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UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 8-K CURRENT REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Date of Report (date of earliest event reported): DECEMBER 20, 2002 CONOCOPHILLIPS (Exact name of registrant as specified in its charter) DELAWARE 000-49987 01-0562944 (State or other jurisdiction of (Commission (I.R.S. Employer incorporation) File Number) Identification No.) 600 NORTH DAIRY ASHFORD ROAD HOUSTON, TEXAS 77079 (Address of principal executive offices and zip code) Registrant's telephone number, including area code: (281) 293-1000

ITEM 5. OTHER EVENTS. On August 30, 2002 (the Merger Date), Phillips Petroleum Company (Phillips) and Conoco Inc. (Conoco) combined their businesses by merging with separate acquisition subsidiaries of ConocoPhillips. For accounting purposes, Phillips was treated as the acquirer of Conoco, and ConocoPhillips was treated as the successor of Phillips. Accordingly, references to ConocoPhillips, including in the financial statements and other information included in the exhibits to this report, for periods prior to the Merger Date are references to Phillips only, and do not include any information relating to Conoco. In accordance with Financial Accounting Standards Board (FASB) Statement No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," ConocoPhillips presented the operations of certain assets held for disposal as discontinued operations in its financial statements included in its Quarterly Report on Form 10-Q for the period ended September 30, 2002, as filed with the U.S. Securities and Exchange Commission on November 14, 2002. ConocoPhillips has also made certain changes to its alignment of operating segments from those formerly reported in the Phillips 2001 Form 10-K, including: o Transferring the natural gas liquids fractionation and marketing business from the Refining and Marketing segment to the Midstream segment. o Transferring the fuels technology business from the Refining and Marketing segment to the newly created Emerging Businesses segment. o Transferring all discontinued operations to Corporate and Other. ConocoPhillips, as successor to Phillips, is restating the audited financial statements included in the Phillips Annual Report on Form 10-K for the year ended December 31, 2001, as amended, to reflect: o as discontinued operations the Woods Cross refinery and associated wholesale marketing activities (Woods Cross business unit). The Woods Cross business unit was the only asset held for sale that qualifies as a "component of an entity" as defined in Statement No. 144; and o the segment realignments discussed above. Such restated audited financial statements and supplementary data are attached as Exhibit 99 to this Current Report on Form 8-K. In addition, ConocoPhillips is also including in Exhibit 99 to this report Selected Financial Data and Management's Discussion and Analysis of Financial Condition and Results of Operations that reflect the changes noted above. The restated audited financial statements of ConocoPhillips, supplementary data and Management's Discussion and Analysis of Financial Condition and Results of Operations supersede those included in the Phillips Annual Report on Form 10-K for the year ended December 31, 2001, filed on March 20, 2002. Except with respect to the limited matters discussed above, the information set forth in Exhibit 99 speaks as of March 15, 2002, and has not been updated to reflect events subsequent to that date. This 2

Form 8-K should be read in conjunction with ConocoPhillips' other public filings with the Securities and Exchange Commission, including ConocoPhillips' Form 10-Q for the quarterly period ended September 30, 2002, filed on November 14, 2002. 3

ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS. (c) Exhibits 12 -- Restated Computation of Ratio of Earnings to Fixed Charges. 23 -- Consent of Independent Auditors. 99 -- Restated Selected Financial Data, Management's Discussion and Analysis of Financial Condition and Results of Operations, and Financial Statements and Supplementary Data. 4

SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. CONOCOPHILLIPS /s/ Rand C. Berney ----------------------------------------- Rand C. Berney Vice President and Controller Date: December 20, 2002 5

EXHIBIT INDEX

EXHIBIT 12 CONOCOPHILLIPS AND CONSOLIDATED SUBSIDIARIES TOTAL ENTERPRISE Computation of Ratio of Earnings to Fixed Charges

* Includes amortization of capitalized interest totaling approximately $20 million in 2001, $17 million each in 2000 and 1999, $16 million in 1998, and $14 million in 1997. Earnings available for fixed charges include, if any, the company's equity in losses of companies owned less than fifty percent and having debt for which the company is contingently liable. Fixed charges include the company's proportionate share, if any, of interest relating to the contingent debt. In 1990, the company guaranteed a $400 million bank loan for the Long-Term Stock Savings Plan (LTSSP), an employee benefit plan. Consolidated interest expense includes interest attributable to the LTSSP borrowings of $4 million in 2000. Interest attributable to the LTSSP borrowings was minimal in 2001, 1999, 1998 and 1997.

EXHIBIT 23 Consent of Independent Auditors We consent to the incorporation by reference in the Registration Statement (Form S-8 No. 333-98681) of our report dated March 15, 2002 (except for notes 23 and 25, as to which the date is December 20, 2002) with respect to the consolidated financial statements and schedule of ConocoPhillips (formerly Phillips Petroleum Company) included in the Current Report on Form 8-K, filed with the U.S. Securities and Exchange Commission on December 20, 2002. /s/ ERNST & YOUNG LLP ---------------------- ERNST & YOUNG LLP Tulsa, Oklahoma December 20, 2002

EXHIBIT 99 SELECTED FINANCIAL DATA CONOCOPHILLIPS (FORMERLY PHILLIPS PETROLEUM COMPANY)

*Restated to include excise taxes on petroleum products sales. 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. All years have been restated to reflect discontinued operations (see Note 25 in the Notes to Financial Statements). 1

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS March 15, 2002 Management's Discussion and Analysis is ConocoPhillips' 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 54. RESULTS OF OPERATIONS The following is a discussion of the results of operations of ConocoPhillips (ConocoPhillips or the company), as successor to Phillips Petroleum Company (Phillips), for the three years ended December 31, 2001, 2000 and 1999, and reflects the following changes to the information included in the Phillips Petroleum Company Annual Report on Form 10-K for the year ended December 31, 2001: o The restatement as discontinued operations of the Woods Cross refinery and associated wholesale marketing activities; and o The realignment of operating segments, including o transferring the natural gas liquids fractionation and marketing businesses from the Refining and Marketing segment to the Midstream segment; o transferring the fuels technology business from the Refining and Marketing segment to the newly created Emerging Businesses segment; and 2

o transferring all discontinued operations to Corporate and Other. On August 30, 2002 (the Merger Date), Phillips and Conoco Inc. (Conoco) combined their businesses by merging with separate acquisition subsidiaries of ConocoPhillips. For accounting purposes, Phillips was treated as the acquirer of Conoco, and ConocoPhillips was treated as the successor of Phillips. Accordingly, references to ConocoPhillips in the following discussion for periods prior to the Merger Date are to the results of operations and financial condition of Phillips only, and do not include any information relating to Conoco for the periods presented. CONSOLIDATED RESULTS A summary of ConocoPhillips' net income by business segment follows:

Net income is affected by transactions, defined by Management and termed "special items," which are not representative of the company's ongoing operations. These special items can obscure the underlying operating results for a period and affect comparability of operating results between periods. The following table summarizes the gains/(losses), on an after-tax basis, from special items included in the company's net income: 3

*See Note 9 to the financial statements for additional information. **Primarily property impairments recorded by the company's chemicals joint venture. ***See Note 25 to the financial statements for additional information. Excluding the special items listed above, the company's net operating income by business segment was:

2001 vs. 2000 ConocoPhillips' net income was $1,661 million in 2001, an 11 percent decline from record net income of $1,862 million in 2000. Special items reduced net income $37 million in 2001 and $39 million in 2000. After excluding special items, net operating income was $1,698 million in 2001, compared with $1,901 million in 2000. The 11 percent decrease in net operating income in 2001 was primarily attributable to lower results from the E&P, Midstream and Chemicals segments. The E&P segment's results were negatively affected by a 17 percent decrease in its average crude oil price in 2001, while Midstream results decreased due to lower natural gas liquids prices. The Chemicals segment continued to experience a difficult market environment in 2001, marked by low product margins and industry overcapacity resulting in reduced output. R&M's net operating income increased 77 percent in 2001, 4

reflecting improved petroleum products margins, as well as the acquisition of Tosco Corporation in September 2001. See Note 3--Acquisition of Tosco Corporation in the Notes to Financial Statements for additional information on the acquisition. 2000 vs. 1999 ConocoPhillips' net income was $1,862 million in 2000, compared with $609 million in 1999. Special items reduced net income $39 million in 2000, while benefiting 1999 net income by $68 million. After excluding special items, net operating income was $1,901 million in 2000, compared with $541 million in 1999. The 251 percent increase in 2000 net operating income, compared with 1999, was the result of higher earnings in ConocoPhillips' E&P, Midstream and R&M segments. The E&P segment benefited from an 89 percent increase in crude oil production, mainly the result of the company's acquisition of Atlantic Richfield Company's (ARCO) Alaskan businesses in late-April 2000. The E&P segment also benefited from significantly higher crude oil and natural gas prices--up 62 percent and 46 percent, respectively, over 1999 levels. The Midstream segment's net operating income increased 18 percent in 2000, primarily reflecting higher natural gas liquids prices. R&M's net operating income increased 358 percent in 2000, compared with 1999, mainly due to higher refining margins for gasoline and distillates and a reduction in last-in, first-out inventories, partly offset by increased fuel and utility costs at the refineries. Chemicals net operating income decreased 64 percent in 2000, reflecting weak margins in most major product lines, along with higher fuel and utility costs. Corporate costs increased 32 percent in 2000, primarily due to higher interest expense and higher foreign currency transaction losses, compared with 1999. INCOME STATEMENT ANALYSIS 2001 vs. 2000 On September 14, 2001, ConocoPhillips closed on the acquisition of Tosco Corporation (Tosco). Accordingly, ConocoPhillips' consolidated income statement for the year ended December 31, 2001, includes activity related to Tosco after September 14. This transaction significantly increased operating revenues, purchase costs, and other income statement line items. See Note 3--Acquisition of Tosco Corporation in the Notes to Financial Statements for additional information. 5

On March 31, 2000, ConocoPhillips and Duke Energy Corporation (Duke Energy) contributed their midstream gas gathering, processing and marketing businesses to Duke Energy Field Services, LLC (DEFS). Effective July 1, 2000, ConocoPhillips and Chevron Corporation, which, following its merger with Texaco Inc. was renamed ChevronTexaco Corporation (ChevronTexaco), contributed their chemicals businesses, excluding ChevronTexaco's Oronite business, to Chevron Phillips Chemical Company LLC (CPChem). Both of these joint ventures are being accounted for using the equity method of accounting, which significantly affects how the Midstream and Chemicals segments' operations are reflected in ConocoPhillips' consolidated income statement. Under the equity method of accounting, ConocoPhillips' share of a joint venture's net income is recorded in a single line item on the income statement: "Equity in earnings of affiliated companies." Correspondingly, the other income statement line items (for example, operating revenues, operating costs, etc.) include activity related to the Midstream and Chemicals operations only up to the effective dates of the joint ventures. Sales and other operating revenues increased 18 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. The company now includes excise taxes on the sale of petroleum products in operating revenues, with the corresponding expense included in taxes other than income taxes. All prior periods presented have been restated to reflect this change in presentation. 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. CPChem continued to face a difficult market environment in 2001. See the discussion of the Chemicals segment's results of operations for additional information. 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 Merey Sweeny, L.P., a 50-percent-owned equity company that owns and operates the coker unit at the Sweeny, Texas, refinery. Other income decreased 65 percent in 2001, primarily attributable to lower net gains on asset sales in 2001 compared with 2000. 6

Purchased crude oil and products increased 21 percent in 2001, mainly the result of the Tosco acquisition. The Tosco impact was partially offset by the use of equity-method accounting for the DEFS and CPChem joint ventures, along with lower crude oil acquisition costs at the company's heritage refineries. Management defines controllable costs as production and operating expenses; selling, general and administrative expenses; and the general administrative, geological, geophysical and lease rentals component (G&G) of exploration expenses. Controllable costs, adjusted to exclude G&G, increased 30 percent in 2001. The increase was primarily due to the impact of the Tosco acquisition, along with higher costs in the company's Alaska E&P operations, which were owned and operated for a full year in 2001. These items were partially offset by the use of equity-method accounting for the DEFS and CPChem joint ventures. Exploration expenses were 3 percent higher in 2001, reflecting higher G&G and leasehold impairments, partially offset by lower foreign dry hole costs. Depreciation, depletion and amortization (DD&A) increased 18 percent in 2001, reflecting the impact of the Tosco acquisition and a full year's DD&A associated with the Alaska operations acquired in April and August of 2000. These items were partly offset by the use of equity-method accounting for the DEFS and CPChem joint ventures, and a reduction in DD&A resulting from asset dispositions in late 2000. ConocoPhillips recorded property impairments of $26 million in 2001, compared with $100 million in 2000. See Note 9--Property Impairments in the Notes to Financial Statements for additional information on property impairments. Taxes other than income taxes increased 42 percent in 2001, reflecting higher excise taxes on petroleum products sales, mainly due to the Tosco acquisition. Production and property taxes were also higher in 2001, primarily the result of a full year's ownership and production in Alaska. The company added a new line to its income statement in 2001 to disclose the accretion of discounted liabilities. The amount of $14 million in 2001 relates to environmental obligations acquired in the Alaska and Tosco acquisitions. Interest and debt expense decreased 8 percent in 2001, as ConocoPhillips benefited from lower short-term interest rates and higher interest amounts being capitalized--mainly related to projects in Alaska, the Timor Sea and Venezuela, partially offset by the interest associated with debt acquired in the Tosco acquisition. 7

Foreign currency losses of $11 million were incurred in 2001, compared with losses of $58 million in 2000. Preferred dividend requirements of capital trusts and minority interests decreased slightly in 2001 from 2000. 2000 vs. 1999 Sales and other operating revenues increased 48 percent in 2000, compared with 1999. The increased revenues reflect higher sales prices in 2000 for petroleum products, crude oil and natural gas, as well as the impact of significantly higher crude oil production and sales volumes resulting from the Alaskan acquisition. These benefits were partially offset by the reduction in operating revenues as a result of using the equity method of accounting for the new DEFS and CPChem joint ventures. Equity in earnings of affiliated companies increased 13 percent in 2000, compared with 1999, primarily due to the formation of the DEFS and CPChem joint ventures in 2000. Other income increased 54 percent in 2000, reflecting a higher net gain on asset sales in 2000. Major asset sales in 2000 included the company's coal operations and the Zama operations in Canada. Total costs and expenses increased 33 percent in 2000, compared with 1999, primarily due to higher purchase prices for crude oil and petroleum products and the impact of the Alaskan acquisition, partially offset by the use of the equity method of accounting for the DEFS and CPChem joint ventures. 8

