenders. Subsequent to closing the
facility and as required by the lender to mitigate certain risks, Immingham CHP
entered into related foreign currency and interest rate derivative hedging
instruments.




                                       112
<PAGE>
                           SUPPLEMENTAL PETROLEUM DATA
                                   (UNAUDITED)
                              (DOLLARS IN MILLIONS)

OIL AND GAS PRODUCING ACTIVITIES AND SYNCRUDE MINING OPERATIONS

     Supplemental Petroleum Data is comprised of information related to oil, gas
and Canadian oil sands. Oil and gas disclosures are presented in accordance with
SFAS No. 69, "Disclosures about Oil and Gas Producing Activities." Management
views the oil sands reserves related to the Canadian Syncrude project and their
development as an integral part of the oil and gas operations of the company.
However, generally accepted accounting principles define these reserves as
mining related and exclude these reserves from the conventional definition of
oil and gas reserves. As a result, oil sands information, identified as
"Syncrude Oil - Canada," is presented separately in the following Supplemental
Petroleum Data.

RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES AND SYNCRUDE MINING
OPERATIONS


<Table>
<Caption>
                                                      OIL AND GAS PRODUCING ACTIVITIES
                                -----------------------------------------------------------------------
                                                                                  TOTAL                  SYNCRUDE
                                  UNITED                              OTHER   CONSOLIDATED   EQUITY        OIL-       TOTAL
                                  STATES     CANADA      EUROPE      REGIONS    COMPANIES  COMPANIES(6)  CANADA(7)  WORLDWIDE
                                ---------   ---------   ---------   --------- ------------ ------------ ----------  ---------
<S>                             <C>         <C>         <C>         <C>         <C>         <C>         <C>         <C>
DECEMBER 31, 2001
Revenues
   Sales(1) ................... $   1,258   $     415   $   1,843   $     879   $   4,395   $     374   $      79   $   4,848
   Transfers ..................       525          33         503          (1)      1,060          --          --       1,060
Exploration(2) ................       (82)        (66)        (71)       (159)       (378)         --          --        (378)
Production ....................      (392)       (164)       (464)       (248)     (1,268)       (188)        (41)     (1,497)
DD&A(3) .......................      (453)       (346)       (570)        (90)     (1,459)        (65)         (6)     (1,530)
Other(4)(5) ...................       472          15           7          31         525          10          (1)        534
Income taxes ..................      (439)         20        (591)       (350)     (1,360)         24         (12)     (1,348)
                                ---------   ---------   ---------   ---------   ---------   ---------   ---------   ---------
Total results of operations ... $     889   $     (93)  $     657   $      62   $   1,515   $     155   $      19   $   1,689
                                =========   =========   =========   =========   =========   =========   =========   =========
DECEMBER 31, 2000
Revenues
   Sales ...................... $   1,022   $     126   $   1,573   $     773   $   3,494   $     399   $      --   $   3,893
   Transfers ..................       688          --         731           1       1,420          --          --       1,420
Exploration(2) ................      (121)        (14)        (59)        (85)       (279)         --          --        (279)
Production ....................      (324)        (34)       (369)       (145)       (872)       (118)         --        (990)
DD&A ..........................      (366)        (31)       (526)        (50)       (973)        (31)         --      (1,004)
Other(4) ......................       (27)          2          73          15          63           5          --          68
Income taxes ..................      (293)        (26)       (698)       (373)     (1,390)        (38)         --      (1,428)
                                ---------   ---------   ---------   ---------   ---------   ---------   ---------   ---------
Total results of operations ... $     579   $      23   $     725   $     136   $   1,463   $     217   $      --   $   1,680
                                =========   =========   =========   =========   =========   =========   =========   =========
DECEMBER 31, 1999
Revenues
   Sales ...................... $     646   $      45   $   1,192   $     506   $   2,389   $     212   $      --   $   2,601
   Transfers ..................       384          --         478          --         862          --          --         862
Exploration(2) ................       (64)         (8)        (62)       (136)       (270)         --          --        (270)
Production ....................      (287)        (11)       (433)       (120)       (851)        (81)         --        (932)
DD&A ..........................      (338)         (9)       (491)        (49)       (887)        (33)         --        (920)
Other(4) ......................        13          --           6          (1)         18          --          --          18
Income taxes ..................       (87)         10        (272)       (152)       (501)          8          --        (493)
                                ---------   ---------   ---------   ---------   ---------   ---------   ---------   ---------
Total results of operations ... $     267   $      27   $     418   $      48   $     760   $     106   $      --   $     866
                                =========   =========   =========   =========   =========   =========   =========   =========
</Table>

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

(1)      2001 includes $38 in hedge realizations in the U.S.

(2)      Includes exploration operating expenses, dry hole costs and impairment
         of unproved properties and depreciation.

(3)      Includes impairment of assets held for sale in 2001 of $69 in the U.S.
         and $127 in Canada.

(4)      Includes gain/(loss) on disposal of fixed assets and other
         miscellaneous revenues and expenses.

(5)      Includes mark-to-market gains on derivatives not designated as hedges
         under SFAS No. 133, as amended, of $214 in the U.S. and $10 in Canada.

(6)      Includes our net share of equity affiliate information.

(7)      Represents our 9.03 percent undivided interest in the Syncrude oil
         project.




                                       113
<PAGE>
                           SUPPLEMENTAL PETROLEUM DATA
                                   (UNAUDITED)
                              (DOLLARS IN MILLIONS)


COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT
ACTIVITIES AND SYNCRUDE MINING OPERATIONS(1)


<Table>
<Caption>

                                                 OIL AND GAS PRODUCING ACTIVITIES
                         --------------------------------------------------------------------------------
                                                                                 TOTAL                     SYNCRUDE
                           UNITED                                  OTHER      CONSOLIDATED     EQUITY        OIL -         TOTAL
                           STATES        CANADA       EUROPE      REGIONS      COMPANIES     COMPANIES(4)  CANADA(5)     WORLDWIDE
                         -----------  -----------  -----------  ------------  ------------  ------------- ------------  ------------
<S>                      <C>          <C>          <C>          <C>           <C>           <C>           <C>           <C>
DECEMBER 31, 2001
Property acquisitions
    Proved(2)(3) ......  $       189  $     2,372  $       401  $        588  $      3,550  $        125  $        525  $      4,200
    Unproved ..........           12        1,115           44           401         1,572            17           270         1,859
Exploration ...........          122           67           96           254           539            --            --           539
Development ...........          544          247          350           223         1,364           176            43         1,583
                         -----------  -----------  -----------  ------------  ------------  ------------  ------------  ------------
Total .................  $       867  $     3,801  $       891  $      1,466  $      7,025  $        318  $        838  $      8,181
                         ===========  ===========  ===========  ============  ============  ============  ============  ============

DECEMBER 31, 2000
Property acquisitions
    Proved(2)(3) ......  $        24  $         1  $       776  $         24  $        825  $         --  $         --  $        825
    Unproved ..........            6            5           11            70            92            --            --            92
Exploration ...........          125           11           61           102           299            --            --           299
Development ...........          398           38          335           137           908           320            --         1,228
                         -----------  -----------  -----------  ------------  ------------  ------------  ------------  ------------
Total .................  $       553  $        55  $     1,183  $        333  $      2,124  $        320  $         --  $      2,444
                         ===========  ===========  ===========  ============  ============  ============  ============  ============

DECEMBER 31, 1999
Property acquisitions
    Proved(2)(3) ......  $         6  $       180  $        --  $         --  $        186  $         --  $         --  $        186
    Unproved ..........            1            6           12            --            19            --            --            19
Exploration ...........           97            3           72           104           276            --            --           276
Development ...........          304           19          342            72           737           337            --         1,074
                         -----------  -----------  -----------  ------------  ------------  ------------  ------------  ------------
Total .................  $       408  $       208  $       426  $        176  $      1,218  $        337  $         --  $      1,555
                         ===========  ===========  ===========  ============  ============  ============  ============  ============
</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 are shown after a gross up for SFAS No. 109,
         "Accounting for Income Taxes" of $190 in 2001 and $204 in 2000 for
         European properties; and a gross up of $48 in 1999 for Canadian
         properties.

