10-K 1 h94945e10-k.txt CONOCO INC - DECEMBER 31, 2001 2001 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001 COMMISSION FILE NUMBER 1-14521 CONOCO INC. (Exact name of registrant as specified in its charter) DELAWARE 51-0370352 (State or other jurisdiction of (I.R.S. employer incorporation or organization) identification No.) 600 NORTH DAIRY ASHFORD ROAD HOUSTON, TEXAS 77079 (Address of principal executive offices) Registrant's telephone number, including area code: 281-293-1000 ---------- Securities registered pursuant to Section 12(b) of the Act: TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED ------------------------------- ----------------------------------------- Common stock ($.01 par value) New York Stock Exchange, Inc. Preferred share purchase rights New York Stock Exchange, Inc. Securities registered pursuant to Section 12(g) of the Act: NONE Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] Aggregate market value of voting common stock held by nonaffiliates of the registrant (excludes outstanding shares beneficially owned by directors and officers) as of March 1, 2002, was approximately $17,449 million based on the closing price on that date of $27.90, on the New York Stock Exchange, Inc. As of such date, 626,312,581 shares of common stock, $.01 par value, were outstanding. DOCUMENTS INCORPORATED BY REFERENCE (to the extent indicated herein)

INCORPORATED BY (REFERENCE IN PART NO.) ----------------------- Portions of the registrant's proxy statement for the annual ~~meeting~~ III meeting of stockholders to be held on May 821, ~~2001~~2002

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

PAGE PART I ~~PAGE~~ Items 1. and 2. Business and Properties...........................................................~~.....~~ 1 Item 3. Legal Proceedings.................................................................~~.....~~ 3235 Item 4. Submission of Matters to a Vote of Security Holders...............................~~.....~~ 3337 Executive Officers of the Registrant..............................................~~.....~~ 3337 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.............~~.....~~ 3539 Item 6. Selected Financial Data...........................................................~~.....~~ 3640 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations........................................................................~~.....~~ 3741 Item 7A. Quantitative and Qualitative Disclosures About Market Risk........................~~.....~~ 5866 Item 8. Financial Statements and Supplementary Data.......................................~~.....~~ 6070 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure........................................................................~~.....~~ ~~106~~123 PART III Item 10. Directors and Executive Officers of the Registrant................................~~.....~~ ~~106~~123 Item 11. Executive Compensation............................................................~~.....~~ ~~106~~123 Item 12. Security Ownership of Certain Beneficial Owners and Management....................~~.....~~ ~~106~~124 Item 13. Certain Relationships and Related Transactions....................................~~.....~~ ~~106~~124 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K..................~~.....~~ ~~106~~124

i PART I ITEMS 1. AND 2. BUSINESS AND PROPERTIES DISCLOSURE REGARDING FORWARD-LOOKING INFORMATION This annual report on Form 10-K includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can identify our forward-looking statements by the words "expects," "intends," "plans," "projects," "believes," "estimates," "will," "should" and similar expressions. We have based the forward-looking statements relating to our operations on our current expectations, estimates and projections about Conoco and the petroleum industry in general. We caution you that these statements are not guarantees of future performance and involve risks and uncertainties that we cannot predict. In addition, we have based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, our actual outcomes and results may differ materially from what we have expressed or forecasted in the forward-looking statements. Any differences could result from a variety of factors, including the following: o fluctuations in crude oil and natural gas prices as well as refining and marketing margins; o potential failure or delays in achieving expected reserve or production levels from existing and future oil and gas development projects due to operating hazards, drilling risks and the inherent uncertainties in predicting oil and gas reserves and oil and gas reservoir performance; o unsuccessful exploratory drilling activities; o failure of new products and services to achieve market acceptance; o unexpected cost increases or technical difficulties in constructing or modifying company manufacturing and refining facilities; o unexpected difficulties in mining, manufacturing, transporting or refining synthetic crude oil; o ability to meet government regulations; o potential disruption or interruption of our production facilities due to accidents, political events, or terrorism; o international monetary conditions and exchange controls; o liability for remedial actions under environmental regulations; o liability resulting from litigation; o general domestic and international economic and political conditions, including armed hostilities and terrorism; and o changes in tax and other laws applicable to our business. GENERAL Conoco, a major, integrated, global energy company, has three operating segments: upstream, downstream and emerging businesses. Upstream operating segment activities include exploring for, developing, producing and selling crude oil, natural gas and natural gas liquids; and Syncrude mining operations (Canadian Syncrude). Downstream operating segment activities include refining crude oil and other feedstocks into petroleum products; buying and selling crude oil and refined products; and transporting, distributing and marketing petroleum products. Emerging businesses operating segment activities include the development of new businesses beyond our traditional operations. Emerging businesses is currently involved in carbon fibers (Conoco Cevolution(R)); natural gas refining including gas-to-liquids; and international power. Conoco operates in over 40 countries worldwide. As of December 31, 2001, Conoco had proved worldwide oil and gas reserves of 3,299 million barrels-of-oil-equivalent (BOE) and proven Canadian Syncrude reserves of 280 million BOE for a total of 3,579 million BOE, 40 percent of which were natural gas. In this document, natural gas volumes have been converted to BOE using a ratio 1 of six thousand cubic feet (mcf) of natural gas to one barrel of oil. Based on 2001 annual production of 281 million BOE, excluding natural gas liquids from gas plant ownership, Conoco had a reserve life of approximately 12 years as of December 31, 2001. As of December 31, 2001, Conoco owned or had equity interests in nine refineries worldwide, with a total crude distillation capacity of approximately 936,000 barrels per day. Conoco had a marketing network of approximately 7,900 outlets in the United States, Europe and Asia Pacific. In 2001, refined product sales averaged 1,502,000 barrels per day. For the year ended December 31, 2001, Conoco reported net income of $1,589 million, which included a net charge of $234 million for special items, on total revenues of $39,539 million. RECENT DEVELOPMENTS On July 16, 2001, Conoco, through a wholly owned subsidiary, completed the acquisition of all the ordinary shares of Gulf Canada Resources Limited (Gulf Canada), now known as Conoco Canada Resources Limited (Conoco Canada) for approximately $4,571 million in cash plus assumed liabilities and minority interests. For ease of reference, we will refer to Conoco Canada as Gulf Canada. Prior to the acquisition, Gulf Canada was a Canadian-based independent exploration and production company, with primary operations in western Canada, Indonesia, the Netherlands and Ecuador. Subsequent to the acquisition, operational responsibilities for Gulf Canada's interests in Indonesia, the Netherlands and Ecuador were realigned within Conoco's regional organizational structure and operationally Conoco's existing Canadian operations were merged with those of Gulf Canada. On September 21, 2001, Conoco's shareholders approved the combination of our Class A and Class B common stock into a single class of new common stock on a one-for-one basis. The combination was effective on October 8, 2001. On November 18, 2001, Conoco and Phillips Petroleum Company (Phillips) announced that their boards of directors unanimously approved the merger of the two companies. The new company will be named ConocoPhillips. Under the terms of the agreement, Phillips shareholders will receive one share of new ConocoPhillips common stock for each share of Phillips common stock they own and Conoco shareholders will receive .4677 shares of new ConocoPhillips common stock for each share of Conoco common stock they own. The merger is conditioned upon, among other things, the approval of the shareholders of each company and customary regulatory approvals. Both companies held special meetings of shareholders on Tuesday, March 12, 2002, and the shareholders of both companies approved the proposed merger. Completion of the transaction is expected in the second half of 2002. BUSINESS STRATEGY We are pursuing an integrated, growth oriented business strategy, with our different businesses working together to create a more economically diverse and value-adding product line to meet the needs of partners and customers. Upstream is focused on maintaining consistent, profitable growth, and is aggressively pursuing high-potential opportunities worldwide. A top priority for 2002 will be to maintain our focus on operational excellence during the integration process for the ConocoPhillips merger. We will continue to pursue profitable production growth through successful exploration, a steady stream of high-value development projects, and securing new opportunities by providing innovative commercial solutions to host governments around the globe. Downstream is focused on maintaining a balanced suite of assets capable of generating strong returns even in cyclical markets. We will continue to pursue innovative growth opportunities that require limited capital investment and continue to upgrade our business in sustainable ways. Our emerging carbon fibers, natural gas refining and international power businesses are focused on developing commercial capability and building our customer base. All three of these emerging businesses complement our core businesses and have the potential to contribute substantially to long-term growth. Conoco's major operations are in four core areas, North America, western Europe, northern South America and southeast Asia, which was officially designated as a core area in 2001 subsequent to our purchase of Gulf Canada. We will continue to improve the profitability, efficiency and effectiveness of existing operations while pursuing opportunities in the Middle East, the Caspian Sea region, Russia and West Africa. 2 In all of our activities, we will strive to act in accordance with our core values of operating safely, protecting the environment, acting ethically and valuing all people. FINANCIAL INFORMATION -- OPERATING SEGMENT AND GEOGRAPHIC INFORMATION For operating segment and geographic information, see note 29 to the consolidated financial statements. UPSTREAM SUMMARY Conoco is currently exploring for, developing or producing crude oil, natural gas and natural gas liquids and mining for Canadian Syncrude in 23 countries around the world. In 2001, production averaged 770,000 BOE per day, consisting of 422,000 barrels per day of petroleum liquids (excluding natural gas liquids from gas plant ownership), 2,030 million cubic feet (mmcf) of natural gas per day and 10,000 barrels of Canadian Syncrude per day. The majority of this production came from fields located in the U.S., Canada, the U.K. and Norway, with the remaining production coming from operations in Indonesia, the United Arab Emirates, the Netherlands, Vietnam, Ecuador, Nigeria, Russia and Venezuela. In 2001, Conoco replaced 432 percent of the oil, natural gas and Canadian Syncrude produced, adding 1,213 million BOE to its worldwide reserves for a net increase of 932 million BOE after producing 281 million BOE, excluding natural gas liquids from gas plant ownership. Excluding the effect of our Gulf Canada acquisition and other purchases and disposals, we replaced 113 percent of our oil and natural gas production, with significant reserves in the U.K., U.S., Vietnam and Indonesia. On December 31, 2001, we had proved reserves of 3,579 million BOE, consisting of 1,862 million barrels of petroleum liquids, 8,619 billion cubic feet (bcf) of natural gas and 280 million barrels of Canadian Syncrude. Excluding our Gulf Canada purchase, Conoco's capital investment in upstream activities in 2001 was $2,214 million, including the continued development of the south Texas Lobo trend, several North Sea fields, and properties in Canada, the West Natuna Sea in Indonesia, and additional producing properties and acreage in the U.K. and Vietnam. These projects will contribute to Conoco's 2002 production. The majority of Conoco's producing assets are located in North America, northern South America, western Europe and southeast Asia. These producing properties will generate cash to fund growth opportunities around the world. Outside of these areas, Conoco's activities are focused in regions that have the potential to become major business areas in the future, such as West Africa, the Caspian Sea region, the Middle East and Russia. Conoco is exploring for oil and/or natural gas in 22 countries. Since 1996, Conoco has acquired significant acreage positions in the following regions: o the deepwater Gulf of Mexico; o the Atlantic Margin of northwest Europe; o northern South America and the Caribbean; o selected basins in southeast Asia; o the Caspian Sea; and o western Canada and the Mackenzie Delta and Laurentian Basin in offshore eastern Canada. In 2001, the performance of the Conoco legacy exploration program was excellent, as in 1998, 1999, and 2000. In 2001, Conoco participated in seven discoveries and 19 appraisal wells that were potentially commercial, achieving a 37 percent success rate for wildcat wells and a 100 percent success rate for appraisal drilling. A significant oil find was made in the Cuu Long Basin, offshore Vietnam, while the high value snuggle exploration program in the North Sea and Canada yielded a total of five new discoveries close to existing infrastructure. Through the purchase of Gulf Canada, we also added exploration discoveries in Canada, Indonesia and the Netherlands to our portfolio. 3 Conoco intends to continue managing our asset portfolio to increase the proportion of upstream assets relative to downstream assets, the proportion of gas volumes to liquids volumes, and the proportion of large-scale, long-lived, early-life cycle assets relative to mature assets. In the course of implementing this strategy, we may from time to time in the future, as we have in the past, purchase or sell producing upstream assets. We may also consider forming alliances or joint ventures to hold and operate selected upstream assets, either to optimize the efficiency of such operations through achieving economies of scale or, in certain circumstances, to monetize a portion of the value of such assets. UNITED STATES Production operations in the U.S. are principally located in the following areas: o the Lobo trend in south Texas; o the Gulf of Mexico; o the San Juan Basin in New Mexico; and o the Permian Basin in west Texas. In 2001 U.S. operations contributed approximately 17 percent of Conoco's worldwide petroleum liquids production and 40 percent of its worldwide natural gas production. U.S. proved reserves as of December 31, 2001, were 600 million BOE, consisting of 244 million barrels of petroleum liquids and 2,138 bcf of natural gas. Conoco's current objectives in the U.S. are to increase production from the deepwater Gulf of Mexico, while maintaining production from other U.S. assets, optimize our natural gas processing capabilities, and strategically focus on natural gas opportunities. Lobo Trend in South Texas Conoco is the largest natural gas producer in the Lobo trend, and a leading producer, marketer and transporter of natural gas in south Texas. Conoco has over 20 years of operating and drilling experience in the Lobo trend and currently holds approximately 450,000 acres in the area under oil and gas leases. In December 2001, our eight rig drilling program was delivering gross natural gas production of approximately 550 mmcf per day. Conoco's 2001 development program included the acquisition of new 3D seismic data and the drilling of 163 wells. We anticipate spending approximately $450 million in 2002 and 2003 to further develop our leases in the Lobo trend. Conoco's average working interest in its leases in the Lobo trend is 96 percent. Certain producing wells are subject to volumetric production payments, the last of which terminate in 2002. These volumetric production payments averaged approximately 39 mmcf per day in 2001. Lobo Pipeline Company, a wholly owned subsidiary of Conoco, owns and operates an intrastate natural gas pipeline system in south Texas that serves as a means of transportation for our gas production and that of third party producers. Gulf of Mexico Conoco's current portfolio of producing properties in the Gulf of Mexico includes two fields operated by Conoco and four operated by other companies. The properties are in various stages of development, ranging from properties that are fully developed to ones with considerable additional development potential. We also hold interests in various offshore platforms, pipelines and other infrastructure. Conoco currently has 15 leases in production or under development in the deepwater Gulf of Mexico. A recent and important development project in the Gulf of Mexico is our Ursa field. Ursa, operated by Shell, is one of the largest discoveries to date in the deepwater Gulf of Mexico based on estimates of ultimate recoverable reserves. We hold a 16 percent interest in the field, and the other owners are Shell, BP and ExxonMobil. The Ursa tension-leg platform was installed in late 1998 in approximately 3,900 feet of water, with first production occurring in March 1999. Ursa has a platform capacity of 163,000 barrels per day of petroleum liquids and 350 mmcf of gas per day. In January 2002, the field reached a cumulative production of over 100 million BOE. 4 The Princess field, which is adjacent to the Ursa field, was discovered in 2000. Because of Princess' proximity to Ursa, petroleum liquids and natural gas produced from Princess may be processed and transported via the Ursa infrastructure already in place. Conoco owns a 16 percent interest in Princess with the remainder of the field owned by Conoco's partners in Ursa. The Ursa unit was expanded to include the Princess field and the resulting alignment of interests is expediting the development of this discovery. Also in 2001, Conoco drilled three appraisal wells further delineating the extent of the Magnolia discovery. The discovery was confirmed to be commercial and the project was approved in December of 2001. Conoco operates and holds a 75 percent interest in the Garden Banks 783 and 784 leases that comprise the field. First oil from Magnolia is scheduled for the fourth quarter of 2004. Peak production will occur in 2005 with rates of 50,000 barrels per day of petroleum liquids and 150 mmcf per day of associated natural gas. In addition to the Princess and Magnolia successes, Conoco is continuing its exploration program in the deepwater Gulf of Mexico. We hold interests in 298 leases, 50 of which are owned 100 percent. Since 1996, we have acquired 3D seismic data over large portions of the deepwater Gulf of Mexico to identify acreage to lease and to select prospects for drilling. In 2002, we expect to participate in five wildcat exploration wells with working interests averaging between 35 and 60 percent. Conoco is carrying out its deepwater Gulf of Mexico drilling program in large part with the Deepwater Pathfinder, a highly sophisticated drillship, which is owned by a joint venture between Transocean Sedco Forex Inc. and Conoco. The vessel, which went into service in January 1999, is capable of drilling in water depths of up to 10,000 feet and provides us with the ability to explore in areas that were previously inaccessible. Other U.S. Producing Properties Outside of south Texas and the Gulf of Mexico, Conoco's largest producing properties in the U.S. are located in the San Juan Basin in New Mexico and the Permian Basin in west Texas. We also have producing properties in the Williston Basin of North Dakota and the Hugoton complex in the Oklahoma/Texas Panhandle. Conoco has a significant acreage position in the San Juan Basin where our average daily net production in 2001 was approximately 11,000 barrels of petroleum liquids and 198 mmcf of natural gas. Conoco has an interest in 26 fields in the Permian Basin in west Texas, which is one of the largest producing areas in the U.S. In the Permian Basin, our average daily net production in 2001 was approximately 18,000 barrels of petroleum liquids and 46 mmcf of natural gas. We are using 3D seismic technology, horizontal wells and other innovative extraction technologies in an effort to extend the productive life of many of the mature fields in the Permian Basin. Dispositions As part of ongoing efforts to rationalize our assets and efficiently manage our portfolio, Conoco divested several U.S. producing properties in 2001 including: o eight Gulf of Mexico properties as follows: the shelf assets of Ewing Bank 305, Main Pass 144, Main Pass 290, Main Pass 311, Mississippi Canyon 109, Ship Shoal 176, S. Marsh Island 9, S. Marsh Island 107; o four Lobo fields; o the North Maurice assets in southern Louisiana; and o the Elk Basin field. In 2001, Conoco sold its interest in the Pocahontas Gas Partnership, a 50/50 partnership between Conoco and Consol Energy Inc., which produced and gathered coal bed methane prior to and during coal mining operations in Virginia. Conoco Gas and Power Conoco's natural gas and gas products facilities in the U.S. include: 5 o an 800-mile intrastate natural gas pipeline system in Louisiana operated by Conoco's wholly owned subsidiary, Louisiana Gas System, Inc.; o natural gas and natural gas liquids pipelines in several states; o an underground gas storage facility in New Mexico; o an underground natural gas liquids storage facility in each of Texas and Louisiana; o a natural gas liquids fractionating plant in Gallup, New Mexico with a capacity of 25,000 barrels per day; and o a 22.5 percent equity interest in Gulf Coast Fractionators, which owns a natural gas liquids fractionating plant in Mt. Belvieu, Texas with a capacity of 110,000 barrels per day. In November 2001, Conoco acquired various assets from Duke Energy, including the Zia Gas Plant in Lea County, New Mexico, which has a processing capacity of 43 mmcf per day. In November 2001, Conoco completed the sale of Conoco's 50 percent interest in Alliance Energy Services Partnership, a gas marketing joint venture, to Allegheny Energy. As of December 31, 2001, Conoco owned interests in 18 natural gas processing plants, an increase of three from last year, located in Louisiana, New Mexico and Texas, as well as approximately 5,400 miles of gathering lines. We operate 14 of the plants. Conoco gathers natural gas, extracts natural gas liquids and sells the remaining residual gas. Most of the gas liquids recovered are supplied to our fractionation operations, which further separate them into finished products that are sold as feedstocks to gasoline and chemicals manufacturers, propane resellers and agricultural end users. Conoco markets over 250,000 barrels per day of natural gas liquids to more than 500 customers in North America. Conoco Gas & Power Marketing (G&PM) was established in 2000 by combining the marketing activities of our natural gas and power businesses. We offer sophisticated, customer-driven energy solutions including joint gas and power procurement, storage, transportation, gas and power price-related risk management services and ancillary services. Conoco's significant natural gas assets give G&PM a competitive advantage that enables us to provide reliable fuel supplies to commercial and industrial customers at attractive prices. During 2001, Conoco marketed and traded 7 bcf of natural gas per day in North America. In 2001, we combined our G&PM group with our North American power generating operations to create a new commercial solutions business within Conoco Gas and Power (CG&P). This move reflects a new business model in which development activities in both natural gas and power are driven by external factors to meet market needs. CG&P has interest in three U.S. power-generating assets, including a new 420-megawatt, joint-venture cogeneration plant near Orange, Texas; a similar 440-megawatt facility close to Corpus Christi, Texas; and a 220-megawatt cogeneration plant near Conoco's refinery at Lake Charles, Louisiana. Conoco's share of total natural gas liquids extracted from natural gas processed averaged 62,500 barrels per day in 2001. Approximately 10,400 barrels per day of natural gas liquids were from Conoco owned reserves that were reported, net of royalties, as U.S. natural gas liquids production. Approximately 12,700 barrels per day of additional natural gas liquids were attributable to the processing of Conoco's natural gas liquids in third party-operated plants. CANADA The acquisition of Gulf Canada considerably strengthened Conoco's position in North America. The transaction increased North American proved oil and gas reserves by 395 million BOE, and added proven Canadian Syncrude reserves of 281 million BOE. Conoco is now the fifth largest oil and gas producer in Canada. The total net oil and gas production for 2001 was 32 million BOE and net annual Canadian Syncrude production of 4 million BOE. At year-end, Conoco had proved oil and gas reserves of 442 million BOE, proven Canadian Syncrude reserves of 280 million BOE and 8.7 million net undeveloped acres. 6 Conventional Oil and Gas Upstream Operations Operations in western Canada encompass properties in Alberta, northeastern British Columbia and southwestern Saskatchewan. The reserve base in central and northwestern Alberta and northeastern British Columbia is dominated by liquids-rich natural gas and light oil fields, as well as large enhanced oil recovery projects. The reserve base in southern Alberta and southwestern Saskatchewan is a mix of medium gravity oil and natural gas. Conoco is working with three other energy companies, as members of the Mackenzie Delta Producers' Group, on the possibility of transporting onshore gas production from the Mackenzie Delta in northern Canada to existing markets. In October 2001, the Group signed a Memorandum of Understanding (MOU) with the Aboriginal peoples of the Northwest Territories, as represented by the Mackenzie Valley Aboriginal Pipeline Corporation (MVAPC). The MOU provides a framework for the parties to move forward on an economic and timely development of a Mackenzie Valley pipeline, running some 800 miles to a connection with the North American gas market. In January 2002, the Group and the MVAPC announced that they would begin preparing the regulatory applications needed to develop onshore natural gas resources in the Mackenzie Delta, including the Mackenzie Valley pipeline. Off the east coast of Canada, we have a joint venture and operating agreement with two other companies, covering 8.2 million acres in French (off the islands of St. Pierre and Miquelon) and Canadian territorial waters. In heavy oil properties, Conoco owns approximately 47 percent of Petrovera, a partnership that combines a substantial portion of Conoco's Canadian heavy oil assets and certain associated gas assets to reap the benefits of combined expertise, technology and economies of scale. Net production is approximately 16,000 barrels of petroleum liquids per day. Midstream Operations Our Canadian natural gas liquids business includes the following assets acquired from Petro-Canada in 2000: o a 92 percent operating interest in the 2.4 bcf per day Empress natural gas processing straddle plant near Medicine Hat, Alberta with a natural gas liquids production capacity of 48,000 barrels per day; o the 580-mile Petroleum Transmission Company pipeline from Empress to Winnipeg and six related pipeline terminals; o an underground natural gas liquids storage facility with 1 million barrels of capacity; o a 10 percent interest in the 1,902-mile Cochin LPG pipeline, originating in Edmonton, Alberta and ending in Sarnia, Ontario, and a terminal storage system that transports propane, ethane and ethylene; and o an 18 percent interest in a 30,000 barrels per day propane-plus fractionator and a 5 percent interest in a 65-mile natural gas liquids pipeline with storage near Edmonton, Alberta. During 2001, Conoco acquired the natural gas and gas liquids storage and distribution facilities of Procor LRP Storage, which includes: o four underground natural gas liquids storage caverns with 2.3 million barrels of capacity; o three natural gas storage caverns with 600 mmcf of capacity; and o rail distribution facilities with 20 rail car capacity. Oil Sands Conoco is piloting a Steam Assisted Gravity Drainage (SAGD) project at Surmont, about 35 miles south of Fort McMurray, Alberta. This SAGD project will test the potential of technology to economically develop oil sands that are too deep to mine. 7 In March 2001, a regulatory application was filed with the Alberta Energy and Utilities Board (AEUB). A MOU relating to the project has also been signed with the local Aboriginal bands. A commercial decision on whether to proceed with the project is expected by September 2002. Canadian Syncrude Conoco owns a 9.03 percent undivided interest in Syncrude Canada Ltd., a joint venture created by a number of energy companies for the purpose of mining shallow deposits of oil sands, extracting the bitumen and upgrading it into a light sweet crude oil called Syncrude Sweet Blend (SSB). The major facilities are at a plant site located at Mildred Lake, about 25 miles north of Fort McMurray, Alberta, together with an auxiliary mining and extraction facility approximately 20 miles from the Mildred Lake plant. Mining operations in the auxiliary mine employ a fleet of large shovels and trucks as well as hydro-transport technology. These technologies are anticipated to eventually replace the draglines and bucket wheel reclaimers utilized in the original base mine. During 2001, the oil and sand grade averaged 11.3 percent and overall extraction recovery of the bitumen was approximately 87 percent. Syncrude Canada Ltd. holds eight oil sands leases, of which Conoco's share is approximately 23,000 net acres. Several of the leases are held under the Province of Alberta's 80-year provisions for producing and upgrading facilities, which entitle the Canadian Syncrude project to protect 17.8 billion barrels of bitumen. The necessary surface rights are also held and the sites are readily accessible. In December 1999, the AEUB extended the project license term to the year 2035. The Crown royalties are subject to a transition agreement with the project owners under which a blended royalty rate of 50 percent of deemed net profits from the first 74 million barrels of annual production attributable to the base mine and a royalty of 25 percent of deemed net profits for incremental annual volumes and production from the newer leases will apply. Following expiry of the transition period in December 2001, the Crown royalties will be the greater of 1 percent of gross revenue or 25 percent of net revenue after deduction of all operating and capital costs. The Canadian Syncrude project is a mature project for which exploration activities are incidental to its current operations. Reclamation of mined areas has been pursued for several years and in 2001 there were 356 hectares of land reclaimed. Future reclamation costs for mined areas were estimated in 2001 to be approximately $800 million, of which Conoco's share is $72 million. The owners have completed the first two stages of an expansion plan intended to more than double production rates from those of the 1990s. The third stage was conditionally approved in May 2001 and is expected to bring the annual production to approximately 135 million barrels per year by 2005 at an aggregate gross cost of approximately $2,700 million. WESTERN EUROPE Conoco has a significant portfolio of producing properties in the U.K., Norway, and the Netherlands. Proved reserves in western Europe as of December 31, 2001, were 943 million BOE, consisting of 426 million barrels of petroleum liquids and 3.1 trillion cubic feet (tcf) of natural gas. In 2001, operations in western Europe contributed 40 percent of our worldwide petroleum liquids production and 41 percent of our natural gas production. Britannia Field Conoco is the largest equity owner in the Britannia natural gas/condensate field--the largest in the U.K. sector of the North Sea, based on estimated recoverable reserves. First production from Britannia occurred in August 1998, and we estimate that the field will have a production life of approximately 30 years. Conoco's proved reserves in Britannia include 1 tcf of natural gas and 34 million barrels of petroleum liquids at December 31, 2001. During 2001, Britannia was able to produce at rates of up to 800 million gross cubic feet of gas per day and 40,000 gross barrels of petroleum liquids per day by taking advantage of additional short-term capacity at the onshore Sage gas terminal. The average annual production rate was 678 million gross cubic feet of gas per day and 31,000 gross barrels of petroleum liquids per day. 8 Southern North Sea Producing Properties Conoco has various ownership interests in 15 producing gas fields in the southern North Sea, a major gas producing area on the U.K. continental shelf. These fields mostly feed into the Conoco-operated Theddlethorpe gas processing facility through three Conoco-operated pipeline systems: Viking, LOGGS and CMS. In 2001, Conoco's net production from the southern North Sea was 353 mmcf of natural gas per day. Our CMS3 project has been sanctioned for development and is well underway, with production expected in the fourth quarter of 2002. This multi-field development will be produced via existing Conoco-operated infrastructure. Another southern North Sea project called Viscount is in the final stages of project approval with first gas expected in the fourth quarter of 2002. The small Venture project, a single well development, is proceeding through front-end design and commercial negotiations with sanction expected early in 2002. In 2001, additional reservoir work on 48-10, a multi-well development, confirmed its commercial viability and front-end work is getting under way with sanction expected near the end of 2002. Other United Kingdom Properties and Discoveries Conoco also has interests in the following fields and discoveries: o Miller producing field (30 percent); o Statfjord producing field (5 percent in the U.K. sector); o MacCulloch producing field (40 percent); o Banff producing field (32 percent); o Clair field in development stage (24 percent); o Gryphon producing field (25 percent in main field and 18 percent in Gryphon South); o Thistle Area producing assets (varying interests averaging approximately 18 percent); o 21/3a exploration discovery (approximately 75 percent); and o Kappa exploration discovery (approximately 83 percent). Conoco operates the MacCulloch and Banff fields, both of which employ floating production, storage and offtake (FPSO) technology. Conoco also operates the 21/3a and Kappa discoveries, both of which are in the greater Britannia area. Conoco drilled an appraisal well establishing the presence of commercial hydrocarbons on each of the 21/3a and Kappa discoveries in 2000. BP operates the Miller field, Thistle Area and the Clair discovery. Clair is one of the largest undeveloped oil discoveries in western Europe based on estimated ultimate recoverable oil reserves. The Gryphon field, which is operated by Kerr McGee, also employs FPSO technology. Interconnector Pipeline and Gas Sales The Interconnector pipeline, which connects the U.K. and Belgium, facilitates the marketing throughout Europe of the natural gas Conoco produces in the U.K. This pipeline commenced operation in October 1998. Conoco's 10 percent equity share of the Interconnector pipeline allows us to ship approximately 200 mmcf of gas per day to markets in continental Europe. We have five-to-six-year contracts to supply natural gas to Gasunie in the Netherlands and Wingas in Germany, which fully utilize this capacity. Because the Interconnector pipeline provides flexibility to flow in either direction, we are able to take advantage of the long-term and short-term market conditions in both the U.K. and continental Europe. Norway Properties Conoco has an ownership interest in three of the largest producing fields in Norway: Heidrun, Statfjord and Troll. We also have an ownership interest in the Visund (9.1 percent), Jotun (3.8 percent) and Troll C (1.6 percent) developments, all of which began producing in 1999. In addition, we have interests in Oseberg South (7.7 percent), 9 Sygna, a Statfjord satellite, (6.6 percent), and Heidrun North Flank (18.3 percent), all of which commenced production during 2000. The Huldra development (23.3 percent) commenced production in December 2001. In 2001, Conoco acquired Statoil's 6.4 percent interest in the Grane field. Grane is located in the Norwegian North Sea and is operated by Norske Hydro. The field is expected to start production in 2003. Norske Conoco AS has executed an agreement with Det Norske Oljeselskap (DNO) to sell our 3.8 percent interest in Jotun. Pending government approval, the sale is expected to close at the end of the second quarter of 2002. Production from the Heidrun field, in which we own an 18.3 percent interest, began in 1995 and averaged approximately 177,000 gross barrels of petroleum liquids per day during 2001. We were the operator for the construction and installation of Heidrun's tension-leg platform. Upon first production, Statoil assumed operatorship in accordance with a pre-agreed arrangement. Associated gas from the Heidrun field currently serves as feedstock for a methanol plant that became operational in Norway in 1997. Statoil operates the plant, in which we also hold an 18.3 percent equity interest. A new Statoil-operated pipeline linking the Heidrun platform to the Aasgaard Transport System for further transport to the European gas market became operational in early 2001. Conoco holds a 10.3 percent interest in the Norwegian sector of the Statfjord field. We are supporting work by Statoil, the operator of Statfjord, to determine ways to slow the natural decline of the field and increase ultimate recovery. Additionally, we own a 1.6 percent interest in the Troll gas field, also operated by Statoil. Exploration in the U.K., Norway and Poland Exploration activities in the U.K. and Norway are focused both on lower-risk, high-value opportunities such as the "snuggle" exploration in the U.K. Southern Gas Basin and also on higher-risk growth opportunities found in the Atlantic Margin plays of the Norwegian Sea. Snuggle exploration describes those opportunities near existing infrastructure, which can be developed quickly, such as the recent Vixen field development. In 2001, Conoco drilled a total of five snuggle wells on its existing assets in the U.K. and Norway and had four discoveries, two in the U.K. southern North Sea and two in the Norwegian North Sea. Two wells were drilled in the U.K. Atlantic Margin area and one in the Atlantic Margin, offshore western Ireland, all of which were written off to dry hole costs. The 2002 drilling program in the U.K. and Norway will focus on snuggle exploration in the North Sea and exploration growth opportunities in the Atlantic Margin, offshore Norway. During 2001, Norske Conoco acquired a 40 percent interest and was designated as operator of the PL 268 block. Norske Conoco plans to drill a well on the Akkar Prospect on this block during the summer of 2002. During 2002 Conoco will begin an exploration program in Poland with the Miloslaw #3 well. The Netherlands Conoco's subsidiary in the Netherlands focuses on growth using a concentrated snuggle exploration strategy. Conoco operated four offshore exploration wells in 2001. The four Conoco operated exploration wells resulted in one significant new discovery from the Q4-10 wildcat well. Conoco is preparing appraisal and development plans for this new field, named Q1-B. In addition to its exploration activity, Conoco completed two natural gas developments in the second half of 2001 in the Dutch sector of the North Sea. Further, Conoco expects to bring on two more developments in 2002 from its Q4-B and G-17 discoveries. Production from the Castricum-Zee field began in July 2001. Extended reach drilling enabled the field to be brought on production quickly, safely and in an environmentally responsible manner via Conoco's existing Q8-A platform some three miles away. Conoco is the operator and has a 50 percent interest in the field. 10 On October 1, 2001, the P6-D natural gas field began production just 19 months after the discovery well was drilled. This quick turnaround was made possible by the design and reuse of an existing Multi-Purpose Platform, which was moved successfully from one of Conoco's depleted fields to its new location. The platform was specifically designed for reuse and relocation as a satellite facility for offshore production. Conoco operates and has a 29.4 percent interest in the P6-D field. NORTHERN SOUTH AMERICA AND THE CARIBBEAN Petrozuata Petrozuata is a key component of Conoco's strategy to deliver production and reserves through implementation of long-lived, large development projects and to utilize our proprietary coking technology in other areas of our business. Petrozuata is a joint venture between Conoco, which holds a 50.1 percent non-controlling equity interest, and PDVSA Petroleo y Gas S.A., a subsidiary of PDVSA, the national oil company of Venezuela, which holds the remaining interest. The project, the first venture of its kind in Venezuela, has developed an integrated operation that produces extra heavy crude oil from known reserves in the Zuata region of the Orinoco Belt, transports it to the Jose industrial complex on the north coast of Venezuela and upgrades it into synthetic crude, with associated by-products of liquefied petroleum gas, sulfur, petroleum coke and heavy gas oil. Petrozuata's synthetic crude is a lighter, partially processed refining feedstock similar to crude oil. Our recorded proved reserves related to our interest in Petrozuata as of December 31, 2001 were 687 million barrels of oil. Drilling began in 1997 and at December 31, 2001, 241 horizontal wells were completed. The joint venture agreement has a 35-year term, with royalty terms of 1 percent for the first nine years and 16 2/3 percent thereafter, which commenced with the first commercial lifting of synthetic crude in April 2001. Petrozuata began early production of extra heavy crude oil in August 1998, and as of December 2001, was producing approximately 120,000 gross barrels per day. Prior to the completion of the upgrading facility and commercialized lifting of synthetic crude, the extra heavy crude was blended with lighter oils and sold on world markets. With the completion of the upgrading facility, the synthetic crude produced by Petrozuata is now used as a feedstock for Conoco's Lake Charles refinery and a Venezuelan refinery operated by PDVSA. The first commercial sales of synthetic crude from the upgrading facility occurred in April 2001. Diluted extra heavy crude oil produced from the Orinoco belt is transported via a 36-inch pipeline from the field to the Jose industrial complex. An adjacent 20-inch pipeline returns naphtha from the upgrading facility to the field for use as a diluent. The field processing and support facilities as well as marine facilities for shipping synthetic crude and by-products are also complete. Conoco has entered into an agreement to purchase up to 104,000 barrels per day of the Petrozuata synthetic crude for a formula price over the term of the joint venture in the event that Petrozuata is unable to sell the production for higher prices. All synthetic crude sales are denominated in U.S. dollars. By-products produced by the upgrading facility, principally coke and sulfur, are sold to a variety of domestic and foreign purchasers. The loading facilities at Jose transfer synthetic crude and some of the by-products to ocean vessels for export. Synthetic crude sales are expected to comprise more than 90 percent of the project's future revenues. The La Luna Trend Exploration activities in northern South America and the Caribbean are focused on a geologic trend known as La Luna. In Venezuela, we conducted seismic surveys in 1997 on the shallow water Gulf of Paria West block and on the Guanare block in the Merida Andes foothills. In 1999, we drilled two exploration wells in the Gulf of Paria West. The first resulted in the Corocoro discovery that flowed hydrocarbons from multiple zones in drill stem tests while the second well, in a different structure, resulted in a dry hole. In 2001, Conoco and its partners commenced a four well appraisal program to evaluate the Corocoro discovery. We drilled three of the four wells in 2001 and completed the fourth well in the first quarter of 2002. All four wells proved to be successful. We currently hold a 50 percent working interest in and operate the Gulf of Paria West block. Our interest in this block is subject to dilution to 32.5 percent at the option of a PDVSA affiliate. On the Guanare block, operated by TotalFinaElf, a dry hole was drilled in 1998. We relinquished the Guanare block in early 2001. 11 In May 1996, Conoco acquired an exclusive deepwater exploration license offshore Barbados. Following hydrocarbon seep-detection surveys using both sea bottom sampling and satellite imaging, we acquired 2D seismic data on the block in 1999. TotalFinaElf farmed in to the license for a 35 percent working interest in 1999 and increased its interest to 45 percent in 2001. Following the acquisition of a 3D seismic survey, Conoco entered into a three-year exploration-drilling phase in February of 2001. We spudded the first exploration well in late 2001 and plugged and abandoned it as a dry hole in early 2002. Conoco acquired rights to acreage in Trinidad in 1997, drilled a well in 1999, and relinquished the block in 2001. Ecuador Through the acquisition of Gulf Canada, Conoco obtained a 14 percent non-operated interest in producing fields in the Oriente basin of Ecuador in the area collectively referred to as "Block 16". Repsol-YPF is the operator of the Block 16 area, which currently has gross production of 30,000 barrels of petroleum liquids per day of 16 degree API crude from over 90 wells in seven different pools in the block. Sales from the block are prorationed due to limited export pipeline capacity. A new export pipeline, the Oleoductos Crudos de Pesados (OCP) was approved in early 2001, and by year-end was almost 20 percent complete. The pipeline is expected to be completed in the first quarter of 2003. Work is underway in the block to increase production to the shipping commitment on the OCP of 100,000 barrels of petroleum liquids per day. During 2001, as part of this work, 12 development wells indicating commercial quantities were drilled in the block. Five of the wells, with total initial production capacity of 22,500 barrels of petroleum liquids per day, were brought on production; the rest remain suspended awaiting the OCP, due to an overall excess of productive capacity on the block. Phoenix Park Conoco holds a 39 percent equity interest in Phoenix Park Gas Processors Limited, a joint venture with the National Gas Company of Trinidad and Tobago Limited, which processes gas in Trinidad and markets natural gas liquids throughout the Caribbean and into the U.S. Gulf Coast. Phoenix Park's facilities include: o a gas processing plant; o a fractionator producing propane, mixed butane and natural gasoline; o storage tanks; and o two marine loading docks. Conoco's share of total natural gas liquids from natural gas processed at Phoenix Park averaged 7,900 barrels per day in 2001. SOUTHEAST ASIA The focus areas for Conoco's upstream efforts in southeast Asia are in the Cuu Long Basin, offshore Vietnam; in the Indonesian sector of the Natuna Sea; and in its 72 percent ownership of Gulf Indonesia Resources Limited (Gulf Indonesia), which has both onshore and offshore assets in Indonesia. Conoco also has interests in exploration blocks in Cambodia and Malaysia. Indonesia Conoco has a 33-year operating history in Indonesia where it operates the Block B, Tobong and Northwest Natuna Sea Block II Production Sharing Contracts (PSCs) and holds an interest in the south Sokang PSC. During 2001, Conoco significantly grew its business in southeast Asia with the acquisition of a majority stake in Gulf Indonesia and as a result declared southeast Asia its fourth core area. In November 2001, the Government of Indonesia formally awarded the Nila Block PSC to Conoco and its partner Inpex. Conoco will serve as operator and hold a 65 percent majority interest in the 5,300 square kilometer block. Extensive seismic and exploration drilling will be conducted under a three-year work program. The Nila block is located adjacent to the Conoco-operated south Natuna Sea Block B PSC. 12 Singaporean Gas Sale to SembGas In 1996, Conoco, as operator of the Indonesian South Natuna Sea Block B PSC, along with the other participants in Block B and the interest holders in the Block A and Kakap PSCs, formed the West Natuna Group (WNG), with the aim of jointly marketing natural gas from the West Natuna Sea to Singapore. In January 1999, the WNG, Pertamina (the Indonesian state-owned oil and gas company) and SembGas (a Singapore gas marketing company owned by SembCorp Industries, Temasek and Tractebel) signed agreements to provide for the sale, transportation and purchase of natural gas from specified fields in the three PSCs operated by the WNG. The agreements provide for the supply of 2.5 tcf of natural gas over a 22-year contract period with approximately 1 tcf of natural gas contributed from fields located in the Block B PSC. After an initial ramp-up period, the WNG will provide an average gross daily volume of 325 mmcf of natural gas to SembGas, of which 144 million gross cubic feet per day is attributable to Conoco and the other Block B participants. Conoco has a 40 percent interest in the Block B PSC. In 2001, efforts were focused on installing the Moveable Offshore Gas Production Unit now named Hang Tuah. Gas sales to Singapore from the newly-installed platform through the West Natuna Transportation System (WNTS) commenced in June 2001. The WNTS is a 400 mile sub-sea pipeline and gathering system, which collects gas from the Block B, Block A and Kakap PSCs in the West Natuna Sea and transports the gas to Singapore. The WNTS is a joint venture among Conoco (operator), Premier Oil and Gulf Indonesia. In support of the next development phase in Block B, the Engineering Procurement, Construction and Installation (EPCI) contracts for the Belanak FPSO vessel and the two wellhead platforms were awarded during the third quarter of 2001 to KBR and McDermott, respectively. It is expected that the EPCI contracts for the Belanak liquefied petroleum gas (LPG) FSO will be awarded in 2003. The project is on schedule for its planned 2004 commencement of production. Malaysian Gas Sale to Petronas In October 2000, Pertamina and Petronas (the Malaysian state-owned oil and gas company) signed an agreement that provided for the supply of 1.5 tcf of natural gas from fields governed by the Block B PSC to be delivered over a 20-year period. In March 2001, Pertamina and Petronas signed the final gas sales agreement. Initial Block B sales are expected to average 100 million gross cubic feet of natural gas per day, eventually increasing to 250 million gross cubic feet per day. First gas production to Petronas is contracted to begin August 1, 2002 when gas will be delivered from the Hang Tuah facilities to Petronas' Duyong receiving facilities. A project is currently in progress to install a 100 kilometer pipeline connecting the Hang Tuah and Duyong facilities. The project also includes installation of infield pipelines and control facilities to connect four dry gas wells to the Hang Tuah platform. Drilling and completion of the four gas source wells is currently in progress. The Keong-3 well has been drilled, completed and tested. The other three wells, the Keong-2, Keong-1 and Kijng-3 will be drilled, completed and tested in the first quarter of 2002. Two appraisal wells were drilled in the Kerisi field in late 2001. These wells proved the presence of a commercial oil rim underlying the previously discovered gas. It is expected that Kerisi will be developed as a tie-in to the nearby Belanak field and could be brought on-line as early as 2005. Belida and Sembilang Oil Fields The Belida and Sembilang Fields have been Block B's principal oil assets since production began in 1992 and 1994, respectively. During 2001 gross production averaged 49,400 barrels per day. A fourth quarter 2001 program of workovers and recompletions, combined with an aggressive reservoir management program, resulted in an average gross production increase to 48,400 barrels per day for January 2002 from a November 2001 level of approximately 36,000. In August 2001, Conoco shot 495 square kilometers of 3D seismic over the Belida area to further define the oil and gas potential of the existing known accumulations and to evaluate the Belida area outside of the current gas dedication boundaries. Seismic data quality proved to be excellent, and interpretation of the 3D to evaluate the prospective area is ongoing. Conoco's Block B PSC proved reserves are approximately 1.5 tcf of gross natural gas and 203 million gross barrels of oil, condensate, and liquid petroleum gas and are expected to be produced over the next 20-30 years. We 13 expect to develop more reserves on the Block through additional drilling. The gas will be sold under the Singaporean and Malasyan contracts, while the liquids will be available for sale to the open market. Gulf Indonesia Gulf Indonesia, headquartered in Jakarta, is a 72 percent owned, indirect subsidiary of Conoco as a result of Conoco's acquisition of Gulf Canada. Since 1997, Gulf Indonesia common shares have been traded publicly on the New York Stock Exchange under the symbol, "GRL". In 2001, Gulf Indonesia celebrated its 40th anniversary of operations in Indonesia. At December 31, 2001, Gulf Indonesia had interests in 13 contract areas in Indonesia, covering a total gross acreage of nearly 10 million acres (6 million net acres). Five of the contract areas have commercial production. One of the contract areas is in the development phase, and the remaining seven areas are in the pre-development or exploration phase. Gulf Indonesia is a party to four substantial long-term U.S. dollar gas sales contracts. Three of these contracts are being supplied or will be supplied from onshore fields in South Sumatra and the gas supply for the fourth is from the Kakap Block in the Natuna Sea. All reserve numbers for the Gulf Indonesia gas contracts are stated net to Gulf Indonesia before royalty. Gulf Indonesia has agreed to deliver approximately 0.6 tcf of natural gas over a 15-year period, which commenced in October 1998, from the Corridor Block PSC area to the Duri Steamflood in central Sumatra. Further, Gulf Indonesia signed agreements for the delivery of an additional 0.6 tcf of natural gas over a 19-year period with first gas deliveries targeted for late 2002. Gulf Indonesia is also a participant in the West Natuna Group consortium, as a participant in the Kakap Block PSC in the Natuna Sea. Gulf Indonesia's share of the Kakap Block PSC will be a part of the total 2.5 tcf to be supplied under the Sembgas contract. In February 2001, Gulf Indonesia signed agreements for the supply of approximately 0.7 tcf of natural gas from Sumatra to Singapore over a 20-year period. First gas deliveries for this contract are targeted for late 2003. In 2001, Gulf Indonesia completed a seven-well offshore exploration program that began in 2000. Four of the seven wells were discoveries with a fifth containing untested gas. Delineation programs for these discoveries are currently being planned for 2002. Vietnam In September 1998, Conoco was awarded a 23.25 percent interest in Block 15-1 in the Cuu Long Basin. 3D seismic was acquired in 1999 and the first exploration well was drilled during the third quarter of 2000. The well flowed 12,600 barrels of light oil per day. In August 2001, Conoco and its partners in Block 15-1 declared the Sutu Den (Black Lion) field commercial after a successful appraisal program. A wildcat discovery was also made on the nearby Sutu Vang (Golden Lion) prospect in the third quarter of 2001. The Sutu Den Phase I development project was approved by Conoco in December 2001. A FPSO vessel and a wellhead platform will be utilized and initial development will start in the southwest portion of the field. Because of the low gas to oil ratio in the reservoir, water injection and gas lift equipment will be installed in the first phase. The field is scheduled to begin production in 2004. In February 2000, Conoco acquired a 30 percent interest in Block 15-2 in the Cuu Long Basin through a farm-in from the Japanese Vietnam Petroleum Company (JVPC). In December 2000, our ownership interest was increased to 36 percent through acquisition of an additional 6 percent interest from JVPC. During 2001, Block 15-2 production increased to over 50,000 (gross) barrels of petroleum liquids per day from the Rang Dong field. This production is expected to increase with an expansion of the facilities through a gas lift, water injection and gas export project that was approved in 2001. In late 2002, two new platforms will be placed in the eastern (E-1) and southern (S-1) part of the Rang Dong field to bring the oil production capacity up within the range of 65,000 to 70,000 barrels of petroleum liquids per day. A successful appraisal step-out well, RD-12X, was drilled in the central part of the field in late 2001 and tested at a rate of 9,300 barrels of petroleum liquids per day. A development plan for this area of the field is being evaluated. 14 In April 2000, Conoco signed an agreement with the Vietnam Oil and Gas Corporation (Petro Vietnam) and the Korean National Oil Company to acquire exploration Block 16-2 in the Cuu Long Basin. Conoco became the operator with a 40 percent interest in the block. The first exploration well was drilled in the fourth quarter of 2001 and was written off to dry hole cost at the end of the year. In December 2001, Conoco purchased Statoil's 50 percent interest in Block 5-3, which covers approximately 462,000 acres. Exploration and appraisal efforts are ongoing. We also acquired all shares of a Statoil subsidiary, Statoil Vietnam AS, which owned a 16.33 percent stake in the Nam Con Son pipeline, a 240-mile delivery system that will transport natural gas from Nam Con Son fields to the Phu My industrial complex near Ho Chi Minh City. Gas delivery is scheduled to begin in late 2002. The purchase supports Conoco's strategic growth plans for southeast Asia and its objective of building a sustainable natural gas business in Vietnam. We are currently the largest acreage holder of any foreign energy company in Vietnam. Malaysia In November 2000, Conoco acquired half of Shell's 80 percent interest in deepwater exploration blocks "G" and "J" offshore the Malaysian state of Sabah. The two blocks cover more than 1.5 million acres adjacent to acreage with proved reserves. Two exploration wells were drilled on the blocks during 2001 and both were determined not to be commercially viable and there is a commitment to drill at least two additional wells over the next two years. RUSSIA Conoco holds a 50 percent ownership interest in Polar Lights Company, a Russian limited liability company established in January 1992 to develop the Ardalin field in the Timan-Pechora basin in Northern Russia. Polar Lights started producing oil in August 1994. Gross production averaged 30,872 barrels of petroleum liquids per day in 2001. Oil is transported through the existing Russian pipeline system and is then exported or sold on the domestic market. During 2001, Polar Lights committed to three Ardalin satellites fields: Oshkotin; Vostochnaya Kolva (VK); and Dyusushev (DY). First oil at the Oshkotin field is planned for 2002. VK and DY fields are expected to start producing in 2003. Conoco is pursuing a number of significant additional development opportunities in Russia including the Northern Territories and Shtokman projects. Since March 1998, Conoco has been working with OAO Lukoil, Russia's largest oil company, to jointly study the development of petroleum reserves in the 1.2 million acre block known as the Northern Territories. The block is located in the Timan-Pechora region and includes the large undeveloped Yuzhno Khilchuyu oil field. The Shtokman project is a large undeveloped natural gas field located in the Barents Sea. The Russian government has approved both the Northern Territories and Shtokman projects for development within a production sharing agreement (PSA) framework. Progress on negotiating the project-specific PSAs has been slow. However, given the promising potential, Conoco and its partners remain committed to pursuing these projects and are taking steps to progress the commercial and financial aspects of the projects. WEST AFRICA Conoco, in partnership with a Nigerian company, produces oil from the shallow water Ukpokiti field located offshore Nigeria. We currently have an 80 percent revenue interest in the field. Gross production from the field is currently about 21,000 barrels per day of oil, and Conoco's net proved reserves as of December 31, 2001, were 7.2 million barrels of oil. Conoco provides technical and operational assistance in the field's development, which includes three remote caisson type structures, five wells, and the conversion of the Conoco tanker Independence into a FPSO. With a 1.7 million barrel storage capacity, the vessel also serves as an export terminal. Conoco also operates and owns a 47.5 percent working interest in the deepwater block OPL 220 located offshore Nigeria, which encompasses 600,000 acres. Conoco acquired a 3D seismic survey and drilled two exploratory wells on this license. The first well, drilled in 1997, was not commercial. Conoco's Chota well, drilled on the license in 1998, encountered both oil and gas-filled sands. Evaluation work is ongoing on this discovery and other potential plays within OPL 220. An appraisal well of the Chota structure was completed on the neighboring block, OPL 219, at the end of 2001. 15 CASPIAN SEA REGION AND MIDDLE EAST In Dubai, United Arab Emirates, Conoco has operated four fields since their discovery between 1966 and 1973. Currently, we are using horizontal drilling techniques and advanced reservoir drainage technology to enhance the efficiency of the offshore production operations and improve recovery rates. In 1999, Conoco entered into a joint venture service agreement with Syria to develop its natural gas resources and to build natural gas infrastructure. Conoco and TotalFinaElf each hold a 50 percent interest in the project service agreement, with Conoco serving as lead operator. The joint venture completed construction of pipelines and plant facilities to gather and process 450 mmcf per day of natural gas. In addition, about 150 mmcf per day of residue gas from the combined facilities will be transported through a new 155-mile pipeline that will connect to the existing delivery system that serves western Syria including the Damascus area. The Deir Ez Zor gas processing plant began operation in September 2001 with the shut down of flares and the processing of associated gas. The project was fully completed prior to year-end. It was finished almost six months ahead of schedule and was built under budget. Conoco was one of three companies chosen to participate in Core Venture 3, a large natural gas opportunity in Saudi Arabia, which will span the value chain from wellhead to market. We were awarded a 30 percent interest in the Core Venture 3 consortium and will have the lead role in gas processing, as well as transmission operations of both gas and natural gas liquids. Other segments of the venture include a petrochemical plant, a power/water desalination facility and gas exploration and development over a 74,000 square-mile area. Commercial negotiations for the project are ongoing. Conoco continues to be active in efforts to re-enter Libya where our partners and we were forced to suspend active participation in the Oasis concession in 1986 because of U.S. government sanctions. In 2001, the U.S. government authorized our partners and us to travel to Libya to evaluate the concession area, where the assets were found to be operating and in good condition. The Oasis partners are meeting with Libyan officials and preparing for a future return to the concession area when political conditions permit. One of Conoco's newest initiatives is its 20 percent interest in the Zafar Mashal exploration prospect in the Caspian Sea. The Zafar Mashal prospect is located in the Volga Delta play in the South Caspian basin, an area that includes previously proved large discoveries. OIL, NATURAL GAS AND CANADIAN SYNCRUDE RESERVES Conoco's estimated proved reserves at December 31, 2001 were 3,579 million BOE, consisting of 1,862 million barrels of oil, 8,619 bcf of natural gas and 280 million barrels of Canadian Syncrude. In addition to conventional liquids and natural gas proved reserves defined by the Securities and Exchange Commission (SEC), Conoco has significant interests in proven oil sands in Canada associated with the Canadian Syncrude project. Management views the oil sands reserves related to the Canadian Syncrude project and their development as an integral part of the oil and gas operations of the company. However, generally accepted accounting principles define these reserves as mining related and exclude these reserves from the conventional definition of oil and gas reserves. As a result, oil sands information identified as Canadian Syncrude is presented separately. Oil and gas proved reserves cannot be measured precisely. The reserve data set forth in this report is only an estimate. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of oil and natural gas. Reserve estimates are based on many factors related to reservoir performance, which require evaluation by engineers interpreting the available data, as well as price and other economic factors. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data, the production performance of the reservoirs, as well as extensive engineering judgment. Consequently, reserve estimates are subject to revision, as additional data become available during the producing life of a reservoir. When a commercial reservoir is discovered, proved reserves are initially determined based on limited data from the first well or wells. Subsequent data may better define the extent of the reservoir and provide additional production performance. Well tests and engineering studies will likely improve the reliability of reserve estimates. Canadian Syncrude proven reserves cannot be measured precisely. The reserve data set forth in this report is only an estimate. Reserve estimates of Canadian Syncrude are based on detailed geological and engineering 16 assessments of in-place crude bitumen volume, the mining plan, historical extraction recovery and upgrading yield factors, installed plant operating capacity and operating approval limits. The in-place volume, depth and grade are established through extensive and closely spaced core drilling. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting the bitumen and upgrading it into a light sweet crude oil. Consequently, Canadian Syncrude reserve estimates are subject to revision as additional data become available. At lower prices for crude oil, natural gas and Canadian Syncrude, it may no longer be economic to produce certain reserves. Actual production revenues and expenditures with respect to Conoco's reserves will likely vary from estimates, and such variances may be material. The following table sets forth Conoco's proved oil and Canadian Syncrude reserves at year-end for the past five years. Proved oil reserves comprise crude oil, condensate and natural gas liquids expected to be removed for our account from our natural gas production.

