CONOCO INC /DE, 10-K405/A, 1999-03-12

CONOCO INC /DE
10-K405/A, 1999-03-12
PETROLEUM REFINING

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K/A
AMENDMENT NO. 1
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998

COMMISSION FILE NUMBER 1-14521

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

<TABLE>
<S> <C>
DELAWARE 51-0370352
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
</TABLE>

600 NORTH DAIRY ASHFORD ROAD
HOUSTON, TEXAS 77079
(Address of principal executive offices)

Registrant's telephone number, including area code: 281-293-1000
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Securities registered pursuant to Section 12(b) of the Act:

<TABLE>
<S> <C>
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
Class A Common Stock ($.01 par value) New York Stock Exchange, Inc.
Preferred Share Purchase Rights New York Stock Exchange, Inc.
</TABLE>

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. [X]

Aggregate market value of voting stock (Class A Common Stock) held by
nonaffiliates of the registrant (excludes outstanding shares beneficially owned
by directors and officers) as of March 5, 1999, was approximately $4,000 million
based on the closing price on that date of $21 1/16 on the New York Stock
Exchange, Inc. Composite Transactions tape. As of such date, 190,564,480 shares
of Class A Common Stock, $0.01 par value, and 436,543,573 shares of Class B
Common Stock, $0.01 par value, were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

<TABLE>
<CAPTION>
INCORPORATED BY
(REFERENCE IN PART NO.)
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<S> <C>
Portions of the Registrant's Proxy Statement for the Annual III
Meeting of Stockholders to be held on May 12, 1999
</TABLE>

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Conoco Inc. hereby amends its Annual Report on Form 10-K for the year ended
December 31, 1998, to exclude Class A Common Stock from the weighted average
shares outstanding for the calculation of earnings per share for periods prior
to Conoco's initial public offerings as required by Statement of Financial
Accounting Standards ("SFAS") No. 128, "Earnings Per Share." The changes are
reflected in Item 6 -- "Selected Financial Data" and Item 8 -- "Financial
Statements and Supplementary Data." Footnote 8 to the Consolidated Financial
Statements in Item 8 provides additional information on the earnings per share
calculation.

In addition, Conoco has updated certain information in Item 5 -- "Market
for Registrant's Common Equity and Related Stockholder Matters" and restated
this report in its entirety to reflect such amendments.

CONOCO INC.

Unless the context otherwise indicates or unless otherwise specifically
indicated, references in this Form 10-K to "Conoco," "the Company," "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

PART I

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<CAPTION>
PAGE
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<S> <C> <C>
Items 1. and 2. Business and Properties..................................... 1
Item 3. Legal Proceedings........................................... 31
Item 4. Submission of Matters to a Vote of Security Holders......... 32
Executive Officers of the Registrant........................ 32

PART II

Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters......................................... 33
Item 6. Selected Financial Data..................................... 36
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................... 37
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk........................................................ 56
Item 8. Financial Statements and Supplementary Data................. 59
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................... 104

PART III

Item 10. Directors and Executive Officers of the Registrant.......... 104
Item 11. Executive Compensation...................................... 104
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 104
Item 13. Certain Relationships and Related Transactions.............. 104

PART IV

Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K......................................................... 104
</TABLE>

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PART I

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

DISCLOSURE REGARDING FORWARD-LOOKING INFORMATION

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

We have based the forward-looking statements relating to our operations on
our current expectations, estimates and projections about us 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. 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 forecast in the forward-looking statements. Any differences
could result from a variety of factors including the following:

- fluctuations in crude oil and natural gas prices

- refining and marketing margins

- failure or delays in achieving expected production from oil and gas
development projects

- uncertainties inherent in predicting oil and gas reserves and oil and gas
reservoir performance

- lack of exploration success

- disruption or interruption of our production facilities due to accidents
or political events

- international monetary conditions and exchange controls

- liability for remedial actions under environmental regulations

- disruption to our operations due to untimely or incomplete resolution of
Year 2000 issues by us or other entities

- liability resulting from litigation

- world economic and political conditions

- changes in tax and other laws applicable to our business

GENERAL

Conoco, a major, integrated, global energy company, is involved in both the
Upstream and Downstream segments of the petroleum business. Upstream activities
include exploring for, and developing, producing and selling crude oil, natural
gas and natural gas liquids. Downstream activities include refining crude oil
and other feedstocks into petroleum products, buying and selling crude oil and
refined products and transporting, distributing and marketing petroleum
products. In addition to Upstream and Downstream operations, Conoco also is
engaged in developing and operating power facilities. Conoco operates in 40
countries worldwide.

As of December 31, 1998, Conoco had proved worldwide reserves of 2,622
million barrels of oil equivalent ("BOE"), 39 percent of which were natural gas
(converted to BOE using a ratio of six thousand cubic feet of gas to one barrel
of oil). Based on 1998 annual production of 213 million BOE (excluding natural
gas liquids from gas plant ownership), the Company had a reserve life of 12.3
years as of December 31, 1998. Over the last five years, Conoco has replaced an
average of 195 percent of the oil and gas it has produced each year. Conoco owns
or has equity interests in nine refineries worldwide, with a total crude and
condensate processing capacity of approximately 807,000 barrels per day. The
Company has a marketing network of approximately 7,900 outlets in the United
States, Europe and Asia. Based on public filings, for the year ended

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December 31, 1998, Conoco ranked eighth in the worldwide production of petroleum
liquids by U.S.-based companies, eleventh in the production of natural gas, and
eighth in refining throughput. For that same period, Conoco reported net income
of $450 million, which included a net charge for Special Items of $271 million,
on total revenues of $23,168 million.

BUSINESS STRATEGY

Conoco intends to pursue a growth-oriented business strategy by exploiting
growth opportunities where Conoco has existing major areas of operation,
creating at least two new major business areas in northern South America and the
Caribbean, and one of the Asia Pacific, West Africa, Middle East or
Russia/Caspian Sea regions, and continuing to improve the profitability,
efficiency and effectiveness of its existing operations. Specifically, the
Company intends to (i) manage its portfolio to increase the proportion of
Upstream assets relative to Downstream assets and the proportion of large-scale,
long-lived, early-life cycle assets relative to mature assets, which could
include forming joint ventures or alliances to optimize the efficiency of
operations or monetize a portion of the value of such assets; (ii) achieve
significant near-term production growth through large scale projects such as
Petrozuata, Britannia, Lobo and Ursa; (iii) seek opportunities created by
worldwide privatizations and the opening of new markets previously closed to
private investment; (iv) apply its strengths in carbon upgrading, project
management, deepwater technology, natural gas processing, seismic processing and
interpretation, and the ability to present integrated Upstream/Downstream
solutions to host governments and other institutions in new and emerging
markets; (v) pursue exploration activities that have significant value creation
potential by concentrating on areas that are under-explored; (vi) capitalize on
its ability to convert low cost, heavy, high sulfur and acidic crude oils into
high value light oil products; and (vii) continuously rationalize its asset
base, contain costs, optimize its investment portfolio, and improve operating
reliability. In all of its activities, the Company will strive to act in
accordance with its core values of operating safely, protecting the environment,
acting ethically and valuing all people.

COMPANY HISTORY

The Company was founded in 1875 in Ogden, Utah, as the Continental Oil and
Transportation Company. In 1885, it was reincorporated with a new name,
Continental Oil Company, as part of the nationwide Standard Oil Trust. In its
early years, its principal operations were marketing oil and petroleum related
products, primarily in the Rocky Mountain area and in California. In 1913, two
years after the U.S. Supreme Court dissolved the Standard Oil Trust, the Company
was again independently incorporated. From 1913 to 1929, the Company evolved
into a fully integrated oil company, with operations in most states west of the
Mississippi River.

By 1929, Conoco had approximately 1,800 producing wells and had become one
of the largest retailers of gasoline in the Rocky Mountain area. In that year,
it merged with the Marland Oil Company, an oil and gas company with wells and
marketing operations from Oklahoma to Maryland. After World War II, the Company
was an early participant in Gulf of Mexico exploration and production activities
and moved aggressively overseas with Upstream assets in many parts of the world
and Downstream assets in Western Europe. In 1981, Conoco was acquired by E.I. du
Pont de Nemours and Company ("DuPont").

On October 21, 1998, Conoco sold 191,456,427 shares of Class A Common Stock
in initial public offerings (the "Offerings"). The net proceeds of the Offerings
were approximately $4,228 million, and were used to repay a portion of Conoco's
indebtedness to DuPont. A discussion of the indebtedness repaid is set forth
under "Use of Proceeds" in Part II of this report. Through its ownership of 100%
of the Company's Class B Common Stock (436,543,573 shares), DuPont owns
approximately 70% of the Company's Common Stock representing approximately 92%
of the combined voting power of all classes of voting stock of the Company at
December 31, 1998. The holders of Class A Common Stock and Class B Common Stock
generally have identical rights, except that holders of Class A Common Stock are
entitled to one vote per share while holders of Class B Common Stock are
entitled to five votes per share on matters to be voted on by stockholders.
DuPont has announced its intention to offer its shares of Class B Common Stock
to DuPont shareholders in exchange for DuPont shares in a tax-free split-off
expected to be completed in 1999.

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FINANCIAL INFORMATION -- OPERATING SEGMENT AND GEOGRAPHIC INFORMATION

See Note 27 to the Consolidated Financial Statements in Item 8 for
Operating Segment and Geographic Information.

UPSTREAM

SUMMARY

Conoco is currently exploring for, developing or producing crude oil,
natural gas and/or natural gas liquids in 17 countries around the world. In
1998, production averaged 583,000 BOE per day, consisting of 348,000 barrels per
day of petroleum liquids (excluding natural gas liquids ("NGLs") from gas plant
ownership) and 1,411 million cubic feet of natural gas per day. The majority of
this production came from fields located in the United States, the United
Kingdom and Norway, with the remaining production coming from operations in
Canada, the United Arab Emirates, Indonesia, Nigeria, Russia and Venezuela.

In 1998, Conoco replaced nearly 110 percent of the oil and natural gas it
produced, adding 234 million BOE to the Company's worldwide reserves while
producing 213 million BOE (excluding NGLs from gas plant ownership), for a net
addition of 21 million BOE. This marks the sixth consecutive year that Conoco
has replaced more reserves than it produced. We replaced 163 percent of the
natural gas produced and 74 percent of the oil produced. On December 31, 1998,
the Company had proved reserves of 2,622 million BOE, consisting of 1,591
million barrels of petroleum liquids and 6,183 billion cubic feet of natural
gas, representing an increase of 48 percent on a BOE basis since December 31,
1994.

Conoco's capital investment in Upstream activities in 1998 was $1,965
million, including the continued development of the Lobo trend, Britannia, Ursa
and Petrozuata. These projects will contribute to Conoco's 1999 production and
significantly increase Conoco's production rates over current levels in future
years.

The majority of Conoco's exploration and production assets are located in
North America (United States and Canada) and Western Europe (United Kingdom and
Norway). The producing properties in these areas generate cash to fund growth
opportunities around the world. Outside of North America and Western Europe,
Conoco's investment activities are focused on areas that have the potential to
become major business areas in the future, such as northern South America and
the Caribbean, and the Asia Pacific, West Africa, Middle East and Russia/Caspian
Sea regions.

Conoco is exploring for oil and/or natural gas in 15 countries. Since 1996,
Conoco has pursued and continues to implement an exploration strategy focused on
acquiring large acreage positions in areas that are relatively under-explored.
The purpose of these acreage acquisitions has been to establish Conoco at an
early stage in areas that have the potential for large discoveries. During the
same period, Conoco acquired significant acreage positions in the deepwater Gulf
of Mexico, the Atlantic Margin of Northwest Europe, northern South America and
the Caribbean, and selected basins in the Asia Pacific region. In 1998, Conoco's
exploratory success rate was its best in 15 years. Approximately 30 percent of
the exploratory wells we drilled (excluding appraisal wells) were potentially
commercial.

As noted above in "Business Strategy," Conoco intends to manage its asset
portfolio to increase the proportion of Upstream assets relative to Downstream
assets and the proportion of large-scale, long-lived, early-life cycle assets
relative to mature assets. In the course of implementing such strategy, the
Company has in the past, and may from time to time in the future, purchase or
sell producing Upstream assets. The Company 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.

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The following table sets forth certain information regarding the Company's
producing properties.

<TABLE>
<CAPTION>
PROVED RESERVES
AS OF DECEMBER 31, 1998
1998 PRODUCTION
NATURE OF INTEREST (MMBOE)(1) (MBOE PER DAY)(1)
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<S> <C> <C> <C>
REGION
UNITED STATES
Lobo................................... Lease 162 70
Gulf of Mexico (including Ursa)........ Lease 80 28
San Juan Basin......................... Lease 185 53
Permian Basin.......................... Lease 133 31
Central Appalachian Basin.............. Partnership 63 2
Other.................................. 88 43
----- ---
Total United States............ 711 227
WESTERN EUROPE
Britannia.............................. License 242 18
Heidrun................................ License 146 39
Statfjord.............................. License 100 54
Troll.................................. License 114 9
Other.................................. 317 111
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Total Western Europe........... 919 231
NORTHERN SOUTH AMERICA AND THE CARIBBEAN
Petrozuata............................. Equity Company 678 5
OTHER.................................... 314 120
----- ---
Total.......................... 2,622 583
===== ===
</TABLE>

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(1) Includes crude oil, condensate, and NGLs expected to be removed for the
Company's account from its natural gas production.

UNITED STATES

Production operations in the United States are principally located in the
Lobo trend in South Texas, the Gulf of Mexico, the San Juan Basin in New Mexico,
the Permian Basin in West Texas and the Central Appalachian Basin in Virginia.
In 1998, United States operations contributed approximately 23 percent of the
Company's worldwide petroleum liquids production and 63 percent of its worldwide
natural gas production. Proved reserves as of December 31, 1998, were 711
million BOE, consisting of 261 million barrels of petroleum liquids and 2,700
billion cubic feet of natural gas.

In recent years, Conoco has consolidated its exploration and production
operations in the United States in order to increase profitability. Conoco sold
hundreds of smaller, less efficient properties, while acquiring an increased
interest in its largest producing areas such as the San Juan Basin and the Lobo
trend. As a result, Conoco has reduced the number of fields in its portfolio
from approximately 700 in 1990 to 104 as of December 31, 1998, while maintaining
production essentially constant on a BOE basis. The Company has also focused its
exploration activities by reducing the number of exploration plays being pursued
in the United States from over 30 in 1995 to less than ten as of December 31,
1998. Exploration activity in the United States is concentrated in the deepwater
Gulf of Mexico.

Conoco's objectives are to increase production from the Lobo trend and the
deepwater Gulf of Mexico, while maintaining production from other United States
assets and focusing on natural gas processing capabilities.

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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 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 1997, in
accordance with our strategy to rapidly increase production through
participation in large development projects, Conoco substantially increased its
holdings in South Texas through the acquisition of $929 million of natural gas
properties and transportation assets (the "Lobo acquisition"). Assets acquired
by Conoco in this transaction included approximately 215,000 acres of leases,
800 wells and 1,150 miles of natural gas gathering and transportation pipeline,
providing direct access to major Texas intrastate and interstate pipeline
systems. As a result of the Lobo acquisition, Conoco is currently the second
largest natural gas producer in Texas.

Conoco's average working interest in its leases in the Lobo trend is 92
percent. A large number of the producing wells acquired in the Lobo acquisition
were acquired subject to volumetric production payments. The holders of these
production payments are entitled to a specific volume of production from these
wells (averaging approximately 91 million cubic feet per day in 1998) until the
last of the production payments terminates in 2002.

With most of the Company's expanded Lobo holdings still undeveloped, the
Company has significantly increased drilling activity and, as of December 31,
1998, had 13 rigs working continuously in the region. This development activity
has resulted in an increase in gross natural gas production in the region from
approximately 510 million cubic feet per day for December 1997 to approximately
750 million cubic feet per day for December 1998, an increase of approximately
47 percent. The Company anticipates spending $600 million between 1999 and 2002
to further develop its leases in the Lobo trend. The Company's 1998 Lobo trend
development program included the acquisition of new 3D seismic data and the
drilling of over 200 wells.

Lobo Pipeline Company, a wholly owned subsidiary of the Company, owns a
1,150 mile intrastate natural gas pipeline system in South Texas and expects to
implement an expansion plan designed to provide transportation for the Company's
gas production and that of third party producers, laying 100 miles of pipeline
per year for the next five years. During the first two years, most of the
pipeline added will be high-pressure trunklines to support regional development.

Gulf of Mexico

Conoco's current portfolio of producing properties in the Gulf of Mexico
includes ten fields operated by the Company and 14 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. The Company also holds interests in various offshore platforms,
pipelines and other infrastructure.

Conoco currently has 13 leases in production or under development in the
deepwater Gulf of Mexico. Our most important current development project in the
Gulf of Mexico is the Ursa field development. Ursa, operated by Shell, is one of
the largest discoveries to date in the deepwater Gulf of Mexico. The Company
holds a 16 percent interest in the field, along with Shell (45 percent), BP
Amoco (23 percent) and Exxon (16 percent). The Ursa tension leg platform was
installed in late 1998 in approximately 3,900 feet of water, with first
production scheduled for early 1999. The Company projects that peak gross
production from the Ursa field will reach 150,000 barrels per day of petroleum
liquids and 400 million cubic feet of gas per day by 2001.

Conoco's most important exploration program in the United States is in the
deepwater Gulf of Mexico. We are the seventh largest deepwater leaseholder in
the Gulf, with interests in 295 leases. Conoco has a 100 percent interest in 104
of these leases, and jointly owns 76 of the remaining leases on a 50-50 basis
with Shell and 60 of the remaining leases on a 50-50 basis with Exxon. Since
1996, Conoco has acquired 3D seismic data over large portions of the deepwater
Gulf of Mexico to identify acreage to lease and to select prospects for
drilling. Seismic interpretation is now underway on many leases and preparations
for a multi-well drilling program are being made.

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Conoco will carry out its deepwater Gulf of Mexico drilling program in
large part with a recently completed deepwater drillship. This vessel went into
service in January 1999, commencing a five year, $400 million drilling program
in the Gulf of Mexico. This highly sophisticated drillship is capable of
drilling in water depths of up to 10,000 feet and provides Conoco with the
ability to explore in areas that were previously inaccessible.

Other U.S. Producing Properties

Outside of South Texas and Gulf of Mexico, Conoco's largest producing
properties in the United States are located in the San Juan Basin of New Mexico,
the Permian Basin in West Texas and the Central Appalachian Basin in Virginia.
Conoco also has producing properties in the Williston Basin and the Hugoton
complex in the Oklahoma/Texas Panhandle.

Conoco has a significant acreage position in the San Juan Basin. Conoco's
average daily net production from the San Juan Basin in 1998 was approximately
15,500 barrels of petroleum liquids and 226 million cubic feet of natural gas.
We believe significant additional hydrocarbons lie below the basin's traditional
producing formations, and are actively exploring for new reserves. In 1998, we
conducted a 300-square-mile 3D seismic survey covering the most promising deep
areas of the basin. Early results have identified several high-potential
prospects, and two wells are planned to be drilled in 1999. Conoco will also
continue to consider potential acquisitions in this basin to take advantage of
synergies resulting from its large asset base and gas plant in the area.

Conoco has an interest in 29 fields in the Permian Basin, which is one of
the largest producing areas in the United States. In the Permian Basin, the
Company's average daily net production in 1998 was approximately 23,500 barrels
of petroleum liquids and approximately 44 million cubic feet of gas. The Company
is using 3D seismic technology, horizontal wells and other innovative extraction
technologies in an effort to extend the productive life of many of the mature
fields in the Permian Basin.

Pocahontas Gas Partnership ("Pocahontas") is a 50/50 partnership between
the Company and Consol Energy Inc. Pocahontas produces and gathers coal bed
methane ("CBM") prior to and during coal mining operations in Virginia.
Pocahontas produced and gathered approximately 34 million cubic feet per day
(gross) of CBM from the existing active mining area in 1998. The Company
recently approved an expansion of the Pocahontas project to develop CBM outside
of the existing mining area, which is expected to increase total Pocahontas
production to approximately 40 million cubic feet per day (gross) in 1999.

NATURAL GAS AND GAS PRODUCTS

In the United States, Conoco owns interests in 23 natural gas processing
plants located in Louisiana, New Mexico, Oklahoma and Texas as well as
approximately 10,000 miles of gathering lines. We operate sixteen of the plants.

Conoco gathers natural gas, extracts NGLs and sells the remaining residual
gas. Most of our raw gas liquids are supplied to our processing operations,
which further separate them into NGL products that are used as feedstocks for
gasoline and chemicals production. Conoco provides service to approximately 800
natural gas producers and sells more than 500 million cubic feet per day of
residue gas to approximately 120 customers.

Conoco's share of total NGLs from natural gas processed at the 23 plants in
which the Company owns an interest averaged 66,300 barrels per day in 1998, of
which approximately 11,000 barrels per day of NGLs were from Conoco owned
reserves, which were reported, net of royalties, as United States NGL
production. In 1998, approximately 28,200 barrels per day of additional NGLs
were attributable to processing of Conoco's natural gas liquids in
third-party-operated plants. Furthermore, the Company's 50 percent-owned equity
affiliate, C&L Processors Partnership, has five natural gas processing plants in
Oklahoma and Texas. Conoco's pro rata share of C&L's NGL production was
approximately 7,600 barrels per day in 1998.

The Company's other natural gas and gas products facilities in the United
States include Lobo Pipeline Company's 1,150-mile intrastate natural gas
pipeline system in South Texas, an 800-mile intrastate natural
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gas pipeline system in Louisiana operated by Conoco's wholly owned subsidiary,
Louisiana Gas System, Inc., natural gas and NGL pipelines in several other
states, three underground NGL storage facilities, a natural gas liquids
fractionating plant in Gallup, New Mexico with a capacity of 25,000 barrels per
day, and a 22.5 percent equity interest in Gulf Coast Fractionators, which owns
a natural gas liquids fractionating plant in Mt. Belvieu, Texas with a capacity
of 104,000 barrels per day.

In 1998 Conoco sold approximately 3.3 billion cubic feet per day of natural
gas, which included 873 million cubic feet per day of its U.S. natural gas
production.

WESTERN EUROPE

Conoco has a significant portfolio of producing properties in the United
Kingdom and Norway. Proved Western Europe reserves, as of December 31, 1998,
were 919 million BOE, consisting of 410 million barrels of petroleum liquids and
3,053 billion cubic feet of natural gas. In 1998, operations in Western Europe
contributed 44 percent of the Company's worldwide petroleum liquids production
and 33 percent of its natural gas production.

Britannia Field

Conoco has a 42.4 percent interest in the Britannia field, which is one of
the largest natural gas/ condensate fields in the United Kingdom sector of the
North Sea. Britannia is a centerpiece of the Company's strategy to increase
production and reserves through large, long-lived projects. First production
from Britannia occurred in August 1998 and the Company estimates that the field
will have a production life of approximately 30 years. The Company's proved
reserves in Britannia include 1.1 trillion cubic feet of natural gas and 56
million barrels of petroleum liquids at December 31, 1998. Britannia is
currently producing 740 million cubic feet of gas per day (gross) and production
is expected to fluctuate due to seasonal demand. Conoco and Chevron, the two
largest interest holders in the field, jointly operate Britannia.

Southern North Sea Producing Properties

Conoco has various equity interests in 13 producing gas fields in the
Southern North Sea, a major gas producing area on the United Kingdom 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 1998, Conoco's net production from the Southern North Sea was
98 billion cubic feet of natural gas.

Conoco believes there are additional development opportunities in the
Southern North Sea. One example is the Viking Phoenix project, in which Conoco
targeted the development of additional reserves using existing infrastructure
and new drilling and completion technology. In November 1998, the Company
started production from this development, for which Conoco's proved reserves
were 73 billion cubic feet of gas as of December 31, 1998. Conoco holds a 50
percent interest in the Viking Field.

At year-end 1998, Conoco acquired Canadian Petroleum UK Ltd., the British
subsidiary of Canadian Occidental Petroleum Ltd. The acquisition included (i)
interests in the Vulcan (7.9 percent), South Valiant (12.5 percent), and Caister
(30 percent) gas producing fields; (ii) a 15 percent interest in the Caister
Murdoch gas pipeline; (iii) a ten percent interest in the Eagles gas pipeline;
and (iv) interests in eight exploration blocks. As a result of this acquisition,
Conoco increased its interest in the Vulcan and South Valiant Fields to 50
percent from 42.1 percent and 37.5 percent, respectively, and increased its
stake in the Caister Murdoch gas pipeline to 42.25 percent. Conoco currently
operates the Vulcan and South Valiant fields.

Other United Kingdom Properties and Discoveries

Conoco also has interests in the Miller (30 percent), Alba (12 percent),
Statfjord (4.8 percent in the United Kingdom/10.3 percent in the Norwegian
sector), MacCulloch (40 percent), and Banff (32 percent) fields, and the Clair
discovery (21 percent). Conoco operates the MacCulloch and Banff fields, both of
which

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will employ floating production, storage and offtake ("FPSO") technology. BP
Amoco operates the Miller field and the Clair discovery, which is one of the
largest undeveloped oil discoveries in Western Europe.

Interconnector Pipeline and Gas Sales

The Interconnector pipeline, which connects the United Kingdom and Belgium,
will facilitate marketing throughout Europe of the natural gas the Company
produces in the United Kingdom. This pipeline commenced operation in October
1998. Conoco's ten percent share of the Interconnector pipeline allows the
Company to ship approximately 200 million cubic feet of gas per day to the
markets in continental Europe. The Company has long-term contracts (seven to ten
years) to supply natural gas to Gasunie in the Netherlands and Wingas in
Germany, which fully utilizes this capacity. Because the Interconnector pipeline
provides flexibility to flow in either direction, Conoco will be able to take
advantage of the long-term and short-term market conditions in both the United
Kingdom and continental Europe.

Norwegian Producing Fields

Conoco is the sixth largest oil producer in Norway. The Company has an
ownership interest in three of the largest fields in the country: Heidrun,
Statfjord and Troll. Conoco also has an interest in the Oseberg South (7.7
percent), Visund (9.1 percent), Jotun (3.75 percent), and Huldra (23.3 percent)
discoveries, which are in development, as well as the PL 203 (20 percent)
discovery.

Production from the Heidrun field began in 1995 and is currently averaging
196,000 barrels of petroleum liquids per day (gross). Conoco's share of the
proved reserves in the field, based on its 18.125 percent interest, is 119
million barrels of petroleum liquids and 159 billion cubic feet of natural gas.
Conoco was 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. The plant, in which the Company holds an 18.125 percent
interest, is operated by Statoil.

Conoco, which holds 10.3 and 4.8 percent interests in the Norwegian and
United Kingdom sectors of the Statfjord field, respectively, had net proved
reserves of 84 million barrels of petroleum liquids and 98 billion cubic feet of
natural gas in the field as of December 31, 1998 (total for Norway and the
United Kingdom). Conoco is supporting work by Statoil, the operator of
Statfjord, to determine ways to slow the natural decline of the field and
increase reserves. The Company also owns a 1.66 percent interest in the Troll
gas field, operated by Statoil, and has net proved reserves in the field of 576
billion cubic feet of natural gas and 18 million barrels of petroleum liquids.

Exploration -- The Atlantic Margin

Exploration activity in Western Europe is focused on the deepwater Atlantic
Margin fairway, which runs from the Voring Basin off the coast of Norway to the
Porcupine Basin off the west coast of Ireland. Along the Atlantic Margin, Conoco
has significant acreage positions in the Voring Basin, the West of Shetlands and
North Rockall Trough areas in the United Kingdom and the Porcupine Basin. In
1997, the United Kingdom government awarded Conoco and three partners
exploration licenses for two deepwater blocks, Block 204/14 and 204/15, in the
West of Shetlands area. These blocks are adjacent to a discovery in BP
Amoco-operated Block 204/19. Conoco, as operator of Blocks 204/14 and 204/15,
drilled two wells in 1998 to test the potential of this acreage. The results of
the wells are being currently evaluated by Conoco and its partners.

NORTHERN SOUTH AMERICA AND THE CARIBBEAN

Petrozuata

Petrozuata is a key component of Conoco's strategy to increase production
and reserves through implementation of long-lived, large development projects
and to utilize its proprietary coking technology in other areas of its business.
Petrozuata is a joint venture between the Company, which holds a 50.1 percent
non-controlling equity interest (subject to an option that expires May 31, 1999,
held by the Venezuelan

8
<PAGE> 11

investment entity SOFIP, to purchase one percent of the joint venture from
Conoco), and PDVSA Petroleo y Gas S.A., a subsidiary of Petroleos de Venezuela
("PDVSA"), the national oil company of the Republic of Venezuela, which holds
the remaining interest. Petrozuata, the first venture of its kind in Venezuela,
is developing an integrated operation to produce extra heavy crude oil from
known reserves in the Zuata region of the Orinoco Belt, transport it to the Jose
industrial complex on the north coast of Venezuela and upgrade it into a
lighter, partially processed refinery feedstock similar to crude oil (synthetic
crude), with associated by-products of liquified petroleum gas, sulfur,
petroleum coke and heavy gas oil. Conoco's recorded proved reserves related to
its interest in this project as of December 31, 1998, were 678 million barrels
of oil. Drilling began in 1997 and at December 31, 1998, approximately 60
horizontal wells were in various stages of development, with another 40 wells
planned by year-end 1999. The joint venture agreement has a 35-year term,
commencing upon the completion of the upgrading facility in 2000, and requires
approval of both Conoco and PDVSA Petroleo y Gas S.A. for major Petrozuata
decisions.

The upgrading facility, which will employ Conoco's proprietary delayed
coking technology, is currently under construction. The upgrading facility will
be located at Jose and is projected to become operational in 2000. Diluted extra
heavy crude oil will be transported via a 36-inch pipeline from the field to the
Jose industrial complex. An adjacent 20-inch pipeline will return naphtha from
the upgrading facility to the field for use as a diluent. Petrozuata has also
begun construction of field processing and support facilities and marine
facilities for shipping synthetic crude and by-products.

Petrozuata began early production of extra heavy crude oil in August 1998,
and we expect that Petrozuata's production will rise to 120,000 barrels (gross)
per day by the time the project's upgrading facility becomes operational. Prior
to completion of the upgrading facility, the extra heavy crude will be blended
with lighter oils and sold on world markets. Following completion of the
upgrading facility, the synthetic crude produced by Petrozuata will either be
used as a feedstock for our Lake Charles refinery and a refinery operated by
PDVSA, or will be sold to third parties. 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 if Petrozuata is unable to sell
the production to third parties for higher prices. All synthetic crude sales
will be denominated in United States dollars. By-products produced by the
upgrading facility (principally coke and sulfur) will be sold to a variety of
domestic and foreign purchasers. The loading facilities at Jose will transfer
synthetic crude and some of the by-products to ocean tankers for export.
Synthetic crude sales are expected to comprise more than 90 percent of the
project's revenues.

The La Luna Trend

Exploration activity in northern South America and the Caribbean is focused
on a geologic trend known as La Luna. In Venezuela, Conoco conducted seismic
surveys in 1997 on the shallow water Gulf of Paria West block, and on the
Guanare block in the Merida Andes foothills. The Company drilled two prospects,
one on each block resulting in one dry hole in the Guanare block and one well in
the Gulf of Paria West block on which a drill stem test was performed in early
1999. Additional exploration and appraisal work is currently planned for 1999.
Conoco currently holds a 50 percent working interest in both the Gulf of Paria
West block, which it operates, and the Guanare block, which is operated by Elf
Aquitane (in each case subject to dilution to 32.5 percent at the option of a
PDVSA affiliate).

In northwestern Colombia, seismic surveys have been completed in
partnership with Texaco on three tracts that Conoco acquired through a 50
percent farm-in. In 1998, Texaco drilled two wells on the acreage (both dry
holes) and plans to drill two additional wells in 1999. In addition, Conoco and
Texaco acquired a fourth tract in a joint bid in 1998.

In 1997, Conoco signed a production sharing contract for Blocks 4a and 4b,
two large prospective blocks off Trinidad's east coast. A 3D seismic survey was
acquired over the acreage in 1997, and the Company is currently drilling a well
to test the potential of this acreage. Conoco is operator of both blocks and has
a 50 percent working interest; Texaco holds the remaining working interest in
both blocks.

Seeking additional opportunities in the La Luna Trend, Conoco has conducted
a two-year study of the hydrocarbon potential of the entire offshore Barbados
area. Encouraged by the study, Conoco has entered into
9
<PAGE> 12

a commitment to acquire seismic data over 50 percent of the original study area
and has the option to enter a drilling program to test the potential of this
largely unexplored area.

Phoenix Park

Conoco holds a 39 percent equity interest in Phoenix Park Gas Processors
Limited ("Phoenix Park"), a joint venture with the National Gas Company of
Trinidad and Tobago Limited, that processes gas in Trinidad and markets in the
eastern Caribbean. Phoenix Park owns a gas processing plant, a fractionator
producing propane, mixed butane and natural gasoline, storage tanks and a
liquified petroleum gas marine loading dock. These facilities produce over
11,000 barrels per day (gross) of NGLs. Phoenix Park is currently expanding its
facilities to process up to 1.4 billion cubic feet of gas per day, increase
fractionation capacity to 33,000 barrels per day, and add additional storage and
marine export facilities. This expansion is expected to be completed in
mid-1999.

ASIA PACIFIC

Conoco has a 30-year operating history in Indonesia. The focus of Conoco's
effort in the Asia Pacific region is the Company's operations in the Indonesian
sector of the Natuna Sea. In this area, Conoco is the operator of the Block B
and North West Natuna Sea Block II production sharing contracts ("PSCs"). Conoco
also has interests in exploration blocks in Cambodia, Vietnam and New Zealand.

West Natuna Gas Project

In 1996, Conoco as operator of the 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," with the aim of jointly marketing
gas from the West Natuna Area to Singapore. In January 1999, Pertamina (the
Indonesian state-owned oil and gas company), Sembgas (a company owned by
Sembcorp Industries, Temasek and Tracetebel, which will act as buyers of the
gas) and the West Natuna Group entered into a definitive set of agreements,
providing for the sale and purchase of natural gas from specified fields in the
PSCs operated by the West Natuna Group.

These agreements provide for gas deliveries to begin by mid-2001 that will
rise to a sales rate of 325 million cubic feet per day. Sembgas will sell the
gas to a series of end users (including Tuas Power, Sembcorp Cogen and Esso
Chemicals) who will use the gas for industrial purposes, primarily power
generation. The West Natuna Group has entered into a gas supply agreement with
Pertamina in which they have undertaken to develop a series of fields and to
supply the gas produced to Pertamina for the sale to Sembgas. In addition, each
of the PSCs has been extended to allow the West Natuna Group to support
Pertamina for the expected 22 year life of the contract with Sembgas.

A 300-mile 28-inch submarine pipeline (along with smaller gathering
pipelines) will be built by the West Natuna Group to transport the gas from the
West Natuna Sea fields to Singapore. Conoco will be the operator of the pipeline
system (including the receiving terminal in Singapore). Contractual arrangements
between the West Natuna Group, Pertamina and Sembgas to govern the construction
and operation of the pipeline are in place. An engineering, procurement,
construction and installation contract to build the pipeline is currently being
bid. The agreements provide for the supply of approximately one trillion cubic
feet of natural gas from fields in Block B to Sembgas. Block B's share of
production will reach 140 million cubic feet of gas daily. Block B constitutes
43.1 percent of the West Natuna Group and Conoco owns a 40 percent interest in
Block B and has net proved reserves of 197 billion cubic feet.

Belida and Sembilang Fields, Indonesia

Conoco holds a 40 percent interest in and serves as operator of the Belida
and Sembilang oil fields in the Block B PSC. An ongoing infill drilling program
in the Belida Field maintained gross production for the Indonesian fields in the
range of 85,000 barrels per day in 1998.