SEGMENT RESULTS E&P

2001 vs. 2000 Net operating income from ConocoPhillips' E&P segment decreased 9 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. ConocoPhillips' average worldwide crude oil sales price was $23.74 per barrel in 2001, a 17 percent decrease from $28.65 in 2000. Crude oil prices have generally trended lower since peaking in the fourth quarter of 2000. Slowing demand growth due to the global economic slowdown and concern over worldwide production and storage levels contributed to the slide in crude prices in 2001. Natural gas prices began 2001 at historically high levels, but also trended lower during the remainder of the year, with the company's December 2001 average price at $2.34 per thousand cubic feet. The company expects that its average natural gas sales price in the first quarter of 2002 will be significantly lower than the $4.90 per thousand cubic feet reported in the first quarter of 2001. 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. ConocoPhillips replaced 135 percent of its worldwide hydrocarbon production in 2001, and has replaced an average of 359 percent over the last five years. 2000 vs. 1999 Net operating income from ConocoPhillips' E&P segment increased 255 percent in 2000, compared with 1999. The increase reflects higher sales prices for crude oil and natural gas, higher crude oil production as a result of the Alaskan acquisition, and higher production from the Norwegian North Sea. ConocoPhillips' average worldwide crude oil price was $28.65 per barrel in 2000, compared with $17.69 in 1999. Crude oil prices trended upward through most of 2000 on demand growth, limited worldwide supply, and, in the fall of 2000, on concern over heating fuel stock levels heading into the winter months. Crude oil price levels eased somewhat late in 2000, as major crude oil exporting countries increased output and global demand growth began to slow. E&P's proved reserves at year-end 2000 were 5.02 billion barrels of oil equivalent, more than double the year-end 1999 level of 2.23 billion barrels. The sharp increase was primarily the result of the Alaskan acquisition, as well as the recording of net proved reserves associated with the equity-affiliate Hamaca 11

heavy-oil project in Venezuela and Phase I of the Peng Lai 19-3 development offshore China. ConocoPhillips replaced 1,128 percent of its worldwide hydrocarbon production in 2000, compared with 114 percent in 1999. U.S. E&P - --------

2001 vs. 2000 Net operating income from the company's U.S. E&P operations decreased slightly in 2001. The 2001 results reflect a 55 percent increase in crude oil production, due to a full year's production from the Alaskan 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 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. Special items in 2001 included a net favorable result from claims and settlements, partially offset by losses incurred on the disposition of assets. Special items in 2000 primarily consisted of 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) and favorable contingency settlements, partially offset by $9 million in property impairments. 2000 vs. 1999 Net operating income increased 327 percent in 2000, compared with 1999. The increase was attributable to the Alaskan acquisition, as well as to higher crude oil, natural gas, and natural gas liquids prices. 12

On April 26, 2000, ConocoPhillips purchased all of ARCO's Alaskan businesses, other than three double-hulled tankers under construction and certain pipeline assets, which were acquired August 1, 2000. Results of operations for the acquired businesses are included in U.S. E&P's results from April 26, and August 1, 2000, respectively. U.S. crude oil production increased 382 percent in 2000, compared with 1999, due to the Alaskan acquisition. Lower 48 production continued to trend downward in 2000, reflecting property dispositions and field declines. U.S. natural gas production decreased 2 percent in 2000, compared with 1999, as property dispositions and field declines were mostly offset by property acquisitions. Special items in 1999 primarily consisted of net gains of $57 million on asset sales and a favorable pricing adjustment of $8 million, partially offset by property impairments. Foreign E&P - -----------

2001 vs. 2000 Net operating income from ConocoPhillips' foreign E&P operations decreased 32 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. After-tax foreign currency gains of $2 million were included in foreign E&P's net operating income in 2001, compared with losses of $10 million in 2000. Foreign 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 a year ago 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. 13

Foreign 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. Special items in 2001 consisted of a net gain on asset dispositions and favorable settlements, mostly offset by a $23 million impairment of the Siri field, offshore Denmark. See Note 9--Property Impairments in the Notes to Financial Statements for additional information on the Siri impairment. ConocoPhillips sold its interests in the Ann, Alison and Audrey fields located in the U.K. North Sea in 2001, and also traded its interests in the Kate and Tornado prospects for an additional interest in the Britannia field and an interest in another property. Special items in 2000 included a favorable deferred-tax adjustment resulting from a tax law change in Australia and a net gain on property dispositions of $118 million, related to the disposition of the Zama area fields in Canada. Special items in 2000 also included an $86 million impairment of the Ambrosio field in Venezuela. See Note 9--Property Impairments in the Notes to Financial Statements for additional information on this impairment. 2000 vs. 1999 The company's foreign E&P operations generated net operating income of $517 million in 2000, a 146 percent increase over 1999's net operating income of $210 million. The increase was primarily due to higher crude oil prices, and, to a lesser extent, higher natural gas prices and increased crude oil production in the Norwegian North Sea and Nigeria. After-tax foreign currency transaction losses of $10 million were included in foreign E&P's net operating income in 2000, compared with gains of $3 million in 1999. Foreign crude oil production increased 8 percent in 2000, compared with 1999, as higher production in most foreign areas was partially offset by lower production in the U.K. sector of the North Sea. Production in the Norwegian sector of the North Sea benefited from an improved operating performance in 2000. In the U.K. North Sea, operating interruptions at the Janice field, as well as lower production from R-Block and J-Block, contributed to the reduced crude oil production. Nigeria production increased on higher quota levels and development drilling. 14

Foreign natural gas production increased 5 percent in 2000, compared with 1999, primarily due to increased production in Nigeria. In mid-1999, ConocoPhillips' Nigerian operations began commercial delivery of natural gas to a third-party liquefied natural gas plant on Bonny Island. Special items in 1999 primarily consisted of property impairments of $27 million, partially offset by a net gain on asset sales of $15 million. MIDSTREAM

*The price for 1999 represents ConocoPhillips' realized price prior to the formation of DEFS. The price for 2000 is an estimate based on a weighted average of ConocoPhillips' realized price in the first quarter of 2000 and DEFS' index prices for the remainder of 2000. DEFS' prices are based on index prices from the Mont Belvieu and Conway market hubs that are weighted by DEFS' natural-gas-liquids-component and location mix. **Production and throughput volumes for 1999 represent ConocoPhillips' production and throughput prior to the formation of DEFS. The volumes in 2000 are estimates based on a weighted average of ConocoPhillips' production and throughput in the first quarter of 2000 and ConocoPhillips' 30.3 percent share of DEFS' production and throughput for the remainder of 2000. The 2001 volumes are ConocoPhillips' 30.3 percent share of DEFS' production and throughput. 2001 vs. 2000 On March 31, 2000, ConocoPhillips combined its gas gathering, processing and marketing business with Duke Energy's gas gathering, processing, marketing and natural gas liquids business into Duke Energy Field Services, LLC (DEFS). ConocoPhillips is using equity-method accounting for its 30.3 percent interest in DEFS. Since March 31, 2000, ConocoPhillips' Midstream segment has included its equity investment in DEFS. 15

Net operating income from the Midstream segment decreased 25 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 earnings 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. See Note 6--Investments and Long-Term Receivables in the Notes to Financial Statements for additional information on the basis difference. There were no special items in the Midstream segment in 2001. Special items in 2000 consisted of special current and deferred state tax items related to the closing of the DEFS transaction and a gain on DEFS' disposition of assets, mostly offset by work force reduction charges. 2000 vs. 1999 Net operating income from the Midstream segment increased 18 percent in 2000, compared with 1999. The improved results were primarily due to a 74 percent increase in natural gas liquids prices in 2000, partially offset by interest expense incurred by DEFS, but not present in the Midstream segment in 1999. In addition, results were lower for the natural gas liquids fractionation business, as a portion of this business was contributed to CPChem on July 1, 2000. Special items in 1999 consisted of work force reduction charges. 16

R&M

*The weighted-average crude oil capacity for the period included the refineries acquired in the Tosco acquisition on September 14, 2001. Actual capacity at December 31, 2001, was 1,656 thousand barrels per day in the United States, and 75 thousand barrels per day from foreign operations (Ireland). 17

2001 vs. 2000 Net operating income from the R&M segment increased 77 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, with R&M's assets increasing from $3.3 billion at year-end 2000 to $17 billion at year-end 2001. R&M results included the acquired Tosco operations after September 14, contributing $87 million to 2001 results. In addition to the Tosco acquisition, R&M's earnings 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 heritage refineries, resulting from higher natural gas prices experienced in the first half of 2001. The Sweeny refinery's 2001 earnings 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. R&M's earnings benefited $60 million from an inventory liquidation in 2000. ConocoPhillips' refineries (including those acquired in the Tosco transaction since the acquisition date) processed an average of 706,000 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. Average barrels of crude oil processed per day will increase significantly in 2002 with a full year's ownership and operation of the Tosco refineries. Special items in 2001 included a cumulative effect of a change in accounting method 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. See Note 2--Extraordinary Item and Accounting Change in the Notes to Financial Statements for additional information on the accounting change, including the pro forma impact of the change on 2000 and 1999. Other special items in 2001 included a $27 million write-down of inventories to market value and work force reduction charges. Special items in 2000 mainly consisted of contingency related items. 18

2000 vs. 1999 Net operating income from ConocoPhillips' R&M segment increased 358 percent in 2000, compared with 1999. The increase was primarily attributable to improved financial results from the company's refineries and branded marketing operations, which experienced higher gasoline and distillates margins. In addition, R&M's 2000 earnings benefited $60 million from an inventory liquidation, compared with $9 million in 1999. The improved margins and inventory-liquidation gain were partly offset by significant increases in fuel and utility costs in 2000, resulting from increased prices for natural gas, as well as the scheduled maintenance shutdowns discussed below. ConocoPhillips' refineries ran at 90 percent of capacity in 2000, compared with 99 percent in 1999. Capacity utilization in 2000 was impacted by major projects at the Sweeny and Borger, Texas, refineries. The Sweeny refinery was shut down in late July 2000 to tie-in a new coker, a vacuum distillation unit, and a continuous catalytic reformer. The refinery resumed operations in late September 2000, and the new coker was operational early in the fourth quarter. The Borger refinery underwent a scheduled major maintenance turnaround on one of its two cat crackers in the third quarter of 2000. Special items in 1999 consisted primarily of work force reduction charges and contingency accruals. CHEMICALS

*Production volumes for periods after July 1, 2000, include ConocoPhillips' 50 percent share of Chevron Phillips Chemical Company LLC. **Production was limited in 2001 due to a fire at the St. James, Louisiana, facility in February 2001. Capacity was restored in October 2001. 19

2001 vs. 2000 On July 1, 2000, ConocoPhillips and ChevronTexaco combined the two companies' worldwide chemicals businesses, excluding ChevronTexaco's Oronite business, into a new company, Chevron Phillips Chemical Company LLC (CPChem). ConocoPhillips is using the equity method of accounting for its 50 percent interest in CPChem. Since July 1, 2000, ConocoPhillips' Chemicals segment has consisted of its equity investment in CPChem. The Chemicals segment posted a net operating loss of $106 million in 2001, compared with net operating income of $53 million in 2000. Global conditions for the chemicals and plastics industry remained 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. 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 assets was increased in 2001 so that the deferred tax assets were fully offset by valuation allowances. ConocoPhillips' share of the financial impact of these items are included as special items in the financial results table above. 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. Special items in 2000 primarily consisted of 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 20

resulted in a non-cash $180 million after-tax charge to CPChem's earnings. ConocoPhillips' share was $90 million. Special items in 2000 also included ConocoPhillips' share of other, less significant property impairments recorded by CPChem, as well as contingency related items. 2000 vs. 1999 Net operating income from the Chemicals segment decreased 64 percent in 2000, compared with 1999. As a result of the CPChem transaction, earnings from ConocoPhillips' Chemicals segment were not directly comparable between 2000 and 1999. Some factors affecting the results for 2000 and 1999 were: o Net operating income for the first six months of 2000, compared with the first six months of 1999 (both periods reflecting results prior to the formation of CPChem), increased 34 percent. The increase was primarily attributable to higher ethylene, propylene, other chemicals, and plastic pipe margins and volumes. o In the third quarter of 2000, margins weakened due to higher feedstock prices in key product lines. Margins continued to weaken in the fourth quarter of 2000, with the Chemicals segment posting a net operating loss of $41 million for the quarter. Of particular importance to CPChem were lower polyethylene and ethylene margins, as well as higher fuel and utility costs. o CPChem's earnings in the last half of 2000 included $65 million of interest charges on financing incurred upon formation to fund operations and cash distributions to the parent companies. Prior to the formation of CPChem, the Chemicals segment did not have interest expense. Special items in 1999 consisted of a favorable deferred tax adjustment and contingency settlements. 21

EMERGING BUSINESSES

The Emerging Businesses segment includes the company's development of new fuels technologies. Prior to the segment realignment, these activities were included in the R&M segment. CORPORATE AND OTHER

2001 vs. 2000 Net interest represents interest income and expense, net of capitalized interest. Net interest decreased 6 percent in 2001, as ConocoPhillips benefited from lower short-term interest rates and higher interest amounts being capitalized--mainly related to projects in Alaska, the Timor Sea and Venezuela--partially offset by the interest associated with debt acquired in the Tosco acquisition. Corporate general and administrative expenses increased 31 percent in 2001, reflecting increased amounts of staff costs and higher contributions, corporate advertising and corporate transportation costs. 22

Preferred dividend requirements represent dividends on the preferred securities of the Phillips 66 Capital I and Capital II trusts. See Note 14--Preferred Stock in the Notes to Financial Statements for additional information on these trusts. The category "Other" consists primarily of a captive insurance subsidiary, certain foreign currency transaction gains and losses, and certain income tax and other items that are not directly associated with the operating segments on a stand-alone basis. Results from Other were improved in 2001, as lower foreign currency transaction losses were partially offset by higher income tax expenses. Special items in 2001 included an extraordinary loss of $10 million on the early retirement of debt, as well as contingency accruals and a loss on the disposition of an asset. Special items in 2000 primarily included costs related to a late-March 2000 K-Resin styrene-butadiene copolymer facility incident that was partially insured by the company's captive insurance subsidiary, as well as environmental accruals. In addition, special items included net income from discontinued operations. 2000 vs. 1999 Adjusted Corporate and Other net costs increased 32 percent in 2000, compared with 1999, mainly due to higher net interest expense. Net interest expense increased 43 percent in 2000, compared with 1999, reflecting higher debt levels in 2000 as a result of funding the Alaskan acquisition in April 2000. Special items in 1999 primarily consisted of a $24 million favorable resolution of prior years' U.S. income tax issues, partially offset by an unfavorable deferred-tax adjustment and by insurance claims against the company's captive insurance subsidiary. In addition, special items included net income from discontinued operations. 23

CAPITAL RESOURCES AND LIQUIDITY FINANCIAL INDICATORS

*Capital includes total debt, company-obligated mandatorily redeemable preferred securities and common stockholders' equity. Cash from operations in 2001 was $3,562 million, a decrease of $452 million from 2000. Income from continuing operations in 2001 was $215 million less than in 2000, driven primarily by lower prices. Commodity price changes during 2001 also affected non-cash working capital items, including receivables, payables, and inventories, contributing to the decrease in cash from operating activities. Reduced levels of revolving sales of accounts receivable under the company's receivables sales programs decreased cash from operations $174 million, compared with increasing cash from operations $317 million in 2000. During 2001, cash and cash equivalents decreased $7 million. In addition to the cash provided by operating activities, $256 million was received from the sale of various assets. Funds were used to support the company's ongoing capital expenditures program, reduce debt, and pay dividends. Following completion of the Tosco acquisition (see Note 3--Acquisition of Tosco Corporation in the Notes to Financial Statements for more information), Moody's Investors Service and Standard and Poors upgraded ConocoPhillips' senior long-term debt ratings from Baa2 to A3, and from BBB to BBB+, respectively, reflecting the company's larger size, asset diversity, and the financial flexibility provided by the acquisition. ConocoPhillips' debt-to-capital ratio was 37 percent at December 31, 2001, improved from 51 percent at year-end 2000, primarily as a result of the company's issuing 124.1 million shares of common stock in the acquisition of Tosco. 24