(4)      Includes our net share of equity affiliate information.

(5)      Represents our 9.03 percent undivided interest in the Syncrude oil
         project.


                                       114
<PAGE>


                           SUPPLEMENTAL PETROLEUM DATA
                                   (UNAUDITED)
                              (DOLLARS IN MILLIONS)


CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES AND SYNCRUDE
MINING OPERATIONS

<Table>
<Caption>

                                                   OIL AND GAS PRODUCING ACTIVITIES
                                    --------------------------------------------------------------
                                                                        TOTAL                    SYNCRUDE
                                    UNITED                   OTHER   CONSOLIDATED     EQUITY       OIL -      TOTAL
                                    STATES  CANADA  EUROPE  REGIONS   COMPANIES    COMPANIES(1)  CANADA(2)  WORLDWIDE
                                    ------  ------  ------  -------  ------------  ------------  ---------  ---------

<S>                                 <C>     <C>     <C>     <C>      <C>           <C>           <C>        <C>
DECEMBER 31, 2001
Gross costs
    Proved properties ............. $5,224  $2,917  $8,116  $ 2,284    $ 18,541      $   1,884    $   544   $  20,969
    Unproved properties ...........    373   1,122     321      708       2,524             16        258       2,798
Less
    Accumulated DD&A ..............  2,721     491   4,112    1,338       8,662            200          5       8,867
                                    ------  ------  ------  -------    --------      ---------    -------   ---------
Total net costs ................... $2,876  $3,548  $4,325  $ 1,654    $ 12,403      $   1,700    $   797   $  14,900
                                    ======  ======  ======  =======    ========      =========    =======   =========

DECEMBER 31, 2000
Gross costs
    Proved properties ............. $5,266  $  490  $7,461  $ 1,513    $ 14,730      $   1,728    $    --   $  16,458
    Unproved properties ...........    497      56     322      231       1,106             --         --       1,106
Less
    Accumulated DD&A ..............  3,099     185   3,668    1,245       8,197            164         --       8,361
                                    ------  ------  ------  -------    --------      ---------    -------   ---------
Total net costs ................... $2,664  $  361  $4,115  $   499    $  7,639      $   1,564    $    --   $   9,203
                                    ======  ======  ======  =======    ========      =========    =======   =========

DECEMBER 31, 1999
Gross costs
    Proved properties ............. $4,968  $  396  $6,939  $ 1,358    $ 13,661      $   1,411    $    --   $  15,072
    Unproved properties ...........    651      51     331      168       1,201             --         --       1,201
Less
    Accumulated DD&A ..............  3,024     147   3,507    1,209       7,887            134         --       8,021
                                    ------  ------  ------  -------    --------      ---------    -------   ---------
Total net costs ................... $2,595  $  300  $3,763  $   317    $  6,975      $   1,277    $    --   $   8,252
                                    ======  ======  ======  =======    ========      =========    =======   =========
</Table>



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

(1)      Includes our net share of equity affiliate information.

(2)      Represents our 9.03 percent undivided interest in the Syncrude oil
         project.



                                       115
<PAGE>



                           SUPPLEMENTAL PETROLEUM DATA
                                   (UNAUDITED)


     The SEC defines proved reserves as the quantities of crude oil, condensate,
natural gas liquids and natural gas that geological and engineering data
demonstrate with reasonable certainty are recoverable in future years from known
reservoirs under existing economic and operating conditions. Proved developed
reserves are those volumes that are expected to be recovered through existing
wells with existing equipment and operating methods. Proved undeveloped reserves
are those volumes that are expected to be recovered as a result of future
investments to drill new wells; recompletion of existing wells; and/or
installation of facilities to collect and deliver the production from existing
and future wells. In addition to conventional liquids and natural gas proved
reserves defined by the SEC, we have significant interests in proven oil sands
in Canada associated with the Syncrude oil project.

ESTIMATED PROVED RESERVES OF OIL, GAS AND SYNCRUDE IN MILLIONS OF
BARRELS-OF-OIL-EQUIVALENT (MMBOE)

<Table>
<Caption>

                                              OIL AND GAS PRODUCING ACTIVITIES(1)(2)
                                       -----------------------------------------------------
                                               CONSOLIDATED COMPANIES(3)           EQUITY       SYNCRUDE
                                       --------------------------------------    COMPANIES        OIL -        TOTAL
                                           OIL          GAS           TOTAL     OIL & GAS(4)    CANADA(5)    WORLDWIDE
                                       ----------    ----------    ----------   ------------    ---------    ---------

<S>                                    <C>           <C>         <C>             <C>            <C>          <C>
DECEMBER 31, 2001
Beginning of year ..................          828           956         1,784            863           --        2,647
Revisions and other changes ........           15             8            23            (43)           3          (17)
Extensions and discoveries .........          156           159           315              4           --          319
Improved recovery ..................           10             5            15             --           --           15
Purchase of reserves(6) ............          225           447           672             39          281          992
Sale of reserves ...................          (25)          (19)          (44)           (52)          --          (96)
Production .........................         (127)         (122)         (249)           (28)          (4)        (281)
                                       ----------    ----------    ----------   ------------    ---------    ---------
End of year ........................        1,082         1,434         2,516            783          280        3,579
                                       ==========    ==========    ==========   ============    =========    =========

DECEMBER 31, 2000
Beginning of year ..................          788           967         1,755            799           --        2,554
Revisions and other changes ........           46           (30)           16             (1)          --           15
Extensions and discoveries .........           56            86           142             87           --          229
Improved recovery ..................           --            --            --             --           --           --
Purchase of reserves ...............           55            37            92             --           --           92
Sale of reserves ...................           (2)           (1)           (3)            --           --           (3)
Production .........................         (115)         (103)         (218)           (22)          --         (240)
                                       ----------    ----------    ----------   ------------    ---------    ---------
End of year ........................          828           956         1,784            863           --        2,647
                                       ==========    ==========    ==========   ============    =========    =========

DECEMBER 31, 1999
Beginning of year ..................          863           967         1,830            792           --        2,622
Revisions and other changes ........           (6)            1            (5)             2           --           (3)
Extensions and discoveries .........           54            75           129             21           --          150
Improved recovery ..................           --            --            --             --           --           --
Purchase of reserves ...............            1            29            30             --           --           30
Sale of reserves ...................           (8)           (5)          (13)            --           --          (13)
Production .........................         (116)         (100)         (216)           (16)          --         (232)
                                       ----------    ----------    ----------   ------------    ---------    ---------
End of year ........................          788           967         1,755            799           --        2,554
                                       ==========    ==========    ==========   ============    =========    =========
</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)      Natural gas has been converted to liquids at a ratio of 6,000 cubic
         feet of natural gas to 1 barrel of liquid.

(3)      2001 includes a minority interest holding of 67 MMBOE.

(4)      Includes our net share of equity affiliate information.

(5)      Proven oil sands reserves are attributable to our 9.03 percent
         undivided interest in the Syncrude oil project after deducting
         estimated net profit royalty. Additional reserves will be added as
         development progresses.

(6)      Purchase of reserves in 2001 includes 928 MMBOE for Gulf Canada.