10
<PAGE> 13

CANADIAN ROCKIES

Conoco has had significant exploration success in the 1990's in the
foothills east of the Canadian Rockies. In this area, Conoco has an interest in
209,000 net acres, much of which has yet to be developed. Development plans for
1999/2000 include bringing on-stream two more of the foothills discoveries. In
addition to the discoveries in the foothills trend, Conoco has a significant
interest in the Peco Gas Field, located just east of the foothills. Conoco also
owns 100 percent of the Peco gas processing plant, which processes gas from the
Peco Field and two of the foothills discoveries.

RUSSIA

The Company holds a 50 percent direct (plus a 4.7 percent indirect)
ownership interest in Polar Lights Company ("Polar Lights"), a Russian limited
liability company established in January 1992. Polar Lights, the first
Russian-Western joint venture to develop a major new oil field, was established
to develop the Ardalin oil field discovered in 1988 by the Russian state
enterprise GP Arkhangelskgeologia. Ardalin is located in the Arctic tundra
approximately 1,000 miles northeast of Moscow. As of December 31, 1998, Conoco's
share of proved reserves was 42 million barrels of petroleum liquids, with an
additional eight million barrels of net proved reserves at the adjacent oil
fields -- Kolva and Dusushev. Polar Lights started producing oil in August 1994
and gross production has increased from an average 21,000 barrels per day in
1994 to an average 35,000 barrels per day in 1998. Oil is transported through
the existing Russian pipeline system and is then exported or sold on the
domestic market.

In March 1998, Conoco signed a memorandum of understanding with OAO Lukoil
("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 in the Timan-Pechora region in northern Russia, which includes the
large undeveloped Yuzhno Khilchuyu oil field. The memorandum of understanding
followed Lukoil's purchase in December 1997 of a majority interest in OAO
Arkhangelskgeoldobycha (successor to GP Arkhangelskgeologia), the Company's
original partner in the Northern Territories. In November 1998, Conoco and
Lukoil signed a second memorandum of understanding to work together to draw up
and submit all documents required by the Russian government to develop the
Northern Territories under production sharing agreement ("PSA") terms, to secure
funding for the project and to work together to resolve other outstanding
issues.

In July 1998, the Company acquired a 15.667 percent interest in OAO
Arkhangelskgeoldobycha for approximately $33 million. OAO Arkhangelskgeoldobycha
owns a 30 percent interest in Polar Lights.

WEST AFRICA

In 1997, Conoco, in partnership with Express Petroleum and Gas Company Ltd.
of Nigeria ("Express"), announced the production of first oil from the shallow
water Ukpokiti field, located offshore in the western Niger delta. Conoco
currently has a 90 percent revenue interest in the field. Total production from
the field is currently 20,000 barrels per day of oil, and Conoco's net proved
reserves as of December 31, 1998 were 13.2 million barrels of oil. Express
operates Ukpokiti, and the Company provides technical and operational assistance
in the field's development, which included three remote caisson-type structures,
five wells, and the conversion of the Conoco tanker "Independence" into a
floating production and storage offtake vessel. With a 1.7 million barrel
storage capacity, the vessel also serves as an export terminal.

In addition to the Company's interest in the Ukpokiti field, Conoco has a
47.5 percent working interest in the deepwater OPL 220 license off the coast of
Nigeria, which is operated by Conoco and encompasses 600,000 acres. The Company
has acquired a 3D seismic survey and drilled two wells on this license. The
first well, which was drilled in 1997, found only gas and was non-commercial.
The second well was drilled in 1998 and encountered both oil and gas-filled
sands. Conoco and its partner, Exxon, are currently evaluating results from this
second well.

11
<PAGE> 14

MIDDLE EAST

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

OIL AND NATURAL GAS RESERVES

The Company's estimated proved reserves at December 31, 1998 were 2,622
million BOE (consisting of 1,591 million barrels of oil and 6,183 billion cubic
feet of natural gas).

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

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

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

<TABLE>
<CAPTION>
DECEMBER 31
----------------------------------
1998 1997 1996 1995 1994
----- ----- ---- ---- ----
(MILLIONS OF BARRELS)
<S> <C> <C> <C> <C> <C>
PROVED OIL RESERVES(1)
CONSOLIDATED COMPANIES
United States.............................................. 261 277 299 294 336
Europe..................................................... 410 421 413 408 394
Other Regions.............................................. 192 195 214 231 223
----- ----- --- --- ---
Worldwide................................................ 863 893 926 933 953
SHARE OF EQUITY AFFILIATES
Europe..................................................... 50 51 47 44 35
Other Regions(2)........................................... 678 680 -- -- --
----- ----- --- --- ---
Total Proved Oil Reserves........................ 1,591 1,624 973 977 988
===== ===== === === ===
</TABLE>

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

(1) Proved oil reserves comprise crude oil, condensate and NGLs expected to be
removed for the Company's account from its natural gas production.

(2) Represents the Company's equity share of the Petrozuata venture in
Venezuela.

12
<PAGE> 15

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

<TABLE>
<CAPTION>
DECEMBER 31
-------------------------------------
1998 1997 1996 1995 1994
----- ----- ----- ----- -----
(BILLIONS OF CUBIC FEET)
<S> <C> <C> <C> <C> <C>
PROVED NATURAL GAS RESERVES
CONSOLIDATED COMPANIES
United States.......................................... 2,319 2,235 1,822 1,891 1,749
Europe................................................. 3,053 3,060 3,068 2,649 2,431
Other Regions.......................................... 430 196 173 169 150
----- ----- ----- ----- -----
Worldwide............................................ 5,802 5,491 5,063 4,709 4,330
SHARE OF EQUITY AFFILIATES
United States.......................................... 381 370 333 339 344
----- ----- ----- ----- -----
Total Proved Natural Gas Reserves............ 6,183 5,861 5,396 5,048 4,674
===== ===== ===== ===== =====
</TABLE>

PRODUCTION DATA

The Company's oil and natural gas production (excluding NGLs from gas plant
ownership) averaged 583,000 BOE per day in 1998, compared with 575,000 BOE per
day in 1997. As a percentage of total production, natural gas production was 40
percent and 35 percent in 1998 and 1997, respectively.

The table below shows the Company's interests in average daily oil
production and natural gas production for the past three years. Oil production
comprises crude oil and condensate produced for the Company's account, plus its
share of NGLs removed from natural gas production from owned leases. Natural gas
production represents the Company's share of production from leases in which the
Company has an ownership interest. Natural gas liquids processed represents the
Company's share of NGLs acquired through gas plant ownership.

<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
(THOUSANDS OF BARRELS
PER DAY)
<S> <C> <C> <C>
NET AVERAGE DAILY OIL PRODUCTION
CONSOLIDATED COMPANIES
United States.......................................... 79 90 91
Europe................................................. 152 176 182
Other Regions.......................................... 95 92 88
--- --- ---
Total Net Production -- Consolidated Companies.... 326 358 361
SHARE OF EQUITY AFFILIATES
Europe................................................. 17 16 13
Other Regions.......................................... 5 -- --
--- --- ---
Total Net Production -- Equity Affiliates......... 22 16 13
--- --- ---
Total Net Oil Production Per Day.................. 348 374 374
=== === ===
</TABLE>

13
<PAGE> 16

<TABLE>
<CAPTION>
1998 1997 1996
------ ------ ------
(MILLIONS OF CUBIC FEET
PER DAY)
<S> <C> <C> <C>
NET AVERAGE DAILY NATURAL GAS PRODUCTION
CONSOLIDATED COMPANIES
United States.......................................... 873 709 738
Europe................................................. 470 432 416
Other Regions.......................................... 53 46 41
----- ----- -----
Total Net Production -- Consolidated Companies.... 1,396 1,187 1,195
SHARE OF EQUITY AFFILIATES
United States.......................................... 15 16 16
----- ----- -----
Total Net Natural Gas Production Per Day.......... 1,411 1,203 1,211
===== ===== =====
</TABLE>

<TABLE>
<CAPTION>
1998 1997 1996
----- ----- -----
(THOUSANDS OF BARRELS
PER DAY)
<S> <C> <C> <C>
NET AVERAGE DAILY NATURAL GAS LIQUIDS PROCESSED
CONSOLIDATED COMPANIES
United States(1)....................................... 55 55 58
SHARE OF EQUITY AFFILIATES
United States.......................................... 8 8 8
Other Regions.......................................... 4 5 5
----- ----- -----
Total Net Processed -- Equity Affiliates.......... 12 13 13
----- ----- -----
Total Net Natural Gas Liquids Processed Per Day... 67 68 71
===== ===== =====
</TABLE>

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

(1) 1997 and 1996 were restated to include only NGLs received as a processing
fee.

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

14
<PAGE> 17

The following table sets forth the Company's 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, 1998.

<TABLE>
<CAPTION>
TOTAL UNITED OTHER
WORLDWIDE STATES EUROPE REGIONS
--------- ------ ------ -------
(UNITED STATES DOLLARS)
<S> <C> <C> <C> <C>
For the year ended December 31, 1998(1)
Average production costs per barrel of oil equivalent
of petroleum produced(2)............................ $ 3.95 $ 3.69 $ 4.54 $ 3.21
Average sales prices of produced petroleum(3)
Per barrel of crude oil and condensate sold......... 12.37 12.17 12.61 12.12
Per mcf of natural gas sold......................... 2.24 1.96 2.86 1.42
For the year ended December 31, 1997(1)
Average production costs per barrel of oil equivalent
of petroleum produced(2)............................ 4.21 4.23 4.51 3.40
Average sales prices of produced petroleum(3)
Per barrel of crude oil and condensate sold......... 18.58 17.93 18.93 18.35
Per mcf of natural gas sold(4)...................... 2.44 2.18 3.25 1.41
For the year ended December 31, 1996(1)
Average production costs per barrel of oil equivalent
of petroleum produced(2)............................ 3.84 4.11 4.13 2.50
Average sales prices of produced petroleum(3)
Per barrel of crude oil and condensate sold......... 20.11 18.68 20.94 19.47
Per mcf of natural gas sold(4)...................... 2.12 1.70 2.92 1.24
</TABLE>

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

(1) Excludes the Company's share of equity affiliates.

(2) 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.

(3) Excludes proceeds from sales of interest in oil and gas properties.

(4) 1997 and 1996 restated from wet gas price to dry gas price.

DRILLING AND PRODUCTIVE WELLS

The following table sets forth the Company's drilling wells and productive
wells by region as of December 31, 1998.

<TABLE>
<CAPTION>
TOTAL UNITED OTHER
WORLDWIDE STATES EUROPE REGIONS
--------- ------ ------ -------
(NUMBER OF WELLS)
<S> <C> <C> <C> <C>
Number of wells drilling(1)(3)
Gross................................................... 56 33 11 12
Net..................................................... 23 16 2 5
Number of productive wells(2)(3)
Oil wells -- gross...................................... 7,553 6,989 236 328
-- net........................................ 2,659 2,517 22 120
Gas wells -- gross...................................... 8,593 8,364 159 70
-- net....................................... 4,370 4,267 43 60
</TABLE>

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

(1) Includes wells being completed.

(2) Approximately 182 gross (31 net) oil wells and 742 gross (275 net) gas wells
have multiple completions.

(3) Excludes the Company's share of equity affiliates.

15
<PAGE> 18

DRILLING ACTIVITY

The following table sets forth the Company's net exploratory and
development wells drilled by region for the three-year period ended December 31,
1998.

<TABLE>
<CAPTION>
TOTAL UNITED OTHER
WORLDWIDE STATES EUROPE REGIONS
--------- ------ ------ -------
(NUMBER OF NET WELLS COMPLETED)
<S> <C> <C> <C> <C>
For the year ended December 31, 1998(1)
Exploratory -- productive............................... 7.3 2.2 1.1 4.0
-- dry..................................... 14.0 5.4 1.9 6.7
Development -- productive............................... 234.8 215.9 2.8 16.1
-- dry................................... 13.0 13.0 0.0 0.0
For the year ended December 31, 1997(1)
Exploratory -- productive............................... 7.1 3.7 1.6 1.8
-- dry..................................... 18.4 11.7 4.9 1.8
Development -- productive............................... 142.6 126.9 5.4 10.3
-- dry................................... 10.2 7.2 0.0 3.0
For the year ended December 31, 1996(1)
Exploratory -- productive............................... 42.8 1.6 2.0 39.2
-- dry..................................... 20.5 10.3 4.0 6.2
Development -- productive............................... 89.9 73.1 6.1 10.7
-- dry................................... 17.3 13.5 0.3 3.5
</TABLE>

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

(1) Excludes the Company's share of equity affiliates.

DEVELOPED AND UNDEVELOPED PETROLEUM ACREAGE

The following table sets forth the Company's developed and undeveloped
petroleum acreage by region as of December 31, 1998.

<TABLE>
<CAPTION>
TOTAL UNITED OTHER
WORLDWIDE STATES EUROPE REGIONS
--------- ------ ------ -------
(THOUSANDS OF ACRES)
<S> <C> <C> <C> <C>
Developed acreage(1)
Gross................................................... 7,691 3,253 1,023 3,415
Net..................................................... 3,121 1,534 265 1,322
Undeveloped acreage(1)
Gross................................................... 93,254 3,613 4,829 84,812
Net..................................................... 61,564 2,428 1,588 57,548
</TABLE>

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

(1) Excludes the Company's share of equity affiliates.

The Company 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 (the "DOE") and the Securities and Exchange Commission (the
"Commission"). The estimates furnished to the DOE have been consistent with
those furnished to the Commission. 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 five percent from the corresponding
estimates reflected in total reserves reported to the Commission.

16
<PAGE> 19

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 United States, Europe
and the Asia Pacific region. United States and European operations each provided
about one-half (55 and 56 percent, respectively) of total Downstream earnings in
1998, partially offset by a small loss resulting from start-up activities in
Asia Pacific. Downstream's objective is to continue to provide an appropriate
return on investment by improving the competitiveness of the core business,
while providing free cash flow to fund growth in Upstream, as well as in new
Downstream businesses. Consistent with such objectives, the Company has in the
past, and may from time to time in the future, purchase or sell Downstream
assets. The Company may also consider forming alliances or joint ventures to
hold and operate all or a selected part of its Downstream assets, either to
optimize the efficiency of such operations through achieving economies of scale
or, in certain circumstances, to monetize a portion of the value of such assets.

Conoco has made capital investments in Downstream activities averaging
approximately $600 million per year for the last three years. 1998 capital
investments in Downstream activities were approximately $530 million.

Downstream's strengths are in processing heavy, high sulfur and acidic
crudes, upgrading bottom-of-the barrel feedstocks via coking technology,
maintaining low cost, high volume retail marketing operations and developing
specialty products. Approximately 50 percent of the Company's worldwide refining
capacity is designed to process heavy, high sulfur crude. The Humber refinery in
the United Kingdom can process about 44 percent acidic crudes in its crude
slate. The Company 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 coke, 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.

The Company produces and markets a full range of refined petroleum
products, including gasolines, diesel fuels, heating oils, aviation fuels, heavy
fuel oils, asphalts, lubricants, petroleum coke products and petrochemical
feedstocks. We own and operate, or are a partner in the operation of nine
refineries worldwide with a total crude and condensate capacity of 807,000
barrels per calendar day. Refining capacity is distributed 62 percent in the
United States, 33 percent in Europe and 5 percent in the Asia Pacific region.

Capacity has risen by over 185,000 barrels per day, or 30 percent, since
year end 1995 as a result of the expansion of the Lake Charles refinery, the
upgrade of the Humber refinery, the acquisition of an interest in two refineries
in the Czech Republic and an investment in the new Melaka refinery in Malaysia.
In the United States, the Company 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
1998, refined product sales averaged 1,049,000 barrels per day, distributed 68
percent, 31 percent and one percent in the United States, Europe and the Asia
Pacific region, respectively.

UNITED STATES

Conoco's four U.S. refineries are high conversion facilities with design
capacity 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 portion of heavy, high sulfur crude oil, 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.

17
<PAGE> 20

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 1994, the Company has increased refining input at its
four U.S. refineries by approximately 14 percent, while lowering average
operating expenses by approximately $2.00 per barrel of refinery input. We have
improved market share through geographic concentration of markets.

Conoco intends to limit future capital investments in Downstream United
States, excluding large, non-discretionary, regulatory-driven projects and
selected growth projects, to a level that is less than half of Downstream United
States' operating cash flow. Capital expenditures were approximately $201
million in 1998, a decline of approximately $26 million compared to $227 million
in 1997, reflecting the completion of major projects. We are positioned to make
the necessary clean fuels investments at our refineries over the next five years
in support of changing motor fuel specifications. We also plan to make
investments at the Lake Charles refinery to facilitate processing of Petrozuata
synthetic crude.

Refining

The Company operates four wholly owned refineries in the United States. The
following tables outline the rated crude and condensate distillation capacity as
of December 31 for each of the past five years, and the average daily crude,
condensate and other inputs for each of the past five years.

<TABLE>
<CAPTION>
DECEMBER 31
--------------------------------
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
(THOUSANDS OF BARRELS PER DAY)
<S> <C> <C> <C> <C> <C>
REFINERY INPUTS(1)
Lake Charles, Louisiana
Crude and condensate(2)................................... 216 211 177 179 183
Other feedstocks.......................................... 24 23 21 23 24
Ponca City, Oklahoma
Crude and condensate(2)................................... 167 161 150 151 144
Other feedstocks.......................................... 4 2 2 5 2
Denver, Colorado
Crude and condensate(2)................................... 50 53 49 49 47
Other feedstocks.......................................... 0 0 0 0 0
Billings, Montana
Crude and condensate(2)................................... 52 51 51 45 48
Other feedstocks.......................................... 3 3 3 3 3
Total crude and condensate........................ 485 476 426 424 422
Total other feedstocks............................ 31 27 26 31 30
</TABLE>

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

(1) Includes feedstocks in addition to crude and condensate on which rated
capacity is based.

(2) Includes actual crude and condensate runs, which may exceed rated capacity.

18
<PAGE> 21

Conoco's U.S. consolidated refined product yields by volume in 1998 were 49
percent motor gasoline, 40 percent middle distillates, including jet and diesel
fuel, 11 percent residual fuel oil and asphalt and other products, including
petroleum coke, lubricants and liquified petroleum gases.

Lake Charles Refinery and Related Facilities

Conoco's Lake Charles refinery, located in Westlake, Louisiana, is a fully
integrated, high conversion facility which has a crude and condensate capacity
of 226,000 barrels per day and processes both heavy, high sulfur crude oil and
low sulfur crude oil. The refinery's Gulf Coast location provides access to
numerous cost effective domestic and international crude oil sources. The crude
design capacity is approximately 170,000 barrels per day of heavy, high sulfur
crudes with the remaining 56,000 barrels per day of local, domestically supplied
low sulfur crudes. While the types and origins of these lower priced, heavy,
high sulfur crudes can vary, the majority consists of Venezuelan and Mexican
crudes delivered via tanker. The 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 United States. In addition,
refinery products can be sold into export markets through the refinery's marine
terminal.

The ability to refine both low sulfur and heavy, high sulfur crudes at the
Lake Charles refinery provides a competitive advantage to the Company by
enabling the refinery to produce from relatively low-cost feedstocks a full
range of products including gasolines, jet fuel, diesel fuel, petroleum coke,
lube oils, LPG and other specialty products. The refinery facilities include
fluid catalytic cracking, delayed coking and hydrodesulfurization units which
enable it to maximize its upgrade of heavier crude oil. A crude unit expansion
and a new catalytic reformer were completed in conjunction with the Excel
Paralubes project (discussed below) to take advantage of synergies generated
between the two facilities. We are making investments in the Lake Charles
refinery so that in the future it will be able to process Petrozuata synthetic
crude.

Integration of fuels and specialty products plays an important role in
maximizing product value at the refinery. Intermediates produced from low sulfur
crude processing allow the refinery to supply the heaviest, highest boiling
range material in the crude to the Cit-Con lube plant (owned 35 percent by
Conoco) for base oils, finished lubes and wax production. Other intermediates
are exchanged with a neighboring chemical plant complex for further processing.

The refinery supplies high sulfur gas oil to Excel Paralubes (a 50/50 joint
venture between the Company and Pennzoil-Quaker State), which owns a
hydrocracked lubricating base oil facility. Excel Paralubes' state-of-the-art
lube oil facility produces approximately 17,000 barrels per day of high quality
hydrocracked base oils, representing approximately ten 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 the
recently formed Penreco joint venture company (also a joint venture with
Pennzoil-Quaker State). Penreco manufactures and markets highly refined
specialty petroleum products for global markets.

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 converting the heaviest part of the crude barrel into diesel
fuel and gasoline. In addition, green petroleum coke is supplied to a nearby
coke calcining venture.

Ponca City Refinery

Conoco's refinery located in Ponca City, Oklahoma has a crude and
condensate capacity of 168,000 barrels per day of light, high sulfur and light,
low sulfur crudes. Both foreign and domestic crudes are delivered by pipeline
from offshore, Oklahoma, Kansas, and North and West Texas fields. 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

19
<PAGE> 22

catalytic cracking, delayed coking and hydrodesulfurization units, which enable
it to produce high ratios of gasoline and diesel fuel from crude oil.

Denver Refinery

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

The Denver refinery is a high conversion refinery that produces a full
range of products including gasolines, jet fuels, diesel and asphalt. The
refinery's upgrading units enable it to process a crude slate containing nearly
50 percent heavy, high sulfur crude. The Company has 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
between the Company and Koch Industries) with high quality asphalt products.
Both of these ventures enable us to turn relatively low value intermediates into
higher margin products.

Billings Refinery

The Company's Billings, Montana refinery has a crude and condensate
capacity of 52,000 barrels per day, processing a mixture of over 80 percent
Canadian heavy, high sulfur crude plus domestic high sulfur and low sulfur crude
oils all delivered by pipeline. Products from the refinery are delivered via
company-owned pipelines, rail, and trucks, thereby 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 sulfur crudes provides us with
significant competitive advantages.

The Billings refinery is a high conversion refinery that produces a full
range of products including gasolines, jet fuels, diesel and fuel grade
petroleum coke. The Billings refinery has a very high conversion rate and the
capability to process less expensive, very heavy, high sulfur crudes. A delayed
coker converts heavy, high sulfur residue into higher value light oils. A gas
oil hydrotreating unit and hydrogen plant improve the light oil production
yields and remove the additional sulfur contained in these heavy, high sulfur
crudes.

Marketing

In the United States, the Company markets gasoline, utilizing the Conoco
brand, in 33 states (20 of which represent primary markets) in the southeast,
mid-continent and Rocky Mountain regions. Market growth continues to be targeted
to those areas where we can obtain a strong market share and areas that leverage
supply from our U.S. refineries and those distribution systems in which we have
an ownership position. Increasing operating market share has resulted in
particularly strong brand recognition in the Rocky Mountain and mid-continent
markets.

Conoco gasoline is sold through approximately 4,900 branded stations in the
United States, 95 percent through retail outlets owned by independent wholesale
marketers and five percent through 255 company-owned stores at year end 1998. We
market gasoline primarily through the wholesale channel in the United States
because it requires a lower capital investment than company-owned retail
stations but still provides a secure, branded outlet for our products. The
Company operates retail stations to establish brand standards and image as well
as to better understand the independent distributors in order to provide
programs and services to them and the consumer. Building on this knowledge, we
have recently introduced "breakplace(R)," a new concept in convenience store
design. This new format, involving the complete redesign of an outlet's exterior
and interior, is designed to increase the frequency and transaction size of
customer visits by catering to the needs of the "convenience connoisseur." There
were 34 breakplace(R) locations as of December 31, 1998, and Conoco is licensing
the trademark to marketers. Many more stores in the network have adopted
comprehen-
20
<PAGE> 23

sive offerings patterned after the format, thereby supporting wholesale
marketing and elevating the Company's brand perception to the consumer.

At year-end 1998, CFJ Properties, a 50/50 joint venture between the Company
and Flying J, owned and operated 83 truck travel plazas that carry both the
Conoco and Flying J brands and provide a secure outlet for the Company's diesel
production. In addition, bulk sales of all refined petroleum products are made
to commercial, industrial and spot market customers.

Transportation

Conoco has approximately 6,500 miles of crude and product mainline
pipelines in the United States, including those partially owned and/or operated
by affiliates. We also own and operate 38 finished product terminals, six
liquified petroleum gas terminals, one crude terminal and one coke-exporting
facility. The Company's 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 products
markets. Our U.S. pipeline system transported an average of 909,000 barrels per
day in 1998. Our equity share of shipments on affiliate pipelines was an
additional 383,000 barrels per day.

The Company currently operates a fleet of seven seagoing crude oil tankers,
principally of Liberian registry, including five double-hulled tankers. Conoco
operates a 100 percent double-hulled tanker and barge fleet in United States
waters. Four vessels are used to provide secure transportation to the Lake
Charles refinery, two others are in use in the Asia Pacific market (currently
slated for disposition later this year) and another 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. An eighth vessel is being used as a floating production
storage and offtake vessel ("FPSO") off the coast of Nigeria. Two additional
double-hulled tankers are currently under construction and will be joining the
fleet in the Gulf of Mexico in 1999.

EUROPE

Conoco's European refining and marketing activities are conducted in 17
countries. Conoco's primary European markets are in the United Kingdom and
Germany, which together accounted for 96 percent of our European Downstream
after-tax earnings in 1998. We also have marketing operations in Austria,
Belgium, Denmark, Finland, France, Luxembourg, Norway, Sweden, and Switzerland.
More recently we have entered the faster growing markets in the Czech Republic,
Hungary, Poland, Slovakia, Spain and Turkey. The marketing operations in Central
and Eastern Europe are complemented by an equity interest in two refineries in
the Czech Republic.

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 United Kingdom and Germany, respectively, as top performers in
Europe. We plan to redirect cash generated by our mature European businesses to
other parts of Upstream and Downstream operations and to the identified European
growth markets.

The Company invested approximately $180 million in its Downstream European
operations in both 1997 and 1998 and expects to invest about $225 million in
1999. We continue to implement relatively low-cost projects in our refining
operations designed to increase production and yields, while reducing feedstock
costs and operating expenses. The Company plans to continue to direct capital
expenditures for marketing operations, which are expected to be approximately 50
percent of the European Downstream total capital expenditures, toward
construction of new stations in growth markets, primarily in Central and Eastern
Europe and also in its 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 high value finished products. In addition, since the United Kingdom
refinery also processes fuel oil as a feedstock, the price

21
<PAGE> 24

difference between low sulfur fuel oil and finished products 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 the Company
operates.

Refining

The Company's principal European refining operations are located in the
United Kingdom, Germany, and the Czech Republic. Since early 1996, the expansion
of the Company's Humber refinery in the United Kingdom, the formation of the
MiRO joint venture through consolidation with a neighboring German refinery and
the purchase of a share in a joint venture owning two Czech Republic refineries
have increased the Company's European crude refining capacity by approximately
52 percent (90,000 barrels per day). We have continuously upgraded our
refineries in Europe since the early 1990's and the configuration and output of
the refineries are two of Conoco's primary sources of competitive advantage. In
1996, the United Kingdom and Germany refineries ranked in the first quartile of
Western European refineries for financial and operating performance (in the net
margin, return on investment, processing efficiency and volumetric expansion
categories) as ranked by Solomon Associates, an independent benchmarking
company.

Conoco has undertaken a major capital investment program totaling
approximately $350 million from 1994 through 1998 to process lower cost
feedstocks and increase conversion capacity, product quality and energy
efficiency at the Humber refinery. The Company plans to make in excess of $100
million in capital expenditures at the Humber refinery in 1999 in order to
continue to improve reliability and efficiency and to make investments to meet
clean fuel specifications. The Company is also participating in upgrading
projects at its joint venture owned refineries in Germany and the Czech
Republic.

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

<TABLE>
<CAPTION>
DECEMBER 31
----------------------------------------
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
(THOUSANDS OF BARRELS PER DAY)
<S> <C> <C> <C> <C> <C>
REFINERY CRUDE AND CONDENSATE CAPACITY
Humber, United Kingdom................................ 180 180 180 130 130
MiRO, Germany(1)...................................... 54 54 43 43 43
Czech Republic(2)..................................... 29 29 29 -- --
--- --- --- --- ---
Total(3).................................... 263 263 252 173 173
=== === === === ===
</TABLE>

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

(1) The 1998 and 1997 figures represent the Company's 18.75 percent interest in
the MiRO refinery complex at Karlsruhe, Germany. For the years 1996 and
earlier, Conoco's interest was 25 percent of the OMW refinery.

(2) Represents the Company's 16.33 percent interest in two Czech Republic
refineries.

(3) Does not include the Company's indirect 1.2 percent interest in a 95,000
barrel per day refinery in Mersin, Turkey acquired as a result of the
Company's marketing joint venture in Turkey.

22
<PAGE> 25

Total crude and condensate(6)..................... 239 209 190 179 171
Total other feedstocks............................ 61 68 90 87 74
</TABLE>

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

(1) Includes feedstocks in addition to crude and condensate on which rated
capacity is based.

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

(3) Includes actual crude and condensate runs, which may exceed rated capacity.

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

(5) Represents the Company's 16.33 percent interest in two refineries in the
Czech Republic.

(6) Does not include the Company's 1.2 percent interest in a 95,000 barrel per
day refinery in Mersin, Turkey.

The yield of the Company's European refineries by product and country for
the year ended December 31, 1998, was as follows:

<TABLE>
<CAPTION>
UNITED
KINGDOM GERMANY CZECH REPUBLIC
------- ------- --------------
<S> <C> <C> <C>
PERCENT OF TOTAL YIELD(1)
Motor gasoline.............................................. 37 40 19
Middle distillate........................................... 42 44 31
Residual fuel oil and asphalt............................... 9 8 23
Other(2).................................................... 12 8 27
</TABLE>

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

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

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

United Kingdom Refinery

Conoco's wholly owned Humber refinery is located in North Lincolnshire,
England, and has a crude and condensate capacity of 180,000 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 up to 60,000 barrels per day of 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. In
1996, Conoco increased crude capacity at the refinery and added a vacuum unit
that allows the refinery to process up to 80,000 barrels per day of the less
expensive, acidic North Sea crudes. 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

23
<PAGE> 26

value graphite and anode petroleum cokes. Approximately 50 percent of the light
oils produced in the refinery are marketed in the United Kingdom while the other
products are exported to the rest of Europe and the United States. This gives
the refinery the flexibility to take full advantage of inland and global export
market opportunities.

Germany Refinery

The MiRO refinery in Karlsruhe, Germany, is a joint venture refinery with a
crude and condensate capacity of 285,000 barrels per day. The MiRO joint venture
arose from the combination in 1996 of the existing OMW refinery, in which the
Company had a 25 percent share, with an adjacent Esso refinery. The Company has
an 18.75 percent interest in MiRO and the Company's capacity share is 54,000
barrels per day. The other owners of MiRO are DEA Mineraloel AG, Esso AG and
Ruhr Oel GmbH (a 50/50 joint venture between Veba and PDVSA). Approximately 55
percent of the refinery's crude feedstock is low cost, high sulfur crude. The
MiRO refinery complex is a fully integrated, high conversion refinery producing
gasoline, middle distillates, residual fuel oil and other products. The refinery
has a high capacity to convert lower cost feedstocks into high value products
primarily with a fluid catalytic cracker and delayed coker. The coker produces
both fuel grade and specialty calcined cokes.

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

Czech Republic Refineries

In late 1995, the Company, through participation in the newly formed Czech
Refining Company ("CRC"), acquired an interest in two refineries in the Czech
Republic. The other owners of CRC are Unipetrol A.S., Agip Petroli, and Shell
Overseas Investment B.V. The refinery at Litvinov has a crude and condensate
capacity of 109,800 barrels per day, and the Kralupy refinery has a crude and
condensate capacity of 67,500 barrels per day. The Company's 16.33 percent
ownership share of the combined capacity is 29,000 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 Company expects that completion of a visbreaker project at the Litvinov
refinery scheduled for the year 2000 will increase conversion rates and
significantly reduce fuel oil production. The Kralupy refinery is currently a
hydroskimming facility, but CRC has approved an investment in major conversion
facilities, to reduce fuel oil production and increase light oil yields. The two
Czech refineries are operated as a single entity with intermediate streams
moving between the two facilities. CRC markets finished products both inland and
abroad. We intend to use our share of the light oil production to support an
expanding retail marketing network in Central and Eastern Europe.

Marketing

Conoco has marketing operations in 17 European countries. Our European
marketing strategy is to sell primarily through owned, leased or joint venture
retail sites using a low cost, high volume, low price strategy. 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.
The Company is standardizing its European retail operations in order to capture
cost savings and prepare for a more integrated Europe. The Company is continuing
to reduce its cost structure for marketing activities while also optimizing the
growing income in the non-fuels sector. The Company also markets aviation fuels,
liquid petroleum gases, heating oils, transportation fuels and marine bunkers to
commercial accounts and into the bulk or spot market.

24
<PAGE> 27

Conoco uses the "Jet" brand name to market its retail products in its
wholly owned operations in Austria, Czech Republic, Denmark, Finland, Germany,
Hungary, Norway, Poland, Slovakia, Sweden and the United Kingdom. In Belgium and
Luxembourg, it markets under the "SECA" brand. Stations throughout Europe also
display the "Conoco" brand. In addition, various joint ventures in which the
Company has an equity interest market products in Spain, Switzerland and Turkey
under the "Jet," "OK Co-op" and "Tabas" or "Turkpetrol" brand names,
respectively.

As of December 31, 1998, the Company had 1,960 marketing outlets in its
wholly owned European operations, of which 1,424 were company-owned. Through its
joint venture operations in Turkey, Spain and Switzerland, the Company also has
an interest in another 963 retail sites. The largest branded site networks are
in Germany and the United Kingdom, which account for 60 percent of the total
branded units. In Germany and Austria, 21 outlets were added during 1998. In the
Nordic countries, the Company has expanded from its base of unmanned sites in
Sweden and Denmark into Norway and Finland with 11 new stations in the region.
In response to weak fuel margins in the United Kingdom over the past several
years, the Company has restructured its operations, reducing the number of
stations and focusing on locations where the Company has a competitive
advantage, which has reduced its unit breakeven cost structure.

Conoco has been expanding in targeted growth markets in Central and Eastern
Europe (Czech Republic, Poland, Hungary and Slovakia) and has added 25 stations
in the last year for a total of 126 stations at December 31, 1998. We expect to
continue this expansion in order to capture the demand growth and rising margins
expected in these inland markets. This marketing expansion allows us to obtain
further integration with products produced at the Czech refineries. Similarly,
Conoco has invested in the growing markets of Spain and Turkey, where at the end
of 1998, it had an interest through its joint ventures in 115 and 761 sites,
respectively. The joint venture marketing operation in Turkey also provides us
with a strategic position and opportunity for Upstream ventures in this region.

ASIA PACIFIC

Conoco is looking to the Asia Pacific region for much of its long-term
Downstream growth. Despite the recent economic downturn, we expect the Asian
market, in the long-term, to grow faster than comparable markets. Conoco intends
to establish at least 100,000 barrels per day of equity refining capacity in the
region long-term and expand its marketing operations to integrate with the
refining supply and capitalize on market deregulation and long-term regional
demand growth.

The refinery in Melaka, Malaysia was built by a joint venture which is 40
percent owned by Conoco (with partners Petronas, the Malaysian state oil
company, and Statoil) and has a rated crude capacity of 100,000 barrels per day
(Conoco's share of which is 40,000 barrels per day). Start-up of the Melaka
refinery was initiated in August 1998 with the commissioning of the crude unit.
Conoco's share of refinery inputs was about 2.6 million barrels for the start-up
period from August 1998 to the end of the year. This volume accounts for 7,000
barrels per day (full-year basis) of Conoco's total refinery inputs for 1998.
Initial crude unit operation was followed shortly thereafter by the start-up of
the reformer, hydrocracker and coker units. The joint venture has a five-year
tax holiday commencing with initial operation. The feedstocks for the refinery
will consist of up to approximately 70 percent high sulfur crude and 30 percent
sweet crude.

This refinery capitalizes on Conoco's proprietary coking technology to
upgrade low-cost feedstocks to higher-margin products. Initial refinery units,
in addition to the fuels delayed coker, include a crude and vacuum distillation
unit, a vacuum gas oil hydrocracker, naphtha and diesel hydrotreater, catalytic
reformer, and an isomerization unit. The refinery is a high conversion facility
that will produce a full range of refined petroleum products.