In July 2001, ConocoPhillips' Board of Directors approved a dividend increase, raising the quarterly per share dividend to $.36, a 6 percent increase, effective with the September 4, 2001, payment. To meet its short-term liquidity requirements, including funding its capital program, paying dividends and repayment of debt, the company looks to a variety of funding sources, the primary of which is cash generated from operating activities. While the stability of the company's cash flows from operating activities does benefit from geographic diversity and the offsetting 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 product purchases. The company's primary swing funding source for short-term working capital needs is a $3 billion commercial paper program. Commercial paper maturities are generally kept within 90 days of individual draw dates. The average outstanding balances of issued commercial paper were $333 million and $1,378 million during 2001 and 2000, respectively. In October 2001, ConocoPhillips entered into two new revolving bank credit facilities: a five-year credit agreement providing for commitments not to exceed $1.5 billion; and a 364-day credit agreement for commitments not to exceed $1.5 billion. The $3 billion of new credit facilities replaced the company's previous bank credit facilities, including a $1 billion facility assumed as part of the Tosco transaction, all of which were canceled subsequent to the effectiveness of the new facilities. The new credit facilities are available either as direct bank borrowings or as support for the issuance of commercial paper. At December 31, 2001, ConocoPhillips had $1,081 million of commercial paper outstanding supported by the long-term revolving credit facility. At December 31, 2001, ConocoPhillips had $3.5 billion of various types of debt and equity securities, and securities convertible into either, available to issue and sell, under a universal shelf registration that was filed with the U.S. Securities and Exchange Commission. In addition to the bank credit facilities, ConocoPhillips sells certain credit card and trade receivables under revolving sales agreements with four unrelated bank-sponsored entities. These agreements provide for ConocoPhillips to sell up to $1.2 billion of senior, undivided interests in pools of the credit card or trade receivables to the bank-sponsored entities. At 25

December 31, 2001 and 2000, the company had sold undivided interests of $940 million and $500 million, respectively. ConocoPhillips also retained interests in the pools of receivables, which are subordinate to the interests sold to the bank-sponsored entities. The subordinate interests are measured and recorded at fair value based on the present value of expected future cash flows, which are estimated using Management's best estimates of 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 for the sold receivables. At December 31, 2001 and 2000, ConocoPhillips' retained interests were $450 million and $224 million, respectively, reported on the balance sheet in accounts and notes receivable. The company leases ocean transport vessels, tank railcars, corporate aircraft, service stations, computers, office buildings and other facilities and equipment. ConocoPhillips has $200 million of master leasing arrangements, under which it leases and supervises the construction of retail marketing outlets. At December 31, 2001, approximately $158 million had been utilized under these arrangements. In addition, at the time ConocoPhillips acquired Tosco, Tosco had in place previously arranged leasing arrangements for various retail stations and two office buildings in Tempe, Arizona. At December 31, 2001, approximately $1.4 billion had been utilized under those arrangements, which was the total capacity available. During 2001, the company sold its first Endeavour, formerly known as Millennium, Class tanker, the Polar Endeavour, for $205 million, then leased it back under a 10-year long-term operating lease. 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 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. Except in an event of default under the terms of the lease agreements, there are not any circumstances at this time under which ConocoPhillips would be required to record the assets and/or liabilities of the SPEs in its financial statements in the future, based on the terms and provisions within the various arrangements. ConocoPhillips considers an event of default under the terms of the lease agreements to be remote. Changes in market interest rates do have an impact on the periodic amount of lease payments. ConocoPhillips has various purchase options to 26

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. During the second quarter of 2001, the company's $250 million 9% Notes due June 1, 2001, matured and were repaid. In September 2001, the company redeemed its $300 million 9.18% Notes due September 15, 2021, at 104.59 percent. Both were funded by the issuance of commercial paper. During 1996 and 1997, ConocoPhillips formed two statutory business trusts, Phillips 66 Capital I and Phillips 66 Capital II, in which the company owns all of the common stock 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. ConocoPhillips established the two trusts to raise funds for general corporate purposes. The subordinated debt securities between ConocoPhillips and the trusts are eliminated in consolidation. The preferred trust securities held by outside investors are mandatorily redeemable in 2036 and 2037, respectively, when the subordinated debt securities between ConocoPhillips and the trusts are required to be repaid. The $300 million of Phillips 66 Capital I preferred securities became callable, at par, $25 per share, during May 2001. The total $650 million of mandatorily redeemable preferred trust securities are presented on the balance sheet as mezzanine-equity minority interests of a consolidated subsidiary. See Note 14--Preferred Stock in the Notes to Financial Statements. 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 Duke Energy Field Services, LLC (DEFS) and Chevron Phillips Chemical Company LLC (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. 27

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 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 years 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 an unguaranteed $470 million 14-year-term commercial bank facility for the project. Total debt of $633 million was outstanding under these credit facilities at December 31, 2001. 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. 28

During 1999, Merey Sweeny, L.P. (MSLP), a limited partnership owned 50 percent by ConocoPhillips and 50 percent by Petroleos de Venezuela, S.A. (PdVSA), issued $350 million of 8.85% Bonds due 2019. The proceeds of the bond issue were used to fund the construction of a coker and related facilities to process heavy, sour crude oil at ConocoPhillips' Sweeny refinery, including improvements to certain existing ConocoPhillips facilities at the refinery. These improvements to the existing ConocoPhillips facilities were sold to ConocoPhillips at a price equal to MSLP's cost of construction, $133 million. ConocoPhillips agreed to pay MSLP the purchase price for the improvements to the existing ConocoPhillips facilities, plus 7 percent interest, monthly over the 240 months following startup, which occurred during September 2000. MSLP continues to own and operate the coker, processing Venezuelan Merey crude oil delivered under a supply agreement with PdVSA. MSLP charges ConocoPhillips a fee to process the heavy crude oil through the coker. This is the partnership's primary source of revenue. MSLP pays a monthly access fee to ConocoPhillips for the use of the improvements to the refinery, equal to the monthly principal and interest paid by ConocoPhillips to purchase the improvements from MSLP. To the extent that the access fee is not paid by MSLP, ConocoPhillips is not obligated to make payments for the improvements. The coker and related facilities began processing heavy crude oil during the third quarter of 2000, but startup certification has not yet been achieved. Once startup certification is achieved, expected during 2002, the MSLP bonds become non-recourse to the two partners and the owners of the bonds can then only look to MSLP's cash flows for payment. 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: 29

*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 obligations to transfer funds in the future for fixed or minimum amounts at fixed or minimum prices under various throughput or tolling agreements with pipeline and processing companies in which the company holds stock interests. 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. The following table summarizes the potential amounts and remaining time frames of these direct and indirect guarantees:

*Amounts represent ConocoPhillips' ownership share of the utilized portion of 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/startup certification of the projects. Figures in the table represent ConocoPhillips' portion due in the event completion/startup certification is not achieved. The Merey Sweeny debt is joint-and-several. See Note 6--Investments and Long-Term Receivables in the Notes to Financial Statements. **Represents amount of obligations directly guaranteed by the company in the event a third party or related party does not perform. 30

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 crude oil, natural gas and related products, and fluctuations in foreign currency exchange rates, or to exploit favorable market conditions. In the past, the company has, on occasion, hedged interest rates and may do so in the future should certain circumstances or transactions warrant. ConocoPhillips' Board of Directors has revised its policy governing the use of derivative instruments. The new policy prohibits the holding or issuing of highly complex or leveraged derivatives, as did the old policy. Except as approved by the Chief Executive Officer, the derivative instruments used by the company must not contain embedded financing features and must be sufficiently liquid that comparable valuations are readily available. The policy also requires the Chief Executive Officer to establish the maximum derivative position limits for ConocoPhillips and requires the company's Risk Management Steering Committee, comprised of senior management, to monitor the use and effectiveness of the derivatives. The Audit Committee of the company's Board of Directors periodically reviews derivatives policy and compliance. Commodity Price Risk In 2001, prior to the Tosco acquisition, ConocoPhillips used commodity-based derivative contracts only to minimize exposures to price fluctuations occurring between the purchasing of feedstock and the selling of refined products, while Tosco used derivatives more extensively as a tool to manage or exploit exposures to price fluctuations. Since acquiring Tosco on September 14, 2001, ConocoPhillips has expanded both the volumes and uses of derivative instruments; however, the aggregate fair market values of futures, swaps, and options outstanding at December 31, 2001, were a gain of less than $6 million and a loss of less than $8 million. In past years, ConocoPhillips used sensitivity analysis to disclose the risk of loss resulting from derivative positions held at year-end. The company now uses a value-at-risk model to estimate the loss 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 31

instruments held or issued, including commodity purchase and sales contracts recorded on the balance sheet as derivative instruments in accordance with Financial Accounting Standards Board (FASB) Statement No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. Using a 95 percent confidence level, the value-at-risk analysis indicated the hypothetical loss in fair values for those instruments issued or held for trading purposes and those instruments that were issued or held for purposes other than trading at December 31, 2001, would be immaterial to ConocoPhillips' net income and cash flows. The value-at-risk for those instruments issued or held for purposes other than trading at December 31, 2000, was also immaterial to ConocoPhillips' net income and cash flows; the company neither held nor issued any derivatives for trading purposes during 2000. For additional information about the company's use of derivative instruments, see Note 13--Financial Instruments and Derivative Contracts in the Notes to Financial Statements. Interest Rate Risk The following tables provide information about the company's financial instruments that are sensitive to changes in interest rates. These tables present principal cash flows and related weighted-average interest rates by expected maturity dates. 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. 32

Foreign Currency Risk At December 31, 2000, ConocoPhillips held a collar (i.e., a purchased call and a written put) on 133 million Australian dollars to provide protection against the exchange rate risk of an anticipated Australian business acquisition, which was completed in 2001. At year-end 2000, the fair market value of the collar was minimal, and a hypothetical 10 percent change in the year-end 2000 exchange rates would have resulted in a potential gain of $8.2 million or a potential loss of $6.2 million. The collar was closed out in 2001 with an actual realized gain of $0.6 million. At December 31, 2001 and 2000, U.S. subsidiaries held long-term sterling-denominated intercompany receivables totaling $191 million and $246 million, respectively, due from a U.K. 33

subsidiary. The U.K. subsidiary also held a dollar-denominated long-term receivable due from a U.S. subsidiary with balances of $75 million and $81 million, respectively, at December 31, 2001 and 2000. A Norwegian subsidiary held $79 million and $111 million of intercompany U.S. dollar-denominated receivables due from its U.S. parent at December 31, 2001 and 2000, 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 2001 and 2000 exchange rates from these intercompany balances are $21 million and $5 million, respectively. CAPITAL SPENDING CAPITAL EXPENDITURES AND INVESTMENTS

*Excludes the Alaskan acquisition. ConocoPhillips' capital spending for the three-year period ending December 31, 2001, totaled $6.8 billion, excluding the purchase of ARCO's Alaska businesses in 2000. The company's spending was primarily focused on the growth of its E&P business, with more than 75 percent of total spending in this segment. Certain Midstream and Chemicals businesses were contributed to joint ventures during 2000--Midstream on March 31, 2000, and Chemicals on July 1, 2000. The capital programs of these joint-venture companies are intended to be self-funding. 34

ConocoPhillips' Board of Directors (Board) has approved $3.5 billion for capital projects and investments in 2002, a 14 percent increase over 2001 capital spending of $3.1 billion. The company plans to direct approximately 75 percent of its 2002 capital budget to E&P and approximately 25 percent to R&M. Fifty-seven percent of the budget is targeted for projects in the United States. In December 2000, ConocoPhillips' Board approved a $2.5 billion capital budget for the year 2001. In October 2001, the Board authorized increasing capital spending to $3.3 billion to cover the fourth-quarter capital requirements related to the Tosco acquisition, investments in Angola and Brazil deepwater leases, and the anticipated purchase of additional Kashagan ownership in Kazakhstan. Actual 2001 expenditures were $3.1 billion, with 82 percent directed to E&P and 16 percent to R&M. The larger capital program for 2002 and the percentage shift in funds for R&M reflect the increased size of this segment since the September 2001 acquisition of Tosco. E&P Capital spending for E&P during the three-year period ending December 31, 2001, totaled $5.3 billion. The expenditures over the three-year period supported several key exploration and development projects including the Bayu-Undan project in the Timor Sea; the Hamaca heavy-oil project in Venezuela's Orinoco Oil Belt; the company's Peng Lai 19-3 discovery in China's Bohai Bay; the Jade development and Eldfisk waterflood development in the U.K. and Norwegian sectors of the North Sea, respectively; and acquisition and development of coalbed-methane and conventional gas prospects and producing properties in the U.S. Lower 48. Also included in the three-year E&P capital outlays were expenditures for development of Alaska North Slope fields and significant worldwide exploration activities including the Kashagan prospect in the north Caspian Sea, offshore Kazakhstan; additional Bohai Bay appraisal and satellite field prospects; National Petroleum Reserve--Alaska (NPR-A) and satellite field prospects on Alaska's North Slope; North Sea prospects in the U.K. and Norwegian sectors, plus other Atlantic Margin wells in the United Kingdom, Greenland and the Faroe Islands; and acquisition of deepwater exploratory interests in Angola, Brazil, and the U.S. Gulf of Mexico. 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 35

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, is expected to enter service in 2002. ConocoPhillips expects to add a new Endeavour Class tanker to its fleet each year through 2005, allowing the company to retire its older ships and cancel non-operated charters. 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 ugrader is expected in 2004. ConocoPhillips owns a 40 percent equity interest in the Hamaca project. In 2001, development activities continued on the company's Peng Lai 19-3 discovery in block 11/05 in China's Bohai Bay in line with the overall approved development plan. First production is scheduled for the third quarter of 2002. During 2001, ConocoPhillips and its co-venturers announced the successful completion and testing of the second exploration well drilled by the co-venturers in the Kashagan structure on the Kazakhstan shelf in the north Caspian Sea. Drilling of the first of five planned appraisal wells was successfully completed in early 2002. Two of the co-venturers in the north Caspian Sea venture have entered into agreements to sell their interests. ConocoPhillips, along with the other remaining co-venturers, exercised preemptive rights to purchase the interests being sold which will increase the company's ownership from 7.14 percent to 8.33 percent when completed. Closing is expected during the second quarter of 2002. At year-end, commissioning work and drilling was in progress on ConocoPhillips' Jade development in the U.K. sector of the North Sea. Production began in the first quarter of 2002. ConocoPhillips is the operator and holds a 32.5 percent interest in Jade. ConocoPhillips' Bayu-Undan gas-recycle project activities continued in the Timor Sea during 2001. The schedule of this first phase of field development was not impacted by the delay in resolving certain critical legal, fiscal, and taxation issues, and the company has proceeded with its $1.9 billion gross gas-recycle project. Full commercial production of liquids is expected to begin in 2004. ConocoPhillips now controls a 58.6 percent interest in the Bayu-Undan project and is the operator of the gas-recycle development. 36