                                       116
<PAGE>

                           SUPPLEMENTAL PETROLEUM DATA
                                   (UNAUDITED)


ESTIMATED PROVED RESERVES OF OIL AND SYNCRUDE IN MILLIONS OF BARRELS

<Table>
<Caption>

                                                     OIL AND GAS PRODUCING ACTIVITIES(1)
                                    -------------------------------------------------------------------------
                                                                                        TOTAL                  SYNCRUDE
                                      UNITED                              OTHER     CONSOLIDATED   EQUITY        OIL -      TOTAL
                                      STATES      CANADA      EUROPE    REGIONS(7)   COMPANIES   COMPANIES(4)  CANADA(6)  WORLDWIDE
                                    ----------  ----------  ----------  ----------   ----------  ------------ ----------  ---------

<S>                                 <C>         <C>         <C>         <C>          <C>         <C>         <C>         <C>

DECEMBER 31, 2001
Beginning of year .................        249           7         405         167          828         810          --       1,638
Revisions and other changes .......         (3)         --         (17)         35           15         (43)          3         (25)
Extensions and discoveries ........         50           3          61          42          156           3          --         159
Improved recovery .................         --          --          --          10           10          --          --          10
Purchase of reserves(2)(5) ........         --         165          34          26          225          37         281         543
Sale of reserves(3) ...............        (25)         --          --          --          (25)         --          --         (25)
Production ........................        (27)        (11)        (57)        (32)        (127)        (27)         (4)       (158)
                                    ----------  ----------  ----------  ----------   ----------  ----------  ----------  ----------
End of year .......................        244         164         426         248        1,082         780         280       2,142
                                    ==========  ==========  ==========  ==========   ==========  ==========  ==========  ==========

DECEMBER 31, 2000
Beginning of year .................        238           8         383         159          788         742          --       1,530
Revisions and other changes .......         23          --          16           7           46           2          --          48
Extensions and discoveries ........         19          --          18          19           56          87          --         143
Improved recovery .................         --          --          --          --           --          --          --          --
Purchase of reserves(2) ...........         --          --          45          10           55          --          --          55
Sale of reserves(3) ...............         (2)         --          --          --           (2)         --          --          (2)
Production ........................        (29)         (1)        (57)        (28)        (115)        (21)         --        (136)
                                    ----------  ----------  ----------  ----------   ----------  ----------  ----------  ----------
End of year .......................        249           7         405         167          828         810          --       1,638
                                    ==========  ==========  ==========  ==========   ==========  ==========  ==========  ==========

DECEMBER 31, 1999
Beginning of year .................        261          11         410         181          863         728          --       1,591
Revisions and other changes .......          4          (2)         (5)         (3)          (6)          8          --           2
Extensions and discoveries ........          7          --          37          10           54          21          --          75
Improved recovery .................         --          --          --          --           --          --          --          --
Purchase of reserves(2) ...........          1          --          --          --            1          --          --           1
Sale of reserves(3) ...............         (8)         --          --          --           (8)         --          --          (8)
Production ........................        (27)         (1)        (59)        (29)        (116)        (15)         --        (131)
                                    ----------  ----------  ----------  ----------   ----------  ----------  ----------  ----------
End of year .......................        238           8         383         159          788         742          --       1,530
                                    ==========  ==========  ==========  ==========   ==========  ==========  ==========  ==========


PROVED DEVELOPED RESERVES IN MILLIONS OF BARRELS

December 31, 2001.............             192         137         226         154          709         289         155       1,153
December 31, 2000.............             215           6         256         130          607         193          --         800
December 31, 1999.............             202           7         217         139          565         129          --         694
December 31, 1998.............             222           8         228         164          622          92          --         714
</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 disposed of through property trades.

(4)      Includes our net share of equity affiliate information.

(5)      Purchase of reserves in 2001 includes 510 MMBOE for Gulf Canada.

(6)      Proven oil sands reserves are attributable to our 9.03 percent
         undivided interest in the Syncrude oil project, after deducting
         estimated net profit royalty. Additional reserves will be added as
         development progresses.

(7)      Other Regions includes a minority interest holding of 5 MMBOE for 2001.


                                       117

<PAGE>


                           SUPPLEMENTAL PETROLEUM DATA
                                   (UNAUDITED)


ESTIMATED PROVED RESERVES OF GAS IN BILLION CUBIC FEET (bcf)


<Table>
<Caption>

                                                     OIL AND GAS PRODUCING ACTIVITIES
                                    -------------------------------------------------------------------------
                                                                                        TOTAL
                                      UNITED                              OTHER     CONSOLIDATED     EQUITY       TOTAL
                                      STATES      CANADA      EUROPE    REGIONS(7)   COMPANIES    COMPANIES(6)  WORLDWIDE
                                    ----------  ----------  ----------  ----------  ------------  ------------  ---------

<S>                                 <C>         <C>         <C>         <C>          <C>          <C>           <C>

DECEMBER 31, 2001
Beginning of year .................      2,061         327       2,837         511         5,736           317      6,053
Revisions and other changes(1) ....        (56)        (56)         76          84            48             1         49
Extensions and discoveries ........        354          94         356         148           952             8        960
Improved recovery .................         --          --          26          --            26            --         26
Purchase of reserves(2)(3) ........        175       1,166         116       1,227         2,684            14      2,698
Sale of reserves(4) ...............       (105)         --          (7)         --          (112)         (314)      (426)
Production ........................       (291)       (111)       (301)        (31)         (734)           (7)      (741)
                                     ---------   ---------   ---------   ---------   -----------   -----------   --------
End of year .......................      2,138       1,420       3,103       1,939         8,600            19      8,619
                                     =========   =========   =========   =========   ===========   ===========   ========

DECEMBER 31, 2000
Beginning of year .................      2,166         385       2,884         364         5,799           343      6,142
Revisions and other changes(1)(5)..       (110)        (39)         42         (69)         (176)          (19)      (195)
Extensions and discoveries ........        284          14           1         216           515            --        515
Purchase of reserves(2) ...........         19          --         203          --           222            --        222
Sales of reserves(4) ..............         (7)         --          --          --            (7)           --         (7)
Production ........................       (291)        (33)       (293)         --          (617)           (7)      (624)
                                     ---------   ---------   ---------   ---------   -----------   -----------   --------
End of year .......................      2,061         327       2,837         511         5,736           317      6,053
                                     =========   =========   =========   =========   ===========   ===========   ========

DECEMBER 31, 1999
Beginning of year .................      2,319         234       3,053         196         5,802           381      6,183
Revisions and other changes(1) ....        (34)         (4)         31          14             7           (35)       (28)
Extensions and discoveries ........        219           8          65         154           446            --        446
Purchase of reserves(2) ...........          8         166          --          --           174             3        177
Sale of reserves(4) ...............        (30)         --          --          --           (30)           --        (30)
Production ........................       (316)        (19)       (265)         --          (600)           (6)      (606)
                                     ---------   ---------   ---------   ---------   -----------   -----------   --------
End of year .......................      2,166         385       2,884         364         5,799           343      6,142
                                     =========   =========   =========   =========   ===========   ===========   ========
</Table>


<Table>
<Caption>

PROVED DEVELOPED RESERVES IN BILLION CUBIC FEET

<S>                                      <C>         <C>         <C>           <C>       <C>           <C>       <C>
December 31, 2001..................      1,868       1,260       2,205         679       6,012          17       6,029
December 31, 2000..................      1,788         292       2,295          --       4,375          74       4,449
December 31, 1999..................      1,792         355       2,017          --       4,164          72       4,236
December 31, 1998..................      1,828         209       1,954          --       3,991          66       4,057
</Table>


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

(1)      Includes Other Regions' price-driven revisions to gas reserve
         entitlements under production-sharing contracts and similar
         arrangements.

(2)      Includes reserves acquired through property trades.

(3)      Purchase of reserves in 2001 includes 2,503 bcf for Gulf Canada.

(4)      Includes reserves disposed of through property trades.