Conoco intends to use its share of refined products from the refinery to
continue growing its retail marketing operations in Thailand, Malaysia and
throughout the Asia Pacific region. The balance of the Company's share of
production will be sold primarily in the spot market. The Company has its
regional crude and product supply and disposition operations centrally located
in Singapore.

25
<PAGE> 28

We began marketing motor fuels in Thailand in 1993. Using a high volume,
low price strategy and marketing concepts and strategies that were new to
Thailand, Conoco has already established a significant presence in the Thai
retail market. At the end of 1998, Conoco had approximately 100 stores in
operation. We plan to build an additional 100 new retail outlets.

Conoco has launched a retail marketing joint venture in Malaysia with Sime
Darby Bhd., a company that has a major presence in the Malaysian business
sector. Capitalizing on the cost benefits of direct supply, the benefits of
being the first licensees since 1969 to establish retail marketing in Malaysia,
and the currently depressed prices of premium Malaysian real estate, we will
initially target major markets within 125 miles of the Melaka refinery. Conoco
plans to have six stores operating by the end of 1999.

SPECIALTY PRODUCTS

Conoco sells a variety of high value lubricants and specialty products to
commercial, industrial and wholesale accounts worldwide, including lubes (such
as automotive and industrial lubricants and waxes), petroleum coke, solvents and
pipeline flow improvers. Our experience has been that specialty products are
attractive because their premium prices generate higher margins and their
markets are generally less cyclical than commodity markets.

Conoco began marketing the HYDROCLEAR(R) brand of lubricants with the
start-up of the Excel Paralubes (a 50/50 joint venture with Pennzoil-Quaker
State) plant in 1997. The HYDROCLEAR(R) lubricants, which are non-toxic, were
designed to compete with synthetics for a range of applications with difficult
operating conditions. We also produce specialty petroleum products for global
markets through our Penreco joint venture company with Pennzoil-Quaker State.

Conoco's technical expertise in carbon upgrading positions it as a leader
in manufacturing and marketing specialty coke and coke products. Conoco
manufactures high quality graphite coke at its Lake Charles and Humber
refineries for use in the global steel industry. It also globally markets anode
and fuel coke produced at its Lake Charles, Ponca City, Billings and Humber
refineries. 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. In 1998, we granted seven licenses for this
technology to other companies. Today our technology is used by more than two
dozen coking facilities -- a third of the world's delayed coking capacity.

Conoco is a leader in the worldwide market for pipeline flow improvers. Our
"LiquidPower(R)" product is a flow improver for increasing petroleum pipeline
capacity by reducing friction loss. We also use "LiquidPower(R)" in our own
pipeline systems.

POWER

Conoco Global Power ("CGP") was founded in 1995 to leverage the economic
advantages of the Company's energy production activities and offer integrated
energy solutions to customers by capitalizing on our strengths in managing major
projects, risk and industrial operations.

CGP owns 37.5 percent of a Colombian joint venture located in
Barrancabermeja, Colombia along with Western Resources (37.5 percent) and five
Colombian companies (five percent each). The joint venture built a natural
gas-fired generation plant capable of producing 160 megawatts of power, which
became operational in August 1998. The joint venture sells primarily to the
local grid.

CGP has entered into a joint venture agreement to build a natural gas-fired
cogeneration plant near Corpus Christi, Texas. Construction has begun on the
plant, which will be located adjacent to chemical complexes owned by DuPont and
OxyChem, Occidental Petroleum Corporation's chemicals division and the Company's
partner in this joint venture. OxyChem will operate the plant under a long-term
contract and will purchase electricity and steam production from the plant. The
plant is designed to produce 440 megawatts of power and 1.1 million pounds per
hour of process steam. The plant will be a qualifying facility under the Public
Utility Regulatory Policies Act and expects to sell excess electricity in the
Texas power markets. Commercial operation of the plant is expected in the third
quarter of 1999.

26
<PAGE> 29

CGP and DuPont have signed letters of intent to develop natural gas-fired
cogeneration facilities at DuPont chemical facilities in the United States,
Spain, Luxembourg, Germany and the United Kingdom. In the United States, the
cogeneration facility will be located at DuPont's Orange, Texas chemical
complex. The proposed facility would be owned by a joint venture between Conoco
and a yet to be selected partner. The facility would provide electric and
process steam to the chemical complex, with much of the electric output being
sold as merchant power. DuPont would be the contract operator of the facility
under a long-term operating agreement. The plant is planned to produce 440
megawatts of power and 780 thousand pounds per hour of process steam.
Construction is expected to commence in mid-1999 with commercial operation
scheduled in mid-2001. In Europe, the four plants, with a total capacity of 510
megawatts, will provide needed electricity and steam for various DuPont
operations. Conoco also will sell surplus electric power to other customers,
including the local utilities. All four plants are expected to be in operation
by 2002.

CORE VALUES

Conoco is committed to four core values: operating safely, protecting the
environment, behaving ethically and valuing all people. Conoco is a recognized
industry leader in safety performance and in protecting employees' health and
the environment.

In 1998, we achieved our lowest recordable injury rate on record for both
employees and contractors. A similar performance in 1997 earned Conoco the
lowest injury rate among all major petroleum companies reporting to the American
Petroleum Institute, an achievement matched in ten out of the last 15 years.

Conoco is also an innovator both at recycling materials and at operating in
environmentally sensitive areas. In the United Kingdom, for example, the Company
recycled over 99 percent of four Viking gas platforms, which it decommissioned
in the North Sea. We have also operated in the Aransas National Wildlife Refuge
in South Texas for 60 years. In 1990, Conoco took a major step toward oil spill
prevention as the first petroleum company to voluntarily commit to build only
double-hulled tankers -- a decision made before U.S. law mandated such
technology. During 1998, Conoco began operating fleets of 100 percent
double-hulled crude oil tankers and tank barges in U.S. waters, more than a year
ahead of its target date of 2000. Also in 1998, Conoco marked the 30th
anniversary of implementing one of the industry's first environmental policies,
which predates both the World Environmental Day and Earth Day in the United
States.

In order to maintain the highest ethical standards, Conoco established
clear guidelines on business ethics which every employee agrees to follow. We
have established annual President's Awards for performance in safety,
environmental protection and valuing all people. A President's Award for ethical
behavior will be added in 1999. Valuing all people includes seeking diversity in
the workforce, nationalizing a significant portion of its workforce in each
country where it operates as soon as practicable, responding to employee ideas
and concerns, treating everyone with dignity and respect, sharing the financial
success of the Company with substantially all employees through the "Conoco
Challenge" program, and helping employees contribute fully in achieving business
goals. The Company believes that these core values result in a motivated
workforce with values and goals firmly aligned with the strategic aims of the
business. They provide guidance to employees in working to meet the expectations
of customers, partners and host governments, and in respecting the communities
in which the Company does business. In addition, we believe our commitment to
core values helps to reduce liabilities, manage risks and improve business
performance.

ENVIRONMENTAL REGULATION

As with other companies and industries, Conoco's operations are subject to
numerous federal, state, local, European Union and other foreign environmental
laws and regulations concerning its oil and gas operations, products and other
activities, including legislation that implements international conventions or
protocols. In particular, these laws and regulations require the acquisition of
permits, restrict the type, quantities, and concentration of various substances
that can be released into the environment, limit or prohibit activities on
certain lands lying within wilderness, wetlands and other protected areas,
regulate the generation, handling,

27
<PAGE> 30

storage, transportation, disposal and treatment of waste materials and impose
criminal or civil liabilities for pollution resulting from oil, natural gas and
petrochemical operations.

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

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

To meet future environmental obligations, the Company is engaged in a
continuing program to develop effective measures to protect the environment.
This program includes research into reducing sulfur levels in heavy fuel oils
and diesel fuel, reducing benzene content in gasoline, reducing vapor emissions
at service stations, developing more effective methods of preventing, containing
and recovering offshore oil spills, reducing emissions and effluents from the
Company's refineries and other facilities, developing and installing monitoring
systems at the Company's facilities and developing environmental impact
assessments before commencing major projects. For a discussion of the Company's
operating expenses and capital expenditures with respect to environmental
protection, see Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Environmental Matters. Although future
environmental obligations are not expected to have a material adverse effect on
the results of operations or financial condition of the Company, there can be no
assurance that future developments, such as increasingly stringent environment
laws or enforcement thereof, will not cause the Company to incur substantial
environmental liabilities or costs.

AIR EMISSIONS

The operations of Conoco are subject to regulations controlling emissions
of air pollutants. The primary legislation affecting the Company's U.S. air
emissions is the Federal Clean Air Act and its 1990 Amendments (the "CAA").
Among other things, the CAA requires all major sources of air emissions to
obtain operating permits. The CAA also revised the definition of "major source"
such that additional equipment involved in oil and gas production may now be
covered by the permitting requirements. Although the precise requirements of the
CAA are not yet known, the Company may incur substantial capital, operating and
maintenance costs to comply with such requirements.

The CAA requires the Environmental Protection Agency ("EPA") to promulgate
regulations imposing Maximum Achievable Control Technology ("MACT") standards to
reduce emissions of certain air pollutants from industrial facilities, such as
Conoco's refineries, transportation terminals and certain crude oil production
operations. EPA has promulgated MACT standards that are applicable to some of
Conoco's operations, and the Company's costs to comply with them have not been
material. However, MACT standards applicable to many of Conoco's other
operations have yet to be promulgated. Consequently, while it is not yet
possible to predict accurately the total expenditures that Conoco may incur to
comply with these standards, the Company anticipates that these costs could be
substantial.

In June 1997, the EPA revised the National Ambient Air Quality Standards
("NAAQS") for ozone and particulate matter, which will ultimately require more
stringent controls on stationary sources and cleaner-burning fuels in certain
parts of the United States. The financial impacts of these revisions cannot
reasonably be estimated until individual states adopt regulations to implement
the revised NAAQS, although Conoco believes that such impacts could be
substantial.

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<PAGE> 31

Under the CAA, the EPA has promulgated a number of regulatory standards
that mandate a variety of specifications for motor fuels designed to reduce
emissions of certain air pollutants from vehicles burning such fuels. These
regulated fuels include gasoline and diesel fuels produced and marketed by
Conoco. In addition, many other countries in which Conoco produces or markets
motor fuels similarly regulate the composition of such products. Conoco has
already incurred the costs of complying with such requirements that are
currently in effect. The European Parliament and European Union governments
recently agreed to enact legislation that, among other things, requires phased
reductions of sulfur and aromatics content in gasoline and diesel fuel and of
benzene in gasoline. While it is not yet possible to predict accurately the
total actual expenditures that Conoco may incur to comply with these
requirements, we anticipate that these costs may be substantial. In the U.S.,
the EPA also continues to consider further regulation of motor fuels composition
specifications. It is anticipated that the EPA will propose regulations in the
near future requiring a significantly lower level of sulfur emissions for
gasoline, but it is not yet possible to predict the precise composition
specifications that may be imposed. As a result, Conoco cannot predict
accurately the total actual expenditures that may be incurred to produce motor
fuels meeting future specifications, but such expenditures could be substantial.

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 combustion of fossil fuels, such as crude oil, results in
emissions of the type sought to be reduced by the Kyoto Protocol. The treaty
codifying the Kyoto Protocol has not been ratified by the United States, but it
may be 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.

HAZARDOUS SUBSTANCES AND WASTE DISPOSAL

The Company currently owns or leases numerous properties that have been
used for many years for hard minerals production or natural gas and crude oil
production. Although the Company has utilized operating and disposal practices
that were standard in the industry at the time, hydrocarbons or other wastes may
have been disposed of or released on or under the properties owned or leased by
the Company. In addition, some of these properties have been operated by third
parties over whom the Company had no control. The Comprehensive Environmental
Response, Compensation, and Liability Act, as Amended ("CERCLA") and comparable
state statutes impose strict, joint and several liability on owners and
operators of sites and on persons who disposed of or arranged for the disposal
of "hazardous substances" found at such sites. The Resource Conservation and
Recovery Act ("RCRA") and comparable state statutes govern the management and
disposal of wastes. Although CERCLA currently excludes petroleum operations from
cleanup liability, many state laws affecting the Company's operations impose
clean-up liability regarding petroleum related products. In addition, although
RCRA currently classifies certain exploration and production wastes as
"nonhazardous," such wastes could be reclassified as hazardous wastes thereby
making such wastes subject to more stringent handling and disposal requirements.
If such a change in legislation were to be enacted, it could have a significant
impact on the Company's operating costs, as well as the gas and oil industry in
general. See Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Environmental Matters.

OIL SPILLS

Under the U.S. Federal Oil Pollution Act of 1990, as amended ("OPA"), (i)
owners and operators of onshore facilities and pipelines, (ii) lessees or
permittees of an area in which an offshore facility is located and (iii) owners
and operators of tank vessels ("Responsible Parties") are strictly liable on a
joint and several basis for removal costs and damages that result from a
discharge of oil into the navigable waters of the United States. These damages
include, for example, natural resource damages, real and personal property
damages and economic losses. OPA limits the strict liability of Responsible
Parties for removal costs and damages that result from a discharge of oil to
$350 million in the case of onshore facilities, $75 million plus removal costs
in

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<PAGE> 32

the case of offshore facilities, and in the case of tank vessels, an amount
based on gross tonnage of the vessel. However, these limits do not apply if the
discharge was caused by gross negligence or willful misconduct, or by the
violation of an applicable Federal safety, construction or operating regulation
by the Responsible Party, its agent or subcontractor or in certain other
circumstances.

In addition, with respect to certain offshore facilities, OPA requires
evidence of financial responsibility in an amount of up to $150 million. OPA
also requires offshore facilities, certain onshore facilities and tank vessels
to prepare spill response plans, which the Company has done, for responding to a
"worst case discharge" of oil. Failure to comply with these requirements or
failure to cooperate during a spill event may subject a Responsible Party to
civil or criminal enforcement actions and penalties.

OFFSHORE PRODUCTION

Offshore oil and gas operations in U.S. waters are subject to regulations
of the United States Department of the Interior, which currently impose strict
liability upon the lessee under a Federal lease for the cost of clean-up of
pollution resulting from the lessee's operations, and such lessee could be
subject to possible liability for pollution damages. In the event of a serious
incident of pollution, the Department of the Interior may require a lessee under
Federal leases to suspend or cease operations in the affected areas.

SOURCES OF SUPPLY

During 1998, 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 49 percent of the crude oil processed in
our U.S. refineries in 1998 came from U.S. sources. The remainder of crude
processed came principally from Venezuela, Mexico and Canada. During 1998, the
Company's Humber refinery in the United Kingdom processed principally North Sea
crude oils. In the joint venture MiRO refinery, the Company processed primarily
Mediterranean crude oils in 1998. Conoco's joint venture CRC refineries in the
Czech Republic processed primarily Russian crudes.

To assure availability, Conoco maintains multiple sources for most raw
materials, supplies, services and equipment, with no one company supplying a
substantial portion of the Company's needs. The Company also routinely leases or
charters equipment, such as drilling rigs, offshore supply boats, seismic boats,
pipeline laying equipment, derrick barges and cranes. Availability of supply
and/or cost of such equipment has been a factor in the past, and could have a
detrimental impact on the Company in the future.

RESEARCH AND DEVELOPMENT

The objectives of the Company'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 $42 million in 1998, $44 million in 1997 and $41
million in 1996.

PATENTS AND TRADEMARKS

Conoco owns and is licensed 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 1998,
the Company was granted seven U.S. and 28 non-U.S. patents. The Company also has
individual trademarks and brands for its 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

The Company'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,

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<PAGE> 33

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, the Company maintains insurance against some, but not all, of such
risks and losses. Given the Company's risk profile and in accordance with the
practices of a number of major integrated, international energy companies,
Conoco does not carry business interruption insurance. The Company's decision
not to carry business interruption insurance is based on several factors,
including its spread of risk over five wholly owned refineries (with some
resultant ability to replace product during periods of business interruption), a
favorable loss history and loss prevention and safety programs. The Company has
elected to retain the risk where management believes the cost of insurance,
although available, is excessive relative to the risks presented. In addition,
pollution and environmental risks are generally not fully insurable.

PROPERTIES

The Company owns its corporate headquarters, consisting of 16 three-story
buildings on a 62-acre site in Houston, Texas. The Company owns and leases
petroleum properties and operates production processing, refining, marketing,
power-generating and research and development facilities worldwide. In addition,
the Company operates sales offices, regional purchasing offices, distribution
centers and various other specialized service locations throughout the world.

EMPLOYEES

Conoco had approximately 16,650 employees as of December 31, 1998.
Approximately 1,400 employees at the Company's U.S. refineries are represented
by the Oil, Chemical and Atomic Workers International Union under separate
bargaining agreements for each refinery. These agreements cover wages, certain
benefit matters, grievance procedures and various employment conditions, and we
believe they are typical of the refining industry in the U.S. In 1999, Conoco
will reduce staff by approximately 975 positions to improve operational
efficiencies by combining some functions in the United States and by more
broadly sharing services and more effectively deploying employees. See Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Restructuring.

ITEM 3. LEGAL PROCEEDINGS

On March 6, 1996, the Department of Justice filed a complaint in the United
States District Court for the District of Montana against Yellowstone Pipeline
Company ("YPL") and the Conoco Pipe Line Company as a 40 percent owner and
operator of YPL. The Complaint alleges discharges of oil from a YPL pipeline in
January 1993 and seeks civil penalties of up to $25,000 per day for each
violation or up to $1,000 for each barrel of oil discharged. The parties have
reached an agreement to settle the case that involves the payment of a penalty
of $165,000 and a supplemental environmental project that involves a fish ladder
in the Jocko River designed to enhance the Bull Trout population. Final
settlement documents are in the process of being executed and are expected to be
lodged with the court for the thirty day comment period by the end of March
1999.

On January 5, 1999, Conoco paid $105,000 in penalties and agreed to perform
a Supplemental Environmental Project valued at $200,000. This agreement was
reached in settlement of allegations made on June 18, 1998, by the New Mexico
Environmental Department, Air Quality Bureau, that Conoco had failed to obtain a
Clean Air Act permit and violated certain conditions in existing permits at the
Maljamar Gas Plant and the MCA field.

On August 31, 1998, Conoco received a Notice of Violation from the
Louisiana Department of Environmental Quality ("LDEQ") for failure to maintain
control equipment to control emissions from the sulfur pits at the Lake Charles
Refinery. On November 11, 1998, Conoco was notified by the LDEQ that the agency
is seeking a fine of $300,000. Conoco is contesting these allegations and the
proposed penalty and is seeking a hearing in this manner.

The Company is subject to various lawsuits and claims involving a variety
of matters including, along with other oil companies, actions challenging oil
and gas royalty and severance tax payments based on posted
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<PAGE> 34

prices, and claims for damages resulting from leaking underground storage tanks.
As a result of its separation from DuPont, Conoco has also assumed
responsibility for current and future claims related to certain discontinued
chemicals and agricultural chemicals businesses operated by Conoco in the past.
In general, the effect on future financial results is not subject to reasonable
estimation because considerable uncertainty exists. We believe the ultimate
liabilities resulting from such lawsuits and claims may be material to results
of operations in the period in which they are recognized but will not materially
affect the consolidated financial position of the Company.

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

On October 19, 1998, DuPont, as Conoco's sole stockholder, acting by
written consent, (i) approved the restatement of Conoco's certificate of
incorporation; (ii) approved the division of the Board of Directors into three
classes; (iii) approved Conoco's 1998 Stock Performance and Incentive Plan, 1998
Key Employee Stock Performance Plan, Global Stock Performance Plan, Deferred
Compensation Plan for Non-employee Directors and Directors' Charitable Gift Plan
(collectively, the "Benefit Plans"); (iv) ratified grants pursuant to the
Benefit Plans; (v) ratified the indemnification agreements between Conoco and
each of the directors; and (vi) ratified the Rights Agreement between Conoco and
First Chicago Trust Company of New York. On October 20, 1998, DuPont, as
Conoco's sole stockholder, acting by written consent, approved an amendment to
Conoco's certificate of incorporation.

EXECUTIVE OFFICERS OF THE REGISTRANT

<TABLE>
<CAPTION>
NAME AGE(1) POSITION WITH THE COMPANY
---- ------ -------------------------
<S> <C> <C>
Archie W. Dunham............... 60 President, Chief Executive Officer and Director
Gary W. Edwards................ 57 Executive Vice President, Refining, Marketing, Supply and
Transportation
Robert E. McKee III............ 52 Executive Vice President, Exploration Production
Robert W. Goldman.............. 56 Senior Vice President, Finance, and Chief Financial Officer
Rick A. Harrington............. 54 Senior Vice President, Legal, and General Counsel
</TABLE>

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

(1) As of March 12, 1999.

Set forth below is information concerning the current executive officers.

Archie W. Dunham has been President and Chief Executive Officer of the
Company since 1996 and has been a director since July 1998. He joined the
Company in 1966 and subsequently held a number of commercial and managerial
positions within the Company and DuPont. He currently serves on both companies'
boards of directors. Mr. Dunham is also a member of the boards of directors of
Louisiana-Pacific Corporation and Phelps Dodge Corporation. Mr. Dunham is a
former Executive Vice President, Exploration Production and Executive Vice
President, Refining, Marketing, Supply and Transportation for the Company. He
was also a Senior Vice President, Polymers and Senior Vice President, Chemicals
and Pigments for DuPont. He is a director of the American Petroleum Institute,
the U.S.-Russia Business Council and the Greater Houston Partnership. He is
Chairman of the United States Energy Association, Vice-Chairman of the National
Petroleum Council and a member of The Business Council. Mr. Dunham is also a
member of the Board of Visitors and the Energy Center board of directors at the
University of Oklahoma. He also serves on the board of trustees of the Memorial
Hermann Healthcare System in Houston, the Houston Grand Opera, the Houston
Symphony, the George Bush Presidential Library and the Smithsonian Institution.

Gary W. Edwards has been Executive Vice President of the Company since
1991, with responsibility for worldwide refining, marketing, supply and
transportation and was a Senior Vice President of DuPont until October 27, 1998.
He joined the Company in 1963, working at various locations throughout the
United States and in the United Kingdom, and was formerly the Company's Vice
President, Refining Marketing Europe;

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<PAGE> 35

Vice President Refining, Marketing and Transportation; and Vice President North
American Marketing. Mr. Edwards has held a number of managerial positions in
Conoco Pipeline, Transportation, Natural Gas and Gas Products, Logistics and
Marketing. He is a director of the American Petroleum Institute and a previous
director and Vice President of the European Petroleum Industry Association in
Brussels, Belgium. Mr. Edwards is a member of the Kansas State University
Engineering advisory council, and serves on the boards of the Yellowstone Park
Foundation, Theatre Under the Stars, Junior Achievement, Inc. (National) as well
as Junior Achievement of Southeast Texas, Target Hunger, Private Sector
Initiative, and the Houston Music Hall Foundation.

Robert E. McKee III has been an Executive Vice President for the Company
since 1992, with responsibility for worldwide exploration and production and was
a Senior Vice President of DuPont until October 27, 1998. He was formerly the
Company'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 (UK) Limited. Since he joined Conoco in 1967, Mr. McKee has worked at
various locations and held numerous managerial, operating, administrative and
technology positions both in the United State 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 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.

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

Rick A. Harrington has been Senior Vice President, Legal, and General
Counsel of the Company since 1998 and was Vice President and General Counsel of
the Company and Vice President and Assistant General Counsel of DuPont from 1994
until October 27, 1998. He joined DuPont in 1979 as a Senior Attorney, and
subsequently held the positions of Managing Counsel, Special Litigation, and
Vice President and General Counsel of Consolidation Coal Company. Prior to
joining DuPont, he was a partner in the firm of Arent, Fox, Kintner, Plotkin and
Kahn in Washington, D.C. where he specialized in antitrust litigation. Mr.
Harrington is a member of the bar of the District of Columbia, the District of
Columbia Court of Appeals and the Fifth Circuit Court of Appeals. He is a
director of the American Corporate Counsel Association and is a member of its
Policy Committee. He is also a member of the American Petroleum Institute
General Committee on Law and the University of Kansas School of Business Dean's
Board.

PART II

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

MARKET, STOCK AND DIVIDEND INFORMATION

The Company's Class A Common Stock is listed on the New York Stock
Exchange, Inc. (symbol: COC). The number of record holders of Class A Common
Stock was 1,702 and Class B Common Stock was one at March 5, 1999.

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<PAGE> 36

QUARTERLY CLASS A COMMON STOCK PRICES

<TABLE>
<CAPTION>
HIGH LOW
---- ---
<S> <C> <C>
1998
Fourth Quarter.............................................. 25 3/4 19 3/8
</TABLE>

The Offerings commenced on October 21, 1998. Conoco's Class A Common Stock
began trading on the New York Stock Exchange on October 22, 1998. There are no
stock prices for any quarters prior to the fourth quarter of 1998. Fourth
quarter market prices are as reported on the New York Stock Exchange, Inc.
Composite Transactions Tape.

No dividends were declared in 1998 relating to the Class A Common Stock.
The Company declared a first quarter cash dividend on January 27, 1999, of $.14
per share on each outstanding share of Class A Common Stock and Class B Common
Stock, payable March 12, 1999, to shareholders of record as of February 12,
1999. This initial dividend was determined on a pro rata basis covering the
period from October 27, 1998 to December 31, 1998, and is equivalent to $.19 per
share for a full quarter.

The determination of the amount of future cash dividends to be declared and
paid will depend upon declaration by the Company's Board of Directors and upon
the Company's financial condition, results of operations, cash flow, the level
of its capital and exploration expenditures, its future business prospects and
such other matters that the Company's Board of Directors deems relevant.

USE OF PROCEEDS

The registration statement with respect to the Offerings was declared
effective on October 21, 1998, on Form S-1 (Registration No. 333-60119) and the
Offerings commenced on October 21, 1998. The Offerings terminated with the sale
of all securities registered.

The U.S. managing underwriters for the Offerings were Morgan Stanley & Co.
Incorporated, Credit Suisse First Boston Corporation, Goldman, Sachs & Co.,
Merrill Lynch, Pierce, Fenner & Smith Incorporated, J.P. Morgan Securities Inc.,
Salomon Smith Barney Inc., BT Alex. Brown Incorporated and Schroder & Co. Inc.
The International managing underwriters were Morgan Stanley & Co. International
Limited, Credit Suisse First Boston (Europe) Limited, Goldman Sachs
International, Merrill Lynch International, J.P. Morgan Securities Ltd., Salomon
Brothers International Limited, BT Alex. Brown International, a division of
Bankers Trust International PLC and J. Henry Schroder & Co. Limited.

Conoco registered and sold 191,456,427 shares of Class A Common Stock at an
initial offering price of $23 per share for an aggregate dollar amount of $4,404
million. After deducting the underwriters' discounts and commissions of
approximately $176 million, the net proceeds received by the Company were $4,228
million. No underwriting discounts or commissions were paid to directors or
officers of Conoco or any of their associates, to persons owning ten percent or
more of any class of equity securities of Conoco, or to affiliates of Conoco.

The Company used the net proceeds of the Offerings ($4,228 million) to
repay or purchase a portion of the indebtedness owed by certain subsidiaries of
the Company to DuPont under certain intercompany notes (the "Intercompany
Notes"). The Intercompany Notes consisted of (i) a promissory note in the
principal amount of $7,500 million, due January 2, 2000, and bearing interest at
a rate of 6.0125 percent per annum, (ii) a promissory note in the principal
amount of approximately $827 million, due January 2, 2000, and bearing interest
at a rate equal to the six-month LIBOR plus 0.375 percent per annum, (iii)
several Norwegian Kroner denominated promissory notes with an aggregate
principal amount of approximately $461 million, after conversion to U.S. dollars
at September 30, 1998, having various maturity dates (ranging from October 1998
to January 2000 and having a remaining weighted average maturity of eight months
as of September 30, 1998) and bearing interest at a rate equal to the six-month
NIBOR plus 0.375 percent per annum and (iv) a promissory note (the principal
amount of which was approximately $204 million at the end of October 1998) due
on demand, and bearing an interest rate during any calendar month based on the
interest rate on DuPont's commercial paper during the preceding month (or 5.65%
in October 1998).

34
<PAGE> 37

The net proceeds of the Offerings were applied, first, to pay accrued
interest ($124 million) on the $7,500 million promissory note (described in
clause (i) of the preceding paragraph) and then to pay principal ($2,654
million) on such promissory note to the extent necessary to reduce the principal
amount to $4,846 million; second, to purchase the Kroner denominated notes ($461
million) (described in clause (iii) of the preceding paragraph) and to pay
accrued interest ($9 million) thereon; third, to repay $820 million of principal
and all accrued interest ($8 million) through October 26, 1998, on the $827
million note referred to in clause (ii) of the preceding paragraph; and fourth,
to repay, $152 million of the principal of the note referred to in clause (iv)
of the preceding paragraph. This accounts for the total use of net proceeds from
the Offerings. The $7,500 million promissory note was incurred in payment of a
dividend in July 1998. The promissory note with a principal amount of
approximately $827 million was incurred to finance the purchase by the Company
of certain loans made by DuPont to the Company. The purchased loans, as well as
the several promissory notes with an aggregate principal amount of approximately
$461 million, were incurred to finance certain capital expenditures,
acquisitions and working capital. The promissory note referred to in clause (iv)
of the preceding paragraph was incurred to finance working capital needs of the
Company.

35
<PAGE> 38

ITEM 6. SELECTED FINANCIAL DATA

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
-----------------------------------------------
1998 1997 1996 1995 1994
------- ------- ------- ------- -------
(IN MILLIONS, EXCEPT PER SHARE)
<S> <C> <C> <C> <C> <C>
STATEMENT OF INCOME DATA:
Total Revenues(1)........................................... $23,168 $26,263 $24,416 $20,518 $19,433
Cost of Goods Sold and Other Operating Expenses............. 13,840 16,226 14,560 11,146 10,640
Selling, General and Administrative Expenses(2)............. 972 726 755 728 679
Exploration Expenses(3)..................................... 380 457 404 331 357
Depreciation, Depletion and Amortization ("DD&A")........... 1,113 1,179 1,085 1,067 1,244
Taxes Other Than on Income(1)............................... 5,970 5,532 5,637 5,823 5,477
Interest and Debt Expense................................... 199 36 74 74 63
------- ------- ------- ------- -------
Income Before Income Taxes.................................. 694 2,107 1,901 1,349 973
Provision for Income Taxes.................................. 244 1,010 1,038 774 551
------- ------- ------- ------- -------
Net Income(4)............................................. $ 450 $ 1,097 $ 863 $ 575 $ 422
======= ======= ======= ======= =======
Segment After-Tax Operating Income:
Upstream:
United States............................................. $ 219 $ 445 $ 314 $ 258 $ 248
International............................................. 283 439 367 234 250
Downstream:
United States............................................. 135 216 172 112 104
International............................................. 156 91 117 121 137
Corporate and Other(4)...................................... (343) (94) (107) (150) (317)
------- ------- ------- ------- -------
$ 450 $ 1,097 $ 863 $ 575 $ 422
======= ======= ======= ======= =======
Earnings Per Share:(5)
Basic..................................................... $ .95 $ 2.51 $ 1.98 $ 1.32 $ .97
Diluted................................................... $ .95 $ 2.51 $ 1.98 $ 1.32 $ .97
Weighted Average Shares Outstanding:(5)
Basic..................................................... 474 437 437 437 437
Diluted................................................... 475 437 437 437 437
OTHER DATA:
Cash Provided by Operations................................. $ 1,373 $ 2,876 $ 2,396 $ 1,924 $ 2,143
Capital Expenditures and Investments........................ 2,516 3,114 1,944 1,837 1,665
Cash Exploration Expense.................................... 217 286 262 204 200
</TABLE>

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

(1) Includes petroleum excise taxes of $5,801, $5,349, $5,461, $5,655, and
$5,291 for 1998, 1997, 1996, 1995, and 1994, respectively.
(2) Includes a non-cash stock option provision for 1998 of $236.
(3) Includes cash exploration overhead and operating expense, DD&A, dry hole
costs and impairments of unproved properties.
(4) Includes after-tax exchange gains (losses) of $32, $21, $(7), $(40), and
$(143) for 1998, 1997, 1996, 1995 and 1994, respectively.
(5) Conoco's capital structure was established at the time of the Offerings.
Earnings per share for the periods prior to the Offerings was calculated
using only Class B Common Stock, as required by SFAS 128. See Note 8 to the
Consolidated Financial Statements in Item 8.

<TABLE>
<CAPTION>
DECEMBER 31
-----------------------------------------------
1998 1997 1996 1995 1994
------- ------- ------- ------- -------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Cash and Cash Equivalents................................... $ 394 $ 1,147 $ 846 $ 286 $ 319
Working Capital............................................. 45 567 862 999 1,790
Net Property, Plant and Equipment........................... 11,413 10,828 10,082 9,758 9,522
Total Assets................................................ 16,075 17,062 15,226 14,229 15,271
Long-Term Borrowings -- Related Parties..................... 4,596 1,450 2,287 2,141 2,279
Other Long-Term Borrowings and Capital Lease Obligations.... 93 106 101 65 342
Total Stockholders' Equity/Owner's Net Investment........... 4,438 7,896 6,579 6,754 7,274
</TABLE>

36
<PAGE> 39

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

GENERAL

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

- fluctuations in crude oil and natural gas prices

- refining and marketing margins

- failure or delays in achieving expected production from oil and gas
development projects

- uncertainties inherent in predicting oil and gas reserves and oil and gas
reservoir performance

- lack of exploration success

- disruption or interruption of our production facilities due to accidents
or political events

- international monetary conditions and exchange controls

- liability for remedial actions under environmental regulations

- disruption to our operations due to untimely or incomplete resolution of
Year 2000 issues by us or other entities

- liability resulting from litigation

- world economic and political conditions

- changes in tax and other laws applicable to our business

The discussion and analysis of the Company's financial condition and
results of operations should be read in conjunction with the Consolidated
Financial Statements of Conoco included in this report.

On October 21, 1998, Conoco sold 191,456,427 shares of Class A Common Stock
in initial public offerings (the "Offerings"). Prior to the Offerings, Conoco
and DuPont entered into a Restructuring, Transfer and Separation Agreement (the
"Separation Agreement"). Pursuant to the Separation Agreement, the operations of
Conoco and DuPont were substantially reorganized and certain entities, assets,
liabilities and related operations were transferred between the companies (the
"Separation").

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

37
<PAGE> 40

the historical operations of both entities owned by Conoco and operations
transferred to Conoco by DuPont at the time of the Offerings. In this context,
no direct ownership relationship existed among all the various units comprising
Conoco. Accordingly, DuPont and its subsidiaries' net investment in Conoco
("Owner's Net Investment") is shown in lieu of Stockholders' Equity in the
Consolidated Financial Statements.

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

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

Conoco has four reporting segments for its Upstream and Downstream
operating segments, reflecting geographic division between the United States and
International. Activities of the Upstream operating segment include exploring
for, and developing, producing and selling, crude oil, natural gas and natural
gas liquids. Activities of the Downstream operating segment include refining
crude oil and other feedstocks into petroleum products, buying and selling crude
oil and refined products and transporting, distributing and marketing petroleum
products. Corporate and Other includes general corporate expenses, financing
costs and other non-operating items, and results for electric power and
related-party 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 $2,126 million, averaging about $425 million a year, through
the disposal of marginal and non-strategic producing properties, by upgrading
and redirecting its exploration portfolio and by increasing its ownership in
large scale properties. As a result, we have maintained production essentially
constant on a BOE basis while undergoing this rationalization. Our policy is to
report material gains and losses from individual asset sales as special items
when reporting Consolidated Net Income.

