10-K 1 h03367e10vk.txt CONOCOPHILLIPS - YEAR ENDED DECEMBER 31, 2002 2002 ================================================================================ 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, 2002 COMMISSION FILE NUMBER 000-49987 CONOCOPHILLIPS (Exact name of registrant as specified in its charter) DELAWARE 01-0562944 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 600 NORTH DAIRY ASHFORD HOUSTON, TX 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:
NAME OF EACH EXCHANGE TITLE OF EACH CLASS ON WHICH REGISTERED ------------------------------------------------------ ------------------------ Common Stock, $.01 Par Value New York Stock Exchange Preferred Share Purchase Rights Expiring June 30, 2012 New York Stock Exchange 6 3/8% Notes due 2009 New York Stock Exchange 6.65% Notes due March 1, 2003 New York Stock Exchange 6.65% Debentures due July 15, 2018 New York Stock Exchange 7% Debentures due 2029 New York Stock Exchange 7.125% Debentures due March 15, 2028 New York Stock Exchange 7.20% Notes due November 1, 2023 New York Stock Exchange 7.92% Notes due April 15, 2023 New York Stock Exchange 8.5% Notes due 2005 New York Stock Exchange 8.75% Notes due 2010 New York Stock Exchange 9 3/8% Notes due 2011 New York Stock Exchange
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 the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. |X| Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes |X| No | | Excluding shares held by affiliates, the registrant had 672,131,287 shares of Common Stock, $.01 Par Value, outstanding at February 28, 2003. The aggregate market value of common stock held by non-affiliates of the registrant was $34,077,056,251 as of February 28, 2003. The registrant, solely for the purpose of this required presentation, has deemed its Board of Directors and the Compensation and Benefits Trust to be affiliates, and deducted their stockholdings of 6,156,952 and 26,785,094 shares, respectively, in determining the aggregate market value. DOCUMENTS INCORPORATED BY REFERENCE: Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 6, 2003 (Part III) ================================================================================ TABLE OF CONTENTS
PART I Item Page ---- ---- 1 and 2. Business and Properties ............................................. 1 Corporate Structure and Current Developments .................... 1 Segment and Geographic Information .............................. 2 Exploration and Production (E&P) ............................ 2 Midstream ................................................... 17 Refining and Marketing (R&M) ................................ 18 Chemicals ................................................... 25 Emerging Businesses ......................................... 27 Competition ..................................................... 28 General ......................................................... 29 3. Legal Proceedings ................................................... 29 4. Submission of Matters to a Vote of Security Holders ................. 32 Executive Officers of the Registrant ................................ 32 PART II 5. Market for Registrant's Common Equity and Related Stockholder Matters 34 6. Selected Financial Data ............................................. 35 7. Management's Discussion and Analysis of Financial Condition and Results of Operations ........................................... 36 7a. Quantitative and Qualitative Disclosures About Market Risk .......... 78 8. Financial Statements and Supplementary Data ......................... 82 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ............................................ 174 PART III 10. Directors and Executive Officers of the Registrant .................. 175 11. Executive Compensation .............................................. 175 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters ................................. 175 13. Certain Relationships and Related Transactions ...................... 175 14. Controls and Procedures ............................................. 176 PART IV 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K .... 176
PART I Unless otherwise indicated, "the company" and "ConocoPhillips" are used in this report to refer to the businesses of ConocoPhillips and its consolidated subsidiaries. "Conoco" and "Phillips" are used in this report to refer to the individual companies prior to the merger date of August 30, 2002. Items 1 and 2, Business and Properties, contain forward-looking statements including, without limitation, statements relating to the company's plans, strategies, objectives, expectations, intentions, and resources, that are made pursuant to the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995. The words "forecasts," "intends," "believes," "expects," "plans," "scheduled," "anticipates," "estimates," and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any of the forward-looking information. Readers are cautioned that such forward-looking statements should be read in conjunction with the company's disclosures under the heading: "CAUTIONARY STATEMENT FOR THE PURPOSES OF THE `SAFE HARBOR' PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995," beginning on page 76. ConocoPhillips files annual, quarterly and current reports, proxy statements and other information with the U.S. Securities and Exchange Commission (SEC). These filings are available free of charge through the company's internet website at www.conocophillips.com as soon as reasonably practicable after the company electronically files such material with, or furnishes it to, the SEC. ITEMS 1 AND 2. BUSINESS AND PROPERTIES CORPORATE STRUCTURE AND CURRENT DEVELOPMENTS ConocoPhillips is a major, integrated, global energy company. ConocoPhillips was incorporated in the state of Delaware on November 16, 2001, in connection with, and in anticipation of, the merger between Conoco Inc. (Conoco) and Phillips Petroleum Company (Phillips). The merger between Conoco and Phillips (the merger) was consummated on August 30, 2002, at which time Conoco and Phillips combined their businesses by merging with separate acquisition subsidiaries of ConocoPhillips. As a result of the merger, Conoco and Phillips each became wholly owned subsidiaries of ConocoPhillips. For accounting purposes, Phillips was designated as the acquirer of Conoco and ConocoPhillips was treated as the successor of Phillips. Accordingly, Phillips' operations and results are presented in this Form 10-K for all periods prior to the close of the merger. From the merger date forward, the operations and results of ConocoPhillips reflect the combined operations of the two companies. Subsequent to the merger, Conoco was renamed ConocoPhillips Holding Company, and Phillips was renamed ConocoPhillips Company, but for ease of reference, those companies will be referred to respectively in this document as Conoco and Phillips. ConocoPhillips' business is organized into five operating segments: 1) Exploration and Production (E&P)--This segment explores for and produces crude oil, natural gas, and natural gas liquids worldwide, and mines oil sands to extract bitumen and upgrade it into synthetic crude oil. 2) Midstream--This segment gathers and processes natural gas produced by ConocoPhillips and others, and fractionates and markets natural gas liquids, primarily in the United States, Canada and Trinidad. The Midstream segment includes ConocoPhillips' 30.3 percent equity investment in Duke Energy Field Services, LLC, a joint venture with Duke Energy. 1 3) Refining and Marketing (R&M)--This segment refines, markets and transports crude oil and petroleum products, primarily in the United States, Europe and Asia. 4) Chemicals--This segment manufactures and markets petrochemicals and plastics on a worldwide basis. The Chemicals segment consists primarily of ConocoPhillips' 50 percent equity investment in Chevron Phillips Chemical Company LLC, a joint venture with ChevronTexaco Corporation. 5) Emerging Businesses--This segment encompasses the development of new businesses beyond the company's traditional operations. Emerging Businesses includes new technologies related to carbon fibers, natural gas conversion into clean fuels and related products (gas-to-liquids), fuels technology, and power generation. At December 31, 2002, ConocoPhillips employed approximately 57,000 people in over 40 countries. SEGMENT AND GEOGRAPHIC INFORMATION For operating segment information and geographic information, see Note 26--Segment Disclosures and Related Information in the Notes to Consolidated Financial Statements, which is incorporated herein by reference. EXPLORATION AND PRODUCTION (E&P) -------------------------------- This segment explores for and produces crude oil, natural gas, and natural gas liquids on a worldwide basis. It also mines deposits of oil sands in Canada to extract the bitumen and upgrade it into a synthetic crude oil. At December 31, 2002, ConocoPhillips' E&P operations were producing in the United States; the Norwegian and U.K. sectors of the North Sea; Canada; Nigeria; Venezuela; the Timor Sea; offshore Australia and China; Indonesia; the United Arab Emirates; Vietnam; Russia; and Ecuador. The information listed below appears in the supplemental oil and gas operations disclosures on pages 146 through 163 and is incorporated herein by reference. o Proved worldwide crude oil, natural gas and natural gas liquids reserves; o Net production of crude oil, natural gas and natural gas liquids; o Average sales prices of crude oil, natural gas and natural gas liquids; o Average production costs per barrel of oil equivalent; o Net wells completed, wells in progress and productive wells; and o Developed and undeveloped acreage. In 2002, ConocoPhillips' worldwide crude oil production, including its share of equity affiliates' production, averaged 682,000 barrels per day, a 21 percent increase from 563,000 barrels per day in 2001. 2 During the year, 371,000 barrels per day of crude oil was produced in the United States, down slightly from 373,000 barrels per day in 2001. The decrease in U.S. production was due to lower production in Alaska, reflecting normal field declines, as well as operating interruptions during the year, partially offset by increased production volumes following the merger. Foreign crude oil production volumes increased 64 percent in 2002, primarily as a result of the merger. E&P's worldwide production of natural gas liquids averaged 46,000 barrels per day in 2002, compared with 35,000 barrels per day in 2001. U.S. production accounted for 32,000 barrels per day in 2002, compared with 26,000 barrels per day in 2001. The increases were primarily the result of the merger. The company's worldwide production of natural gas averaged 2,047 million cubic feet per day in 2002, compared with 1,335 million cubic feet per day in 2001. U.S. natural gas production increased 20 percent in 2002, while foreign natural gas production increased 126 percent. The increases were primarily due to the merger. ConocoPhillips' worldwide annual average crude oil sales price increased 1 percent in 2002, to $24.07 per barrel. E&P's annual average worldwide natural gas sales price decreased 14 percent from 2001, to $2.77 per thousand cubic feet. The company's finding and development costs in 2002 were $5.57 per barrel of oil equivalent, compared with $5.97 in 2001. Over the last five years, ConocoPhillips' finding and development costs averaged $4.31 per barrel of oil equivalent. Finding and development costs per barrel of oil equivalent is calculated by dividing the net reserve change for the period (excluding production and sales) into the costs incurred for the period, as reported in the "Costs Incurred" disclosure required by Statement of Financial Accounting Standards No. 69, "Disclosures about Oil and Gas Producing Activities." At December 31, 2002, ConocoPhillips, including its share of equity affiliates, held a combined 101.9 million net developed and undeveloped acres, compared with 25.8 million net acres at year-end 2001. The increase in acreage was primarily the result of the merger. At year-end 2002, the company held acreage in 29 countries (counting the Timor Gap Zone of Cooperation between Australia and East Timor as a single country for this purpose). E&P--U.S. OPERATIONS In 2002, U.S. E&P operations contributed 55 percent of ConocoPhillips' worldwide liquids production and 54 percent of its worldwide natural gas production. The company's U.S. operations are managed in two divisions: Alaska and the Lower 48 States. ALASKA ConocoPhillips is a major producer of crude oil on Alaska's North Slope, and produces natural gas in the Cook Inlet. A brief summary of the major Alaskan producing fields, transportation infrastructure, and exploration activities follows. Greater Prudhoe Area The Greater Prudhoe Area is comprised of the Prudhoe Bay field and satellites, as well as the Greater Point McIntyre Area fields. In 2002, an agreement was reached among all owners to align ownership across all fields within the Greater Prudhoe Area. ConocoPhillips now holds a 36.1 percent interest in all fields within the Greater Prudhoe Area, all of which are operated by BP p.l.c. (BP). 3 The Prudhoe Bay field is the largest oil field on Alaska's North Slope. It is the site of a large waterflood and enhanced oil recovery project, as well as a gas processing plant that processes and re-injects more than 8 billion cubic feet of natural gas daily. ConocoPhillips' net crude oil production from the Prudhoe Bay field averaged 130,800 barrels per day in 2002, compared with 144,900 barrels per day in 2001, while natural gas liquids production averaged 24,100 barrels per day in 2002, compared with 25,000 barrels per day in 2001. Prudhoe Bay satellite fields Aurora, Borealis, Polaris, and Midnight Sun produced 12,700 net barrels per day of crude oil in 2002 compared with 3,400 net barrels per day in 2001. The newly developed Borealis satellite field contributed the biggest share in 2002, producing 7,200 net barrels per day compared with 1,100 net barrels per day in 2001. All Prudhoe Bay satellite fields are produced through Prudhoe Bay production facilities. The Greater Point McIntyre Area (GPMA) is made up of the Point McIntyre, Niakuk, Lisburne, West Beach, and North Prudhoe Bay State fields. All fields within the GPMA are produced through the Lisburne Production Center. Net crude oil production for GPMA averaged 19,800 barrels per day in 2002, compared with 26,000 barrels per day in 2001. The bulk of this production came from the Point McIntyre field where an enhanced oil recovery project began in 2000. Greater Kuparuk Area ConocoPhillips operates the Greater Kuparuk Area, which is comprised of the Kuparuk field and four satellite fields: Tarn, Tabasco, Meltwater and West Sak. ConocoPhillips holds a 55.2 percent interest in the Kuparuk field, located about 40 miles west of Prudhoe Bay. Field installations include three central production facilities that separate oil, gas and water. The gas is either used for fuel or compressed for reinjection. ConocoPhillips' net crude oil production from Kuparuk averaged 79,000 barrels per day in 2002, compared with 91,400 barrels per day in 2001. The decrease was due to normal field declines. The Greater Kuparuk Area's satellite fields of Tarn, Tabasco and Meltwater produced 21,300 net barrels per day of crude oil in 2002, compared with 12,600 net barrels per day in 2001. The increase was due to a full year's production from Meltwater, which came online in late 2001. ConocoPhillips holds a 55.4 percent interest in these satellite fields. In late 2002, ConocoPhillips announced the startup of Kuparuk field Drill Site 3S (Palm). This drill site will develop the oil accumulation discovered by the Palm exploration wells drilled during the winter 2001 season. The Palm oil accumulation effectively extends the Kuparuk field on Alaska's North Slope approximately three miles to the northwest. The drill site produced crude oil at a 6,000 net-barrel-per-day rate following startup and is expected to reach peak production in 2004 following additional development drilling. Production from Palm is processed through existing Kuparuk field facilities. The Greater Kuparuk Area also includes the West Sak heavy-oil field. ConocoPhillips is studying and applying new ways to develop this heavy-oil field. In 2002, West Sak produced 3,300 net barrels of heavy oil per day, compared with 2,700 net barrels per day in 2001. ConocoPhillips holds a 55.4 percent interest in this field. Alpine Field The Alpine field, located west of the Kuparuk field, began production in November 2000. In 2002, the field produced at a net rate of 63,400 barrels of oil per day, compared with 57,800 barrels per day in 2001. ConocoPhillips is the operator and holds a 78 percent interest in Alpine. 4 In January 2003, ConocoPhillips and the U.S. Department of Interior Bureau of Land Management signed a Memorandum of Understanding that provides for completion of an Environmental Impact Statement (EIS) for five prospective satellites, Fiord, Nanuq, Lookout, Spark, and Alpine West, as well as future potential developments in the northeast corner of the National Petroleum Reserve-Alaska (NPR-A) and near the Alpine oil field. A final decision to move forward on these projects will be made after the EIS is completed and the appropriate permits have been granted. Cook Inlet ConocoPhillips' assets in Alaska include the North Cook Inlet field, the Beluga natural gas field, and the Kenai liquefied natural gas facility. ConocoPhillips has a 100 percent interest in the North Cook Inlet field. Net production in 2002 averaged 125 million cubic feet per day. All of the production from the North Cook Inlet field is used to supply ConocoPhillips' share of gas to the Kenai liquefied natural gas plant. ConocoPhillips' interest in the Beluga River field is 33 percent. Net production averaged 41 million cubic feet per day in 2002. Gas from the Beluga River field is sold to local utilities and industrial consumers. ConocoPhillips owns a 70 percent interest in the Kenai liquefied natural gas plant, which supplies liquefied natural gas to two utility companies in Japan. Utilizing two leased tankers, the company transports the liquefied natural gas to Japan, where it is reconverted to dry gas at the receiving terminal. ConocoPhillips sold 44.4 billion cubic feet of liquefied natural gas to Japan in 2002, compared with 46.1 billion cubic feet in 2001. Exploration ConocoPhillips holds more than one million net exploration acres in Alaska. ConocoPhillips drilled or participated in eight exploratory wells during 2002, on locations near Kuparuk, Prudhoe Bay and Alpine, as well as in the NPR-A and the Cook Inlet. Of the eight wells, two are moving forward with development plans and one is pending further appraisal. In May 2001, ConocoPhillips announced the first discoveries in the NPR-A since the area was reopened to exploration in 1999. ConocoPhillips plans to drill or participate in four exploration wells in Alaska during 2003. Transportation ConocoPhillips transports the petroleum liquids it produces on the North Slope to market through the Trans-Alaska Pipeline System (TAPS), an 800-mile pipeline, marine terminal and spill response and escort vessel system that ties the North Slope of Alaska to the port of Valdez in south-central Alaska. While ownership interest in TAPS was 26.7 percent in 2002, regulatory approval was received in early 2003 to purchase an additional 1.5 percent interest from Amerada Hess, thereby increasing ConocoPhillips ownership in TAPS to 28.2 percent. The purchase was effective January 24, 2003. In the second quarter of 2001, ConocoPhillips and the five other owners of TAPS completed and filed state and federal applications for renewal of the pipeline's right-of-way permit through 2034. The State of Alaska approved the 30-year right-of-way renewal in November 2002 and U.S. federal approval was received in January 2003. TAPS was shut down in early November 2002 following a major earthquake in Alaska. There were no associated oil leaks, spills or pipeline ruptures. TAPS remained shut down for approximately three days and was restarted after all necessary inspections, leak testing and temporary repairs were made. 5 ConocoPhillips' ownership of stock in the Alyeska Pipeline Service Company increased from 26.7 percent in 2002 to 28.2 percent as a result of the January 2003 purchase of an additional interest from Amerada Hess. Alyeska constructed and operates the pipeline system on behalf of the TAPS owners. ConocoPhillips also has ownership interests in the Alpine, Kuparuk and Oliktok pipelines on the North Slope. In 2002, ConocoPhillips sold its 20 percent ownership interest in the Cook Inlet Pipeline Company. ConocoPhillips, BP and ExxonMobil agreed in late 2000 to jointly evaluate a gas pipeline project to deliver natural gas from Alaska's North Slope to the Lower 48. The three co-owners shared equally in the costs and governance of the program. ConocoPhillips does not believe the project provides the desired return on investment in the current economic environment, given the significant size and risk associated with the project. However, ConocoPhillips continues to search for a solution that will allow this energy resource to be produced. ConocoPhillips' wholly owned subsidiary, Polar Tankers Inc., manages the marine transportation of the company's Alaska North Slope production. Polar Tankers is based in Long Beach, California, and operates five ships in the Alaskan trade, chartering additional third party operated vessels as necessary. In 2001, Polar Tankers brought the Polar Endeavour into service, and the Polar Resolution was brought into service in 2002. After the Polar Endeavour was placed in service, ConocoPhillips entered into a transaction to sell and subsequently lease back the vessel for 10 years. These 125,000-deadweight-ton, double-hulled crude oil tankers are the first two of five Endeavour Class tankers that ConocoPhillips plans to add to its Alaskan-trade fleet over a five-year period. The third tanker, the Polar Discovery, is scheduled to enter the fleet in 2003. LOWER 48 STATES ConocoPhillips' operations in the Lower 48 States are principally located in the following areas: o Offshore: Gulf of Mexico; o Onshore: Various trends in Texas, New Mexico, Oklahoma, Louisiana, Utah, Colorado, and Wyoming Gulf of Mexico ConocoPhillips' current portfolio of producing properties in the Gulf of Mexico includes three fields operated by ConocoPhillips and 24 operated by other companies. At December 31, 2002, ConocoPhillips had 14 leases in production or under development in the deepwater Gulf of Mexico. ConocoPhillips held interests in 391 lease blocks in the deepwater Gulf of Mexico as of December 31, 2002. In 2003, ConocoPhillips expects to participate in four exploration wells in the deepwater Gulf of Mexico. ConocoPhillips' deepwater Gulf of Mexico drilling program utilizes the Deepwater Pathfinder, a drillship that is owned by a joint venture between Transocean Sedco Forex Inc. and ConocoPhillips. The vessel, which went into service in January 1999, is capable of drilling in water depths of up to 10,000 feet. ConocoPhillips holds a 16 percent interest in the Ursa field, which is operated by Shell. The Ursa tension-leg platform was installed in late 1998 in approximately 3,900 feet of water, with first production occurring in March 1999. As Ursa was owned by Conoco before the merger, only the production from August 30 through December 31, 2002, is included in ConocoPhillips' 2002 statistics and financial results. Production during this period averaged a net 12,500 barrels per day of liquids and 16 million cubic feet per day of gas. 6 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 can be processed and transported via the Ursa infrastructure already in place. ConocoPhillips owns a 16 percent interest in Princess. First production from Princess began in late 2002 with the completion of a well on the Ursa platform. ConocoPhillips operates and holds a 75 percent interest in the Garden Banks 783 and 784 leases which contain the Magnolia field. First production from Magnolia is scheduled for late 2004. ConocoPhillips owns a non-operated interest of 18.2 percent in the K2 discovery. K2 was discovered in 1999 and appraisal continued in 2002. Further appraisal and preliminary development operations are scheduled for 2003. Onshore ConocoPhillips is a large natural gas producer in three major gas producing trends: the Lobo trend in south Texas, the San Juan Basin of New Mexico, and the Guymon-Hugoton trend in the panhandles of Texas and Oklahoma. At December 31, 2002, the company held over 2.2 million net acres of oil and gas leases in these trends. Combined production from the date of the merger through year-end from these three areas averaged a net 948 million cubic feet per day of natural gas. E&P--THE NORTH SEA In 2002, E&P operations in the North Sea contributed 28 percent of ConocoPhillips' worldwide liquids production and 29 percent of its worldwide natural gas production. The company's North Sea assets are principally located in the Norwegian and U.K. sectors. NORWAY The Ekofisk Area is located approximately 200 miles offshore Norway in the center of the North Sea. The Ekofisk Area is comprised of four producing fields: Ekofisk, Eldfisk, Embla and Tor. Ekofisk serves as a hub for petroleum operations in the area, with surrounding developments utilizing the infrastructure. Net production in 2002 from the Ekofisk Area was 127,000 barrels of liquids per day and 133 million cubic feet of natural gas per day. ConocoPhillips is the operator and has a 35.1 percent interest in Ekofisk. The production license for the Ekofisk Area runs until 2028. ConocoPhillips also has ownership interests in several other producing fields in the Norwegian North Sea, the more significant of which include a 24.3 percent interest in the Heidrun field, a 10.3 percent interest in the Statfjord field, and a 1.6 percent interest in the Troll field. Production from these, and other fields in the Norwegian sector of the North Sea acquired in the merger, averaged a net 105,000 barrels of liquids per day and 112 million cubic feet of natural gas per day for the last four months of 2002. UNITED KINGDOM ConocoPhillips is the largest equity owner in and the joint operator of the Britannia natural gas/condensate field. ConocoPhillips holds a 58.7 percent interest in Britannia. First production from Britannia occurred in August 1998. ConocoPhillips' proved reserves in Britannia included approximately 1.1 trillion cubic feet of natural gas and 34 million barrels of petroleum liquids at December 31, 2002. For the last four months of 2002, production from Britannia averaged a net 13,000 barrels per day of liquids and 336 million cubic feet per day of natural gas. 7 ConocoPhillips operates and holds a 36.5 percent interest in the Judy/Joanne fields which together comprise J-Block. Additionally, the Jade field began production in the first quarter of 2002 from a wellhead platform and pipeline tied to the J-Block facilities. ConocoPhillips is the operator and holds a 32.5 percent interest in Jade. Together, these fields produced a net 14,000 barrels of liquids per day and 96 million cubic feet of natural gas per day in 2002. ConocoPhillips continues to supply gas from J-Block to Enron Capital and Trade Resources Limited (Enron Capital), which was placed in Administration in the United Kingdom on November 29, 2001. ConocoPhillips has been paid all amounts currently due and payable by Enron Capital, including outstanding amounts due for the period prior to the appointment of the Administrator. The company believes that Enron Capital will continue to pay the amounts due for gas supplied by ConocoPhillips in accordance with the terms of the gas sales agreement. ConocoPhillips does not currently expect that it will have to curtail sales of gas under the gas sales agreement or shut in production as a result of the Administration of Enron Capital. However, in the event Enron Capital is no longer under Administration, there may be additional risk of production constraints. ConocoPhillips has various ownership interests in 15 producing gas fields in the southern North Sea that were acquired in the merger. These fields mostly feed into the ConocoPhillips-operated Theddlethorpe gas processing facility through three ConocoPhillips-operated pipeline systems. Production for the last four months of 2002 averaged a net 357 million cubic feet per day of natural gas. The investment in the Viscount development was charged to impairment expense in the fourth quarter of 2002 due to disappointing development drilling results. In September 2002, ConocoPhillips began production from the Hawksley field in the southern sector of the U.K. North Sea. The Hawksley discovery well, 44/17 a-6y, was completed in July 2002 in one of five natural gas reservoirs currently being developed by ConocoPhillips as a single, unitized project. The other reservoirs are McAdam, Murdoch K., Boulton, and Watt. Collectively, they are known as CMS3 due to their utilization of the production and transportation facilities of the ConocoPhillips-operated Caister Murdoch System (CMS). ConocoPhillips is the operator of CMS3 and holds a 59.5 percent interest. ConocoPhillips has a 24 percent interest in the Clair field development. Net proved reserves are 24 million barrels of petroleum liquids. The Clair development is comprised of a conventional steel jacket structure with minimum manned facilities topside. First production from Clair is targeted for 2004. ConocoPhillips is also assessing the development of the Callanish and Brodgar fields. These new satellite development projects would be tied back to the Britannia facility. Appraisal wells for both discoveries were drilled in 2000. ConocoPhillips has a 75 percent interest in the Brodgar field and an 83.5 percent interest in the Callanish field. ConocoPhillips also has ownership interests in several other producing fields in the U.K. North Sea, including a 23.4 percent interest in the Alba field, a 40 percent interest in the MacCulloch field, and an 11.5 percent interest in the Armada field. Production from these and other fields in the U.K. sector of the North Sea averaged a net 50,000 barrels of liquids per day and 85 million cubic feet of natural gas per day for the last four months of 2002. The Interconnector pipeline, which connects the United Kingdom and Belgium, facilitates the marketing throughout Europe of the natural gas ConocoPhillips produces in the United Kingdom. ConocoPhillips' 10 percent equity share of the Interconnector pipeline allows the company to ship approximately 200 million cubic feet of natural gas per day to markets in continental Europe. ConocoPhillips has multi-year contracts to supply natural gas to Gasunie in the Netherlands and Wingas in Germany. Because the Interconnector pipeline provides the flexibility to flow in either direction, ConocoPhillips is able to take 8 advantage of the long-term and short-term market conditions in both the United Kingdom and continental Europe. OTHER AREAS ConocoPhillips sold its interests in the Netherlands in the fourth quarter of 2002. Financial results for the Netherlands from the date of the merger through the date of sale are included in Corporate and Other as discontinued operations. Accordingly, the Netherlands production statistics are not included in E&P. EXPLORATION ConocoPhillips plans six exploration wells and two appraisal wells in the North Sea in 2003. In the Norwegian sector, three exploration wells and an appraisal well are planned for 2003. In the U.K. sector, two exploratory wells that were spudded in late 2002 will continue drilling operations into 2003. ConocoPhillips plans to participate in an additional exploration well and an appraisal well in the U.K. sector in 2003. E&P--CANADA In 2002, E&P operations in Canada contributed 2 percent of ConocoPhillips' worldwide liquids production and 8 percent of its worldwide natural gas production, excluding Syncrude production. CONVENTIONAL OIL AND GAS 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 crude oil and natural gas. ConocoPhillips is working with three other energy companies, as members of the Mackenzie Delta Producers' Group (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 the development of a Mackenzie Valley pipeline, running some 800 miles to serve 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. Conceptual engineering commenced in April 2002, and in September 2002, after receiving expressions of interest from other potential shippers, the consortium decided to increase the initial design capacity for the Mackenzie Valley pipeline from 830 to 1,200 million cubic feet per day. The pipeline capacity would be expandable with additional compression. ConocoPhillips would hold a 16 percent interest in the pipeline and a 75 percent interest in the development of the Parsons Lake gas field. The Parsons Lake gas field would be one of the three primary fields in the Mackenzie Delta that would anchor the pipeline development. Submission of regulatory applications for the project is anticipated in late 2003 and first gas production is currently targeted by 2008. ConocoPhillips owns approximately 47 percent of Petrovera, a joint venture that combines a substantial portion of ConocoPhillips' Canadian heavy-oil assets and certain associated natural gas assets. Net production was approximately 15,100 barrels of petroleum liquids per day from the date of the merger through year-end 2002, and is reported separately in equity affiliate production. 9 OTHER CANADIAN OPERATIONS ConocoPhillips has two oil sands projects in Canada: Syncrude Canada Ltd. and Surmont. Syncrude Canada Ltd. ConocoPhillips 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 (Syncrude). The primary plant and facilities are 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. Syncrude Canada Ltd. holds eight oil sands leases, of which ConocoPhillips' share is approximately 23,000 net acres. The necessary surface rights are also held and the sites are readily accessible. In December 1999, the Alberta Energy and Utilities Board extended the project license term to the year 2035. The U.S. Securities and Exchange Commission's regulations define this project as mining-related and not part of conventional oil and gas operations. As such, Syncrude reserves are not included in the company's proved oil and gas reserves as reported in its supplemental oil and gas reserves information. Surmont The Surmont lease is located about 35 miles south of Fort McMurray, Alberta. ConocoPhillips owns a 43.5 percent interest and is the operator. Currently, a pilot project is being conducted to evaluate the potential of the Steam Assisted Gravity Drainage technology at Surmont to economically develop oil sands that are too deep to mine. In 2001, the company submitted a regulatory application to develop 100,000 barrels per day of heavy-oil production. This application is in the final stages of review and a regulatory decision is expected in 2003. E&P--SOUTH AMERICA In 2002, E&P operations in South America were comprised of interests in Venezuela, Ecuador and Brazil. South American operations contributed 4 percent of ConocoPhillips' worldwide liquids production. VENEZUELA ConocoPhillips has two major heavy-oil projects in Venezuela: Petrozuata and Hamaca. In addition, ConocoPhillips owns blocks in the Gulf of Paria, which contains the Corocoro conventional oil and gas discovery and other exploration opportunities. Petrozuata Petrozuata is a joint venture between ConocoPhillips, which holds a 50.1 percent non-controlling equity interest that was acquired in the merger, and a subsidiary of Petroleos de Venezuela S.A. (PDVSA), the national oil company of Venezuela, which holds the remaining interest. The project is an integrated operation that produces extra-heavy crude oil from reserves in the Zuata region of the Orinoco Oil Belt, transports it to the Jose industrial complex on the north coast of Venezuela, and upgrades it into medium-grade crude oil, with associated by-products of liquefied petroleum gas, sulfur, petroleum coke and heavy gas oil. The joint-venture agreement has a 35-year term. Petrozuata began early production of extra-heavy crude oil in August 1998, and, after completion of the upgrader at Jose, made the first commercial sales of upgraded, medium-grade crude oil in April 2001. ConocoPhillips' net production was approximately 52,200 barrels of medium-grade crude oil per day for the last four months of 2002, and is reported separately as equity affiliate production. The medium-grade 10 crude oil produced by Petrozuata is used as a feedstock for ConocoPhillips' Lake Charles, Louisiana, refinery and the Cardon refinery operated by PDVSA. ConocoPhillips has entered into an agreement to purchase up to 104,000 barrels per day of the Petrozuata upgraded crude oil for a market-based formula price over the term of the joint venture in the event that Petrozuata is unable to sell the production for higher prices. All upgraded crude oil 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 crude oil and some of the by-products to ocean vessels for export. Hamaca The Hamaca project also involves the development of heavy-oil reserves from the Orinoco Oil Belt. ConocoPhillips' share in the Hamaca project is 40 percent. ConocoPhillips holds its interest in Hamaca through a jointly held limited liability company, which ConocoPhillips accounts for using the equity method. The other participants in Hamaca are PDVSA and ChevronTexaco Corporation. Drilling of development wells started in January 2001, with early production of extra-heavy oil starting in the fourth quarter of 2001. Production averaged 8,500 net barrels per day of heavy oil in 2002, and is reported separately as equity affiliate production. Construction of the heavy-oil upgrader, pipelines and associated production facilities at the Jose industrial complex began in 2000. The upgrader is expected to begin producing commercial quantities of medium-grade crude oil in 2004, at which time ConocoPhillips' net production from the Hamaca field is expected to increase to over 60,000 barrels per day from proved reserves. Gulf of Paria In 1999, Conoco drilled the Corocoro discovery that, during drill stem tests, flowed hydrocarbons from multiple zones. In 2001, Conoco and its partners commenced a four-well appraisal program to evaluate the Corocoro discovery. Three of the four wells were drilled in 2001 and the fourth well was completed in the first quarter of 2002. All four wells were successful. ConocoPhillips currently holds a 50 percent working interest in the Gulf of Paria West Block and is the operator. In November 2002, ConocoPhillips began progressing development discussions with the Venezuelan government and the company expects development approval in the first half of 2003. Upon approval of the development plan, an affiliate of PDVSA has the option to increase its participation in the development, which could reduce ConocoPhillips' current 50 percent interest down to as low as 32.5 percent. In addition, Venezuelan legislation enacted in 2001 introduced a new 30 percent flat royalty regime and reduced the income tax rate on light oil projects from 67.7 percent to 50 percent. The Corocoro Project's Royalty Agreement, which provides for a sliding scale royalty with a 16.55 percent maximum rate, was in effect prior to the 2001 legislation and is expected to continue to apply to the project. In addition to the Corocoro discovery, ConocoPhillips is pursuing additional prospects in the Gulf of Paria, with two exploration wells planned for 2003. In December of 2002, political unrest in Venezuela caused economic and other disruptions that shut down most oil and gas operations in Venezuela, including the company's Petrozuata, Hamaca and Gulf of Paria operations. Limited production began from these operations in February 2003. For more information about the impact of the disruptions on the company's operations in Venezuela, see "Management's Discussion and Analysis of Financial Condition and Results of Operations--Outlook" on page 74. 11 BRAZIL ConocoPhillips announced in August 2001 that the Brazilian government had signed concession agreements finalizing the award of two exploration blocks. ConocoPhillips, bidding alone, previously placed winning bids on BM-ES-11 and BM-PAMA-3 in Brazil's third bid round held in June 2001. Both blocks are located in deepwater offshore Brazil. ConocoPhillips entered into partnerships on both blocks in late 2002, reducing its interest to 70 percent in BM-ES-11 and 65 percent in BM-PAMA-3. In 2002 a significant seismic program was initiated over the acreage position. The evaluation of that seismic is ongoing and will continue in 2003. ConocoPhillips will operate both blocks. ECUADOR ConocoPhillips has a 14 percent non-operating interest in producing fields in the Oriente basin in Ecuador in the area collectively referred to as "Block 16," that was acquired in the merger. Repsol YPF, s.a. is the operator of the Block 16 area. ConocoPhillips' net production was 3,200 barrels of crude oil per day for the last four months of 2002. Net production for 2003 is expected to increase to over 8,000 barrels of crude oil per day with the completion of a trans-Andean heavy-oil pipeline. The pipeline completion is anticipated in the second half of 2003. E&P--ASIA PACIFIC In 2002, E&P operations in the Asia Pacific area contributed 3 percent of ConocoPhillips' worldwide liquids production and 7 percent of its worldwide natural gas production. CHINA In the South China Sea, ConocoPhillips' combined net production of crude oil from its Xijiang facilities averaged 11,600 barrels per day in 2002. Production from Phase I development of the Peng Lai 19-3 field in Bohai Bay Block 11-05 began in late December 2002. By the end of January 2003, the field was producing at a net rate of 8,200 barrels per day. ConocoPhillips holds a 49 percent interest, with the remainder held by the China National Offshore Oil Corporation. The Phase I development utilizes one wellhead platform and a floating production, storage and offloading facility. ConocoPhillips continues to move forward with feasibility planning and design for Phase II of the Peng Lai 19-3 development. Phase II would include multiple wellhead platforms, central processing facilities, and a floating storage and offloading facility. The Peng Lai 25-6 field, discovered in 2000 and located three miles east of Peng Lai 19-3, will be developed in conjunction with Phase II of the Peng Lai 19-3 development project. Several other exploration prospects have been identified in Block 11-05, with two exploration wells planned for 2003. INDONESIA ConocoPhillips operates 14 Production Sharing Contracts (PSCs) in Indonesia and has a non-operating interest in three others, all of which were acquired in the merger. ConocoPhillips' assets are concentrated in two core areas: the West Natuna Sea and South Sumatra; with a potentially emerging area offshore East Java. ConocoPhillips is party to five long-term U.S. dollar pipeline gas contracts that have been signed in Indonesia. 12 Offshore Assets ConocoPhillips operates six offshore PSCs: 1) South Natuna Sea Block B, 2) Nila, 3) Tobong, 4) Kakap, 5) Sakala Timur, and 6) Ketapang. The company holds a non-operator interest in the Pangkah PSC offshore East Java, and is a co-venturer in the West Natuna Gas Supply Group (WNG). ConocoPhillips participates in various gas marketing arrangements in connection with these assets. The Block B PSC is comprised of two mature oil fields and 15 gas fields in various phases of development. The largest current development in the Block B PSC is the Belanak field, which is scheduled for first production in late 2004. Two additional developments are scheduled for startup dates in 2006 and 2008, and would produce into the Belanak infrastructure. The company also has an active exploration program in both the Natuna Sea and East Java. Onshore Assets ConocoPhillips operates eight onshore PSCs: 1) Corridor TAC, 2) Corridor PSC, 3) South Jambi 'B', 4) Sakakemang JOB (jointly operated with a co-venturer), 5) Banyumas, 6) Tungkal, 7) Block A PSC in Aceh, and 8) Warim, and holds non-operator interests in the Bentu and Korinci-Baru PSCs. As with its offshore properties, the company participates in various gas marketing arrangements in connection with these fields. Exploration efforts focus on locating additional natural gas reserves. Gas sales are transported to Duri through a pipeline system formerly owned and operated by the state-owned pipeline company, PGN. This system has recently been transferred to a new company, Transgasindo (TGI), in which ConocoPhillips received a 14 percent equity share. Production of natural gas from Indonesia averaged a net 217 million cubic feet per day for the last four months of 2002, while production of crude oil over the same period averaged a net 14,700 barrels per day. The company plans to drill five exploratory and four appraisal wells in Indonesia in 2003. VIETNAM ConocoPhillips has a 23.25 percent interest in Block 15-1 in the Cuu Long Basin. In 2001, the partners in Block 15-1 declared the southwest portion of the Su Tu Den (Black Lion) field commercial after a successful appraisal program. In addition, an appraisal well in the northeast portion of Su Tu Den was successfully drilled in 2002. The Su Tu Den Phase I development project was approved in December 2001. A floating production, storage and offloading vessel and a wellhead platform will be utilized. The field is scheduled to begin production in the second quarter of 2004. An exploration discovery was also made on the nearby Su Tu Vang (Golden Lion) prospect in the third quarter of 2001. The potential commerciality of Su Tu Vang and the Northeast portion of Su Tu Den are currently being evaluated. ConocoPhillips has a 36 percent interest in the Rang Dong field in Block 15-2 in the Cuu Long Basin. In the third quarter of 2002, production began from two new wellhead platforms in the Rang Dong field. These additional platforms increased net production from the field from under 6,800 to over 12,400 barrels per day at year-end 2002. A successful appraisal step-out well, Rang Dong-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. ConocoPhillips also owns interests in offshore Blocks 16-2, 5-3, 133 and 134, as well as a 16.33 percent interest in the Nam Con Son gas pipeline. 13 TIMOR SEA AND AUSTRALIA Bayu-Undan ConocoPhillips' direct interest in the unitized Bayu-Undan field, located in the Timor Sea, was 55.9 percent at year-end 2002. A further 8.25 percent interest was held through Petroz N.L., in which the company had an 89.7 percent stock ownership at year-end. The field is being developed in two phases. Phase I is a gas-recycle project, where condensate and natural gas liquids will be separated and removed and the dry gas reinjected into the reservoir. This phase is expected to begin production in 2004, with the goal of attaining a net rate of 50,000 barrels of liquids per day from proved reserves. Phase II would involve the export and sale of the natural gas from the field. In March 2002, ConocoPhillips announced that it had signed a Heads of Agreement (LNG HOA) with The Tokyo Electric Power Company, Incorporated (TEPCO) and Tokyo Gas Co., Ltd. (Tokyo Gas) that would enable Phase II to proceed upon resolution of certain legal, regulatory, and fiscal issues. The Timor Sea Treaty (Treaty) was ratified by Timor-Leste (formerly East Timor) in December 2002 and by Australia in March 2003 and is subject to certain procedural events before it is fully effective. The Treaty will allow the issuance of new production sharing contracts to the existing contractors in the Bayu-Undan unit, which when combined with the expected approval of the Development Plan and the expected enactment of certain Timor-Leste legislation will provide the legal, regulatory and fiscal basis necessary to proceed with the project. Under the LNG HOA, TEPCO and Tokyo Gas will purchase 3 million tons per year in total of liquefied natural gas (LNG) for a period of 17 years, utilizing natural gas from the Bayu-Undan field. Shipments would begin in 2006 from an LNG facility near Darwin, Australia, utilizing ConocoPhillips' Optimized Cascade liquefied natural gas process. Under a separate agreement, the company plans to sell a 22.5 percent interest in one of the production sharing contracts via an indirect sale of an affiliate to TEPCO and Tokyo Gas. Following the sale to TEPCO and Tokyo Gas and a rebalancing of interests, ConocoPhillips' interest in the unitized Bayu-Undan field, including Petroz N.L., would be 56.72 percent. Greater Sunrise During 2002, the Sunrise joint venture conducted a thorough review of a proposal based on piping gas 330 miles to shore for sale in Darwin and elsewhere in Australia and an alternative proposal to supply LNG to North America from a floating LNG facility. The review found neither proposal to be commercially viable at that time. However, the review did acknowledge the level of demand and interest within the Australian domestic gas market, and highlighted the potential for a floating LNG facility at Greater Sunrise to become a cost competitive supplier of LNG into regional markets. Consequently, in 2003, the Greater Sunrise joint venture participants plan to continue evaluating commercial development options and markets. The Sunrise joint venture participants are: Woodside 33.44 percent (Operator), ConocoPhillips 30 percent, Shell 26.56 percent and Osaka Gas 10 percent. E&P--AFRICA AND THE MIDDLE EAST NIGERIA ConocoPhillips' crude oil production from five leases in Nigeria averaged a net 29,100 barrels per day in 2002. These five leases include four onshore Oil Mining Leases (OML) and a shallow-water offshore OML. Continued development and exploratory drilling is planned for 2003 on the leases. 14 ConocoPhillips entered into a production sharing contract on Oil Prospecting Lease (OPL) 318, deepwater Nigeria, on June 14, 2002, where ConocoPhillips is operator with 50 percent interest. The acquisition of 3D seismic data on OPL 318 is planned to begin in 2003, with the first exploratory well expected to be drilled in the fourth quarter of 2004. The company is participating in a 450-megawatt gas-fired power plant to supply electricity to Nigeria's national electricity supplier. The plant will consume 75 million cubic feet per day of natural gas sourced from within ConocoPhillips' Nigerian proved natural gas reserves. The plant is expected to be operational in 2005. ANGOLA ConocoPhillips has a 20 percent interest in exploratory activity in deepwater Block 34, offshore Angola. The first exploration well, completed in 2002, did not encounter commercial quantities of hydrocarbons, which led to a substantial financial impairment of the investment in the block. Further drilling is planned on the block in 2003. CAMEROON On December 18, 2002, ConocoPhillips announced a successful drill stem test on an exploratory well offshore Cameroon. The well, located in exploration permit PH 77, offshore in the Douala Basin, obtained a maximum flow rate of 3,000 barrels of oil per day and 1.8 million cubic feet of natural gas per day during the test. Contractor interests in the 2,830 square mile permit are held 50 percent by ConocoPhillips and 50 percent by a subsidiary of Petronas Carigali (Petronas). ConocoPhillips serves as the operator of the consortium. ConocoPhillips and Petronas are currently analyzing well results, and will be working with the National Hydrocarbon Corporation of Cameroon on developing forward plans to evaluate the discovery and other identified exploration prospects in the permit. DUBAI In Dubai, United Arab Emirates, ConocoPhillips is using horizontal drilling techniques and advanced reservoir drainage technology to enhance the efficiency of the offshore production operations and improve recovery rates from four fields. SAUDI ARABIA ConocoPhillips has a 15 percent interest in Core Venture 1 and a 30 percent interest in Core Venture 3 of the Kingdom of Saudi Arabia's natural gas initiative. ConocoPhillips and its co-venturers continue to define the project components in more detail, and to negotiate the implementation agreement, which would set out all major financial, operational and legal terms for the initiative, as well as a timeline for the project execution. E&P--RUSSIA AND CASPIAN SEA REGION RUSSIA ConocoPhillips 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, which was acquired in the merger, started producing oil in August 1994 from the Ardalin field. In June 2002, production commenced from the Oshkotyn field, the first of three satellite fields under development. Net production averaged 13,500 barrels of petroleum liquids per day for the last four months of 2002. ConocoPhillips accounts for its interest in Polar Lights using the equity method of accounting. 15 CASPIAN SEA ConocoPhillips has an 8.33 percent interest in an exploration project in the Kazakhstan sector of the Caspian Sea. The exploration area consists of 10.5 blocks, totaling nearly 2,000 square miles about 50 miles west-northwest of the Tengiz oil field, onshore Kazakhstan. The blocks are covered by a production sharing agreement with the Kazakhstan government. The initial production phase of the contract is for 20 years, with options to extend the agreement an additional 20 years. In June 2002, ConocoPhillips and the other contracting companies in conjunction with KazMunayGas, which represents the Government of the Republic of Kazakhstan, declared the Kashagan discovery commercial. The declaration of commerciality enables the preparation of a development plan for the Kashagan field. The contracting companies plan to continue to explore other structures within the North Caspian Sea license. In October 2002, ConocoPhillips and its co-venturers announced a new hydrocarbon discovery in the Kazakhstan sector of the Caspian Sea. An initial test well, the Kalamkas-1, located adjacent to the Kashagan field, flowed oil. E&P--OTHER ConocoPhillips is continuing with plans to develop a project to build a liquefied natural gas import terminal in northern Baja California to provide access to gas markets in that region. The company is working with federal, state, and local officials in Mexico to secure permits for the project, and a decision whether or not to proceed with the terminal project is expected during 2003, pending resolution of local permitting issues. E&P--RESERVES The company has not filed any information with any other federal authority or agency with respect to its estimated total proved reserves at December 31, 2002. No difference exists between the company's estimated total proved reserves for year-end 2001 and year-end 2000, which are shown in this filing, and estimates of these reserves shown in a filing with another federal agency in 2002. DELIVERY COMMITMENTS ConocoPhillips has future commitments to deliver fixed and determinable quantities of crude oil to U.S. customers under various supply agreements over the next three years. During the period, the company is obligated to supply a total of 127 million barrels of crude oil under long-term contracts. To fulfill these obligations, ConocoPhillips plans to use production from domestic proved reserves, which are greater than these obligations and which have estimated production levels sufficient to meet the required delivery amounts. ConocoPhillips has a commitment to deliver a fixed and determinable quantity of liquefied natural gas in the future to two utility customers in Japan. The company is obligated over the next three years to supply a total of 108 billion cubic feet of liquefied natural gas. Production from one field in Alaska, with estimated proved reserves greater than the company's obligation and estimated production levels sufficient to meet the required delivery amount, will be used to fulfill the obligation. 16 MIDSTREAM --------- ConocoPhillips' Midstream business is conducted through owned and operated assets as well as through its 30.3 percent equity investment in Duke Energy Field Services, LLC (DEFS). The Midstream businesses purchase raw natural gas from producers and gather natural gas through extensive pipeline gathering systems. The gathered natural gas is then processed to extract natural gas liquids from the raw gas stream. The remaining "residue" gas is marketed by both ConocoPhillips and DEFS to electrical utilities, industrial users, and gas marketing companies. Most of the natural gas liquids are fractionated--separated into individual components like ethane, butane and propane--and marketed as chemical feedstock, fuel, or blendstock. Total natural gas liquids extracted in 2002, including ConocoPhillips' share of DEFS, was 156,000 barrels per day, with 133,000 barrels per day of natural gas liquids fractionated. DEFS supplies a substantial portion of its natural gas liquids to ConocoPhillips and Chevron Phillips Chemical Company LLC (a joint venture between ConocoPhillips and ChevronTexaco) under a supply agreement that continues until December 31, 2014. This purchase commitment is on an "if-produced, will-purchase" basis and so it has no fixed production schedule, but has been, and is expected to be, a relatively stable purchase pattern over the term of the contract. Under this agreement, natural gas liquids are purchased at various published market index prices, less transportation and fractionation fees. DEFS also purchases raw natural gas from ConocoPhillips' E&P operations. DEFS is headquartered in Denver, Colorado. At December 31, 2002, DEFS owned and operated 60 natural gas liquids extraction plants, and owned an equity interest in another 11. Also at year end, DEFS' gathering and transmission systems included 60,000 miles of pipeline. In 2002, DEFS' raw natural gas throughput averaged 7.4 billion cubic feet per day, and natural gas liquids extraction averaged 392,000 barrels per day. DEFS' assets are primarily located in the Gulf Coast area, west Texas, Oklahoma, the Texas Panhandle, the Rocky Mountain area, and western Canada. Outside of DEFS, ConocoPhillips' U.S. Midstream assets at December 31, 2002, included nine owned and operated natural gas liquids extraction plants in New Mexico, Texas and Louisiana with a combined net plant inlet capacity of 757 million cubic feet per day and an equity interest in another two plants. One of the company owned plants in Louisiana also includes a 10,500 barrel-per-day liquids fractionator. In addition, ConocoPhillips owns an underground natural gas liquids storage facility in each of Texas and Louisiana. ConocoPhillips owns a 25,000 barrel-per-day capacity liquids fractionation plant in Gallup, New Mexico; owns a 22.5 percent equity interest in Gulf Coast Fractionators, which owns a natural gas liquids fractionating plant in Mt. Belvieu, Texas (with ConocoPhillips' net share of capacity at 25,000 barrels per day); and owns a 40 percent interest in a fractionation plant in Conway, Kansas (with ConocoPhillips' share of capacity at 42,000 barrels per day). ConocoPhillips owns a 700-mile intrastate natural gas and liquids pipeline system in Louisiana and gas gathering and natural gas liquids pipelines in several states. ConocoPhillips' Canadian natural gas liquids business includes the following assets: o A 92 percent operating interest in the 2.4 billion-cubic-feet-per-day Empress natural gas processing straddle plant near Medicine Hat, Alberta, with natural gas liquids production capacity of 46,000 barrels per day; o A 580-mile Petroleum Transmission Company pipeline from Empress to Winnipeg and six related pipeline terminals; 17 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 liquefied petroleum gas 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 barrel-per-day propane-plus fractionator and a 5 percent interest in a 65-mile natural gas liquids pipeline with storage near Edmonton, Alberta. Canadian natural gas liquids extracted averaged 15,000 barrels per day in 2002. ConocoPhillips also owns 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 a gas processing plant and a natural gas liquids fractionator. ConocoPhillips' share of natural gas liquids extracted averaged 3,000 barrels per day in 2002. REFINING AND MARKETING (R&M) ---------------------------- R&M operations encompass refining crude oil and other feedstocks into petroleum products (such as gasoline, distillates and aviation fuels), buying and selling crude oil and refined products, and transporting, distributing and marketing petroleum products. R&M operations are organized regionally with operations in the United States, Europe and the Asia Pacific region. As a condition to the merger, the U.S. Federal Trade Commission (FTC) required that the company divest specified Conoco and Phillips assets, the most significant of which were Phillips' Woods Cross, Utah, refinery and associated motor fuel marketing operations; Conoco's Commerce City, Colorado, refinery and related crude oil pipelines; and Phillips' Colorado motor fuel marketing operations. In addition, in December 2002, the company committed to and initiated a plan to sell a substantial portion of its company-owned retail sites. Both the FTC-required dispositions and the retail site dispositions have been classified as discontinued operations for financial reporting purposes, and are included in Corporate and Other. Accordingly, they are excluded from the descriptions of R&M's continuing operations contained in this section. See Note 4--Discontinued Operations, in the Notes to Consolidated Financial Statements, for additional information. UNITED STATES REFINING At December 31, 2002, ConocoPhillips owned and operated 12 crude oil refineries in the United States (excluding two refineries that are held for sale and reported in discontinued operations in Corporate and Other) having an aggregate rated crude oil refining capacity at year-end 2002 of 2,166,000 barrels per day. The average purchase cost of a barrel of crude delivered to the company's U.S. refineries in 2002 was $24.92, compared to $20.77 in 2001. 18 East Coast Region BAYWAY REFINERY Located on the New York Harbor in Linden, New Jersey, Bayway has a crude oil processing capacity of 250,000 barrels per day and processes mainly light low-sulfur crudes. Crude oil is supplied to the refinery by tanker, primarily from the North Sea and West Africa. The refinery produces a high percentage of transportation fuels such as gasoline, diesel, and jet fuel along with home heating oil. Other products include petrochemical feedstocks (propylene) and residual fuel oil. The facility distributes its refined products to East Coast customers through pipelines, barges, railcars and trucks. Product production changes to meet seasonal demand. Gasoline is in higher demand during the summer, while in winter, the refinery optimizes operations to increase heating oil production. A 775 million-pound-per-year polypropylene plant became operational in March 2003. TRAINER REFINERY The Trainer refinery is located in Trainer, Pennsylvania, about 10 miles southwest of the Philadelphia airport on the Delaware River. The refinery has a crude oil processing capacity of 180,000 barrels per day and processes mainly light low-sulfur crudes. The Bayway and Trainer refineries are operated in coordination with each other by sharing crude oil cargoes, moving feedstocks between the facilities, and sharing certain personnel. Trainer also receives crude oil from the North Sea and West Africa. The refinery produces a high percentage of transportation fuels such as gasoline, diesel, and jet fuel along with home heating oil. Other products include petrochemical feedstocks (propylene) and residual fuel oil. Refined products are distributed to customers in Pennsylvania, New York and New Jersey via pipeline, barge, railcar and truck. Gulf Coast Region ALLIANCE REFINERY The Alliance refinery, located in Belle Chasse, Louisiana, on the Mississippi River, is about 25 miles south of New Orleans and 63 miles north of the Gulf of Mexico. The refinery has a crude oil processing capacity of 250,000 barrels per day and processes mainly light low-sulfur crudes. Alliance receives domestic crude oil via pipeline, and crude oil from the North Sea and West Africa via pipeline connected to the Louisiana Offshore Oil Port. The refinery produces a high percentage of transportation fuels such as gasoline, diesel, and jet fuel along with home heating oil. Other products include petrochemical feedstocks (benzene) and petroleum (fuel) coke. The majority of the refined products are distributed to customers through the Colonial and Plantation pipeline systems. LAKE CHARLES REFINERY The Lake Charles refinery is located in Westlake, Louisiana. The refinery has a crude oil processing capacity of 252,000 barrels per day. The refinery receives domestic and international crude oil and processes heavy, high-sulfur, low-sulfur and acidic crude oil. While the sources of international crude oil can vary, the majority is Venezuelan and Mexican heavy crudes delivered via tanker. The refinery produces a high percentage of transportation fuels such as gasoline, off-road diesel, and jet fuel along with heating oil. The majority of the refined products are distributed to customers by truck, rail or major common-carrier pipelines. In addition, refinery products can be sold into export markets through the refinery's marine terminal. The Lake Charles facilities also include a specialty coker and calciner that manufactures graphite and anode petroleum cokes supplied to the steel and aluminum industries, and provides 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. The Lake Charles refinery supplies feedstocks to Excel Paralubes, Penreco and Venture Coke Company (Venco), all joint ventures that are part of the company's Specialty Businesses function within R&M. 19 SWEENY REFINERY The Sweeny refinery is located in Old Ocean, Texas, about 65 miles southwest of Houston. Effective March 1, 2003, the refinery's crude oil processing capacity increased to 215,000 barrels per day as a result of incremental debottlenecking. The refinery primarily receives crude oil through ConocoPhillips' and jointly owned terminals on the Gulf Coast, including a deepwater terminal at Freeport, Texas. The refinery produces a high percentage of transportation fuels such as gasoline, diesel, and jet fuel along with home heating oil. Other products include petrochemical feedstocks (benzene) and petroleum (fuel) coke. Refined products are distributed throughout the Midwest and southeastern United States through pipeline, barge and railcar. ConocoPhillips and PDVSA have a limited partnership that operates a 58,000 barrel-per-day delayed coker and related facilities at the Sweeny refinery. Under the terms of the agreements, PDVSA supplies the refinery up to 165,000 barrels per day of Venezuelan Merey, or equivalent, crude oil. ConocoPhillips is the operator of, and holds a 50 percent interest in, the coker through its interest in Merey Sweeny, L.P. Central Region WOOD RIVER REFINERY The Wood River refinery is located in Roxana, Illinois, about 15 miles north of St. Louis, Missouri, on the east side of the Mississippi River. It is the company's largest refinery, with a crude oil processing capacity of 286,000 barrels per day and can process a mix of both light low-sulfur and heavy high-sulfur crudes. The facility receives domestic and foreign crude oil by pipeline. The refinery produces a high percentage of transportation fuels such as gasoline, diesel, and jet fuel along with home heating oil. Other products include petrochemical feedstocks (benzene) and asphalt. Through an off-take agreement, a significant portion of its gasoline, diesel and jet fuel is sold to a third party at the refinery for delivery via pipelines into the upper Midwest, including the Chicago, Illinois, and Milwaukee, Wisconsin, metropolitan areas. Remaining refined products are distributed to customers in the Midwest by pipeline, truck, barge and railcar. PONCA CITY REFINERY ConocoPhillips' refinery located in Ponca City, Oklahoma, has a crude oil processing capacity of 194,000 barrels per day. Both foreign and domestic crudes are delivered by pipeline from the Gulf of Mexico, Oklahoma, Kansas, Texas and Canada. 