(5)      Year 2000 data includes revisions due to wet gas and natural gas
         liquids accounting realignment in the U.S. This resulted in net
         additional reserves of 11 MMBOE.

(6)      Includes our net share of equity affiliate information.

(7)      In 2001, Other Regions includes a minority interest holding of 376 bcf.



                                       118

<PAGE>

                           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, 2001, data averaged $16.72 for the U.S., $17.31 for
Canada, $17.79 for Europe and $18.43 for other regions. The gas prices per
thousand cubic feet averaged $2.41 for the U.S., $1.96 for Canada, $3.64 for
Europe and $2.65 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. Future net cash flows
from our interest in Canadian Syncrude are excluded, as are gains from closing
current commodity hedge positions.

     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 information presented on the following
page, 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.




                                       119
<PAGE>


                           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
                                       UNITED                              OTHER       CONSOLIDATED      EQUITY           TOTAL
                                       STATES     CANADA      EUROPE     REGIONS(3)     COMPANIES      COMPANIES(1)     WORLDWIDE
                                     ---------   ---------   ---------   ----------    ------------    ------------     ---------
<S>                                  <C>         <C>         <C>         <C>            <C>            <C>              <C>
DECEMBER 31, 2001
Future cash flows
   Revenues .......................  $   8,769   $   5,465   $  18,729   $    9,295    $     42,258    $      8,748     $  51,006
   Production costs ...............     (2,919)     (2,599)     (5,007)      (2,827)        (13,352)         (2,120)      (15,472)
   Development costs ..............       (440)       (378)     (1,543)      (1,535)         (3,896)           (724)       (4,620)
   Income tax expense .............     (1,290)       (727)     (5,669)      (2,469)        (10,155)         (1,184)      (11,339)
                                     ---------   ---------   ---------   ----------    ------------    ------------     ---------
Future net cash flows .............      4,120       1,761       6,510        2,464          14,855           4,720        19,575
Discounted to present value at a
   10% annual rate ................     (1,806)       (707)     (2,226)      (1,365)         (6,104)         (3,042)       (9,146)
                                     ---------   ---------   ---------   ----------    ------------    ------------     ---------

Total(2) ..........................  $   2,314   $   1,054   $   4,284   $    1,099    $      8,751    $      1,678     $  10,429
                                     =========   =========   =========   ==========    ============    ============     =========

DECEMBER 31, 2000
Future cash flows
   Revenues .......................  $  25,990   $   3,174   $  17,664   $    5,346    $     52,174    $     15,366     $  67,540
   Production costs ...............     (3,342)       (333)     (4,794)      (1,229)         (9,698)         (1,578)      (11,276)

   Development costs ..............       (304)        (37)       (627)        (936)         (1,904)         (1,239)       (3,143)
   Income tax expense .............     (7,505)       (794)     (6,515)      (2,078)        (16,892)         (3,341)      (20,233)
                                     ---------   ---------   ---------   ----------    ------------    ------------     ---------

Future net cash flows .............     14,839       2,010       5,728        1,103          23,680           9,208        32,888
Discounted to present value at a
   10% annual rate ................     (6,350)       (754)     (1,699)        (538)         (9,341)         (5,771)      (15,112)
                                     ---------   ---------   ---------   ----------    ------------    ------------     ---------
Total .............................  $   8,489   $   1,256   $   4,029   $      565    $     14,339    $      3,437     $  17,776
                                     =========   =========   =========   ==========    ============    ============     =========

DECEMBER 31, 1999
Future cash flows
   Revenues .......................  $   9,824   $   1,010   $  15,724   $    5,124    $     31,682    $     13,524     $  45,206
   Production costs ...............     (2,604)       (244)     (4,460)        (987)         (8,295)         (2,489)      (10,784)
   Development costs ..............       (347)        (35)       (665)        (526)         (1,573)         (1,168)       (2,741)
   Income tax expense .............     (1,805)       (270)     (5,581)      (2,556)        (10,212)         (2,522)      (12,734)
                                     ---------   ---------   ---------   ----------    ------------    ------------     ---------
Future net cash flows .............      5,068         461       5,018        1,055          11,602           7,345        18,947
Discounted to present value at a
   10% annual rate ................     (2,157)       (185)     (1,468)        (563)         (4,373)         (5,039)       (9,412)
                                     ---------   ---------   ---------   ----------    ------------    ------------     ---------
Total .............................  $   2,911   $     276   $   3,550   $      492    $      7,229    $      2,306     $   9,535
                                     =========   =========   =========   ==========    ============    ============     =========
</Table>


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

(1)      Includes our net share of equity affiliate information.

(2)      Does not include the discounted future net cash flows from Canadian
         Syncrude of $472 and unrecognized hedge positions of $92 after-tax at
         December 31, 2001.

(3)      In 2001, Other Regions includes $170 for a minority interest holding.





                                       120
<PAGE>



                           SUPPLEMENTAL PETROLEUM DATA
                                   (UNAUDITED)
                              (DOLLARS IN MILLIONS)


SUMMARY OF CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO PROVED OIL AND GAS RESERVES

<Table>
<Caption>

                                                                           CONSOLIDATED          EQUITY             TOTAL
                                                                             COMPANIES        COMPANIES(1)        WORLDWIDE
                                                                           ------------       ------------        ---------

<S>                                                                        <C>                <C>                 <C>
DECEMBER 31, 2001
Balance at beginning of year ............................................  $     14,339       $      3,437        $  17,776
Sales and transfers of oil and gas produced, net of production costs ....        (4,187)              (186)          (4,373)
Development costs incurred during the period ............................         1,364                176            1,540
Net changes in prices and in development and production costs ...........       (14,054)            (2,765)         (16,819)
Extensions, discoveries and improved recovery, less related costs .......         2,531                 --            2,531
Revisions of previous quantity estimates ................................           132               (152)             (20)
Purchases (sales) of reserves in place - net(2) .........................         2,757                (32)           2,725
Accretion of discount ...................................................         2,377                348            2,725
Net change in income taxes ..............................................         3,881                847            4,728
Other ...................................................................          (389)                 5             (384)
                                                                           ------------       ------------        ---------
Balance at end of year ..................................................  $      8,751       $      1,678        $  10,429
                                                                           ============       ============        =========

DECEMBER 31, 2000
Balance at beginning of year ............................................  $      7,229       $      2,306        $   9,535
Sales and transfers of oil and gas produced, net of production costs ....        (4,041)              (281)          (4,322)
Development costs incurred during the period ............................           908                320            1,228
Net changes in prices and in development and production costs ...........         9,150                541            9,691
Extensions, discoveries and improved recovery, less related costs .......         2,241                423            2,664
Revisions of previous quantity estimates ................................            77                (39)              38
Purchases (sales) of reserves in place - net ............................           869                 --              869
Accretion of discount ...................................................         1,321                294            1,615
Net change in income taxes ..............................................        (3,450)              (444)          (3,894)
Other ...................................................................            35                317              352
                                                                           ------------       ------------        ---------
Balance at end of year ..................................................  $     14,339       $      3,437        $  17,776
                                                                           ============       ============        =========

DECEMBER 31, 1999
Balance at beginning of year ............................................  $      4,203       $        261        $   4,464
Sales and transfers of oil and gas produced, net of production costs ....        (2,400)              (124)          (2,524)
Development costs incurred during the period ............................           737                337            1,074
Net changes in prices and in development and production costs ...........         6,650              2,112            8,762
Extensions, discoveries and improved recovery, less related costs .......         1,023                 80            1,103
Revisions of previous quantity estimates ................................           (24)                25                1
Purchases (sales) of reserves in place - net ............................            99                  2              101
Accretion of discount ...................................................           620                 36              656
Net change in income taxes ..............................................        (3,978)              (530)          (4,508)
Other ...................................................................           299                107              406
                                                                           ------------       ------------        ---------
Balance at end of year ..................................................  $      7,229       $      2,306        $   9,535
                                                                           ============       ============        =========
</Table>



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

(1)      Includes our net share of equity affiliate information.