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

Crude oil prices declined substantially in 1998, and we expect these
depressed prices to continue in 1999. During 1998, West Texas Intermediate crude
oil prices fell to 12-year lows as measured in absolute dollars (and 25-year
lows as measured in inflation-adjusted dollars), and closed at $12.05 per barrel
on December 31, 1998. These lower prices had a significant negative impact on
the Company's financial results in 1998 and are expected to continue to
negatively impact 1999 financial results. Conoco's profitability is determined
in large part by the difference between the prices it receives for the crude
oil, natural gas, natural gas liquids and refined products it produces and the
costs of finding, developing, producing, refining and marketing these resources.
Conoco has no control over many factors affecting prices for its products.
Prices for crude oil, natural gas and refined products may fluctuate widely in
response to changes in global and regional supply, political developments and
the ability of the Organization of Petroleum Exporting Countries ("OPEC") and
other producing nations to set and maintain production levels and prices. Prices
for crude oil, natural gas and refined products are also affected by changes in
demand for these products, which may result from global events, as well as
supply and demand in industrial markets, such as the steel and aluminum markets.
Reduced Asian demand, as a result of the recent economic downturn in Asia, has
negatively affected worldwide crude oil and product prices. Even small decreases
in crude oil and natural gas prices and refined product margins
38
<PAGE> 41

may adversely affect Conoco. Lower crude oil and natural gas prices may reduce
the amount of oil and natural gas reserves Conoco can produce economically, and
existing contracts that Conoco has entered into may become uneconomic.

Local political and economic factors in international markets may have a
material adverse effect on Conoco. There are many risks associated with
operations in international markets, including changes in foreign governmental
policies relating to crude oil, natural gas or refined product pricing and
taxation, other political, economic or diplomatic developments, changing
political conditions and international monetary fluctuations. Recent turmoil in
regions such as Russia, Southeast Asia and South America has subjected Conoco's
operations in these regions to increased risks. These risks include (i) the risk
of political and economic instability, (ii) the risk of war, (iii) the risk that
Conoco's property will be seized by a foreign government with or without
compensation, (iv) the risk of confiscatory taxation, (v) the risk that the
foreign governments will attempt to renegotiate or revoke existing contractual
arrangements, and (vi) increased risks of fluctuating currency values, hard
currency shortages and currency controls. Civil unrest and changes in government
are also potential hazards.

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

LIQUIDITY AND CAPITAL RESOURCES

CASH PROVIDED BY OPERATIONS

Cash provided by operations in 1998 decreased $1,503 million to $1,373
million versus $2,876 million in 1997. Cash provided by operations before
changes in operating assets and liabilities decreased $303 million compared to
1997, primarily due to lower net realized crude oil and natural gas prices,
partially offset by higher natural gas volumes and improved international
Downstream margins. Negative changes to net operating assets and liabilities of
$1,200 million were due to higher tax payments attributable to 1997 asset sales
and a decrease in accounts payable, offset by a decrease in accounts receivable
due to lower crude oil prices.

Cash provided by operations increased $480 million, or 20 percent, to
$2,876 million during 1997 versus $2,396 million in 1996. Positive changes to
net operating assets and liabilities of $446 million were principally due to the
$303 million received from a contract for future sales of natural gas to
Centrica, a United Kingdom gas marketing company.

INVESTMENT ACTIVITIES

CAPITAL EXPENDITURES AND INVESTMENTS

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
------------------------
1998 1997 1996
------ ------ ------
(IN MILLIONS)
<S> <C> <C> <C>
Upstream:
United States............................................. $ 788 $1,534 $ 400
International............................................. 1,177 999 864
------ ------ ------
Total Upstream.................................... $1,965 $2,533 $1,264
Downstream:
United States............................................. $ 201 $ 227 $ 218
International............................................. 332 331 462
------ ------ ------
Total Downstream.................................. $ 533 $ 558 $ 680
Corporate and Other......................................... 18 23 --
------ ------ ------
Total Capital Expenditures and Investments........ $2,516 $3,114 $1,944
====== ====== ======
</TABLE>

39
<PAGE> 42

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
------------------------
1998 1997 1996
------ ------ ------
(IN MILLIONS)
<S> <C> <C> <C>
United States............................................... $1,007 $1,761 $ 618
International............................................... 1,509 1,353 1,326
------ ------ ------
Total............................................. $2,516 $3,114 $1,944
====== ====== ======
</TABLE>

Total capital investments in 1998, including investments in affiliates and
acquisitions, were $2,516 million, a decrease of 19 percent versus 1997 capital
investments of $3,114 million, which included a $929 million acquisition of
natural gas properties and transportation assets in the Lobo trend in South
Texas (the "Lobo acquisition"). Approximately 60 percent of 1998 capital
investments were outside the United States. About 78 percent of 1998 capital
investments were spent in Upstream, with a majority of this devoted to
development projects in South Texas, deepwater Gulf of Mexico, Venezuela, the
United Kingdom and Norway. Approximately $312 million was spent on exploratory
drilling and leasing. Downstream capital investments in 1998 included completion
of the Melaka refinery, expansion of retail marketing operations, particularly
in Europe, and upgrades and maintenance of existing facilities. The Company also
spent approximately $18 million for corporate software in 1998.

Total capital investments, including investments in affiliates and
acquisitions, were $3,114 million in 1997, a 60 percent increase over 1996
capital investments of $1,944 million. This increase primarily reflects the Lobo
acquisition.

Upstream
--------

Upstream capital investments totaled $1,965 million in 1998, a decrease of
$568 million, or 22 percent, compared to $2,533 million in 1997, which included
the $929 million Lobo acquisition.

Upstream capital investments totaled $2,533 million in 1997, an increase of
$1,269 million, or 100 percent, compared to $1,264 million in 1996, primarily as
a result of the Lobo acquisition. The Lobo acquisition added significant
reserves and 1,150 miles of natural gas gathering and transportation pipeline,
providing direct access to major Texas intrastate and interstate pipelines. As a
result, the Company is the largest natural gas producer in the area and the
second largest natural gas producer in Texas.

United States

In 1998, U.S. capital investments were $788 million, a decrease of $746
million, or 49 percent, compared to 1997 U.S. capital investments of $1,534
million. Expenditures in 1998 focused on continuing operations and development.
This included the development of the Lobo field, the Ursa field in deepwater
Gulf of Mexico, the construction of two deepwater drillships, the first of which
went into service in January 1999 in the Gulf of Mexico, the acquisition of
exploratory acreage, and the expansion of onshore natural gas operations. The
Ursa field development represents a major development project in the Gulf of
Mexico. The project involved installing a new generation tension leg platform in
approximately 3,900 feet of water. First production is scheduled for 1999. The
Company has increased its deepwater holdings in the Gulf of Mexico, and
exploration within these holdings will be carried out by a deepwater drillship.

During 1997, the Company spent $1,534 million on capital projects in the
United States, an increase of $1,134 million, or 284 percent, compared to 1996
U.S. capital investments of $400 million. Besides the $929 million Lobo
acquisition and exploratory drilling, expenditures focused on development of the
partner-operated Ursa field in deepwater Gulf of Mexico, construction of two
deepwater drillships, acquisition of additional reserves and exploratory acreage
in the San Juan Basin and expansion of onshore natural gas operations. In 1996,
U.S. capital investments focused on continuing operations and development.

International

In 1998, international capital investments were $1,177 million, an increase
of $178 million, or 18 percent, compared to $999 million in 1997. The 1998
increase reflects expenditures to complete the multi-year

40
<PAGE> 43

development program in the Britannia gas field in the U.K. North Sea, with first
production in August 1998. Other significant capital investments were made for
exploratory drilling and development projects, such as the Petrozuata joint
venture in Venezuela, which also began production in August 1998, the Visund
field in the Norwegian North Sea and the Viking Phoenix project in the U.K.
North Sea. Conoco increased its natural gas holdings in the U.K. sector of the
North Sea through its acquisition of the British subsidiary of Canadian
Occidental Petroleum Ltd., which held an interest in the South Valiant, Vulcan
and Caister fields, as well as interests in the Murdoch and Esmond gas
transportation systems.

International capital investments totaled $999 million in 1997, an increase
of $135 million, or 16 percent, compared to international capital investments of
$864 million in 1996. Conoco continued to develop the Britannia gas field in the
U.K. North Sea. Other significant capital investments were made for exploratory
drilling and development projects such as the Petrozuata joint venture in
Venezuela, the Ukpokiti field offshore Nigeria, the Visund field in the
Norwegian North Sea, a methanol plant in Norway and the Boulton gas field in the
U.K. North Sea. In 1996, international capital investments were $864 million,
reflecting expenditures to develop the Britannia field and $67 million to fund
the Company's share of losses incurred by a European gas marketing joint
venture.

Downstream
----------

Downstream capital investments were $533 million in 1998, a decrease of $25
million, or four percent, versus $558 million in 1997, primarily as a result of
lower investments in equity affiliates.

Downstream capital investments totaled $558 million in 1997, a decrease of
$122 million, or 18 percent, versus $680 million in 1996, primarily reflecting
completion of the acidic crude vacuum unit at the Company's Humber refinery in
the U.K., as well as the acquisition of an equity interest in two refineries in
the Czech Republic during 1996.

United States

Investments in 1998 totaled $201 million, a decrease of $26 million, or 11
percent, versus 1997 investments of $227 million. Investments in 1998 included
costs for continued operations and optimization of retail marketing operations.
Conoco also invested $8 million for an increased ownership interest in Penreco,
a joint venture with Pennzoil-Quaker State that produces and markets highly
refined specialty petroleum products.

During 1997, Conoco spent $227 million on Downstream capital projects in
the United States, an increase of $9 million, or four percent, compared to
investments of $218 million in 1996. The majority of the 1997 funds were used to
support continuing operations and optimization of retail marketing operations.
The Company also invested funds for an initial equity interest in Penreco.

Capital investments in 1996 totaled $218 million. The most significant
investments related to the completion of the 45,000 barrel per day expansion of
the Lake Charles refinery's sour crude oil processing capability to support the
Excel Paralubes lube oil hydrocracker joint venture with Pennzoil. The lube oil
hydrocracker converts low quality, high sulphur vacuum gas oil into base oil of
extremely high purity and enhances the value of the Company's finished
lubricants business by producing improved motor oils, transmission fluids and
industrial lubes blended from hydrocracked base oils.

International

In 1998, the Company made capital investments of $332 million including
investments in the Company's retail marketing position in core markets such as
Germany and Austria, and newer retail markets such as Thailand, as well as
investments for completing the construction of the Melaka refinery, a joint
venture with Petronas and Statoil, which began operation in the third quarter of
1998.

During 1997, the Company spent $331 million on Downstream international
capital investments, a decrease of $131 million, or 28 percent, from 1996
capital investments of $462 million. The decrease was due to expenditures in
1996 relating to costs for the acidic crude vacuum unit at the Company's Humber
refinery.

41
<PAGE> 44

The installation of the vacuum unit at the Humber refinery allowed the refinery
to process acidic crude oil, including equity crude oil from the Heidrun field.
Expenditures in 1997 focused on strengthening the Company's retail marketing
position in core markets such as Germany, Austria and the Nordic countries,
expanding in targeted retail growth markets in Central and Eastern Europe,
Spain, Turkey and the Asia Pacific region, and continuing the construction of
the Melaka refinery.

Capital investments in 1996 totaled $462 million and included costs for the
acidic crude vacuum unit at the Company's Humber refinery, construction
expenditures related to the Melaka refinery, acquisition of equity interests in
two Czech refineries, and expansion of retail marketing operations, particularly
in Eastern Europe. The acquisition of the equity interests in the two Czech
refineries supported the expansion of the Company's retail marketing operations
in the emerging markets in Eastern Europe, including the Czech Republic, Poland,
Hungary and Slovakia.

Corporate and Other
-------------------

Capital investments in 1998 were $18 million and were primarily associated
with corporate software.

Capital investments in 1997 were $23 million, most of which represent the
Company's investment in electric power generation projects in international
equity affiliates. Because of deregulation within this industry, the Company
expects to continue to pursue projects which leverage the economic advantages of
the Company's energy production activities and the demand for energy in DuPont
or third party manufacturing operations.

There were no capital investments in Corporate and Other during 1996.

PROCEEDS FROM SALES OF ASSETS AND SUBSIDIARIES

Conoco's 1998 investment activities included proceeds of $721 million, a 28
percent increase over $565 million in 1997. The 1998 proceeds included $245
million from the sale of certain Upstream U.S. and North Sea properties, $156
million from the sale of various Downstream assets in the U.S., as well as $54
million from the sale of an office building in Europe. These and other proceeds
are a result of the Company's ongoing strategic portfolio upgrading and
rationalization efforts. 1997 proceeds were $565 million, an increase of $237
million versus 1996 proceeds of $328 million.

FINANCING ACTIVITIES

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

Prior to the Separation, the businesses transferred to Conoco were funded
through DuPont. Apart from limited recourse project financing related to various
joint ventures, equipment lease facilities and financing of certain refinery
equipment and other small financings, the Company has had limited indebtedness
to third parties. Since the time of the Offerings, Conoco's operations have been
funded through internally generated funds and related party debt with DuPont.

In July 1998, Conoco issued a promissory note (the "Note") to DuPont in the
aggregate principal amount of $7,500 million bearing interest at a rate of
6.0125 percent per annum. The Note has a maturity date of January 2, 2000. The
Note may be voluntarily prepaid without penalty or premium. The Note also
provides for mandatory prepayments in the event cash proceeds are realized by
Conoco from the incurrence of indebtedness or the issuance of equity securities
by Conoco or its subsidiaries. The Note includes certain covenants and customary
events of default, including failure to pay interest when due, certain events of
bankruptcy of the Company and change of control. The consent of DuPont is also
required prior to the Company entering into certain transactions.

In October 1998, Conoco raised net proceeds of $4,228 million in the
Offerings. The net proceeds from the Offerings were used to repay a portion of
the $7,500 million promissory note and certain other

42
<PAGE> 45

intercompany notes with DuPont. Total indebtedness owed to DuPont, following
application of the net proceeds of the Offerings and the determination of the
Company's cash and cash equivalents in excess of $225 million, was $4,853
million, consisting of $4,846 million related to the $7,500 million promissory
note described in the above paragraph and $7 million remaining on an $827
million promissory note, due January 2, 2000, and bearing interest at a rate
equal to the six-month LIBOR plus 0.375 percent per annum. As of December 31,
1998, total indebtedness owed to DuPont was $4,596 million.

On October 27, 1998, the Company and DuPont entered into a Revolving Credit
Agreement under which DuPont provides Conoco with a revolving credit facility in
principal amount of up to $500 million. Loans under the Revolving Credit
Agreement will be subject to mandatory prepayment to the extent the Company's
cash and cash equivalents exceed $325 million or such higher amount as the
Company and DuPont may agree. Loans under this facility will bear interest at a
rate equal to 30-day LIBOR plus 0.20 percent per annum and may be voluntarily
prepaid without penalty or premium. As of December 31, 1998, the outstanding
balance under this credit facility was zero.

Conoco is obligated to repay all outstanding debt owed to DuPont at such
time as DuPont's direct or indirect voting power in the Company falls below 50
percent of the outstanding voting power of the Company. The Company intends to
refinance outstanding related party debt owed to DuPont with a combination of
commercial paper and public debt in 1999. On February 12, 1999, Conoco filed a
"shelf" registration statement under the Securities Act of 1933 pursuant to
which it may issue debt securities. Conoco intends to use the proceeds from
issuances of securities under the shelf registration statement to refinance a
portion of the outstanding debt owed to DuPont. There can be no assurance that
the Company will be able to refinance this debt on terms as favorable as those
existing with respect to the debt owed to DuPont.

43
<PAGE> 46

RESULTS OF OPERATIONS

CONSOLIDATED RESULTS

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
---------------------------
1998 1997 1996
------- ------- -------
(IN MILLIONS)
<S> <C> <C> <C>
SALES AND OTHER OPERATING REVENUES
Upstream
United States.......................................... $ 3,200 $ 3,348 $ 2,783
International.......................................... 1,601 1,906 1,943
------- ------- -------
Total Upstream.................................... $ 4,801 $ 5,254 $ 4,726
Downstream
United States.......................................... $ 8,949 $11,394 $10,545
International.......................................... 8,297 8,639 8,880
------- ------- -------
Total Downstream.................................. $17,246 $20,033 $19,425
Corporate and Other....................................... 749 509 79
------- ------- -------
Total Sales and Other Operating Revenues.......... $22,796 $25,796 $24,230
======= ======= =======
AFTER-TAX OPERATING INCOME
Upstream
United States.......................................... $ 219 $ 445 $ 314
International.......................................... 283 439 367
------- ------- -------
Total Upstream.................................... $ 502 $ 884 $ 681
Downstream
United States.......................................... $ 135 $ 216 $ 172
International.......................................... 156 91 117
------- ------- -------
Total Downstream.................................. $ 291 $ 307 $ 289
Corporate and Other....................................... (271) (82) (74)
------- ------- -------
Total After-Tax Operating Income.................. $ 522 $ 1,109 $ 896
Interest and Other Non-Operating Expense
Net of Tax........................................ (72) (12) (33)
------- ------- -------
CONSOLIDATED NET INCOME........................... $ 450 $ 1,097 $ 863
======= ======= =======
</TABLE>

44
<PAGE> 47

SPECIAL ITEMS

Consolidated net income includes the following non-recurring items
("Special Items") on an after-tax basis:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
-----------------------
1998 1997 1996
------ ------ -----
(IN MILLIONS)
<S> <C> <C> <C>
UPSTREAM
Asset sales................................................. $ 95 $ 240 $ 16
Property impairments........................................ (38) (112) (63)
Tax rate changes............................................ -- 19 --
Employee separation costs................................... (42) -- (11)
Inventory write-downs....................................... (4) -- --
----- ----- ----
Total Upstream Special Items...................... $ 11 $ 147 $(58)
===== ===== ====
DOWNSTREAM
Asset sales................................................. $ 12 $ -- $ 19
Property impairments........................................ -- (55) --
Tax rate changes............................................ -- 11 --
Environmental insurance litigation recoveries............... -- -- 44
Employee separation costs................................... (10) -- (11)
Inventory write-downs....................................... (59) -- --
Environmental litigation charges............................ (28) (23) --
----- ----- ----
Total Downstream Special Items.................... $ (85) $ (67) $ 52
===== ===== ====
CORPORATE AND OTHER
Stock option provision...................................... $(183) $ -- $ --
Environmental litigation charges............................ (14) -- --
----- ----- ----
Total Corporate and Other Special Items........... $(197) $ -- $ --
===== ===== ====
TOTAL SPECIAL ITEMS......................................... $(271) $ 80 $ (6)
===== ===== ====
</TABLE>

Special Items in 1998 include $107 million in gains from several unrelated
asset sales. The gains consist of $54 million from the sale of producing and
non-producing international Upstream properties, $41 million from U.S. Upstream
producing properties and assets, and $12 million in Downstream from the sale of
an office building in Europe. The Upstream sales are a normal part of the
Company's portfolio rationalization program designed to improve profitability by
disposing of marginal properties and concentrating operations on core
properties. Offsetting the gains were property impairments of $38 million, of
which $32 million were in the U.S., made in accordance with Conoco's policy on
impairment of long-lived assets, inventory write-downs of $63 million to market
prices, restructuring and employee separation costs of $52 million, and other
losses of $42 million for environmental litigation charges. The $183 million
stock option provision is a one-time non-cash charge for stock option employee
compensation expenses related to the replacement of outstanding DuPont stock
options held by Conoco employees with Conoco stock options in connection with
the Offerings.

Upstream Special Items in 1997 include $240 million in gains from asset
sales consisting of $191 million associated with producing and non-producing
properties in the North Sea and $49 million in the United States. Such asset
sales are part of the Company's rationalization program, designed to improve
profitability by disposing of marginal properties and concentrating operations
on core properties. A United Kingdom tax rate change also provided a $19 million
benefit in 1997. Offsetting these benefits were property impairments of $112
million relating to certain international non-revenue producing properties.
Downstream Special Items in 1997 include a United Kingdom tax rate change
benefit of $11 million. Offsetting this benefit were property impairments of $55
million attributable to the write-down of an office building held for sale in
Europe. Other losses of $23 million include environmental litigation charges.

45
<PAGE> 48

Upstream Special Items in 1996 include a gain of $16 million from the sale
of producing and non-producing properties in the United States. Offsetting this
gain was a $63 million impairment associated with a write-down of an investment
in a European gas marketing joint venture and employee separation costs of $11
million. Downstream Special Items in 1996 include a gain of $19 million
associated with the sale of the Company's retail marketing business in Ireland.
Environmental insurance litigation recoveries also resulted in a $44 million
benefit. Offsetting these benefits were employee separation costs of $11
million.

Consolidated Net Income Before Special Items ("Earnings Before Special
Items") was $721 million in 1998, $1,017 million in 1997 and $869 million in
1996.

1998 Versus 1997

Consolidated Net Income for 1998 of $450 million was down 59 percent from
$1,097 million in 1997. The Company had Earnings Before Special Items of $721
million in 1998, down 29 percent from $1,017 million in 1997. Lower Earnings
Before Special Items primarily reflect lower net realizable crude oil and
natural gas prices and refined product prices. The lower prices were partly
offset by higher natural gas volumes, lower exploration expenses, improved
international Downstream marketing margins and the favorable resolution of
certain tax issues.

Sales and Other Operating Revenues of $22,796 million in 1998 were down 12
percent compared to $25,796 million in 1997, primarily due to a decrease in
worldwide crude oil and natural gas prices and lower refined product prices.
Downstream Sales and Other Operating Revenues were $17,246 million, down 14
percent compared to $20,033 million in 1997. Crude oil and refined product
buy/sell and natural gas and electric power resale activities in 1998 totaled
$5,004 million, down 9 percent compared to $5,509 million in 1997.

Cost of Goods Sold and Other Operating Expenses in 1998 totaled $13,840
million, down 15 percent compared to $16,226 million in 1997. This reduction is
primarily due to lower feedstock prices.

Selling, General and Administrative Expenses for 1998 totaled $736 million,
an increase of $10 million, or one percent, compared to $726 million in 1997,
primarily due to environmental litigation charges related to a discontinued
business assumed by Conoco under the Separation Agreement with DuPont.

Included in 1998 is a pretax charge of $236 million, labeled "Stock Option
Provision" on the Income Statement. This expense is a one-time non-cash charge
for employee stock option compensation relating to the replacement of
outstanding DuPont stock options held by Conoco employees with Conoco stock
options in connection with the Offerings.

Exploration Expenses in 1998 totaled $380 million, a decline of $77
million, or 17 percent, compared to $457 million in 1997. The decrease is
primarily a result of a more focused exploration program. Also contributing to
the decrease were lower amortization of non-producing leasehold properties in
the United States and lower exploration overhead and operating expenses compared
to 1997, which included seismic surveys conducted in the Gulf of Paria, located
between Venezuela and Trinidad, and in the Merida Andes foothills in Venezuela.

Depreciation, Depletion and Amortization for 1998 totaled $1,113 million, a
decrease of $66 million, or six percent, compared to $1,179 million in 1997.

Provision for Income Taxes for 1998 totaled $244 million, down 76 percent,
compared to $1,010 million for 1997. This reflects an effective tax rate of
approximately 35 percent in 1998 compared to 48 percent in 1997. The lower
effective tax rate in 1998 is due to the increased impact of the U.S.
alternative fuels tax credit, realization of a tax benefit on the sale of a
subsidiary and a greater percentage of earnings in countries with lower
effective tax rates.

1997 versus 1996

Consolidated Net Income for 1997 of $1,097 million was up 27 percent from
$863 million in the prior year. The Company had Earnings Before Special Items of
$1,017 million in 1997, up 17 percent from
46
<PAGE> 49

$869 million in 1996. The increase was attributable to improved U.S. natural gas
prices and higher international natural gas volumes in addition to stronger
worldwide Downstream product margins and increased worldwide refinery
production.

Sales and Other Operating Revenues of $25,796 million in 1997 were up six
percent compared to $24,230 million in the prior year, as higher Downstream
product prices and volumes, increased international natural gas volumes and
stronger domestic natural gas prices more than compensated for lower crude oil
prices. Crude oil and refined product buy/sell and natural gas and electric
power resale activities in 1997 totaled $5,509 million, up 32 percent compared
to $4,167 million in 1996.

Cost of Goods Sold and Other Operating Expenses in 1997 totaled $16,226
million, up 11 percent compared to $14,560 million in 1996, due to higher
refined product volumes and crude oil and refined product buy/sell contract
activity and natural gas and electric power resale activities.

Selling, General and Administrative Expenses in 1997 totaled $726 million,
a decrease of $29 million, or four percent, compared to $755 million in 1996,
primarily due to one-time costs in 1996 for retail expansion activities in the
U.S.

Exploration Expenses in 1997 totaled $457 million, an increase of $53
million, or 13 percent, compared to $404 million in 1996, due to higher
international exploration overhead and operating costs primarily from seismic
surveys conducted in the Gulf of Paria, located between Venezuela and Trinidad,
and in the Merida Andes foothills in Venezuela, higher international dry hole
costs and an adjustment of certain non-producing U.S. leasehold properties.

Depreciation, Depletion and Amortization in 1997 totaled $1,179 million, an
increase of $94 million, or nine percent, compared to $1,085 million in 1996 due
to higher depreciation resulting from a write-down of an office building held
for sale in the United Kingdom and an impairment of certain international
non-revenue producing properties, partially offset by lower depreciation in U.S.
Downstream operations.

Provision for Income Taxes totaled $1,010 million in 1997, down three
percent, compared to $1,038 million in 1996. The lower provision reflects an
effective tax rate of approximately 48 percent in 1997 compared to 55 percent in
1996. The decrease in the effective tax rate was primarily due to a lower
proportion of earnings from operations in countries with higher effective tax
rates.

UPSTREAM SEGMENT RESULTS

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
----------------------
1998 1997 1996
----- ------ -----
(IN MILLIONS)
<S> <C> <C> <C>
After-Tax Operating Income
United States............................................. $219 $ 445 $314
International............................................. 283 439 367
---- ----- ----
After-Tax Operating Income............................. $502 $ 884 $681
Special Items
United States............................................. $ 14 $ (49) $ (9)
International............................................. (25) (98) 67
---- ----- ----
Special Items.......................................... $(11) $(147) $ 58
Earnings Before Special Items
United States............................................. $233 $ 396 $305
International............................................. 258 341 434
---- ----- ----
Earnings Before Special Items.......................... $491 $ 737 $739
==== ===== ====
</TABLE>

47
<PAGE> 50

1998 versus 1997

Upstream After-Tax Operating Income was $502 million in 1998, down 43
percent from $884 million in 1997, principally due to lower crude oil and
natural gas prices. Upstream Earnings Before Special Items were $491 million in
1998, down 33 percent from $737 million in 1997.

The Company's worldwide net realized crude oil price was $12.37 per barrel
for 1998, down $6.21 per barrel, or 33 percent, from $18.58 per barrel in 1997.
Excess supply caused by weak Asian demand, higher crude oil production from OPEC
producing countries and warmer winter weather caused the sharp drop in crude oil
prices. Worldwide natural gas prices averaged $2.24 per thousand cubic feet
(mcf) for 1998, compared with $2.44 per mcf in 1997, primarily because of warmer
winter weather. Lower worldwide natural gas prices were primarily driven by
lower natural gas prices inside the United States. In the U.S., natural gas
prices averaged $1.96 per mcf, down 10 percent, while internationally they
remained steady at $2.72 per mcf. Worldwide crude oil and condensate production
in 1998 was 315,000 barrels per day versus 337,000 barrels per day in 1997.
Worldwide natural gas production in 1998 was up 17 percent to 1,411 million
cubic feet per day from 1,203 million cubic feet per day in 1997.

U.S. Upstream Earnings Before Special Items totaled $233 million in 1998,
down 41 percent from $396 million in 1997. Lower U.S. Upstream Earnings Before
Special Items were due to lower crude oil and natural gas prices and lower crude
oil volumes resulting from asset dispositions and crude oil production declines.
These reductions more than offset benefits from increased natural gas
production, gains on property sales and lower exploration expenses. Natural gas
volumes were up 22 percent as increased production from the holdings in the
South Texas Lobo trend, acquired in 1997, more than offset the decline in
natural gas production elsewhere. U.S. production costs were $3.69 per BOE, down
$0.54 per BOE, or 13 percent, compared to $4.23 per BOE in 1997, due to lower
production taxes and higher gas volumes.

Outside the United States, Upstream Earnings Before Special Items were $258
million, down 24 percent, from $341 million in the comparable period in 1997,
primarily due to lower crude oil and natural gas prices, offset by higher
natural gas volumes, lower exploration expenses and the favorable resolution of
certain tax issues. International crude volumes, which comprise over 80 percent
of Conoco's oil production, were down five percent to 265,000 barrels per day
due to the sale of the Company's interest in the mature Ula and Gyda fields in
Norway and natural production declines. However, earnings benefited from higher
production in countries with relatively lower tax rates (primarily the United
Kingdom and Nigeria). International gas volume was up nine percent.
International production costs were $4.13 per BOE, down $0.06 per BOE, or one
percent, compared to $4.19 per BOE in 1997, due to reduced costs from asset
dispositions and other operating costs in 1998, partly offset by lower
international crude oil production.

1997 versus 1996

Upstream After-Tax Operating Income was $884 million in 1997, up 30
percent, compared to $681 million in 1996. Upstream Earnings Before Special
Items totaled $737 million in 1997, essentially unchanged from the previous
year.

Worldwide natural gas prices were up 15 percent to $2.44 per mcf in 1997
from $2.12 per mcf in 1996, resulting primarily from higher U.S. industry
demand. Worldwide net realized crude oil prices were $18.58 per barrel, down
$1.53 per barrel, or eight percent, from $20.11 per barrel in 1996. Crude oil
prices declined despite higher crude oil demand and strong crude oil production
growth, which included initial exports of Iraqi crude oil. Worldwide crude oil
and condensate production averaged 337,000 barrels per day for the year, up
slightly versus 1996. Worldwide natural gas deliveries in 1997 of 1,203 million
cubic feet per day were essentially unchanged from 1,211 million cubic feet per
day in 1996 as higher international natural gas volumes were offset by lower
domestic natural gas volumes.

U.S. Upstream Earnings Before Special Items totaled $396 million, up 30
percent from $305 million in 1996, due to higher gas prices which more than
offset lower crude oil prices. U.S. production costs per BOE were $4.23, up
$0.12 per BOE or 3 percent, compared to $4.11 per BOE in 1996, due to higher
production taxes.

48
<PAGE> 51

Outside the United States, Earnings Before Special Items were $341 million,
down 21 percent from $434 million in 1996 due to lower crude oil prices, partly
offset by increased crude oil and natural gas volumes associated with the first
year of oil production from Nigeria and increased production from the Heidrun
and Troll fields in Norway and the Canadian Foothills. International production
costs per BOE were $4.19 per BOE, up $0.51 per BOE, or 14 percent, compared to
$3.68 per BOE in 1996, resulting from floating production storage offtake
("FPSO") lease costs on new fields in the United Kingdom and costs incurred on
development projects that had not yet begun production.

DOWNSTREAM SEGMENT RESULTS

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
------------------------
1998 1997 1996
------ ------ ------
(IN MILLIONS)
<S> <C> <C> <C>
After-Tax Operating Income
United States............................................. $135 $216 $172
International............................................. 156 91 117
---- ---- ----
After-Tax Operating Income............................. $291 $307 $289
Special Items
United States............................................. $ 73 $ 23 $(36)
International............................................. 12 44 (16)
---- ---- ----
Special Items.......................................... $ 85 $ 67 $(52)
Earnings Before Special Items
United States............................................. $208 $239 $136
International............................................. 168 135 101
---- ---- ----
Earnings Before Special Items.......................... $376 $374 $237
==== ==== ====
</TABLE>

1998 versus 1997

Downstream After-Tax Operating Income was $291 million in 1998, down five
percent compared to $307 million in 1997. Downstream Earnings Before Special
Items totaled $376 million in 1998, up one percent from $374 million in 1997.

United States Downstream Earnings Before Special Items were $208 million in
1998, compared to $239 million in 1997, a decrease of 13 percent. The decline
was mainly attributable to weaker refinery margins, which were partly offset by
record refinery runs, lower feedstock and operating costs and higher marketing
margins.

International Downstream Earnings Before Special Items were $168 million in
1998, up 24 percent from $135 million in the comparable period in 1997,
reflecting higher European marketing margins, lower costs, and 11 percent higher
refinery runs.

The Company's refineries, excluding the Melaka refinery, operated at 95
percent capacity in 1998, four percent higher than 1997. The increase was
primarily due to refinery upgrades in Europe in 1997, increased reliability
throughout the system, and increased rates at the Lake Charles refinery
subsequent to debottlenecking work completed in February 1998.

1997 versus 1996

Downstream After-Tax Operating Income was $307 million, up six percent from
$289 million in 1996. Downstream Earnings Before Special Items increased 58
percent to $374 million in 1997, compared with $237 million in the prior year.
Worldwide refined product sales volumes were 1,048,000 barrels per day in 1997,
up five percent versus 1996.

In the United States, Downstream Earnings Before Special Items were $239
million versus $136 million in 1996, an increase of 76 percent. The improvement
was attributable to strong refining margins, reduced

49
<PAGE> 52

operating costs and higher refined product volumes from the new Lake Charles,
Louisiana, hydrocracker expansion project.

International Downstream Earnings Before Special Items were $135 million,
up 34 percent from $101 million in the comparable period in 1996, primarily due
to higher European refining margins and increased refinery production from the
Humber refinery's new vacuum unit in the United Kingdom.

The Company's refineries operated at 91 percent capacity in 1997, ten
percent higher than 1996. The increase was primarily due to less downtime
incurred in 1997, compared to 1996 when major expansions were taking place at
the Lake Charles and Humber refineries.

CORPORATE AND OTHER SEGMENT RESULTS

CORPORATE AND OTHER OPERATING

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
----------------------
1998 1997 1996
------ ----- -----
(IN MILLIONS)
<S> <C> <C> <C>
After-Tax Operating Income.................................. $(271) $(82) $(74)
Special Items............................................... 197 -- --
----- ---- ----
Earnings Before Special Items............................... $ (74) $(82) $(74)
===== ==== ====
</TABLE>

1998 versus 1997

Corporate and Other Segment After-Tax Operating Income was a loss of $271
million in 1998, an impairment of $189 million from a loss of $82 million in
1997, primarily as a result of the one-time stock option provision. Corporate
and Other Earnings Before Special Items were a loss of $74 million, an
improvement of $8 million from the 1997 loss of $82 million as a result of lower
compensation costs.

1997 versus 1996

Corporate and Other Segment After-Tax Operating Income was a loss of $82
million, an impairment of $8 million from a loss of $74 million in 1996 due to
higher compensation costs.

INTEREST AND OTHER CORPORATE NON-OPERATING EXPENSES NET OF TAX

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
------------------------
1998 1997 1996
------ ------ ------
(IN MILLIONS)
<S> <C> <C> <C>
Net Interest Income (Expense)............................... $(62) $ 35 $ 28
Exchange Gains (Losses)..................................... 32 21 (7)
Other Corporate Expenses(1)................................. (42) (68) (54)
---- ---- ----
Total............................................. $(72) $(12) $(33)
==== ==== ====
</TABLE>

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

(1) Includes financing costs and other non-operating items.

1998 versus 1997

Interest and Other Corporate Non-Operating Expenses for 1998 were $72
million, an increase of $60 million versus $12 million in 1997. The increase is
primarily attributable to higher interest expense from debt incurred in the
second half of the year, which more than offset interest income earned in the
first half of the year.

1997 versus 1996

Interest and Other Corporate Non-Operating Expenses were a loss of $12
million in 1997, an improvement of $21 million from 1996 results. Net Interest
Income (Expense) in 1997 was improved by
50
<PAGE> 53

$7 million versus 1996, primarily due to increased after-tax capitalized
interest on major Upstream development projects. The Company incurred an
after-tax exchange gain of $21 million in 1997 compared with a loss of $7
million in 1996, primarily reflecting the impact of Norwegian Kroner and British
Pound exchange rate movements on U.S. dollar-denominated working capital
balances. Other Corporate Expenses of $68 million in 1997 were $14 million
higher than 1996.

ENVIRONMENTAL EXPENDITURES

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

Estimated pre-tax environmental expenses charged to current operations
totaled about $131 million in 1998, as compared to approximately $136 million in
1997 and $162 million in 1996. These expenses include the remediation accruals
discussed below, operating maintenance and depreciation costs for solid waste,
air and water pollution control facilities and the costs of certain other
environmental activities. The largest of these expenses resulted from the
operation of wastewater treatment facilities and solid waste management
facilities and facilities for the control and abatement of air emissions.
Approximately 80 percent of 1998 total annual environmental expenses resulted
from the operations of the Company's business in the United States.