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. Finished petroleum products are shipped by truck, rail and company-owned and common-carrier pipelines to markets throughout the mid-continent region. BORGER REFINERY The Borger refinery is located in Borger, Texas, in the Texas Panhandle about 50 miles north of Amarillo. It includes a natural gas liquids fractionation facility. The crude oil processing capacity is 148,000 barrels per day, and the natural gas liquids fractionation capacity is 95,000 barrels per day. The refinery processes mainly heavy high-sulfur crudes. The refinery receives crude oil and natural gas liquids feedstocks through ConocoPhillips' pipelines from west Texas, the Texas Panhandle and Wyoming. The Borger refinery can also receive water-borne crude oil via ConocoPhillips' pipeline systems. The refinery produces a high percentage of transportation fuels such as gasoline, diesel, and jet fuel along with a variety of natural gas liquids and solvents. Pipelines move refined products from the refinery to west Texas, New Mexico, Arizona, Colorado, Kansas, Nebraska and the Chicago area. 20 BILLINGS REFINERY ConocoPhillips' Billings, Montana, refinery has a crude oil processing 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. A delayed coker converts heavy high-sulfur residue into higher value light oils. The refinery produces a high percentage of transportation fuels such as gasoline, jet fuel, diesel and fuel grade petroleum coke. Finished petroleum products from the refinery are delivered via company-owned pipelines, rail, and trucks. West Coast Region LOS ANGELES REFINERY The Los Angeles refinery is composed of two linked facilities located about five miles apart in Carson and Wilmington, California, about 15 miles southeast of Los Angeles International airport. Carson serves as the front-end of the refinery by processing crude oil, and Wilmington serves as the back-end by upgrading products. The refinery has a crude oil processing capacity of 132,000 barrels per day and processes mainly heavy high-sulfur crudes. The refinery receives domestic crude oil via pipeline from California and foreign and domestic crude oil by tanker through company-owned and third-party terminals in the Port of Los Angeles. The refinery produces a high percentage of transportation fuels such as gasoline, diesel, and jet fuel. Other products include fuel grade petroleum coke. The refinery produces California Air Resources Board gasoline, and also produces gasoline without methyl tertiary-butyl ether (MTBE) by using ethanol to meet federally mandated oxygenate requirements. Refined products are distributed to customers in southern California, Nevada and Arizona by pipeline and truck. SAN FRANCISCO AREA REFINERY The San Francisco Area refinery is composed of two linked facilities located about 200 miles apart. The Santa Maria facility is located in Arroyo Grande, California, about 200 miles south of San Francisco, while the Rodeo facility is in the San Francisco Bay area. The refinery's crude oil processing capacity is 109,000 barrels per day of mainly heavy high-sulfur crudes. Both the Santa Maria and Rodeo facilities have calciners to upgrade the value of the coke that is produced. The refinery receives crude oil from central California, including the Elk Hills oil field, and foreign crude oil by tanker. Semi-refined liquid products from the Santa Maria facility are sent by pipeline to the Rodeo facility for upgrading to finished petroleum products. The refinery produces transportation fuels such as gasoline, diesel, and jet fuel. Other products include fuel grade petroleum coke. The refinery produces California Air Resources Board gasoline, and also produces gasoline without MTBE by using ethanol to meet federally mandated oxygenate requirements. Refined products are distributed by pipeline, railcar, truck and barge. FERNDALE REFINERY The Ferndale refinery in Ferndale, Washington, is about 20 miles south of the United States-Canada border on Puget Sound. The refinery has a crude oil processing capacity of 92,000 barrels per day. The refinery receives crude oil primarily from the Alaskan North Slope, with secondary sources supplied by Canada or the Far East. Ferndale operates a deepwater dock that is capable of taking in full tankers bringing North Slope crude oil from Valdez, Alaska. The refinery is also connected to the Transmountain crude oil pipeline that originates in Canada. The refinery produces transportation fuels such as gasoline, diesel, and jet fuel. Other products include residual fuel oil supplying the northwest marine transportation market. Construction of a new fluidized catalytic cracking unit that will increase the yield of transportation fuel is expected to become fully operational in the second quarter of 2003. Most refined products are distributed by pipeline and barge to major markets in the northwest United States. 21 MARKETING At December 31, 2002, ConocoPhillips marketed gasoline through approximately 13,700 outlets in 48 states (excluding operations reported in discontinued operations in Corporate and Other). About 31 percent of these utilize the Conoco brand, about 47 percent are branded Phillips 66 outlets, while the remaining outlets feature the Circle K, 76, Exxon and Mobil brands. ConocoPhillips has the right to use the Exxon and Mobil brands in certain areas until 2010. ConocoPhillips also has the use of the Coastal brand in 10 states until 2011. Wholesale In its wholesale operations, the company utilizes a network of marketers and dealers operating approximately 12,600 outlets. ConocoPhillips also buys and sells petroleum products in spot markets. ConocoPhillips' refined products are marketed on both a branded and unbranded basis. In addition to automotive gasoline and diesel fuel, ConocoPhillips produces and markets aviation gasoline, which is used by smaller, piston-engine aircraft. Aviation gasoline and jet fuel are sold through independent marketers at approximately 600 branded locations in the United States. At December 31, 2002, CFJ Properties, a 50/50 joint venture between ConocoPhillips and Flying J, owned and operated 96 truck travel plazas that carry the Conoco and/or Flying J brands. Retail At December 31, 2002, ConocoPhillips owned and operated approximately 400 convenience stores under the Circle K, Phillips 66, Conoco and 76 brands in 12 states. The company-operated retail operations are focused in the mid-continent and West Coast regions. All the Phillips 66 branded outlets market merchandise through the Kicks 66 brand convenience stores. TRANSPORTATION Pipelines and Terminals At December 31, 2002, ConocoPhillips' R&M segment had approximately 31,500 miles of common-carrier crude oil, raw natural gas liquids and products pipeline systems in the United States, including those partially owned and/or operated by affiliates. The company also owned and/or operated 82 finished product terminals, six liquefied petroleum gas terminals, seven crude oil terminals and one coke exporting facility. Tankers At December 31, 2002, ConocoPhillips chartered 15 double-hulled crude oil tankers, with capacities ranging in size from 650,000 to 1,100,000 barrels. These tankers are utilized to transport feedstocks to certain of the company's U.S. refineries. The company also has an ocean-going barge under charter, as well as a domestic fleet of both owned and chartered boats and barges providing inland waterway transportation. The information above excludes the operations of the company's subsidiary, Polar Tankers Inc., which is discussed in the E&P section, as well as an owned tanker on lease to a third party for use in the North Sea. ConocoPhillips has agreements for the long-term chartering of five double-hulled crude oil tankers that are currently under construction. Delivery is expected in the third and fourth quarters of 2003. Two of these vessels are 825,000-barrel tankers, and three are 1,115,000-barrel tankers. The term of the agreement is 12 years from date of delivery. ConocoPhillips plans to utilize the new tankers to replace older vessels in supplying its East Coast refining operations. 22 SPECIALTY BUSINESSES ConocoPhillips manufactures and sells a variety of high-value lubricants and specialty products including petroleum cokes, lubes, such as automotive and industrial lubricants, solvents and pipeline flow improvers, to commercial, industrial and wholesale accounts worldwide. Lubricants are marketed under the Conoco, Hydroclear, Phillips 66, 76 and Kendall brands. These lubricants are sold by marketers, mass merchandise stores, fast lubes, tire stores, automotive dealers, and convenience stores. Lubricants are also sold to industrial customers in many markets. Excel Paralubes is a joint-venture hydrocracked lubricating base oil manufacturing facility located adjacent to the Lake Charles refinery, and is 50 percent owned by ConocoPhillips. Excel Paralubes' lube oil facility produces approximately 20,000 barrels per day of high-quality, clear hydrocracked base oils. Hydrocracked base oils are second in quality only to synthetic base oils, but are produced at a much lower cost. The Lake Charles refinery supplies Excel Paralubes with gas-oil feedstocks. ConocoPhillips has a 50 percent interest in Penreco, a fully integrated specialties company, which manufactures and markets highly refined specialty petroleum products, including solvents, waxes, petrolatums and white oils, for global markets. The company manufactures high-quality graphite and anode-grade cokes in the United States and Europe, for use in the global steel and aluminum industries. Venco is a coke calcining joint venture in which ConocoPhillips has a 50 percent interest. Green petroleum coke is supplied to Venco's Lake Charles calcining facility from the Lake Charles refinery. INTERNATIONAL REFINING At December 31, 2002, ConocoPhillips owned or had an interest in six refineries outside the United States with an aggregate rated crude oil capacity of 440,000 net barrels per day. The average purchase cost of crude oil delivered to the company's international refineries in 2002 was $24.55 per barrel, compared with a $21.10 per barrel in 2001. Humber Refinery ConocoPhillips' wholly owned Humber refinery is located in North Lincolnshire, United Kingdom. Effective January 1, 2003, Humber's capacity was increased by 2,000 barrels per day to 234,000 barrels per day as a result of incremental debottlenecking. Crude oil processed at the refinery is 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. 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 is a fully integrated 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 United Kingdom, while the other products are exported to the rest of Europe and the United States. This gives the refinery the flexibility to take full advantage of inland and global export market opportunities. 23 Whitegate Refinery The Whitegate refinery is located in Cork, Ireland. Whitegate is Ireland's only refinery, and has a processing capacity of 72,000 barrels per day. Crude oil processed by the refinery is light sweet crude sourced mostly from the North Sea. The refinery primarily produces transportation fuels and fuel oil, which are distributed to the inland market via truck and sea, as well as being exported to the European market. ConocoPhillips also operates a deepwater crude oil and products storage complex in Bantry Bay, Ireland. MiRO Refinery The MiRO refinery in Karlsruhe, Germany, is a joint-venture refinery with a crude oil processing capacity of 283,000 barrels per day. ConocoPhillips has an 18.75 percent interest in MiRO, giving the company a net capacity share of 53,000 barrels per day. The other owners of MiRO are Shell & DEA Oil GmbH (formerly 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 oil feedstock is low-cost, high-sulfur crude. The MiRO complex is a fully integrated 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 refinery 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 ConocoPhillips, through its participation in Ceska rafinerska, a.s. (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 oil processing capacity of 103,000 barrels per day, and the Kralupy refinery has a crude oil processing capacity of 63,000 barrels per day. ConocoPhillips' 16.33 percent ownership share of the combined capacity is 27,000 barrels per day. Both refineries process mostly high-sulfur crude oil, with a large portion being Russian export blend delivered by pipeline. The refineries have an alternative crude supply via a pipeline from the Mediterranean. The two refineries are operated as a single entity, with certain intermediate streams moving between the two facilities. CRC markets finished products both inland and abroad. Melaka Refinery The refinery in Melaka, Malaysia, is a joint venture with Petronas, the Malaysian state oil company. ConocoPhillips owns a 47 percent interest in the joint venture. The refinery has a rated crude oil processing capacity of 120,000 barrels per day, of which ConocoPhillips' share is 56,000 barrels per day. Crude oil processed by the refinery is sourced mostly from the Middle East. The refinery produces a full range of refined petroleum products. The refinery capitalizes on ConocoPhillips' proprietary coking technology to upgrade low-cost feedstocks to higher-margin products. ConocoPhillips' share of refined products is distributed by truck to the company's ProJET retail sites in Malaysia, or transported by sea primarily to Asian markets. MARKETING ConocoPhillips had marketing operations in 15 European countries at December 31, 2002. The company's European marketing strategy is to sell primarily through owned, leased or joint-venture retail sites using a low-cost, high-volume, low-price strategy. ConocoPhillips also markets aviation fuels, liquid petroleum gases, heating oils, transportation fuels and marine bunkers to commercial customers and into the bulk or spot market. 24 ConocoPhillips uses the "JET" brand name to market its retail products in its wholly owned operations in Austria, the Czech Republic, Denmark, Finland, Belgium, Luxembourg, Germany, Hungary, Norway, Poland, Slovakia, Sweden and the United Kingdom. In addition, various joint ventures in which ConocoPhillips has an equity interest market products in Switzerland and Turkey under the "Coop" and "Tabas" or "Turkpetrol" brand names, respectively. As of December 31, 2002, ConocoPhillips had approximately 2,100 marketing outlets in its wholly owned European operations, of which about 1,200 were company-owned. Through ConocoPhillips' joint venture operations in Turkey and Switzerland, the company also has an interest in an additional 770 sites. The company's largest branded site networks are in Germany and the United Kingdom, which account for 60 percent of total European branded units. As of December 31, 2002, ConocoPhillips had 137 marketing outlets in its wholly owned Thailand operations in Asia. In addition, through a joint venture in Malaysia with Sime Darby Bhd., a company that has a major presence in the Malaysian business sector, ConocoPhillips also has an interest in another 25 retail sites. In Thailand and Malaysia, retail products are marketed under the "JET" and "ProJET" brands, respectively. CHEMICALS --------- On July 1, 2000, ConocoPhillips and ChevronTexaco combined their worldwide chemicals businesses, excluding ChevronTexaco's Oronite business, into a new company, Chevron Phillips Chemical Company LLC (CPChem). In addition to contributing the assets and operations included in the company's Chemicals segment, ConocoPhillips also contributed the natural gas liquids business associated with its Sweeny, Texas, complex. ConocoPhillips and ChevronTexaco each own 50 percent of CPChem. ConocoPhillips uses the equity method of accounting for its investment in CPChem. CPChem, headquartered in The Woodlands, Texas, has 32 production facilities and six research and technology centers. CPChem uses natural gas liquids and other feedstocks to produce petrochemicals such as ethylene, propylene, styrene, benzene and paraxylene. These products are then marketed and sold, or used as feedstocks to produce plastics and specialty chemicals, such as polyethylene, cumene, and cyclohexane. CPChem's domestic facilities are located at Baytown, Borger, Conroe, La Porte, Orange, Pasadena, Port Arthur and Old Ocean, Texas; St. James, Louisiana; Pascagoula, Mississippi; Marietta, Ohio; and Guayama, Puerto Rico. CPChem also has nine plastic pipe plants and one pipe fittings plant in eight states. Major international facilities are located or under construction in Belgium, China, Saudi Arabia, Singapore, South Korea and Qatar. There is one plastic pipe plant in Mexico. Construction continued in Qatar on a major olefins and polyolefins complex, named Q-Chem I. The facility is designed to have an annual capacity of 1.1 billion pounds of ethylene, 1 billion pounds of polyethylene and 100 million pounds of 1-hexene. Construction of the complex, located in Mesaieed, Qatar, is nearing completion and the complex is undergoing commissioning. CPChem has a 49 percent interest, with a Qatar state-firm owning the remaining 51 percent interest. CPChem also signed an agreement for the development of a complex to be built in Ras Laffan, Qatar, named Q-Chem II. The facility will be an integrated ethylene and polyethylene complex. Final approval of Q-Chem II is anticipated in mid-2004, with startup expected in 2007. 25 CPChem announced plans in 2002 for a 50 percent-owned joint venture project in Al Jubail, Saudi Arabia. The project, expected to cost approximately $1 billion, is planned to produce styrene and propylene. Final approval of the project is anticipated in the fourth quarter of 2003, with operational start-up expected in 2006. A brief description of CPChem's major product lines follows. OLEFINS AND POLYOLEFINS Ethylene: Ethylene is a simple olefin used primarily to produce plastics, such as polyethylene. Ethylene is produced at Old Ocean, Port Arthur and Baytown, Texas. CPChem's net annual capacity at December 31, 2002, was approximately 7.6 billion pounds. Polyethylene: Polyethylene is used to make a wide variety of plastic products, including trash bags, milk jugs, bottles and plastic films. Polyethylene is produced at Pasadena, Baytown, and Orange, Texas, as well as in China and Singapore. CPChem's net annual capacity at December 31, 2002, was approximately 5.1 billion pounds. Plastic Pipe: Polyethylene is used to manufacture plastic pipe and pipe fittings. Plastic pipe is produced at nine plants in the United States and one plant in Mexico. Pipe fittings are produced at one plant in the United States. CPChem's net annual capacity at December 31, 2002, was approximately 544 million pounds. Normal Alpha Olefins: Normal alpha olefins can be custom blended for special applications and are used extensively as polyethylene comonomers and in plasticizers, synthetic motor oils and lubricants. Normal alpha olefins are produced at Baytown, Texas. CPChem's net annual capacity at December 31, 2002, was approximately 1.3 billion pounds. AROMATICS AND STYRENICS Styrene: Styrene, produced from benzene and ethylene, is used as a feedstock for polystyrene and other applications. Styrene is produced at St. James, Louisiana. CPChem's net annual capacity at December 31, 2002, was approximately 2.1 billion pounds. Polystyrene: Polystyrene is a thermoplastic polymer used in cups, disposable cameras, disposable signs, and other applications. It is produced at Marietta, Ohio, and in China. CPChem's net annual capacity at December 31, 2002, was approximately 990 million pounds. Benzene: Benzene is used to make cumene, cyclohexane, styrene and other products. Benzene is produced at Pascagoula, Mississippi; Port Arthur, Texas; and in Saudi Arabia. CPChem's net annual capacity at December 31, 2002, was approximately 2.7 billion pounds. Cyclohexane: Cyclohexane is a derivative of benzene that is used as a feedstock for nylon. It is produced at Port Arthur, Texas, and in Saudi Arabia. CPChem markets all of its own cyclohexane production, as well as that of its affiliates. CPChem's net annual capacity at December 31, 2002, was approximately 575 million pounds. In addition, CPChem markets cyclohexane production from ConocoPhillips' Sweeny and Borger complexes. K-Resin(R): K-Resin(R) is a styrene-butadiene (SBC) copolymer used to produce a clear, shatter-resistant resin. It is produced at the Houston Chemical Complex (HCC) in Pasadena, Texas, and in South Korea. Production of K-Resin SBC at HCC was idled in March 2000 as a result of an accident and fire at the plant. The plant began a phased-in start-up in the fourth quarter of 2001 and the force majeure status of the plant was lifted in May 2002. CPChem's annual capacity at HCC at December 31, 2002, was 26 approximately 270 million pounds. CPChem also has a net annual capacity of 69 million pounds at an equity affiliate's plant in Yochon, South Korea. Paraxylene: Paraxylene is an aromatic used as a feedstock for polyester. It is produced at Pascagoula, Mississippi. CPChem's net annual capacity at December 31, 2002, was approximately 1.0 billion pounds. SPECIALTY PRODUCTS Specialty Chemicals: CPChem manufactures, markets and distributes organosulfur, paraffinic, olefinic and aromatic specialty chemicals as well as a complete line of natural gas odorants, specialty catalysts, specialty fuels, mining chemicals and oilfield drilling additives, enhancers and cements. These products are manufactured and processed in Borger and Conroe, Texas and Tessenderlo, Belgium. Ryton(TM) Polyphenylene Sulfide: CPChem produces high-performance polyphenylene sulfide polymers sold under the trademark Ryton(TM), which is produced at Borger, Texas. CPChem's annual capacity of Ryton polymer at December 31, 2002, was 22 million pounds. Ryton compounds are produced in Belgium and Singapore. These facilities have a net annual capacity of approximately 29 million pounds of Ryton compounds in the aggregate. CPChem has research facilities in Oklahoma, Ohio, and Texas, as well as in Singapore and Brussels, Belgium. EMERGING BUSINESSES ------------------- Emerging businesses encompass the development of new businesses beyond the company's traditional operations. CARBON FIBERS In 2002, ConocoPhillips completed the construction of its first carbon fibers manufacturing plant located in Ponca City, Oklahoma. ConocoPhillips confronted technology issues during construction, which resulted in a delay in the development of carbon fibers applications. As a result of market, operating and technological uncertainties, the company announced in February 2003 that it would shut down this project. GAS-TO-LIQUIDS (GTL) The GTL process refines natural gas into a wide range of transportable products. ConocoPhillips' GTL research facility is located in Ponca City, Oklahoma. The research facility includes laboratories and pilot plants to facilitate technology advancements. A 400 barrel-per-day pilot plant, designed to produce clean fuels from natural gas, is under construction in Ponca City and scheduled for completion in 2003. FUELS TECHNOLOGY ConocoPhillips' fuels technology businesses provide technologies and services that can be used in the company's operations or licensed to third parties. Downstream, major product lines include sulfur removal technologies (S Zorb), alkylation technologies (ReVAP), and delayed coking technologies. For upstream and downstream, fuels technology offers analytical services, pilot plant, and industrial hygiene services. 27 POWER GENERATION The focus of the power business is on developing integrated projects in support of the company's E&P and R&M strategies and business objectives. The projects that enable these strategies are included within the respective E&P and R&M segments. The projects and assets that have a significant merchant component are included in the Emerging Business segment. The power business is developing a 730-megawatt gas-fired combined heat and power plant in North Lincolnshire, United Kingdom. The facility will provide steam and electricity to the Humber refinery and steam to a neighboring refinery, as well as market power into the U.K. market. Construction began in 2002, with commercial operation anticipated in 2004. ConocoPhillips also owns or has an interest in gas-fired cogeneration plants in Orange and Corpus Christi, Texas. EMERGING TECHNOLOGY Emerging Technology focuses on developing new business opportunities designed to provide growth options for ConocoPhillips well into the future. Example areas of interest include renewable energy, advanced hydrocarbon processes, energy conversion technologies and new petroleum-based products. COMPETITION ConocoPhillips competes with private, public and state-owned companies in all facets of the petroleum and chemicals businesses. Some of the company's competitors are larger and have greater resources. Each of the segments in which ConocoPhillips operates is highly competitive. No single competitor, or small group of competitors, dominates any of ConocoPhillips' business lines. Upstream, the company's E&P segment competes with numerous other companies in the industry to locate and obtain new sources of supply, and to produce oil and natural gas in an efficient, cost-effective manner. Based on reserves statistics published in the September 9, 2002, issue of the Oil and Gas Journal, ConocoPhillips had the sixth-largest total of worldwide reserves of non-state-owned companies. The company delivers its oil and natural gas production into the worldwide oil and natural gas commodity markets. The principal methods of competing include geological, geophysical and engineering research and technology; experience and expertise; and economic analysis in connection with property acquisitions. The company's Midstream segment, through its equity investment in DEFS and its consolidated operations, competes with numerous other integrated petroleum companies, as well as natural gas transmission and distribution companies, to deliver the components of natural gas to end users in the commodity natural gas markets. DEFS is one of the largest producers of natural gas liquids in the United States, based on the November 18, 2002, Gas Processors Report. DEFS' principle methods of competing include economically securing the right to purchase raw natural gas into its gathering systems, managing the pressure of those systems, operating efficient natural gas liquids processing plants, and securing markets for the products produced. Downstream, the company's R&M segment competes primarily in the United States, Europe and the Asia Pacific region. Based on the statistics published in the December 23, 2002, issue of the Oil and Gas Journal, ConocoPhillips had the largest U.S. refining capacity of about 20 large refiners of petroleum products. In the Chemicals' segment, through its equity investment in CPChem, the company generally ranks in the middle of approximately 10 major competitors, based on ethylene, polyethylene, benzene and 28 styrene production capacity at year-end 2002, as published by Chemical Market Associates Inc. Petroleum products are primarily delivered into U.S. commodity markets, while petrochemicals and plastics are delivered into the worldwide commodity markets. Elements of downstream competition include product improvement, new product development, low-cost structures, and manufacturing and distribution systems. In the marketing portion of the business, competitive factors include product properties and processibility, reliability of supply, customer service, price and credit terms, advertising and sales promotion, and development of customer loyalty to ConocoPhillips' or CPChem's branded products. GENERAL At the end of 2002, ConocoPhillips held a total of 2,043 active patents in 72 countries worldwide, including 737 active U.S. patents. During 2002, the company received 61 patents in the United States and 134 foreign patents. The company's products and processes generated licensing revenues of $28 million in 2002. The overall profitability of any business segment is not dependent on any single patent, trademark, license, franchise or concession. Company-sponsored research and development activities charged against earnings were $355 million, $44 million and $43 million in 2002, 2001 and 2000, respectively. The environmental information contained in Management's Discussion and Analysis on pages 66 through 70 under the caption, "Environmental" is incorporated herein by reference. It includes information on expensed and capitalized environmental costs for 2002 and those expected for 2003 and 2004. Like all major, international oil companies, the company has for many years operated in countries that are subject to U.S. Government restrictions or prohibitions on business activities by U.S. companies. In some cases, business is permitted if the company has received a license from the Office of Foreign Assets Control (OFAC). In some cases where the company is prohibited from doing business, non-U.S. subsidiaries of the company are not restricted. The regulations implementing the restrictions are complicated and subject to interpretation by OFAC. The company has programs designed to ensure compliance with the restrictions and believes that its present operations do not violate the restrictions. In view of recent political, diplomatic and military developments in the Middle East, and throughout the world, the company is reexamining its policies and procedures in order to prevent any actions that would violate the letter, or even the spirit of the restrictions. These developments may affect prices, production levels, allocation and distribution of raw materials and products, including their import, export and ownership; the amount of tax and timing of payment; and the cost of compliance with environmental regulations. In recent weeks, a number of institutional investors and state governmental agencies have questioned the appropriateness of U.S. companies transacting business in or with any country that has reportedly been linked to terrorism, even if the country is not subject to legal restrictions. The company is also reexamining its policies to seek to ensure that its activities in or with certain countries is consistent with the U.S. government's policy, interests and objectives in such countries. Political or military developments, enactment by the U.S. of new legal restrictions, more stringent interpretation of existing legal restrictions, or decisions by the company to voluntarily cease operations in certain areas in order to protect its reputation could materially adversely affect the company. ITEM 3. LEGAL PROCEEDINGS The following is a description of legal proceedings involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment for this reporting period. The 29 following proceedings include those matters previously reported in Conoco's and Phillips' respective 2001 Forms 10-K, first- and second- quarter 2002 Forms 10-Q and ConocoPhillips' third-quarter 2002 Form 10-Q that have not been resolved. While it is not possible to predict the outcome of such proceedings, if any of such proceeding were decided adversely to ConocoPhillips, there would be no material effect on the company's consolidated financial position. Nevertheless, such proceedings are reported pursuant to the United States Securities and Exchange Commission's regulations. ConocoPhillips has responded to information requests from the United States Environmental Protection Agency (EPA) regarding New Source Review compliance at its Alliance, Bayway, Borger, Ferndale, Los Angeles, Rodeo, Santa Maria, Sweeny, Trainer and Wood River refineries. Although ConocoPhillips has not been notified of any formal findings or violations arising from these information requests, ConocoPhillips has been informed that the EPA is contemplating the filing of a civil proceeding against ConocoPhillips for alleged violations of the Clean Air Act. ConocoPhillips currently seeks a negotiated resolution of these matters which will likely result in increased environmental capital expenditures and governmental monetary sanctions. On December 31, 2002, the company received a Revised Proposed Agreed Order, which amended the June 24, 2002, Proposed Agreed Order, from the Texas Commission on Environmental Quality (TCEQ), proposing a penalty of $458,163 in connection with alleged air emission violations at the company's Borger, Texas, refinery as a result of an inspection conducted by the TCEQ in October 2000. On March 19, 2003, the TCEQ issued a recalculation of the proposed penalty in the amount of $467,834. On December 17, 2002, the United States Department of Justice (DOJ) notified ConocoPhillips of various alleged violations of the National Pollution Discharge Elimination System (NPDES) Permit for the Sweeny Refinery. DOJ asserts that these alleged violations occurred at various times during the period beginning January 1997 through July 2002. DOJ seeks a civil penalty in the amount of $1.6 million. On November 14, 2002, the TCEQ issued a proposed agreed Findings Order to resolve alleged water discharge violations of the Texas Water Code and Commission Rules at the Sweeny Refinery for the period beginning March 2000 through July 2002. The proposed order assesses a penalty in the amount of $488,125. On September 27, 2002, the Montana Department of Environmental Quality (MDEQ) issued a Notice of Violation (NOV) to ConocoPhillips. The NOV alleges that on December 13, 2000, the company discharged 52,374 gallons of gasoline from Tank 32 at its Helena, Montana product storage terminal. The NOV seeks a penalty in the amount of $114,000. The company anticipates that this matter will be settled early in the second quarter of 2003. On September 26, 2002, the EPA Region 5 filed an Administrative Complaint against the company alleging federal clean air act compliance violations associated with a product tank roof seal during the period December 15, 1997 through October 1, 2001. On November 25, 2002, the company and the EPA entered into a Consent Agreement and Final Order requiring the company to pay a $46,381 cash penalty and perform a supplemental environmental project (SEP). The SEP is estimated to cost approximately $180,000. On July 15, 2002, the United States filed a Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) cost recovery action against the company alleging that the United States has incurred unreimbursed oversight costs at the Lowry Superfund Site located in Arapahoe County, Colorado. The United States seeks recovery of approximately $12.3 million in past oversight costs and a declaratory judgment for future CERCLA response cost liability. Pursuant to the terms of a prior settlement agreement between the company, Waste Management, Inc. and others, Waste Management has assumed the 30 company's defense for this matter and it is the company's position that Waste Management should indemnify it for any liability arising from this action. On June 28, 2002, the company received an administrative civil complaint from the EPA, alleging violation of Emergency Planning and Community Right to Know Act found during an audit of the Los Angeles refinery in March 2000. This matter was settled in the first quarter of 2003. The company conducted negotiations with the EPA and the states of Colorado, Louisiana, Montana, and Oklahoma throughout 2001 as part of the EPA's nationwide initiative to enforce federal air regulations at petroleum refineries. In December 2001, the company entered into a Consent Decree with the United States, Colorado, Louisiana, Montana, and Oklahoma to reduce emissions from the company's Billings, Denver, Lake Charles and Ponca City refineries by a total of 7,500 tons per year over the subsequent seven years. The company expects to spend an estimated $95 million to $110 million over that time period to install control technology and equipment to reduce emissions from stacks, vents, valves, heaters, boilers and flares. The Consent Decree required and the company has paid a civil penalty of $1.5 million, in addition to requiring $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. During August 2001, the EPA and the DOJ notified the company 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 the company's Denver refinery. The matter was settled in the fourth quarter of 2002. In June of 1997, the company experienced pipeline spills on its Seminoe pipeline at Banner, Wyoming, and Lodge Grass, Montana. In response to these spills, the DOJ advised the company in August 2000 that the United States is contemplating a legal proceeding under the Clean Water Act against the company. The company and DOJ are currently in negotiations to resolve these matters. In addition to the above environmental matters, on March 27, 2000, an explosion and fire occurred at the K-Resin SBC plant due to the overpressurization of an out-of-service butadiene storage tank. One employee was killed and several individuals, including employees of both ConocoPhillips and its contractors, were injured. Additionally, individuals who were allegedly in the area of the Houston Chemical Complex at the time of the incident have claimed they suffered various personal injuries due to exposure to the event. The wrongful death claim and the claims of the most seriously injured workers have been resolved. Currently, there are eight lawsuits pending on behalf of approximately 100 primarily plaintiffs. Under the indemnification provisions of subcontracting agreements with Zachry Construction Corporation and Brock Maintenance, Inc., ConocoPhillips sought indemnification from these subcontractors with respect to claims made by their employees. Although that plant was contributed to CPChem under the Contribution Agreement, ConocoPhillips retains liability for damages arising out of the incident. Additionally, the company 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 toxic tort claims. As a result of Conoco's separation agreement with DuPont, ConocoPhillips 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 31 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 None. EXECUTIVE OFFICERS OF THE REGISTRANT
Name Position Held Age* ---- ------------- ---- Rand C. Berney Vice President and Controller 47 William B. Berry Executive Vice President, Exploration and Production 50 John A. Carrig Executive Vice President, Finance, and Chief Financial Officer 51 Archie W. Dunham Chairman of the Board of Directors 64 Philip L. Frederickson Executive Vice President, Commercial 46 Rick A. Harrington Senior Vice President, Legal, and General Counsel 58 John E. Lowe Executive Vice President, Planning and Strategic Transactions 44 Robert E. McKee III Executive Vice President 56 J. J. Mulva President and Chief Executive Officer 56 J. W. Nokes Executive Vice President, Refining, Marketing, Supply and Transportation 56
---------- *On March 1, 2003. There is no family relationship among the officers named above. Each officer of the company is elected by the Board of Directors at its first meeting after the Annual Meeting of Stockholders and thereafter as appropriate. Each officer of the company holds office from date of election until the first meeting of the directors held after the next Annual Meeting of Stockholders or until a successor is elected. The date of the next annual meeting is May 6, 2003. Set forth below is information concerning the executive officers. 32 RAND C. BERNEY was appointed Vice President and Controller of ConocoPhillips upon completion of the merger. Prior to the merger, he was Phillips' Vice President and Controller since 1997. WILLIAM B. BERRY was appointed Executive Vice President, Exploration and Production of ConocoPhillips on January 1, 2003, having previously served as President of ConocoPhillips' Asia Pacific operations since completion of the merger. Prior to the merger, he was Phillips' Senior Vice President E&P Eurasia-Middle East operations since 2001; and Phillips' Vice President E&P Eurasia operations since 1998. JOHN A. CARRIG was appointed Executive Vice President, Finance, and Chief Financial Officer of ConocoPhillips upon completion of the merger. Prior to the merger, he was Phillips' Senior Vice President and Chief Financial Officer since 2001; Phillips' Senior Vice President, Treasurer and Chief Financial Officer since 2000; and Phillips' Vice President and Treasurer since 1996. ARCHIE W. DUNHAM was appointed Chairman of the Board of Directors of ConocoPhillips upon completion of the merger. Prior to the merger, he was Conoco's Chairman of the Board, President and Chief Executive Officer since 1999; and Conoco's President and Chief Executive Officer since 1996. PHILIP L. FREDERICKSON was appointed Executive Vice President, Commercial of ConocoPhillips upon completion of the merger. Prior to the merger, he was Conoco's Senior Vice President of Corporate Strategy and Business Development since 2001; and Conoco's Vice President of Business Development since 1998. RICK A. HARRINGTON was appointed Senior Vice President, Legal, and General Counsel of ConocoPhillips upon completion of the merger. Prior to the merger, he was Conoco's Senior Vice President, Legal and General Counsel since 1998. JOHN E. LOWE was appointed Executive Vice President, Planning and Strategic Transactions of ConocoPhillips upon completion of the merger. Prior to the merger, he was Phillips' Senior Vice President, Corporate Strategy and Development since 2001; Phillips' Senior Vice President of Planning and Strategic Transactions since 2000; Phillips' Vice President of Planning and Strategic Transactions since 1999; Phillips' Manager of Strategic Growth Projects since earlier in 1999; and Phillips' Supply Chain Manager in refining, marketing and transportation since 1997. ROBERT E. MCKEE III was appointed Executive Vice President of ConocoPhillips on January 1, 2003, having previously served as Executive Vice President, Exploration and Production since the completion of the merger. Prior to the merger, he was Conoco's Executive Vice President, Exploration Production since 1996. J. J. MULVA was appointed President and Chief Executive Officer of ConocoPhillips upon completion of the merger. Prior to the merger, he was Phillips' Chairman of the Board of Directors and Chief Executive Officer since 1999; Phillips' Vice Chairman of the Board of Directors, President, and Chief Executive Officer since earlier in 1999; and Phillips' President and Chief Operating Officer since 1994. J. W. NOKES was appointed Executive Vice President, Refining, Marketing, Supply and Transportation of ConocoPhillips upon completion of the merger. Prior to the merger, he was Conoco's Executive Vice President, Worldwide Refining, Marketing, Supply and Transportation since 1999; and Conoco's President of North American Refining and Marketing since 1998. 33 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS QUARTERLY COMMON STOCK PRICES AND CASH DIVIDENDS PER SHARE Phillips Petroleum Company's (predecessor to ConocoPhillips) stock was traded primarily on the New York, Pacific and Toronto stock exchanges. On August 30, 2002, it ceased trading.
Stock Price ---------------------- Phillips Petroleum Company (predecessor to ConocoPhillips) High Low Dividends ---------------------- --------- 2002 First $ 63.80 55.30 .36 Second 64.10 54.53 .36 Third (through August 30) 59.21 44.75 N/A ------------------------------------------------------------------------------------------------------------ 2001 First $ 59.00 51.70 .34 Second 68.00 52.78 .34 Third 59.86 50.00 .36 Fourth 60.95 50.66 .36 ------------------------------------------------------------------------------------------------------------
ConocoPhillips' common stock began trading on September 3, 2002, the first trading day after the effective date of the merger.
Stock Price ---------------------- High Low Dividends ---------------------- --------- 2002 Third (from September 3) $ 53.20 45.87 .36 Fourth 50.75 44.03 .40 ------------------------------------------------------------------------------------------------------------ Closing Stock Price at December 31, 2002 $ 48.39 Number of Stockholders of Record at February 28, 2003 60,666 ------------------------------------------------------------------------------------------------------------
ConocoPhillips' common stock is traded on the New York Stock Exchange. 34 ITEM 6. SELECTED FINANCIAL DATA
Millions of Dollars Except Per Share Amounts ----------------------------------------------------- 2002 2001 2000 1999 1998 ----------------------------------------------------- Sales and other operating revenues* $ 56,748 24,892 22,155 14,988 12,853 Income from continuing operations* 714 1,611 1,848 604 228 Per common share Basic 1.48 5.50 7.26 2.39 .88 Diluted 1.47 5.46 7.21 2.37 .88 Net income (loss) (295) 1,661 1,862 609 237 Per common share Basic (.61) 5.67 7.32 2.41 .92 Diluted (.61) 5.63 7.26 2.39 .91 Total assets 76,836 35,217 20,509 15,201 14,216 Long-term debt* 18,917 8,610 6,622 4,271 4,106 Mandatorily redeemable other minority interests and preferred securities 491 650 650 650 650 Cash dividends declared per common share 1.48 1.40 1.36 1.36 1.36 -----------------------------------------------------------------------------------------------------------
*Restated to exclude discontinued operations. See Management's Discussion and Analysis of Financial Condition and Results of Operations for a discussion of factors that will enhance an understanding of this data. The following transactions affect the comparability of the amounts included in the table above: o the merger of Conoco and Phillips in 2002; o the acquisition of Tosco Corporation in 2001; o the acquisition of Atlantic Richfield Company's Alaskan operations in 2000; and o the contribution of a significant portion of the company's midstream and chemicals businesses into joint ventures accounted for using equity-method accounting in 2000. 35 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS March 24, 2003 Management's Discussion and Analysis is the company's analysis of its financial performance and of significant trends that may affect future performance. It should be read in conjunction with the financial statements and notes, and supplemental oil and gas disclosures. It contains forward-looking statements including, without limitation, statements relating to the company's plans, strategies, objectives, expectations, intentions, and resources that are made pursuant to the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995. The words "intends," "believes," "expects," "plans," "scheduled," "anticipates," "estimates," and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any of the forward-looking information. Readers are cautioned that such forward-looking statements should be read in conjunction with the company's disclosures under the heading: "CAUTIONARY STATEMENT FOR THE PURPOSES OF THE 'SAFE HARBOR' PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995," beginning on page 76. RESULTS OF OPERATIONS CONOCO AND PHILLIPS MERGER On August 30, 2002, Conoco Inc. (Conoco) and Phillips Petroleum Company (Phillips) combined their businesses by merging with wholly owned subsidiaries of a new company named ConocoPhillips (the merger). The merger was accounted for using the purchase method of accounting. Although the business combination of Conoco and Phillips was a merger of equals, generally accepted accounting principles required that one of the two companies in the transaction be designated as the acquirer for accounting purposes. Phillips was designated as the acquirer based on the fact that its former common stockholders initially held more than 50 percent of the ConocoPhillips common stock after the merger. Because Phillips was designated as the acquirer, its operations and results are presented in this annual report for all periods prior to the close of the merger. From the merger date forward, the operations and results of ConocoPhillips reflect the combined operations of the two companies. As a condition of the merger, the U.S. Federal Trade Commission (FTC) required that the company divest specified Conoco and Phillips assets, the most significant of which were Phillips' Woods Cross, Utah, refinery and associated motor fuel marketing operations; Conoco's Commerce City, Colorado, refinery and related crude oil pipelines and Phillips' Colorado motor fuel marketing operations. All assets and operations that are required by the FTC to be divested are included in Corporate and Other as discontinued operations. Included in the results of discontinued operations in 2002 was a $69 million after-tax charge for the write-down to fair value of the Phillips operations to be disposed. Because the Conoco assets to be disposed of were recorded at fair value in the purchase price allocation, no further write-downs were required. Discontinued operations also include other, non-FTC mandated assets held for sale. See Note 4--Discontinued Operations in the Notes to Consolidated Financial Statements for additional information, including a complete list of assets required by the FTC to be divested. As a result of the merger, the company implemented a restructuring program in September 2002 to capture the synergies of combining Phillips and Conoco by eliminating redundancies, consolidating assets, and sharing common services and functions across regions. The restructuring program that was implemented in September 2002 is expected to be completed by the end of February 2004 and, through December 31, 36 2002, approximately 2,900 positions worldwide, most of which are in the United States, had been identified for elimination. Of this total, 775 employees were terminated by December 31, 2002. Associated with implementation of the restructuring program, ConocoPhillips accrued $770 million for merger-related restructuring and work force reduction liabilities in 2002. These liabilities primarily represent estimated termination payments and related employee benefits associated with the reduction in positions. These liabilities include $337 million related to Conoco operations, which was reflected in the purchase price allocation as an assumed liability, and $422 million ($253 million after-tax) related to Phillips operations that was charged to selling, general and administrative, and production and operating expenses; and $11 million before-tax included in discontinued operations. Of the above accruals, $598 million related primarily to severance benefits. Payments will be made to former Conoco and Phillips employees under each company's respective severance plans. During 2002, payments of $223 million were made, resulting in a year-end 2002 severance accrual balance of $375 million. Also related to the merger and recorded in 2002 was a $246 million write-off of acquired in-process research and development costs related to Conoco's natural gas-to-liquids and other technologies. In accordance with Financial Accounting Standards Board (FASB) Interpretation No. 4, "Applicability of FASB Statement No. 2 to Business Combinations Accounted for by the Purchase Method," value assigned to research and development activities in the purchase price allocation that have no alternative future use should be charged to expense at the date of the consummation of the combination. The $246 million charge was recorded in the Emerging Businesses segment and was the same on both a before-tax and after-tax basis. ConocoPhillips also accrued $22 million, after-tax, in 2002 for change-in-control costs associated with seismic contracts as a result of the merger. The expense was recorded in Corporate and Other and did not impact exploration expenses. In addition, the 2002 net loss also included transition costs of $36 million, bringing total after-tax merger-related costs to $557 million. See Note 3--Merger of Conoco and Phillips in the Notes to Consolidated Financial Statements for additional information on the merger. CONSOLIDATED RESULTS
Millions of Dollars -------------------------- Years Ended December 31 2002 2001 2000 -------------------------- Income from continuing operations $ 714 1,611 1,848 Income (loss) from discontinued operations (993) 32 14 Extraordinary items (16) (10) -- Cumulative effect of accounting changes -- 28 -- ----------------------------------------------------------------------- Net income (loss) $ (295) 1,661 1,862 =======================================================================
37 A summary of the company's net income (loss) by business segment follows:
Millions of Dollars ----------------------------- Years Ended December 31 2002 2001 2000 ----------------------------- Exploration and Production (E&P) $ 1,749 1,699 1,945 Midstream 55 120 162 Refining and Marketing (R&M) 143 397 238 Chemicals (14) (128) (46) Emerging Businesses (310) (12) -- Corporate and Other* (1,918) (415) (437) ---------------------------------------------------------------------------------------- Net income (loss) $ (295) 1,661 1,862 ======================================================================================== *Includes income (loss) from discontinued operations of: $ (993) 32 14
2002 vs. 2001 ConocoPhillips incurred a net loss of $295 million in 2002, compared with net income of $1,661 million in 2001. The decrease was primarily attributable to recognizing impairments and loss accruals totaling $1,077 million after-tax associated with the company's retail and wholesale marketing operations that were classified as discontinued operations in late 2002, as well as merger-related costs totaling $557 million after-tax. Also negatively impacting results for 2002 were asset impairments totaling $192 million after-tax, lower refining margins, lower natural gas sales prices, decreased equity earnings from Duke Energy Field Services, LLC (DEFS), and higher interest expenses. These factors were partially offset by improved results from Chemicals and higher production volumes in E&P after the merger. 2001 vs. 2000 ConocoPhillips' net income was $1,661 million in 2001, an 11 percent decline from net income of $1,862 million in 2000. The decrease was primarily attributable to lower crude oil and natural gas liquids prices and lower results from the Chemicals business, partially offset by improved petroleum products margins, as well as the acquisition of Tosco Corporation (Tosco) in September 2001. See Note 6--Acquisition of Tosco Corporation in the Notes to Consolidated Financial Statements for additional information on the acquisition. Also contributing to the lower results in 2001 was a decrease in the amount of gains on asset sales, compared with 2000, partially offset by lower property impairments in 2001. INCOME STATEMENT ANALYSIS 2002 vs. 2001 In addition to the merger discussed previously, ConocoPhillips closed on the $7 billion acquisition of Tosco on September 14, 2001. Together, these transactions significantly increased operating revenues, purchase costs, operating expenses and other income statement line items. See Note 3--Merger of Conoco and Phillips and Note 6--Acquisition of Tosco Corporation in the Notes to Consolidated Financial Statements for additional information. 38 Sales and other operating revenues increased 128 percent in 2002. The increase was primarily attributable to increased product sales volumes due to the impact of the Tosco acquisition and the merger. These items were partially offset by lower natural gas sales prices in 2002 compared with 2001. Equity in earnings of affiliates increased 537 percent in 2002. In addition to equity earnings from affiliates acquired in the merger for the last four months of 2002, equity earnings from Chevron Phillips Chemical Company LLC (CPChem) improved in 2002 as a result of improved margins. Partially offsetting these items were lower earnings in 2002 from DEFS and Merey Sweeny, L.P. (MSLP). DEFS' decline was primarily attributable to higher operating expenses, gas imbalance adjustments, and lower natural gas liquids prices, while MSLP's decline was mainly due to lower crude oil light-heavy differentials. Other income increased 94 percent in 2002, mainly the result of a favorable revaluation and settlement of long-term incentive performance units held by former senior Tosco executives, as well as additional interest income following the merger. During 2002, the company recorded gains totaling $59 million before-tax, as the incentive performance units were marked-to-market each reporting period and eventually settled. See Note 6--Acquisition of Tosco Corporation in the Notes to Consolidated Financial Statements for more information. Purchased crude oil and products increased 176 percent in 2002. The increase reflects higher purchase volumes of crude oil and petroleum products resulting from the Tosco acquisition and the merger. Production and operating expenses increased 89 percent in 2002, while selling, general and administrative (SG&A) expenses increased 171 percent. Both increases were primarily attributable to the Tosco acquisition and the merger. In conjunction with the merger, ConocoPhillips wrote off $246 million of acquired in-process research and development costs related to Conoco's natural gas-to-liquids and other technologies to production and operating expenses in 2002. ConocoPhillips also expensed $135 million in merger-related costs to production and operating expenses and $379 million to SG&A expenses in 2002. Exploration expenses increased 93 percent in 2002. The increase reflects the merger, a $77 million leasehold impairment of deepwater Block 34, offshore Angola, and dry hole costs of $161 million in 2002, compared with $48 million in 2001. Depreciation, depletion and amortization increased 65 percent in 2002, compared with 2001. The increase was primarily the result of an increased depreciable base of properties, plants and equipment following the merger and the Tosco acquisition. During 2002, ConocoPhillips recorded property impairments totaling $49 million in connection with the sale of its Point Arguello assets, offshore California; two fields in the U.K. North Sea; and its interest in a non-producing field in Alaska. Impairment of tradenames ($102 million) was also recognized in the statement of operations in 2002. Property impairments recorded in 2001 consisted primarily of a $23 million impairment of the Siri field, offshore Denmark. See Note 10--Impairments in the Notes to Consolidated Financial Statements for additional information. Taxes other than income taxes increased 153 percent in 2002, compared with 2001. The increase reflects higher excise taxes due to higher petroleum products sales and increased property and payroll taxes following the merger and the Tosco acquisition. Environmental liabilities assumed in acquisitions and mergers are recorded as liabilities at discounted amounts--i.e. the total future estimated cost is determined, then discounted back to current dollars using a time-value-of-money concept. Over time the liability is increased by accretion to reflect the time value of 39 money. Accretion on discounted liabilities increased 214 percent in 2002, reflecting the impact of the environmental liabilities assumed in the Tosco acquisition and the merger. Interest expense increased 67 percent in 2002, mainly due to higher debt levels following the Tosco acquisition and the merger. Foreign currency losses of $24 million were recorded in 2002, compared with losses of $11 million in 2001. Preferred dividend requirements decreased in 2002, reflecting the redemption of $300 million of preferred securities in May 2002. The company's effective tax rate from continuing operations in 2002 was 67 percent, compared with 51 percent in 2001. The increase in the effective tax rate in 2002 was primarily the result of the write-off of in-process research and development costs without a corresponding tax benefit and a higher proportion of income in higher-tax-rate jurisdictions. Losses from discontinued operations were $993 million in 2002, compared with income of $32 million in 2001. The 2002 amount includes after-tax impairments and loss accruals. See Note 4--Discontinued Operations in the Notes to Consolidated Financial Statements for additional information. 2001 vs. 2000 On March 31, 2000, ConocoPhillips and Duke Energy Corporation contributed their midstream gas gathering, processing and marketing businesses to DEFS. Effective July 1, 2000, ConocoPhillips and ChevronTexaco Corporation contributed their chemicals businesses, excluding ChevronTexaco's Oronite business, to CPChem. Both of these joint ventures are being accounted for using the equity method of accounting, which significantly affects how these operations are reflected in ConocoPhillips' consolidated statement of operations. Under the equity method of accounting, ConocoPhillips' share of a joint venture's net income is recorded in a single line item on the statement of operations: "Equity in earnings of affiliates." Correspondingly, the other income statement line items (for example, operating revenues, operating costs, etc.) include activity related to these operations only up to the effective dates of the joint ventures. Sales and other operating revenues increased 12 percent in 2001, primarily due to the Tosco acquisition and increased crude oil production. These items were partially offset by the use of equity-method accounting for the DEFS and CPChem joint ventures, as well as a reduction in revenues attributable to certain non-core assets sold at year-end 2000. Equity in earnings of affiliated companies decreased 64 percent in 2001. In the 2001 period, ConocoPhillips incurred a before-tax equity loss from its investment in CPChem of $240 million. ConocoPhillips' equity earnings related to DEFS were higher in 2001, as a result of a full year's activity in 2001, compared with only nine months in 2000. Equity earnings in 2001 benefited from a full year's operations at MSLP, a 50-percent-owned equity company that owns and operates the coker unit at the Sweeny, Texas, refinery. Other income decreased 59 percent in 2001, primarily attributable to lower net gains on asset sales in 2001 compared with 2000. Total costs and expenses increased 16 percent in 2001, compared with 2000. The increase was mainly the result of the Tosco acquisition, as well as a full year's ownership of the company's Alaskan E&P operations that were acquired in April 2000. These items were partially offset by the use of equity-method accounting for the DEFS and CPChem joint ventures, and lower crude oil acquisition costs at the company's refineries. 40 SEGMENT RESULTS E&P
2002 2001 2000 ------------------------------ Millions of Dollars ------------------------------ NET INCOME Alaska $ 870 866 829 Lower 48 286 476 559 ------------------------------------------------------------------------------------------- United States 1,156 1,342 1,388 International 593 357 557 ------------------------------------------------------------------------------------------- $1,749 1,699 1,945 ===========================================================================================
Dollars Per Unit ------------------------------ AVERAGE SALES PRICES Crude oil (per barrel) United States $23.83 23.57 28.83 International 25.14 24.16 28.42 Total consolidated 24.38 23.77 28.65 Equity affiliates 18.41 12.36 -- Worldwide 24.07 23.74 28.65 Natural gas--lease (per thousand cubic feet) United States 2.75 3.56 3.47 International 2.79 2.60 2.56 Total consolidated 2.77 3.23 3.13 Equity affiliates 2.71 -- -- Worldwide 2.77 3.23 3.13 ------------------------------------------------------------------------------------------- AVERAGE PRODUCTION COSTS PER BARREL OF OIL EQUIVALENT United States $ 5.66 5.52 5.27 International 3.99 2.70 2.85 Total consolidated 4.94 4.60 4.29 Equity affiliates 4.38 2.74 -- Worldwide 4.92 4.60 4.29 ------------------------------------------------------------------------------------------- FINDING AND DEVELOPMENT COSTS PER BARREL OF OIL EQUIVALENT United States $ 7.46 5.15 2.78 International* 5.09 6.80 1.17 Worldwide* 5.57 5.97 2.41 -------------------------------------------------------------------------------------------
*Includes ConocoPhillips' share of equity affiliates
Millions of Dollars ------------------------------ WORLDWIDE EXPLORATION EXPENSES General administrative; geological and geophysical; and lease rentals $ 285 207 168 Leasehold impairment 146 51 39 Dry holes 161 48 91 ------------------------------------------------------------------------------------------- $ 592 306 298 ===========================================================================================
41
2002 2001 2000 ------------------------------ Thousands of Barrels Daily ------------------------------ OPERATING STATISTICS Crude oil produced Alaska 331 339 207 Lower 48 40 34 34 ------------------------------------------------------------------------------------------- United States 371 373 241 Norway 157 117 114 United Kingdom 39 19 25 Canada 13 1 6 Other areas 67 51 51 ------------------------------------------------------------------------------------------- Total consolidated 647 561 437 Equity affiliates 35 2 -- ------------------------------------------------------------------------------------------- 682 563 437 =========================================================================================== Natural gas liquids produced Alaska 24 25 19 Lower 48 8 1 1 ------------------------------------------------------------------------------------------- United States 32 26 20 Norway 6 5 5 United Kingdom 2 2 2 Canada 4 -- 1 Other areas 2 2 1 ------------------------------------------------------------------------------------------- 46 35 29 ===========================================================================================
Millions of Cubic Feet Daily ------------------------------ Natural gas produced* Alaska 175 177 158 Lower 48 928 740 770 ------------------------------------------------------------------------------------------- United States 1,103 917 928 Norway 171 130 136 United Kingdom 424 178 214 Canada 165 18 83 Other areas 180 92 33 ------------------------------------------------------------------------------------------- Total consolidated 2,043 1,335 1,394 Equity affiliates 4 -- -- ------------------------------------------------------------------------------------------- 2,047 1,335 1,394 ===========================================================================================
*Represents quantities available for sale. Excludes gas equivalent of natural gas liquids shown above.