YEAR ENDED DECEMBER 31 ---------------------------------------------------------- 2001 2000 1999 1998 1997 ~~1996~~ ---------- ---------- ---------- ---------- ---------- (MILLIONS OF BARRELS) PROVED OIL AND CANADIAN SYNCRUDE RESERVES ~~CONSOLIDATED~~Consolidated ~~COMPANIES~~Companies United States ............................ 244 249 238 261 277 Canada ........... ~~249 238 261 277 299 Europe~~ ........................ 164 7 8 11 8 Europe ................................... 426 405 383 410 421 ~~413~~ Other regions ............................~~...........~~ ~~174~~248 167 ~~192~~159 ~~195~~181 ~~214~~187 ---------- ---------- ---------- ---------- ---------- ~~Worldwide~~Total consolidated companies ...........~~..............................~~ 1,082 828 788 863 893 ~~926~~Equity ~~SHARE~~companies ~~OF EQUITY AFFILIATES Europe~~ ............................~~..................~~ 60780 60810 50742 51728 47731 ~~Other~~Canadian ~~regions(1)~~Syncrude ...........................~~.........~~ ~~750~~280 ~~682 678 680~~ -- -- -- -- ------ ------ ------ ------ ~~Total proved oil reserves~~ - ~~equity affiliates ..... 810 742 728 731 47~~ ------ --- --- ------- ------ ------ Total ~~proved~~worldwide ~~oil reserves~~ ............................. 2,142 1,638 1,530 1,591 1,624 ~~973~~ ========== ========== ========== ========== ==========

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

YEAR ENDED DECEMBER 31 ---------------------------------------------------------- 2001 2000 1999 1998 1997 ~~1996~~ ---------- ---------- ---------- ---------- ---------- (BILLIONS OF CUBIC FEET) PROVED NATURAL GAS RESERVES ~~CONSOLIDATED~~Consolidated ~~COMPANIES~~Companies United States ............................~~...........~~ 2,138 2,061 2,166 2,319 2,235 ~~1,822~~Canada ~~Europe~~ ................................... 1,420 327 385 234 196 Europe ................................... 3,103 2,837 2,884 3,053 3,060 ~~3,068~~ Other regions ............................~~...........~~ ~~838~~1,939 ~~749~~511 ~~430~~364 196 ~~173~~-- ---------- ---------- ---------- ---------- ---------- ~~Worldwide~~Total consolidated companies ...........~~.............................~~ 8,600 5,736 5,799 5,802 5,491 ~~5,063~~Equity ~~SHARE~~companies ~~OF EQUITY AFFILIATES United States~~ ............................~~...........~~ 19 317 343 381 370 ~~333~~ ---------- ---------- ---------- ---------- ---------- Total ~~proved~~worldwide ~~natural gas reserves~~ ............................. 8,619 6,053 6,142 6,183 5,861 ~~5,396~~ ========== ========== ========== ========== ==========

PRODUCTION DATA Conoco's oil, natural gas and Canadian Syncrude production, excluding natural gas liquids from gas plant ownership, averaged 770,000 BOE per day in 2001, compared with 654,000 BOE per day in 2000. As a percentage of total production, natural gas production was 44 percent in 2001 and 2000. The following table shows Conoco's interests in average daily oil and Canadian Syncrude production and average natural gas production for the past three years. Oil production comprises crude oil and condensate produced for our account, plus our share of natural gas liquids removed from natural gas production from our owned leases. Canadian Syncrude production represents our share of the production from our Canadian Syncrude joint venture in Canada. Natural gas production represents our share of production from leases in which we have an ownership interest. Natural gas liquids processed represent our share of natural gas liquids acquired through gas plant ownership. 17

2001 2000 1999 ~~1998~~ ---------- ---------- ---------- (THOUSANDS OF BARRELS PER DAY) NET AVERAGE DAILY OIL AND CANADIAN SYNCRUDE PRODUCTION ~~CONSOLIDATED~~Consolidated ~~COMPANIES~~Companies United States ........................................... 73 80 74 79Canada .................................................. 30 1 1 Europe .................................................. 155 155 161 ~~152~~ Other regions ........................................... 7991 8478 9583 ---------- ---------- ---------- Total net production - consolidated companies ......... 349 314 319 ~~326~~Equity ~~SHARE~~companies ~~OF EQUITY AFFILIATES Europe~~ ...........................................~~...~~ 1773 1856 1740 ~~Other~~Canadian ~~regions~~Syncrude .......................................... 3910 22-- 5-- ---------- ---------- ---------- Total ~~net~~worldwide ~~production - equity affiliates~~ ......... ~~56 40 22 -------- -------- -------- Total net oil production per day~~ ................................... 432 370 359 ~~348~~ ========== ========== ==========

2001 2000 1999 ~~1998~~ ---------- ---------- ---------- (MILLIONS OF CUBIC FEET PER DAY) NET AVERAGE DAILY NATURAL GAS PRODUCTION ~~CONSOLIDATED~~Consolidated ~~COMPANIES~~Companies United States ....................................... 797 796 865 ~~873~~Canada ............................................. 303 91 53 Europe .............................................. 825 800 ~~728~~727 ~~470~~ Other regions ....................................... 9186 52-- 53-- ---------- ---------- ---------- Total net production - consolidated companies .... 2,011 1,687 1,645 ~~1,396~~Equity ~~SHARE~~companies ~~OF EQUITY AFFILIATES United States~~ ....................................... 19 18 15 15 ---------- ---------- ---------- Total ~~net~~worldwide ~~natural gas production per day~~ ....................................... 2,030 1,705 1,660 ~~1,411~~ ========== ========== ==========

2001 2000 1999 ~~1998~~ ---------- ---------- ---------- (THOUSANDS OF BARRELS PER DAY) NET AVERAGE DAILY NATURAL GAS LIQUIDS PROCESSED ~~CONSOLIDATED~~Consolidated ~~COMPANIES~~Companies United States ....................................... 52 50 51 55Canada ~~Other regions~~ ............................................. 36 33 -- -- -------- ---------- ---------- Total net processed - consolidated companies ...... 88 83 51 55Equity ~~SHARE~~companies ~~OF EQUITY AFFILIATES United States~~ ....................................... ~~1 7~~ 8 ~~Other~~9 ~~regions~~13 ~~....................................... 8 6 4~~ ------ ------ ------ ~~Total net processed~~ - ~~equity affiliates ........... 9 13 12~~ ---~~---~~ ------ ------ Total ~~net~~worldwide ~~natural gas liquids processed per day~~ ....................................... 96 92 64 67 ========== ========== ==========

See the supplemental petroleum data in Item 8 for the annual production volumes of oil (crude oil, condensate and natural gas liquids), Canadian Syncrude and natural gas from proved reserves. Proved oil production volumes exclude natural gas liquids from plant ownership. The following table sets forth for Conoco, including equity affiliates, the average production costs per BOE produced, average sales prices per barrel of crude oil and condensate sold, and average sales prices per mcf of natural gas sold for the three-year period ended December 31, 2001. Average sales prices exclude proceeds from sales of interests in oil and gas properties. 18

~~TOTAL~~ UNITED OTHER ~~WORLDWIDE~~CONSOLIDATED EQUITY TOTAL STATES CANADA EUROPE REGIONS COMPANIES COMPANIES WORLDWIDE ------ ------ ------ ------- ------------ --------- --------- (UNITED STATES DOLLARS) ~~TOTAL~~FOR ~~CONOCO~~THE ~~For~~YEAR ~~the~~ENDED ~~year~~DECEMBER ~~ended December~~ 31, ~~2000~~2001 Average production costs per barrel of oil equivalent of petroleum produced (1) .......... $ 5.23 $ 5.~~............~~61 $ 4.1334 $ 46.2748 $ 35.6108 $ 6.71 $ 5.0925 Average sales prices of produced petroleum Per barrel of crude oil and condensate sold ...~~.............~~ ~~26.08 27.72 27.13~~ 23.~~91 Per mcf of natural gas sold ................................ 3.07 3.42 2.68 3.33 For the year ended December 31, 1999 Average production costs per barrel of oil equivalent of petroleum produced~~95(12) 17.~~.....................................~~74 423.0407 323.6744 4.22 4.2889 ~~Average sales prices of produced petroleum Per barrel of crude oil and condensate sold~~ 13.~~...............~~16 1721.0914 ~~17.33 17.33 16.55~~ Per mcf of natural gas sold ...................~~.............~~ 24.~~12 1.99 2.30 1.92 For the year ended December 31, 1998 Average production costs per barrel of oil equivalent of petroleum produced~~13(12) 2.~~.....................................~~40 ~~4.17~~ 3.7632 ~~4.65~~ 3.~~93 Average sales prices of produced petroleum Per barrel of crude oil and condensate sold ................ 12.14 12.17 12.~~31 113.8651 ~~Per mcf of natural gas sold~~ 4.~~...............................~~61 23.2452 ~~1.97~~FOR ~~2.86~~THE ~~1.42~~YEAR ~~CONSOLIDATED~~ENDED ~~COMPANIES~~DECEMBER ~~For the year ended December~~ 31, 2000 Average production costs per barrel of oil equivalent of petroleum produced (1) ..........~~..............~~ $ 4.0017 $ 45.1749 $ 3.49 $ 5.1407 $ 4.00 $ 5.43 $ 4.13 Average sales prices of produced petroleum Per barrel of crude oil and condensate sold ...~~.............~~ 27.6772 27.7278 27.96 27.0706 27.67 18.21 26.08 Per mcf of natural gas sold ...................~~.............~~ 3.0642 3.4233 2.68 ~~3.33~~-- ~~For the year ended December 31, 1999 Average production costs per barrel of oil equivalent of petroleum produced(1) ......................................~~ 3.9306 3.6077 ~~4.20~~ 3.~~91 Average sales prices of produced petroleum Per barrel of crude oil and condensate sold ................ 17.51 17.33 17.80 17.~~07 ~~Per~~FOR ~~mcf~~THE ofYEAR ~~natural~~ENDED ~~gas~~DECEMBER ~~sold ................................ 2.12 1.98 2.30 1.92 For the year ended December~~ 31, ~~1998~~1999 Average production costs per barrel of oil equivalent of petroleum produced (1) ..........~~............................~~ ~~3.95~~$ 3.6960 ~~4.54~~$ 3.2110 ~~Average~~$ ~~sales prices of produced petroleum Per barrel of crude oil and condensate sold~~ 4.~~...............~~20 12.37 12.17 12.61 12.12 Per mcf of natural gas sold ................................ 2.24 1.96 2.86 1.42 EQUITY AFFILIATES For the year ended December 31, 2000 Average production costs per barrel of oil equivalent of petroleum produced(1) ........................ $ 54.4301 $ 103.6993 $ 5.5853 $ 4.9604 Average sales prices of produced petroleum Per barrel of crude oil and condensate sold ... 17.33 18.20 17.80 17.~~.........~~05 1817.2151 ~~-- 19~~13.6386 17.6209 Per mcf of natural gas sold ...................~~.............~~ 31.7798 ~~3.77 -- -- For the year ended December 31, 1999 Average production costs per barrel of oil equivalent of petroleum produced(~~1) .~~.....................................~~92 52.5330 ~~10.02 4.51 5.84 Average sales prices of produced petroleum Per barrel of crude oil and condensate sold ................ 13.86~~ -- 132.0312 ~~14.55 Per mcf of natural gas sold ................................~~ 2.35 2.~~35 -- --~~12

---------------- (1) Average production costs per barrel of equivalent liquids, with natural gas converted to liquids at a ratio of 6,000 cubic feet of natural gas to one barrel of liquid. (2) Includes favorable U.S. hedging effect of $38 million or $1.29 per barrel for crude oil and condensate sold and $.05 per mcf for natural gas sold. The following table sets forth for Conoco the average production cost per barrel of Canadian Syncrude produced and average sales price per barrel of Canadian Syncrude sold from the Canadian Syncrude project in Canada.

~~TOTAL~~AMOUNT ~~UNITED OTHER WORLDWIDE STATES EUROPE REGIONS~~ --------- -~~---------~~ ~~---------- ----------~~ (UNITED STATES DOLLARS) ~~EQUITY~~CANADIAN ~~AFFILIATES~~SYNCRUDE ~~(CONT'D.)~~FOR ~~For~~THE ~~the~~SIX ~~year~~MONTHS ~~ended~~ENDED ~~December~~DECEMBER 31, ~~1998~~2001 Average production costs per barrel of ~~oil~~Canadian ~~equivalent~~Syncrude ~~of petroleum~~ produced~~(1)~~ ...........~~...........................~~ ~~9.10~~$ ~~10.~~11 6.1634 ~~18.64~~ Average sales ~~prices~~price ofper ~~produced petroleum Per~~ barrel of ~~crude~~Canadian ~~oil~~Syncrude ~~and condensate~~ sold ................ 8.~~90 -- 9~~.~~85 3~~.~~76 Per mcf of natural gas sold~~ .~~...............................~~ 221.~~39 2.39 -- --~~98

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

~~TOTAL~~ UNITED OTHER ~~WORLDWIDE~~TOTAL STATES CANADA(3) EUROPE REGIONS WORLDWIDE ---------- ---------- ---------- ---------- ---------- (NUMBER OF WELLS) Number of wells drilling(1) Gross ...............................~~.........................~~ 6747 42261 1720 83 331 Net .................................~~.........................~~ 3731 30135 3 4 2 172 Number of productive wells(2) Oil wells -- gross ..................~~..........................~~ 75,~~268~~709 63,~~534~~651 ~~381~~441 ~~353~~868 10,669 -- net ....................~~..........................~~ 21,~~381~~517 2,~~216~~495 4151 ~~124~~380 4,443 Gas wells -- gross ..................~~..........................~~ 87,~~887~~735 85,~~263~~302 ~~206~~282 ~~418~~44 13,363 -- net ....................~~..........................~~ 43,~~535~~659 43,~~104~~624 5468 ~~377~~20 7,371

---------- (1) Includes wells being completed. (2) Approximately 337 gross (226 net) oil wells and 1,538 gross (825 net) gas wells have multiple completions. (3) Includes Gulf Canada acquisition in 2001. 19 DRILLING ACTIVITY The following table sets forth Conoco's net exploratory and development wells drilled by region for the three-year period ended December 31, 2001. The table excludes our share of equity affiliates.

~~TOTAL~~ UNITED OTHER ~~WORLDWIDE~~TOTAL STATES CANADA EUROPE REGIONS WORLDWIDE ---------- ---------- ---------- ---------- ---------- (NUMBER OF NET WELLS COMPLETED) ~~For~~FOR ~~the~~THE ~~year~~YEAR ~~ended~~ENDED ~~December~~DECEMBER 31, ~~2000~~2001 Exploratory -- productive ..........~~..........................~~ 4.13 127.06 12.69 18.5 43.3 -- dry ................. 1.~~.........................~~3 420.3 2.69 3.26 128.51 Development -- productive ..........~~..........................~~ ~~304~~286.8 ~~267~~73.25 12.8 10.0 25383.61 -- dry .................~~..........................~~ 4518.76 2036.14 -- 254.62 ~~For~~59.2 ~~the~~FOR ~~year~~THE ~~ended~~YEAR ~~December~~ENDED DECEMBER 31, ~~1999~~2000 Exploratory -- productive .......... 1.~~.........................~~0 60.85 1.76 1.30 34.81 -- dry .................~~..........................~~ 32.36 ~~0.0~~-- 0.8 2 1.5 4.3 Development -- productive .......... 267.~~.........................~~2 ~~179~~20.17 ~~165~~12.20 84.79 5304.28 -- dry .................~~..........................~~ 1920.1 1825.36 ~~0.0~~-- 0-- 45.87 ~~For~~FOR ~~the~~THE ~~year~~YEAR ~~ended~~ENDED ~~December~~DECEMBER 31, ~~1998~~1999 Exploratory -- productive ..........~~..........................~~ 71.37 20.25 1.13 43.03 6.8 -- dry .................~~..........................~~ ~~14.0~~-- 5-- 0.48 12.95 63.73 Development -- productive .......... 165.~~.........................~~2 ~~234~~4.3 8.7 ~~215~~0.9 2179.~~8 16.~~1 -- dry .................~~..........................~~ 1318.03 ~~13.0~~-- -- 0.08 019.01

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

~~TOTAL~~ UNITED OTHER ~~WORLDWIDE~~TOTAL STATES CANADA EUROPE REGIONS WORLDWIDE ---------- ---------- ---------- ---------- ---------- (~~THOUSANDS~~THOUSAND OF ACRES) Developed acreage Gross ..........................~~..............................~~ 82,~~816~~940 4,224 3,~~000~~848 13,~~608~~825 414,~~208~~837 Net ............................~~..............................~~ 31,~~807~~508 13,~~565~~041 ~~417~~844 1,~~825~~495 6,888 Undeveloped acreage Gross ..........................~~..............................~~ 822,~~587~~765 214,~~963~~497 68,~~111~~109 7381,~~513~~141 106,512 Net ............................~~..............................~~ 441,~~263~~568 18,~~857~~704 12,~~765~~767 4045,~~641~~775 58,814

Conoco is not required to file, and has not filed on a recurring basis, estimates of its total proved net oil and gas reserves with any U.S. or non U.S. governmental regulatory authority or agency other than the Department of Energy (DOE) and the SEC. The estimates furnished to the DOE have been consistent with those furnished to the SEC. They are not necessarily directly comparable, however, due to special DOE reporting requirements, such as requirements to report in some instances on a gross, net or total operator basis, and requirements to report in terms of smaller units. In no instance have the estimates for the DOE differed by more than 5 percent from the corresponding estimates reflected in total reserves reported to the SEC. DOWNSTREAM SUMMARY Downstream operations encompass refining crude oil and other feedstocks into petroleum products, buying and selling crude oil and refined products and transporting, distributing and marketing petroleum products. Downstream operations are organized regionally with operations in the U.S., Europe and the Asia Pacific region. Downstream's objective is to continue to generate a competitive return on investment and surplus cash to support Conoco's global growth initiatives, while selectively expanding refining and marketing operations in high-growth markets, including Asia Pacific and central and eastern Europe. Consistent with this objective, Conoco has in the past, and may from time to time in the future, purchase or sell downstream assets. We may also consider forming alliances or joint ventures to hold and operate all or a selected part of our downstream assets either to 20 optimize the efficiency of such operations through achieving economies of scale or, in certain circumstances, to monetize a portion of the value of such assets. Conoco has made capital investments in downstream activities averaging approximately $465 million per year for the last three years. Capital investments for 2001 in downstream activities were approximately $389 million. Conoco's downstream strengths are in the following areas: o continually improving the operating and cost efficiency of our refineries; o processing heavy, high sulfur and acidic crudes; o upgrading bottom-of-the-barrel feedstocks via coking technology; o maintaining low cost, high volume retail operations in selected markets; o developing and marketing specialty products; and o integrating our refining and marketing infrastructure. These strengths are enhanced by the integration that exists with our upstream operations. Conoco produces and markets a full range of refined petroleum products, including gasoline, diesel fuels, heating oils, aviation fuels, heavy fuel oils, asphalts, lubricants, petroleum coke and specialty products and petrochemical feedstocks. We own and operate, or are a partner in the operation of, nine refineries worldwide with a total crude distillation capacity of about 936,000 barrels per day. Refining capacity is distributed 61 percent in the U.S., 33 percent in Europe and 6 percent in the Asia Pacific region. Approximately 50 percent of Conoco's worldwide refining capacity is designed to process heavy, high sulfur crude. In addition, the crude slate for the Humber refinery in the U.K. and the Lake Charles refinery in the U.S. comprises about 45 percent and 25 percent acidic crudes respectively. Refining capacity has risen by about 155,000 barrels per day, or 20 percent, since year-end 1997, primarily as a result of: o the expansion of the Lake Charles refinery; o the upgrade of the Humber refinery; o the addition of the Melaka refinery in Malaysia; and o low cost incremental expansion of existing refining units. Conoco has applied its coking technology to nearly all of its refining operations throughout the world. This has enabled us to become a world leader in producing petroleum coke products, such as high value graphite and anode cokes, which are used in the production of electrodes and anodes for the steel and aluminum industries, respectively. We have also licensed our fuel coking technology around the world, which has in turn created other business development opportunities. In the U.S., Conoco primarily markets through low cost wholesale operations. We have a growing marketing presence in Europe and Asia Pacific, where we are a leader in operating low cost, high volume retail stations. In 2001, downstream refined product sales volumes averaged 1,304,000 barrels per day. UNITED STATES Conoco's four U.S. refineries are high conversion facilities with capacity designed to process over 50 percent high sulfur crude oils, much of which is also heavy crude. A principal factor affecting the profitability of our U.S. operations is the price of refined products in relation to the cost of crude oils and other feedstocks processed. Because we are able to process a relatively large proportion of heavy, high sulfur and acidic crudes, the cost advantage of these crude oils, such as those from Mexico, Venezuela and Canada, over lighter, low sulfur crude oils, such as West Texas Intermediate, is particularly significant. Over half of our U.S. refining capacity is located in inland markets and therefore benefits from the price differential for products produced and sold inland versus those produced and sold on the Gulf Coast. 21 Integration of refining, transportation and marketing and continuous improvement initiatives have provided increased profitability through improvements in refinery reliability, utilization, product yield and energy usage. Since the end of 1997, Conoco has increased refining input at its four U.S. refineries by approximately 7 percent. We have also improved market share through geographic concentration of markets. Conoco intends to limit future capital investments in downstream U.S., excluding capital investments in large, non-discretionary, regulatory-driven projects and selected growth projects, to a level that is less than half of downstream U.S. operating cash flow. Capital expenditures decreased by approximately $180 million to $164 million in 2001, compared to $344 million in 2000, primarily as a result of the installation of an acidic crude unit at our Lake Charles refinery in 2000. We are positioned to make the necessary clean fuels investments, starting in 2002, at our refineries over the next five years in support of changing motor fuel specifications. Refining Conoco operates four wholly owned refineries in the U.S. The following tables outline the rated crude distillation capacity as of December 31 for each of the past five years, and the average daily inputs to crude distillation units and other feedstocks for each of the past five years:

YEAR ENDED DECEMBER 31 ---------------------------------------------------------- 2001 2000 1999 1998 1997 ~~1996~~ ---------- ---------- ---------- ---------- ---------- (THOUSANDS OF BARRELS PER DAY) CRUDE DISTILLATION CAPACITY (1) Lake Charles, Louisiana ..........................~~...............~~ 252 248 248 241 226 ~~226~~ Ponca City, Oklahoma .............................~~...............~~ 194 184 174 168 155 ~~155~~ Denver, Colorado .................................~~...............~~ 5862 58 58 58 58 Billings, Montana ................................~~...............~~ 60 56 54 52 52 52 ---------- ---------- ---------- ---------- ---------- Total crude distillation capacity ................~~...............~~ 568 546 534 519 491 ~~491 ======== ======== ======== ======== ========~~ REFINERY INPUTS (2) Lake Charles, Louisiana Inputs to crude distillation units (3) .......~~................~~ 228 208 234 216 211 ~~176~~ Other inputs .................................~~...............~~ 27 25 20 24 22 21 Ponca City, Oklahoma Inputs to crude distillation units (3) .......~~................~~ 174 181 173 167 161 ~~150~~ Other inputs .................................~~...............~~ 1 1 3 4 2 2 Denver, Colorado Inputs to crude distillation units (3) .......~~................~~ 54 58 56 50 53 ~~49 Other inputs ................................................ 0 0 0 0 0~~ Billings, Montana Inputs to crude distillation units (3) .......~~................~~ 53 57 49 52 51 51 Other inputs .................................~~...............~~ 3 3 3 3 3 Total inputs to crude distillation units .........~~...............~~ 509 504 512 485 476 ~~426~~ ========== ========== ========== ========== ========== Total other inputs ...............................~~...............~~ 31 29 26 31 27 26 ========== ========== ========== ========== ==========

---------- (1) Reflects all inputs to crude distillation units. (2) Reflects all inputs to crude distillation units and all other inputs (excluding internal recycles). (3) Actual inputs to crude distillation units may exceed rated capacity. Conoco's U.S. consolidated refined product sales by volume in 2001 were 50 percent motor gasoline, 34 percent middle distillates, including jet and diesel fuel, and 16 percent residual fuel oil and asphalt and other products, including petroleum coke, lubricants and liquefied petroleum gases. 22 Lake Charles Refinery and Related Facilities Conoco's Lake Charles refinery, located in Westlake, Louisiana, is a fully integrated, high conversion facility, which has a crude distillation capacity of 252,000 barrels per day. The refinery processes heavy, high sulfur, low sulfur and acidic crude oil. The refinery's Gulf Coast location provides access to numerous cost effective domestic and international crude oil sources. The crude capacity is approximately 192,000 barrels per day of heavy, high sulfur crudes including 75,000 barrels per day of acidic crude. The remaining 60,000 barrels per day is comprised of domestic sourced low sulfur crudes. While the types and origins of these lower priced heavy, high sulfur and acidic crudes can vary, the majority consists of Venezuelan and Mexican crudes delivered via tanker. Lake Charles refinery products can be delivered by truck, rail or major common carrier product pipelines, partially owned by Conoco, which serve the eastern and mid-continent U.S. In addition, refinery products can be sold into export markets through the refinery's marine terminal. The ability to refine low sulfur, heavy, high sulfur and acidic crudes at the Lake Charles refinery provides a competitive advantage by enabling the refinery to produce a full range of products including gasoline, jet fuel, diesel fuel, LPG, fuel grade petroleum coke and specialty coke from relatively low-cost feedstocks. The refinery facilities include fluid catalytic cracking, delayed coking and hydrodesulfurization units, which enable it to maximize the upgrade of heavier crude oil. Integration of fuels and specialty products plays an important role in maximizing product value at the refinery. The refinery supplies high sulfur gas oil to Excel Paralubes, a 50/50 joint venture between Conoco and Pennzoil-Quaker State, which owns a hydrocracked lubricating base oil facility. Excel Paralubes' state-of-the-art lube oil facility produces approximately 21,000 barrels per day of high quality clear hydrocracked base oils, representing approximately 13 percent of U.S. lubricating base oil production. Hydrocracked base oils are second in quality only to synthetic base oils, but are produced at a much lower cost. The refinery produces other specialty intermediates for making solvents to supply Penreco, a fully integrated specialties company, which manufactures and markets highly refined specialty petroleum products for global markets. Conoco has a 50 percent interest in Penreco. The Lake Charles facilities also include a specialty coker and calciner that manufacture the more highly valued graphite and anode petroleum cokes for the steel and aluminum industries, and provide a substantial increase in light oils production by breaking down the heaviest part of the crude barrel to allow additional production of diesel fuel and gasoline. In addition, green petroleum coke is supplied to a nearby coke calcining venture. In 2001, Conoco reached agreement to divest its 35 percent interest in Cit-Con, a paraffinic lubricants refinery. The sale closed in January 2002. Ponca City Refinery Conoco's refinery located in Ponca City, Oklahoma has a crude distillation capacity of 194,000 barrels per day of light, high sulfur crude, light, low sulfur crude and Canadian heavy, high sulfur crude. Both foreign and domestic crudes are delivered by pipeline from offshore, Oklahoma, Kansas, north and west Texas and Canada. Finished products are shipped by truck, rail and company-owned and common carrier pipelines to markets throughout the mid-continent region. The Ponca City refinery is a high conversion facility that produces a full range of products, including gasoline, jet fuel, diesel, LPG and anode and fuel grade petroleum cokes. The refinery's facilities include fluid catalytic cracking, delayed coking and hydrodesulfurization units, which enable it to produce high ratios of gasoline and diesel fuel from crude oil. Denver Refinery Conoco's Denver refinery, located in Commerce City, Colorado, has a crude distillation capacity of 62,000 barrels per day, processing a mixture of Canadian heavy, high sulfur crudes, and domestic heavy, high sulfur and low sulfur crudes. Almost all crude oil processed at the refinery is transported via pipeline. Products are delivered predominantly through a local truck loading terminal to the east side of the Rockies, but also by rail to other Colorado markets. The refined gasoline products from the Denver refinery help supply our marketing operations in the Rocky Mountain states. 23 The Denver refinery is a high conversion refinery that produces a full range of products including gasoline, jet fuels, diesel and asphalt. The refinery's upgrading units enable it to process a crude slate containing nearly 50 percent heavy, high sulfur crude. We have a processing agreement with a refinery located in Cheyenne, Wyoming, that has coking capabilities, from which the refinery receives intermediate feedstocks for processing into finished products. The Denver refinery also supplies KC Asphalt, a 50/50 joint venture with Koch Industries, which markets high quality asphalt products. Both of these ventures enable us to turn relatively low value intermediates into higher margin products. Billings Refinery Conoco's Billings, Montana refinery has a crude distillation capacity of 60,000 barrels per day, processing a mixture of about 95 percent Canadian heavy, high sulfur crude plus domestic high sulfur and low sulfur crudes, all delivered by pipeline. Products from the refinery are delivered via company-owned pipelines, rail, and trucks, supplying Conoco's extensive branded marketing operations in eastern Washington and the northern Rocky Mountain states. The refinery's proximity to its primary source of crude and its ability to refine both low sulfur and heavy, high sulfur crudes provides us with significant competitive advantages. The Billings refinery is a high conversion refinery that produces a full range of products including gasoline, jet fuels, diesel and fuel grade petroleum coke. A delayed coker converts heavy, high sulfur residue into higher value light oils. Marketing In the U.S., Conoco markets gasoline, utilizing the Conoco brand, in 39 states, 23 of which represent primary markets, in the southeast, mid-continent and Rocky Mountain regions. Market growth continues to be targeted to those areas where we can obtain a strong market share and areas that leverage supply from our U.S. refineries and those distribution systems in which we have an ownership position. Conoco gasoline is sold through approximately 4,900 branded stations in the U.S., 88 percent of the gasoline through retail outlets owned by independent wholesale marketers and 12 percent through 120 company-owned stores at year-end 2001. We market gasoline primarily through the wholesale channel in the U.S. because it requires a lower capital investment than company-owned retail stations, but still provides a secure branded outlet for Conoco's products. Conoco operates retail stations to establish brand standards and image, as well as to better understand the independent distributors in order to provide better programs and services to them and the consumer. In 2001, we realigned our marketing department to provide best in class service to our branded marketer network, which comprises nearly 400 independent businesses. We continue to build and enhance ConocoNet, a paperless platform to deliver key operating information and best-practice sharing to our marketers. Emphasis on reducing break-even operating costs, improving convenience product margins, and building consumer loyalty anchored our effort. At year-end 2001, CFJ Properties, a 50/50 joint venture between Conoco and Flying J, owned and operated 95 truck travel plazas that carry the Conoco and/or Flying J brands and provide a secure outlet for our low sulfur diesel production. In addition, bulk sales of all refined petroleum products are made to commercial, industrial and spot market customers. Transportation Conoco has approximately 7,400 miles of crude and product mainline pipelines in the U.S., including those partially owned and/or operated by affiliates. We also own and operate 36 finished product terminals, five liquefied petroleum gas terminals, two crude terminals and one coke-exporting facility. Our crude pipeline interests and terminals provide integral logistical links between crude sources and refineries to lower crude costs. The product pipelines serve as secure links between refineries and key product markets. Our U.S. pipeline system transported an average of 933,000 barrels per day in 2001. Our equity share of shipments on affiliate pipelines was an additional 446,000 barrels per day. 24 Conoco currently operates a fleet of seven seagoing double-hulled crude oil tankers. Six of the ships typically travel to Mexico, Central America and South America to load crude oil and discharge at a Gulf Coast location. The vessels are used to provide secure transportation to the Lake Charles refinery, but when not in service for Conoco, are available for charter to third parties. The seventh double-hulled tanker, the Rangrid, is on lease to a third party for use as a shuttle tanker for the Heidrun field in the North Sea, in which Conoco has an interest. Conoco also operates a domestic fleet of seven boats and 14 double-hulled barges, providing the Gulf Coast Regional Business Unit with inland waterway transportation services. The fleet operates along the Gulf Coast from Corpus Christi, Texas to Mobile, Alabama transporting crude oil and refined products. EUROPE Conoco's European refining and marketing activities are conducted in 15 countries and are generally organized into two regional clusters to facilitate operational synergies and best practices. In addition, the regional clusters centralize and leverage certain support activities, which allow the individual country organizations to focus on serving customers and developing our business within and across European borders. The Northern cluster is based in the U.K. and includes marketing operations in Sweden, Norway, Finland and Denmark, in addition to refining and marketing activities in the U.K. The Continental cluster is based in Germany and includes marketing operations in Austria, Switzerland, Belgium, Luxembourg, Hungary, Slovakia, Poland and the Czech Republic. The Continental cluster also includes refining joint ventures in Germany and the Czech Republic. In addition, although it is not part of either cluster, a marketing joint venture in Turkey is also included in Conoco's European operations. Together, our refining and marketing operations in the U.K. and Germany accounted for 91 percent of our European downstream after-tax earnings before special items in 2001. Conoco's European downstream strategy has been to operate low cost, high volume retail outlets in selected key markets where we have a competitive advantage, pursue opportunities in growth regions, and maintain our Humber refinery and the Mineraloel Raffinerie Oberrhein GmbH (MiRO) joint venture refinery, in the U.K. and Germany, respectively, as top quartile performers in Europe. Conoco invested approximately $182 million in its European downstream operations in 2001, and $175 million in 2000. A significant portion of these expenditures went towards meeting current and expected future clean fuels regulations. Our European refineries are on schedule to produce motor fuels that meet the more stringent European Union specifications expected to come into force in 2005. The majority of our diesel production is currently in full compliance, with the majority of our gasoline production expected to be in compliance during 2003. Tax incentives are in place to promote this early compliance. We continue to implement relatively low-cost projects in our refining operations designed to increase production and improve yields, while reducing feedstock costs and operating expenses. Conoco plans to continue to direct capital expenditures for marketing operations toward construction of new stations in growth markets. These markets are primarily in central and eastern Europe, and also in our areas of competitive strength in Germany, Austria and the Nordic countries. Conoco's European downstream profitability is affected by several factors. As with all refining operations, the difference between the market price of refined products and the cost of crude oil is the major factor. Our European refineries are able to process lower cost crudes or upgrade other feedstocks into higher value finished products. In addition, since the U.K. refinery also processes fuel oil as a feedstock, the price difference between low sulfur fuel oil and finished product is important to earnings. European operations also include significant retail marketing volumes, and therefore earnings are driven by retail margins, fuel and convenience product sales and operating expenses in the various countries where we operate. Refining Conoco's principal European refining operations are located in the U.K., Germany and the Czech Republic. The expansion of Conoco's Humber refinery in the U.K. has increased our European refining capacity by approximately 8 percent, or 22,000 barrels per day since 1997. We have continuously upgraded our refineries in Europe since the early 1990s and their configuration and output are two of Conoco's primary sources of competitive 25 advantage. In 2000, the U.K. and Germany refineries ranked in the first quartile of western European refineries by Solomon Associates, an independent benchmarking company for financial and operating performance, as measured by net margin. In addition, Wood Mackenzie, a recognized petroleum industry consultant, rated Conoco's European refining operations number two in Europe in a 2001 study, as measured by net cash margin per barrel. Conoco has undertaken a major capital investment program, totaling approximately $597 million from 1994 through 2001, to process lower cost feedstocks and increase conversion capacity, product quality and energy efficiency at the Humber refinery. From 1999 through 2001, we have spent about $132 million at the Humber refinery, and in 2002 we plan to spend another $16 million to meet current and expected future clean fuel specifications and to fund other environmental projects. We are also participating in upgrading projects at our MiRO joint venture refinery and our joint venture Ceska rafinerska, a.s. (CRC) refineries in the Czech Republic. The following tables outline the rated crude distillation capacity as of December 31 for each of the past five years and the average daily inputs to crude distillation units and other feedstocks for each of the past five years:

YEAR ENDED DECEMBER 31 ------------------------------------------------~~----~~ 2001 2000 1999 1998 1997 ~~1996~~ -------- -------- -------- -------- -------- (THOUSANDS OF BARRELS PER DAY) CRUDE DISTILLATION CAPACITY(1) Humber, United Kingdom ...........................~~...............~~ 232 230 218 218 210 ~~210~~ MiRO, Germany(2) .................................~~...............~~ 53 53 53 53 4353 CRC, Czech Republic(3) ...........................~~...............~~ 27 27 27 27 27 -------- -------- -------- -------- -------- Total crude distillation capacity(4) .............~~...............~~ 312 310 298 298 290 ~~280~~ ======== ======== ======== ======== ======== REFINERY INPUTS(5) Humber, United Kingdom(6) Inputs to crude distillation units(7) ..........~~...............~~ 166 203 213 214 174 ~~162~~ Other inputs ...................................~~...............~~ 20 21 13 8 19 35 MiRO, Germany(2) Inputs to crude distillation units(7) ..........~~...............~~ 54 54 56 54 51 47 Other inputs ...................................~~...............~~ 2 3 4 3 11 13 CRC, Czech Republic (3) Inputs to crude distillation units (7) .........~~................~~ 18 17 17 20 21 22 Other inputs ...................................~~...............~~ 1 1 1 1 1 Total inputs to crude distillation units(4) ......~~...............~~ 238 274 286 288 246 ~~231~~ ======== ======== ======== ======== ======== Total other inputs ...............................~~...............~~ 23 25 18 12 31 49 ======== ======== ======== ======== ========

---------- (1) Reflects all inputs to crude distillation units. (2) Represents Conoco's 18.75 percent interest in the MiRO refinery complex at Karlsruhe, Germany. (3) Represents Conoco's 16.33 percent interest in two refineries in the Czech Republic. (4) Does not include Conoco's 1.4 percent interest in a 95,000 barrel per day refinery in Mersin, Turkey. (5) Reflects all inputs to crude distillation units and all other inputs (excluding internal recycles). (6) The 2001 utilization was significantly impacted by the fire and major turnaround at the Humber refinery in the second quarter. The tie-in of a major expansion project significantly affected the Humber refinery's utilization in 1997. (7) Actual inputs to crude distillation units may exceed rated capacity. The yields of Conoco's European refineries by product and country for the year ended December 31, 2001, were as follows:

UNITED CZECH KINGDOM(1) GERMANY REPUBLIC(2) ----------- ------------- ----------- PERCENT OF TOTAL YIELD (13) Motor gasoline ........................................... 28 36 3529 19 Middle distillate ........................................ 4544 4246 3846 Residual fuel oil and asphalt ............................ 610 910 1813 Other (24) ................................................ 1318 148 2512

---------- 26 (1) Significant changes in motor gasoline, resid and other resulted from plant downtime associated with the fire and major turnaround in the second quarter of 2001. (2) Increased production of gasoline and distillate resulted from the FCC unit coming on stream at the Kralupy refinery in 2001. (3) Percentages are volume based, not weight based. (4) Other products primarily include petroleum coke, lubricants and liquefied petroleum gases. United Kingdom Refinery Conoco's wholly owned Humber refinery is located in North Lincolnshire, U.K., and has a crude distillation capacity of 232,000 barrels per day. Crude processed at the refinery is exclusively low or medium sulfur, supplied primarily from the North Sea and includes lower cost, acidic crudes. The refinery also processes other intermediate feedstocks, mostly vacuum gas oils and residual fuel oil, which many other European refineries are not able to process. The refinery's location on the east coast of England provides for cost-effective North Sea crude imports and product exports to European and world markets. The Humber refinery, one of the most sophisticated refineries in Europe, is a fully integrated, high conversion refinery that produces a full slate of light products and minimal fuel oil. The refinery also has two coking units with associated calcining plants, which upgrade the heavy "bottoms" and imported feedstocks into light oil products and high value graphite and anode petroleum cokes. Approximately 58 percent of the light oils produced in the refinery are marketed in the U.K., while the other products are exported to the rest of Europe and the U.S. This gives the refinery the flexibility to take full advantage of inland and global export market opportunities. The Humber refinery sustained damage in a localized area of the plant in the second quarter of 2001 as the result of a fire. There were no serious injuries as a result of the incident and a majority of the refinery units were not damaged. Most of the units were back in operation by the end of the third quarter of the year, although repair work continued on certain units. The fire and a major turnaround in the second quarter significantly impacted refinery utilization and yields in the second and third quarters, but operations resumed to near normal levels by the fourth quarter. Germany Refinery The MiRO refinery in Karlsruhe, Germany, is a joint venture refinery with a crude distillation capacity of 283,000 barrels per day. Conoco has an 18.75 percent interest in MiRO and Conoco's capacity share is 53,000 barrels per day. The other owners of MiRO are DEA Mineraloel AG, Esso AG and Ruhr Oel GmbH, a 50/50 joint venture between Veba and PDVSA. Approximately 60 percent of the refinery's crude feedstock is low cost, high sulfur crude. The MiRO complex is a fully integrated, high conversion refinery producing gasoline, middle distillates, and specialty products along with a small amount of residual fuel oil. The refinery has a high capacity to convert lower cost feedstocks into higher value products, primarily with a fluid catalytic cracker and delayed coker. The coker produces both fuel grade and specialty calcined cokes. The refinery processes crude and other feedstocks supplied by each of the partners in proportion to their respective ownership interests. Czech Republic Refineries Conoco, through participation in CRC, has an interest in two refineries in the Czech Republic: one in Kralupy and the other in Litvinov. The other owners of CRC are Unipetrol A.S., Agip Petroli, and Shell Overseas Investment B.V. The refinery at Litvinov has a crude distillation capacity of 103,000 barrels per day, and the Kralupy refinery has a crude distillation capacity of 63,000 barrels per day. Conoco's 16.33 percent ownership share of the combined capacity is 27,000 barrels per day. Both refineries process mostly high sulfur crude, with a large portion being Russian export blend delivered by pipeline at an advantageous cost. The refineries have an alternative crude supply via a pipeline from the Mediterranean. The commissioning of a visbreaker unit at the Litvinov refinery in 2000 increased conversion rates and significantly reduced fuel oil production. Completion of a fluid catalytic cracking unit at the Kralupy refinery in early 2001 significantly increased light oil yields and reduced the production of less valuable heavy fuel oil. The two Czech refineries are operated as a single entity, with certain intermediate streams moving between the two facilities. CRC markets finished products both inland and abroad. We are using our share of the light oil production to support an expanding retail marketing network in central and eastern Europe. 27 Marketing Conoco has marketing operations in 15 European countries. Our European marketing strategy is to sell primarily through owned, leased or joint venture retail sites using a low cost, high volume, low price strategy. Conoco has a strong reputation in the European marketing area, as evidenced by Wood Mackenzie's 2000 study that ranked our retail marketing operations in the top quartile in marketing efficiency (measured as average sales per station relative to industry average sales per station in countries where Conoco operates). We intend to expand into identified growing markets, while concurrently strengthening our market share in core markets such as Germany, Austria and the Nordic countries. Conoco is standardizing its European retail operations in order to capture cost savings and prepare for a more integrated Europe. We are continuing to reduce our cost structure for marketing activities while also optimizing activities to grow income in the non-fuels sector. We also market aviation fuels, liquid petroleum gases, heating oils, transportation fuels and marine bunkers to commercial customers and into the bulk or spot market. Conoco uses the "JET" brand name to market its retail products in its wholly owned operations in Austria, the Czech Republic, Denmark, Finland, Germany, Hungary, Norway, Poland, Slovakia, Sweden and the U.K. In Belgium and Luxembourg, where we historically marketed under the "SECA" brand, we have now moved to a standardized European offering under the "JET" brand. Stations throughout Europe also display the "Conoco" logo next to the brand, indicating Conoco corporate ownership. In addition, various joint ventures, in which Conoco has an equity interest, market products in Switzerland and Turkey under the "Coop" and "Tabas" or "Turkpetrol" brand names, respectively. As of December 31, 2001, Conoco had 2,033 marketing outlets in its wholly owned European operations, of which 1,154 were company-owned. Through our joint venture operations in Turkey and Switzerland, we also have an interest in another 819 retail sites. Our largest branded site networks are in Germany and the U.K., which account for 61 percent of the total branded units. In Germany and Austria, 24 outlets were added during 2001, most of which were newly constructed sites. In the Nordic countries, we have expanded our base of unattended sites in Sweden, Denmark, Norway and Finland, with 12 new stations in the region. Conoco sold its U.K. network of company-owned retail sites in the fourth quarter of 2001 to Fuelforce Limited. Under terms of the sale, we will supply petroleum products to the outlets that Fuelforce will continue to operate under the "JET" brand. The transaction allows Conoco to maximize the sale of quality products from the Humber refinery through "JET" branded outlets and optimizes overhead and operating and capital costs. Conoco has 130 stations in central and eastern Europe in the Czech Republic, Poland, Hungary and Slovakia as of December 31, 2001. We expect to continue building high quality new stores, retrofitting current stations and rationalizing our network in 2002. Our marketing position should allow us to capture demand growth and expected rising margins in these inland markets and to obtain further integration with products produced at the Czech refineries. In Turkey, Conoco has retail marketing operations through a 28.5 percent joint venture, Turcas, where at the end of 2001, we had an interest in 718 sites. Conoco sold its 50 percent interest in CONSA, a retail marketing joint venture in Spain, in the second quarter of 2001. ASIA PACIFIC Despite the economic downturn in the late 1990s, Conoco views the Asian market as a source for potential long-term growth. We intend to continue the expansion of our marketing operations to integrate with our refining supply and capitalize on market deregulation and long-term regional demand growth. Refining The refinery in Melaka, Malaysia is a joint venture with Petronas, the Malaysian state oil company. We now own a 47 percent interest in the joint venture. The refinery became operational in August 1998, and has a rated crude distillation capacity of about 120,000 barrels per day, of which Conoco's share is 56,400 barrels per day. Conoco's share of refinery inputs, sourced mostly from the Middle East, was 19.5 million barrels for 2001. This volume is equivalent to approximately 53,000 barrels per day. In 2001, Conoco and Petronas completed the acquisition of a 15 percent share in the Melaka refinery from Statoil, the Norwegian state oil company, increasing Conoco's interest to 47 percent from 40 percent. 28 The following tables outline the rated crude distillation capacity as of December 31 for each of the past four years and the average daily inputs to crude distillation units and other feedstocks.

YEAR ENDED DECEMBER 31 -------------------------------------- 2001 2000 1999 1998 -------- -------- -------- -------- (THOUSANDS OF BARRELS OFPER DAY) CRUDE DISTILLATION CAPACITY(1)(2) Melaka, Malaysia .................................~~.....~~ 56 48 45 45 REFINERY INPUTS(1)(3) Melaka, Malaysia Inputs to crude distillation units(4) ..........~~.....~~ 53 39 32 7 ~~Other inputs ........................................ -- -- --~~

---------- (1) Represents Conoco's 47 percent interest in the Melaka refinery for 2001 and Conoco's 40 percent interest for 2000, 1999 and 1998. (2) Reflects all inputs to crude distillation units. (3) Reflects all inputs to crude distillation units and all other inputs (excluding internal recycles). (4) Actual inputs to crude distillation units may exceed rated capacity. The refinery is a high conversion facility that produces a full range of refined petroleum products. The refinery capitalizes on Conoco's proprietary coking technology to upgrade low-cost feedstocks to higher-margin products. The feedstocks for Conoco's capacity in the refinery typically consist of between 70 and 90 percent high sulfur crude with the remainder being regional heavy sweet crude, depending on processing economics. The joint venture has a five-year tax holiday commencing with initial operation. Conoco intends to utilize some of its share of refined products from the refinery to continue growing its retail marketing operations in the Asia Pacific region. The balance of Conoco's share of production will be sold primarily in the spot market. Our regional crude supply and product disposition operations are centrally located in Singapore. Marketing Conoco has established a significant presence in the Thailand retail market. At the end of 2001, Conoco had 132 stores in operation and continued expansion is anticipated in 2002. Conoco has a retail marketing joint venture in Malaysia with Sime Darby Bhd., a company that has a major presence in the Malaysian business sector, initially targeting major markets within 125 miles of the Melaka refinery. A total of 11 stores were in operation at the end of 2001. SPECIALTY PRODUCTS Conoco sells a variety of high value lubricants and specialty products including petroleum coke, lubes, such as automotive and industrial lubricants and waxes, solvents and pipeline flow improvers, to commercial, industrial and wholesale accounts worldwide. Conoco's technical expertise in carbon upgrading positions it as a leader in manufacturing and marketing specialty coke and coke products. We manufacture high quality graphite coke, at our Lake Charles and Humber refineries, for use in the global steel industry. We also globally market anode and fuel coke produced at our Lake Charles, Ponca City, Billings, Humber and joint venture MiRO refineries, as well as fuel coke produced at our joint venture Melaka refinery. In addition, we participate in the Asia Pacific coke market by providing technical and marketing expertise to our PetroCokes joint venture with Sumitomo and Japan Energy. Today our technology is used by more than two dozen coking facilities--a third of the world's delayed coking capacity. Conoco began marketing the HYDROCLEAR(R) brand of lubricants with the start-up of Excel Paralubes in 1997. In 2001, Conoco continued its expansion of marketing the HYDROCLEAR(R) brand of lubricants into Asia Pacific. This growth has been achieved with minimal capital investment as blending and supply chain management activities have been outsourced to established vendors in the region. The HYDROCLEAR(R) lubricants, which are 29 non-toxic, were designed to compete with synthetics for a range of applications with difficult operating conditions. We also have a 50 percent interest in Penreco providing high quality products for use in the global cosmetic, pharmaceutical, industrial and home markets. Conoco is a leader in the worldwide market for pipeline flow improvers. Our "LiquidPower(TM) Flow Improver" product is used for increasing petroleum pipeline capacity by reducing frictional pressure drop or used for energy savings. We also use "LiquidPower(TM) Flow Improver" in our own pipeline systems. In 1999, we introduced "RefinedPower(R) Flow Improver," an innovative new generation product designed for petroleum product pipelines. EMERGING BUSINESSES SUMMARY Emerging businesses encompass the development of new businesses that will take us beyond our traditional operations. These are built on our core businesses and have the potential to contribute substantially to long-term growth. At present, these new businesses include our carbon fibers (Conoco Cevolution(R)), natural gas refining and international power businesses. CARBON FIBERS In January 2000, Conoco announced its entry into the carbon fiber industry with the formation of Conoco Carbon Fibers, a new business solely dedicated to the manufacture, marketing, and sale of the company's new mesophase pitch-based carbon fiber technology, which was also introduced at that time. In June 2001, we changed the name of Conoco Carbon Fibers to Conoco Cevolution to reflect our new rapidly expanding market scope. This initiative included building upon Conoco's leadership position in carbon customization with the development and integration of several new carbon technologies into Conoco Cevolution's growing portfolio of products. Conoco Cevolution now offers customers a variety of advanced carbon technology solutions, targeting a broad range of potential applications in several key global industries. These include plastics, composites, automotive, electrical/electronics, telecommunications, data storage and entertainment devices, computers and business machines, building and construction, infrastructure, and portable power, as well as a number of high-end, niche market segments. We expect to complete the construction of our first commercial-scale carbon fibers manufacturing plant located in Ponca City, Oklahoma with first production expected in mid-2002. The plant has an initial capacity of 4 million pounds per year and is designed to allow expansion up to 8 million pounds per year. Conoco Cevolution is headquartered in Houston, with technical facilities located in Ponca City. In December 2000, we opened a new office in Tokyo to serve our growing Asian customer base, and in September 2001, we opened a second regional office in Amsterdam, the Netherlands, to benefit our European customers. NATURAL GAS REFINING In 1997, Conoco initiated a natural gas refining program, with the goal to develop the best technology solution for stranded gas reserves around the world. Stranded gas reserves are those gas reserves that are located in areas from which they may not be currently economically transported to market. The volume of stranded gas reserves is thought to be significant, and Conoco believes that this large volume of stranded gas reserves presents an opportunity to develop new competitive gas technologies that can create future value. The natural gas refining program includes research into several alternative gas technologies, but gas-to-liquids (GTL) is the main emphasis. The GTL process refines natural gas into a wide range of transportable products, from light naphtha, kerosene and diesel to heavier waxes, high-quality lubricants and white oils. Developing our natural gas refining technologies is a technology group of approximately 140 people working at our natural gas refining research facility in Ponca City, Oklahoma. The research facility includes state-of-the-art laboratories and pilot plants to facilitate technology advancements. A GTL plant consists of three major processes: synthesis gas production, synthesis gas conversion and product refining. We have developed proprietary technology 30 for both synthesis gas production and synthesis gas conversion. Our GTL technology is being developed with a focus on reducing costs and increasing product yields to a level where commercial plants can be built. A 400-barrel per day demonstration plant is under construction in Ponca City and is scheduled for completion during the fourth quarter of 2002. A successful program would give us a technology that could result in significant new business opportunities. There are several different ways of commercializing this technology, and also many integration opportunities exist for our upstream and downstream businesses. INTERNATIONAL POWER Conoco Global Power was restructured in mid 2001, to accomplish two primary objectives: o capitalize on the gas/power convergence in North America by merging the remaining natural gas and power development groups into our Gas and Power Marketing organization; and o develop new markets outside North America for stranded/undervalued gas reserves via power generation. The focus will be on developing integrated projects in support of our upstream and downstream strategies and business objectives, with a goal of monetizing natural gas reserves and strengthening the downstream portfolio. We hope to accomplish this by bringing together people with project development skills, commercial skills, engineering skills, water desalination skills, and economic evaluation skills. During 2001, Conoco Global Power completed the divesture of its 37.5 percent interest in a Colombian power venture. The divestiture was completed in the first quarter of 2001. Conoco Global Power is developing a 730-megawatt combined heat and power cogeneration plant in North Lincolnshire, U.K. The facility will provide steam and electricity to the Conoco refinery and a neighboring refinery, as well as market power into the U.K. market. Construction is scheduled to begin in 2002 with commercial operation anticipated in 2004. ELECTRONIC COMMERCE During 2000, Conoco participated in a number of electronic business-to-business (B2B) initiatives. These initiatives included Internet marketplaces for procurement of goods and services, as well as wholesale energy trading. Additionally, in 2001, we participated in a joint venture to provide heavy equipment condition monitoring systems via the Internet. Because some of these investments in B2B initiatives are in new or unproven technologies and business processes, ultimate success is not always certain. Although not all initiatives may prove to be economically viable, our overall investment in this area is not significant to our consolidated financial position. CORE VALUES Conoco is committed to four core values: operating safely, protecting the environment, behaving ethically, and valuing all people. Each year, Conoco President's Awards honor individuals and teams of employees for advancing these core values. Conoco's core values provide the foundation for the company's commitment to sustainable growth and support the basic tenets of sustainability -- financial excellence, environmental responsibility, and social progress. Sustainability integrates Conoco's core values with business excellence. Conoco issued its first sustainable growth report to show how the company creates value for shareholders while maintaining respect for environmental and social considerations. The report, "Conoco Sustainable Growth Report -- a Look at Our Progress, May 2001," documents Conoco's successes, takes a look at areas in need of improvement, and outlines the company's commitment to sustainable growth. The document is a major step in Conoco's journey toward transparency and includes a record of the company's global environmental and safety performance and sustainable development goals for 2001. The report received worldwide recognition, including coverage on CNN. At the local level, two U.S. downstream businesses issued their own sustainability reports, further driving stakeholder engagement in their communities. 31 For the second consecutive year, in 2001 Conoco was selected as a component of the Dow Jones Sustainability World Index (DJSI), formerly known as the Dow Jones Sustainability Group Index. The DJSI represents the top 10 percent of sustainability companies worldwide that exhibit strength in balancing environmental protection, social and cultural responsibility, and economic performance. Conoco also was named to the FTSE4Good U.S. 100 Index, a stock index representing the 100 largest U.S. companies with high standards of corporate social responsibility. Conoco was the only oil and gas company to make the list. In 2001, the Houston Business Journal named Conoco as the "Best Place to Work" in Houston among companies with more than 500 employees. In 2001, Conoco maintained its record level of employee safety performance. Conoco is the safest integrated global energy company in the United States, according to data published in the American Petroleum Institute (API) annual survey of Occupational Injuries and Illnesses in the Petroleum Industry for performance in 2001. This was the fifth consecutive year, as well as the 17th time in the past 23 years, that Conoco topped the safety list among its industry peers. Conoco also ranked No. 1 for the third consecutive year in API's third survey of the industry's safety performance outside the United States. Operating responsibly requires diligence in carrying out the company's operations safely - in a manner that not only manages risks, but also uses comprehensive incident and crisis management systems to effectively mitigate the impact of any unplanned event. In 2001, significant progress was made in furthering Conoco's crisis management and emergency response capability at both the corporate and the business levels. The company's ability to respond effectively to a crisis is drilled extensively. In 2001, Conoco received external recognition for its environmental leadership and innovation. Conoco was awarded the European Bank for Reconstruction and Development's Corporate Environmental Award, recognizing the environmental excellence of Conoco's Polar Lights joint venture in Russia. The company was honored by the Canadian Council of Ministers of the Environment for outstanding efforts showing innovation and leadership in pollution prevention for significant reductions in greenhouse gas emissions. In addition, our Canadian operations again were recognized as a Gold Champion Level Reporter by the Canadian Voluntary Challenge and Registry, a not-for-profit organization commissioned by the Canadian Federal Government to promote voluntary reduction of greenhouse gas emissions. Conoco's Indonesian operations received a first place award for Safety, Health and Environment from Pertamina, Indonesia's national oil company. Conoco (U.K.) Limited, Conoco's upstream business unit in the United Kingdom, received full company ISO 14001 certification in 2001. One of our upstream operations in the Middle East and a downstream lubricants facility in the U.S. also received ISO 14001 certification. Our U.S. CG&P division continues its leadership role by participating in the United States Environmental Protection Agency (USEPA) Natural Gas Star program to reduce methane emissions in the oil and gas industry. Conoco began operating only double-hulled tankers in U.S. waters in 1998. Today, Conoco operates a fleet of 100 percent double-hulled crude oil tankers globally and a 100 percent double-hulled tank barge fleet in U.S. waters. Conoco's international fleet of tankers is required to maintain American Bureau of Shipping International Safety Management System (ISM) certification. ISM certification verifies that the company has met the rigorous International Maritime Organization standard requirements for a marine safety and pollution prevention management system. In 2001, Conoco's U.S. marine operations proactively pursued voluntary certification of the inland tank barge fleet and received certification following rigorous audits of each vessel and the overall management system. In order to maintain high ethical standards, Conoco has a formal ethics policy and established procedures for conducting business with integrity and in compliance with all applicable laws. At Conoco, adherence to Conoco's published ethics policy is a condition of employment. Employees are required to review the policy and procedures regularly and complete an annual certificate of compliance. We also have a 24-hour telephone hotline that provides employees an avenue for seeking guidance on ethics issues or reporting possible problems. As an international energy company, Conoco has an extremely diverse global workforce. By drawing on the different perspectives and cultures of our 20,000 employees, along with their combined knowledge and creativity, Conoco has a powerful business advantage around the world. At Conoco, we strive to create an inclusive work environment that treats all people with dignity and respect, and encourages employees to express their ideas and develop to their maximum ability. This helps employees reach their personal career goals, while increasing their contributions toward achieving the company's objectives. Conoco in 2001 awarded employees globally a "Learning is Timeless" gift. Employees were able to select from several choices of high-tech learning tools for their personal use. Such investments in our employees contribute to their personal development and motivation and results in a highly motivated, innovative work force. 32 We believe these core values result in a motivated workforce with values and goals firmly aligned with the strategic aims of the business. This belief is reinforced through our 2001 Employee Opinion Survey results, which reached an eight-year high, indicating employees were quite pleased with the company and their jobs. Core values guide employees in working to meet the expectations of customers, partners and host governments, and in respecting the communities in which we do business. In addition, we believe our commitment to core values reduces liabilities, helps to manage risks and improves business performance. The financial success of Conoco -- which is influenced by performance in our core values -- is shared with substantially all employees through the "Conoco Challenge" and "Global Variable Compensation" programs. ENVIRONMENTAL ISSUES Conoco adheres to a comprehensive published environmental policy. Conoco's environmental policy, originally adopted in 1968, has guided the company for more than 30 years. The policy statement is "Our company will conduct business with respect and care for the environments in which we operate." More specifically, the policy addresses minimizing the environmental impact of our operations, fostering open communication of company environmental performance, systematically managing environmental performance, and continually improving the total environmental performance of the company. The Board of Directors' Audit and Compliance Committee provides oversight of performance as set forth in environmental policy, standards, and goals. Conoco's Management Committee provides strategic direction for environmental policy and reviews performance. Corporate staff oversees the governance, implements standards, conducts safety and environmental audits, and tracks company performance. Environmental professionals within Conoco's global business units support local management in managing environmental affairs and performance. The Vice President, Safety, Health and Environment provides overall coordination and reports to the President and Chief Executive Officer. Conoco and each of its various businesses are subject to numerous international, federal, state, and local laws and regulations relating to the protection of the environment. These environmental laws and regulations include, among others, the: o federal Clean Air Act (CAA), which governs air emissions; o federal Clean Water Act (CWA), which governs discharges to water bodies; o federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), which imposes liability on generators, transporters, and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatened to occur; o federal Resource Conservation and Recovery Act (RCRA), which governs the treatment, storage, and disposal of solid waste; o federal Oil Pollution Act of 1990 (OPA) under which owners and operators of onshore facilities and pipelines, lessees or permittees of an area in which an offshore facility is located, and owners and operators of vessels are liable for removal costs and damages that result from a discharge of oil into navigable waters of the United States; o federal Emergency Planning and Community Right-to-Know Act (EPCRA) which requires facilities to report toxic chemical inventories with local emergency planning committees and responses departments; o federal Safe Drinking Water Act (SDWA) which governs the disposal of wastewater in underground injections wells; and o U.S. Department of the Interior regulations, which relate to offshore oil and gas operations in U.S. waters and impose liability for the cost of pollution cleanup resulting from the lessee's operations and potential liability for pollution damages. Moreover, many states and foreign countries where Conoco operates have similar environmental laws and regulations covering the same types of matters. The ultimate financial impact arising from these environmental laws and regulations is neither clearly known nor easily determined as new standards, such as new air emission standards, water quality standards and stricter fuel regulations, continue to evolve. Notwithstanding, environmental laws and regulations are expected to have an increasing impact on Conoco's operations here in the United States and in most of the countries in which the 33 company operates. Notable areas of potential impacts include air emission compliance and remediation obligations. Under the CAA, the USEPA has promulgated a number of stringent limits on air emissions and established a federally mandated operating permit program. Violations of the CAA are enforceable with civil and criminal sanctions. Moreover, the new CAA Tier II Fuels regulations pertaining to gasoline fuels, finalized by the USEPA in early 2000, and the regulations pertaining to on-road diesel fuels, finalized by the USEPA in early 2001, require substantially reduced sulfur levels. Conoco is positioning itself to be able to supply the low-sulfur gasoline according to the phase-in schedule. While the on-road diesel regulations have been finalized, the regulations controlling the future sulfur content of off-road diesel fuel emissions have not been issued which has complicated estimating diesel compliance costs because those two products are inherently tied in the refining process. New technologies are also being developed in the industry that may lower the capital costs of compliance with these regulations. Conoco continues to assess the compliance costs associated with the Tier II Fuels regulations, and while it is premature to estimate these costs accurately, Conoco expects to average less than 20 percent to 25 percent of its yearly downstream capital spending over the next six years to install the appropriate equipment. Similarly, the European Parliament enacted legislation in October 1998 that, among other things, required phased reductions of the sulfur and aromatics content in gasoline and diesel fuel and of benzene in gasoline. Our European refineries already are in compliance with the first level of sulfur reduction and we already have the ability to produce some of the 2005 specification gasoline and diesel at both the Humber and MiRO refineries. The costs to comply with the 2005 specifications will not be significant. We also are studying the possibility of producing 2011 specification products well in advance of that required date. Additional areas of potential air-related impacts to Conoco are the proposed revisions to the National Ambient Air Quality Standards (NAAQS) and the Kyoto Protocol. In July 1997, the USEPA promulgated more stringent revisions to the NAAQS for ozone and particulate matter. Since that time, final adoption of these revisions has been the subject of litigation (American Trucking Association, Inc. et al. v. United States Environmental Protection Agency) that eventually reached the U. S. Supreme Court during fall 2000. In February 2001, the U. S. Supreme Court remanded this matter in part to the USEPA to address the implementation provisions relating to the revised ozone NAAQS. If adopted, the impact of the revised NAAQS could result in substantial future environmental expenditures for Conoco. In 1997, an international conference on global warming concluded an agreement, known as the Kyoto Protocol, which called for reductions of certain emissions that contribute to increases in atmospheric greenhouse gas concentrations. The United States has not ratified the treaty codifying the Kyoto Protocol but may in the future. In addition, other countries where Conoco has interests, or may have interests in the future, have made commitments to the Kyoto Protocol and are in various stages of formulating applicable regulations. Although it is not yet possible to estimate accurately the total actual expenditures that may be incurred by Conoco as a result of the Kyoto Protocol, such expenditures could be substantial. Conoco also is subject to certain laws and regulations relating to environmental remediation obligations associated with current and past operations. Such laws and regulations include CERCLA and RCRA and their state equivalents. Conoco's estimated remediation expenditures related to its CERCLA and RCRA matters are discussed in Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of Operations -- Environmental Expenditures. Remediation obligations include clean-up responsibility arising from petroleum releases from underground storage tanks (UST) located at numerous past and present Conoco owned and/or operated petroleum-marketing outlets throughout the United States. Federal and state laws require that contamination caused by such UST releases be assessed and remediated to meet applicable standards. In addition to other clean-up standards, many states have adopted clean-up criteria for methyl tertiary butyl ether (MTBE) for both soil and groundwater. MTBE standards continue to evolve, and future environmental expenditures associated with the remediation of MTBE contaminated UST sites could be substantial. Notwithstanding any of the foregoing and as with other companies engaged in similar businesses, environmental costs and liabilities are inherent in Conoco's operations and products and there can be no assurance that material costs and liabilities will not be incurred. However, Conoco currently does not expect any material adverse affect upon its results of operations or financial position as a result of compliance with environmental laws and regulations. For a discussion of our operating expenses and capital expenditures with respect to environmental protection, see Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of Operations -- Environmental Expenditures, and Item 3 -- Legal Proceedings. 34 SOURCES OF SUPPLY During 2001, Conoco supplemented its own crude oil production to meet its refining requirements by the purchase of crude oil from both domestic and international sources. Approximately 46 percent of the crude oil processed in our U.S. refineries in 2001 came from U.S. sources. The remainder of crude oil processed came principally from Venezuela, Mexico and Canada. During 2001, Conoco's Humber refinery processed principally North Sea crude oils. In the MiRO joint venture refinery, Conoco processed primarily Mediterranean crude oils, while Conoco's joint venture CRC refineries processed primarily Russian crude oils. The majority of the crude oil processed in our Melaka joint venture refinery was from the Middle East. RESEARCH AND DEVELOPMENT The objectives of Conoco's research and development programs are to discover new products, processes and business opportunities in relevant fields, and to improve existing products and processes. Research and development also focuses on optimizing existing assets and improving efficiency, safety and environmental protection. Worldwide expenditures for research and development amounted to approximately $96 million in 2001, $58 million in 2000 and $54 million in 1999. PATENTS AND TRADEMARKS Conoco owns and is the licensee under various patents, which expire from time to time, covering many products, processes and product uses. No individual patent is of material importance to Conoco's business as a whole. During 2001, we were granted 10 U.S. and 38 non-U.S. patents. We also have individual trademarks and brands for our products and services, which are registered in various countries throughout the world. None of these trademarks and brands is considered material other than the "Conoco" and "JET" brands. OPERATING HAZARDS AND INSURANCE Conoco's operations are subject to certain operating hazards, such as well blowouts, collapsed wells, explosions, uncontrolled flows of oil, natural gas or well fluids, fires, formations with abnormal pressures, pipeline ruptures or spills, refinery explosions, surface or marine transportation incidents, pollution, releases of toxic gas and other environmental hazards and risks. In accordance with customary industry practices, Conoco maintains insurance against some, but not all, of such risks and losses. Given our risk profile, and in accordance with the practices of a number of major, integrated, international energy companies, Conoco does not carry business interruption insurance. Conoco discontinued its limited business interruption insurance in late 2001 because of several factors including the high cost of such insurance relative to Conoco's spread of risks, a favorable long-term loss history, and loss prevention and safety programs. Conoco has elected to retain risks where management believes the cost of insurance, although available, is excessive for the risks presented. In addition, pollution and environmental risks are generally not fully insurable. PROPERTIES Conoco's corporate headquarters, consisting of 16 three-story buildings on a 62-acre site, is located in Houston, Texas. We own and lease petroleum properties and operate production processing, refining, marketing, power generating and research and development facilities worldwide. In addition, we operate sales offices, regional purchasing offices, distribution centers and various other specialized service locations throughout the world. EMPLOYEES Conoco had about 20,000 employees at December 31, 2001, approximately 2,400 more employees than last year. Approximately 1,400 employees at our four U.S. refineries are primarily represented by the Paper, Allied-Industrial, Chemical and Energy Workers International Union, under separate bargaining agreements for each refinery. These agreements cover wages; certain benefits matters; grievance procedures and various employment conditions; and we believe they are typical of the refining industry in the U.S. ITEM 3. LEGAL PROCEEDINGS In June of 1997, Conoco experienced pipeline spills on its Seminoe pipeline at Banner, Wyoming and Lodge Grass, Montana. In response to these spills, the U.S. Department of Justice (DOJ) advised Conoco in August 2000 35 that the U.S. Government is contemplating a legal proceeding under the Clean Water Act against Conoco. Conoco and DOJ are currently in negotiations to resolve these matters. In June 1998, the United States Environmental Protection Agency (USEPA) and the Louisiana Department of Environmental Quality (LDEQ) conducted a multi-media environmental inspection of Conoco's Lake Charles refinery. The U.S. and the State of Louisiana, in response to the inspection findings, filed an enforcement action under the Clean Water Act and Clean Air Act. In 2001, Conoco, LDEQ and USEPA entered into a Consent Decree to resolve this matter. Under this Consent Decree, Conoco agreed to pay a civil penalty of $240,000. On March 27, 2000, the Montana Department of Environmental Quality (MDEQ) issued a Notice of Violation (NOV) to Conoco for alleged exceedences of Montana's 3-hour SO2 limit at the Billings refinery. On March 1, 2001, Conoco received an Enforcement Action Letter indicating Montana's proposed penalty of $3 million for these alleged violations. Subsequently, the parties negotiated a tentative settlement in which Conoco will pay a cash penalty of $207,300 and perform a supplemental environmental project valued at $3 million to $5 million. During June 2001, the New Mexico Environmental Department (NMED) issued two Compliance Orders to Conoco, one related to the Maljamar Gas Plant and the other related to the San Juan Basin Gas Plant. The NMED alleges that the Maljamar Gas Plant exceeded air quality emission limits and failed to complete compliance tests within the specified time period. The NMED further alleges that the San Juan Basin Gas Plant failed to design and operate a flare with no visible emissions. In December 2001, the parties agreed to settle both matters by paying $200,000 to the State of New Mexico and making a commitment to redesign flare operations at the San Juan Basin Gas Plant. During August 2001, the USEPA issued a NOV to Conoco for certain alleged violations of the federal fuels regulations of the Clear Air Act. The NOV arises from a June 1998 USEPA audit of each of Conoco's Billings, Denver, Lake Charles and Ponca City refineries and its Conoco Center complex in Houston, Texas. The NOV seeks a penalty of $190,000. During August 2001, the USEPA and the U.S. DOJ notified Conoco of their intent to seek sanctions for alleged violations of the Clean Air Act arising from a 1998 Maximum Achievable Control Technology (MACT) compliance test of a flare at Conoco's Denver refinery. The USEPA and DOJ seek a cash penalty of $38,775 and the performance of a Supplemental Environmental Project (SEP) valued at $130,000. In 2000, Conoco conducted an audit of its air compliance systems at the Denver refinery. Conoco then self reported the results of this audit. Beginning in August 2001, Conoco and the State of Colorado began negotiating a resolution associated with the self-reported items. In December 2001, Conoco agreed to pay a civil penalty of $139,800 and perform a supplemental environmental project valued at $630,000 to resolve this matter. Conoco conducted negotiations with the USEPA and the states of Colorado, Louisiana, Montana, and Oklahoma throughout 2001 as part of USEPA's nationwide initiative to enforce federal air regulations at petroleum refineries. In December 2001, Conoco entered into a Consent Decree with the United States, Colorado, Louisiana, Montana and Oklahoma to reduce emissions from Conoco's Billings, Denver, Lake Charles and Ponca City refineries by a total of 7,500 tons per year over the next seven years. Conoco will spend an estimated $95 million to $110 million over the next seven years to install control technology and equipment to reduce emissions from stacks, vents, valves, heaters, boilers and flares. The Consent Decree requires Conoco to pay a civil penalty of $1.5 million, in addition to $5.1 million to be spent on supplemental environmental projects in Colorado, Louisiana, Montana and Oklahoma. This Consent Decree also resolves certain refinery air compliance issues previously self-disclosed to the state environmental agencies for Colorado, Montana and Oklahoma. Other self-disclosed air compliance issues that were outside the scope of the Consent Decree have been or will be resolved by consent orders entered directly with the appropriate state agency. An accrual of $112 million was recorded during the fourth quarter of 2001 for a litigation settlement related to certain discontinued chemicals businesses for which Conoco assumed responsibility for claims as a result of the separation agreement with DuPont. On May 2, 2000, a jury in federal court in Virginia found that Conoco infringed patents of General Technology Applications (GTA) involving part of a process for manufacturing flow improver products. The amount awarded as damages was $55 million. The Federal Circuit Court of Appeals handed down a decision on September 19, 2001 without a written opinion, affirming the trial court's verdict. On November 9, 2001, we paid approximately $60 36 million that included interest to the settlement date, in partial satisfaction of the judgment. The parties entered into settlement negotiations and in December 2001 reached a confidential settlement of all disputes between the parties. Conoco is subject to various lawsuits and claims including but not limited to: actions challenging oil and gas royalty and severance tax payments; actions related to gas measurement and valuation methods; actions related to joint interest billings to operating agreement partners; claims for damages resulting from leaking underground storage tanks; and related toxic tort claims. As a result of the separation agreement with DuPont, Conoco also has assumed responsibility for current and future claims related to certain discontinued chemicals and agricultural chemicals businesses operated by Conoco in the past. In general, the effect on future financial results is not subject to reasonable estimation because considerable uncertainty exists. The ultimate liabilities resulting from such lawsuits and claims may be material to results of operations in the period in which they are recognized. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matter was submitted during the fourth quarter of 2001 to a vote of security holders through the solicitation of proxies or otherwise. EXECUTIVE OFFICERS OF THE REGISTRANT