Capital expenditures for environmental control facilities totaled
approximately $53 million in 1998, as compared to approximately $50 million in
1997 and $78 million in 1996. The Company estimates that capital expenditures
will increase by about $100 million in 1999 due to regulations in Europe
requiring cleaner burning fuels.

REMEDIATION EXPENDITURES

The Resource Conservation and Recovery Act ("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,
the Company may be required to remediate contamination caused by prior
operations. In contrast to the Comprehensive Environmental Response,
Compensation, and Liability Act, as amended ("CERCLA"), often referred to as
"Superfund," the cost of corrective action activities under the RCRA corrective
action program is typically borne solely by the Company. The Company anticipates
that significant ongoing expenditures for RCRA remediation activities may be
required over the next decade although annual expenditures for the near term are
not expected to vary significantly from the range of such expenditures over the
past few years. The Company's expenditures associated with RCRA and similar
remediation activities conducted voluntarily or pursuant to state law were
approximately $27 million in 1998, $31 million in 1997 and $34 million in 1996.
In the long term, expenditures are subject to considerable uncertainty and may
fluctuate significantly.

The Company from time to time receives requests for information or notices
of potential liability from EPA and state environmental agencies alleging that
the Company is a potentially responsible party ("PRP") under CERCLA or an
equivalent state statute. The Company on occasion 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 Company owned but allegedly contain
wastes attributable to the Company's past operations. As of December 31, 1998,
the Company had been notified of potential liability under CERCLA or state law
at about 13 sites around the United States, with active remediation under way at
six of those sites. The Company received notice of potential liability at one
new site during 1998, which was resolved, compared with four similar notices in
1997 and one in 1996. The

51
<PAGE> 54

Company's expenditures associated with CERCLA and similar state remediation
activities were not significant in 1998, 1997 or 1996.

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

Cash expenditures not charged against income for previously accrued
remediation activities under CERCLA, RCRA and similar state and foreign laws
were $17 million in 1998, $19 million in 1997 and $19 million in 1996. Although
future remediation expenditures in excess of current reserves are possible, the
effect of any such excess on future financial results is not subject to
reasonable estimation because of the considerable uncertainty regarding the cost
and timing of expenditures.

REMEDIATION ACCRUALS

The Company 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 the Company's insurers or
other third parties and are not discounted. Many of these liabilities result
from CERCLA, RCRA and similar state laws that require the Company to undertake
certain investigative and remedial activities at sites where the Company
conducts or once conducted operations or at sites where company-generated waste
was disposed. The accrual also includes a number of sites identified by the
Company that may require environmental remediation, but which are not currently
the subject of CERCLA, RCRA or state enforcement activities. Over the next
decade, the Company 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, 1998.

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, 1998, the Company's balance sheet included an accrued liability of
$129 million as compared to $144 million at year-end 1997. Approximately 89
percent of the Company's environmental reserve at December 31, 1998, was
attributable to RCRA and similar remediation liabilities (excluding voluntary
remediations) and 11 percent to CERCLA liabilities. During 1998, remediation
accruals resulted in a $2 million charge, compared to credits of $41 million and
$70 million in 1997 and 1996, respectively, which resulted from insurance
recoveries. No significant additional recoveries are expected.

TAX MATTERS

As a result of the Separation and the Offerings, the Company will no longer
be able to combine the results of its operations with those of DuPont in
reporting income for U.S. federal income tax purposes and for state and non-U.S.
income tax purposes in certain states and countries. The Company believes this
will not have a material adverse effect on its earnings.

As of December 31, 1998, the Company had deferred tax assets in the amount
of $1,238 million. Of this amount, $496 million related to tax benefits from
operating losses incurred in start-up operations, including exploration and U.S.
foreign tax credit carry forwards. These benefits were substantially offset by a
valuation reserve. The Company believes it is more likely than not the balance
of the deferred tax assets will be realized in future years.

52
<PAGE> 55

YEAR 2000

Historically, certain computerized systems have used two digits rather than
four digits to define the applicable year, which could result in recognizing a
date using "00" as the year 1900 rather than the year 2000. This could result in
major failures or miscalculations and is generally referred to as the "Year 2000
issue."

The Company recognizes that the impact of the Year 2000 issue extends
beyond traditional computer hardware and software to automated plant systems and
instrumentation, as well as to third parties. The Year 2000 issue is being
addressed within the Company by its individual business units, and progress is
reported periodically to management and the Board of Directors.

The Company has committed resources to conduct risk assessments and to take
corrective action, where required, within each of the following areas:
information technology, plant systems and external parties. Information
technology includes telecommunications as well as traditional computer software
and hardware in the mainframe, midrange and desktop environments. Plant systems
include all automation and embedded chips used in plant operations. External
parties include any third party with whom the Company interacts. Most of the
resources committed to this work are internal.

Managing Year 2000 risk is being handled in three tiers -- through Year
2000 Compliance Plans, Mitigation Plans and Emergency Recovery Plans. The Year
2000 Compliance Plans include inventorying and assessing risk, and outlining
action to be taken for each of these items. Year 2000 Compliance Plans have been
developed and are being implemented for all business units. Mitigation Plans
outline a list of actions that will be taken on a specified date to further
minimize risk. These plans will be developed for areas in which the Year 2000
Compliance Plans do not adequately address all of the relevant risk issues. For
example, operations that rely heavily on external partners will develop
Mitigation Plans. Mitigation Plans will be developed, as needed, for all
business units by the third quarter of 1999. Emergency Recovery Plans already
exist in many of the Company's operations to address other issues such as oil
tanker spills and plant explosions.

Typically, the Emergency Recovery Plans address the results of single
events. These plans are designed to facilitate the resumption of normal
operations following a disruption. In contrast to a "normal" disruption, the
scope of Year 2000 issues may cause multiple concurrent events, which may have a
longer duration. Accordingly, the Emergency Recovery Plans will be reviewed and
supplemented to address Year 2000 risks for all business units by the third
quarter of 1999. The progress reported below covers only the replacement or
upgrade of existing non-compliant systems. Replacement projects planned and
managed outside of the Year 2000 Program have been excluded. Approximately 73
percent of the work required to fix Year 2000 issues identified by the Year 2000
Program has been completed.

In the information technology area, inventory and assessment audits in the
mainframe and midrange environments are completed. Excluding business
applications, corrective action in the mainframe area will be completed by the
end of the first quarter of 1999. Corrective action in the midrange area will be
completed by the end of the first quarter of 1999 and business application
software is expected to be completed by the fourth quarter of 1999. Inventory
and assessment audits of telecommunications are completed, with corrective
action expected to be completed by the second quarter of 1999. Finally,
inventory and assessment audits in the desktop environment are completed, with
corrective action expected to be completed by the end of the third quarter of
1999.

In the plant systems area, all but two of the Company's business units have
completed their inventory and assessment audits; the remaining units are
expected to complete this work by the end of the second quarter of 1999. The
Company is relying on vendor testing and certification with validation through
limited internal testing and/or industry test results. Downtime for normally
scheduled plant maintenance will be used to conduct testing, with corrective
action expected to be completed by the end of the third quarter of 1999.

With respect to external parties, the inventory of critical external
parties is essentially complete. Risks are being assessed, and monitoring of
risk in this area will continue throughout 1999, as many external parties will
not have completed their work.

53
<PAGE> 56

The total cost of Year 2000 activities is not expected to be material to
the Company's operations, liquidity or capital resources. Costs are being
managed within each business unit. The total estimated cost for the Company's
Year 2000 work is $47 million. 1997 costs were $5 million, and 1998 costs were
$25 million. This includes costs for the replacement or upgrade of existing
non-compliant systems. Replacement projects planned and managed outside of the
Year 2000 program have been excluded.

There can be no guarantee that third parties of business importance to
Conoco will successfully reprogram or replace, and test, all of their own
computer hardware, software and process control systems to ensure such systems
are Year 2000 compliant. Failure to address a Year 2000 issue could result in
business disruption that could materially affect the Company's operations,
liquidity or capital resources. There is still uncertainty around the scope of
the Year 2000 issue. At this time the Company cannot quantify the potential
impact of these failures. The Company's Year 2000 program and contingency plans
are being developed to address issues within the Company's control. The program
minimizes, but does not eliminate, the issues of external parties.

EUROPEAN MONETARY UNION

Within Europe, the European Economic and Monetary Union (the "EMU")
introduced a new currency, the Euro, on January 1, 1999. The new currency is 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.

On January 1, 1999, 11 participating countries adopted the Euro as their
local currency, initially available for currency trading on currency exchanges
and non-cash (banking) transactions. The existing local currencies, or legacy
currencies, will remain legal tender through January 1, 2002. Beginning on
January 1, 2002, Euro-denominated notes and coins will be issued for cash
transactions. For a period of six months from this date, both legacy currencies
and the Euro will be legal tender. On or before July 1, 2002, the participating
countries will withdraw all legacy currency and use the Euro exclusively.

The Company has recognized the introduction of the Euro as a significant
event with potential implications for existing operations. Conoco currently
operates in a number of countries which are participating in the EMU, including
Austria, Belgium, Finland, Germany and Spain. The Company expects non-
participating European Union countries, such as the United Kingdom, to
eventually join the EMU.

The Company has committed resources to conduct risk assessments and to take
corrective actions, where required, to ensure the Company is prepared for the
introduction of the Euro. The Company has undertaken a review of the Euro
implementation and has concentrated on areas such as operations, finance,
treasury, legal, information management, procurement and others, both in
participating and non-participating European Union countries where the Company
operates. Also, existing legacy accounting and business systems and other
business assets have been reviewed for Euro compliance, including assessing any
risks from third parties. Progress regarding Euro implementation is reported
periodically to management.

Because of the staggered introduction of the Euro regarding non-cash and
cash transactions, the Company has developed its plans to address first its
accounting and business systems and second, its business assets. The Company
undertook steps to be Euro compliant within its accounting and business systems
by the end of 1998 relative to the conversion rules when performing translations
between EMU currencies. The Company has an implementation plan to convert its
accounting and reporting systems from legacy currency to the Euro by January 1,
2002, for those operations that are in EMU countries. The plan also incorporates
steps to ensure the corresponding business assets are fully compliant by that
date, in preparation for being able to conduct business involving Euro notes and
coins. Compliance in participating and nonparticipating countries will be
achieved primarily through upgraded systems, which were previously planned to be
upgraded. Remaining systems will be modified to achieve compliance. The Company
does not currently expect to experience any significant operational disruptions
or to incur any significant costs, including any currency risk, which could
materially affect the Company's liquidity or capital resources. The Company is
preparing plans to address issues within the transitional period when both
legacy and Euro currencies may be tendered.

54
<PAGE> 57

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

RESTRUCTURING

In December 1998, Conoco announced that as a result of a comprehensive
review of assets and long-term strategy the Company was making organizational
realignments consistent with furthering the efficiency of operations and taking
advantage of synergies created by the upgrading of its asset portfolio. The
announced plans will be implemented in 1999 and result in a reduction of
approximately 775 Upstream positions and 200 Downstream positions worldwide.
About three quarters of the Upstream positions and about half of the Downstream
positions affected will be in the United States. These reductions largely
reflect the elimination of redundancies at all levels resulting from past and
ongoing consolidation of assets into operations requiring less employee support,
as well as better sharing of common services and functions across regions.
Implementation of the plans is being expedited in response to low oil prices and
operating margins that lingered through the end of 1998 and are expected to
continue in 1999. Associated with these announcements, the Company recorded a
charge of $82 million pretax ($52 million after-tax), nearly all of which
represents termination payments and related employee benefits to be made to
persons affected. Payments will be made under existing company severance
policies, generally based on years of service up to a maximum varying by
country. On an after-tax basis, the charge is reflected as $19 million and $23
million in Upstream United States and International results, respectively, and
$5 million each in Downstream United States and International results. The
accrual is reflected in fourth quarter Cost of Goods Sold and Other Operating
Expenses. As of December 31, 1998, none of the persons had yet been terminated
and no related payments had been made.

NEW ACCOUNTING STANDARDS

The Company adopted Statement No. 131 for the year ended December 31, 1998,
and has disclosed segment information on the same basis used internally for
evaluating segment performance and deciding how to allocate resources to
segments. The Company has assessed the effect of the new disclosure, and
adoption of Statement No. 131 had no financial impact on the Company.

In February 1998, the Financial Accounting Standards Board issued Statement
No. 132, "Employers' Disclosure About Pension and Other Postretirement
Benefits," which revised disclosure requirements for pension and other
postretirement benefits. It does not affect the measurement of the expense of
the Company's pension and other postretirement benefits. The Company adopted
this Statement for the year ended December 31, 1998.

In June 1998, the Financial Accounting Standards Board issued Statement No.
133, "Accounting for Derivative Instruments and Hedging Activities," which
requires that companies recognize all derivatives as either assets or
liabilities in the balance sheet and measure those instruments at fair value.
The Company is required to adopt this Statement by the first quarter of 2000 and
is currently assessing the effect of the new standard.

Statement No. 133 provides, if certain conditions are met, that a
derivative may be specifically designated as (1) a hedge of the exposure to
changes in the fair value of a recognized asset or liability or an unrecognized
firm commitment (fair value hedge), (2) a hedge of the exposure to variable cash
flows of a forecasted transaction (cash flow hedge) or (3) a hedge of the
foreign currency exposure of a net investment in a foreign operation, an
unrecognized firm commitment, an available-for-sale security or a
foreign-currency-denominated forecasted transaction (foreign currency hedge).

Under Statement No. 133, the accounting for changes in fair value of a
derivative depends on its intended use and designation. For a fair value hedge,
the gain or loss is recognized in earnings in the period of change together with
the offsetting loss or gain on the hedged item. For a cash flow hedge, the
effective portion of the derivative's gain or loss is initially reported as a
component of other comprehensive income and subsequently reclassified into
earnings when the forecasted transaction affects earnings. For a foreign
currency hedge, the gain or loss is reported in other comprehensive income as
part of the cumulative translation adjustment. For all
55
<PAGE> 58

other items not designated as hedging instruments, the gain or loss is
recognized in earnings in the period of change.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

MARKET RISKS

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

The Company has established a Financial Risk Management Policy Framework
that provides guidelines for entering into contractual arrangements
(derivatives) to manage the Company's commodity price, foreign currency rate,
and interest rate risks. The Conoco Risk Management Committee has ongoing
responsibility for the content of this policy and has principal oversight
responsibility to ensure the Company is in compliance with the policy and 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, the Company's
internal audit group conducts reviews of these risk management activities to
assess the adequacy of internal controls. The audit results are reviewed by 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 the Company is exposed to credit loss in the event of
nonperformance by these counterparties, this exposure is managed through credit
approvals, limits and monitoring procedures, and limits to the period over which
unpaid balances are allowed to accumulate. The Company has not experienced
nonperformance by counterparties to these contracts, and no material loss would
be expected from any such nonperformance.

Commodity Price Risk

The Company enters into energy-related futures, forwards, swaps and options
in various markets to balance its physical systems, to meet customer needs and
to manage its price exposure on anticipated crude oil, natural gas, refined
product and electric power transactions. These instruments provide a natural
extension of the underlying cash market and are used to physically acquire a
portion of supply requirements as well as to manage pricing of near term
physical requirements. The commodity futures market has underlying principles of
increased liquidity and longer trading periods than the cash market and is one
method of managing price risk in the energy business.

Conoco policy is to generally 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 the Company's equity
crude oil and natural gas production as well as refinery margins.

56
<PAGE> 59

Under the Company's policy, hedging includes only those transactions that
offset physical positions and reduce overall company exposure to price risk.
Trading is defined as any transaction that does not meet the definition of
hedging. After-tax gain/loss from risk trading has not been material.

The fair value gain (loss) of outstanding derivative commodity instruments
and the change in fair value that would be expected from a ten percent adverse
price change are shown in the table below:

<TABLE>
<CAPTION>
CHANGE IN FAIR VALUE
FROM 10% ADVERSE
FAIR VALUE PRICE CHANGE
---------- --------------------
(IN MILLIONS)
<S> <C> <C>
AT DECEMBER 31, 1998
Crude Oil and Refined Products
Hedging............................................... $ (1) $ (5)
Trading............................................... 3 3
---- ----
Combined.............................................. $ 2 $ (2)
Natural Gas
Hedging............................................... $(25) $(20)
Trading............................................... (2) (1)
---- ----
Combined.............................................. $(27) $(21)
AT DECEMBER 31, 1997
Crude Oil and Refined Products
Hedging............................................... $ (3) $ (8)
Trading............................................... (6) (18)
---- ----
Combined.............................................. $ (9) $(26)
Natural Gas
Hedging............................................... $ 8 $ (9)
Trading............................................... -- --
---- ----
Combined.............................................. $ 8 $ (9)
</TABLE>

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.

All hedge positions offset physical positions exposed to the cash market;
none of these offsetting physical positions is included in the above table.

Price-risk sensitivities were calculated by assuming an across-the-board
ten 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 ten percent change in prompt month
crude or natural gas prices, the fair value of the Company's derivative
portfolio would typically change less than that shown in the table due to lower
volatility in out-month prices.

Additional details regarding accounting policy for these financial
instruments are set forth in Note 2 to the Consolidated Financial Statements.

Foreign Currency Risk

Conoco has foreign currency exchange rate risk resulting from operations in
over 40 countries around the world. The Company does not comprehensively hedge
its exposure to currency rate changes, although it may choose to selectively
hedge exposure to foreign currency exchange rate risk. Examples include firm
commitments for capital projects, certain local currency tax payments, and cash
returns from net investments in foreign affiliates to be remitted within the
coming year. At December 31, 1998, the Company had no open forward exchange
contracts. At December 31, 1997, the Company had open forward exchange contracts

57
<PAGE> 60

designated as a hedge of firm foreign currency commitments. The notional amount
of these contracts was $50 million and the estimated fair value was $38 million.

Interest Rate Risk

Prior to the Offerings, the Company had no material interest rate risk to
manage. Subsequent to the Offerings, however, the Company intends to manage any
material risk arising from exposure to interest rates by using a combination of
financial derivative instruments as part of a program to manage the fixed and
floating interest rate mix of the total debt portfolio and related overall cost
of borrowing.

Risk of Refinancing Debt Owed to DuPont

Conoco is obligated to repay all outstanding debt owed to DuPont at such
time as DuPont's direct or indirect voting power in Conoco falls below 50
percent of the outstanding voting power of Conoco. The Company intends to
refinance outstanding related party debt owed to DuPont with a combination of
commercial paper and public debt in 1999. On February 12, 1999, Conoco filed a
"shelf" registration statement under the Securities Act of 1933 pursuant to
which it may issue debt securities. Conoco intends to use the proceeds from
issuances of securities under the shelf registration statement to refinance a
portion of the outstanding debt owed to DuPont. There can be no assurance that
the Company will be able to refinance this debt on terms as favorable as those
existing with respect to the debt owed to DuPont.

58
<PAGE> 61

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Report of Management........................................ 60

Audited Consolidated Financial Statements

Report of Independent Accountants......................... 61

Consolidated Statement of Income -- Years Ended December
31, 1998, 1997 and 1996................................ 62

Consolidated Balance Sheet -- at December 31, 1998 and
1997................................................... 63

Consolidated Statement of Stockholders' Equity/Owner's Net
Investment and Accumulated Other Comprehensive
Loss -- Years Ended December 31, 1998, 1997 and 1996... 64

Consolidated Statement of Cash Flows -- Years Ended
December 31, 1998, 1997 and 1996....................... 65

Notes to Consolidated Financial Statements................ 66

Unaudited Financial Information

Supplemental Petroleum Data............................... 96

Consolidated Quarterly Financial Data -- 1998 and 1997.... 102
</TABLE>

Certain supplementary financial statement schedules have been omitted
because the information required to be set forth therein is either not
applicable or is shown in the financial statements or notes thereto.

59
<PAGE> 62

REPORT OF MANAGEMENT

Management is responsible for the Consolidated Financial Statements of
Conoco Inc. (the "Company") and other information appearing in this annual
report. The Consolidated Financial Statements have been prepared in accordance
with generally accepted accounting principles considered by management to
present fairly the Company'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.

The Company'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. The Company's business
ethics policy is the cornerstone of the 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. The system is monitored by an extensive
program of internal audit, and management believes that the system of internal
controls at December 31, 1998 meets the objective noted above.

The Consolidated Financial Statements have been audited by the Company's
independent accountants, PricewaterhouseCoopers LLP. The purpose of their audit
is to independently affirm the fairness of management's reporting of financial
position, results of operations and cash flows. To express the opinion set forth
in their report, they study and evaluate the internal controls to the extent
they deem necessary. The adequacy of the Company's internal controls 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. No member of this committee may be an
officer or employee of the Company. 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.

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

60
<PAGE> 63

REPORT OF INDEPENDENT ACCOUNTANTS

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

In our opinion, the consolidated financial statements listed in the
accompanying index present fairly, in all material respects, the financial
position of Conoco Inc. and its subsidiaries at December 31, 1998 and 1997, and
the results of their operations and their cash flows for each of the three years
in the period ended December 31, 1998, in conformity with generally accepted
accounting principles. These financial statements are the responsibility of the
Company's management; our responsibility is to express an opinion on these
consolidated financial statements based on our audits. We conducted our audits
of these statements in accordance with generally accepted auditing standards,
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 the opinion expressed above.

PRICEWATERHOUSECOOPERS LLP

Houston, Texas
February 15, 1999

61
<PAGE> 64

CONOCO INC.

CONSOLIDATED STATEMENT OF INCOME

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
--------------------------------
1998 1997 1996
-------- -------- --------
(IN MILLIONS, EXCEPT PER SHARE)
<S> <C> <C> <C>
Revenues
Sales and Other Operating Revenues*....................... $22,796 $25,796 $24,230
Other Income (Note 4)..................................... 372 467 186
------- ------- -------
Total Revenues.................................... 23,168 26,263 24,416
------- ------- -------
Costs and Expenses
Cost of Goods Sold and Other Operating Expenses........... 13,840 16,226 14,560
Selling, General and Administrative Expenses.............. 736 726 755
Stock Option Provision (Note 22).......................... 236 -- --
Exploration Expenses...................................... 380 457 404
Depreciation, Depletion and Amortization.................. 1,113 1,179 1,085
Taxes Other Than on Income* (Note 5)...................... 5,970 5,532 5,637
Interest and Debt Expense (Note 6)........................ 199 36 74
------- ------- -------
Total Costs and Expenses.......................... 22,474 24,156 22,515
------- ------- -------
Income Before Income Taxes.................................. 694 2,107 1,901
Provision for Income Taxes (Note 7)......................... 244 1,010 1,038
------- ------- -------
Net Income.................................................. $ 450 $ 1,097 $ 863
======= ======= =======
Earnings Per Share (Note 8)
Basic..................................................... $ .95 $ 2.51 $ 1.98
Diluted................................................... $ .95 $ 2.51 $ 1.98
Weighted Average Shares Outstanding
Class A**................................................. 37 -- --
Class B................................................... 437 437 437
------- ------- -------
Total Basic............................................ 474 437 437
Stock Options**........................................... 1 -- --
------- ------- -------
Total Diluted.......................................... 475 437 437
- ---------------
* Includes petroleum excise taxes.......................... $ 5,801 $ 5,349 $ 5,461
** Earnings Per Share for the periods prior to the Offerings was calculated using only Class B
Common Stock, as required by SFAS 128 (see Note 8).
</TABLE>

See accompanying Notes to Consolidated Financial Statements

62
<PAGE> 65

CONOCO INC.

CONSOLIDATED BALANCE SHEET

ASSETS

<TABLE>
<CAPTION>
DECEMBER 31
------------------
1998 1997
------- -------
(IN MILLIONS)
<S> <C> <C>
Current Assets
Cash and Cash Equivalents................................. $ 394 $ 1,147
Marketable Securities..................................... -- 7
Accounts and Notes Receivable (Note 9).................... 1,191 1,497
Notes Receivable -- Related Parties (Note 3).............. -- 490
Inventories (Note 10)..................................... 807 830
Prepaid Expenses.......................................... 378 236
------- -------
Total Current Assets.............................. 2,770 4,207
Property, Plant and Equipment (Note 11)..................... 22,094 21,229
Less: Accumulated Depreciation, Depletion and
Amortization.............................................. (10,681) (10,401)
------- -------
Net Property, Plant and Equipment........................... 11,413 10,828
------- -------
Investment in Affiliates (Note 12).......................... 1,363 1,085
Long-Term Notes Receivable -- Related Parties (Note 3)...... -- 450
Other Assets (Note 13)...................................... 529 492
------- -------
Total............................................. $16,075 $17,062
======= =======
</TABLE>

<TABLE>
<CAPTION>
LIABILITIES AND STOCKHOLDERS' EQUITY/OWNER'S NET INVESTMENT
<S> <C> <C>
Current Liabilities
Accounts Payable (Note 14)................................ $ 1,312 $ 1,090
Short-Term Borrowings -- Related Parties (Note 3)......... -- 644
Other Short-Term Borrowings and Capital Lease Obligations
(Note 15).............................................. 52 72
Income Taxes (Note 7)..................................... 199 545
Other Accrued Liabilities (Note 16)....................... 1,162 1,289
------- -------
Total Current Liabilities......................... 2,725 3,640
Long-Term Borrowings -- Related Parties (Note 3)............ 4,596 1,450
Other Long-Term Borrowings and Capital Lease Obligations
(Note 17)................................................. 93 106
Deferred Income Taxes (Note 7).............................. 1,714 1,739
Other Liabilities and Deferred Credits (Note 18)............ 2,200 1,922
------- -------
Total Liabilities................................. 11,328 8,857
------- -------
Commitments and Contingent Liabilities (Note 26)
Minority Interests (Note 19)................................ 309 309
Owner's Net Investment...................................... -- 8,087
Stockholders' Equity (Note 20)
Preferred Stock, $.01 par value:
250,000,000 shares authorized; none issued................ -- --
Class A Common Stock, $.01 par value:
3,000,000,000 shares authorized; 191,497,821 shares
issued................................................. 2 --
Class B Common Stock, $.01 par value:
1,600,000,000 shares authorized; 436,543,573 shares issued
and outstanding........................................ 4 --
Additional Paid-In Capital................................ 4,955 --
Accumulated Deficit....................................... (244) --
Accumulated Other Comprehensive Loss (Note 21)............ (274) (191)
Treasury Stock, at cost (249,863 Class A shares).......... (5) --
------- -------
Total Stockholders' Equity........................ 4,438 (191)
------- -------
Total Stockholders' Equity/Owner's Net
Investment....................................... 4,438 7,896
------- -------
Total............................................. $16,075 $17,062
======= =======
</TABLE>

See accompanying Notes to Consolidated Financial Statements

63
<PAGE> 66

CONOCO INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY/OWNER'S NET
INVESTMENT AND ACCUMULATED OTHER COMPREHENSIVE LOSS
(NOTES 20 AND 21)

<TABLE>
<CAPTION>
ACCUMULATED
ADDITIONAL OTHER
OWNER'S NET COMMON PAID-IN ACCUMULATED COMPREHENSIVE COMPREHENSIVE TREASURY
INVESTMENT STOCK CAPITAL DEFICIT INCOME LOSS STOCK
----------- ------ ---------- ----------- ------------- ------------- --------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C> <C>
Balance January 1, 1996.............. $ 6,762 $ (8)
Comprehensive Income
Net Income......................... 863 $ 863
Other Comprehensive Income (Loss):
Foreign Currency Translation
Adjustment..................... (39)
Minimum Pension Liability
Adjustment..................... (10)
------
Other Comprehensive Loss....... (49) (49)
------
Comprehensive Income......... $ 814
======
Net Cash Contribution to Owner....... (993)
Other Transfer from Owner............ 4
------- -----
Balance December 31, 1996............ 6,636 (57)
Comprehensive Income
Net Income (Loss).................. 1,097 $1,097
Other Comprehensive Income (Loss):
Foreign Currency Translation
Adjustment..................... (121)
Minimum Pension Liability
Adjustment..................... (13)
------
Other Comprehensive Loss....... (134) (134)
------
Comprehensive Income......... $ 963
======
Net Cash Contribution from Owner..... 360
Other Transfers to Owner............. (6)
------- -----
Balance December 31, 1997............ 8,087 (191)
Comprehensive Income
Net Income (Loss).................. 694 $(244) $ 450
Other Comprehensive Income (Loss):
Foreign Currency Translation
Adjustment..................... (25)
Minimum Pension Liability
Adjustment..................... (58)
------
Other Comprehensive Loss....... (83) (83)
------
Comprehensive Income......... $ 367
======
Net Cash Contribution to Owner....... (512)
Dividends to Owner (Note 3).......... (8,200)
Other Transfers from Owner........... 433
Capitalization from Owner at
Offerings.......................... (502) $4 $ 498
Initial Public Offerings............. 2 4,226
Compensation Plans................... (5)
Treasury Stock Purchases............. $(5)
Stock Option Provision (Note 22)..... 236
------- -- ------ ----- ----- ---
Balance December 31, 1998............ $ -- $6 $4,955 $(244) $(274) $(5)
======= == ====== ===== ===== ===
</TABLE>

See accompanying Notes to Consolidated Financial Statements

64
<PAGE> 67

CONOCO INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
---------------------------
1998 1997 1996
------- ------- -------
(IN MILLIONS)
<S> <C> <C> <C>
Cash Provided by Operations
Net Income................................................ $ 450 $ 1,097 $ 863
Adjustments to Reconcile Net Income to Cash Provided by
Operations:
Depreciation, Depletion and Amortization............... 1,113 1,179 1,085
Dry Hole Costs and Impairment of Unproved Properties... 163 169 137
Stock Option Provision (Note 22)....................... 236 -- --
Inventory Write-down to Market (Note 10)............... 97 -- --
Deferred Income Taxes (Note 7)......................... (32) 16 10
Income Applicable to Minority Interests................ 21 24 19
Other Non-Cash Charges and Credits -- Net.............. (137) (271) 66
Decrease (Increase) in Operating Assets:
Accounts and Notes Receivable........................ 125 127 (280)
Inventories.......................................... (62) (79) 22
Other Operating Assets............................... (172) (96) 10
Increase (Decrease) in Operating Liabilities:
Accounts Payable and Other Operating Liabilities..... (85) 622 362
Accrued Interest and Income Taxes (Notes 6 and 7).... (344) 88 102
------- ------- -------
Cash Provided by Operations....................... 1,373 2,876 2,396
------- ------- -------
Investing Activities (Note 24)
Purchases of Property, Plant and Equipment................ (1,965) (2,644) (1,616)
Investments in Affiliates................................. (385) (339) (326)
Proceeds from Sales of Assets and Subsidiaries............ 721 565 328
Net Decrease (Increase) in Short-Term Financial
Instruments............................................ 31 381 (33)
------- ------- -------
Cash Used for Investing Activities................ (1,598) (2,037) (1,647)
------- ------- -------
Financing Activities
Short-Term Borrowings -- Receipts......................... -- 24 --
-- Payments..................... (26) (2) (90)
Other Long-Term Borrowings -- Receipts.................... -- 33 38
-- Payments............... (4) (3) (1)
Proceeds from Initial Public Offerings (Notes 3 and 20)... 4,228 -- --
Treasury Stock Purchases.................................. (5) -- --
Transactions with Related Parties:
Notes Receivable -- Receipts........................... 444 9 402
-- Payments......................... (152) (617) (9)
Borrowings -- Receipts................................. 927 413 706
-- Payments................................ (5,434) (695) (520)
Net Cash Contribution From (To) Owner.................. (512) 360 (993)
Increase (Decrease) in Minority Interests (Note 19)....... (21) (21) 280
------- ------- -------
Cash Used for Financing Activities................ (555) (499) (187)
------- ------- -------
Effect of Exchange Rate Changes on Cash..................... 27 (39) (2)
------- ------- -------
Increase (Decrease) in Cash and Cash Equivalents............ (753) 301 560
Cash and Cash Equivalents at Beginning of Year.............. 1,147 846 286
------- ------- -------
Cash and Cash Equivalents at End of Year.................... $ 394 $ 1,147 $ 846
======= ======= =======
SUPPLEMENTAL SCHEDULE OF NON-CASH FINANCING ACTIVITIES:
Transactions with Related Parties (Note 3):
Dividends to Owner..................................... $(8,200)
Promissory Note Issued................................. 7,500
Notes Receivable Reduced............................... 700
Borrowings Contributed to Capital...................... (544)
-------
Total Non-Cash Financing Activities............... $ (544)
=======
</TABLE>

See accompanying Notes to Consolidated Financial Statements
65
<PAGE> 68

CONOCO INC.

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

1. BASIS OF PRESENTATION

Conoco Inc., including its consolidated subsidiaries, ("Conoco" or the
"Company") is an integrated, global energy company that is involved in the
Upstream and Downstream segments of the petroleum business. Activities of the
Upstream operating segment include exploring for, and developing, producing and
selling crude oil, natural gas and natural gas liquids. Activities of the
Downstream operating segment include refining crude oil and other feedstocks
into petroleum products, buying and selling crude oil and refined products and
transporting, distributing and marketing petroleum products. The Company has
four reporting segments for its Upstream and Downstream operating segments,
reflecting geographic division between the United States and International.
Corporate and Other includes general corporate expenses, financing costs and
other non-operating items, and results for electric power and related-party
insurance operations.

The initial public offerings (the "Offerings") of the Class A Common Stock
of Conoco, a subsidiary of E.I. du Pont de Nemours and Company ("DuPont"),
commenced on October 21, 1998, and the Class A Common Stock began trading on the
New York Stock Exchange on October 22, 1998. The Offerings consisted of
191,456,427 shares of Class A Common Stock issued at a price of $23 per share,
and represented DuPont's first step in the planned divestiture of its entire
petroleum business. Through its ownership of 100% of the Company's Class B
Common Stock (436,543,573 shares), DuPont owned approximately 70% of the
Company's common stock representing approximately 92% of the combined voting
power of all classes of voting stock of the Company at December 31, 1998. The
holders of Class A Common Stock and Class B Common Stock generally have
identical rights, except that holders of Class A Common Stock are entitled to
one vote per share while holders of Class B Common Stock are entitled to five
votes per share on matters to be voted on by stockholders.

Prior to the date of the Offerings, operations were conducted by Conoco
Inc., subsidiaries of Conoco Inc. and, in some cases, subsidiaries of DuPont.
The accompanying Consolidated Financial Statements for these periods are
presented on a carve-out basis prepared from DuPont's historical accounting
records, and include the historical operations of both entities owned by Conoco
and operations transferred to Conoco by DuPont at the time of the Offerings. In
this context, no direct ownership relationship existed among all the various
units comprising Conoco. Accordingly, DuPont and its subsidiaries' net
investment in Conoco ("Owner's Net Investment") is shown in lieu of
Stockholders' Equity in the Consolidated Financial Statements. Net Cash
Contributions from/to Owner prior to the Offerings include funds transferred
between Conoco and DuPont for operating needs, cash dividends paid and other
equity transactions.

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

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. The equity method is used to account
for investments in corporate entities, partnerships and limited liability
companies in which the Company exerts significant influence, generally having a
20-50% ownership interest. The Company's 50.1 percent non-controlling interest
in Petrozuata C.A. in Venezuela is accounted for using the equity method because
the minority shareholder, a subsidiary of the national oil company of the
Republic of Venezuela, has substantive participating rights. Undivided interests
in oil and gas joint ventures and transportation assets are combined on a pro
rata basis. Other investments, excluding marketable securities, are carried at
cost.

Use of Estimates

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

Cash Equivalents

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

Inventories

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

Property, Plant and Equipment ("PP&E")

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

Maintenance and repairs are charged to expense; replacements and
improvements are capitalized.

Oil and Gas Properties

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

Unproved properties which are individually significant are periodically
assessed for impairment, whereas the impairment of individually insignificant
properties is provided by amortizing the costs based on past experience and the
estimated holding period. Exploratory well costs are expensed in the period the
well is

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

determined to be unsuccessful. All other exploration costs, including geological
and geophysical costs, production costs and overhead costs, are expensed in the
period incurred.