Thousands of Barrels Daily ------------------------------ Mining operations Syncrude produced 8 -- -- -------------------------------------------------------------------------------------------
2002 vs. 2001 Net income from ConocoPhillips' E&P segment increased 3 percent in 2002. Although E&P benefited from four months of increased production volumes in 2002 following the merger, this was mostly offset by lower natural gas sales prices, higher exploration expenses, and the unfavorable $24 million impact of a tax law change in the United Kingdom. ConocoPhillips' average worldwide crude oil sales price was 42 $24.07 per barrel in 2002, a 1 percent increase over $23.74 in 2001. The company's average worldwide natural gas price in 2002 was $2.77 per thousand cubic feet, a 14 percent decrease from $3.23 in 2001. However, natural gas prices trended upward during 2002, with the company's December 2002 worldwide price averaging $3.51 per thousand cubic feet. ConocoPhillips' proved reserves at year-end 2002 were 7.81 billion barrels of oil equivalent, a 52 percent increase over 5.13 billion barrels at year-end 2001. The increase was attributable to the merger. 2001 vs. 2000 Net income from ConocoPhillips' E&P segment decreased 13 percent in 2001, as the positive impact of increased crude oil production was more than offset by lower crude oil prices, and, to a lesser extent, lower natural gas production due mainly to asset dispositions in Canada. Benefiting 2000 net income was higher net gains on asset sales than in 2001. ConocoPhillips' average worldwide crude oil sales price was $23.74 per barrel in 2001, a 17 percent decrease from $28.65 in 2000. Natural gas prices began 2001 at historically high levels, but trended lower during the remainder of the year, with the company's December 2001 average price at $2.34 per thousand cubic feet. ConocoPhillips' proved reserves at year-end 2001 were 5.13 billion barrels of oil equivalent, a 2 percent increase over 5.02 billion barrels at year-end 2000. U.S. E&P 2002 vs. 2001 Net income from the company's U.S. E&P operations decreased 14 percent in 2002. Although net income for 2002 benefited from four months of increased production volumes following the merger, this was more than offset by lower natural gas prices, lower production volumes in Alaska, and higher dry hole costs. The company's U.S. average natural gas price in 2002 was 23 percent lower than 2001. However, natural gas prices trended upward during 2002, with the company's December 2002 average U.S. price at $3.66 per thousand cubic feet. The company's U.S. crude oil production decreased slightly in 2002, while natural gas production increased 20 percent. The increase in natural gas production was mainly due to four months of production from fields acquired in the merger. The merger impact on total crude oil production was offset by lower production in Alaska, which experienced normal field declines, along with operating interruptions at the Prudhoe Bay field during the year. With a full year's combined production from both Conoco and Phillips operations, the company expects that its total U.S. oil and gas production volumes will increase in 2003 over those of 2002. ConocoPhillips' fourth quarter production volumes, which included a full period of combined operations, averaged 426,000 barrels per day of liquids and 1,548 million cubic feet per day of natural gas. 2001 vs. 2000 Net income from the company's U.S. E&P operations decreased 3 percent in 2001, compared with 2000. The 2001 results reflect a 55 percent increase in crude oil production, due to a full year's production from the Alaska operations acquired in April 2000, as well as increased production due to the startup of the Alpine field in Alaska in December 2000. The benefit of increased crude oil production was offset by 43 lower U.S. crude oil prices, which declined 18 percent in 2001. U.S. natural gas production declined slightly in 2001, reflecting field declines and asset dispositions. Benefiting 2000 net income was a net gain on asset sales of $44 million--most of which was related to the disposition of the company's coal and lignite operations. International E&P 2002 vs. 2001 Net income from the company's international E&P operations increased 66 percent in 2002. The improvement reflects four months of increased production volumes following the merger. However, 2002 net income included a $24 million deferred tax charge related to tax law changes in the United Kingdom. In April 2002, the U.K. government announced proposed changes to corporate tax laws specifically impacting the oil and gas industry and production from the U.K. sector of the North Sea. The proposed changes became law in July 2002. A 10 percent supplementary charge to corporation taxes is now assessed on profits, which is expected to be partially offset by the elimination of royalties and an increase in first-year deduction allowances for capital investments. Net income in 2002 also included a $77 million leasehold impairment of deepwater Block 34, offshore Angola, due to an unsuccessful exploratory well in the block, along with higher dry hole charges. The company's international crude oil production increased 64 percent in 2002, while natural gas production increased 126 percent. The increases were mainly due to the addition of four months of production from fields acquired in the merger. With a full year's combined production from both Conoco and Phillips operations, the company expects that its total international oil and gas production volumes will increase in 2003 over those of 2002. ConocoPhillips' fourth quarter production volumes, which included a full period of combined operations, averaged 585,000 barrels per day of liquids and 1,994 million cubic feet per day of natural gas. 2001 vs. 2000 Net income from ConocoPhillips' international E&P operations decreased 36 percent in 2001. The decrease was primarily the result of lower crude oil and natural gas production volumes, as well as lower crude oil prices. Additionally, after-tax foreign currency gains of $2 million were included in international E&P's net income in 2001, compared with losses of $10 million in 2000. Net income in 2000 included a net gain on property dispositions of $118 million related to the disposition of the Zama area fields in Canada, partially offset by an $86 million impairment of the Ambrosio field in Venezuela. International crude oil production declined 3 percent in 2001, mainly due to lower production in the U.K. North Sea, Venezuela and Canada, partly offset by increased production from Norway and Nigeria. Canadian and Venezuelan crude oil production declined relative to 2000 due to asset dispositions. Production in the U.K. North Sea decreased on normal field declines. Production from Norway improved in 2001 due to improved processing reliability and well workovers, while Nigerian production increased on development activities and higher quotas. International natural gas production declined 10 percent in 2001, primarily the result of the Canadian asset dispositions and lower U.K. North Sea output noted above, partially offset by higher production in Nigeria and new natural gas production from offshore western Australia. 44 MIDSTREAM
2002 2001 2000 ---------------------------- Millions of Dollars ---------------------------- NET INCOME $ 55 120 162 -------------------------------------------------------------------
Dollars Per Barrel ---------------------------- AVERAGE SALES PRICES U.S. natural gas liquids* Consolidated $19.07 -- -- Equity 15.92 18.77 21.83** -------------------------------------------------------------------
Thousands of Barrels Daily ---------------------------- OPERATING STATISTICS Natural gas liquids extracted 156 120 131*** Natural gas liquids fractionated 133 108 158 --------------------------------------------------------------------
*Based on index prices from the Mont Belvieu and Conway market hubs that are weighted by natural gas liquids component and location mix. **Estimate based on ConocoPhillips' first quarter realized price and DEFS' index price for the remainder of the year. ***Based on a weighted average of ConocoPhillips' volumes in the first quarter of 2000, and ConocoPhillips' share of DEFS volumes for the remainder of 2000. 2002 vs. 2001 ConocoPhillips' Midstream segment consists of the company's 30.3 percent interest in Duke Energy Field Services, LLC (DEFS), as well as company-owned natural gas gathering and processing operations and natural gas liquids fractionation and marketing businesses. Net income from the Midstream segment decreased 54 percent in 2002. The decrease was primarily due to lower results from DEFS, which experienced a decline in natural gas liquids prices, increased costs for gas imbalance accruals and other adjustments, and higher operating expenses. These items were partially offset by the benefit of four month's results from operations acquired in the merger. Included in the Midstream segment's net income in 2002 was a benefit of $35 million, representing the amortization of the basis difference between the book value of ConocoPhillips' contribution to DEFS and its 30.3 percent equity interest in DEFS. The corresponding amount for 2001 was $36 million. See Note 8--Investments and Long-Term Receivables, in the Notes to Consolidated Financial Statements for additional information on the basis difference. 2001 vs. 2000 Net income from the Midstream segment decreased 26 percent in 2001, primarily the result of a 14 percent decline in natural gas liquids prices. In addition, the Midstream segment's results were affected by the lack of interest charges in the first quarter of 2000 prior to the formation of DEFS. DEFS incurs interest expense in connection with financing incurred upon formation to fund cash distributions to the parent entities. Prior to the formation of DEFS, the Midstream segment did not have interest expense. Included in the Midstream segment's net income in 2001 was a benefit of $36 million, representing the amortization of the basis difference between the book value of ConocoPhillips' contribution to DEFS and its 30.3 percent equity interest in DEFS. The corresponding amount for 2000 was $27 million. 45 R&M
2002 2001 2000 ------------------------------- Millions of Dollars ------------------------------- NET INCOME United States $ 138 395 209 International 5 2 29 -------------------------------------------------------------------------- $ 143 397 238 ==========================================================================
Dollars Per Gallon ------------------------------- U.S. AVERAGE SALES PRICES* Automotive gasoline Wholesale $ .96 .83 .92 Retail 1.03 1.01 1.07 Distillates--wholesale .77 .78 .88 --------------------------------------------------------------------------
*Excludes excise taxes
Thousands of Barrels Daily ------------------------------- OPERATING STATISTICS Refining operations* United States Rated crude oil capacity** 1,829 732 335 Crude oil runs 1,661 686 303 Capacity utilization (percent) 91% 94 90 Refinery production 1,847 795 365 International Rated crude oil capacity** 195 22 -- Crude oil runs 152 20 -- Capacity utilization (percent) 78% 91 -- Refinery production 164 19 -- Worldwide Rated crude oil capacity** 2,024 754 335 Crude oil runs 1,813 706 303 Capacity utilization (percent) 90% 94 90 Refinery production 2,011 814 365 -------------------------------------------------------------------------- Petroleum products sales volumes*** United States Automotive gasoline 1,147 465 267 Distillates 392 170 107 Aviation fuels 185 78 41 Other products 372 220 50 -------------------------------------------------------------------------- 2,096 933 465 International 162 10 43 -------------------------------------------------------------------------- 2,258 943 508 ==========================================================================
*2002 includes ConocoPhillips' share of equity affiliates. **Weighted-average crude oil capacity for the period, including the refineries acquired in the Tosco acquisition in September 2001 and the refineries acquired as a result of the merger. Actual capacity at year-end 2002 and 2001 was 2,166 thousand and 1,656 thousand barrels per day, respectively, in the United States and 440 thousand and 72 thousand barrels per day, respectively, internationally. ***Excludes spot market sales. 46 2002 vs. 2001 Net income from the R&M segment declined 64 percent in 2002, reflecting lower refining margins, along with an $84 million after-tax impairment of a tradename and leasehold improvements of certain retail sites. See Note 10--Impairments in the Notes to Consolidated Financial Statements for additional information on these impairments. The R&M earnings for 2002 included four months' results from operations acquired in the merger, as well as the impact of a full year's results from Tosco operations, while the 2001 results included Tosco operations for only the last three and one-half months of 2001. Worldwide crude oil refining capacity utilization was 90 percent in 2002, compared with 94 percent in 2001. The company's refineries produced 2,011,000 barrels per day of petroleum products in 2002, compared with 814,000 barrels per day in 2001. The increase reflects a full year of operations for refineries acquired in the Tosco acquisition and four months of operations for the refineries acquired in the merger. 2001 vs. 2000 Net income from the R&M segment increased 67 percent in 2001. On September 14, 2001, ConocoPhillips closed on the acquisition of Tosco. This transaction significantly increased the size of ConocoPhillips' R&M segment and benefited 2001 results. In addition to the Tosco acquisition, R&M's net income benefited from higher gasoline and distillates margins, particularly during the second quarter of 2001. Negatively affecting R&M results for the year were higher utility costs at the company's refineries, resulting from higher natural gas prices experienced in the first half of 2001. Worldwide crude oil refining capacity utilization was 94 percent in 2001, compared with 90 percent in 2000. The company's refineries produced 814,000 barrels per day of petroleum products in 2001, compared with 365,000 barrels per day in 2000. The increase reflects the Tosco acquisition. U.S. R&M 2002 vs. 2001 Net income from U.S. R&M operations declined 65 percent in 2002. The decrease was primarily due to lower refining margins, particularly in the Midcontinent and Gulf Coast regions, along with an $84 million after-tax impairment of a tradename and leasehold improvements of certain retail sites. See Note 10--Impairments in the Notes to Consolidated Financial Statements for additional information on these impairments. These items were partially offset by increased production and sales volumes as a result of the Tosco acquisition and the merger. Net income for 2002 included four months from operations acquired in the merger, and a full year of Tosco operations, while the 2001 results included Tosco operations for only three and one-half months. Results for 2001 included a cumulative effect of a change in accounting principle that increased R&M net income by $26 million. Effective January 1, 2001, ConocoPhillips changed its method of accounting for the costs of major maintenance turnarounds from the accrue-in-advance method to the expense-as-incurred method. Also included in 2001 was a $27 million write-down of inventories to market value. The crude oil capacity utilization rate for ConocoPhillips' U.S. refineries was 91 percent in 2002, compared with 94 percent in 2001. The lower utilization rate in 2002 reflects increased maintenance turnaround activity in 2002, the impact of tropical storms on the company's Gulf Coast refineries in the third quarter of 2002, and the impact of the loss of Venezuelan crude oil supply in the fourth quarter. 47 2001 vs. 2000 Net income from the R&M segment's U.S. operations increased 89 percent in 2001, compared with 2000. On September 14, 2001, ConocoPhillips closed on the acquisition of Tosco. This transaction significantly increased the size of ConocoPhillips' U.S. R&M operations and benefited 2001 net income. In addition to the Tosco acquisition, R&M's earnings benefited from higher gasoline and distillates margins, particularly during the second quarter of 2001, and the accounting change discussed above. Negatively affecting R&M results for the year were higher utility costs at the company's refineries, resulting from higher natural gas prices experienced in the first half of 2001, as well as a $27 million write-down of inventories to market value. The Sweeny refinery's 2001 net income benefited from the coker unit that was started up in late 2000. The coker unit allows for the processing of heavier, lower-cost crude oil, which reduced crude oil purchase costs and contributed to the improved gasoline and distillates margins experienced during 2001. ConocoPhillips' U.S. refineries (including those acquired in the Tosco acquisition since the acquisition date) processed an average of 686,000 barrels per day of crude oil in 2001, yielding a 94 percent capacity utilization rate. This compares with 303,000 barrels per day and a utilization rate of 90 percent in 2000. The Tosco acquisition accounted for 378,000 barrels per day in 2001. International R&M 2002 vs. 2001 Net income from international R&M operations increased $3 million in 2002, reflecting the impact of the merger, which added one wholly owned and five joint-venture international refineries. A substantial part of ConocoPhillips' international R&M results are related to its Humber refinery in the United Kingdom, which had a 232,000 barrel per day crude oil processing capacity at December 31, 2002. This refinery was shut down for an extended period of time during the fourth quarter due to a power outage and subsequent downtime, which negatively impacted international R&M's 2002 results. The crude oil capacity utilization rate for ConocoPhillips' international refineries was 78 percent in 2002, compared with 91 percent in 2001. The lower utilization rate in 2002 reflects the extended shutdown at the Humber refinery noted above. 2001 vs. 2000 Net income from the R&M segment's international operations decreased 93 percent in 2001, compared with 2000, reflecting the late-2000 disposition of the company's 50 percent interest in a refinery in Teesside, England. This was partially offset by the addition of the Whitegate refinery in Ireland as part of the Tosco acquisition in September 2001. 48 CHEMICALS
2002 2001 2000 ------------------------------------ Millions of Dollars ------------------------------------ NET LOSS $ (14) (128) (46) -----------------------------------------------------------------
Millions of Pounds ----------------------------------- OPERATING STATISTICS Production* Ethylene 3,217 3,291 3,574 Polyethylene 2,004 1,956 2,230 Styrene 887 456 404 Normal alpha olefins 592 563 293 ----------------------------------------------------------------
*Production volumes for periods after July 1, 2000, include ConocoPhillips' 50 percent share of Chevron Phillips Chemical Company LLC. 2002 vs. 2001 ConocoPhillips' Chemicals segment consists of its 50 percent equity investment in CPChem, which was formed when the company and ChevronTexaco combined their worldwide chemicals businesses in July 2000. The Chemicals segment incurred a net loss of $14 million in 2002, compared with a net loss of $128 million in 2001. The worldwide chemicals industry experienced an economic downturn beginning in the second half of 2000, and these difficult conditions remained present through 2001 and 2002. The downturn has been marked by decreased product demand and low product margins across key product lines. The smaller net loss in 2002 was primarily the result of higher margins due to lower operating expenses, feedstock costs and energy prices, partially offset by decreased sales prices. A fire caused the shutdown of styrene production at CPChem's St. James, Louisiana, facility in February 2001. Production was restored in October 2001. Production volumes for other major product lines were comparable between 2002 and 2001. The net loss in 2001 included several asset retirements and impairments totaling $84 million after-tax because of depressed economic conditions. A developmental reactor at the Houston Chemical Complex in Pasadena, Texas, was retired; property impairments were recorded on two polyethylene reactors at the Orange chemical plant in Orange, Texas; an ethylene unit was retired at the Sweeny complex in Old Ocean, Texas; an equity affiliate of CPChem recorded a property impairment related to a polypropylene facility; property impairments were taken on the manufacturing facility in Puerto Rico; and the benzene and cyclohexane units at the Puerto Rico facility were retired. In addition, the valuation allowance on the Puerto Rico facility's deferred tax asset related to its net operating losses was increased in 2001 so that the deferred tax assets were fully offset by valuation allowances. Partially offsetting these impairments was a business interruption insurance settlement recorded by CPChem and a favorable deferred tax adjustment, related to the tax basis of its investment, recorded by ConocoPhillips that resulted from an impairment related to the Puerto Rico facility, together totaling $57 million after-tax. 49 2001 vs. 2000 The Chemicals segment incurred a net loss of $128 million in 2001, compared with a net loss of $46 million in 2000. Global conditions for the chemicals and plastics industry were extremely difficult in 2001. Worldwide economic slowdowns, including a recessionary economy in the United States, led to decreased product demand and low product margins across many key product lines. CPChem's results were negatively affected by low ethylene, polyethylene and aromatics margins, as well as lower ethylene and polyethylene production. In addition to low margins and production volumes, 2001 contained interest charges incurred by CPChem that were not present in the first six months of 2000 prior to the formation of CPChem. The difficult marketing environment led to several asset retirements and impairments being recorded by CPChem in 2001. Partially offsetting these impairments was a business interruption insurance settlement recorded by CPChem and a favorable deferred tax adjustment recorded by ConocoPhillips that resulted from the Puerto Rico facility impairment, together totaling $57 million after-tax. The net loss in 2000 included ConocoPhillips' share of a property impairment that CPChem recorded in the fourth quarter related to its Puerto Rico facility. The impairment was required due to the deteriorating outlook for future paraxylene market conditions and a shift in strategic direction at the facility. In addition, a valuation allowance was recorded against a related deferred tax asset. Combined, these two items resulted in a non-cash $180 million after-tax charge to CPChem's earnings. ConocoPhillips' share was $90 million. EMERGING BUSINESSES
Millions of Dollars -------------------------------- 2002 2001 2000 -------------------------------- NET LOSS Carbon fibers $ (15) -- -- Fuels technology (16) (12) -- Gas-to-liquids (273) -- -- Power generation and other (6) -- -- ------------------------------------------------------------------ $ (310) (12) -- ==================================================================
2002 vs. 2001 The Emerging Businesses segment includes the development of new businesses beyond the company's traditional operations. Emerging Businesses include carbon fibers, natural gas-to-liquids technology, fuels technology and power generation. Prior to the merger, this segment only included Phillips' fuels technology business. The Emerging Businesses segment posted a net loss of $310 million in 2002, compared with a net loss of $12 million in 2001. Results for 2002 included a $246 million write-off of acquired in-process research and development costs related to Conoco's natural gas-to-liquids and other technologies. In accordance with FASB Interpretation No. 4, "Applicability of FASB Statement No. 2 to Business Combinations Accounted for by the Purchase Method," value assigned to research and development activities in the purchase price allocation that have no alternative future use should be charged to expense at the date of the consummation of the combination. The $246 million charge was the same on both a before-tax and after- 50 tax basis, as there was no tax basis to the assigned value prior to its write-off. The increased number of developing businesses after the merger also contributed to the larger losses in 2002. ConocoPhillips announced in February 2003 that it will shut down its carbon fibers project, as a result of market, operating and technology uncertainties. At the time of the merger, the company identified these uncertainties facing the carbon fibers project and initiated a strategic update for the new management of the company. In early 2003, the strategic update was completed and management made the decision to shut down the project. In the preliminary purchase price allocation, the company valued the carbon fibers technology at an amount equal to the plant construction costs. In the first quarter of 2003, the company will reduce the preliminary purchase price allocation associated with this project and accrue for shutdown, severance and other related costs that will result in a corresponding net increase in goodwill of $125 million. 2001 vs. 2000 In 2001, the Emerging Businesses segment included the company's development of new fuels technologies. Prior to 2001, these activities were not separately identifiable, and were included in the R&M segment. CORPORATE AND OTHER
Millions of Dollars ---------------------------------------- 2002 2001 2000 ---------------------------------------- NET LOSS Net interest $ (396) (262) (278) Corporate general and administrative expenses (173) (114) (87) Discontinued operations (993) 32 14 Merger-related costs (307) -- -- Other (49) (71) (86) --------------------------------------------------------------------------------------------- $(1,918) (415) (437) =============================================================================================
2002 vs. 2001 Net interest represents interest expense, net of interest income and capitalized interest. Net interest increased 51 percent in 2002, mainly due to higher debt levels following the Tosco acquisition and the merger of Conoco and Phillips. Corporate general and administrative expenses increased 52 percent in 2002, primarily due to the impact of the merger. In addition, 2002 also included higher benefit-related costs, primarily from the accelerated vesting of awards under certain long-term compensation plans that occurred at the time of stockholder approval of the merger. Losses from discontinued operations were $993 million in 2002, compared with income of $32 million in 2001. The 2002 amount included after-tax impairments and loss accruals of $1,077 million associated with the assets held for sale. See Note 4--Discontinued Operations in the Notes to Consolidated Financial Statements for additional information on the impairments and loss accruals, as well as a description of the assets included in discontinued operations. 51 Merger-related costs in 2002 included restructuring accruals of $252 million, primarily related to work force reduction charges; change-in-control costs associated with seismic contracts totaling $22 million; and other transition costs of $33 million. Other merger-related costs of $250 million were recorded by the operating segments, bringing total merger-related costs to $557 million after-tax. The category "Other" consists primarily of items not directly associated with the operating segments on a stand-alone basis, including captive insurance operations, certain foreign currency gains and losses, the tax impact of consolidations, and dividends on the preferred securities of the Phillips 66 Capital Trusts I and II. Results from Other were improved in 2002 primarily due to more favorable foreign currency transactions, and a favorable revaluation and settlement of certain long-term incentive units that were converted into Phillips performance units held by former senior Tosco executives, none of whom are employees of ConocoPhillips. Included in 2002 and 2001 were extraordinary losses on the early retirement of debt totaling $16 million and $10 million, respectively. 2001 vs. 2000 Corporate and Other net loss decreased 5 percent in 2001, compared with 2000, primarily due to lower net interest expense and improved results from discontinued operations partially offset by higher staff costs, contributions, corporate advertising and corporate transportation costs. 52 CAPITAL RESOURCES AND LIQUIDITY FINANCIAL INDICATORS
Millions of Dollars Except as Indicated -------------------------------------- 2002 2001 2000 -------------------------------------- Current ratio .9 1.3 .8 Total debt repayment obligations due within one year $ 849 44 262 Total debt $19,766 8,654 6,884 Mandatorily redeemable preferred securities of trust subsidiaries $ 350 650 650 Other minority interests $ 651 5 1 Common stockholders' equity $29,517 14,340 6,093 Percent of total debt to capital* 39% 37 51 Percent of floating-rate debt to total debt 12% 20 17 -------------------------------------------------------------------------------------------------------------
*Capital includes total debt, mandatorily redeemable preferred securities, other minority interests and common stockholders' equity. Expected new accounting rules in 2003 likely will cause mandatorily redeemable preferred securities to be presented as a liability. The increase in ConocoPhillips' debt-to-capital ratio from December 31, 2001, to December 31, 2002, resulted primarily from the merger. In addition to $12 billion of Conoco debt assumed, purchase accounting required the debt to be recorded at fair value at the time of the merger, increasing total debt by an additional $565 million. SIGNIFICANT SOURCES OF CAPITAL During 2002, cash of $4,969 million was provided by operating activities, an increase of $1,407 million from 2001. Cash provided by operating activities before changes in working capital increased $54 million compared with 2001, primarily due to higher dividends from equity affiliates, higher crude oil prices and higher crude oil and natural gas volumes, offset by lower natural gas prices, lower refining margins, higher interest expenses and merger-related costs. Positive working capital changes of $1,184 million were primarily due to an increase in accounts payable, an increase in taxes and other accruals and a decrease in inventories, partially offset by increased receivables. Discontinued operations provided $202 million of operating cash flows in 2002, an increase of $169 million compared to 2001. The increase in 2002 was primarily due to 2002 including a full year of cash flow from a portion of assets acquired in the Tosco acquisition that are now included in discontinued operations. During 2002, cash and cash equivalents increased $165 million. In addition to the cash provided by operating activities, $815 million was received from the sale of various ConocoPhillips assets; including the sale of exploration and production assets in the Netherlands, assets in Canada and propane terminal assets at Jefferson City, Missouri, and East St. Louis, Illinois. Funds were used to support the company's ongoing capital expenditures program, repay debt and pay dividends. In October 2002, ConocoPhillips' Board of Directors declared a dividend of $.40 per share, payable December 2, 2002, which represented an 11 percent increase in the quarterly dividend. To meet its liquidity requirements, including funding its capital program, paying dividends and repaying debt, the company looks to a variety of funding sources, primarily cash generated from operating activities. By the end of 2004, however, the company anticipates raising funds of $3 billion to $4 billion, of which approximately $600 million had been raised as of December 31, 2002, from the sale of assets, including those assets required by the FTC to be sold. In December 2002, ConocoPhillips entered into an agreement to sell its Woods Cross refinery and associated marketing assets, subject to state and federal regulatory approvals. Also in December 2002, the company committed to and initiated a plan to sell a substantial portion of its U.S. company-owned retail sites. 53 While the stability of the company's cash flows from operating activities benefits from geographic diversity and the effects of upstream and downstream integration, the company's operating cash flows remain exposed to the volatility of commodity crude oil and natural gas prices and downstream margins, as well as periodic cash needs to finance tax payments and crude oil, natural gas and petroleum product purchases. The company's primary funding source for short-term working capital needs is a $4 billion commercial paper program, a portion of which may be denominated in euros (limited to euro 3 billion), supported by $4 billion in revolving credit facilities. Commercial paper maturities are generally kept within 90 days. At December 31, 2002, ConocoPhillips had $1,517 million of commercial paper outstanding, of which $206 million was denominated in foreign currencies. Effective October 15, 2002, ConocoPhillips entered into two new revolving credit facilities to replace the previously existing $2.5 billion Conoco credit facilities, and also amended and restated a prior Phillips revolving credit facility to include ConocoPhillips as a borrower. The company now has a $2 billion 364-day revolving credit facility expiring on October 14, 2003, and two revolving credit facilities totaling $2 billion expiring in October 2006. There were no outstanding borrowings under any of these facilities at December 31, 2002. These credit facilities support the company's $4 billion commercial paper program. ConocoPhillips' Norwegian subsidiary has two $300 million revolving credit facilities that expire in June 2004, under which no borrowings were outstanding as of December 31, 2002. In addition to the bank credit facilities, ConocoPhillips sells certain credit card and trade receivables to two Qualifying Special Purpose Entities (QSPEs) in revolving-period securitization arrangements. These arrangements provide for ConocoPhillips to sell, and the QSPEs to purchase, certain receivables and for the QSPEs to then issue beneficial interests of up to $1.5 billion to five bank-sponsored entities. At December 31, 2002 and 2001, the company had sold accounts receivable of $1.3 billion and $940 million, respectively. The receivables sold have been sufficiently isolated from ConocoPhillips to qualify for sales treatment. All five bank-sponsored entities are multi-seller conduits with access to the commercial paper market and purchase interests in similar receivables from numerous other companies unrelated to ConocoPhillips. ConocoPhillips has no ownership in any of the bank-sponsored entities and has no voting influence over any bank-sponsored entity's operating and financial decisions. As a result, ConocoPhillips does not consolidate any of these entities. Beneficial interests retained by ConocoPhillips in the pool of receivables held by the QSPEs are subordinate to the beneficial interests issued to the bank-sponsored entities and were measured and recorded at fair value based on the present value of future expected cash flows estimated using management's best estimates concerning the receivables performance, including credit losses and dilution discounted at a rate commensurate with the risks involved to arrive at present value. These assumptions are updated periodically based on actual credit loss experience and market interest rates. ConocoPhillips also retains servicing responsibility related to the sold receivables. The fair value of the servicing responsibility approximates adequate compensation for the servicing costs incurred. ConocoPhillips' retained interest in the sold receivables at December 31, 2002 and 2001, was $1.3 billion and $450 million, respectively. Under accounting principles generally accepted in the United States, the QSPEs are not consolidated by ConocoPhillips. ConocoPhillips retained interest in sold receivables is reported on the balance sheet in accounts and notes receivable. See Note 13--Sales of Receivables in the Notes to Consolidated Financial Statements for additional information. On October 9, 2002, ConocoPhillips issued $2 billion of senior unsecured debt securities, consisting of $400 million 3.625% notes due 2007, $1 billion 4.75% notes due 2012, and $600 million 5.90% notes due 2032. The $1,980 million net proceeds of the offering were used to reduce commercial paper, to retire Conoco's $500 million floating rate notes due October 15, 2002, and for general corporate purposes. 54 Moody's Investor Service has assigned a rating of A3 on ConocoPhillips' senior long-term debt; and Standard and Poors and Fitch have assigned a rating of A-. ConocoPhillips 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 ConocoPhillips' debt rating and thereby impacting ConocoPhillips' access to liquidity. In the event that ConocoPhillips' credit were to deteriorate to a level that would prohibit ConocoPhillips from accessing the commercial paper market, ConocoPhillips would still be able to access funds under its $4.6 billion revolving credit facilities. Based on ConocoPhillips' year-end commercial paper balance of $1.5 billion, ConocoPhillips had access to $3.1 billion in borrowing capacity as of December 31, 2002, after repaying all outstanding commercial paper, which provides ample liquidity to cover any needs that its businesses may require to cover daily operations. OTHER FINANCING AND OFF-BALANCE SHEET ARRANGEMENTS During 1996 and 1997, ConocoPhillips formed two statutory business trusts, Phillips 66 Capital I and Phillips 66 Capital II. The company owns all of the common securities of the trusts and the trusts are consolidated by the company. The trusts exist for the sole purpose of issuing preferred securities to outside investors, and investing the proceeds thereof in an equivalent amount of subordinated debt securities of ConocoPhillips. The two trusts were established to raise funds for general corporate purposes. The subordinated debt securities of ConocoPhillips held by the trusts are eliminated in consolidation. The $300 million of 8.24% Trust Originated Preferred Securities issued by Phillips 66 Capital Trust I became callable, at par, $25 per share, during May 2001. On May 31, 2002, ConocoPhillips redeemed all of its outstanding subordinated debt securities held by the Trust, which triggered the redemption of the $300 million of trust preferred securities at par value, $25 per share. The redemption was funded by the issuance of commercial paper. The remaining $350 million of mandatorily redeemable preferred trust securities issued by Phillips 66 Capital Trust II are mandatorily redeemable in 2037, when the subordinated debt securities of ConocoPhillips held by the trust are required to be repaid. The mandatorily redeemable preferred securities are presented in the mezzanine section of the balance sheet. See Note 17--Preferred Stock and Other Minority Interests in the Notes to Consolidated Financial Statements. ConocoPhillips also had outstanding, at December 31, 2002, $645 million of equity held by minority interest owners, which provide a preferred return to those minority interest holders. 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, which represented 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 was $141 million at December 31, 2002, and is mandatorily redeemable in 2019 or callable without penalty beginning in the fourth quarter of 2004. In 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 Finance S.a.r.l. held a $504 million net minority interest in Ashford Energy at December 31, 2002, and is entitled to a cumulative annual preferred return on its investment, based on three-month LIBOR rates plus 1.27 percent. The preferred return at December 31, 2002, was 2.70 percent. These minority interests are presented in the mezzanine section of the balance sheet. See Note 17--Preferred Stock and Other Minority Interests in the Notes to Consolidated Financial Statements. In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities," and later in 2003, the FASB is expected to issue Statement of Financial Accounting Standards (SFAS) No. 149, "Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity." The company is evaluating these new pronouncements to determine whether the amounts currently presented in the mezzanine section of the balance sheet will be required to be presented as debt or as equity 55 on the balance sheet. See Note 27--New Accounting Standards and Note 28--Variable Interest Entities in the Notes to Consolidated Financial Statements for more information. The company leases ocean transport vessels, drillships, tank railcars, corporate aircraft, service stations, computers, office buildings, certain refining equipment, and other facilities and equipment. Prior to the acquisition of Tosco and the merger, the company had in place leasing arrangements for tankers, corporate aircraft and the construction of various retail marketing outlets. At December 31, 2002, approximately $730 million had been utilized under those arrangements, which is the total capacity available. At the time the company acquired Tosco, Tosco had in place previously arranged leasing arrangements for various retail stations and two office buildings in Tempe, Arizona. At December 31, 2002, approximately $1.3 billion had been utilized under those arrangements, which is the total capacity available. In addition, at the time of the merger, Conoco had in place leasing arrangements for certain refining equipment, two drillships, and various retail marketing outlets. At December 31, 2002, approximately $370 million had been utilized under those arrangements. Several of the above leasing arrangements are with special purpose entities (SPEs) that are third-party trusts established by a trustee and funded by financial institutions. Other than those leasing arrangements, ConocoPhillips has no other direct or indirect relationship with the trusts or their investors. Each SPE from which ConocoPhillips leases assets is funded by at least 3 percent substantive, unaffiliated third-party, residual equity capital investment, which is at risk during the entire term of the lease. Changes in market interest rates do have an impact on the periodic amount of lease payments. ConocoPhillips has various purchase options to acquire the leased assets from the SPEs at the end of the lease term, but those purchase options are not required to be exercised by ConocoPhillips under any circumstances. If ConocoPhillips does not exercise its purchase option on a leased asset, the company does have guaranteed residual values, which are due at the end of the lease terms, but those guaranteed amounts would be reduced by the fair market value of the leased assets returned. These various leasing arrangements meet all requirements under generally accepted accounting principles to be treated as operating leases. However, in January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities," which will require consolidation in July 2003 of certain SPEs that were created prior to January 31, 2003, and which are still in existence at June 15, 2003. The company is evaluating the new Interpretation to determine whether the assets and debt of the leasing arrangements would be consolidated. See Note 28--Variable Interest Entities in the Notes to Consolidated Financial Statements for more information. If the company is required to consolidate all of these entities, the assets of the entities and debt of approximately $2.4 billion would be required to be included in the consolidated financial statements. The company's maximum exposure to loss as a result of its involvement with the entities would be the debt of the entity less the fair value of the assets at the end of the lease terms. Of the $2.4 billion debt that would be consolidated, approximately $1.5 billion is associated with a major portion of the company's owned retail stores that the company has announced it plans to sell. As a result of the planned divestiture, the company plans to exercise purchase option provisions during 2003 and terminate various operating leases involving approximately 900 store sites and two office buildings. In addition, see Note 4--Discontinued Operations in the Notes to Consolidated Financial Statements for details regarding the provisions for losses and penalties recorded in the fourth quarter, 2002 for the planned divestiture. Depending upon the timing of the company's exercise of these purchase options, and the determination of whether or not the lessor entities in these operating leases are variable interest entities requiring consolidation in 2003, some or all of these lessor entities could become consolidated subsidiaries of the company prior to the exercise of the purchase options and termination of the leases. See Note 14--Guarantees and Note 19--Non-Mineral Leases in the Notes to Consolidated Financial Statements. 56 During 2000, ConocoPhillips contributed its midstream gas gathering, processing and marketing business and its worldwide chemicals business to joint ventures with Duke Energy Corporation and ChevronTexaco Corporation, as successor to Chevron Corporation (ChevronTexaco), respectively, forming DEFS and CPChem, respectively. ConocoPhillips owns 30.3 percent of DEFS and 50 percent of CPChem, accounting for its interests in both companies using the equity method of accounting. The capital and financing programs of both of these joint-venture companies are intended to be self-funding. DEFS supplies a substantial portion of its natural gas liquids to ConocoPhillips and CPChem under a supply agreement that continues until December 31, 2014. This purchase commitment is on an "if-produced, will-purchase" basis so it has no fixed production schedule, but has been, and is expected to be, a relatively stable purchase pattern over the term of the contract. Natural gas liquids are purchased under this agreement at various published market index prices, less transportation and fractionation fees. DEFS also purchases raw natural gas from ConocoPhillips' E&P operations. ConocoPhillips and CPChem have multiple supply and purchase agreements in place, ranging in initial terms from four to 15 years, with extension options. These agreements cover sales and purchases of refined products, solvents, and petrochemical and natural gas liquids feedstocks, as well as fuel oils and gases. Delivery quantities vary by product, ranging from zero to 100 percent of production capacity at a particular refinery, most at the buyer's option. All products are purchased and sold under specified pricing formulas based on various published pricing indexes, consistent with terms extended to third-party customers. In the second quarter of 2001, ConocoPhillips and its co-venturers in the Hamaca project secured approximately $1.1 billion in a joint debt financing for their heavy-crude oil project in Venezuela. The Export-Import Bank of the United States provided a guarantee supporting a 17-year-term $628 million bank facility. The joint venture also arranged a $470 million 14-year-term commercial bank facility for the project. Total debt of $947 million was outstanding under these credit facilities at December 31, 2002. ConocoPhillips, through the joint venture, holds a 40 percent interest in the Hamaca project, which is operated on behalf of the co-venturers by Petrolera Ameriven. The proceeds of these joint financings are being used to partially fund the development of the heavy-oil field and the construction of pipelines and a heavy-oil upgrader. The remaining necessary funding will be provided by capital contributions from the co-venturers on a pro rata basis to the extent necessary to successfully complete construction. Once completion certification is achieved, the joint project financings will become non-recourse with respect to the co-venturers and the lenders under those facilities can then look only to the Hamaca project's cash flows for payment. MSLP is a limited partnership in which ConocoPhillips and PDVSA each own an indirect 50 percent interest. During 1999, MSLP issued $350 million of 8.85 percent bonds due 2019 that ConocoPhillips and PDVSA are joint-and-severally liable for under a construction completion guarantee. The bond proceeds were used to fund construction of a coker, vacuum unit and related facilities at the ConocoPhillips Sweeny refinery plus certain improvements to existing facilities at the same location. MSLP owns and operates the coker and vacuum unit and, in the third quarter of 2000, began processing long residue produced from the Venezuelan Merey crude oil delivered under a supply agreement that ConocoPhillips has with PDVSA. MSLP charges ConocoPhillips a fee to process the long residue through the vacuum unit and coker. This is the partnership's primary source of revenue. If completion certification is not attained by 2004, the full debt is due. Upon completion certification, the 8.85 percent bonds become non-recourse to the two MSLP partners and the bondholders can then look only to MSLP cash flows for payment. 57 ConocoPhillips purchased the improvements to existing facilities from MSLP for a price equal to the cost of construction and MSLP provided seller financing. Terms of financing provide for 240 monthly payments of principal and interest commencing September 2000 with interest accruing at a 7 percent annual rate. The principal balance due on the seller financing was $131 million at December 31, 2002, and is included as long-term debt in ConocoPhillips' balance sheet. MSLP pays a monthly access fee to ConocoPhillips for the use of the improvements to the refinery. The access fee equals the monthly principal and interest paid by ConocoPhillips to purchase the improvements from MSLP. To the extent the access fee is not paid by MSLP, ConocoPhillips is not obligated to make payments for the improvements. During the first quarter of 2002, MSLP issued $25 million of tax-exempt bonds due 2021. This issuance, combined with similar bonds MSLP issued in 1998, 2000, and 2001, bring the total outstanding to $100 million. As a result of the company's support as a primary obligor of a 50 percent share of these MSLP financings, $50 million and $38 million of long-term debt is included in ConocoPhillips' balance sheet at December 31, 2002, and December 31, 2001, respectively. ConocoPhillips has transactions with many unconsolidated affiliates. Equity affiliate sales and services to ConocoPhillips amounted to $1,545 million in 2002, $1,110 million in 2001 and $1,347 million in 2000. Equity affiliate purchases from ConocoPhillips totaled $1,554 million in 2002, $935 million in 2001 and $1,573 million in 2000. These agreements were not the result of arms-length negotiations. However, ConocoPhillips believes that these contracts are generally at values that are similar to those that could be negotiated with independent third parties. CAPITAL REQUIREMENTS For information about ConocoPhillips' capital expenditures and investments, see "Capital Spending" below. During 2002 and January 2003, ConocoPhillips redeemed the following notes and funded the redemptions with commercial paper: o its $250 million 8.86% notes due May 15, 2022, at 104.43 percent; o its $171 million 7.443% senior unsecured notes due 2004; o its $250 million 8.49% notes due January 1, 2023, at 104.245 percent; and o its $181 million SRW Cogeneration Limited Partnership note. In addition, in April 2003, ConocoPhillips plans to redeem its $250 million 7.92% notes due in 2023 at 103.96 percent. 58 The following table summarizes the maturities of the drawn balances of the company's various debt instruments, as well as other non-cancelable, fixed or minimum, contractual commitments, as of December 31, 2002:
Millions of Dollars ------------------------------------------------------------- Payments Due by Period ------------------------------------------------------------- Up to 1 2-3 4-5 After Debt and other non-cancelable cash commitments Total Year Years Years 5 Years ------------------------------------------------------------------------------------------------------------------------------ Total debt* $ 19,766 849 2,667 3,827 12,423 Mandatorily redeemable other minority interests and preferred securities 491 -- -- -- 491 Operating leases Minimum rental payments** 4,101 649 1,025 792 1,635 Sublease offsets (641) (129) (165) (83) (264) Unconditional throughput and processing fee and purchase commitments*** 3,785 438 760 598 1,989 ------------------------------------------------------------------------------------------------------------------------------
*Includes net unamortized premiums and discounts. **Excludes $383 million in lease commitments that begin upon delivery of five crude oil tankers currently under construction. Delivery is expected in the third and fourth quarters of 2003. ***Represents non-market purchase commitments and obligations to transfer funds in the future for fixed or minimum amounts at fixed or minimum prices under various throughput or tolling agreements. In addition to the above contractual commitments, the company has various guarantees that have the potential for requiring cash outflows resulting from a contingent event that could require company performance pursuant to a funding commitment to a third or related party. See Note 14--Guarantees in the Notes to Consolidated Financial Statements for additional details. The following table summarizes the potential amounts and remaining time frames of these direct and indirect guarantees, as of December 31, 2002.