NAME AGE (1) POSITION WITH THE COMPANY ---- ------- ------------------------- Archie W. Dunham...................... 6263 Chairman, President and Chief Executive Officer ~~Gary~~Robert E. McKee III................... 55 Executive Vice President, Exploration Production Jimmy W. ~~Edwards~~Nokes........................ 5955 ~~Senior~~ Executive Vice President, ~~Corporate~~Refining, ~~Strategy~~Marketing, Supply and ~~Development~~Transportation Robert EW. ~~McKee III~~Goldman..................... 5459 ~~Executive~~Senior Vice President, ~~Exploration~~Finance, ~~Production~~and ~~Jim~~Chief WFinancial Officer Rick A. ~~Nokes~~Harrington.................... 57 Senior Vice President, Legal, and General Counsel Phillip L. Frederickson............... 5445 ~~Executive~~Senior Vice President, ~~Refining,~~Corporate ~~Marketing,~~Strategy ~~Supply~~ and ~~Transportation~~Business ~~Robert~~Development WThomas C. ~~Goldman~~Knudson..................... 5855 Senior Vice President, ~~Finance~~Human Resources, ~~and~~Information ~~Chief~~Management ~~Financial~~and ~~Officer~~Corporate ~~Rick~~Communications AJ. ~~Harrington~~Michael Stinson.................... 5658 Senior Vice President, ~~Legal,~~Government ~~and General Counsel~~Affairs

---------- (1) As of March 12, 2002. Set forth below is information concerning the current executive officers. Archie W. Dunham has been Chairman of the Board of Conoco since August 12, 1999 and the President and Chief Executive Officer of Conoco since 1996. He joined Conoco in 1966 and subsequently held a number of commercial and managerial positions within Conoco and DuPont. Mr. Dunham is also a member of the boards of directors of Louisiana-Pacific Corporation, Phelps Dodge Corporation and Union Pacific Corporation. Mr. Dunham is a former Executive Vice President, Exploration Production and Executive Vice President, Refining, Marketing, Supply and Transportation for Conoco. He was also a Senior Vice President, Polymers and an Executive Vice President of DuPont. He is a director of the American Petroleum Institute, the U.S.-Russia Business Council and the Greater Houston Partnership. He is a past Chairman of both the United States Energy Association and the National Petroleum Council and a member of The Business Council and The Business Roundtable. Mr. Dunham is also a member of the board of visitors at the University of Oklahoma. He serves on the board of the Memorial Hermann Healthcare System in Houston, the board of visitors of M.D. Anderson Cancer Center and the board of trustees of the Houston Symphony, the George Bush Presidential Library and the Smithsonian Institution. Mr. Dunham is the Chairman and a trustee of the Houston Grand Opera. Robert E. McKee III has been an Executive Vice President for Conoco since 1992, and was a Senior Vice President of DuPont until October 27, 1998 with responsibility for worldwide exploration and production. He was formerly Conoco's Executive Vice President for Corporate Strategy and Development, Senior Vice President for Administration, Vice President of North American Refining and Marketing and Vice President, Chairman and Managing Director of Conoco (U.K.) Limited. Since he joined Conoco in 1967, Mr. McKee has worked at various 37 locations and held numerous managerial, operating, administrative and technology positions both in the U.S. and overseas. He currently serves on the board of directors of the American Petroleum Institute and is a former director of Consol Energy Inc. and Consol Inc. In addition, he is a past Chairman of the Southern Regional Advisory Board of the Institute of International Education and a member of the advisory committee of the University of Texas Engineering Department. Mr. McKee also serves as Chairman of the President's Council of the Colorado School of Mines. Jimmy W. Nokes has been Executive Vice President for Conoco since November 1999, with responsibility for worldwide refining, marketing, supply and transportation, and was President of North American Refining and Marketing from 1998 until 1999. Mr. Nokes was Vice President of North American Refining and Marketing from 1994 until 1998. Since he joined Conoco in 1970, Mr. Nokes has held various administrative, planning and operating management positions with Conoco's gas and natural gas processing departments and a pipeline subsidiary. In 1989, he transferred to London to serve as Director and General Manager of Business Development for Conoco's exploration and production affiliate, returning to the U.S. in 1991 to become Vice President and General Manager for North American Marketing. Robert W. Goldman has been Senior Vice President, Finance, and Chief Financial Officer of Conoco since 1998 and was its Vice President, Finance from 1991 to 1998. Mr. Goldman began his career with DuPont in 1965 and subsequently held many technical and managerial positions within the finance, tax and treasury functions both in the United States and internationally. He is the former Treasurer, DuPont (Puerto Rico, Inc.), Vice President-Finance of DuPont (Mexico), and Vice President, Remington Arms Company; and served as Director and Comptroller of several operating departments of DuPont in Wilmington, Delaware. Mr. Goldman transferred to Conoco in 1988 as Vice President and Controller. He currently serves on the Board of Directors and Audit Committees of Conoco Canada Resources Limited and Gulf Indonesia Resources Limited. He is co-chairman of Conoco's Risk Management Committee and is a member of the American Petroleum Institute, a former chairman of its Accounting Committee and currently serves on its Executive Committee of the General Committee on Finance. Mr. Goldman is on the Advisory Board of the Center for Finance Education and Research of the McCombs School of Business at the University of Texas at Austin. He is also a member of the Financial Executives Institute and the Executive Committee of the Board of Directors of the Alley Theatre in Houston, Texas. Rick A. Harrington has been Senior Vice President, Legal and General Counsel of Conoco since 1998. He was named Vice President and General Counsel for Conoco in 1994. Mr. Harrington joined DuPont in 1979 as a senior litigation attorney and subsequently held the positions of Managing Counsel, Special Litigation, and Vice President and General Counsel of Consolidation Coal Company. Prior to joining DuPont, he was a partner in the firm of Arent, Fox, Kintner, Plotkin and Kahn in Washington, D.C. where he specialized in antitrust litigation. Mr. Harrington is a member of the bar of the District of Columbia, the District of Columbia Court of Appeals and the Fifth Circuit Court of Appeals. He is past Chairman of the American Petroleum Institute General Committee on Law and served on the American Corporate Counsel Board of Directors. Currently, Mr. Harrington serves on the Conoco Executive Committee and the Conoco Management Committee. He is also a Director of Gulf Indonesia Resources Limited and the Minority Corporate Counsel Association. Philip L. Frederickson has been Senior Vice President of Corporate Strategy and Business Development since November 2001. He joined Conoco in 1978 and held a series of positions supporting the company's U.S. transportation operations and its natural gas business. In 1987 he was named Manager of Planning and Administration for the company's North American Petroleum Products Department. Mr. Frederickson transferred to London in 1989 as General Manager for the European refining and marketing operations. He then became President and Managing Director of Conoco Ireland, headquartered in Dublin. He returned to Houston in 1990 and served in assignments in U.S. retail and global downstream operations. In 1994 he was named General Manager of Refining and Marketing Operations in the Rocky Mountain region. He returned to Houston in 1997 to become General Manager of Strategy and Portfolio Management for Conoco's upstream segment and became Vice president of Business Development in 1998. Mr. Frederickson is a member of the Texas Tech University Industrial Engineering Academy. He serves on the Board of Directors of Theatre Under the Stars. Thomas C. Knudson has been Senior Vice President, Human Resources, Information Management and Corporate Communications since November 2001. Prior to his current position, he was Vice President, Human Resources since July 2000. He is a graduate of the U.S. Naval Academy and served as a naval aviator before joining Conoco's natural gas and gas products division in Houston in 1975. His career includes assignments as Chief Executive Officer of DuPont Scandinavia, General Manager of External Affairs and Communications, General Manager of Business Development for Conoco's upstream business. He was Vice President and General Manager 38 for Natural Gas and Gas Products from June 1995 to June 1997. From June 1997 to July 2000, he was Chairman of Conoco Exploration Production Europe Limited, based in London, where he was responsible for developing and executing the company's upstream strategy throughout Europe and the former Soviet Union. Knudson was the founding president of the Business Council for Sustainable Development (BCSD) in the Gulf of Mexico and most recently was the founding Chairman of the BCSD in the North Sea Region. He currently serves on the boards of the Houston Museum of Natural Science, Covenant House Texas, and Alpha Houston. J. Michael Stinson has been Senior Vice President, Government Affairs since November 2001. He joined Conoco in 1965. He held a number of positions in the U.S. before being named a Director and General Manager for Conoco (U.K.) Limited in 1982. He has served as President of Conoco Norway Inc. and as the Chairman and Managing Director of Conoco (U.K.) Limited. He became Vice President of Business development in 1993. In 1998 he was named Senior Vice President, Government Affairs, Corporate Strategy and Communications. Mr. Stinson is a fellow of the Institute of Petroleum and a member of the American Petroleum Institute, the Society of Petroleum Engineers and the American Association of Petroleum Geologists. He is past Chairman of the American Heart Association's Houston Division. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS MARKET, STOCK AND DIVIDEND INFORMATION Conoco's common stock (symbol: COC) is listed on the New York Stock Exchange, Inc. The number of record holders of common stock was 8,685 at March 1, 2002. On September 21, 2001, Conoco's shareholders approved the combination of Conoco's Class A and Class B common stock into a single class of new common stock on a one-for-one basis. The combination was effective on October 8, 2001. QUARTERLY COMMON STOCK PRICES AND DIVIDENDS

COMMON STOCK PRICE RANGE(1) ---------------------------------------------- 2001 2000 ~~1999~~ ---------------------- ---------------------- HIGH LOW HIGH LOW ---------- ---------- ---------- ---------- CLASS A COMMON STOCK First quarter ..................... $ 2730.8879 $ 1825.8175 $ 2527.4488 $ 1918.3881 Second quarter .................... 2732.0699 2226.0030 3127.2506 22.9400 Third quarter ..................... 31.60 23.65 27.63 21.38 ~~29.25 25.31~~ Fourth quarter .................... 2926.5658 24.0060 29.0656 2024.9400 CLASS B COMMON STOCK First quarter ..................... 28$ 31.7510 19$ 26.00 --$ --28.75 ~~Second~~$ ~~quarter~~ 19.~~................... 29.~~00 ~~23.25~~Second ~~-- -- Third~~ quarter .................... 33.35 2826.75 ~~22.31~~ 29.3800 2423.5025 ~~Fourth~~Third quarter ..................... 2932.6900 2423.6977 28.~~94 20.~~75 ~~DIVIDENDS PER SHARE~~ 22.~~..............~~31 ~~2000~~Fourth ~~1999 -------- -------- First~~ quarter ..................... $ 26.1957 $ 24.1461 ~~Second quarter~~ 29.~~...................~~69 24.1969 ~~.19~~COMMON ~~Third~~STOCK ~~quarter ..................... .19 .19~~ Fourth quarter .................... ~~.19 .19 -------- -------- Total Dividends per Share .........~~ $ 28.7680 $ 23.7197 ~~========~~n/a ~~========~~n/a

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

~~YEAR~~DIVIDENDS ~~ENDED~~PER ~~DECEMBER~~SHARE 312001 ~~--------------------------------------------------------~~ 2000 ~~1999 1998 1997 1996~~ -------- --~~------~~ -------- --~~------~~ ~~--------~~First ~~(IN~~quarter ~~MILLIONS, EXCEPT PER SHARE) STATEMENT OF INCOME DATA Sales and other operating revenues~~ ............... ~~$ 38,737 $ 27,039 $ 22,796 $ 25,796 $ 24,230 Equity in earnings of affiliates~~ ...........~~......~~ ~~277~~$ ~~150~~.19 22$ 40.19 ~~(25)~~Second ~~Other~~quarter ~~income~~ .........................~~............~~ ~~273 120 350 427 211 -------- -------- -------- -------- -------- Total revenues(1)~~ .~~...............................~~19 ~~39,287 27,309 23,168 26,263 24,416 Cost of goods sold~~ .~~..............................~~19 ~~23,921~~Third ~~14,781~~quarter ~~11,751 14,333 12,847 Operating expenses~~ ..........................~~.....~~ ~~2,215 2,060 2,089 1,893 1,713 Selling, general and administrative expenses(2)~~ .~~................................~~19 ~~794 809 972 726 755 Exploration expenses(3)~~ .~~.........................~~19 ~~279~~Fourth ~~270~~quarter ~~380 457 404 Depreciation, depletion and amortization (DD&A)~~ .........................~~.............~~ ~~1,301 1,193 1,113 1,179 1,085 Taxes other than on income(1)~~ .~~...................~~19 ~~6,981 6,668 5,970 5,532 5,637 Interest and debt expense~~ .~~.......................~~19 ~~338 311 199 36 74~~ -------- --~~------~~ -------- --~~------~~ ~~--------~~Total ~~Income~~Dividends ~~before~~per ~~income~~Share ~~taxes~~ ..............~~.........~~ ~~3,458 1,217 694 2,107 1,901 Provision for income taxes ....................... 1,556 473 244 1,010 1,038 -------- -------- -------- -------- -------- Net income(4) ....................................~~ $ ~~1,902 $ 744 $ 450 $ 1,097 $ 863 ======== ======== ======== ======== ======== SEGMENT NET INCOME Upstream United States~~ .~~................................~~76 $ ~~719 $ 322 $ 223 $ 447 $ 314 International~~ .~~................................~~76 1,148 534 283 439 367 Downstream United States ................................. 182 119 141 223 186 International ................................. 230 129 156 91 117 Emerging businesses .............................. (69) (35) (31) (24) (16) Corporate(4) ..................................... (308) (325) (322) (79) (105) -------- -------- -------- -------- -------- Net income(4) .................................... $ 1,902 $ 744 $ 450 $ 1,097 $ 863 ======== ==~~======~~ ======== ======== ======== Earnings per share(5) Basic ......................................... $ 3.05 $ 1.19 $ .95 $ 2.51 $ 1.98 Diluted ....................................... $ 3.00 $ 1.17 $ .95 $ 2.51 $ 1.98 Weighted-average shares outstanding(5) Basic ......................................... 624 627 474 437 437 Diluted ....................................... 633 636 475 437 437 Dividends per common share ....................... $ .76 $ .71 $ -- $ -- $ -- OTHER DATA Cash provided by operations ...................... $ 3,438 $ 2,216 $ 1,373 $ 2,876 $ 2,396 Capital expenditures and investments ............. 2,796 1,787 2,516 3,114 1,944 Cash exploration expense ......................... 191 139 217 286 262

39 Dividends were declared on a quarterly basis throughout 2001 and 2000. Conoco declared a first quarter cash dividend on January 24, 2002, of $.19 per share on each outstanding share of common stock, payable March 10, 2002, to shareholders of record as of February 10, 2002. Conoco's Board of Directors will determine the amount of future cash dividends to be declared and paid based upon Conoco's financial condition, results of operations, cash flow, the level of its capital and exploration expenditures, its future business prospects and such other matters as the Board of Directors deems relevant. ITEM 6. SELECTED FINANCIAL DATA

YEAR ENDED DECEMBER 31 -------------------------------------------------------------- 2001 2000 1999 1998 1997 ~~1996~~ ---------- ---------- ---------- ---------- ---------- ~~BALANCE~~(IN ~~SHEET~~MILLIONS, EXCEPT PER SHARE) STATEMENT OF INCOME DATA ~~Cash~~Sales and ~~cash~~other ~~equivalents~~operating revenues .................... $ 38,737 $ 38,737 $ 27,039 $ 22,796 $ 25,796 Equity in earnings of affiliates ...................... $181 ~~342~~277 $150 ~~317~~22 $40 ~~394~~Other $income .......................................... 621 273 120 350 427 ---------- ---------- ---------- ---------- ---------- Total revenues (1) .................................... 39,~~147~~539 $39,287 ~~846~~27,309 ~~Working~~23,168 ~~capital~~26,263 Cost of goods sold .................................... 23,043 23,921 14,781 11,751 14,333 Operating expenses .................................... 3,053 2,215 2,060 2,089 1,893 Selling, general and administrative expenses (~~776~~2) ....................................... 888 794 809 972 726 Exploration expenses (~~690~~3) 45.............................. ~~567~~378 ~~862~~279 ~~Net~~270 ~~property~~380 457 Depreciation, ~~plant~~depletion and ~~equipment~~amortization (DD&A) ............................................. 121,~~207~~811 111,~~235~~301 111,~~413~~193 101,~~828~~113 101,~~082~~179 ~~Total~~Taxes ~~assets~~other than on income (1) ........................ 6,983 6,981 6,668 5,970 5,532 Interest and debt expense ............................. 18396 338 311 199 36 ---------- ---------- ---------- ---------- ---------- Income before income taxes ............................ 2,~~127~~987 163,~~375~~458 161,~~075~~217 17694 2,~~062~~107 15Income tax expense .................................... 1,~~226~~391 ~~Long~~1,556 473 244 1,010 -~~term~~--------- ~~borrowings~~-~~related~~--------- ~~parties~~---------- ---------- ---------- Income before extraordinary item and accounting change .................................. 1,596 1,902 744 450 1,097 Extraordinary item, net of income taxes ............... (44) -- -- -- -- Cumulative effect of accounting change, net of income taxes ....................................... 37 -- -- -- -- ---------- ---------- ---------- ---------- ---------- Net income (4) ........................................ $ 1,~~596~~589 $ 1,902 $ 744 $ 450 2$ 1,~~287~~097 ~~Long-term~~========== ~~borrowings~~========== ~~and~~========== ~~capital~~========== ~~lease~~========== ~~obligations~~SEGMENT NET INCOME Upstream United States ...................................... 4$ 987 $ 719 $ 322 $ 223 $ 447 International ...................................... 824 1,~~138~~148 534 283 439 Downstream United States ...................................... 329 182 119 141 223 International ...................................... 86 230 129 156 91 Emerging businesses ................................... (90) (69) (35) (31) (24) Corporate (4) ......................................... (547) (308) (325) (322) (79) ---------- ---------- ---------- ---------- ---------- Net income (4) ........................................ $ 1,~~080~~589 93$ ~~106~~1,902 ~~101~~$ ~~Total~~744 ~~stockholders'~~$ ~~equity/owner's~~450 ~~net~~$ ~~investment~~1,097 ========== ========== ========== ========== ========== EARNINGS PER SHARE (5) Basic .............................................. $ 2.54 $ 3.05 $ 1.19 $ .95 $ 2.51 Diluted ............................................ $ 2.50 $ 3.00 $ 1.17 $ .95 $ 2.51 Weighted-average shares outstanding (5~~,628~~) 4Basic .............................................. 626 624 627 474 437 Diluted ............................................ 635 633 636 475 437 Dividends per common share ............................ $ .76 $ .76 $ .71 $ -- $ -- OTHER DATA Cash provided by operations ........................... $ 3,~~555~~141 4$ 3,438 7$ 2,~~896~~216 $ 1,373 $ 2,876 Capital expenditures and investments (6) .............. 2,~~579~~835 2,796 1,787 2,516 3,114 Cash exploration expense .............................. 262 191 139 217 286

40 ---------- (1) Includes petroleum excise taxes of $6,744, $6,774, $6,492, $5,801 and $5,349 for 2001, 2000, 1999, 1998 and 1997, respectively. (2) Includes a non-cash stock option provision of $236 for 1998. (3) Includes cash exploration overhead and operating expense, dry hole costs and impairments of unproved properties. (4) Includes after-tax exchange gains (losses) of $(33), $38, $6, $32 and $21 for 2001, 2000, 1999, 1998 and 1997, respectively. (5) Conoco's capital structure was established at the time of the initial public offering. Earnings per share for the periods prior to the initial public offering was calculated using only Class B common stock, as required by SFAS No. 128. (6) Excludes acquisition of Gulf Canada of $4,571 cash plus assumed liabilities and minority interests.

~~YEAR ENDED~~ DECEMBER 31 ------------------------------ ~~2000 1999 1998~~ -------- -------- --------------- ~~(IN~~2001 ~~MILLIONS)~~2000 ~~Upstream~~1999 ~~United~~1998 ~~States~~1997 ~~.....................................~~---------- $---------- ~~667 $ 413 $ 788 International ..................................... 1,486 839 1,177~~ ---------- ---------- ---------- ~~Total~~BALANCE ~~upstream~~SHEET DATA Cash and cash equivalents .............................~~....~~ ~~2,153~~$ ~~1,252~~388 ~~1,965~~$ ~~Downstream~~342 ~~United~~$ ~~States~~317 ~~.....................................~~$ ~~344~~394 ~~214~~$ ~~201~~1,147 ~~International~~Working capital ....................................... ~~201~~(1,159) ~~248~~(776) ~~332~~(690) ~~--------~~45 ~~--------~~567 ~~--------~~Net ~~Total~~property, ~~downstream~~plant and equipment .....................~~..........~~ ~~545~~17,918 ~~462~~12,207 ~~533~~11,235 ~~Emerging~~11,413 ~~businesses~~10,828 ~~...................................~~Total 72assets ~~69 1 Corporate~~ ..........................................~~...~~ 2627,904 418,127 16,375 16,075 17,062 Long-~~-------~~term ~~--------~~borrowings --~~------~~ ~~Total~~related ~~capital~~parties ~~expenditures and investments~~ ............... $-- ~~2,796~~-- $-- 14,~~787~~596 ~~$ 2~~1,~~516~~450 ~~========~~Long-term ~~========~~borrowings ~~========~~and ~~United~~capital ~~States~~lease obligations ....~~.....................................~~ $8,267 14,~~101~~138 $4,080 ~~700~~93 $106 ~~1,007~~Minority ~~International~~interests ....................................~~.....~~ 1,~~695~~204 ~~1,087~~337 ~~1,509~~335 ~~--------~~309 ~~--------~~309 ~~--------~~ Total stockholders' equity/owner's net investment .....~~............................................~~ $6,610 25,~~796~~628 ~~$ 1~~4,~~787~~555 ~~$ 2~~4,~~516~~438 ~~======== ======== ========~~7,896

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS GENERAL References to "Conoco," "we" or "us" are references to Conoco Inc. and its consolidated subsidiaries. This annual report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can identify our forward-looking statements by the words "expects," "intends," "plans," "projects," "believes," "estimates," "will," "should" and similar expressions. We have based the forward-looking statements relating to our operations on our current expectations and on estimates and projections about Conoco and the petroleum industry in general. We caution you that these statements are not guarantees of future performance and involve risks, uncertainties and assumptions that we cannot predict with certainty. Accordingly, our actual outcomes and results may differ materially from what we have expressed or forecasted in the forward-looking statements. Any differences could result from a variety of factors, including the following: o fluctuations in crude oil and natural gas prices and refining and marketing margins; o potential failure or delays in achieving expected reserve or production levels from existing and future oil and gas development projects due to operating hazards, drilling risks and the inherent uncertainties in predicting oil and gas reserves and oil and gas reservoir performance; o unsuccessful exploratory drilling activities; o failure of new products and services to achieve market acceptance; o unexpected cost increases or technical difficulties in constructing or modifying company manufacturing and refining facilities; o unexpected difficulties in mining, manufacturing, transporting or refining synthetic crude oil; o ability to meet government regulations; o potential disruption or interruption of our production facilities due to accidents, political events or terrorism; o international monetary conditions and exchange controls; 41 o liability for remedial actions under environmental regulations; o liability resulting from litigation; o general domestic and international economic and political conditions, including armed hostilities and terrorism; and o changes in tax and other laws applicable to our business. The discussion and analysis of Conoco's financial condition and results of operations should be read in conjunction with Conoco's consolidated financial statements included in this report. The initial public offering of Conoco's Class A common stock commenced on October 21, 1998. The initial public offering consisted of approximately 191 million shares of Class A common stock issued at a price of $23.00 per share, and represented E.I. du Pont de Nemours and Company's (DuPont) first step in the planned divestiture of Conoco. After the initial public offering, DuPont owned 100 percent of Conoco's Class B common stock (approximately 437 million shares), representing approximately 70 percent of Conoco's outstanding common stock and approximately 92 percent of the combined voting power of all classes of voting stock of Conoco. On August 6, 1999, DuPont concluded an exchange offer to its stockholders, which resulted in all 437 million shares of Class B common stock being distributed to DuPont stockholders. The exchange offer was the final step in DuPont's planned divestiture of Conoco. On September 21, 2001, Conoco's shareholders approved the combination of our Class A and Class B common stock into a single class of new common stock on a one-for-one basis. The combination was effective on October 8, 2001. The number of shares of common stock issued and outstanding as of December 31, 2000, has been restated to give effect to the combination. There was no effect on previously reported earnings per share amounts. On November 18, 2001, Conoco and Phillips Petroleum Company (Phillips) announced that their boards of directors unanimously approved the merger of the two companies. The new company will be named ConocoPhillips. Under the terms of the agreement, Phillips shareholders will receive one share of new ConocoPhillips common stock for each share of Phillips common stock they own and Conoco shareholders will receive .4677 shares of new ConocoPhillips common stock for each share of Conoco common stock they own. The merger is conditioned upon, among other things, the approval of the shareholders of each company and customary regulatory approvals. Both companies held special meetings of shareholders on Tuesday, March 12, 2002, and the shareholders of both companies approved the proposed merger. Completion of the transaction is expected in the second half of 2002. Conoco has three operating segments -- upstream, downstream and emerging businesses. Upstream operating segment activities include exploring for, developing, producing and selling crude oil, natural gas and natural gas liquids; and Syncrude mining operations (Canadian Syncrude). Downstream operating segment activities include refining crude oil and other feedstocks into petroleum products; buying and selling crude oil and refined products; and transporting, distributing and marketing petroleum products. Emerging businesses operating segment activities include the development of new businesses beyond our traditional operations. Currently, we are involved in the carbon fibers (Conoco Cevolution(R)); natural gas refining, including gas-to-liquids; and international power businesses. We have five reporting segments. Four reporting segments reflect the geographic division between the U.S. and international operations for our upstream and downstream businesses. One reporting segment is for emerging businesses. Corporate includes general corporate expenses, financing costs and other non-operating items, and captive insurance operations. Conoco considers portfolio optimization to be an ongoing business strategy and continuously seeks to rationalize its investment portfolio in order to maximize profitability. Over the past five years, Conoco has generated proceeds of approximately $2,465 million, averaging about $493 million a year, through the disposal of marginal and non-strategic producing properties, while upgrading and redirecting its exploration portfolio and increasing its ownership in large-scale properties. As a result, we have increased production by 34 percent on a barrel-of-oil-equivalent (BOE) basis while undergoing this rationalization. Our policy is to report material gains and losses from individual asset sales as special items when reporting consolidated net income. Conoco conducts its activities through wholly and majority-owned subsidiaries and, increasingly, through equity affiliates. This trend of conducting business in the petroleum industry through equity affiliates is expected to 42 increase in the future as Conoco attempts to minimize either the capital or political risks associated with new large-scale, high-impact projects and capture synergies leading to growth opportunities. Conoco's profitability is largely determined by the difference between prices received for crude oil, natural gas, natural gas liquids, Canadian Syncrude and refined products produced, and the costs of finding, mining, developing, producing, refining and marketing these resources. Conoco has no control over many factors affecting prices for its products. Prices for crude oil, natural gas, Canadian Syncrude and refined products may fluctuate widely in response to changes in global and regional supply, political developments and the ability of the Organization of Petroleum Exporting Countries (OPEC) and other producing nations to set and maintain production levels and prices. Crude oil and natural gas prices in 2001 decreased from the prices experienced during 2000. West Texas Intermediate crude oil averaged $25.97 per barrel for 2001, a decrease of $4.18 from $30.15 per barrel in 2000. In addition, NYMEX natural gas spot prices averaged $4.38 per thousand cubic feet (mcf) in 2001, up $.67 from $3.71 per mcf in 2000. Conoco had lower earnings for the year, largely due to lower crude oil prices, partially offset by higher gas prices and healthy refining margins in the U.S. Prices for crude oil, natural gas, Canadian Syncrude and refined products also are affected by changes in demand for these products. Changes may result from global events, as well as supply and demand in industrial markets, such as the steel and aluminum markets. Even small decreases in crude oil, natural gas and Canadian Syncrude prices and refined product margins may adversely affect Conoco. Lower crude oil, natural gas and Canadian Syncrude prices may reduce the amount of oil, natural gas and Canadian Syncrude reserves Conoco can produce economically, and existing contracts that Conoco has entered into may become uneconomic. Local political and economic factors in international markets may have a material adverse effect on Conoco. There are many risks associated with operations in international markets, including changes in foreign governmental policies relating to crude oil, natural gas or refined product pricing and taxation; other political, economic or diplomatic developments; changing political conditions; and international monetary fluctuations. Recent turmoil in regions such as Russia, Asia Pacific, the Middle East and South America has subjected Conoco's operations in these regions to increased risks. These risks include: o the risk of political and economic instability; o the risk of war and terrorism; o the risk that Conoco's property will be seized by a foreign government with or without compensation; o the risk of confiscatory taxation; o the risk that foreign governments will attempt to renegotiate or revoke existing contractual arrangements; o increased risks of fluctuating currency values, hard currency shortages and currency controls; and o the risk of civil unrest and changes in government. Actions of the U.S. government also can expose Conoco's operations to risk. The U.S. government can use tax and other legislation, executive orders and commercial restrictions to prevent or restrict Conoco from doing business in foreign countries. These restrictions and those of foreign governments have in the past limited Conoco's ability to operate in, or gain attractive opportunities in, various countries. Actions by both the U.S. and host governments have affected operations significantly in the past and will continue to do so in the future. CRITICAL ACCOUNTING POLICIES In preparing financial statements, management is required to select appropriate accounting policies and make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Certain of those accounting policies involve judgments and uncertainties and there is reasonable likelihood that materially different amounts could have been reported had different assumptions and judgments been made. OIL AND GAS ACTIVITIES The accounting for our upstream oil and gas activities is subject to special accounting rules that are unique to the oil and gas business. There are two methods to account for oil and gas business activities, the successful efforts 43 method and the full cost method. Conoco has elected to use the successful efforts method. A description of our policies for oil and gas properties, impairment, maintenance and repair activities is located in note 2 to our consolidated financial statements. The successful efforts method reflects the volatility that is inherent in exploring for mineral resources in that costs of unsuccessful exploratory efforts are charged to expense as they are incurred. These costs primarily include dry hole costs, seismic costs and other exploratory costs. Under the full cost method, these costs are capitalized and written-off (depreciated) over time. OIL AND GAS RESERVES Engineering estimates of Conoco's oil and gas reserves are inherently imprecise and represent only approximate amounts because of the subjective judgments involved in developing such information. There are authoritative guidelines regarding the engineering criteria that have to be met before estimated oil and gas reserves can be designated as "proved." Proved reserve estimates are updated at least annually and take into account recent production and technical information about each field. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also changes. This change is considered a change in estimate for accounting purposes and is reflected on a prospective basis in related depreciation rates. Despite the inherent imprecision in these engineering estimates, these estimates are used in determining depreciation expense and impairment expense, and in disclosing the supplemental standardized measure of discounted future net cash flows relating to proved oil and gas properties. Depreciation rates are determined based on estimated proved reserve quantities (the denominator) and capitalized costs of producing properties (the numerator). Producing properties' capitalized costs are amortized based on the units of oil or gas produced. Therefore, assuming all other variables are held constant, an increase in estimated proved reserves decreases our depreciation, depletion and amortization expense. Also, estimated reserves are often used to calculate future cash flows from our oil and gas operations, which serve as an indicator of fair value in determining whether a property is impaired or not. The larger the estimated reserves, the less likely the property is impaired. CANADIAN SYNCRUDE RESERVES Canadian Syncrude proven reserves cannot be measured precisely. Reserve estimates of Canadian Syncrude are based on subjective judgments involving geological and engineering assessments of in-place crude bitumen volume, the mining plan, historical extraction recovery and upgrading yield factors, installed plant operating capacity and operating approval limits. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting the bitumen and upgrading it into a light sweet crude oil. Despite the inherent imprecision in these engineering estimates, these estimates are used in determining such amounts as depreciation expense, impairment expense and estimated future cash flows relating to mining operations. IMPAIRMENTS If circumstances indicate that the net book value of an asset or investment, including oil and gas properties, may not be recoverable, this asset may be considered "impaired," and an impairment loss may be recognized in accordance with Statement of Financial Accounting Standards (SFAS) Nos. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" and 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" or Accounting Principles Board (APB) Opinion No. 18, "The Equity Method of Accounting for Investments in Common Stock." The amount of impairment loss is the difference between the carrying amount of the asset or investment and its fair market value. It is difficult to precisely estimate fair value because quoted market prices for our assets and investments are not easily available. We will use all readily available information in determining an amount that is a reasonable approximation of fair value, including the net present value of future net cash flows based on reserve quantities as indicated above. In recording the purchase of Gulf Canada Resources Limited (Gulf Canada), we recorded a material amount of goodwill. Under current accounting rules, goodwill is not amortized; instead, it is subject to annual impairment testing. Effective January 1, 2002, impairment testing will use the fair market value of individual reporting units to which goodwill has been allocated to determine whether an impairment exists. Management will use all reasonably 44 available information to make these fair value determinations and may hire an outside firm to help in determining reporting unit fair values. ASSET RETIREMENT OBLIGATIONS Conoco has significant obligations to remove tangible equipment and restore land or seabed at the end of operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells and removal and disposal of offshore oil and gas platforms around the world. The estimated undiscounted costs, net of salvage value, of dismantling and removing these facilities are accrued over the productive life of the asset. Estimating the future asset removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as well as political, environmental, safety and public relations considerations. In addition, the Financial Accounting Standards Board (FASB) has recently issued SFAS No. 143, "Accounting for Asset Retirement Obligations," which significantly changes the method of accruing for costs, associated with the retirement of fixed assets, that an entity is legally obligated to incur. We are evaluating the impact and timing of implementing SFAS No. 143. ENVIRONMENTAL LIABILITIES Conoco incurs costs to comply with complex environmental laws and regulations, and internal voluntary programs. These costs are significant and will continue to be so in the foreseeable future. We accrue for these costs when it is probable that a liability has been incurred and reasonable estimates of the liability can be made. It is difficult to develop reasonable estimates of future site remediation costs due to changing regulations, changing technologies and their associated costs, as well as changing economic and political environments. Also, it is difficult to determine our liability in proportion to that of other responsible parties. As a result, from time to time significant charges to income may be recorded to properly accrue for such liabilities. For additional information, see note 28 to the consolidated financial statements. CONTINGENCIES In addition to accruing the estimated costs for asset retirement obligations and environmental liabilities, Conoco accrues for all known and estimable contingencies. These other contingencies are primarily related to litigation and tax issues. Determining appropriate amounts for accrual is a complex estimation process that includes subjective judgments. We review these contingencies on at least a quarterly basis to determine if new accruals need to be recorded or if adjustments to existing accruals need to be made. In accordance with SFAS No. 5, "Accounting for Contingencies," accruals are recorded when an adverse outcome is probable and the amount can be reasonably estimated. For additional information, see note 28 to the consolidated financial statements. INVENTORIES Conoco uses the last-in, first-out (LIFO) method for determining the value of crude oil and petroleum products and Canadian Syncrude inventories. Under the LIFO method, cost of goods sold more closely reflects current prices and inventory value more closely reflects prior period costs. As a result, the valuation of inventory is more likely to experience lower-of-cost-or-market impairments, as compared to other methods, when price levels decline. In addition, current period earnings could be impacted when inventory is drawn down into prior LIFO cost inventory layers. In determining how to price the LIFO layers each period, we use objective evidence based on internally developed criteria that are consistently applied. FOREIGN CURRENCY Conoco has operations in numerous countries and conducts business transactions in several foreign currencies. In accounting and reporting for these foreign operations, U.S. generally accepted accounting principles require that an entity designate a "reporting currency" in which its financial statements are presented and designate the "functional currency" of each of its foreign operations. Selection of the functional currency involves management judgment regarding the economic environments in which foreign entities conduct business. The selection of a functional currency affects our income statement as foreign currency gains and losses from re-measurements into the functional currency are reported in current period income and gains and losses from translation from the functional currency into the "reporting currency" are not reported in current income, but instead are recorded in other comprehensive income in the Stockholders' Equity section of the balance sheet. The U.S. dollar is Conoco's 45 reporting currency, as well as the functional currency of all foreign operations except Europe and Canada. The local currency is the functional currency of Conoco's European and Canadian operations. BASIS OF CONSOLIDATION The decision of the appropriate method of reporting financial results of investments in activities of affiliates (full consolidation, equity or cost method) is based on: o the extent of influence Conoco can exert on the affiliate; and o the structure of the investor agreements. In assessing the degree of influence, management takes into account the legal structure (corporation, partnership, joint venture, etc.), as well as Conoco's and other investors' voting percentage. The percentage guidelines set forth in the accounting literature are not absolutes, but merely guidelines for making an initial assessment of Conoco's level of control. Other items (e.g., veto rights) also influence whether control exists in actuality. It is necessary to consider all relevant facts and circumstances and apply judgment to ensure that the reporting methods reflect the substance, not just the form, of the relationship between Conoco and its affiliates. Refer to notes 2, 15 and 22 in the consolidated financial statements and Other Liquidity Matters. DERIVATIVE FINANCIAL INSTRUMENTS The current accounting rules require that derivative instruments be recorded at fair value. Quoted market prices are the best evidence of fair value. If quoted market prices are not available, management's best estimate of fair value is based on the quoted market price of financial instruments with similar characteristics or on valuation techniques (e.g., option pricing models). As discussed in further detail in Item 7A -- Quantitative and Qualitative Disclosures About Market Risk, Conoco's fair values of exchange traded futures contracts are based on publicly quoted prices. The fair value non-exchange traded contracts (swaps and other over-the-counter instruments) are estimated based on quoted market prices of comparable contracts. SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities," (SFAS 133) requires that gains and losses from the change in fair value of derivative instruments that do not qualify for hedge accounting be reported in current period income, rather than in the period in which the hedged transaction is settled. This may result in significant volatility to current period income. SFAS 133 is complex and subject to a potentially wide range of interpretations in its application. As such, in 1998 the FASB established the Derivative Implementation Group (DIG) task force specifically to consider and to publish official interpretations of issues arising from the implementation of SFAS 133. The DIG is still active, and the potential exists for additional issues to be brought under its review. Therefore, if subsequent DIG interpretations of SFAS 133 are different than our current policy, it is possible that our policy, as stated above, would be modified. LIQUIDITY AND CAPITAL RESOURCES CASH PROVIDED BY OPERATIONS Cash provided by operations in 2001 decreased $297 million to $3,141 million versus $3,438 million in 2000. Cash provided by operations before changes in operating assets and liabilities increased $434 million compared to 2000, primarily due to higher natural gas prices and strong U.S. refining margins in the first six months of the year, increased crude oil and natural gas volumes and higher dividends from equity affiliates, partially offset by lower crude oil prices. Negative changes to net operating assets and liabilities of $731 million were due to decreases in payables, partially offset by a decrease in accounts receivable. Cash provided by operations in 2000 increased $1,222 million to $3,438 million versus $2,216 million in 1999. Cash provided by operations before changes in operating assets and liabilities increased $1,376 million compared to 1999, primarily due to higher crude oil, natural gas and natural gas liquids prices, along with stronger refining margins and higher dividends from equity affiliates. Negative changes to net operating assets and liabilities of $154 46 million were due to increased inventories and funds required for the recent commencement of a service contract in Syria, partially offset by decreases in accounts receivable and higher taxes payable. INVESTING ACTIVITIES PURCHASE OF BUSINESSES On July 16, 2001, Conoco, through a wholly owned subsidiary, completed the acquisition of all the ordinary shares of Gulf Canada, now known as Conoco Canada Resources Limited (Conoco Canada) for approximately $4,571 million in cash plus assumed liabilities and minority interests. For ease of reference, we will refer to Conoco Canada as Gulf Canada. Prior to the acquisition, Gulf Canada was a Canadian-based independent exploration and production company, with primary operations in western Canada, Indonesia, the Netherlands and Ecuador. Subsequent to the acquisition, operational responsibilities for Gulf Canada's interests in Indonesia, the Netherlands and Ecuador were realigned within Conoco's regional organizational structure, and operationally Conoco's existing Canadian operations were merged with those of Gulf Canada. CAPITAL EXPENDITURES AND INVESTMENTS

YEAR ENDED DECEMBER 31 ------------------------------------- 2001 2000 1999 ~~1998~~ ---------- ---------- ---------- (IN MILLIONS) ~~SALES AND OTHER OPERATING REVENUES~~ Upstream United States ..................................... $ ~~5,531~~856 $ ~~3,309~~667 $ ~~3,200~~413 International ..................................... 31,~~666~~358(1) ~~2,247~~ 1,~~601~~486 839 ---------- ---------- ---------- Total upstream ................................. 92,~~197~~214 52,~~556~~153 41,~~801~~252 Downstream United States ..................................... ~~17,379~~164 ~~11,191~~344 ~~8,949~~214 International ..................................... ~~12,157~~225 ~~10,264~~201 ~~8,297~~248 ---------- ---------- ---------- Total downstream ............................... ~~29,536~~389 ~~21,455~~545 ~~17,246~~462 Emerging businesses ................................... 4196 2872 ~~729~~69 Corporate ............................................. --36 --26 204 ---------- ---------- ---------- Total ~~sales~~capital expenditures and ~~other~~investments ~~operating revenues~~ .............. $ 382,~~737~~835 $ 272,~~039~~796 $ 221,~~796~~787 ========== ========== ========== ~~AFTER-TAX OPERATING INCOME Upstream~~ United States ~~...................................~~ $ ~~719~~1,218 $ ~~322~~1,101 $ ~~223~~700 International ................................... ~~1,148 534 283 -------- -------- -------- Total upstream~~ ......~~...........................~~ 1,~~867~~617 ~~856~~1,695 ~~506~~1,087 ~~Downstream United States ................................... 182 119 141 International ................................... 230 129 156~~ -------- --~~------~~ -------- ~~Total downstream ............................... 412 248 297 Emerging businesses ................................ (69) (35) (31) Corporate .......................................... (104) (98) (250)~~ --~~------~~ -------- --~~------~~ Total ~~after-tax operating income~~ ............... ~~$ 2,106 $ 971 $ 522 Interest and other non-operating expenses net of tax~~ ..................................~~...~~ ~~(204) (227) (72) -------- -------- -------- Net income ............................................~~ $ 12,~~902~~835 $ ~~744~~2,796 $ ~~450~~1,787 ========== ========== ==========

---------- (1) Excludes acquisition of Gulf Canada for $4,571 million cash plus assumed liabilities and minority interests. Total capital expenditures and investments in 2001, including investments in affiliates and acquisitions other than Gulf Canada, were $2,835 million, an increase of 1 percent versus 2000 capital expenditures and investments of $2,796 million. The increase was due primarily to higher spending on emerging businesses partially offset by lower expenditures on U.S. refining operations. During 2001, 78 percent of total capital expenditures and investments were upstream-related, with a majority devoted to the acquisition of coalbed methane properties in the San Juan Basin and drilling in deepwater Gulf of Mexico, Vietnam, Venezuela and Indonesia, as well as continued development of various fields. Worldwide, approximately $324 million was spent on exploratory drilling and leasing. The decrease in 2001 downstream capital expenditures and investments primarily resulted from decreased expenditures on U.S. refining operations. Emerging businesses capital expenditures and investments increased versus 2000, as a result of continued construction of our first commercial-scale carbon fibers manufacturing plant, in Ponca City, Oklahoma, and project costs associated with our U.S. power business. The increase in corporate capital expenditures and investments was due primarily to computer infrastructure additions. Total capital expenditures and investments in 2000, including investments in affiliates and acquisitions, were $2,796 million, an increase of 56 percent versus 1999 capital expenditures and investments of $1,787 million. The increase was due primarily to significant acquisitions in the U.K. and U.S., as well as increased capital spending in Indonesia, Vietnam, the Caspian Sea and the Gulf of Mexico. During 2000, 77 percent of total capital expenditures and investments were upstream-related, with a majority devoted to the acquisition of producing acreage in the North Sea and gas processing plants in Canada and the U.S., and to our Petrozuata joint venture in Venezuela. Worldwide, 47 approximately $204 million was spent on exploratory drilling and leasing. The increase in 2000 downstream capital expenditures and investments primarily resulted from the upgrade to our Lake Charles, Louisiana, refinery to enable it to process Petrozuata synthetic crude. Emerging businesses capital expenditures and investments were essentially unchanged versus 1999, as our initial capital expenditures and investments in our carbon fibers business were offset by a decrease in capital spending in our power business. The increase in corporate capital expenditures and investments was due primarily to investments in several e-commerce initiatives and to computer hardware and software costs. In 2002, Conoco expects its capital budget, including investments in affiliates and acquisitions, to be about $2,800 million. We expect about $2,300 million will be spent on upstream projects for worldwide exploration, production and natural gas activities, while about $500 million will be spent on downstream projects. These expenditures will be funded primarily through cash flow from operations, augmented as necessary by asset dispositions and existing borrowing capacity. Upstream Upstream capital expenditures and investments totaled $2,214 million in 2001. The increase of $61 million, or approximately 3 percent, compared to $2,153 million in 2000, was primarily the result of increased drilling operations. Expenditures in 2001 included the purchase of coalbed methane properties in the San Juan Basin and drilling in deepwater Gulf of Mexico, Vietnam, Venezuela and Indonesia, as well as continued development of various fields. Upstream capital expenditures and investments totaled $2,153 million in 2000. The increase of $901 million, or approximately 72 percent, compared to $1,252 million in 1999, was primarily the result of the acquisitions of Saga U.K. Ltd. and gas processing plants in the U.S. Additionally, we increased our capital spending in the Caspian Sea, Indonesia and the U.S. We also have spent approximately $892 million, $705 million and $587 million to develop our proved undeveloped reserves in 2001, 2000 and 1999 and expect to spend an estimated $1,100 million, $1,000 million and $600 million in 2002, 2003 and 2004. United States U.S. capital expenditures and investments were $856 million in 2001, an increase of $189 million, or 28 percent, compared to 2000 capital expenditures and investments of $667 million. Expenditures during 2001 were focused on continued development of the Lobo field in south Texas and the acquisition of coalbed methane properties in the San Juan Basin of New Mexico. Expenditures also were centered on the deepwater Gulf of Mexico with the drilling of the appraisal wells in the Magnolia discovery. U.S. capital expenditures and investments were $667 million in 2000, an increase of $254 million, or 62 percent, compared to 1999 capital expenditures and investments of $413 million. Expenditures during 2000 were focused on continued development of the Lobo field in south Texas and the San Juan field in New Mexico, as well as the acquisition of gas processing plants in the U.S. Expenditures also were centered on the deepwater Gulf of Mexico with the drilling of the Princess discovery near the Ursa field and the drilling of an appraisal well in the Magnolia discovery to confirm the field's commerciality. International International capital expenditures and investments were $1,358 million in 2001, a decrease of $128 million, or 9 percent, compared to $1,486 million in 2000. The decrease was primarily the result of lower spending on acquisitions. Expenditures in 2000 included the acquisition of Saga U.K. Ltd. and Canadian natural gas gathering and processing assets. International capital expenditures and investments were $1,486 million in 2000, an increase of $647 million, or 77 percent, compared to $839 million in 1999. The 2000 expenditures were focused on the acquisition of Saga U.K. Ltd. and natural gas gathering and processing assets in Canada, continued developmental spending in the North Sea, exploratory drilling in the North Sea and Indonesia, development of Petrozuata and construction of a natural gas pipeline system offshore Indonesia. 48 Downstream Downstream capital expenditures and investments for 2001 totaled $389 million, a decrease of $156 million, or 29 percent, versus $545 million in 2000, primarily reflecting decreased expenditures on U.S. refining operations. For 2000, downstream capital expenditures and investments totaled $545 million, an increase of $83 million, or 18 percent, versus $462 million in 1999, primarily reflecting increased expenditures in the U.S. United States For 2001, U.S. capital expenditures and investments totaled $164 million, a decrease of $180 million, or 52 percent, versus 2000 capital expenditures and investments of $344 million. Expenditures in 2001 were principally related to pipeline and refining operations. For 2000, U.S. capital expenditures and investments totaled $344 million, an increase of $130 million, or 61 percent, versus 1999 capital expenditures and investments of $214 million. Expenditures in 2000 were focused on the installation of new units at our Lake Charles refinery to process acidic synthetic crude from Petrozuata and expansion of pipeline assets in the Rocky Mountain region, as well as on our refining and marketing operations. International Conoco made international capital expenditures and investments of $225 million during 2001, an increase of $24 million, or 12 percent, from the $201 million spent in 2000. The majority of the funds in 2001 were directed toward our ongoing refining and marketing operations, as well as continuing investments relating to upgrades to meet future clean fuels specifications in Europe. Conoco made international capital expenditures and investments of $201 million during 2000, a decrease of $47 million, or 19 percent, from the $248 million spent in 1999. Expenditures in 2000 were focused on supporting our refining operations, including upgrades to meet future clean fuels specifications in Europe, as well as growth in selected retail markets. Emerging Businesses During 2001, emerging businesses capital expenditures and investments totaled $196 million, compared to $72 million in 2000. The increased expenditures in 2001 were primarily related to the construction of our first commercial-scale carbon fibers manufacturing plant, in Ponca City, Oklahoma, and project costs associated with our U.S. power business. Completion of the carbon fibers plant is expected soon, with first production expected in mid-2002. During 2000, emerging businesses capital expenditures and investments totaled $72 million, compared to $69 million in 1999. Investments in 2000 were focused on the construction of our carbon fibers manufacturing plant in Ponca City, Oklahoma, which began during 2000. There was an offsetting decrease in the capital expenditures associated with our power business. Corporate During 2001, corporate capital expenditures and investments totaled $36 million, an increase of $10 million from 2000 capital expenditures and investments of $26 million. The increased expenditures during 2001 were largely for computer infrastructure. During 2000, corporate capital expenditures and investments totaled $26 million, an increase of $22 million from 1999 capital expenditures and investments of $4 million. The increased expenditures during 2000 were primarily related to investments in e-commerce initiatives and technology-related investments in hardware and software. 49 PROCEEDS FROM SALES OF ASSETS AND SUBSIDIARIES Conoco's 2001 disposition proceeds were $795 million, up $573 million, or 258 percent, from $222 million in 2000, due to more asset dispositions in 2001 resulting from our asset disposition program implemented in 2001. Our asset dispositions included the sale of our interest in the Pocahontas Gas Partnership; the sale of our interest in Arkhangelskgeoldobycha, a Russian oil company; the sale of retail units and natural gas facilities in the United States; exiting our downstream operation in Spain; the sale of oil and gas properties in shallow waters in the Gulf of Mexico; the sale of oil and gas properties in Texas and Wyoming; and the sale of retail units in the U.K. Conoco's 2000 disposition proceeds were $222 million, up $60 million, or 37 percent, from $162 million in 1999, due to a greater number of large asset dispositions in 2000, including the sale of gas processing plants in Oklahoma, retail outlets in the Dallas-Fort Worth area and the Gulf Coast region, and our interest in a pipeline in the southeastern U.S. FINANCING ACTIVITIES Conoco's ability to maintain and grow its operating income and cash flow is dependent upon continued capital spending to replace depleting assets. We believe our future cash flow from operations and our borrowing capacity should be sufficient to fund our payments of dividends, if any, capital expenditures and working capital requirements and to service debt. In April 1999, Conoco issued and sold in a public offering $4,000 million in senior fixed-rate debt securities with a weighted-average interest rate of 6.49 percent. The $3,970 million net proceeds of this offering were used to repay a portion of Conoco's separation-related indebtedness to DuPont. In May of 1999, we repaid the remaining debt owed to DuPont with proceeds from a $2,000 million U.S. commercial paper program. On October 18, 2001, we amended and increased our unsecured $2,000 million revolving credit facility with a syndicate of U.S. and international banks by $1,000 million to facilitate an increase in our commercial paper program. The terms consist of a 364-day committed facility in the amount of $2,350 million and a five-year committed facility, with over two years remaining, in the amount of $650 million. At December 31, 2001, and at December 31, 2000, we had no outstanding borrowings under the credit facility. Also, during October, we increased our U.S. commercial paper program to $3,000 million and increased our European commercial paper program to euro 1,000 million. Both programs are fully supported by the credit facility. We have the ability to issue commercial paper at any time with maturities not to exceed 270 days. At December 31, 2001, we had $558 million of commercial paper outstanding, with a weighted-average interest rate of 2.16 percent, of which $29 million was denominated in foreign currencies. At December 31, 2000, there was $187 million of commercial paper outstanding, with a weighted-average interest rate of 6.8 percent, of which $85 million was denominated in foreign currencies. At the time of the Gulf Canada acquisition, Gulf Canada had a $500 million unsecured credit facility. This facility was subsequently cancelled in October 2001. In connection with the July 2001 Gulf Canada acquisition, we arranged a $4,500 million senior unsecured 364-day bridge credit facility to finance the transaction and assumed approximately $2,000 million of net debt and minority interests. The borrowings under the bridge facility were repaid on October 11, 2001, primarily with the net proceeds of $4,469 million from the $4,500 million debt offering by Conoco and Conoco Funding Company, a wholly owned Nova Scotia finance subsidiary, described in the subsequent paragraphs. The bridge facility was subsequently cancelled on October 16, 2001. Subsequent to the Gulf Canada acquisition, Gulf Indonesia Resources Limited (Gulf Indonesia), a consolidated subsidiary of Gulf Canada, repaid $116 million of its outstanding debt and Gulf Canada repaid $1,015 million of its $1,048 million in outstanding U.S. dollar debt securities. In addition, Gulf Canada repaid $207 million of its subordinated debt and an additional $234 million of outstanding private placement debt. In association with the debt securities repaid in 2001, we incurred an extraordinary loss of $77 million ($44 million after-tax) for a premium charged on the early repayment of this debt. We funded these repayments and the repayment of the balance of the bridge facility through a combination of cash on hand, our issuance of commercial paper and borrowings under other available credit lines. On October 11, 2001, Conoco Funding Company issued $3,500 million of senior debt securities, fully and unconditionally guaranteed by Conoco, as follows: 50 o $1,250 million of 5.45 percent notes due 2006; o $1,750 million of 6.35 percent notes due 2011; and o $500 million of 7.25 percent notes due 2031. Conoco also issued $1,000 million of floating rate notes as follows: o $500 million notes due October 15, 2002, with a floating rate based on the three-month LIBOR rate plus .77 percent; and o $500 million notes due April 15, 2003, with a floating rate based on the three-month LIBOR rate plus .85 percent. In 1996, various upstream subsidiaries contributed oil and gas assets to Conoco Oil & Gas Associates L.P. for a general partnership interest of 67 percent. Vanguard Energy Investors L.P. then purchased the remaining 33 percent as a limited partner. In December 1999, Conoco elected to retire Vanguard's interest and terminate the Conoco Oil & Gas Associates partnership, reducing minority interest by $302 million. As a result of this transaction, Vanguard received from Conoco Oil & Gas Associates $310 million cash, which represented its mark-to-market adjusted capital account value plus a priority return for the period of October 1, 1999, through December 31, 1999. In 1999, Conoco formed Conoco Corporate Holdings L.P. by contributing an office building and four aircraft. The limited partner interest was sold to Highlander Investors L.L.C. for $141 million, or an initial net 47 percent interest. Highlander is entitled to a cumulative annual priority return on its investment of 7.86 percent. The net minority interest in Conoco Corporate Holdings held by Highlander was $141 million at December 31, 2001 and December 31, 2000. In 1999, Conoco and Armadillo Investors L.L.C. formed Conoco Gas Holdings L.L.C. We contributed certain domestic upstream assets for a 75 percent common member interest and cash, and Armadillo contributed cash for a 25 percent preferred member interest. Armadillo is entitled to a cumulative annual preferred dividend on its investment of 7.16 percent. The net minority interest in Conoco Gas Holdings held by Armadillo was $185 million at December 31, 2000. In March 2001, we acquired the minority interest in Conoco Gas Holdings L.L.C. from Armadillo L.L.C. The acquisition resulted in a reduction of minority interest of $185 million, an increase in debt of $171 million and a reduction in cash of $14 million. We assumed the $171 million debt from Armadillo L.L.C. In December 2001, Conoco and Cold Spring Finance S.a.r.l. formed Ashford Energy Capital S.A. through the contribution of cash and a Conoco subsidiary promissory note. Ashford Energy issued $498 million in equity certificates to Cold Spring, and they are entitled to a cumulative annual preferred return based upon current short-term interest rates. The initial return will be 3.18 percent and will adjust quarterly. As a result, Cold Spring held a $500 million net minority interest in Ashford Energy at December 31, 2001. Total Conoco debt was $9,392 million at December 31, 2001, up $4,998 million versus $4,394 million at December 31, 2000. The total debt-to-capitalization ratio was 54.6 percent at December 31, 2001, and 42.4 percent at December 31, 2000. Effective with the third quarter of 2001, the debt-to-capitalization ratio calculation was changed to include minority interest in the denominator. The December 31, 2000, debt-to-capitalization ratio has been restated to reflect this change. In February 2001, we commenced a new three-year $1,000 million common stock buyback program. The stock buyback program allowed us to repurchase shares from time to time in the open market or possibly, under certain circumstances, through private transactions, as our financial condition and market conditions warranted. The stock buyback program was suspended in May 2001 with our purchase of Gulf Canada. During 2001, we purchased 1.3 million shares of our common stock at a total cost of $37 million. On February 14, 2002, Gulf Canada announced that its board of directors approved the redemption of its Series I and Series II preferred stock and its 6.45 percent senior unsecured Canadian dollar notes due 2007. The Series II preferred shares will be redeemed on April 10, 2002, at a cost of Canadian $150 million; while both the Series I preferred shares and the 6.45 percent senior unsecured notes will be redeemed on April 22, 2002, at a cost of Canadian $472 million and Canadian $106 million, respectively. 51 In January 2002, Immingham CHP, L.L.P., a subsidiary of Conoco, executed a British pound 257 million bank facility for the planned construction of a 730-megawatt combined heat and power cogeneration plant near our Humber refinery in the U.K. The bank facility is designed to provide 65 percent of the construction costs of the project with the remaining 35 percent of the funds coming in the form of equity from certain Conoco subsidiaries. Borrowing under the bank facility is not projected to begin until September 2002. In addition, we have issued a construction support guarantee that indirectly guarantees up to approximately 25 percent of the debt, depending upon the initial operating performance of the plant. This guarantee will be released upon meeting the various completion tests as required by the lenders. Subsequent to closing the facility and as required by the lender to mitigate certain risks, Immingham CHP entered into related foreign currency and interest rate derivative hedging instruments. OTHER LIQUIDITY MATTERS LIQUIDITY AVAILABILITY Conoco's debt securities have current investment grade ratings of BBB+, Baa1, and BBB+ from Standard & Poor's, Moody's Investor Services, and Fitch Ratings Services, respectively. As a result of the proposed merger with Phillips, all three agencies have put Conoco's ratings on Creditwatch positive for a potential upgrade pending the completion of the merger. As a result of Conoco's investment grade ratings, Conoco has access to the money markets, which include the commercial paper markets and bank loan market. As a component of the debt refinancing activities in connection with the Gulf Canada acquisition, Conoco increased its U.S. commercial paper program by $1,000 million in October (see the discussion in financing activities above). During 2001, Conoco had a total daily average of unused capacity of approximately $1,300 million under its commercial paper programs available to support any unforeseen capital needs. Conoco does not have any ratings triggers on any of its corporate debt that would cause an automatic event of default in the event of a downgrade of Conoco's debt rating, thereby impacting Conoco's access to liquidity. In the highly unlikely event that Conoco's credit deteriorates to a level that prohibits Conoco from accessing the commercial paper market, Conoco would still be able to access funds under its $3,000 million revolving credit facility. Based on Conoco's year-end commercial paper balance of $558 million, Conoco would still have access to over $2,400 million in borrowing capacity, after repaying all outstanding commercial paper, to provide ample liquidity to cover any needs that its business may require to cover daily operations. COMMITMENT AND GUARANTEES OF JOINT-VENTURE DEBT At December 31, 2001, Conoco had guarantees outstanding of about $1,014 million for its portion of joint-venture debt totaling $1,955 million. The most significant guarantee was a completion guarantee, guaranteed by DuPont on behalf of and indemnified by Conoco, supporting our share of Petrozuata's debt ($707 million). Petrozuata has now successfully met all of the operational, financial and legal requirements of the completion test associated with this guarantee. On March 14, 2002, Conoco was notified that DuPont was released from its guarantee and the debt became non-recourse to both of the sponsors. Substantially all of the joint ventures whose debt we guarantee are appropriately capitalized and have sufficient cash flow to service their debt. Management believes our current exposure could be up to $50 million for joint ventures that may have insufficient sources of cash to service their debt. OFF-BALANCE SHEET ARRANGEMENTS AND MINORITY INTERESTS Conoco uses various leased facilities and equipment in its operations, some of which are structured in off-balance sheet entities. These structures are principally used to reduce the after-tax cost of leasing such assets. Should the accounting rules concerning consolidation or leasing entities change such that these arrangements would be consolidated by Conoco, we would be required to record the outstanding debt and assets of these arrangements. At December 31, 2001, this amount approximated $400 million. The impact on earnings would not be significant, since current lease payments approximate any resulting depreciation and interest costs from such a reclassification. Conoco also consolidates several entities that have issued equity interests to third parties and provides for a preferred return to those parties. Those entities, which are described in note 22 to the consolidated financial statements, are consolidated with the preferred equity interests accounted for as minority interests. If the accounting rules for consolidations or for classification of debt and equity were to change, the amounts recorded as minority 52 interest might have to be reclassified to long-term debt, with the returns included in interest expense. There would be no effect on cash flow or earnings available to common shareholders for such a reclassification. Conoco has not pledged its stock directly or on a contingency basis as a guarantee or support to any financing transactions. DISCLOSURES ABOUT CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