During 2001, ConocoPhillips announced its plans to invest $85 million for a 20 percent share of a new independent power project to be built near Kwale, Nigeria. The plant is expected to start up in 2004. ConocoPhillips also agreed with its co-venturers to evaluate the development of a liquefied natural gas facility to be located offshore Nigeria. If approved, the facility, which would be 20 percent owned by ConocoPhillips, would come onstream by 2007, utilizing natural gas feedstocks supplied by ConocoPhillips and its co-venturers. In the third quarter of 2001, ConocoPhillips increased its presence in deepwater areas by securing interests in three blocks--a 20 percent interest in a block offshore Angola and a 100 percent interest in two deepwater exploration blocks in Brazil, where ConocoPhillips will be the operator. E&P's 2002 capital budget is $2.6 billion, 3 percent higher than actual expenditures in 2001. Forty-three percent of E&P's 2002 capital budget is planned for the United States. Of that, 72 percent is slated for Alaska. ConocoPhillips has budgeted $238 million for worldwide exploration activities in 2002, with 31 percent of that amount allocated for the United States. More than half 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, Angola and Norway. The company plans to spend $807 million in 2002 for its Alaska operations. Large capital projects include the ongoing construction of four 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; capacity expansion at the Alpine field; as well as the exploratory activity discussed above. In the Lower 48, capital expenditures will be focused on exploration and development of coalbed methane assets in the Rocky Mountain region and continued exploitation of the company's acreage positions in the San Juan Basin, Permian Basin, Texas Panhandle, northern Louisiana, and the upper Texas Gulf Coast. E&P is directing $1.5 billion of its 2002 capital budget to international projects. The majority of these funds will go toward developing major long-term projects, including the Bayu-Undan liquids development and gas-recycling project in the Timor Sea, the Hamaca heavy-oil development in Venezuela, and the Bohai Bay oil development in China. North Sea projects include 37

development of the Jade field in the U.K. sector and further development of the Ekofisk and Eldfisk fields in the Norwegian sector. Costs incurred for the years ended December 31, 2001, 2000, and 1999, relating to the development of proved undeveloped oil and gas reserves were $1,627 million, $857 million, and $301 million, respectively. Of the $1,627 million incurred in 2001, $204 million was funded by the Hamaca Holding LLC joint venture, an equity affiliate, and was not part of ConocoPhillips' reported capital expenditures for the year. As of December 31, 2001, estimated future development costs relating to the development of proved undeveloped oil and gas reserves for the years 2002 through 2004 were projected to be $1,528 million, $991 million, and $314 million, respectively. Of the $1,528 million estimated future development costs for 2002, $117 million was estimated to be funded by Hamaca Holding LLC, not by ConocoPhillips' capital expenditures. R&M Capital spending for R&M during the three-year period ending December 31, 2001, 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 completion of a coker and continuous catalytic reformer at the company's Sweeny, Texas, refinery; capacity expansion and debottlenecking projects at the Borger, Texas, refinery; successful completion of a commercial S Zorb Sulfur Removal Technology (S Zorb) unit at the Borger refinery; an expansion of capacity in the Seaway crude-oil pipeline; and installation of advanced central control buildings and technologies at the Sweeny and Borger facilities. In the fourth quarter of 2001, the R&M segment's capital expenditures included $238 million related to projects which were in progress upon the acquisition of Tosco, including construction of a polypropylene plant at the Bayway refinery in New Jersey and the Retail Enterprise Program initiative, a new electronic scanning and business system being implemented in the company's retail convenience stores. Total capital spending for R&M for the three-year period was $1.0 billion, representing approximately 15 percent of ConocoPhillips' total capital spending. During 2001, ConocoPhillips successfully completed and started up a new 6,000-barrel-per-day unit at its Borger refinery using the company's proprietary S Zorb technology to significantly reduce sulfur content in gasoline in preparation for meeting new 38

government regulations. During 2001, the company announced its third licensing agreement for the use of S Zorb for gasoline and announced that S Zorb for diesel was available for licensing. A large continuous pilot plant demonstrating S Zorb for diesel is under construction and a commercial-scale unit within ConocoPhillips' refining system is in the planning stages. A project to increase capacity at the Borger refinery through debottlenecking and expansion continued to progress in 2001. The project is expected to increase the facility's capacity to process crude oil by 20,000 barrels per day and move the facility toward production of lower-sulfur products. Operations have been largely unaffected by the debottlenecking project, with most work occurring during normal scheduled maintenance periods. Startup is expected in early 2002. R&M's 2002 capital budget is $833 million, a 70 percent increase over spending of $489 million in 2001. The 2001 spending does not include capital spending by Tosco prior to its acquisition by ConocoPhillips on September 14. Domestic spending is expected to consume 96 percent of the R&M budget, with the remainder allocated to the Whitegate refinery in Ireland. The company plans to direct 73 percent of the R&M capital budget to refining, 19 percent to marketing, and the remainder to transportation and other projects. Approximately two-thirds of R&M's budget is slated for ongoing operating requirements, including safety and environmental projects. The largest refining projects include construction of a fluid catalytic cracking unit at the Ferndale refinery, a diesel hydrotreater at the San Francisco refinery, and a low-sulfur gasoline project at the Wood River refinery. There are no individually significant marketing projects. 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. On June 23, 1999, a flash fire occurred in a reactor vessel at the K-Resin styrene-butadiene copolymer (SBC) plant at the Houston Chemical Complex. Two individuals employed by a subcontractor, Zachry Construction Corporation (Zachry), were 39

killed and other workers were injured. Ten lawsuits were filed in Texas in connection with the incident, including two actions for wrongful death. Both wrongful death lawsuits and many of the personal injury claims have been resolved. Two lawsuits remain pending on behalf of 12 workers. The first trial is scheduled for the spring of 2002. Under the indemnification provisions of the subcontracting agreement between ConocoPhillips and Zachry, ConocoPhillips has sought indemnification from Zachry with respect to the claims of the Zachry workers. ConocoPhillips has, in addition, filed an action against various Zachry insurers to obtain a declaration that coverage is available in regard to the incident under policies issued by them. There are also provisions in the Contribution Agreement, under which CPChem was formed, providing for indemnification of ConocoPhillips by CPChem for damages stemming from this incident. On March 27, 2000, an explosion and fire occurred at ConocoPhillips' K-Resin SBC plant at the Houston Chemical Complex 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, several 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 fourteen lawsuits pending on behalf of 67 primary plaintiffs. The first trial is scheduled for April 2002. Under the indemnification provisions of subcontracting agreements with Zachry and Brock Maintenance, Inc., ConocoPhillips has sought indemnification from these subcontractors with respect to claims made by their employees. The Contribution Agreement, pursuant to which CPChem was formed, does not require CPChem to indemnify ConocoPhillips for liability arising out of this litigation. ENVIRONMENTAL ConocoPhillips is subject to the same numerous federal, state, local and foreign environmental laws and regulations as are other companies in the oil and gas exploration and production; and refining, marketing and transportation of crude oil and refined products businesses. The most significant of those laws, and the regulations issued thereunder, affecting ConocoPhillips' operations are: o The Clean Air Act, as amended. 40

o The Federal Water Pollution Control Act. o Safe Drinking Water Act. o Regulations of the United States Department of the Interior governing offshore oil and gas operations. These acts 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 obtain substantial information in connection with the application process. The obtaining of this information 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 also have similar statutes and regulations governing air and water. While similar, in some cases these regulations impose additional, or more stringent, requirements that can add to the cost and difficulty of marketing or transporting products across state lines. ConocoPhillips is also subject to certain acts and regulations primarily governing remediation of wastes or oil spills. Most of the expenditures to fulfill these obligations relate to facilities and sites where past operations followed practices and procedures that were considered appropriate under regulations, if any, existing at the time, but that may now require investigatory or remedial work to adequately protect the environment or to address new regulatory requirements. The applicable acts are: o The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), commonly referred to as Superfund, and comparable state statutes. CERCLA primarily addresses historic contamination and imposes joint and several liability for cleanup of contaminated sites on owners and operators of the contaminated sites, or on those who have contributed wastes to a site. Many states have their own statutes and regulatory requirements that are similar to CERCLA. ConocoPhillips is involved in a number of Superfund sites--see the discussion below. CERCLA also requires reporting of releases to the environment of substances defined as hazardous. These requirements add cost and complexity to ConocoPhillips' operations. o The Resource Conservation and Recovery Act of 1976, as amended, and comparable state statutes, govern the management and disposal of wastes, with the most stringent regulations 41

applicable to treatment, storage or disposal of hazardous wastes at the owner's property. o The Oil Pollution Act of 1990, as amended, under which owners and operators of tankers, owners and operators of onshore facilities and pipelines, and lessees or permittees of an area in which an offshore facility is located are liable for removal and cleanup costs of oil discharges into navigable waters of the United States. Pursuant to the authority of the Clean Air Act (CAA), the Environmental Protection Agency (EPA) has issued several standards applicable to the formulation of motor fuels, which are designed to reduce emissions of certain air pollutants when the fuel enters commerce or is used. Pursuant to state laws corresponding to the CAA, several states have passed similar or more stringent regulations governing the formulation of motor fuels. Where these regulations are currently applicable, ConocoPhillips has already incurred the operational or capital costs of control or manufacturing limitations, but will continue to incur the costs of compliance such as ongoing operational requirements and recordkeeping. 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. ConocoPhillips expects to use a combination of technologies to achieve compliance with the rules. ConocoPhillips has made preliminary estimates of its cost of compliance with this rule and will include these costs 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 estimates for compliance at this time, but will do so and report these compliance costs as required by law. In 1997, an international conference on global warming concluded an agreement known as the Kyoto Protocol, which called for the reduction of certain emissions that may contribute to increases in atmospheric greenhouse gas concentrations. The United States has not ratified the treaty codifying the Kyoto Protocol and it is not clear whether it will do so in the future. If the 42

protocol is ratified by the United States, the cost of complying with regulations implementing the protocol could be substantial. It is not, however, possible to accurately estimate the costs that could be incurred by ConocoPhillips to comply with such regulations. Because of the nature of ConocoPhillips' businesses, it is likely that environmental laws and regulations will continue to have an effect on its operations in the future. ConocoPhillips does not, however, currently expect any material adverse effect on its operations or financial position as a result of compliance with such laws and regulations. At year-end 2000, ConocoPhillips reported 30 sites where it had information indicating that it might have been identified as a Potentially Responsible Party (PRP) under the federal Superfund law. Since then, six of these PRP sites have been resolved and five sites were added. Of the 29 sites remaining at December 31, 2001, the company believes it has a legal defense or its records indicated no involvement for six sites. At six other sites, present information indicates that it is probable that the company's exposure is less than $100,000 per site. Of the remaining sites, the company has provided for any probable costs that can be reasonably estimated. At a number of sites, ConocoPhillips has had no communication or activity with government agencies or other PRPs in more than two years. Experience has shown, however, that the mere passage of time is no guarantee that the site will never become active or that the company's connection to the site will not be established. ConocoPhillips does not consider the number of sites at which it has been designated potentially responsible by state or federal agencies as a relevant measure of liability. Some companies may be involved in few sites but have much larger liabilities than companies involved in many more sites. Although liability of those potentially responsible is generally joint and several for federal sites and frequently so for state sites, the company is usually but one of many companies cited at a particular site. ConocoPhillips has, to date, been successful 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 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. 43

At December 31, 2001, contingent liability accruals of $11 million had been made for the company's PRP sites, and $3 million for other environmental contingent liabilities. In addition, the company had accrued $525 million for other planned remediation activities, including resolved state, PRP, and other federal sites, as well as sites where no claims have been asserted, for total environmental accruals of $539 million, compared with $127 million at December 31, 2000. The 2001 increase in accrued environmental costs is primarily the result of ConocoPhillips' recent acquisition of Tosco on September 14, 2001. Accruals totaling $303 million were added as a result of that transaction. Earlier in 2001, the accrual was increased for remediation activities required by the state of Alaska at exploration and production sites formerly owned by ARCO. Because these accruals relate to environmental conditions that existed when ConocoPhillips acquired Tosco and the Alaska businesses, the charges impacted the allocation of the purchase price of each acquisition, not the company's net income. No one site exceeds 10 percent of the total. Expensed environmental costs were $345 million in 2001 and are expected to be approximately $235 million in 2002 and 2003. Capitalized environmental costs were $632 million in 2001, and are expected to be approximately $275 million and $375 million in 2002 and 2003, respectively. After an assessment of environmental exposures for cleanup and other costs, except those acquired in purchase business combinations, the company makes accruals on an undiscounted 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. These accruals have not been reduced for possible insurance recoveries. 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 operating income. The alternative minimum tax credit can be 44

carried forward indefinitely to reduce the company's regular tax liability. NEW ACCOUNTING STANDARDS In June 2001, the FASB issued FASB Statement No. 143, "Accounting for Asset Retirement Obligations." In August 2001, the FASB issued FASB Statement No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." For additional information, see Note 24--New Accounting Standards in the Notes to 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 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. Property Acquisition Costs For leasehold acquisition costs, Management exercises judgment and determines a percentage probability that the prospect ultimately will fail to find proved oil and gas reserves. 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 45

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 amortization 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 46

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 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 change. 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 or at an entire complex level for downstream assets. Because there usually is a lack of quoted market prices for long-lived assets, the fair value usually is based on the 47

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 9--Property Impairments in the Notes to 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 10--Accrued Dismantlement, Removal and Environmental Costs in the Notes to Financial Statements. 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. 48

Intangible Assets and Goodwill In connection with the acquisition of Tosco Corporation on September 14, 2001, the company recorded material intangible assets for Tosco 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 3--Acquisition of Tosco Corporation in the Notes to Financial Statements. Also in connection with the acquisition of Tosco, 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 the hypothetical amount is the lower of the two. 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 49