Millions of Dollars ------------------------------------------------------------ Amount of Expected Guarantee Expiration Per Period ------------------------------------------------------------ Up to 1 2-3 4-5 After Direct and indirect guarantees Total Year Years Years 5 Years ------------------------------------------------------------------------------------------------------------------------------ Construction completion guarantees* $ 859 418 441 -- -- Guaranteed residual values on leases** 1,821 196 1,046 145 434 Guarantees of joint-venture debt*** 355 54 74 8 219 Other guarantees and indemnifications**** 662 121 141 37 363 ------------------------------------------------------------------------------------------------------------------------------
*Amounts represent ConocoPhillips' maximum future potential payments under construction completion guarantees for debt and bond financing arrangements secured by the Hamaca and Merey Sweeny joint-venture projects in Venezuela and Texas, respectively. The debt is non-recourse to ConocoPhillips upon completion certification of the projects. Figures in the table represent maximum amount due under the guarantee in the event completion certification is not achieved. The Merey Sweeny debt is joint-and-several and included at its gross amount. **Represents maximum additional amounts that would be due at the end of the term of certain operating leases if the fair value of the leased property was less than the guaranteed amount. See Note 19--Non-Mineral Leases in the Notes to Consolidated Financial Statements. ***Represents amount of obligations directly guaranteed by the company in the event a guaranteed joint venture does not perform. ****Represents Merey Sweeny, L.P. agreement requirement to pay cash calls as required to meet minimum operating requirements of the venture, in the event revenues do not cover expenses over the next 18 years. Also includes certain potential payments related to two drillships, two LNG vessels, dealer and jobber loan guarantees to support the company's marketing business, a guarantee supporting a lease assignment on a corporate aircraft and guarantees of lease payment obligations for a joint venture. The maximum amount of future payments under tax and general indemnifications from normal ongoing operations is indeterminable. 59 CAPITAL SPENDING CAPITAL EXPENDITURES AND INVESTMENTS
Millions of Dollars -------------------------------------- 2003 Budget 2002 2001 2000** -------------------------------------- E&P United States-Alaska $ 704 706 965 538 United States-Lower 48 780 499 389 413 International 3,433 2,071 1,162 726 -------------------------------------------------------------------- 4,917 3,276 2,516 1,677 -------------------------------------------------------------------- Midstream 23 5 -- 17 -------------------------------------------------------------------- R&M United States 881 676 423 217 International 250 164 5 -- -------------------------------------------------------------------- 1,131 840 428 217 -------------------------------------------------------------------- Chemicals -- 60 6 67 Emerging Businesses 248 122 -- -- Corporate and Other* 173 85 66 39 -------------------------------------------------------------------- $6,492 4,388 3,016 2,017 ==================================================================== United States $2,630 2,043 1,849 1,264 International 3,862 2,345 1,167 753 -------------------------------------------------------------------- $6,492 4,388 3,016 2,017 ==================================================================== Discontinued operations $ 60 97 69 5 --------------------------------------------------------------------
*Excludes discontinued operations. **Excludes the Alaskan acquisition. ConocoPhillips' capital spending for continuing operations for the three-year period ending December 31, 2002, totaled $9.4 billion, excluding the purchase of ARCO's Alaskan businesses in 2000. The company's spending was primarily focused on the growth of its E&P business, with more than 79 percent of total spending for continuing operations in this segment. On March 31, 2000, ConocoPhillips contributed the gas gathering, processing and marketing portion of its then Midstream business to DEFS. On July 1, 2000, ConocoPhillips contributed its Chemicals business to CPChem. The capital programs of these joint-venture companies are intended to be self-funding. Including approximately $400 million in capitalized interest and $200 million that will be funded by minority interests in the Bayu-Undan gas export project, ConocoPhillips' Board of Directors (Board) has approved $6.5 billion for capital projects and investments for continuing operations in 2003, a 48 percent increase over 2002 capital spending of $4.4 billion. The company plans to direct approximately 75 percent of its 2003 capital budget to E&P and about 17 percent to R&M. The remaining budget will be allocated toward emerging businesses, mainly power generation, and general corporate purposes, with a significant majority related to global integration of systems. Forty-one percent of the budget is targeted for projects in the United States. In addition to the above budget, ConocoPhillips expects to spend about $300 million to exercise purchase options for retail stores and office buildings, which are currently within various lease arrangements. 60 E&P Capital spending for continuing operations for E&P during the three-year period ending December 31, 2002, totaled $7.5 billion. The expenditures over the three-year period supported several key exploration and development projects including: o National Petroleum Reserve--Alaska (NPR-A) and satellite field prospects on Alaska's North Slope; o the Hamaca heavy-oil project in Venezuela's Orinoco Oil Belt; o the Peng Lai 19-3 discovery in China's Bohai Bay and additional Bohai Bay appraisal and satellite field prospects; o the Kashagan field in the north Caspian Sea, offshore Kazakhstan; o the Jade, Clair and CMS3 developments in the United Kingdom; o the Bayu-Undan gas recycle project in the Timor Sea; o acquisition of deepwater exploratory interests in Angola, Nigeria, Brazil, and the U.S. Gulf of Mexico; o fields in Vietnam; o Canadian conventional oil and gas projects, as well as expansion of the Syncrude project; and o fields in Indonesia. Capital expenditures for construction of the Endeavour Class tankers and an additional interest in the Trans-Alaska Pipeline System were also included in the E&P segment. ConocoPhillips has contracted to build, for approximately $200 million each, five double-hulled Endeavour Class tankers for use in transporting Alaskan crude oil to the U.S. West Coast. During 2001, the Polar Endeavour, the first Endeavour Class tanker, entered service. The second tanker, the Polar Resolution, entered service in May 2002. The third tanker, the Polar Discovery, was christened on April 13, 2002, and is expected to enter service in 2003. ConocoPhillips expects to add a new Endeavour Class tanker to its fleet each year through 2005, allowing the company to retire older ships and cancel non-operated charters. In 2002, the company and its co-venturers drilled or participated in 69 development wells at the Alaska Prudhoe Bay field. Also, new equipment was added to increase the efficiency of the field's existing water flood. At the Kuparuk field, 14 new development wells were added, and the Drill Site 3S (Palm) was installed earlier in the year. Production at Palm began in the fourth quarter. At Alpine, nine new development wells were added. Other capital spending at Alpine included facility improvements. During the fourth quarter of 2001, heavy-crude-oil production began from the Hamaca project in Venezuela's Orinoco Oil Belt. Construction of an upgrader to convert heavy crude into a 26-degree API synthetic crude continues. Completion of the upgrader is expected in 2004. ConocoPhillips owns a 61 40 percent equity interest in the Hamaca project. ConocoPhillips' other heavy-oil project, Petrozuata, incurred no significant capital expenditures in 2002. In addition to the Hamaca development and Petrozuata, ConocoPhillips submitted a Declaration of Commerciality to the Venezuelan government on the Corocoro oil discovery in the fourth quarter of 2002. Development approval is expected in the first half of 2003, with expenditures to follow later in the year. In 2002, development activities continued on the company's Peng Lai 19-3 discovery in Block 11/05 in China's Bohai Bay with production beginning late in the fourth quarter of 2002. Technical design activities for the second phase of development continued during 2002. In 2002, ConocoPhillips and its co-venturers, in conjunction with the government of the Republic of Kazakhstan, declared the Kashagan field on the Kazakhstan shelf in the north Caspian Sea to be commercial. This declaration of commerciality enabled preparation of a development plan for the field. Drilling of the first of five planned appraisal wells was successfully completed in early 2002. Evaluation of test results continues on the second and third wells, drilling operations continue on the fourth, and testing continues on the fifth of these appraisal wells. In May 2002, ConocoPhillips, along with the other remaining co-venturers, completed the acquisition of proportionate interests of other co-venturers rights, which increased ConocoPhillips' ownership interest from 7.14 percent to 8.33 percent. In October 2002, ConocoPhillips and its co-venturers announced a new hydrocarbon discovery in the Kazakhstan sector of the Caspian Sea. An initial test well, the Kalamkas-1, flowed oil. This well is located adjacent to the Kashagan field. In 2002, development of ConocoPhillips' Jade field, in the U.K. sector of the North Sea, continued with first production occurring in February 2002. A second production well was successfully drilled and began producing during the second quarter of 2002. In the second half of the year, two more production wells were completed and began producing. ConocoPhillips is the operator and holds a 32.5 percent interest in Jade. An exploration well was spudded late in 2002 and drilling operations are continuing into 2003. In September 2002, ConocoPhillips began production from the Hawksley field in the southern sector of the U.K. North Sea. The Hawksley discovery well, 44/17a-6y, was completed in July 2002 in one of five natural gas reservoirs currently being developed by ConocoPhillips as a single, unitized project. The other reservoirs are McAdam, Murdoch K, Boulton, and Watt. Collectively, they are known as CMS3 due to their utilization of the production and transportation facilities of the ConocoPhillips-operated Caister Murdoch system (CMS). ConocoPhillips is the operator of CMS3 and holds a 59.5 percent interest. ConocoPhillips' $1.9 billion gross Bayu-Undan gas-recycle project activities continued in the Timor Sea during 2002. This involved the drilling of future production wells from the wellhead platform and the installation of the platform jackets and all in-field flowlines. Fabrication and assembly of two large platform decks continues in Korea, as does work on the multi-product floating, storage and offtake vessel (FSO). At year-end, the project was approximately 69 percent complete. During mid-2003, the decks and FSO will be installed with first gas and commissioning commencing in the third quarter of 2003. Liquid sales will commence in early 2004 with production ramp-up occurring during the first six months of 2004. Activity associated with the Bayu-Undan gas export project, including a pipeline to Darwin and a liquefied natural gas plant, currently is focused on preparation of approval documentation and project design. Construction is expected to start in early 2003, following the Timor Sea Treaty ratification by Australia. ConocoPhillips' direct interest in the unitized Bayu-Undan field was 55.9 percent at year-end 2002. A further 8.25 percent interest was held through Petroz N.L., in which the company had an 89.7 percent stock ownership at year-end. ConocoPhillips has effective voting control over the pipeline and liquefied natural gas plant component of the gas export project and thus plans to consolidate that part of the Bayu-Undan project and present the other venturers as minority interests. 62 In 2002, ConocoPhillips continued pursuing the goal of increasing its presence in high-potential deepwater areas. ConocoPhillips was the high bidder in the central Gulf of Mexico sale for the Lorien prospect located in Green Canyon Block 199 and was officially awarded the block in 2002. In Brazil, ConocoPhillips acquired joint-venture partners for its two deepwater blocks and purchased additional seismic data. Plans for 2003 include the purchase of additional seismic data and the further evaluation of the two blocks' prospects. In May 2002, initial results showed that the first exploratory well drilled in Block 34, offshore Angola, was a dry hole. In view of this information, ConocoPhillips reassessed the fair value of the remainder of the block and determined that its investment in the block was impaired by $77 million, both before- and after-tax. Further technical analysis of the results of this first well continues. The second of three commitment wells in this block is scheduled for drilling in 2003. ConocoPhillips entered into a production sharing contract on Oil Prospecting Lease (OPL) 318, deepwater Nigeria, on June 14, 2002, where ConocoPhillips is operator with 50 percent interest. The acquisition of 3-D seismic data on OPL 318 is planned to begin in 2003, with the first exploratory well expected to be drilled in the fourth quarter of 2004. In the third quarter of 2002, production began from two new wellhead platforms in the Block 15-2 Rang Dong field in Vietnam. These additional platforms increased production from the field from under 6,800 to over 12,400 net barrels per day at year-end 2002. In Canada, total capital expended in 2002 was $136 million. Capital spending for conventional oil and gas properties was $75 million and Syncrude expansion continued with $54 million expended. In addition, the Mackenzie Delta/Parson's Lake project efforts focused on gaining pipeline regulatory approval and acquiring seismic data. ConocoPhillips continued with the development of key gas fields in the Natuna Sea in Indonesia. Total spending on Block B gas development in the last four months of 2002 was $101 million, including investment in the Belanak floating, production, storage and offtake vessel and wellhead platform, plus wells and pipeline infrastructure required for the newly commenced gas sales to Petronas Malaysia. ConocoPhillips acquired a 14 percent interest in PT Transportasi Gas Indonesia (TGI) in 2002. The primary assets of TGI are the Grissik-Duri pipeline, which has been in operation since 1998, and the Grissik-Singapore pipeline that is currently under construction with a completion date expected in late 2003. Total funding in 2002 was $54 million, which includes acquisition cost and capital expenditures. Other capital spending for E&P during the three year-period ended December 31, 2002, supported: o the Eldfisk waterflood development in Norway; o the acquisition and development of coalbed-methane and conventional gas prospects and producing properties in the U.S. Lower 48; and o North Sea prospects in the U.K. and Norwegian sectors, plus other Atlantic Margin wells in the United Kingdom, Greenland and the Faroe Islands. 63 2003 Capital Budget E&P's 2003 capital budget for continuing operations is $4.9 billion, 50 percent higher than actual expenditures in 2002. Thirty percent of E&P's 2003 capital budget is planned for the United States. Of that, 47 percent is slated for Alaska. ConocoPhillips has budgeted $461 million for worldwide exploration capital activities in 2003, with 28 percent of that amount, $131 million allocated for the United States. More than $41 million of the U.S. total will be directed toward the exploration program in Alaska, where wells are planned in the NPR-A and other locations on the North Slope. Outside the United States, significant exploration expenditures are planned in Kazakhstan, Venezuela, the United Kingdom and Norway. The company plans to spend about $700 million in 2003 for its Alaskan operations. Large capital projects include the ongoing construction of three Endeavour Class tankers; development of the Meltwater, Palm and West Sak fields in the Greater Kuparuk area; development of the Borealis field in the Greater Prudhoe Bay area; as well as the exploratory activity discussed above. In the Lower 48, capital expenditures will be focused on exploration and continued development of the company's acreage positions in the deepwater Gulf of Mexico, South Texas, the San Juan Basin, the Permian Basin, and the Texas Panhandle. Major deepwater developments include Magnolia, K2, and the Princess fields, while exploration continues using the drillship Pathfinder. E&P is directing $3.4 billion of its 2003 capital budget to international projects. The majority of these funds will be directed to developing major long-term projects, including the Bayu-Undan liquids development and gas-recycling project in the Timor Sea, the Hamaca heavy-oil project and Corocoro development in Venezuela, additional development of oil and gas reserves in offshore Block B and onshore South Sumatra blocks in Indonesia, Blocks 15-1 and 15-2 in Vietnam, and Bohai Bay in China. In addition, funds will be used to expand the company's positions in the U.K. and Norwegian sectors of the North Sea, Syncrude operations in western Canada and to develop the Surmont heavy-oil project in Canada, and the Kashagan field in the Caspian Sea. Costs incurred for the years ended December 31, 2002, 2001, and 2000, relating to the development of proved undeveloped oil and gas reserves were $1,631 million, $1,423 million, and $857 million, respectively. As of December 31, 2002, estimated future development costs relating to the development of proved undeveloped oil and gas reserves for the years 2003 through 2005 were projected to be $1,815 million, $939 million, and $539 million, respectively. R&M Capital spending for continuing operations for R&M during the three-year period ending December 31, 2002, was primarily for refinery-upgrade projects to improve product yields, to meet new environmental standards, to improve the operating integrity of key processing units, and to install advanced process control technology, as well as for safety projects. Key significant projects during the three-year period included: o construction of a polypropylene plant at the Bayway refinery in New Jersey; o construction on a fluid catalytic cracking (FCC) unit at the Ferndale, Washington, refinery; 64 o expansion of the alkylation unit at the Los Angeles refinery; o completion of a coker and continuous catalytic reformer at the company's Sweeny, Texas, refinery; o capacity expansion and debottlenecking projects at the Borger, Texas, refinery; o completion of a commercial S Zorb Sulfur Removal Technology (S Zorb) unit at the Borger refinery; o an expansion of capacity in the Seaway crude-oil pipeline; and o installation of advanced central control buildings and technologies at the Sweeny and Borger facilities. Total capital spending for continuing operations for R&M for the three-year period was $1.5 billion, representing approximately 16 percent of ConocoPhillips' total capital spending for continuing operations. During 2002, construction continued on two major projects: a polypropylene plant at the Bayway refinery in Linden, New Jersey, and an FCC unit at the Ferndale, Washington, refinery. The Bayway polypropylene plant will utilize propylene feedstock from the Bayway refinery to make up to 775 million pounds per year of polypropylene. The plant became operational in March 2003. The FCC unit at Ferndale is expected to be fully operational in the second quarter of 2003 and will enable the refinery to significantly improve gasoline production per barrel of crude input. In 2002, ConocoPhillips made investments to improve its ability to meet regulatory "clean fuels" requirements throughout its refining system. The company plans to spend approximately $400 million per year for the next two years on clean fuels projects in the United States and already is well ahead of regulatory mandates for producing clean fuel in Europe. In 2002, ConocoPhillips completed a large continuous pilot plant demonstrating S Zorb for diesel, began construction of an S Zorb gasoline unit at its Ferndale, Washington, refinery, and announced its sixth licensing agreement for the use of S Zorb for gasoline and second licensing agreement for the use of S Zorb for diesel. The S Zorb process significantly reduces sulfur content in gasoline or diesel fuel for meeting new government regulations. In 2002, a major expansion of the alkylation unit at the Los Angeles refinery was completed and as a result, production of non-MTBE (methyl tertiary-butyl ether) gasoline has increased. 2003 Capital Budget R&M's 2003 capital budget for continuing operations is $1.1 billion, a 35 percent increase over spending of $840 million in 2002. Domestic spending is expected to consume about 80 percent of the R&M budget. The company plans to direct about $750 million of the R&M capital budget to domestic refining, of which about 45 percent of the expenditures are related to clean fuels, safety and environmental projects. Domestic marketing, transportation and specialty businesses expect to spend about $130 million, with the remaining budget to fund projects in the company's international refining and marketing businesses in Europe and the Asia-Pacific region. 65 EMERGING BUSINESSES Capital spending for Emerging Businesses during 2002 was primarily for construction of the Immingham combined heat and power cogeneration plant near the company's Humber refinery in the United Kingdom. Additional investments were made at a domestic power plant in Orange, Texas, and at the company's carbon fibers plant in Ponca City, Oklahoma. Emerging Businesses' 2003 capital budget of $248 million is primarily dedicated to the continued construction of the Immingham combined heat and power cogeneration plant. CONTINGENCIES LEGAL AND TAX MATTERS ConocoPhillips accrues for contingencies when a loss is probable and the amounts can be reasonably estimated. Based on currently available information, the company believes that it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on the company's financial statements. All significant litigation arising from the June 23, 1999, flash fire that occurred in a reactor vessel at the K-Resin styrene-butadiene copolymer (SBC) plant at the Houston Chemical Complex has now been resolved. On March 27, 2000, an explosion and fire occurred at the K-Resin SBC plant due to the overpressurization of an out-of-service butadiene storage tank. One employee was killed and several individuals, including employees of both ConocoPhillips and its contractors, were injured. Additionally, individuals who were allegedly in the area of the Houston Chemical Complex at the time of the incident have claimed they suffered various personal injuries due to exposure to the event. The wrongful death claim and the claims of the most seriously injured workers have been resolved. Currently, there are eight lawsuits pending on behalf of approximately 100 primary plaintiffs. Under the indemnification provisions of subcontracting agreements with Zachry and Brock Maintenance, Inc., ConocoPhillips sought indemnification from these subcontractors with respect to claims made by their employees. Although that plant was contributed to CPChem under the Contribution Agreement, ConocoPhillips retains liability for damages arising out of the incident. ENVIRONMENTAL ConocoPhillips and each of its various businesses are subject to the same numerous international, federal, state, and local environmental laws and regulations as are other companies in the petroleum exploration and production; and refining, marketing and transportation of crude oil and refined products businesses. The most significant of these environmental laws and regulations include, among others, the: o Federal Clean Air Act, which governs air emissions; o Federal Clean Water Act, 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; 66 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 (OPA90) 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 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. These laws and their implementing regulations set limits on emissions and, in the case of discharges to water, establish water quality limits. They also, in most cases, require permits in association with new or modified operations. These permits can require an applicant to collect substantial information in connection with the application process, which can be expensive and time-consuming. In addition, there can be delays associated with notice and comment periods and the agency's processing of the application. Many of the delays associated with the permitting process are beyond the control of the applicant. Many states and foreign countries where ConocoPhillips operates also have, or are developing, similar environmental laws and regulations governing the same types of activities. While similar, in some cases these regulations may impose additional, or more stringent, requirements that can add to the cost and difficulty of marketing or transporting products across state and international borders. The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor easily determinable as new standards, such as air emission standards, water quality standards and stricter fuel regulations, continue to evolve. However, environmental laws and regulations are expected to continue to have an increasing impact on ConocoPhillips' operations in the United States and in most of the countries in which the company operates. Notable areas of potential impacts include air emission compliance and remediation obligations in the United States. Under the Clean Air Act, the EPA has promulgated a number of stringent limits on air emissions and established a federally mandated operating permit program. Violations of the Clean Air Act are enforceable with civil and criminal sanctions. The EPA has also promulgated specific rules governing the sulfur content of gasoline, known generically as the "Tier II Sulfur Rules," which become applicable to ConocoPhillips' gasoline as early as 2004. The company is implementing a compliance strategy for meeting the requirements, including the use of ConocoPhillips' proprietary technology known as S Zorb. The company expects to use a combination of technologies to achieve compliance with these rules and has made preliminary estimates of its cost of compliance. These costs will be included in future budgeting for refinery compliance. The EPA has also promulgated sulfur content rules for highway diesel fuel that become applicable in 2006. ConocoPhillips is currently developing and testing an S Zorb system for removing sulfur from diesel fuel. It is anticipated that S Zorb will be used as part of ConocoPhillips' strategy for complying with these rules. Because the company is still evaluating and developing capital strategies for compliance with the rule, ConocoPhillips cannot provide precise cost estimates at this time, but will do so and report these compliance costs as required by law. 67 Additional areas of potential air-related impacts to ConocoPhillips are the proposed revisions to the National Ambient Air Quality Standards (NAAQS) and the Kyoto Protocol. In July 1997, the EPA 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 EPA to address the implementation provisions relating to the revised ozone NAAQS. If adopted, the revised NAAQS could result in substantial future environmental expenditures for ConocoPhillips. 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 ConocoPhillips 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. It is not, however, possible to accurately estimate the costs that could be incurred by ConocoPhillips to comply with such regulations, but such expenditures could be substantial. ConocoPhillips 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. Remediation obligations include cleanup responsibility arising from petroleum releases from underground storage tanks located at numerous past and present ConocoPhillips owned and/or operated petroleum-marketing outlets throughout the United States. Federal and state laws require that contamination caused by such underground storage tank releases be assessed and remediated to meet applicable standards. In addition to other cleanup standards, many states have adopted cleanup criteria for MTBE for both soil and groundwater. MTBE standards continue to evolve, and future environmental expenditures associated with the remediation of MTBE-contaminated underground storage tank sites could be substantial. RCRA requires permitted facilities to undertake an assessment of environmental conditions at the facility. If conditions warrant, ConocoPhillips may be required to remediate contamination caused by prior operations. In contrast to CERCLA, which is often referred to as "Superfund," the cost of corrective action activities under the RCRA corrective action program typically is borne solely by ConocoPhillips. Over the next decade, ConocoPhillips anticipates that significant ongoing expenditures for RCRA remediation activities may be required, but such annual expenditures for the near term are not expected to vary significantly from the range of such expenditures the company has experienced over the past few years. Longer term, expenditures are subject to considerable uncertainty and may fluctuate significantly. ConocoPhillips from time to time receives requests for information or notices of potential liability from the EPA and state environmental agencies alleging that we are a potentially responsible party under CERCLA or an equivalent state statute. On occasion, ConocoPhillips 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 ConocoPhillips but allegedly contain wastes attributable to the company's past operations. As of December 31, 2001, the company reported it had been notified of potential liability under CERCLA at 29 sites around the United States. The company also had been notified of potential liability under comparable state laws at 11 sites around the United States. At August 30, 2002, the date of the merger, Conoco had been notified of potential liability under CERCLA and comparable state laws at 24 sites around the United States. At seven of these sites, both Conoco and the company had been notified of potential liability. The resulting total for ConocoPhillips was 57 sites. At December 31, 2002, ConocoPhillips had resolved three of these 68 sites and received four new notices of potential liability, leaving approximately 58 sites where ConocoPhillips has been notified of potential liability. For most Superfund sites, ConocoPhillips' potential liability will be significantly less than the total site remediation costs because the percentage of waste attributable to ConocoPhillips versus that attributable to all other potentially responsible parties is relatively low. Although liability of those potentially responsible is generally joint and several for federal sites and frequently so for state sites, other potentially responsible parties at sites where ConocoPhillips 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, ConocoPhillips' share of liability has not increased materially. Many of the sites at which the company is potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess site conditions, apportion responsibility and determine the appropriate remediation. In some instances, ConocoPhillips may have no liability or attain a settlement of liability. Actual cleanup costs generally occur after the parties obtain EPA or equivalent state agency approval. There are relatively few sites where ConocoPhillips is a major participant, and neither the cost to ConocoPhillips 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 ConocoPhillips. Expensed environmental costs were $546 million in 2002 and are expected to be approximately $687 million in 2003 and $717 million in 2004. Capitalized environmental costs were $325 million in 2002 and are expected to be approximately $638 million and $718 million in 2003 and 2004, respectively. Remediation Accruals ConocoPhillips 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 are not reduced for potential recoveries from insurers or other third parties and are not discounted (except, if assumed in a purchase business combination, such costs are recorded on a discounted basis). Many of these liabilities result from CERCLA, RCRA and similar state laws that require the company to undertake certain investigative and remedial activities at sites where it conducts, or once conducted, operations or at sites where ConocoPhillips-generated waste was disposed. The accrual also includes a number of sites identified by ConocoPhillips that may require environmental remediation, but which are not currently the subject of CERCLA, RCRA or state enforcement activities. If applicable, undiscounted receivables are accrued for probable insurance or other third-party recoveries. In the future, ConocoPhillips 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, 2002. 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, 2002, ConocoPhillips' balance sheet included a total environmental accrual of $743 million, compared with $439 million at December 31, 2001, an increase of $304 million, primarily resulting from the merger. The majority of these expenditures are expected to be incurred within the next 30 years. Notwithstanding any of the foregoing and as with other companies engaged in similar businesses, environmental costs and liabilities are inherent in ConocoPhillips' operations and products, and there can be no assurance that material costs and liabilities will not be incurred. However, ConocoPhillips currently 69 does not expect any material adverse effect upon its results of operations or financial position as a result of compliance with environmental laws and regulations. OTHER ConocoPhillips has deferred tax assets related to certain accrued liabilities, alternative minimum tax credits, and loss carryforwards. Valuation allowances have been established for certain foreign and state net operating loss carryforwards that reduce deferred tax assets to an amount that will, more likely than not, be realized. Uncertainties that may affect the realization of these assets include tax law changes and the future level of product prices and costs. Based on the company's historical taxable income, its expectations for the future, and available tax-planning strategies, management expects that the net deferred tax assets will be realized as offsets to reversing deferred tax liabilities and as reductions in future taxable income. The alternative minimum tax credit can be carried forward indefinitely to reduce the company's regular tax liability. NEW ACCOUNTING STANDARDS There are a number of new FASB Statements of Financial Accounting Standards (SFAS) and Interpretations that ConocoPhillips implemented either in December 2002 or January 2003, as required: SFAS No. 143, "Accounting for Asset Retirement Obligations;" SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections;" SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities;" SFAS No. 148, "Accounting for Stock-Based Compensation--Transition and Disclosure;" Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others;" and Interpretation No. 46, "Consolidation of Variable Interest Entities." In addition, in 2003, the FASB is expected to issue SFAS No. 149, "Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity." For additional information about these, see Note 27--New Accounting Standards in the Notes to Consolidated Financial Statements, which is incorporated herein by reference. CRITICAL ACCOUNTING POLICIES The preparation of financial statements in conformity with generally accepted accounting principles requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. See Note 1--Accounting Policies in the Notes to Consolidated Financial Statements for descriptions of the company's major accounting policies. Certain of these accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used. OIL AND GAS ACCOUNTING Accounting for oil and gas exploratory activity is subject to special accounting rules that are unique to the oil and gas industry. The acquisition of geological and geophysical seismic information, prior to the discovery of proved reserves, is expensed as incurred, similar to accounting for research and development costs. However, leasehold acquisition costs and exploratory well costs are capitalized on the balance sheet, pending determination of whether proved oil and gas reserves have been discovered on the prospect. 70 Property Acquisition Costs For individually significant leaseholds, management periodically assesses for impairment based on exploration and drilling efforts to date. For leasehold acquisition costs that individually are relatively small, management exercises judgment and determines a percentage probability that the prospect ultimately will fail to find proved oil and gas reserves and pools that leasehold information with others in the geographic area. For prospects in areas that have had limited, or no, previous exploratory drilling, the percentage probability of ultimate failure is normally judged to be quite high. This judgmental percentage is multiplied by the leasehold acquisition cost, and that product is divided by the contractual period of the leasehold to determine a periodic leasehold impairment charge that is reported in exploration expense. This judgmental probability percentage is reassessed and adjusted throughout the contractual period of the leasehold based on favorable or unfavorable exploratory activity on the leasehold or on adjacent leaseholds, and leasehold impairment amortization expense is adjusted prospectively. By the end of the contractual period of the leasehold, the impairment probability percentage will have been adjusted to 100 percent if the leasehold is expected to be abandoned, or will have been adjusted to zero percent if there is an oil or gas discovery that is under development. See the supplemental Oil and Gas Operations disclosures about Costs Incurred and Capitalized Costs for more information about the amounts and geographic locations of costs incurred in acquisition activity, and the amounts on the balance sheet related to unproved properties. Exploratory Costs For exploratory wells, drilling costs are temporarily capitalized, or "suspended," on the balance sheet, pending a judgmental determination of whether potentially economic oil and gas reserves have been discovered by the drilling effort. This judgment usually is made within two months of the completion of the drilling effort, but can take longer, depending on the complexity of the geologic structure. Accounting rules require that this judgment be made at least within one year of well completion. If a judgment is made that the well did not encounter potentially economic oil and gas quantities, the well costs are expensed as a dry hole and are reported in exploration expense. Exploratory wells that are judged to have discovered potentially economic quantities of oil and gas and that are in areas where a major capital expenditure (e.g., a pipeline or offshore platform) would be required before production could begin, and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area, remain capitalized on the balance sheet as long as additional exploratory appraisal work is under way or firmly planned. For complicated offshore exploratory discoveries, it is not unusual to have exploratory wells remain suspended on the balance sheet for several years while the company performs additional appraisal drilling and seismic work on the potential oil and gas field. Unlike leasehold acquisition costs, there is no periodic impairment assessment of suspended exploratory well costs. Management continuously monitors the results of the additional appraisal drilling and seismic work and expenses the suspended well costs as dry holes when it judges that the potential field does not warrant further exploratory efforts in the near term. See the supplemental Oil and Gas Operations disclosures about Costs Incurred and Capitalized Costs for more information about the amounts and geographic locations of costs incurred in exploration activity and the amounts on the balance sheet related to unproved properties, as well as the Wells In Progress disclosure for the number and geographic location of wells not yet declared productive or dry. Proved Oil and Gas Reserves Engineering estimates of the quantities of recoverable oil and gas reserves in oil and gas fields are inherently imprecise and represent only approximate amounts because of the subjective judgments involved in developing such information. Despite the inherent imprecision in these engineering estimates, accounting rules require supplemental disclosure of "proved" oil and gas reserve estimates due to the importance of these estimates to better understanding the perceived value and future cash flows of a company's oil and gas operations. The judgmental estimation of proved oil and gas reserves is also important to the income statement because the proved oil and gas reserve estimate for a field serves as the 71 denominator in the unit-of-production calculation of depreciation, depletion and amortization of the capitalized costs for that field. There are several authoritative guidelines regarding the engineering criteria that have to be met before estimated oil and gas reserves can be designated as "proved." The company's reservoir engineering department has policies and procedures in place that are consistent with these authoritative guidelines. The company has qualified and experienced internal engineering personnel who make these estimates. Proved reserve estimates are updated annually and take into account recent production and seismic information about each field. Also, as required by authoritative guidelines, the estimated future date when a field will be permanently shut-in for economic reasons is based on an extrapolation of oil and gas prices and operating costs prevalent at the balance sheet date. This estimated date when production will end affects the amount of estimated recoverable reserves. Therefore, as prices and cost levels change from year to year, the estimate of proved reserves also changes. 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 depreciation expense. IMPAIRMENT OF ASSETS Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets--generally on a field-by-field basis for exploration and production assets, at an entire complex level for downstream assets, or at a site level for retail stores. Because there usually is a lack of quoted market prices for long-lived assets, the fair value usually is based on the present values of expected future cash flows using discount rates commensurate with the risks involved in the asset group. The expected future cash flows used for impairment reviews and related fair value calculations are based on judgmental assessments of future production volumes, prices and costs, considering all available information at the date of review. See Note 10--Impairments in the Notes to Consolidated Financial Statements. DISMANTLEMENT, REMOVAL AND ENVIRONMENTAL COSTS Under various contracts, permits and regulations, the company has material legal obligations to remove tangible equipment and restore the land or seabed at the end of operations at production sites. The largest asset removal obligations facing ConocoPhillips involve removal and disposal of offshore oil and gas platforms around the world, and oil and gas production facilities and pipelines in Alaska. The estimated undiscounted costs, net of salvage values, of dismantling and removing these facilities are accrued, using primarily the unit-of-production method, over the productive life of the asset. Estimating the future asset removal costs necessary for this accounting calculation is difficult. Most of these removal obligations are many years in the future and the contracts and regulations often have vague descriptions of what removal practices and criteria will have to be met when the removal event actually occurs. Asset removal technologies and costs are constantly changing, as well as political, environmental, safety and public relations considerations. See Note 11--Accrued Dismantlement, Removal and Environmental Costs in the Notes to Consolidated Financial Statements. 72 BUSINESS ACQUISITIONS Purchase Price Allocation Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets and liabilities of the acquired business. For most assets and liabilities, purchase price allocation is accomplished by recording the asset or liability at its estimated fair value. The most difficult estimations of individual fair values are those involving properties, plants and equipment and identifiable intangible assets. The company uses all available information to make these fair value determinations and, for major business acquisitions, typically engages an outside appraisal firm to assist in the fair value determination of the acquired long-lived assets. The company has, if necessary, up to one year after the acquisition closing date to finish these fair value determinations and finalize the purchase price allocation. Intangible Assets and Goodwill In connection with the acquisition of Tosco Corporation on September 14, 2001, and the merger on August 30, 2002, the company recorded material intangible assets for tradenames, air emission permit credits, and permits to operate refineries. These intangible assets were determined to have indefinite useful lives and so are not amortized. This judgmental assessment of an indefinite useful life has to be continuously evaluated in the future. If, due to changes in facts and circumstances, management determines that these intangible assets then have definite useful lives, amortization will have to commence at that time on a prospective basis. As long as these intangible assets are judged to have indefinite lives, they will be subject to periodic lower-of-cost-or-market tests, which requires management's judgment of the estimated fair value of these intangible assets. See Note 6--Acquisition of Tosco Corporation, Note 3--Merger of Conoco and Phillips, and Note 10--Impairments in the Notes to Consolidated Financial Statements. Also in connection with the acquisition of Tosco and the merger, the company recorded a material amount of goodwill. Under the accounting rules for goodwill, this intangible asset is not amortized. Instead, goodwill is subject to annual reviews for impairment based on a two-step accounting test. The first step is to compare the estimated fair value of any reporting units within the company that have recorded goodwill with the recorded net book value (including the goodwill) of the reporting unit. If the estimated fair value of the reporting unit is higher than the recorded net book value, no impairment is deemed to exist and no further testing is required that year. If, however, the estimated fair value of the reporting unit is below the recorded net book value, then a second step must be performed to determine the amount of the goodwill impairment to record, if any. In this second step, the estimated fair value from the first step is used as the purchase price in a hypothetical new acquisition of the reporting unit. The various purchase business combination rules are followed to determine a hypothetical purchase price allocation for the reporting unit's assets and liabilities. The residual amount of goodwill that results from this hypothetical purchase price allocation is compared with the recorded amount of goodwill for the reporting unit, and the recorded amount is written down to the hypothetical amount if lower. Because quoted market prices for the company's reporting units are not available, management has to apply judgment in determining the estimated fair value of its reporting units for purposes of performing the first step of this periodic goodwill impairment test. Management uses all available information to make these fair value determinations and may engage an outside appraisal firm for assistance. In addition, if the first test step is not met, further judgment has to be applied in determining the fair values of individual assets and liabilities for purposes of the hypothetical purchase price allocation. Again, management has to use all available information to make these fair value determinations and may engage an outside appraisal firm for assistance. At year-end 2002, the estimated fair values of the company's domestic refining and marketing reporting units, excluding those acquired in the merger and those included in discontinued operations, were more than 10 percent higher than the recorded net book values (including the Tosco goodwill) of the reporting units. However, a lower fair value estimate in the future could result in impairment of the remaining $2.4 billion 73 of Tosco goodwill. The allocation of goodwill attributable to the ConocoPhillips merger to reporting units, and its sensitivity to future impairment, will occur after the final allocation of the purchase price in 2003. INVENTORY VALUATION Prior to the acquisition of Tosco in September 2001 and the merger in August 2002, the company's inventories on the last-in, first-out (LIFO) cost basis were predominantly reflected on the balance sheet at historical cost layers established many years ago, when price levels were much lower. Therefore, prior to 2001, the company's LIFO inventories were relatively insensitive to current price level changes. However, the acquisition of Tosco and the merger added LIFO cost layers that were recorded at replacement cost levels prevalent in late September 2001 and August 2002, respectively. As a result, the company's LIFO cost inventories are now much more sensitive to lower-of-cost-or-market impairment write-downs, whenever price levels fall. ConocoPhillips recorded a LIFO inventory lower-of-cost-or-market impairment in the fourth quarter of 2001 due to a crude oil price deterioration. While crude oil is not the only product in the company's LIFO pools, its market value is a major factor in lower-of-cost-or-market calculations. The company estimates that additional impairments could occur if a 60 percent/40 percent blended average of West Texas Intermediate/Brent crude oil prices falls below $21.75 per barrel at a reporting date. The determination of replacement cost values for the lower-of-cost-or-market test uses objective evidence, but does involve judgment in determining the most appropriate objective evidence to use in the calculations. PROJECTED BENEFIT OBLIGATIONS Determination of the projected benefit obligations for the company's defined benefit pension and postretirement plans are important to the recorded amounts for such obligations on the balance sheet and to the amount of benefit expense in the income statement. This also impacts the required company contributions into the plans. The actuarial determination of projected benefit obligations and company contribution requirements involves judgment about uncertain future events, including estimated retirement dates, salary levels at retirement, mortality rates, lump-sum election rates, rates of return on plan assets, future health care cost-trend rates, and rates of utilization of health care services by retirees. Due to the specialized nature of these calculations, the company engages outside actuarial firms to assist in the determination of these projected benefit obligations. For Employee Retirement Income Security Act- qualified pension plans, the actuary exercises fiduciary care on behalf of plan participants in the determination of the judgmental assumptions used in determining required company contributions into plan assets. Due to differing objectives and requirements between financial accounting rules and the pension plan funding regulations promulgated by governmental agencies, the actuarial methods and assumptions for the two purposes differ in certain important respects. Ultimately, the company will be required to fund all promised benefits under pension and postretirement benefit plans not funded by plan assets or investment returns, but the judgmental assumptions used in the actuarial calculations significantly affect periodic financial statements and funding patterns over time. Benefit expense is particularly sensitive to the discount rate and return on plan assets assumptions. A 1 percent decrease in the discount rate would increase annual benefit expense by $79 million, while a 1 percent decrease in the return on plan assets assumption would increase annual benefit expense by $21 million. OUTLOOK As a condition to the merger, the U.S. Federal Trade Commission (FTC) required that both Conoco and Phillips divest certain assets. In the fourth quarter of 2002, the propane terminal assets at Jefferson City, Missouri, and East St. Louis, Illinois, were sold and ConocoPhillips agreed to sell its Woods Cross business unit in Salt Lake City, Utah, plus associated assets. See Note 4--Discontinued Operations in the Notes to Consolidated Financial Statements for a list of the remaining assets held for sale. 74 In December 2002, ConocoPhillips committed to and initiated a plan to sell a substantial portion of its company-owned retail sites. In connection with the anticipated sale, the company, in the fourth quarter, recorded charges totaling $1,412 million before-tax, $1,008 million after-tax, primarily related to the impairment of properties, plants and equipment; goodwill; intangible assets and provision for losses and penalties to unwind various lease arrangements. The company expects to complete the sale of the sites in 2003. In December of 2002, political unrest in Venezuela caused economic and other disruptions which shut down most oil production in Venezuela, including the company's Petrozuata, Hamaca and Gulf of Paria operations. At ConocoPhillips' Petrozuata joint venture, operations were closed down on December 15, 2002, due to shortages of hydrogen and natural gas (required for processing and fuel). Prior to the disruptions, Petrozuata was producing and processing approximately 120,000 gross (60,000 net) barrels of extra-heavy crude oil per day. Similarly, the disruptions have impacted development production and construction progress at the Hamaca joint-venture project. Construction of the Hamaca upgrader continues, although at a reduced rate. Difficulty in obtaining supplies has been the primary impediment. Production was shut in on December 6, 2002. Prior to the disruptions, Hamaca was producing approximately 55,000 gross (18,000 net) barrels of extra-heavy crude per day. In addition, the crude oil produced by Petrozuata is used as feedstock for ConocoPhillips' Lake Charles, Louisiana, refinery and a Venezuelan refinery operated by PDVSA. In December 2002, ConocoPhillips substituted about 1.2 million crude barrels for its Lake Charles refinery. At the company's Sweeny refinery, crude throughputs were reduced slightly due to short supply of Merey Venezuelan crude oil. Overall, there was minimum impact to net income; however, it could reduce net income $30 million to $50 million per month in 2003 as long as production at Petrozuata and Hamaca is shut in. Limited production began from Hamaca and Petrozuata in February 2003. On March 12, 2002, ConocoPhillips announced that it had signed a Heads of Agreement (LNG HOA) with The Tokyo Electric Power Company, Incorporated (TEPCO) and Tokyo Gas Co., Ltd. (Tokyo Gas) that would enable Phase II, which involves the export and sale of natural gas, of the Bayu-Undan field development to proceed upon resolution of certain legal, regulatory and fiscal issues. The Timor Sea Treaty (Treaty) was ratified by Timor-Leste (formerly East Timor) in December 2002 and by Australia in March 2003 and is subject to certain procedural events before it is fully effective. The Treaty will allow the issuance of new production sharing contracts to the existing contractors in the Bayu-Undan unit, which when combined with the expected approval of the Development Plan and the expected enactment of certain Timor-Leste legislation will provide the legal, regulatory and fiscal basis necessary to proceed with the gas project. Under the terms of the LNG HOA with TEPCO and Tokyo Gas, TEPCO and Tokyo Gas will purchase 3 million tons per year of liquefied natural gas (LNG) for a period of 17 years, utilizing natural gas from the Bayu-Undan field. Shipments would begin in 2006, from an LNG facility near Darwin, Australia, utilizing ConocoPhillips' Optimized Cascade liquefied natural gas process. In 2003, ConocoPhillips expects worldwide production of approximately 1.55 million barrels of oil equivalent per day from currently proved reserves. Improvements for the year are expected to come from the United Kingdom, Norway and China. These improvements will be offset by decreases in the U.S. Lower 48 and Canada as a result of the disposition of assets, as well as the impact of the disruptions in Venezuela. In R&M, crude oil throughputs in 2003 are expected to average approximately 2.5 million barrels per day. Crude oil and natural gas prices are subject to external factors over which the company has no control, such as global economic conditions, political events, demand growth, inventory levels, weather, competing fuels prices and availability of supply. Crude oil prices increased significantly during 2002 due to production restraint by major exporting countries serving to rebalance inventories, supply concerns resulting from Middle East tensions, tropical storms in the U.S. Gulf of Mexico temporarily shutting in oil 75 production and shipping, and the disruptions in Venezuela. Global oil demand is starting to recover on a year-over-year basis, compared with the declines that resulted from the U.S. recession and the events of September 11, 2001. However, the pace of improvement will depend on a continuation of the economic recovery in the United States and globally. Conflicts in oil-producing countries and uncertainties surrounding the global economic recovery could keep prices volatile in 2003. U.S. natural gas prices strengthened considerably at the end of the third quarter and remained strong in the fourth quarter stemming from growing natural gas supply concerns, rising oil prices and an increased demand due to the weather. Supply concerns arose from the decline in domestic gas production and Canadian imports versus 2001, and tropical storms temporarily shutting in production in the Gulf of Mexico. Refining margins are subject to movements in the price of crude oil and other feedstocks, and the prices of petroleum products, which are subject to market factors over which the company has no control, such as the U.S. and global economies; government regulations; seasonal factors that affect demand, such as the summer driving months; and the levels of refining output and product inventories. Global refining margins remained depressed during much of 2002 due to weak oil demand, relatively high levels of gasoline and distillate inventories and strengthening crude prices, which increased feedstock costs. As a result of tropical storms in the Gulf of Mexico, industry refining crude oil runs were temporarily reduced, which caused product inventory draws in the United States and improved refining margins modestly. Refining and marketing margins can be expected to improve when the U.S. and global economies recover. CAUTIONARY STATEMENT FOR THE PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995 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. Forward-looking statements can be identified by the words "expects," "anticipates," "intends," "plans," "projects," "believes," "estimates" and similar expressions. ConocoPhillips has based the forward-looking statements relating to its operations on its current expectations, estimates and projections about ConocoPhillips and the industries in which it operates in general. ConocoPhillips cautions you that these statements are not guarantees of future performance and involve risks, uncertainties and assumptions that the company cannot predict. In addition, ConocoPhillips has based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, ConocoPhillips' actual outcomes and results may differ materially from what the company has expressed or forecast in the forward-looking statements. Any differences could result from a variety of factors, including the following: o fluctuations in crude oil, natural gas and natural gas liquids prices, refining and marketing margins and margins for ConocoPhillips' chemicals business; o changes in the business, operations, results and prospects of ConocoPhillips; o the operation and financing of ConocoPhillips' midstream and chemicals joint ventures; o potential failure to realize fully or within the expected time frame the expected cost savings and synergies from the combination of Conoco and Phillips; o costs or difficulties related to the integration of the businesses of Conoco and Phillips, as well as the continued integration of businesses recently acquired by each of them; 76 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 facilities for exploration and production projects, manufacturing or refining; o unexpected difficulties in manufacturing or refining ConocoPhillips' refined products, including synthetic crude oil, and chemicals products; o lack of, or disruptions in, adequate and reliable transportation for ConocoPhillips' crude oil, natural gas and refined products; o inability to timely obtain or maintain permits, comply with government regulations or make capital expenditures required to maintain compliance; o potential disruption or interruption of ConocoPhillips' facilities due to accidents, political events or terrorism; o international monetary conditions and exchange controls; o liability for remedial actions, including removal and reclamation obligations, under environmental regulations; o liability resulting from litigation; o general domestic and international economic and political conditions, including armed hostilities and governmental disputes over territorial boundaries; o changes in tax and other laws or regulations applicable to ConocoPhillips' business; and o inability to obtain economical financing for exploration and development projects, construction or modification of facilities and general corporate purposes. 77 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK FINANCIAL INSTRUMENT MARKET RISK ConocoPhillips and certain of its subsidiaries hold and issue derivative contracts and financial instruments that expose cash flows or earnings to changes in commodity prices, foreign exchange rates or interest rates. The company may use financial and commodity-based derivative contracts to manage the risks produced by changes in the prices of electric power, natural gas, and crude oil and related products, fluctuations in interest rates and foreign currency exchange rates, or to exploit market opportunities. With the completion of the merger on August 30, 2002, the derivatives policy adopted during the third quarter of 2001 is no longer in effect; however, the ConocoPhillips Board of Directors has approved an "Authority Limitations" document that prohibits the use of highly leveraged derivatives or derivative instruments without sufficient liquidity for comparable valuations without approval from the Chief Executive Officer. The Authority Limitations document also authorizes the Chief Executive Officer to establish the maximum Value at Risk (VaR) limits for the company. Compliance with these limits is monitored daily. The function of the Risk Management Steering Committee, monitoring the use and effectiveness of derivatives, was assumed by the Chief Financial Officer for risks resulting from foreign currency exchange rates and interest rates, and by the Executive Vice President of Commercial, a new position that reports to the Chief Executive Officer, for commodity price risk. ConocoPhillips' Commercial Group manages commercial marketing, optimizes the commodity flows and positions of the company, monitors related risks of the company's upstream and downstream businesses, and selectively takes price risk to add value. Commodity Price Risk ConocoPhillips operates in the worldwide crude oil, refined product, natural gas, natural gas liquids, and electric power markets and is exposed to fluctuations in the prices for these commodities. These fluctuations can affect the company's revenues as well as the cost of operating, investing, and financing activities. Generally, the company's policy is to remain exposed to market prices of commodities; however, executive management may elect to use derivative instruments to hedge the price risk of the company's equity crude oil and natural gas production, as well as refinery margins. The ConocoPhillips' Commercial Group uses futures, forwards, swaps, and options in various markets to optimize the value of the company's supply chain, which may move the company's risk profile away from market average prices to accomplish the following objectives: o Balance physical systems. In addition to cash settlement prior to contract expiration, exchange traded futures contracts may also be settled by physical delivery of the commodity, providing another source of supply to meet the company's refinery requirements or marketing demand; o Meet customer needs. Consistent with the company's policy to generally remain exposed to market prices, the company uses swap contracts to convert fixed-price sales contracts, which are often requested by natural gas and refined product consumers, to a floating market price; o Manage the risk to the company's cash flows from price exposures on specific crude oil, natural gas, refined product and electric power transactions; and 78 o Enable the company to use the market knowledge gained from these activities to do a limited amount of trading not directly related to the company's physical business. For the 12 months ended December 31, 2002 and 2001, the gains or losses from this activity were not material to the company's cash flows or income from continuing operations. ConocoPhillips uses a VaR model to estimate the loss in fair value that could potentially result on a single day from the effect of adverse changes in market conditions on the derivative financial instruments and derivative commodity instruments held or issued, including commodity purchase and sales contracts recorded on the balance sheet at December 31, 2002, as derivative instruments in accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. Using Monte Carlo simulation, a 95 percent confidence level and a one-day holding period, the VaR for those instruments issued or held for trading purposes at December 31, 2002 and 2001, was $0.7 million at each year-end. The VaR for instruments held for purposes other than trading at December 31, 2002 and 2001, was $2 million and $1.7 million, respectively. Interest Rate Risk The following tables provide information about the company's financial instruments that are sensitive to changes in interest rates. The debt tables present principal cash flows and related weighted-average interest rates by expected maturity dates; the derivative table shows the notional quantities on which the cash flows will be calculated by swap termination date. Weighted-average variable rates are based on implied forward rates in the yield curve at the reporting date. The carrying amount of the company's floating-rate debt approximates its fair value. The fair value of the fixed-rate financial instruments is estimated based on quoted market prices. 79
Millions of Dollars Except as Indicated ------------------------------------------------------------------------------------------------- Mandatorily Redeemable Other Minority Interests and Debt Preferred Securities ------------------------------------------------------------- -------------------------- Expected Fixed Average Floating Average Fixed Average Maturity Rate Interest Rate Interest Rate Interest Date Maturity Rate Maturity Rate Maturity Rate --------------- -------- -------- -------- -------- -------- -------- YEAR-END 2002 2003 $ 762 7.99% $ 706 2.60% $ -- --% 2004 1,362 5.91 -- -- -- -- 2005 1,169 8.49 -- -- -- -- 2006 1,507 5.82 1,517 4.54 -- -- 2007 613 4.88 -- -- -- -- Remaining years 10,740 6.95 691 6.02 491 7.96 ------------------------------------------------------------------------------------------------------------------------ Total $16,153 $ 2,914 $ 491 ======================================================================================================================== Fair value $17,930 $ 2,914 $ 516 ======================================================================================================================== Year-End 2001 2002 $ 43 9.31% $ -- --% $ -- --% 2003 255 7.60 -- -- -- -- 2004 6 7.02 -- -- -- -- 2005 1,155 8.49 -- -- -- -- 2006 246 7.61 1,081 7.06 -- -- Remaining years 5,134 7.99 625 6.86 650 8.11 ------------------------------------------------------------------------------------------------------------------------ Total $ 6,839 $ 1,706 $ 650 ======================================================================================================================== Fair value $ 7,469 $ 1,706 $ 662 ========================================================================================================================
Interest Rate Derivatives at December 31, 2002 ---------------------------------------------------- Floating-to-Fixed ---------------------------------------------------- Expected Maturity Date Notional Average Pay Rate Average Receive Rate ---------------------- -------- ---------------- -------------------- 2003 $ 500 3.41% 2.56% 2004 -- -- -- 2005 -- -- -- 2006 166 5.85 4.76 2007 -- -- -- Remaining years -- -- -- ------------------------------------------------------------------------------------------------------------------------ Total $ 666 ======================================================================================================================== Fair value loss position $ 22 ========================================================================================================================
80 Foreign Currency Risk ConocoPhillips has foreign currency exchange rate risk resulting from operations in over 40 countries around the world. ConocoPhillips does not comprehensively hedge the exposure to currency rate changes, although the company 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. At December 31, 2002, ConocoPhillips had the following significant foreign currency derivative contracts: o approximately $194 million in foreign currency swaps hedging the company's European commercial paper program, with a fair value of $7.1 million; o approximately $536 million in foreign currency swaps hedging short-term intercompany loans between U.K. subsidiaries and a U.S. subsidiary, with a fair value of $9 million; and o approximately $24 million in foreign currency swaps hedging the company's firm purchase and sales commitments for gasoline in Germany, with a negative fair value of $4 million. Although these swaps hedge exposures to fluctuations in exchange rates, the company elected not to utilize hedge accounting as allowed by SFAS No. 133. As a result, the change in the fair value of these foreign currency swaps is recorded directly in earnings. Assuming an adverse hypothetical 10 percent change in the December 31, 2002, exchange rates, the potential foreign currency remeasurement loss in non-cash pretax earning from these swaps, intercompany loans, and commercial paper would be approximately $3 million. In addition to the intercompany loans discussed above, at December 31, 2002 and 2001, U.S. subsidiaries held long-term sterling-denominated intercompany receivables totaling $152 million and $191 million, respectively, due from a U.K. subsidiary. The U.K. subsidiary also held a dollar-denominated long-term receivable due from a U.S. subsidiary with no balance at December 31, 2002, and a $75 million balance at December 31, 2001. A Norwegian subsidiary held $198 million and $79 million of intercompany U.S. dollar-denominated receivables due from its U.S. parent at December 31, 2002 and 2001, respectively. Also at year-end 2001, a foreign subsidiary with the U.S. dollar as its functional currency owed a $9 million Norwegian kroner-denominated payable to a Norwegian subsidiary. The potential foreign currency remeasurement gains or losses in non-cash pretax earnings from a hypothetical 10 percent change in the year-end 2002 and 2001 exchange rates from these intercompany balances were $35 million and $21 million, respectively. For additional information about the company's use of derivative instruments, see Note 16--Derivative Instruments in the Notes to Consolidated Financial Statements. 81 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA CONOCOPHILLIPS INDEX TO FINANCIAL STATEMENTS
Page ---- Report of Management............................................................................. 83 Report of Independent Auditors................................................................... 84 Consolidated Statement of Operations for the years ended December 31, 2002, 2001 and 2000........ 85 Consolidated Balance Sheet at December 31, 2002 and 2001......................................... 86 Consolidated Statement of Cash Flows for the years ended December 31, 2002, 2001 and 2000........ 87 Consolidated Statement of Changes in Common Stockholders' Equity for the years ended December 31, 2002, 2001 and 2000............................................................. 88 Notes to Consolidated Financial Statements....................................................... 89 Supplementary Information Oil and Gas Operations................................................................ 146 Selected Quarterly Financial Data..................................................... 164 Condensed Consolidating Financial Information......................................... 165 INDEX TO FINANCIAL STATEMENT SCHEDULES Schedule II--Valuation and Qualifying Accounts................................................... 177
All other schedules are omitted because they are either not required, not significant, not applicable or the information is shown in another schedule, the financial statements or in the notes to consolidated financial statements. 82 -------------------------------------------------------------------------------- REPORT OF MANAGEMENT Management prepared, and is responsible for, the consolidated financial statements and the other information appearing in this annual report. The consolidated financial statements present fairly the company's financial position, results of operations and cash flows in conformity with accounting principles generally accepted in the United States. In preparing its consolidated financial statements, the company includes amounts that are based on estimates and judgments that management believes are reasonable under the circumstances. The company maintains internal controls designed to provide reasonable assurance that the company's assets are protected from unauthorized use and that all transactions are executed in accordance with established authorizations and recorded properly. The internal controls are supported by written policies and guidelines and are complemented by a staff of internal auditors. Management believes that the internal controls in place at December 31, 2002, provide reasonable assurance that the books and records reflect the transactions of the company and there has been compliance with its policies and procedures. The company's financial statements have been audited by Ernst & Young LLP, independent auditors selected by the Audit and Compliance Committee of the Board of Directors. Management has made available to Ernst & Young LLP all of the company's financial records and related data, as well as the minutes of stockholders' and directors' meetings. /s/ Archie W. Dunham /s/ J. J. Mulva /s/ John A. Carrig ARCHIE W. DUNHAM J. J. MULVA JOHN A. CARRIG Chairman of the Board President and Executive Vice President, Finance, Chief Executive Officer and Chief Financial Officer
March 24, 2003 83 -------------------------------------------------------------------------------- REPORT OF INDEPENDENT AUDITORS The Board of Directors and Stockholders ConocoPhillips We have audited the accompanying consolidated balance sheets of ConocoPhillips as of December 31, 2002 and 2001, and the related consolidated statements of operations, changes in common stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2002. Our audits also included the condensed consolidating financial information and financial statement schedule listed in the Index in Item 8. These financial statements, condensed consolidating financial information and schedule are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements, condensed consolidating financial information and schedule based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of ConocoPhillips at December 31, 2002 and 2001, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States. Also, in our opinion, the related condensed consolidating financial information and financial statement schedule, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein. As discussed in Note 2 to the consolidated financial statements, in 2001 ConocoPhillips changed its method of accounting for the costs of major maintenance turnarounds. /s/ Ernst & Young LLP ERNST & YOUNG LLP Houston, Texas March 24, 2003 84
------------------------------------------------------------------------------------------------------------------------ CONSOLIDATED STATEMENT OF OPERATIONS CONOCOPHILLIPS Years Ended December 31 Millions of Dollars ----------------------------------------- 2002 2001** 2000** ----------------------------------------- REVENUES Sales and other operating revenues* $ 56,748 24,892 22,155 Equity in earnings of affiliates 261 41 114 Other income 215 111 270 ------------------------------------------------------------------------------------------------------------------------ Total Revenues 57,224 25,044 22,539 ------------------------------------------------------------------------------------------------------------------------ COSTS AND EXPENSES Purchased crude oil and products 37,823 13,708 11,794 Production and operating expenses 4,988 2,643 2,136 Selling, general and administrative expenses 1,660 613 571 Exploration expenses 592 306 298 Depreciation, depletion and amortization 2,223 1,344 1,169 Impairments 177 26 100 Taxes other than income taxes* 6,937 2,740 2,242 Accretion on discounted liabilities 22 7 -- Interest and debt expense 566 338 369 Foreign currency transaction losses 24 11 58 Preferred dividend requirements of capital trusts and minority interests 48 53 54 ------------------------------------------------------------------------------------------------------------------------ Total Costs and Expenses 55,060 21,789 18,791 ------------------------------------------------------------------------------------------------------------------------ Income from continuing operations before income taxes 2,164 3,255 3,748 Provision for income taxes 1,450 1,644 1,900 ------------------------------------------------------------------------------------------------------------------------ INCOME FROM CONTINUING OPERATIONS 714 1,611 1,848 Income (loss) from discontinued operations (net of income taxes (benefit) of $(394), $15 and $7 for 2002, 2001 and 2000, respectively) (993) 32 14 ------------------------------------------------------------------------------------------------------------------------ INCOME (LOSS) BEFORE EXTRAORDINARY ITEMS AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE (279) 1,643 1,862 Extraordinary items (16) (10) -- Cumulative effect of change in accounting principle -- 28 -- ------------------------------------------------------------------------------------------------------------------------ NET INCOME (LOSS) $ (295) 1,661 1,862 ======================================================================================================================== NET INCOME (LOSS) PER SHARE OF COMMON STOCK Basic Continuing operations $ 1.48 5.50 7.26 Discontinued operations (2.06) .11 .06 ------------------------------------------------------------------------------------------------------------------------ Before extraordinary items and cumulative effect of change in accounting principle (.58) 5.61 7.32 Extraordinary items (.03) (.04) -- Cumulative effect of change in accounting principle -- .10 -- ------------------------------------------------------------------------------------------------------------------------ Net Income (Loss) $ (.61) 5.67 7.32 ======================================================================================================================== Diluted Continuing operations $ 1.47 5.46 7.21 Discontinued operations (2.05) .11 .05 ------------------------------------------------------------------------------------------------------------------------ Before extraordinary items and cumulative effect of change in accounting principle (.58) 5.57 7.26 Extraordinary items (.03) (.03) -- Cumulative effect of change in accounting principle -- .09 -- ------------------------------------------------------------------------------------------------------------------------ Net Income (Loss) $ (.61) 5.63 7.26 ======================================================================================================================== AVERAGE COMMON SHARES OUTSTANDING (in thousands) Basic 482,082 292,964 254,490 Diluted 485,505 295,016 256,326 ------------------------------------------------------------------------------------------------------------------------ *Includes excise taxes on petroleum products sales: $ 6,236 2,178 1,781 **Restated for discontinued operations.