(2)      Purchases (sales) of reserves in place - net in 2001 includes $2,644
         for Gulf Canada recognizing the proved reserves upon the mid-year 2001
         acquisition valued at year-end prices less estimated future costs.


                                       121
<PAGE>




                      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>
2001
Sales and other operating revenues(1)(2) ................  $     10,625     $     10,377     $      9,627       $      8,108
Cost of goods sold and other expenses(3) ................  $      9,457     $      9,382     $      9,102       $      8,215
Interest and debt expense ...............................  $         75     $         67     $        135       $        119
Net income before special items .........................  $        616     $        606     $        404       $        197
Net income before extraordinary item and accounting
   change ...............................................  $        616     $        552     $        281       $        147
Extraordinary item, charge for the early
   extinguishment of debt net of income taxes ...........            --               --              (24)               (20)
Cumulative effect of accounting change, net of income
   tax ..................................................            37               --               --                 --
                                                           ------------     ------------     ------------       ------------
Net income ..............................................  $        653(4)  $        552(5)  $        257(6)    $        127(7)
                                                           ============     ============     ============       ============
Earnings per share
   Basic(12)
      Before extraordinary item and accounting change ...  $        .99     $        .88     $        .45       $        .23
      Extraordinary item ................................            --               --             (.04)              (.03)
      Cumulative effect of accounting change ............           .05               --               --                 --
                                                           ------------     ------------     ------------       ------------
                                                           $       1.04     $        .88     $        .41       $        .20
                                                           ============     ============     ============       ============
   Diluted(12)
      Before extraordinary item and accounting change ...  $        .97     $        .87     $        .44       $        .23
      Extraordinary item ................................            --               --             (.04)              (.03)
      Cumulative effect of accounting change ............           .06               --               --                 --
                                                           ------------     ------------     ------------       ------------
                                                           $       1.03     $        .87     $        .40       $        .20
                                                           ============     ============     ============       ============

Dividends per common share ..............................  $        .19     $        .19     $        .19       $        .19
Market price of Conoco common stock(13)
   High .................................................  $         --     $         --     $         --       $      28.80
   Low ..................................................  $         --     $         --     $         --       $      23.97
Market price of Class A common stock(14)
   High .................................................  $      30.79     $      32.99     $      31.60       $      26.58
   Low ..................................................  $      25.75     $      26.30     $      23.65       $      24.60
Market price of Class B common stock(14)
   High .................................................  $      31.10     $      33.35     $      32.00       $      26.57
   Low ..................................................  $      26.00     $      26.75     $      23.77       $      24.61

2000
Sales and other operating revenues(1) ...................  $      8,524     $      9,357     $     10,587       $     10,269
Cost of goods sold and other expenses ...................  $      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(8)  $        456(9)  $        497(10)   $        550(11)
Earnings per share
   Basic(12) ............................................  $        .64     $        .73     $        .80       $        .88
   Diluted(12) ..........................................  $        .63     $        .72     $        .79       $        .87
Dividends per common share ..............................  $        .19     $        .19     $        .19       $        .19
Market price of Class A common stock(14)
   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(14)
   High .................................................  $      28.75     $      29.00     $      28.75       $      29.69
   Low ..................................................  $      19.00     $      23.25     $      22.31       $      24.69
</Table>

(1)      Excludes other income and equity in earnings of affiliates of $52,
         $173, $194 and $383 in each of the quarters in 2001 and $167, $149,
         $110 and $124 in each of the quarters in 2000.

(2)      Includes a reclassification of revenues previously reported as a
         reduction in cost of goods sold and other expenses for sales of crude
         oil from Conoco's subsidiaries of $90, $117 and $77 for the first,
         second and third quarters of 2001, respectively.



                                       122
<PAGE>
                      CONSOLIDATED QUARTERLY FINANCIAL DATA
                                   (UNAUDITED)
                     (DOLLARS IN MILLIONS, EXCEPT PER SHARE)

(3)  Excludes provision for income taxes.

(4)  Includes $37 for a cumulative transition gain recorded on January 1, 2001,
     upon initial adoption of SFAS No. 133, as amended.

(5)  Includes a $54 charge to record repairs and other costs associated with the
     April 16, 2001 explosion and fire at our Humber refinery in North
     Lincolnshire, U.K.

(6)  Includes a $23 gain from the sale of our Pocahontas Gas Partnership, a
     write-down of $44 of certain upstream producing assets held for sale, a
     write-down of $23 of a downstream joint-venture investment held for sale, a
     charge of $41 related to an adverse ruling on the patent dispute with GTA,
     a $24 extraordinary item charge for a premium on the early repayment of
     Gulf Canada debt securities and a foreign currency exchange loss of $38
     associated with the purchase of Gulf Canada.

(7)  Includes $70 for settlement costs associated with the separation agreement
     from DuPont related to a discontinued business; $87 for the write-down of
     western Canadian legacy assets held for sale; $23 for the write-down of an
     equity investment held for sale; $20 premium charge on the early retirement
     of debt related to the acquisition of Gulf Canada; and $4 of costs
     associated with the ConocoPhillips merger; partially offset by a $134 gain
     from the sale of various Gulf of Mexico properties.

(8)  Includes $8 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.

(9)  Includes $4 for settlement costs associated with the separation agreement
     from DuPont related to a discontinued business.

(10) Includes $26 for the write-off of our share of a Colombian power venture.

(11) Includes $24 related to the write-down of an international refinery
     venture's inventories to market value.

(12) 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
     10 to the consolidated financial statements).

(13) On September 21, 2001, our shareholders approved the combination of
     Conoco's Class A and Class B common stock into a single class of new common
     stock on a one-for-one basis. As a result of the combination, each
     outstanding share of Class A and Class B common stock was converted into
     one share of a new class of a common stock. On October 8, 2001, the
     combination was effective and the new common stock began trading on the
     New York Stock Exchange under the symbol COC. The stock symbols COC.A and
     COC.B no longer apply. Prices are reported by the New York Stock Exchange.

(14) Conoco's 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. Class A and Class B common
     stock (trading symbol COC.A and COC.B) traded on the New York Stock
     Exchange until October 8, 2001, when they were combined into a single class
     of common stock. Prices are reported by the New York Stock Exchange.

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 2002 annual meeting proxy statement
filed in connection with the annual meeting of stockholders to be held on May
21, 2002.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

     The information required by this item will be set forth under the captions
"Proposal 2 -- Election of Directors" and "Stock Ownership of Directors and
Executive Officers -- Beneficial Ownership Reporting Compliance" in Conoco's
definitive proxy statement (the "2002 proxy statement") for its annual meeting
of stockholders to be held on May 21, 2002, 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 under the caption "Executive Officers of the Registrant" in Part 1 of this
report (page 37).

ITEM 11. EXECUTIVE COMPENSATION

     The information required by this item will be set forth under the captions
"Proposal 1 -- Election of Directors -- Board Compensation" and "Compensation of
Executive Officers" in the 2002 proxy statement, which sections are incorporated
herein by reference.

                                      123
<PAGE>

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     The information required by this item is set forth under the captions
"Principal Stockholders" and "Stock Ownership of Directors and Executive
Officers" in the 2002 proxy statement, which sections are incorporated herein by
reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     Any information required by this item will be set forth under the captions
"Compensation of Executive Officers -- Certain Relationships and Related
Transactions" in the 2002 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, 2001.