~~YEAR~~PAYMENTS ~~ENDED~~DUE ~~DECEMBER~~BY 31PERIOD -------------------------------- ~~2000 1999 1998~~ -------- -------- ---------- (IN MILLIONS) ~~UPSTREAM~~UP ~~Asset~~TO ~~sales~~2 ~~........................................ $ 27 $~~ -- $3 954 ~~Property impairments ...............................~~ -- --5 ~~(38)~~AFTER ~~Employee~~5 ~~separation~~TOTAL ~~costs~~1 ~~..........................~~YEAR --YEARS --YEARS ~~(42)~~YEARS ~~Inventory write~~-~~downs ..............................~~ -- -- ~~(4)~~ ----- --- -------- -------- ~~Total upstream ................................ 27~~ -- ~~11 DOWNSTREAM Asset sales ........................................~~ -- -- ~~12 Property impairments ............................... (3)~~ -- -- ~~Employee separation costs ..........................~~ -- -- ~~(10) Inventory write~~-~~downs .............................. (24)~~ -- ~~(59) Litigation ......................................... (16) (18) (28)~~ -----~~---~~ ~~--------~~CONTRACTUAL OBLIGATIONS Long-~~-------~~term ~~Total~~debt ~~downstream~~ .............................. ~~(43)~~$ ~~(18)~~8,862 ~~(85)~~$ ~~EMERGING~~506 ~~BUSINESSES~~$ ~~Property~~2,033 ~~impairments~~$ ~~...............................~~1,276 ~~(26)~~$ --5,047 --Capital ~~--------~~lease ~~--------~~obligations ~~-------- Total emerging businesses~~ ..................... ~~(26)~~22 --2 -- ~~CORPORATE~~3 ~~Stock~~17 ~~option~~Operating ~~provision~~leases ............................. --1,674 --329 ~~(183)~~439 ~~Discontinued~~357 ~~businesses~~549 ~~............................~~Unconditional ~~(4)~~purchase obligations (201) ~~-- Litigation~~ ......~~...................................~~ --1,264 --222 ~~(14)~~315 197 530 -------- -- ------ ---- ---- ~~Total corporate ............................... (4) (20) (197)~~ ------ -- -------- ---------- Total ~~special~~contractual ~~items~~cash obligations ..........~~.........................~~ $ ~~(46)~~11,822 $ ~~(38)~~1,059 $ ~~(271)~~2,787 $ 1,833 $ 6,143 ========== ========== ========== ========== ==========

---------- (1) Includes only non-market based purchase commitments; does not include purchase commitments for materials, supplies, services and items of permanent investment incident to the ordinary conduct of business. EXCHANGE AND NON-EXCHANGE TRADED CONTRACTS ACCOUNTED FOR AT FAIR VALUE See Item 7A. Quantitative and Qualitative Disclosures About Market Risk. RELATED PARTY AND OTHER TRANSACTIONS Conoco has transactions with many unconsolidated affiliates. Equity affiliate sales to Conoco amounted to $1,023 million in 2001, $804 million in 2000 and $720 million in 1999. Equity affiliate purchases from Conoco totaled $1,690 million in 2001, $2,200 million in 2000 and $1,519 million in 1999. These agreements were not the result of arms-length negotiations. However, Conoco believes that these contracts are generally at values that are similar to those that could be negotiated with independent third parties. Conoco does have employees of the company that serve as management committee members of all of our joint ventures. However, neither Conoco's management nor employees have any personal financial ownership in any of these ventures. RESULTS OF OPERATIONS CONSOLIDATED RESULTS

YEAR ENDED DECEMBER 31 ------------------------------------------ 2001 2000 1999 ~~1998~~ ------------ ------------ ------------ (IN MILLIONS) ~~After-tax~~SALES ~~operating~~AND ~~income~~OTHER OPERATING REVENUES Upstream United States ............................................. $ ~~719~~7,028 $ ~~322~~5,531 $ ~~223~~3,309 International ............................................. 15,~~148~~120 ~~534~~3,666 ~~283~~2,247 ------------ ------------ -------- ~~After~~-~~tax~~--- ~~operating~~Total ~~income~~upstream ........................................... 112,~~867~~148 ~~856~~9,197 ~~506~~5,556 ~~Special~~Downstream ~~items~~ United States ............................................. ~~(27)~~15,288 --17,379 1411,191 International ............................................. 11,296 12,157 10,264 -- -- ~~(25)~~ -------- ------------ ------------ ~~Special~~Total ~~items~~downstream ......................................... ~~(27)~~26,584 --29,536 ~~(11)~~21,455 ~~Earnings~~Emerging ~~before~~businesses ~~special items United States~~ ......................................... ~~692~~5 ~~322~~4 ~~237~~28 ~~International~~Corporate ................................................... ~~1,148~~-- ~~534~~-- ~~258~~-- ------------ ------------ ------------ ~~Earnings~~Total ~~before~~sales ~~special~~and ~~items~~other operating revenues ........................ $ 138,~~840~~737 $ ~~856~~38,737 $ ~~495~~27,039 ============ ============ ============

~~TOTAL~~YEAR ~~UNITED~~ENDED ~~WORLDWIDE~~DECEMBER ~~STATES~~31 ~~INT'L.~~------------------------------------------ 2001 2000 1999 ------------ ------------ ------------ (~~UNITED~~IN ~~STATES DOLLARS~~MILLIONS) ~~TOTAL~~AFTER-TAX ~~CONOCO~~OPERATING ~~For~~INCOME ~~the~~Upstream ~~year~~United ~~ended~~States ~~December~~............................................. ~~31,~~$ ~~2000~~987 ~~Average~~$ ~~production~~719 ~~costs~~$ ~~per~~322 ~~barrel~~International of............................................. ~~oil~~824 ~~equivalent~~1,148 of534 ~~petroleum~~------------ ~~produced(1)~~------------ ------------ Total upstream ........................................... $1,811 ~~4.13~~1,867 $856 ~~4.27~~Downstream $United 4States .06............................................ ~~Average~~329 ~~sales~~182 ~~prices~~119 ofInternational ~~produced~~............................................. ~~petroleum~~86 ~~Per~~230 ~~barrel~~129 of------------ ~~crude~~------------ ~~oil~~------------ ~~and~~Total ~~condensate~~downstream ~~sold~~ ................ 26.~~08 27~~.~~72 25~~.77...................... ~~Per~~415 ~~mcf~~412 of248 ~~natural~~Emerging ~~gas~~businesses ~~sold~~ ................................ 3.~~07 3~~.~~42 2~~.75...... ~~For~~(90) ~~the~~(69) ~~year~~(35) ~~ended~~Corporate ~~December~~................................................... ~~31,~~(201) ~~1999~~(104) ~~Average~~(98) ~~production~~------------ ~~costs~~------------ ~~per~~------------ ~~barrel~~Total ofafter-tax ~~oil~~operating ~~equivalent~~income ~~of petroleum produced(1)~~ ........................ 4.04 ~~3.67~~1,935 ~~4.24~~2,106 ~~Average~~971 ~~sales~~Interest ~~prices~~and other non-operating expenses net of ~~produced~~tax ~~petroleum~~......... ~~Per~~(346) ~~barrel~~(204) of(227) ~~crude~~------------ ~~oil~~------------ ~~and~~------------ ~~condensate~~Net ~~sold~~income ................ 17.~~09 17~~.~~33 17~~.~~04 Per mcf of natural gas sold~~ ................................ 2.12.. $ 1~~.99~~,589 ~~2.27~~$ 1,902 $ 744 ============ ============ ============

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

~~TOTAL~~YEAR ~~UNITED~~ENDED ~~WORLDWIDE~~DECEMBER ~~STATES~~31 ~~INT'L.~~ ---------- ---------- ---------------- ~~(UNITED~~2001 ~~STATES~~2000 ~~DOLLARS)~~1999 ~~TOTAL~~---------- ~~CONOCO~~---------- ---------- (~~CONT'D.~~IN MILLIONS) ~~For~~UPSTREAM ~~the~~Asset ~~year~~sales ~~ended December 31, 1998 Average production costs per barrel of oil equivalent of petroleum produced(1)~~ ........................ 4.~~17 3~~.~~76 4~~.43................................. ~~Average~~$ ~~sales~~134 ~~prices~~$ of27 ~~produced~~$ ~~petroleum~~-- ~~Per~~Affiliate ~~barrel~~sales ~~of crude oil~~ and ~~condensate~~write-downs ~~sold~~ ................ 12.~~14 12~~.~~17 12~~.14..................... ~~Per~~23 ~~mcf~~-- of-- ~~natural~~Cumulative ~~gas~~effect ~~sold~~of accounting change ................................ 2.24 ~~1.97~~40 ~~2.72~~-- ~~CONSOLIDATED~~-- ~~COMPANIES~~Assets ~~For~~held ~~the~~for ~~year~~sale ~~ended~~and ~~December~~other ~~31,~~write-downs ~~2000~~............................. ~~Average~~(131) ~~production~~-- ~~costs~~-- ~~per~~---------- ~~barrel~~---------- of---------- ~~oil~~Total ~~equivalent~~upstream ~~of petroleum produced(1)~~ ........................ ~~$ 4~~.~~00 $ 4~~.~~17 $ 3~~.90......................... ~~Average~~66 ~~sales~~27 ~~prices~~-- ofDOWNSTREAM ~~produced~~Affiliate ~~petroleum~~sales ~~Per barrel of crude oil~~ and ~~condensate~~write-downs ~~sold~~ ................ 27.~~67 27~~.~~72 27~~.65..................... ~~Per~~(46) ~~mcf~~-- of-- ~~natural~~Inventory ~~gas~~write-downs ~~sold~~ ................................ 3.~~06 3~~.~~42 2~~.75............... ~~For~~-- ~~the~~(24) ~~year~~-- ~~ended~~Cumulative ~~December~~effect ~~31, 1999 Average production costs per barrel~~ of ~~oil~~accounting ~~equivalent~~change ~~of petroleum produced(1)~~ ........................ 3.~~93 3~~.~~60 4~~.13...... ~~Average~~(3) ~~sales~~-- ~~prices~~-- ofAssets ~~produced~~held ~~petroleum~~for ~~Per~~sale ~~barrel of crude oil~~ and ~~condensate~~other ~~sold~~write-downs ................ 17.~~51 17~~.~~33 17~~.55.......... ~~Per~~-- ~~mcf~~(3) of-- ~~natural~~Humber ~~gas~~fire ~~sold~~repairs ................................ 2.~~12 1~~.~~98 2~~.27................. ~~For~~(54) ~~the~~-- ~~year~~-- ~~ended~~Litigation ~~December 31, 1998 Average production costs per barrel of oil equivalent of petroleum produced(1)~~ ........................ 3.~~95 3~~.~~69 4~~.~~13 Average sales prices of produced petroleum Per barrel of crude oil and condensate sold~~ ................ 12.~~37 12~~.~~17 12~~.40............... ~~Per~~(41) ~~mcf~~(16) of(18) ~~natural~~---------- ~~gas~~---------- ~~sold~~---------- Total downstream ................................ 2.~~24 1~~.~~96 2~~.72............... ~~EQUITY~~(144) ~~AFFILIATES~~(43) ~~For~~(18) ~~the~~EMERGING ~~year~~BUSINESSES ~~ended~~Affiliate ~~December~~sales ~~31,~~and ~~2000~~write-downs ~~Average production costs per barrel of oil equivalent of petroleum produced(1)~~ ........................ ~~$ 5~~.~~43 $ 10~~.~~69 $ 5~~.15............. ~~Average~~-- ~~sales~~(26) ~~prices~~-- of---------- ~~produced~~---------- ~~petroleum~~---------- ~~Per~~Total ~~barrel~~emerging ofbusinesses ~~crude oil and condensate sold~~ ................ 18.21........................ -- ~~18.21~~(26) ~~Per~~-- ~~mcf~~CORPORATE ofDiscontinued ~~natural~~businesses ~~gas sold~~ ................................ 3.~~77 3~~.77.............. --(70) ~~For~~(4) ~~the year ended December 31, 1999 Average production costs per barrel of oil equivalent of petroleum produced~~(120) Other ........................ 5.~~53 10~~.~~02 5~~.~~24 Average sales prices of produced petroleum Per barrel of crude oil and condensate sold~~ ................ 13.86...................... (4) -- ~~13.86~~-- ~~Per~~---------- ~~mcf~~---------- of---------- ~~natural~~Total ~~gas~~corporate ~~sold~~ ................................ 2.~~35 2~~.35................. --(74) ~~For~~(4) ~~the~~(20) ~~year~~INTEREST ~~ended~~AND ~~December~~OTHER ~~31,~~NON-OPERATING ~~1998~~EXPENSES ~~Average~~NET ~~production~~OF ~~costs~~TAX ~~per~~Foreign ~~barrel~~currency ofexchange ~~oil~~loss ~~equivalent~~......................................... ~~of petroleum produced~~(138) -- -- Premium on debt retirement ........................ 9.~~10 10~~.~~11 8~~.98.................. ~~Average~~(44) ~~sales~~-- ~~prices~~-- of---------- ~~produced~~---------- ~~petroleum~~---------- ~~Per~~Total ~~barrel~~interest ofand ~~crude~~other ~~oil~~non-operating ~~and~~expenses ~~condensate~~net ~~sold~~of tax ........~~........~~ ~~8.90~~(82) -- ~~8.90~~-- ~~Per~~---------- ~~mcf~~---------- of---------- ~~natural~~Total ~~gas~~special ~~sold~~items ................................ 2.~~39 2~~.39..................... --$ (234) $ (46) $ (38) ========== ========== ==========

Special items in 2001 included gains of $194 million, consisting of: 54 o $134 million from the sale of several shallow Gulf of Mexico properties; o $23 million from the sale of our interest in the Pocahontas Gas Partnership; and o $37 million from a cumulative transition gain recorded on January 1, 2001, upon initial adoption of SFAS No. 133, as amended. The cumulative transition gain of $37 million included a $40 million gain in upstream related to changes in the fair value of certain crude oil put options from their purchase date to the January 1, 2001, adoption of the aforementioned standards and a $3 million charge in U.S. downstream associated with various derivatives. The $40 million upstream transition gain consisted of $8 million that was U.S. related and $32 million that was related to international operations. Offsetting this transition gain and included in net income for upstream was a $53 million expense for 2001 related to changes in the fair value of these same crude oil put options. The $53 million expense for 2001 consisted of $10 million for U.S. operations and $43 million for international operations. Offsetting these gains were: o upstream assets held for sale and other write-downs of $131 million, consisting of a $44 million write-down of certain U.S. producing assets held for sale and an $87 million write-down of Canadian legacy assets held for sale; o downstream affiliate sales and write-downs of $46 million, consisting of a $23 million write-down of a U.S. joint-venture investment held for sale and a $23 million write-down of an international joint-venture investment held for sale; o a $54 million charge to record repairs and other costs associated with the April 16, 2001, explosion and fire at our Humber refinery in North Lincolnshire, U.K.; o a $41 million charge related to an adverse ruling on the patent dispute with General Technology Applications (GTA); o an accrual of $70 million for a litigation settlement for a discontinued business related to the separation agreement from DuPont; o $4 million in costs associated with the ConocoPhillips merger; o a $38 million foreign currency exchange loss from changes in the fair value of Canadian dollar forward exchange contracts related to the acquisition of Gulf Canada; and o $44 million for extraordinary item charges for premiums on the early repayment of high-cost Gulf Canada debt. Special items in 2000 included a $27 million gain from the sale of U.S. natural gas processing assets. This asset sale was part of Conoco's effort to move away from a midstream business of scattered assets in mature areas toward a business built on centralized, large-scale gas processing systems. The following charges also were recorded during 2000: o $24 million write-down of inventories to market value; o assets held for sale and other write-downs of $3 million for U.S. refinery assets; o $16 million from U.S. downstream litigation charges; o affiliate sales and write-downs of $26 million; and o $4 million from discontinued businesses. The $24 million write-down of inventories at year-end 2000 was the result of significant declines in crude oil and finished product prices during December. The write-down occurred at our Melaka refinery joint venture as Dubai crude oil prices fell from $33.00 per barrel to $23.00 per barrel during December. The after-tax affiliate sales and other write-downs were the result of our write-off of $26 million related to our 37.5 percent interest in a Colombian power venture. The Colombian power venture write-off was due to 55 unfavorable business conditions in Colombia. In October 1996, Conoco Global Energy purchased shares in a Colombian power venture that was formed to generate and market electric power by means of a gas-fired electrical generating facility near Barrancabermeja, Colombia. The gas-fired plant became operational in August 1998 and received capacity payments for idle periods. With the deterioration of the Colombian economy, the plant suffered small losses in 1998 and 1999. The continued weak demand for electricity created a large surplus in generating capacity, prompting a reduction in the capacity payment rate for 2000. A combination of lower capacity payment revenue, continued weak demand for electricity, onerous gas supply contract provisions, safety and security concerns from continued guerrilla activity and forecasted losses for 2000 prompted management's decision in the third quarter of 2000 to exit the venture, resulting in a revaluation of the investment. After pursuing various options, Conoco's interest was sold in February 2001 for a nominal amount. The $4 million loss was for settlement costs associated with the separation agreement from DuPont related to a discontinued business. Special items in 1999 included charges for $18 million related to the settlement of certain posted price litigation and $20 million for the resolution of certain liabilities associated with the separation from DuPont related to discontinued businesses operated by Conoco in the past. Net income before special items (earnings before special items) totaled $1,823 million in 2001, $1,948 million in 2000 and $782 million in 1999. 2001 VERSUS 2000 Conoco's 2001 net income of $1,589 million was down 16 percent from $1,902 million in 2000. Earnings before special items of $1,823 million in 2001 were 6 percent lower than the $1,948 million in 2000. The decrease in earnings before special items was predominantly the result of lower worldwide crude oil prices, higher operating and overhead costs and higher depreciation, depletion and amortization (DD&A), partly offset by higher worldwide natural gas prices and strong U.S. refining margins in the first six months of 2001 and increased production. Sales and other operating revenues of $38,737 million in 2001 were unchanged from 2000. Downstream sales and other operating revenues were $26,584 million, down 10 percent compared to $29,536 million in 2000. Crude oil and refined product buy/sell and natural gas resale activities in 2001 totaled $9,509 million, up 5 percent compared to $9,044 million in 2000. The increase was primarily due to higher natural gas prices in the first six months of 2001 and increased natural gas volumes. Income from equity affiliates for 2001 was $181 million, down $96 million, or 35 percent, compared to $277 million in 2000. Lower prices for heavy crude reduced our earnings from Petrozuata by $95 million and from Polar Lights, our Russian joint venture, by $35 million in 2001 compared to 2000. This was partially offset by an increase in our earnings from the Pocahontas Gas Partnership in the first nine months of the year due to strong natural gas prices; reduced losses from the Melaka, Malaysia, refinery; and increased earnings from Excel Paralubes. Other income for 2001 was $621 million, up 127 percent from $273 million in 2000. The increase in other income was primarily due to a gain of $283 million on natural gas and crude oil hedges (that were not afforded hedge accounting treatment) associated with the Gulf Canada acquisition and a gain of $214 million from the sale of shallow-water Gulf of Mexico properties, partially offset by an $84 million charge related to changes in the fair value of certain crude oil options from January 1, 2001, to December 31, 2001, and a $59 million foreign currency loss associated with the Gulf Canada acquisition. Cost of goods sold totaled $23,043 million in 2001, a decrease of 4 percent compared to $23,921 million in 2000. The decrease was primarily due to lower feedstock costs associated with lower crude oil prices for the last six months of 2001. Operating expenses were $3,053 million in 2001, up 38 percent from $2,215 million for 2000, primarily attributable to our Gulf Canada acquisition, higher energy costs experienced by our downstream operations, higher volume-related and price-related operating costs, and higher transportation and tariff charges experienced by our upstream operations. Selling, general and administrative expenses for 2001 amounted to $888 million, up 12 percent compared to $794 million in 2000. The increase was related to our Gulf Canada acquisition and higher computer services expenses. 56 In 2001, exploration expenses totaled $378 million, an increase of $99 million, or 35 percent, compared to $279 million in 2000. The higher expenses were primarily a result of our Gulf Canada acquisition. DD&A for 2001 totaled $1,811 million, an increase of $510 million, or 39 percent, compared to $1,301 million in 2000, principally due to our Gulf Canada acquisition. The remainder of the increase was due to write-downs of $197 million related to certain North American upstream producing assets held for sale and changes in rates and field mix. Provision for income taxes for 2001 was $1,391 million, a decrease of 11 percent compared to $1,556 million for 2000. This decrease was primarily the result of lower pretax income in 2001. The effective tax rate in 2001 was approximately 47 percent versus 45 percent in 2000. The higher effective tax rate was due to a greater portion of 2001 earnings being generated by operations in countries with higher effective tax rates. 2000 VERSUS 1999 Conoco's 2000 net income of $1,902 million was up 156 percent from $744 million in 1999. Earnings before special items of $1,948 million in 2000 were 149 percent higher than the $782 million in 1999. The increase in earnings before special items was primarily the result of higher crude oil, natural gas and natural gas liquids prices, increased volumes, lower dry hole costs and stronger refining margins. Partly offsetting these improvements were weaker co-product margins, lower European marketing earnings and higher operating costs associated with increased volumes and higher energy costs. Sales and other operating revenues of $38,737 million in 2000 increased 43 percent compared to $27,039 million in 1999, primarily driven by higher crude oil and natural gas prices and improved refined product prices and volumes. Downstream sales and other operating revenues were $29,536 million, up 38 percent compared to $21,455 million in 1999. Crude oil and refined product buy/sell and natural gas and electric power resale activities in 2000 totaled $9,044 million, up 71 percent compared to $5,299 million in 1999. The increase was primarily due to higher crude oil, natural gas and refined product prices, slightly offset by reduced power-trading activities. Income from equity affiliates for 2000 was $277 million, up $127 million, or 85 percent, compared to $150 million in 1999. Additional crude oil volumes from our Petrozuata joint venture and higher crude oil and natural gas prices primarily drove this increase. Other income for 2000 was $273 million, up 128 percent from $120 million in 1999, primarily due to the gain on the sale of natural gas processing assets in the U.S., revenue from our Syrian service contract, foreign exchange gains and additional interest income. These improvements were partly offset by the $26 million write-off of our 37.5 percent interest in a Colombian power venture. Cost of goods sold totaled $23,921 million in 2000, an increase of 62 percent compared to $14,781 million in 1999. The increase is primarily attributable to higher feedstock costs associated with higher crude oil prices. Operating expenses were $2,215 million in 2000, up 8 percent from the $2,060 million for 1999, primarily due to higher energy costs and higher overall compensation charges due to variable compensation based on higher earnings in 2000. Selling, general and administrative expenses for 2000 amounted to $794 million, down 2 percent compared to $809 million in 1999. During 2000, exploration expenses totaled $279 million, an increase of $9 million, or 3 percent, compared to $270 million in 1999. The higher expenses were primarily driven by deepwater Gulf of Mexico seismic purchases, partially offset by lower dry hole costs. DD&A for 2000 totaled $1,301 million, an increase of $108 million, or 9 percent, compared to $1,193 million in 1999 due to higher production volumes and the write-down of a non-operating natural gas processing plant. Provision for income taxes for 2000 was $1,556 million, an increase of 229 percent compared to $473 million for 1999. This increase was primarily the result of higher pretax income in 2000. The effective tax rate in 2000 was approximately 45 percent versus 39 percent in 1999. The higher effective tax rate was due to a greater portion of 57 2000 earnings being generated by operations in countries with higher tax rates and the reduced impact of U.S. alternative fuels tax credits on higher pretax income in 2000. UPSTREAM SEGMENT RESULTS

YEAR ENDED DECEMBER 31 ------------------------------------------ 2001 2000 1999 ~~1998~~ ------------ ------------ ------------ (IN MILLIONS) After-tax operating income United States .......................~~...............~~ $ ~~182~~987 $ ~~119~~719 $ ~~141~~322 International .......................~~...............~~ ~~230~~824 ~~129~~1,148 ~~156~~534 ------------ ------------ ------------ After-tax operating income ........~~...............~~ ~~412~~1,811 ~~248~~1,867 ~~297~~856 Special items United States .......................~~...............~~ 19(121) 18(27) 73-- International .......................~~...............~~ 2455 -- 12-- ------------ ------------ ------------ Special items .....................~~...............~~ 43(66) 18(27) 85-- Earnings before special items United States .......................~~...............~~ ~~201~~866 ~~137~~692 ~~214~~322 International .......................~~...............~~ ~~254~~879 ~~129~~1,148 ~~168~~534 ------------ ------------ ------------ Earnings before special items ..........~~...............~~ $ ~~455~~1,745 $ ~~266~~1,840 $ ~~382~~856 ============ ============ ============

The following table sets forth for Conoco, including equity affiliates, the average production costs per BOE produced, average sales prices per barrel of crude oil and condensate sold and average sales prices per mcf of natural gas sold for the three-year period ended December 31, 2001. Average sales prices exclude proceeds from sales of interests in oil and gas properties.

~~YEAR~~UNITED ~~ENDED~~CONSOLIDATED ~~DECEMBER~~EQUITY 31TOTAL STATES INT'L. COMPANIES COMPANIES WORLDWIDE ---------- ---------- ------------ ~~2000 1999 1998~~ -------- -- ------ ----~~----~~ (INUNITED ~~MILLIONS~~STATES DOLLARS) ~~After-tax~~FOR ~~operating~~THE ~~losses~~YEAR ENDED DECEMBER 31, 2001 Average production costs per barrel of oil equivalent of petroleum produced (1) ............... $ 5.23 $ 5..02 $ ~~(69)~~5.08 $ ~~(35)~~6.71 $ 5.25 Average sales prices of produced petroleum Per barrel of crude oil and condensate sold ........ 23.95(312) ~~Special~~22.69 ~~items~~22.89 13.16 21.14 Per mcf of natural gas sold ........................ 4.13(2) 3.09 3.51 4.61 3.52 26FOR --THE --YEAR ~~--------~~ENDED ~~--------~~DECEMBER ~~--------~~31, ~~Losses~~2000 ~~before~~Average ~~special~~production ~~items~~costs per barrel of oil equivalent of petroleum produced (1) ............... $ 4.17 $ 3.90 $ (4.00 $ 5.43) $ 4.13 Average sales prices of produced petroleum Per barrel of crude oil and condensate sold ........ 27.72 27.65 27.67 18.21 26.08 Per mcf of natural gas sold ........................ 3.42 2.75 3.06 3.77 3.07 FOR THE YEAR ENDED DECEMBER 31, 1999 Average production costs per barrel of oil equivalent of petroleum produced (351) ............... $ ~~(31)~~3.60 ~~========~~$ ~~========~~4.13 ~~========~~$ 3.93 $ 5.53 $ 4.04 Average sales prices of produced petroleum Per barrel of crude oil and condensate sold ........ 17.33 17.55 17.51 13.86 17.09 Per mcf of natural gas sold ........................ 1.98 2.27 2.12 2.35 2.12

---------- (1) Average production costs per barrel of equivalent liquids, with natural gas converted to liquids at a ratio of 6,000 cubic feet of gas to one barrel of liquid. (2) Includes favorable U.S. hedging effect of $38 million or $1.29 per barrel for crude oil and condensate sold and $.05 per mcf for natural gas sold. The following table sets forth for Conoco the average production cost per barrel of Canadian Syncrude produced and average sales price per barrel of Canadian Syncrude sold from the Canadian Syncrude project in Canada. 58

~~YEAR~~AMOUNT ~~ENDED DECEMBER 31~~ ----------~~----------------------~~ ~~2000~~(UNITED ~~1999~~STATES ~~1998~~DOLLARS) ~~--------~~CANADIAN ~~--------~~SYNCRUDE ~~--------~~FOR ~~(IN~~THE ~~MILLIONS)~~SIX ~~After-tax~~MONTHS ~~losses~~ENDED ~~.................................~~DECEMBER $31, ~~(104)~~2001 $Average ~~(98)~~production $costs ~~(250)~~per ~~Special~~barrel ~~items~~of Canadian Syncrude produced...........~~.........................~~ 4$ 2011.34 ~~197~~Average ~~--------~~sales ~~--------~~price ~~--------~~per ~~Losses~~barrel ~~before~~of ~~special~~Canadian ~~items~~Syncrude sold...................... ~~$ (100) $ (78) $ (53) ======== ======== ========~~21.98

2001 VERSUS 2000 Upstream after-tax operating income was $1,811 million in 2001, down 3 percent from $1,867 million in 2000, principally due to lower crude oil prices and higher operating and overhead costs and DD&A resulting from the Gulf Canada acquisition. These factors were partly offset by stronger gas prices in the first six months of 2001, increased production volumes and gains from natural gas and crude oil hedges associated with the Gulf Canada acquisition. Upstream earnings before special items were $1,745 million in 2001, a decrease of 5 percent from $1,840 million in 2000. Including equity affiliates, Conoco's worldwide net realized crude oil price was $21.14 per barrel for 2001, a reduction of $4.94 per barrel, or 19 percent, versus $26.08 per barrel for 2000, primarily driven by a decrease in demand for oil and an increase in inventory levels. Worldwide net realized natural gas prices, including equity affiliates, averaged $3.52 per mcf for 2001, compared to $3.07 per mcf for 2000, an improvement of 15 percent. U.S. natural gas prices increased from $3.42 per mcf in 2000 to $4.13 per mcf in 2001, up 21 percent, while international natural gas prices averaged $3.09 per mcf in 2001, up 12 percent from $2.75 per mcf in 2000. The increase in U.S. gas prices was largely due to increased demand during the first quarter of 2001. Worldwide petroleum liquids production in 2001, including Conoco's share from its equity affiliates, but excluding Canadian Syncrude, was 422,000 barrels per day versus 370,000 barrels per day in 2000, a 14 percent increase. Canadian Syncrude production for the last six months of 2001 averaged 20,000 barrels per day. Conoco's 2001 worldwide natural gas production, including its share from equity affiliates, was up 19 percent to 2,030 million cubic feet (mmcf) per day from 2000 production of 1,705 mmcf per day. Conoco's total net hydrocarbon production, including its share from equity affiliates and including Canadian Syncrude, was 770,000 BOE per day, an increase of 18 percent over 2000. U.S. upstream earnings before special items totaled $866 million in 2001, an increase of 25 percent, from $692 million in 2000. The increase was largely due to higher natural gas prices and natural gas and crude oil hedging gains. These improvements were partly offset by lower crude oil prices, higher production operating and overhead costs and higher DD&A associated with field mix. U.S. petroleum liquids production, including Conoco's share from its equity affiliates, was down 7,000 barrels per day to 73,000 barrels per day, due to natural field decline in the Gulf Coast and Mid-Continent regions. U.S. natural gas production, including Conoco's share from its equity affiliates, was 811 mmcf per day, 3 mmcf less than in 2000, due primarily to natural field decline. U.S. production costs were $5.23 per BOE, up $1.06 per BOE, compared to $4.17 per BOE in 2000, primarily due to a reclassification of transportation charges from sales and other operating revenues to operating costs. International upstream earnings before special items were $879 million, an impairment of 23 percent, from $1,148 million in 2000. This was primarily due to lower crude oil prices, higher production operating and overhead costs related to the Gulf Canada acquisition, higher DD&A due to the Gulf Canada acquisition and higher exploration expenses and dry hole costs. These factors were partly offset by higher petroleum liquids production. International petroleum liquids production, including our share from equity affiliates and including Canadian Syncrude, increased 24 percent, or 69,000 barrels per day, to 359,000 barrels per day in 2001. The increase is primarily attributable to the acquisition of Gulf Canada. In addition, there was increased production from both Vietnam, where there were additional wells producing, and Petrozuata, where the upgrader is operational. These increases were partly offset by decreases in Russia. In 2001, the 1,219 mmcf per day of international natural gas production, including our share from equity affiliates, was up 37 percent, or 328 mmcf per day, over 2000, due primarily to our Gulf Canada acquisition, offset by lower production from the Murdoch field, Miller field and V fields in the North Sea. International production costs were $5.02 per BOE, up 29 percent from $3.90 per BOE in 2000, due to our Gulf Canada acquisition and increased pipeline charges in the U.K. 2000 VERSUS 1999 Upstream after-tax operating income was $1,867 million in 2000, up 118 percent from $856 million in 1999, principally due to higher crude oil, natural gas and natural gas liquids prices, increased U.S. petroleum liquids 59 production, increased international natural gas production and lower dry hole costs. These improvements were partly offset by a drop in U.S. natural gas volumes due to the disposition of our Grand Isle, Louisiana, assets and natural field decline. Upstream earnings before special items were $1,840 million in 2000, an increase of 115 percent from $856 million in 1999. Including equity affiliates, Conoco's worldwide net realized crude oil price was $26.08 per barrel for 2000, an improvement of $8.99 per barrel, or 53 percent, versus $17.09 per barrel for 1999, primarily driven by strong demand, as well as by members of OPEC adhering to production quotas implemented in early 1999. Worldwide net realized natural gas prices, including equity affiliates, averaged $3.07 per mcf for 2000, compared to $2.12 per mcf for 1999, an improvement of 45 percent. U.S. natural gas prices increased from $1.98 per mcf in 1999 to $3.42 per mcf in 2000, up 73 percent, while international natural gas prices averaged $2.75 per mcf in 2000, up $.48 from $2.27 per mcf in 1999. The increase in U.S. gas prices was largely due to increased demand during an extended and severe winter season. Worldwide petroleum liquids production in 2000, including Conoco's share from its equity affiliates, was 370,000 barrels per day versus 359,000 barrels per day in 1999, a 3 percent increase. Conoco's 2000 worldwide natural gas production, including its share from equity affiliates, was up 3 percent to 1,705 mmcf per day from 1999 production of 1,660 mmcf per day. Conoco's total net hydrocarbon production, including its share from equity affiliates, was 654,000 BOE per day, an increase of 3 percent over 1999. U.S. upstream earnings before special items totaled $692 million in 2000, a 115 percent increase from $322 million in 1999. The increase was largely due to higher crude oil, natural gas and natural gas liquids prices and increased petroleum liquids production. These improvements were partly offset by higher exploration expenses, higher DD&A associated with field mix and lower natural gas production. U.S. petroleum liquids production, including Conoco's share from its equity affiliates, was up 6,000 barrels per day to 80,000 barrels per day, as a result of additional volumes from the Ursa field, partially offset by the disposition of our Grand Isle assets and natural field decline. U.S. natural gas production, including Conoco's share from its equity affiliates, was 814 mmcf per day, 66 mmcf per day less than in 1999, due primarily to the disposition of our Grand Isle assets and natural field decline. U.S. production costs were $4.17 per BOE, up $.57 per BOE, compared to $3.60 per BOE in 1999, due to an increase in price-driven production taxes. International upstream earnings before special items were $1,148 million, an improvement of 115 percent, from $534 million in 1999. This was due primarily to higher crude oil, natural gas and natural gas liquids prices; improved earnings from equity affiliates; lower dry hole costs; and increased natural gas volumes. These improvements were partly offset by lower petroleum liquids production and higher DD&A associated with field mix. International petroleum liquids production, including our share from equity affiliates, increased 2 percent, or 5,000 barrels per day, to 290,000 barrels per day in 2000. The increase is primarily attributable to higher production in Norway and Venezuela, and the acquisition of Saga U.K. Ltd. This increase was partly offset by downtime at the U.K. Banff field and natural decline in other U.K. fields. In 2000, the 891 mmcf per day of international natural gas production, including our share from equity affiliates, was up 14 percent, or 111 mmcf per day, over 1999, due primarily to our acquisitions in Canada and our Saga acquisition in the U.K., and higher production from the Britannia field, Vampire field and V fields in the North Sea. International production costs were $3.90 per BOE, down 6 percent from $4.13 per BOE in 1999, due to higher production volumes in Norway and the U.K. DOWNSTREAM SEGMENT RESULTS

YEAR ENDED DECEMBER 31 ----------------------------~~----~~ 2001 2000 1999 ~~1998~~ -------- -------- -------- (IN MILLIONS) ~~Interest~~After-tax ~~expense~~operating onincome ~~debt~~United States .............................. $ ~~(277)~~329 $ ~~(243)~~182 $ ~~(177)~~119 ~~Interest~~International ~~income~~ ............................ 86 230 129 -------- -------- -------- After-tax operating income ............... 35415 10412 73248 ~~Exchange~~Special ~~gains~~items United States ............................ 67 19 18 International ............................ 3877 624 32-- -------- -------- -------- ~~Total~~Special items ............................ 144 43 18 Earnings before special items United States ............................ 396 201 137 International ............................ 163 254 129 -------- -------- -------- Earnings before special items ............... $ ~~(204)~~559 $ ~~(227)~~455 $ ~~(72)~~266 ======== ======== ========

60 2001 VERSUS 2000 Downstream after-tax operating income was $415 million in 2001, up 1 percent compared to $412 million in 2000. Downstream earnings before special items totaled $559 million in 2001, an increase of 23 percent from $455 million in 2000. In 2001, U.S. downstream earnings before special items totaled $396 million, which was $195 million, or 97 percent, higher than $201 million in 2000. The increase was attributable to significantly improved inland refining margins, wider price differentials between light and heavy crude oil and stronger margins for co-products, such as petroleum coke and asphalt. This was partly offset by higher operating and overhead costs, including increased energy costs in the first half of 2001. International downstream earnings before special items were $163 million in 2001, a decrease of 36 percent from $254 million in 2000, reflecting lower refining margins. Conoco's refineries operated at 88 percent capacity in 2001 versus 93 percent in 2000. The decrease is primarily due to downtime resulting from the April explosion and fire at our U.K. Humber refinery. 2000 VERSUS 1999 Downstream after-tax operating income was $412 million in 2000, up 66 percent compared to $248 million in 1999. Downstream earnings before special items totaled $455 million in 2000, an increase of 71 percent from $266 million in 1999. In 2000, U.S. downstream earnings before special items totaled $201 million, which was $64 million, or 47 percent, higher than $137 million in 1999. The increase was attributable to significantly improved refining margins, offset partly by weaker margins for co-products, such as petroleum coke and asphalt, lower marketing margins and reduced earnings in our lubricants and specialty products business, as a result of higher feedstock costs. Additionally, earnings were reduced due to higher operating costs, including energy and variable compensation charges. International downstream earnings before special items were $254 million in 2000, an increase of 97 percent from $129 million in 1999, reflecting stronger refinery margins, partly offset by weaker co-product margins as a result of higher crude oil costs and lower European marketing earnings. Conoco's refineries operated at 93 percent capacity in 2000 versus 96 percent in 1999. The decrease is primarily due to downtime in connection with the major modifications at our Lake Charles refinery to enable it to process Petrozuata synthetic crude. EMERGING BUSINESSES SEGMENT RESULTS

~~CHANGE~~YEAR INENDED ~~FAIR~~DECEMBER ~~VALUE~~31 ~~FROM 10% ADVERSE FAIR VALUE PRICE CHANGE~~ --------------- --------------- ~~COMMODITY DERIVATIVES(1) AT DECEMBER 31, 2000 Crude oil and refined products Trading ...................................................... $ 1 $ 1 Non~~-~~trading(2) ............................................... 92 (29)~~ -----~~----------~~ ~~---------------~~2001 ~~Combined~~2000 ~~........................................................~~1999 ~~$ 93 $ (28) =============== =============== Natural gas Trading ...................................................... $ 3 $ 2 Non~~-~~trading .................................................. 103 (33)~~ --------- ------ ---- ----------- ~~Combined ........................................................ $ 106 $~~ (31IN MILLIONS) ~~===============~~After-tax ~~===============~~operating ATlosses ~~DECEMBER 31, 1999 Crude oil and refined products Trading~~ ........~~..............................................~~ $ 10(90) $ ~~2 Non-trading .................................................. 10~~ (469) ~~--------------- --------------- Combined ........................................................~~ $ ~~20 $~~ (235) ~~===============~~Special ~~===============~~items ~~Natural gas Trading~~ .....................~~.................................~~ $ -- $26 -- ~~Non~~-~~trading ..................................................~~ -- ~~(8)~~ ------- -------- -- ----------~~---~~ ~~Combined~~Losses before special items .......~~.................................................~~ $ --(90) $ (843) $ (35) ========== ===== ===== ==========

2001 VERSUS 2000 Emerging businesses after-tax operating losses were $90 million in 2001, an impairment of $21 million from losses of $69 million in 2000, primarily resulting from increased research and development costs and operating expenses required to grow these new businesses. Emerging businesses operating losses before special items for 2001 were $90 million, up $47 million from the $43 million loss in 2000. 2000 VERSUS 1999 Emerging businesses after-tax operating losses were $69 million in 2000, an impairment of $34 million from losses of $35 million in 1999, primarily resulting from the $26 million write-off of Conoco's 37.5 percent interest in 61 a Colombian power venture, and from higher operating expenses required to grow these new businesses. Emerging businesses operating losses before special items for 2000 were $43 million, up $8 million from the $35 million loss in 1999. CORPORATE SEGMENT RESULTS

~~PAGE~~YEAR ~~Report~~ENDED ofDECEMBER ~~Management......................................................................................~~31 ~~61 Audited Consolidated Financial Statements Report of Independent Accountants...................................................................... 62 Consolidated Statement of Income~~ ------------------------------------ ~~Years~~2001 ~~Ended December 31,~~ 2000, 1999 ~~and~~---------- ~~1998........................~~---------- 63---------- ~~Consolidated~~(IN ~~Balance~~MILLIONS) ~~Sheet~~ After-tax atlosses ~~December 31, 2000 and 1999~~..................~~...........................~~ 64$ ~~Consolidated~~(201) ~~Statement~~$ of(104) ~~Stockholders'~~$ ~~Equity/Owner's~~(98) ~~Net~~Special ~~Investment~~items ~~and Accumulated Other Comprehensive Loss - Years Ended December 31, 2000, 1999 and 1998~~.....................~~.........~~ 6574 ~~Consolidated~~4 ~~Statement~~20 of---------- ~~Cash~~---------- ~~Flows~~ ---------- ~~Years~~Losses ~~Ended~~before ~~December~~special ~~31,~~items ~~2000, 1999 and 1998~~.......~~.............~~ 66$ ~~Notes~~(127) to$ ~~Consolidated~~(100) ~~Financial~~$ ~~Statements.............................................................~~(78) 67========== ~~Unaudited~~========== Financial Information Supplemental Petroleum Data - 2000, 1999 and 1998...................................................... 99 Consolidated Quarterly Financial Data - 2000 and 1999.................................................. 105==========

2001 VERSUS 2000 Corporate after-tax losses were $201 million in 2001, an impairment of $97 million from losses of $104 million in 2000. Corporate losses before special items for 2001 were $127 million, an impairment of $27 million from $100 million in 2000, reflecting higher information technology costs, increased compensation and increased legal fees. 2000 VERSUS 1999 Corporate after-tax losses were $104 million in 2000, an impairment of $6 million from losses of $98 million in 1999. Corporate losses before special items for 2000 were $100 million, an impairment of $22 million from $78 million in 1999, reflecting larger advertising and compensation costs and an increase in other administrative costs associated with becoming an independent company. INTEREST AND OTHER NON-OPERATING EXPENSES NET OF TAX

YEAR ENDED DECEMBER 31 ------------------------------------~~---~~ 2001 2000 1999 ~~1998~~ ----------- ----------- ----------- (IN MILLIONS~~, EXCEPT PER SHARE~~) ~~Revenues~~Interest ~~Sales~~expense ~~and~~on ~~other~~debt operating revenues* .................... $ ~~38,737~~(365) $ ~~27,039~~(277) $ ~~22,796 Equity in earnings of affiliates~~ (~~note 12~~243) ~~...........~~Interest ~~277 150 22 Other~~ income ~~(note 4)~~ .............................~~...~~ ~~273~~63 ~~120~~35 ~~350~~10 ~~-----------~~Exchange ~~-----------~~gains ~~-----------~~(losses) ~~Total revenues~~ .....................~~............~~ ~~39,287~~(33) ~~27,309~~38 ~~23,168~~6 ~~-----------~~Other ~~----------- ----------- Costs and expenses Cost of goods sold~~ ................................... ~~23,921 14,781 11,751 Operating expenses~~ ....~~...............................~~ ~~2,215 2,060 2,089 Selling, general and administrative expenses ......... 794 809 736 Stock option provision~~ (~~note 22~~11) ~~.....................~~ -- -- 236 Exploration expenses ................................. 279 270 380 Depreciation, depletion and amortization ............. 1,301 1,193 1,113 Taxes other than on income* (note 5) ................. 6,981 6,668 5,970 Interest and debt expense (note 6) ................... 338 311 199 ----------- ----------- ----------- ~~Total~~Expenses ~~costs~~net ~~and~~of ~~expenses~~tax ......................... ~~35,829~~(346) ~~26,092~~(204) ~~22,474~~(227) ~~-----------~~Special ~~-----------~~items ~~----------- Income before income taxes~~ .............................. ~~3,458 1,217 694 Provision for income taxes (note 7)~~ .~~....................~~ ~~1,556~~82 ~~473~~-- ~~244~~ -- ---------- ----------- ----------- ~~Net~~Expenses ~~income~~net of tax before special items ....~~..........................................~~ $ ~~1,902~~(264) $ ~~744~~(204) $ ~~450~~(227) =========== =========== =========== Earnings per share** (note 8) Basic ................................................ $ 3.05 $ 1.19 $ .95 Diluted .............................................. $ 3.00 $ 1.17 $ .95 Weighted-average number of shares outstanding (note 8) Basic ................................................ 624 627 474 Diluted .............................................. 633 636 475 ---------- * Includes petroleum excise taxes .................... $ 6,774 $ 6,492 $ 5,801 ** Earnings per share for 1998, prior to Conoco's initial public offering, was calculated by using only Class B common stock, as required by SFAS No. 128 (see note 8).