See Notes to Consolidated Financial Statements. 85
------------------------------------------------------------------------------------------------------- CONSOLIDATED BALANCE SHEET CONOCOPHILLIPS At December 31 Millions of Dollars ----------------------- 2002 2001* ----------------------- ASSETS Cash and cash equivalents $ 307 142 Accounts and notes receivable (net of allowance of $48 million in 2002 and $33 million in 2001) 2,904 1,124 Accounts and notes receivable--related parties 1,476 105 Inventories 3,845 2,452 Prepaid expenses and other current assets 766 293 Assets of discontinued operations held for sale 1,605 2,382 ------------------------------------------------------------------------------------------------------- Total Current Assets 10,903 6,498 Investments and long-term receivables 6,821 3,309 Net properties, plants and equipment 43,030 22,133 Goodwill 14,444 2,281 Intangibles 1,119 861 Other assets 519 135 ------------------------------------------------------------------------------------------------------- Total $ 76,836 35,217 ======================================================================================================= LIABILITIES Accounts payable $ 5,949 2,531 Accounts payable--related parties 303 91 Notes payable and long-term debt due within one year 849 44 Accrued income and other taxes 1,991 897 Other accruals 3,075 720 Liabilities of discontinued operations held for sale 649 538 ------------------------------------------------------------------------------------------------------- Total Current Liabilities 12,816 4,821 Long-term debt 18,917 8,610 Accrued dismantlement, removal and environmental costs 1,666 1,059 Deferred income taxes 8,361 4,015 Employee benefit obligations 2,755 948 Other liabilities and deferred credits 1,803 769 ------------------------------------------------------------------------------------------------------- Total Liabilities 46,318 20,222 ------------------------------------------------------------------------------------------------------- COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF PHILLIPS 66 CAPITAL TRUSTS I AND II 350 650 ------------------------------------------------------------------------------------------------------- OTHER MINORITY INTERESTS 651 5 ------------------------------------------------------------------------------------------------------- COMMON STOCKHOLDERS' EQUITY Common stock (2002--2,500,000,000 shares authorized at $.01 par value; 2001--1,000,000,000 shares authorized at $1.25 par value) Issued (2002--704,354,839 shares; 2001--430,439,743 shares) Par value 7 538 Capital in excess of par 25,178 9,069 Treasury stock (at cost: 2001--20,725,114 shares) -- (1,038) Compensation and Benefits Trust (CBT) (at cost: 2002--26,785,094 shares; 2001--27,556,573 shares) (907) (934) Accumulated other comprehensive loss (164) (255) Unearned employee compensation--Long-Term Stock Savings Plan (LTSSP) (218) (237) Retained earnings 5,621 7,197 ------------------------------------------------------------------------------------------------------- Total Common Stockholders' Equity 29,517 14,340 ------------------------------------------------------------------------------------------------------- Total $ 76,836 35,217 =======================================================================================================
*Restated for discontinued operations. See Notes to Consolidated Financial Statements. 86
--------------------------------------------------------------------------------------------------------------------- CONSOLIDATED STATEMENT OF CASH FLOWS CONOCOPHILLIPS Years Ended December 31 Millions of Dollars ---------------------------------- 2002 2001* 2000* ---------------------------------- CASH FLOWS FROM OPERATING ACTIVITIES Income from continuing operations $ 714 1,611 1,848 Adjustments to reconcile income from continuing operations to net cash provided by continuing operations Non-working capital adjustments Depreciation, depletion and amortization 2,223 1,344 1,169 Impairments 177 26 100 Dry hole costs and leasehold impairment 307 99 130 Accretion on discounted liabilities 22 7 -- Acquired in-process research and development 246 -- -- Deferred taxes 142 513 412 Other (46) 131 (210) Working capital adjustments** Increase (decrease) in aggregate balance of accounts receivable sold (22) (174) 317 Decrease (increase) in other accounts and notes receivable (401) 1,357 (710) Decrease (increase) in inventories 200 (289) (12) Decrease (increase) in prepaid expenses and other current assets (37) 50 84 Increase (decrease) in accounts payable 788 (1,004) 417 Increase (decrease) in taxes and other accruals 454 (142) 439 --------------------------------------------------------------------------------------------------------------------- Net cash provided by continuing operations 4,767 3,529 3,984 Net cash provided by discontinued operations 202 33 30 --------------------------------------------------------------------------------------------------------------------- Net Cash Provided by Operating Activities 4,969 3,562 4,014 --------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM INVESTING ACTIVITIES Acquisitions, net of cash acquired 1,180 80 (6,443) Capital expenditures and investments, including dry hole costs (4,388) (3,016) (2,017) Proceeds from contributing assets to joint ventures -- -- 2,061 Proceeds from asset dispositions 815 262 850 Long-term advances to affiliates and other investments (92) (28) (208) --------------------------------------------------------------------------------------------------------------------- Net cash used in continuing operations (2,485) (2,702) (5,757) Net cash used in discontinued operations (99) (68) (5) --------------------------------------------------------------------------------------------------------------------- Net Cash Used in Investing Activities (2,584) (2,770) (5,762) --------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM FINANCING ACTIVITIES Issuance of debt 3,502 566 2,552 Repayment of debt (4,592) (945) (360) Redemption of preferred stock of subsidiary (300) -- -- Issuance of company common stock 44 51 31 Dividends paid on common stock (684) (403) (346) Other (190) (68) (118) --------------------------------------------------------------------------------------------------------------------- Net cash provided by (used in) continuing operations (2,220) (799) 1,759 --------------------------------------------------------------------------------------------------------------------- Net Cash Provided by (Used in) Financing Activities (2,220) (799) 1,759 --------------------------------------------------------------------------------------------------------------------- NET CHANGE IN CASH AND CASH EQUIVALENTS 165 (7) 11 Cash and cash equivalents at beginning of year 142 149 138 --------------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents at End of Year $ 307 142 149 =====================================================================================================================
*Restated for discontinued operations. **Net of acquisition and disposition of businesses. See Notes to Consolidated Financial Statements. 87
-------------------------------------------------------------------------------------------------------------------------------- CONSOLIDATED STATEMENT OF CHANGES CONOCOPHILLIPS IN COMMON STOCKHOLDERS' EQUITY Shares of Common Stock -------------------------------------------- Held in Issued Treasury Held in CBT -------------------------------------------- December 31, 1999 306,380,511 24,409,545 28,358,258 Net income Other comprehensive income Foreign currency translation Unrealized loss on securities Equity affiliates: Foreign currency translation Comprehensive income Cash dividends paid on common stock Distributed under incentive compensation and other benefit plans (1,267,540) (508,828) Recognition of LTSSP unearned compensation Tax benefit of dividends on unallocated LTSSP shares ---------------------------------------------------------------------------------------- December 31, 2000 306,380,511 23,142,005 27,849,430 Net income Other comprehensive income Minimum pension liability adjustment Foreign currency translation Unrealized loss on securities Hedging activities Equity affiliates: Foreign currency translation Derivatives related Comprehensive income Cash dividends paid on common stock Tosco acquisition 124,059,232 Distributed under incentive compensation and other benefit plans (2,416,891) (292,857) Recognition of LTSSP unearned compensation Tax benefit of dividends on unallocated LTSSP shares ---------------------------------------------------------------------------------------- December 31, 2001 430,439,743 20,725,114 27,556,573 Net loss Other comprehensive income Minimum pension liability adjustment Foreign currency translation Unrealized loss on securities Hedging activities Equity affiliates: Foreign currency translation Derivatives related Comprehensive loss Cash dividends paid on common stock ConocoPhillips merger 273,471,505 (19,852,674) Distributed under incentive compensation and other benefit plans 443,591 (872,440) (771,479) Recognition of LTSSP unearned compensation Tax benefit of dividends on unallocated LTSSP shares ---------------------------------------------------------------------------------------- DECEMBER 31, 2002 704,354,839 -- 26,785,094 ======================================================================================== Millions of Dollars ------------------------------------------------------------------------------------------- Common Stock Accumulated Unearned --------------------------------------- Other Employee Par Capital in Treasury Comprehensive Compensation Retained Value Excess of Par Stock CBT Loss --LTSSP Earnings Total ------------------------------------------------------------------------------------------- December 31, 1999 $ 383 2,098 (1,217) (961) (31) (286) 4,563 4,549 ------- Net income 1,862 1,862 Other comprehensive income Foreign currency translation (53) (53) Unrealized loss on securities (1) (1) Equity affiliates: Foreign currency translation (15) (15) ------- Comprehensive income 1,793 ------- Cash dividends paid on common stock (346) (346) Distributed under incentive compensation and other benefit plans 55 61 18 (65) 69 Recognition of LTSSP unearned compensation 23 23 Tax benefit of dividends on unallocated LTSSP shares 5 5 --------------------------------------------------------------------------------------------------------------------------------- December 31, 2000 383 2,153 (1,156) (943) (100) (263) 6,019 6,093 ------- Net income 1,661 1,661 Other comprehensive income Minimum pension liability adjustment (143) (143) Foreign currency translation (14) (14) Unrealized loss on securities (2) (2) Hedging activities (4) (4) Equity affiliates: Foreign currency translation (3) (3) Derivatives related 11 11 ------- Comprehensive income 1,506 ------- Cash dividends paid on common stock (403) (403) Tosco acquisition 155 6,883 7,038 Distributed under incentive compensation and other benefit plans 33 118 9 (84) 76 Recognition of LTSSP unearned compensation 26 26 Tax benefit of dividends on unallocated LTSSP shares 4 4 --------------------------------------------------------------------------------------------------------------------------------- December 31, 2001 538 9,069 (1,038) (934) (255) (237) 7,197 14,340 ------- Net loss (295) (295) Other comprehensive income Minimum pension liability adjustment (93) (93) Foreign currency translation 182 182 Unrealized loss on securities (3) (3) Hedging activities (1) (1) Equity affiliates: Foreign currency translation 40 40 Derivatives related (34) (34) ------- Comprehensive loss (204) ------- Cash dividends paid on common stock (684) (684) ConocoPhillips merger (531) 16,056 999 (562) 15,962 Distributed under incentive compensation and other benefit plans 53 39 27 (39) 80 Recognition of LTSSP unearned compensation 19 19 Tax benefit of dividends on unallocated LTSSP shares 4 4 --------------------------------------------------------------------------------------------------------------------------------- DECEMBER 31, 2002 $ 7 25,178 -- (907) (164) (218) 5,621 29,517 =================================================================================================================================
See Notes to Consolidated Financial Statements. 88 -------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS CONOCOPHILLIPS NOTE 1--ACCOUNTING POLICIES o CONSOLIDATION PRINCIPLES AND INVESTMENTS--Majority-owned, controlled subsidiaries are consolidated. The equity method is used to account for investments in affiliates in which the company exerts significant influence, generally having a 20 to 50 percent ownership interest. The company also uses the equity method for its 50.1 percent and 57.1 percent non-controlling interests in Petrozuata C.A. and Hamaca Holding LLC, respectively, located in Venezuela because the minority shareholders have substantive participating rights, under which all substantive operating decisions (e.g., annual budgets, major financings, selection of senior operating management, etc.) require joint approvals. Undivided interests in oil and gas joint ventures, pipelines, natural gas plants, certain transportation assets and Canadian Syncrude mining operations are consolidated on a proportionate basis. Other securities and investments, excluding marketable securities, are generally carried at cost. o REVENUE RECOGNITION--Revenues associated with sales of crude oil, natural gas, natural gas liquids, petroleum and chemical products, and all other items are recorded when title passes to the customer. Revenues include the sales portion of contracts involving purchases and sales necessary to reposition supply to address location or quality or grade requirements (e.g., when the company repositions crude by entering into a contract with a counterparty to sell crude in one location and purchase it in a different location) and sales related to purchase for resale activity. Revenues from the production of natural gas properties in which the company has an interest with other producers are recognized based on the actual volumes sold by the company during the period. Any differences between volumes sold and entitlement volumes, based on the company's net working interest, which are deemed non-recoverable through remaining production, are recognized as accounts receivable or accounts payable, as appropriate. Cumulative differences between volumes sold and entitlement volumes are not significant. Revenues associated with royalty fees from licensed technology are recorded based either upon volumes produced by the licensee or upon the successful completion of all substantive performance requirements related to the installation of licensed technology. o RECLASSIFICATION--Certain amounts in the 2001 and 2000 financial statements have been reclassified to conform with the 2002 presentation. o USE OF ESTIMATES--The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Actual results could differ from the estimates and assumptions used. o CASH EQUIVALENTS--Cash equivalents are highly liquid short-term investments that are readily convertible to known amounts of cash and have original maturities within three months from their date of purchase. They are carried at cost plus accrued interest, which approximates fair value. o INVENTORIES--The company has several valuation methods for its various types of inventories and consistently uses the following methods for each type of inventory. Crude oil, petroleum products, and Canadian Syncrude inventories are valued at the lower of cost or market in the aggregate, primarily on the last-in, first-out (LIFO) basis. Any necessary lower-of-cost-or-market write-downs are recorded as permanent adjustments to the LIFO cost basis. LIFO is used to better match current inventory costs with current revenues and to meet tax-conformity requirements. Materials, supplies and other miscellaneous inventories are valued using the weighted-average-cost method, consistent 89 with general industry practice. Merchandise inventories at the company's retail marketing outlets are valued using the first-in, first-out (FIFO) retail method, consistent with general industry practice. o DERIVATIVE INSTRUMENTS--All derivative instruments are recorded on the balance sheet at fair value in either accounts and notes receivable, other assets, accounts payable, or other liabilities and deferred credits. Recognition of the gain or loss that results from recording and adjusting a derivative to fair value depends on the purpose for issuing or holding the derivative. Gains and losses from derivatives that are not used as hedges are recognized immediately in earnings. For derivative instruments that are designated and qualify as a fair value hedge, the gains or losses from adjusting the derivative to its fair value will be immediately recognized in earnings and, to the extent the hedge is effective, offset the concurrent recognition of changes in the fair value of the hedged item. Gains or losses from derivative instruments that are designated and qualify as a cash flow hedge will be recorded on the balance sheet in accumulated other comprehensive income/(loss) until the hedged transaction is recognized in earnings; however, to the extent the change in the value of the derivative exceeds the change in the anticipated cash flows of the hedged transaction, the excess gains or losses will be recognized immediately in earnings. In the consolidated statement of operations, gains and losses from derivatives that are not directly related to the company's movement of its products are recorded in other income. Gains and losses from derivatives used for other purposes are recorded in either sales and other operating revenues, other income, or purchased crude oil and products, depending on the purpose for issuing or holding the derivative. o OIL AND GAS EXPLORATION AND DEVELOPMENT--Oil and gas exploration and development costs are accounted for using the successful efforts method of accounting. PROPERTY ACQUISITION COSTS--Oil and gas leasehold acquisition costs are capitalized. Leasehold impairment is recognized based on exploratory experience and management's judgment. Upon discovery of commercial reserves, leasehold costs are transferred to proved properties. EXPLORATORY COSTS--Geological and geophysical costs and the costs of carrying and retaining undeveloped properties are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. All exploratory wells are evaluated for economic viability within one year of well completion. Exploratory wells that discover potentially economic reserves that are in areas where a major capital expenditure would be required before production could begin, and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area, remain capitalized as long as the additional exploratory work is under way or firmly planned. DEVELOPMENT COSTS--Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. DEPLETION AND AMORTIZATION--Leasehold costs of producing properties are depleted using the unit-of-production method based on estimated proved oil and gas reserves. Amortization of intangible development costs is based on the unit-of-production method using estimated proved developed oil and gas reserves. 90 o 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. o INTANGIBLE ASSETS OTHER THAN GOODWILL--Intangible assets that have finite useful lives are amortized by the straight-line method over their useful lives. Intangible assets that have indefinite useful lives are not amortized but are tested at least annually for impairment. The company evaluates the remaining useful lives of intangible assets not being amortized each reporting period to determine whether events and circumstances continue to support indefinite useful lives. Intangible assets are considered impaired if the fair value of the intangible asset is lower than cost. The fair value of intangible assets is determined based on quoted market prices in active markets, if available. If quoted market prices are not available, fair value of intangible assets is determined based upon the present values of expected future cash flows using discount rates commensurate with the risks involved in the asset, or upon estimated replacement cost, if expected future cash flows from the intangible asset are not determinable. o GOODWILL--Goodwill is not amortized but is tested at least annually for impairment. If the fair value of a reporting unit is less than the recorded book value of the reporting unit's assets (including goodwill), less liabilities, then a hypothetical purchase price allocation is performed on the reporting unit's assets and liabilities using the fair value of the reporting unit as the purchase price in the calculation. If the amount of goodwill resulting from this hypothetical purchase price allocation is less than the recorded amount of goodwill, the recorded goodwill is written down to the new amount. Reporting units for purposes of goodwill impairment calculations are one level below or at the company's operating segment level. Because quoted market prices are not available for the company's reporting units, the fair value of the reporting units is determined based upon consideration of several factors, including observed market multiples of operating cash flows and net income, the depreciated replacement cost of tangible equipment, and/or the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. o DEPRECIATION AND AMORTIZATION--Depreciation and amortization of properties, plants and equipment on producing oil and gas properties, certain pipeline assets (those which are expected to have a declining utilization pattern), and on Syncrude mining operations are determined by the unit-of-production method. Depreciation and amortization of all other properties, plants and equipment are determined by either the individual-unit-straight-line method or the group-straight-line method (for those individual units that are highly integrated with other units). o IMPAIRMENT OF PROPERTIES, PLANTS AND EQUIPMENT--Properties, plants and equipment used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value through additional amortization or depreciation provisions in the periods in which the determination of impairment is made. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets--generally on a field-by-field basis for exploration and production assets, at an entire complex level for downstream assets or at a site level for retail stores. The fair value of impaired assets is determined based on quoted market prices in active markets, if available, or upon the present values of expected future cash flows using discount rates commensurate with the risks involved in the asset group. Long-lived assets committed by management for disposal within one year are accounted for at the lower of amortized cost or fair value, less cost to sell. 91 The expected future cash flows used for impairment reviews and related fair value calculations are based on estimated future production volumes, prices and costs, considering all available evidence at the date of review. If the future production price risk has been hedged, the hedged price is used in the calculations for the period and quantities hedged. The impairment review includes cash flows from proved developed and undeveloped reserves, including any development expenditures necessary to achieve that production. The price and cost outlook assumptions used in impairment reviews differ from the assumptions used in the Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities. In that disclosure, Statement of Financial Accounting Standards (SFAS) No. 69, "Disclosures about Oil and Gas Producing Activities," requires the use of prices and costs at the balance sheet date, with no projection of future changes in those assumptions. o MAINTENANCE AND REPAIRS--The costs of maintenance and repairs, which are not significant improvements, are expensed when incurred. Effective January 1, 2001, turnaround costs of major producing units are expensed as incurred. Prior to 2001, the estimated turnaround costs of major producing units were accrued in other liabilities over the estimated interval between turnarounds. See Note 2--Extraordinary Items and Accounting Change for further discussion of this change in accounting method. o SHIPPING AND HANDLING COSTS--The company's Exploration and Production segment includes shipping and handling costs in production and operating expenses, while the Refining and Marketing segment records shipping and handling costs in purchased crude oil and products. o ADVERTISING COSTS--Production costs of media advertising are deferred until the first public showing of the advertisement. Advances to secure advertising slots at specific sports, racing or other events are deferred until the event occurs. All other advertising costs are expensed as incurred, unless the cost has benefits which clearly extend beyond the interim period in which the expenditure is made, in which case the advertising cost is deferred and amortized ratably over the interim periods which clearly benefit from the expenditure. By the end of the fiscal year, all such interim deferred advertising costs are fully amortized to expense. o PROPERTY DISPOSITIONS--When complete units of depreciable property are retired or sold, the asset cost and related accumulated depreciation are eliminated, with any gain or loss reflected in income. When less than complete units of depreciable property are disposed of or retired, the difference between asset cost and salvage value is charged or credited to accumulated depreciation. o DISMANTLEMENT, REMOVAL AND ENVIRONMENTAL COSTS--Through December 31, 2002, the estimated undiscounted costs, net of salvage values, of dismantling and removing major oil and gas production and transportation facilities, including necessary site restoration, were accrued using either the unit-of-production or the straight-line method, which was used for certain regional production transportation assets that are expected to have a straight-line utilization pattern. Effective January 1, 2003, the company adopted SFAS No. 143, "Accounting for Asset Retirement Obligations." See Note 27--New Accounting Standards. Environmental expenditures are expensed or capitalized, depending upon their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have future economic benefit, are expensed. Liabilities for these expenditures are recorded on an undiscounted basis (unless acquired in a purchase business acquisition) when environmental assessments or cleanups are probable and the costs can be reasonably estimated. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is probable. 92 o STOCK COMPENSATION--Through December 31, 2002, the company accounted for stock options using the intrinsic value method as prescribed by the 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 SFAS No. 123, "Accounting for Stock-Based Compensation," had been applied) is presented in Note 20--Employee Benefit Plans. Effective January 1, 2003, the company voluntarily adopted SFAS No. 123 prospectively. See Note 20--Employee Benefit Plans. o FOREIGN CURRENCY TRANSLATION--Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in accumulated other comprehensive loss in common stockholders' equity. Foreign currency transaction gains and losses are included in current earnings. Most of the company's foreign operations use their local currency as the functional currency. o INCOME TAXES--Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial-reporting basis and the tax basis of the company's assets and liabilities, except for deferred taxes on income considered to be permanently reinvested in certain foreign subsidiaries and foreign corporate joint ventures. Allowable tax credits are applied currently as reductions of the provision for income taxes. o NET INCOME PER SHARE OF COMMON STOCK--Basic income per share of common stock is calculated based upon the daily weighted-average number of common shares outstanding during the year, including shares held by the Long-Term Stock Savings Plan (LTSSP). Diluted income per share of common stock includes the above, plus "in-the-money" stock options issued under company compensation plans. Treasury stock and shares held by the Compensation and Benefits Trust (CBT) are excluded from the daily weighted-average number of common shares outstanding in both calculations. o 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. NOTE 2--EXTRAORDINARY ITEMS AND ACCOUNTING CHANGE During 2002, the company incurred extraordinary losses totaling $16 million after-tax ($24 million before-tax) on the following items: o the call premium on the early retirement of the company's $250 million 8.86% notes due May 15, 2022; o the redemption of the company's outstanding 8.24% Junior Subordinated Deferrable Interest Debentures due 2036, which triggered the redemption of the $300 million of 8.24% Trust Originated Preferred Securities of Phillips 66 Capital Trust I; and o the call premium on the early retirement of the company's $171 million 7.443% notes due 2004. 93 In 2001, ConocoPhillips incurred an extraordinary loss of $10 million after-tax ($14 million before-tax) attributable to the call premium on the early retirement of its $300 million 9.18% notes due September 15, 2021. Effective January 1, 2001, the company changed its method of accounting for the costs of major maintenance turnarounds from the accrue-in-advance method to the expense-as-incurred method to reflect the impact of a turnaround in the period that it occurs. The new method is preferable because it results in the recognition of costs at the time obligations are incurred. The cumulative effect of this accounting change increased net income in 2001 by $28 million (after reduction for income taxes of $15 million). The pro forma effects of retroactive application of the change in accounting method are presented below:
Millions of Dollars Except Per Share Amounts ------------------------ 2001 2000 ------------------------ Income before extraordinary items $1,643 1,851 Earnings per share Basic 5.61 7.27 Diluted 5.57 7.22 ----------------------------------------------------------------- Net income $1,633 1,851 Earnings per share Basic 5.57 7.27 Diluted 5.54 7.22 -----------------------------------------------------------------
NOTE 3--MERGER OF CONOCO AND PHILLIPS On August 30, 2002, Conoco and Phillips combined their businesses by merging with separate acquisition subsidiaries of ConocoPhillips (the merger). As a result, each company became a wholly owned subsidiary of ConocoPhillips. For accounting purposes, Phillips was treated as the acquirer of Conoco, and ConocoPhillips was treated as the successor of Phillips. Immediately after the closing of the merger, former Phillips stockholders held approximately 56 percent of the outstanding shares of ConocoPhillips common stock, while former Conoco stockholders held approximately 44 percent. ConocoPhillips common stock, listed on the New York Stock Exchange under the symbol "COP," began trading on September 3, 2002. The primary reasons for the merger and the principal factors that contributed to an accounting treatment that resulted in the recognition of goodwill were: o the combination of Conoco and Phillips would create a stronger, major, integrated oil company with the benefits of increased size and scale, improving the stability of the combined business' earnings in varying economic and market climates; o ConocoPhillips would emerge with a global presence in both upstream and downstream petroleum businesses, increasing its overall international presence to over 40 countries while maintaining a strong domestic base; and 94 o combining the two companies' operations would provide significant synergies and related cost savings, and improve future access to capital. The $16 billion purchase price attributed to Conoco for accounting purposes was based on an exchange of Conoco shares for ConocoPhillips common shares. ConocoPhillips issued approximately 293 million shares of common stock and approximately 23.3 million of employee stock options in exchange for 627 million shares of Conoco common stock and 49.8 million Conoco stock options. The common stock was valued at $53.15 per share, which was Phillips' average common stock price over the two-day trading period immediately before and after the November 18, 2001, public announcement of the transaction. The Conoco stock options, the fair value of which was determined using the Black-Scholes option-pricing model, were exchanged for ConocoPhillips stock options valued at $384 million. Transaction-related costs, included in the purchase price, were $82 million. The preliminary allocation of the purchase price to specific assets and liabilities was based, in part, upon an outside appraisal of the fair value of Conoco's assets. Over the next few months ConocoPhillips expects to receive the final outside appraisal of the long-lived assets and conclude the fair value determination of all other Conoco assets and liabilities. Subsequent to completion of the final allocation of the purchase price and the determination of the ultimate asset and liability tax bases, the deferred tax liabilities will also be finalized. The following table summarizes, based on the year-end preliminary purchase price allocation, the fair values of the assets acquired and liabilities assumed as of August 30, 2002:
Millions of Dollars ---------- Cash and cash equivalents $ 1,250 Accounts and notes receivable 2,821 Inventories 1,603 Prepaid expenses and other current assets 324 Investments and long-term receivables 3,074 Properties, plants and equipment (including $300 million of land) 19,269 Goodwill 12,079 Intangibles 661 In-process research and development 246 Other assets 312 ------------------------------------------------------------------------------ Total assets $41,639 ============================================================================== Accounts payable $ 2,879 Notes payable and long-term debt due within one year 3,101 Accrued income and other taxes 1,320 Other accruals 1,543 Long-term debt 8,930 Accrued dismantlement, removal and environmental costs 332 Deferred income taxes 4,073 Employee benefit obligations 1,648 Other liabilities and deferred credits 1,109 Minority interests 648 Common stockholders' equity 16,056 ------------------------------------------------------------------------------ Total liabilities and equity $41,639 ==============================================================================
95 The allocation of the purchase price, as reflected above, has not been adjusted for the U.S. Federal Trade Commission (FTC)-mandated dispositions described in Note 4--Discontinued Operations. Goodwill, land and certain identifiable intangible assets recorded in the acquisition are not subject to amortization, but the goodwill and intangible assets will be tested periodically for impairment as required by SFAS No. 142, "Goodwill and Other Intangible Assets." Of the $661 million allocated to intangible assets, $545 million is assigned to marketing tradenames which are not subject to amortization. Of the remaining value assigned to intangible assets, $66 million assigned to refining technology will be amortized over 11 years and $50 million was allocated to other intangible assets with a weighted-average amortization period of 11 years. ConocoPhillips has not yet determined the assignment of Conoco goodwill to specific reporting units. Currently, Conoco goodwill is being reported as part of the Corporate and Other reporting segment. Of the $12,079 million of goodwill, $4,302 million is attributable to the gross-up required under purchase accounting for deferred taxes. This and the remaining "true" goodwill, or $7,777 million, will ultimately be assigned to reporting units based on the benefits received by the units from the synergies and strategic advantages of the merger. None of the goodwill is deductible for tax purposes. The purchase price allocation included $246 million of in-process research and development costs related to Conoco's natural gas-to-liquids and other technologies. In accordance with Financial Accounting Standards Board (FASB) Interpretation No. 4, "Applicability of FASB Statement No. 2 to Business Combinations Accounted for by the Purchase Method," the value assigned to the research and development activities was charged to production and operating expenses in the Emerging Businesses segment at the date of the consummation of the merger, as these research and development costs had no alternative future use. Merger-related items that reduced ConocoPhillips' 2002 income from continuing operations were:
Millions of Dollars -------------------------- Before-Tax After-Tax -------------------------- Write-off of acquired in-process research and development costs $246 246 Restructuring charges (see Note 5) 422 253 Incremental seismic contract costs 35 22 Transition costs 55 36 ----------------------------------------------------------------------------------------------- Total $758 557 ===============================================================================================
In total, these items reduced 2002 income from continuing operations by $557 million ($1.15 per share on a diluted basis). 96 The following pro forma summary presents information as if the merger had occurred at the beginning of each period presented, and includes the $557 million effect of the merger-related items mentioned above.
Millions of Dollars Except Per Share Amounts --------------------------------- 2002 2001 --------------------------------- Revenues $ 81,433 79,554 Income from continuing operations 918 3,635 Net income (loss) (70) 4,072 Income from continuing operations per share of common stock Basic 1.36 5.39 Diluted 1.34 5.32 Net income (loss) per share of common stock Basic (.10) 6.04 Diluted (.10) 5.97 --------------------------------------------------------------------------------------------------------
During 2001, both Phillips and Conoco entered into other significant transactions that are not reflected in the companies' historical income statements for the full year 2001. The pro forma results have been prepared as if the Phillips' September 14, 2001, acquisition of Tosco Corporation (Tosco) (see Note 6--Acquisition of Tosco Corporation) and Conoco's July 16, 2001, $4.6 billion acquisition of Gulf Canada Resources Limited occurred on January 1, 2001. Gulf Canada Resources Limited was a Canadian-based independent exploration and production company with primary operations in Western Canada, Indonesia, the Netherlands and Ecuador. The pro forma results reflect the following: o recognition of depreciation and amortization based on the preliminary allocated purchase price of the properties, plants and equipment acquired; o adjustment of interest for the amortization of the fair-value adjustment to debt; o cessation of the amortization of deferred gains not recognizable in the purchase price allocation; o accretion of discount on environmental accruals recorded at net present value; and o various other adjustments to conform Conoco's accounting policies to ConocoPhillips'. The pro forma adjustments use estimates and assumptions based on currently available information. Management believes that the estimates and assumptions are reasonable, and that the significant effects of the transactions are properly reflected. The pro forma information does not reflect any anticipated synergies that might be achieved from combining the operations. The pro forma information is not intended to reflect the actual results that would have occurred had the companies been combined during the periods presented. This pro forma information is not intended to be indicative of the results of operations that may be achieved by ConocoPhillips in the future. 97 NOTE 4--DISCONTINUED OPERATIONS During 2002, the company disposed of, or had committed to a plan to dispose of, U.S. retail and wholesale marketing assets, U.S. refining and related assets, and exploration and production assets in the Netherlands. Certain of these planned dispositions were mandated by the FTC as a condition of the merger. For reporting purposes, these operations are classified as discontinued operations, and in Note 26--Segment Disclosures and Related Information, these operations are included in Corporate and Other. Revenues and income (loss) from discontinued operations were as follows:
Millions of Dollars ---------------------------------- 2002 2001 2000 ---------------------------------- Sales and other operating revenues from discontinued operations $ 7,406 2,670 786 ======================================================================================================= Income (loss) from discontinued operations before-tax $(1,387) 47 21 Income tax expense (benefit) (394) 15 7 ------------------------------------------------------------------------------------------------------- Income (loss) from discontinued operations $ (993) 32 14 =======================================================================================================
Major classes of assets and liabilities of discontinued operations held for sale were as follows:
Millions of Dollars ------------------- ASSETS 2002 2001 ------------------- Inventories $ 211 166 Other current assets 136 81 Net properties, plants and equipment 1,178 1,663 Intangibles 23 452 Other assets 57 20 ------------------------------------------------------------------------------------------------------- Assets of discontinued operations $1,605 2,382 ====================================================================================================== LIABILITIES Accounts payable and other current liabilities $ 331 259 Long-term debt 34 35 Accrued dismantlement, removal and environmental costs 86 83 Other liabilities and deferred credits 198 161 ------------------------------------------------------------------------------------------------------ Liabilities of discontinued operations $ 649 538 ======================================================================================================
In the fourth quarter of 2002, ConocoPhillips concluded a strategic business review of its company-owned retail sites. The review included quantitative and qualitative measures and identified 3,200 retail sites throughout the United States that did not fit the company's long-range plans. The assets are being actively marketed by an investment banking firm. The retail sites are being grouped and marketed in packages, including the planned sale of the company's Circle K Corporation subsidiary. Discussions are under way with potential buyers, and the company expects to complete the sales in 2003. 98 In connection with the anticipated sale of these retail sites, ConocoPhillips recorded charges totaling $1,412 million before-tax, $1,008 million after-tax, primarily related to the impairment of properties, plants and equipment ($249 million); goodwill ($257 million); intangible asset ($429 million); and provisions for losses and penalties associated with various operating lease commitments ($477 million). The intangible asset represents the Circle K tradename. Properties, plants and equipment include land, buildings and equipment of owned retail sites and leasehold improvements of leased sites. Fair value determinations were based on estimated sales prices for comparable sites. The provisions for losses and penalties associated with various operating lease commitments include obligations for residual value guarantee deficiencies, and future minimum rental payments that existed prior to the commitment date that will continue after the exit plan is completed with no economic benefit. It also includes penalties incurred to cancel the contractual arrangements. An additional $130 million of lease loss provisions ($85 million after-tax) will be recognized in 2003 as the company continues to operate the sites until sold. As a condition to the merger of Conoco and Phillips, the FTC required that the company divest the following assets: o Phillips' Woods Cross business unit, which includes the Woods Cross, Utah, refinery and associated motor fuel marketing operations (both retail and wholesale) in Utah, Idaho, Wyoming, and Montana, as well as Phillips' 50 percent interests in two refined products terminals in Boise and Burley, Idaho; o Conoco's Commerce City, Colorado, refinery and related crude oil pipelines; o Phillips' Colorado motor fuel marketing operations (both retail and wholesale); o Phillips' refined products terminal in Spokane, Washington; o Phillips' propane terminal assets at Jefferson City, Missouri, and East St. Louis, Illinois, which include the propane portions of these terminals and the customer relationships and contracts for the supply of propane therefrom; o certain of Conoco's midstream natural gas gathering and processing assets in southeast New Mexico; and o certain of Conoco's midstream natural gas gathering assets in West Texas. Further, the FTC required that certain of these assets be held separately within ConocoPhillips, under the management of a trustee until sold. In connection with these anticipated sales, ConocoPhillips recorded an impairment of $113 million before-tax, $69 million after-tax, related to the Phillips assets in the third quarter of 2002. In the fourth quarter of 2002, ConocoPhillips agreed to sell its Woods Cross business unit for $25 million, subject to an adjustment for certain pension obligations and the value of crude oil, refined products and other inventories. Also in the fourth quarter, the company sold its propane terminal assets at Jefferson City, Missouri, and East St. Louis, Illinois. The sales amounts did not differ significantly from the fair-value estimates used in the third quarter impairment calculations. Sale of the Colorado assets and the midstream assets is expected to occur in 2003. The company's Netherlands exploration and production assets were sold in the fourth quarter of 2002. No gain or loss was recognized on the sale, as these assets were recorded at fair value in the Conoco purchase price allocation. 99 NOTE 5--RESTRUCTURING As a result of the merger, the company implemented a restructuring program in September 2002 to capture the synergies of combining the two companies. In connection with this program, the company recorded accruals totaling $770 million for anticipated employee severance payments, incremental pension and medical plan benefit costs associated with the work force reductions, site closings, and Conoco employee relocations. Of the total accrual, $337 million is reflected in the Conoco purchase price allocation as an assumed liability, and $422 million ($253 million after-tax) related to Phillips is reflected in selling, general and administrative expense and production and operating expense, and $11 million before-tax is included in discontinued operations. Included in the total accruals of $770 million was $172 million related to pension and other post-retirement benefits that will be paid in conjunction with other retirement benefits over a number of future years. The table below summarizes the balance of the accrual of $598 million, which consists of severance related benefits to be provided to approximately 2,900 employees worldwide and other merger related expenses. By the end of 2002, approximately 775 employees had been terminated. Changes in the severance related accrual balance are summarized below.
Millions of Dollars ---------------------------------------------------------- 2002 Reserve at Accruals Benefit Payments December 31, 2002 -------- ---------------- ----------------- Conoco $297* (191) 106 Phillips 301 (32) 269 ---------------------------------------------------------------------------------- Total $598 (223) 375 ==================================================================================
*Purchase price adjustment. The ending accrual balance is expected to be extinguished within one year, except for $37 million, which is classified as long-term. NOTE 6--ACQUISITION OF TOSCO CORPORATION On September 14, 2001, Tosco was merged with a subsidiary of ConocoPhillips, as a result of which ConocoPhillips became the owner of 100 percent of the outstanding common stock of Tosco. Tosco's results of operations have been included in ConocoPhillips' consolidated financial statements since that date. Tosco's operations included seven U.S. refineries with a total crude oil capacity of 1.31 million barrels per day; one 75,000-barrel-per-day refinery located in Cork, Ireland; and various marketing, transportation, distribution and corporate assets. The primary reasons for ConocoPhillips' acquisition of Tosco, and the primary factors that contributed to a purchase price that resulted in recognition of goodwill, are: o the Tosco operations would deliver earnings prospects, and potential strategic and other benefits; o combining the two companies' operations would provide significant cost savings; o adding Tosco to ConocoPhillips' Refining and Marketing (R&M) operations would give the segment the size, scale and resources to compete more effectively; 100 o the merger would transform ConocoPhillips into a stronger, more integrated oil company with the benefits of increased size and scale, improving the stability of the combined business' earnings in varying economic and market climates; o the combined company would have a stronger balance sheet, improving its access to capital in the future; and o the increased cash flow and access to capital resulting from the Tosco acquisition would allow ConocoPhillips to pursue other opportunities in the future. Based on an exchange ratio of 0.8 shares of ConocoPhillips common stock for each Tosco share, ConocoPhillips issued approximately 124.1 million common shares and 4.7 million vested employee stock options in the exchange, which increased common stockholders' equity by approximately $7 billion. The common stock was valued at $55.50 per share, which was ConocoPhillips' average common stock price over the two-day trading period before and after the February 4, 2001, public announcement of the transaction. The employee stock options were valued using the Black-Scholes option pricing model, based on assumptions prevalent at the February 2001 announcement date. The allocation of the purchase price to specific assets and liabilities was based, in part, upon an outside appraisal of Tosco's long-lived assets. Goodwill and indefinite-lived intangible assets recorded in the acquisition are not subject to amortization, but the goodwill and intangible assets will be tested periodically for impairment as required by SFAS No. 142, "Goodwill and Other Intangible Assets." During the third quarter of 2002, the company concluded: o the outside appraisal of the long-lived assets; o the determination of the fair value of all other Tosco assets and liabilities; o the tax basis calculation of Tosco's assets and liabilities and the related deferred tax liabilities; and o the allocation of Tosco goodwill to reporting units within the R&M operating segment. The resulting adjustments to the purchase price allocation made in 2002 increased goodwill by $341 million. The more significant adjustments to goodwill were a $247 million reduction in the value of refinery air emission permits to reflect a more appropriate appraisal methodology, a $70 million liability recorded for Tosco Long-Term Incentive Plan performance units, and a $69 million increase in deferred tax liabilities, resulting primarily from an updated analysis of the tax bases of Tosco's assets and liabilities. All other adjustments in the aggregate reduced goodwill by $45 million. Tosco Long-Term Incentive Plan performance units were derivative financial instruments tied to ConocoPhillips' stock price and were marked-to-market each reporting period. The resulting gains or losses from these mark-to-market adjustments were reported in other income in the consolidated statement of operations. In October 2002, the company and former Tosco executives negotiated a complete cancellation of the performance units in exchange for a cash payment to the former executives. During 2002, the company recorded gains totaling $38 million, after-tax, as this liability was marked-to-market each reporting period and eventually settled. 101 The following table summarizes, based on the final purchase price allocation described above, the fair values of the assets acquired and liabilities assumed as of September 14, 2001:
Millions of Dollars ---------- Cash and cash equivalents $ 103 Accounts and notes receivable 718 Inventories 1,965 Prepaid expenses and other current assets 154 Investments and long-term receivables 150 Properties, plants and equipment (including $1,720 million of land) 7,681 Goodwill 2,644 Intangibles 1,003 Other assets 11 ---------------------------------------------------------------------------------------------- Total assets $14,429 ============================================================================================== Accounts payable $ 1,917 Accrued income and other taxes 350 Other accruals 206 Long-term debt 2,135 Accrued environmental costs 332 Deferred income taxes 1,824 Employee benefit obligations 177 Other liabilities and deferred credits 408 Common stockholders' equity 7,080 ---------------------------------------------------------------------------------------------- Total liabilities and equity $14,429 ==============================================================================================
Of the $1,003 million allocated to intangible assets, marketing tradenames comprised $655 million, refinery air emission and operating permits totaled $315 million and other miscellaneous intangible assets amounted to $33 million. The $1,003 million of intangible assets included $992 million allocated to indefinite-lived intangible assets not subject to amortization and $11 million allocated to intangible assets with a weighted-average amortization period of seven years. In late 2002, the Circle K tradename ($429 million) was included with the retail marketing operations that are held for sale at December 31, 2002, and included in the loss on disposal. See Note 4--Discontinued Operations. ConocoPhillips finalized the required assignment of Tosco goodwill to specific reporting units in 2002, with $1,944 million assigned to the refining reporting unit and $700 million assigned to the marketing reporting unit. The goodwill was assigned to the reporting units that were deemed to have benefited from the synergies and strategic advantages of the merger. In late 2002, $257 million of goodwill assigned to the marketing reporting unit was allocated to the retail marketing operations held for sale at December 31, 2002, and included in the loss on disposal. See Note 4--Discontinued Operations. 102 NOTE 7--INVENTORIES Inventories at December 31 were:
Millions of Dollars ------------------- 2002 2001 ------------------- Crude oil and petroleum products $3,395 2,231 Canadian Syncrude (from mining operations) 4 -- Materials, supplies and other 446 221 --------------------------------------------------------------------------- $3,845 2,452 ===========================================================================
Inventories valued on a LIFO basis totaled $3,349 million and $2,211 million at December 31, 2002 and 2001, respectively. The remainder of the company's inventories are valued under various other methods, including FIFO and weighted average. The excess of current replacement cost over LIFO cost of inventories amounted to $1,083 million and $2 million at December 31, 2002 and 2001, respectively. In the fourth quarter of 2001, the company recorded a $42 million before-tax, $27 million after-tax, lower-of-cost-or-market write-down of its petroleum products inventory. During 2000, certain inventory quantity reductions caused a liquidation of LIFO inventory values. This liquidation increased net income by $63 million, of which $60 million was attributable to ConocoPhillips' R&M segment. NOTE 8--INVESTMENTS AND LONG-TERM RECEIVABLES Components of investments and long-term receivables at December 31 were:
Millions of Dollars ------------------- 2002 2001 ------------------- Investment in and advances to affiliated companies $5,900 2,788 Long-term receivables 526 241 Other investments 395 280 --------------------------------------------------------------------------- $6,821 3,309 ===========================================================================
At December 31, 2002, retained earnings included $825 million related to the undistributed earnings of affiliated companies, and distributions received from affiliates were $313 million, $163 million and $2,180 million in 2002, 2001 and 2000, respectively. EQUITY INVESTMENTS The company owns or owned investments in chemicals, heavy-oil projects, oil and gas transportation, coal mining and other industries. The affiliated companies for which ConocoPhillips uses the equity method of accounting include, among others, the following companies: Chevron Phillips Chemical Company LLC (CPChem) (50 percent), Duke Energy Field Services, LLC (DEFS) (30.3 percent), Petrozuata C.A. (50.1 percent non-controlling interest), Merey Sweeny L.P. (MSLP) (50 percent), Petrovera Resources Limited (46.7 percent), and Hamaca Holding LLC (57.1 percent non-controlling interest). See Note 1--Accounting Policies for additional information. 103 Summarized 100 percent financial information for DEFS, CPChem and all other equity companies accounted for using the equity method follows:
2002 Millions of Dollars ------------------------------------------------- Other Equity DEFS CPChem Companies Total ------- ------- ------------ ------- Revenues $ 5,492 5,473 5,378 16,343 Income (loss) before income taxes (37) (24) 776 715 Net income (loss) (47) (30) 751 674 Current assets 1,123 1,561 5,783 8,467 Noncurrent assets 5,457 4,548 14,386 24,391 Current liabilities 1,426 1,051 4,696 7,173 Noncurrent liabilities 2,504 1,307 10,063 13,874 ----------------------------------------------------------------------------------------
2001 Millions of Dollars ------------------------------------------------- Other Equity DEFS CPChem Companies Total ------- ------- ------------ ------- Revenues $ 8,025 6,010 1,555 15,590 Income (loss) before income taxes 367 (431) 607 543 Net income (loss) 364 (480) 414 298 Current assets 1,165 1,551 689 3,405 Noncurrent assets 5,465 4,309 3,949 13,723 Current liabilities 1,251 820 1,184 3,255 Noncurrent liabilities 2,426 1,606 1,960 5,992 ----------------------------------------------------------------------------------------
2000 Millions of Dollars ------------------------------------------------- Other Equity DEFS* CPChem** Companies Total ------- ------- ------------ ------- Revenues $ 5,099 3,463 3,241 11,803 Income (loss) before income taxes 321 (213) 611 719 Net income (loss) 318 (241) 412 489 ----------------------------------------------------------------------------------------
*For the period April 1, 2000, through December 31, 2000. **For the period July 1, 2000, through December 31, 2000. ConocoPhillips' share of income taxes incurred directly by the equity companies is reported in equity in earnings of affiliates, and as such is not included in income taxes in ConocoPhillips' consolidated financial statements. DUKE ENERGY FIELD SERVICES, LLC On March 31, 2000, ConocoPhillips combined its midstream gas gathering, processing and marketing business with the gas gathering, processing, marketing and natural gas liquids business of Duke Energy Corporation (Duke Energy) forming a new company, DEFS. Duke Energy owns 69.7 percent of the company, which it consolidates, while ConocoPhillips owns 30.3 percent, which it accounts for using the equity method. 104 Duke Energy estimated the fair value of the ConocoPhillips' midstream business at $1.9 billion in its purchase method accounting for the acquisition. The book value of the midstream business contributed to DEFS was $1.1 billion, but no gain was recognized in connection with the transaction because of ConocoPhillips' and CPChem's long-term commitment to purchase the natural gas liquids output from the former ConocoPhillips' natural gas processing plants until December 31, 2014. This purchase commitment is on an "if-produced, will-purchase" basis so it has no fixed production schedule, but has been, and is expected to be, a relatively stable purchase pattern over the term of the contract. Natural gas liquids are purchased under this agreement at various published market index prices, less transportation and fractionation fees. ConocoPhillips' consolidated results of operations include 100 percent of the activity of the gas gathering, processing and marketing business contributed to DEFS through March 31, 2000, and its 30.3 percent share of DEFS' earnings since that date. At December 31, 2002, the book value of ConocoPhillips' common investment in DEFS was $67 million. ConocoPhillips' 30.3 percent share of the net assets of DEFS was $743 million. This basis difference of $676 million, is being amortized on a straight-line basis over 15 years, consistent with the remaining estimated useful lives of the properties, plants and equipment contributed to DEFS. Included in operating results for 2002, 2001 and 2000 was after-tax income of $35 million, $36 million and $27 million, respectively, representing the amortization of the basis difference. On August 4, 2000, DEFS, Duke Energy and ConocoPhillips agreed to modify the Limited Liability Company Agreement governing DEFS to provide for the admission of a class of preferred members in DEFS. Subsidiaries of Duke Energy and ConocoPhillips purchased new preferred member interests for $209 million and $91 million, respectively. The preferred member interests have a 30-year term, will pay a distribution yielding 9.5 percent annually, and contain provisions that require their redemption with any proceeds from an initial public offering. On September 9, 2002, ConocoPhillips received $30 million return of preferred member interest reducing its preferred interest to $61 million. CHEVRON PHILLIPS CHEMICAL COMPANY LLC On July 1, 2000, ConocoPhillips and ChevronTexaco Corporation, as successor to Chevron Corporation (ChevronTexaco), combined their worldwide chemicals businesses, excluding ChevronTexaco's Oronite business, into a new company, CPChem. In addition to contributing the assets and operations included in the company's Chemicals segment, ConocoPhillips also contributed the natural gas liquids business associated with its Sweeny, Texas, complex. ConocoPhillips and ChevronTexaco each own 50 percent of the voting and economic interests in CPChem, and on July 1, 2000, ConocoPhillips began accounting for its investment in CPChem using the equity method. Accordingly, ConocoPhillips' results of operations include 100 percent of the activity of its chemicals business through June 30, 2000, and its 50 percent share of CPChem's earnings since that date. CPChem accounted for the combination using the historical bases of the assets and liabilities contributed by ConocoPhillips and ChevronTexaco. At December 31, 2002, the book value of ConocoPhillips' investment in CPChem was $1,919 million. ConocoPhillips' 50 percent share of the total net assets of CPChem was $1,747 million. This basis difference of $172 million is being amortized over 20 years, consistent with the remaining estimated useful lives of the properties, plants and equipment contributed to CPChem. On July 1, 2002, ConocoPhillips purchased $125 million of Members' Preferred Interests. Preferred distributions are cumulative at 9 percent per annum and will be payable quarterly, upon declaration by CPChem's Board of Directors, from CPChem's cash earnings. The securities have no stated maturity date and are redeemable quarterly, in increments of $25 million, when CPChem's ratio of debt to total capitalization falls below a stated level. The Members' Preferred Interests are also redeemable at CPChem's sole option at any time. 105 NOTE 9--PROPERTIES, PLANTS AND EQUIPMENT, GOODWILL AND INTANGIBLES The company's investment in properties, plants and equipment (PP&E), with accumulated depreciation, depletion and amortization (DD&A), at December 31 was:
Millions of Dollars ---------------------------------------------------------------------------------- 2002 2001 ------------------------------------- ------------------------------------- Gross Net Gross Net PP&E DD&A PP&E PP&E DD&A PP&E ------------------------------------- ------------------------------------- E&P $36,884 8,600 28,284 20,995 7,870 13,125 Midstream 903 16 887 49 34 15 R&M 15,605 2,765 12,840 11,553 2,804 8,749 Chemicals -- -- -- -- -- -- Emerging Businesses 690 5 685 -- -- -- Corporate and Other 477 143 334 493 249 244 ------------------------------------------------------------------------------------------------------------- $54,559 11,529 43,030 33,090 10,957 22,133 =============================================================================================================
Changes in the carrying amount of goodwill are as follows:
Millions of Dollars ---------------------------------------------------------- E&P R&M Corporate Total ---------------------------------------------------------- Balance at December 31, 2000 $ -- -- -- -- Acquired (primarily Tosco acquisition) 15 2,266 -- 2,281 ------------------------------------------------------------------------------------------------------------- Balance at December 31, 2001 15 2,266 -- 2,281 Acquired (merger of Conoco and Phillips)* -- -- 12,079 12,079 Valuation and other adjustments -- 341 -- 341 Allocated to discontinued operations -- (257) -- (257) ------------------------------------------------------------------------------------------------------------- BALANCE AT DECEMBER 31, 2002 $ 15 2,350 12,079 14,444 =============================================================================================================
*Has not yet been allocated to reporting units. Information on the carrying value of intangible assets at December 31 follows:
Millions of Dollars ------------------- 2002 2001 ------------------- AMORTIZED INTANGIBLE ASSETS Refining technology related $ 78 -- Other 44 11 ------------------------------------------------------------------------------------------------------------ $122 11 ============================================================================================================ UNAMORTIZED INTANGIBLE ASSETS Tradenames $669 226 Refinery air and operating permits 315 562 Other 13 62 ------------------------------------------------------------------------------------------------------------ $997 850 ============================================================================================================
106 NOTE 10--IMPAIRMENTS During 2002, 2001 and 2000, the company recognized the following before-tax impairment charges:
Millions of Dollars ---------------------------- 2002 2001 2000 ---------------------------- E&P United States $ 12 3 13 International 37 23 87 R&M Tradenames 102 -- -- Retail site leasehold improvements 26 -- -- ---------------------------------------------------------------------- $177 26 100 ======================================================================
After-tax, the above impairment charges were $115 million in 2002, $25 million in 2001, and $95 million in 2000. The company's E&P segment recognized impairments of $49 million before-tax on four fields in 2002. Impairment of the Janice field in the U.K. North Sea was triggered by its sale, while the Viscount field in the U.K. North Sea was impaired following an evaluation of development drilling results. Sales of properties in Alaska and offshore California resulted in the remaining E&P impairments in 2002. The company initiated a plan in late 2002 to sell a substantial portion of its R&M retail sites. The planned dispositions will result in a reduction of the amount of gasoline volumes marketed under the company's "76" tradename. As a result, the carrying value of the "76" tradename was impaired, with the $102 million impairment determined by an analysis of the discounted cash flows based on the gasoline volumes projected to be sold under the brand name after the planned dispositions, compared with the volumes being sold prior to the dispositions. The company also impaired the carrying value of certain leasehold improvements associated with leased retail sites that are held for use. The impairment was triggered by a review of the leased-site guaranteed residual values and was determined by comparing the guaranteed residual values and leasehold improvements with current market values of the related assets. See Note 4--Discontinued Operations for information regarding the impairments recognized in 2002 in connection with the anticipated sale of certain assets mandated by the FTC, and the planned sale of a substantial portion of the company's retail marketing operations. In the second quarter of 2001, the company committed to a plan to sell its 12.5 percent interest in the Siri oil field, offshore Denmark, triggering a write-down of the field's assets to fair market value. The sale closed in early 2002. The company also recorded a property impairment on a crude oil tanker that was sold in the fourth quarter of 2001. The company recorded an impairment of its Ambrosio field, located in Lake Maracaibo, Venezuela, in 2000. The Ambrosio field exploitation program did not achieve originally premised results. The $87 million impairment charge was based on the difference between the net book value of the property and the discounted value of estimated future cash flows. The remaining property impairments in 2000 were related to fields in the United States, and were prompted by an evaluation of drilling results or negative oil and gas reserve revisions. 107 NOTE 11--ACCRUED DISMANTLEMENT, REMOVAL AND ENVIRONMENTAL COSTS ACCRUED DISMANTLEMENT AND REMOVAL COSTS At December 31, 2002 and 2001, the company had accrued $1,065 million and $776 million, respectively, of dismantlement and removal costs, primarily related to worldwide offshore production facilities and to production facilities in Alaska. The increase in 2002 was primarily due to the merger and increased cost estimates related to production facilities in Alaska. Estimated uninflated total future dismantlement and removal costs at December 31, 2002, were $4,751 million, compared with $2,827 million in 2001. The increase was partially due to the merger. The remaining increase was primarily attributable to changes in future dismantlement and removal cost estimates. These costs are accrued primarily on the unit-of-production method. Pursuant to SFAS No. 143, "Accounting for Asset Retirement Obligations," the accounting for these costs was changed effective January 1, 2003. See Note 27--New Accounting Standards for additional information. ENVIRONMENTAL COSTS Total environmental accruals at December 31, 2002 and 2001, were $743 million and $439 million, respectively. The 2002 increase in accrued environmental costs was primarily the result of the merger. A large portion of these accrued environmental costs were acquired in various business combinations and thus are discounted obligations. For the discounted accruals, expected inflated expenditures are: $112 million in 2003, $71 million in 2004, $58 million in 2005, $54 million in 2006, and $53 million in 2007. Remaining expenditures in all future years after 2007 are expected to total $399 million. These expected expenditures are discounted using a weighted-average 5 percent discount factor, resulting in an accrued balance of $675 million at December 31, 2002. ConocoPhillips had accrued environmental costs, primarily related to cleanup at domestic refineries and underground storage tanks at U.S. service stations, and remediation activities required by the state of Alaska at exploration and production sites formerly owned by Atlantic Richfield Company, of $427 million and $288 million at December 31, 2002 and 2001, respectively. ConocoPhillips had also accrued at Corporate $236 million and $136 million of environmental costs associated with non-operating sites at December 31, 2002 and 2001, respectively. In addition, $70 million and $12 million were included at December 31, 2002 and 2001, respectively, for sites where the company has been named a potentially responsible party under the Federal Comprehensive Environmental Response, Compensation and Liability Act, the Federal Resource Conservation and Recovery Act, or similar state laws. At December 31, 2002 and 2001, $10 million and $3 million, respectively, had been accrued for other environmental litigation. Accrued environmental liabilities will be paid over periods extending up to 30 years. Of the total $1,808 million and $1,215 million of accrued dismantlement, removal and environmental costs at December 31, 2002 and 2001, $142 million and $156 million was classified as a current liability on the balance sheet, under the caption "Other accruals." 108 NOTE 12--DEBT Long-term debt at December 31 was:
Millions of Dollars ------------------------- 2002 2001 ------------------------- 9 3/8% Notes due 2011 $ 350 350 8.86% Notes due 2022 -- 250 8.75% Notes due 2010 1,350 1,350 8.5% Notes due 2005 1,150 1,150 8.49% Notes due 2023 250 250 8.25% Mortgage Bonds due 2003 150 150 8.125% Notes due 2030 600 600 7.92% Notes due 2023 250 250 7.9% Notes due 2047 100 100 7.8% Notes due 2027 300 300 7.68% Notes due 2012 64 -- 7.625% Notes due 2006 240 240 7.25% Notes due 2007 200 200 7.25% Notes due 2031 500 -- 7.20% Notes due 2023 250 250 7.125% Debentures due 2028 300 300 7% Debentures due 2029 200 200 6.95% Notes due 2029 1,900 -- 6.65% Notes due 2003 100 100 6.65% Debentures due 2018 300 300 6.375% Notes due 2009 300 300 6.35% Notes due 2011 1,750 -- 6.35% Notes due 2009 750 -- 5.90% Notes due 2004 1,350 -- 5.90% Notes due 2032 600 -- 5.45% Notes due 2006 1,250 -- 4.75% Notes due 2012 1,000 -- 3.625% Notes due 2007 400 -- Commercial paper and revolving debt due to banks and others through 2006 at 1.46% - 1.94% at year end 2002 1,517 1,081 SRW Cogeneration Limited Partnership 180 -- Floating Rate Notes due 2003 500 -- Industrial Development bonds 153 55 Guarantee of LTSSP bank loan payable at 1.69% at year-end 2002 299 322 Note payable to Merey Sweeny, L.P. at 7% 131 133 Marine Terminal Revenue Refunding Bonds at 2.9% - 3.1% at year-end 2002 265 265 Other notes payable 68 49 -------------------------------------------------------------------------------------------------------- Debt at face value 19,067 8,545 Capitalized leases 23 -- Net unamortized premiums and discounts 676 109 -------------------------------------------------------------------------------------------------------- Total debt 19,766 8,654 Notes payable and long-term debt due within one year (849) (44) -------------------------------------------------------------------------------------------------------- Long-term debt $ 18,917 8,610 ========================================================================================================
109 Maturities inclusive of net unamortized premiums and discounts in 2003 through 2007 are: $849 million (included in current liabilities), $1,438 million, $1,229 million, $3,173 million and $654 million, respectively. The company assumed $12,031 million of debt in connection with the merger. In October 2002, ConocoPhillips entered into two new revolving credit facilities and amended and restated a prior Phillips revolving credit facility to include ConocoPhillips as a borrower. These credit facilities support the company's $4 billion commercial paper program, a portion of which may be denominated in euros (limited to euro 3 billion). The company now has a $2 billion 364-day revolving credit facility expiring on October 14, 2003, and two revolving credit facilities totaling $2 billion expiring in October 2006. Effective with the execution of the new facilities, the previously existing $2.5 billion in Conoco facilities were terminated. At December 31, 2002, ConocoPhillips had no debt outstanding under these credit facilities, but had $1,517 million in commercial paper outstanding, which is supported 100 percent by the long-term credit facilities. This amount approximates fair value. As of December 31, 2002, the company's wholly owned subsidiary, ConocoPhillips Norway, had no outstanding debt under its two $300 million revolving credit facilities expiring in June 2004. Depending on the credit facility, borrowings may bear interest at a margin above rates offered by certain designated banks in the London interbank market or at margins above certificate of deposit or prime rates offered by certain designated banks in the United States. The agreements call for commitment fees on available, but unused, amounts. The agreements also contain early termination rights if the company's current directors or their approved successors cease to be a majority of the Board of Directors. In October 2002, ConocoPhillips privately placed $2 billion of senior unsecured debt securities, consisting of $400 million 3.625% notes due 2007, $1 billion 4.75% notes due 2012, and $600 million 5.90% notes due 2032, in each case fully and unconditionally guaranteed by Conoco and Phillips. The $1,980 million proceeds from the offering were used to reduce commercial paper, retire Conoco's $500 million floating rate notes due October 15, 2002, and for general corporate purposes. ConocoPhillips redeemed the following notes during 2002 and early 2003 and funded the redemptions with commercial paper: o on May 15, 2002, its $250 million 8.86% notes due May 15, 2022, at 104.43 percent, resulting in a second quarter extraordinary loss from the early retirement of debt of $13 million before-tax, $9 million after-tax; o on November 26, 2002, its $171 million 7.443% senior unsecured notes due 2004 resulting in a fourth quarter extraordinary loss from the early retirement of debt of $3 million before-tax, $1 million after-tax; o on January 1, 2003, its $250 million 8.49% notes due January 1, 2023, at 104.245 percent; and o on January 31, 2003, its $181 million SRW Cogeneration Limited Partnership note which was assumed in September 2002 as a result of acquiring its partners' interest in the partnership. 110 At December 31, 2002, $299 million was outstanding under the company's Long-Term Stock Savings Plan (LTSSP) term loan, which will require annual installments beginning in 2008 and continue through 2015. Under this bank loan, any participating bank in the syndicate of lenders may cease to participate on December 5, 2004, by giving not less than 180 days' prior notice to the LTSSP and the company. If participating lenders give the cessation notice, the company plans to resyndicate the loan. Each bank participating in the LTSSP loan has the optional right, if the current company directors or their approved successors cease to be a majority of the Board, and upon not less than 90 days' notice, to cease to participate in the loan. Under the above conditions, such banks' rights and obligations under the loan agreement must be purchased by the company if not transferred to a bank of the company's choice. See Note 20--Employee Benefit Plans for additional discussion of the LTSSP. NOTE 13--SALES OF RECEIVABLES At December 31, 2002, ConocoPhillips sold certain credit card and trade receivables to two Qualifying Special Purpose Entities (QSPEs) in revolving-period securitization arrangements. These arrangements provide for ConocoPhillips to sell, and the QSPEs to purchase, certain receivables and for the QSPEs to then issue beneficial interests of up to $1.5 billion to five bank-sponsored entities. The receivables sold have been sufficiently isolated from ConocoPhillips to qualify for sales treatment. All five bank-sponsored entities are multi-seller conduits with access to the commercial paper market and purchase interests in similar receivables from numerous other companies unrelated to ConocoPhillips. ConocoPhillips has no ownership in any of the bank-sponsored entities and has no voting influence over any bank-sponsored entity's operating and financial decisions. As a result, ConocoPhillips does not consolidate any of these entities. Beneficial interests retained by ConocoPhillips in the pool of receivables held by the QSPEs are subordinate to the beneficial interests issued to the bank-sponsored entities and were measured and recorded at fair value based on the present value of future expected cash flows estimated using management's best estimates concerning the receivables performance, including credit losses and dilution discounted at a rate commensurate with the risks involved to arrive at present value. These assumptions are updated periodically based on actual credit loss experience and market interest rates. ConocoPhillips also retains servicing responsibility related to the sold receivables. The fair value of the servicing responsibility approximates adequate compensation for the servicing costs incurred. ConocoPhillips' retained interest in the sold receivables at December 31, 2002 and 2001, was $1.3 billion and $450 million, respectively. Under accounting principles generally accepted in the United States, the QSPEs are not consolidated by ConocoPhillips. ConocoPhillips retained interest in sold receivables is reported on the balance sheet in accounts and notes receivable--related parties. Total cash flows received from and paid under the securitization arrangements were as follows:
Millions of Dollars ------------------------- 2002 2001 ------------------------- Receivables sold at beginning of year $ 940 500 Conoco receivables sold at August 30, 2002 400 -- Tosco receivables sold at September 14, 2001 -- 614 New receivables sold 18,613 8,907 Cash collections remitted (18,630) (9,081) ------------------------------------------------------------------------------------ Receivables sold at end of year $ 1,323 940 ==================================================================================== Discounts and other fees paid on revolving balances $ 21 24 ------------------------------------------------------------------------------------