          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 129 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:

<Table>
<Caption>
EXHIBIT NUMBER                             DESCRIPTION
--------------                             -----------

<S>                 <C>
     2.1         -- Agreement and Plan of Merger dated as of November 18, 2001
                    by and among Phillips Petroleum Company (Phillips),
                    CorvettePorsche Corp. (ConocoPhillips), Porsche Merger
                    Corp., Corvette Merger Corp. and Conoco Inc. (Conoco)
                    (incorporated by reference to Exhibit 2.1 to Phillips' Form
                    8-K filed with the Securities and Exchange Commission (SEC)
                    on November 19, 2001, File No. 001-00720).

     2.2         -- Agreement and Plan of Merger dated as of July 17, 2001, and
                    amended and restated in its entirety as of July 31, 2001, by
                    and between Conoco and Conoco Delaware I, Inc. (incorporated
                    by reference to Appendix A of Conoco's Proxy Statement filed
                    with the SEC on August 3, 2001, File No. 001-14521).

     3.1         -- Restated Certificate of Incorporation of Conoco
                    (incorporated by reference to Appendix B of Conoco's Proxy
                    Statement filed with the SEC on August 3, 2001, File No.
                    001-14521).

     3.2         -- Bylaws of Conoco, as amended as of September 4, 2001,
                    (incorporated by reference to Exhibit 3.3 of Conoco's
                    Registration Statement on Form S-3/A filed with the SEC on
                    October 5, 2001, Registration No. 333-67004).
</Table>

                                      124
<PAGE>

<Table>
<Caption>
EXHIBIT NUMBER                             DESCRIPTION
--------------                             -----------

<S>                 <C>
     4.1         -- Form of certificate representing Common Stock (incorporated
                    by reference to Exhibit 4.1 of Conoco's Registration
                    Statement on Form 8-A filed with the SEC on September 28,
                    2001, File No. 001-14521).

     4.2         -- Rights Agreement dated as of October 19, 1998 between Conoco
                    and EquiServe Trust Company, N.A., as successor rights agent
                    to First Chicago Trust Company of New York (the Rights
                    Agent) (incorporated by reference to Exhibit 4.4 of Conoco's
                    Registration Statement on Form S-8 relating to the Conoco
                    Inc. 1998 Stock and Performance Incentive Plan, filed with
                    the SEC on October 22, 1998, Registration No. 333-65977).

     4.3         -- Amendment to Rights Agreement dated as of October 20, 1998
                    between Conoco and the Rights Agent (incorporated by
                    reference to Exhibit 4.6 of Conoco's Registration Statement
                    on Form S-8 relating to the Conoco Inc. 1998 Stock and
                    Performance Incentive Plan, filed with the SEC on October
                    22, 1998, Registration No. 333-65977).

     4.4         -- Second Amendment to Rights Agreement dated as of July 29,
                    1999 between Conoco and the Rights Agent (incorporated by
                    reference to Exhibit 4.1 of Conoco's Form 10-Q for the
                    quarterly period ended June 30, 1999, File No. 001-14521).

     4.5         -- Third Amendment to Rights Agreement dated as of October 8,
                    2001 between Conoco and the Rights Agent, which includes as
                    Exhibit A the form Certificate of Designations, Preferences
                    and Rights of Series A Junior Participating Preferred Stock,
                    as Exhibit B the form of Rights Certificate and as Exhibit D
                    the Summary of Rights to Purchase Preferred Stock
                    (incorporated by reference to Exhibit 4.4 of Conoco's Form
                    10-Q for the quarterly period ended September 30, 2001, File
                    No. 001-14521).

     4.6         -- Fourth Amendment to Rights Agreement dated as of November
                    18, 2001 between Conoco and the Rights Agent (incorporated
                    by reference to Exhibit 4.6 of Conoco's Registration
                    Statement on Form 8-A/A (Amendment No. 1) filed with the SEC
                    on November 19, 2001, File No. 001-14521).

     4.7         -- Indenture, dated as of April 15, 1999, between Conoco, as
                    issuer, and Bank One, N.A., as trustee (incorporated by
                    reference to Exhibit 4.1 of the Registration Statement of
                    Conoco and Conoco Funding Company on Form S-3 filed with the
                    SEC on September 10, 2001, Registration No. 333-69198).

     4.8         -- Indenture, dated as of October 11, 2001, among Conoco
                    Funding Company, as issuer, Conoco, as guarantor, and Bank
                    One, N.A., as trustee (incorporated by reference to Exhibit
                    4.6 of Conoco's Form 10-Q for the quarterly period ended
                    September 30, 2001, File No. 001-14521).

     4.9         -- Terms of Conoco's 5.90% Notes due 2004, 6.35% Notes due 2009
                    and 6.95% Notes due 2029 (including the form of note)
                    (incorporated by reference to Exhibit 4.1 to Conoco's Form
                    8-K filed with the SEC on April 16, 1999, File No.
                    001-14521).

     4.10        -- Terms of Conoco Funding Company's 5.45% Notes due 2006,
                    6.35% Notes due 2011 and 7.25% Notes due 2031 (including the
                    form of note) (incorporated by reference to Exhibit 4.8 of
                    Conoco's Form 10-Q for the quarterly period ended September
                    30, 2001, File No. 001-14521).

     4.11        -- Terms of Conoco's Floating Rate Notes due October 15, 2002
                    and April 15, 2003 (including the form of note)
                    (incorporated by reference to Exhibit 4.7 to Conoco's Form
                    10-Q for the quarterly period ended September 30, 2001, File
                    No. 001-14521).

    10.1#        -- Employment Agreement dated October 19, 2000 between Conoco
                    and Archie W. Dunham (incorporated by reference to Exhibit
                    10.1 of Conoco's Form 10-K for the year ended December 31,
                    2000, File No. 001-14521).

    10.2#        -- Employment Agreement dated November 18, 2001 by and among
                    ConocoPhillips, Conoco and Archie W. Dunham (incorporated by
                    reference to Exhibit 10.2 of ConocoPhillips' Registration
                    Statement on Form S-4 filed with the SEC on December 7,
                    2001, Registration No. 333-74798).

    10.3#        -- 1998 Stock and Performance Incentive Plan, as amended and
                    restated effective October 8, 2001, (incorporated by
                    reference to Exhibit 4.9 of Conoco's Registration Statement
                    on Form S-8 filed with the SEC on October 5, 2001,
                    Registration No. 333-71070).
</Table>

                                      125
<PAGE>

<Table>
<Caption>
EXHIBIT NUMBER                             DESCRIPTION
--------------                             -----------

<S>                 <C>
   10.4#         -- 1998 Key Employee Stock Performance Plan as amended and
                    restated effective October 8, 2001, (incorporated by
                    reference to Exhibit 4.10 of Conoco's Registration Statement
                    on Form S-8 filed with the SEC on October 5, 2001,
                    Registration No. 333-71070).

   10.5#         -- Deferred Compensation Plan for Non-Employee Directors as
                    amended and restated effective October 8, 2001,
                    (incorporated by reference to Exhibit 4.11 of Conoco's
                    Registration Statement on Form S-8 filed with the SEC on
                    October 5, 2001, Registration No. 333-71070).

   10.6*#        -- Key Employee Severance Plan.

   10.7#         -- Salary Deferral and Savings Restoration Plan, as amended
                    (incorporated by reference to Exhibit 10.4 of Conoco's
                    Registration Statement on Form S-1 filed with the SEC on
                    October 7, 1999, Registration No. 333-88573).

   10.8#         -- Directors' Charitable Gift Plan, as amended (incorporated by
                    reference to Exhibit 10.5 of Conoco's Registration Statement
                    on Form S-1 filed with the SEC on October 7, 1999,
                    Registration No. 333-88573).