2001 VERSUS 2000 Interest and other non-operating expenses before special items of $264 million for 2001 were up $60 million, or 29 percent, versus $204 million in 2000, primarily due to an increase in interest expense brought on by additional debt incurred to acquire Gulf Canada, and lower foreign currency exchange gains, partially offset by higher interest income. 2000 VERSUS 1999 Interest and other non-operating expenses before special items of $204 million for 2000 were down $23 million, or 10 percent, versus $227 million in 1999, primarily the result of foreign currency exchange gains and higher interest income due to higher average cash balances as a result of increased crude oil and natural gas prices. These benefits were partially offset by higher interest expense on debt due to higher interest rates. ENVIRONMENTAL EXPENDITURES The costs to comply with complex environmental laws and regulations, as well as the cost of internal voluntary programs, are significant and will continue to be so in the foreseeable future. Estimated pretax environmental expenses charged to current operations totaled about $253 million in 2001, compared to approximately $165 million in 2000 and $127 million in 1999. These expenses include remediation accruals; operating, maintenance and 62 depreciation costs for solid waste; air and water pollution control facilities; and the costs of certain other environmental activities. The largest of these expenses resulted from the operation of wastewater treatment facilities, solid waste management facilities and facilities for the control and abatement of air emissions. Approximately 66 percent of total annual environmental expenses in 2001 resulted from our U.S. operations. The 2001 increase in pretax environmental expenses was attributable partly to additions from the Gulf Canada acquisition. Capital expenditures for environmental control facilities totaled approximately $79 million in 2001, compared to approximately $115 million in 2000 and $81 million in 1999. The 2001 decrease was attributable primarily to a capital spending decrease in European downstream operations as capital projects have been completed to comply with regulations requiring cleaner-burning fuels. We estimate that worldwide capital expenditures will be about $137 million in 2002, including initial expenditures to comply with the new Clean Air Act (CAA) Tier II Fuels regulations and planned expenditures to lower emissions of pollutants from our four U.S. refineries. Over the next seven years, we also will spend an estimated $95 million to $100 million for capital improvements at our U.S. refineries to install control technology and equipment to reduce emissions from stacks, vents, valves, heaters, boilers and flares. The new CAA Tier II Fuels regulations pertaining to gasoline fuels, finalized by the United States Environmental Protection Agency (USEPA) in early 2000, and the regulations pertaining to on-road diesel fuels, finalized by the USEPA in early 2001, require substantially reduced sulfur levels. Conoco is positioning itself to be able to supply the low-sulfur gasoline according to the phase-in schedule. While the on-road diesel regulations have been finalized, the regulations controlling the future sulfur content of off-road diesel fuel emissions have not been issued. This has complicated estimating diesel compliance costs because those two products are inherently tied in the refining process. New technologies also are being developed in the industry that may lower the capital costs. Conoco continues to assess the compliance costs associated with the Tier II Fuels regulations, and while it may be premature to estimate these costs accurately, we expect to average less than 20 percent to 25 percent of our yearly downstream capital spending over the next six years to install the appropriate equipment. Similarly, the European Parliament enacted legislation in October 1998 that, among other things, required phased reductions of the sulfur and aromatics content in gasoline and diesel fuel and of benzene in gasoline. Our European refineries already are in compliance with the first level of sulfur reduction and we already have the ability to produce some of the 2005 specification gasoline and diesel at both the Humber and MiRO refineries. The costs to comply with the 2005 specifications will not be significant. We also are studying the possibility of producing 2011 specification products well in advance of that required date. Conoco does not anticipate substantial additional expenditures to comply with Maximum Achievable Control Technology II (MACT II) standards expected to be promulgated by the USEPA under the CAA in 2002. REMEDIATION EXPENDITURES The Resource Conservation and Recovery Act, as amended (RCRA), extensively regulates the treatment, storage and disposal of hazardous waste and requires a permit to conduct such activities. RCRA requires permitted facilities to undertake an assessment of environmental conditions at the facility. If conditions warrant, Conoco may be required to remediate contamination caused by prior operations. In contrast to the Comprehensive Environmental Response, Compensation and Liability Act, as amended (CERCLA), and often referred to as "Superfund," the cost of corrective action activities under the RCRA corrective action program typically is borne solely by Conoco. Over the next decade, Conoco anticipates that significant ongoing expenditures for RCRA remediation activities may be required. However, annual expenditures for the near term are not expected to vary significantly from the range of such expenditures over the past few years. Conoco's expenditures associated with RCRA and similar remediation activities conducted voluntarily or pursuant to state and foreign laws were approximately $63 million in 2001, $34 million in 2000 and $33 million in 1999. In the long term, expenditures are subject to considerable uncertainty and may fluctuate significantly. Conoco from time to time receives requests for information or notices of potential liability from the USEPA and state environmental agencies alleging that we are a potentially responsible party under CERCLA or an equivalent state statute. On occasion, Conoco also has been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by Conoco but allegedly contain wastes attributable to Conoco's past operations. As of December 31, 2001, Conoco had been notified of potential liability under CERCLA or comparable state law at about 22 sites around the U.S., with active remediation under way at six of those sites. Conoco received notice of 63 potential liability at five new sites during 2001, compared with two similar notices in 2000 and four in 1999. Expenditures associated with CERCLA and similar state remediation activities were not significant for Conoco in 2001, 2000 or 1999. For most Superfund sites, Conoco's potential liability will be significantly less than the total site remediation costs because the percentage of waste attributable to Conoco versus that attributable to all other potentially responsible parties is relatively low. Other potentially responsible parties at sites where Conoco is a party typically have had the financial strength to meet their obligations, and where they have not, or where potentially responsible parties could not be located, Conoco's own share of liability has not increased materially. There are relatively few sites where Conoco is a major participant, and neither the cost to Conoco of remediation at those sites nor such cost at all CERCLA sites in the aggregate is expected to have a material adverse effect on the competitive or financial condition of Conoco. Cash expenditures not charged against income for previously accrued remediation activities under CERCLA, RCRA and similar state and foreign laws were $33 million in 2001, $25 million in 2000 and $26 million in 1999. Although future remediation expenditures in excess of current reserves are possible, the effect of any such excess on future financial results is not subject to reasonable estimation because of the considerable uncertainty regarding the cost and timing of such expenditures. REMEDIATION ACCRUALS Conoco accrues for remediation activities when it is probable that a liability has been incurred and reasonable estimates of the liability can be made. These accrued liabilities exclude claims against Conoco's insurers or other third parties and are not discounted. Many of these liabilities result from CERCLA, RCRA and similar state laws that require Conoco to undertake certain investigative and remedial activities at sites where we conduct, or once conducted, operations or at sites where Conoco-generated waste was disposed. The accrual also includes a number of sites identified by Conoco that may require environmental remediation, but which are not currently the subject of CERCLA, RCRA or state enforcement activities. Over the next decade, Conoco may incur significant costs under both CERCLA and RCRA. Considerable uncertainty exists with respect to these costs, and under adverse changes in circumstances, potential liability may exceed amounts accrued as of December 31, 2001. Remediation activities vary substantially in duration and cost from site to site, depending on the mix of unique site characteristics, evolving remediation technologies, diverse regulatory agencies and enforcement policies, and the presence or absence of potentially liable third parties. Therefore, it is difficult to develop reasonable estimates of future site remediation costs. At December 31, 2001, Conoco's balance sheet included an accrued liability of $157 million, compared to $119 million at year-end 2000, for future site remediation costs. These expenditures are expected to be incurred over the next 10 years. Approximately 90 percent of Conoco's environmental reserve at December 31, 2001, was attributable to RCRA and similar remediation liabilities (including voluntary remediation) and 10 percent to CERCLA liabilities. During 2001, remediation accruals resulted in a $44 million charge, compared to a $35 million charge in 2000 and a $6 million charge in 1999. Conoco also assumed environmental remediation liabilities with the purchase of Gulf Canada in the third quarter of 2001. These liabilities totaled $27 million at December 31, 2001, and were discounted at 5 percent. TAX MATTERS In connection with the separation from DuPont and the initial public offering, Conoco and DuPont entered into a Tax Sharing Agreement and a Restructuring, Transfer and Separation Agreement. Certain disputes arose under these agreements and on November 8, 2001, these matters were settled. The $93 million net effect of this settlement is included in additional paid-in capital as an adjustment to capitalization from DuPont in our consolidated financial statements. EUROPEAN MONETARY UNION The European Economic and Monetary Union (EMU) introduced a new currency, the euro, on January 1, 1999. The new currency was established in response to the EMU's policy of economic convergence to harmonize trade policy, eliminate business costs associated with currency exchange, and to promote the free flow of capital goods and services. 64 The euro was initially available for currency trading on currency exchanges and non-cash (banking) transactions for the 12 EMU countries that adopted it as their local currency. On January 1, 2002, euro-denominated notes and coins were issued for cash transactions. The existing local currencies, or legacy currencies, remain legal tender during a "dual-circulation" period. During the dual-circulation period, both legacy currencies and the euro can be used for transactions. However, when legacy currencies are offered, any change returned is in euro. At the end of the dual-circulation period, the legacy currencies will be withdrawn from circulation, but can be exchanged for euros at specified banks. Generally the dual-circulation period is from January 1, 2002, until February 28, 2002. Exceptions to this general rule are listed below: o Germany - no official dual-circulation period; o France - February 17, 2002; o Ireland - February 9, 2002; and o the Netherlands - January 28, 2002. Conoco operates in a number of countries that are participating in the EMU, including Austria, Belgium, Finland and Germany, and uses the euro in business transactions with other EMU countries. Conoco prepared for the impact of the euro's introduction on areas such as operations, finance, treasury, legal, information management, procurement and others, both in participating and non-participating European Union (EU) countries where Conoco currently operates. Existing legacy accounting and business systems and other business assets were upgraded or replaced as necessary for euro compliance. Out of the three non-participating EU countries, Conoco has a significant presence only in the U.K., where the British pound continues to be the local currency. Because of the staged introduction of the euro regarding non-cash and cash transactions, we addressed our accounting and business systems first and our business assets second. During 2001, we implemented a new converged SAP system for our Refining & Marketing Europe organization that is euro compliant. As of October 2001, all operations in EMU countries were using the new system for accounting and reporting. By December 31, 2001, corresponding business assets were compliant and capable of conducting business with euro notes and coins. Amounts spent for our conversion to the euro were not material. Conoco has not experienced any operational disruptions as the result of the introduction of the euro. Because of the competitive business environment within the petroleum industry, Conoco does not anticipate any long-term competitive implications or the need to materially change its mode of conducting business as a result of increased price transparency. RESTRUCTURING During 1999, 704 employees left Conoco as part of the implementation of our 1998 realignment plans, with related charges against the restructuring reserve of $68 million. In the fourth quarter 1999, estimates of the number of severances were revised due to changes in operational requirements. The original number of estimated severances was reduced by 137 positions, primarily in our upstream business, to 838 positions. The reduction of positions eliminated resulted in a corresponding reduction in the restructuring reserve of $3 million that was recorded in the fourth quarter of 1999. Total charges and adjustments to the reserve during 1999 were $71 million, resulting in a December 31, 1999, reserve balance of $11 million. During the first half of 2000, 79 employees left Conoco as part of the realignment plans. Related charges against the reserve totaled $6 million. The remaining reserve balance of $5 million was reversed into earnings in the second quarter of 2000. RECENT ACCOUNTING STANDARDS In early July 2001, the FASB issued SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets," which revise the accounting for business combinations by requiring that the purchase method of accounting be used on all business combinations initiated after June 30, 2001, and that separately 65 identified intangible assets be recorded as assets. In addition, goodwill must be tested at least annually for impairment and is no longer amortized. SFAS No. 141 was applicable to our 2001 acquisition of Gulf Canada. SFAS No. 142 was adopted on January 1, 2002. The goodwill we recorded with the acquisition of Gulf Canada, which occurred prior to our adoption of SFAS No. 142, was subject to review for impairment under the provisions of APB Opinion No. 17, "Intangible Assets," and SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." No impairment was recognized on goodwill at December 31, 2001. The impact of these standards on existing goodwill from previous acquisitions is not material. The FASB also recently issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This statement significantly changes the method of accruing for costs, associated with the retirement of fixed assets (e.g., oil and gas production facilities and oil and gas properties, etc.), that an entity is legally obligated to incur. We will further evaluate the impact and timing of implementing SFAS No. 143. Implementation of this standard is required no later than January 1, 2003, with earlier adoption encouraged. In October 2001, the FASB approved SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which clarified certain implementation issues arising from SFAS No. 121. This standard was adopted on January 1, 2002, and there was no impact upon adoption. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK GENERAL We operate in the worldwide crude oil, refined product, natural gas, natural gas liquids and electric power markets and are exposed to fluctuations in hydrocarbon and power prices, foreign currency rates and interest rates. These fluctuations can affect revenues and the cost of operating, investing and financing. Our management has used and intends to continue to use financial- and commodity-based derivative contracts to reduce the risk in overall earnings and cash flow when the benefits provided are anticipated to more than offset the risk management costs involved. We have established a Risk Management Policy that provides guidelines for entering into contractual arrangements (derivatives) to manage our commodity price, foreign currency rate and interest rate risks. The Conoco Risk Management Committee, composed of certain senior officers of the company, has: o an ongoing responsibility for the content of this policy; o principal oversight responsibility to ensure that we are in compliance with the policy; and o responsibility to ensure that procedures and controls are in place for the use of commodity, foreign currency and interest rate instruments. These procedures clearly establish derivative control and valuation processes, routine monitoring and reporting requirements, and counterparty credit approval procedures. Additionally, to assess the adequacy of internal controls, Conoco's internal audit group reviews these risk management activities. The audit results are then reviewed by both the Conoco Risk Management Committee and by management. The counterparties to these contractual arrangements are limited to major financial institutions and other established companies in the petroleum industry. Although Conoco, in the event of nonperformance by these counterparties, is exposed to credit loss, this exposure is managed through credit approvals, limits and monitoring procedures and limits to the period over which unpaid balances are allowed to accumulate. We have not experienced any material nonperformance by counterparties to these contracts, and no material loss would be expected from any such nonperformance. Our exposure to the recent Enron Corp. bankruptcy is not material. COMMODITY PRICE RISK We enter into energy-related futures, forwards, swaps and options in various markets: 66 o to balance our physical systems -- In addition to being able to settle exchange traded futures contracts in cash prior to contract expiry, they also can be settled by physical delivery of the commodity. These barrels can provide another source of supply to our physical or "wet barrel" pool to meet refinery requirements or marketing demand; o to meet customer needs -- Consistent with our policy to generally remain exposed to market prices, we use swap contracts to convert fixed price sales contracts (often requested by natural gas and refined product consumers) to a floating market basis; and o to manage our price exposure on anticipated crude oil, natural gas, refined product and electric power transactions. Our policy is generally to be exposed to market pricing for commodity purchases and sales. From time to time, management may use derivatives to establish longer-term positions to hedge the price risk for our equity crude oil and natural gas production, as well as our refinery margins. Specifically, in conjunction with the Gulf Canada acquisition, we initiated an extensive hedging program to mitigate volatile crude oil and natural gas prices through the purchase of derivative instruments. The fair value gain or loss of outstanding derivative commodity instruments and the change in the fair value that would be expected from a 10 percent adverse price change are shown in the following table:

~~DECEMBER~~CHANGE 31IN FAIR VALUE FROM 10% ADVERSE FAIR VALUE PRICE CHANGE ---------------~~---------~~ ~~2000 1999~~ ---------- ------~~----~~ (IN MILLIONS) ~~ASSETS~~COMMODITY ~~Current~~DERIVATIVES ~~assets Cash and cash equivalents ...................................................... $ 342 $ 317 Accounts and notes receivable~~ (~~note 9~~1) ~~.........................................~~AT ~~1,837~~DECEMBER 131,~~735~~ ~~Inventories~~2001 ~~(note~~Crude ~~10)~~oil ~~.......................................................... 791 703 Prepaid expenses~~ and ~~other~~refined ~~current~~products ~~assets~~Trading ........................~~..............~~ ~~441~~$ ~~313~~ --~~--------~~ ~~----------~~$ ~~Total current assets .....................................................~~ (3~~,411~~) ~~3,068~~Non-trading ~~Property, plant and equipment~~ (~~note 11~~2) ...............~~............................~~ ~~23,890~~264 ~~22,476 Less: accumulated depreciation, depletion and amortization ........................~~ (~~11,683~~105) ~~(11,241)~~ ---------- -----~~-----~~ Net property, plant and equipment ................................................. 12,207 11,235 Investment in affiliates (note 12) ................................................ 1,831 1,604 Other assets (note 13) ............................................................ 678 468 ---------- -----~~-----~~ ~~Total~~Combined ~~assets~~ ..........................~~............................................~~ $ ~~18,127~~264 $ ~~16,375~~(108) =============== =============== ~~LIABILITIES~~Natural ~~AND~~gas ~~STOCKHOLDERS'~~and ~~EQUITY~~electricity ~~Current~~Trading ~~liabilities Accounts payable (note 14)~~ ........................~~.............................~~ $ ~~1,723~~-- $ (1~~,489~~) ~~Short~~Non-~~term~~trading ~~borrowings and capital lease obligations~~ (~~note 15~~3) ...............~~...~~ ~~256~~74 ~~663 Income taxes~~ (~~note 7~~8) ~~.......................................................... 665 303 Other accrued liabilities (note 16) ............................................ 1,543 1,303~~ --------------- --------------- ~~Total~~Combined ~~current liabilities~~ ..........................~~......................~~ ~~4,187~~$ ~~3,758~~74 ~~Long-term~~$ ~~borrowings~~(9) ~~and~~=============== ~~capital~~=============== ~~lease~~AT ~~obligations~~DECEMBER ~~(note 17) ...................... 4~~31,~~138~~ ~~4,080~~2000 ~~Deferred~~Crude ~~income~~oil ~~taxes~~and ~~(note~~refined 7)products Trading ........................~~............................~~ ~~1,911~~$ 1~~,689~~ ~~Other~~$ ~~liabilities~~1 ~~and~~Non-trading ~~deferred credits~~ (~~note 18~~4) ................~~..................~~ ~~1,926~~92 ~~1,958~~(29) ---------- -----~~-----~~ ~~Total liabilities ........................................................ 12,162 11,485~~ ---------- -----~~-----~~ ~~Commitments~~Combined ~~and contingent liabilities (note 26) Minority interests (note 19)~~ ..........................~~............................~~ ~~337~~$ ~~335~~93 ~~Stockholders'~~$ ~~equity~~ (~~note 20~~28) ~~Preferred~~=============== ~~stock,~~=============== ~~$.01~~Natural ~~par~~gas ~~value~~and ~~250,000,000~~electricity ~~shares~~Trading ~~authorized; none issued~~ ........................~~...........~~ ~~-- -- Class A common stock,~~ $~~.01~~ ~~par value~~ 3~~,000,000,000~~ ~~shares~~$ ~~authorized; 191,497,821 shares issued with 186,646,358 shares outstanding at December 31, 2000 and 189,039,861 shares outstanding at December 31, 1999 ...........................................~~ 2 2 Class B common stock, $.01 par value 1,599,776,271 shares authorized, 436,786,482 shares issued and outstanding at December 31, 2000; 1,600,000,000 shares authorized, 436,543,573 shares issued and outstanding at December 31, 1999 ............. 4 4 Additional paidNon-intrading ~~capital~~ ....................~~.................................~~ ~~4,932~~103 ~~4,941 Retained earnings .............................................................. 1,460 44 Accumulated other comprehensive loss~~ (~~note 21~~33) ................................. (653) (372) Treasury stock, at cost 4,851,463 and 2,457,960 Class A shares at December 31, 2000 and December 31, 1999, respectively ............................................ (117) (64) ---------- -----~~-----~~ ~~Total stockholders' equity ............................................... 5,628 4,555~~ ---------- -----~~-----~~ ~~Total~~Combined ~~liabilities and stockholders' equity~~ ..........................~~..............~~ $ ~~18,127~~106 $ ~~16,375~~(31) =============== ===============

~~RETAINED~~EXCHANGE ~~ACCUMULATED ADDITIONAL EARNINGS OTHER OWNER'S NET COMMON PAID~~NON-INEXCHANGE ~~(ACCUMULATED~~TRADED ~~COMPREHENSIVE~~TRADED ~~COMPREHENSIVE~~TOTAL ~~TREASURY INVESTMENT STOCK CAPITAL DEFICIT) INCOME LOSS STOCK~~ ----------- --------- -~~--------~~ ------------ ~~------------- --------- ---------~~ (IN MILLIONS) ~~Balance~~Fair ~~January~~value 1,of ~~1998~~contracts ~~.............~~outstanding $at ~~8,087~~the $beginning --of $the --period ~~$ -- $ (191) $ -- Comprehensive income Net income (loss)~~ ...~~..............~~ ~~694~~$ ~~(244)~~8 $ ~~450~~191 ~~Other~~$ ~~comprehensive~~199 ~~income~~Contracts ~~(loss)~~realized ~~Foreign~~or ~~currency~~otherwise ~~translation~~settled ~~adjustment~~during ~~...................~~the ~~(25)~~period ~~Minimum pension liability adjustment~~ ............~~.......~~ (5828) ~~--------- Other comprehensive loss .....~~ (83108) (83136) ~~---------~~Fair ~~Comprehensive~~value ~~income~~of ~~................~~new $contracts ~~367~~when ~~=========~~entered ~~Cash~~into ~~distribution~~during tothe ~~owner~~period ......~~....~~ -- (~~512~~28) ~~Dividends to owner ..................~~ (~~8,200~~28) ~~Other~~Changes ~~transfers~~in ~~from~~fair ~~owner~~value ~~..........~~values ~~433~~attributable ~~Capitalization~~to ~~from~~changes ~~owner~~in atvaluation ~~initial~~techniques ~~public offering~~ ................... ~~(502) 4 498 Initial public offering~~ ............. ~~2 4,226 Compensation plans~~ .................. ~~(5) Treasury stock purchases~~ ......~~......~~ ~~(5) Stock option provision (note 22) .... 236~~ --~~-------~~ --~~-------~~ --~~-------~~ ~~--------- ------ --------- Balance December 31, 1998 ........... -- 6 4,955 (244) (274) (5) Comprehensive income Net income ........................ 744 $ 744~~ Other ~~comprehensive~~changes ~~income~~in ~~(loss)~~fair ~~Foreign~~values ~~currency translation adjustment~~ ................... ~~(162) Minimum pension liability adjustment~~ ................... ~~64 --------- Other comprehensive loss~~ ..... ~~(98)~~16 ~~(98)~~287 ~~---------~~303 Comprehensive income ................ $ 646 ========= Adjustment to capitalization from owner at initial public offering (note 20) ................ (26) Dividends ........................... (445) Compensation plans .................. 12 Treasury stock - ~~purchases .......... (87)~~ - ~~issuances .......... (11) 28~~ --------- --------- -~~--------~~ --------- -~~--------~~ ~~---------~~Fair ~~Balance~~value ~~December~~of ~~31,~~contracts ~~1999~~outstanding ~~...........~~at --the 6end ~~4,941~~of 44the ~~(372)~~period ~~(64) Comprehensive income Net income~~ .........~~...............~~ ~~1,902~~ $ ~~1,902 Other comprehensive income~~ (~~loss~~4).. Foreign currency translation adjustment ................... (272) Minimum pension liability adjustment ................... (9) --------- Other comprehensive loss ..... (281) (281) --------- Comprehensive income ................ $ ~~1,621~~342 ========= Dividends ........................... (474) Compensation plans .................. 5 Redemption of minority interests .... (9) Treasury stock - purchases .......... (90) - issuances .......... (17) 37 --------- --------- --------- --------- --------- --------- Balance December 31, 2000 ........... $ --338 ~~$ 6 $ 4,932 $ 1,460 $ (653) $ (117)~~ ========= =~~========~~ ========= =~~========~~ ========= =~~========~~

~~YEAR~~FAIR ~~ENDED~~VALUE ~~DECEMBER~~OF 31CONTRACTS AT PERIOD-END ------------------------------------- ~~2000 1999 1998~~ ---------- ---------- ----~~------~~ (MATURITY IN ~~MILLIONS)~~MATURITY ~~Cash~~UP ~~provided~~MATURITY byMATURITY ~~operations~~EXCESS ~~Net~~OF ~~income~~TOTAL ~~..........................................................~~FAIR $TO 1~~,902~~ $YEAR ~~744~~2 $ 450 Adjustments to reconcile net income to cash provided by operations Depreciation, depletion and amortization ......................... 1,301 1,193 1,113 Dry hole costs and impairment of unproved properties ............. 88 131 163 Stock option provision (note 22) ................................. -- --3 ~~236~~YEARS ~~Inventory~~4 ~~write~~-~~down~~ to5 ~~market~~YEARS (note 10) ......................... -- -- 97 Deferred income taxes (note 7) ................................... 236 (111) (32) Income applicable to minority interests .......................... 24 25 21 Gain on asset dispositions ....................................... (72) (20) (206) Undistributed equity earnings .................................... (145) (73) 83 Other non-cash charges and credits - net ......................... (87) (18) (14) Decrease (increase) in operating assets Accounts and notes receivable .................................. (153) (573) 125 Inventories .................................................... (119) 80 (62) Other operating assets ......................................... (313) 107 (172) Increase (decrease) in operating liabilities Accounts and other operating payables .......................... 567 639 (69) Income and other taxes payable (notes 5 ~~and~~YEARS 7)VALUE ~~................. 209 92 (360)~~ ---------- ---------- -~~---------~~ ~~Cash provided by operations ................................. 3,438 2,216 1,373~~ ---------- -~~---------~~ ---------- ~~Investing activities (note 24) Purchases of property, plant and equipment ......................... (1,921) (1,675) (1,965) Purchases of businesses~~ - ~~net of cash acquired ..................... (661)~~ -- -- ~~Investments in affiliates~~ - ~~additions .............................. (173) (272) (391)~~ - ~~repayment of loans and advances ........ 64 45 6 Proceeds from sales of assets and subsidiaries ..................... 222 162 721 Net (increase) decrease in short~~-~~term financial instruments ........ (3) 34 31~~ --~~--------~~ ~~---------- ---------- Cash used in investing activities ...........................~~ (~~2,472)~~IN ~~(1,706~~MILLIONS) ~~(1,598)~~SOURCE ~~----------~~OF ~~----------~~FAIR ~~----------~~VALUE ~~Financing~~Prices ~~activities~~actively ~~Short-term~~quoted ~~borrowings~~Exchange ~~(note 15) - receipts~~ ......................... ~~28,091 12,778 -- - payments~~ ....~~.....................~~ ~~(28,498)~~$ (~~12,156~~4) ~~(26)~~$ ~~Long~~-~~term borrowings~~ - ~~receipts~~$ ~~.................................... 65 3,970~~ -- -$ ~~payments ....................................~~ -- ~~(20)~~$ (4) ~~Related party borrowings~~ Non-exchange ~~receipts~~ .........................~~.......~~ --350 ~~865 927 - payments ................................ --~~ (~~5,461~~7) (~~5,434~~1) ~~Related party notes receivable~~ - ~~receipts ..........................~~ -- --342 ~~444~~ - ~~payments ..........................~~ -- -- ~~(152) Treasury stock~~ - ~~purchases ......................................... (90) (87) (5)~~ - ~~proceeds from issuances ........................... 12 13~~ -- ~~Cash dividends ..................................................... (474) (445)~~ -- ~~Proceeds from initial public offering ..............................~~ -- -- ~~4,228 Cash distribution to owner .........................................~~ -- ~~(11) (512) Minority interests (note 19)~~ - ~~receipts ............................~~ -- ~~326~~ -- - ~~payments ............................ (26) (324) (21)~~ ---------- ---------- ---------- ~~Cash~~Total ~~used in financing activities~~ ........................... ~~(920) (552) (555) ---------- ---------- ---------- Effect of exchange rate changes on cash~~ ..~~..............................~~ ~~(21)~~$ ~~(35)~~346 27$ ~~---------- ---------- ---------- Increase~~ (~~decrease~~7) in$ ~~cash and cash equivalents ....................... 25~~ (771) ~~(753)~~$ ~~Cash and cash equivalents at beginning of year ......................... 317 394 1,147~~ --~~--------~~ ~~---------- ---------- Cash and cash equivalents at end of year ...............................~~ $ ~~342~~338 $========== ~~317~~=========== ~~$ 394~~ =========== ========== ========== ~~SUPPLEMENTAL~~Prices ~~SCHEDULE~~provided OFby ~~NON-CASH~~other ~~FINANCING~~external ~~ACTIVITIES~~sources ~~Transactions with DuPont Dividends to owner~~ .............................~~....................~~ $ -- $ -- ~~$ (8,200) Promissory note issued .............................................~~ -- -- ~~7,500 Notes receivable reduced ...........................................~~ -- --Prices ~~700~~based ~~Borrowings~~on ~~contributed~~models toand ~~capital~~other valuation methods ...................~~...............~~ -- -- ~~(544)~~ --~~--------~~ --~~--------~~ --~~-------- Total non-cash financing activities .................................... $ -- $ -- $ (544) ========== ========== ==========~~

We do a limited amount of trading unrelated to our underlying physical business, for which after-tax gains or losses have not been material. FOREIGN CURRENCY RISK Conoco has foreign currency exchange rate risk resulting from operations in over 40 countries around the world. We do not comprehensively hedge our exposure to currency rate changes, although we may choose to selectively hedge exposures to foreign currency rate risk. Examples include firm commitments for future capital projects and operating costs, certain local currency tax payments and dividends, and cash returns from net investments in foreign affiliates to be remitted within the coming year. In conjunction with our European commercial paper program, we enter into foreign currency swaps for all non-U.S. dollar notes issued in order to receive the U.S. dollar equivalent proceeds upon note issuance and to lock in the forward foreign currency rate on note maturity. At December 31, 2001, the U.S. dollar equivalent of all non-U.S. dollar notes outstanding was $29 million, all of which were swapped to the U.S. dollar. At December 31, 2000, the U.S. dollar equivalent of all non-U.S. dollar notes outstanding was $81 million, all of which were swapped for the U.S. dollar. At December 31, 2001, we had open foreign currency exchange derivative instruments with a notional value of $9 million related to forward currency sales. At December 31, 2000, we had open foreign currency exchange 68 derivative instruments with a notional value of $45 million related to anticipated foreign currency capital investments. The fair value of outstanding foreign currency hedges and the change in the fair value that would be expected from a 10 percent adverse foreign currency rate change are shown in the following table:

~~2000~~CHANGE ~~1999~~IN ~~1998~~FAIR VALUE FROM 10% ADVERSE FAIR FOREIGN CURRENCY VALUE RATE CHANGE -----~~----~~ --------- --~~-------~~ ~~Interest income DuPont~~ (~~see~~IN ~~note 3~~MILLIONS) ~~........................~~FOREIGN $CURRENCY --DERIVATIVES $AT --DECEMBER $31, 432001 ~~Other~~ Non-trading...................................... ~~39 25 46 --------- --------- --------- Total~~ ................~~......................~~ 39$ 25-- 89$ ~~Gain on sales of assets and subsidiaries~~ (14) ..AT 72DECEMBER 2631, ~~207~~2000 ~~Write~~Non-~~off of Colombia power venture~~ trading........... ~~(26) -- -- Syrian service contract~~ ....................... ~~110 3 -- Exchange gain (loss) and other~~ ................ ~~78 66 54 --------- --------- --------- Other income~~ ....~~..............................~~ $ ~~273~~2 $ ~~120 $ 350 ========= ========= =========~~(4)

Price-risk sensitivities were calculated by assuming an across-the-board 10 percent adverse change in foreign currency rates. INTEREST RATE RISK Conoco manages any material risk arising from exposure to interest rates by using a combination of financial derivative instruments. This program was developed to manage the fixed and floating interest rate mix of our total debt portfolio and related overall cost of borrowing. Beginning in the fourth quarter 2001, we executed several interest rate swaps to increase our overall debt portfolio's exposure to floating interest rates. These transactions included swapping $1,650 million of fixed rate debt to floating rate debt, as well as swapping $900 million of floating rate debt to fixed rate debt. Through these transactions, we effectively increased our exposure to floating interest rates on $750 million of debt. In addition to increasing our floating rate exposure, we effectively swapped $900 million of debt to a lower fixed rate, reducing the pretax interest rate by approximately 250 basis points. The fair value gain or loss of outstanding interest rate swaps and the change in fair value that would be expected from a 10 percent adverse interest rate change are shown in the following table:

~~2000~~CHANGE ~~1999~~IN ~~1998~~FAIR VALUE FROM 10% ADVERSE INTEREST RATE FAIR VALUE CHANGE --------- ------ --- ------------ ~~Petroleum~~(IN ~~excise~~MILLIONS) ~~taxes~~INTEREST ~~U.S.~~RATE DERIVATIVES AT DECEMBER 31, 2001 Fixed rate to floating rate Notes due 2009 ..................~~..................................................~~ $ ~~1,572~~(35) $ ~~1,495~~(52) $Notes ~~1,286~~due ~~Non-U.S.~~2029 ..................~~..............................................~~ ~~5,202~~(74) ~~4,997~~(134) ~~4,515~~ --------- ------ --- ------------ ~~Total~~Fixed ~~................................................................~~rate ~~6,774~~to ~~6,492~~floating ~~5,801~~rate ~~Payroll taxes~~ .......~~.......................................................~~ 45(109) 44(186) 42Floating ~~Property~~rate ~~taxes~~to ~~.............................................................~~fixed 65rate ~~64 64 Production and other taxes~~ .......~~..........................................~~ 97(8) 68(1) 63 --------- ------ --- ------------ ~~Taxes~~Total ~~other than on income~~.............................~~.....................~~ $ ~~6,981~~(117) $ ~~6,668~~(187) ~~$ 5,970~~ ========= ====== === ============

At December 31, 2000, Conoco had no significant open interest rate financial derivative instruments. 69 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA INDEX

~~2000~~PAGE ~~1999~~Report ~~1998~~of ~~---------~~Management...................................................................................... ~~---------~~71 ~~---------~~Audited ~~Interest~~Consolidated ~~and~~Financial ~~debt~~Statements ~~cost~~Report ~~incurred~~of ~~DuPont~~Independent ~~(see note 3)~~ Accountants...................................................................... $72 Consolidated Statement of Income -- $Year 91Ended $December ~~264~~31, ~~Other~~2001, ~~debt~~2000 and ~~capital~~1999......................... ~~leases~~73 Consolidated Balance Sheet - at December 31, 2001 and 2000............................................. ~~354~~74 ~~226~~Consolidated 7Statement ~~---------~~of ~~---------~~Stockholders' Equity and Accumulated Other Comprehensive Loss -~~--------~~ ~~Total~~Years Ended December 31, 2001, 2000 and 1999.................................................. 75 Consolidated Statement of Cash Flows - Year Ended December 31, 2001, 2000 and 1999..................... ~~354~~76 ~~317~~Notes ~~271~~to ~~Less:~~Consolidated ~~Interest~~Financial ~~and debt cost capitalized~~ Statements............................................................. 1677 6Unaudited 72Financial ~~---------~~Information ~~---------~~Supplemental ~~---------~~Petroleum ~~Interest~~Data ~~and~~- ~~debt~~2001, ~~expense~~2000 ~~(1)~~and 1999...................................................... $113 ~~338~~Consolidated $Quarterly ~~311~~Financial $Data ~~199~~- ~~=========~~2001 ~~=========~~and ~~=========~~2000.................................................. 122

70 REPORT OF MANAGEMENT Management of Conoco Inc. is responsible for preparing the accompanying consolidated financial statements and other information. The consolidated financial statements have been prepared in accordance with generally accepted accounting principles considered by management to present fairly Conoco's financial position, results of operations and cash flows. The consolidated financial statements include some amounts that are based on management's best estimates and judgments. Conoco's system of internal controls is designed to provide reasonable assurance as to the protection of assets against loss from unauthorized use or disposition, and the reliability of financial records for preparing financial statements and maintaining accountability for assets. Conoco's business ethics policy is the cornerstone of our internal control system. This policy sets forth management's commitment to conduct business worldwide with the highest ethical standards and in conformity with applicable laws. The business ethics policy also requires that all documents supporting transactions clearly describe their true nature and that all transactions be properly reported and classified in the financial records. An extensive internal audit program monitors Conoco's system of internal controls. Management believes Conoco's system of internal controls meets the objective noted above. Conoco's independent accountants, PricewaterhouseCoopers LLP, have audited the consolidated financial statements. The purpose of their audit is to independently affirm the fairness of management's reporting of financial position, results of operations and cash flows. Management has made available to PricewaterhouseCoopers LLP all of Conoco's financial records and related data, as well as the minutes of the stockholders' and directors' meetings. To express the opinion set forth in their report, PricewaterhouseCoopers LLP evaluates the internal controls to the extent they deem necessary. The adequacy of Conoco's internal control systems and the accounting principles employed in financial reporting are under the general oversight of the Audit and Compliance Committee of the Board of Directors. This committee also has responsibility for employing the independent accountants, subject to stockholder ratification. All members of this committee are independent of Conoco, pursuant to the rules of the New York Stock Exchange. The independent accountants and the internal auditors have direct access to the Audit and Compliance Committee, and they meet with the Audit and Compliance Committee from time to time, with and without management present, to discuss accounting, auditing and financial reporting matters. /s/ ARCHIE W. DUNHAM /s/ ROBERT W. GOLDMAN /s/ W. DAVID WELCH ----------------------------------- -------------------------------- -------------------------------- Archie W. Dunham Robert W. Goldman W. David Welch Chairman, President and Senior Vice President, Finance, Vice President, Controller and Chief Executive Officer and Chief Financial Officer Principal Accounting Officer

71 REPORT OF INDEPENDENT ACCOUNTANTS To the Stockholders and the Board of Directors of Conoco Inc. In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of income, of stockholders' equity and accumulated other comprehensive loss, and of cash flows present fairly, in all material respects, the financial position of Conoco Inc. and its subsidiaries at December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. As discussed in note 9 to the consolidated financial statements, in accordance with the requirements of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities," the Company changed its method of accounting for derivative instruments and hedging activities effective January 1, 2001. PRICEWATERHOUSECOOPERS LLP Houston, Texas February 19, 2002 72 CONOCO INC. CONSOLIDATED STATEMENT OF INCOME

YEAR ENDED DECEMBER 31 ----------------------------------------- 2001 2000 1999 ~~1998~~ ---------- ---------- ---------- ~~Current~~(IN ~~tax~~MILLIONS, ~~expense~~EXCEPT ~~U.S.~~PER ~~federal~~SHARE) Revenues Sales and other operating revenues* ............................... $ 38,737 $ 38,737 $ 27,039 Equity in earnings of affiliates (note 15) ........................~~....~~ $181 ~~126~~277 $150 26Other $income (57note 4) U.S. ~~state and local~~ ...........................................~~........~~ 11621 4273 10120 ~~Non~~-~~U.S.~~--------- ---------- ---------- Total revenues ..............................................~~.................~~ 139,~~183~~539 ~~554~~39,287 ~~323~~27,309 ---------- ---------- ---------- ~~Current~~Costs ~~tax~~and ~~expense~~expenses Cost of goods sold** .............................................. 23,043 23,921 14,781 Operating expenses ................................................ 13,~~320~~053 ~~584~~2,215 ~~276~~2,060 ~~---------~~Selling, ~~---------~~general ~~---------~~and ~~Deferred~~administrative ~~tax~~expenses ~~expense U~~.S. ~~federal~~ .................... 888 794 809 Exploration expenses .............................................. ~~125~~378 ~~(84)~~279 ~~(51)~~270 ~~U.S.~~Depreciation, ~~state~~depletion and ~~local~~amortization .......................... 1,811 1,301 1,193 Taxes other than on income* (note 5) .............................. 36,983 ~~(5)~~6,981 6,668 Interest and debt expense (5note 6) ~~Non-U~~.S. .............................. 396 338 311 ---------- ---------- ---------- Total costs and expenses ................................... ~~108~~36,552 ~~(22)~~35,829 2426,092 ---------- ---------- ---------- ~~Deferred~~Income ~~tax~~before ~~expense~~income taxes ........................................... 2,987 3,458 1,217 Income tax expense (note 7) .......................................... ~~236~~1,391 ~~(111)~~1,556 ~~(32)~~473 ---------- ---------- ---------- ~~Provision~~Income before extraordinary item and accounting change ............... 1,596 1,902 744 Extraordinary item, charge for the early extinguishment of debt, net of income taxes of $33 (note 8) .............................. (44) -- -- Cumulative effect of accounting change, net of income taxes of $22 (note 9) ......................................................... ~~1,556~~37 ~~473~~-- ~~244~~-- ~~Foreign~~---------- ~~currency~~---------- ~~translation~~---------- ~~(see~~Net ~~note~~income ~~21)~~ ........................................................... ~~(83)~~$ ~~(29)~~1,589 ~~(22)~~$ ~~Minimum~~1,902 ~~pension~~$ ~~liability~~744 ~~(see~~========== ========== ========== Earnings per share (note 2110) Basic Before extraordinary item and accounting change .................. $ 2.55 $ 3.05 $ 1.19 Extraordinary item ............................................... (5.07) 29-- ~~(26)~~-- Cumulative effect of accounting change ........................... .06 -- -- ---------- ---------- ---------- ~~Total~~$ ~~provision~~2.54 $ 3.05 $ 1.19 ========== ========== ========== Diluted Before extraordinary item and accounting change .................. $ 2.51 $ 3.00 $ 1.17 Extraordinary item ............................................... (.07) -- -- Cumulative effect of accounting change ........................... .06 -- -- ---------- ---------- ---------- $ ~~1,468~~2.50 $ ~~473~~3.00 $ ~~196~~1.17 ========== ========== ========== Weighted-average shares outstanding (note 10) Basic ............................................................ 626 624 627 Diluted .......................................................... 635 633 636 ---------- * Includes petroleum excise taxes ................................... $ 6,744 $ 6,774 $ 6,492 ** Excludes refining depreciation .................................... $ 127 $ 122 $ 116

See accompanying notes to consolidated financial statements. 73 CONOCO INC. CONSOLIDATED BALANCE SHEET

~~2000~~DECEMBER ~~1999~~31 -------------------------- 2001 2000 ---------- ~~Prepaid~~---------- ~~expenses~~(IN MILLIONS) ASSETS Current assets Cash and ~~other~~cash equivalents ................................................... $ 388 $ 342 Accounts and notes receivable (note 11) ..................................... 1,894 1,837 Inventories (note 12) ....................................................... 995 791 Other current assets (note 13) .............................................. $1,066 441 ---------- ---------- Total current assets .................................................. 4,343 3,411 Property, plant and equipment (43note 14) $........................................ 30,224 23,890 Less: accumulated depreciation, depletion and amortization ..................... (12,306) (11,683) ---------- ---------- Net property, plant and equipment .............................................. 17,918 12,207 Investment in affiliates (note 15) ............................................. 1,894 1,831 Goodwill (note 3) .............................................................. 2,933 10 Other assets (~~see~~ note 1316) ......................................................... 816 668 ---------- ---------- Total assets ................................................................... $ 27,904 $ 18,127 ========== ========== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities Accounts payable (39note 17) .................................................. $ 1,950 $ 1,723 Short-term borrowings and capital lease obligations (61note 18) ............... 1,125 256 Income taxes (note 7) ....................................................... 66530 27665 Other accrued liabilities (note 19) ......................................... 1,897 1,543 ---------- ---------- Total current liabilities ............................................. 5,502 4,187 Long-term borrowings and capital lease obligations (note 20) ................... 8,267 4,138 Deferred income taxes (note 7) ................................................. 3,975 1,911 Other liabilities and deferred credits (note 21) ............................... 2,346 1,~~689~~926 ---------- ---------- ~~Net~~Total ~~deferred~~liabilities ~~tax~~..................................................... 20,090 12,162 ---------- ---------- Commitments and contingent liabilities (note 28) Minority interests (note 22) ................................................... 1,204 337 Stockholders' equity (note 23) Preferred stock, $.01 1par value 250,~~895~~000,000 shares authorized; none issued ................................ -- -- Common stock, $.01 par value (note 23) 4,600,000,000 shares authorized, 628,938,046 shares issued with 625,658,528 shares outstanding at December 31, 2001; 4,599,776,271 shares authorized, 628,284,303 shares issued with 623,432,840 shares outstanding at December 31, 2000 ........................................ 6 6 Additional paid-in capital .................................................. 5,044 4,932 Retained earnings ........................................................... 2,537 1,~~640~~460 Accumulated other comprehensive loss (note 24) .............................. (894) (653) Treasury stock, at cost 3,279,518 and 4,851,463 shares at December 31, 2001, and December 31, 2000, respectively ......................................... (83) (117) ---------- ---------- Total stockholders' equity ............................................ 6,610 5,628 ---------- ---------- Total liabilities and stockholders' equity ..................................... $ 27,904 $ 18,127 ========== ==========

See accompanying notes to consolidated financial statements. 74 CONOCO INC. CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY AND ACCUMULATED OTHER COMPREHENSIVE LOSS (NOTES 23 AND 24)

~~2000~~RETAINED ~~1999~~ADDITIONAL EARNINGS ACCUMULATED OTHER COMMON PAID-IN (ACCUMULATED COMPREHENSIVE COMPREHENSIVE TREASURY STOCK CAPITAL DEFICIT) INCOME LOSS STOCK ------ ---------- ------------ ~~Deferred~~------------- ~~tax~~----------------- ~~liabilities~~-------- ~~PP&E~~(IN MILLIONS) Balance January 1, 1999 ........................ $ 6 $ 4,955 $ (244) $ (274) $ (5) Comprehensive income Net income .................................. 744 $ ~~2,452~~744 Other comprehensive income (loss) Foreign currency translation adjustment ... (162) Minimum pension liability adjustment ...... 64 ------------- Other comprehensive loss ................ (98) (98) ------------- Comprehensive income ........................... $ ~~2,349~~646 ~~Inventories~~============= Adjustment to capitalization from DuPont ....... (26) Dividends ...................................... 15(445) 46Compensation ~~Other~~plans ............................. 12 Treasury stock - purchases ..................... ~~181~~(87) 85- issuances ..................... (11) 28 ------ ---------- ------------ ~~Deferred~~----------------- ~~tax~~--------- ~~liabilities~~Balance December 31, 1999 ...................... ~~2,648~~6 24,~~480~~941 ~~Deferred~~44 ~~tax~~(372) ~~assets~~(64) ~~PP&E~~Comprehensive income Net income .................................. 1,902 $ 1,902 Other comprehensive income (loss) Foreign currency translation adjustment ... (272) Minimum pension liability adjustment ...... (359) ------------- Other comprehensive loss ................ (~~244~~281) ~~Employee~~(281) ~~benefits~~------------- Comprehensive income ........................... ~~(252)~~$ ~~(241)~~1,621 ~~Other~~============= ~~accrued~~Dividends ~~expenses~~ ...................................... (~~275~~474) ~~(236)~~Compensation ~~Tax~~plans ~~loss/tax~~............................. ~~credit~~5 ~~carry~~Redemption ~~forwards~~of minority interests ............... (~~442~~9) ~~(512)~~Treasury ~~Other~~stock - purchases ..................... (90) - issuances ..................... (~~158~~17) ~~(59)~~37 ------ ---------- ------------ ~~Deferred~~----------------- ~~tax~~-------- ~~assets~~Balance December 31, 2000 ...................... (6 4,932 1,~~162~~460 (653) (117) Comprehensive income Net income .................................. 1,~~292~~589 $ 1,589 Other comprehensive income (loss) ~~Valuation~~Foreign ~~allowance~~currency translation adjustment ... (309) Minimum pension liability adjustment ...... (19) Unrealized gains on derivatives ........... 86 Unrealized gain on derivatives from adoption of SFAS No. 133 ................. ~~409~~1 ~~452~~ ------------- Other comprehensive loss ................ (241) (241) ------------- ~~Net~~Comprehensive ~~deferred~~income ~~tax~~........................... ~~assets~~$ 1,348 ============= Adjustment to capitalization from DuPont ....... 93 Dividends ...................................... (~~753~~474) Compensation plans ............................. 24 Redemption of minority interests ............... (~~840~~3) Costs related to the combination of Class A and B stock ................................. (2) Treasury stock - purchases ..................... (37) - issuances ..................... (38) 71 ------ ---------- ------------ ~~Net~~----------------- ~~deferred~~-------- ~~tax~~Balance ~~liabilities~~December 31, 2001 ...................... $ 16 $ 5,~~895~~044 $ 12,~~640~~537 $ (894) $ (83) ====== ========== ============ ================= ========

See accompanying notes to consolidated financial statements. 75 CONOCO INC. CONSOLIDATED STATEMENT OF CASH FLOWS

~~2000~~YEAR ~~1999~~ENDED ~~1998~~DECEMBER 31 --------- ------------------------- 2001 2000 1999 -------- -------- ~~Statutory~~-------- U(IN MILLIONS) Cash provided by operations Net income .S........................................................................ ~~federal~~$ 1,589 $ 1,902 $ 744 Adjustments to reconcile net income ~~tax~~to ~~rate~~cash provided by operations Extraordinary item, charge for the early extinguishment of debt (note 8) ......... 77 -- -- Cumulative effect of accounting change (note 9) ......... 35.0%........................ 35(59) -- -- Depreciation, depletion and amortization .0%........................................ 351,811 1,301 1,193 Dry hole costs and impairment of unproved properties .0%............................ ~~Higher~~116 88 131 Deferred tax ~~rate~~expense on(note ~~international~~7) ~~operations~~.................................................... 282 236 (111) Income applicable to minority interests .......................................... 1123 24 25 Gain on asset dispositions .3...................................................... 10(311) (72) (20) Dividends received greater than (less than) equity in earnings from affiliates .0.. 717 (145) (73) Other non-cash charges and (credits) - net .8...................................... ~~Alternative~~136 ~~fuels~~(87) ~~credit~~(18) Decrease (increase) in operating assets Accounts and notes receivable .................................................. 521 (1153) (573) Inventories .2................................................................... (159) (4119) 80 Other operating assets .0........................................................ (724) (8313) 107 Increase (decrease) in operating liabilities Accounts and other operating payables .2......................................... 132 567 639 Income and other taxes payable ................................................. (310) ~~Reduced~~209 ~~tax~~92 ~~benefit~~-------- ~~from~~-------- ~~stock~~-------- ~~option~~Cash ~~provision~~provided by operations ................................................. 3,141 3,438 2,216 -------- -------- -------- Investing activities Purchases of property, plant and equipment ......................................... (2,702) (1,921) (1,675) Purchase of Gulf Canada - net of cash acquired (note 3) ............................ (4,318) -- -- Purchases of businesses - net of cash acquired .9.................................... ~~Realization~~-- (661) -- Investments in affiliates - additions .............................................. (133) (173) (272) - repayment of ~~unbenefited~~loans ~~loss~~and advances ........................ 14 64 45 Proceeds from ~~sale~~sales of ~~subsidiary~~assets and subsidiaries ..................................... 795 222 162 Net (increase) decrease in short-term financial instruments ........................ (3) (3) 34 -------- -------- -------- Cash used in investing activities ........................................... (46,347) (2,472) (1,706) -------- -------- -------- Financing activities Short-term borrowings (note 18) - receipts ......................................... 27,048 28,091 12,778 - payments ......................................... (24,147) (28,498) (12,156) Long-term borrowings (note 20) - receipts .......................................... 6,195 65 3,970 - payments .......................................... (5,802) ~~Other~~-- (20) Related-party ~~net~~borrowings - receipts ................................................ -- -- 865 - payments ................................................ -- -- (05,461) Treasury stock - purchases .1........................................................ (37) (290) (87) - proceeds from issuances .1.......................................... 31 12 13 Cash dividends ..................................................................... (474) 0(474) (445) Cash distribution (to) from DuPont (note 32) .3...................................... 93 -- (11) Minority interests (note 22) - receipts ............................................ 488 -- 326 - payments ............................................ (33) (26) (324) -------- -------- -------- Cash provided by (used in) financing activities ............................. 3,362 (920) (552) -------- -------- ~~Effective~~-------- ~~income~~Effect ~~tax~~of exchange rate changes on cash ................................................ 45(110) (21) (35) -------- -------- -------- Increase (decrease) in cash and cash equivalents .0%...................................... 3846 25 (77) Cash and cash equivalents at beginning of year .9%........................................ 35342 317 394 -------- -------- -------- Cash and cash equivalents at end of year .2%.............................................. $ 388 $ 342 $ 317 ========= ========= =========

See accompanying notes to consolidated financial statements. 76 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) 1. BASIS OF PRESENTATION Conoco is an integrated, global energy company that has three operating segments -- upstream, downstream and emerging businesses. Activities of the upstream operating segment include exploring for, developing, producing and selling crude oil, natural gas and natural gas liquids, and Syncrude mining operations (Canadian Syncrude). Downstream operating segment activities include refining crude oil and other feedstocks into petroleum products; buying and selling crude oil and refined products; and transporting, distributing and marketing petroleum products. Emerging businesses operating segment activities include the development of new businesses beyond our traditional operations. Emerging businesses currently is involved in carbon fibers (Conoco Cevolution(R)); natural gas refining, including gas-to-liquids; and international power. We have five reporting segments. Four of these segments reflect the geographic division between U.S. and international operations in our upstream and downstream businesses, and one segment is for emerging businesses. Corporate includes general corporate expenses, financing costs and other non-operating items and captive insurance operations. The initial public offering of Conoco's Class A common stock commenced on October 21, 1998. The initial public offering consisted of approximately 191 million shares of Class A common stock issued at a price of $23.00 per share and represented E.I. du Pont de Nemours and Company's (DuPont) first step in the planned divestiture of Conoco. After the initial public offering, DuPont owned 100 percent of Conoco's Class B common stock (approximately 437 million shares), representing approximately 70 percent of Conoco's outstanding common stock and approximately 92 percent of the combined voting power of all classes of voting stock of Conoco. On August 6, 1999, DuPont concluded an exchange offer to its stockholders, which resulted in all 437 million shares of Class B common stock being distributed to DuPont stockholders. The exchange offer was the final step in DuPont's planned divestiture of Conoco. On September 21, 2001, Conoco's shareholders approved the combination of Conoco's Class A and Class B common stock into a single class of new common stock on a one-for-one basis. The combination was effective on October 8, 2001. See note 23 for further details. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Consolidation The accounts of wholly owned and majority-owned subsidiaries are included in the consolidated financial statements. All intercompany balances have been eliminated. The equity method is used to account for investments in corporate entities, partnerships and limited liability companies in which we exert significant influence, generally having a 20 percent to 50 percent ownership interest. Our 50.1 percent non-controlling interest in Petrozuata C.A., located in Venezuela, is accounted for using the equity method. The equity method is used because the minority shareholder, a subsidiary of PDVSA, the national oil company of the Bolivarian Republic of Venezuela, has substantive participating rights, under which all substantive operating decisions (e.g., annual budgets, major financings, selection of senior operating management, etc.) require joint approvals, and therefore Conoco does not effectively control Petrozuata C.A. Undivided interests in oil and gas properties, certain transportation assets and Canadian Syncrude mining operations are accounted for on a proportionate gross basis. Other investments, excluding marketable securities, are carried at cost. Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses; the disclosure of contingent assets and liabilities; and the reported amounts of proved oil, gas and Canadian Syncrude reserves. Actual results may differ from those estimates and assumptions. Revenue Recognition Revenues are recorded when title passes to the customer. Revenues from the production of oil and gas properties in which we have interests with other companies are recorded on the basis of sales to customers. Differences between these sales and our share of production are not significant. Revenues from construction service contracts are recorded on a percentage-of-completion method. 77 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) Cash Equivalents Cash equivalents represent investments with maturities of three months or less from the time of purchase. They are carried at cost plus accrued interest, which approximates fair value. Inventories Inventories are carried at the lower of cost or market. Cost is determined under the last-in, first-out (LIFO) method for inventories of crude oil and petroleum products and Canadian Syncrude. Cost for remaining inventories, principally materials and supplies, is generally determined by the average cost method. Market is determined on a regional basis and any lower of cost or market write-down is recorded as a permanent adjustment to the cost of inventory. Property, Plant and Equipment (PP&E) PP&E is carried at cost, including interest capitalized on construction projects. Depreciation of PP&E, other than oil and gas and Canadian Syncrude properties, is generally computed on a straight-line basis over the estimated economic lives (of 14 to 25 years for major assets) of the facilities. When assets that are part of a composite group are retired, sold, abandoned or otherwise disposed of, the cost, net of sales proceeds or salvage value, is charged against the accumulated reserve for depreciation, depletion and amortization (DD&A). Where depreciation is accumulated for specific assets, gains or losses on disposal are included in period income. Oil and Gas Properties We follow the successful efforts method of accounting. Under successful efforts, the costs of property acquisitions, successful exploratory wells, development wells and related support equipment and facilities are capitalized. The costs of producing properties are amortized at the field level on a unit-of-production method. Unproved properties that are individually significant are periodically assessed for impairment. The impairment of individually insignificant properties is recorded by amortizing the costs based on past experience and the estimated holding period. Exploratory well costs are expensed in the period a well is determined to be unsuccessful. All other exploration costs, including geological and geophysical costs, production costs and overhead costs, are expensed in the period incurred. The estimated costs of dismantlement and removal of oil-and gas-related facilities, well plugging and abandonment, and other site restoration costs are accrued over the properties' productive lives using the unit-of-production method and recognized as a liability as the amortization expense is recorded. See note 21 for further details. Syncrude Mining Operations Capitalized costs, including support facilities, include the cost of the acquisition and other capital costs incurred. Capital costs are depreciated using the unit-of-production method based on the applicable portion of proven reserves associated with each mine location and its facilities. Impairment of Long-lived Assets Long-lived assets, including oil and gas properties with recorded values that are not expected to be recovered through future cash flows, are fully written down to current fair value through additional amortization or depreciation provisions in the periods in which the determination of impairments are made. Fair value is generally determined from estimated discounted future net cash flows. Capitalized Interest Interest from external borrowings is capitalized on major projects with an expected construction period of one year or longer. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful lives of the assets in the same manner as the underlying assets. 78 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) Maintenance and Repair Activities We accrue in advance for planned major maintenance. Through December 31, 2001, costs primarily related to work to be done as part of refinery turnarounds and drydock maintenance for tankers, barges and boats are accrued and are classified as liabilities on the balance sheet. However, effective January 1, 2002, we changed to a preferable method of accounting as recommended by the American Institute of Certified Public Accountants' proposed Statement of Position (SOP), "Accounting for Certain Costs and Activities Related to Property, Plant and Equipment" and the Financial Accounting Standards Board's (FASB) Exposure Draft, "Accounting in Interim and Annual Financial Statements for Certain Costs and Activities Related to Property, Plant and Equipment." Effective with this change, we began expensing all major maintenance costs as incurred. The effect of implementation of this change is a reversal of amounts previously accrued through December 31, 2001, of $47, which will be reported in the first quarter of 2002 as a change in accounting principle. Minor maintenance and repairs are charged to expense as incurred and improvements are capitalized. Shipping and Handling Costs We include shipping and handling costs in cost of goods sold if they are a component of manufacturing of refined products; otherwise they are reported as either operating expense or cost of goods sold, depending on the nature of the cost. Environmental Costs Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures, which relate to an existing condition caused by past operations, and that do not have future economic benefit, are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated. Stock Compensation We apply the intrinsic value method of accounting for stock options as prescribed by Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations. Pro forma information regarding changes in net income and earnings per share data (as if the accounting prescribed by Statement of Financial Accounting Standards (SFAS) No. 123, "Accounting for Stock-Based Compensation," had been applied) is presented in note 25. Income Taxes The provision for income taxes has been determined using the asset and liability approach of accounting for income taxes. Under this approach, deferred taxes represent the future tax consequences expected to occur when the reported amounts of assets and liabilities are recovered or paid. The provision for income taxes represents income taxes paid or payable for the current year plus the change in deferred taxes during the year. Deferred taxes result from differences between the financial and tax basis of Conoco's assets and liabilities and are adjusted for changes in tax rates and tax laws when changes are enacted. Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that some or all of the deferred tax asset will not be realized. Provision has been made for income taxes on unremitted earnings of subsidiaries and affiliates, except in cases in which earnings are deemed to be permanently invested. Foreign Currency Translation The local currency is the functional currency for our integrated European and Canadian petroleum operations because it is the currency of the primary economic environment in which those entities operate. For subsidiaries whose functional currency is the local currency, assets and liabilities denominated in local currency are translated into U.S. dollars at end-of-period exchange rates. The resulting translation adjustment is a component of accumulated other comprehensive loss (see note 24). Monetary assets and liabilities denominated in currencies other than the local currency are remeasured into the local currency prior to translation into U.S. dollars. The resulting exchange gains or losses, together with their related tax effects, are included in income in the period in 79 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) which they occur. Revenues and expenses are translated into U.S. dollars at the average exchange rates in effect during the period. For all other subsidiaries, the U.S. dollar is the functional currency. All foreign currency asset and liability amounts are remeasured into U.S. dollars at end-of-period exchange rates. Inventories, prepaid expenses and PP&E are exceptions to this policy and are remeasured at historical rates. Foreign currency revenues and expenses are remeasured at average exchange rates in effect during the year. Exceptions to this policy include all expenses related to balance sheet amounts that are remeasured at historical exchange rates. Exchange gains and losses arising from remeasured foreign currency-denominated monetary assets and liabilities are included in current period income. Derivative Instruments Effective January 1, 2001, we follow the methods prescribed by SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities," to account for derivative instruments. Under SFAS No. 133, as amended (SFAS 133), all derivative instruments are recorded on the balance sheet at their fair value. See note 9 for details on the accounting change generated from implementing SFAS 133; note 24 for the impact of implementing SFAS 133 on "Other comprehensive loss;" and note 27 for additional details of the accounting for the gain or loss resulting from changes in the fair value of derivatives designated as hedging instruments. Prior to the adoption of SFAS 133, derivative instruments that were designated and qualified as hedges were recognized in income in the period in which the underlying transaction affected earnings. Neither the hedging contracts nor the unrealized gains or losses on these contracts were recognized in the financial statements. All other derivative contracts were reflected at their fair market value on the balance sheet. Changes in market values of all other derivative contracts were reflected in income in the period in which the change occurred. Reclassifications Certain data in the prior years' financial statements have been reclassified to conform to the 2001 presentation. Recent Accounting Standards In early July 2001, the FASB issued SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets," which revise the accounting for business combinations by requiring that the purchase method of accounting be used on all business combinations initiated after June 30, 2001, and that separately identified intangible assets be recorded as assets. In addition, goodwill must be tested at least annually for impairment and is no longer amortized. SFAS No. 141 was applicable to our 2001 acquisition of Gulf Canada Resources Limited (Gulf Canada). SFAS No. 142 was adopted on January 1, 2002. The goodwill we recorded with the acquisition of Gulf Canada, which occurred prior to our adoption of SFAS No. 142, was subject to review for impairment under the provisions of APB Opinion No. 17, "Intangible Assets," and SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." No impairment was recognized on goodwill at December 31, 2001. The impact of these standards on existing goodwill from previous acquisitions is not material. The FASB also recently issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This statement significantly changes the method of accruing for costs, associated with the retirement of fixed assets (e.g., oil and gas production facilities and oil and gas properties, etc.), that an entity is legally obligated to incur. We will further evaluate the impact and timing of implementing SFAS No. 143. Implementation of this standard is required no later than January 1, 2003, with earlier adoption encouraged. In October 2001, the FASB approved SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which clarified certain implementation issues arising from SFAS No. 121. This standard was adopted on January 1, 2002, and there was no impact upon adoption. 80 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) 3. GULF CANADA ACQUISITION On July 16, 2001, Conoco, through a wholly owned subsidiary, completed the acquisition of all the ordinary shares of Gulf Canada, now known as Conoco Canada Resources Limited (Conoco Canada) for approximately $4,571 in cash plus assumed liabilities and minority interests. For ease of reference, we will refer to Conoco Canada as Gulf Canada. Prior to the acquisition, Gulf Canada was a Canadian-based independent exploration and production company, with primary operations in western Canada, Indonesia, the Netherlands and Ecuador. Subsequent to the acquisition, operational responsibilities for Gulf Canada's interests in Indonesia, the Netherlands and Ecuador were realigned within Conoco's regional organizational structure, and operationally Conoco's existing Canadian operations were merged with those of Gulf Canada. We acquired Gulf Canada to strengthen our oil and gas position in North America, to enhance our competitive position in key regions of the world, to add to our inventory of near- and long-term growth opportunities, to increase our exposure to North American and European markets, and to establish southeast Asia as our fourth core area. The following is a table of the calculation and allocation of the purchase price to the assets acquired and liabilities assumed based on their relative fair market values: CALCULATION OF THE PURCHASE PRICE FOR ASSETS ACQUIRED(1) Cash paid for stock purchased ............................................ $ 4,551 Other purchase price costs (e.g., fees, etc.) ............................ 20 -------- Total purchase price for common equity ................................. 4,571 Plus fair market value of liabilities assumed and minority interest Current and other liabilities ............................................ 776 Debt ..................................................................... 1,691 Deferred tax ............................................................. 1,824 Minority interest ........................................................ 552 -------- Total liabilities and minority interests ............................... 4,843 -------- Total purchase price for assets acquired .................................... $ 9,414 ======== ALLOCATION OF PURCHASE PRICE FOR ASSETS ACQUIRED(1) Property, plant and equipment(2) ......................................... $ 5,396 Goodwill(3) .............................................................. 3,066 All other assets, including working capital and intangibles(4) ........... 952 -------- Total ....................................................................... $ 9,414 ========

---------- (1) The purchase price was converted from Canadian dollars to U.S. dollars at the July 1, 2001, exchange rate of .66. Amounts shown on the December 31, 2001, balance sheet were converted to U.S. dollars using a .63 exchange rate. (2) Proved properties were valued at $3,549, unproved properties at $1,788 and other properties and equipment at $59. (3) None of the goodwill is deductible for tax purposes. Due to foreign currency translation adjustments, goodwill at December 31, 2001 was $2,933, of which $2,927 was attributable to Gulf Canada. (4) Includes the fair value of identifiable intangible assets of $6. These intangible assets have indefinite useful lives and will be tested for impairment. The purchase price allocation is subject to changes as additional information becomes available for certain accounts and properties. Management does not believe the final purchase price allocation will differ materially from the current purchase price allocation. Upon full implementation of SFAS No. 142 in 2002, the goodwill from this transaction will be disclosed in the reporting segments that include the "reporting units" to which this goodwill must be allocated in accordance with the requirements of this standard. Conoco's unaudited pro forma results are presented below for the years ended December 31, 2001, and December 31, 2000 (collectively the unaudited pro forma results). The unaudited pro forma results have been prepared to illustrate the estimated effect of the acquisition of Gulf Canada on Conoco under the purchase method of accounting as if Conoco's acquisition of Gulf Canada had occurred on January 1, 2000. The unaudited pro forma 81 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) results also give effect to the acquisition (that closed effective November 6, 2000) of Crestar Energy Inc. (Crestar) by Gulf Canada as if the acquisition had occurred on January 1, 2000. For these unaudited pro forma results, the historical income statement information of Gulf Canada has been converted to U.S. Generally Accepted Accounting Principles (GAAP) and converted to U.S. dollars using the average exchange rates of .64 for the six months ended December 31, 2001, .65 for the six months ended June 30, 2001, and .67 for the year ended December 31, 2000. The unaudited results do not purport to represent what the results of operations would actually have been if the acquisition had in fact occurred on such dates or to project Conoco's results of operations for any future date or period.