111 At year-end, ConocoPhillips sold $264 million of receivables under a factoring arrangement. ConocoPhillips also retains servicing responsibility related to the sold receivables. The fair value of the servicing responsibility approximates adequate compensation for the servicing costs incurred. At maturity of the receivables, ConocoPhillips has a recourse obligation to repurchase uncollected receivables. The fair value of this recourse obligation is not significant. NOTE 14--GUARANTEES At December 31, 2002, the company was liable for certain contingent obligations under various contractual arrangements as described below. CONSTRUCTION COMPLETION GUARANTEES o The company has a construction completion guarantee related to debt and bond financing arrangements secured by the Merey Sweeny, L.P. (MSLP) joint-venture project in Texas. The maximum potential amount of future payment under the guarantee, including joint-and-several debt at its gross amount, is estimated to be $418 million assuming that completion certification is not achieved. Of this amount, $209 million is attributable to Petroleos de Venezuela, S.A. (PDVSA), because they are joint-and-severally liable for a portion of the debt. If completion certification is not attained by 2004, the full debt balance is due. The debt is non-recourse to ConocoPhillips upon completion certification. o The company has issued a construction completion guarantee related to debt financing arrangements for the Hamaca Holding LLC joint venture project in Venezuela. The maximum potential amount of future payments under the guarantee is estimated to be $441 million, which could be payable if the full debt financing capacity is utilized and startup and completion of the Hamaca project is not achieved by October 1, 2005. The project financing debt is non-recourse to ConocoPhillips upon startup and completion certification. GUARANTEED RESIDUAL VALUE ON LEASES o The company leases ocean transport vessels, drillships, tank railcars, corporate aircraft, service stations, computers, office buildings, certain refining equipment, and other facilities and equipment. Associated with these leases the company has guaranteed approximately $1,821 million in residual values, which are due at the end of the lease terms. However, those guaranteed amounts would be reduced by the fair market value of the leased assets returned. See Note 19--Non-Mineral Leases. GUARANTEES OF JOINT-VENTURE DEBT o At December 31, 2002, ConocoPhillips had guarantees of about $355 million outstanding for its portion of joint-venture debt obligations. Of that amount, $176 million is associated with the Polar Lights Company joint-venture project in Russia. Smaller amounts and in some cases debt service reserves are associated with Interconnector (UK) Ltd., Turcas Petrol, Malaysian Refining Company Sdn. Bhd (Melaka), Hydroserve, Excel Paralubes, and Ingleside Cogeneration Limited Partnership. The various debt obligations have terms of up to 24 years. 112 OTHER GUARANTEES o In addition to the construction completion guarantee explained above, the MSLP agreement also requires the partners in the venture to pay cash calls as required to meet minimum operating requirements of the venture, in the event revenues do not cover expenses over the next 18 years. The maximum potential future payments under the agreement are estimated to be $258 million assuming MSLP does not earn any revenue over the entire period. To the extent revenue was generated by the venture, future required payments would be reduced accordingly. o The company has guaranteed certain potential payments related to its interest in two drillships, which are operated by joint ventures. Potential payments could be required for guaranteed residual value amounts and amounts due under interest rate hedging agreements. The maximum potential future payments under the agreements are estimated to be approximately $193 million. o During 2001, the company entered into a letter agreement authorizing the charter, by an unaffiliated third party, of up to four LNG vessels, which included an indemnity by the company in respect of claims for charter hire and other charter payments. The indemnity was subject to certain limitations and was to be applied net of sub-charter rental income and other receipts of the unaffiliated third party. In February 2003, the company entered into new agreements which cancelled the 2001 letter agreement and established separate guarantee facilities for $50 million each for two of the LNG vessels. Under each such facility, the company may be required to make payments should the charter revenue generated by the relevant ship fall below certain specified minimum thresholds, and the company will receive payments to the extent that such revenues exceed those thresholds. The net maximum future payments over the 20 year terms of the agreements could be up to $100 million. In the event the two ships are sold or a total loss occurs, the company also may have recourse to the sales or insurance proceeds to recoup payments made under the guarantee facilities. o Other guarantees, consisting primarily of dealer and jobber loan guarantees to support the company's marketing business, a guarantee supporting a lease assignment on a corporate aircraft and guarantees of lease payment obligations for a joint venture totaled $111 million. These guarantees generally extend up to 15 years and payment would only be required if the dealer, jobber or lessee was in default. INDEMNIFICATIONS o Over the years, the company has entered into various agreements to sell ownership interests in certain corporations and joint ventures. In addition, the company entered into a Tax Sharing Agreement in 1998 related to Conoco's separation from DuPont. These agreements typically include indemnifications for additional taxes determined to be due under the relevant tax law in connection with the company's operations for years prior to the sale or separation. Generally, the obligation extends until the related tax years are closed. The maximum potential amount of future payments under the indemnifications is the amount of additional tax determined to be due under relevant tax law and the various agreements. There are no material outstanding claims that have been asserted under these agreements. o As part of its normal ongoing business operations and consistent with generally accepted and recognized industry practice, ConocoPhillips enters into various agreements with other parties (the Agreements). These Agreements apportion future risks between the parties for the transaction(s) or relationship(s) governed by such Agreements; one method of apportioning risk 113 between the company and the other contracting party is the inclusion of provisions requiring one party to indemnify the other party against losses that might otherwise be incurred by such other party in the future (the Indemnity or Indemnities). Many of the company's Agreements contain an Indemnity or Indemnities that require the company to perform certain obligations as a result of the occurrence of a triggering event or condition. In some instances the company indemnifies third parties against losses resulting from certain events or conditions that arise out of operations conducted by the company's equity affiliates. The nature of these indemnity obligations are diverse and too numerous to list in this disclosure because of the thousands of different Agreements to which the company is a party, each of which may have a different term, business purpose, and triggering events or conditions for an indemnity obligation. Consistent with customary business practice, any particular indemnity obligation incurred by the company is the result of a negotiated transaction or contractual relationship for which the company has accepted a certain level of risk in return for a financial or other type of benefit to the company. In addition, the Indemnity or Indemnities in each Agreement vary widely in their definitions of both the triggering event and the resulting obligation, which is contingent on that triggering event. The company's risk management philosophy is to limit risk in any transaction or relationship to the maximum extent reasonable in relation to commercial and other considerations. Before accepting any indemnity obligation, the company makes an informed risk management decision considering, among other things, the remoteness of the possibility that the triggering event will occur, the potential costs to perform any resulting indemnity obligation, possible actions to reduce the likelihood of a triggering event or to reduce the costs of performing an indemnity obligation, whether the company is in fact indemnified by an unrelated third party, insurance coverage that may be available to offset the cost of the indemnity obligation, and the benefits to the company from the transaction or relationship. Because many or most of the company's indemnity obligations are not limited in duration or potential monetary exposure, the company cannot calculate the maximum potential amount of future payments that could be paid under the company's indemnity obligations stemming from all its existing Agreements. The company has disclosed contractual matters, including, but not limited to, indemnity obligations, which will or could have a material impact on the company's financial performance in quarterly, annual and other reports required by applicable securities laws and regulations. The company also accrues for contingent liabilities, including those arising out of indemnity obligations, when a loss is probable and the amounts can be reasonably estimated (see Note 15--Contingencies). The company is not aware of the occurrence of any triggering event or condition that would have a material adverse impact on the company's financial statements as a result of an indemnity obligation relating to such triggering event or condition. NOTE 15--CONTINGENCIES The company 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; and claims for damages resulting from leaking underground storage tanks, with related toxic tort claims. In the case of all known contingencies, the company accrues an undiscounted liability when the loss is probable and the amount is reasonably estimable. These liabilities are not reduced for potential insurance recoveries. If applicable, undiscounted receivables are accrued for probable insurance or other third-party 114 recoveries. Based on currently available information, the company believes that it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on the company's financial statements. As facts concerning contingencies become known to the company, the company reassesses its position both with respect to accrued liabilities and other potential exposures. Estimates that are particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the unknown magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of the company's liability in proportion to that of other responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes. ENVIRONMENTAL--The company is subject to federal, state and local environmental laws and regulations. These may result in obligations to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various sites. When the company prepares its financial statements, accruals for environmental liabilities are recorded based on management's best estimate using all information that is available at the time. Loss estimates are measured and liabilities are based on currently available facts, existing technology, and presently enacted laws and regulations, taking into consideration the likely effects of inflation and other societal and economic factors. Also considered when measuring environmental liabilities are the company's prior experience in remediation of contaminated sites, other companies' cleanup experience and data released by the U.S. Environmental Protection Agency (EPA) or other organizations. Unasserted claims are reflected in ConocoPhillips' determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable. Although liability of those potentially responsible for environmental remediation costs is generally joint and several for federal sites and frequently so for state sites, the company is usually only one of many companies cited at a particular site. Due to the joint and several liabilities, the company could be responsible for all of the cleanup costs related to any site at which it has been designated as a potentially responsible party. If ConocoPhillips were solely responsible, the costs, in some cases, could be material to its, or one of its segments', operations, capital resources or liquidity. However, settlements and costs incurred in matters that previously have been resolved have not been materially significant to the company's results of operations or financial condition. The company has been successful to date in sharing cleanup costs with other financially sound companies. Many of the sites at which the company is potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess the site conditions, apportion responsibility and determine the appropriate remediation. In some instances, ConocoPhillips may have no liability or attain a settlement of liability. Where it appears that other potentially responsible parties may be financially unable to bear their proportional share, this inability has been considered in estimating the company's potential liability and accruals have been adjusted accordingly. Upon ConocoPhillips' acquisition of Tosco on September 14, 2001, the assumed environmental obligations of Tosco, some of which are mitigated by indemnification agreements, became contingencies reportable on a consolidated basis by ConocoPhillips. Beginning with the acquisition of the Bayway refinery in 1993, but excluding the Alliance refinery acquisition, Tosco negotiated, as part of its acquisitions, environmental indemnification from the former owners for remediating contamination that occurred prior to the respective acquisition dates. Some of the environmental indemnifications are subject to caps and time limits. No accruals have been recorded for any potential contingent liabilities that will be funded by the prior owners under these indemnifications. 115 As part of Tosco's acquisition of Unocal's West Coast petroleum refining, marketing, and related supply and transportation assets in March 1997, Tosco agreed to pay the first $7 million per year of any environmental remediation liabilities at the acquired sites arising out of, or relating to, the period prior to the transaction's closing, plus 40 percent of any amount in excess of $7 million per year, with Unocal paying the remaining 60 percent per year. The indemnification agreement with Unocal has a 25-year term from inception, and, at December 31, 2002, had a maximum cap of $131 million for environmental remediation costs that ConocoPhillips would be required to fund during the remainder of the agreement period. This maximum has been adjusted for amounts paid through December 31, 2002. The company is currently participating in environmental assessments and cleanups at federal Superfund and comparable state sites. After an assessment of environmental exposures for cleanup and other costs, the company makes accruals on an undiscounted basis (except, if assumed in a purchase business combination, such costs are recorded on a discounted basis) for planned investigation and remediation activities for sites where it is probable that future costs will be incurred and these costs can be reasonably estimated. See Note 11--Accrued Dismantlement, Removal and Environmental Costs, for a summary of the company's accrued environmental liabilities. OTHER LEGAL PROCEEDINGS--ConocoPhillips is a party to a number of other legal proceedings pending in various courts or agencies for which, in some instances, no provision has been made. OTHER CONTINGENCIES--ConocoPhillips has contingent liabilities resulting from throughput agreements with pipeline and processing companies. Under these agreements, ConocoPhillips may be required to provide any such company with additional funds through advances and penalties for fees related to throughput capacity not utilized by ConocoPhillips. ConocoPhillips 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, the company has obligations under an international contract to purchase natural gas over a period of up to 17 years. These long-term purchase obligations are at prices in excess of December 31, 2002, quoted market prices. No material annual gain or loss is expected from these long-term commitments. NOTE 16--FINANCIAL INSTRUMENTS AND DERIVATIVE CONTRACTS DERIVATIVE INSTRUMENTS The company and certain of its subsidiaries may use financial and commodity-based derivative contracts to manage exposures to fluctuations in foreign currency exchange rates, commodity prices, and interest rates, or to exploit market opportunities. With the completion of the merger of Phillips and Conoco on August 30, 2002, the derivatives policy adopted during the third quarter of 2001 is no longer in effect; however, the ConocoPhillips Board of Directors has approved an "Authority Limitations" document that prohibits the use of highly leveraged derivatives or derivative instruments without sufficient liquidity for comparable valuations without approval from the Chief Executive Officer. The Authority Limitations document also authorizes the Chief Executive Officer to establish the maximum Value at Risk (VaR) limits for the company. Compliance with these limits is monitored daily. The function of the Risk Management Steering Committee, monitoring the use and effectiveness of derivatives, was assumed by the Chief Financial Officer for risks resulting from foreign currency exchange rates and interest rates, and by the Executive Vice President of Commercial, a new position that reports to the Chief Executive Officer, for commodity price risk. ConocoPhillips' Commercial Group manages commercial marketing, 116 optimizes the commodity flows and positions of the company, monitors related risks of the company's upstream and downstream businesses and selectively takes price risk to add value. SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended (Statement No. 133 or SFAS No. 133), requires companies to recognize all derivative instruments as either assets or liabilities on the balance sheet at fair value. Assets and liabilities resulting from derivative contracts open at December 31, 2002, were $197 million and $206 million, respectively, and appear as accounts and notes receivables, other assets, accounts payable, or other liabilities and deferred credits on the balance sheet. The accounting for changes in fair value (i.e., gains or losses) of a derivative instrument depends on whether it meets the qualifications for, and has been designated as, a SFAS No. 133 hedge, and the type of hedge. At this time, ConocoPhillips is not using SFAS No. 133 hedge accounting for commodity derivative contracts, but the company is using hedge accounting for the interest-rate derivatives noted below. All gains and losses, realized or unrealized, from derivative contracts not designated as SFAS No. 133 hedges have been recognized in the statement of operations. Gains and losses from derivative contracts held for trading not directly related to the company's physical business, whether realized or unrealized, have been reported net in other income. SFAS No. 133 also requires purchase and sales contracts for commodities that are readily convertible to cash (e.g., crude oil, natural gas, and gasoline) to be recorded on the balance sheet as derivatives unless the contracts are for quantities expected to be used or sold by the company over a reasonable period in the normal course of business (the normal purchases and normal sales exception), among other requirements, and the company has documented its intent to apply this exception. ConocoPhillips generally applies this exception to eligible purchase and sales contracts; however, the company may elect not to apply this exception (e.g., when another derivative instrument will be used to mitigate the risk of the purchase or sale contract but hedge accounting will not be applied). When this occurs, both the purchase or sales contract and the derivative contract mitigating the resulting risk will be recorded on the balance sheet at fair value in accordance with the preceding paragraphs. INTEREST RATE DERIVATIVE CONTRACTS--On August 30, 2002, the company obtained a number of fixed-to-floating and floating-to-fixed interest rate swaps from the merger. ConocoPhillips designated these swaps as hedges, but by December 31, 2002, all of the fixed-to-floating rate swaps and a portion of the floating- to-fixed rate swaps had been terminated. The floating-to-fixed interest rate swaps still open at December 31, 2002, are as follows:
Millions of Dollars ------------------------- Notional Fair CASH FLOW HEDGES Amount Value -------- ----- Maturing 2006 $ 166 (19) Maturing in less than one year 500 (3) --------------------------------------------------------------------------------
ConocoPhillips generally reports gains, losses, and ineffectiveness from interest rate derivatives on the statement of operations in interest and debt expense; however, when interest rate derivatives are used to hedge the interest component of a lease, the resulting gains and losses are reported on the statement of operations in production and operating expense. No portion of the gain or loss from the swaps designated as interest rate hedges has been excluded from the assessment of hedge ineffectiveness, which was immaterial for the period from August 30 to December 31, 2002. In accordance with the hedge accounting provisions of Statement No. 133, any realized gains or losses from these derivative hedging 117 instruments will be recognized as income or expense in future periods concurrent with the forecasted transactions. The company expects the amount of net unrealized losses from interest rate hedges in accumulated other comprehensive loss at December 31, 2002, that will be reclassified to earnings during the next 12 months to be immaterial. CURRENCY EXCHANGE RATE DERIVATIVE CONTRACTS--During the third quarter of 2001, ConocoPhillips used hedge accounting to record the results of using a forward exchange contract to hedge the exposure to fluctuations in the exchange rate between the U.S. dollar and Brazilian real, resulting from a firm commitment to pay reals to acquire an exploratory lease. The hedge was closed in August 2001, upon payment of the lease bonus. Results from the hedge appear in accumulated other comprehensive loss on the balance sheet and will be reclassified into earnings concurrent with the amortization or write-down of the lease bonus, but no portion of this amount is expected to be reclassified during 2003. No component of the hedge results was excluded from the assessment of hedge effectiveness, and no gain or loss was recorded in the statement of operations from hedge ineffectiveness. After the merger, the company has foreign currency exchange rate risk resulting from operations in over 40 countries. ConocoPhillips does not comprehensively hedge the exposure to currency rate changes, although the company 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. Hedge accounting is not currently being used for any of the company's foreign currency derivatives. COMMODITY DERIVATIVE CONTRACTS--ConocoPhillips operates in the worldwide crude oil, refined product, natural gas, natural gas liquids, and electric power markets and is exposed to fluctuations in the prices for these commodities. These fluctuations can affect the company's revenues as well as the cost of operating, investing, and financing activities. Generally, ConocoPhillips' policy is to remain exposed to market prices of commodity purchases and sales; however, executive management may elect to use derivative instruments to establish longer-term positions to hedge the price risk of the company's equity crude oil and natural gas production, as well as refinery margins. The ConocoPhillips Commercial Group use futures, forwards, swaps, and options in various markets to optimize the value of the company's supply chain, which may move the company's risk profile away from market average prices to accomplish the following objectives: o Balance physical systems. In addition to cash settlement prior to contract expiration, exchange traded futures contracts may also be settled by physical delivery of the commodity, providing another source of supply to meet the company's refinery requirements or marketing demand; o Meet customer needs. Consistent with the company's policy to generally remain exposed to market prices, the company uses swap contracts to convert fixed-price sales contracts, which are often requested by natural gas and refined product consumers, to a floating market price; o Manage the risk to the company's cash flows from price exposures on specific crude oil, natural gas, refined product and electric power transactions; and o Enable the company to use the market knowledge gained from these activities to do a limited amount of trading not directly related to the company's physical business. For the 12 months ended December 31, 2002 and 2001, the gains or losses from this activity were not material to the company's cash flows or income from continuing operations. 118 At December 31, 2002, ConocoPhillips was not using hedge accounting for commodity derivative contracts; however, during the first half of 2002, the company did use hedge accounting for West Texas Intermediate (WTI) crude oil futures designated as fair-value hedges of firm commitments to sell WTI crude oil at Cushing, Oklahoma. The changes in the fair values of the futures and firm commitments have been recognized in income. No component of the futures gain or loss was excluded from the assessment of hedge effectiveness, and the amount recognized in earnings during the year from ineffectiveness was immaterial. CREDIT RISK The company's financial instruments that are potentially exposed to concentrations of credit risk consist primarily of cash equivalents, over-the-counter derivative contracts, and trade receivables. ConocoPhillips' cash equivalents, which are placed in high-quality money market funds and time deposits with major international banks and financial institutions, are generally not maintained at levels material to the company's financial position. The credit risk from the company's over-the-counter derivative contracts, such as forwards and swaps, derives from the counterparty to the transaction, typically a major bank or financial institution. ConocoPhillips closely monitors these credit exposures against predetermined credit limits, including the continual exposure adjustments that result from market movements. Individual counterparty exposure is managed within these limits, and includes the use of cash-call margins when appropriate, thereby reducing the risk of significant non-performance. ConocoPhillips also uses futures contracts, but futures have a negligible credit risk because they are traded on the New York Mercantile Exchange or the International Petroleum Exchange of London Limited. The company's trade receivables result primarily from its petroleum operations and reflect a broad national and international customer base, which limits the company's exposure to concentrations of credit risk. The majority of these receivables have payment terms of 30 days or less, and the company continually monitors this exposure and the creditworthiness of the counterparties. ConocoPhillips does not generally require collateral to limit the exposure to loss; however, ConocoPhillips will sometimes use letters of credit, prepayments, and master netting arrangements to mitigate credit risk with counterparties that both buy from and sell to the company, as these agreements permit the amounts owed by ConocoPhillips to be offset against amounts due to the company. FAIR VALUES OF FINANCIAL INSTRUMENTS The company used the following methods and assumptions to estimate the fair value of its financial instruments: Cash and cash equivalents: The carrying amount reported on the balance sheet approximates fair value. Accounts and notes receivable: The carrying amount reported on the balance sheet approximates fair value. Debt and mandatorily redeemable preferred securities: The carrying amount of the company's floating-rate debt approximates fair value. The fair value of the fixed-rate debt and mandatorily redeemable preferred securities is estimated based on quoted market prices. Swaps: Fair value is estimated based on forward market prices and approximates the net gains and losses that would have been realized if the contracts had been closed out at year-end. When forward market prices are not available, they are estimated using the forward prices of a similar commodity with adjustments for differences in quality or location. 119 Futures: Fair values are based on quoted market prices obtained from the New York Mercantile Exchange or the International Petroleum Exchange of London Limited. Forward-exchange contracts: Fair value is estimated by comparing the contract rate to the forward rate in effect on December 31 and approximates the net gains and losses that would have been realized if the contracts had been closed out at year-end. Certain company financial instruments at December 31 were:
Millions of Dollars ---------------------------------------------- Carrying Amount Fair Value -------------------- ------------------- 2002 2001 2002 2001 -------------------- ------------------- Financial assets Foreign currency derivatives $ 17 -- 17 -- Commodity derivatives 180 5 180 5 Financial liabilities Total debt, excluding capital leases $19,743 8,654 20,844 9,175 Mandatorily redeemable other minority interests and preferred securities 491 650 516 662 Interest rate derivatives 22 -- 22 -- Foreign currency derivatives 4 -- 4 -- Commodity derivatives 180 7 180 7 --------------------------------------------------------------------------------------------------------------------
NOTE 17--PREFERRED STOCK AND OTHER MINORITY INTERESTS COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF PHILLIPS 66 CAPITAL TRUSTS During 1996 and 1997, the company formed two statutory business trusts, Phillips 66 Capital I (Trust I) and Phillips 66 Capital II (Trust II), in which the company owns all common stock. The Trusts were created for the sole purpose of issuing securities and investing the proceeds thereof in an equivalent amount of subordinated debt securities of ConocoPhillips. ConocoPhillips established the two trusts to raise funds for general corporate purposes. On May 31, 2002, ConocoPhillips redeemed all of its outstanding 8.24% Junior Subordinated Deferrable Interest Debentures due 2036 held by Trust I. This triggered the redemption of $300 million of Trust I's 8.24% Trust Originated Preferred Securities at par value, $25 per share. An extraordinary loss of $8 million before-tax, $6 million after-tax, was incurred during the second quarter of 2002 as a result of the redemption. Trust II has outstanding $350 million of 8% Capital Securities (Capital Securities). The sole asset of Trust II is $361 million of the company's 8% Junior Subordinated Deferrable Interest Debentures due 2037 (Subordinated Debt Securities II) purchased by Trust II on January 17, 1997. The Subordinated Debt Securities II are due January 15, 2037, and are redeemable in whole, or in part, at the option of ConocoPhillips, on or after January 15, 2007, at a redemption price of $1,000 per share, plus accrued and unpaid interest. 120 Subordinated Debt Securities II are unsecured obligations of ConocoPhillips, equal in right of payment but subordinate and junior in right of payment to all present and future senior indebtedness of ConocoPhillips. The subordinated debt securities and related income statement effects are eliminated in the company's consolidated financial statements. When the company redeems the Subordinated Debt Securities II, Trust II is required to apply all redemption proceeds to the immediate redemption of the Capital Securities. ConocoPhillips fully and unconditionally guarantees Trust II's obligations under the Capital Securities. OTHER MANDATORILY REDEEMABLE MINORITY INTERESTS The minority limited partner in Conoco Corporate Holdings L.P. is entitled to a cumulative annual 7.86 percent priority return on its investment. The net minority interest in Conoco Corporate Holdings held by the limited partner was $141 million at December 31, 2002, and is mandatorily redeemable in 2019 or callable without penalty beginning in the fourth quarter of 2004. OTHER MINORITY INTERESTS The minority interest owner in Ashford Energy Capital S.A. is entitled to a cumulative annual preferred return on its investment, based on three-month LIBOR rates plus 1.27 percent. The preferred return at December 31, 2002, was 2.70 percent. At December 31, 2002, the minority interest was $504 million. In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities," and later in 2003, the FASB is expected to issue SFAS No. 149, "Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity." The company is evaluating these new pronouncements to determine whether the above items currently presented in the mezzanine section of the balance sheet will be required to be presented as debt or equity on the balance sheet. See Note 27--New Accounting Standards and Note 28--Variable Interest Entities for more information. PREFERRED STOCK ConocoPhillips has 500 million shares of preferred stock authorized, par value $.01 per share, none of which was issued or outstanding at December 31, 2002. NOTE 18--PREFERRED SHARE PURCHASE RIGHTS ConocoPhillips' Board of Directors authorized and declared a dividend of one preferred share purchase right for each common share outstanding, and authorized and directed the issuance of one right per common share for any newly issued shares. The rights, which expire June 30, 2012, will be exercisable only if a person or group acquires 15 percent or more of the company's common stock or commences a tender offer that would result in ownership of 15 percent or more of the common stock. Each right would entitle stockholders to buy one one-hundredth of a share of preferred stock at an exercise price of $300. In addition, the rights enable holders to either acquire additional shares of ConocoPhillips common stock or purchase the stock of an acquiring company at a discount, depending on specific circumstances. The company may redeem the rights in whole, but not in part, for one cent per right. 121 NOTE 19--NON-MINERAL LEASES The company leases ocean transport vessels, railroad tank cars, corporate aircraft, service stations, computers, office buildings and other facilities and equipment. Certain leases include escalation clauses for adjusting rentals to reflect changes in price indices, as well as renewal options and/or options to purchase the leased property for the fair market value at the end of the lease term. There are no significant restrictions on ConocoPhillips imposed by the leasing agreements in regards to dividends, asset dispositions or borrowing ability. Leased assets under capital leases were not significant in any period presented. ConocoPhillips has leasing arrangements with several special purpose entities (SPEs) that are third-party trusts established by a trustee and funded by financial institutions. Other than the leasing arrangement, ConocoPhillips has no other direct or indirect relationship with the trusts or their investors. Each SPE from which ConocoPhillips leases assets is funded by at least 3 percent substantive third-party residual equity capital investment, which is at-risk during the entire term of the lease. ConocoPhillips does have various purchase options to acquire the leased assets from the SPEs at the end of the lease term, but those purchase options are not required to be exercised by ConocoPhillips. See Note 28--Variable Interest Entities, for a discussion of how the accounting for certain leasing arrangements with SPEs may change in 2003. In connection with the committed plan to sell a major portion of the company's owned retail stores, the company plans to exercise purchase option provisions of various operating leases during 2003 involving approximately 900 store sites and two office buildings. Depending upon the timing of when the company adopts FASB Interpretation No. 46, "Consolidation of Variable Interest Entities," and the determination of whether or not the lessor entities in these leases are variable interest entities, some or all of these lessor entities could become consolidated subsidiaries of the company prior to the exercise of the purchase options. See Note 27--New Accounting Standards, and Note 28--Variable Interest Entities, for additional information on FASB Interpretation No. 46. At December 31, 2002, future minimum rental payments due under non-cancelable leases, including those associated with discontinued operations, were:
Millions of Dollars ---------- 2003 $ 649 2004 546 2005 479 2006 425 2007 367 Remaining years 1,635 ------------------------------------------------------------------------------- Total 4,101 Less income from subleases 641* ------------------------------------------------------------------------------- Net minimum operating lease payments $3,460 ===============================================================================
*Includes $164 million related to railroad cars subleased to CPChem, a related party. 122 The above amounts exclude guaranteed residual value payments, including those associated with discontinued operations, totaling $196 million in 2003, $219 million in 2004, $827 million in 2005, $145 million in 2006, and $434 million in the remaining years, due at the end of lease terms, which would be reduced by the fair market value of the leased assets returned. See Note 4--Discontinued Operations regarding the company's commitment to exit certain retail sites and the related accrual for probable deficiencies under the residual value guarantees. The company also expects to recognize probable guaranteed residual value deficiencies associated with certain retail sites included in continuing operations. The company plans to exercise its purchase options under these leases in 2003, resulting in the recognition of a $142 million, $92 million after-tax, loss. ConocoPhillips has agreements with a shipping company for the long-term charter of five crude oil tankers that are currently under construction. The charters will be accounted for as operating leases upon delivery, which is expected in the third and fourth quarters of 2003. If the completed tankers are not delivered to ConocoPhillips before specified dates in 2004, the chartering commitments are cancelable by ConocoPhillips. Upon delivery, the base term of the charter agreements is 12 years, with certain renewal options by ConocoPhillips. ConocoPhillips has options to cancel the charter agreements at any time, including during construction or after delivery. After delivery, if ConocoPhillips were to exercise its cancellation options, the company's maximum commitment for the five tankers together would be $92 million. If ConocoPhillips does not exercise its cancellation options, the total operating lease commitment over the 12-year term for the five tankers would be $383 million on an estimated bareboat basis. Operating lease rental expense for the years ended December 31 was:
Millions of Dollars ---------------------------------- 2002 2001 2000 ---------------------------------- Total rentals* $541 271 128 Less sublease rentals 21 22 2 -------------------------------------------------------------------------------- $520 249 126 ================================================================================
*Includes $12 million of contingent rentals in 2002. Contingent rentals in 2001 and 2000 were not significant. 123 NOTE 20--EMPLOYEE BENEFIT PLANS PENSION AND POSTRETIREMENT PLANS An analysis of the projected benefit obligations for the company's pension plans and accumulated benefit obligations for its postretirement health and life insurance plans follows:
Millions of Dollars ------------------------------------------------------------------- Pension Benefits Other Benefits ------------------------------------------- ------------------- 2002 2001 2002 2001 ------------------- ------------------- ------- ------- U.S. INT'L. U.S. Int'l. ------- ------- ------- ------- CHANGE IN BENEFIT OBLIGATION Benefit obligation at January 1 $ 1,432 417 991 386 239 140 Service cost 75 32 40 15 9 4 Interest cost 133 48 82 24 31 11 Plan participant contributions -- 2 -- 1 15 11 Plan amendments (12) -- 6 -- 133 21 Actuarial (gain) loss 205 (21) 161 8 31 14 Acquisitions 1,349 908 277 -- 509 68 Benefits paid (159) (23) (131) (12) (47) (31) Curtailment (36) -- -- (2) (4) -- Recognition of termination benefits 92 3 6 5 3 1 Foreign currency exchange rate change -- 135 -- (8) -- -- ----------------------------------------------------------------------------------------------------------------------------------- Benefit obligation at December 31 $ 3,079 1,501 1,432 417 919 239 =================================================================================================================================== Accumulated benefit obligation portion of above at December 31 $ 2,455 1,325 1,121 345 =========================================================================================================== CHANGE IN FAIR VALUE OF PLAN ASSETS Fair value of plan assets at January 1 $ 732 381 696 401 21 20 Actual return on plan assets (85) (74) (91) (19) (5) 2 Acquisitions 600 594 166 -- -- 4 Company contributions 145 39 92 18 27 15 Plan participant contributions -- 2 -- 1 15 11 Benefits paid (159) (21) (131) (12) (47) (31) Foreign currency exchange rate change -- 106 -- (8) -- -- ----------------------------------------------------------------------------------------------------------------------------------- Fair value of plan assets at December 31 $ 1,233 1,027 732 381 11 21 ===================================================================================================================================
124
Millions of Dollars ------------------------------------------------------------------- Pension Benefits Other Benefits ------------------------------------------- ------------------- 2002 2001 2002 2001 ------------------- ------------------- ------- ------- U.S. INT'L. U.S. Int'l. ------- ------- ------- ------- FUNDED STATUS Excess obligation $(1,846) (474) (700) (36) (908) (218) Unrecognized net actuarial loss 697 171 418 61 60 30 Unrecognized prior service cost 30 5 57 7 131 18 ----------------------------------------------------------------------------------------------------------------------------------- Total recognized amount in the consolidated balance sheet $(1,119) (298) (225) 32 (717) (170) =================================================================================================================================== Components of above amount: Prepaid benefit cost $ -- 52 5 37 -- -- Accrued benefit liability (1,484) (400) (501) (15) (717) (170) Intangible asset 43 3 57 4 -- -- Accumulated other comprehensive loss 322 47 214 6 -- -- ----------------------------------------------------------------------------------------------------------------------------------- Total recognized $(1,119) (298) (225) 32 (717) (170) =================================================================================================================================== WEIGHTED-AVERAGE ASSUMPTIONS AS OF DECEMBER 31 Discount rate 6.75% 5.85 7.25 6.30 6.75 7.25 Expected return on plan assets 7.05 7.45 8.70 7.60 5.50 5.20 Rate of compensation increase 4.00 3.80 4.00 3.75 4.00 4.00 -----------------------------------------------------------------------------------------------------------------------------------
Pension plan funds are invested in a diversified portfolio of assets. Approximately $198 million held in a participating annuity contract is not available for meeting benefit obligations in the near term. At December 31, 2002, approximately 4,300 shares of company stock were included in plan assets. At December 31, 2001, no company stock was included in plan assets. The company's funding policy for U.S. plans is to contribute at least the minimum required by the Employee Retirement Income Security Act of 1974. Contributions to foreign plans are dependent upon local laws and tax regulations. In 2003, the company expects to contribute approximately $340 million to its domestic qualified pension plans and $50 million to its international qualified pension plans. The funded status of the plans was impacted in 2002 by changes in assumptions used to calculate plan liabilities, the merger of Conoco and Phillips, and negative asset performance. During 2002, the company recorded charges to other comprehensive loss totaling $149 million ($93 million net of tax), resulting in accumulated other comprehensive loss due to minimum pension liability adjustments at December 31, 2002, of $369 million ($236 million net of tax). 125
Millions of Dollars --------------------------------------------------------------------------------------------- Pension Benefits Other Benefits ------------------------------------------------------------ --------------------------- 2002 2001 2000 2002 2001 2000 ---------------- ---------------- ---------------- ----- ----- ----- U.S. INT'L. U.S. Int'l. U.S. Int'l. ----- ----- ----- ----- ----- ------ COMPONENTS OF NET PERIODIC BENEFIT COST Service cost $ 75 32 40 15 32 16 9 4 2 Interest cost 133 48 82 24 75 23 31 11 9 Expected return on plan assets (73) (49) (74) (30) (80) (29) (1) (1) (1) Amortization of prior service cost 5 2 6 1 5 1 8 (1) (3) Recognized net actuarial loss (gain) 48 7 16 -- (5) -- 3 2 1 Amortization of net asset -- -- -- (1) (7) -- -- -- -- ----------------------------------------------------------------------------------------------------------------------------------- Net periodic benefit cost $ 188 40 70 9 20 11 50 15 8 ===================================================================================================================================
The company recorded curtailment losses of $23 million and $1 million in 2002 and 2000, respectively, and a curtailment gain of $2 million in 2001. The company recorded settlement losses of $10 million in 2001. In determining net pension and other postretirement benefit costs, ConocoPhillips has elected to amortize net gains and losses on a straight-line basis over 10 years. Prior service cost is amortized on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plan. For the company's tax-qualified pension plans with projected benefit obligations in excess of plan assets, the projected benefit obligation, the accumulated benefit obligation, and the fair value of plan assets were $4,288 million, $3,542 million, and $2,259 million at December 31, 2002, respectively, and $1,519 million, $1,211 million, and $886 million at December 31, 2001, respectively. For the company's unfunded non-qualified supplemental key employee pension plans, the projected benefit obligation and the accumulated benefit obligation were $260 million and $206 million, respectively, at December 31, 2002, and were $109 million and $76 million, respectively, at December 31, 2001. The company has multiple non-pension postretirement benefit plans for health and life insurance. The health care plans are contributory, with participant and company contributions adjusted annually; the life insurance plans are non-contributory. For most groups of retirees, any increase in the annual health care escalation rate above 4.5 percent is borne by the participant. The weighted-average health care cost trend rate for those participants not subject to the cap is assumed to decrease gradually from 10 percent in 2003 to 5 percent in 2009. 126 The assumed health care cost trend rate impacts the amounts reported. A one-percentage-point change in the assumed health care cost trend rate would have the following effects on the 2002 amounts:
Millions of Dollars --------------------------- One-Percentage-Point --------------------------- Increase Decrease -------- -------- Effect on total of service and interest cost components $ -- -- Effect on the postretirement benefit obligation 3 3 ---------------------------------------------------------------------------------------
DEFINED CONTRIBUTION PLANS At December 31, 2002, most employees (excluding retail service station employees) were eligible to participate in either the company-sponsored Thrift Plan of Phillips Petroleum Company, the Tosco Corporation Capital Accumulation Plan, or the Thrift Plan for Employees of Conoco Inc. Employees could contribute a portion of their salaries to various investment funds, including a company stock fund, a percentage of which was matched by the company. In addition, eligible participants in the Tosco Corporation Capital Accumulation Plan could receive an additional company contribution in lieu of pension plan benefits. Company contributions charged to expense in total for all three plans were $40 million in 2002, and $14 million in 2001 and $6 million in 2000. The company's Long-Term Stock Savings Plan (LTSSP) was a leveraged employee stock ownership plan. Prior to January 1, 2003, employees eligible for the Thrift Plan of Phillips Petroleum Company could also elect to participate in the LTSSP by contributing 1 percent of their salaries and receiving an allocation of shares of common stock proportionate to their contributions. On January 1, 2003, the Thrift Plan of Phillips Petroleum Company and the Tosco Corporation Capital Accumulation Plan were merged into the LTSSP and the name was changed to the ConocoPhillips Savings Plan (and the LTSSP became known as the Stock Savings Feature within that plan). The ConocoPhillips Savings Plan replaced most features available under the Thrift Plan of Phillips Petroleum Company and the Tosco Corporation Capital Accumulation Plan. In addition to participating in the Thrift Plan for Employees of Conoco Inc., on January 1, 2003, heritage Conoco employees became eligible to participate in the Stock Savings Feature of the ConocoPhillips Savings Plan. In 1990, the LTSSP borrowed funds that were used to purchase previously unissued shares of company common stock. Since the company guarantees the LTSSP's borrowings, the unpaid balance is reported as a liability of the company and unearned compensation is shown as a reduction of common stockholders' equity. Dividends on all shares are charged against retained earnings. The debt is serviced by the LTSSP from company contributions and dividends received on certain shares of common stock held by the plan, including all unallocated shares. The shares held by the LTSSP are released for allocation to participant accounts based on debt service payments on LTSSP borrowings. In addition, during the period from 2003 through 2007, when no debt principal payments are scheduled to occur, the company has committed to make direct contributions of stock to the LTSSP, or make prepayments on LTSSP borrowings, to ensure a certain minimum level of stock allocation to participant accounts. The company recognizes interest expense as incurred and compensation expense based on the fair market value of the stock contributed or on the cost of the unallocated shares released, using the shares-allocated method. The company recognized total LTSSP expense of $39 million, $33 million and $40 million in 2002, 2001 and 2000, respectively, all of which was compensation expense. In 2002, 2001 and 2000, respectively, the company made cash contributions to the LTSSP of $2 million, $17 million and 127 $23 million. In 2002, 2001 and 2000, the company contributed 771,479 shares, 292,857 shares and 508,828 shares, respectively, of company common stock from the Compensation and Benefits Trust. The shares had a fair market value of $41 million, $17 million and $24 million, respectively. Dividends used to service debt were $28 million, $28 million and $32 million in 2002, 2001 and 2000, respectively. These dividends reduced the amount of expense recognized each period. Interest incurred on the LTSSP debt in 2002, 2001 and 2000 was $7 million, $17 million and $26 million, respectively. The total LTSSP shares as of December 31 were:
2002 2001 ------------------------------- Unallocated shares 7,717,710 8,379,924 Allocated shares 14,925,443 14,794,203 -------------------------------------------------------------------------------- Total LTSSP shares 22,643,153 23,174,127 ================================================================================
The fair value of unallocated shares at December 31, 2002, and 2001, was $373 million and $505 million, respectively. STOCK-BASED COMPENSATION PLANS Under the company's Omnibus Securities Plan approved by shareholders in 1993, stock options and stock awards for certain employees were authorized for up to eight-tenths of 1 percent (0.8 percent) of the total outstanding shares as of December 31 of the year preceding the awards. Any shares not issued in the current year were available for future grant. Upon the adoption of the 2002 Omnibus Securities Plan discussed below, the number of shares available for issuance under the Omnibus Securities Plan was limited to 700,000. The term of the Omnibus Securities Plan ended on December 31, 2002. In 2001, shareholders approved the 2002 Omnibus Securities Plan, which has a term of five years, from January 1, 2002, through December 31, 2006, and which is authorized to issue approximately 18,000,000 shares of company common stock. The two plans also provided for non-stock-based awards. Shares of company stock awarded under both plans were:
2002 2001 2000 ------------------------------------- Shares 1,090,082 237,849 319,726 Weighted-average fair value $ 57.84 56.23 46.98 --------------------------------------------------------------------------------
Stock options granted under provisions of the plans and earlier plans permit purchase of the company's common stock at exercise prices equivalent to the average market price of the stock on the date the options were granted. The options have terms of 10 years and normally become exercisable in increments of up to one-third on each anniversary date following the date of grant. Stock Appreciation Rights (SARs) may, from time to time, be affixed to the options. Options exercised in the form of SARs permit the holder to receive stock, or a combination of cash and stock, subject to a declining cap on the exercise price. 128 The merger was a change-in-control event that resulted in a lapsing of restrictions on, and payout of, stock and stock option awards under the plans. ConocoPhillips offered to exchange certain stock awards under the plans with new awards in the form of restricted stock units. These new restricted stock units were converted, at the time of the merger, into awards based on the same number of shares of ConocoPhillips common stock. Conoco had several stock-based compensation plans that were assumed in the merger: the 1998 Stock and Performance Incentive Plan; the 1998 Key Employee Stock Performance Plan; the 1998 Global Performance Sharing Plan; and the 2001 Global Performance Sharing Plan. Upon the merger, outstanding stock options under these plans were converted to ConocoPhillips stock options at the merger exchange ratio of 0.4677. The Conoco plans award stock options at exercise prices equivalent to the average market price of the stock on the date the option was granted. Awards have option terms of 10 years and become exercisable based on various formulas, including those that become exercisable one year from date of grant, and those that become exercisable in increments of one-third on each anniversary date following date of grant. In total, there were 16 million shares of company stock at December 31, 2002, available for issuance under the Conoco plans. Stock-based compensation expense recognized by ConocoPhillips in connection with all the plans discussed above was $60 million, $21 million and $23 million in 2002, 2001 and 2000, respectively. Beginning in 2003, ConocoPhillips has elected to use the fair-value accounting method provided for under SFAS No. 123, "Accounting for Stock-Based Compensation." The company will use the prospective transition method provided under SFAS 123, applying the fair-value accounting method and recognizing compensation expense for all stock options granted, modified or settled after December 31, 2002. Employee stock options granted prior to 2003 will continue to be accounted for under APB No. 25, "Accounting for Stock Issued to Employees," and related Interpretations. Because the exercise price of ConocoPhillips employee stock options equals the market price of the underlying stock on the date of grant, no compensation expense is generally recognized under APB No. 25. The following table displays pro forma information as if the provisions of SFAS No. 123 had been applied to employee stock options granted since January 1, 1996:
2002 2001 2000 ------------------------------------ Pro forma net income (loss) in millions $ (358) 1,644 1,850 Pro forma basic income (loss) per share (.74) 5.61 7.27 Pro forma diluted income (loss) per share (.74) 5.57 7.21 ------------------------------------------------------------------------------------ Assumptions used Risk-free interest rate 4.1% 4.5 5.9 Dividend yield 3.0% 2.5 2.5 Volatility factor 26.2% 27.0 26.0 Average grant date fair value of options $ 11.67 23.19 16.00 Expected life (years) 6 5 5 ------------------------------------------------------------------------------------
129 In August 2002, ConocoPhillips issued 23.3 million vested stock options to replace unexercised Conoco stock options at the time of the merger. These options had a weighted-average exercise price of $47.65 per option, and a Black-Scholes option-pricing model value of $16.50 per option. In September 2001, ConocoPhillips issued 4.7 million vested stock options to replace unexercised Tosco stock options at the time of the acquisition. These options had a weighted-average exercise price of $23.15 per option, and a Black-Scholes option-pricing model value of $32.51 per option. A summary of ConocoPhillips' stock option activity follows:
Weighted-Average Options Exercise Price ---------- ---------------- Outstanding at December 31, 1999 9,844,524 $39.84 Granted 1,299,500 61.85 Exercised (1,223,779) 30.79 Forfeited (57,278) 47.06 ------------------------------------------------------------------- ---------------- Outstanding at December 31, 2000 9,862,967 $43.82 Granted (including Tosco exchange) 9,038,571 38.81 Exercised (2,373,062) 22.36 Forfeited (96,126) 60.41 ------------------------------------------------------------------- ---------------- Outstanding at December 31, 2001 16,432,350 $44.06 Granted (including the merger) 28,830,903 48.11 Exercised (2,032,232) 24.66 Forfeited (124,416) 57.78 ------------------------------------------------------------------- ---------------- OUTSTANDING AT DECEMBER 31, 2002 43,106,605 $47.65 =================================================================== ----------------
OUTSTANDING AT DECEMBER 31, 2002
Weighted-Average ------------------------------------------ Exercise Prices Options Remaining Lives Exercise Price ---------------- ---------- --------------- -------------- $ 9.04 TO $31.44 5,067,979 2.18 YEARS $25.06 $31.52 TO $44.91 6,384,431 4.29 YEARS 39.88 $45.75 TO $66.72 31,654,195 7.67 YEARS 52.83 ----------------------------------------------------------------------------------------------
EXERCISABLE AT DECEMBER 31
Weighted-Average Exercise Exercise Prices Options Price --------------- ---------- ---------------- 2002 $ 9.04 TO $31.44 5,067,979 $25.06 $31.52 TO $44.91 6,384,431 39.88 $45.75 TO $66.72 21,614,181 52.17 ---------------------------------------------------------------------------------------------- 2001 $ 9.04 to $31.44 3,056,009 $22.67 $31.52 to $44.91 3,075,354 38.06 $45.75 to $64.43 3,525,616 48.32 ---------------------------------------------------------------------------------------------- 2000 $22.57 to $31.44 1,754,047 $29.42 $32.25 to $44.91 1,674,129 37.49 $45.75 to $62.57 2,029,352 46.46 ----------------------------------------------------------------------------------------------
130 COMPENSATION AND BENEFITS TRUST (CBT) The CBT is an irrevocable grantor trust, administered by an independent trustee and designed to acquire, hold and distribute shares of the company's common stock to fund certain future compensation and benefit obligations of the company. The CBT does not increase or alter the amount of benefits or compensation that will be paid under existing plans, but offers the company enhanced financial flexibility in providing the funding requirements of those plans. ConocoPhillips also has flexibility in determining the timing of distributions of shares from the CBT to fund compensation and benefits, subject to a minimum distribution schedule. The trustee votes shares held by the CBT in accordance with voting directions from eligible employees, as specified in a trust agreement with the trustee. The company sold 29.2 million shares of previously unissued company common stock to the CBT in 1995 for $37 million of cash, previously contributed to the CBT by ConocoPhillips, and a promissory note from the CBT to ConocoPhillips of $952 million. The CBT is consolidated by ConocoPhillips, therefore the cash contribution and promissory note are eliminated in consolidation. Shares held by the CBT are valued at cost and do not affect earnings per share or total common stockholders' equity until after they are transferred out of the CBT. In 2002 and 2001, shares transferred out of the CBT were 771,479 and 292,857, respectively. At December 31, 2002, 26.8 million shares remained in the CBT. All shares are required to be transferred out of the CBT by January 1, 2021. NOTE 21--TAXES Taxes charged to income from continuing operations were:
Millions of Dollars ---------------------------------- 2002 2001 2000 ---------------------------------- TAXES OTHER THAN INCOME TAXES Excise $ 6,246 2,177 1,781 Property 244 148 108 Production 303 328 278 Payroll 99 54 50 Environmental 5 14 12 Other 40 19 13 --------------------------------------------------------------------- $ 6,937 2,740 2,242 ===================================================================== INCOME TAXES Federal Current $ 71 133 470 Deferred 56 426 224 Foreign Current 1,188 842 965 Deferred 114 126 127 State and local Current 57 97 100 Deferred (36) 20 14 --------------------------------------------------------------------- $ 1,450 1,644 1,900 =====================================================================
131 Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for tax purposes. Major components of deferred tax liabilities and assets at December 31 were:
Millions of Dollars -------------------- 2002 2001 -------------------- DEFERRED TAX LIABILITIES Properties, plants and equipment, and intangibles $10,147 4,750 Investment in joint ventures 1,013 522 Inventory 385 212 Other 144 74 -------------------------------------------------------------------------------- Total deferred tax liabilities 11,689 5,558 -------------------------------------------------------------------------------- DEFERRED TAX ASSETS Benefit plan accruals 1,304 450 Accrued dismantlement, removal and environmental costs 724 452 Deferred state income tax 201 164 Other financial accruals and deferrals 311 182 Alternative minimum tax carryforwards 421 180 Operating loss and credit carryforwards 650 310 Other 394 107 -------------------------------------------------------------------------------- Total deferred tax assets 4,005 1,845 Less valuation allowance 608 263 -------------------------------------------------------------------------------- Net deferred tax assets 3,397 1,582 -------------------------------------------------------------------------------- Net deferred tax liabilities $ 8,292 3,976 ================================================================================
Current assets, long-term assets, current liabilities and long-term liabilities included deferred taxes of $68 million, $41 million, $40 million and $8,361 million, respectively, at December 31, 2002, and $47 million, $9 million, $17 million and $4,015 million, respectively, at December 31, 2001. The company has operating loss and credit carryovers in multiple taxing jurisdictions. These attributes generally expire between 2003 and 2009 with some carryovers, including the alternative minimum tax, having indefinite carryforward periods. Valuation allowances have been established for certain operating loss and credit carryforwards that reduce deferred tax assets to an amount that will, more likely than not, be realized. Uncertainties that may affect the realization of these assets include tax law changes and the future level of product prices and costs. Based on the company's historical taxable income, its expectations for the future, and available tax-planning strategies, management expects that the net deferred tax assets will be realized as offsets to reversing deferred tax liabilities and as offsets to the tax consequences of future taxable income. The Conoco purchase price allocation for the merger resulted in net deferred tax liabilities of $4,073 million. Included in this amount is a valuation allowance for certain deferred tax assets of $251 million, for which subsequently recognized tax benefits, if any, will be allocated to goodwill. 132 At December 31, 2002, and December 31, 2001, income considered to be permanently reinvested in certain foreign subsidiaries and foreign corporate joint ventures totaled approximately $569 million and $247 million, respectively. Deferred income taxes have not been provided on this income, as the company does not plan to initiate any action that would require the payment of income taxes. It is not practicable to estimate the amount of additional tax that might be payable on this foreign income if distributed. The amounts of U.S. and foreign income from continuing operations before income taxes, with a reconciliation of tax at the federal statutory rate with the provision for income taxes, were:
Percent of Millions of Dollars Pretax Income ----------------------------- ------------------------------ 2002 2001 2000 2002 2001 2000 ----------------------------- ------------------------------- Income from continuing operations before income taxes United States $ 628 2,080 2,041 29.0% 63.9 54.4 Foreign 1,536 1,175 1,707 71.0 36.1 45.6 ------------------------------------------------------------------------------------------------------------------------ $ 2,164 3,255 3,748 100.0% 100.0 100.0 ======================================================================================================================== Federal statutory income tax $ 757 1,139 1,312 35.0% 35.0 35.0 Foreign taxes in excess of federal statutory rate 680 515 572 31.4 15.8 15.3 Domestic tax credits (77) (84) (53) (3.6) (2.6) (1.4) Write-off of acquired in-process research and development costs 86 -- -- 4.0 -- -- State income tax 14 76 74 .6 2.3 2.0 Other (10) (2) (5) (.4) -- (.2) ------------------------------------------------------------------------------------------------------------------------ $ 1,450 1,644 1,900 67.0% 50.5 50.7 ========================================================================================================================
133 NOTE 22--OTHER COMPREHENSIVE INCOME (LOSS) The components and allocated tax effects of other comprehensive income (loss) follow:
Millions of Dollars ------------------------------------------ Tax Expense Before-Tax (Benefit) After-Tax ------------------------------------------- 2002 Minimum pension liability adjustment $(149) (56) (93) Unrealized loss on securities (3) -- (3) Foreign currency translation adjustments 223 41 182 Hedging activities (1) -- (1) Equity affiliates: Foreign currency translation 40 -- 40 Derivatives related (34) -- (34) --------------------------------------------------------------------------------------- Other comprehensive income $ 76 (15) 91 ======================================================================================= 2001 Minimum pension liability adjustment $(220) (77) (143) Unrealized loss on securities (3) (1) (2) Foreign currency translation adjustments (14) -- (14) Hedging activities (4) -- (4) Equity affiliates: Foreign currency translation (3) -- (3) Derivatives related 17 6 11 --------------------------------------------------------------------------------------- Other comprehensive loss $(227) (72) (155) ======================================================================================= 2000 Unrealized loss on securities $ (2) (1) (1) Foreign currency translation adjustments (53) -- (53) Equity affiliates: Foreign currency translation (15) -- (15) --------------------------------------------------------------------------------------- Other comprehensive loss $ (70) (1) (69) =======================================================================================
See Note 20--Employee Benefit Plans for more information on the minimum pension liability adjustment. Unrealized gains on securities relate to available-for-sale securities held by irrevocable grantor trusts that fund certain of the company's domestic, non-qualified supplemental key employee pension plans. Deferred taxes have not been provided on temporary differences related to foreign currency translation adjustments for investments in certain foreign subsidiaries and foreign corporate joint ventures that are essentially permanent in duration. 134 Accumulated other comprehensive loss in the equity section of the balance sheet included:
Millions of Dollars ---------------------- 2002 2001 ---------------------- Minimum pension liability adjustment $(236) (143) Foreign currency translation adjustments 98 (84) Unrealized gain on securities 1 4 Deferred net hedging loss (5) (4) Equity affiliates: Foreign currency translation 1 (39) Derivatives related (23) 11 ---------------------------------------------------------------------------------------------------------------------------------- Accumulated other comprehensive loss $(164) (255) ==================================================================================================================================
NOTE 23--CASH FLOW INFORMATION
Millions of Dollars ---------------------------------- 2002 2001 2000 ---------------------------------- NON-CASH INVESTING AND FINANCING ACTIVITIES The merger by issuance of stock $15,974 -- -- Acquisition of Tosco by issuance of stock -- 7,049 -- Note payable to purchase properties, plants and equipment -- 25 111 Investment in properties, plants and equipment of businesses through the assumption of non-cash liabilities 181 125 472 Investment in equity affiliates through exchange of non-cash assets and liabilities* -- (15) 4,272 ---------------------------------------------------------------------------------------------------------------------------------- CASH PAYMENTS Interest $ 441 324 323 Income taxes 1,363 1,504 1,066 ----------------------------------------------------------------------------------------------------------------------------------
*On March 31, 2000, ConocoPhillips combined its gas gathering, processing and marketing business with the gas gathering, processing, marketing and natural gas liquids business of Duke Energy into DEFS and on July 1, 2000, ConocoPhillips and ChevronTexaco combined the two companies' worldwide chemicals businesses into CPChem. 135 NOTE 24--OTHER FINANCIAL INFORMATION
Millions of Dollars Except Per Share Amounts ------------------------------------ 2002 2001 2000 ------------------------------------ INTEREST Incurred Debt $ 740 524 511 Other 58 45 32 -------------------------------------------------------------------------------------------------------------- 798 569 543 Capitalized (232) (231) (174) -------------------------------------------------------------------------------------------------------------- Expensed $ 566 338 369 ============================================================================================================== RESEARCH AND DEVELOPMENT EXPENDITURES--expensed $ 355* 44 43 -------------------------------------------------------------------------------------------------------------- *Includes $246 million of in-process research and development expenses related to the merger ADVERTISING EXPENSES* $ 37 56 43 -------------------------------------------------------------------------------------------------------------- *Deferred amounts at December 31 were immaterial in all three years CASH DIVIDENDS paid per common share $ 1.48 1.40 1.36 -------------------------------------------------------------------------------------------------------------- FOREIGN CURRENCY TRANSACTION GAINS (LOSSES)--after-tax E&P $ (34) 2 (10) R&M 9 3 (3) Chemicals -- -- (1) Corporate and Other 21 (8) (25) -------------------------------------------------------------------------------------------------------------- $ (4) (3) (39) ==============================================================================================================
NOTE 25--RELATED PARTY TRANSACTIONS Significant transactions with related parties were:
Millions of Dollars ------------------------------------ 2002 2001 2000 ------------------------------------ Operating revenues (a) $ 1,554 935 1,573 Purchases (b) 1,545 1,110 1,347 Operating expenses and selling, general and administrative expenses (c) 279 243 108 Net interest (income) expense (d) (6) 8 (3) --------------------------------------------------------------------------------------------------------------
(a) ConocoPhillips' Exploration and Production (E&P) segment sells natural gas to Duke Energy Field Services, LLC (DEFS) and crude oil to the Malaysian Refining Company Sdn. Bhd (Melaka), among others, for processing and marketing. Natural gas liquids, solvents and petrochemical feedstocks are sold to Chevron Phillips Chemical Company LLC (CPChem) and refined products are sold to CFJ Properties and GKG Mineraloelhandel GMbH & Co. KG. Also, the company charges several of its affiliates including CPChem; Merey Sweeny, L.P. (MSLP); Hamaca Holding LLC; and Venture 136 Coke Company for the use of common facilities, such as steam generators, waste and water treaters, and warehouse facilities. (b) ConocoPhillips purchases natural gas and natural gas liquids from DEFS and CPChem for use in its refinery processes and other feedstocks from various affiliates. ConocoPhillips purchases crude oil from Petrozuata C.A. and refined products from Melaka and Ceska rafinerska, a.s. located in the Czech Republic. Also, ConocoPhillips pays fees to various pipeline equity companies for transporting finished refined products. (c) ConocoPhillips pays processing fees to various affiliates, the most significant being MSLP. Additionally, ConocoPhillips pays contract drilling fees to two deepwater drillship affiliates. Fees are paid to ConocoPhillips' pipeline equity companies for transporting crude oil. Commissions are paid to the receivable monetization companies (see Note 13--Sales of Receivables for more information). (d) ConocoPhillips pays and/or receives interest to/from various affiliates including the receivable monetization companies and MSLP. Elimination of the company's equity percentage share of profit or loss on the above transactions was not material. NOTE 26--SEGMENT DISCLOSURES AND RELATED INFORMATION ConocoPhillips has organized its reporting structure based on the grouping of similar products and services, resulting in five operating segments: 1) E&P--This segment explores for and produces crude oil, natural gas, and natural gas liquids worldwide; and mines oil sands to extract bitumen and upgrade it into synthetic crude oil. At December 31, 2002, E&P was producing in the United States; the Norwegian and U.K. sectors of the North Sea; Canada; Nigeria; Venezuela; the Timor Sea; offshore Australia and China; Indonesia; the United Arab Emirates; Vietnam; Russia; and Ecuador. The E&P segment's U.S. and international operations are disclosed separately for reporting purposes. 2) Midstream--Through both consolidated and equity interests, this segment gathers and processes natural gas produced by ConocoPhillips and others, and fractionates and markets natural gas liquids, primarily in the United States, Canada and Trinidad. The Midstream segment includes ConocoPhillips' 30.3 percent equity investment in DEFS. 3) R&M--This segment refines, markets and transports crude oil and petroleum products, mostly in the United States, Europe and Asia. At December 31, 2002, ConocoPhillips owned 12 refineries in the United States (excluding two refineries treated as discontinued operations and reported in Corporate and Other); one in the United Kingdom; one in Ireland; and had equity interests in one refinery in Germany, two in the Czech Republic, and one in Malaysia. The R&M segment's U.S. and international operations are disclosed separately for reporting purposes. 4) Chemicals--This segment manufactures and markets petrochemicals and plastics on a worldwide basis. The Chemicals segment consists primarily of ConocoPhillips' 50 percent equity investment in CPChem. 137 5) Emerging Businesses--This segment encompasses the development of new businesses beyond the company's traditional operations. Emerging Businesses includes new technologies related to carbon fibers, natural gas conversion into clean fuels and related products (gas-to-liquids), fuels technology, and power generation. Corporate and Other includes general corporate overhead; all interest income and expense; preferred dividend requirements of capital trusts; discontinued operations; restructuring charges; goodwill resulting from the merger of Conoco and Phillips that has not yet been allocated to the operating segments; certain eliminations; and various other corporate activities. Corporate assets include all cash and cash equivalents. The company evaluates performance and allocates resources based on, among other items, net income. Segment accounting policies are the same as those in Note 1--Accounting Policies. Intersegment sales are at prices that approximate market. 138 ANALYSIS OF RESULTS BY OPERATING SEGMENT
Millions of Dollars --------------------------------------- 2002 2001 2000 --------------------------------------- SALES AND OTHER OPERATING REVENUES E&P United States $ 7,222 5,879 5,346 International 4,850 2,266 2,919 Intersegment eliminations-U.S (1,304) (534) (433) Intersegment eliminations-international (484) -- (221) --------------------------------------------------------------------------------------------------------------- E&P 10,284 7,611 7,611 --------------------------------------------------------------------------------------------------------------- Midstream Total sales 2,049 1,193 1,819 Intersegment eliminations (510) (416) (665) --------------------------------------------------------------------------------------------------------------- Midstream 1,539 777 1,154 --------------------------------------------------------------------------------------------------------------- R&M United States 41,011 16,445 11,570 International 5,630 142 532 Intersegment eliminations-U.S (1,773) (92) (361) Intersegment eliminations-international -- -- -- --------------------------------------------------------------------------------------------------------------- R&M 44,868 16,495 11,741 --------------------------------------------------------------------------------------------------------------- Chemicals Total sales 13 -- 1,794 Intersegment eliminations -- -- (147) --------------------------------------------------------------------------------------------------------------- Chemicals 13 -- 1,647 --------------------------------------------------------------------------------------------------------------- Emerging Businesses 36 7 -- Corporate and Other 8 2 2 --------------------------------------------------------------------------------------------------------------- Consolidated sales and other operating revenues $ 56,748 24,892 22,155 =============================================================================================================== DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENTS E&P United States $ 999 817 552 International 735 324 487 --------------------------------------------------------------------------------------------------------------- Total E&P 1,734 1,141 1,039 --------------------------------------------------------------------------------------------------------------- Midstream 19 1 24 --------------------------------------------------------------------------------------------------------------- R&M United States 564 203 139 International 50 1 -- --------------------------------------------------------------------------------------------------------------- Total R&M 614 204 139 --------------------------------------------------------------------------------------------------------------- Chemicals -- -- 54 Emerging Businesses 4 -- -- Corporate and Other 29 24 13 --------------------------------------------------------------------------------------------------------------- Consolidated depreciation, depletion, amortization and impairments $ 2,400 1,370 1,269 ===============================================================================================================
139
Millions of Dollars --------------------------------------- 2002 2001 2000 --------------------------------------- EQUITY IN EARNINGS OF AFFILIATES E&P United States $ 29 9 15 International 162 19 16 --------------------------------------------------------------------------------------------------------------- Total E&P 191 28 31 --------------------------------------------------------------------------------------------------------------- Midstream 46 165 137 --------------------------------------------------------------------------------------------------------------- R&M United States 43 88 28 International -- -- 8 --------------------------------------------------------------------------------------------------------------- Total R&M 43 88 36 --------------------------------------------------------------------------------------------------------------- Chemicals (16) (240) (90) Emerging Businesses (3) -- -- Corporate and Other -- -- -- --------------------------------------------------------------------------------------------------------------- Consolidated equity in earnings of affiliates $ 261 41 114 =============================================================================================================== INCOME TAXES E&P United States $ 473 670 744 International 1,337 913 1,050 --------------------------------------------------------------------------------------------------------------- Total E&P 1,810 1,583 1,794 --------------------------------------------------------------------------------------------------------------- Midstream 42 73 91 --------------------------------------------------------------------------------------------------------------- R&M United States 90 210 115 International (11) -- 10 --------------------------------------------------------------------------------------------------------------- Total R&M 79 210 125 --------------------------------------------------------------------------------------------------------------- Chemicals (18) (89) 21 Emerging Businesses (38) (7) -- Corporate and Other (425) (126) (131) --------------------------------------------------------------------------------------------------------------- Consolidated income taxes $ 1,450 1,644 1,900 =============================================================================================================== NET INCOME (LOSS) E&P United States $ 1,156 1,342 1,388 International 593 357 557 --------------------------------------------------------------------------------------------------------------- Total E&P 1,749 1,699 1,945 --------------------------------------------------------------------------------------------------------------- Midstream 55 120 162 --------------------------------------------------------------------------------------------------------------- R&M United States 138 395 209 International 5 2 29 --------------------------------------------------------------------------------------------------------------- Total R&M 143 397 238 --------------------------------------------------------------------------------------------------------------- Chemicals (14) (128) (46) Emerging Businesses (310)* (12) -- Corporate and Other (1,918) (415) (437) --------------------------------------------------------------------------------------------------------------- Consolidated net income (loss) $ (295) 1,661 1,862 =============================================================================================================== *Includes a non-cash $246 million write-off of acquired in-process research and development costs.