   10.9#         -- Form Indemnity Agreement with Directors (incorporated by
                    reference to Exhibit 10.19 of Conoco's Registration
                    Statement on Form S-1/A filed with the SEC on October 16,
                    1998, Registration No. 333-60119).

   10.10#        -- Rabbi Trust Agreement dated December 17, 1999, (incorporated
                    by reference to Exhibit 10.11 of Conoco's Form 10-K for the
                    year ended December 31, 1999, File No. 001-14521).

   10.11#        -- 2001 Global Performance Sharing Plan, as amended and
                    restated effective October 8, 2001, (incorporated by
                    reference to Exhibit 4.8 of Conoco's Registration Statement
                    on Form S-8 filed with the SEC on October 5, 2001,
                    Registration No. 333-71070).

   10.12#        -- 1998 Global Performance Sharing Plan, as amended and
                    restated effective October 8, 2001, (incorporated by
                    reference to Exhibit 4.12 of Conoco's Registration Statement
                    on Form S-8 filed with the SEC on October 5, 2001,
                    Registration No. 333-71070).

   11*           -- Statement re: Computation of Per Share Earnings.

   12*           -- Computation of Ratio of Earnings to Fixed Charges.

   21.1*         -- List of Principal Subsidiaries of the Registrant.

   23.1*         -- Consent of PricewaterhouseCoopers LLP.

   99.1*         -- Consent of Solomon Associates.
</Table>

----------

*    Filed herewith.

#    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.   In a current report on Form 8-K dated October 5, 2001, we reported
          pursuant to Item 5 of Form 8-K that on October 3, 2001, we had entered
          into an underwriting agreement relating to the offering by us of $500
          million principal amount of Floating Rate Notes due October 15, 2002,
          and $500 million principal amount of Floating Rate Notes due April 15,
          2003, and we had also, with Conoco Funding Company, our wholly owned
          finance subsidiary, entered into an underwriting agreement relating to
          the offering by Conoco Funding of $1,250 million principal amount of
          5.45 percent Notes due 2006, $1,750 million principal amount of 6.35
          percent Notes due 2011 and $500 million principal amount of 7.25
          percent Notes due 2031 fully and unconditionally guaranteed by us. We
          also filed as exhibits pursuant to Item 7 of Form 8-K (i) the
          underwriting agreements, (ii) the form of the terms of the Floating
          Rate Notes, including the form of note, (iii) the form of the terms of
          the Conoco Funding Notes, including the form of note, (iv) an opinion
          of Baker Botts L.L.P., our counsel, as to certain tax matters and (v)
          the Statement of Eligibility and Qualification under the Trust
          Indenture Act of 1939 of the Conoco Funding Trustee on Form T-1.

     2.   In a current report on Form 8-K dated October 9, 2001, we furnished
          pursuant to Item 9 of Form 8-K a copy of an IR Gram relating to our
          commodity price hedging activities, which was posted on our web site
          on October 9, 2001.

     3.   In a current report on Form 8-K dated October 22, 2001, we furnished
          pursuant to Item 9 of Form 8-K unaudited quarterly pro forma financial
          data for the year ended December 31, 2000, and the six-month

                                      126
<PAGE>

          period ended June 30, 2001 for Conoco and Gulf Canada, and unaudited
          quarterly capital expenditure and operating data for the year ended
          December 31, 2000, and the six-month period ended June 30, 2001 for
          Gulf Canada.

     4.   In a current report on Form 8-K dated November 14, 2001, we furnished
          pursuant to Item 9 of Form 8-K a slide presentation that was posted on
          our website in connection with our security analyst meeting on
          November 14, 2001.

     5.   In a current report on Form 8-K dated November 19, 2001, we reported
          pursuant to Item 5 of Form 8-K that we had entered a merger agreement
          with Phillips. We also filed as exhibits pursuant to Item 7 of Form
          8-K the merger agreement and the joint press release dated November
          18, 2001 that we issued with Phillips with respect to the transaction.

                                      127
<PAGE>

                      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, 2002 appearing in the 2001 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
February 19, 2002

                                      128
<PAGE>

                                   CONOCO INC.
                SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
              FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
                            (IN MILLIONS OF DOLLARS)

<Table>
<Caption>

                                                 BALANCE AT                                           BALANCE AT
DESCRIPTION                                      JANUARY 1    ADDITIONS   DEDUCTIONS     OTHER        DECEMBER 31
-----------                                      ----------   ---------   ----------     -----        -----------

<S>                                              <C>          <C>         <C>            <C>          <C>
2001
Deducted from asset accounts:
    Deferred tax asset valuation allowance ...     $409         $267         $ 57         $ --           $619
    Allowance for doubtful accounts ..........        2           --            2           10*            10
Included in other accrued liabilities:
    Reserve for maintenance turnarounds ......       69           61           82           (1)            47
2000
Deducted from asset accounts:
    Deferred tax asset valuation allowance ...     $452         $ 80         $123         $ --           $409
    Allowance for doubtful accounts ..........        1            1           --           --              2
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
    Allowance for doubtful accounts ..........        1           --           --           --              1
Included in other accrued liabilities:
    Restructuring ............................       82           --           71           --             11
    Reserve for maintenance turnarounds ......       55           62           54           (1)            62
</Table>

----------

*    As a result of the Gulf Canada acquisition.

                                      129
<PAGE>

                                   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 15th day of March, 2002.

                                       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
                                              Vice President, Controller and
                                               Principal Accounting Officer

     Pursuant to the requirements of the Securities exchange Act of 1934; this
report has been signed, as of the 15th day of March, 2002, 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
                                       Senior Vice President, Finance, and Chief Financial
      /s/ ROBERT W. GOLDMAN               Officer
-----------------------------------
       Robert W. Goldman
                                       Vice President, Controller and Principal Accounting
       /s/ W. DAVID WELCH                 Officer
-----------------------------------
        W. David Welch

    /s/ RICHARD H. AUCHINLECK          Director
-----------------------------------
      Richard H. Auchinleck

    /s/ KENNETH M. DUBERSTEIN          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

     /s/ WILLIAM K. REILLY             Director
-----------------------------------
      William K. Reilly

    /s/ WILLIAM R. RHODES              Director
-----------------------------------
      William R. Rhodes

    /s/ FRANKLIN A. THOMAS             Director
-----------------------------------
     Franklin A. Thomas

    /s/ A. R. SANCHEZ, JR.             Director
-----------------------------------
     A. R. Sanchez, Jr.
</Table>

                                      130
<PAGE>

                                INDEX TO EXHIBITS

<Table>
<Caption>
EXHIBIT NUMBER                            DESCRIPTION
--------------                            -----------

<S>                 <C>
   2.1           -- Agreement and Plan of Merger dated as of November 18, 2001
                    by and among Phillips Petroleum Company (Phillips),
                    CorvettePorsche Corp. (ConocoPhillips), Porsche Merger
                    Corp., Corvette Merger Corp. and Conoco Inc. (Conoco)
                    (incorporated by reference to Exhibit 2.1 to Phillips' Form
                    8-K filed with the Securities and Exchange Commission (SEC)
                    on November 19, 2001, File No. 001-00720).

   2.2           -- Agreement and Plan of Merger dated as of July 17, 2001, and
                    amended and restated in its entirety as of July 31, 2001, by
                    and between Conoco and Conoco Delaware I, Inc. (incorporated
                    by reference to Appendix A of Conoco's Proxy Statement filed
                    with the SEC on August 3, 2001, File No. 001-14521).

   3.1           -- Restated Certificate of Incorporation of Conoco
                    (incorporated by reference to Appendix B of Conoco's Proxy
                    Statement filed with the SEC on August 3, 2001, File No.
                    001-14521).

   3.2           -- Bylaws of Conoco, as amended as of September 4, 2001,
                    (incorporated by reference to Exhibit 3.3 of Conoco's
                    Registration Statement on Form S-3/A filed with the SEC on
                    October 5, 2001, Registration No. 333-67004).