~~2000~~PRO ~~1999~~FORMA ~~1998~~YEAR ENDED DECEMBER 31 ------------------------- 2001 2000 ---------- ---------- U(UNAUDITED) Total revenues .S. ............................................................ $ ~~735~~40,736 $ 9341,265 $Income ~~(173)~~before ~~Non-U~~extraordinary item and accounting change .S..................... 1,711 1,890 Net income .................................................................. 21,~~723~~704 1,~~124~~890 ~~867~~Earnings ~~---------~~per ~~---------~~share ~~---------~~before ~~Income~~extraordinary ~~before~~item ~~income~~and ~~taxes~~accounting change Basic .................................................................. $2.73 3~~,458~~.03 $Diluted ~~1,217~~................................................................ $2.69 ~~694~~2.99 ~~=========~~Earnings ~~=========~~per ~~=========~~share Basic .................................................................. 2.72 3.03 Diluted ................................................................ 2.68 2.99

4. OTHER INCOME

2001 2000 1999 ~~1998~~ ----------~~--------~~ ----------~~-------~~ ---------- Interest income .................................................. $ 21 $ 39 $ 25 Gain on sales of assets and subsidiaries ......................... 310 72 26 Gain (loss) on derivative activities ............................. 212 (15) -- Syrian service contract .......................................... 118 110 3 Write-~~----~~down ~~Basic~~of various affiliates ................................. (50) (26) -- Exchange gain (loss) and other ................................... ~~624,354,441~~10 ~~627,233,229~~93 ~~473,826,632~~66 ~~Diluted~~---------- ---------- ---------- Other income ..................................................... ~~632,760,439~~$ ~~636,475,125~~621 ~~475,486,448~~$ 273 $ 120 ========== ========== ==========

5. TAXES OTHER THAN ON INCOME

~~DECEMBER~~2001 312000 1999 ---------- ---------- ---------- ~~2000~~Petroleum ~~1999~~excise taxes U.S. ........................................................... $ 1,463 $ 1,572 $ 1,495 Non-U.S. ....................................................... 5,281 5,202 4,997 ---------- ---------- ~~Trade~~---------- Total ....................................................... $6,744 16,~~506~~774 ~~$ 1~~6,~~394~~492 ~~Notes~~Payroll taxes .................................................... 54 45 44 Property taxes ................................................... 67 65 64 Production and other taxes ....................................... ~~331~~118 ~~341~~97 68 ---------- ---------- ~~Accounts~~---------- ~~and~~Taxes ~~notes~~other ~~receivable~~than on income ....................................... $ 16,~~837~~983 $ 16,~~735~~981 $ 6,668 ========== ========== ==========

6. INTEREST AND DEBT EXPENSE

~~DECEMBER~~2001 312000 1999 ---------- ----------- ~~2000 1999~~ --------- -~~--------~~ ~~Crude~~Interest ~~oil~~ and ~~petroleum~~debt ~~products~~cost incurred .............. ~~$ 643 $ 554 Other merchandise~~ ....................~~.........~~ 27$ 33429 ~~Materials~~$ 354 $ 317 Less: interest and ~~supplies~~debt cost capitalized ......................... ~~121~~33 ~~116~~16 6 ---------- ---------- ~~Inventories~~---------- Interest and debt expense(1) ..................................... $ ~~791~~396 $ ~~703~~338 $ 311 ========== ========== ==========

---------- (1) Cash interest paid, net of amounts capitalized, was $363 in 2001, $331 in 2000 and $297 in 1999. 82 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) 7. PROVISION FOR INCOME TAXES

~~DECEMBER~~2001 312000 1999 ---------- ---------- ---------- Current tax expense U.S. federal ................................................. $ 102 $ 126 $ 26 U.S. state and local ......................................... (5) 11 4 Non-~~--------------~~U.S. ~~COST~~..................................................... ~~NET~~1,001 1,183 554 ---------- ----------- ----------~~-----------~~ ~~2000~~Current ~~1999~~tax ~~2000~~expense ~~1999~~........................................ ~~---------~~1,098 1,320 584 ---------- ---------- ---------- ~~Oil~~Deferred ~~and~~tax ~~gas~~expense ~~properties~~U.S. ~~Unproved~~federal ................................................. $290 ~~1,106~~125 $(84) ~~1,201~~U.S. $state ~~920~~and $local ~~985 Proved~~ ......................................... 14~~,730~~ ~~13,661~~3 ~~6,719~~ (5~~,990~~) ~~Other~~Non-U.S. ..................................................... ~~1,449~~(11) ~~1,222~~108 ~~1,009~~(22) ~~792~~ --------- -~~--------~~ ---------- ---------- ~~Total~~Deferred ~~upstream~~tax expense ....... ~~17,285 16,084 8,648 7,767 Refining~~ .................... ~~4,264 4,082 2,161 2,072 Marketing and distribution~~ ............ ~~2,202~~293 ~~2,214~~236 ~~1,292~~(111) ~~1,309~~ ---------- ---------- ---------- Income tax expense ............................................... 1,391 1,556 473 Extraordinary item (see note 8) .............................. (33) -- --~~-----~~ ~~Total~~Cumulative ~~downstream~~effect of accounting change (see note 9) .......... ~~6,466~~22 ~~6,296~~-- ~~3,453~~-- ~~3,381~~Foreign ~~Emerging~~currency ~~businesses~~translation (see note 24) ................... 58(20) 60(83) 58(29) 60Minimum ~~Corporate~~pension liability (see note 24) ...................... 81(8) 36(5) 4829 27Unrealized gains on derivatives (see note 24) ................ 54 -- --~~-----~~ ---------- ---------- ---------- ~~PP&E~~Total provision for income taxes ................................. $ 231,~~890~~406 $ 221,~~476~~468 $ ~~12,207~~473 ~~$ 11,235~~ ========= =~~========~~ ========== ==========

Total income taxes paid worldwide were $1,379 in 2001, $1,030 in 2000 and $493 in 1999. At December 31, 2001 and 2000, the current and non-current deferred taxes were classified in the consolidated balance sheet as follows:

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

~~100%~~2001 ~~-------------------------------------------------~~2000 ~~OTHER CONOCO'S PETROZUATA AFFILIATES TOTAL SHARE~~ ----------~~----~~ ----------~~-----~~ ~~---------------~~Deferred ~~-------------~~tax ~~1999~~liabilities ~~RESULTS~~PP&E ~~OF OPERATIONS Sales~~.............................................. ~~$ 228 $ 8,304 $ 8,532 $ 3,208 Cost of goods sold~~.............~~....................~~ $ ~~-- $ 5~~4,~~665~~681 $ ~~5,665 $~~ 2,~~361 Operating expenses................................. $ 84 $ 1,340 $ 1,424 $~~ 452 ~~DD&A...............................................~~Inventories ~~$ 26 $ 314 $ 340 $ 127 Interest~~........................................... ~~$ 24 $ 208 $ 232 $ 80 Earnings before income taxes~~.........~~..............~~ $42 9215 $Other ~~665 $ 757 $ 163 Net income~~......................................... ~~$ 109 $ 490 $ 599 $ 150 FINANCIAL POSITION Current assets~~.................~~....................~~ $415 ~~190~~181 ~~$ 2,662 $ 2,852 $ 776 Non~~-~~current assets................................. 2,202 6,702 8,904 3,223~~ ---------~~-----~~ ----------~~-----~~ ~~---------------~~Deferred ~~-------------~~tax ~~Total~~liabilities ~~assets~~....................................... $5,138 2,~~392~~648 $Deferred ~~9,364~~tax $assets ~~11,756~~PP&E ~~$ 3,999 ============== =============== =============== ============= Short-term borrowings (2)~~.......................... ~~$ -- $ 581 $ 581 $ 182 Other current liabilities~~.......................... ~~149 1,525 1,674 588 Long-term borrowings (2)~~....... (33) (35) Employee benefits .................... ~~1,282 3,719 5,001 1,677 Other long-term borrowings~~.......................... ~~896~~(281) ~~422~~(252) ~~1,318~~Other ~~522~~accrued ~~--------------~~expenses ~~--------------- --------------- ------------- Total liabilities~~......................................... $(403) ~~2,327~~(275) $Tax ~~6,247~~loss/tax $credit ~~8,574~~carryforwards ~~$ 2,969 ============== =============== =============== ============= Conoco's net investment in affiliates (includes advances)~~.............................. (724) (442) Other .......... ~~$ 445 $ 1,159 $ 1,604 ============== =============== ============= 1998 RESULTS OF OPERATIONS Sales~~................................................ $(174) 9(158) $---------- ~~6,735~~---------- $Deferred ~~6,744~~tax $assets ~~2,386 Cost of goods sold~~................................. ~~$ -- $ 4,195 $ 4,195 $ 1,679 Operating expenses~~.........~~........................~~ ~~$ 46 $~~ (1,~~438~~615) $ (1,~~484~~162) $Valuation ~~488~~allowance ~~DD&A~~............................................... $619 7409 $---------- ~~276~~---------- $Net ~~283~~deferred $tax 97assets ~~Interest~~......................................~~.....~~ $(996) ~~21 $ 323 $ 344 $ 55 Earnings before income taxes....................... $~~ (54753) $---------- ~~412~~---------- $Net ~~358~~deferred $tax 43liabilities ~~Net income~~.....................................~~....~~ $ ~~(16)~~4,142 $ ~~268~~1,895 $========== ~~252 $ 22~~==========

Valuation allowances, which reduce deferred tax assets to an amount that will more likely than not be realized, increased $210 in 2001. This reflects a $201 increase to offset tax assets representing operating and tax losses incurred in exploration, production, and start-up operations and a $66 increase due to the Gulf Canada acquisition. 83 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) This increase is partially offset by a decrease of $57 related to tax loss carryforwards, which have been utilized or have expired, and to tax assets representing operating losses that we determined will more likely than not be realized in future years. In 2000, valuation allowances decreased $43, primarily reflecting a $123 decrease related to tax assets representing operating losses, which we determined will more likely than not be realized in future years and tax loss carryforwards that have been relinquished or expired. This decrease was partially offset by an $80 increase in the valuation allowance used to offset tax assets representing operating and tax losses incurred in exploration, production and start-up operations. Under the tax laws of various jurisdictions in which we operate, deductions or credits that cannot be fully utilized for tax purposes during the current year may be carried forward. These loss carryforwards, subject to statutory limitations, can reduce taxable income or taxes payable in a future year. At December 31, 2001, the tax effect of such loss carryforwards approximated $724. Of this amount, $271 has no expiration date, $22 expires in 2002, $45 expires in 2003, $47 expires in 2004, $72 expires in 2005, $185 expires in 2006, $1 expires in 2007, $71 expires in 2008 and $10 expires in 2011 and later years. As a result of the Gulf Canada acquisition, gross deferred tax assets of $137 were recorded, representing tax loss and tax credit carryforwards. Valuation allowances of $66 reduce the gross asset to the amount we believe will more likely than not be realized. Also as a result of the acquisition, net deferred tax liabilities of $1,895 were recorded, reflecting the temporary differences between book value and carryover tax basis in the assets acquired. An analysis of Conoco's effective income tax rate follows:

~~DECEMBER~~2001 312000 1999 ----------~~-----------------~~ ~~2000 1999~~ ----------- ------------ ~~Prepaid~~Statutory ~~pension~~U.S. ~~cost~~federal ~~(see~~income ~~note~~tax ~~23)~~rate ........................... 35.0% 35.0% 35.0% Higher tax rate on international operations ...................... 13.4 $11.3 510.0 $Alternative 13fuels ~~Long-term~~credit ~~receivables (1)~~......................................... (1.3) (1.2) (4.~~..................~~0) ~~280 69~~ Other ~~securities~~- ~~and~~net ~~investments~~...................................................... (0.2) ~~105~~0.2 87(1.3) ~~Leveraged~~---------- ~~lease~~---------- on---------- ~~Deepwater~~Consolidated ~~Pathfinder~~companies ...................................... 46.9 45.3 39.~~.......~~7 61Effect 55of ~~Deferred~~recording ~~tax~~equity ~~assets~~in ~~(see~~income ~~note~~of ~~7).......................................................~~certain 39affiliated 61companies ~~Deferred~~on ~~pension~~an ~~transition~~after-tax ~~obligation~~basis ~~(see note 23)~~............................. (0.~~.....~~3) ~~33 54 Other~~ (20.3) (0.~~.............................................................................~~8) ~~155 129~~ ---------- ---------- ---------- ~~Other~~Effective ~~assets~~income tax rate(1) ..................................... 46.6% 45.0% 38.~~...................................~~9% ~~$ 678 $ 468~~ ========== ========== ==========

---------- (1) Effective income tax rate based on income and income taxes before extraordinary item and cumulative effect of accounting change. Income before income taxes was based on the location of the corporate unit to which such earnings are attributable. However, since such earnings are often subject to taxation in more than one country, the income tax provision shown above, as U.S. or non-U.S., does not correspond to the earnings as set forth in the following table:

~~DECEMBER~~2001 312000 1999 ----------~~-----------------~~ ~~2000 1999~~ ----------- ------------ ~~Trade~~U.S. .............................................................~~...................~~ $ 1,~~287~~122 $ ~~959~~735 ~~Payables~~$ to93 ~~banks~~Non-U.S.~~....................................................................~~ ~~130 81 Product exchanges~~.........................................................~~.............~~ ~~217~~1,865 ~~210~~2,723 ~~Other..................................................................................~~1,124 ~~89 239~~ ---------- ---------- ---------- ~~Accounts~~Income ~~payable~~before income taxes .......................................~~................................~~ $ 12,~~723~~987 $ 3,458 $ 1,~~489~~217 ========== ========== ==========

Unremitted earnings of certain international subsidiaries totaling $1,687 at December 31, 2001, and $1,661 at December 31, 2000, are deemed to be permanently invested. No deferred tax liability was recognized for the remittance of such earnings. It is not practicable to estimate the income tax liability that might be incurred if such earnings were remitted to the U.S. 8. EXTRAORDINARY CHARGE FOR THE EARLY EXTINGUISHMENT OF DEBT Subsequent to the Gulf Canada acquisition, Conoco repaid various high-cost Gulf Canada outstanding notes with an aggregate principal value of $1,572. The extraordinary charge of $44, net of a tax benefit of $33, principally represents the premium associated with the early repayment of these notes. See note 20. 84 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) 9. CUMULATIVE EFFECT OF ACCOUNTING CHANGE In June 2000, the FASB issued SFAS No. 138, which made amendments to SFAS No. 133. We adopted SFAS No. 133, as amended (SFAS 133), on January 1, 2001. It modified the criteria for identifying derivative instruments and required that derivatives, whether in stand-alone contracts or, in certain cases, those embedded into other contracts, be recorded at their fair value as assets or liabilities on the balance sheet. Upon initial adoption of SFAS 133, we recorded a cumulative transition gain of $37 after-tax into net income, which was mainly the result of certain derivative instruments that did not meet the conditions for hedge accounting pursuant to SFAS 133, and $1 into other comprehensive income to reflect the fair value of derivatives qualifying as cash flow hedges. In addition, $297 was recorded as assets and $259 was recorded as liabilities. Note 27 provides additional details of the accounting for the gain or loss resulting from changes in the fair value of derivatives designated as hedging instruments, as prescribed by SFAS 133. In accordance with the transition provisions of SFAS 133, we recorded the following after-tax cumulative adjustments into earnings on January 1, 2001: Previously designated fair value hedging relationships(1): Fair value of hedging instruments ................................................... $ 27 Offsetting changes in fair value of hedged items .................................... (25) Hedging instruments not designated for hedge accounting under the standard(2) .......... 36 Contracts previously not designated as derivative instruments prior to the standard .... (1) -------- Total cumulative effect of adoption on earnings, after-tax ............................. $ 37 ========

The total cumulative effect is shown on the consolidated statement of income as "Cumulative effect of accounting change." ---------- (1) These fair value hedging relationships reflect conversions of certain commodity contracts from fixed prices to market prices, in accordance with Conoco's Risk Management Policy. For the year ended December 31, 2001, the ineffective portions of these hedges were immaterial. (2) Primarily reflects a pretax gain of $64 ($40 after-tax) related to changes in the fair value of certain crude oil put options from their purchase date to the January 1, 2001, adoption date of SFAS 133. Included in income before extraordinary item and accounting change on the consolidated statement of income is an $84 pretax expense ($53 after-tax) related to changes in the fair value of these same crude oil put options for the year ended December 31, 2001. 10. EARNINGS PER SHARE Basic earnings per share (EPS) is computed by dividing net income (the numerator) by the weighted-average number of common shares outstanding plus the effects of certain vested Conoco employee and director awards and fee deferrals that are invested in Conoco stock units (the denominator). Diluted EPS is similarly computed using the treasury stock method, except the denominator is increased to include the dilutive effect of outstanding stock options and unvested shares of restricted stock awarded under Conoco's compensation plans (see note 25). Fixed options and restricted stock grants that are contingent upon continued service to the company are included in the diluted earnings per share calculation and are excluded in the basic earnings per share calculation. Issuance of these shares is contingent only upon a continued specified service period of the grantees, and there are no other contingency provisions in these fixed options and restricted stock grants. Diluted EPS includes the dilutive effect of an additional 9,591,024 shares for 2001, 8,405,998 shares for 2000 and 9,241,896 shares for 1999. The denominator is based on the following weighted-average number of common shares outstanding:

~~DECEMBER~~2001 312000 1999 -----------~~----------------~~ ~~2000 1999~~ ----------- ------------ ~~Commercial~~Basic ~~paper~~............................................................~~...........~~ $625,503,098 ~~187~~624,354,441 $627,233,229 ~~628~~Diluted ~~Industrial development bonds~~........................................................... 59635,094,122 24632,760,439 Long-term borrowings payable within one year........................................... 8 9 Capital lease obligations.............................................................. 2 2 ---------- ----------- Short-term borrowings and capital lease obligations.................................... $ 256 $ 663 ========== ===========636,475,125

At December 31, 2001, variable stock options for 1,331,300 shares of common stock were outstanding, and at December 31, 2000 and 1999, variable stock options for 3,124,146 shares of common stock were outstanding. 85 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) These options were not included in the computation of diluted EPS because the threshold price required for these options to be vested had not been reached. Fixed stock options for 7,691,426; 89,530; and 30,972 shares of common stock were not included in the diluted earnings per share calculation for 2001, 2000 and 1999, respectively, because the exercise price was greater than the average market price. The weighted-average number of common shares held as treasury stock is deducted in determining the weighted-average number of shares outstanding. 11. ACCOUNTS AND NOTES RECEIVABLE

DECEMBER 31 --------------------------- 2001 2000 ~~1999~~ ----------- ------------ ~~Taxes~~Trade ~~other than on income~~............................................................. $ ~~384~~1,415 $ ~~371~~1,506 ~~Operating~~Notes ~~expenses..................................................................... 469 347 Payroll~~ and other ~~employee-related costs~~............................................... ~~206 153 Royalties~~...~~...........................................................................~~ ~~134~~479 99331 ~~Restructuring costs (1)................................................................~~ -- ~~11 Accrued post~~-~~retirement benefits cost (see note 23).................................... 18 18 Other.................................................................................. 332 304~~ -------~~---~~ ----------- ~~Other~~Accounts ~~accrued~~and ~~liabilities~~notes receivable ....................................~~..........................~~ $ 1,~~543~~894 $ 1,~~303~~837 ========== ===========

Included in the preceding table are accounts and notes receivable from affiliated companies (see note 15) of $685 at December 31, 2001, and $548 at December 31, 2000. The carrying value of accounts and notes receivable approximates fair value because of their short maturity. See note 29 for a description of operating segment markets and associated concentrations of credit risk. 12. INVENTORIES

DECEMBER 31 --------------------------- 2001 2000 ~~1999~~ ----------- ------------ ~~5.90%~~Crude ~~senior~~oil ~~unsecured~~and ~~notes~~petroleum ~~due~~products ~~2004~~.................................~~.................~~ $ ~~1,348~~773 $ ~~1,348~~643 ~~6.50%~~Canadian ~~senior~~Syncrude ~~unsecured~~(from ~~notes~~mining ~~due~~operations) ~~2008~~.......................~~...........................~~ 710 ~~7 6.35% senior unsecured notes due 2009.................................................. 750 750 7.68% senior unsecured notes due 2012.................................................. 65~~ -- ~~5.75%~~Other ~~senior~~merchandise ~~unsecured notes due 2026~~.................................................. 1626 1627 ~~6.95%~~Materials ~~senior~~and ~~unsecured~~supplies ~~notes due 2029~~...........................................~~.......~~ ~~1,900~~186 ~~1,900~~121 ~~Other loans (various currencies) due 2002~~-2008 (1)..................................... 20 24 Capitalization obligation to affiliate due 2008........................................ 9 8 Capital lease obligations.............................................................. 23 27 ---------- ----------- ~~Long-term~~Inventories ~~borrowings and capital lease obligations~~...................................................... $ ~~4,138~~995 $ ~~4,080~~791 ========== ===========

The excess of market over book value of inventories valued under the LIFO method was $268 and $643 at December 31, 2001 and 2000, respectively. Inventories valued at LIFO represented 79 percent and 81 percent of consolidated inventories at December 31, 2001 and 2000, respectively. During 2000, certain inventory quantities were reduced, resulting in a partial liquidation of the LIFO basis. The 2000 liquidation of inventories, carried at lower costs prevailing in prior years, as compared with the replacement costs of these inventories, had no material effect on net income. The effect of a liquidation of the LIFO basis during 1999 decreased cost of goods sold by approximately $67 and increased net income by approximately $42. 13. OTHER CURRENT ASSETS

DECEMBER 31 --------------------------- 2001 2000 ~~1999~~ ----------- ------------ ~~Deferred~~Fair ~~gas~~value ~~revenue...................................................................~~of $derivative ~~280~~instruments ~~$ 361 Accrued post-retirement benefits cost~~ (see note 2327) ...............~~.....................~~ ~~335~~$ ~~335~~574 ~~Accrued~~$ ~~pension~~36 ~~liability~~Prepaid ~~(see~~expenses ~~note 23)~~................................................ ~~184 200 Abandonment costs~~.~~.....................................................................~~ ~~397~~18 ~~289~~20 ~~Environmental~~Deferred ~~remediation~~taxes ~~costs~~ (see note 267) ......................................~~....~~ ~~107~~13 9743 Other ............................................................~~......................~~ ~~623~~461 ~~676~~342 ---------- ----------- Other ~~liabilities~~current ~~and~~assets ~~deferred credits~~.............................................~~....~~ $ 1,~~926~~066 $ ~~1,958~~441 ========== ===========

86 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) 14. PROPERTY, PLANT AND EQUIPMENT

~~CLASS~~DECEMBER A31 ~~CLASS~~------------------------------------------------------- BCOST ~~TOTAL~~NET ----------- -------------- ------------------------- ~~Issued~~2001 in2000 ~~connection~~2001 ~~with~~2000 ~~the~~---------- ~~initial~~---------- ~~public~~---------- ~~offering~~---------- ofOil ~~Class A shares~~ and ~~recapitalization~~gas ofproperties ~~DuPont~~Unproved ~~ownership (Class B shares)~~...................................................... ~~191,456,427~~$ ~~436~~2,~~543,573~~524 ~~628~~$ 1,~~000,000~~106 ~~Purchase~~$ of2,310 ~~shares~~$ ~~for~~920 ~~treasury~~Proved ~~(1)~~........................................................ ~~(250~~18,~~000)~~541 --14,730 ~~(250~~10,~~000)~~093 ~~Issued~~6,719 onCanadian ~~exercise~~Syncrude ~~of stock options (including 137 from treasury)~~................................................. ~~41,531~~802 -- ~~41,531~~797 --~~---------~~ ~~-----------~~Other ~~----------- Common shares outstanding - December 31, 1998~~............... ~~191,247,958 436,543,573 627,791,531 Purchase of shares for treasury (1)~~......................... ~~(3,494,616) -- (3,494,616) Issued on exercise of stock options and compensation awards from treasury (see note 22)~~....................~~....~~ 1,~~286~~537 1,~~519~~449 --1,044 1,~~286,519~~009 ----------- ----------- ----------- ~~Common shares outstanding~~ ---------- ~~December~~Total ~~31,~~upstream ~~1999~~................................................ ~~189~~23,~~039~~404 17,~~861~~285 ~~436~~14,~~543~~244 8,~~573~~648 ~~625~~Refining,~~583,434~~ ~~-----------~~marketing ~~-----------~~and ~~-----------~~distribution ~~Purchase of shares for treasury (1)~~............................. (36,~~634~~497 6,~~400)~~466 --3,392 (3,~~634,400)~~453 ~~Additional~~Emerging ~~shares~~businesses ~~issued~~.............................................. --229 ~~466,638~~58 ~~466,638~~228 ~~Shares~~58 ~~purchased~~Corporate ~~and retired (1) (2)~~........................ ~~-- (223,729) (223,729) Issued on exercise of stock options and compensation awards from treasury (see note 22)~~................................ ~~1,240,897~~94 --81 ~~1,240,897~~54 48 ----------- ----------- ----------- ~~Common shares outstanding~~ ---------- ~~December~~PP&E ~~31, 2000~~............................................................. ~~186~~$ 30,~~646~~224 $ 23,~~358~~890 ~~436~~$ 17,~~786,482~~918 ~~623~~$ 12,~~432,840~~207 =========== =========== ========== ==========

PP&E includes downstream assets acquired under capital leases of $44 at December 31, 2001, and $36 at December 31, 2000. DD&A expense associated with these assets was $18 at December 31, 2001, $16 at December 31, 2000, and $15 at December 31, 1999. 15. SUMMARIZED FINANCIAL INFORMATION FOR AFFILIATED COMPANIES Summarized consolidated financial information for Petrozuata C.A. (50.1 percent non-controlling interest) and other affiliated companies for which Conoco uses the equity method of accounting (see note 2) is shown below. Other affiliates includes the financial information of, among others, the following: Ceska rafinerska, a.s. (16.33 percent), CFJ Properties (50 percent), Excel Paralubes (50 percent), Malaysian Refining Company Sdn. Bhd. (47 percent), Petrovera (46.7 percent), Pocahontas Gas Partnership (50 percent) and Polar Lights Company (50 percent). During the third quarter 2001, Conoco sold its 50 percent interest in the Pocahontas Gas Partnership.

~~2000~~100% ~~1999~~---------------------------------------- OTHER CONOCO'S PETROZUATA AFFILIATES TOTAL SHARE ---------- ---------- ~~First~~---------- ~~quarter~~---------- ~~(1)~~2001 RESULTS OF OPERATIONS Sales ............................................................ $ 577 $ 11,079 $ 11,656 $ 4,719 Cost of goods sold ............................................... $~~.19~~ 115 $~~.14~~ ~~Second~~8,458 ~~quarter~~$ 8,573 $ 3,678 Operating expenses ............................................... $ 233 $ 1,201 $ 1,434 $ 529 DD&A ............................. .19 .19.............................. ~~Third~~$ ~~quarter~~74 $ 414 $ 488 $ 180 Interest ......................................................... $ 101 $ 52 $ 153 $ 77 Earnings before income taxes .................... .19 .19............... ~~Fourth~~$ ~~quarter~~37 $ 597 $ 634 $ 153 Net income(1) .................................................... $ 105 $ 394 $ 499 $ 181 Dividends received ............................................... $ 198 FINANCIAL POSITION Current assets .19.................................................. $ 323 $ 2,229 $ 2,552 $ 956 Non-current assets .19.............................................. 3,047 7,585 10,632 3,843 ---------- ---------- ~~Dividends~~---------- ~~per~~---------- ~~share~~Total assets ..................................................... $ 3,370 $ 9,814 $ 13,184 $ 4,799 ========== ========== ========== ========== Short-term borrowings(2) ......................................... $ 64 $ 974 $ 1,038 $ 256 Other current liabilities .76....................................... 113 1,872 1,985 764 Long-term borrowings(2) .......................................... 1,364 3,626 4,990 1,699 Other long-term liabilities ...................................... 1,365 812 2,177 934 ---------- ---------- ---------- ---------- Total liabilities ................................................ $ 2,906 $ 7,284 $ 10,190 $ 3,653 ========== ========== ========== ========== Conoco's net investment in affiliates (includes advances) .71....... $ 822 $ 1,072 $ 1,894 ========== ========== ==========

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

~~DECEMBER~~100% 31 ---------------------------------------- ~~2000~~OTHER ~~1999~~CONOCO'S PETROZUATA AFFILIATES TOTAL SHARE ---------- ---------- ~~Foreign~~---------- ~~currency~~---------- ~~translation~~2000 ~~adjustment~~RESULTS OF OPERATIONS Sales ............................................................ $ ~~(619)~~512 $ ~~(347)~~10,836 ~~Minimum~~$ ~~pension~~11,348 ~~liability~~$ ~~adjustment~~4,368 ~~(see~~Cost ~~note~~of ~~23)~~goods sold ............................................... ~~(34)~~$ 17 $ 8,031 $ 8,048 $ 3,287 Operating expenses ............................................... $ 125 $ 1,349 $ 1,474 $ 493 DD&A ............................................................. $ 26 $ 380 $ 406 $ 133 Interest ......................................................... $ 40 $ 165 $ 205 $ 86 Earnings before income taxes ..................................... $ 307 $ 744 $ 1,051 $ 387 Net income (251) ................................................... $ 294 $ 545 $ 839 $ 277 Dividends received ............................................... $ 132 FINANCIAL POSITION Current assets ................................................... $ 324 $ 2,238 $ 2,562 $ 874 Non-current assets ............................................... 2,799 7,423 10,222 3,638 ---------- ---------- ~~Accumulated~~---------- ~~other~~---------- ~~comprehensive~~Total ~~loss~~assets ..................................................... $ 3,123 $ 9,661 $ 12,784 $ 4,512 ========== ========== ========== ========== Short-term borrowings(~~653~~2) ......................................... $ -- $ 564 $ 564 $ 163 Other current liabilities ........................................ 218 1,604 1,822 603 Long-term borrowings(~~372~~2) .......................................... 1,373 3,938 5,311 1,787 Other long-term liabilities ...................................... 1,174 721 1,895 793 ---------- ---------- ---------- ---------- Total liabilities ................................................ $ 2,765 $ 6,827 $ 9,592 $ 3,346 ========== ========== ========== ========== Conoco's net investment in affiliates (includes advances) ........ $ 693 $ 1,138 $ 1,831 ========== ========== ========== 1999 RESULTS OF OPERATIONS Sales ............................................................ $ 228 $ 8,304 $ 8,532 $ 3,208 Cost of goods sold ............................................... $ -- $ 5,665 $ 5,665 $ 2,361 Operating expenses ............................................... $ 84 $ 1,340 $ 1,424 $ 452 DD&A ............................................................. $ 26 $ 314 $ 340 $ 127 Interest ......................................................... $ 24 $ 208 $ 232 $ 80 Earnings before income taxes ..................................... $ 92 $ 665 $ 757 $ 163 Net income(1) .................................................... $ 109 $ 490 $ 599 $ 150 Dividends received ............................................... $ 77

---------- (1) Conoco's equity in Petrozuata's earnings totaled $52 in 2001, $147 in 2000 and $50 in 1999. (2) Equity affiliate borrowings of $1,014 in 2001 and $979 in 2000 were guaranteed by Conoco or DuPont, on behalf of and indemnified by Conoco. These amounts are included in the guarantees disclosed in note 28. Equity affiliate sales to Conoco amounted to $1,023 in 2001, $804 in 2000 and $720 in 1999. Equity affiliate purchases from Conoco totaled $1,690 in 2001, $2,200 in 2000 and $1,519 in 1999. Conoco's equity in undistributed earnings of its affiliated companies was $585 at December 31, 2001, $446 at December 31, 2000 and $366 at December 31, 1999. 16. OTHER ASSETS

~~YEAR ENDED~~ DECEMBER 31 -------------------------~~------------------------------------------------------------------------~~ 2001 2000 ~~1999 1998~~ ----------~~---------------------~~ ----------~~---------------------~~ Long-~~------------------------------~~term ~~PRETAX~~receivables(1) ~~INCOME~~......................................... ~~TAX~~$ ~~AFTER-TAX~~359 ~~PRETAX~~$ ~~INCOME~~280 ~~TAX~~Other ~~AFTER-TAX~~securities ~~PRETAX~~and ~~INCOME~~investments ~~TAX~~................................. ~~AFTER-TAX~~85 ~~------~~105 ~~----------~~Leveraged ~~---------~~lease ~~------~~on ~~----------~~Deepwater ~~---------~~Pathfinder ~~------~~.......................... ~~----------~~63 ~~---------~~61 ~~Foreign~~Deferred ~~currency~~taxes ~~translation~~(see ~~adjustment~~note 7) ...................................... $28 ~~(355)~~39 $Deferred ~~(83)~~pension $transition ~~(272)~~obligation $ (~~191)~~see $note ~~(29~~26) $............. ~~(162)~~70 $33 ~~(47)~~Prepaid $pension cost (~~22)~~see $note ~~(25~~26) ~~Minimum pension liability adjustment~~ ............................... ~~(14)~~-- (5) ~~(9)~~Fair 93value 29of 64derivative ~~(84)~~instruments (~~26)~~see ~~(58~~note 27) ~~--------~~............... ~~--------~~27 --~~------~~ ~~--------~~Other ~~--------~~............................................................ 184 145 -------- --~~------~~ -------- --~~------~~ Other ~~comprehensive~~assets ~~loss~~ ..................................................... $ ~~(369)~~816 $ ~~(88)~~668 ~~$ (281) $ (98) $ -- $ (98) $ (131) $ (48) $ (83)~~ ======== ==~~======~~ ======== ==~~====== ======== ======== ======== ======== ========~~

88 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) ---------- (1) Includes $277 at December 31, 2001, and $223 at December 31, 2000, attributable to a long-term service contract for the development of a gas and condensate infrastructure in Syria. This amount is recoverable from the gas and condensate revenue stream generated over a period up to five years commencing in early 2002. 17. ACCOUNTS PAYABLE

~~FIXED~~DECEMBER ~~VARIABLE~~31 -------------------------~~----------~~ ~~-------------------------------~~2001 ~~NUMBER~~2000 ~~WEIGHTED~~- ~~NUMBER WEIGHTED~~- ~~OF AVERAGE OF AVERAGE SHARES PRICE SHARES PRICE~~ --------~~-----------~~ ----------~~----~~ ~~----------------~~Trade ~~------------ DUPONT OPTIONS January 1, 1998~~........................... ~~8,990,428 $ 35~~.~~14 1,259,600 $ 52~~.~~50 Granted~~................................ 1,241,055 59.53 -- -- Reclassified........................... 629,800 52.50 (629,800) 52.50 Exercised.............................. (460,314) 24.64 -- -- Forfeited.............................. (65,852) 50.68 -- -- --------------- -------------- October 21, 1998 (at initial public offering).............................. 10,335,117 39.50 629,800 52.50 Cancelled for Conoco options........... (8,291,708) -- (629,800) -- --------------- -------------- Options retained by DuPont ............ 2,043,409 -- -- -- CONOCO OPTIONS Granted at initial public offering date for cancelled DuPont options........... 22,551,544 $ ~~14.62~~ 1,~~724,146~~439 $ ~~19.18 New awards............................. 9~~1,~~721,750~~287 ~~23.00~~Payables --to --banks ~~Exercised~~.............................. ~~(41,531) 14~~.~~18 -- -- Forfeited~~.................~~.............~~ ~~(53,840)~~146 ~~23.00~~130 --Product --exchanges ~~--------------- -------------- December 31, 1998~~......................... ~~32,177,923 17~~.~~14 1,724,146 19~~.~~18 Granted~~.....................~~...........~~ ~~30,689~~250 ~~27.46~~217 ~~1,400,000~~Other 26.~~50 Exercised~~.............................. ~~(1,225,424) 12~~.~~37 -- -- Forfeited~~.............................. ~~(133,929)~~115 ~~22.28~~89 -- -- ------~~---------~~ ----------~~----~~ ~~December~~Accounts ~~31,~~payable ~~1999~~......................... ~~30,849,259 17~~.~~31 3,124,146 22~~.~~46 Granted~~......................~~..........~~ ~~6,419,256~~$ ~~21.31 -- -- Exercised.............................. (~~1,~~406,597)~~950 ~~10.47~~$ ~~-- -- Forfeited.............................. (170~~1,~~785)~~723 ~~20.54~~========== ~~-- -- --------------- -------------- December 31, 2000......................... 35,691,133 18.29 3,124,146 22.46~~==========

Included in the preceding table are accounts payable to affiliated companies (see note 15) of $195 at December 31, 2001, and $573 at December 31, 2000. Payables to banks represent checks issued on certain disbursement accounts but not presented to the banks for payment. The amounts above are carried at historical cost, which approximate fair value because of their short maturity. 18. SHORT-TERM BORROWINGS AND CAPITAL LEASE OBLIGATIONS

~~EXERCISE~~DECEMBER ~~PRICE~~31 ------------------------- 2001 2000 ---------- ----------~~------------------------------~~ ~~$6.57~~Commercial -paper ~~$10~~.~~13 - $19~~.~~17 - $28~~.~~00 - $9~~.~~59 $14~~.~~47 $27~~.20........................................... $~~29.72~~ ~~---------------~~558 ~~----------------~~$ ~~----------------~~187 ~~---------------~~Industrial ~~Options~~development ~~outstanding~~bonds ..................................... ~~3,987,574~~59 ~~6,676,845~~59 ~~24,988,871~~Floating ~~37,843~~rate ~~Weighted-average~~notes ~~remaining~~due ~~contractual life~~ 2002(~~years~~1) ............ 2.~~0 4~~.~~5 7~~.~~6 8~~.~~6 Weighted-average price~~.................. $500 ~~8.79~~-- $Long-term ~~11.92~~borrowings $payable ~~21.49~~within $one ~~28.03~~year ~~Options exercisable~~..................... ~~3,987,574~~ 6~~,676,845~~ ~~14,764,448~~8 ~~14,963~~Capital ~~Weighted-average~~lease ~~price~~obligations ........................................ $2 ~~8.79~~2 $---------- 11---------- Short-term borrowings and capital lease obligations .92............. $ ~~21.24~~1,125 $ ~~28.09~~256 ========== ==========

---------- (1) At December 31, 2001, the effective interest rate was 3.2 percent. These amounts are carried at historical cost, which approximate fair value because of their short maturity. During October 2001, we amended and increased our unsecured $2,000 revolving credit facility by $1,000 to facilitate an increase in our U.S. commercial paper program. Also effective in October, the European commercial paper program was increased from euro 500 to euro 1,000. We have the ability to issue commercial paper at any time with maturities not to exceed 270 days. At December 31, 2001, we had $558 of commercial paper outstanding, of which $29 was denominated in foreign currencies. The weighted-average interest rate was 2.16 percent. At December 31, 2000, there was $187 of commercial paper outstanding, with a weighted-average interest rate of 6.8 percent, of which $85 was denominated in foreign currencies. Supporting the commercial paper programs, we have an unsecured $3,000 revolving credit facility with a syndicate of U.S. and international banks. The terms consist of a 364-day committed facility in the amount of $2,350 and a five-year committed facility, with over two years remaining, in the amount of $650. At December 31, 2001, and at December 31, 2000, we had no outstanding borrowings under this credit facility. The weighted-average interest rate on short-term borrowings and capital lease obligations outstanding was 2.7 percent at December 31, 2001, and 6.3 percent at December 31, 2000. 89 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) 19. OTHER ACCRUED LIABILITIES

~~2000~~DECEMBER ~~1999~~31 ~~1998~~ ----------------- -------- 2001 2000 -------- -- ----------~~----~~ ~~OPTIONS~~Taxes ~~EXERCISABLE~~other ATthan ~~YEAR-END~~on ~~Number~~income ~~of shares~~....................................... $ 402 $ 384 Operating expenses and other related costs ....................... ~~25,443,830~~402 ~~22,481,408~~537 ~~19,425,900~~Payroll ~~Weighted~~and other employee-~~average~~related ~~price~~costs ......................... 185 206 Royalties ........... ~~$ 16~~.85............................................ $70 ~~15.31~~134 $Interest 13payable .49................................................ ~~WEIGHTED-AVERAGE~~112 ~~FAIR~~66 ~~VALUE~~Fair OFvalue ~~OPTIONS~~of ~~GRANTED~~derivative ~~DURING~~instruments ~~THE~~(see ~~YEAR~~note ~~New~~27) ~~options~~............... 222 -- Accrual for litigation settlement (see note 28) .................. 112 -- Accrued post-retirement benefits cost (see note 26) .............. $30 ~~6.14~~18 $Environmental ~~6.85~~remediation $costs ~~4.15~~(see ~~Options~~note ~~substituted~~28) ~~for~~.................... ~~DuPont~~23 ~~options~~12 Other ............................................................ $339 186 ---------- $ ---------- $Other 9accrued liabilities .22....................................... $ 1,897 $ 1,543 ========== ==========

20. LONG-TERM BORROWINGS AND CAPITAL LEASE OBLIGATIONS

~~DUPONT~~DECEMBER ~~CONOCO~~31 ~~OPTIONS (1) OPTIONS~~ -------------------------- 2001 2000 ----------~~----------~~ ----------- ~~2000~~Floating ~~1999~~rate ~~1998~~notes ~~1998~~due ~~------------~~2003 ~~----------~~................................................ ~~----------------------~~$ 500 $ --~~---------~~ ~~NEW~~7.443% ~~NEW~~senior ~~NEW~~unsecured ~~SUBSTITUTES~~notes ~~FIXED~~due ~~------------~~2004 ~~----------~~...................................... ~~----------~~171 --~~---------~~ ~~-----------~~5.90% ~~Dividend~~senior ~~yield~~unsecured notes due 2004 ....................................... 1,349 1,348 8.375% senior unsecured notes due 2005(1) ................................... 39 -- 5.345% 3senior unsecured notes due 2006 .3%...................................... 31,248 -- 8.335% 3senior unsecured notes due 2006(1) .3................................... 4 -- 6.45% senior unsecured notes due 2007(1)(2) .1................................ 62 -- 6.50% ~~Volatility~~senior unsecured notes due 2008 ....................................... 7 7 6.35% senior unsecured notes due 2009 ....................................... 30750 750 6.035% 25senior unsecured notes due 2011 .0%...................................... 201,747 -- 7.0125% 20senior unsecured notes due 2011(1) .0%.................................. 195 -- 7.968% ~~Risk-free~~senior ~~interest~~unsecured ~~rate~~notes due 2012 ....................................... 563 65 8.125% senior unsecured notes due 2017(1) .................................... 9 -- 5.875% 4senior unsecured notes due 2026 ....................................... 16 16 6.95% 4senior unsecured notes due 2029 .4%...................................... 51,900 1,900 7.525% ~~Expected~~senior ~~life~~unsecured notes due 2031 ....................................... 494 -- Other loans (~~years~~various currencies) due 2003-2008(3) ........................... 9 20 Capitalization obligation to affiliate due 2008 ....... 6.0..................... 613 9 Capital lease obligations .0.................................................. 520 23 ---------- ---------- Total long-term borrowings and capital lease obligations before hedges ... 8,376 34,138 Fair market value adjustment on notes subject to hedging (see note 27) Notes due 2009(4) .9....................................................... (35) -- Notes due 2029(5) ........................................................ (74) -- ---------- ---------- Long-term borrowings and capital lease obligations .......................... $ 8,267 $ 4,138 ========== ==========

---------- (1) Outstanding notes originally issued by Crestar and Gulf Canada reflect a $2 fair value adjustment as a result of the acquisition. (2) The principal amount of these notes is Canadian $100. The obligation is converted based on the year-end exchange rate of .63. (3) Weighted-average interest rate was 6 percent at December 31, 2001, and 7.5 percent at December 31, 2000. (4) Fair market value of the $750 executed interest rate swaps. (5) Fair market value of the $900 executed interest rate swaps. In connection with the July 2001 Gulf Canada acquisition, we arranged a $4,500 senior unsecured 364-day bridge credit facility to finance the transaction and assumed approximately $2,000 of net debt and minority interests. The borrowings under the bridge facility were repaid on October 11, 2001, primarily with the net proceeds of $4,469 from the $4,500 debt offerings by Conoco and Conoco Funding Company, a wholly owned Nova Scotia finance subsidiary, described in the subsequent paragraphs. The bridge was subsequently cancelled on October 16, 2001. 90 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) Subsequent to the Gulf Canada acquisition, Gulf Indonesia Resources Limited (Gulf Indonesia), a consolidated subsidiary of Gulf Canada, repaid $116 of its outstanding debt, and Gulf Canada repaid $1,015 of its $1,048 in outstanding public debt securities. In addition, Gulf Canada repaid $207 of its subordinated debt and an additional $234 of outstanding private placement debt. We funded these repayments and the repayment of the balance of the bridge facility through a combination of cash on hand, our issuance of commercial paper and borrowings under other available credit lines. On October 11, 2001, Conoco Funding Company issued $3,500 of senior unsecured debt securities, fully and unconditionally guaranteed by Conoco, as follows: o $1,250 of 5.45 percent notes due 2006; o $1,750 of 6.35 percent notes due 2011; and o $500 of 7.25 percent notes due 2031. Conoco also issued $1,000 of floating rate notes as follows: o $500 notes due October 15, 2002, with a floating rate based on the three-month LIBOR rate plus .77 percent. The effective interest rate for the floating rate notes was 3.20 percent at December 31, 2001; and o $500 notes due April 15, 2003, with a floating rate based on the three-month LIBOR rate plus .85 percent. The effective interest rate for the floating rate notes was 3.28 percent at December 31, 2001. Maturities of long-term borrowings, together with sinking fund requirements for years ending after December 31, 2002, are $506 for 2003, $1,527 for 2004, $19 for 2005, $1,260 for 2006 and $5,064 for 2007 and thereafter. Long-term borrowings and capital lease obligations outstanding at December 31, 2001, before interest rate hedges, had an estimated fair value of $8,557. At December 31, 2000, these outstanding obligations approximate fair value. These estimates were based on quoted market prices for the same or similar issues. 21. OTHER LIABILITIES AND DEFERRED CREDITS

~~2000~~DECEMBER ~~1999~~31 ~~1998~~ ------------ -------------- 2001 2000 ---------- ---------- ~~Increase~~Deferred ~~(decrease)~~gas inrevenue ~~Net income~~........................................................~~....~~ $ ~~(28)~~231 $ 280 Accrued post-retirement benefits cost (18see note 26) $......................... ~~157~~363 ~~Earnings~~335 ~~per~~Accrued ~~share~~pension ~~Basic~~liability (see note 26) ..................................... 266 184 Abandonment costs(1) ........................................................ $432 397 Environmental remediation costs (~~.04~~see note 28) $............................... 134 107 Fair value of derivative instruments (~~.03)~~see $note 27) .33......................... ~~Diluted~~158 -- Other ....................................................................... $762 (623 ---------- ---------- Other liabilities and deferred credits .~~04)~~..................................... $ ~~(.03)~~2,346 $ ~~.33~~1,926 ========== ==========

---------- (1) Total future abandonment costs are currently estimated to be $1,062. 22. MINORITY INTERESTS In 1996, various upstream subsidiaries contributed oil and gas assets to Conoco Oil & Gas Associates L.P. for a general partnership interest of 67 percent. Vanguard Energy Investors L.P. then purchased the remaining 33 percent as a limited partner. In December 1999, Conoco elected to retire Vanguard's interest and terminate the Conoco Oil & Gas Associates partnership, reducing minority interest by $302. As a result of this transaction, Vanguard received from Conoco Oil & Gas Associates $310 cash, which represented its mark-to-market adjusted capital account value plus a priority return for the period of October 1, 1999, through December 31, 1999. In 1999, Conoco formed Conoco Corporate Holdings L.P. by contributing an office building and four aircraft. The limited partner interest was sold to Highlander Investors L.L.C. for $141, or an initial net 47 percent interest. Highlander is entitled to a cumulative annual priority return on its investment of 7.86 percent. The net minority interest in Conoco Corporate Holdings held by Highlander was $141 at December 31, 2001, and December 31, 2000. 91 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) In 1999, Conoco and Armadillo Investors L.L.C. formed Conoco Gas Holdings L.L.C. We contributed certain domestic upstream assets for a 75 percent common member interest and cash, and Armadillo contributed cash for a 25 percent preferred member interest. Armadillo is entitled to a cumulative annual preferred dividend on its investment of 7.16 percent. The net minority interest in Conoco Gas Holdings held by Armadillo was $185 at December 31, 2000. In March 2001, we acquired the minority interest in Conoco Gas Holdings L.L.C. from Armadillo L.L.C. The acquisition resulted in a reduction of minority interest of $185, an increase in debt of $171 and a reduction in cash of $14. Conoco assumed the $171 debt from Armadillo L.L.C. In July 2001, Conoco assumed minority interests of $552 as part of the Gulf Canada acquisition. The minority interests included $381 of two classes (Series I and II) preferred stock of Gulf Canada that remained outstanding after the acquisition and $171 representing 28 percent of the outside ownership of the common shares outstanding of its subsidiary, Gulf Indonesia. Both Series I preferred stock of Gulf Canada and common shares of Gulf Indonesia are publicly traded. In December 2001, Conoco and Cold Spring Finance S.a.r.l. formed Ashford Energy Capital S.A. through the contribution of cash and a Conoco subsidiary promissory note. Cold Spring is entitled to a cumulative annual preferred return based upon current short-term interest rates. A small portion of our return is a preferred return based on short-term interest rates, while the remainder of our return is based on the residual earnings of Ashford Energy. Cold Spring held a $500 net minority interest in Ashford Energy at December 31, 2001. There was no consolidated gain or loss recognized on the formation of Conoco Oil & Gas Associates, Conoco Corporate Holdings, Conoco Gas Holdings or Ashford Energy. Conoco's net income was reduced by minority interest earnings of $23 for 2001, $24 for 2000 and $25 for 1999. Minority interest at December 31, 2001, and December 31, 2000, was $1,204 and $337, respectively. 23. STOCKHOLDERS' EQUITY As described in note 1, Conoco's capital structure was established at the time of the initial public offering in October 1998. On September 21, 2001, Conoco's shareholders approved the combination of our Class A and Class B common stock into a single class of new common stock on a one-for-one basis. As a result of the combination, each outstanding share of Class A and Class B common stock was converted into one share of a new class of common stock. Each shareholder has the same economic ownership of Conoco stock that they had prior to the combination, and each share of the new common stock is entitled to one vote. Prior to the combination, Class B shareholders had five votes per share. The combination was effective on October 8, 2001. The number of shares of common stock issued and outstanding as of December 31, 2000, has been restated to give effect to the combination of the Class A and Class B common stock. There was no effect on previously reported earnings per share amounts. A summary of the activity in common shares outstanding for 1999, 2000 and 2001 is presented as follows:

~~OTHER~~TOTAL ~~POST~~-~~RETIREMENT PENSION BENEFITS BENEFITS~~ -----------~~-----------------------------------------~~ ~~------------------------------~~Common ~~2000~~shares ~~1999~~outstanding ~~1998~~- ~~2000~~December ~~1999~~31, 1998 ~~-------------------~~..................................................... ~~-------------------~~627,791,531 ~~--------~~Purchase ~~--------~~of ~~--------~~shares ~~--------~~for Utreasury(1) .S. ~~INT'L~~. U.S............................................................ ~~INT'L~~(3,494,616) Issued on exercise of stock options and compensation awards from treasury (see note 25) ........... ~~--------~~1,286,519 -------- ----~~----~~ Common shares outstanding -~~-------~~ ~~Service~~December ~~cost~~31, 1999 ..................................................... $625,583,434 35Purchase $of 27shares $for 44treasury(1) $................................................................ 42(3,634,400) $Additional 65shares $issued 7.......................................................................... $466,638 9Shares $purchased 7and ~~Interest~~retired(1) ~~cost~~ ................................................................... 62(223,729) 37Issued 58on 41exercise 94of 25stock 22options 21and ~~Expected~~compensation ~~return~~awards onfrom ~~plan~~treasury ~~assets~~(see note 25) ........... ~~(76)~~1,240,897 ~~(33) (79) (36) (105)~~ -- -- -------- ~~Amortization~~Common ofshares ~~prior~~outstanding ~~service~~- ~~cost~~December ~~(credit)~~31, 2000 ..................................................... ~~(6)~~623,432,840 5Purchase ~~(7)~~of 5shares 9for treasury(41) ~~(4)~~................................................................ (41,258,070) ~~Recognized~~Additional ~~actuarial~~shares ~~loss~~issued ~~(gain)~~ .......................................................................... 4684,443 --Shares 4purchased 5and retired(41) ................................................................... (130,700) 2Issued --on ~~--------~~exercise ~~--------~~of ~~--------~~stock ~~--------~~options ~~--------~~and ~~--------~~compensation awards from treasury (see note 25) ........... 2,830,015 -------- ----~~----~~ ~~Net~~Common ~~periodic~~shares ~~benefit~~outstanding ~~cost~~- December 31, 2001 ..................................................... $625,658,528 ~~19 $ 36 $ 20 $ 57 $ 59 $ 27 $ 29 $ 24~~ ======== ====~~==== ======== ======== ======== ======== ======== ========~~

---------- 92 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) (1) To offset dilution from issuances under compensation plans. Additionally, in February 2001, we commenced a new three-year $1,000 common stock buyback program. The stock buyback program allowed us to repurchase shares from time to time in the open market or possibly, under certain circumstances, through private transactions, as our financial condition and market conditions warranted. The stock buyback program was suspended in May 2001, with our purchase of Gulf Canada. During 2001, we purchased 1,288,770 shares of our common stock at a total cost of $37. At December 31, 2001 and 2000, 250,000,000 shares of preferred stock were authorized. Of this amount, 1,000,000 shares were designated as Series A Junior Participating Preferred Stock and reserved for issuance on the exercise of preferred stock purchase rights under Conoco's Share Purchase Rights Plan. Each issued share of common stock has one preferred stock purchase right attached to it. No preferred shares have been issued, and the rights currently are not exercisable. The purchase rights would generally become exercisable under the direction of our board of directors, if a person or group acquires 15 percent or more of the company's common stock or announces a tender offer that would result in a person becoming an acquiring person. In connection with the separation from DuPont, Conoco recorded in additional paid-in capital a net increase of $93 and a $26 charge in 2001 and 1999, respectively. These are included in additional paid-in capital as an adjustment to capitalization from DuPont (see note 32). Dividends declared and paid on common stock for 2001 and 2000 are shown as follows:

~~OTHER~~2001 ~~POST-RETIREMENT PENSION BENEFITS BENEFITS -------------------------------------------- --------------------~~ 2000 ~~1999 2000 1999~~ ----------~~----------~~ ----------~~----------~~ ~~--------~~First ~~--------~~quarter U.S. ~~INT'L~~. U.S. ~~INT'L~~. ~~-------- -------- -------- -------- CHANGE IN BENEFIT OBLIGATION Benefit obligation at beginning of year~~ ................. ~~$ 834 $ 679 $ 113 $ 753 $ 323 $ 350 Adjustment to include U~~.S. ~~qualified plan balance~~ ....... ~~-- -- 871 -- -- -- -------- -------- -------- -------- -------- -------- Adjusted benefit obligation at beginning of year~~......... ~~834 679 984 753 323 350 Service cost~~ ......................~~......................~~ 35$ ~~27 44 42 7 9 Interest cost~~ .~~..........................................~~19 62$ ~~37 58 41 25 22 Exchange gain~~ .~~..........................................~~19 --Second ~~(58)~~quarter ~~-- (24) -- -- Participant contributions~~ ............................... ~~-- -- -- -- 4 4 Actuarial (gain) loss~~ ...............................~~....~~ ~~(2) 17 (151) (104) 46 (32) Divestitures and other~~ .~~.................................~~19 ~~-- 18 13 -- -- (5) Benefits paid~~ .~~..........................................~~19 ~~(74)~~Third ~~(22)~~quarter ~~(114) (29) (31) (25) -------- -------- -------- -------- -------- -------- Benefit obligation at end of year~~ ....................... ~~$ 855 $ 698 $ 834 $ 679 $ 374 $ 323 ======== ======== ======== ======== ======== ======== CHANGE IN PLAN ASSETS Fair value of plan assets at beginning of year~~ .......... ~~$ 884 $ 494 $ -- $ 438 $ -- $ -- Adjustment for fair value of U~~.S. ~~qualified plan assets~~.. ~~-- -- 878 -- -- -- -------- -------- -------- -------- -------- -------- Adjusted fair value of plan assets at beginning of year~~ ..........................~~.......................~~ ~~884 494 878 438 -- -- Actual return on plan assets~~ .~~...........................~~19 ~~(29) 49 130 59 -- -- Employer contribution~~ .~~..................................~~19 17Fourth 29quarter ~~6 32 26 21 Participant contributions~~ ............................... ~~-- -- -- -- 5 4 Exchange gain~~ ...............................~~............~~ ~~-- (40) -- (14) -- -- Divestitures and other~~ .~~.................................~~19 ~~-- 10 (16) -- -- -- Benefits paid~~ .~~..........................................~~19 ~~(74) (18) (114) (21) (31) (25)~~ -------- --~~------~~ -------- --~~------~~ ~~--------~~Dividends ~~--------~~per ~~Fair~~share ~~value of plan assets at end of year~~ ................ ~~$ 798 $ 524 $ 884 $ 494 $ -- $ -- ======== ======== ======== ======== ======== ======== Funded status of plans at end of year~~ ................... ~~$ (57) $ (174) $ 50 $ (185) $ (374) $ (323) Transition asset~~ ......................~~..................~~ (15) (6) (23) (14) -- -- Unrecognized actuarial (gain) loss ...................... 55 12 (41) 12 62 15 Unrecognized prior service cost (credit) ................ 11 81 13 94 (41) (45) -------- -------- -------- -------- -------- -------- Net amount recognized at end of year .................... $ ~~(6) $ (87) $ (1) $ (93) $ (353) $ (353) ======== ======== ======== ======== ======== ======== AMOUNTS RECOGNIZED IN CONSOLIDATED BALANCE SHEET AT END OF YEAR Prepaid benefit (see note 13)~~ .~~..........................~~76 $ ~~5 $ -- $ 13 $ -- $ -- $ -- Accrued benefit liability Short-term (see note 16)~~ .~~.............................~~76 -- -- -- -- (18) (18) Long-term (see note 18) ............................... (69) (115) (58) (142) (335) (335) Deferred pension transition obligation (see note 13)..... 5 28 5 49 -- -- Accumulated other comprehensive loss (1) ................ 53 -- 39 -- -- -- -------- -------- -------- -------- -------- -------- Net amount recognized ................................... $ (6) $ (87) $ (1) $ (93) $ (353) $ (353) ======== ==~~======~~ ======== ==~~====== ======== ========~~

Conoco declared a first quarter cash dividend on January 24, 2002, of $.19 per share on each outstanding share of common stock. This quarterly dividend will be paid on March 10, 2002, to all shareholders of record as of February 10, 2002. 24. ACCUMULATED OTHER COMPREHENSIVE LOSS Balances of related after-tax components comprising accumulated other comprehensive loss are summarized in the following table:

~~OTHER~~DECEMBER ~~POST-RETIREMENT~~31 ~~PENSION BENEFITS BENEFITS~~ --------------------------~~---------------------~~ ~~--------------------~~2001 2000 ~~1999 2000 1999~~ ----------~~-------------~~ ----------~~--------~~ ~~---------~~Foreign ~~---------~~currency ~~U.S.~~translation ~~INT'L.~~adjustment U.S. ~~INT'L~~. ~~------ ------- ------ ------- WEIGHTED-AVERAGE ASSUMPTIONS AT END OF YEAR Discount rate~~..................................~~...~~ ~~7.50%~~$ ~~6.00%~~(928) ~~7.75%~~$ ~~6.00%~~(619) ~~7.50%~~Minimum ~~8.00%~~pension ~~Rate~~liability ofadjustment ~~compensation~~(see ~~increase~~note 26) ..................... 4.~~60% 4~~.~~50% 5~~.~~20% 4~~.~~50% 4~~.~~60%~~ ~~5.15%~~(53) ~~Expected~~(34) ~~return~~Unrealized gains on ~~plan~~derivatives ~~assets~~(see note 9) .................... 9.~~00% 7~~.~~00% 9~~.~~00% 7~~.~~00%~~........ 87 -- ---------- ~~Health~~---------- ~~care~~Accumulated ~~escalation~~other ~~rate~~comprehensive loss ........................................ --$ --(894) --$ --(653) ~~4.50%~~========== ~~4.50%~~==========

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

~~FAIR~~YEAR ~~CARRYING~~ENDED ~~NOTIONAL~~DECEMBER ~~VALUE~~31 ~~AMOUNT~~---------------------------------------------------------------------------------------- ~~VALUE~~2001 2000 1999 --------------------------- --------------------------- ---------------------------- ~~COMMODITY~~INCOME ~~DERIVATIVES~~INCOME ~~(1)~~INCOME ~~December~~PRETAX ~~31,~~TAX ~~2000~~AFTER-TAX ~~Trading~~PRETAX TAX AFTER-TAX PRETAX TAX AFTER-TAX ------ ------ --------- ------ ------ --------- ------ ------ --------- Foreign currency translation adjustment .....................~~................~~ $ 6(329) $ 6(20) $ ~~811~~(309) ~~Non-trading~~$ (2355)~~.............................~~ $ ~~185~~(83) $ ~~125~~(272) $ ~~1,606~~(191) ~~December~~$ ~~31,~~(29) ~~1999~~$ ~~Trading~~(162) Minimum pension liability adjustment ..................... (27) (8) (19) (14) (5) (9) 93 29 64 Unrealized gains on derivatives ... 141 54 87 -- -- -- -- -- -- ------ ------ --------- ------ ------ --------- ------ ------ --------- Other comprehensive loss ..........~~...~~ $ 10(215) $ 1026 $ ~~529~~(241) ~~Non-trading.................................~~$ (369) $ 6(88) $ 5(281) $ ~~464~~(98) $ -- $ (98) ====== ====== ========= ====== ====== ========= ====== ====== =========