140
Millions of Dollars --------------------------------------- 2002 2001 2000 --------------------------------------- INVESTMENTS IN AND ADVANCES TO AFFILIATES E&P United States $ 156 13 5 International 2,184 573 342 --------------------------------------------------------------------------------------------------------------- Total E&P 2,340 586 347 --------------------------------------------------------------------------------------------------------------- Midstream 318 166 43 --------------------------------------------------------------------------------------------------------------- R&M United States 762 166 147 International 416 -- -- --------------------------------------------------------------------------------------------------------------- Total R&M 1,178 166 147 --------------------------------------------------------------------------------------------------------------- Chemicals 2,050 1,852 2,046 Emerging Businesses -- -- -- Corporate and Other 14 18 29 --------------------------------------------------------------------------------------------------------------- Consolidated investments in and advances to affiliates $ 5,900 2,788 2,612 =============================================================================================================== TOTAL ASSETS E&P United States $ 14,196 9,501 9,296 International 19,541 5,295 4,538 --------------------------------------------------------------------------------------------------------------- Total E&P 33,737 14,796 13,834 --------------------------------------------------------------------------------------------------------------- Midstream 1,931 196 145 --------------------------------------------------------------------------------------------------------------- R&M United States 19,553 14,553 3,112 International 3,632 183 68 --------------------------------------------------------------------------------------------------------------- Total R&M 23,185 14,736 3,180 --------------------------------------------------------------------------------------------------------------- Chemicals 2,095 1,934 2,170 Emerging Businesses 737 2 -- Corporate and Other 15,151 3,553 1,180 --------------------------------------------------------------------------------------------------------------- Consolidated total assets $ 76,836 35,217 20,509 =============================================================================================================== CAPITAL EXPENDITURES AND INVESTMENTS* E&P United States $ 1,205 1,354 951 International 2,071 1,162 726 --------------------------------------------------------------------------------------------------------------- Total E&P 3,276 2,516 1,677 --------------------------------------------------------------------------------------------------------------- Midstream 5 -- 17 --------------------------------------------------------------------------------------------------------------- R&M United States 676 423 217 International 164 5 -- --------------------------------------------------------------------------------------------------------------- Total R&M 840 428 217 --------------------------------------------------------------------------------------------------------------- Chemicals 60 6 67 Emerging Businesses 122 -- -- Corporate and Other 85 66 39 --------------------------------------------------------------------------------------------------------------- Consolidated capital expenditures and investments $ 4,388 3,016 2,017 ===============================================================================================================
*Including dry hole costs. 141 Additional information on items included in Corporate and Other (on a before-tax basis unless otherwise noted):
Millions of Dollars --------------------------------------- 2002 2001 2000 --------------------------------------- Interest income $ 40 13 28 Interest expense 566 338 369 Extraordinary losses, after-tax 16 10 -- Significant non-cash items Impairments included in discontinued operations 1,048 -- -- Loss accruals related to retail site leases included in discontinued operations 477 -- -- Restructuring charges, net of benefits paid 269 -- -- --------------------------------------------------------------------------------------------------------------------------
GEOGRAPHIC INFORMATION
Millions of Dollars --------------------------------------------------------------------------------------- Other United United Foreign Worldwide States Norway Kingdom Canada Countries Consolidated --------------------------------------------------------------------------------------- 2002 Sales and Other Operating Revenues* $46,674 1,850 3,387 997 3,840 56,748 -------------------------------------------------------------------------------------------------------------------------- Long-Lived Assets** $28,492 3,767 4,969 3,460 8,242 48,930 -------------------------------------------------------------------------------------------------------------------------- 2001 Sales and Other Operating Revenues* $22,466 1,322 380 42 682 24,892 -------------------------------------------------------------------------------------------------------------------------- Long-Lived Assets** $19,955 1,484 654 29 2,799 24,921 -------------------------------------------------------------------------------------------------------------------------- 2000 Sales and Other Operating Revenues* $18,700 231 2,183 175 866 22,155 -------------------------------------------------------------------------------------------------------------------------- Long-Lived Assets** $13,198 1,487 709 30 1,831 17,255 --------------------------------------------------------------------------------------------------------------------------
*Sales and other operating revenues are attributable to countries based on the location of the operations generating the revenues. **Defined as net properties, plants and equipment plus investments in and advances to affiliates. 142 NOTE 27--NEW ACCOUNTING STANDARDS In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 was adopted by the company on January 1, 2003, and requires major changes in the accounting for asset retirement obligations, such as required decommissioning of oil and gas production platforms, facilities and pipelines. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period when it is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related property, plant and equipment. Over time, the liability is accreted for the change in its present value each period, and the initial capitalized cost is depreciated over the useful life of the related asset. Upon adoption of SFAS No. 143, the company adjusted its recorded asset retirement obligations to the new requirements using a cumulative-effect approach as required. All transition amounts were measured using the company's current information, assumptions, and credit-adjusted, risk-free interest rates. While the original discount rates used to establish an asset retirement obligation will not change in the future, changes in cost estimates or the timing of expenditures will result in immediate adjustments to the recorded liability, with an offsetting adjustment to properties, plants and equipment. Application of the new rules, effective January 1, 2003, should result in an increase in net properties, plants and equipment of approximately $1.2 billion, an asset retirement obligation liability increase of approximately $1.1 billion, and a cumulative after-tax effect of adoption gain that is expected to increase net income and stockholders' equity by approximately $137 million. The estimated after-tax impact on income before extraordinary items and cumulative effect of changes in accounting principle for the year 2003 is an improvement of $33 million. The majority of the liability and asset increase is attributable to assets acquired in the merger and production facilities in Alaska. Following prevalent oil and gas industry practice for acquisitions completed prior to January 1, 2003, ConocoPhillips did not record an initial liability for the estimated cost of removing properties, plants and equipment at the end of their useful lives. Instead, estimated removal costs were accrued on a unit-of-production basis as an additional component of depreciation, building the removal cost liability over the remaining useful lives of the properties, plants and equipment. However, upon adoption of SFAS No. 143, these asset retirement obligations are required to be recorded, significantly increasing asset retirement liabilities on the balance sheet with an offsetting increase to properties, plants and equipment. In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities," (VIEs) in an effort to expand upon and strengthen existing accounting guidance that addresses when a company should include in its financial statements the assets, liabilities and activities of another entity. In general, a VIE is a corporation, partnership, trust, or any other legal structure used for business purposes that either (a) does not have equity investors with voting rights or (b) has equity investors that do not provide sufficient financial resources for the entity to support its activities. Interpretation No. 46 requires a VIE to be consolidated by a company if that company is subject to a majority of the risk of loss from the VIE's activities, is entitled to receive a majority of the VIE's residual returns, or both. The interpretation also requires disclosures about VIEs that the company is not required to consolidate, but in which it has a significant variable interest. The consolidation requirements of Interpretation No. 46 applied immediately to variable interest entities created after January 31, 2003, and to older entities no later than the third quarter of 2003. The company is studying the impact of the interpretation on existing variable interest entities with which the company is involved. Certain of the disclosure requirements are required in all financial statements issued after January 31, 2003, regardless of when the variable interest entity was established. These are included in Note 28--Variable Interest Entities. 143 In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities," which addresses financial accounting and reporting for costs associated with exit or disposal activities initiated after December 31, 2002, and nullifies Emerging Issues Task Force (EITF) Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized and measured initially at fair value at the date the liability is incurred, rather than at the commitment date. The company plans to apply the provisions of SFAS No. 146 prospectively for restructuring activities initiated in 2003 and future years. However, for restructuring activities initiated in 2002 the company will continue to apply EITF Issue Nos. 94-3 and 95-3 until those identified restructuring activities are completed. See Note 4--Discontinued Operations and Note 5--Restructuring for more information. In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." For specified guarantees issued or modified after December 31, 2002, the interpretation requires a guarantor to recognize, at the inception of the guarantee, a liability for the fair value of all the obligations it has undertaken in issuing the guarantee, including its ongoing obligation to stand ready and make cash payments over the term of the guarantee in the event that specified triggering events or conditions occur. The measurement of the liability for the fair value of the guarantee obligation should be based on the premium that would be required to issue the same guarantee in a stand-alone arm's-length transaction with an unrelated party if that information is available, or estimated using expected present value measurement techniques. For specified guarantees existing as of December 31, 2002, the interpretation also requires a guarantor to disclose (a) the nature of the guarantee, including how the guarantee arose and the events or circumstances that would require the guarantor to perform under the guarantee; (b) the maximum potential amount of future payments under the guarantee; (c) the carrying amount of the liability; and (d) the nature and extent of any recourse provisions or available collateral that would enable the guarantor to recover the amounts paid under the guarantee. The required disclosures are included in Note 14--Guarantees. In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections." The rescission of SFAS No. 4 will require that gains and losses on extinguishments of debt no longer be presented as extraordinary items in the income statement, commencing in 2003. All prior periods will be restated to reflect this change in presentation. See Note 2--Extraordinary Items and Accounting Change. In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure," an amendment of SFAS No. 123, "Accounting for Stock-Based Compensation," to provide alternative methods of transition for a voluntary change to the fair value method of accounting for stock-based employee compensation. ConocoPhillips adopted the fair-value method recommended by SFAS No. 123 on January 1, 2003, and is using the prospective transition method. See Note 20--Employee Benefit Plans for more information on this accounting change. In 2003, the FASB is expected to issue SFAS No. 149, "Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity," to address the balance sheet classification of certain financial instruments that have characteristics of both liabilities and equity. SFAS No. 149 is expected to provide that mandatorily redeemable instruments meet the conceptual definition of liabilities and must be presented as such on the balance sheet. The statement is expected to be effective upon issuance for all contracts created or modified after the issuance date and is otherwise effective on all previously existing contracts no later than the third quarter of 2003. ConocoPhillips is currently evaluating the impact of proposed SFAS No. 149, and it is likely that some or all of currently reported mandatorily redeemable preferred stock and minority interest securities will be reclassified as liabilities. See Note 17--Preferred Stock and Other Minority Interests for more information. 144 NOTE 28--VARIABLE INTEREST ENTITIES In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities," which provides guidance related to identifying variable interest entities and determining whether such entities should be consolidated. See Note 27--New Accounting Standards for further explanation of this new accounting standard. As required, the company will immediately apply this interpretation to variable interest entities created, or interests in variable interest entities obtained, after January 31, 2003. For variable interest entities created before February 1, 2003, the company will initially apply the guidance in this interpretation in the third quarter of 2003. At that time, if the company is determined to be the primary beneficiary of a variable interest entity created before February 1, 2003, the company will consolidate that entity. This interpretation excludes the QSPE's discussed in Note 13--Sales of Receivables. The company is still evaluating the impact of this very recent, complex interpretation on existing potential variable interest entities in which the company is involved. Based on a preliminary review, when the company initially applies the guidance of this interpretation in July 2003, it is reasonably possible that the company will be required to begin consolidating entities in the following areas: o The company leases ocean transport vessels, drillships, corporate aircraft, service stations, office buildings, and certain refining equipment from special purpose entities (SPEs) that are third-party trusts established by a trustee and principally funded by financial institutions. If the company is required to consolidate all of these entities, the assets of the entities and debt of approximately $2.4 billion would be required to be included in the consolidated financial statements. The company's maximum exposure to loss as a result of its involvement with the entities would be the debt of the entity, less the fair value of the assets at the end of the lease terms. Of the $2.4 billion debt that would be consolidated, approximately $1.5 billion is associated with a major portion of the company's owned retail stores that the company has announced it plans to sell. As a result of the planned divestiture, the company plans to exercise purchase option provisions during 2003 and terminate various operating leases involving approximately 900 store sites and two office buildings. In addition, see Note 4--Discontinued Operations for details regarding the provisions recorded for losses and penalties in the fourth quarter of 2002 for the planned divestiture. Depending upon the timing of the company's exercise of these purchase options, and the determination of whether or not the lessor entities in these operating leases are variable interest entities requiring consolidation in 2003, some or all of these lessor entities could become consolidated subsidiaries of the company prior to the exercise of the purchase options and termination of the leases. See Note 14--Guarantees and Note 19--Non-Mineral Leases. o In December 2001, in order to raise funds for general corporate purposes, 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. Through its $504 million investment, Cold Spring is entitled to a cumulative annual preferred return, based on three-month LIBOR rates plus 1.27 percent. The preferred return at December 31, 2002, was 2.70 percent. The company already consolidates Ashford and reports Cold Spring's investment as a minority interest. If it is determined that Cold Spring is a variable interest entity, the company may have to consolidate Cold Spring under Interpretation No. 46. If that were to occur, Cold Spring's financing of approximately $500 million at December 31, 2002, could be reported as debt of ConocoPhillips. 145 -------------------------------------------------------------------------------- OIL AND GAS OPERATIONS (Unaudited) Exploration and Production In accordance with SFAS No. 69, "Disclosures about Oil and Gas Producing Activities," and regulations of the U.S. Securities and Exchange Commission, the company is making certain supplemental disclosures about its oil and gas exploration and production operations. While this information was developed with reasonable care and disclosed in good faith, it is emphasized that some of the data is necessarily imprecise and represents only approximate amounts because of the subjective judgments involved in developing such information. Accordingly, this information may not necessarily represent the current financial condition of the company or its expected future results. ConocoPhillips' disclosures by geographic areas include the United States (U.S.), Norway, the United Kingdom (U.K.), Canada and Other Areas. Other Areas include Nigeria, China, Australia, the Timor Sea, Indonesia, Vietnam, United Arab Emirates, Ecuador and other countries. When the company uses equity accounting for operations that have proved reserves, these oil and gas operations are shown separately and designated as Equity Affiliates. In 2002, these consisted of two heavy-oil projects in Venezuela, an oil development project in northern Russia and a heavy-oil project in Canada. In 2001 and 2000 this consisted of a heavy-oil project in Venezuela. Amounts in 2000 were impacted by ConocoPhillips' purchase of all of Atlantic Richfield Company's (ARCO) Alaska businesses in late April 2000. Amounts in 2002 were impacted by the merger of Conoco and Phillips (the merger) in late August 2002.
CONTENTS--OIL AND GAS OPERATIONS PAGE -------------------------------------------------------------------------------- Proved Reserves Worldwide 147 Results of Operations 153 Statistics 155 Costs Incurred 159 Capitalized Costs 160 Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities 161
146 o PROVED RESERVES WORLDWIDE
Years Ended CRUDE OIL December 31 ----------------------------------------------------------------------------------------------------- Millions of Barrels ----------------------------------------------------------------------------------------------------- Consolidated Operations ------------------------------------------------------------------------------ Lower Total Other Equity Combined Alaska 48 U.S Norway U.K. Canada Areas Total Affiliates Total ----------------------------------------------------------------------------------------------------- DEVELOPED AND UNDEVELOPED End of 1999 33 109 142 521 57 12 232 964 -- 964 Revisions 9 12 21 73 3 (2) 1 96 -- 96 Improved recovery 31 -- 31 5 -- -- -- 36 -- 36 Purchases 1,594 1 1,595 -- -- -- -- 1,595 -- 1,595 Extensions and discoveries 12 3 15 -- -- 6 34 55 613 668 Production (75) (12) (87) (41) (9) (2) (19) (158) -- (158) Sales -- (1) (1) -- -- (12) -- (13) -- (13) ---------------------------------------------------------------------------------------------------------------------------------- End of 2000 1,604 112 1,716 558 51 2 248 2,575 613 3,188 Revisions 77 (2) 75 51 (6) -- 4 124 48 172 Improved recovery 67 1 68 12 -- -- -- 80 -- 80 Purchases -- -- -- -- -- -- 17 17 -- 17 Extensions and discoveries 9 6 15 -- 2 -- 12 29 -- 29 Production (126) (12) (138) (43) (6) -- (19) (206) (1) (207) Sales -- -- -- -- -- -- (3) (3) -- (3) ---------------------------------------------------------------------------------------------------------------------------------- End of 2001 1,631 105 1,736 578 41 2 259* 2,616 660 3,276 Revisions 32 (8) 24 (26) (5) 5 (32) (34) (27) (61) Improved recovery 46 1 47 5 2 -- -- 54 -- 54 Purchases -- 132 132 262 143 101 223 861 733 1,594 Extensions and discoveries 14 6 20 3 3 1 22 49 4 53 Production (120) (14) (134) (58) (14) (5) (24) (235) (13) (248) Sales -- (2) (2) (13) (7) (13) (1) (36) -- (36) ---------------------------------------------------------------------------------------------------------------------------------- END OF 2002 1,603 220 1,823 751 163 91 447** 3,275 1,357 4,632 ================================================================================================================================== DEVELOPED End of 1999 25 93 118 433 37 10 114 712 -- 712 End of 2000 1,207 98 1,305 478 25 2 116 1,926 -- 1,926 End of 2001 1,275 91 1,366 513 21 2 96 1,998 47 2,045 END OF 2002 1,335 169 1,504 611 102 81 223 2,521 378 2,899 ----------------------------------------------------------------------------------------------------------------------------------
*Includes proved reserves of 17 million barrels attributable to a consolidated subsidiary in which there is a 13 percent minority interest. **Includes proved reserves of 14 million barrels attributable to a consolidated subsidiary in which there is a 10 percent minority interest. 147 o Purchases in 2002 were primarily related to the merger. Other Areas in 2002 includes 1 million barrels related to an operation that was classified as discontinued following the merger, and was sold by year-end. The amount for this operation was not included in the schedule of sources of change in discounted future net cash flows, or as a part of the company's per-unit finding and development cost calculation. o At the end of 2000 and 1999, Other Areas included 2 million and 14 million barrels, respectively, of reserves in Venezuela in which the company had an economic interest through risk-service contracts. These properties were sold in June 2001. Net production to the company was approximately 400,000 barrels in 2001; 1,200,000 barrels in 2000; and 600,000 barrels in 1999. o In addition to conventional crude oil, natural gas and natural gas liquids (NGL) proved reserves, ConocoPhillips has proven oil sands reserves in Canada, associated with a Syncrude project totaling 272 million barrels at the end of 2002. For internal management purposes, ConocoPhillips views these reserves and their development as part of its total exploration and production operations. However, U.S. Securities and Exchange Commission regulations define these reserves as mining related. Therefore, they are not included in the company's tabular presentation of proved crude oil, natural gas and NGL reserves. These oil sand reserves are also not included in the standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities. 148
Years Ended NATURAL GAS December 31 ----------------------------------------------------------------------------------------------------- Billions of Cubic Feet ----------------------------------------------------------------------------------------------------- Consolidated Operations ------------------------------------------------------------------------------ Lower Total Other Equity Combined Alaska 48 U.S Norway U.K. Canada Areas Total Affiliates Total ----------------------------------------------------------------------------------------------------- DEVELOPED AND UNDEVELOPED End of 1999 798 2,554 3,352 1,176 681 521 634 6,364 -- 6,364 Revisions 87 183 270 (162) 10 (200) 1 (81) -- (81) Improved recovery -- -- -- 52 -- -- -- 52 -- 52 Purchases 2,448 193 2,641 -- -- -- -- 2,641 -- 2,641 Extensions and discoveries 7 211 218 -- -- 22 4 244 131 375 Production (103) (283) (386) (54) (79) (33) (14) (566) -- (566) Sales -- (5) (5) -- -- (246) -- (251) -- (251) ---------------------------------------------------------------------------------------------------------------------------------- End of 2000 3,237 2,853 6,090 1,012 612 64 625 8,403 131 8,534 Revisions 60 9 69 (65) (59) (2) 64 7 14 21 Improved recovery -- -- -- 13 -- -- -- 13 -- 13 Purchases -- 12 12 -- 10 -- 10 32 -- 32 Extensions and discoveries 5 405 410 -- 23 -- 374 807 -- 807 Production (141) (261) (402) (53) (68) (7) (40) (570) -- (570) Sales -- -- -- -- (8) -- -- (8) -- (8) ---------------------------------------------------------------------------------------------------------------------------------- End of 2001 3,161 3,018 6,179 907 510 55 1,033* 8,684 145 8,829 Revisions (27) (70) (97) 4 (24) 16 (75) (176) -- (176) Improved recovery 5 1 6 13 1 -- -- 20 -- 20 Purchases -- 1,862 1,862 1,003 1,580 1,241 2,062 7,748 17 7,765 Extensions and discoveries 2 225 227 -- 43 21 420 711 1 712 Production (147) (340) (487) (68) (158) (59) (68) (840) (2) (842) Sales (5) (1) (6) (1) (3) (97) (161) (268) -- (268) ---------------------------------------------------------------------------------------------------------------------------------- END OF 2002 2,989 4,695 7,684 1,858 1,949 1,177 3,211** 15,879 161 16,040 ================================================================================================================================== DEVELOPED End of 1999 630 2,317 2,947 856 413 131 349 4,696 -- 4,696 End of 2000 2,969 2,564 5,533 738 321 54 336 6,982 -- 6,982 End of 2001 2,969 2,684 5,653 788 265 45 736 7,487 3 7,490 END OF 2002 2,806 4,302 7,108 1,544 1,734 1,098 1,349 12,833 28 12,861 ----------------------------------------------------------------------------------------------------------------------------------
*Includes proved reserves of 10 billion cubic feet attributable to a consolidated subsidiary in which there is a 13 percent minority interest. **Includes proved reserves of 10 billion cubic feet attributable to a consolidated subsidiary in which there is a 10 percent minority interest. 149 o Natural gas production may differ from gas production (delivered for sale) in the company's statistics disclosure, primarily because the quantities above include gas consumed at the lease, but omit the gas equivalent of liquids extracted at any ConocoPhillips-owned, equity-affiliate, or third-party processing plant or facility. o Purchases in 2002 were related to the merger. Other Areas in 2002 includes 161 billion cubic feet related to an operation that was classified as discontinued following the merger, and was sold by year-end. The amount for this operation was not included in the schedule of sources of change in discounted future net cash flows, or as a part of the company's per-unit finding and development cost calculation. o Extensions and discoveries in Other Areas in 2002 were primarily in Nigeria. o Sales in Other Areas in 2002 were for a discontinued operation. See note on purchases above. o Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit. 150
Years Ended NATURAL GAS LIQUIDS December 31 ----------------------------------------------------------------------------------------------------- Millions of Barrels ----------------------------------------------------------------------------------------------------- Consolidated Operations ------------------------------------------------------------------------------ Lower Total Other Equity Combined Alaska 48 U.S Norway U.K. Canada Areas Total Affiliates Total ----------------------------------------------------------------------------------------------------- DEVELOPED AND UNDEVELOPED End of 1999 1 91 92 29 4 4 78 207 -- 207 Revisions 57 11 68 7 -- (2) 2 75 -- 75 Purchases 147 -- 147 -- -- -- -- 147 -- 147 Extensions and discoveries -- 2 2 -- -- -- -- 2 -- 2 Production (7) (8) (15) (2) (1) -- (1) (19) -- (19) Sales -- -- -- -- -- (2) (1) (3) -- (3) ---------------------------------------------------------------------------------------------------------------------------------- End of 2000 198 96 294 34 3 -- 78 409 -- 409 Revisions (25) 2 (23) -- -- -- 4 (19) -- (19) Improved recovery -- -- -- 1 -- -- -- 1 -- 1 Purchases -- -- -- -- -- -- 10 10 -- 10 Extensions and discoveries -- 2 2 -- -- -- -- 2 -- 2 Production (9) (7) (16) (2) -- -- (1) (19) -- (19) ---------------------------------------------------------------------------------------------------------------------------------- End of 2001 164 93 257 33 3 -- 91* 384 -- 384 Revisions (4) 5 1 (3) 2 -- (11) (11) -- (11) Improved recovery -- 1 1 -- -- -- -- 1 -- 1 Purchases -- 80 80 12 2 38 21 153 -- 153 Extensions and discoveries -- 4 4 -- -- 1 -- 5 -- 5 Production (9) (9) (18) (2) (1) (2) (1) (24) -- (24) Sales -- -- -- -- -- (2) (1) (3) -- (3) ---------------------------------------------------------------------------------------------------------------------------------- END OF 2002 151 174 325 40 6 35 99** 505 -- 505 ================================================================================================================================== DEVELOPED End of 1999 1 89 90 22 3 1 17 133 -- 133 End of 2000 197 94 291 27 2 1 17 338 -- 338 End of 2001 163 92 255 29 2 -- 16 302 -- 302 END OF 2002 151 166 317 34 6 30 15 402 -- 402 ----------------------------------------------------------------------------------------------------------------------------------
*Includes proved reserves of 10 million barrels attributable to a consolidated subsidiary in which there is a 13 percent minority interest. **Includes proved reserves of 9 million barrels attributable to a consolidated subsidiary in which there is a 10 percent minority interest. 151 o Natural gas liquids reserves include estimates of natural gas liquids to be extracted from ConocoPhillips' leasehold gas at gas processing plants or facilities. Estimates are based at the wellhead and assume full extraction. Production above differs from natural gas liquids production per day delivered for sale primarily due to: (1) Natural gas consumed at the lease. (2) Natural gas liquids production delivered for sale includes only natural gas liquids extracted from ConocoPhillips' leasehold gas and sold by ConocoPhillips' Exploration and Production (E&P) segment, whereas the production above also includes natural gas liquids extracted from ConocoPhillips' leasehold gas at equity-affiliate or third-party facilities. o Purchases in 2002 were related to the merger. 152 o RESULTS OF OPERATIONS
Years Ended Millions of Dollars December 31 ---------------------------------------------------------------------------------------------------- Consolidated Operations ----------------------------------------------------------------------------- Lower Total Other Equity Combined Alaska 48 U.S Norway U.K. Canada Areas Total Affiliates Total ----------------------------------------------------------------------------------------------------- 2002 Sales $ 2,997 927 3,924 400 794 125 747 5,990 180 6,170 Transfers 102 401 503 1,285 30 235 -- 2,053 62 2,115 Other revenues (2) 3 1 35 28 7 21 92 12 104 ----------------------------------------------------------------------------------------------------------------------------------- Total revenues 3,097 1,331 4,428 1,720 852 367 768 8,135 254 8,389 Production costs 769 444 1,213 209 134 118 190 1,864 57 1,921 Exploration expenses 101 108 209 33 34 32 276* 584 -- 584 Depreciation, depletion and amortization 552 334 886 206 274 105 85 1,556 30 1,586 Property impairments 4 8 12 -- 41 -- -- 53 -- 53 Transportation costs 681 87 768 75 50 -- 15 908 8 916 Other related expenses 23 16 39 60 15 14 12 140 12 152 ----------------------------------------------------------------------------------------------------------------------------------- 967 334 1,301 1,137 304 98 190 3,030 147 3,177 Provision for income taxes 294 66 360 857 124 49 275 1,665 (18) 1,647 ----------------------------------------------------------------------------------------------------------------------------------- Results of operations for producing activities 673 268 941 280 180 49 (85) 1,365 165 1,530 Other earnings 197 18 215 20 (10) 24** (6) 243 (24) 219 ----------------------------------------------------------------------------------------------------------------------------------- E&P net income (loss) $ 870 286 1,156 300 170 73 (91) 1,608 141 1,749 =================================================================================================================================== 2001 Sales $ 3,020 1,178 4,198 175 371 31 478 5,253 8 5,261 Transfers 119 119 238 1,039 -- -- -- 1,277 -- 1,277 Other revenues 34 26 60 13 10 5 (4) 84 1 85 ----------------------------------------------------------------------------------------------------------------------------------- Total revenues 3,173 1,323 4,496 1,227 381 36 474 6,614 9 6,623 Production costs 784 328 1,112 124 41 6 92 1,375 2 1,377 Exploration expenses 61 69 130 20 11 -- 154 315 -- 315 Depreciation, depletion and amortization 531 203 734 115 118 4 49 1,020 2 1,022 Property impairments -- -- -- -- -- -- 23 23 -- 23 Transportation costs 726 77 803 27 33 3 6 872 -- 872 Other related expenses 2 5 7 -- (8) 1 28 28 2 30 ----------------------------------------------------------------------------------------------------------------------------------- 1,069 641 1,710 941 186 22 122 2,981 3 2,984 Provision for income taxes 392 173 565 729 50 7 139 1,490 -- 1,490 ----------------------------------------------------------------------------------------------------------------------------------- Results of operations for producing activities 677 468 1,145 212 136 15 (17) 1,491 3 1,494 Other earnings 189 8 197 17 -- -- (9) 205 -- 205 ----------------------------------------------------------------------------------------------------------------------------------- E&P net income (loss) $ 866 476 1,342 229 136 15 (26) 1,696 3 1,699 =================================================================================================================================== 2000 Sales $ 2,252 1,102 3,354 139 481 169 556 4,699 -- 4,699 Transfers 74 275 349 1,186 -- -- -- 1,535 -- 1,535 Other revenues 9 25 34 5 (1) 140 (2) 176 -- 176 ----------------------------------------------------------------------------------------------------------------------------------- Total revenues 2,335 1,402 3,737 1,330 480 309 554 6,410 -- 6,410 Production costs 494 308 802 118 42 35 100 1,097 -- 1,097 Exploration expenses 38 73 111 14 36 5 138 304 -- 304 Depreciation, depletion and amortization 305 190 495 106 138 68 65 872 -- 872 Property impairments -- 13 13 -- -- -- 87 100 -- 100 Transportation costs 364 101 465 27 39 9 5 545 -- 545 Other related expenses (9) 4 (5) 21 (2) 4 32 50 -- 50 ----------------------------------------------------------------------------------------------------------------------------------- 1,143 713 1,856 1,044 227 188 127 3,442 -- 3,442 Provision for income taxes 443 207 650 817 69 13 153 1,702 -- 1,702 ----------------------------------------------------------------------------------------------------------------------------------- Results of operations for producing activities 700 506 1,206 227 158 175 (26) 1,740 -- 1,740 Other earnings 129 53 182 16 (1) -- 8 205 -- 205 ----------------------------------------------------------------------------------------------------------------------------------- E&P net income (loss) $ 829 559 1,388 243 157 175 (18) 1,945 -- 1,945 ===================================================================================================================================
*Includes a $77 million leasehold impairment charge for an investment in Angola. **Includes $27 million for a Syncrude oil project in Canada that is defined as a mining operation by U.S. Securities and Exchange Commission regulations. 153 o Results of operations for producing activities consist of all the activities within the E&P organization, except for pipeline and marine operations, a liquefied natural gas operation, Syncrude operations, and crude oil and gas marketing activities, which are included in Other earnings. Also excluded are non-E&P activities, including ConocoPhillips' Midstream segment, downstream petroleum and chemical activities, as well as general corporate administrative expenses and interest. o Transfers are valued at prices that approximate market. o Other revenues include gains and losses from asset sales, certain amounts resulting from the purchase and sale of hydrocarbons, and other miscellaneous income. o Production costs consist of costs incurred to operate and maintain wells and related equipment and facilities used in the production of petroleum liquids and natural gas. These costs also include taxes other than income taxes, depreciation of support equipment and administrative expenses related to the production activity. Excluded are depreciation, depletion and amortization of capitalized acquisition, exploration and development costs. o Exploration expenses include dry hole, leasehold impairment, geological and geophysical expenses and the cost of retaining undeveloped leaseholds. Also included are taxes other than income taxes, depreciation of support equipment and administrative expenses related to the exploration activity. o Exploration expenses in 2002 included $77 million for the impairment of a substantial portion of the company's investment in deepwater Block 34, offshore Angola. Initial results released in early May 2002 indicated that the first exploratory well drilled in Block 34 was a dry hole, resulting in ConocoPhillips' reassessment of the fair value of the remainder of the block. o Depreciation, depletion and amortization (DD&A) in Results of Operations differs from that shown for total E&P in Note 26--Segment Disclosures and Related Information in the Notes to Consolidated Financial Statements, mainly due to depreciation of support equipment being reclassified to production or exploration expenses, as applicable, in Results of Operations. In addition, Other earnings include certain E&P activities, including their related DD&A charges. o Transportation costs include costs to transport oil, natural gas or natural gas liquids to their points of sale. The profit element of transportation operations in which the company has an ownership interest are deemed to be outside the oil and gas producing activity. The net income of the transportation operations is included in Other earnings. o Other related expenses include foreign currency gains and losses, and other miscellaneous expenses. o The provision for income taxes is computed by adjusting each country's income before income taxes for permanent differences related to the oil and gas producing activities that are reflected in the company's consolidated income tax expense for the period, multiplying the result by the country's statutory tax rate and adjusting for applicable tax credits. o Other earnings consist of activities within the E&P segment that are not a part of the "Results of operations for producing activities." These non-producing activities include pipeline and marine operations, liquefied natural gas operations, Syncrude operations, and crude oil and gas marketing activities. 154 o STATISTICS
NET PRODUCTION 2002 2001 2000 ---------------------------- Thousands of Barrels Daily ---------------------------- CRUDE OIL Alaska 331 339 207 Lower 48 40 34 34 --------------------------------------------------------------------------------- United States 371 373 241 Norway 157 117 114 United Kingdom 39 19 25 Canada 13 1 6 Other areas 67 51 51 --------------------------------------------------------------------------------- Total consolidated 647 561 437 Equity affiliates 35 2 -- --------------------------------------------------------------------------------- 682 563 437 ================================================================================= NATURAL GAS LIQUIDS* Alaska 24 25 19 Lower 48 8 1 1 --------------------------------------------------------------------------------- United States 32 26 20 Norway 6 5 5 United Kingdom 2 2 2 Canada 4 -- 1 Other areas 2 2 1 --------------------------------------------------------------------------------- 46 35 29 =================================================================================
*Represents amounts extracted attributable to E&P operations (see natural gas liquids reserves for further discussion). Includes for 2002, 2001 and 2000, 14,000, 15,000 and 12,000 barrels daily in Alaska, respectively, that were sold from the Prudhoe Bay lease to the Kuparuk lease for reinjection to enhance crude oil production.
Millions of Cubic Feet Daily ----------------------------- NATURAL GAS* Alaska 175 177 158 Lower 48 928 740 770 --------------------------------------------------------------------------------- United States 1,103 917 928 Norway 171 130 136 United Kingdom 424 178 214 Canada 165 18 83 Other areas 180 92 33 --------------------------------------------------------------------------------- Total consolidated 2,043 1,335 1,394 Equity affiliates 4 -- -- --------------------------------------------------------------------------------- 2,047 1,335 1,394 =================================================================================
*Represents quantities available for sale. Excludes gas equivalent of natural gas liquids shown above. 155
2002 2001 2000 ------------------------------- AVERAGE SALES PRICES CRUDE OIL PER BARREL Alaska $ 23.75 23.60 28.87 Lower 48 24.48 23.27 28.57 United States 23.83 23.57 28.83 Norway 25.21 24.02 28.27 United Kingdom 25.33 24.52 28.19 Canada 22.87 26.96 28.21 Other areas 25.33 24.30 28.87 Total international 25.14 24.16 28.42 Total consolidated 24.38 23.77 28.65 Equity affiliates 18.41 12.36 -- Worldwide 24.07 23.74 28.65 ---------------------------------------------------------------------------------------------- NATURAL GAS LIQUIDS PER BARREL Alaska $ 23.48 23.61 28.97 Lower 48 15.66 22.47 22.97 United States 20.00 23.49 27.94 Norway 16.51 16.55 14.13 United Kingdom 20.61 18.49 20.57 Canada 20.39 18.77 25.49 Other areas 7.23 7.22 7.18 Total international 17.47 14.61 15.14 Worldwide 18.93 19.74 21.20 ---------------------------------------------------------------------------------------------- NATURAL GAS (LEASE) PER THOUSAND CUBIC FEET Alaska $ 1.85 1.75 1.40 Lower 48 2.79 3.68 3.56 United States 2.75 3.56 3.47 Norway 3.20 3.53 2.56 United Kingdom 2.92 2.88 2.61 Canada 3.03 3.80 3.26 Other areas 1.90 .50 .50 Total international 2.79 2.60 2.56 Total consolidated 2.77 3.23 3.13 Equity affiliates 2.71 -- -- Worldwide 2.77 3.23 3.13 ---------------------------------------------------------------------------------------------- AVERAGE PRODUCTION COSTS PER BARREL OF OIL EQUIVALENT Alaska $ 5.48 5.46 5.35 Lower 48 6.00 5.67 5.15 United States 5.66 5.52 5.27 Norway 2.99 2.36 2.28 United Kingdom 3.29 2.22 1.83 Canada 7.26 4.08 4.59 Other areas 5.26 3.69 4.75 Total international 3.99 2.70 2.85 Total consolidated 4.94 4.60 4.29 Equity affiliates 4.38 2.74 -- Worldwide 4.92 4.60 4.29 ----------------------------------------------------------------------------------------------
156
2002 2001 2000 ------------------------------- DEPRECIATION, DEPLETION AND AMORTIZATION PER BARREL OF OIL EQUIVALENT Alaska $ 3.94 3.70 3.30 Lower 48 4.52 3.51* 3.18 United States 4.14 3.58 3.25 Norway 2.95 2.19 2.04 United Kingdom 6.73 6.38 6.02 Canada 6.46 2.72 8.91 Other areas 2.35 1.96 3.09 Total international 4.11 2.94 3.64 Total consolidated 4.13 3.37 3.41 Equity affiliates 2.30 2.74 -- Worldwide 4.06 3.37 3.41 ----------------------------------------------------------------------------------------------
*Includes a $12 million charge related to an asset transfer.
