10-Q 1 h98663e10vq.txt CONOCO INC.- PERIOD ENDED JUNE 30, 2002 SECOND QUARTER 2002 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2002 [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 COMMISSION FILE NUMBER 1-14521 CONOCO INC. (Exact name of registrant as specified in its charter) ~~DELAWARE 51-0370352 (State or other jurisdiction of incorporation (I.R.S. Employer Identification No.) or organization)~~

600 NORTH DAIRY ASHFORD ROAD HOUSTON, TEXAS 77079 (Address of principal executive offices and zip code) (281) 293-1000 (Registrant's telephone number, including area code) ---------- Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] 627,079,286 shares of common stock, $.01 par value, were outstanding as of August 2, 2002. ================================================================================ CONOCO INC. TABLE OF CONTENTS

i PART I FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS CONOCO INC. CONSOLIDATED STATEMENT OF INCOME (NOTE 1) (UNAUDITED)

See accompanying notes to consolidated financial statements. 1 CONOCO INC. CONSOLIDATED BALANCE SHEET (NOTE 1) (UNAUDITED)

See accompanying notes to consolidated financial statements. 2 CONOCO INC. CONSOLIDATED STATEMENT OF CASH FLOWS (NOTE 1) (UNAUDITED)

See accompanying notes to consolidated financial statements. 3 CONOCO INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (DOLLARS IN MILLIONS, EXCEPT PER SHARE) 1. BASIS OF PRESENTATION AND ACCOUNTING POLICY These consolidated interim financial statements are unaudited, but reflect all adjustments that, in the opinion of management, are necessary to provide a fair presentation of the financial position, results of operations and cash flows for the dates and periods covered. All such adjustments are of a normal recurring nature. Interim period results are not necessarily indicative of results of operations or cash flows for a full-year period. These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in Conoco's 2001 Annual Report on Form 10-K. 2. RECENTLY ISSUED STATEMENT OF FINANCIAL ACCOUNTING STANDARDS In April 2002, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections," which among other changes and technical corrections, rescinded SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt." As a result of the rescission of SFAS No. 4, Conoco will, beginning January 1, 2003, include gains and losses from the extinguishment of debt in "Income before extraordinary items" rather than report such amounts separately as extraordinary items. 3. CUMULATIVE EFFECT OF ACCOUNTING CHANGES Effective January 1, 2002, we changed our method of accounting for the cost of planned major maintenance expenditures from the accrue-in-advance method to the expense-as-incurred method, a preferable method of accounting. The new method results in the recognition of refinery and plant turnaround or tanker, barge and boat dry dock maintenance costs in the period that the obligation occurs. The cumulative effect of this change in accounting principle is an increase in net income in the first six months of 2002 of $42 (net of income taxes of $20), or $.07 per basic share and $.06 per diluted share. The effect of adopting this accounting principle on income before extraordinary item and accounting changes and on net income is an increase of $2, or $.01 per basic and diluted share, for the second quarter of 2002 and an increase of $11 (net of income taxes of $5), or $.02 per basic and diluted share, for the first six months of 2002. The pro forma effects of the retroactive application of the change in accounting principle related to planned major maintenance are as follows:

Additionally, effective January 1, 2002, we adopted FASB Derivative Implementation Group (DIG) Interpretations A18 and A19 of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities," (SFAS 133) as they relate to the fair value at January 1, 2002 of certain long-term international gas contracts. The cumulative effect of this change in accounting principle is a transition loss of $19 (net of income taxes of $9), or $.03 per basic and diluted share. Prior to the issuance of the interpretations, these contracts were excluded from mark-to-market accounting under SFAS 133. Other income for the second quarter and the first six months of 2002 included a $12 pretax loss ($7 after-tax) and a $28 pretax gain ($18 after-tax), respectively, from changes in the fair 4 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (UNAUDITED) (DOLLARS IN MILLIONS, EXCEPT PER SHARE) value of these same contracts from the January 1 adoption date of Interpretations A18 and A19 through June 30, 2002. 4. DERIVATIVE INSTRUMENTS For the first six months of 2002, other income included a $170 unrealized pretax loss ($107 after-tax) and sales and other operating revenues included a $36 realized pretax gain ($23 after-tax) related to changes in the fair value of crude oil and natural gas collars and swaps from January 1, 2002 through June 30, 2002 initiated with the 2001 Gulf Canada acquisition (see footnote 5). The fair value of these derivative instruments was $160 pretax ($101 after-tax) at June 30, 2002. Hedge accounting was not applied to the derivatives where the change in fair value was reported in other income. In addition, other income for the first six months of 2002 included a $28 pretax gain ($18 after-tax) from changes in the fair value of the long-term international gas contracts mentioned in footnote 3 above. For derivative instruments where hedge accounting was applied, the ineffective portions of these hedges were immaterial. In accordance with the transition provisions of SFAS 133, we recorded the following after-tax cumulative adjustments into earnings on January 1, 2001. The total amount is shown on the consolidated statement of income as cumulative effect of accounting change for 2001. Previously designated fair value hedging relationships:(1) Fair value of hedging instruments ............................................... $ 27 Offsetting changes in fair value of hedged items ................................ (25) Hedging instruments not designated for hedge accounting under SFAS 133(2) .......... 36 Contracts previously not designated as derivative instruments prior to SFAS 133 .... (1) ------ Total cumulative effect of adoption on earnings, after-tax ......................... $ 37 ======