Conoco recorded an after-tax gain of $87 into other comprehensive income from derivatives during 2001. This gain includes an after-tax gain of $92 related to derivative instruments designated as cash flow hedges of certain forecasted sales of crude oil and natural gas and a net after-tax charge of $5 due to changes in the fair values of 93 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) derivative instruments designated as cash flow hedges of variable interest rate obligations. During the next 12-month period, all of the $92 after-tax gain associated with the forecasted sales of crude oil and natural gas, as well as an immaterial portion of the $5 net after-tax charge related to variable interest rate obligations, is expected to be reclassified into income. 25. COMPENSATION PLANS TRANSITION FROM DUPONT PLANS TO CONOCO PLANS Until the date of the initial public offering, employees of Conoco participated in stock-based compensation plans administered through DuPont. Conoco employees held a total of 10,964,917 stock options for DuPont common stock and 1,333,135 stock appreciation rights (SARs) with respect to DuPont common stock. At the time of the initial public offering, Conoco gave those persons the option, subject to specific country tax and legal requirements, to participate in a program involving the cancellation of all or part of their DuPont stock options or SARs and replacement with Conoco options or SARs. The substitute stock options and other awards had the same total intrinsic value, vesting provisions, option periods and other terms and conditions as the DuPont options and awards they replaced. A total of 8,921,508 DuPont stock options and 745,358 DuPont SARs were cancelled and replaced by 24,275,690 stock options for Conoco common stock and 2,279,834 SARs with respect to Conoco common stock. DuPont retained responsibility for delivery of DuPont common stock to Conoco employees for DuPont stock options not cancelled. Of the converted options, 1,724,146 were variable options for which a threshold price of $32.88 (closing price for five consecutive days) had to be reached within five years of the grant date in order to become exercisable. In 2001, the time deadline to reach the threshold price was extended by two years. Of these options, 392,846 were granted to the Chief Executive Officer (CEO). Due to an application of a vesting provision in the CEO's employment contract, these 392,846 options have been reclassified as fixed options. AWARDS UNDER CONOCO PLANS The 1998 Stock and Performance Incentive Plan provides incentives to certain corporate officers and non-employee directors who can contribute materially to the success and profitability of Conoco and its subsidiaries. Awards may be in the form of cash, stock, stock options or SARs with respect to Conoco common stock. This plan also provides for the Conoco Global Variable Compensation Plan. The Conoco Global Variable Compensation Plan is an annual management incentive program for officers and certain non-officer employees with awards made in cash and stock. Stock options and SARs granted under the 1998 Stock and Performance Incentive Plan: o are awarded at market price on the date of grant; o have a 10-year life; o generally vest one year from date of grant; and o may be subject to exercise restrictions, such as the attainment of specific stock price targets or the passage of time. For some senior management, certain shares can be deferred as stock units for a designated future delivery. In 1999, a variable option grant to acquire 1,400,000 shares of common stock was made to Conoco's Chairman, President and CEO. Of this grant, 50 percent was subject to forfeiture if, within three years from the date of grant, the market price of Conoco common stock did not achieve a price of $35.00 per share for five consecutive days. The remaining 50 percent of the grant was subject to forfeiture if, within five years from the date of grant, the market price of Conoco common stock did not achieve a price of $42.00 per share for five consecutive days. The exercise price was $26.50, which was the market price on the grant date. In 2001, due to an extension of the time deadline to reach the threshold price for 700,000 options and application of a vesting provision in the CEO's employment contract, all 1,400,000 options were reclassified as fixed options. Prior to 2001, the maximum number of shares of common stock and stock options granted under the plan was limited to the highest of 20,000,000 or 3.3 percent of outstanding shares of common stock. In September 2001, the plan was amended to increase the number of shares that may be granted. The maximum number of shares of 94 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) common stock and stock options granted under the plan is now limited to 31,397,830. At December 31, 2001, 19,953,208 shares and at December 31, 2000, 12,028,155 shares of common stock were available for issuance under the plan. Conoco adopted the 1998 Key Employee Stock Performance Plan to attract and retain employees. The plan will accomplish this by enhancing the proprietary and personal interests of employees in Conoco's success and profitability. Awards to employees may be in the form of Conoco stock options or SARs, both with respect to common stock. Such awards granted under this plan are awarded under the same terms and conditions of the 1998 Stock and Performance Incentive Plan as described above. Prior to 2001, the maximum number of shares of common stock and stock options granted under the plan was limited to the higher of 18,000,000 or 3 percent of outstanding shares of common stock. In September 2001, the plan was amended to increase the number of shares that may be granted. The maximum number of shares of common stock and stock options granted under the plan is now limited to 37,580,628. At December 31, 2001, 24,879,789 shares of common stock were available for issuance under the plan, while at December 31, 2000, 10,556,261 shares of common stock were available for issuance under the plan. Under both the 1998 Stock and Performance Incentive Plan and the 1998 Key Employee Stock Performance Plan, reload options are available for certain managers upon the exercise of stock options. Reload provisions associated with options considered to be fixed were contained in the original terms of the plans and have not been modified. These reload options include a condition that shares received from the exercise of the original option may not be sold for at least two years. Under a reload option, the number of new options granted is equal to the number of shares required to satisfy the total exercise price of the original option. Reload options are granted at the market price of the stock on the reload grant date. The 1998 Global Performance Sharing Plan is a broad-based plan under which, on the date of the initial public offering, grants of stock options and SARs with respect to common stock were made to certain non-officer employees. This was done to encourage a sense of proprietorship and an active interest in the financial success of Conoco and its subsidiaries. The stock options and SARs: o were awarded at the price of the initial public offering ($23.00 per share); o have a 10-year life; and o become exercisable in one-third increments on the first, second and third anniversaries of the grant date. Currently, there are no additional shares available for issuance under this plan. The 2001 Global Performance Sharing Plan is a broad-based plan under which grants of stock options and SARs with respect to common stock were made to certain non-officer employees. This was done to encourage a sense of proprietorship and an active interest in the financial success of Conoco and its subsidiaries. The stock options and SARs: o were awarded at the market price of stock at the award date ($29.15 per share); o have a 10-year life; and o become exercisable at the earliest of when Conoco stock closing price is $36.25 or above for five consecutive days, or six months before the expiration date of the options. Most stock options granted under Conoco plans are fixed and have no intrinsic value at grant date. The exceptions to this fixed status are the 1,724,146 options granted to substitute for cancelled DuPont options granted in 1997 and the 1,400,000 options granted on August 17, 1999. 95 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) The following table summarizes activity for fixed and variable options for the last three years:

~~UPSTREAM~~FIXED ~~DOWNSTREAM~~VARIABLE -------------------- --------- ----------- ~~EMERGING ELIMINA~~- ~~CONSOLI~~- ~~SEGMENT INFORMATION U.S. INT'L. U.S. INT'L. BUSINESSES CORPORATE TIONS DATED~~ -------- ------- NUMBER WEIGHTED- NUMBER WEIGHTED- OF AVERAGE OF AVERAGE SHARES PRICE SHARES PRICE ------- ---- ---- -------- -- --------- ----------- -~~-------~~ ~~2000~~December ~~Sales~~31, ~~and other operating revenues (2) Refined products~~ 1998................. $32,177,923 -- $ --17.14 ~~$ 12~~1,~~343 $ 11~~724,~~284~~146 $ --19.18 $Granted ~~-- $ -- $ 23,627 Crude oil~~ ....................... 1630,689 27.46 1,~~627 4~~400,~~754~~000 ~~497~~26.50 --Exercised ~~-- -- 6,894 Natural gas~~ ..................... ~~4,099~~ (1,~~686~~225,424) --12.37 -- -- --Forfeited ~~-- 5,785 Other~~ .....................~~.....~~ 1(133,~~416~~929) ~~353~~22.28 ~~282 376 4~~ -- -- ~~2,431~~ -------- ---~~-----~~ -------- --~~------~~ ~~--------~~December ~~--------~~31, ~~-----------~~1999 ~~-------- Total~~ ................~~.....~~ 530,~~531 3~~849,~~666~~259 17~~,379~~.31 123,~~157 4 -- -- 38~~124,~~737~~146 ~~Transfers between segments~~ 22.~~.......~~46 ~~740~~Granted ~~831 177 644 -- -- (2,392) -- -------- -------- -------- -------- -------- -------- ----------- -------- Total operating revenues~~ .......... ~~$ 6,271 $ 4,497 $ 17,556 $ 12,801 $ 4 $ -- $ (2,392) $ 38,737 ======== ======== ======== ======== ======== ======== =========== ======== Operating profit~~ .............~~.....~~ ~~$ 1~~6,~~051 $ 2~~419,~~103~~256 ~~$ 208 $ 344 $ (89) $ (159) $ -- $ 3,458 Equity in earnings of affiliates~~ 21..31 ~~20 230 53 (26)~~ -- -- --Exercised ~~277 Corporate non-operating items Interest and debt expense~~ ...... ~~-- -- -- -- -- (338) -- (338) Interest income (net of misc~~. ~~interest expense)~~ .............. --(1,406,597) --10.47 -- -- --Forfeited ~~39 -- 39 Other~~ .....................~~.....~~ --(170,785) --20.54 -- -- -- 22 -- 22 -------- -------- --~~------~~ ~~--------~~December ~~--------~~31, ~~--------~~2000 ~~----------- -------- Income before income taxes~~ ................ 135,~~071 2~~691,~~333~~133 ~~261~~18.29 ~~318 (89) (436) --~~ 3,~~458~~124,146 ~~Provision~~22.46 ~~for~~Granted ~~income taxes~~ ........ ~~(352) (1,185) (79) (88) 20 128 -- (1,556) -------- -------- -------- -------- -------- -------- ----------- -------- Net income (loss) (1)~~ ............... ~~$ 719 $ 1~~7,~~148~~840,895 $29.44 ~~182~~-- ~~$ 230 $ (69) $ (308) $~~ -- $Issued ~~1,902~~in ~~========~~exchange ~~========~~for ~~========~~Gulf ~~========~~Canada ~~========~~options ~~======== =========== ======== Capital employed at December 31 (3) Excluding investment in affiliates~~ .............~~.......~~ ~~$ 2~~132,~~501~~571 ~~$ 3,278 $ 1,265 $ 918 $ 27 $ 202 $ -- $ 8,191 Investment in affiliates (4)~~ 19...07 ~~162 865 285 490 29~~ -- -- ~~1,831~~Reclassified ~~-------- -------- -------- -------- -------- -------- ----------- -------- Total capital employed~~ .................. ~~$ 2~~1,~~663 $ 4~~792,~~143~~846 $24.90 (1,~~550 $ 1~~792,~~408 $ 56 $ 202 $ -- $ 10,022 ======== ======== ======== ======== ======== ======== =========== ======== Return on capital employed (ROCE~~846) ~~(5)~~24.90 Exercised ...................... ~~25.9%~~(3,460,154) ~~30.2%~~ 12.9%14 ~~18.0% N/A N/A~~ -- ~~23.1% Significant non~~-~~cash~~- ~~items~~Forfeited ~~DD&A~~ .....................~~.......~~ ~~$ 412 $ 611 $ 136 $ 138 $ -- $ 4 $ -- $ 1~~(144,~~301~~528) ~~Dry hole costs and impairment of unproved properties~~ 24.~~..........~~66 ~~$ 44 $ 44 $~~ -- $ -- $ -- $ -- $ -- ~~$ 88 Inventory write~~-~~down to market .. $~~ -- $ -- $ -- ~~$ 24 $~~ -- $ -- $ -- ~~$ 24 Capital expenditures and investments (6) ................. $ 667 $ 1,486 $ 344 $ 201 $ 72 $ 26 $~~ -- $December 231,~~796~~ ~~Total~~2001 ~~assets~~ ................~~......~~ ~~$ 3~~41,~~733 $ 7~~852,~~195~~763 $21.15 31,~~461 $ 2~~331,~~925~~300 ~~$ 88 $ 725 $ -- $~~ 19.18~~,127~~

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

~~UPSTREAM~~EXERCISE ~~DOWNSTREAM~~PRICE -------------------- -------------------- ~~SEGMENT INFORMATION EMERGING ELIMINA~~- ~~CONSOLI~~- ~~U.S. INT'L. U.S. INT'L. BUSINESSES CORPORATE TIONS DATED~~ -------- -------- -------- ---~~-----~~ ~~---------- --------- ---------- -------- 1999 Sales and other operating revenues (2) Refined products~~ $8.~~..............~~40 $ -- $12.78 -- $19.17 ~~7,771 $ 9,253 $~~ -- $29.15 -- $ ~~-- $ 17,024 Crude oil ......................~~ 10 ~~1,101 3,165 621 -- -- -- 4,897 Natural gas~~ .~~...................~~42 ~~2,436 1,033 -- -- -- -- -- 3,469 Other~~ $18.~~.........................~~31 863 113 255 390 28 -- -- 1,649 -------- -------- -------- -------- -------- -------- ---------- -------- Total ..................... 3,309 2,247 11,191 10,264 28 -- -- 27,039 Transfers between segments ........ 435 476 106 325 -- -- (1,342) -- -------- -------- -------- -------- -------- -------- ---------- -------- Total operating revenues .......... $ ~~3,744 $ 2,723 $ 11,297 $ 10,589 $~~ 28 ~~$ -- $ (1,342) $ 27,039 ======== ======== ======== ======== ======== ======== ========== ======== Operating profit~~ .~~.................~~55 $ ~~381 $ 891 $ 110 $ 192 $ (54) $ (154) $ -- $ 1,366 Equity in earnings of affiliates~~ 31..21 ~~8 94 55 (7)~~ -- -- -- ~~150 Corporate non~~-~~operating items Interest and debt expense ......~~ -- -- -- -- -- ~~(311)~~ -- ~~(311) Interest income (net of misc. interest expense) .............~~ -- -- -- -- -- 25 -- ~~25 Other ..........................~~ -- -- -- -- -- ~~(13)~~ -- ~~(13)~~ -~~-------~~ -------- -------- ~~--------~~Options ~~--------~~outstanding ~~-------- ---------- -------- Income before income taxes~~ ........ ~~389 985 165 185 (54) (453) -- 1~~5,217 Provision for income taxes ........ (67) (451) (46) (56) 19 128 -- (473) -------- -------- -------- -------- -------- -------- ---------- -------- Net income (loss) (1) ............. $ 322 $ 534 $ 119 $ 129 $ (35) $ (325) $ -- $ 744 ======== ======== ======== ======== ======== ======== ========== ======== Capital employed at December 31 (3) Excluding investment in affiliates .................... $ 2517,~~509~~691 $ 2,~~840 $ 1~~644,~~311~~842 ~~$ 890 $ 50 $ 94 $ -- $ 7~~25,~~694 Investment in affiliates (4) ... 166 620 260 526 32 -- -- 1~~968,~~604~~804 ~~-------- -------- -------- -------- -------- -------- ---------- -------- Total capital employed ............ $ 2~~7,~~675 $ 3~~721,~~460~~426 ~~$ 1,571 $ 1,416 $ 82 $ 94 $~~ Weighted--average $remaining ~~9,298~~contractual ~~========~~life ~~======== ======== ======== ======== ======== ========== ======== Return on capital employed~~ (~~ROCE~~years) ~~(5)~~ ..~~....................~~ 122.3%61 164.0%23 86.9%65 89.8%08 ~~N/A N/A~~ Weighted--average ~~11.1%~~price ~~Significant non-cash items DD&A~~ .....~~......................~~ $ ~~374 $ 547 $ 126 $ 142 $ -- $ 4 $ -- $ 1,193 Dry hole costs and impairment of unproved properties~~ 9.~~..........~~84 $ ~~16 $ 115 $ -- $ -- $ -- $ -- $ -- $ 131 Capital expenditures and investments(6)~~ 14.~~.................~~35 $ ~~413 $ 839 $ 214 $ 248 $ 69 $ 4 $ -- $ 1,787 Total assets~~ 21.~~.....................~~77 $ ~~3,502 $ 5,949 $ 3,287 $ 2,835 $ 91 $ 711 $ -- $ 16,375 1998 Sales and other operating revenues (2) Refined products~~ 29.~~..............~~46 $Options --exercisable ~~$ -- $ 6,082 $ 7,647 $ -- $ -- $ -- $ 13,729 Crude oil~~ ........~~..............~~ ~~14 774 2~~5,~~650 299 -- -- -- 3~~517,~~737~~691 ~~Natural gas ....................~~ 2,~~416 723 -- -- -- -- -- 3~~644,~~139~~842 ~~Other .......................... 770 104 217 351 729 20 -- 2~~23,~~191 -------- -------- -------- -------- -------- -------- ---------- -------- Total ..................... 3~~690,~~200~~960 129,~~601~~099 ~~8,949 8,297 729 20~~ Weighted--average ~~22,796~~price ~~Transfers between segments~~ .....~~...~~ ~~308 378 89 181 -- -- (956) -- -------- -------- -------- -------- -------- -------- ---------- -------- Total operating revenues ..........~~ $ ~~3,508 $ 1,979 $~~ 9~~,038 $ 8,478 $ 729 $ 20 $ (956) $ 22,796 ======== ======== ======== ======== ======== ======== ========== ======== Operating profit~~ .~~.................~~84 $ ~~229 $ 482 $ 157 $ 256 $ (47) $ (346) $ -- $ 731 Equity in earnings of affiliates .. 1 (~~14~~) 56 (20) (1) -- -- 22 Corporate non-operating items Interest and debt expense~~ .~~.....~~35 --$ ~~-- -- -- -- (199) -- (199) Interest income (net of misc~~21. ~~interest expense) ............. -- -- -- -- -- 89 -- 89 Other .......................... -- -- -- -- --~~ 51 -- 51 -------- -------- -------- -------- -------- -------- ---------- -------- Income before income taxes ........ 230 468 213 236 (48) (405) -- 694 Provision for income taxes ........ (7) (185) (72) (80) 17 83 -- (244) -------- -------- -------- -------- -------- -------- ---------- -------- Net income (loss) (1) ............. $ ~~223 $ 283 $ 141 $ 156 $ (31) $ (322) $ -- $ 450 ======== ======== ======== ======== ======== ======== ========== ======== Capital employed at December 31 (3) Excluding investment in affiliates~~ 30.................... $ 2,349 $ 2,849 $ 1,245 $ 989 $ 2 $ 382 $ -- $ 7,816 Investment in affiliates (4) ... 191 371 248 531 22 -- -- 1,363 -------- -------- -------- -------- -------- -------- ---------- -------- Total capital employed ............ $ 2,540 $ 3,220 $ 1,493 $ 1,520 $ 24 $ 382 $ -- $ 9,179 ======== ======== ======== ======== ======== ======== ========== ======== Return on capital employed (ROCE) (5) ...................... 9.3% 8.9% 13.6% 10.9% N/A N/A -- 10.3%03

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

~~UPSTREAM~~2001 ~~DOWNSTREAM~~2000 ~~-------------------~~1999 --------------~~-----~~ ~~EMERGING ELIMINA~~- ~~CONSOLI~~- ~~SEGMENT INFORMATION U.S. INT'L. U.S. INT'L. BUSINESSES CORPORATE TIONS DATED~~ -------- ------- -------- ------- -~~---------~~ ~~---------~~Options ~~--------~~exercisable ~~--------~~at ~~1998 (CONTINUED) Significant non~~year-~~cash~~end ~~items~~Number ~~DD&A~~of shares ...................... ~~$ 383 $ 457 $ 139 $ 133 $ -- $ 1 $ -- $ 1,113 Dry hole costs and impairment of unproved properties~~ ............... $31,882,592 5925,443,830 $22,481,408 ~~104 $~~ Weighted--average $price ~~-- $ -- $ -- $ -- $ 163 Stock option provision~~ .... ~~$ -- $ -- $ -- $ -- $ -- $ 236 $ -- $ 236 Inventory write-down to market~~ ........................... $ 618.90 $ --16.85 $ 6315.31 ~~$ 28 $~~ Weighted--average $fair --value $of --options $granted 97during ~~Capital~~the ~~expenditures~~year ~~and investments (6)~~............. ~~$ 788 $ 1,177 $ 201 $ 332 $ 1 $ 17 $ -- $ 2,516 Total assets~~ ................................ $ ~~3,653~~8.64 $ ~~5,693 $ 2,805 $ 2,815 $~~ 6.14 $ ~~1,095 $ -- $ 16,075~~6.85

The incremental fair value of Conoco variable options with a hurdle price of $32.88 per share was assumed to be zero. Except for the $2 related to the conversion of the CEO's variable options to fixed, no compensation expense has been recognized for fixed options. 96 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) The fair value of options is calculated using the Black-Scholes option-pricing model. Assumptions used were as follows:

~~2000~~CONOCO ~~1999~~OPTIONS(1) ~~1998~~ ---------- ------------------ 2001 2000 1999 ------- ------- ~~Buy/sell~~------- ~~supply~~NEW ~~transactions~~NEW ~~settled~~NEW in------- ~~cash~~------- ~~Crude~~------- ~~oil~~Dividend yield ........... 3.3% 3.~~.....................~~3% ~~$ 4,786 $~~ 3~~,282~~.3% $Volatility ~~2,728 Refined products~~............... 30.0% 30.0% 25.~~.........~~0% $Risk-free ~~1,703~~interest ~~$ 747 $ 438 Natural gas resales~~rate... 5.~~........................~~3% ~~$ 2,551 $~~ 5.1~~,242~~% $5.8% ~~1,109~~Expected ~~Electric~~life ~~power~~(years) ~~resales~~.... 6.0 6.~~...................~~0 ~~$ 4 $ 28 $ 729~~6.0

---------- (1) For 2001 and 2000, Conoco's historical volatility is used. However, due to insufficient history, the volatility of Conoco stock was estimated by referencing oil industry experience trends in 1999. The expected life for exercise of Conoco stock options was estimated by using DuPont experience trends. The following table sets forth pro forma information as if we had adopted the optional recognition provisions of SFAS No. 123 (see note 2):

~~OTHER~~2001 ~~GEOGRAPHIC~~2000 ~~INFORMATION~~1999 ~~U.S. U.K. GERMANY NORWAY COUNTRIES CONSOLIDATED~~ ------- ---~~-----~~ ------- ---~~----~~ --------- -~~-----------~~ ~~2000~~Increase ~~Sales and other operating revenues~~ (1decrease)~~.........~~ ~~$22,914~~in ~~$7,851~~Net ~~$3,606~~income ~~$ 474 $3,892 $38,737 Long-lived assets at December 31 (2)~~........... $ ~~5,492~~(46) $~~3,662~~ $(28) ~~143~~ $~~1,473~~ ~~$1,437 $12,207 1999 Sales and other operating revenues~~ (118)~~.........~~ ~~$14,528~~Earnings ~~$5,950~~per ~~$3,150~~share $Basic ~~330 $3,081 $27,039 Long-lived assets at December 31 (2)~~............ $ ~~5,192~~(.07) $~~3,265~~ ~~$ 154 $1,574 $1,050 $11,235 1998 Sales and other operating revenues~~ (1).~~........~~04) $~~12,878~~ ~~$4,305 $2,881 $ 289 $2,443 $22,796 Long-lived assets at December 31~~ (2.03) Diluted ........... $ ~~5,122~~(.07) $~~3,577~~ $(.04) ~~195~~ $~~1,547~~ ~~$ 972 $11,413~~(.03)

The incremental fair value for cancellation and substitution of stock options originally granted before adoption of SFAS No. 123 was zero because intrinsic value exceeds fair value. Compensation expense recognized in income for stock-based employee compensation awards was $6 for 2001, $4 for 2000 and $24 for 1999. Prior to the initial public offering, the Conoco Unit Option Plan awarded SARs with respect to DuPont common stock to key salaried employees in certain grade levels who showed early evidence of the ability to assume significant responsibility and leadership. At the time of the initial public offering, 1,131,494 unit options were outstanding, of which 593,722 were cancelled and substituted with comparable SARs with respect to Conoco common stock under Conoco's 1998 Key Employee Stock Performance Plan. Effective with the initial public offering, no new grants were made or are planned out of the Conoco Unit Option Plan. At December 31, 2001, outstanding unit options based on common stock were 1,150,975, and at December 31, 2000, outstanding unit options based on common stock were 1,330,485. For these same time periods, outstanding unit options based on DuPont common stock were 346,724 and 403,115, respectively. The related liability provisions totaled $16 at December 31, 2001, and $21 at December 31, 2000. Through the date of the initial public offering, certain Conoco employees who participated in the DuPont Variable Compensation Plan received grants of stock and cash. Overall amounts were dependent on financial performance of DuPont and Conoco and other factors and were subject to maximum limits as defined by the plan. Amounts charged against earnings in anticipation of awards to be made later were $39 in 1998. Actual cash and stock awards made in 1999 for the 1998 plan year totaled $24. These awards were made out of the Conoco 1998 Stock and Performance Incentive Plan based on performance standards set previously in the DuPont Variable Compensation Plan. Both the DuPont Variable Compensation Plan and the Conoco 1998 Stock and Performance Incentive Plan allow future delivery of stock awards. Beginning with the 1999 plan year, grants of stock and cash were made from the Conoco 1998 Stock and Performance Incentive Plan according to the financial performance of Conoco and its business units. Awards are subject to maximum limits as defined by the plan. Amounts charged against earnings during 2001 in anticipation of awards to be made in 2002 were $49, while amounts charged against earnings during 2000 in anticipation of awards to be made in 2001 were $62. Under the Conoco 1998 Stock and Performance Incentive Plan, employees were offered the opportunity to cancel DuPont shares, which were granted under previous awards, and receive substitute shares of Conoco Class A 97 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) common stock for designated future delivery. At December 31, 2001, 54,421 shares of DuPont stock and 329,572 shares of Conoco common stock were awaiting delivery. Conoco recognized a liability of $2 for the delivery of DuPont shares. Awards under the separate Conoco Challenge Program may be granted in cash to employees not covered by the Variable Compensation Plan. This plan provides awards based on meeting financial goals and upholding our core values. Overall amounts are dependent on Conoco's earnings and cash provided by operations. Beginning with the 1999 plan year, awards also are adjusted up or down based on a measure of Conoco's shareholder return as compared to a group of selected benchmark competitors. All payout amounts are subject to maximum limits as defined by the plan. Amounts charged against earnings for the current year and to adjust for over/under accruals in prior years totaled $47 for 2001, $63 in 2000 and $40 in 1999. GULF CANADA FIXED OPTIONS At the time of the acquisition offer, Gulf Canada employees holding Gulf Canada options were given the opportunity to convert those options to Conoco options with comparable intrinsic value, terms and conditions. Accordingly, 473,112 Gulf Canada options were converted to 132,571 Conoco options. All Gulf Canada options not converted (approximately 21 million) were exercised immediately prior to the acquisition and the resulting shares were included as part of the purchase price. 26. PENSIONS AND OTHER POST-RETIREMENT BENEFITS Prior to the split-off, Conoco participated in the DuPont U.S. tax-qualified defined-benefit pension plan. In 1999, Conoco established a U.S. tax-qualified defined-benefit pension plan (Conoco plan), which was spun off from the DuPont U.S. tax-qualified defined-benefit pension plan. In 2000, DuPont transferred cash and assets valued at $858 to fund the plan. The Conoco plan covers substantially all U.S. non-retail employees, as well as about half of all U.S. retail employees. In addition, Conoco has separate U.S. non-tax-qualified defined-benefit pension plans covering certain U.S. and international employees. The benefits for the plans mentioned in this paragraph are based primarily on years of service and the average of the employee's highest 36 consecutive months' pay. Conoco's funding policy for the U.S. tax-qualified plan is consistent with the funding requirements of federal laws and regulations. The nonqualified plans are not funded. In 1999, however, we set up a "Rabbi Trust," which may be funded in the future. A Rabbi Trust sets aside assets to pay for benefits under a nonqualified pension plan, but those assets remain subject to claims of our general creditors in preference to the claims of plan participants and beneficiaries. The trust is currently not active and is funded with $2 cash that is consolidated in our financial statements. Pension coverage is provided to the extent appropriate for employees of our international subsidiaries through separate plans. Obligations under such plans are systematically provided for by depositing funds with trustees, under insurance policies or by book reserves. Conoco and certain subsidiaries also provide medical and life insurance benefits to U.S. retirees and survivors. The associated plans, principally health, are not funded, and approved claims are paid from Conoco's funds. Under the terms of these plans, we reserve the right to change, modify or discontinue the plans. We have communicated to plan participants that any increase in the annual health care escalation rate above 4.5 percent will be borne by the participants. However, for 2002 we approved a one-year increase to Conoco's contributions to 9.0 percent. Because cost increases for years prior to 2002 were less than 4.5 percent, the overall average through 2002 does not exceed 4.5 percent. As a result, we do not expect a material increase to the accumulated post-retirement benefit obligation or the other post-retirement benefit cost. 98 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE)

~~TOTAL~~PENSION ~~WORLDWIDE~~BENEFITS ~~UNITED STATES EUROPE~~ OTHER ~~REGIONS~~POST-RETIREMENT BENEFITS ----------------------- ------------------------ ---------------- ------ ------------------------~~---~~ ~~2000~~2001 ~~1999 1998~~ 2000 1999 ~~1998~~2001 2000 1999 ~~1998 2000 1999 1998~~ ------ ------ ------ ------ ------ ------- ------ ------ ------- -------- -------- ------- ~~CONSOLIDATED COMPANIES Revenues Sales~~ U.S.~~..........~~ ~~$3,494 $2,389 $1,938 $1,022 $ 646 $ 643 $1,573 $1,192 $ 831 $ 899 $ 551 $ 464 Transfers~~ INT'L.~~.......~~ ~~1,420 862 646 688 384 272 731 478 374 1 -- -- Exploration (1)~~ U.S.~~....~~ ~~(279) (270) (380) (121) (64) (128) (59) (62) (108) (99) (144) (144) Production~~ INT'L.~~..........~~ ~~(872) (851) (806) (324) (287) (303) (369) (433) (382) (179) (131) (121) DD&A~~ U.S.~~...............~~ ~~(973) (887) (799) (366) (338) (345) (526) (491) (372) (81) (58) (82) Other (2)~~ INT'L.~~...........~~ ~~63 18 148 (27) 13 104 73 6 48 17 (1) (4) Income taxes ......... (1,390) (501) (201) (293) (87) (36) (698) (272) (100) (399) (142) (65)~~ ------ --~~----~~ ------ -~~-----~~ ------ --~~----~~ ------ --~~----~~ ------ --~~-----~~ ------- -~~------~~ ~~Results~~Service ~~of Operations~~ cost.................. ~~1,463~~$ ~~760~~39 ~~546~~$ ~~579~~26 ~~267~~$ ~~207~~35 ~~725~~$ ~~418~~27 ~~291~~$ ~~159~~44 75$ 4842 ~~------~~$ ~~------~~6 ~~------~~$ ~~------~~7 ~~------~~$ ~~------~~9 ~~------~~Interest ~~------ ------ ------- ------- ------- EQUITY AFFILIATES (3) Revenues~~ cost................. ~~399~~61 ~~212~~41 7862 2537 1458 1441 ~~118~~28 8425 6022 ~~256~~Expected ~~114~~return 4on ~~Production~~plan assets...................... (~~118~~76) (8137) (6776) (1233) (979) (636) ~~(35)~~-- ~~(30)~~-- ~~(38)~~-- ~~(71)~~Amortization ~~(42)~~of ~~(23)~~prior ~~DD&A~~service cost (credit).......~~.........~~ (317) ~~(33)~~5 (~~23) (~~6) ~~(4)~~5 (47) ~~(12)~~5 (164) (164) (134) ~~(13)~~Recognized ~~(3)~~actuarial ~~Other~~loss (2gain) ........... ~~5 -- -- 3 -- -- (2) -- -- 4 -- -- Income taxes~~ ........ ~~(38)~~5 ~~8 18~~ -- --4 -- ~~(13)~~4 ~~(1)~~5 2 (1) ~~(25)~~2 ~~9 19~~ ------ --~~----~~ ------ -~~-----~~ ------ --~~----~~ ------ --~~----~~ ------ --~~-----~~ ------- -~~------~~ ~~Results of Operations ..... 217 106 6 10 1 4 56 37 5 151 68 (3)~~ ------ --~~----~~ ------ --~~----~~ ------ -~~-----~~ ~~------~~Net ~~------~~periodic ~~------~~benefit ~~------- ------- ------- Total Results of Operations~~ cost.....~~...~~ $~~1,680~~ $22 ~~866~~ $ ~~552~~35 $ ~~589~~19 $ ~~268~~36 $ ~~211~~20 $ ~~781~~57 $ ~~455~~32 $ ~~296~~27 $ ~~310~~29 ~~$ 143 $ 45~~ ====== == ==== === === ====== ====== == ==== ====== ====== ==~~====~~ ======== ======== =======

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

~~TOTAL~~OTHER ~~WORLDWIDE~~PENSION ~~UNITED~~BENEFITS ~~STATES~~POST-RETIREMENT ~~EUROPE~~BENEFITS ~~OTHER REGIONS~~ ------------------------------------------ ------------------------ 2001 2000 2001 2000 ------------------ ------------------ ---------- ---------- U.S. INT'L. U.S. INT'L. ------ ~~2000~~------ ~~1999~~------ ~~1998~~------ ~~2000~~CHANGE ~~1999~~IN ~~1998~~BENEFIT ~~2000~~OBLIGATION ~~1999~~Benefit ~~1998~~obligation ~~2000~~at ~~1999~~beginning ~~1998~~of year .......... $ 855 $ 698 $ 834 $ 679 $ 374 $ 323 Service cost ..................................... 39 26 35 27 6 7 Interest cost .................................... 61 41 62 37 28 25 Exchange gain .................................... -- (20) -- (58) (2) -- Participant contributions ........................ -- -- -- -- -- 4 Amendment(1) ..................................... 27 -- -- -- 6 -- Actuarial (gain) loss ............................ 53 (17) (2) 17 38 46 Acquisitions, divestitures and other ............. -- 25 -- 18 32 -- Benefits paid .................................... (50) (23) (74) (22) (29) (31) ------ ------ ------ ------ ------ ---- -- -------- ~~CONSOLIDATED~~Benefit ~~COMPANIES~~obligation ~~Property~~at ~~acquisitions~~end ~~Proved~~of ~~(2)~~year ~~(3) (4)~~ ................ $ ~~621~~985 $ ~~138~~730 $ ~~199~~855 $ 24698 $ 6453 $ 24374 ====== ====== ====== ====== ========== ========== CHANGE IN PLAN ASSETS Fair value of plan assets at beginning of year ... $ ~~572~~798 $ --524 $ ~~175~~884 $ 25494 $ ~~132~~-- $ -- ~~Unproved~~Actual return on plan assets ..................... 92(45) 19(68) 93(29) 649 1-- 55-- 11Employer 12contribution 25............................ 757 632 1317 ~~Exploration~~29 24 26 Participant contributions ........................ ~~299~~-- ~~276~~-- ~~436~~-- ~~125~~-- 975 ~~119~~5 61Exchange 72gain ~~114~~.................................... ~~113~~-- ~~107~~(15) ~~203~~-- ~~Development~~(40) -- -- Acquisitions, divestitures and other ............. ~~908~~-- ~~737~~23 ~~1,019~~-- ~~398~~10 ~~304~~-- ~~542~~-- ~~335~~Benefits ~~342~~paid ~~403~~.................................... ~~175~~(50) 91(21) (74) (18) (29) (31) ------ ------ ------ ------ ---------- ---------- Fair value of plan assets at end of year ......... $ 710 $ 475 $ 798 $ 524 $ -- $ -- ====== ====== ====== ====== ========== ========== Funded status of plans at end of year ............ $ (275) $ (254) $ (57) $ (174) $ (453) $ (374) Transition asset ................................. (7) (5) (15) (6) -- -- Unrecognized actuarial loss ...................... 225 95 55 12 99 62 Exchange gain .................................... -- -- -- -- (2) -- Unrecognized prior service cost (credit) ......... 37 68 11 81 (37) (41) ------ ------ ------ ~~Total~~------ ---------- ---------- Net amount recognized at end of year .............. ~~1,920~~$ ~~1,170~~(20) ~~1,747~~$ ~~553~~(96) ~~408~~$ ~~740~~(6) ~~979~~$ ~~426~~(87) ~~717~~$ ~~388~~(393) ~~336~~$ ~~290~~(353) ~~EQUITY~~====== ~~AFFILIATES~~====== ====== ====== ========== ========== AMOUNTS RECOGNIZED IN CONSOLIDATED BALANCE SHEET AT END OF YEAR Prepaid benefit (5)see ~~Development~~note 16) .................... ~~320~~$ ~~337~~-- ~~564~~$ 18-- 15$ 305 8$ 1-- 2$ ~~294~~-- ~~321~~$ ~~532~~ -- Accrued benefit liability Short-term (see note 19) ....................... --- -- -- -- (30) (18) Long-term (see note 21) ........................ (70) (196) (69) (115) (363) (335) Deferred pension transition obligation (see note 16) ........................................... -- 70 5 28 -- -- Accumulated other comprehensive loss(2) .......... 50 30 53 -- -- -- ------ ------ ------ ------ ------ ------ ------ ------ ~~Total~~Net amount recognized ............................ $~~2,240~~ ~~$1,507~~(20) $~~2,311~~ $(96) ~~571~~ $ ~~423~~(6) $ ~~770~~(87) $ ~~987~~(393) $ ~~427~~(353) ~~$ 719 $ 682 $ 657 $ 822~~ ====== ====== ====== ====== ====== ====== ====== ====~~== ====== ====== ====== ======~~

---------- 99 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) (1) Represents a change in the U.S. pension plan for the survivors' benefit provisions. (2) Before reduction for associated deferred tax benefit of $27 at December 31, 2001, and $19 at December 31, 2000 (see note 24).

~~TOTAL~~OTHER ~~WORLDWIDE~~POST-RETIREMENT ~~UNITED~~PENSION ~~STATES~~BENEFITS ~~EUROPE~~BENEFITS ~~OTHER REGIONS~~ ------------------------- -------------~~---------~~ -----------------~~-----~~ ~~----------------------~~2001 2000 ~~1999~~2001 ~~1998~~ 2000 ~~1999 1998 2000 1999 1998 2000 1999 1998~~ ------- ------- -- ----- ------ ------ ------ ------ U.S. INT'L. U.S. INT'L. ------ ------ ------ ------ WEIGHTED-~~-----~~AVERAGE ~~CONSOLIDATED~~ASSUMPTIONS ~~COMPANIES~~AT ~~Gross~~END ~~costs~~OF ~~Proved~~YEAR ~~properties~~Discount ~~(1)~~rate .. ~~$14,730 $13,661 $13,488 $5,266 $4,968 $5,013 $7,461 $6,939 $6,942 $2,003 $1,754 $1,533 Unproved properties~~ .... ~~1,106 1,201 1,159 497 651 634 322 331 262 287 219 263 Less Accumulated DD&A~~ ....... ~~8,197 7,887 7,469 3,099 3,024 2,983 3,668 3,507 3,182 1,430 1,356 1,304 ------- ------- ------- ------ ------ ------ ------ ------ ------ ------ ------ ------ Total net costs~~ ............. 7~~,639~~.00% 6~~,975~~.00% 7~~,178~~.50% ~~2,664~~6.00% ~~2,595~~7.00% ~~2,664~~7.50% ~~4,115~~Rate ~~3,763~~of ~~4,022~~compensation ~~860~~increase ~~617 492 EQUITY AFFILIATES (2) Gross costs Proved properties~~ .......... ~~1,728~~4.60% ~~1,411~~4.05% ~~1,075~~4.60% ~~119~~4.50% ~~102~~4.60% 874.60% ~~213~~Expected ~~207~~return ~~207~~on ~~1,396~~plan ~~1,102~~assets ~~781 Less Accumulated DD&A~~ ......... ~~164 134 99 29~~ 9.25% 217.00% ~~101~~9.00% 907.00% ~~75 34 19 3~~ --~~-----~~ --~~-----~~ ~~-------~~Health ~~------~~care ~~------~~escalation ~~------~~rate ~~------ ------ ------ ------ ------ ------ Total net costs~~ ............ ~~1,564 1,277 976 90 77 66 112 117 132 1,362 1,083 778~~ --~~-----~~ --~~-----~~ --~~-----~~ --~~----~~ ~~------ ------ ------ ------ ------ ------ ------ ------ Total~~ 4.~~....................~~50% ~~$ 9,203 $ 8,252 $ 8,154 $2,754 $2,672 $2,730 $~~4~~,227 $3,880 $4,154 $2,222 $1,700 $1,270 ======= ======= ======= ====== ====== ====== ====== ====== ====== ====== ====== ======~~.50%

U.S. defined benefit plan assets consisted primarily of common stock and fixed income securities at December 31, 2001. The assets included 1,100 shares of Conoco stock. At December 31, 2000, U.S. defined benefit plan assets consisted primarily of common stocks. No Conoco common stock was included in the 2000 holdings. 27. FINANCIAL INSTRUMENTS AND OTHER RISK MANAGEMENT ACTIVITIES GENERAL We operate in the worldwide crude oil, refined product, natural gas, natural gas liquids and electric power markets and are exposed to fluctuations in hydrocarbon and power prices, foreign currency rates and interest rates. These fluctuations can affect revenues and the cost of operating, investing and financing. Our management has used and intends to continue to use financial- and commodity-based derivative contracts to reduce the risk in overall earnings and cash flow when the benefits provided are anticipated to more than offset the risk management costs involved. We have established a Risk Management Policy that provides guidelines for entering into contractual arrangements (derivatives) to manage our commodity price, foreign currency rate and interest rate risks. The Conoco Risk Management Committee, composed of certain senior officers, has: o an ongoing responsibility for the content of this policy; o principal oversight responsibility to ensure that we are in compliance with the policy; and o responsibility to ensure that procedures and controls are in place for the use of commodity, foreign currency and interest rate instruments. These procedures clearly establish derivative control and valuation processes, routine monitoring and reporting requirements, and counterparty credit approval procedures. Additionally, to assess the adequacy of internal controls, our internal audit group reviews these risk management activities. The audit results are then reviewed by both the Conoco Risk Management Committee and by management. The counterparties to these contractual arrangements are limited to major financial institutions and other established companies in the petroleum industry. Although Conoco, in the event of nonperformance by these counterparties, is exposed to credit loss, this exposure is managed through credit approvals, limits and monitoring procedures and limits to the period over which unpaid balances are allowed to accumulate. We have not experienced any material nonperformance by counterparties to these contracts, and no material loss would be expected from any such nonperformance. Our exposure to the recent Enron Corp. bankruptcy is not material. 100 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) ADOPTION OF NEW ACCOUNTING STANDARD Effective January 1, 2001, we adopted SFAS No. 133, as amended by SFAS No. 138 (SFAS 133). Upon initial adoption of SFAS 133, we recorded a cumulative transition gain of $37 after-tax into net income, which was mainly the result of certain derivative instruments that did not meet the conditions for hedge accounting pursuant to SFAS 133, and $1 into other comprehensive income to reflect the fair value of derivatives qualifying as cash flow hedges. In addition, $297 was recorded as assets, and $259 was recorded as liabilities. See note 9 for details on the accounting change generated from implementing SFAS 133 and note 24 for the impact of implementing SFAS 133 to "Other Comprehensive Income." ACCOUNTING POLICY All derivatives are recognized on the balance sheet at their fair value. At the time Conoco enters into a derivative commodity instrument, the derivative is designated as a fair value hedge, a cash flow hedge or a non-hedging instrument. At December 31, 2001, the fair value of all derivative instruments was recorded in the balance sheet captions as follows: o other current assets $574; o other assets $27; o other accrued liabilities $222; and o other liabilities and deferred credits $158. For those derivatives designated as fair value or cash flow hedges, we formally document the hedging relationship and our risk management objective and strategy prior to undertaking the hedge. Hedge accounting is adopted for reporting gains and losses from changes in the fair value of cash flow and fair value hedges when the impact is material and the hedging instruments meet the criteria for hedge accounting, as defined in SFAS 133. Gains or losses from derivative instruments for which hedge accounting is applied are reported at the same time and in the same income statement caption as the hedged item. Gains or losses from derivative instruments for which hedge accounting is not applied are reported in other income. Conoco formally assesses, both at inception of the hedge and on an ongoing basis, the effectiveness of the hedging instrument. If it is determined that a hedging instrument has not been highly effective in offsetting gains or losses on the hedged transaction, hedge accounting will be discontinued on a prospective basis. Hedge accounting was not discontinued during 2001 for any hedging instruments. In the event a derivative designated as a hedge is terminated prior to the maturity of the hedged transaction, gains or losses at termination are deferred and included in the measurement of the hedged transaction. If a hedged transaction matures, is sold, extinguished or terminated prior to the maturity of a derivative designated as a hedge of such transaction, then the gains or losses associated with the derivative, through the maturity date of the transaction, are included in the measurement of the hedged transaction. The derivative also is reclassified as a non-hedging instrument. If the anticipated transaction is no longer expected to occur, derivatives designated as a hedge are reclassified to non-hedging instruments and gains (losses) are recognized in earnings in the current period. SFAS No. 133 and SFAS No. 138 are complex and subject to a potentially wide range of interpretations in their application. As such, in 1998 the FASB established the Derivative Implementation Group (DIG) task force specifically to consider and to publish official interpretations of issues arising from the implementation of SFAS 133. The DIG is still active, and the potential exists for additional issues to be brought under its review. Therefore, if subsequent DIG interpretations of SFAS 133 are different than our current policy, it is possible that our policy, as stated above, would be modified. 101 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) COMMODITY PRICE RISK We enter into energy-related futures, forwards, swaps and options in various markets: o to balance our physical systems -- In addition to being able to settle exchange traded futures contracts in cash prior to contract expiry, they also can be settled by physical delivery of the commodity. These barrels can provide another source of supply to our physical or "wet barrel" pool to meet refinery requirements or marketing demand; o to meet customer needs -- Consistent with our policy to generally remain exposed to market prices, we use swap contracts to convert fixed price sales contracts (often requested by natural gas and refined product consumers) to a floating market basis; and o to manage our price exposure on anticipated crude oil, natural gas, refined product and electric power transactions. Our policy is generally to be exposed to market pricing for commodity purchases and sales. From time to time, management may use derivatives to establish longer-term positions to hedge the price risk for our equity crude oil and natural gas production, as well as our refinery margins. Specifically, in conjunction with the Gulf Canada acquisition, we initiated an extensive hedging program to mitigate volatile crude oil and natural gas prices through the purchase of derivative instruments. The fair value gain or loss of outstanding derivative commodity instruments is shown in the following table:

~~TOTAL~~FAIR ~~WORLDWIDE~~VALUE ~~UNITED~~AT ~~STATES~~DECEMBER ~~EUROPE~~31 ~~OTHER REGIONS~~ ---------------------- ---~~-------------------~~ ~~----------------------~~2001 ~~----------------------~~ 2000 ~~1999 1998 2000 1999 1998 2000 1999 1998 2000 1999 1998~~ ------ -~~-----~~ ------ ---~~---~~ ~~------~~COMMODITY ------ ------ ------ ------ ------ ------ ------ PROVED RESERVES OF CONSOLIDATED COMPANIES Beginning of year ............... 788 863 893 238 261 277 383 410 421 167 192 195 Revisions and other changes ..... 46 DERIVATIVES(61) 42Crude 23oil ~~4 14 16 (5) 20 7 (5) 8 Extensions~~ and ~~discoveries~~refined ~~......~~products 56Trading ~~54 41 19 7 15 18 37 6 19 10 20 Improved recovery~~ ............... ~~-- -- 14 -- -- -- -- -- 11 -- -- 3 Purchase of reserves (2) (3)~~ .... ~~55 1 8 -- 1 -- 45 -- 8 10 -- -- Sale of reserves (4)~~ ...~~.........~~ ~~(2)~~$ ~~(8) (16) (2) (8) (16)~~ -- --$ --1 Non--trading ~~-- -- Production~~ ..................~~....~~ 264(~~115~~2) 92(~~116~~3) ~~(119) (29) (27) (29) (57) (59) (56) (29) (30) (34)~~ ------ -~~-----~~ ------ ---~~---~~ ~~------~~Combined ~~------ ------ ------ ------ ------ ------ ------ End of year~~ .................. ~~828 788 863 249 238 261 405 383 410 174 167 192 ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ PROVED RESERVES OF EQUITY AFFILIATES (5) Beginning of year~~ ......~~.........~~ ~~742~~$ ~~728~~264 ~~731~~$ --93 --======= --========= 60Natural 50gas ~~51 682 678 680 Revisions~~ and ~~other~~electricity ~~changes~~Trading ..... ~~2 8 5 -- -- -- 3 8 5 (1) -- -- Extensions and discoveries~~ ...... ~~87 21 -- -- -- -- 4 9 -- 83 12 -- Production~~ ...........~~...........~~ ~~(21)~~$ ~~(15) (8)~~ -- --$ --3 ~~(7) (7) (6) (14) (8) (2)~~ Non-~~-----~~trading ~~------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ End of year~~ .................. ~~810~~74(4) ~~742~~103 ~~728~~ -- -- -- ~~60 60 50 750 682 678~~ -~~-----~~ ------ ---~~---~~ ~~------~~Combined ~~------ ------ ------ ------ ------ ------ ------ ------ Total~~ ........................~~...~~ ~~1,638~~$ ~~1,530~~74 ~~1,591~~$ ~~249~~106 ~~238 261 465 443 460 924 849 870~~ ====== =~~=====~~ ====== ====== ====== ====== ====== ====== ====== ====== ====== ====== PROVED DEVELOPED RESERVES OF CONSOLIDATED COMPANIES Beginning of year ............... 565 622 600 202 222 242 217 228 174 146 172 184 End of year ..................... 607 565 622 215 202 222 256 217 228 136 146 172 PROVED DEVELOPED RESERVES OF EQUITY AFFILIATES (5) Beginning of year ............... 129 92 43 -- -- -- 43 42 43 86 50 -- End of year ..................... 193 129 92 -- -- -- 39 43 42 154 86 50

---------- (1) Includes derivative instruments that can be settled in cash or by physical delivery of the commodity. (2) Includes collars with a $24.04 floor price and a $26.54 cap price (West Texas Intermediate equivalent) on 54.5 million barrels for the period October 2001 through December 2002. Includes swaps at $25.30 on 18.3 million barrels for the period October 2001 through December 2002. (3) Includes purchased crude oil put options with a strike price of $22.00 (West Texas Intermediate equivalent) per barrel on 63 million barrels during the period of April through December 2001. (4) Includes collars with a $4.00 floor price and a $4.60 cap price (NYMEX equivalent) on approximately 120,000 mmbtu per day for the period October 2001 through December 2002. Includes swaps at $4.02 on approximately 100,000 mmbtu per day for the period October 2001 through December 2002. The fair values of the futures contracts are based on quoted market prices obtained from the New York Mercantile Exchange or the International Petroleum Exchange of London. The fair values of swaps and other over-the-counter instruments are estimated based on quoted market prices of comparable contracts and approximate the gain or loss that would have been realized if the contracts had been closed out at year-end. We do a limited amount of trading unrelated to our underlying physical business for which after-tax gains or losses have not been material. 102 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) The amount of hedge accounting ineffectiveness related to commodity derivatives for the year 2001 was not material. FOREIGN CURRENCY RISK Conoco has foreign currency exchange rate risk resulting from operations in over 40 countries around the world. We do not comprehensively hedge our exposure to currency rate changes, although we may choose to selectively hedge exposures to foreign currency rate risk. Examples include firm commitments for capital projects, certain local currency tax payments and dividends, and cash returns from net investments in foreign affiliates to be remitted within the coming year. In conjunction with our European commercial paper program, we enter into foreign currency swaps for all non-U.S. dollar notes issued in order to receive the U.S. dollar equivalent proceeds upon note issuance and to lock in the forward foreign currency rate on note maturity. At December 31, 2001, the U.S. dollar equivalent of all non-U.S. dollar notes outstanding was $29, all of which were swapped to the U.S. dollar. At December 31, 2000, the U.S. dollar equivalent of all non-U.S. dollar notes outstanding was $81, all of which were swapped for the U.S. dollar. At December 31, 2001, we had open foreign currency exchange derivative instruments with a notional value of $9 related to forward currency sales. At December 31, 2000, we had open foreign currency exchange derivative instruments with a notional value of $45 related to anticipated foreign currency capital investments. The fair value of outstanding foreign currency hedges is shown in the following table:

~~TOTAL~~FAIR ~~WORLDWIDE~~VALUE ~~UNITED~~AT ~~STATES~~DECEMBER ~~EUROPE~~31 ~~OTHER REGIONS~~ ---------------------- ---~~-------------------~~ ~~----------------------~~2001 ~~----------------------~~ 2000 ~~1999 1998 2000 1999 1998 2000 1999 1998 2000 1999 1998~~ ------ ---~~---~~ ------ ---~~---~~ ~~------~~FOREIGN ~~------~~CURRENCY ~~------~~DERIVATIVES Non-~~-----~~trading ~~------ ------ ------ ------ PROVED RESERVES OF CONSOLIDATED COMPANIES Beginning of year~~ .............. ~~5,799~~$ 5,802 5,491 2,166 2,319 2,235 2,884 3,053 3,060 749 430 196 Revisions and other changes (1) (2) .................... (176) 7 25 (110) (34) 18 42 31 (20) (108) 10 27 Extensions and discoveries ..... 515 446 961 284 219 624 1 65 111 230 162 226 Purchase of reserves (3) (4) ... 222 174 116 19 8 4 203 -- ~~112~~$ -- 166 -- Sale of reserves (5) ........... (7) (30) (281) (7) (30) (243) -- -- (38) -- -- -- Production ..................... (617) (600) (510) (291) (316) (319) (293) (265) (172) (33) (19) (19) ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ End of year ................. 5,736 5,799 5,802 2~~,061~~ ~~2,166 2,319 2,837 2,884 3,053 838 749 430~~ ------ ---~~---~~ ------ ---~~---~~ ~~------~~Total ~~------ ------ ------ ------ ------ ------ ------ PROVED RESERVES OF EQUITY AFFILIATES (6) Beginning of year~~ .............. ~~343 381 370 343 381 370 -- -- -- -- -- -- Revisions and other changes~~ .... ~~(19) (35) (12) (19) (35) (12) -- -- -- -- -- -- Extensions and discoveries~~ ..... --$ -- 1$ -- -- 1 -- -- -- -- -- -- Purchase of reserves ........... -- 3 27 -- 3 27 -- -- -- -- -- -- Production ..................... (7) (6) (5) (7) (6) (5) -- -- -- -- -- -- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ End of year ................. 317 343 381 317 343 381 -- -- -- -- -- -- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ Total .......................... 6,053 6,142 6,183 2~~,378~~ ~~2,509 2,700 2,837 2,884 3,053 838 749 430~~ ====== ===~~===~~ ====== ====== ====== ====== ====== ====== ====== ====== ====== ====== PROVED DEVELOPED RESERVES OF CONSOLIDATED COMPANIES Beginning of year .............. 4,164 3,991 3,061 1,792 1,828 1,801 2,017 1,954 1,091 355 209 169 End of year .................... 4,375 4,164 3,991 1,788 1,792 1,828 2,295 2,017 1,954 292 355 209 PROVED DEVELOPED RESERVES OF EQUITY AFFILIATES (6) Beginning of year .............. 72 66 40 72 66 40 -- -- -- -- -- -- End of year .................... 74 72 66 74 72 66 -- -- -- -- -- --

There was no amount of hedge accounting ineffectiveness recognized in earnings related to foreign currency derivatives for the year 2001. INTEREST RATE RISK Conoco manages any material risk arising from exposure to interest rates by using a combination of financial derivative instruments. This program was developed to manage the fixed and floating interest rate mix of our total debt portfolio and related overall cost of borrowing. Beginning in the fourth quarter 2001, we executed several interest rate swaps to increase our overall debt portfolio's exposure to floating interest rates. These transactions included swapping $1,650 of fixed rate debt to floating rate debt, as well as swapping $900 of floating rate debt to fixed rate debt. These instruments qualify for the short-cut method of hedge accounting and had no ineffectiveness. Through these transactions, we effectively increased our exposure to floating interest rates by $750. In addition to increasing our floating rate exposure, we effectively swapped $900 of debt to a lower fixed rate, reducing the pretax interest rate by approximately 250 basis points. The fair value gain or loss of outstanding interest rate swaps is shown in the following table:

~~TOTAL~~FAIR ~~WORLDWIDE~~VALUE ~~UNITED~~AT ~~STATES~~DECEMBER ~~EUROPE~~31 ~~OTHER REGIONS~~ --------------------------- ~~-------------------------~~2001 ~~------------------------- -------------------------~~ 2000 ~~1999 1998 2000 1999 1998 2000 1999 1998 2000 1999 1998~~ -------- -~~-------~~ ------- --~~-----~~ ~~-------~~INTEREST ~~-------~~RATE ~~-------~~DERIVATIVES ~~-------~~Fixed ~~-------~~rate ~~-------~~to ~~-------~~floating ~~-------~~rate ~~CONSOLIDATED~~hedges ~~COMPANIES~~Notes ~~Future~~due ~~cash~~2009 ~~flows Revenues~~............ ~~$ 52,174 $ 31,682 $20,340 $25,990 $ 9,824 $ 6,148 $17,664 $15,724 $11,376 $ 8,520 $ 6,134 $ 2,816 Production costs~~.... ~~(9,698) (8,295) (8,271) (3,342) (2,604) (2,665) (4,794) (4,460) (4,742) (1,562) (1,231) (864) Development costs~~... ~~(1,904) (1,573) (1,548) (304) (347) (370) (627) (665) (823) (973) (561) (355) Income tax expense~~.. ~~(16,892)~~$ (~~10,212~~35) ~~(3,904)~~$ ~~(7,505) (1,805) (546) (6,515) (5,581) (2,239) (2,872) (2,826) (1,119)~~ --~~------~~ ~~--------~~Notes ~~-------~~due ~~-------~~2029 ~~------- ------- ------- ------- ------- ------- ------- ------- Future net cash flows~~............... ~~23,680 11,602 6,617 14,839 5,068 2,567 5,728 5,018 3,572 3,113 1,516 478 Discounted to present value at a 10% annual rate~~......~~...~~ (~~9,341~~74) ~~(4,373) (2,414) (6,350) (2,157) (1,055) (1,699) (1,468) (1,151) (1,292) (748) (208)~~ --~~------~~ -------- -~~------~~ ------- --~~-----~~ ~~-------~~Fixed ~~-------~~rate ~~-------~~to ~~-------~~floating ~~-------~~rate ~~-------~~hedges ~~-------~~(see ~~Total~~note (120) ....... 14,339 7,229 4,203 8,489 2,911 1,512 4,029 3,550 2,421 1,821 768 270 -------- -------- ------- ------- ------- ------- ------- ------- ------- ------- ------- ------- EQUITY AFFILIATES (2) Future cash flows Revenues............ ~~15,366 13,524 5,327 3,158 839 1,001 1,015 976 427 11,193 11,709 3,899 Production costs~~.... (~~1,578~~109) ~~(2,489)~~-- ~~(2,228)~~Floating ~~(514)~~rate ~~(334)~~to ~~(346)~~fixed ~~(417)~~rate ~~(492) (266) (647) (1,663) (1,616) Development costs~~hedges... (~~1,239~~8) ~~(1,168) (1,086) (288) (181) (191) (39) (38) (28) (912) (949) (867) Income tax expense.. (3,341) (2,522) (425) (867) (115) (166) (161) (78) (63) (2,313) (2,329) (196)~~ --~~------~~ -------- -~~------~~ ------- --~~-----~~ ~~-------~~Total ~~------- ------- ------- ------- ------- ------- Future net cash flows~~............... ~~9,208 7,345 1,588 1,489 209 298 398 368 70 7,321 6,768 1,220 Discounted to present value at a 10% annual rate~~......... ~~(5,771) (5,039) (1,327) (833) (155) (220) (139) (106) (9) (4,799) (4,778) (1,098) -------- -------- ------- ------- ------- ------- ------- ------- ------- ------- ------- ------- Total~~........... ~~3,437~~$ ~~2,306~~(117) ~~261~~$ ~~656 54 78 259 262 61 2,522 1,990 122~~ --~~------~~ -------- ------- ------- ------- ------- ------- ------- ------- ------- ------- ------- Total................. $ 17,776 $ 9,535 $ 4,464 $ 9,145 $ 2,965 $ 1,590 $ 4,288 $ 3,812 $ 2,482 $ 4,343 $ 2,758 $ 392 ======== =~~=======~~ ======= ==~~===== ======= ======= ======= ======= ======= ======= ======= =======~~