---------------------------------------------------------------------------------------------- NET WELLS COMPLETED* Productive Dry ---------------------- ---------------------- 2002 2001 2000 2002 2001 2000 ---------------------- ---------------------- EXPLORATORY Alaska -- 1 -- 4 1 1 Lower 48 29 63 45 6 3 4 ---------------------------------------------------------------------------------------------- United States 29 64 45 10 4 5 Norway -- ** ** ** -- -- United Kingdom ** ** 1 2 1 1 Canada 19 -- 3 2 -- 1 Other areas 2 2 6 7 1 6 ---------------------------------------------------------------------------------------------- Total consolidated 50 66 55 21 6 13 Equity affiliates 3 -- -- 1 -- -- ---------------------------------------------------------------------------------------------- 53 66 55 22 6 13 ============================================================================================== DEVELOPMENT Alaska 48 47 52 1 2 1 Lower 48 283 333 208 14 11 8 ---------------------------------------------------------------------------------------------- United States 331 380 260 15 13 9 Norway 4 3 1 -- -- -- United Kingdom 7 1 1 -- -- -- Canada 20 5 8 1 -- 1 Other areas 13 2 6 ** -- -- ---------------------------------------------------------------------------------------------- Total consolidated 375 391 276 16 13 10 Equity affiliates 49 20 -- 1 -- -- ---------------------------------------------------------------------------------------------- 424 411 276 17 13 10 ==============================================================================================
*Includes wildcat and production step-out wells. Excludes farmout arrangements. **ConocoPhillips' total proportionate interest was less than one. 157
WELLS AT YEAR-END 2002 Productive** --------------------------------------- In Progress* Oil Gas ----------------- ----------------- ----------------- Gross Net Gross Net Gross Net ----------------- ----------------- ----------------- Alaska 25 15 1,680 735 24 15 Lower 48 101 61 11,801 2,826 15,534 7,586 ------------------------------------------------------------------------------------ United States 126 76 13,481 3,561 15,558 7,601 Norway 13 2 519 85 60 7 United Kingdom 14 5 189 37 288 87 Canada 7 5 3,395 2,408 5,359 3,463 Other areas 33 16 943 321 76 31 ------------------------------------------------------------------------------------ Total consolidated 193 104 18,527 6,412 21,341 11,189 Equity affiliates 4 2 2,095 875 161 63 ------------------------------------------------------------------------------------ 197 106 20,622 7,287 21,502 11,252 ====================================================================================
*Includes wells that have been temporarily suspended. **Includes 3,205 gross and 1,554 net multiple completion wells. ACREAGE AT DECEMBER 31, 2002
Thousands of Acres ------------------------ Gross Net ------------------------ DEVELOPED Alaska 878 431 Lower 48 5,219 3,142 ------------------------------------------------------------------------------------ United States 6,097 3,573 Norway 430 47 United Kingdom 1,496 465 Canada 4,764 2,343 Other areas 5,147 2,128 ------------------------------------------------------------------------------------ Total consolidated 17,934 8,556 Equity affiliates 490 151 ------------------------------------------------------------------------------------ 18,424 8,707 ==================================================================================== UNDEVELOPED Alaska 2,467 1,422 Lower 48 3,494 2,115 ------------------------------------------------------------------------------------ United States 5,961 3,537 Norway 5,243 1,309 United Kingdom 3,298 1,379 Canada 13,631 7,716 Other areas* 118,115 78,324 ------------------------------------------------------------------------------------ Total consolidated 146,248 92,265 Equity affiliates 2,118 943 ------------------------------------------------------------------------------------ 148,366 93,208 ====================================================================================
*Includes two Somalia concessions where operations have been suspended by declarations of force majeure totaling 33,905 thousand gross and net acres. 158 o COSTS INCURRED
Millions of Dollars ---------------------------------------------------------------------------------------------------- Consolidated Operations ----------------------------------------------------------------------------- Lower Total Other Equity Combined Alaska 48 U.S Norway U.K. Canada Areas Total Affiliates Total ---------------------------------------------------------------------------------------------------- 2002 Acquisition $ 9 3,735 3,744 1,348 3,050 2,562 2,064 12,768 1,671 14,439 Exploration 94 112 206 33 28 58 309 634 1 635 Development 433 409 842 174 232 46 857 2,151 467 2,618 ----------------------------------------------------------------------------------------------------------------------------------- $ 536 4,256 4,792 1,555 3,310 2,666 3,230 15,553 2,139 17,692 =================================================================================================================================== 2001 Acquisition $ 17 37 54 -- -- -- 228 282 -- 282 Exploration 93 57 150 26 18 -- 223 417 -- 417 Development 610 312 922 94 75 3 401 1,495 420 1,915 ----------------------------------------------------------------------------------------------------------------------------------- $ 720 406 1,126 120 93 3 852 2,194 420 2,614 =================================================================================================================================== 2000 Acquisition $5,787 151 5,938 36 -- 33 5 6,012 3 6,015 Exploration 32 66 98 17 36 6 213 370 -- 370 Development 422 218 640 71 50 42 192 995 135 1,130 ----------------------------------------------------------------------------------------------------------------------------------- $6,241 435 6,676 124 86 81 410 7,377 138 7,515 ===================================================================================================================================
o Costs incurred include capitalized and expensed items. o Acquisition costs include the costs of acquiring proved and unproved oil and gas properties. The amounts in 2002 relate primarily to the merger. Acquisition costs included proved properties of $3,420 million, $13 million and $87 million in the Lower 48 for 2002, 2001, and 2000, respectively. The 2002 amounts in Norway and the U.K. included $1,255 million and $2,464 million for proved properties, respectively. The 2002 and 2000 amounts in Canada included proved properties of $2,003 million and $33 million, respectively. The 2002 and 2001 amounts in Other Areas included $1,493 million and $63 million for proved properties. The 2002 amount for Equity Affiliates of $1,671 million is for proved properties. The 2000 amount in Alaska included $5,125 million for proved properties. o Exploration costs include geological and geophysical expenses, the cost of retaining undeveloped leaseholds, and exploratory drilling costs. o Development costs include the cost of drilling and equipping development wells and building related production facilities for extracting, treating, gathering and storing petroleum liquids and natural gas. 159 o CAPITALIZED COSTS
At December 31 Millions of Dollars ---------------------------------------------------------------------------------------------------- Consolidated Operations ----------------------------------------------------------------------------- Lower Total Other Equity Combined Alaska 48 U.S Norway U.K. Canada Areas Total Affiliates Total ---------------------------------------------------------------------------------------------------- 2002 Proved properties $7,037 7,737 14,774 5,422 4,178 2,023 3,832 30,229 2,847 33,076 Unproved properties 849 489 1,338 142 622 546 1,556 4,204 -- 4,204 ----------------------------------------------------------------------------------------------------------------------------------- 7,886 8,226 16,112 5,564 4,800 2,569 5,388 34,433 2,847 37,280 Accumulated depreciation, depletion and amortization 1,636 2,891 4,527 2,224 1,033 182 661 8,627 37 8,664 ----------------------------------------------------------------------------------------------------------------------------------- $6,250 5,335 11,585 3,340 3,767 2,387 4,727 25,806 2,810 28,616 =================================================================================================================================== 2001 Proved properties $6,646 4,552 11,198 2,889 1,773 104 1,752 17,716 708 18,424 Unproved properties 772 181 953 40 41 3 768 1,805 -- 1,805 ----------------------------------------------------------------------------------------------------------------------------------- 7,418 4,733 12,151 2,929 1,814 107 2,520 19,521 708 20,229 Accumulated depreciation, depletion and amortization 1,097 3,238 4,335 1,529 1,161 79 540 7,644 4 7,648 ----------------------------------------------------------------------------------------------------------------------------------- $6,321 1,495 7,816 1,400 653 28 1,980 11,877 704 12,581 ===================================================================================================================================
o Capitalized costs include the cost of equipment and facilities for oil and gas producing activities. These costs include the activities of ConocoPhillips' E&P organization, excluding pipeline and marine operations, the Kenai liquefied natural gas operation, Syncrude operations, and crude oil and natural gas marketing activities. o Proved properties include capitalized costs for oil and gas leaseholds holding proved reserves; development wells and related equipment and facilities (including uncompleted development well costs); and support equipment. o Unproved properties include capitalized costs for oil and gas leaseholds under exploration (including where petroleum liquids and natural gas were found but determination of the economic viability of the required infrastructure is dependent upon further exploratory work under way or firmly planned) and for uncompleted exploratory well costs, including exploratory wells under evaluation. 160 o STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVE QUANTITIES Amounts are computed using year-end prices and costs (adjusted only for existing contractual changes), appropriate statutory tax rates and a prescribed 10 percent discount factor. Continuation of year-end economic conditions also is assumed. The calculation is based on estimates of proved reserves, which are revised over time as new data become available. Probable or possible reserves, which may become proved in the future, are not considered. The calculation also requires assumptions as to the timing of future production of proved reserves, and the timing and amount of future development and production costs. While due care was taken in its preparation, the company does not represent that this data is the fair value of the company's oil and gas properties, or a fair estimate of the present value of cash flows to be obtained from their development and production. 161 DISCOUNTED FUTURE NET CASH FLOWS
At December 31 Millions of Dollars ---------------------------------------------------------------------------------------------------- Consolidated Operations ----------------------------------------------------------------------------- Lower Total Other Equity Combined Alaska 48 U.S Norway U.K. Canada Areas Total Affiliates Total ---------------------------------------------------------------------------------------------------- 2002 Future cash inflows $54,497 28,679 83,176 29,571 11,709 8,076 22,654 155,186 32,983 188,169 Less: Future production and transportation costs 26,035 7,763 33,798 4,598 3,376 1,885 5,403 49,060 4,992 54,052 Future development costs 2,927 1,168 4,095 1,762 1,227 617 2,249 9,950 1,698 11,648 Future income tax provisions 7,665 5,349 13,014 16,998 3,077 2,361 6,912 42,362 8,501 50,863 ----------------------------------------------------------------------------------------------------------------------------------- Future net cash flows 17,870 14,399 32,269 6,213 4,029 3,213 8,090 53,814 17,792 71,606 10 percent annual discount 9,097 7,405 16,502 2,515 1,483 1,422 3,730 25,652 11,585 37,237 ----------------------------------------------------------------------------------------------------------------------------------- Discounted future net cash flows $ 8,773 6,994 15,767 3,698 2,546 1,791 4,360* 28,162 6,207 34,369 =================================================================================================================================== 2001 Future cash inflows $33,138 9,441 42,579 14,278 2,143 174 6,712 65,886 11,581 77,467 Less: Future production and transportation costs 20,541 4,241 24,782 2,117 357 52 1,426 28,734 3,483 32,217 Future development costs 3,071 530 3,601 627 248 9 1,079 5,564 1,282 6,846 Future income tax provisions 1,797 1,253 3,050 8,762 389 8 2,596 14,805 2,133 16,938 ----------------------------------------------------------------------------------------------------------------------------------- Future net cash flows 7,729 3,417 11,146 2,772 1,149 105 1,611 16,783 4,683 21,466 10 percent annual discount 3,297 1,821 5,118 1,247 360 44 1,019 7,788 3,687 11,475 ----------------------------------------------------------------------------------------------------------------------------------- Discounted future net cash flows $ 4,432 1,596 6,028 1,525 789 61 592** 8,995 996 9,991 =================================================================================================================================== 2000 Future cash inflows $39,554 29,027 68,581 16,002 3,012 537 7,792 95,924 14,812 110,736 Less: Future production and transportation costs 20,338 3,996 24,334 2,060 426 105 1,379 28,304 2,519 30,823 Future development costs 2,916 479 3,395 679 372 1 1,024 5,471 1,684 7,155 Future income tax provisions 3,772 8,206 11,978 10,103 592 160 2,316 25,149 2,546 27,695 ----------------------------------------------------------------------------------------------------------------------------------- Future net cash flows 12,528 16,346 28,874 3,160 1,622 271 3,073 37,000 8,063 45,063 10 percent annual discount 5,660 8,684 14,344 1,429 571 113 1,761 18,218 6,428 24,646 ----------------------------------------------------------------------------------------------------------------------------------- Discounted future net cash flows $ 6,868 7,662 14,530 1,731 1,051 158 1,312 18,782 1,635 20,417 ===================================================================================================================================
*Includes $139 million attributable to a consolidated subsidiary in which there is a 10 percent minority interest. **Includes $17 million attributable to a consolidated subsidiary in which there is a 13 percent minority interest. Excludes discounted future net cash flows from Canadian Syncrude of $869 million. 162 SOURCES OF CHANGE IN DISCOUNTED FUTURE NET CASH FLOWS
Millions of Dollars ---------------------------------------------------------------------------------------- Consolidated Operations Equity Affiliates Total ---------------------------- --------------------------- --------------------------- 2002 2001 2000 2002 2001 2000 2002 2001 2000 ---------------------------- --------------------------- --------------------------- Discounted future net cash flows at the beginning of the year $ 8,995 18,782 6,205 996 1,635 -- 9,991 20,417 6,205 --------------------------------------------------------------------------------------------------------------------------------- Changes during the year Revenues less production and transportation costs for the year (5,271) (4,283) (4,592) (177) (6) -- (5,448) (4,289) (4,592) Net change in prices, and production and transportation costs 15,566 (14,668) 10,396 2,734 (1,552) -- 18,300 (16,220) 10,396 Extensions, discoveries and improved recovery, less estimated future costs 1,284 757 1,817 22 -- 2,402 1,306 757 4,219 Development costs for the year 2,151 1,495 995 467 420 135 2,618 1,915 1,130 Changes in estimated future development costs (1,790) (1,011) (775) (108) (17) (135) (1,898) (1,028) (910) Purchases of reserves in place, less estimated future costs 22,161 130 8,168 4,781 -- -- 26,942 130 8,168 Sales of reserves in place, less estimated future costs (563) (9) (1,037) (16) -- -- (579) (9) (1,037) Revisions of previous quantity estimates* (185) 15 1,750 (712) 38 -- (897) 53 1,750 Accretion of discount 1,540 2,877 1,217 177 260 -- 1,717 3,137 1,217 Net change in income taxes (15,726) 4,909 (5,360) (1,957) 218 (767) (17,683) 5,127 (6,127) Other -- 1 (2) -- -- -- -- 1 (2) --------------------------------------------------------------------------------------------------------------------------------- Total changes 19,167 (9,787) 12,577 5,211 (639) 1,635 24,378 (10,426) 14,212 --------------------------------------------------------------------------------------------------------------------------------- Discounted future net cash flows at year-end $ 28,162 8,995 18,782 6,207 996 1,635 34,369 9,991 20,417 =================================================================================================================================
*Includes amounts resulting from changes in the timing of production. o The net change in prices, and production and transportation costs is the beginning-of-the-year reserve-production forecast multiplied by the net annual change in the per-unit sales price, and production and transportation cost, discounted at 10 percent. o Purchases and sales of reserves in place, along with extensions, discoveries and improved recovery, are calculated using production forecasts of the applicable reserve quantities for the year multiplied by the end-of-the-year sales prices, less future estimated costs, discounted at 10 percent. o The accretion of discount is 10 percent of the prior year's discounted future cash inflows, less future production, transportation and development costs. o The net change in income taxes is the annual change in the discounted future income tax provisions. 163 -------------------------------------------------------------------------------- SELECTED QUARTERLY FINANCIAL DATA
Millions of Dollars Per Share of Common Stock ------------------------------------------------------- ---------------------------------------------------- Income (Loss) Before Extraordinary Income (loss) Before Income from Items and Extraordinary Items Continuing Cumulative and Cumulative Sales and Operations Effect of Effect of Change in Other Before Change in Net Accounting Principle Net Income (loss) Operating Income Accounting Income ---------------------- ---------------------- Revenues* Taxes* Principle (Loss) Basic Diluted Basic Diluted -------------------------------------------------------- ------- ------- ------- ------- 2002 First $ 8,431 51 (102) (102) (.27) (.27) (.27) (.27) Second 10,414 678 366 351 .95 .95 .91 .91 Third 14,557 312 (116) (116) (.24) (.24) (.24) (.24) Fourth 23,346 1,123 (427) (428) (.63) (.63) (.63) (.63) ------------------------------------------------------------------------------------------------------------------------------ 2001 First $ 5,160 1,019 488 516 1.91 1.90 2.02 2.01 Second 5,179 1,198 619 619 2.42 2.40 2.42 2.40 Third 5,808 699 374 364 1.35 1.34 1.31 1.30 Fourth 8,745 339 162 162 .42 .42 .42 .42 ------------------------------------------------------------------------------------------------------------------------------
*Restated to exclude discontinued operations. See Management's Discussion and Analysis and Note 4--Discontinued Operations in the Notes to Consolidated Financial Statements for additional information. Sales and other operating revenues include excise taxes on petroleum products sales. 164 CONDENSED CONSOLIDATING FINANCIAL INFORMATION In connection with the merger of ConocoPhillips Holding Company (formerly named Conoco Inc.) and ConocoPhillips Company (formerly named Phillips Petroleum Company) with wholly owned subsidiaries of ConocoPhillips, and to simplify the company's credit structure, the companies have established various cross guarantees. With the new organizational structure, ConocoPhillips Company is the direct or indirect parent of former Conoco and Phillips subsidiaries and is wholly owned by ConocoPhillips Holding Company, which is wholly owned by ConocoPhillips. ConocoPhillips and ConocoPhillips Holding Company have fully and unconditionally guaranteed the payment obligations of ConocoPhillips Company with respect to its publicly held debt securities. Similarly, ConocoPhillips and ConocoPhillips Company have fully and unconditionally guaranteed the payment obligations of ConocoPhillips Holding Company with respect to the publicly held debt securities of ConocoPhillips Holding Company. In addition, ConocoPhillips Company and ConocoPhillips Holding Company have fully and unconditionally guaranteed the payment obligations of ConocoPhillips with respect to its publicly held debt securities. All guarantees are joint and several. The following condensed consolidating financial statements present the results of operations, financial position and cash flows for: o ConocoPhillips, ConocoPhillips Company, ConocoPhillips Holding Company (in each case, reflecting investments in subsidiaries utilizing the equity method of accounting); o All other non-guarantor subsidiaries of ConocoPhillips Holding Company and ConocoPhillips Company; and o The consolidating adjustments necessary to present ConocoPhillips' results on a consolidated basis. These condensed consolidating financial statements should be read in conjunction with the company's accompanying consolidated financial statements. 165
Millions of Dollars ---------------------------------------------------------------------------------------- Year Ended December 31, 2002 ---------------------------------------------------------------------------------------- ConocoPhillips Consoli- Holding ConocoPhillips All Other dating Total STATEMENT OF OPERATIONS ConocoPhillips Company Company Subsidiaries* Adjustments Consolidated -------------- -------------- -------------- ------------- ----------- ------------ REVENUES Sales and other operating revenues $ -- -- 16,744 40,004 -- 56,748 Equity in earnings (losses) of affiliates (646) (682) 352 255 982 261 Other income -- -- (48) 263 -- 215 Intercompany revenues -- 191 2,800 3,123 (6,114) -- ----------------------------------------------------------------------------------------------------------------------------------- Total revenues (646) (491) 19,848 43,645 (5,132) 57,224 ----------------------------------------------------------------------------------------------------------------------------------- COSTS AND EXPENSES Purchased crude oil and products -- -- 15,595 27,854 (5,626) 37,823 Production and operating expenses -- 9 1,438 3,573 (32) 4,988 Selling, general and administrative expenses 3 -- 980 681 (4) 1,660 Exploration expenses -- -- 165 427 -- 592 Depreciation, depletion and amortization -- -- 584 1,639 -- 2,223 Impairments -- -- -- 177 -- 177 Taxes other than income taxes -- -- 785 6,152 -- 6,937 Accretion on discounted liabilities -- -- (1) 23 -- 22 Interest and debt expense 29 120 745 124 (452) 566 Foreign currency transaction losses -- -- 8 16 -- 24 Preferred dividend requirements of capital trusts and minority interests -- -- -- 48 -- 48 ----------------------------------------------------------------------------------------------------------------------------------- Total Costs and Expenses 32 129 20,299 40,714 (6,114) 55,060 ----------------------------------------------------------------------------------------------------------------------------------- Income (loss) from continuing operations before income taxes (678) (620) (451) 2,931 982 2,164 Provision for income taxes (11) 26 (202) 1,637 -- 1,450 ----------------------------------------------------------------------------------------------------------------------------------- Income (loss) from continuing operations (667) (646) (249) 1,294 982 714 Income (loss) from discontinued operations -- -- (70) (923) -- (993) ----------------------------------------------------------------------------------------------------------------------------------- Income (loss) before extraordinary items (667) (646) (319) 371 982 (279) Extraordinary items -- -- (14) (2) -- (16) ----------------------------------------------------------------------------------------------------------------------------------- NET INCOME (LOSS) $ (667) (646) (333) 369 982 (295) ===================================================================================================================================
*At December 31, 2002, Tosco Corporation (Tosco) was a wholly owned subsidiary of ConocoPhillips Company and included in All Other Subsidiaries. On January 1, 2003, Tosco was merged into ConocoPhillips Company. As a result of this merger, Tosco ceased to exist as a legal entity and ConocoPhillips Company assumed all of Tosco's properties, rights and obligations. 166
Millions of Dollars ------------------------------------------------------------------------------------ Year Ended December 31, 2001 ------------------------------------------------------------------------------------ ConocoPhillips Consoli- Holding ConocoPhillips All Other dating Total STATEMENT OF OPERATIONS ConocoPhillips Company Company Subsidiaries* Adjustments Consolidated -------------- -------------- -------------- ------------- ----------- ------------ REVENUES Sales and other operating revenues $ - - 12,457 12,435 - 24,892 Equity in earnings (losses) of affiliates - - 1,583 222 (1,764) 41 Other income - - (1) 112 - 111 Intercompany revenues - - 1,308 1,985 (3,293) - ----------------------------------------------------------------------------------------------------------------------------------- Total revenues - - 15,347 14,754 (5,057) 25,044 ----------------------------------------------------------------------------------------------------------------------------------- COSTS AND EXPENSES Purchased crude oil and products - - 9,015 7,290 (2,597) 13,708 Production and operating expenses - - 1,166 1,746 (269) 2,643 Selling, general and administrative expenses - - 540 90 (17) 613 Exploration expenses - - 139 222 (55) 306 Depreciation, depletion and amortization - - 379 965 - 1,344 Impairments - - - 26 - 26 Taxes other than income taxes - - 1,874 866 - 2,740 Accretion on discounted liabilities - - 2 5 - 7 Interest and debt expense - - 551 142 (355) 338 Foreign currency transaction losses (gains) - - (1) 12 - 11 Preferred dividend requirements of capital trusts and minority interests - - - 53 - 53 ----------------------------------------------------------------------------------------------------------------------------------- Total Costs and Expenses - - 13,665 11,417 (3,293) 21,789 ----------------------------------------------------------------------------------------------------------------------------------- Income (loss) from continuing operations before income taxes - - 1,682 3,337 (1,764) 3,255 Provision for income taxes - - 50 1,594 - 1,644 ----------------------------------------------------------------------------------------------------------------------------------- Income (loss) from continuing operations - - 1,632 1,743 (1,764) 1,611 Income from discontinued operations - - 11 21 - 32 ----------------------------------------------------------------------------------------------------------------------------------- Income (loss) before extraordinary items and cumulative effect of change in accounting principle - - 1,643 1,764 (1,764) 1,643 Extraordinary items - - (10) - - (10) Cumulative effect of change in accounting principle - - 28 - - 28 ------------------------------------------------------------------------------------------------------------------------------------ NET INCOME (LOSS) $ - - 1,661 1,764 (1,764) 1,661 ====================================================================================================================================
*At December 31, 2002, Tosco Corporation (Tosco) was a wholly owned subsidiary of ConocoPhillips Company and included in All Other Subsidiaries. On January 1, 2003, Tosco was merged into ConocoPhillips Company. As a result of this merger, Tosco ceased to exist as a legal entity and ConocoPhillips Company assumed all of Tosco's properties, rights and obligations. 167
Millions of Dollars --------------------------------------------------------------------------------------- Year Ended December 31, 2000 --------------------------------------------------------------------------------------- ConocoPhillips Consoli- Holding ConocoPhillips All Other dating Total STATEMENT OF OPERATIONS ConocoPhillips Company Company Subsidiaries Adjustments Consolidated -------------- -------------- -------------- ------------ ----------- ------------ REVENUES Sales and other operating revenues $ - - 15,252 6,903 - 22,155 Equity in earnings (losses) of affiliates - - 1,471 218 (1,575) 114 Other income - - 292 (22) - 270 Intercompany revenues - - 1,663 2,319 (3,982) - ------------------------------------------------------------------------------------------------------------------------------------ Total revenues - - 18,678 9,418 (5,557) 22,539 ------------------------------------------------------------------------------------------------------------------------------------ COSTS AND EXPENSES Purchased crude oil and products - - 11,924 3,173 (3,303) 11,794 Production and operating expenses - - 1,244 1,160 (268) 2,136 Selling, general and administrative expenses - - 563 42 (34) 571 Exploration expenses - - 112 208 (22) 298 Depreciation, depletion and amortization - - 391 778 - 1,169 Impairments - - 13 87 - 100 Taxes other than income taxes - - 1,939 303 - 2,242 Interest and debt expense - - 575 149 (355) 369 Foreign currency transaction losses - - - 58 - 58 Preferred dividend requirements of capital trusts and minority interests - - - 54 - 54 ------------------------------------------------------------------------------------------------------------------------------------ Total Costs and Expenses - - 16,761 6,012 (3,982) 18,791 ------------------------------------------------------------------------------------------------------------------------------------ Income (loss) from continuing operations before income taxes - - 1,917 3,406 (1,575) 3,748 Provision for income taxes - - 70 1,830 - 1,900 ------------------------------------------------------------------------------------------------------------------------------------ Income (loss) from continuing operations - - 1,847 1,576 (1,575) 1,848 Income (loss) from discontinued operations - - 15 (1) - 14 ------------------------------------------------------------------------------------------------------------------------------------ NET INCOME (LOSS) $ - - 1,862 1,575 (1,575) 1,862 ====================================================================================================================================
168
Millions of Dollars -------------------------------------------------------------------------------------- At December 31, 2002 -------------------------------------------------------------------------------------- ConocoPhillips Consoli- Holding ConocoPhillips All Other dating Total BALANCE SHEET ConocoPhillips Company Company Subsidiaries* Adjustments Consolidated -------------- -------------- -------------- ------------- ----------- ------------ ASSETS Cash and cash equivalents $ -- -- 113 194 -- 307 Accounts and notes receivable 8 -- 15,655 13,921 (25,204) 4,380 Inventories -- -- 1,321 2,524 -- 3,845 Prepaid expenses and other current assets 5 -- 153 543 65 766 Assets of discontinued operations held for sale -- -- 263 1,342 -- 1,605 ----------------------------------------------------------------------------------------------------------------------------------- Total Current Assets 13 -- 17,505 18,524 (25,139) 10,903 Investments and long-term receivables 32,301 35,538 44,011 23,124 (128,153) 6,821 Net properties, plants and equipment -- -- 8,893 34,137 -- 43,030 Goodwill** -- -- -- 14,444 -- 14,444 Intangibles -- -- 6 1,113 -- 1,119 Other assets 14 19 110 376 -- 519 ----------------------------------------------------------------------------------------------------------------------------------- Total 32,328 35,557 70,525 91,718 (153,292) 76,836 =================================================================================================================================== LIABILITIES AND STOCKHOLDERS' EQUITY Accounts payable 5,840 3,291 14,071 8,254 (25,204) 6,252 Notes payable and long-term debt due within one year -- 526 164 159 -- 849 Accrued income and other taxes (1) 53 255 1,684 -- 1,991 Other accruals 21 58 1,242 1,754 -- 3,075 Liabilities of discontinued operations held for sale -- -- 126 523 -- 649 ----------------------------------------------------------------------------------------------------------------------------------- Total Current Liabilities 5,860 3,928 15,858 12,374 (25,204) 12,816 Long-term debt 3,509 4,054 5,553 5,801 -- 18,917 Accrued dismantlement, removal and environmental costs -- -- 247 1,419 -- 1,666 Deferred income taxes -- (41) 766 7,644 (8) 8,361 Employee benefit obligations -- -- 1,213 1,542 -- 2,755 Other liabilities and deferred credits -- 3,729 34,081 32,100 (68,107) 1,803 ----------------------------------------------------------------------------------------------------------------------------------- Total Liabilities 9,369 11,670 57,718 60,880 (93,319) 46,318 Trust Preferred Securities and other minority interests -- (12) -- 1,013 -- 1,001 Retained earnings (937) (1,349) 7,331 8,792 (8,216) 5,621 Other stockholders' equity 23,896 25,248 5,476 21,033 (51,757) 23,896 ----------------------------------------------------------------------------------------------------------------------------------- Total $ 32,328 35,557 70,525 91,718 (153,292) 76,836 ===================================================================================================================================
*At December 31, 2002, Tosco Corporation (Tosco) was a wholly owned subsidiary of ConocoPhillips Company and included in All Other Subsidiaries. On January 1, 2003, Tosco was merged into ConocoPhillips Company. As a result of this merger, Tosco ceased to exist as a legal entity and ConocoPhillips Company assumed all of Tosco's properties, rights and obligations. **ConocoPhillips has not yet determined the assignment of Conoco goodwill to specific reporting units and related subsidiaries. Currently, Conoco goodwill is reported as part of the Corporate and Other reporting segment in All Other Subsidiaries. 169
Millions of Dollars ---------------------------------------------------------------------------------------- At December 31, 2001 ---------------------------------------------------------------------------------------- ConocoPhillips Consoli- Holding ConocoPhillips All Other dating Total BALANCE SHEET ConocoPhillips Company Company Subsidiaries* Adjustments Consolidated -------------- -------------- -------------- ------------- ----------- ------------ ASSETS Cash and cash equivalents $ -- -- 19 123 -- 142 Accounts and notes receivable -- -- 1,535 2,232 (2,538) 1,229 Inventories -- -- 307 2,145 -- 2,452 Prepaid expenses and other current assets -- -- 93 200 -- 293 Assets of discontinued operations held for sale -- -- 184 2,198 -- 2,382 ----------------------------------------------------------------------------------------------------------------------------------- Total Current Assets -- -- 2,138 6,898 (2,538) 6,498 Investments and long-term receivables -- -- 25,381 10,148 (32,220) 3,309 Net properties, plants and equipment -- -- 3,879 18,254 -- 22,133 Goodwill -- -- -- 2,281 -- 2,281 Intangibles -- -- 59 802 -- 861 Other assets -- -- 68 67 -- 135 ----------------------------------------------------------------------------------------------------------------------------------- Total -- -- 31,525 38,450 (34,758) 35,217 =================================================================================================================================== LIABILITIES AND STOCKHOLDERS' EQUITY Accounts payable -- -- 1,939 3,190 (2,507) 2,622 Notes payable and long-term debt due within one year -- -- 4 40 -- 44 Accrued income and other taxes -- -- (31) 928 -- 897 Other accruals -- -- 238 482 -- 720 Liabilities of discontinued operations held for sale -- -- 34 504 -- 538 ----------------------------------------------------------------------------------------------------------------------------------- Total Current Liabilities -- -- 2,184 5,144 (2,507) 4,821 Long-term debt -- -- 7,282 1,328 -- 8,610 Accrued dismantlement, removal and environmental costs -- -- 356 703 -- 1,059 Deferred income taxes -- -- 467 3,556 (8) 4,015 Employee benefit obligations -- -- 725 223 -- 948 Other liabilities and deferred credits -- -- 6,175 3,072 (8,478) 769 ----------------------------------------------------------------------------------------------------------------------------------- Total Liabilities -- -- 17,189 14,026 (10,993) 20,222 Trust Preferred Securities and other minority interests -- -- -- 655 -- 655 Retained earnings -- -- 7,197 23,889 (23,889) 7,197 Other stockholders' equity -- -- 7,139 (120) 124 7,143 ----------------------------------------------------------------------------------------------------------------------------------- Total $ -- -- 31,525 38,450 (34,758) 35,217 ===================================================================================================================================
*At December 31, 2002, Tosco Corporation (Tosco) was a wholly owned subsidiary of ConocoPhillips Company and included in All Other Subsidiaries. On January 1, 2003, Tosco was merged into ConocoPhillips Company. As a result of this merger, Tosco ceased to exist as a legal entity and ConocoPhillips Company assumed all of Tosco's properties, rights and obligations. 170
Millions of Dollars ---------------------------------------------------------------------------------------- Year Ended December 31, 2002 ---------------------------------------------------------------------------------------- ConocoPhillips Consoli- Holding ConocoPhillips All Other dating Total STATEMENT OF CASH FLOWS ConocoPhillips Company Company Subsidiaries* Adjustments Consolidated -------------- -------------- -------------- ------------- ----------- ------------ CASH FLOWS FROM OPERATING ACTIVITIES Net cash provided by (used in) continuing operations $ 1,120 2,859 1,060 1,887 (2,159) 4,767 Net cash provided by (used in) discontinued operations -- -- (7) 209 -- 202 ----------------------------------------------------------------------------------------------------------------------------------- Net Cash Provided by (Used in) Operating Activities 1,120 2,859 1,053 2,096 (2,159) 4,969 ----------------------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM INVESTING ACTIVITIES Acquisitions, net of cash acquired -- -- (81) 1,261 -- 1,180 Capital expenditures and investments, including dry holes -- (346) (618) (3,897) 473 (4,388) Proceeds from asset dispositions -- -- (179) 794 200 815 Long-term advances to affiliates and other investments (4,344) (1,200) (12,154) (2,030) 19,636 (92) ----------------------------------------------------------------------------------------------------------------------------------- Net cash used in continuing operations (4,344) (1,546) (13,032) (3,872) 20,309 (2,485) Net cash used in discontinued operations -- -- (6) (93) -- (99) ----------------------------------------------------------------------------------------------------------------------------------- Net Cash Used in Investing Activities (4,344) (1,546) (13,038) (3,965) 20,309 (2,584) ----------------------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM FINANCING ACTIVITIES Issuance of debt 3,502 3,012 15,350 1,274 (19,636) 3,502 Repayment of debt -- (3,006) (1,680) (215) 309 (4,592) Redemption of preferred stock of subsidiaries -- -- -- (300) -- (300) Issuance of company common stock 7 -- 37 -- -- 44 Dividends paid on common stock (271) (1,200) (1,621) 1,231 1,177 (684) Other (14) (119) (7) (50) -- (190) ----------------------------------------------------------------------------------------------------------------------------------- Net Cash Provided by (Used in) Financing Activities 3,224 (1,313) 12,079 1,940 (18,150) (2,220) ----------------------------------------------------------------------------------------------------------------------------------- NET CHANGE IN CASH AND CASH EQUIVALENTS -- -- 94 71 -- 165 Cash and cash equivalents at beginning of year -- -- 19 123 -- 142 ----------------------------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents at End of Year $ -- -- 113 194 -- 307 ===================================================================================================================================
*At December 31, 2002, Tosco Corporation (Tosco) was a wholly owned subsidiary of ConocoPhillips Company and included in All Other Subsidiaries. On January 1, 2003, Tosco was merged into ConocoPhillips Company. As a result of this merger, Tosco ceased to exist as a legal entity and ConocoPhillips Company assumed all of Tosco's properties, rights and obligations. 171
Millions of Dollars ---------------------------------------------------------------------------------------- Year Ended December 31, 2001 ---------------------------------------------------------------------------------------- ConocoPhillips Consoli- Holding ConocoPhillips All Other dating Total STATEMENT OF CASH FLOWS ConocoPhillips Company Company Subsidiaries* Adjustments Consolidated -------------- -------------- -------------- ------------- ----------- ------------ CASH FLOWS FROM OPERATING ACTIVITIES Net cash provided by (used in) continuing operations $ -- -- 2,302 1,628 (401) 3,529 Net cash provided by discontinued operations -- -- 25 8 -- 33 ----------------------------------------------------------------------------------------------------------------------------------- Net Cash Provided by (Used in) Operating Activities -- -- 2,327 1,636 (401) 3,562 ----------------------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM INVESTING ACTIVITIES Acquisitions, net of cash acquired -- -- (23) 103 -- 80 Capital expenditures and investments, including dry holes -- -- (814) (2,343) 141 (3,016) Proceeds from asset dispositions -- -- 17 245 -- 262 Long-term advances to affiliates and other investments -- -- (670) 446 196 (28) ----------------------------------------------------------------------------------------------------------------------------------- Net cash used in continuing operations -- -- (1,490) (1,549) 337 (2,702) Net cash used in discontinued operations -- -- (8) (60) -- (68) ----------------------------------------------------------------------------------------------------------------------------------- Net Cash Used in Investing Activities -- -- (1,498) (1,609) 337 (2,770) ----------------------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM FINANCING ACTIVITIES Issuance of debt -- -- 566 643 (643) 566 Repayment of debt -- -- (1,050) (342) 447 (945) Issuance of company common stock -- -- 51 -- -- 51 Dividends paid on common stock -- -- (403) (259) 259 (403) Other -- -- (13) (56) 1 (68) ----------------------------------------------------------------------------------------------------------------------------------- Net Cash Provided by (Used in) Financing Activities -- -- (849) (14) 64 (799) ----------------------------------------------------------------------------------------------------------------------------------- NET CHANGE IN CASH AND CASH EQUIVALENTS -- -- (20) 13 -- (7) Cash and cash equivalents at beginning of year -- -- 39 110 -- 149 ----------------------------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents at End of Year $ -- -- 19 123 -- 142 ===================================================================================================================================
*At December 31, 2002, Tosco Corporation (Tosco) was a wholly owned subsidiary of ConocoPhillips Company and included in All Other Subsidiaries. On January 1, 2003, Tosco was merged into ConocoPhillips Company. As a result of this merger, Tosco ceased to exist as a legal entity and ConocoPhillips Company assumed all of Tosco's properties, rights and obligations. 172
Millions of Dollars --------------------------------------------------------------------------------------- Year Ended December 31, 2000 --------------------------------------------------------------------------------------- ConocoPhillips Consoli- Holding ConocoPhillips All Other dating Total STATEMENT OF CASH FLOWS ConocoPhillips Company Company Subsidiaries Adjustments Consolidated -------------- -------------- -------------- ------------ ----------- ------------ CASH FLOWS FROM OPERATING ACTIVITIES Net cash provided by (used in) continuing operations $ - - 1,684 3,893 (1,593) 3,984 Net cash provided by discontinued operations - - 30 - - 30 ---------------------------------------------------------------------------------------------------------------------------------- Net Cash Provided by (Used in) Operating Activities - - 1,714 3,893 (1,593) 4,014 ---------------------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM INVESTING ACTIVITIES Acquisitions, net of cash acquired - - (6,443) - - (6,443) Capital expenditures and investments, including dry holes - - (1,342) (1,825) 1,150 (2,017) Proceeds from contributing assets to joint ventures - - 841 1,220 - 2,061 Proceeds from asset dispositions - - 313 854 (317) 850 Long-term advances to affiliates and other investments - - (349) (3,251) 3,392 (208) ---------------------------------------------------------------------------------------------------------------------------------- Net cash used in continuing operations - - (6,980) (3,002) 4,225 (5,757) Net cash used in discontinued operations - - (5) - - (5) ---------------------------------------------------------------------------------------------------------------------------------- Net Cash Used in Investing Activities - - (6,985) (3,002) 4,225 (5,762) ---------------------------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM FINANCING ACTIVITIES Issuance of debt - - 5,675 269 (3,392) 2,552 Repayment of debt - - (39) (321) - (360) Issuance of company common stock - - 31 - - 31 Dividends paid on common stock - - (346) (761) 761 (346) Other - - (53) (64) (1) (118) ---------------------------------------------------------------------------------------------------------------------------------- Net Cash Provided by (Used in) Financing Activities - - 5,268 (877) (2,632) 1,759 ---------------------------------------------------------------------------------------------------------------------------------- NET CHANGE IN CASH AND CASH EQUIVALENTS - - (3) 14 - 11 Cash and cash equivalents at beginning of year - - 42 96 - 138 ---------------------------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents at End of Year $ - - 39 110 - 149 ==================================================================================================================================
173 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. 174 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Information presented under the headings "Election of Directors and Director Biographies" and "Stock Ownership--Section 16(a) Beneficial Ownership Reporting Compliance" in the company's definitive proxy statement for the Annual Meeting of Stockholders on May 6, 2003 (2003 Proxy Statement), is incorporated herein by reference.* Information regarding the executive officers appears in Part I of this report on pages 32 and 33. ITEM 11. EXECUTIVE COMPENSATION Information presented under the following headings in the 2003 Proxy Statement is incorporated herein by reference: "Board of Directors Information--How are Directors Compensated?" "Executive Compensation--Compensation Tables" "Executive Compensation--Employment Agreements" "Executive Compensation--Severance Arrangements" ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS Information presented under the headings "Stock Ownership--Holdings of Major Stockholders," "--Holdings of Officers and Directors" and "Executive Compensation--Compensation Tables--Equity Compensation Plan Information" in the 2003 Proxy Statement is incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS None. ---------- *Except for information or data specifically incorporated herein by reference under Items 10 through 13, other information and data appearing in the 2003 Proxy Statement are not deemed to be a part of this Annual Report on Form 10-K or deemed to be filed with the Commission as a part of this report. 175 ITEM 14. CONTROLS AND PROCEDURES Within the 90 days prior to the date of this annual report, ConocoPhillips carried out an evaluation, under the supervision, and with the participation of, the company's Management, including the company's President and Chief Executive Officer, and its Executive Vice President Finance and Chief Financial Officer, of the effectiveness of ConocoPhillips' disclosure controls and procedures pursuant to Rule 13a-14 under the Securities Exchange Act of 1934, as amended. Based upon that evaluation, the company's President and Chief Executive Officer and its Executive Vice President Finance and Chief Financial Officer concluded that ConocoPhillips' disclosure controls and procedures are effective, in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Securities and Exchange Commission's rules and forms, of information required to be disclosed by the issuer in the reports that it files or submits under the Exchange Act. There were no significant changes in ConocoPhillips' internal controls or in other factors that could significantly affect internal controls subsequent to the date of the evaluation referred to above. PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) 1. Financial Statements and Financial Statement Schedules ------------------------------------------------------ The financial statements and schedule listed in the Index to Financial Statements and Financial Statement Schedules, which appears on page 82 are filed as part of this annual report. 2. Exhibits -------- The exhibits listed in the Index to Exhibits, which appears on pages 178 through 181, are filed as a part of this annual report. (b) Reports on Form 8-K ------------------- During the three months ended December 31, 2002, the company filed the following Current Reports on Form 8-K: o Amendment No. 1, filed October 1, 2002, to the Current Report on Form 8-K filed August 30, 2002, providing audited financial statements and pro forma financial information related to the merger of Conoco and Phillips. o Filed on October 8, 2002, to report in Item 5 the private placement of $2 billion of various types of Notes and to report the company's third-quarter 2002 interim update of market and operating conditions. o Filed on December 20, 2002, to report in Item 5 that the company was restating its audited financial statements included in its Annual Report on Form 10-K for the year ended December 31, 2001, to reflect discontinued operations and a segment realignment. 176 CONOCOPHILLIPS (CONSOLIDATED) SCHEDULE II--VALUATION AND QUALIFYING ACCOUNTS
Millions of Dollars ----------------------------------------------------------------------------------- Additions --------------------------- Balance At Charged to Balance At Description January 1 Expense Other Deductions December 31 ------------------------------------------------------------------------------------------------------------------------------------ (a) (b) 2002 Deducted from asset accounts: Allowance for doubtful accounts and notes receivable $ 33 21 13 19(c) 48 Deferred tax asset valuation allowance 263 102 251(f) 8 608 Included in other liabilities: Employee termination benefits -- 301 297(f) 223(g) 375 ------------------------------------------------------------------------------------------------------------------------------------ 2001 Deducted from asset accounts: Allowance for doubtful accounts and notes receivable $ 18 13 18 16(c) 33 Deferred tax asset valuation allowance 315 14 (47) 19 263 Included in other liabilities: Reserve for maintenance turnarounds 47 -- -- 47(e) -- ------------------------------------------------------------------------------------------------------------------------------------ 2000 Deducted from asset accounts: Allowance for doubtful accounts and notes receivable $ 19 8 -- 9*(c) 18 Deferred tax asset valuation allowance 328 (11) (2) -- 315 Included in other liabilities: Reserve for maintenance turnarounds 88 52 -- 93(d) 47 ------------------------------------------------------------------------------------------------------------------------------------
*Includes $2 million transferred to joint-venture companies. (a) Amounts charged to income less reversal of amounts previously charged to income. (b) Represents acquisitions/dispositions and the effect of translating foreign financial statements. (c) Amounts charged off less recoveries of amounts previously charged off. (d) Includes $24 million transferred to an equity-affiliate company on July 1, 2000. (e) Effective January 1, 2001, ConocoPhillips changed its method of accounting for the costs of major maintenance turnarounds from the accrue-in-advance method to the expense-as-incurred method. (f) Included in the merger purchase price allocation. (g) Benefit payments. 177 CONOCOPHILLIPS INDEX TO EXHIBITS
Exhibit Number Description ------ ----------- 2 Agreement and Plan of Merger, dated as of November 18, 2001, by and among ConocoPhillips Company (formerly named Phillips Petroleum Company) ("CPCo"), ConocoPhillips (formerly named CorvettePorsche Corp.), P Merger Corp. (formerly named Porsche Merger Corp.), C Merger Corp. (formerly named Corvette Merger Corp.) and ConocoPhillips Holding Company (formerly named Conoco Inc.) ("Holding") (incorporated by reference to Annex A to the Joint Proxy Statement/Prospectus included in ConocoPhillips' Registration Statement on Form S-4; Registration No. 333-74798 (the "Form S-4")). 3.1 Restated Certificate of Incorporation of ConocoPhillips (incorporated by reference to Exhibit 3.1 to the Current Report of ConocoPhillips on Form 8-K filed on August 30, 2002; File No. 000-49987 (the "Form 8-K")). 3.2 Certificate of Designations of Series A Junior Participating Preferred Stock of ConocoPhillips (incorporated by reference to Exhibit 3.2 to the Form 8-K). 3.3 By-Laws of ConocoPhillips (incorporated by reference to Exhibit 3.3 to the Form 8-K). 4.1 Rights agreement, dated as of June 30, 2002, between ConocoPhillips and Mellon Investor Services LLC, as rights agent, which includes as Exhibit A the form of Certificate of Designations of Series A Junior Participating Preferred Stock, as Exhibit B the form of Rights Certificate and as Exhibit C the Summary of Rights to Purchase Preferred Stock (incorporated by reference to Exhibit 4.1 to the Form 8-K). ConocoPhillips and its subsidiaries are parties to several debt instruments under which the total amount of securities authorized does not exceed 10% of the total assets of ConocoPhillips and its subsidiaries on a consolidated basis. Pursuant to paragraph 4(iii)(A) of Item 601(b) of Regulation S-K, ConocoPhillips agrees to furnish a copy of such instruments to the SEC upon request. MATERIAL CONTRACTS 10.1 Trust Agreement dated June 23, 1995, between CPCo and WestStar Bank, as Trustee of the Deferred Compensation Plan for Non-Employee Directors of Phillips Petroleum Company Trust. 10.2 Trust Agreement dated December 12, 1995, between CPCo and Vanguard Fiduciary Trust Company, as Trustee of the Phillips Petroleum Company Compensation and Benefits Arrangements Stock Trust (incorporated by reference to Exhibit 10(c) to the Annual Report of CPCo on Form 10-K for the year ended December 31, 1995; File No. 1-720). 10.3 Contribution Agreement, dated as of December 16, 1999, by and among CPCo, Duke Energy Corporation and Duke Energy Field Services, LLC (incorporated by reference to Exhibit 99.1 to the Current Report of CPCo on Form 8-K, filed December 22, 1999; File No. 1-720).
178
Exhibit Number Description ------ ----------- 10.4 Governance Agreement, dated as of December 16, 1999, by and among CPCo, Duke Energy Corporation and Duke Energy Field Services, LLC (incorporated by reference to Exhibit 99.2 to the Current Report of CPCo on Form 8-K, filed December 22, 1999; File No. 1-720). 10.5 Amended and Restated Limited Liability Company Agreement of Duke Energy Field Services, LLC, dated as of March 31, 2000, by and between Phillips Gas Company and Duke Energy Field Services Corporation (incorporated by reference to Exhibit 99.1 to the Current Report of CPCo on Form 8-K, filed April 13, 2000; File No. 1-720). 10.6 Parent Company Agreement, dated as of March 31, 2000, by and among CPCo, Duke Energy Corporation, Duke Energy Field Services, LLC, and Duke Energy Field Services Corporation (incorporated by reference to Exhibit 99.2 to the Current Report of CPCo on Form 8-K, filed April 13, 2000; File No. 1-720). 10.7 Contribution Agreement, dated as of May 23, 2000, by and among CPCo, Chevron Corporation and Chevron Phillips Chemical Company LLC (incorporated by reference to Exhibit 2.1 to the Current Report of CPCo on Form 8-K, filed June 1, 2000; File No. 1-720). 10.8 Amended and Restated Limited Liability Company Agreement of Chevron Phillips Chemical Company LLC, dated as of July 1, 2000, by and between CPCo, Chevron Corporation, Chevron U.S.A. Inc., Chevron Overseas Petroleum Inc., Chevron Pipe Line Company, Drilling Specialties Co., WesTTex 66 Pipeline Co., and Phillips Petroleum International Corporation (incorporated by reference to Exhibit 99.1 to the Current Report of CPCo on Form 8-K filed July 14, 2000; File No. 1-720). 10.9 Master Purchase and Sale Agreement dated as of March 15, 2000, as amended as of April 6, 2000, among Atlantic Richfield Company, CH-Twenty, Inc., BP Amoco p.l.c. and CPCo (incorporated by reference to Exhibit 2 to the Current Report of CPCo on Form 8-K, filed April 18, 2000; File No. 1-720). 10.10 Trust Agreement dated June 1, 1998, between CPCo and Wachovia Bank, N.A., as Trustee of the Phillips Petroleum Company Grantor Trust. MANAGEMENT CONTRACTS AND COMPENSATORY PLANS OR ARRANGEMENTS 10.11 1986 Stock Plan of Phillips Petroleum Company. 10.12 1990 Stock Plan of Phillips Petroleum Company. 10.13 Annual Incentive Compensation Plan of Phillips Petroleum Company. 10.14 Incentive Compensation Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10(g) to the Annual Report of CPCo on Form 10-K for the year ended December 31, 1999; File No. 1-720).
179
Exhibit Number Description ------ ----------- 10.15 Principal Corporate Officers Supplemental Retirement Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10(h) to the Annual Report of CPCo on Form 10-K for the year ended December 31, 1995; File No. 1-720) 10.16 Phillips Petroleum Company Supplemental Executive Retirement Plan (incorporated by reference to Exhibit 10(n) to the Annual Report of CPCo on Form 10-K for the year ended December 31, 2000; File No. 1-720). 10.17 Key Employee Deferred Compensation Plan of Phillips Petroleum Company. 10.18 Non-Employee Director Retirement Plan of Phillips Petroleum Company. 10.19 Omnibus Securities Plan of Phillips Petroleum Company. 10.20 Deferred Compensation Plan for Non-Employee Directors of Phillips Petroleum Company. 10.21 Key Employee Missed Credited Service Retirement Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10(s) to the Annual Report of CPCo on Form 10-K for the year ended December 31, 2000; File No. 1-720). 10.22 Phillips Petroleum Company Stock Plan for Non-Employee Directors. 10.23 Key Employee Supplemental Retirement Plan of Phillips Petroleum Company. 10.24 Defined Contribution Makeup Plan of ConocoPhillips. 10.25 Phillips Petroleum Company Executive Severance Plan (incorporated by reference to Exhibit 10(a) to the Quarterly Report of CPCo on Form 10-Q for the quarter ended June 30, 1999; File No. 1-720). 10.26 2002 Omnibus Securities Plan of Phillips Petroleum Company. 10.27 1998 Stock and Performance Incentive Plan of ConocoPhillips. 10.28 1998 Key Employee Stock Performance Plan of ConocoPhillips. 10.29 Deferred Compensation Plan for Non-Employee Directors of ConocoPhillips. 10.30 Conoco Inc. Key Employee Severance Plan (incorporated by reference to Exhibit 10.6 to the Annual Report of Holding on Form 10-K for the year ended December 31, 2001; File No. 1-14521). 10.31 Conoco Inc. Salary Deferral and Savings Restoration Plan. 10.32 Conoco Inc. Directors' Charitable Gift Plan. 10.33 Phillips Petroleum Company Director Charitable Contribution Plan.
180
Exhibit Number Description ------ ----------- 10.34 ConocoPhillips Form Indemnity Agreement with Directors. 10.35 Employment Agreement, dated as of November 18, 2001, by and among ConocoPhillips, CPCo and J. J. Mulva (incorporated by reference to Exhibit 10.1 to the Form S-4). 10.36 Employment Agreement, dated as of November 18, 2001, by and among ConocoPhillips, Holding and Archie W. Dunham (incorporated by reference to Exhibit 10.2 to the Form S-4). 10.36.1 Letter Agreement, dated as of July 22, 2002, by and among Holding and Archie W. Dunham. 10.37 Letter Agreement, dated as of April 12, 2002, between Holding and Robert E. McKee III (incorporated by reference to Exhibit 10.1 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarterly period ended September 30, 2002; File No. 000-49987 (the "Form 10-Q")). 10.38 Letter Agreement, dated as of April 12, 2002, between Holding and Jim W. Nokes (incorporated by reference to Exhibit 10.2 to the Form 10-Q). 10.39 Rabbi Trust Agreement dated December 17, 1999 (incorporated by reference to Exhibit 10.11 of Holding's Form 10-K for the year ended December 31, 1999, File No. 001-14521). 10.39.1 Amendment to Rabbi Trust Agreement dated February 25, 2002. 12 Computation of Ratio of Earnings to Fixed Charges. 21 List of Principal Subsidiaries of ConocoPhillips. 23 Consent of Independent Auditors. 99.1 Certification pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 99.2 Certification pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 99.3 Unaudited Pro Forma Combined Statement of Operations for the Year Ended December 31, 2002.
181 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) 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. CONOCOPHILLIPS March 24, 2003 /s/ J. J. Mulva ------------------------------------- J. J. Mulva President and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed on behalf of the registrant by the following officers in the capacity indicated and by a majority of directors in response to Instruction D to Form 10-K on March 24, 2003. SIGNATURE TITLE /s/ Archie W. Dunham Chairman of the Board of Directors -------------------------------- Archie W. Dunham /s/ J. J. Mulva President and Chief Executive Officer -------------------------------- (Principal executive officer) J. J. Mulva /s/ John A. Carrig Executive Vice President, Finance, -------------------------------- and Chief Financial Officer John A. Carrig (Principal financial officer) /s/ Rand C. Berney Vice President and Controller -------------------------------- (Principal accounting officer) Rand C. Berney 182 /s/ Kenneth M. Duberstein Director and Member of -------------------------------- Audit and Compliance Committee Kenneth M. Duberstein /s/ Ruth R. Harkin Director and Member of -------------------------------- Audit and Compliance Committee Ruth R. Harkin /s/ Larry D. Horner Director and Member of -------------------------------- Audit and Compliance Committee Larry D. Horner /s/ Frank A. McPherson Director and Chairperson of -------------------------------- Audit and Compliance Committee Frank A. McPherson /s/ J. Stapleton Roy Director and Member of -------------------------------- Audit and Compliance Committee J. Stapleton Roy /s/ Victoria J. Tschinkel Director and Chairperson of -------------------------------- Public Policy Committee Victoria J. Tschinkel /s/ Kathryn C. Turner Director and Member of -------------------------------- Audit and Compliance Committee Kathryn C. Turner 183 CERTIFICATIONS I, J.J. Mulva, certify that: 1. I have reviewed this annual report on Form 10-K of ConocoPhillips; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: March 24, 2003 /s/ J. J. Mulva -------------------------------------- J. J. Mulva President and Chief Executive Officer 184 I, John A. Carrig, certify that: 1. I have reviewed this annual report on Form 10-K of ConocoPhillips; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: March 24, 2003 /s/ John A. Carrig --------------------------------------------- John A. Carrig Executive Vice President, Finance, and Chief Financial Officer 185 CONOCOPHILLIPS INDEX TO EXHIBITS
Exhibit Number Description ------ ----------- 2 Agreement and Plan of Merger, dated as of November 18, 2001, by and among ConocoPhillips Company (formerly named Phillips Petroleum Company) ("CPCo"), ConocoPhillips (formerly named CorvettePorsche Corp.), P Merger Corp. (formerly named Porsche Merger Corp.), C Merger Corp. (formerly named Corvette Merger Corp.) and ConocoPhillips Holding Company (formerly named Conoco Inc.) ("Holding") (incorporated by reference to Annex A to the Joint Proxy Statement/Prospectus included in ConocoPhillips' Registration Statement on Form S-4; Registration No. 333-74798 (the "Form S-4")). 3.1 Restated Certificate of Incorporation of ConocoPhillips (incorporated by reference to Exhibit 3.1 to the Current Report of ConocoPhillips on Form 8-K filed on August 30, 2002; File No. 000-49987 (the "Form 8-K")). 3.2 Certificate of Designations of Series A Junior Participating Preferred Stock of ConocoPhillips (incorporated by reference to Exhibit 3.2 to the Form 8-K). 3.3 By-Laws of ConocoPhillips (incorporated by reference to Exhibit 3.3 to the Form 8-K). 4.1 Rights agreement, dated as of June 30, 2002, between ConocoPhillips and Mellon Investor Services LLC, as rights agent, which includes as Exhibit A the form of Certificate of Designations of Series A Junior Participating Preferred Stock, as Exhibit B the form of Rights Certificate and as Exhibit C the Summary of Rights to Purchase Preferred Stock (incorporated by reference to Exhibit 4.1 to the Form 8-K). ConocoPhillips and its subsidiaries are parties to several debt instruments under which the total amount of securities authorized does not exceed 10% of the total assets of ConocoPhillips and its subsidiaries on a consolidated basis. Pursuant to paragraph 4(iii)(A) of Item 601(b) of Regulation S-K, ConocoPhillips agrees to furnish a copy of such instruments to the SEC upon request. MATERIAL CONTRACTS 10.1 Trust Agreement dated June 23, 1995, between CPCo and WestStar Bank, as Trustee of the Deferred Compensation Plan for Non-Employee Directors of Phillips Petroleum Company Trust. 10.2 Trust Agreement dated December 12, 1995, between CPCo and Vanguard Fiduciary Trust Company, as Trustee of the Phillips Petroleum Company Compensation and Benefits Arrangements Stock Trust (incorporated by reference to Exhibit 10(c) to the Annual Report of CPCo on Form 10-K for the year ended December 31, 1995; File No. 1-720). 10.3 Contribution Agreement, dated as of December 16, 1999, by and among CPCo, Duke Energy Corporation and Duke Energy Field Services, LLC (incorporated by reference to Exhibit 99.1 to the Current Report of CPCo on Form 8-K, filed December 22, 1999; File No. 1-720).
Exhibit Number Description ------ ----------- 10.4 Governance Agreement, dated as of December 16, 1999, by and among CPCo, Duke Energy Corporation and Duke Energy Field Services, LLC (incorporated by reference to Exhibit 99.2 to the Current Report of CPCo on Form 8-K, filed December 22, 1999; File No. 1-720). 10.5 Amended and Restated Limited Liability Company Agreement of Duke Energy Field Services, LLC, dated as of March 31, 2000, by and between Phillips Gas Company and Duke Energy Field Services Corporation (incorporated by reference to Exhibit 99.1 to the Current Report of CPCo on Form 8-K, filed April 13, 2000; File No. 1-720). 10.6 Parent Company Agreement, dated as of March 31, 2000, by and among CPCo, Duke Energy Corporation, Duke Energy Field Services, LLC, and Duke Energy Field Services Corporation (incorporated by reference to Exhibit 99.2 to the Current Report of CPCo on Form 8-K, filed April 13, 2000; File No. 1-720). 10.7 Contribution Agreement, dated as of May 23, 2000, by and among CPCo, Chevron Corporation and Chevron Phillips Chemical Company LLC (incorporated by reference to Exhibit 2.1 to the Current Report of CPCo on Form 8-K, filed June 1, 2000; File No. 1-720). 10.8 Amended and Restated Limited Liability Company Agreement of Chevron Phillips Chemical Company LLC, dated as of July 1, 2000, by and between CPCo, Chevron Corporation, Chevron U.S.A. Inc., Chevron Overseas Petroleum Inc., Chevron Pipe Line Company, Drilling Specialties Co., WesTTex 66 Pipeline Co., and Phillips Petroleum International Corporation (incorporated by reference to Exhibit 99.1 to the Current Report of CPCo on Form 8-K filed July 14, 2000; File No. 1-720). 10.9 Master Purchase and Sale Agreement dated as of March 15, 2000, as amended as of April 6, 2000, among Atlantic Richfield Company, CH-Twenty, Inc., BP Amoco p.l.c. and CPCo (incorporated by reference to Exhibit 2 to the Current Report of CPCo on Form 8-K, filed April 18, 2000; File No. 1-720). 10.10 Trust Agreement dated June 1, 1998, between CPCo and Wachovia Bank, N.A., as Trustee of the Phillips Petroleum Company Grantor Trust. MANAGEMENT CONTRACTS AND COMPENSATORY PLANS OR ARRANGEMENTS 10.11 1986 Stock Plan of Phillips Petroleum Company. 10.12 1990 Stock Plan of Phillips Petroleum Company. 10.13 Annual Incentive Compensation Plan of Phillips Petroleum Company. 10.14 Incentive Compensation Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10(g) to the Annual Report of CPCo on Form 10-K for the year ended December 31, 1999; File No. 1-720).
Exhibit Number Description ------ ----------- 10.15 Principal Corporate Officers Supplemental Retirement Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10(h) to the Annual Report of CPCo on Form 10-K for the year ended December 31, 1995; File No. 1-720) 10.16 Phillips Petroleum Company Supplemental Executive Retirement Plan (incorporated by reference to Exhibit 10(n) to the Annual Report of CPCo on Form 10-K for the year ended December 31, 2000; File No. 1-720). 10.17 Key Employee Deferred Compensation Plan of Phillips Petroleum Company. 10.18 Non-Employee Director Retirement Plan of Phillips Petroleum Company. 10.19 Omnibus Securities Plan of Phillips Petroleum Company. 10.20 Deferred Compensation Plan for Non-Employee Directors of Phillips Petroleum Company. 10.21 Key Employee Missed Credited Service Retirement Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10(s) to the Annual Report of CPCo on Form 10-K for the year ended December 31, 2000; File No. 1-720). 10.22 Phillips Petroleum Company Stock Plan for Non-Employee Directors. 10.23 Key Employee Supplemental Retirement Plan of Phillips Petroleum Company. 10.24 Defined Contribution Makeup Plan of ConocoPhillips. 10.25 Phillips Petroleum Company Executive Severance Plan (incorporated by reference to Exhibit 10(a) to the Quarterly Report of CPCo on Form 10-Q for the quarter ended June 30, 1999; File No. 1-720). 10.26 2002 Omnibus Securities Plan of Phillips Petroleum Company. 10.27 1998 Stock and Performance Incentive Plan of ConocoPhillips. 10.28 1998 Key Employee Stock Performance Plan of ConocoPhillips. 10.29 Deferred Compensation Plan for Non-Employee Directors of ConocoPhillips. 10.30 Conoco Inc. Key Employee Severance Plan (incorporated by reference to Exhibit 10.6 to the Annual Report of Holding on Form 10-K for the year ended December 31, 2001; File No. 1-14521). 10.31 Conoco Inc. Salary Deferral and Savings Restoration Plan. 10.32 Conoco Inc. Directors' Charitable Gift Plan. 10.33 Phillips Petroleum Company Director Charitable Contribution Plan.
Exhibit Number Description ------ ----------- 10.34 ConocoPhillips Form Indemnity Agreement with Directors. 10.35 Employment Agreement, dated as of November 18, 2001, by and among ConocoPhillips, CPCo and J. J. Mulva (incorporated by reference to Exhibit 10.1 to the Form S-4). 10.36 Employment Agreement, dated as of November 18, 2001, by and among ConocoPhillips, Holding and Archie W. Dunham (incorporated by reference to Exhibit 10.2 to the Form S-4). 10.36.1 Letter Agreement, dated as of July 22, 2002, by and among Holding and Archie W. Dunham. 10.37 Letter Agreement, dated as of April 12, 2002, between Holding and Robert E. McKee III (incorporated by reference to Exhibit 10.1 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarterly period ended September 30, 2002; File No. 000-49987 (the "Form 10-Q")). 10.38 Letter Agreement, dated as of April 12, 2002, between Holding and Jim W. Nokes (incorporated by reference to Exhibit 10.2 to the Form 10-Q). 10.39 Rabbi Trust Agreement dated December 17, 1999 (incorporated by reference to Exhibit 10.11 of Holding's Form 10-K for the year ended December 31, 1999, File No. 001-14521). 10.39.1 Amendment to Rabbi Trust Agreement dated February 25, 2002. 12 Computation of Ratio of Earnings to Fixed Charges. 21 List of Principal Subsidiaries of ConocoPhillips. 23 Consent of Independent Auditors. 99.1 Certification pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 99.2 Certification pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 99.3 Unaudited Pro Forma Combined Statement of Operations for the Year Ended December 31, 2002.