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

Impairment of Long-Lived Assets

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

Environmental Costs

Environmental expenditures are expensed or capitalized, as appropriate,
depending on their future economic benefit. Expenditures that relate to an
existing condition caused by past operations, and that do not have future
economic benefit, are expensed. Liabilities related to these 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

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

Income Taxes

The provision for income taxes has been determined using the asset and
liability approach of accounting for income taxes. Under this approach, deferred
taxes represent the future tax consequences expected to occur when the reported
amounts of assets and liabilities are recovered or paid. The provision for
income taxes represents income taxes paid or payable for the current year plus
the change in deferred taxes during the year. Deferred taxes result from
differences between the financial and tax bases of the Company'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 a tax benefit will not be realized.

Prior to the date of the Offerings, Conoco was included in the DuPont
consolidated tax return and the provision for income taxes was determined using
the loss benefit method. Under the loss benefit method, the current tax
provision or benefit is allocated based on the amount expected to be paid or
received from the consolidated group and benefits of losses and credit carry
forwards are recorded when such benefits are expected to be realized by members
of the consolidated group. The pro forma effect on the Consolidated Statement of
Income reflecting the provision for income taxes on a separate return basis
prior to the Offerings is not material. For periods ending after the Offerings,
Conoco will file a separate tax return. Accordingly, for periods subsequent to
the Offerings, the provision for income taxes has been determined on a separate
tax return basis.

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

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

Foreign Currency Translation

Local currency is the functional currency for the Company's integrated
Western European petroleum operations. For subsidiaries whose functional
currency is the local currency, assets and liabilities denominated in local
currency are translated into United States dollars at end-of-period exchange
rates. The resultant translation adjustment is a component of Accumulated Other
Comprehensive Loss (see Note 21). Assets and liabilities denominated in other
than the local currency are remeasured into the local currency prior to
translation into United States dollars, and the resultant exchange gains or
losses, together with their related tax effects, are included in income in the
period in which they occur. Income and expenses are translated into United
States dollars at average exchange rates in effect during the period.

For subsidiaries where the United States dollar is the functional currency,
all foreign currency asset and liability amounts are remeasured into United
States dollars at end-of-period exchange rates, except for inventories, prepaid
expenses and property, plant and equipment, which are remeasured at historical
rates. Foreign currency income and expenses are remeasured at average exchange
rates in effect during the year, except for expenses related to balance sheet
amounts, which are remeasured at historical exchange rates. Exchange gains and
losses arising from remeasurement of foreign currency-denominated monetary
assets and liabilities are included in current period income.

Effective January 1, 1999, the Euro was adopted as the local currency by 11
countries participating in the European Economic and Monetary Union. For those
countries in which the Company operates, the Euro concurrently became the
functional currency.

Commodity Hedging and Trading Activities

The Company enters into energy-related futures, forwards, swaps, and
options in various markets to balance its physical systems, to meet customer
needs, and to manage its exposure to price fluctuations on anticipated crude
oil, natural gas, refined product and electric power transactions.

Under the Company's policy, hedging includes only those transactions that
offset physical positions and reduce overall Company exposure to price risk.
Trading is defined as any transaction that does not meet the definition of
hedging.

Gains and losses on hedging contracts are deferred and included in the
measurement of the related transaction. Changes in market values of trading
contracts are reflected in income in the period the change occurs.

In the event a derivative designated as a hedge is terminated prior to the
maturation of the hedged transaction, gains or losses realized 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, gains or
losses associated with the derivative through the date the transaction matured
are included in the measurement of the hedged transaction and the derivative is
reclassified as for trading purposes. Derivatives designated as a hedge of an
anticipated transaction are reclassified as for trading purposes if the
anticipated transaction is no longer likely to occur.

In the Consolidated Statement of Cash Flows, the Company reports the cash
flows resulting from its hedging activities in the same category as the related
item that is being hedged.

Recent Accounting Standards

In June 1997, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 131, "Disclosures about Segments of an Enterprise and Related Information,"
which the Company has adopted for the year ended December 31, 1998. This
standard requires disclosing segment information on the same basis used
internally for evaluating segment performance and deciding how to allocate
resources to segments. It also

69
<PAGE> 72
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(DOLLARS IN MILLIONS, EXCEPT PER SHARE)

requires disclosure of revenue and long-lived assets attributed to operations in
individual countries outside the United States for which such information is
material. No substantive changes in segment reporting resulted from this
standard. The Company has four reporting segments for its Upstream and
Downstream operating segments, reflecting geographic division between the United
States and International. In addition, geographic reporting changed with
revenues and long-lived assets attributed to operations in the United Kingdom,
Germany and Norway disclosed separately.

In February 1998, the FASB issued SFAS No. 132, "Employers' Disclosure
About Pensions and Other Postretirement Benefits," that revised disclosure
requirements for pension and other postretirement benefits. This statement did
not affect measurement of the expense of the Company's pension and other
postretirement benefits. The Company has adopted the disclosure requirements of
this Statement for the year ended December 31, 1998.

In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities," which requires that companies recognize all
derivatives as either assets or liabilities in the balance sheet and measure
those instruments at fair value. SFAS No. 133 provides, if certain conditions
are met, that a derivative may be specifically designated as (1) a hedge of the
exposure to changes in the fair value of a recognized asset or liability or an
unrecognized firm commitment (fair value hedge), (2) a hedge of the exposure to
variable cash flows of a forecasted transaction (cash flow hedge), or (3) a
hedge of the foreign currency exposure of a net investment in a foreign
operation, an unrecognized firm commitment, an available-for-sale security or a
foreign-currency-denominated forecasted transaction (foreign currency hedge).
Under SFAS No. 133, the accounting for changes in fair value of a derivative
depends on its intended use and designation. For a fair value hedge, the gain or
loss is recognized in earnings in the period of change together with the
offsetting loss or gain on the hedged item. For a cash flow hedge, the effective
portion of the derivative's gain or loss is initially reported as a component of
other comprehensive income and subsequently reclassified into earnings when the
forecasted transaction affects earnings. For a foreign currency hedge, the gain
or loss is reported in other comprehensive income as part of the cumulative
translation adjustment. For all other items not designated as hedging
instruments, the gain or loss is recognized in earnings in the period of change.
The Company is required to adopt this Statement by the first quarter of 2000 and
is currently assessing its effect on the Consolidated Financial Statements.

3. RELATED PARTY TRANSACTIONS

The Consolidated Financial Statements include significant transactions with
DuPont involving services (such as cash management, other financial services,
purchasing, legal, computer and corporate aviation) and general corporate
expenses that were provided between Conoco and centralized DuPont organizations.
For periods prior to the Offerings, the costs of services have been directly
charged or allocated between Conoco and DuPont using methods management believes
are reasonable. These methods include negotiated usage rates, dedicated asset
assignment and proportionate corporate formulas involving assets, revenues and
employees. Such charges and allocations are not necessarily indicative of what
would have been incurred if Conoco had been a separate entity.

Amounts charged and allocated to Conoco for these services were $121, $125
and $101 for the years 1998, 1997 and 1996, respectively, and are principally
included in Selling, General and Administrative Expenses. Conoco provided DuPont
services, such as computer, legal and purchasing, as well as certain technical
and plant operating services, which amounted to $61, $62 and $66 in 1998, 1997
and 1996, respectively. These charges to DuPont were treated as reductions, as
appropriate, of Cost of Goods Sold and Other Operating Expenses or Selling,
General and Administrative Expenses.

Interest expense charged by DuPont was $264, $124 and $143 for the years
1998, 1997 and 1996, respectively, and reflects market-based interest rates. A
portion of this and other interest and debt expense was

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

capitalized as cost associated with major construction projects. Interest income
from DuPont was $43, $11 and $57 for the same years and also reflects
market-based interest rates.

Sales and Other Operating Revenues include sales of products from Conoco to
DuPont, principally natural gas and gas liquids to supply several DuPont plant
sites. These sales totaled $427, $420 and $413 for the years 1998, 1997 and
1996, respectively. Also included are revenues from insurance premiums charged
to DuPont for property and casualty coverage outside the United States. These
revenues totaled $20, $22 and $21 for the years 1998, 1997 and 1996,
respectively. Purchases of products from DuPont during these periods were not
material.

Subsequent to the Offerings, these intercompany arrangements between DuPont
and Conoco, excluding insurance coverage provided to DuPont, are being provided
under transition service agreements or other long-term agreements. It is not
anticipated that a change, if any, in these costs and revenues would have a
material effect on the Company's results of operations or consolidated financial
position.

Accounts and Notes Receivable include amounts due from DuPont of $80 and
$79 at December 31, 1998 and 1997, respectively, representing current month
balances of transactions between Conoco and DuPont, mainly product sales and
certain charges billed annually. Accounts Payable include amounts due DuPont of
$52 and $4 at December 31, 1998 and 1997, respectively. Other Liabilities
include accrued interest of $51 due DuPont at December 31, 1998.

Amounts representing notes receivable or borrowings from DuPont, including
its subsidiary organizations, are identified as related parties and presented
separately in the Consolidated Balance Sheet. The current portion of Notes
Receivable represents the accumulation of a variety of cash transfers and
operating transactions with DuPont. These balances are generally interest
bearing and represent net amounts of cash transferred for funding and cash
management purposes and amounts charged between the companies for certain
product and service purchases. At December 31, 1997, the long-term portion of
Notes Receivable and amounts shown for Short-Term and Long-Term Borrowings
represent borrowings between Conoco and DuPont with established due dates at
market-based interest rates, except for certain short-term non-interest bearing
borrowings due DuPont of $492. At December 31, 1998, related balances only
reflected long-term borrowings due DuPont as further described.

In July 1998, a dividend was declared and paid by the Company in the form
of a promissory note (the "Note") to DuPont in the aggregate principal amount of
$7,500 bearing interest at a rate of 6.0125 percent per annum and due on January
2, 2000. The Note may be voluntarily prepaid without penalty or premium. The
Note also provides for mandatory prepayments in the event cash proceeds are
realized by the Company from the incurrence of indebtedness or the issuance of
equity securities by the Company or its subsidiaries. The Note includes certain
covenants and customary events of default, including failure to pay interest
when due, certain events of bankruptcy of the Company and change of control. The
consent of DuPont is also required prior to the Company entering into certain
transactions.

In September 1998, the Company declared a dividend of $700 paid through a
reduction of notes receivable from DuPont and further certain intercompany notes
were created.

The net proceeds from the Offerings referred to in Note 1 were $4,228,
after deducting the underwriting discounts and commissions payable by the
Company. The Company used these net proceeds to repay indebtedness owed to
DuPont or purchase a portion of the indebtedness owed by certain subsidiaries of
the Company to DuPont as follows:

(a) to pay accrued interest ($124) on the $7,500 Note and then to
repay principal ($2,654) on such Note to the extent necessary to reduce the
principal amount to $4,846;

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

(b) to purchase certain intercompany notes denominated in Norwegian
Kroner with an aggregate principal amount of approximately $461 after
conversion to U.S. dollars, together with accrued interest ($9);

(c) to pay accrued interest ($8) and a portion of the principal ($820)
on a certain other intercompany note to the extent necessary to reduce the
principal amount to $7;

(d) to pay a portion of the principal ($152) on an intercompany demand
note which reduced the outstanding balance to $52.

During 1998, DuPont made capital contributions of $544 to the Company
reflecting the retirement of certain non-interest bearing borrowings of $492 and
the remaining balance of $52 on the foregoing demand note.

Subsequent to the Offerings, the Company made an additional principal
payment of $257 on the Note reducing the outstanding balance to $4,589 at
December 31, 1998. Aggregate borrowings from related parties at December 31,
1998, totaled $4,596 and reflected a weighted average interest rate of 6.0
percent with maturity on January 2, 2000.

On October 27, 1998, the Company and DuPont entered into a Revolving Credit
Agreement under which DuPont will provide the Company with a revolving credit
facility in principal amount of up to $500. Loans under the Revolving Credit
Agreement will be subject to mandatory repayment to the extent the Company's
cash and cash equivalents exceed $325 or such higher amount as the Company and
DuPont may agree. Loans under this facility bear interest at a rate equal to
30-day LIBOR plus 0.20 percent per annum and may be voluntarily prepaid without
penalty or premium. There was no outstanding debt under this facility on
December 31, 1998.

The Company is obligated to repay all outstanding debt owed to DuPont at
such time as DuPont's direct or indirect voting power in the Company falls below
50 percent of the outstanding voting power of the Company. The Company intends
to refinance outstanding related party debt owed to DuPont with a combination of
commercial paper and public debt in 1999.

4. OTHER INCOME

<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Interest income
Related parties (see Note 3).............................. $ 43 $ 11 $ 57
Other, net of miscellaneous interest expense.............. 46 66 67
---- ---- ----
89 77 124
Equity in earnings of affiliates (see Note 12).............. 22(1) 40 (25)
Gain on sales of assets(2).................................. 206 314 84
Exchange gain (loss)........................................ 51 27 (5)
Other -- net................................................ 4 9 8
---- ---- ----
$372 $467 $186
==== ==== ====
</TABLE>

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

(1) Includes a $5 charge for write-down of inventories to market in accordance
with the Company's inventory valuation policy (see Note 2).

(2) 1998 includes a gain of $89 from sale of certain Upstream properties in the
North Sea and the United States. 1997 includes a gain of $239 from sale of
certain Upstream properties in the North Sea.

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

5. TAXES OTHER THAN ON INCOME

<TABLE>
<CAPTION>
1998 1997 1996
------ ------ ------
<S> <C> <C> <C>
Petroleum excise taxes
U.S...................................................... $1,286 $1,201 $1,145
Non-U.S.................................................. 4,515 4,148 4,316
------ ------ ------
5,801 5,349 5,461
Payroll taxes.............................................. 42 43 48
Property taxes............................................. 64 63 55
Production and other taxes................................. 63 77 73
------ ------ ------
$5,970 $5,532 $5,637
====== ====== ======
</TABLE>

6. INTEREST AND DEBT EXPENSE

<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Interest and debt cost incurred
Related parties (see Note 3).............................. $264 $124 $143
Other..................................................... 7 6 6
---- ---- ----
271 130 149
Less: Interest and debt cost capitalized.................... 72 94 75
---- ---- ----
Interest and debt expense................................... $199 $ 36 $ 74
==== ==== ====
</TABLE>

Interest paid (net of amounts capitalized) was $145 in 1998, $33 in 1997
and $77 in 1996.

7. PROVISION FOR INCOME TAXES

<TABLE>
<CAPTION>
1998 1997 1996
---- ------ ------
<S> <C> <C> <C>
Current tax expense
U.S. federal............................................ $(57) $ 64 $ 155
U.S. state and local.................................... 10 5 8
Non-U.S. ............................................... 323 925 865
---- ------ ------
Total........................................... 276 994 1,028
---- ------ ------
Deferred tax expense
U.S. federal............................................ (51) 80 (78)
U.S. state and local.................................... (5) 8 --
Non-U.S. ............................................... 24 (72) 88
---- ------ ------
Total........................................... (32) 16 10
---- ------ ------
Provision for Income Taxes................................ 244 1,010 1,038
Foreign Currency Translation(1)........................... (22) -- --
Minimum Pension Liability(1).............................. (26) (7) (5)
---- ------ ------
Total Provision................................. $196 $1,003 $1,033
==== ====== ======
</TABLE>

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

(1) Represents respective deferred tax provisions for adjustments included in
other comprehensive loss (see Note 21).

Total income taxes paid worldwide were $714 in 1998, $935 in 1997 and $901
in 1996.

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

The significant components of deferred tax assets and liabilities at
December 31, 1998 and 1997 are as follows:

<TABLE>
<CAPTION>
1998 1997
-------------------- --------------------
ASSET LIABILITY ASSET LIABILITY
------ --------- ------ ---------
<S> <C> <C> <C> <C>
Property, plant and equipment....................... $ 233 $2,296 $ 182 $2,219
Employee benefits................................... 247 -- 166 --
Other accrued expenses.............................. 237 -- 273 --
Inventories......................................... -- 90 -- 102
Tax loss/tax credit carry forwards.................. 496 -- 417 --
Other............................................... 25 188 27 169
------ ------ ------ ------
Total..................................... $1,238 $2,574 $1,065 $2,490
====== ======
Valuation allowances................................ (423) (392)
------ ------
Net....................................... $ 815 $ 673
====== ======
</TABLE>

Valuation allowances, which reduce deferred tax assets to an amount that
will more likely than not be realized, increased $31 in 1998, primarily
reflecting increases in tax assets representing operating losses incurred in
exploration and start-up operations. Valuation allowances decreased by $22 in
1997, principally reflecting a $37 decrease related to tax assets representing
operating losses which the Company determined will more likely than not be
realized in future years. This decrease was partially offset by an increase of
$15 reflecting offsets to operating losses. Valuation allowances in 1996
increased by $52 to offset increases in deferred tax assets resulting primarily
from operating losses incurred in exploration and start-up operations.

Under the tax laws of various jurisdictions in which the Company operates,
deductions or credits that cannot be fully utilized for tax purposes during the
current year may be carried forward, subject to statutory limitations, to reduce
taxable income or taxes payable in a future year. At December 31, 1998, the tax
effect of such carry forwards approximated $496. Of this amount, $312 has no
expiration date, $3 expires in 1999, $5 expires in 2000, $75 expires in 2001,
$46 expires in 2002, and $55 expires in 2003 and later years.

Current deferred tax liabilities (included in the Consolidated Balance
Sheet caption "Income Taxes") were $76 and $122 at December 31, 1998 and 1997,
respectively.

Current deferred tax assets included in Prepaid Expenses were $7 at
December 31, 1997. In addition, Other Assets includes deferred tax assets of $31
and $37 at December 31, 1998 and 1997, respectively.

An analysis of the Company's effective income tax rate follows:

<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Statutory U.S. federal income tax rate..................... 35.0% 35.0% 35.0%
Higher effective tax rate on non-U.S. operations........... 7.8 13.9 21.6
Alternative fuels credit................................... (8.2) (3.0) (3.4)
Reduced tax benefit from Stock Option Provision............ 4.9 -- --
Realization of unbenefited loss from sale of subsidiary.... (4.6) -- --
Other -- net............................................... 0.3 2.0 1.4
---- ---- ----
Effective income tax rate.................................. 35.2% 47.9% 54.6%
==== ==== ====
</TABLE>

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

Earnings before income taxes shown below are 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
set forth below.

At December 31, 1998 and 1997, respectively, unremitted earnings of
non-U.S. subsidiaries totaling $1,536 and $1,645 were deemed to be permanently
invested. No deferred tax liability has been recognized with regard to 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 United
States.

8. EARNINGS PER SHARE

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

As described in Note 1, the Company's capital structure was established at
the time of the Offerings. In accordance with SEC Staff Accounting Bulletin No.
98, the capitalization of Class B Common Stock has been retroactively reflected
for the purposes of presenting earnings per share for periods prior to the
Offerings. For the period subsequent to the Offerings, basic EPS reflects the
Class B Common Stock plus the weighted average from the date of the Offerings of
Class A Common Stock and deferred award units outstanding at the date of the
Offerings. Corresponding diluted EPS for 1998 includes an additional 1,659,816
shares representing the weighted average dilutive effect of outstanding stock
options that resulted from the concurrent cancellation of DuPont stock options
at the date of the Offerings and issuance of options with respect to Class A
Common Stock.

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

<TABLE>
<CAPTION>
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
Basic......................................... 473,826,632 436,543,573 436,543,573
Diluted....................................... 475,486,448 436,543,573 436,543,573
</TABLE>

Variable stock options for 1,724,146 shares of common stock were
outstanding at December 31, 1998, but were not included in the computation of
diluted EPS since the threshold price of $32.88 required for these options to be
vested had not been reached.

Common shares held as Treasury Stock are deducted in determining the number
of shares outstanding.

MANAGEMENT VIEW

The substance of the Offerings was the sale by DuPont of approximately 30
percent ownership of Conoco. Therefore, management believes a more meaningful
presentation of basic EPS is to divide historical net income for all periods
presented by the total Class A and Class B Common Stock plus deferred award
units outstanding immediately after the Offerings. For diluted EPS, weighted
average shares have been adjusted to reflect the effect of outstanding stock
options immediately after the Offerings as though outstanding for all

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

periods presented. Using this presentation, but excluding any pro forma
adjustment for additional interest expense on the dividend Note (see Note 3),
EPS would be as follows:

<TABLE>
<CAPTION>
1998 1997 1996
----- ----- -----
<S> <C> <C> <C>
Basic....................................................... $ .72 $1.75 $1.37
Diluted..................................................... $ .71 $1.72 $1.36
</TABLE>

9. ACCOUNTS AND NOTES RECEIVABLE

<TABLE>
<CAPTION>
DECEMBER 31
---------------
1998 1997
------ ------
<S> <C> <C>
Trade....................................................... $ 805 $ 916
Related parties (see Note 3)................................ 80 79
Other....................................................... 306 502
------ ------
$1,191 $1,497
====== ======
</TABLE>

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

10. INVENTORIES

<TABLE>
<CAPTION>
DECEMBER 31
-----------------
1998 1997
------- -------
<S> <C> <C>
Crude oil and petroleum products............................ $ 661 $ 675
Other merchandise........................................... 22 25
Materials and supplies...................................... 124 130
------- -------
$ 807 $ 830
======= =======
</TABLE>

As a result of reduced crude oil and petroleum product price levels, a
write-down to market of $97 was made in the fourth quarter of 1998, in
accordance with the Company's inventory valuation policy (see Note 2). At
December 31, 1997, the excess of market over book value of inventories valued
under the LIFO method was $152. Inventories valued at LIFO represented 82
percent and 81 percent of consolidated inventories at December 31, 1998 and
1997, respectively.

During 1998, 1997 and 1996, certain LIFO inventory quantities were reduced
resulting in partial liquidation of the LIFO bases, with no material effect on
net income.

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

11. PROPERTY, PLANT AND EQUIPMENT

<TABLE>
<CAPTION>
DECEMBER 31
-------------------------------------
GROSS NET
----------------- -----------------
1998 1997 1998 1997
------- ------- ------- -------
<S> <C> <C> <C> <C>
Oil and Gas Properties
Unproved............................................. $ 1,159 $ 1,491 $ 942 $ 1,230
Proved............................................... 13,488 12,420 6,236 5,480
Other.................................................. 1,280 1,316 845 871
------- ------- ------- -------
Total Upstream............................... 15,927 15,227 8,023 7,581
Refining............................................... 3,834 3,803 1,958 1,952
Marketing and Distribution............................. 2,255 2,199 1,375 1,295
------- ------- ------- -------
Total Downstream............................. 6,089 6,002 3,333 3,247
Corporate(1)........................................... 78 -- 57 --
------- ------- ------- -------
$22,094 $21,229 $11,413 $10,828
======= ======= ======= =======
</TABLE>

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

(1) Includes aviation investment transferred from DuPont in 1998 and corporate
software.

Property, Plant and Equipment includes Downstream gross assets acquired
under capital leases of $41 at December 31, 1998 and 1997; related amounts
included in Accumulated Depreciation, Depletion and Amortization were $12 and
$10 at December 31, 1998 and 1997, respectively.

12. SUMMARIZED FINANCIAL INFORMATION FOR AFFILIATED COMPANIES

Summarized consolidated financial information for affiliated companies for
which Conoco uses the equity method of accounting (see Note 2, "Basis of
Consolidation") is shown below on a 100 percent basis. The most significant of
these affiliates are Malaysia Refining Company Sdn. Bhd. (40%), Petrozuata C.A.
(50.1% -- see Note 2), CFJ Properties (50%), Pocahontas Gas Partnership (50%),
Excel Paralubes (50%), Polar Lights Company (50%), and Ceska Rafinerska a.s.
(16.33%).

Dividends received from equity affiliates were $105 in 1998, $58 in 1997
and $85 in 1996.

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
------------------------
1998 1997 1996
------ ------ ------
<S> <C> <C> <C>
RESULTS OF OPERATIONS
Sales(1)................................................... $6,744 $7,521 $6,622
Earnings before income taxes............................... 358 556 305
Net income................................................. 252 345 140
Conoco's equity in earnings of affiliates (see Note 4)..... 22 40 (25)
</TABLE>

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

(1) Includes sales to Conoco of $574 in 1998, $568 in 1997 and $359 in 1996.

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

<TABLE>
<CAPTION>
DECEMBER 31
----------------
1998 1997
------- ------
<S> <C> <C>
FINANCIAL POSITION
Current assets.............................................. $ 2,771 $2,543
Non-current assets.......................................... 8,682 6,826
------- ------
Total assets...................................... $11,453 $9,369
------- ------
Short-term borrowings(1).................................... $ 897 $ 550
Other current liabilities................................... 1,650 1,308
Long-term borrowings(1)..................................... 4,743 4,364
Other long-term liabilities................................. 1,119 645
------- ------
Total liabilities................................. $ 8,409 $6,867
------- ------
Conoco's investment in affiliates (includes advances)....... $ 1,363 $1,085
======= ======
</TABLE>

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

(1) Conoco's pro rata interest in total borrowings was $1,828 in 1998 and $1,586
in 1997, of which $967 in 1998 and $826 in 1997 were guaranteed by the
Company or DuPont, on behalf of, and indemnified by, the Company. These
amounts are included in the guarantees disclosed in Note 26.

At December 31, 1998, Conoco's equity in undistributed earnings of its
affiliated companies was $114.

13. OTHER ASSETS

<TABLE>
<CAPTION>
DECEMBER 31
----------------
1998 1997
------- ------
<S> <C> <C>
Prepaid pension cost (see Note 23).......................... $ 50 $ 71
Long-term receivables....................................... 71 74
Other securities and investments(1)......................... 116 100
Deferred pension transition obligation (see Note 23)........ 109 116
Other(2).................................................... 183 131
------- ------
$ 529 $ 492
======= ======
</TABLE>

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

(1) Includes $74 and $97 at December 31, 1998 and 1997, respectively,
representing marketable securities classified as available for sale and
reported at fair value. The remainder represents investments which are
reported at cost.

(2) Includes intangible assets of $14 and $15 at December 31, 1998 and 1997,
respectively.

14. ACCOUNTS PAYABLE

<TABLE>
<CAPTION>
DECEMBER 31
----------------
1998 1997
------ ------
<S> <C> <C>
Trade....................................................... $ 906 $ 969
Payables to banks........................................... 124 85
Related parties (see Note 3)................................ 52 4
Other....................................................... 230(1) 32
------ ------
$1,312 $1,090
====== ======
</TABLE>

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

(1) Includes $158 for property acquisitions.

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

Payables to banks represent checks issued on certain disbursement accounts
but not presented to the banks for payment.

15. OTHER SHORT-TERM BORROWINGS AND CAPITAL LEASE OBLIGATIONS

<TABLE>
<CAPTION>
DECEMBER 31
---------------
1998 1997
------ ------
<S> <C> <C>
Industrial development bonds................................ $ 24 $ 24
Bank borrowings (foreign currency).......................... -- 21
Long-term borrowings payable within one year................ 26 25
Capital lease obligations................................... 2 2
------ ------
$ 52 $ 72
====== ======
</TABLE>

The Company has uncommitted short-term bank credit lines of approximately
$122 and $42 at December 31, 1998 and 1997, respectively. These lines are
denominated in United States dollars or various foreign currencies to support
general international operating needs. No significant advances were outstanding
under these lines at these respective dates.

The weighted average interest rate on other short-term borrowings
outstanding at December 31, 1998 and 1997, was 3.8 percent and 3.7 percent,
respectively.

16. OTHER ACCRUED LIABILITIES

<TABLE>
<CAPTION>
DECEMBER 31
---------------
1998 1997
------ ------
<S> <C> <C>
Taxes other than on income.................................. $ 354 $ 376
Operating expenses.......................................... 293 343
Payroll and other employee-related costs.................... 102 135
Restructuring costs(1)...................................... 82 --
Accrued postretirement benefits cost (see Note 23).......... 18 24
Other....................................................... 313 411
------ ------
$1,162 $1,289
====== ======
</TABLE>

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

(1) Represents estimated charges associated with cost reduction program
announced in December 1998. This program is focused on obtaining operational
efficiencies, mainly in the Upstream businesses, and was expedited in
response to adverse changes in the current business environment. The program
primarily involves the elimination of approximately 975 employee positions
on a worldwide basis. The accrual is reflected in Cost of Goods Sold and
Other Operating Expenses. At December 31, 1998, no persons had been
terminated and no related payments had been made.

17. OTHER LONG-TERM BORROWINGS AND CAPITAL LEASE OBLIGATIONS

<TABLE>
<CAPTION>
DECEMBER 31
---------------
1998 1997
------ ------
<S> <C> <C>
5.75% notes due 2026........................................ $ 16 $ 16
6.50% notes due 2008........................................ 7 7
Other loans (various currencies) due 1999-2007(1)........... 29 30
Capitalization obligation to affiliate due 2008............. 11 --
Capitalization obligation to affiliate due 1999............. -- 20
Capital lease obligations................................... 30 33
------ ------
$ 93 $ 106
====== ======
</TABLE>

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

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

(1) Weighted average interest rates were 7.3 percent at December 31, 1998 and
1997, respectively.

Maturities of long-term borrowings, together with sinking fund requirements
for years ending after December 31, 1999, are $4 for each of the years 2000,
2001, 2002 and 2003.

18. OTHER LIABILITIES AND DEFERRED CREDITS

<TABLE>
<CAPTION>
DECEMBER 31
---------------
1998 1997
------ ------
<S> <C> <C>
Deferred gas revenue........................................ $ 371 $ 379(1)
Accrued postretirement benefits cost (see Note 23).......... 331 318
Accrued pension liability (see Note 23)..................... 320 230
Abandonment costs........................................... 297 310
Environmental remediation costs (see Note 26)............... 117 132
Related parties (see Note 3)................................ 51 --
Other....................................................... 713 553
------ ------
$2,200 $1,922
====== ======
</TABLE>

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

(1) 1997 includes $303 received from a contract for future sales of natural gas
to Centrica, a United Kingdom gas marketing company.

19. MINORITY INTERESTS

In 1996, certain upstream subsidiaries contributed assets with an aggregate
fair value of $613 to Conoco Oil & Gas Associates L.P. (COGA) for a general
partnership interest of 67 percent. The remaining 33 percent was purchased by
Vanguard Energy Investors L.P. (Vanguard) as a limited partner. The net result
of this transaction was to increase minority interests by $297.

Vanguard is entitled to a cumulative annual priority return on its
investment and participation in residual earnings at rates established in the
partnership agreement. The priority return rate, currently 6.52 percent, is
scheduled to be renegotiated in the second half of 1999. In the event the
parties are unable to agree on a new return rate, Vanguard has the option to
call for liquidation of the partnership, which could take place before December
31, 1999. Cash outflows arising from such liquidation should not be materially
different from the recorded amount of minority interest.

Vanguard's share of COGA's earnings was $22 or 25 percent in 1998 and $22
or 18 percent in 1997; the net minority interest in COGA held by Vanguard was
$302 and $301 on December 31, 1998 and 1997, respectively.

20. STOCKHOLDERS' EQUITY

As described in Note 1, the Company's capital structure was established at
the time of the Offerings in October 1998.

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

At December 31, 1998, 4,600,000,000 shares of Class A and Class B Common
Stock were authorized and 628,041,394 shares were issued, including 249,863
Class A shares held in the treasury. A summary of activity in common shares
outstanding for the year 1998 is presented below:

<TABLE>
<CAPTION>
CLASS A CLASS B TOTAL
----------- ----------- -----------
<S> <C> <C> <C>
Issued in connection with initial public
offerings of Class A shares and
recapitalization of DuPont ownership (Class B
shares)........................................ 191,456,427 436,543,573 628,000,000
Purchase of shares for treasury (to offset
dilution from issuances under compensation
plans)......................................... (250,000) -- (250,000)
Issued on exercise of stock options (including
137 from treasury)............................. 41,531 -- 41,531
----------- ----------- -----------
Common Shares Outstanding -- December 31, 1998... 191,247,958 436,543,573 627,791,531
=========== =========== ===========
</TABLE>

At December 31, 1998, 250,000,000 shares of Preferred Stock were
authorized, of which 1,000,000 shares were designated Series A Junior
Participating Preferred Stock and reserved for issuance on exercise of preferred
stock purchase rights under the Company's Share Purchase Rights Plan. Each
issued share of Class A and Class B Common Stock has one preferred stock
purchase Right attached to it. No preferred shares have been issued and the
Rights are not currently exercisable.

Net proceeds received from the Offerings totaled $4,228, after deduction
for underwriting discounts and commissions payable by the Company, and were used
to reduce indebtedness owed to DuPont (see Note 3). In addition, Additional
Paid-In Capital was increased by $236 during 1998 as a result of a corresponding
non-cash charge to compensation expense associated with changes in certain
outstanding compensation awards made at the time of the Offerings (see Note 22).

The Company declared a first quarter cash dividend on January 27, 1999, of
$.14 per share on each outstanding share of Class A Common Stock and Class B
Common Stock, payable March 12, 1999, to shareholders of record as of February
12, 1999. This initial dividend was determined on a pro rata basis covering the
period from October 27, 1998 to December 31, 1998, and is equivalent to $.19 per
share for a full quarter.

21. ACCUMULATED OTHER COMPREHENSIVE LOSS

Balances of related after-tax components comprising Accumulated Other
Comprehensive Loss are summarized below:

<TABLE>
<CAPTION>
DECEMBER 31
-------------
1998 1997
----- -----
<S> <C> <C>
Foreign Currency Translation Adjustment..................... $(185) $(160)
Minimum Pension Liability Adjustment (see Note 23).......... (89) (31)
----- -----
$(274) $(191)
===== =====
</TABLE>

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

Changes in related components of other comprehensive income (loss) are
reported net of associated income tax effects as summarized below:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
------------------------------------------------------------------------------
1998 1997 1996
------------------------ ------------------------ ------------------------
INCOME AFTER- INCOME AFTER- INCOME AFTER-
PRETAX TAX TAX PRETAX TAX TAX PRETAX TAX TAX
------ ------ ------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Foreign Currency Translation
Adjustment............................. $ (47) $(22) $(25) $(121) $-- $(121) $(39) $-- $(39)
Minimum Pension Liability Adjustment..... (84) (26) (58) (20) (7) (13) (15) (5) (10)
----- ---- ---- ----- --- ----- ---- --- ----
Other Comprehensive Income (Loss)........ $(131) $(48) $(83) $(141) $(7) $(134) $(54) $(5) $(49)
===== ==== ==== ===== === ===== ==== === ====
</TABLE>

22. COMPENSATION PLANS

Until the date of the Offerings, employees of Conoco participated in
stock-based compensation plans administered through DuPont and involving options
to acquire DuPont common stock. At the time of the Offerings, 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, and the
Company 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 the issuance by the Company, upon
such cancellation, of comparable options to acquire Class A Common Stock or SARs
with respect to Class A Common Stock. The substitute stock options and other
awards have the same vesting provisions, option periods and other terms and
conditions as the DuPont options and awards they replaced. The substitute stock
options had the same ratio of the exercise price per share to the market value
per share, and the same aggregated difference between market value and exercise
price, as the DuPont stock options. A total of 8,921,508 DuPont stock options
and 745,358 DuPont SARs were cancelled with Conoco issuing 24,275,690 stock
options for Class A Common Stock and 2,279,834 SARs with respect to Class A
Common Stock with comparable terms and conditions. The program was deemed a
change in the terms of certain awards granted to Conoco employees. As a result,
the Company incurred a non-cash charge to compensation expense of $236 in the
fourth quarter of 1998, with a corresponding increase in Additional Paid-In
Capital. DuPont retained responsibility for delivery of DuPont common stock to
Conoco employees when DuPont stock options not cancelled are exercised.