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. Inventory Valuation - ------------------- Prior to the acquisition of Tosco in September 2001, 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. So, prior to 2001, the company's LIFO inventories were relatively insensitive to current price level changes. However, the acquisition of Tosco added a very large LIFO cost layer that was recorded at replacement cost levels prevalent in late September 2001. As a result, the company's LIFO cost inventories will now be much more sensitive to lower-of-cost-or-market impairment write-downs in the future, whenever price levels fall. ConocoPhillips recorded a LIFO inventory lower-of-cost-or-market impairment in the fourth quarter of 2001 due to such a deterioration. 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 ERISA-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, but the judgmental assumptions used in the actuarial calculations 50

significantly affect periodic financial statements and funding patterns over time. OUTLOOK On November 18, 2001, Phillips and Conoco announced that their Boards of Directors had unanimously approved a merger of equals, and that the companies had signed a definitive merger agreement to form a new company to be named ConocoPhillips. At special shareholder meetings held on March 12, 2002, the stockholders of both companies approved the merger. On August 30, 2002, after receiving clearance from the U.S. Federal Trade Commission, Conoco and Phillips combined their businesses by merging with separate acquisition subsidiaries of ConocoPhillips. As a result, each company became a wholly owned subsidiary of ConocoPhillips. For accounting purposes, Phillips was treated as the acquirer and ConocoPhillips was treated as the successor of Phillips. Under the terms of the agreement, Phillips shareholders received one share of the new ConocoPhillips common stock for each share of Phillips common stock that they owned and Conoco shareholders received 0.4677 shares of the new ConocoPhillips common stock for each share of Conoco that they own. When the merger was consummated, former Phillips stockholders held approximately 58 percent of the outstanding shares of ConocoPhillips common stock, while former Conoco shareholders held approximately 42 percent. Effective January 1, 2002, the Norwegian authorities implemented a production curtailment on the Norwegian Continental shelf to support the efforts of major oil exporting countries to stabilize crude prices. ConocoPhillips expects to incur minimal impacts to its Norway production volumes during 2002 as a result of these curtailments--less than 1 percent, compared with budgeted volumes for the first and second quarters of the year. In Venezuela, Petroleos de Venezuela S.A. (PdVSA), the state-owned oil company, has indicated production capacity for the Hamaca heavy-oil project will be restricted during 2002, taking into consideration pipeline constraints and major oil exporting country curtailment recommendations. The future impact of curtailment on Hamaca's 2002 production is uncertain, but has not been significant to date. In December 2001, the Norwegian government endorsed the company's recommendation for the removal and disposal of the steel structures onshore and in-place disposal of cuttings related to Ekofisk I. Removal of 11 platforms and the topside of the Ekofisk tank is scheduled to be completed by 2013. In addition, the OSPAR (Oslo and Paris Convention for the Protection of the Marine Environment of the Northeast Atlantic countries) has 51

endorsed in-place disposal of the concrete structure in a cleaned condition. This issue is expected to be finalized by the Norwegian government in a separate parliamentary bill during the spring session of 2002. In December 2001, ConocoPhillips and its co-venturers in the Bayu-Undan field received from the East Timor Council of Ministers an endorsement of the Understanding on a tax and fiscal package that will allow the Bayu-Undan gas development in the Timor Sea to proceed. The company is currently awaiting ratification by Australia so that finalization of gas sales arrangements can proceed. Finalization of a new treaty between Australia and East Timor would allow plans to develop the potential gas resources to move forward. On March 12, 2002, ConocoPhillips announced that it and its co-venturers had signed a Heads of Agreement with The Tokyo Electric Power Company, Incorporated (TEPCO) and Tokyo Gas Co., Ltd. (Tokyo Gas) that would enable ConocoPhillips and its co-venturers to move forward with the gas development phase of the project when the Australian authorities ratify the tax and fiscal package. Under the terms of the agreement, the co-venturers would supply TEPCO and Tokyo Gas with three million tons per year of liquefied natural gas for a period of 17 years, utilizing natural gas from the Bayu-Undan field. First shipments would be scheduled for January 2006. The agreement would allow ConocoPhillips to go forward with plans to develop a liquefied natural gas facility near Darwin, Australia, utilizing the company's Optimized Cascade liquefied natural gas process. Final board approvals from co-venturers and formal project commitments are expected to be completed by the end of the third quarter of 2002. On March 12, ConocoPhillips also announced that, under a separate agreement, the company plans to sell a 10.08 percent interest in the unitized Bayu-Undan field to TEPCO and Tokyo Gas. During 2001, ConocoPhillips announced that it had signed a letter of intent with El Paso Corporation contemplating EL Paso's purchasing liquefied natural gas from the Greater Sunrise fields with possible transportation to markets in Southern California and northern Baja California in Mexico. A definitive purchase agreement was not reached between El Paso and the Greater Sunrise owners. However, ConocoPhillips and El Paso are 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. Front-end engineering design is under way and the companies are working with federal, state, and local officials in Mexico to secure permits for the project. A decision to proceed with the terminal project is expected in the third quarter of 2002. ConocoPhillips and El Paso would each control 50 percent of the terminal capacity and each are pursuing 52

liquefied natural gas supplies and downstream gas markets to utilize their respective shares of the capacity. During 2001, ConocoPhillips was selected to participate in Core Venture 1 (CV-1), the largest of three proposed developments offered by the Kingdom of Saudi Arabia's Natural Gas Initiative. CV-1 would include natural gas exploration, midstream, petrochemical, and power and water investments in Saudi Arabia. Negotiations are in progress between the Kingdom and co-venturers in the CV-1 project with anticipated finalization of issues within the Preparatory Agreement in the second quarter of 2002. ConocoPhillips has a 15 percent interest in the project. ConocoPhillips, along with BP and ExxonMobil, is evaluating the potential for a natural gas pipeline from the North Slope to the Lower 48. While, in the current economic environment, the company does not believe the project provides the desired return on investment, given the significant size and risk associated with the project, ConocoPhillips continues to search for a solution that will allow this resource to be produced. The company's net book value of these North Slope natural gas resources was $369 million at December 31, 2001. In 2002, ConocoPhillips expects worldwide production of approximately 830,000 barrels-of-oil-equivalent per day from currently proved reserves, a slight increase over the 821,000 daily average rate for 2001. Crude oil and natural gas prices are subject to external factors over which the company has no control, such as global economic conditions, demand growth, inventory levels, weather, competing fuel prices and the availability of supply. A worldwide economic slowdown, along with adequate inventories and an unusually warm early winter, put downward pressure on energy prices in 2001 and early 2002. Major oil exporting countries pledged production restraints in late 2001, somewhat stabilizing crude oil prices in early 2002. The warm winter and adequate natural gas storage levels have kept U.S. natural gas prices around $2 per thousand cubic feet into early 2002. Refining margins are subject to the price of crude oil and other feedstocks, and the price of petroleum products, which are subject to market factors over which the company has no control, such as the U.S. economy; seasonal factors that affect demand, such as the summer driving months; and the levels of refining output, including refining capacity relative to demand. A weak U.S. economy and adequate supply have resulted in low refining margins in early 2002. The outlook for the remainder of 2002, for both upstream and downstream prices, is dependent on an economic recovery in the United States and worldwide, as well as 53

the level of output from major crude oil producing nations and their compliance with pledged production restraints. Conflicts in the Middle East could also lead to price volatility in 2002. CAUTIONARY STATEMENT FOR THE PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995 ConocoPhillips is including the following cautionary statement to take advantage of the "safe harbor" provisions of the PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995 for any forward-looking statement made by, or on behalf of, the company. The factors identified in this cautionary statement are important factors (but not necessarily all important factors) that could cause actual results to differ materially from those expressed. Where any such forward-looking statement includes a statement of the assumptions or bases underlying such forward-looking statement, the company believes such assumptions or bases to be reasonable and makes them in good faith. Assumed facts or bases almost always vary from actual results, and the differences between assumed facts or bases and actual results can be material, depending on the circumstances. Where, in any forward-looking statement, the company, or its Management, expresses an expectation or belief as to future results, there can be no assurance that the statement of expectation or belief will result, or be achieved or accomplished. The following are identified as important risk factors, but not all of the risk factors, that could cause actual results to differ materially from those expressed in any forward-looking statement made by, or on behalf of, the company: o Plans for the further implementation of Management's announced strategy for certain of its business segments are subject to: the completion of the announced merger with Conoco; receipt of any approvals or clearances that may be required from domestic and foreign government authorities; required disposition of assets, if any, to meet regulatory requirements; successful integration of Conoco businesses, assets, operations and personnel with those of the company; continued successful integration of the recently acquired Tosco assets; the successful development and operation of the company's current E&P projects, and the achievement of production estimates; the achievement of cost savings and synergies that are dependent on the integration of personnel, business systems and operations from the Conoco merger and the Tosco acquisition; the operation and financing of the DEFS and CPChem joint ventures; and the demand and prices for the products produced by DEFS and CPChem. 54

o Plans to drill wells and develop offshore or onshore exploration and production properties are subject to: the company's ability to obtain agreements with co-venturers, partners and governments and government agencies, including necessary permits; its ability to engage specialized drilling, construction and other contractors and equipment and to obtain economical and timely financing; construction of pipelines, processing and production facilities for its Bayu-Undan, Bohai Bay, Hamaca and other E&P projects; geological, land or sea conditions; world prices for oil, natural gas and natural gas liquids; adequate and reliable transportation systems, including the Trans-Alaska Pipeline System, the Valdez Marine Harbor Terminal, and the acquired and to-be-constructed crude oil tankers; and foreign and United States laws, including tax laws. o Plans for the modernization, the debottlenecking or other improvement projects at its refineries, including the installation and operation of its proprietary sulfur removal technology implementation, and the timing of production from such plants are subject to: approval from the company's and/or subsidiaries' Boards of Directors; obtaining loans and/or project financing; the issuance by foreign, federal, state, and municipal governments, or agencies thereof; obtaining timely building, environmental and other permits; and the availability of specialized contractors, work force and equipment. Production and delivery of the company's products are subject to: domestic and worldwide prices and demand for refined products; availability of raw materials; and the availability of transportation for products in the form of pipelines, railcars, trucks or ships. o The ability to meet liquidity requirements, including the funding of the company's capital program from borrowings, asset sales, and operations, is subject to: the negotiation and execution of various bank, project and public financings and related financing documents, the market for any such debt, and interest rates on the debt; the identification of buyers and the negotiation and execution of instruments of sale for any assets that may be identified for sale; changes in the commodity prices of the company's basic products of oil, natural gas and natural gas liquids, over which ConocoPhillips may have little or no control; its ability to operate refineries and exploration and production operations consistently and safely, with no major disruption in production or transportation of products from such operations; and the effect of foreign and domestic legislation of federal, state and municipal governments that have jurisdiction in regard to taxes, the environment and human resources. 55

o Estimates of proved reserves, and planned spending for maintenance and environmental remediation were developed by company personnel using the latest available information and data, and recognized techniques of estimating, including those prescribed by the U.S. Securities and Exchange Commission, generally accepted accounting principles and other applicable requirements. Estimates of project costs, cost savings and synergies were developed by the company from current information. The estimates for reserves, supplies, costs, maintenance, environmental remediation, savings and synergies can change positively or negatively as new information and data become available. 56

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA CONOCOPHILLIPS INDEX TO FINANCIAL STATEMENTS

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 financial statements. 57

- -------------------------------------------------------------------------------- REPORT OF INDEPENDENT AUDITORS The Board of Directors and Stockholders ConocoPhillips We have audited the accompanying consolidated balance sheets of ConocoPhillips (formerly Phillips Petroleum Company) as of December 31, 2001 and 2000, and the related consolidated statements of income, changes in common stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2001. Our audits also included financial statement Schedule II--Valuation Accounts and Reserves. These financial statements and schedule are the responsibility of the company's Management. Our responsibility is to express an opinion on these financial statements 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, 2001 and 2000, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein. As discussed in Note 2 to the financial statements, in 2001 ConocoPhillips changed its method of accounting for the costs of major maintenance turnarounds. /s/ ERNST & YOUNG LLP ERNST & YOUNG LLP Tulsa, Oklahoma March 15, 2002 except for Notes 23 and 25, as to which the date is December 20, 2002 58

- -------------------------------------------------------------------------------- CONSOLIDATED STATEMENT OF INCOME CONOCOPHILLIPS (FORMERLY PHILLIPS PETROLEUM COMPANY)

See Notes to Financial Statements. 59

- -------------------------------------------------------------------------------- CONSOLIDATED BALANCE SHEET CONOCOPHILLIPS (FORMERLY PHILLIPS PETROLEUM COMPANY)

See Notes to Financial Statements. 60

- -------------------------------------------------------------------------------- CONSOLIDATED STATEMENT OF CASH FLOWS CONOCOPHILLIPS (FORMERLY PETROLEUM COMPANY)

*Net of acquisition and disposition of businesses. See Notes to Financial Statements. 61

- -------------------------------------------------------------------------------- CONSOLIDATED STATEMENT OF CHANGES CONOCOPHILLIPS IN COMMON STOCKHOLDERS' EQUITY (FORMERLY PHILLIPS PETROLEUM COMPANY)

See Notes to Financial Statements. 62

- -------------------------------------------------------------------------------- NOTES TO FINANCIAL STATEMENTS CONOCOPHILLIPS (FORMERLY PETROLEUM COMPANY) NOTE 1--ACCOUNTING POLICIES o CONSOLIDATION PRINCIPLES AND INVESTMENTS--Majority-owned, controlled subsidiaries are consolidated. Investments in affiliates in which the company owns 20 percent to 50 percent of voting control are generally accounted for under the equity method. Undivided interests in oil and gas joint ventures, pipelines and natural gas plants are consolidated on a pro rata basis. Other securities and investments 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 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--All periods have been reclassified for discontinued operations (see Note 25--Merger with Conoco Inc.). Certain amounts in the 2000 and 1999 financial statements have been reclassified to conform with the 2001 presentation, including presenting excise taxes on petroleum products sales as a component of operating revenues and taxes other than income taxes. 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. 63

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. 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 and petroleum products 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 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 market value in either accounts and notes receivable or accounts payable. Recognition of the gain or loss that results from recording and adjusting a derivative to fair market 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. If a derivative is used to hedge the fair value of an asset, liability, or firm commitment, the gains or losses from adjusting the derivative to its market 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 derivatives hedging cash flows 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 income, gains and losses from derivatives used for trading are recorded in other income. Gains and losses from derivatives used for purposes other than trading are recorded in either sales and other operating revenues or purchased crude oil and products, 64

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. 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. Intangible assets are considered impaired if the fair value of the intangible asset is lower than cost. Fair value of intangible assets is determined based on quoted market prices in active markets, 65

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 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 asset. o DEPRECIATION AND AMORTIZATION--Depreciation and amortization of properties, plants and equipment on producing oil and gas properties and on certain pipeline assets (those which are expected to have a declining utilization pattern) 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. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are 66

largely independent of the cash flows of other groups of assets--generally on a field-by-field basis for exploration and production assets or at an entire complex level for downstream assets. 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. 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, Financial Accounting Standards Board (FASB) Statement 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. 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 67

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--The estimated undiscounted costs, net of salvage values, of dismantling and removing major oil and gas production and transportation facilities, including necessary site restoration, are accrued using either the unit-of-production or the straight-line method, which is used for certain regional production transportation assets that are expected to have a straight-line utilization pattern. Environmental expenditures are expensed or capitalized as appropriate, 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 deemed probable. 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 temporary differences related to investments in certain foreign subsidiaries and foreign corporate joint ventures that are essentially permanent in duration. Allowable tax 68

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 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 CBT are excluded from the daily weighted-average number of common shares outstanding in both calculations. NOTE 2--EXTRAORDINARY ITEM AND ACCOUNTING CHANGE In the third quarter of 2001, ConocoPhillips incurred an extraordinary loss of $10 million (after reduction for income taxes of $4 million) attributable to the call premium on the early retirement of its $300 million 9.18% Notes due September 15, 2021, at 104.59 percent. The redemption was funded by issuing commercial paper. 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:

NOTE 3--ACQUISITION OF TOSCO CORPORATION On September 14, 2001, Tosco Corporation (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. 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 businesses' 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. 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 70

pricing model, based on assumptions prevalent at the February announcement date. The transaction was accounted for using the purchase method of accounting as required by FASB Statement No. 141, "Business Combinations," which was issued in the second quarter of 2001. Goodwill and identifiable intangible assets recorded in the acquisition will be tested periodically for impairment as required by FASB Statement No. 142, "Goodwill and Other Intangible Assets," also issued in the second quarter of 2001. The allocation of the purchase price to specific assets and liabilities is based, in part, upon an outside appraisal of Tosco's long-lived assets. The allocation is still preliminary at this time. The company expects to finalize the outside appraisal of the long-lived assets and the determination of the fair value of all other Tosco assets and liabilities in 2002. Deferred tax liabilities will also be finalized after the final allocation of the purchase price and the final tax basis of the assets and liabilities has been determined. Based on the year-end 2001 preliminary purchase price allocation, the following table summarizes the fair values of the assets acquired and liabilities assumed at September 14, 2001:

The $1,251 million of identifiable intangible assets consist primarily of marketing trade names ($655 million) and refinery air emission and operating permits ($562 million). The preliminary appraisal methodology used to value refinery air emission permits is presently under review and, depending on the outcome of that review, could result in a reallocation of purchase price between identifiable intangible assets and goodwill. Of the $1,251 million, $1,240 million has been preliminarily allocated to intangible assets not subject to amortization, while $11 million has been preliminarily allocated to intangible assets with a weighted-average amortization period of seven years. The company has not yet determined the assignment of Tosco goodwill to specific reporting units. Currently, all Tosco goodwill is being reported as part of the R&M reporting segment. Of the $2,288 million of goodwill, a significant portion, $1,755 million, was attributable to deferred tax liabilities, which are required to be recorded on an undiscounted basis. Therefore, a significant portion of the goodwill will be allocated to reporting units based on the sources of the book-tax differences that give rise to the deferred tax liabilities. This goodwill is not deductible for tax purposes. The remaining $533 million of true goodwill will ultimately be assigned to those reporting units that benefit from the synergies and strategic advantages of the merger. Expected expenditures for Tosco environmental remediation activities are: $61 million in 2002, $55 million in 2003, $43 million in 2004, $34 million in 2005, and $33 million in 2006. Remaining expenditures thereafter are expected to be $150 million. The effect of inflation, net of a 5 percent discount factor, reduced the accrual by $73 million, resulting in a discounted environmental liability of $303 million at December 31, 2001. The following unaudited pro forma summary presents information as if Tosco had been acquired at the beginning of each period presented. The pro forma amounts include certain adjustments, including recognition of depreciation and amortization based on the preliminary allocated purchase price of the properties, plants and equipment acquired; adjustment of interest for the amortization of the fair-value adjustment to debt; cessation of the amortization of deferred gains not recognizable in the purchase price allocation; accretion of discount on environmental accruals recorded at net present values; and adjustments to conform Tosco's accounting policies for major maintenance turnarounds to ConocoPhillips' expense-as-incurred method. The pro forma amounts do not reflect any benefits from economies 72

which might be achieved from combining the operations. The pro forma information does not necessarily reflect the actual results that would have occurred had the companies been combined during the periods presented, nor is it necessarily indicative of the future results of operations of the combined companies:

NOTE 4--ALASKAN ACQUISITION On April 26, 2000, ConocoPhillips purchased all of Atlantic Richfield Company's (ARCO) Alaska businesses, other than three double-hulled tankers under construction and certain pipeline operations, which were acquired on August 1, 2000. The acquisition was accounted for using the purchase method of accounting. Because the purchase was retroactive to January 1, 2000, the activity from that date until the dates of closing has been reflected as adjustments to the purchase price. Results of operations for the acquired businesses were included in ConocoPhillips' income statement effective after April 26, and August 1, 2000, respectively. ConocoPhillips used a combination of new corporate borrowings and available cash to fund the $6,441 million cash purchase price of the ARCO Alaska businesses, paid $15 million cash for acquisition-related costs, assumed $265 million of variable-rate long-term debt, and assumed working capital and various other liabilities and assets. ConocoPhillips did not receive any indemnification for environmental liabilities associated with the ARCO Alaska operations. The allocation of the purchase price to specific assets and liabilities was based, in part, on an outside 73

appraisal of ARCO Alaska's long-lived assets. Based on the final purchase price allocation, the following table summarizes the fair values of the assets acquired and liabilities assumed during 2000:

No goodwill was recorded in the purchase price allocation. The following unaudited pro forma summary presents information as if the businesses acquired on April 26, and August 1, 2000, had been acquired at the beginning of each period presented. The pro forma amounts include certain adjustments, including recognition of depreciation, depletion and amortization; interest on additional debt incurred; capitalization of interest on major projects under development; and adjustments to conform ARCO Alaska's accounting policy that capitalized the costs of enhanced oil recovery miscible injectants to ConocoPhillips' policy of expensing such injectants as incurred. The pro forma amounts do not reflect any benefits from economies which might be achieved from combining the operations. The pro forma information does not necessarily reflect the actual results that would have occurred had the businesses been combined during the periods presented, nor is it necessarily indicative of future results of operations of the combined companies: 74

*Restated to include excise taxes on petroleum products sales. During 2001, net cash activity with BP related to the acquisition was not material. However, there was a $128 million increase in properties, plants and equipment during the period due to the additional quantification and recognition of certain non-cash liabilities of the acquired businesses, primarily an additional accrual, on a discounted basis, to cover environmental remediation activities required by the state of Alaska at exploration and production sites formerly owned by ARCO. Expected expenditures for Alaska remediation activities are: $27 million in 2002, $18 million in 2003, $16 million in 2004, $17 million in 2005, and $15 million in 2006. Remaining expenditures thereafter are expected to be $83 million. The effect of inflation, net of a 5 percent discount factor, reduced the accrual by $13 million, resulting in a discounted environmental liability of $163 million at December 31, 2001. NOTE 5--INVENTORIES Inventories at December 31 were:

Included were inventories valued on a LIFO basis totaling $2,178 million and $200 million at December 31, 2001 and 2000, 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 75

of inventories amounted to $2 million and $493 million at December 31, 2001 and 2000, 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. Inventories were significantly higher at year-end 2001, compared with year-end 2000, due to the Tosco acquisition (see Note 3--Acquisition of Tosco Corporation). NOTE 6--INVESTMENTS AND LONG-TERM RECEIVABLES Components of investments and long-term receivables at December 31 were:

At December 31, 2001, retained earnings included $124 million related to the undistributed earnings of affiliated companies, and distributions received from affiliates were $163 million, $2,180 million and $111 million in 2001, 2000 and 1999, respectively. 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, Duke Energy Field Services, LLC (DEFS). Duke Energy owns 69.7 percent of the new company, which it consolidates, and ConocoPhillips owns 30.3 percent. At the close of business on March 31, 2000, ConocoPhillips began accounting for its investment in the new company on the equity basis. DEFS arranged debt financing and on April 3, 2000, made one-time cash distributions to both Duke Energy and ConocoPhillips. ConocoPhillips received $1.2 billion. Duke Energy estimated the 76

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 Chevron Phillips Chemical Company'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 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 its gas gathering, processing and marketing business through March 31, 2000, and its 30.3 percent share of DEFS' earnings since that date. Included in operating results in 2001 and 2000 were after-tax benefits of $36 million and $27 million, respectively, representing the amortization of the $824 million basis difference between the book value of ConocoPhillips' contribution to DEFS and its 30.3 percent equity interest in DEFS. This difference 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. 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 which require their redemption with any proceeds from an initial public offering. 77

Summarized financial information for DEFS (100 percent) follows:

The members of DEFS are generally taxable on their respective shares of income for U.S. and state income tax purposes. ConocoPhillips' share of income taxes incurred directly by DEFS is reported in equity in earnings, and as such is not included in income taxes in ConocoPhillips' consolidated financial statements. CHEVRON PHILLIPS CHEMICAL COMPANY LLC On July 1, 2000, ConocoPhillips and ChevronTexaco Corporation, as successor to Chevron Corporation (ChevronTexaco), combined the companies' 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 the voting and economic interests in CPChem, and on July 1, 2000, ConocoPhillips began accounting for its investment in CPChem using the equity method. CPChem accounted for the combination using the historical bases of the assets and liabilities contributed by ConocoPhillips and ChevronTexaco. At December 31, 2001, the book value of the net assets contributed to CPChem was $3.0 billion. ConocoPhillips' 50 percent share of the total net assets of CPChem was $2.9 billion. A basis difference of $116 million is being amortized over 20 years, consistent with the remaining estimated 78

useful lives of the properties, plants and equipment contributed to CPChem. In connection with the combination, CPChem borrowed $1.67 billion. The proceeds of the borrowing were used to make cash distributions of $835 million each to ConocoPhillips and ChevronTexaco. Also in connection with the combination, ConocoPhillips made a $70 million cash contribution to CPChem related to re-establishing the K-Resin styrene-butadiene copolymer operations contributed by ConocoPhillips. ConocoPhillips will continue to contribute approximately $3 million per month during 2002 until the K-Resin facilities can demonstrate production and sales capacity of specified quantities, or December 31, 2002, whichever occurs earlier. These cash contributions will be treated as contributed capital and reflected in the basis difference. ConocoPhillips' consolidated 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. Also included in ConocoPhillips' 2001 and 2000 operating results were a $4 million and a $2 million after-tax reduction, respectively, for the amortization of the $116 million basis difference between the book value of ConocoPhillips' contribution to CPChem and its 50 percent interest in the equity of CPChem. Summarized financial information for CPChem (100 percent) follows:

The members of CPChem are generally taxable on their respective shares of income for U.S. and state income tax purposes. ConocoPhillips' share of income taxes incurred directly by CPChem is reported in equity in earnings, and as such is not included in income taxes in ConocoPhillips' consolidated financial statements. 79

OTHER EQUITY INVESTMENTS The company owns or owned investments in chemicals, a heavy-oil project, oil and gas transportation, coal mining, and other industries. During 2000, certain of ConocoPhillips' equity investments were contributed to the CPChem and DEFS joint ventures. As a result, the information included in the summarized financial information for other equity companies includes financial information for those equity investments only for those periods prior to the effective dates of the joint ventures. Summarized financial information for all entities accounted for using the equity method, except DEFS and CPChem, follows:

MEREY SWEENY, L.P. In August 1998, Merey Sweeny, L.P. (MSLP) was formed to build and own a 58,000-barrel-per-day coker, vacuum unit and related facilities located at ConocoPhillips' Sweeny Complex. The coker unit was operational in the fourth quarter of 2000. ConocoPhillips and the Venezuelan state oil company, Petroleos de Venezuela S.A., each hold an indirect 50 percent interest in Merey Sweeny, L.P. In 1998, 2000 and 2001, the limited partnership issued $25 million of tax-exempt bonds due 2018, 2020 and 2021, respectively. Until the senior bank debt of MSLP is repaid in full, interest and principal payments on the tax-exempt bonds are made by drawing upon a letter of credit facility that has to be immediately reimbursed by the two partners in MSLP. ConocoPhillips' December 31, 2001 and 2000, balance sheets included $38 million and $25 million, respectively, of long-term debt as a result of the company's primary obligor support of its 50 percent share of these financings. During 1999, MSLP issued $350 million of 8.85% Bonds due 2019 and entered into a 15-year, $80 million bank facility. The bank facility's commitment was reduced to $75 million on December 18, 2001, according to the 80

terms of the facility. At December 31, 2001, no funds had been drawn under the bank facility. In February 2002, MSLP reduced the credit facility to $25 million. The proceeds of the bond issues were used to fund the construction of the coker and related refinery improvements. Any additional expenditures will be funded through the bank facility, equity contributions or cash from operations. In connection with any financing, the partners made capital contributions to the partnership on a pro rata joint-and-several basis to the extent necessary to successfully complete construction. When startup certification is achieved the bonds become non-recourse to the two MSLP owners and the bondholders can then look only to MSLP's cash flows for payment. HAMACA HOLDING LLC During 2000, ConocoPhillips and ChevronTexaco, as successor to Texaco Inc. (ChevronTexaco), formed Hamaca Holding LLC, which holds the companies' 70 percent ownership interests in the Hamaca heavy-oil project in Venezuela. The other 30 percent ownership interest in the Hamaca project is held by Petroleos de Venezuela S.A. Hamaca Holding LLC participates, on behalf of its two owners, in both the development of the heavy-oil field and the operations to upgrade the heavy oil into a marketable, medium-grade oil and in the placement of joint project financing. ConocoPhillips owns approximately 57 percent of Hamaca Holding LLC and accounts for it using the equity method of accounting, as control is shared equally with ChevronTexaco. In the second quarter of 2001, Hamaca Holding LLC and its co-venturer in the Hamaca project secured approximately $1.1 billion in debt financing for the project. The Export-Import Bank of the United States provided a guarantee supporting a 17-year-term $628 million bank facility. Additionally, an unguaranteed $470 million 14-year-term commercial bank facility was arranged for the project. At December 31, 2001, $633 million had been drawn under these credit facilities. 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 become non-recourse to the co-venturers and the lenders under those facilities can then look only to the Hamaca project's cash flows for payment. 81

NOTE 7--PROPERTIES, PLANTS AND EQUIPMENT The company's investment in properties, plants and equipment (PP&E), with accumulated depreciation, depletion and amortization (DD&A), at December 31 was:

Net properties, plants and equipment increased approximately $9 billion during 2001, primarily due to the acquisition of Tosco (see Note 3--Acquisition of Tosco Corporation). 82

NOTE 8--OTHER COMPREHENSIVE INCOME The components and allocated tax effects of other comprehensive income (loss) follow:

At year-end 2001, a minimum pension liability adjustment was required for certain of the company's domestic pension plans and for its plan covering employees in the United Kingdom. For these plans, accumulated benefit obligations exceeded the fair value of plan assets by $383 million, compared with a net liability recognized in the balance sheet of $102 million. After 83

reductions for amounts charged to intangible assets ($61 million) and deferred taxes ($77 million), a charge to accumulated other comprehensive loss of $143 million was recorded. 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. 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. Accumulated other comprehensive loss in the equity section of the balance sheet included:

NOTE 9--PROPERTY IMPAIRMENTS During 2001, 2000 and 1999, the company recognized the following before-tax impairment charges in its E&P segment:

After-tax, the above impairment charges were $25 million in 2001, $95 million in 2000, and $34 million in 1999. 84

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 investment 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 disappointing drilling results or negative oil and gas reserve revisions. The U.S. E&P impairment charges in 1999 were primarily related to the Agate subsalt field in the Gulf of Mexico, where a downhole well failure resulted in the shutdown of the field. The U.K. E&P impairment charges in 1999 were primarily related to the Renee and Maureen fields. The Renee impairment was triggered by an unsuccessful development well, while the Maureen impairment resulted from upward revisions of platform dismantlement costs. Other E&P impairments in 1999 were caused by upward revisions of decommissioning costs related to outlying fields in the Ekofisk area. NOTE 10--ACCRUED DISMANTLEMENT, REMOVAL AND ENVIRONMENTAL COSTS At December 31, 2001 and 2000, the company had accrued $776 million and $681 million, respectively, of dismantlement and removal costs, primarily related to worldwide offshore production facilities and to production facilities in Alaska. Estimated total future dismantlement and removal costs at December 31, 2001, were $2,827 million, compared with $2,570 million in 2000. These costs are accrued primarily on the unit-of-production method. ConocoPhillips had accrued environmental costs, primarily related to cleanup of ponds and pits 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 ARCO, of $388 million and $78 million at December 31, 2001 and 2000, respectively. ConocoPhillips had also accrued $136 million and $40 million of environmental costs associated with discontinued or sold operations at December 31, 2001 and 2000, respectively. 85

Also,$12 million and $6 million were included at December 31, 2001 and 2000, respectively, for sites where the company has been named a Potentially Responsible Party. At December 31, 2001 and 2000, $3 million had been accrued for other environmental litigation. Total environmental accruals at December 31, 2001 and 2000, were $539 million and $127 million, respectively. The 2001 increase in accrued environmental costs of $412 million is primarily the result of ConocoPhillips' recent acquisition of Tosco on September 14, 2001. Accruals totaling approximately $303 million were added as a result of that transaction. Earlier in the year, the company's accrual was increased by approximately $107 million for remediation activities required by the state of Alaska at exploration and production sites formerly owned by ARCO. Because these accruals relate to environmental conditions that existed when ConocoPhillips acquired Tosco and the Alaskan businesses, the charges impacted the allocation of the purchase price of each acquisition, not the company's net income. Of the total $1,315 million of accrued dismantlement, removal and environmental costs at December 31, 2001, $173 million was classified as a current liability on the balance sheet, under the caption "Other accruals." At year-end 2000, $106 million was classified as current. 86

NOTE 11--DEBT Long-term debt at December 31 was:

*Debt assumed in the Tosco acquisition completed on September 14, 2001. Maturities in 2002 through 2006 are: $44 million (included in current liabilities), $264 million, $7 million, $1,154 million and $1,349 million, respectively. 87

During 2001, ConocoPhillips redeemed its $300 million 9.18% Notes due September 15, 2021, at 104.59 percent, retired its $250 million 9% Notes due 2001, and assumed $2.1 billion of debt with the acquisition of Tosco. After amortization of the fair-value-adjustment premiums, the fixed-rate debt had a weighted-average effective interest rate of 7.3 percent. In October 2001, ConocoPhillips entered into two new revolving bank credit facilities: a five-year credit agreement providing for commitments not to exceed $1.5 billion; and a 364-day credit agreement for commitments not to exceed $1.5 billion. The $3 billion of new credit facilities replaced all those that were previously available, including a $1 billion facility assumed as part of the Tosco transaction. All previous facilities were canceled subsequent to the effectiveness of the new facilities. The new facilities are available for use either as direct bank borrowings or as support for the issuance of commercial paper. At December 31, 2001, ConocoPhillips had $1,081 million of commercial paper outstanding, supported by the long-term credit facility. This amount approximates fair market value. As of December 31, 2001, the company's wholly owned subsidiary, Phillips Petroleum Company 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 (Board). At December 31, 2001, $322 million was outstanding under the company's Long-Term Stock Savings Plan (LTSSP) term loan, which will require annual installments beginning in 2007 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. The company does not anticipate a cessation of participation by the lenders, and plans to commence scheduled repayments beginning in 2007. 88

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 17--Employee Benefit Plans for additional discussion of the LTSSP. NOTE 12--CONTINGENCIES 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 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 change 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 89

likely effects of inflation and other societal and economic factors. Also considered when measuring environmental liability are the company's prior experience in remediation of contaminated sites, other companies' cleanup experience and data released by the 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 is generally joint and several for federal sites and frequently so for state sites, the company is usually but 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 at any site which it has been designated as a potentially responsible party. If ConocoPhillips was 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, to date, been successful 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 ConocoPhillips' 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. 90

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. This indemnification agreement with Unocal has a 25-year term and ConocoPhillips has a maximum cap, adjusted for amounts paid through December 31, 2001, of $140 million of environmental remediation costs that ConocoPhillips has to fund during the remainder of the agreement period. The company is currently participating in environmental assessments and cleanup under these laws 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 (unless acquired in a purchase business combination) 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. At December 31, 2001, contingent liability accruals of $11 million had been made for the company's PRP sites, and $3 million for other environmental contingent liabilities. Accrued environmental liabilities will be paid over periods extending as far as 30 years in the future. These accruals have not been reduced for possible insurance recoveries. In the future, the company may be involved in additional environmental assessments, cleanups and proceedings. OTHER LEGAL PROCEEDINGS--The company 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--The company has contingent liabilities resulting from throughput agreements with pipeline and processing companies in which it holds stock interests. 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. 91

NOTE 13--FINANCIAL INSTRUMENTS AND DERIVATIVE CONTRACTS DERIVATIVE INSTRUMENTS AND OTHER CONTRACTS 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 favorable market conditions. During the third quarter of 2001, ConocoPhillips' Board of Directors revised its policy governing the use of derivative instruments. The revised policy prohibits the holding or issuing of highly complex or leveraged derivatives, as did the previous policy, and unless approved by the Chief Executive Officer, all derivative instruments used by the company must not contain embedded financing features and must be sufficiently liquid that comparable valuations are readily available. The policy also requires the Chief Executive Officer to establish the maximum derivative position limits for ConocoPhillips and requires the company's Risk Management Steering Committee, comprised of senior management, to monitor the use and effectiveness of derivatives. The Audit Committee of the company's Board of Directors periodically reviews the derivatives policy and compliance with the policy. FASB Statement No. 133, "Accounting for Derivative Instruments and Hedging Activities" (Statement No. 133), as amended, requires companies to recognize all derivative instruments as either assets or liabilities on the balance sheet at fair value. 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 hedge, and the type of hedge. ConocoPhillips elected not to use hedge accounting for derivative contracts used in the company's risk management programs during 2001, except for the two programs noted below. All gains and losses, realized or unrealized, from derivative contracts not designated as hedges have been recognized in the statement of income. Assets and liabilities resulting from derivative contracts open at December 31, 2001, appear as receivables or payables on the balance sheet. The amount related to hedging activity in other comprehensive income is the net loss from the cash-flow hedges of the company's hedge of the Brazilian real, discussed below. ConocoPhillips had no cumulative effect of accounting change as a result of adopting Statement No. 133, as of January 1, 2001. Statement 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 92

expected to be used or sold by the company over a reasonable period in the normal course of business and the company has documented its intent to apply this exception. ConocoPhillips generally applies this exception to all eligible purchase and sales contracts; however, the company may elect not to apply this exception if a derivative instrument will be used to hedge the contract but hedge accounting will not be applied. When this occurs, the purchase or sale contract will be recorded on the balance sheet as a derivative in accordance with the preceding paragraph. FINANCIAL DERIVATIVE CONTRACTS--During the third quarter of 2001, the company 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 2002. No component of the hedge results was excluded from the assessment of hedge effectiveness, and no gain or loss was recorded in earnings from hedge ineffectiveness. The company on occasion uses forward-exchange contracts or collars to manage exposures to currency-exchange-rate fluctuations associated with certain assets, liabilities and firm commitments for which hedge accounting was not used. During 2001, ConocoPhillips used derivative contracts to manage exposures to: 1) exchange-rate fluctuations between U.S. and Australian dollars to fund an Australian acquisition; and 2) exchange-rate fluctuations between revenues received in U.S. dollars and various European currencies and the company's Norwegian subsidiary's expenditures payable in kroner. Results from this activity appear in foreign currency transaction gains and losses on the statement of income. COMMODITY DERIVATIVE CONTRACTS--During the last four months of 2001, the company used hedge accounting for West Texas Intermediate crude oil (WTI) futures designated as fair-value hedges of firm commitments to sell WTI at Cushing, Oklahoma. The changes in the fair values of the futures and the 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. 93

ConocoPhillips also used various derivative instruments to manage exposures to commodity price fluctuations for which hedge accounting was not used. Futures, swaps, options, and fixed-price contracts were used to lock in future sales prices for crude oil, motor fuel, distillates, propane, butane and other light ends, blending components, and residual fuels, and also to lock in margins (e.g., the spread between the cost of feedstock purchased and refined products sold). These instruments were also used to manage the exposure to changes in the value of physical inventory. In addition, the company uses futures contracts to exploit favorable market conditions. 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 does not anticipate non-performance by any of these counterparties, none of whom does sufficient volume with the company to create a significant concentration of credit risk. 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 customer base, both nationally and internationally. At December 31, 2001, the amount of trade receivables owed to ConocoPhillips or its U.S. subsidiaries, excluding credit card receivables, by companies directly or indirectly exposed to the U.S. market for oil, gas, and refined products was less than $700 million. 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 uses 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. 94

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. 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:

*Indicates amount was less than $1 million. 95

NOTE 14--PREFERRED STOCK 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 exist 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 29, 1996, Trust I completed a $300 million underwritten public offering of 12,000,000 shares of 8.24% Trust Originated Preferred Securities (Preferred Securities). The sole asset of Trust I is $309 million of ConocoPhillips' 8.24% Junior Subordinated Deferrable Interest Debentures due 2036 (Subordinated Debt Securities I), purchased by Trust I on May 29, 1996. On January 17, 1997, Trust II completed a $350 million underwritten public offering of 350,000 shares 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 I are due May 29, 2036, and are redeemable in whole, or in part, at the option of ConocoPhillips, on or after May 29, 2001, at a redemption price of $25 per share, plus accrued and unpaid interest. 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. Subordinated Debt Securities I and 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, Trusts I and II are required to apply all redemption proceeds to the immediate redemption of the Trusts' Securities. ConocoPhillips fully and unconditionally guarantees the Trusts' obligations under the Preferred and Capital Securities. 96

PREFERRED STOCK ConocoPhillips has 300 million shares of preferred stock authorized, none of which was issued or outstanding at December 31, 2001, or 2000. NOTE 15--PREFERRED SHARE PURCHASE RIGHTS ConocoPhillips' Board of Directors authorized and declared a dividend of one preferred share purchase right for each common share outstanding on August 1, 1999, and authorized and directed the issuance of one right per common share for any shares issued after that date. The rights, which expire July 31, 2009, will be exercisable only if a person or group acquires 15 percent or more of the company's common stock or announces a tender offer that would result in 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 $180. 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 rights may be redeemed by the company in whole, but not in part, for one cent per right. In connection with its approval of the proposed merger transaction among Phillips Petroleum Company (Phillips) and Conoco Inc. (Conoco), the Board of Directors approved amendments to the rights that would render them inoperative in connection with the merger. NOTE 16--NON-MINERAL LEASES The company leases ocean transport vessels, tank railcars, corporate aircraft, service stations, computers, office buildings and other facilities and equipment. ConocoPhillips has sale-leaseback transactions involving office buildings, corporate aircraft, retail service stations, railroad tank cars, and ocean-going vessels. 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 in the gross and net amounts of $31 million and $24 million, respectively, were included in the R&M segment's "properties, plants and equipment" balance at December 31, 2001. 97

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. Except in an event of default under the terms of the lease agreements, there are not any circumstances at this time under which ConocoPhillips would be required to record the assets and/or liabilities of the SPEs in its financial statements in the future, based on the terms and provisions within the various arrangements. ConocoPhillips considers an event of default under the terms of the lease agreements to be remote. 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 under any circumstances. At December 31, 2001, future minimum rental payments due under non-cancelable leases were:

*Includes $67 million of above-market capital lease obligations acquired in an acquisition, which are presented as part of Other liabilities and deferred credits on the balance sheet. The above amounts exclude guaranteed residual value payments totaling $197 million in 2003, $262 million in 2004, $866 million in 2005, $52 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. 98

ConocoPhillips has agreements with a shipping company for the long-term chartering 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 years ended December 31 was:

Contingent rentals were not significant in any year presented. 99

NOTE 17--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:

100

Pension plan funds are invested in a diversified portfolio of assets. Approximately $200 million held in a participating annuity contract is not available for meeting benefit obligations in the near term. None of the plans hold company stock. 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. The funded status of the plans was impacted the last year by changes in assumptions used to calculate plan liabilities, acquisition of the Tosco benefit plans, and negative asset performance. At year-end 2001, a minimum pension liability adjustment was required for certain of the company's domestic pension plans and for its plan covering employees in the United Kingdom. For these plans, accumulated benefit obligations exceeded the fair value of plan assets by $383 million, compared with a net liability 101

recognized in the balance sheet of $102 million. After reductions for amounts charged to intangible assets ($61 million) and deferred taxes ($77 million), a charge to accumulated other comprehensive loss of $143 million was recorded.

The company recorded settlement losses of $10 million and $8 million in 2001 and 1999, respectively. 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 $1,519 million, $1,211 million, and $886 million at December 31, 2001, respectively, and $890 million, $739 million, and $683 million at December 31, 2000, respectively. For the company's unfunded non-qualified supplemental key employee pension plans, the projected benefit obligation and the accumulated benefit obligation were $109 million and $76 million, respectively, at December 31, 2001, and were $105 million and $77 million at December 31, 2000. 102

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. As of December 31, 2001, the weighted-average health care cost trend rate is assumed to decrease gradually from 11.5 percent in 2002 to 10.0 percent in 2004. For certain groups of employees, no increases in medical costs are assumed for years beginning in 2005 because of a provision in the health plan that freezes the company's contribution at 2004 levels. For other groups of employees, the trend rate decreases to 5.5 percent by 2010, subject to per capita maximums. The assumed health care cost trend rate has a significant effect on the amounts reported. A one-percentage-point change in the assumed health care cost trend rate would have the following effects on the 2001 amounts:

DEFINED CONTRIBUTION PLANS Most employees are eligible to participate in either the company-sponsored Thrift Plan of Phillips Petroleum Company or the Tosco Corporation Capital Accumulation Plan. Employees contribute a portion of their salaries to any of several investment funds, including a company stock fund, a percentage of which is matched by the company. In addition, eligible participants in the Tosco Corporation Capital Accumulation Plan may receive an additional company contribution in lieu of pension plan benefits. Company contributions charged to expense in total for both plans were $14 million in 2001, and $6 million each in 2000 and 1999. The company's LTSSP is a leveraged employee stock ownership plan. Employees eligible for the Thrift Plan may 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. In 1990, the LTSSP borrowed funds that were used to purchase previously unissued shares of company common stock. 103

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 2002 through 2006, 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 $33 million, $40 million and $35 million in 2001, 2000 and 1999, respectively, all of which was compensation expense. In 2001 and 2000, respectively, the company made cash contributions to the LTSSP of $17 million and $23 million. In 2001, 2000 and 1999, the company contributed 292,857 shares, 508,828 shares and 767,605 shares, respectively, of ConocoPhillips common stock from the Compensation and Benefits Trust. The shares had a fair market value of $17 million, $24 million and $36 million, respectively. Dividends used to service debt were $28 million, $32 million and $41 million in 2001, 2000 and 1999, respectively. These dividends reduced the amount of expense recognized each period. Interest incurred on the LTSSP debt in 2001, 2000 and 1999 was $17 million, $26 million and $22 million, respectively. The total LTSSP shares as of December 31 were:

The fair value of unallocated shares at December 31, 2001, and 2000, was $505 million and $530 million, respectively. 104

STOCK-BASED COMPENSATION PLANS Under the Omnibus Securities Plan (the Plan) approved by shareholders in 1993, stock options and stock awards for certain employees are authorized for up to eight-tenths of 1 percent (0.8 percent) of the total issued and outstanding shares as of December 31 of the year preceding the awards. Any shares not issued in the current year are available for future grant. The Plan could result in an 8 percent dilution of stockholders' interest if all available shares are awarded over the 10-year life of the Plan. The Plan also provides for non-stock-based awards. Stock-based compensation expense recognized in connection with the Plan was $21 million, $23 million and $8 million in 2001, 2000 and 1999, respectively. Shares of stock awarded under the Plan were:

Stock options granted under provisions of the Plan 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 33.33 percent 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. The planned merger with Conoco (see Note 25--Merger with Conoco Inc.) would be a change-in-control event that would result in a lapsing of restrictions on, and payout of, stock and stock option awards under the Plan. ConocoPhillips offered to exchange certain stock awards under the Plan with new awards in the form of restricted stock units. These new restricted stock units would be converted, at the time of the merger with Conoco, into awards based on the same number of shares of ConocoPhillips common stock. The exchange offer expired January 16, 2002. The company has elected to follow Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB No. 25), and related Interpretations in accounting for its employee stock options, and not the fair-value accounting provided for under FASB Statement No. 123, "Accounting for Stock- 105

Based Compensation." 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 recognized under APB No. 25. If the provisions of FASB Statement No. 123 had been applied, net income would have been reduced $17 million, $12 million and $10 million in 2001, 2000 and 1999, respectively. Basic and diluted earnings per share would have been reduced $.06 in 2001, $.05 in 2000 and $.04 in 1999. The average grant-date fair values of options awarded during 2001, 2000 and 1999 were $23.19, $16.00 and $9.92, respectively. The fair value of each option was estimated using the Black-Scholes option-pricing model with the following assumptions: expected dividend yields of 2.5 percent in 2001 and 2000, and 3 percent in 1999; expected life of five years in all years; expected volatility of 27 percent in 2001, 26 percent in 2000, and 21 percent in 1999; and risk-free interest rates of 4.5 percent in 2001, 5.9 percent in 2000 and 6.0 percent in 1999. In September 2001, ConocoPhillips issued 4.7 million vested stock options to replace unexercised Tosco stock options. 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 share. A summary of ConocoPhillips' stock option activity follows:

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OUTSTANDING AT DECEMBER 31, 2001

EXERCISABLE AT DECEMBER 31

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 ConocoPhillips common stock, $1.25 par value, 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 107

of the CBT. In 2001 and 2000, shares transferred out of the CBT were 292,857 and 508,828, respectively. At December 31, 2001, 27.6 million shares remained in the CBT. All shares are required to be transferred out of the CBT by January 1, 2021. NOTE 18--TAXES Taxes charged to income before extraordinary item and cumulative effect of change in accounting principle were:

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: 108

The acquisition of Tosco in September 2001 (see Note 3--Acquisition of Tosco Corporation) significantly increased deferred tax liabilities and assets. 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 offsets to the tax consequences of future taxable operating income. The alternative minimum tax credit can be carried forward indefinitely to reduce the company's regular tax liability. 109

Deferred taxes have not been provided on temporary differences related to investments in certain foreign subsidiaries and foreign corporate joint ventures that are essentially permanent in duration. At December 31, 2001 and 2000, these temporary differences were $247 million and $270 million, respectively. Determination of the amount of unrecognized deferred taxes on these temporary differences is not practicable due to foreign tax credits and exclusions. The amounts of U.S. and foreign income before income taxes, extraordinary item and cumulative effect of change in accounting principle, with a reconciliation of tax at the federal statutory rate with the provision for income taxes, were:

110

NOTE 19--CASH FLOW INFORMATION

*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 into DEFS and on July 1, 2000, ConocoPhillips and ChevronTexaco combined the two companies' worldwide chemicals businesses, excluding ChevronTexaco's Oronite business, into CPChem. See Note 6--Investments and Long-Term Receivables. 111

NOTE 20--SALES OF RECEIVABLES At December 31, 2001, ConocoPhillips had sold certain credit card and trade receivables under revolving sales agreements with four unrelated bank-sponsored entities. These agreements provide for ConocoPhillips to sell up to $1.2 billion of senior, undivided interests in pools of the credit card or trade receivables to the bank-sponsored entities. The sold receivables have been legally isolated from ConocoPhillips and qualify as sales under generally accepted accounting principles. Three of the bank-sponsored entities are multi-seller conduits, with access to commercial paper markets, which purchase interests in similar receivables from numerous other companies unrelated to ConocoPhillips. A fourth entity is a consolidated subsidiary of an unrelated bank, which engages in other financing and banking activities with companies unrelated to ConocoPhillips. ConocoPhillips has no ownership in any of the four 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. ConocoPhillips also retained interests in the pools of receivables, which are subordinate to the interests sold to the bank-sponsored entities. The subordinate interests are measured and recorded at fair value based on the present value of future expected cash flows, which are estimated using Management's best estimates of 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 for the sold receivables. The fair value of the servicing responsibility approximates adequate compensation for the servicing costs incurred. At December 31, 2001 and 2000, ConocoPhillips' retained interests were $450 million and $224 million, respectively, reported on the balance sheet in accounts and notes receivable. 112

Total cash flows received from and paid to the bank-sponsored entities in 2001 and 2000 were as follows:

NOTE 21--OTHER FINANCIAL INFORMATION

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NOTE 22--RELATED PARTY TRANSACTIONS Significant transactions with related parties were:

(a) ConocoPhillips' E&P segment sells natural gas to DEFS for processing and marketing. The company sells natural gas liquids, solvents and petrochemical feedstocks to CPChem and charges CPChem for the use of common facilities, such as steam generators, waste and water treaters, and warehouse facilities at its refining operations. (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. (c) ConocoPhillips pays processing fees to various affiliates. (d) ConocoPhillips charges both DEFS and CPChem for corporate services provided to the two equity companies under transition service agreements. ConocoPhillips pays fees to its pipeline equity companies for transporting finished products. ConocoPhillips pays processing and common facility fees to its affiliates. (e) Prior to July 1, 2000, ConocoPhillips earned interest on loans to certain affiliates, primarily Sweeny Olefins Limited Partnership. (f) ConocoPhillips paid interest to Merey Sweeny, L.P. for a loan related to improvements at the Sweeny refinery. Elimination of the company's equity percentage share of profit or loss on the above transactions was not material. 114

NOTE 23--SEGMENT DISCLOSURES AND RELATED INFORMATION With the merger of Conoco and Phillips, ConocoPhillips' operating segments were realigned. The following changes were made: o The natural gas liquids fractionation and marketing business was transferred from the Refining and Marketing segment to the Midstream segment. o The fuels technology business was transferred from the Refining and Marketing segment to the newly created Emerging Businesses segment. o Businesses classified as discontinued operations are included in Corporate and Other. Amounts reported for 2001, 2000 and 1999 have been reclassified to reflect these changes. ConocoPhillips has organized its reporting structure based on the grouping of similar products and services, resulting in five operating segments: (1) Exploration and Production (E&P)--This segment explores for and produces crude oil, natural gas and natural gas liquids on a worldwide basis. At December 31, 2001, E&P was producing in the United States; the Norwegian and U.K. sectors of the North Sea; Canada; Nigeria; Venezuela; the Timor Sea; and offshore Australia and China. (2) Midstream (formerly Gas Gathering, Processing and Marketing)--This segment gathers and processes natural gas produced by ConocoPhillips and others, and fractionates and markets natural gas liquids. Since March 31, 2000, ConocoPhillips' Midstream segment has included its 30.3 percent equity investment in DEFS. (3) Refining and Marketing (R&M)--This segment refines, markets and transports crude oil and petroleum products, primarily in the United States. The company has nine U.S. refineries (excluding one refinery treated as discontinued operations and reported in Corporate and Other) and one in Ireland. ConocoPhillips markets petroleum products nationwide. On September 14, 2001, ConocoPhillips acquired Tosco Corporation. This acquisition significantly increased the R&M segment's assets and operations. 115

(4) Chemicals--This segment manufactures and markets petrochemicals and plastics on a worldwide basis. Since July 1, 2000, ConocoPhillips' Chemicals segment has consisted primarily of its 50 percent equity investment in CPChem. (5) Emerging Businesses--This segment includes the development of new fuels technologies. Corporate and Other includes general corporate overhead; all interest revenue and expense, including preferred dividend requirements of capital trusts; certain eliminations; discontinued operations; and various other corporate activities, such as a captive insurance subsidiary and tax items not directly attributable to the operating segments. Corporate identifiable assets include all cash and cash equivalents, the company's owned office buildings and research and development facilities in Bartlesville, Oklahoma, and discontinued operations. Reporting reclassifications represent adjustments to assets to include debit balances in liability accounts and exclude credit balances in asset accounts, which is done for consolidated reporting but not at the operating segment level. 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. 116

ANALYSIS OF RESULTS BY OPERATING SEGMENT

117

GEOGRAPHIC INFORMATION

*In 2000 and 1999, Norway crude oil production was sold internally to the United Kingdom operations, which then sold it externally to third parties. **Revenues are attributable to countries based on the location of the operations generating the revenues. ***Defined as net properties, plants and equipment (including discontinued operations) plus investments in and advances to affiliates. Export sales totaled $262 million, $367 million and $356 million in 2001, 2000 and 1999, respectively. 118

NOTE 24--NEW ACCOUNTING STANDARDS In June 2001, the FASB issued Statement No. 143, "Accounting for Asset Retirement Obligations." Statement No. 143 is required to be adopted by the company no later than January 1, 2003, and will require major changes in the accounting for asset retirement obligations, such as required decommissioning of oil and gas production platforms, facilities and pipelines. Statement 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 a 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 Statement No. 143, the company will adjust its recorded asset retirement obligations to the new requirements using a cumulative-effect approach. All transition amounts are to be measured using the company's current information, assumptions, and credit-adjusted, risk-free interest rates. The company is studying the impact of Statement No. 143 to quantify the potentially significant impact of the new standard. In August 2001, the FASB issued Statement No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which supersedes Statement No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," and the accounting and reporting provisions for the disposal of a segment of a business from APB Opinion No. 30, "Reporting the Results of Operations--Reporting the Effect of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions." Statement No. 144 retains the basic recognition and measurement requirements of Statement No. 121 but addresses certain issues that had surfaced implementing Statement No. 121. In addition, Statement No. 144 revised the rules governing non-monetary exchanges of proved oil and gas properties to require recognition of any loss implied in the exchange. Previously, the book value of the relinquished property was carried over to the acquired property. This change is required on a prospective basis so no restatement of exchanges made prior to January 1, 2002, when ConocoPhillips adopted Statement No. 144, is required. 119

NOTE 25--MERGER WITH CONOCO INC. On November 18, 2001, Phillips and Conoco announced that their Boards of Directors had unanimously approved a merger of equals, and that the companies had signed a definitive merger agreement to form a new company to be named ConocoPhillips. At special shareholder meetings held on March 12, 2002, the stockholders of both companies approved the merger. On August 30, 2002, after receiving clearance from the U.S. Federal Trade Commission (FTC), Conoco and Phillips combined their businesses by merging with separate acquisition subsidiaries of ConocoPhillips. As a result, each company became a wholly owned subsidiary of ConocoPhillips. For accounting purposes, Phillips was treated as the acquirer and ConocoPhillips was treated as the successor of Phillips. Under the terms of the agreement, Phillips shareholders received one share of the new ConocoPhillips common stock for each share of Phillips common stock that they owned and Conoco shareholders received 0.4677 shares of the new ConocoPhillips common stock for each share of Conoco that they own. When the merger was consummated, former Phillips stockholders held approximately 58 percent of the outstanding shares of ConocoPhillips common stock, while former Conoco shareholders held approximately 42 percent. As a condition to the merger of Conoco and Phillips, the FTC required that ConocoPhillips 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; 120

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. Of the Phillips assets listed above, only the Woods Cross business unit qualified as a "component of an entity" as defined in FASB Statement No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." Accordingly, the assets and liabilities of the Woods Cross business unit, along with its earnings and cash flows, are reflected in the financial statements as discontinued operations. Results from discontinued operations for the years ended December 31, 2001, 2000 and 1999, included $388 million, $425 million, and $306 million of sales and other operating revenues, respectively. The company expects to finalize the sale of the Woods Cross business unit during 2003. 121

- -------------------------------------------------------------------------------- OIL AND GAS OPERATIONS (Unaudited) Exploration and Production In accordance with FASB Statement 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.), Africa (mainly Nigeria) and Other Areas. Other Areas include Canada, China, Denmark, Australia, the Timor Sea, and other countries. When the company uses equity accounting for operations that have proved reserves, the oil and gas operations are shown separately and designated as Equity Affiliate. 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) Alaskan businesses in late-April 2000.

122

o PROVED RESERVES WORLDWIDE

*Includes proved reserves of 17 million barrels attributable to a consolidated subsidiary in which there is a 13 percent minority interest. 123

o Purchases in Other Areas in 2001 were related to the acquisition of a majority interest in Petroz N.L., which resulted in the addition of reserves in the Bayu-Undan field in the Timor Sea. 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. 124

*Includes proved reserves of 10 billion cubic feet attributable to a consolidated subsidiary in which there is a 13 percent minority interest. 125

o Natural gas production may differ from gas production (delivered for sale) on page 132, 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 Other Areas in 2001 were related to the acquisition of a majority interest in Petroz N.L., which resulted in the addition of reserves in the Bayu-Undan field in the Timor Sea. o Extensions and discoveries in Other Areas in 2001 were in Australia. o Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit. 126

*Includes proved reserves of 10 million barrels attributable to a consolidated subsidiary in which there is a 13 percent minority interest. 127

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 Other Areas in 2001 were related to the acquisition of a majority interest in Petroz N.L., which resulted in the addition of reserves in the Bayu-Undan field in the Timor Sea. 128

o RESULTS OF OPERATIONS

*Includes a $5 million decommissioning accrual adjustment in Norway. 129

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, coal operations, and crude oil and gas marketing activities, which are included in Other earnings. Also excluded are non-E&P activities, including natural gas liquids extraction facilities in ConocoPhillips' gas gathering, processing and marketing joint venture, as well as downstream petroleum and chemical activities. In addition, there is no deduction for general corporate administrative expenses or 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 Depreciation, depletion and amortization (DD&A) in Results of Operations differs from that shown for total E&P in Note 23--Segment Disclosures and Related Information in the Notes to 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. 130

o Transportation costs include costs to transport oil, natural gas or natural gas liquids to their points of sale. Transportation operations in which the company has an ownership interest are deemed to be outside the oil and gas producing activity. Therefore, the profit element related to the cost of transporting hydrocarbons using operations, in which the company has an ownership interest, has not been eliminated. The net income of the transportation operations is included in Other earnings. o Other related expenses include transportation costs in Alaska for purchased liquids that were transported to their point of sale, 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, coal operations, and crude oil and gas marketing activities. 131

o STATISTICS

*Represents amounts extracted attributable to E&P operations (see natural gas liquids reserves on page 128 for further discussion). Includes for 2001 and 2000, 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.

*Represents quantities available for sale. Excludes gas equivalent of natural gas liquids shown above. 132

133

* Includes conventional and coalbed methane wells. Excludes farmout arrangements. ** ConocoPhillips' total proportionate interest was less than one. 134

WELLS AT YEAR-END 2001

* Includes wells that have been temporarily suspended. ** Includes 1,322 gross and 524 net multiple completion wells. *** ConocoPhillips' total proportionate interest was less than one.

* Includes two Somalia concessions where operations have been suspended by declarations of force majeure totaling 21,865 gross and 8,135 net acres. 135

o COSTS INCURRED

o Costs incurred include capitalized and expensed items. o Acquisition costs include the costs of acquiring proved and unproved oil and gas properties. It included proved properties of $13 million, $87 million and $89 million in the Lower 48 for 2001, 2000 and 1999, respectively. The 2001 amount in Other Areas included $63 million for proved properties in the Timor Sea. The 2000 amount in Alaska included $5,125 million for proved properties. The 2000 amount in Other Areas included $33 million for proved properties in Canada. The 1999 amount in Other Areas included $191 million for proved properties in the Timor Sea. 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. 136

o CAPITALIZED COSTS

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, coal 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. 137

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 becomes 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. 138

DISCOUNTED FUTURE NET CASH FLOWS

*Includes $17 million attributable to a consolidated subsidiary in which there is a 13 percent minority interest. 139

SOURCES OF CHANGE IN DISCOUNTED FUTURE NET CASH FLOWS

* 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. 140

SELECTED QUARTERLY FINANCIAL DATA

* Includes excise taxes on petroleum products sales, beginning third quarter 2001. Prior periods have been restated to conform. ** Restated to reflect a change in the company's method of accounting for the costs of major maintenance turnarounds from the accrue-in-advance method to the expense-as-incurred method. In the above table, amounts for net income include certain special items, as shown in the following table:

All periods restated for discontinued operations (see Note 25 in the financial statements notes) 141

CONOCOPHILLIPS (FORMERLY PHILLIPS PETROLEUM COMPANY) (CONSOLIDATED) SCHEDULE II--VALUATION ACCOUNTS AND RESERVES

*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. 142