   4.1           -- Form of certificate representing Common Stock (incorporated
                    by reference to Exhibit 4.1 of Conoco's Registration
                    Statement on Form 8-A filed with the SEC on September 28,
                    2001, File No. 001-14521).

   4.2           -- Rights Agreement dated as of October 19, 1998 between Conoco
                    and EquiServe Trust Company, N.A., as successor rights agent
                    to First Chicago Trust Company of New York (the Rights
                    Agent) (incorporated by reference to Exhibit 4.4 of Conoco's
                    Registration Statement on Form S-8 relating to the Conoco
                    Inc. 1998 Stock and Performance Incentive Plan, filed with
                    the SEC on October 22, 1998, Registration No. 333-65977).

   4.3           -- Amendment to Rights Agreement dated as of October 20, 1998
                    between Conoco and the Rights Agent (incorporated by
                    reference to Exhibit 4.6 of Conoco's Registration Statement
                    on Form S-8 relating to the Conoco Inc. 1998 Stock and
                    Performance Incentive Plan, filed with the SEC on October
                    22, 1998, Registration No. 333-65977).

   4.4           -- Second Amendment to Rights Agreement dated as of July 29,
                    1999 between Conoco and the Rights Agent (incorporated by
                    reference to Exhibit 4.1 of Conoco's Form 10-Q for the
                    quarterly period ended June 30, 1999, File No. 001-14521).

   4.5           -- Third Amendment to Rights Agreement dated as of October 8,
                    2001 between Conoco and the Rights Agent, which includes as
                    Exhibit A the form Certificate of Designations, Preferences
                    and Rights of Series A Junior Participating Preferred Stock,
                    as Exhibit B the form of Rights Certificate and as Exhibit D
                    the Summary of Rights to Purchase Preferred Stock
                    (incorporated by reference to Exhibit 4.4 of Conoco's Form
                    10-Q for the quarterly period ended September 30, 2001, File
                    No. 001-14521).

   4.6           -- Fourth Amendment to Rights Agreement dated as of November
                    18, 2001 between Conoco and the Rights Agent (incorporated
                    by reference to Exhibit 4.6 of Conoco's Registration
                    Statement on Form 8-A/A (Amendment No. 1) filed with the SEC
                    on November 19, 2001, File No. 001-14521).

   4.7           -- Indenture, dated as of April 15, 1999, between Conoco, as
                    issuer, and Bank One, N.A., as trustee (incorporated by
                    reference to Exhibit 4.1 of the Registration Statement of
                    Conoco and Conoco Funding Company on Form S-3 filed with the
                    SEC on September 10, 2001, Registration No. 333-69198).

   4.8           -- Indenture, dated as of October 11, 2001, among Conoco
                    Funding Company, as issuer, Conoco, as guarantor, and Bank
                    One, N.A., as trustee (incorporated by reference to Exhibit
                    4.6 of Conoco's Form 10-Q for the quarterly period ended
                    September 30, 2001, File No. 001-14521).

   4.9           -- Terms of Conoco's 5.90% Notes due 2004, 6.35% Notes due 2009
                    and 6.95% Notes due 2029 (including the form of note)
                    (incorporated by reference to Exhibit 4.1 to Conoco's Form
                    8-K filed with the SEC on April 16, 1999, File No.
                    001-14521).
</Table>

                                      131
<PAGE>

<Table>
<Caption>
EXHIBIT NUMBER                            DESCRIPTION
--------------                            -----------

<S>                 <C>
  4.10           -- Terms of Conoco Funding Company's 5.45% Notes due 2006,
                    6.35% Notes due 2011 and 7.25% Notes due 2031 (including the
                    form of note) (incorporated by reference to Exhibit 4.8 of
                    Conoco's Form 10-Q for the quarterly period ended September
                    30, 2001, File No. 001-14521).

  4.11           -- Terms of Conoco's Floating Rate Notes due October 15, 2002
                    and April 15, 2003 (including the form of note)
                    (incorporated by reference to Exhibit 4.7 to Conoco's Form
                    10-Q for the quarterly period ended September 30, 2001, File
                    No. 001-14521).

 10.1#           -- Employment Agreement dated October 19, 2000 between Conoco
                    and Archie W. Dunham (incorporated by reference to Exhibit
                    10.1 of Conoco's Form 10-K for the year ended December 31,
                    2000, File No. 001-14521).

 10.2#           -- Employment Agreement dated November 18, 2001 by and among
                    ConocoPhillips, Conoco and Archie W. Dunham (incorporated by
                    reference to Exhibit 10.2 of ConocoPhillips' Registration
                    Statement on Form S-4 filed with the SEC on December 7,
                    2001, Registration No. 333-74798).

 10.3#           -- 1998 Stock and Performance Incentive Plan, as amended and
                    restated effective October 8, 2001, (incorporated by
                    reference to Exhibit 4.9 of Conoco's Registration Statement
                    on Form S-8 filed with the SEC on October 5, 2001,
                    Registration No. 333-71070).

 10.4#           -- 1998 Key Employee Stock Performance Plan as amended and
                    restated effective October 8, 2001, (incorporated by
                    reference to Exhibit 4.10 of Conoco's Registration Statement
                    on Form S-8 filed with the SEC on October 5, 2001,
                    Registration No. 333-71070).

 10.5#           -- Deferred Compensation Plan for Non-Employee Directors as
                    amended and restated effective October 8, 2001,
                    (incorporated by reference to Exhibit 4.11 of Conoco's
                    Registration Statement on Form S-8 filed with the SEC on
                    October 5, 2001, Registration No. 333-71070).

 10.6*#          -- Key Employee Severance Plan.

 10.7#           -- Salary Deferral and Savings Restoration Plan, as amended
                    (incorporated by reference to Exhibit 10.4 of Conoco's
                    Registration Statement on Form S-1 filed with the SEC on
                    October 7, 1999, Registration No. 333-88573).

 10.8#           -- Directors' Charitable Gift Plan, as amended (incorporated by
                    reference to Exhibit 10.5 of Conoco's Registration Statement
                    on Form S-1 filed with the SEC on October 7, 1999,
                    Registration No. 333-88573).

 10.9#           -- Form Indemnity Agreement with Directors (incorporated by
                    reference to Exhibit 10.19 of Conoco's Registration
                    Statement on Form S-1/A filed with the SEC on October 16,
                    1998, Registration No. 333-60119).

 10.10#          -- Rabbi Trust Agreement dated December 17, 1999 (incorporated
                    by reference to Exhibit 10.11 of Conoco's Form 10-K for the
                    year ended December 31, 1999, File No. 001-14521).

 10.11#          -- 2001 Global Performance Sharing Plan, as amended and
                    restated effective October 8, 2001, (incorporated by
                    reference to Exhibit 4.8 of Conoco's Registration Statement
                    on Form S-8 filed with the SEC on October 5, 2001,
                    Registration No. 333-71070).

 10.12#          -- 1998 Global Performance Sharing Plan, as amended and
                    restated effective October 8, 2001, (incorporated by
                    reference to Exhibit 4.12 of Conoco's Registration Statement
                    on Form S-8 filed with the SEC on October 5, 2001,
                    Registration No. 333-71070).

 11*             -- Statement re: Computation of Per Share Earnings.

 12*             -- Computation of Ratio of Earnings to Fixed Charges.

 21.1*           -- List of Principal Subsidiaries of the Registrant.

 23.1*           -- Consent of PricewaterhouseCoopers LLP.

 99.1*           -- Consent of Solomon Associates.
</Table>

----------

*    Filed herewith.

#    Management contract or compensatory plan or arrangement required to be
     filed as an exhibit to this Form 10-K.

                                      132