AWARDS UNDER DUPONT PLANS

Stock option awards under the DuPont Stock Performance Plan were granted to
key employees of the Company prior to the Offerings and were "fixed" and/or
"variable." The purchase price of shares subject to option is the market price
of DuPont stock at the date of grant. In January 1997, a reload feature was
added to the Stock Performance Plan to accelerate stock ownership. Generally,
fixed options granted under the DuPont Stock Performance Plan are fully
exercisable one year after date of grant and expire ten years from date of
grant. However, awards in 1998 vest over a three-year period and, except for the
last six months of the ten-year option term, are exercisable when the market
price of DuPont common stock exceeds the option grant price by 20 percent.

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

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

From time to time, the DuPont Board of Directors has approved the adoption
of a worldwide Corporate Sharing Program. Under these programs, a majority of
the Company's employees received a one-time grant to acquire shares of DuPont
common stock at the fair market value at the date of grant. Option terms are
"fixed" and generally are exercisable one year after date of grant and expire
ten years from date of grant.

AWARDS UNDER CONOCO PLANS

The 1998 Stock and Performance Incentive Plan provides incentives to
certain corporate officers, non-employee directors and independent contractors
who can contribute materially to the success and profitability of the Company
and its subsidiaries and provides for substitution of certain existing DuPont
awards in connection with the Offerings. Awards may be in the form of cash,
stock, stock options or SARs with respect to Class A Common Stock. This plan
also provides for the Conoco Global Variable Compensation Plan, which is an
annual management incentive program for officers and certain non-officer
employees with awards made in cash and stock. Stock options and SARs granted
under the 1998 Stock and Performance Incentive Plan (except those granted to
substitute for DuPont awards) are awarded at market price on the date of grant,
have a ten year life, and generally vest one year from date of grant with
one-third becoming exercisable each of the first three years. For certain senior
management, shares otherwise receivable from the exercise of nonqualified
options with respect to Class A Common Stock granted under the 1998 Stock and
Performance Incentive Plan of Conoco to substitute for cancelled 1998 DuPont
stock options, as well as incremental new Conoco stock options granted at the
date of the Offerings, can be deferred as stock units for a designated future
delivery. The maximum number of shares of common stock and stock options granted
under the plan is limited to the higher of 20 million or 3.3 percent of
outstanding shares of Class A and Class B Common Stock. Awards made in
substitution for DuPont awards do not count against the number of shares
available under the plan. At December 31, 1998, 16,850,266 shares of Class A
Common Stock were available for issuance under the plan.

The Company adopted the 1998 Key Employee Stock Performance Plan to attract
and retain employees by enhancing the proprietary and personal interests of
employees in the success and profitability of the Company and to grant some
awards in substitution for certain existing DuPont awards in connection with the
Offerings. Awards to employees may be in the form of Company stock options or
SARs, both with respect to Class A Common Stock. Such awards granted under this
plan (except to substitute for DuPont awards) are awarded at market price on the
date of grant, have a ten year life, and generally vest one year from date of
grant with one-third becoming exercisable each of the first three years. The
maximum number of shares of common stock and stock options granted under the
plan is limited to the higher of 18 million or three percent of outstanding
Class A and Class B Common Stock. Awards made in substitution for DuPont awards
do not count against the number of shares available under the plan. At December
31, 1998, 14,484,936 shares of Class A Common Stock were available for issuance
under the plan.

Persons electing to substitute Conoco stock options with respect to Class A
Common Stock for DuPont stock options and persons receiving incremental new
Conoco stock options with respect to Class A Common Stock at the date of the
Offerings under the 1998 Stock and Performance Incentive Plan and the 1998 Key
Employee Stock Performance Plan are eligible for reload options upon the
exercise of stock options, with the condition that shares received from the
exercise of the original option may not be sold for at least five years. Reloads
are granted at the market price on the reload grant date and have a term equal
to the remaining term of the original option. The number of new options granted
under a reload option is equal to the number of shares required to satisfy the
total exercise price of the original option.

The 1998 Global Performance Sharing Plan is a broad-based plan under which
grants of stock options and SARs with respect to Class A Common Stock were made
to certain non-officer employees on the date of the Offerings to encourage a
sense of proprietorship and an active interest in the financial success of
Conoco and its subsidiaries. The stock options and SARs were awarded at the
price of the Offerings ($23 per share), have a ten year life, and become
exercisable in one-third increments on the first, second and third anniversaries
of the grant date. There are no additional shares available for issuance under
this plan.
83
<PAGE> 86
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(DOLLARS IN MILLIONS, EXCEPT PER SHARE)

All stock options granted under Conoco plans are "fixed" and have no
intrinsic value at grant date except for those granted to substitute for
cancelled DuPont options. Accordingly, except for the fourth quarter 1998 charge
related to the one-time offer to cancel DuPont options and substitute Conoco
options, no compensation expense has been recognized for fixed options.

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

<TABLE>
<CAPTION>
FIXED VARIABLE
---------------------- ---------------------
NUMBER WEIGHTED- NUMBER WEIGHTED-
OF AVERAGE OF AVERAGE
SHARES PRICE SHARES PRICE
---------- --------- --------- ---------
<S> <C> <C> <C> <C>
DUPONT OPTIONS
January 1, 1996.................................. 7,811,547 $24.27 -- --
Granted........................................ 1,140,780 39.20 -- --
Exercised...................................... (1,781,277) 23.33 -- --
Forfeited...................................... (95,330) 26.38 -- --
---------- ------ --------- ------
December 31, 1996................................ 7,075,720 $26.88 -- --
Granted........................................ 2,761,416 52.90 1,259,600 $52.50
Exercised...................................... (730,383) 23.97 -- --
Forfeited...................................... (116,325) 50.44 -- --
---------- ------ --------- ------
December 31, 1997................................ 8,990,428 $35.14 1,259,600 $52.50
Granted........................................ 1,241,055 59.53 -- --
Reclassified................................... 629,800 52.50 (629,800) 52.50
Exercised...................................... (460,314) 24.64 -- --
Forfeited...................................... (65,852) 50.68 -- --
---------- ------ --------- ------
October 21, 1998 (Offerings date)................ 10,335,117 $39.50 629,800 $52.50
Cancelled for Conoco options................... (8,291,708) (629,800)
---------- ---------
Retained by DuPont............................. 2,043,409 --
CONOCO OPTIONS
Granted at Offerings date:
For cancelled DuPont options................... 22,551,544 $14.62 1,724,146 $19.18
New awards..................................... 9,721,750 23.00 -- --
Exercised........................................ (41,531) 14.18 -- --
Forfeited........................................ (53,840) 23.00 -- --
---------- ------ --------- ------
December 31, 1998................................ 32,177,923 $17.14 1,724,146 $19.18
</TABLE>

The following table summarizes information concerning outstanding and
exercisable fixed Conoco options at December 31, 1998. For total variable
options outstanding at December 31, 1998, the weighted-average remaining
contractual life was 3.1 years.

<TABLE>
<CAPTION>
EXERCISE PRICE
--------------------------------------------------
$5.89- $8.90- $14.47- $21.73-
$8.41 $12.80 $21.64 $29.58
---------- ---------- ---------- -----------
<S> <C> <C> <C> <C>
Options outstanding......................... 2,766,632 7,335,094 9,281,970 12,794,227
Weighted-average remaining contractual life
(years)................................... 2.9 5.5 7.8 9.6
Weighted-average price...................... $ 7.60 $ 10.02 $ 17.94 $ 22.70
Options exercisable......................... 2,766,632 7,335,094 9,281,970 42,204
Weighted-average price...................... $ 7.60 $ 10.02 $ 17.94 $ 24.22
</TABLE>

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

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

<TABLE>
<CAPTION>
CONOCO DUPONT OPTIONS
OPTIONS ------------------------------------
1998 1998* 1997 1996
----------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Options exercisable at year-end:
Number of shares.......................... 19,425,900 9,113,046 6,229,012 5,934,940
Weighted-average price.................... $ 13.49 $ 36.81 $ 27.26 $ 24.51
Weighted-average fair value of options
granted during the year:
New options............................... $ 4.15 $ 13.85 $ 12.84 $ 9.01
Options substituted for DuPont options.... $ 9.22
</TABLE>

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

* As of the date of the Offerings rather than year-end.

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

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

<TABLE>
<CAPTION>
CONOCO OPTIONS DUPONT OPTIONS
------------------ --------------------------------
1998 1997
FIXED 1998 ---------------- 1996
NEW SUBSTITUTES FIXED FIXED VARIABLE FIXED
---- ----------- ----- ----- -------- -----
<S> <C> <C> <C> <C> <C> <C>
Dividend yield................................ 3.3% 3.3% 2.1% 2.2% 2.2% 2.6%
Volatility.................................... 20.0%* 20.0%* 19.9% 18.6% 18.6% 21.0%
Risk-free interest rate....................... 4.6% 4.4% 5.5% 6.4% 6.4% 5.4%
Expected life (years)......................... 5.8* 3.9* 5.8 5.6 5.7 6.0
</TABLE>

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

* Due to insufficient history, DuPont experience trends have been used to
estimate the volatility of Conoco stock and the expected life for exercise of
Conoco stock options.

The following table sets forth pro forma information as if the Company had
adopted the optional recognition provisions of SFAS No. 123:

<TABLE>
<CAPTION>
1998 1997 1996
---- ----- -----
<S> <C> <C> <C>
Increase (Decrease) in:
Net income.................................................. $157 $ (28) $ (6)
Earnings per share
Basic..................................................... $.33 $(.06) $(.01)
Diluted................................................... $.33 $(.06) $(.01)
</TABLE>

Total fair value underpinning the pro forma disclosure for 1998 presented
above includes the fair value of new DuPont grants and a pro rata portion of new
Conoco grants made at the Offerings date, plus incremental fair value of the
Conoco stock options that were substituted for DuPont stock options granted
after the adoption of SFAS No. 123. The incremental fair value for cancellation
and substitution of stock options originally granted before adoption of SFAS No.
123 is zero because intrinsic value exceeds fair value.

Compensation expense recognized in income for stock-based employee
compensation awards was $229, $26 and $13 for 1998, 1997 and 1996, respectively,
with 1998 including a one-time charge of $236 for the cancellation of DuPont
stock options described above.

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

Prior to the Offerings, 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 ability to assume significant responsibility and
leadership. At the time of the Offerings, 1,131,494 unit options were
outstanding of which 593,722 were cancelled and substituted with comparable SARs
with respect to Conoco Class A Common Stock under the 1998 Key Employee Stock
Performance Plan of Conoco. Effective with the Offerings, no new grants were
made or are planned out of the Conoco Unit Option Plan. At December 31, 1998,
outstanding unit options based on Conoco Class A Common Stock were 1,605,614. At
December 31, 1998 and 1997, outstanding unit options based on DuPont common
stock were 545,724 and 908,532, respectively. At these same dates, related
liability provisions totaled $22 and $27, respectively.

Through the date of the Offerings, 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, $38 in 1997 and $38 in 1996. Awards made for plan years
1998, 1997 and 1996 were $24, $45 and $38, respectively, with awards distributed
in 1999 for the 1998 plan year made out of the 1998 Stock and Performance
Incentive Plan of Conoco based on performance standards set previously in the
DuPont Variable Compensation Plan. Both the DuPont Variable Compensation Plan
and the 1998 Stock and Performance Incentive Plan of Conoco allow future
delivery of stock awards. Employees were offered the opportunity to cancel
DuPont shares granted under previous awards and receive substitute shares of
Conoco Class A Common Stock for designated future delivery under the 1998 Stock
and Performance Incentive Plan of Conoco. At December 31, 1998, 72,345 shares of
DuPont stock and 199,268 shares of Conoco Class A Common Stock are awaiting
delivery. A liability of $4 has been recognized for delivery of DuPont shares.

Awards under the separate Conoco Challenge Program may be granted in cash
to employees not covered by the Variable Compensation Plan. This plan provides
awards based on meeting financial goals and upholding Conoco's core values.
Overall amounts are dependent on Company earnings and cash provided by
operations and are subject to maximum limits as defined by the plan. Amounts
charged against earnings in anticipation of awards to be made later were $22 in
1998, $49 in 1997 and $47 in 1996. Awards made for plan years 1998, 1997 and
1996 were $19, $47 and $47, respectively.

23. PENSIONS AND OTHER POSTRETIREMENT BENEFITS

The Company participates in the DuPont U.S. defined benefit pension plan,
which covers substantially all U.S. employees and has separate defined benefit
pension plans covering certain U.S. and non-U.S. employees. The benefits for
these plans are based primarily on years of service and employees' pay near
retirement. The Company's funding policy is consistent with the funding
requirements of federal laws and regulations.

With respect to the DuPont U.S. defined benefit pension plan, the Company
and DuPont agreed upon an amount of approximately $820 at the date of the
Offerings that will eventually be transferred to a separate trust for the
Company's pension plan. Ninety percent of this amount, adjusted for benefit
payments and investment return from the date of the Offerings, will be
transferred to the Company within six months following the date on which DuPont
owns neither 80 percent of the voting power nor 80 percent of the economic value
of the Common Stock, assuming certain conditions are satisfied. The remainder
will be transferred within a further 90-day period. The adjusted value subject
to transfer was approximately $878 at December 31, 1998. DuPont allocated the
pension obligations based on the Company's individual employees covered and
allocated the unrecognized prior service cost and unrecognized net gain in
proportion to the Company's projected benefit obligation to the total projected
benefit obligation of the DuPont plan. The projected benefit obligation
approximates $871 and $723 at December 31, 1998 and 1997, respectively, and the
prepaid pension asset recognized in the Consolidated Balance Sheet (see Note 13)
is $50 and $71 at December 31, 1998 and 1997, respectively. The net periodic
pension cost components included in the table below are also based on the
foregoing allocation factors.
86
<PAGE> 89
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(DOLLARS IN MILLIONS, EXCEPT PER SHARE)

Pension coverage for employees of the Company's non-U.S. subsidiaries is
provided, to the extent deemed appropriate, 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 retirees and survivors. The associated plans, principally health,
are unfunded, and approved claims are paid from Company funds. Under the terms
of these plans, the Company reserves the right to change, modify or discontinue
the plans. Conoco has communicated to plan participants that any increase in the
annual health care escalation rate above 4.5 percent will be borne by the
participants and, therefore, result in no increase to the accumulated
postretirement benefit obligation or the other postretirement benefits cost.

<TABLE>
<CAPTION>
OTHER
PENSION BENEFITS POSTRETIREMENT BENEFITS
------------------- -------------------------
1998 1997 1996 1998 1997 1996
----- ---- ---- ------ ------ -------
<S> <C> <C> <C> <C> <C> <C>
NET PERIODIC BENEFIT COST
Service cost....................................... $ 65 $ 60 $ 55 $ 7 $ 6 $ 7
Interest cost...................................... 94 88 76 21 18 16
Expected return on plan assets..................... (105) (98) (91) -- -- --
Amortization of prior service cost (credit)........ 9 2 2 (4) (4) (4)
Recognized actuarial loss (gain)................... (4) 1 (5) -- (1) (1)
----- ---- ---- --- --- ---
Net periodic benefit cost.......................... $ 59 $ 53 $ 37 $24 $19 $18
===== ==== ==== === === ===
</TABLE>

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

Information concerning benefit obligations, plan assets, funded status and
recorded values for these plans (excluding the DuPont U.S. defined benefit plan)
follows:

<TABLE>
<CAPTION>
OTHER
POSTRETIREMENT
PENSION BENEFITS BENEFITS
----------------- ---------------
1998 1997 1998 1997
------- ------- ------ ------
<S> <C> <C> <C> <C>
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year..................... $ 682 $ 533 $ 301 $ 242
Service cost................................................ 33 28 7 6
Interest cost............................................... 44 39 21 18
Amendments.................................................. (4) -- -- --
Participant contributions................................... -- -- 3 3
Actuarial (gain) loss....................................... 160 113 43 58
Divestitures and other...................................... (17) (2) -- --
Benefits paid............................................... (32) (29) (25) (26)
----- ----- ----- -----
Benefit obligation at end of year........................... $ 866 $ 682 $ 350 $ 301
===== ===== ===== =====
CHANGE IN PLAN ASSETS
Fair Value of plan assets at beginning of year.............. $ 386 $ 323 $ -- $ --
Actual return on plan assets................................ 61 48 -- --
Employer contribution....................................... 26 28 22 23
Participant contributions................................... -- -- 3 3
Divestitures and other...................................... (14) -- -- --
Benefits paid............................................... (21) (13) (25) (26)
----- ----- ----- -----
Fair Value of plan assets at end of year.................... $ 438 $ 386 $ -- $ --
===== ===== ===== =====
Funded status of plans at end of year....................... $(428) $(296) $(350) $(301)
Unrecognized actuarial loss................................. 240 109 53 14
Unrecognized prior service cost (credit).................... 109 121 (52) (55)
----- ----- ----- -----
Net amount recognized at end of year........................ $ (79) $ (66) $(349) $(342)
===== ===== ===== =====
AMOUNTS RECOGNIZED IN CONSOLIDATED BALANCE SHEET AT END OF
YEAR
Accrued benefit liability:
Short-term (see Note 16).................................. $ -- $ -- $ (18) $ (24)
Long-term (see Note 18)................................... (320) (230) (331) (318)
Deferred pension cost (see Note 13)......................... 109 116 -- --
Accumulated other comprehensive loss(1)..................... 132 48 -- --
----- ----- ----- -----
Net amount recognized..................................... $ (79) $ (66) $(349) $(342)
===== ===== ===== =====
</TABLE>

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

(1) Before reduction for associated deferred tax
savings of $43 and $17 at December 31, 1998
and 1997, respectively (see Note 21).

<TABLE>
<S> <C> <C> <C> <C>
WEIGHTED-AVERAGE ASSUMPTIONS AT END OF YEAR
Discount rate(1)............................................ 6.50% 7.00% 6.50% 7.00%
Rate of compensation increase(1)............................ 5.15% 5.15% 5.15% 5.15%
Expected return on plan assets(1)........................... 9.00% 9.00% -- --
Health care escalation rate................................. -- -- 4.50% 4.50%
</TABLE>

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

(1) Represents rates for U.S. plans; similar economic assumptions were used for
non-U.S. plans, with the exception of the United Kingdom where discount
rates of 6 percent and 7.25 percent were used at year-end 1998 and 1997,
respectively.

88
<PAGE> 91
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(DOLLARS IN MILLIONS, EXCEPT PER SHARE)

At December 31, 1998, U.S. defined benefit plan assets consisted
principally of common stocks, including 471,667 shares of DuPont.

24. INVESTING ACTIVITIES

Purchases of property, plant and equipment in 1997 include $929 for
Upstream natural gas properties in South Texas (see Supplementary Petroleum
Data).

Non-cash additions to property, plant and equipment totaled $162 and $127
for the years 1998 and 1997, respectively.

Proceeds from sales of assets in 1998 include $245 from the sale of certain
Upstream properties in the U.S. and North Sea, $156 for various U.S. Downstream
assets, and $54 from sale of a Downstream office building in Europe. Proceeds in
1997 include $272 from the sale of certain Upstream North Sea properties.

25. FINANCIAL INSTRUMENTS AND OTHER RISK MANAGEMENT ACTIVITIES

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

The Company has established a Financial Risk Management Policy Framework
that provides guidelines for entering into contractual arrangements
(derivatives) to manage the Company's commodity price, foreign currency rate and
interest rate risks. The Conoco Risk Management Committee has ongoing
responsibility for the content of this policy and has principal oversight
responsibility to ensure the Company is in compliance with the policy and 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, the Company's
internal audit group conducts reviews of these risk management activities to
assess the adequacy of internal controls. The audit results are reviewed by 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 the Company is exposed to credit loss in the event of
nonperformance by these counterparties, this exposure is managed through credit
approvals, limits and monitoring procedures and limits to the period over which
unpaid balances are allowed to accumulate. The Company has not experienced
nonperformance by counterparties to these contracts, and no material loss would
be expected from any such nonperformance.

COMMODITY PRICE RISK

These instruments provide a natural extension of the underlying cash market
and are used to physically acquire a portion of supply requirements as well as
to manage pricing of near-term physical requirements. The commodity futures
market has underlying principles of increased liquidity and longer trading
periods than the cash market and is one method of managing price risk in the
energy business.

89
<PAGE> 92
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(DOLLARS IN MILLIONS, EXCEPT PER SHARE)

Conoco's policy is to generally 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 the Company's equity
crude oil and natural gas production as well as refinery margins.

FOREIGN CURRENCY RISK

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

At December 31, 1998, the Company had no open forward exchange contracts.
At December 31, 1997, the Company had open forward exchange contracts designated
as a hedge of firm foreign currency commitments. The notional amount of these
contracts was $50 and the estimated fair value was $38.

INTEREST RATE RISK

Prior to the Offerings, the Company had no significant interest rate risk
to manage. Subsequent to the Offerings, however, the Company intends to manage
any material risk arising from exposure to interest rates by using a combination
of financial derivative instruments as part of a program to manage the fixed and
floating interest rate mix of the total debt portfolio and related overall cost
of borrowing.

FAIR VALUES OF FINANCIAL INSTRUMENTS

The carrying values of most financial instruments are based on historical
costs. The carrying values of marketable securities, receivables, payables and
short-term obligations approximate their fair value because of their short
maturity. Long-term receivables from and long-term borrowings due to related
parties approximate fair value because associated interest rates are market
based. At December 31, 1998, however, long-term borrowings due related parties
included $4,589 at a fixed rate with fair value estimated at $4,624. Excluding
amounts due related parties, the estimated fair value of other long-term
borrowings outstanding at December 31, 1998 and 1997 of $93 and $106,
respectively, was $96 and $108, respectively. These estimates were based on
quoted market prices for the same or similar issues, or the current rates
offered to the Company for issues with the same remaining maturities.

SUMMARY OF OUTSTANDING DERIVATIVE FINANCIAL INSTRUMENTS

Set forth below is a summary of the fair values, carrying amounts and
notional values of outstanding commodity financial instruments at December 31,
1998 and 1997.

Notional amounts represent the face amount of the contractual arrangements
and are not a measure of market or credit exposure. The fair value of swaps and
other over-the-counter instruments are estimated based on quoted market prices
of comparable contracts and approximate the gain or (loss) that would have been

90
<PAGE> 93
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(DOLLARS IN MILLIONS, EXCEPT PER SHARE)

realized if the contracts had been closed out at the balance sheet date.
Carrying amounts represent the receivable (payable) recorded in the Consolidated
Balance Sheet.

<TABLE>
<CAPTION>
FAIR CARRYING NOTIONAL
COMMODITY DERIVATIVES VALUE AMOUNT VALUE
--------------------- ----- -------- --------
<S> <C> <C> <C>
December 31, 1998:
Hedging................................................... $(10) $(6) $ 422
Trading................................................... 2 -- 330
December 31, 1997:
Hedging................................................... $ 10 $12 $1,037
Trading................................................... (2) (1) 1,089
</TABLE>

Estimated fair values for hedging instruments only represent the value of
the hedge component of the transactions and, thus, are not indicative of the
fair value of the Company's overall hedged position.

26. COMMITMENTS AND CONTINGENT LIABILITIES

The Company uses various leased facilities and equipment in its operations.
Future minimum lease payments under noncancelable operating leases are $246,
$226, $216, $199 and $194 for the years 1999, 2000, 2001, 2002 and 2003,
respectively, and $580 for subsequent years, and are not reduced by
noncancelable minimum sublease rentals due in the future in the amount of $69.
Rental expense under operating leases was $198 in 1998, $132 in 1997 and $118 in
1996.

The Company has various purchase commitments for materials, supplies,
services and items of permanent investment incident to the ordinary conduct of
business. In the aggregate, such commitments are not at prices in excess of
current market. In addition, at December 31, 1998, the Company has obligations
under international contracts to purchase, over periods up to 20 years, natural
gas at prices that were in excess of year-end 1998 market prices. No material
annual loss is expected from these long-term commitments.

The Company is subject to various lawsuits and claims involving a variety
of matters including, along with other oil companies, actions challenging oil
and gas royalty payments, severance tax payments and other payments, including
claims based on posted prices, and claims for damages resulting from leaking
underground storage tanks. As a result of the Separation Agreement with DuPont,
the Company 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
Company believes the ultimate liabilities resulting from such lawsuits and
claims may be material to results of operations in the period in which they are
recognized but will not materially affect the consolidated financial position of
the Company.

The Company is also subject to contingencies pursuant to environmental laws
and regulations that in the future may require the Company to take further
action to correct the effects on the environment of prior disposal practices or
releases of petroleum substances by the Company or other parties. The Company
has accrued for certain environmental remediation activities consistent with the
policy set forth in Note 2. The Company has 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. At December 31, 1998 and 1997, such
accrual amounted to $129 and $144, respectively, and, in management's opinion,
was appropriate based on existing facts and circumstances. Under adverse changes
in circumstances, potential liability may exceed amounts accrued. In the event
future monitoring and remediation expenditures are in excess of amounts accrued,
they may be significant to results of operations in the period recognized but
management does not anticipate they will have a material adverse effect on the
consolidated financial position of the Company.

91
<PAGE> 94
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(DOLLARS IN MILLIONS, EXCEPT PER SHARE)

The Company has indirectly guaranteed various debt obligations under
agreements with certain affiliated and other companies to provide specified
minimum revenues from shipments or purchases of products. These indirect
guarantees totaled $18 and $19 at December 31, 1998 and 1997, respectively. The
Company, as of August 1, 1998, terminated a multiparty account banking agreement
that provided for the indirect guarantee of bank account overdrafts of certain
European DuPont subsidiaries. The Company now has a new multiparty banking
agreement that provides for the indirect guarantee of bank account overdrafts
for itself and its subsidiaries. Management believes the exposure under this
agreement is not material. In addition, the Company or DuPont, on behalf of, and
indemnified by, the Company, had directly guaranteed obligations of certain
affiliated companies and others. These guarantees totaled $1,353 and $1,131 at
December 31, 1998 and 1997, respectively. The increase in 1998 is primarily
related to additional financing associated with the construction of drillships
and cogeneration facilities in South Texas. The balance at December 31, 1998,
includes a drillship construction guarantee of $260 that was eliminated through
successful completion in early 1999. No material loss is anticipated by reason
of such agreements and guarantees.

The Company's operations, particularly oil and gas exploration and
production, can be affected by changing economic, regulatory and political
environments in the various countries, including the United States, in which it
operates. In certain locations, host governments have imposed restrictions,
controls and taxes, and in others, political conditions have existed that may
threaten the safety of employees and the Company's continued presence in those
countries. Internal unrest or strained relations between a host government and
the Company or other governments may affect the Company's operations. Those
developments have, at times, significantly affected the Company's operations and
related results and are carefully considered by management when evaluating the
level of current and future activity in such countries.

Areas in which the Company has significant operations include the United
States, the United Kingdom, Norway, Germany, Venezuela, the United Arab
Emirates, Indonesia, Russia, Canada, the Czech Republic, Malaysia and Nigeria.

27. OPERATING SEGMENT AND GEOGRAPHIC INFORMATION

Conoco is involved in both the Upstream and Downstream operating segments
of the petroleum business that comprise the structure used by senior management
to make key operating decisions and assess performance. Activities of the
Upstream operating segment include exploring for, and developing, producing and
selling, crude oil, natural gas and natural gas liquids. Activities of the
Downstream operating segment include refining crude oil and other feedstocks
into petroleum products, buying and selling crude oil and refined products and
transporting, distributing and marketing petroleum products. The Company has
four reporting segments for its Upstream and Downstream operating segments,
reflecting geographic division between the United States and International.
Corporate and Other includes general corporate expenses, financing costs and
other non-operating items, and results for electric power and related-party
insurance operations. The Company sells its products worldwide; however, in
1998, about 57 percent and 39 percent of sales were made in the United States
and Europe, respectively. Major products include crude oil, natural gas and
refined products that are sold primarily in the energy and transportation
markets. The Company's sales are not materially dependent on a single customer
or small group of customers. Transfers between segments are on the basis of
estimated market values.

92
<PAGE> 95
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(DOLLARS IN MILLIONS, EXCEPT PER SHARE)

<TABLE>
<CAPTION>
UPSTREAM DOWNSTREAM
----------------------- ----------------------- CORPORATE
UNITED UNITED AND
SEGMENT INFORMATION STATES INTERNATIONAL STATES INTERNATIONAL OTHER CONSOLIDATED
- ------------------- ------ ------------- ------- ------------- --------- ------------
<S> <C> <C> <C> <C> <C> <C>
1998
Sales and Other Operating Revenues(2)
Refined Products.......................... $ -- $ -- $ 6,082 $7,647 $ -- $13,729
Crude Oil................................. 14 774 2,650 299 -- 3,737
Natural Gas............................... 2,416 723 -- -- -- 3,139
Other..................................... 770 104 217 351 749 2,191
------ ------ ------- ------ ------ -------
Total............................... 3,200 1,601 8,949 8,297 749 22,796
Transfers Between Segments.................. 308 378 89 181 -- --
------ ------ ------- ------ ------ -------
Total Operating Revenues............ $3,508 $1,979 $ 9,038 $8,478 $ 749 $22,796
====== ====== ======= ====== ====== =======
Operating Profit............................ $ 223 $ 482 $ 149 $ 256 $ (379) $ 731
Equity in Earnings of Affiliates............ 1 (14) 56 (20) (1) 22
Corporate Non-Operating Items:
Interest and Debt Expense................. (199) (199)
Interest Income (net of misc. interest
expense)................................ 89 89
Other..................................... 51 51
Provision for Income Taxes.................. (5) (185) (70) (80) 96 (244)
------ ------ ------- ------ ------ -------
Net Income (Loss)(1)........................ $ 219 $ 283 $ 135 $ 156 $ (343) $ 450
====== ====== ======= ====== ====== =======
Capital Employed at December 31:
Excluding Investment in Affiliates........ $2,349 $2,849 $ 1,245 $ 989 $ 384 $ 7,816
Investment in Affiliates.................. 191 371 248 531 22 1,363
------ ------ ------- ------ ------ -------
Total(3)............................ $2,540 $3,220 $ 1,493 $1,520 $ 406 $ 9,179
====== ====== ======= ====== ====== =======
Depreciation, Depletion and Amortization.... $ 383 $ 457 $ 139 $ 133 $ 1 $ 1,113
Dry Hole Costs and Impairment of Unproved
Properties................................ $ 59 $ 104 $ 163
Other Significant Non-Cash Items:
Stock Option Provision.................... $ 236 $ 236
Inventory Write-down to Market............ $ 6 $ 63 $ 28 $ 97
Capital Expenditures and Investments(4)..... $ 788 $1,177 $ 201 $ 332 $ 18 $ 2,516

1997
Sales and Other Operating Revenues(2)
Refined Products.......................... $ -- $ -- $ 7,664 $8,165 $ -- $15,829
Crude Oil................................. 24 1,191 3,483 181 -- 4,879
Natural Gas............................... 2,415 556 -- -- -- 2,971
Other..................................... 909 159 247 293 509 2,117
------ ------ ------- ------ ------ -------
Total............................... 3,348 1,906 11,394 8,639 509 25,796
Transfers Between Segments.................. 599 622 115 191 -- --
------ ------ ------- ------ ------ -------
Total Operating Revenues............ $3,947 $2,528 $11,509 $8,830 $ 509 $25,796
====== ====== ======= ====== ====== =======
Operating Profit............................ $ 489 $1,174 $ 287 $ 185 $ (132) $ 2,003
Equity in Earnings of Affiliates............ 18 (7) 30 (1) 40
Corporate Non-Operating Items:
Interest and Debt Expense................. (36) (36)
Interest Income (net of misc. interest
expense)................................ 77 77
Other..................................... 23 23
Provision for Income Taxes.................. (62) (728) (101) (93) (26) (1,010)
------ ------ ------- ------ ------ -------
Net Income (Loss)(1)........................ $ 445 $ 439 $ 216 $ 91 $ (94) $ 1,097
====== ====== ======= ====== ====== =======
</TABLE>

93
<PAGE> 96
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(DOLLARS IN MILLIONS, EXCEPT PER SHARE)

<TABLE>
<CAPTION>
UPSTREAM DOWNSTREAM
----------------------- ----------------------- CORPORATE
UNITED UNITED AND
SEGMENT INFORMATION (CONT'D) STATES INTERNATIONAL STATES INTERNATIONAL OTHER CONSOLIDATED
- ---------------------------- ------ ------------- ------- ------------- --------- ------------
<S> <C> <C> <C> <C> <C> <C>
Capital Employed at December 31:
Excluding Investment in Affiliates........ $2,390 $2,299 $ 1,421 $1,130 $ 903 $ 8,143
Investment in Affiliates.................. 155 256 226 425 23 1,085
------ ------ ------- ------ ------ -------
Total(3)............................ $2,545 $2,555 $ 1,647 $1,555 $ 926 $ 9,228
====== ====== ======= ====== ====== =======
Depreciation, Depletion and Amortization.... $ 268 $ 578 $ 145 $ 188 $ 1,179
Dry Hole Costs and Impairment of Unproved
Properties................................ $ 63 $ 106 $ 169
Capital Expenditures and Investments(4)..... $1,534 $ 999 $ 227 $ 331 $ 23 $ 3,114
1996
Sales and Other Operating Revenues(2)
Refined Products.......................... $ -- $ -- $ 7,355 $8,598 $ -- $15,953
Crude Oil................................. 29 1,359 2,897 1 -- 4,286
Natural Gas............................... 1,907 471 -- -- -- 2,378
Other..................................... 847 113 293 281 79 1,613
------ ------ ------- ------ ------ -------
Total............................... 2,783 1,943 10,545 8,880 79 24,230
Transfers Between Segments.................. 587 572 125 151 -- --
------ ------ ------- ------ ------ -------
Total Operating Revenues............ $3,370 $2,515 $10,670 $9,031 $ 79 $24,230
====== ====== ======= ====== ====== =======
Operating Profit............................ $ 328 $1,231 $ 244 $ 202 $ (118) $ 1,887
Equity in Earnings of Affiliates............ 11 (41) 8 (3) (25)
Corporate Non-Operating Items:
Interest and Debt Expense................. (74) (74)
Interest Income (net of misc. interest
expense)................................ 124 124
Other..................................... (11) (11)
Provision for Income Taxes.................. (25) (823) (80) (82) (28) (1,038)
------ ------ ------- ------ ------ -------
Net Income (Loss)(1)........................ $ 314 $ 367 $ 172 $ 117 $ (107) $ 863
====== ====== ======= ====== ====== =======
Capital Employed at December 31:
Excluding Investment in Affiliates........ $1,371 $3,042 $ 1,538 $1,195 $ 995 $ 8,141
Investment in Affiliates.................. 105 129 154 315 -- 703
------ ------ ------- ------ ------ -------
Total(3)............................ $1,476 $3,171 $ 1,692 $1,510 $ 995 $ 8,844
====== ====== ======= ====== ====== =======
Depreciation, Depletion and Amortization.... $ 307 $ 485 $ 156 $ 137 $ 1,085
Dry Hole Costs and Impairment of Unproved
Properties................................ $ 65 $ 72 $ 137
Capital Expenditures and Investments(4)..... $ 400 $ 864 $ 218 $ 462 $ 1,944
- ------------
(1) Includes After-Tax Benefits (Charges)
from Special Items:
1998
Asset Sales........................... $ 41 $ 54 $ -- $ 12 $ -- $ 107
Property Impairments.................. (32) (6) -- -- -- (38)
Inventory Write-downs................. (4) -- (40) (19) -- (63)
Employee Separation Costs............. (19) (23) (5) (5) -- (52)
Environmental Litigation Charges...... -- -- (28) -- (14) (42)
Stock Option Provision................ -- -- -- -- (183) (183)
------ ------ ------- ------ ------ -------
Total........................... $ (14) $ 25 $ (73) $ (12) $ (197) $ (271)
====== ====== ======= ====== ====== =======
1997
Asset Sales........................... $ 49 $ 191 $ -- $ -- $ -- $ 240
Property Impairments.................. -- (112) -- (55) -- (167)
Environmental Litigation Charges...... -- -- (23) -- -- (23)
Tax Rate Changes...................... -- 19 -- 11 -- 30
------ ------ ------- ------ ------ -------
Total........................... $ 49 $ 98 $ (23) $ (44) $ -- $ 80
====== ====== ======= ====== ====== =======
</TABLE>

94
<PAGE> 97
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(DOLLARS IN MILLIONS, EXCEPT PER SHARE)

(2) Includes sales of purchased products substantially at cost:

<TABLE>
<CAPTION>
1998 1997 1996
------ ------ ------
<S> <C> <C> <C>
Buy/sell supply transactions settled in cash:
Crude oil................................................. $2,728 $3,566 $2,820
Refined products.......................................... 438 683 729
Natural gas resales......................................... 1,109 773 560
Electric power resales...................................... 729 487 58
</TABLE>

(3) Capital Employed is equivalent to the sum of Stockholders' Equity/Owner's
Net Investment and Borrowings (both short-term and long-term portions).
Borrowings include amounts due 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, such as cash
and cash equivalents, financing-oriented items and aviation investment.