At December 31, 2000, Conoco had no significant open interest rate financial derivative instruments. 103 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) FAIR VALUES OF NON-DERIVATIVE FINANCIAL INSTRUMENTS The carrying values of most non-derivative financial instruments are based on historical costs. The carrying values of marketable securities, receivables, payables and short-term obligations approximate their fair value because of their short maturity. Long-term borrowings and capital lease obligations outstanding at December 31, 2001, before interest rate hedges, of $8,376, had an estimated fair value of $8,557. Obligations outstanding at December 31, 2000, of $4,138 approximate fair value. These estimates were based on quoted market prices for the same or similar issues, or the current rates offered to Conoco for issues with the same remaining maturities. 28. COMMITMENTS AND CONTINGENT LIABILITIES We use various leased facilities and equipment in our operations. Future minimum lease payments under noncancelable operating leases are $329 for 2002, $285 for 2003, $154 for 2004, $136 for 2005, $221 for 2006 and $549 for subsequent years. Future minimum lease payments are not reduced by $66 of noncancelable minimum sublease rentals, where we continue to be the primary obligator under the original leases. Rental expense under operating leases was $322 in 2001, $274 in 2000 and $301 in 1999. Rental revenue under operating subleases was $15 in 2001, $11 in 2000 and $15 in 1999. Conoco has various purchase commitments for materials, supplies, services and items of permanent investment incident to the ordinary conduct of business. Such commitments are not at prices in excess of current market. Additionally, we have obligations under international contracts to purchase natural gas over periods up to 18 years. At December 31, 2001, these long-term purchase obligations were at prices approximating year-end quoted market prices. However, at December 31, 2000, these obligations were at prices lower than year-end 2000 market prices. No material annual loss is expected from these long-term commitments. We are subject to various lawsuits and claims including but not limited to: actions challenging oil and gas royalty and severance tax payments; actions related to gas measurement and valuation methods; actions related to joint interest billings to operating agreement partners; claims for damages resulting from leaking underground storage tanks; and related toxic tort claims. As a result of the separation agreement with DuPont, we also have assumed responsibility for current and future claims related to certain discontinued chemicals and agricultural chemicals businesses operated by Conoco in the past. In general, the effect on future financial results is not subject to reasonable estimation because considerable uncertainty exists. The ultimate liabilities resulting from such lawsuits and claims may be material to results of operations in the period in which they are recognized. An accrual of $112 was recorded during the fourth quarter of 2001 for a litigation settlement related to certain discontinued chemicals businesses for which we assumed responsibility for claims as a result of the separation agreement with DuPont. On May 2, 2000, a jury in federal court in Virginia found that Conoco infringed patents of General Technology Applications (GTA) involving part of a process for manufacturing flow improver products. The amount awarded as damages was $55. The Federal Circuit Court of Appeals handed down a decision on September 19, 2001, without a written opinion, affirming the trial court's verdict. On November 9, 2001, we paid approximately $60 that included interest to the settlement date, in partial satisfaction of the judgment. The parties entered into settlement negotiations and in December 2001 reached a confidential settlement of all disputes between the parties. Over the next seven years, we will spend an estimated $95 to $100 for capital improvements at our U.S. refineries to install control technology and equipment to reduce emissions from stacks, vents, valves, heaters, boilers and flares. We also are subject to contingencies pursuant to environmental laws and regulations that in the future may require further action to correct the effects on the environment of prior disposal practices or releases of petroleum substances by Conoco or other parties. We have accrued for certain environmental remediation activities consistent with our policy set forth in note 2. These accrued liabilities exclude claims against Conoco's insurers or other third parties and are not discounted. Many of these liabilities result from the Comprehensive Environmental Response, Compensation and Liability Act, as amended and often referred to as "Superfund" (CERCLA); the Resource Conservation and Recovery Act, as amended (RCRA); and similar state laws that require us to undertake certain 104 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) investigative and remedial activities at sites where we conduct, or once conducted, operations or at sites where Conoco-generated waste was disposed. The accrual also includes a number of sites identified by Conoco that may require environmental remediation, but which are not currently the subject of CERCLA, RCRA or state enforcement activities. Over the next decade, we may incur significant costs under both CERCLA and RCRA. Considerable uncertainty exists with respect to these costs, and under adverse changes in circumstances, potential liability may exceed amounts accrued as of December 31, 2001. Conoco assumed environmental remediation liabilities from DuPont related to certain discontinued chemicals and agricultural chemicals businesses operated by Conoco in the past that are included in the environmental accrual. We also assumed environmental remediation liabilities with the purchase of Gulf Canada in the third quarter 2001. These liabilities totaled $27 at December 31, 2001, and were discounted at 5 percent. The total environmental liability accrual amounted to $157 at December 31, 2001, and $119 at December 31, 2000. These expenditures are expected to be incurred over the next 10 years. Approximately 90 percent of Conoco's environmental reserve at December 31, 2001, was attributable to RCRA and similar remediation liabilities (including voluntary remediations) and 10 percent to CERCLA liabilities. Remediation activities vary substantially in duration and cost from site to site depending on the mix of unique site characteristics, evolving remediation technologies, diverse regulatory agencies and enforcement policies, and the presence or absence of potentially liable third parties. Therefore, it is difficult to develop reasonable estimates of future site remediation costs. In management's opinion, this accrual was appropriate based on existing facts and circumstances. In the event future monitoring and remediation expenditures are in excess of amounts accrued, they may be significant to results of operations in the period recognized. However, management does not anticipate they will have a material adverse effect on the consolidated financial position of Conoco. During 2001, remediation accruals resulted in a $44 charge, compared to a $35 charge in 2000 and a $6 charge in 1999. RCRA extensively regulates the treatment, storage and disposal of hazardous waste and requires a permit to conduct such activities. RCRA requires permitted facilities to undertake an assessment of environmental conditions at the facility. If conditions warrant, we may be required to remediate contamination caused by prior operations. In contrast to the CERCLA, the cost of corrective action activities under the RCRA corrective action program typically is borne solely by Conoco. Over the next decade, we anticipate that significant ongoing expenditures for RCRA remediation activities may be required. However, annual expenditures for the near term are not expected to vary significantly from the range of such expenditures over the past few years. Conoco's expenditures associated with RCRA and similar remediation activities conducted voluntarily or pursuant to state and foreign laws were approximately $63 in 2001, $34 in 2000 and $33 in 1999. In the long term, expenditures are subject to considerable uncertainty and may fluctuate significantly. Conoco from time to time receives requests for information or notices of potential liability from the United States Environmental Protection Agency (USEPA) and state environmental agencies alleging that we are a potentially responsible party under CERCLA or an equivalent state statute. On occasion, Conoco also has been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by Conoco but allegedly contain wastes attributable to Conoco's past operations. As of December 31, 2001, we had been notified of potential liability under CERCLA or comparable state law at about 22 sites around the U.S., with active remediation under way at six of those sites. We received notice of potential liability at five new sites during 2001, compared with two similar notices in 2000 and four in 1999. Expenditures associated with CERCLA and similar state remediation activities were not significant for Conoco in 2001, 2000 or 1999. For most Superfund sites, Conoco's potential liability will be significantly less than the total site remediation costs because the percentage of waste attributable to Conoco versus that attributable to all other potentially responsible parties is relatively low. Other potentially responsible parties at sites where Conoco is a party typically have had the financial strength to meet their obligations, and where they have not, or where potentially responsible parties could not be located, Conoco's own share of liability has not increased materially. There are relatively few sites where Conoco is a major participant, and neither the cost to Conoco of remediation at those sites nor such cost at all CERCLA sites in the aggregate is expected to have a material adverse effect on the competitive or financial condition of Conoco. Cash expenditures not charged against income for previously accrued remediation activities under CERCLA, RCRA and similar state and foreign laws were $33 in 2001, $25 in 2000 and $26 in 1999. Although future 105 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) remediation expenditures in excess of current reserves are possible, the effect of any such excess on future financial results is not subject to reasonable estimation because of the considerable uncertainty regarding the cost and timing of such expenditures. Conoco or DuPont, on behalf of and indemnified by Conoco, has directly guaranteed borrowings and other obligations of certain affiliated companies and others. These guarantees totaled $1,097 at December 31, 2001, and $1,090 at December 31, 2000. The balance at December 31, 2001, included $719 and $150 associated with Petrozuata and Polar Lights, respectively, while the balance at December 31, 2000, included $706 and $167. Petrozuata has successfully met the operational requirements of the completion test associated with this guarantee, and upon acceptance of the financial certificate by the trustee, Conoco will be released from its guarantee and the debt will become non-recourse to the sponsors. We expect this release to occur no later than April 2002. In addition, Conoco owned 7.5 billion shares at December 31, 2001, and 2.0 billion shares at December 31, 2000, of Turcas Petrol A.S., of which 1,304 million shares at December 31, 2001, and 909 million shares at December 31, 2000, were pledged to a group of Turkish banks that issued letters of credit in support of a $70 borrowing. Conoco had no indirect guarantees as of December 31, 2001, and December 31, 2000. Our operations, particularly oil and gas exploration and production, can be affected by changing economic, regulatory and political environments in the various countries in which we operate, including the U.S. In certain locations, host governments have imposed restrictions, controls and taxes. In others, political conditions have existed that may threaten the safety of employees and our continued presence in those countries. Internal unrest or strained relations between a host government and Conoco or other governments may affect our operations. Those developments have, at times, significantly affected our operations and related results and are carefully considered by management when evaluating the level of current and future activity in such countries. We do take various steps to minimize our financial exposure to loss including, in certain cases, obtaining risk insurance coverage. Areas in which we have a significant active presence include Canada, the Czech Republic, Ecuador, Germany, Indonesia, Malaysia, the Netherlands, Nigeria, Norway, Russia, Syria, the United Arab Emirates, the U.K., the U.S., Venezuela and Vietnam. 29. OPERATING SEGMENT AND GEOGRAPHIC INFORMATION Conoco has three operating segments that comprise the structure used by senior management to make key operating decisions and assess performance. These are the upstream, downstream and emerging businesses segments. Upstream operating segment activities include exploring for, developing, producing and selling crude oil, natural gas and natural gas liquids; and Canadian Syncrude. Activities of the downstream operating segment include refining crude oil and other feedstocks into petroleum products; buying and selling crude oil and refined products; and transporting, distributing and marketing petroleum products. Emerging businesses operating segment activities include the development of new businesses beyond our traditional operations. Emerging businesses currently is involved in carbon fibers (Conoco Cevolution(R)); natural gas refining, including gas-to-liquids; and international power. Conoco has five reporting segments. Four reporting segments reflect the geographic division between the U.S. and international operations of its upstream and downstream businesses. One reporting segment is for emerging businesses. Corporate includes general corporate expenses, financing costs and other non-operating items and captive insurance operations. We sell our products worldwide. In 2001, about 58 percent of sales were made in the U.S. and 36 percent of sales were made in Europe. In 2000, about 59 percent of sales were made in the U.S. and 36 percent of sales were made in Europe. Major products include crude oil, natural gas, Canadian Syncrude and refined products that are sold primarily in the energy and transportation markets. Our sales are not materially dependent on any single customer or small group of customers. Transfers between segments are on the basis of estimated market values. 106 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE)

~~CONSOLIDATED~~UPSTREAM ~~COMPANIES~~DOWNSTREAM ~~EQUITY AFFILIATES(1)~~ -------------------- -------- ------------ EMERGING ELIMINA- CONSOLI- SEGMENT INFORMATION U.S. INT'L. U.S. INT'L. BUSINESSES CORPORATE TIONS DATED -------- -------- ~~2000 1999 1998 2000 1999 1998~~ -------- -------- ---------- --------- -------- -------- ~~Balance~~2001 atSales ~~January~~and other operating revenues(1) Refined products ................. $ -- $ 22 $ 11,425 $ 10,696 $ -- $ -- $ -- $ 22,143 Crude oil ........................ 40 1,905 3,674 250 -- -- -- 5,869 Natural gas ...................... $5,615 72,~~229~~509 $-- ~~4,203~~-- $-- ~~5,623~~-- $-- 28,~~306~~124 $Canadian ~~261~~Syncrude $................ ~~604~~-- ~~Sales~~79 ~~and~~-- ~~transfers~~-- of-- ~~oil~~-- ~~and~~-- ~~gas~~79 ~~produced~~Other ............................ 1,373 ~~net~~605 of189 ~~production~~350 ~~costs~~5 -- -- 2,522 -------- -------- -------- -------- -------- -------- -------- -------- Total ....................... 7,028 5,120 15,288 11,296 5 -- -- 38,737 Transfers between segments .......... 764 624 173 490 24 -- (2,075) -- -------- -------- -------- -------- -------- -------- -------- -------- Total operating revenues ............ $ 7,792 $ 5,744 $ 15,461 $ 11,786 $ 29 $ -- $ (2,075) $ 38,737 ======== ======== ======== ======== ======== ======== ======== ======== Operating profit .................... (4$ 1,~~041~~451 $ 1,642 $ 447 $ 159 $ (131) $ (2305) $ -- $ 3,~~400~~263 Equity in earnings of affiliates .... 33 106 71 (22) (~~1,778~~7) -- -- 181 Corporate non-operating items Interest and debt expense ........ -- -- -- -- -- (~~281~~396) -- (~~124~~396) Interest income (2net of misc. interest expense) ~~Development~~.............. ~~costs~~-- ~~incurred~~-- ~~during~~-- ~~the~~-- ~~period~~-- 21 -- 21 Other ............................ ~~908~~-- ~~737~~-- ~~1,019~~-- ~~320~~-- ~~337~~-- ~~555~~(82) ~~Net~~-- ~~changes~~(82) in-------- ~~prices~~-------- ~~and~~-------- in-------- ~~development~~-------- ~~and~~-------- ~~production~~-------- ~~costs~~-------- Income before income taxes .......... 91,~~150~~484 61,~~650~~748 518 137 (~~3,948~~138) ~~541~~(762) -- 2,~~112~~987 Income tax expense .................. (505) (956) (186) (51) 48 259 -- (1,~~155~~391) ~~Extensions,~~-------- ~~discoveries~~-------- ~~and~~-------- ~~improved~~-------- ~~recovery,~~-------- ~~less~~-------- ~~related~~-------- ~~costs~~-------- Income before extraordinary item and accounting change ....... ~~2,241~~979 792 332 86 (90) (503) -- 1,~~023~~596 ~~838~~Extraordinary ~~423~~item, 80charge 1for ~~Revisions~~the early extinguishment of ~~previous~~debt, ~~quantity~~net ~~estimates~~of income taxes .............. -- -- -- -- -- (44) -- (44) Cumulative effect of accounting change, net of income taxes ...... 8 32 (3) -- -- -- -- 37 -------- -------- -------- -------- -------- -------- -------- -------- Net income (loss)(2) ................ 77$ 987 $ 824 $ 329 $ 86 $ (2490) ~~189~~$ (39547) 25$ 2-- ~~Purchases~~$ 1,589 ======== ======== ======== ======== ======== ======== ======== ======== Capital employed at December 31(~~sales~~3) ofExcluding ~~reserves~~investment in ~~place~~affiliates ~~- net~~ .................. $ 2,854 $ 6,886 $ 1,308 $ 933 $ 194 $ 203 $ -- $ 12,378 Investment in affiliates(4) ....... ~~869~~92 991,129 ~~(92)~~253 420 -- -- -- 1,894 -------- -------- -------- -------- -------- -------- -------- -------- Total capital employed .............. $ 2,946 18$ ~~Accretion~~8,015 of$ ~~discount~~1,561 $ 1,353 $ 194 $ 203 $ -- $ 14,272 ======== ======== ======== ======== ======== ======== ======== ======== Return on capital employed (ROCE)(5) ...................... 30.0% 14.5% 25.6% 11.8% N/A N/A -- 17.7% Significant non-cash items DD&A ........................... $ 508 $ 1,~~321~~014 ~~620~~$ ~~916~~140 ~~294~~$ 36141 84$ ~~Net~~-- ~~change~~$ in8 ~~income~~$ ~~taxes~~-- $ 1,811 Dry hole costs and impairment of unproved properties .......... $ 18 $ 98 $ -- $ -- $ -- $ -- $ -- $ 116 Capital expenditures and investments(6) ................. $ 856 $ 1,358 $ 164 $ 225 $ 196 $ 36 $ -- $ 2,835 Purchase of Gulf Canada, net of cash acquired ........... $ -- $ 4,318 $ -- $ -- $ -- $ -- $ -- $ 4,318 Total assets(7) ..................... (3$ 4,~~450)~~378 ($ 16,607 $ 3,~~978)~~411 1$ 2,~~541~~786 ~~(444)~~$ 234 $ 488 $ -- $ 27,904 2000 Sales and other operating revenues(~~530~~1) ~~128~~Refined ~~Other~~products ................. $ -- $ -- $ 12,343 $ 11,284 $ -- $ -- $ -- $ 23,627 Crude oil ........................ 16 1,627 4,754 497 -- -- -- 6,894 Natural gas ...................... 4,099 1,686 -- -- -- -- -- 5,785 Other ............................ 351,416 ~~299~~353 ~~(105)~~282 ~~317~~376 ~~107~~4 26-- -- 2,431 -------- -------- -------- -------- -------- -------- ~~Balance~~-------- at-------- ~~December~~Total 31 ....................... 5,531 3,666 17,379 12,157 4 -- -- 38,737 Transfers between segments .......... 740 831 177 644 -- -- (2,392) -- -------- -------- -------- -------- -------- -------- -------- -------- Total operating revenues .............. $ 146,~~339~~271 $ 74,~~229~~497 $ 417,~~203~~556 $ 312,~~437~~801 $ 4 $ -- $ (2,~~306~~392) $ ~~261~~38,737 ======== ======== ======== ======== ======== ======== ======== ======== Operating profit .................... $ 1,051 $ 2,103 $ 208 $ 344 $ (89) $ (159) $ -- $ 3,458 Equity in earnings of affiliates .... 20 230 53 (26) -- -- -- 277 Corporate non-operating items Interest and debt expense ........ -- -- -- -- -- (338) -- (338) Interest income (net of misc. interest expense) ............. -- -- -- -- -- 39 -- 39

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

~~QUARTER~~UPSTREAM ~~ENDED~~DOWNSTREAM ------------------- ------------------- EMERGING ELIMINA- CONSOLI- SEGMENT INFORMATION U.S. INT'L. U.S. INT'L. BUSINESSES CORPORATE TIONS DATED -------- -------- -------- ~~MARCH~~-------- 31---------- ~~JUNE~~--------- 30-------- ~~SEPTEMBER~~-------- 302000 ~~DECEMBER~~(CONT'D.) 31Other ................................. -- -- -- -- -- 22 -- 22 -------- -------- -------- -------- ---------- ~~2000~~--------- ~~Sales~~-------- ~~and~~-------- ~~other~~Income ~~operating~~before ~~revenues~~income taxes ............... 1,071 2,333 261 318 (89) (436) -- 3,458 Income tax expense ....................... (352) (1,185) (79) (88) 20 128 -- (1,556) -------- -------- -------- -------- ---------- --------- -------- -------- Net income (loss)(2) ..................... $ ~~8,524~~719 $ 91,~~357~~148 $ ~~10,587~~182 $ 10230 $ (69) $ (308) $ -- $ 1,~~269~~902 ~~Cost~~======== of======== ~~goods~~======== ~~sold~~======== ~~and~~========== ~~other~~========= ~~expenses~~======== ======== Capital employed at December 31(23) Excluding investment in affiliates .... $ 72,~~896~~684 $ 83,~~643~~278 $ 91,~~654~~266 $ 9918 $ 27 $ 346 $ -- $ 8,~~298~~519 ~~Interest~~Investment ~~and~~in ~~debt~~affiliates(4) ~~expense~~........... 162 865 285 490 29 -- -- 1,831 -------- -------- -------- -------- ---------- --------- -------- -------- Total capital employed ................... $ 832,846 $ 894,143 $ 781,551 $ 881,408 ~~Net~~$ ~~income~~56 ~~before~~$ ~~special~~346 ~~items~~$ -- $ 10,350 ======== ======== ======== ======== ========== ========= ======== ======== Return on capital employed (ROCE)(5) ..... 24.7% 30.2% 12.8% 18.~~....~~0% $N/A ~~391~~N/A $-- ~~460~~22.6% $Significant ~~523~~cash $items ~~574~~DD&A ~~Net income~~ ................................... $ ~~399(3)~~412 $ ~~456(~~611 $ 136 $ 138 $ -- $ 4) $ ~~497(5)~~-- $ ~~550(6)~~1,301 ~~Earnings~~Dry ~~per~~hole ~~share~~costs ~~Basic~~and ~~(7)~~impairment of unproved properties .................. $ 44 $ 44 $ -- $ -- $ -- $ -- $ -- $ 88 Inventory write-down to market .........~~.....~~ $ ~~.64~~-- $ ~~.73~~-- $ ~~.80~~-- $ ~~.88~~24 ~~Diluted~~$ -- $ -- $ -- $ 24 Capital expenditures and investments(76) .. $ 667 $ 1,486 $ 344 $ 201 $ 72 $ 26 $ -- $ 2,796 Total assets ............................. $ ~~.63~~3,733 $ ~~.72~~7,195 $ ~~.79~~3,461 $ ~~.87~~2,925 ~~Dividends~~$ ~~per~~88 ~~common~~$ ~~share~~725 $ -- $ 18,127 1999 Sales and other operating revenues(1) Refined products ...................... $ ~~.19~~-- $ ~~.19~~-- $ ~~.19~~7,771 $ ~~.19~~9,253 ~~Market~~$ ~~price~~-- of$ ~~Class~~-- A$ ~~common~~-- ~~stock~~$ ~~(8)~~17,024 ~~High~~Crude oil .............................~~........~~ $10 ~~27.88~~1,101 $3,165 ~~27.06~~621 $-- ~~27.63~~-- $-- ~~29.56~~4,897 ~~Low~~Natural gas ...........................~~...........~~ $2,436 ~~18.81~~1,033 $-- ~~22.00~~-- $-- ~~21.38~~-- $-- ~~24.00~~3,469 ~~Market~~Other ~~price of Class B common stock (8) High~~ .................................~~....~~ $863 113 255 390 28~~.75~~ $-- ~~29.00~~-- $1,649 ~~28.75~~-------- $-------- ~~29.69~~-------- ~~Low~~-------- ---------- --------- -------- -------- Total ............................. 3,309 2,247 11,191 10,264 28 -- -- 27,039 Transfers between segments ............... $435 ~~19.00~~476 $106 ~~23.25~~325 $-- ~~22.31~~-- $(1,342) ~~24.69~~-- ~~1999~~-------- ~~Sales~~-------- ~~and~~-------- ~~other~~-------- ---------- --------- -------- -------- Total operating revenues ~~(1)~~ ................. $ 53,~~311~~744 $ 62,~~252~~723 $ 711,~~409~~297 $ 810,~~067~~589 ~~Cost~~$ of28 ~~goods~~$ ~~sold~~-- ~~and~~$ ~~other expenses~~ (21,342) ~~...~~ $ 527,~~130~~039 $======== ~~6,090~~======== $======== ~~7,020~~======== $========== ~~7,541~~========= ~~Interest~~======== ~~and~~======== ~~debt~~Operating ~~expense~~profit ......................... $ 71381 $ 79891 $ 80110 $ 81192 ~~Net~~$ ~~income~~(54) ~~before~~$ ~~special~~(154) ~~items~~$ -- $ 1,366 Equity in earnings of affiliates .........~~....~~ $8 8394 $55 ~~114~~(7) $-- ~~261~~-- $-- ~~324~~150 ~~Net~~Corporate ~~income~~non-operating items Interest and debt expense ............. -- -- -- -- -- (311) -- (311) Interest income (net of misc. interest expense) .................... $-- 83-- $-- ~~114~~-- $-- ~~223(9)~~25 $-- ~~324~~25 ~~Earnings~~Other ~~per share Basic (7)~~ ................................ $ .13 $-- ~~.18~~-- $-- ~~.36~~-- $-- ~~.52~~(13) ~~Diluted~~-- (713) -------- -------- -------- -------- ---------- --------- -------- -------- Income before income taxes ............... 389 985 165 185 (54) (453) -- 1,217 Income tax expense ....................... $(67) ~~.13~~(451) $(46) ~~.18~~(56) $19 ~~.35~~128 $-- ~~.51~~(473) ~~Dividends~~-------- ~~per~~-------- ~~common~~-------- ~~share~~-------- ---------- --------- -------- -------- Net income (loss)(2) ..................... $ ~~.14~~322 $ ~~.19~~534 $ ~~.19~~119 $ ~~.19~~129 ~~Market~~$ ~~price~~(35) of$ ~~Class~~(325) A$ ~~common~~-- ~~stock~~$ 744 ======== ======== ======== ======== ========== ========= ======== ======== Capital employed at December 31(83) ~~High~~Excluding investment in affiliates .... $ 2,694 $ 2,842 $ 1,313 $ 884 $ 50 $ 232 $ -- $ 8,015 Investment in affiliates(4) ........... 166 620 260 526 32 -- -- 1,604 -------- -------- -------- -------- ---------- --------- -------- -------- Total capital employed ...................~~...~~ $ ~~25.44~~2,860 $ ~~31.25~~3,462 $ ~~29.25~~1,573 $ 291,410 $ 82 $ 232 $ -- $ 9,619 ======== ======== ======== ======== ========== ========= ======== ======== Return on capital employed (ROCE)(5).06..... ~~Low~~12.1% 16.0% 9.0% 8.8% N/A N/A -- 11.0% Significant non-cash items DD&A .................................. $ ~~19.38~~374 $ ~~22.94~~547 $ ~~25.31~~126 $ ~~20.94~~142 ~~Market~~$ ~~price~~-- of$ ~~Class~~4 B$ ~~common~~-- ~~stock~~$ ~~(8)~~1,193 ~~High~~Dry hole costs and impairment of unproved properties ................~~.....................~~ $ 16 $ 115 $ -- $ -- $ ~~29.38~~-- $ ~~28.94~~-- ~~Low~~$ -- $ 131 Capital expenditures and investments(6) .. $ 413 $ 839 $ 214 $ 248 $ 69 $ 4 $ -- $ 1,787 Total assets .............................~~.......~~ $ --3,502 $ --5,949 $ ~~24.50~~3,287 $ ~~20.75~~2,835 $ 91 $ 711 $ -- $ 16,375

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

~~MILLIONS~~2001 OF2000 ~~DOLLARS~~1999 -----------~~------------------------------------------------------------~~ ~~BALANCE AT BALANCE AT DESCRIPTION JANUARY 1 ADDITIONS DEDUCTIONS OTHER DECEMBER 31~~ ---------- --------- --~~--------~~ ~~--------~~Buy/sell ~~-----------~~supply ~~2000~~transactions ~~Deducted~~settled ~~from~~in ~~asset~~cash ~~accounts:~~Crude ~~Deferred tax asset valuation allowance~~ oil....... ~~$ 452 $ 80 $ 123 $ -- $ 409 Included in other accrued liabilities: Restructuring~~ ................................ ~~11 -- 6 5 -- Reserve for maintenance turnarounds~~ .......~~...~~ 62$ 553,770 46$ ~~(2)~~4,786 69$ ~~1999~~3,282 ~~Deducted~~Refined ~~from asset accounts: Deferred tax asset valuation allowance~~ products....... ~~423 80 51 -- 452 Included in other accrued liabilities: Restructuring~~ ................................ 82$ --1,803 71$ --1,703 11$ ~~Reserve~~747 ~~for~~Natural ~~maintenance~~gas ~~turnarounds~~ resales.......... ~~55 62 54 (1) 62 1998 Deducted from asset accounts: Deferred tax asset valuation allowance~~ .............................. ~~392~~$ 543,931 23$ --2,551 ~~423~~$ ~~Included~~1,242 inElectric ~~other~~power ~~accrued liabilities: Restructuring~~ resales................................ ~~-- 82 -- -- 82 Reserve for maintenance turnarounds~~ .....~~.....~~ 41$ 535 39$ --4 55$ 28

108 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) Sales to equity affiliates totaled $1,690 for 2001, $2,200 for 2000 and $1,519 for 1999. The majority of these sales was in downstream and represented refined products. (2) Includes after-tax benefits (charges) from the following items:

~~EXHIBIT~~UPSTREAM ~~NUMBER~~DOWNSTREAM ~~DESCRIPTION~~ ------------------ ------------------- 3EMERGING ELIMINA- CONSOLI- SEGMENT INFORMATION U.1S. INT'L. U.S. INT'L. BUSINESSES CORPORATE TIONS DATED -------- ~~Second~~------- ~~Amended~~-------- ~~and~~-------- ~~Restated~~----------- ~~Certificate~~--------- of-------- ~~Incorporation~~-------- of2001 ~~Conoco~~Asset ~~Inc.(1)~~sales 3.2.............................. $ 134 $ -- By$ -~~Laws~~- of$ ~~Conoco~~-- ~~Inc~~$ -- $ -- $ -- $ 134 Affiliate sales and write-downs .,.......... as23 ~~amended~~-- ~~October~~(23) ~~28,~~(23) ~~1999~~-- -- -- (223) 4Foreign currency exchange loss .1........... -- ~~Specimen~~-- ~~Certificate~~-- ~~for~~-- ~~shares~~-- of(38) ~~Class~~-- A(38) ~~Common~~Cumulative ~~Stock~~effect of ~~the~~accounting ~~Registrant~~change .... 8 32 (3) ~~4.2~~-- -- ~~Specimen~~-- ~~Certificate~~-- ~~for~~37 ~~shares~~Assets ofheld ~~Class~~for Bsale ~~Common~~and ~~Stock~~other ofwrite-downs ~~the~~....................... ~~Registrant~~(344) ~~4.3~~(87) -- ~~Preferred~~-- ~~Share~~-- ~~Purchase~~-- ~~Rights~~-- ~~Agreement~~(3131) 4Premium on debt retirement .4............... -- ~~Amendment~~-- to-- ~~Preferred~~-- ~~Share~~-- ~~Purchase~~(44) ~~Rights~~-- ~~Agreement~~(444) 4Humber fire repairs .5...................... -- ~~Second~~-- ~~Amendment~~-- to(54) ~~Preferred~~-- ~~Share~~-- ~~Purchase~~-- ~~Rights Agreement~~(554) 4Discontinued businesses .6.................. -- ~~Indenture~~-- ~~between~~-- ~~Conoco~~-- ~~and~~-- ~~the~~(70) ~~Trustee~~-- ~~relating~~(70) toLitigation ~~the~~................................ ~~Debt~~-- ~~Securities~~-- (641) ~~10.1#~~-- -- ~~Employment~~-- ~~Agreement,~~-- ~~dated~~(41) ~~October~~Other ~~19,~~..................................... ~~2000~~-- ~~between~~-- ~~Conoco~~-- ~~and~~-- ~~Archie~~-- W.(4) ~~Dunham~~-- (74) ~~10.2#~~-------- ------- ~~Conoco~~-------- ~~Inc~~-------- ----------- -------- ------- ------- Total special items ....................... ~~Key~~$ ~~Employee~~121 ~~Severance~~$ ~~Plan,~~(55) as$ ~~amended~~(867) ~~10.3#~~$ (77) $ -- ~~Conoco~~$ ~~Inc.~~(156) ~~Key~~$ ~~Employee~~-- ~~Temporary~~$ ~~Severance~~(234) ~~Plan,~~======== as======= ~~amended(9)~~======== 10======== =========== ======== ======= ======= 2000 Asset sales .4#.............................. $ 27 $ -- ~~Conoco~~$ ~~Inc.~~-- ~~Salary~~$ ~~Deferral~~-- $ -- $ -- $ -- $ 27 Affiliate sales and ~~Savings~~write-downs ~~Restoration~~........... ~~Plan,~~-- as-- ~~amended~~-- -- (1026) ~~10.5#~~-- -- ~~Directors'~~(26) ~~Charitable~~Inventory ~~Gift~~write-downs ~~Plan,~~..................... as-- ~~amended~~-- -- (1024) ~~10.6#~~-- -- ~~Deferred~~-- ~~Compensation~~(24) ~~Plan~~Assets held for ~~Nonemployee~~sale ~~Directors,~~and asother ~~amended~~write-downs ~~May~~....................... ~~12,~~-- ~~1999~~-- (113) ~~10.7#~~-- -- ~~Form~~-- ~~Indemnity~~-- ~~Agreement with Directors~~(123) 10Discontinued businesses .8#.................. -- ~~1998~~-- ~~Stock~~-- ~~and~~-- ~~Performance~~-- ~~Incentive~~(4) ~~Plan,~~-- as(4) ~~amended~~Litigation ~~October~~................................ ~~28,~~-- ~~1999~~-- (1316) ~~10.9#~~-- -- ~~1998~~-- ~~Key~~-- ~~Employee~~(16) ~~Stock~~-------- ~~Performance~~------- ~~Plan,~~-------- as-------- ~~amended~~---------- ~~October~~-------- ~~28,~~------- ~~1999(14)~~------- 10Total special items .~~11#~~...................... $ 27 $ -- ~~Rabbi~~$ ~~Trust~~(19) ~~Agreement~~$ ~~dated~~(24) ~~December~~$ ~~17,~~(26) ~~1999~~$ (154) 11$ -- ~~Statement~~$ ~~re:~~(46) ~~Computation~~======== of======= ~~Per~~======== ~~Share~~======== ~~Earnings(7)~~========== 12======== ======= ======= 1999 Discontinued businesses ................... $ -- ~~Computation~~$ of-- ~~Ratio~~$ of-- ~~Earnings~~$ to-- ~~Fixed~~$ ~~Charges~~-- $ (720) 21$ -- $ (20) Litigation .1............................... -- ~~List~~-- of(18) ~~Principal~~-- ~~Subsidiaries~~-- of-- ~~the~~-- ~~Registrant~~(718) 23-------- ------- -------- -------- ----------- -------- ------- ------- Total special items .1...................... $ -- ~~Consent~~$ of-- ~~PricewaterhouseCoopers~~$ ~~LLP~~(718) 24$ -- ~~Power~~$ of-- ~~Attorney~~$ (720) ~~99.1~~$ -- ~~Consent~~$ ~~of Solomon Associates~~(738) ======== ======= ======== ======== =========== ======== ======= =======

Special items in 2001 included gains of $194, consisting of: o $134 from the sale of several shallow Gulf of Mexico properties; o $23 from the sale of our interest in the Pocahontas Gas Partnership; and o $37 from a cumulative transition gain recorded on January 1, 2001, upon initial adoption of SFAS No. 133, as amended. The cumulative transition gain of $37 included a $40 gain in upstream related to changes in the fair value of certain crude oil put options from their purchase date to the January 1, 2001, adoption of the aforementioned standards and a $3 charge in U.S. downstream associated with various derivatives. The $40 upstream transition gain consisted of $8 that was U.S. related and $32 that was related to international operations. Offsetting this transition gain and included in net income for upstream was a $53 expense for 2001 related to changes in the fair value of these same crude oil put options. The $53 expense for 2001 consisted of $10 for U.S. operations and $43 for international operations. Offsetting these gains were: o downstream affiliate sales and write-downs of $46, consisting of a $23 write-down of a U.S. joint-venture investment held for sale and a $23 write-down of an international joint-venture investment held for sale; o a $38 foreign currency exchange loss from changes in the fair value of Canadian dollar forward exchange contracts related to the acquisition of Gulf Canada; o upstream assets held for sale and other write-downs of $131, consisting of a $44 write-down of certain U.S. producing assets held for sale and an $87 write-down of Canadian legacy assets held for sale; o $44 for extraordinary item charges for premiums on the early repayment of high-cost Gulf Canada debt; o a $54 charge to record repairs and other costs associated with the April 16, 2001, explosion and fire at our Humber refinery in North Lincolnshire, U.K.; o an accrual of $70 for a litigation settlement for a discontinued business related to the separation agreement from DuPont; o a $41 charge related to an adverse ruling on the patent dispute with GTA; and 109 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) o $4 in costs associated with the ConocoPhillips merger. Special items in 2000 included a $27 gain from the sale of U.S. natural gas processing assets. This asset sale was part of Conoco's effort to move away from a midstream business of scattered assets in mature areas toward a business built on centralized, large-scale gas processing systems. The following charges also were recorded during 2000: o affiliate sales and write-downs of $26; o $24 write-down of inventories to market value; o assets held for sale and other write-downs of $3 for U.S. refinery assets; o $4 from discontinued businesses; and o $16 from U.S. downstream litigation charges. The after-tax affiliate sales and write-downs were the result of our write-off of $26 related to our 37.5 percent interest in a Colombian power venture. The Colombian power venture write-off was due to unfavorable business conditions in Colombia. In October 1996, Conoco Global Energy purchased shares in a Colombian power venture that was formed to generate and market electric power by means of a gas-fired electrical generating facility near Barrancabermeja, Colombia. The gas-fired plant became operational in August 1998 and received capacity payments for idle periods. With the deterioration of the Colombian economy, the plant suffered small losses in 1998 and 1999. The continued weak demand for electricity created a large surplus in generating capacity, prompting a reduction in the capacity payment rate for 2000. A combination of lower capacity payment revenue, continued weak demand for electricity, onerous gas supply contract provisions, safety and security concerns from continued guerrilla activity, and forecasted losses for 2000 prompted management's decision in the third quarter of 2000 to exit the venture, resulting in a revaluation of the investment. After pursuing various options, Conoco's interest was sold in February 2001 for a nominal amount. The $24 write-down of inventories at year-end 2000 was the result of significant declines in crude oil and finished product prices during December. The write-down occurred at our Melaka refinery joint venture as Dubai crude oil prices fell from $33.00 per barrel to $23.00 per barrel during December. The $4 loss was for settlement costs associated with the separation agreement from DuPont related to a discontinued business. Special items in 1999 included charges for $18 related to the settlement of certain posted price litigation and $20 for the resolution of certain liabilities associated with the separation from DuPont related to discontinued businesses operated by Conoco in the past. Net income before special items (earnings before special items) totaled $1,823 in 2001, $1,948 in 2000 and $782 in 1999. (3) Capital employed is equivalent to the sum of stockholders' equity, minority interests and borrowings (both short-term and long-term) and excludes goodwill. Borrowings include amounts due to related parties, net of associated notes receivable. Amounts identified for operating segments comprise those assets and liabilities not deemed to be of a general corporate nature, including cash and cash equivalents, financing-oriented items and aviation investment. (4) Investment in affiliates (including advances) for Petrozuata was $822, $693 and $445 for 2001, 2000 and 1999, respectively. (5) ROCE is a measure of annual net income before special items, excluding after-tax debt cost incurred and minority interests incurred, generated as a percentage of the two-year average capital employed as defined above. (6) Includes investments in affiliates. (7) Includes goodwill arising from the third quarter 2001 acquisition of Gulf Canada. Upon full implementation in 2002 of SFAS No. 142, this amount will be disclosed in the reporting segments that include the "Reporting Units" to which this goodwill must be allocated in accordance with the requirement of this standard.

----------------- (1) Revenues are attributed to countries based on location of the selling entity. (2) Represents net PP&E. 110 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) 30. INVESTING ACTIVITIES In 2001, purchases of businesses included $4,571 cash paid for Gulf Canada. See note 3 for details of the acquisition. Purchases of businesses in 2000 included a third quarter cash purchase of Saga U.K. Ltd. for $545, which was allocated $796 to fixed assets, $92 to other assets and $343 to liabilities assumed. In 1999, Conoco purchased substantially all of Petro-Canada's natural gas liquids business for $176 cash, which was allocated $189 to fixed assets, $9 to working capital and $22 to deferred taxes and liabilities assumed. The pro forma effect on prior period revenue, net income and earnings per share was not material. Non-cash additions to PP&E were $61 for 2001, $41 for 2000 and zero for 1999. Total proceeds in 2001 from the sales of assets of $795 included the shallow Gulf of Mexico properties for $294; the third quarter sale of our 50 percent interest in the Pocahontas Gas Partnership for $152; Lobo natural gas properties for $69; and the disposition of various U.K. retail assets for $98. For 2000, total proceeds from sales of assets of $222 included the sale of Oklahoma gas plants and the sale of retail assets in the Dallas-Fort Worth area and the Gulf Coast region. There were no significant proceeds from any single asset sale in 1999. The after-tax earnings impact of such asset sales was a gain of $197 in 2001, $47 in 2000 and $10 in 1999. The carrying value of assets held for sale, primarily upstream property, plant and equipment, totaled $42 at December 31, 2001, and zero at December 31, 2000. 31. OTHER FINANCIAL INFORMATION Research and development expenses were $96 for 2001, $58 for 2000, and $54 for 1999. 32. TRANSACTIONS WITH DUPONT As disclosed in note 1, DuPont ceased to be a related party effective August 6, 1999. However, the 1999 consolidated financial statements included related-party transactions with DuPont involving services such as cash management, other financial services, purchasing, legal, computer, corporate aviation and general corporate expenses that were provided between Conoco and DuPont organizations. Amounts charged to Conoco for these services were $21 for 1999. These amounts were principally included in selling, general and administrative expenses. We provided DuPont services such as computer, legal and purchasing, as well as certain technical and plant operating services. Charges for these services amounted to $15 for 1999. These charges to DuPont were treated as reductions, as appropriate, of cost of goods sold, operating expenses or selling, general and administrative expenses. Interest expense charged by DuPont was $91 for 1999 and reflected market-based interest rates. A portion of historical related-party interest cost and other interest expense was capitalized as cost associated with major construction projects. Sales and other operating revenues included sales of products from Conoco to DuPont; principally natural gas and gas liquids supplied to several DuPont plant sites. These sales totaled $211 for 1999. In connection with the separation from DuPont and the initial public offering, Conoco and DuPont entered into a Tax Sharing Agreement and a Restructuring, Transfer and Separation Agreement. Certain disputes arose under these agreements and on November 8, 2001, these matters were settled. The $93 net effect of this settlement is included in additional paid-in capital as an adjustment to capitalization from DuPont. 33. SUBSEQUENT AND OTHER EVENTS On November 18, 2001, Conoco and Phillips Petroleum Company (Phillips) announced that their boards of directors unanimously approved the merger of the two companies. The new company will be named ConocoPhillips. Under the terms of the agreement, Phillips shareholders will receive one share of new ConocoPhillips common stock for each share of Phillips stock they own, and Conoco shareholders will receive .4677 shares of new ConocoPhillips common stock for each share they own. The merger is conditioned upon, among other things, the approvals of the shareholders of each company and customary regulatory approvals. Both 111 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN MILLIONS, EXCEPT PER SHARE) companies intend to hold special meetings of stockholders on Tuesday, March 12, 2002, to seek approval of the proposed merger. Completion of the transaction is expected in the second half of 2002. On February 14, 2002, Gulf Canada announced that its board of directors approved the redemption of its Series I and Series II preferred stock and its 6.45 percent senior unsecured Canadian $100 notes due 2007. The Series II preferred shares will be redeemed on April 10, 2002, at a cost of Canadian $150; while both the Series I preferred shares and the 6.45 percent senior unsecured notes will be redeemed on April 22, 2002, at a cost of Canadian $472 and Canadian $106, respectively. See notes 20 and 22 for further details. In January 2002, Immingham CHP, L.L.P., a subsidiary of Conoco, executed a British pound 257 million bank facility for the planned construction of a 730- megawatt combined heat and power cogeneration plant near our Humber refinery in the U.K. The bank facility is designed to provide 65 percent of the construction costs of the project with the remaining 35 percent of the funds coming in the form of equity from certain Conoco subsidiaries. Borrowing under the bank facility is not projected to begin until September 2002. In addition, we have issued a construction support guarantee that indirectly guarantees up to approximately 25 percent of the debt depending upon the initial operating performance of the plant. This guarantee will be released upon meeting the various completion tests as required by the lenders. Subsequent to closing the facility and as required by the lender to mitigate certain risks, Immingham CHP entered into related foreign currency and interest rate derivative hedging instruments. 112 SUPPLEMENTAL PETROLEUM DATA (UNAUDITED) (DOLLARS IN MILLIONS) OIL AND GAS PRODUCING ACTIVITIES AND SYNCRUDE MINING OPERATIONS Supplemental Petroleum Data is comprised of information related to oil, gas and Canadian oil sands. Oil and gas disclosures are presented in accordance with SFAS No. 69, "Disclosures about Oil and Gas Producing Activities." Management views the oil sands reserves related to the Canadian Syncrude project and their development as an integral part of the oil and gas operations of the company. However, generally accepted accounting principles define these reserves as mining related and exclude these reserves from the conventional definition of oil and gas reserves. As a result, oil sands information, identified as "Syncrude Oil - Canada," is presented separately in the following Supplemental Petroleum Data. RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES AND SYNCRUDE MINING OPERATIONS

------------------- (1) 2001 includes $38 in hedge realizations in the U.S. (2) Includes exploration operating expenses, dry hole costs and impairment of unproved properties and depreciation. (3) Includes impairment of assets held for sale in 2001 of $69 in the U.S. and $127 in Canada. (4) Includes gain/(loss) on disposal of fixed assets and other miscellaneous revenues and expenses. (5) Includes mark-to-market gains on derivatives not designated as hedges under SFAS No. 133, as amended, of $214 in the U.S. and $10 in Canada. (6) Includes our net share of equity affiliate information. (7) Represents our 9.03 percent undivided interest in the Syncrude oil project. 113 SUPPLEMENTAL PETROLEUM DATA (UNAUDITED) (DOLLARS IN MILLIONS) COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES AND SYNCRUDE MINING OPERATIONS(1)

------------------- (1) These data comprise all costs incurred in the activities shown, whether capitalized or charged to expense at the time they were incurred. (2) Does not include properties acquired through property trades. (3) Acquisition costs are shown after a gross up for SFAS No. 109, "Accounting for Income Taxes" of $190 in 2001 and $204 in 2000 for European properties; and a gross up of $48 in 1999 for Canadian properties. (4) Includes our net share of equity affiliate information. (5) Represents our 9.03 percent undivided interest in the Syncrude oil project. 114 SUPPLEMENTAL PETROLEUM DATA (UNAUDITED) (DOLLARS IN MILLIONS) CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES AND SYNCRUDE MINING OPERATIONS

------------------- (1) Includes our net share of equity affiliate information. (2) Represents our 9.03 percent undivided interest in the Syncrude oil project. 115 SUPPLEMENTAL PETROLEUM DATA (UNAUDITED) The SEC defines proved reserves as the quantities of crude oil, condensate, natural gas liquids and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those volumes that are expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are those volumes that are expected to be recovered as a result of future investments to drill new wells; recompletion of existing wells; and/or installation of facilities to collect and deliver the production from existing and future wells. In addition to conventional liquids and natural gas proved reserves defined by the SEC, we have significant interests in proven oil sands in Canada associated with the Syncrude oil project. ESTIMATED PROVED RESERVES OF OIL, GAS AND SYNCRUDE IN MILLIONS OF BARRELS-OF-OIL-EQUIVALENT (MMBOE)

------------------- (1) Oil reserves comprise crude oil and condensate, and natural gas liquids expected to be removed for Conoco's account from its natural gas deliveries. (2) Natural gas has been converted to liquids at a ratio of 6,000 cubic feet of natural gas to 1 barrel of liquid. (3) 2001 includes a minority interest holding of 67 MMBOE. (4) Includes our net share of equity affiliate information. (5) Proven oil sands reserves are attributable to our 9.03 percent undivided interest in the Syncrude oil project after deducting estimated net profit royalty. Additional reserves will be added as development progresses. (6) Purchase of reserves in 2001 includes 928 MMBOE for Gulf Canada. 116 SUPPLEMENTAL PETROLEUM DATA (UNAUDITED) ESTIMATED PROVED RESERVES OF OIL AND SYNCRUDE IN MILLIONS OF BARRELS

---------------- (1) Oil reserves comprise crude oil and condensate, and natural gas liquids expected to be removed for Conoco's account from its natural gas deliveries. (2) Includes reserves acquired through property trades. (3) Includes reserves disposed of through property trades. (4) Includes our net share of equity affiliate information. (5) Purchase of reserves in 2001 includes 510 MMBOE for Gulf Canada. (6) Proven oil sands reserves are attributable to our 9.03 percent undivided interest in the Syncrude oil project, after deducting estimated net profit royalty. Additional reserves will be added as development progresses. (7) Other Regions includes a minority interest holding of 5 MMBOE for 2001. 117 SUPPLEMENTAL PETROLEUM DATA (UNAUDITED) ESTIMATED PROVED RESERVES OF GAS IN BILLION CUBIC FEET (bcf)

---------------- (1) Includes Other Regions' price-driven revisions to gas reserve entitlements under production-sharing contracts and similar arrangements. (2) Includes reserves acquired through property trades. (3) Purchase of reserves in 2001 includes 2,503 bcf for Gulf Canada. (4) Includes reserves disposed of through property trades. (5) Year 2000 data includes revisions due to wet gas and natural gas liquids accounting realignment in the U.S. This resulted in net additional reserves of 11 MMBOE. (6) Includes our net share of equity affiliate information. (7) In 2001, Other Regions includes a minority interest holding of 376 bcf. 118 SUPPLEMENTAL PETROLEUM DATA (UNAUDITED) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES The following information has been prepared in accordance with SFAS No. 69, which requires the standardized measure of discounted future net cash flows to be based on year-end prices, costs and statutory income tax rates and a 10 percent annual discount rate. Specifically, the per barrel oil prices used to calculate the December 31, 2001, data averaged $16.72 for the U.S., $17.31 for Canada, $17.79 for Europe and $18.43 for other regions. The gas prices per thousand cubic feet averaged $2.41 for the U.S., $1.96 for Canada, $3.64 for Europe and $2.65 for Other Regions. Because prices used in the calculation are as of December 31, the standardized measure could vary significantly from year to year based on market conditions at that specific date. Future net cash flows from our interest in Canadian Syncrude are excluded, as are gains from closing current commodity hedge positions. The projections should not be viewed as realistic estimates of future cash flows nor should the "standardized measure" be interpreted as representing current value to Conoco. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used and actual costs also may vary. Conoco's investment and operating decisions are not based on the information presented on the following page, but on a wide range of reserve estimates that include probable as well as proved reserves, and on different price and cost assumptions from those reflected in this information. 119 SUPPLEMENTAL PETROLEUM DATA (UNAUDITED) (DOLLARS IN MILLIONS) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES

------------- (1) Includes our net share of equity affiliate information. (2) Does not include the discounted future net cash flows from Canadian Syncrude of $472 and unrecognized hedge positions of $92 after-tax at December 31, 2001. (3) In 2001, Other Regions includes $170 for a minority interest holding. 120 SUPPLEMENTAL PETROLEUM DATA (UNAUDITED) (DOLLARS IN MILLIONS) SUMMARY OF CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES

-------------------- (1) Includes our net share of equity affiliate information. (2) Purchases (sales) of reserves in place - net in 2001 includes $2,644 for Gulf Canada recognizing the proved reserves upon the mid-year 2001 acquisition valued at year-end prices less estimated future costs. 121 CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED) (DOLLARS IN MILLIONS, EXCEPT PER SHARE)

(1) Excludes other income and equity in earnings of affiliates of $52, $173, $194 and $383 in each of the quarters in 2001 and $167, $149, $110 and $124 in each of the quarters in 2000. (2) Includes a reclassification of revenues previously reported as a reduction in cost of goods sold and other expenses for sales of crude oil from Conoco's subsidiaries of $90, $117 and $77 for the first, second and third quarters of 2001, respectively. 122 CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED) (DOLLARS IN MILLIONS, EXCEPT PER SHARE) (3) Excludes provision for income taxes. (4) Includes $37 for a cumulative transition gain recorded on January 1, 2001, upon initial adoption of SFAS No. 133, as amended. (5) Includes a $54 charge to record repairs and other costs associated with the April 16, 2001 explosion and fire at our Humber refinery in North Lincolnshire, U.K. (6) Includes a $23 gain from the sale of our Pocahontas Gas Partnership, a write-down of $44 of certain upstream producing assets held for sale, a write-down of $23 of a downstream joint-venture investment held for sale, a charge of $41 related to an adverse ruling on the patent dispute with GTA, a $24 extraordinary item charge for a premium on the early repayment of Gulf Canada debt securities and a foreign currency exchange loss of $38 associated with the purchase of Gulf Canada. (7) Includes $70 for settlement costs associated with the separation agreement from DuPont related to a discontinued business; $87 for the write-down of western Canadian legacy assets held for sale; $23 for the write-down of an equity investment held for sale; $20 premium charge on the early retirement of debt related to the acquisition of Gulf Canada; and $4 of costs associated with the ConocoPhillips merger; partially offset by a $134 gain from the sale of various Gulf of Mexico properties. (8) Includes $8 reflecting a $27 gain from the sale of natural gas processing assets in the U.S., partially offset by a $16 loss for litigation provisions and $3 for the write-off of related refinery assets. (9) Includes $4 for settlement costs associated with the separation agreement from DuPont related to a discontinued business. (10) Includes $26 for the write-off of our share of a Colombian power venture. (11) Includes $24 related to the write-down of an international refinery venture's inventories to market value. (12) Earnings per share for the year may not equal the sum of the quarterly earnings per share due to changes in average shares outstanding (see note 10 to the consolidated financial statements). (13) On September 21, 2001, our shareholders approved the combination of Conoco's Class A and Class B common stock into a single class of new common stock on a one-for-one basis. As a result of the combination, each outstanding share of Class A and Class B common stock was converted into one share of a new class of a common stock. On October 8, 2001, the combination was effective and the new common stock began trading on the New York Stock Exchange under the symbol COC. The stock symbols COC.A and COC.B no longer apply. Prices are reported by the New York Stock Exchange. (14) Conoco's Class A common stock commenced trading on October 22, 1998, subsequent to Conoco's initial public offering. Class B common stock commenced trading on August 16, 1999, subsequent to the conclusion of DuPont's exchange offer, which resulted in 100 percent of Class B common stock being distributed to DuPont shareholders. Class A and Class B common stock (trading symbol COC.A and COC.B) traded on the New York Stock Exchange until October 8, 2001, when they were combined into a single class of common stock. Prices are reported by the New York Stock Exchange. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III Except as indicated below, information with respect to the following items is incorporated by reference to Conoco's 2002 annual meeting proxy statement filed in connection with the annual meeting of stockholders to be held on May 21, 2002. ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required by this item will be set forth under the captions "Proposal 2 -- Election of Directors" and "Stock Ownership of Directors and Executive Officers -- Beneficial Ownership Reporting Compliance" in Conoco's definitive proxy statement (the "2002 proxy statement") for its annual meeting of stockholders to be held on May 21, 2002, which sections are incorporated herein by reference. Pursuant to general instruction G to Form 10-K, the information required by Item 401 of Regulation S-K with respect to executive officers of Conoco is set forth under the caption "Executive Officers of the Registrant" in Part 1 of this report (page 37). ITEM 11. EXECUTIVE COMPENSATION The information required by this item will be set forth under the captions "Proposal 1 -- Election of Directors -- Board Compensation" and "Compensation of Executive Officers" in the 2002 proxy statement, which sections are incorporated herein by reference. 123 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required by this item is set forth under the captions "Principal Stockholders" and "Stock Ownership of Directors and Executive Officers" in the 2002 proxy statement, which sections are incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Any information required by this item will be set forth under the captions "Compensation of Executive Officers -- Certain Relationships and Related Transactions" in the 2002 proxy statement, which section is incorporated herein by reference. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) Financial statements, financial statement schedules and exhibits 1. Financial statements (see Part II, Item 8 of this report regarding financial statements). 2. Financial statement schedules. The following should be read in conjunction with the previously referenced financial statements -- financial statement schedules listed under SEC rules but not included in this report are omitted because they are not applicable or the required information is shown in the financial statements or notes. Condensed financial information of the parent company is omitted because restricted net assets of consolidated subsidiaries do not exceed 25 percent of consolidated net assets. Footnote disclosure of restrictions on the ability of subsidiaries and affiliates to transfer funds is omitted because the restricted net assets of subsidiaries combined with Conoco's equity in the undistributed earnings of affiliated companies does not exceed 25 percent of consolidated net assets at December 31, 2001. Separate financial statements of affiliated companies accounted for by the equity method are omitted because no such affiliate individually constitutes a 20 percent significant subsidiary. Included on page 129 of this annual report on Form 10-K is financial statement Schedule II -- Valuation and Qualifying Accounts. 3. Exhibits The following list of exhibits includes both exhibits submitted with this Form 10-K as filed with the SEC and those incorporated by reference to other filings:

124

125

---------- * Filed herewith. # Management contract or compensatory plan or arrangement required to be filed as an exhibit to this Form 10-K. (b) Reports on Form 8-K 1. In a current report on Form 8-K dated October 5, 2001, we reported pursuant to Item 5 of Form 8-K that on October 3, 2001, we had entered into an underwriting agreement relating to the offering by us of $500 million principal amount of Floating Rate Notes due October 15, 2002, and $500 million principal amount of Floating Rate Notes due April 15, 2003, and we had also, with Conoco Funding Company, our wholly owned finance subsidiary, entered into an underwriting agreement relating to the offering by Conoco Funding of $1,250 million principal amount of 5.45 percent Notes due 2006, $1,750 million principal amount of 6.35 percent Notes due 2011 and $500 million principal amount of 7.25 percent Notes due 2031 fully and unconditionally guaranteed by us. We also filed as exhibits pursuant to Item 7 of Form 8-K (i) the underwriting agreements, (ii) the form of the terms of the Floating Rate Notes, including the form of note, (iii) the form of the terms of the Conoco Funding Notes, including the form of note, (iv) an opinion of Baker Botts L.L.P., our counsel, as to certain tax matters and (v) the Statement of Eligibility and Qualification under the Trust Indenture Act of 1939 of the Conoco Funding Trustee on Form T-1. 2. In a current report on Form 8-K dated October 9, 2001, we furnished pursuant to Item 9 of Form 8-K a copy of an IR Gram relating to our commodity price hedging activities, which was posted on our web site on October 9, 2001. 3. In a current report on Form 8-K dated October 22, 2001, we furnished pursuant to Item 9 of Form 8-K unaudited quarterly pro forma financial data for the year ended December 31, 2000, and the six-month 126 period ended June 30, 2001 for Conoco and Gulf Canada, and unaudited quarterly capital expenditure and operating data for the year ended December 31, 2000, and the six-month period ended June 30, 2001 for Gulf Canada. 4. In a current report on Form 8-K dated November 14, 2001, we furnished pursuant to Item 9 of Form 8-K a slide presentation that was posted on our website in connection with our security analyst meeting on November 14, 2001. 5. In a current report on Form 8-K dated November 19, 2001, we reported pursuant to Item 5 of Form 8-K that we had entered a merger agreement with Phillips. We also filed as exhibits pursuant to Item 7 of Form 8-K the merger agreement and the joint press release dated November 18, 2001 that we issued with Phillips with respect to the transaction. 127 REPORT OF INDEPENDENT ACCOUNTANTS ON FINANCIAL STATEMENT SCHEDULE To the Stockholders and the Board of Directors of Conoco Inc.: Our audit of the consolidated financial statements referred to in our report dated February 19, 2002 appearing in the 2001 Annual Report to Shareholders of Conoco Inc. (which report and consolidated financial statements are included in this Annual Report on Form 10-K) also included an audit of the financial statement schedule listed in Item 14(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. PRICEWATERHOUSECOOPERS LLP Houston, Texas February 19, 2002 128 CONOCO INC. SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999 (IN MILLIONS OF DOLLARS)

---------- * As a result of the Gulf Canada acquisition. 129 SIGNATURES Pursuant to the requirements of Section 13 of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized and in the capacities indicated, as of the 15th day of March, 2002. CONOCO INC. (REGISTRANT) BY: /s/ ROBERT W. GOLDMAN ------------------------------------- Robert W. Goldman Senior Vice President, Finance, and Chief Financial Officer BY: /s/ W. DAVID WELCH ------------------------------------- W. David Welch Vice President, Controller and Principal Accounting Officer Pursuant to the requirements of the Securities exchange Act of 1934; this report has been signed, as of the 15th day of March, 2002, by the following persons on behalf of the registrant in the capacities indicated: /s/ ARCHIE W. DUNHAM Chairman, President and Chief Executive Officer ----------------------------------- Archie W. Dunham Senior Vice President, Finance, and Chief Financial /s/ ROBERT W. GOLDMAN Officer ----------------------------------- Robert W. Goldman Vice President, Controller and Principal Accounting /s/ W. DAVID WELCH Officer ----------------------------------- W. David Welch /s/ RICHARD H. AUCHINLECK Director ----------------------------------- Richard H. Auchinleck /s/ KENNETH M. DUBERSTEIN Director ----------------------------------- Kenneth M. Duberstein /s/ RUTH R. HARKIN Director ----------------------------------- Ruth R. Harkin /s/ CHARLES C. KRULAK Director ----------------------------------- Charles C. Krulak /s/ FRANK A. MCPHERSON Director ----------------------------------- Frank A. McPherson /s/ WILLIAM K. REILLY Director ----------------------------------- William K. Reilly /s/ WILLIAM R. RHODES Director ----------------------------------- William R. Rhodes /s/ FRANKLIN A. THOMAS Director ----------------------------------- Franklin A. Thomas /s/ A. R. SANCHEZ, JR. Director ----------------------------------- A. R. Sanchez, Jr.

130 INDEX TO EXHIBITS

131

---------- * Filed herewith. # Management contract or compensatory plan or arrangement required to be filed as an exhibit to this Form 10-K. 132

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