(4) Includes investments in affiliates.

<TABLE>
<CAPTION>
UNITED UNITED OTHER
GEOGRAPHIC INFORMATION STATES KINGDOM GERMANY NORWAY COUNTRIES CONSOLIDATED
- ---------------------- ------- ------- ------- ------ --------- ------------
<S> <C> <C> <C> <C> <C> <C>
1998
Sales and Other Operating Revenues(1)... $12,878 $4,305 $2,881 $ 289 $2,443 $22,796
Long-Lived Assets at December 31(2)..... $ 5,122 $3,577 $ 195 $1,547 $ 972 $11,413
1997
Sales and Other Operating Revenues(1)... $15,229 $4,480 $3,007 $ 406 $2,674 $25,796
Long-Lived Assets at December 31(2)..... $ 4,956 $3,284 $ 168 $1,559 $ 861 $10,828
1996
Sales and Other Operating Revenues(1)... $13,386 $4,241 $3,260 $ 508 $2,835 $24,230
Long-Lived Assets at December 31(2)..... $ 4,086 $3,201 $ 203 $1,757 $ 835 $10,082
</TABLE>

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

(1) Revenues are attributed to countries based on location of the selling
entity.

(2) Represents Net Property, Plant and Equipment.

28. OTHER FINANCIAL INFORMATION

Research and development expenses were $42, $44 and $41 for the years 1998,
1997 and 1996, respectively.

95
<PAGE> 98

SUPPLEMENTAL PETROLEUM DATA
(UNAUDITED)
(DOLLARS IN MILLIONS)

OIL AND GAS PRODUCING ACTIVITIES

Supplemental Petroleum Data disclosures are presented in accordance with
the provisions of Statement of Financial Accounting Standards (SFAS) No. 69,
"Disclosures About Oil and Gas Producing Activities."

Accordingly, volumes of reserves and production exclude royalty interests
of others, and royalty payments are reflected as reductions in revenues.

RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES

<TABLE>
<CAPTION>
TOTAL WORLDWIDE UNITED STATES EUROPE OTHER REGIONS
------------------------ --------------------- ----------------------- ---------------------
1998 1997 1996 1998 1997 1996 1998 1997 1996 1998 1997 1996
------ ------ ------ ----- ----- ----- ----- ------ ------ ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
CONSOLIDATED
COMPANIES
Revenues:
Sales.............. $1,938 $2,603 $2,479 $ 643 $ 787 $ 621 $ 831 $1,181 $1,204 $ 464 $ 635 $ 654
Transfers.......... 646 849 927 272 272 363 374 577 566 -- -- (2)
Exploration(1)....... (380) (457) (404) (128) (134) (151) (108) (131) (159) (144) (192) (94)
Production........... (806) (854) (755) (303) (320) (297) (382) (409) (372) (121) (125) (86)
DD&A................. (799) (827) (770) (345) (246) (282) (372) (419) (440) (82) (162)(2) (48)
Other(3)............. 148 321 69 104 106 48 48 215 (1) (4) -- 22
Income taxes......... (201) (847) (912) (36) (109) (47) (100) (393) (436) (65) (345) (429)
------ ------ ------ ----- ----- ----- ----- ------ ------ ----- ----- -----
Results of
operations....... 546 788 634 207 356 255 291 621 362 48 (189) 17
EQUITY AFFILIATES
Results of
operations......... (4) 30 32 4 7 7 5 29 25 (13) (6) --
------ ------ ------ ----- ----- ----- ----- ------ ------ ----- ----- -----
Total........ $ 542 $ 818 $ 666 $ 211 $ 363 $ 262 $ 296 $ 650 $ 387 $ 35 $(195) $ 17
====== ====== ====== ===== ===== ===== ===== ====== ====== ===== ===== =====
</TABLE>

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

(1) Includes exploration operating expenses, dry hole costs, impairment of
unproved properties and depreciation.

(2) Includes charges of $112 for impairment of non-revenue producing properties.

(3) Includes gain/(loss) on disposal of fixed assets and other miscellaneous
revenues and expenses.

96
<PAGE> 99

SUPPLEMENTAL PETROLEUM DATA
(UNAUDITED)
(DOLLARS IN MILLIONS)

COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT
ACTIVITIES(1)

<TABLE>
<CAPTION>
TOTAL WORLDWIDE UNITED STATES EUROPE OTHER REGIONS
------------------------ --------------------- ------------------- --------------------
1998 1997 1996 1998 1997 1996 1998 1997 1996 1998 1997 1996
------ ------ ------ ---- ------ ---- ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
CONSOLIDATED COMPANIES
Property acquisitions
Proved(2)........................ $ 254 $ 152 $ 21 $ 24 $ 148 $ 14 $230(3) $ -- $ -- $ -- $ 4 $ 7
Unproved......................... 93 831 42 55 723(4) 41 25 95 -- 13 13 1
Exploration....................... 436 450 445 119 107 144 114 135 169 203 208 132
Development....................... 1,019 921 828 542 289 203 403 568 543 74 64 82
------ ------ ------ ---- ------ ---- ---- ---- ---- ---- ---- ----
Total...................... 1,802 2,354 1,336 740 1,267 402 772 798 712 290 289 222
EQUITY AFFILIATES
Total Equity Affiliates........... 564 263 19 30 12 5 2 2 14 532(5) 249(5) --
------ ------ ------ ---- ------ ---- ---- ---- ---- ---- ---- ----
Total...................... $2,366 $2,617 $1,355 $770 $1,279 $407 $774 $800 $726 $822 $538 $222
====== ====== ====== ==== ====== ==== ==== ==== ==== ==== ==== ====
</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) Includes acquisition costs associated with petroleum reserves acquired in
the North Sea.

(4) Includes acquisition costs associated with gas reserves acquired in the
South Texas Lobo trend.

(5) Represents Conoco's equity share of the Petrozuata heavy oil venture in
Venezuela.

CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES
<TABLE>
<CAPTION>
TOTAL WORLDWIDE UNITED STATES EUROPE
--------------------------- ------------------------- -------------------------
1998 1997 1996 1998 1997 1996 1998 1997 1996
------- ------- ------- ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
CONSOLIDATED COMPANIES
Gross costs:
Proved properties..... $13,488 $12,420 $11,914 $5,013 $4,676 $4,255 $6,942(1) $6,276 $6,268
Unproved properties... 1,159 1,491 913 634 774(2) 262 262 432 444
Less: Accumulated
DD&A.................. 7,469 7,201 6,886 2,983 2,907 2,816 3,182 3,008 2,954
------- ------- ------- ------ ------ ------ ------ ------ ------
Total net
costs.......... 7,178 6,710 5,941 2,664 2,543 1,701 4,022 3,700 3,758
EQUITY AFFILIATES
Net costs of equity
affiliates............ 976 441 199 66 45 37 132 147 162
------- ------- ------- ------ ------ ------ ------ ------ ------
Total........... $ 8,154 $ 7,151 $ 6,140 $2,730 $2,588 $1,738 $4,154 $3,847 $3,920
======= ======= ======= ====== ====== ====== ====== ====== ======

<CAPTION>
OTHER REGIONS
--------------------------
1998 1997 1996
------ ------ ------
<S> <C> <C> <C>
CONSOLIDATED COMPANIES
Gross costs:
Proved properties..... $1,533 $1,468 $1,391
Unproved properties... 263 285 207
Less: Accumulated
DD&A.................. 1,304 1,286 1,116
------ ------ ------
Total net
costs.......... 492 467 482
EQUITY AFFILIATES
Net costs of equity
affiliates............ 778(3) 249(3) --
------ ------ ------
Total........... $1,270 $ 716 $ 482
====== ====== ======
</TABLE>

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

(1) Includes acquisition costs associated with petroleum reserves acquired in
the North Sea.

(2) Includes acquisition costs associated with gas reserves acquired in the
South Texas Lobo trend.

(3) Represents Conoco's equity share of the Petrozuata heavy oil venture in
Venezuela.

97
<PAGE> 100

SUPPLEMENTAL PETROLEUM DATA
(UNAUDITED)
(IN MILLIONS OF BARRELS)

ESTIMATED PROVED RESERVES OF OIL(1)

<TABLE>
<CAPTION>
TOTAL WORLDWIDE UNITED STATES EUROPE OTHER REGIONS
-------------------- ------------------ ------------------ ------------------
1998 1997 1996 1998 1997 1996 1998 1997 1996 1998 1997 1996
----- ----- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
PROVED RESERVES OF
CONSOLIDATED COMPANIES
Beginning of year............. 893 926 933 277 299 294 421 413 408 195 214 231
Revisions and other changes... 42 54 55 14 3 11 20 43 36 8 8 8
Extensions and discoveries.... 41 62 75 15 12 31 6 44 35 20 6 9
Improved recovery............. 14 3 4 -- 3 4 11 -- -- 3 -- --
Purchase of reserves(2)....... 8 5 (1) -- 4 (1) 8 1 -- -- -- --
Sale of reserves(3)........... (16) (27) (12) (16) (11) (10) -- (16) -- -- -- (2)
Production.................... (119) (130) (128) (29) (33) (30) (56) (64) (66) (34) (33) (32)
----- ----- ---- --- --- --- --- --- --- --- --- ---
End of year(4)................ 863 893 926 261 277 299 410 421 413 192 195 214
----- ----- ---- --- --- --- --- --- --- --- --- ---
PROVED RESERVES OF EQUITY
AFFILIATES
Beginning of year............. 731 47 44 -- -- -- 51 47 44 680 -- --
Revisions and other changes... 5 10 8 -- -- -- 5 10 8 -- -- --
Extensions and discoveries.... -- 680 -- -- -- -- -- -- -- -- 680(5) --
Production.................... (8) (6) (5) -- -- -- (6) (6) (5) (2) -- --
----- ----- ---- --- --- --- --- --- --- --- --- ---
End of year................... 728 731 47 -- -- -- 50 51 47 678 680 --
----- ----- ---- --- --- --- --- --- --- --- --- ---
Total................. 1,591 1,624 973 261 277 299 460 472 460 870 875 214
===== ===== ==== === === === === === === === === ===
PROVED DEVELOPED RESERVES OF
CONSOLIDATED COMPANIES
Beginning of year............. 600 630 684 242 258 265 174 185 217 184 187 202
End of year................... 622 600 630 222 242 258 228 174 185 172 184 187
PROVED DEVELOPED RESERVES OF
EQUITY AFFILIATES
Beginning of year............. 43 39 32 -- -- -- 43 39 32 -- -- --
End of year................... 92 43 39 -- -- -- 42 43 39 50 -- --
</TABLE>

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

(1) Oil reserves comprise crude oil and condensate and natural gas liquids
expected to be removed for the Company's account from its natural gas
deliveries.

(2) Includes reserves acquired through property trades.

(3) Includes reserves disposed of through property trades.

(4) Includes reserves of 123, 87 and 89 at year-end 1998, 1997 and 1996,
respectively, attributable to Conoco Oil & Gas Associates L.P. in which
there is a minority interest with an approximate 20 percent average revenue
share (see Note 19).

(5) Represents Conoco's equity share of the Petrozuata heavy oil venture in
Venezuela.

98
<PAGE> 101

SUPPLEMENTAL PETROLEUM DATA
(UNAUDITED)
(IN BILLION CUBIC FEET)

ESTIMATED PROVED RESERVES OF GAS

<TABLE>
<CAPTION>
TOTAL WORLDWIDE UNITED STATES EUROPE OTHER REGIONS
--------------------- ---------------------- --------------------- ---------------------
1998 1997 1996 1998 1997 1996 1998 1997 1996 1998 1997 1996
---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
PROVED RESERVES OF
CONSOLIDATED COMPANIES
Beginning of year........... 5,491 5,063 4,709 2,235 1,822 1,891 3,060 3,068 2,649 196 173 169
Revisions and other
changes................... 25 134 41 18 -- 79 (20) 97 (39) 27 37 1
Extensions and
discoveries............... 961 518 780 624 453 176 111 59 574 226 6 30
Improved recovery........... -- 1 -- -- 1 -- -- -- -- -- -- --
Purchase of reserves(1)..... 116 270 41 4 264(2) 3 112 -- 36 -- 6 2
Sale of reserves(3)......... (281) (62) (71) (243) (46) (57) (38) (7) -- -- (9) (14)
Production.................. (510) (433) (437) (319) (259) (270) (172) (157) (152) (19) (17) (15)
----- ----- ----- ----- ----- ----- ----- ----- ----- --- --- ---
End of year(4).............. 5,802 5,491 5,063 2,319 2,235 1,822 3,053 3,060 3,068 430 196 173
----- ----- ----- ----- ----- ----- ----- ----- ----- --- --- ---
PROVED RESERVES OF EQUITY
AFFILIATES
Beginning of year........... 370 333 339 370 333 339 -- -- -- -- -- --
Revisions and other
changes................... (12) (6) -- (12) (6) -- -- -- -- -- -- --
Extensions and
discoveries............... 1 49 -- 1 49 -- -- -- -- -- -- --
Purchase of reserves........ 27 -- -- 27 -- -- -- -- -- -- -- --
Production.................. (5) (6) (6) (5) (6) (6) -- -- -- -- -- --
----- ----- ----- ----- ----- ----- ----- ----- ----- --- --- ---
End of Year................. 381 370 333 381 370 333 -- -- -- -- -- --
----- ----- ----- ----- ----- ----- ----- ----- ----- --- --- ---
Total............... 6,183 5,861 5,396 2,700 2,605 2,155 3,053 3,060 3,068 430 196 173
===== ===== ===== ===== ===== ===== ===== ===== ===== === === ===
PROVED DEVELOPED RESERVES OF
CONSOLIDATED COMPANIES
Beginning of year........... 3,061 2,843 2,933 1,801 1,672 1,733 1,091 1,041 1,071 169 130 129
End of year................. 3,991 3,061 2,843 1,828 1,801 1,672 1,954 1,091 1,041 209 169 130
PROVED DEVELOPED RESERVES OF
EQUITY AFFILIATES
Beginning of year........... 40 36 40 40 36 40 -- -- -- -- -- --
End of year................. 66 40 36 66 40 36 -- -- -- -- -- --
</TABLE>

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

(1) Includes reserves acquired through property trades.

(2) Includes reserves acquired in the South Texas Lobo trend.

(3) Includes reserves disposed of through property trades.

(4) Includes reserves of 121, 115 and 104 at year-end 1998, 1997 and 1996,
respectively, attributable to Conoco Oil & Gas Associates L.P. in which
there is a minority interest with an approximate 20 percent average revenue
share (see Note 19).

99
<PAGE> 102

SUPPLEMENTAL PETROLEUM DATA
(UNAUDITED)

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVES

The information on the following page 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 sales prices, costs and statutory income tax
rates and a 10 percent annual discount rate. Specifically, the per-barrel oil
sales prices used to calculate the December 31, 1998, data averaged $9.40 for
the United States, $10.69 for Europe and $10.67 for Other Regions, and the gas
prices per thousand cubic feet averaged approximately $1.70 for the United
States, $2.29 for Europe and $1.90 for Other Regions. Because prices used in the
calculation are as of December 31, the standardized measure could vary
significantly from year to year based on market conditions at that specific
date.

The projections should not be viewed as realistic estimates of future cash
flows nor should the "standardized measure" be interpreted as representing
current value to the Company. 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 may also vary. The Company'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 includes
probable as well as proved reserves, and on different price and cost assumptions
from those reflected in this information.

100
<PAGE> 103

SUPPLEMENTAL PETROLEUM DATA
(UNAUDITED)
(DOLLARS IN MILLIONS)

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVES
<TABLE>
<CAPTION>
TOTAL WORLDWIDE UNITED STATES EUROPE
---------------------------- --------------------------- ---------------------------
1998 1997 1996 1998 1997 1996 1998 1997 1996
------- ------- -------- ------- ------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
CONSOLIDATED COMPANIES
Future cash flows:
Revenues............. $20,340 $26,666 $ 34,366 $ 6,148 $ 8,355 $10,044 $11,376 $15,119 $19,364
Production costs..... (8,271) (9,251) (10,406) (2,665) (2,997) (3,085) (4,742) (5,387) (6,378)
Development costs.... (1,548) (1,586) (1,669) (370) (446) (283) (823) (1,094) (1,294)
Income tax expense... (3,904) (6,822) (10,364) (546) (1,175) (2,041) (2,239) (3,921) (5,179)
------- ------- -------- ------- ------- ------- ------- ------- -------
Future net cash
flows................ 6,617 9,007 11,927 2,567 3,737 4,635 3,572 4,717 6,513
Discounted to present
value at a 10% annual
rate................. (2,414) (3,384) (4,638) (1,055) (1,552) (2,088) (1,151) (1,679) (2,317)
------- ------- -------- ------- ------- ------- ------- ------- -------
Total(1)....... 4,203 5,623 7,289 1,512 2,185 2,547 2,421 3,038 4,196
------- ------- -------- ------- ------- ------- ------- ------- -------
EQUITY AFFILIATES
Future cash flows:
Revenues............. 5,327 8,520 1,971 1,001 893 968 427 651 1,003
Production costs..... (2,228) (2,640) (597) (346) (267) (242) (266) (315) (355)
Development costs.... (1,086) (1,300) (180) (191) (174) (157) (28) (30) (23)
Income tax expense... (425) (1,090) (496) (166) (161) (193) (63) (170) (303)
------- ------- -------- ------- ------- ------- ------- ------- -------
Future net cash
flows................ 1,588 3,490 698 298 291 376 70 136 322
Discounted to present
value at a 10% annual
rate................. (1,327) (2,886) (398) (220) (226) (277) (9) (44) (121)
------- ------- -------- ------- ------- ------- ------- ------- -------
Total.......... 261 604 300 78 65 99 61 92 201
------- ------- -------- ------- ------- ------- ------- ------- -------
Total.......... $ 4,464 $ 6,227 $ 7,589 $ 1,590 $ 2,250 $ 2,646 $ 2,482 $ 3,130 $ 4,397
======= ======= ======== ======= ======= ======= ======= ======= =======

<CAPTION>
OTHER REGIONS
---------------------------
1998 1997 1996
------- ------- -------
<S> <C> <C> <C>
CONSOLIDATED COMPANIES
Future cash flows:
Revenues............. $ 2,816 $ 3,192 $ 4,958
Production costs..... (864) (867) (943)
Development costs.... (355) (46) (92)
Income tax expense... (1,119) (1,726) (3,144)
------- ------- -------
Future net cash
flows................ 478 553 779
Discounted to present
value at a 10% annual
rate................. (208) (153) (233)
------- ------- -------
Total(1)....... 270 400 546
------- ------- -------
EQUITY AFFILIATES
Future cash flows:
Revenues............. 3,899 6,976 --
Production costs..... (1,616) (2,058) --
Development costs.... (867) (1,096) --
Income tax expense... (196) (759) --
------- ------- -------
Future net cash
flows................ 1,220 3,063 --
Discounted to present
value at a 10% annual
rate................. (1,098) (2,616) --
------- ------- -------
Total.......... 122 447 --
------- ------- -------
Total.......... $ 392 $ 847 $ 546
======= ======= =======
</TABLE>

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

(1) Includes $263, $372 and $686 at year-end 1998, 1997 and 1996, respectively,
attributable to Conoco Oil & Gas Associates L.P. in which there is a
minority interest with an approximate 20 percent average revenue share (see
Note 19).

SUMMARY OF CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO
PROVED OIL AND GAS RESERVES

<TABLE>
<CAPTION>
CONSOLIDATED COMPANIES EQUITY AFFILIATES
----------------------------- ---------------------------
1998 1997 1996 1998 1997 1996
------- ------- ------- ------- ------- -----
<S> <C> <C> <C> <C> <C> <C>
Balance at January 1........................................ $ 5,623 $ 7,289 $ 5,158 $ 604 $ 300 $ 151
Sales and transfers of oil and gas produced, net of
production costs.......................................... (1,778) (2,583) (2,647) (2) (56) (73)
Development costs incurred during the period................ 1,019 921 828 555 218 20
Net changes in prices and in development and production
costs..................................................... (3,948) (4,974) 2,525 (1,155) (1,242) 119
Extensions, discoveries and improved recovery, less related
costs..................................................... 838 818 1,630 1 1,181 4
Revisions of previous quantity estimates.................... 189 439 553 2 37 83
Purchases (sales) of reserves in place -- net............... (92) 36 (54) 18 -- --
Accretion of discount....................................... 916 1,312 931 84 55 25
Net change in income taxes.................................. 1,541 2,285 (1,676) 128 16 (152)
Other....................................................... (105) 80 41 26 95 123
------- ------- ------- ------- ------- -----
Balance at December 31...................................... $ 4,203 $ 5,623 $ 7,289 $ 261 $ 604 $ 300
======= ======= ======= ======= ======= =====
</TABLE>

101
<PAGE> 104

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>
1998
Sales and Other Operating Revenues(1)........... $5,736 $5,612 $5,916 $5,532
Cost of Goods Sold and Other Expenses(2)........ 5,327 5,374 5,620 5,954
Interest and Debt Expense....................... 1 -- 107 91
Net Income (Loss)............................... 316(5) 214(6) 183 (263)(7)
Earnings Per Share
Basic(3)...................................... $ .72 $ .49 $ .42 $ (.45)
Diluted(3).................................... $ .72 $ .49 $ .42 $ (.45)
Market Price of Common Stock(4)
High.......................................... $25 3/4
Low........................................... $19 3/8
1997
Sales and Other Operating Revenues(1)........... $6,560 $5,915 $6,671 $6,650
Cost of Goods Sold and Other Expenses(2)........ 5,898 5,501 6,269 6,452
Interest and Debt Expense....................... 15 9 7 5
Net Income...................................... 341 246(8) 289(9) 221(10)
Earnings Per Share
Basic(3)...................................... $ .78 $ .56 $ .66 $ .51
Diluted(3).................................... $ .78 $ .56 $ .66 $ .51
</TABLE>

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

(1) Excludes other income of $98, $40, $113 and $121 in each of the quarters in
1998 and $55, $70, $28 and $314 in each of the quarters in 1997.

(2) Excludes provision for income taxes.

(3) Earnings per share for the year may not equal the sum of the quarterly
earnings per share due to changes in average shares outstanding. Earnings
per share for the periods prior to the Offerings was calculated using only
Class B Common Stock, as required by SFAS No. 128 (see Note 8 to the
Consolidated Financial Statements). Management believes, considering the
substance of the Offerings, a more meaningful presentation of EPS would be
to reflect, as if outstanding for all periods presented, both Class A and
Class B Common Stock and certain dilutive effects. Using this presentation,
but excluding any pro forma adjustment for additional interest expense on
the dividend Note (see Note 3 to the Consolidated Financial Statements),
quarterly EPS would be as follows:

<TABLE>
<CAPTION>
QUARTER ENDED
-------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- ------- ------------ -----------
<S> <C> <C> <C> <C>
1998
Basic..................................... $ .50 $ .34 $ .29 $ (.42)
Diluted................................... $ .50 $ .34 $ .29 $ (.42)
1997
Basic..................................... $ .54 $ .39 $ .46 $ .35
Diluted................................... $ .54 $ .39 $ .45 $ .35
</TABLE>

(4) The Company's Class A Common Stock is listed on the New York Stock Exchange
(trading symbol: COC) and commenced trading on October 22, 1998. Prices are
as reported in the New York Stock Exchange, Inc. Composite Transactions
Tape.

(5) Includes gain of $23 ($.04 per share-diluted) from sale of certain Upstream
properties.

(6) Includes net benefit of $3 ($.01 per share-diluted) reflecting: tax benefit
of $31 from sale of an international Upstream subsidiary and a $28 charge
for U.S. Downstream environmental litigation.

102
<PAGE> 105

(7) Includes net charge of $297 ($.47 per share-diluted) reflecting: charges of
$183 for non-cash stock option compensation expense related to the
Offerings, $63 for write-down of inventories to market, $52 principally for
employee separation costs, $38 for impairment of long-lived Upstream
properties and $14 for environmental litigation charges and gains of $41
from the sale of U.S. producing properties and $12 from sale of an office
building.

(8) Includes gain of $24 ($.04 per share-diluted) from sale of U.S. producing
properties.

(9) Includes net benefit of $37 ($.05 per share-diluted) reflecting: gain of
$30 from sale of North Sea properties, benefit of $30 from foreign tax rate
changes, and charge of $23 for environmental litigation charges.

(10) Includes a net benefit of $19 ($.03 per share-diluted) reflecting: a gain
of $186 from the sale of North Sea and U.S. Upstream properties, a charge
of $112 for impairment of non-revenue producing properties, and a charge of
$55 for write-down of an office building held for sale.

103
<PAGE> 106

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

None

PART III

Information with respect to the following items is incorporated by
reference to the Company's 1999 Annual Meeting Proxy Statement to be filed in
connection with the Annual Meeting of Stockholders to be held May 12, 1999.
However, the information regarding executive officers is contained in Part I of
this report pursuant to General Instruction G of this form.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information required by this item will be set forth under the captions
"Proposal I -- Election of Directors" and "Stock Ownership of Directors and
Executive Officers -- Section 16(a) Beneficial Ownership Reporting Compliance"
in Conoco's definitive proxy statement (the "1999 Proxy Statement") for its
annual meeting of stockholders to be held on May 12, 1999, which sections are
incorporated herein by reference.

Pursuant to General Instruction G to Form 10-K, the information required by
this item with respect to executive officers of Conoco is set forth in Part I of
this report.

ITEM 11. EXECUTIVE COMPENSATION

The information required by this item will be set forth in the sections
entitled "Proposal I -- Election of Directors -- Board Compensation" and
"Compensation of Executive Officers" in the 1999 Proxy Statement, which sections
are incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The information required by this item will be set forth in the sections
entitled "Principal Stockholders" and "Stock Ownership of Directors and
Executive Officers" in the 1999 Proxy Statement, which sections are incorporated
herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information required by this item will be set forth in the section
entitled "Additional Information -- Arrangements between Conoco and DuPont" in
the 1999 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 -- none required.

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

104
<PAGE> 107

net assets of subsidiaries combined with the Company's equity in the
undistributed earnings of affiliated companies does not exceed 25 percent
of consolidated net assets at December 31, 1998.

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.

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
-------------- -----------
<C> <S>
3.1 -- Second Amended and Restated Certificate of Incorporation
of Conoco Inc.***
3.2 -- By-Laws of Conoco Inc. as amended October 29, 1998***
4.1 -- Specimen Certificate for shares of Class A Common Stock
of the Registrant**
4.2 -- Specimen Certificate for shares of Class B Common Stock
of the Registrant**
4.3 -- Preferred Share Purchase Rights Agreement**
4.4 -- Promissory Note and Guaranty to DuPont Energy Company**
4.5 -- Promissory Note to DuPont Chemical and Energy Operations
Inc. (Norway)**
4.6 -- Promissory Note to DuPont Chemical and Energy Operations
Inc. (United Kingdom and Poland)**
4.7 -- Promissory Note to DuPont Energy Company**
4.8 -- Revolving Credit Agreement**
10.1 -- Restructuring, Transfer and Separation Agreement between
DuPont and Conoco**
10.2 -- Tax Sharing Agreement between DuPont and Conoco**
10.3 -- Employee Matters Agreement between DuPont and Conoco**
10.4 -- Information Systems and Telecommunications Carrier
Transitional Services and Facilities Lease Agreement
between DuPont and Conoco**
10.5 -- Transitional Services Agreement between DuPont and the
Company**
10.6 -- Registration Rights Agreement between DuPont and Conoco**
10.7 -- Natural Gas Supply Agreement between DuPont and Conoco**
10.8# -- Severance Agreement, dated May 10, 1998, between Conoco
and Archie W. Dunham**
10.9# -- 1998 Stock and Performance Incentive Plan**
10.10# -- 1998 Key Employee Stock Performance Plan**
10.11 -- Humber DME Agreement**
10.12# -- Deferred Compensation Plan for Nonemployee Directors**
10.13# -- Conoco Inc. Key Employee Severance Plan**
10.14# -- Conoco Inc. Key Employee Temporary Severance Plan**
10.15# -- Conoco Salary Deferral & Savings Restoration Plan**
10.16# -- Directors' Charitable Gift Plan**
10.17 -- Motor Carrier Contract between Sentinel and Conoco**
10.18 -- Mont Belvieu Agreements**
11 -- Statement re Computation of Per Share Earnings*
21.1 -- List of Principal Subsidiaries of the Registrant****
</TABLE>

105
<PAGE> 108

<TABLE>
<CAPTION>
EXHIBIT NUMBER DESCRIPTION
-------------- -----------
<C> <S>
23.1 -- Consent of PricewaterhouseCoopers LLP*
24 -- Power of Attorney****
27 -- Financial Data Schedule*
99 -- Consent of Solomon Associates*
</TABLE>

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

# Management contract or compensatory plan or arrangement required to be
filed as an exhibit to this Form 10-K.

* Filed herein.

** Incorporated by reference to exhibit of the same number filed previously as
part of Form S-1 or Amendments thereto.

*** Incorporated by reference to exhibit of the same number filed as part of
Form 10-Q filed November 18, 1998.

**** Previously filed.

(b) Reports on Form 8-K

None

106
<PAGE> 109

SIGNATURES

Pursuant to the requirements of Section 13 of the Securities Exchange Act
of 1934, the registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized and in the capacities indicated,
as of the 12th day of March 1999.

CONOCO INC.

By: /s/ ROBERT W. GOLDMAN By: /s/ W. DAVID WELCH
- ------------------------------------------ ---------------------------------------
Robert W. Goldman W. David Welch
Senior Vice President, Finance, and Controller
Chief Financial Officer
</TABLE>

107
<PAGE> 110

INDEX TO EXHIBITS

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

# Management contract or compensatory plan or arrangement required to be
filed as an exhibit to this Form 10-K.

* Filed herein.

** Incorporated by reference to exhibit of the same number filed previously as
part of Form S-1 or Amendments thereto.

*** Incorporated by reference to exhibit of the same number filed as part of
Form 10-Q filed November 18, 1998.

**** Previously filed.

<PAGE> 1
EXHIBIT 11

STATEMENT RE COMPUTATION OF PER SHARE EARNINGS
(DOLLARS IN MILLIONS, EXCEPT PER SHARE)

YEARS ENDED DECEMBER 31
----------------------------------------------------------------------------
1998 1997 1996 1995 1994(1)
------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
Net Income $ 450 $ 1,097 $ 863 $ 575 $ 422

Weighted Average Shares Outstanding
(excluding Treasury Stock)--Basic
Class A................................ 37,283,059 -- -- -- --
Class B................................ 436,543,573 436,543,573 436,543,573 436,543,573 436,543,573
------------ ------------ ------------ ------------ ------------
Total Basic........................ 473,826,632 436,543,573 436,543,573 436,543,573 436,543,573

Shares assumed to be issued due
to stock options........................... 1,659,816 -- -- -- --
------------ ------------ ------------ ------------ ------------

Adjusted average number of Class A
and Class B common shares and share
equivalents-Diluted........................ 475,486,448 436,543,573 436,543,573 436,543,573 436,543,573

Earnings per share:*
- Diluted.............................. $ .95 $ 2.51 $ 1.98 $ 1.32 $ .97

- Basic................................ $ .95 $ 2.51 $ 1.98 $ 1.32 $ .97
</TABLE>

(1) Unaudited

* Earnings per share (EPS) for the periods prior to the Offerings was
calculated using only Class B Common Stock as required by SFAS 128.
However, since the substance of the Offerings was the sale of
approximately 30% ownership of Conoco, management believes a more
meaningful presentation of EPS for periods prior to the Offerings would
include both Class A and Class B Common Stock, including stock options
with respect to Class A Common Stock, as though outstanding for all prior
periods (see Note 8 to the Consolidated Financial Statements). On this
basis, diluted EPS would be $.71, $1.72, $1.36, $.90, and $.66 for the
years 1998, 1997, 1996, 1995 and 1994 respectively.

<PAGE> 1

EXHIBIT 23.1

CONSENT OF INDEPENDENT ACCOUNTANTS

We hereby consent to the incorporation by reference in the Prospectus
constituting part of the Registration Statement on Amendment No. 1 to Form S-3
(No. 333-72291) and the incorporation by reference in the Registration
Statements on Form S-8 (Nos. 333-65977, 333-65979, 333-65981, 333-65983,
333-65985, 333-69253) of our report dated February 15, 1999 appearing on page 61
of this Form 10-K/A.

PRICEWATERHOUSECOOPERS LLP

Houston, Texas
March 11, 1999

<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE ANNUAL
FINANCIAL STATEMENTS FOR THE YEAR 1998 AND 1997 OF CONOCO INC. AND CONSOLIDATED
SUBSIDIARIES. THE SCHEDULE IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<RESTATED>

<S> <C> <C>
<PERIOD-TYPE> 12-MOS 12-MOS
<FISCAL-YEAR-END> DEC-31-1998 DEC-31-1997
<PERIOD-START> JAN-01-1998 JAN-01-1997
<PERIOD-END> DEC-31-1998 DEC-31-1997
<CASH> 394 1,147
<SECURITIES> 0 7
<RECEIVABLES> 1,191<F1> 1,987<F1>
<ALLOWANCES> 0 0
<INVENTORY> 807 830
<CURRENT-ASSETS> 2,770 4,207
<PP&E> 22,094 21,229
<DEPRECIATION> 10,681 10,401
<TOTAL-ASSETS> 16,075 17,062
<CURRENT-LIABILITIES> 2,725 3,640
<BONDS> 4,689<F2> 1,556<F2>
0 0
0 0
<COMMON> 6 0
<OTHER-SE> 4,438 7,896
<TOTAL-LIABILITY-AND-EQUITY> 16,075 17,062
<SALES> 22,796 25,796
<TOTAL-REVENUES> 23,168 26,263
<CGS> 13,840<F3> 16,226<F3>
<TOTAL-COSTS> 22,275<F4> 24,120<F4>
<OTHER-EXPENSES> 0 0
<LOSS-PROVISION> 0 0
<INTEREST-EXPENSE> 199 36
<INCOME-PRETAX> 694 2,107
<INCOME-TAX> 244 1,010
<INCOME-CONTINUING> 450 1,097
<DISCONTINUED> 0 0
<EXTRAORDINARY> 0 0
<CHANGES> 0 0
<NET-INCOME> 450 1097
<EPS-PRIMARY> .95<F5> 2.51<F5>
<EPS-DILUTED> .95<F5> 2.51<F5>
<FN>
<F1>Includes Notes Receivable - Related Parties
<F2>Includes Long-Term Borrowings-Related Parties of $4,596 and $1,450 for 1998 and
1997, respectively
<F3>Includes Other Expenses
<F4>Cost of Goods Sold and Other Operating Expenses; Selling, General, and
Administrative; Stock Option Provision; Exploration Expense; Depreciation,
Depletion and Amortization; and Taxes other than on Income.
<F5>Basic Earnings Per Share and Diluted Earnings Per Share
</FN>

</TABLE>

<PAGE> 1
EXHIBIT 99

CONSENT OF SOLOMON ASSOCIATES

We hereby consent to the use in the 1998 Form 10-K (amended) of Conoco Inc. of
our name in reference to ranking of the performance of Conoco's European
refineries which appear in such 1998 Amended Form 10-K, to be filed on or
before March 12, 1999. We also consent to the reference to us under the
headings "Downstream" and "European-Refining" and reference to us as "an
independent benchmarking company."

/s/ M. D. HANNAN
- ----------------
M. D. Hannan
President

Solomon Associates, Inc.
March 10, 1999