---------- (1) These fair value hedging relationships reflect conversions of certain commodity contracts from fixed prices to market prices, in accordance with Conoco's Risk Management Policy. During the first six months of 2001, the ineffective portions of these hedges were immaterial. (2) Primarily reflects a pretax gain of $64 ($40 after-tax) related to changes in the fair value of certain crude oil put options from their purchase date to the January 1, 2001 adoption date of SFAS 133. Included in income before extraordinary item and accounting changes on the consolidated statement of income is an $83 pretax expense ($52 after-tax) related to changes in the fair value of these same crude oil put options from January 1, 2001 to June 30, 2001. 5. GULF CANADA ACQUISITION On July 16, 2001, Conoco, through a wholly owned subsidiary, completed the acquisition of all the ordinary shares of Gulf Canada Resources Limited (Gulf Canada), now known as Conoco Canada Resources Limited (Conoco Canada), for approximately $4,571 in cash plus assumed liabilities and minority interests. In this document, for ease of reference, we will refer to Conoco Canada as Gulf Canada. Prior to the acquisition, Gulf Canada was a Canadian-based independent exploration and production company, with primary operations in western Canada, Indonesia, the Netherlands and Ecuador. Subsequent to the acquisition, operational responsibilities for Gulf Canada's interests in Indonesia, the Netherlands and Ecuador were realigned within Conoco's regional organizations and Conoco's existing Canadian operations were merged with those of Gulf Canada. The following table presents the unaudited pro forma results of Conoco giving effect to the Gulf Canada acquisition as if the acquisition had occurred on January 1, 2001. For these unaudited pro forma results, the historical information of Gulf Canada has been converted to U.S. GAAP and converted to U.S. dollars using the average exchange rates for the periods involved. The unaudited results do not purport to represent what the results of operations would actually have been if the acquisition had in fact occurred on such dates or to project the results of operations of Conoco for any future date or period. 5 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (UNAUDITED) (DOLLARS IN MILLIONS, EXCEPT PER SHARE)

6. SUMMARIZED FINANCIAL INFORMATION FOR PETROZUATA Summarized below is the consolidated financial information for Petrozuata C.A. on a 100 percent basis. We use the equity method to account for our noncontrolling 50.1 percent equity interest in Petrozuata.

Conoco's equity in Petrozuata's earnings was $41 for the three months ended June 30, 2002 and $55 for the six months ended June 30, 2002, which included a $19 impairment for the three months ended June 30, 2002 and a $34 impairment for the six months ended June 30, 2002 from the devaluation of the bolivar. Conoco's equity in Petrozuata's earnings was $16 for the three months ended June 30, 2001 and $7 for the six months ended June 30, 2001. Conoco received dividends of $25 from Petrozuata in the second quarter and first six months of 2002. We did not receive any dividends from Petrozuata in 2001. 7. EARNINGS PER SHARE Basic earnings per share (EPS) is computed by dividing net income (the numerator) by the weighted-average number of common shares outstanding plus the effects of certain vested Conoco employee and director awards and fee deferrals that are invested in Conoco stock units (the denominator). Diluted EPS is similarly computed using the treasury stock method, except the denominator is increased to include the dilutive effect of outstanding stock options and unvested shares of restricted stock awarded under Conoco's compensation plans. Fixed options and restricted stock grants that are contingent upon continued service to the company are included in the diluted earnings per share calculation and are excluded in the basic earnings per share calculation. Issuance of these shares is contingent only upon a continued specified service period of the grantees, and there are no other contingency provisions in these fixed options and restricted stock grants. For the three months and six months ended June 30, 2002 and June 30, 2001, basic EPS reflected the weighted-average number of shares of common stock and deferred award units outstanding. Corresponding diluted EPS for the second quarter of 2002 and the first six months of 2002 included the dilutive effect of an additional 8,766,514 and 8,947,780 shares, respectively, while the second quarter of 2001 and first six months of 2001 included the dilutive effect of an additional 10,797,008 and 10,474,296 shares, respectively. 6 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (UNAUDITED) (DOLLARS IN MILLIONS, EXCEPT PER SHARE) The denominator is based on the following weighted-average number of common shares outstanding:

Variable stock options for 1,331,300 shares of common stock became vested and exercisable on March 12, 2002 as a result of stockholder approval of Conoco's previously announced merger with Phillips Petroleum Company (Phillips) at the stockholders meeting held on that date. These options have been reclassified as fixed and are included in the computation of diluted EPS for the three months and six months ended June 30, 2002. Variable stock options for 1,331,300 shares of common stock were outstanding for the three months and six months ended June 30, 2001. These options were not included in the computation of diluted EPS because the threshold price required for these options to be vested had not been reached. For the three months and six months ended June 30, 2002, fixed stock options for 15,288,339 shares of common stock were not included in the diluted earnings per share calculation. For the three months and six months ended June 30, 2001, fixed stock options for 33,036 and 6,675,749 shares of common stock were not included in the diluted earnings per share calculation. The fixed options were not included in that calculation because the exercise price was greater than the average market price. Common shares held as treasury stock are deducted in determining the number of shares outstanding. 8. DIVIDENDS Dividends per share paid through June 30 are as follows:

On July 23, 2002, Conoco declared a third quarter cash dividend of $.19 per share on each outstanding share of common stock, payable on September 10, 2002 to shareholders of record on August 10, 2002. 9. SECURITIZATION OF RECEIVABLES In April 2002, Conoco began selling certain U.S. credit card and trade receivables under a revolving sales agreement to Conoco Enterprise Funding L.L.C., a consolidated wholly owned special purpose entity, which in turn sells undivided interests in the receivables on a limited recourse basis to an unaffiliated bank-sponsored entity. This revolving sales agreement provides for the sale of up to $400 of senior, undivided interests in pools of the credit card or trade receivables. Conoco Enterprise Funding L.L.C. retains an undivided interest in the conveyed pool of receivables, which is subordinated to the interests sold to the unaffiliated bank-sponsored entity. Conoco also retains the servicing responsibility for the sold receivables. At June 30, 2002, Conoco Enterprise Funding L.L.C.'s retained interest in the conveyed pool of receivables was $315 and was reported on the consolidated balance sheet in accounts and notes receivable. 7 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (UNAUDITED) (DOLLARS IN MILLIONS, EXCEPT PER SHARE) Total cash flows related to the program were as follows:

10. INVENTORIES

11. COMMITMENTS AND CONTINGENT LIABILITIES Conoco has various purchase commitments for materials, supplies, services and items of permanent investment incident to the ordinary conduct of business. Such commitments are not at prices in excess of current market. Additionally, we have obligations under international contracts to purchase natural gas over periods up to 18 years. Due to weakening market prices since year-end, these long-term purchase obligations are at prices in excess of June 30, 2002 quoted market prices. No material annual gain or loss is expected from these long-term commitments. We are subject to various lawsuits and claims including but not limited to: actions challenging oil and gas royalty and severance tax payments; actions related to gas measurement and valuation methods; actions related to joint interest billings to operating agreement partners; claims for damages resulting from leaking underground storage tanks; and related toxic tort claims. As a result of the separation agreement with DuPont, we also have assumed responsibility for current and future claims related to certain discontinued chemicals and agricultural chemicals businesses operated by Conoco in the past. In general, the effect on future financial results is not subject to reasonable estimation because considerable uncertainty exists. The ultimate liabilities resulting from such lawsuits and claims may be material to results of operations and cash flows in the period in which they are recognized. An accrual of $112 was recorded during the fourth quarter of 2001 for a litigation settlement related to certain discontinued chemicals businesses for which we assumed responsibility for claims as a result of the separation agreement with DuPont. As of the end of July 2002, we paid $109 of the accrual, with the remainder to be paid during August 2002. Additionally, to date we have recovered insurance proceeds of $28 related to this claim. Over the next seven years, we will spend an estimated $95 to $110 for capital improvements at our U.S. refineries to install control technology and equipment to reduce emissions from stacks, vents, valves, heaters, boilers and flares. We also are subject to contingencies pursuant to environmental laws and regulations that in the future may require further action to correct the effects on the environment of prior disposal practices or releases of petroleum substances by us or other parties. We have accrued for certain environmental remediation activities consistent with the policy set forth in note 2 to the consolidated financial statements presented in our 2001 Annual Report on Form 8 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (UNAUDITED) (DOLLARS IN MILLIONS, EXCEPT PER SHARE) 10-K. These accrued liabilities exclude claims against our insurers or other third parties and are not discounted. We assumed environmental remediation liabilities from DuPont related to certain discontinued chemicals and agricultural chemicals businesses operated by us in the past and in the third quarter of 2001, we assumed environmental remediation liabilities with the purchase of Gulf Canada. The liabilities are included in our environmental accrual. At June 30, 2002, our environmental accrual was $181. In management's opinion, this accrual was appropriate based on existing facts and circumstances. Under adverse changes in circumstances, potential liability may exceed amounts accrued. In the event future monitoring and remediation expenditures are in excess of amounts accrued, they may be significant to results of operations and cash flows in the period recognized. However, management does not anticipate they will have a material adverse effect on the consolidated financial position of Conoco. At June 30, 2002, Conoco or DuPont, on behalf of and indemnified by Conoco, had directly guaranteed $358 of borrowings and other obligations of certain affiliated companies and others. The balance at June 30, 2002 no longer includes the $719 associated with Petrozuata that was outstanding at year-end 2001. In March 2002, Conoco was notified that DuPont was released from its guarantee of the debt associated with Petrozuata, and that debt became non-recourse to both Conoco and DuPont. In addition, at June 30, 2002, Conoco owned 7,510 million shares of Turcas Petrol A.S., of which 3,964 million shares were pledged to a group of Turkish banks that issued letters of credit in support of a $29 borrowing. Conoco had no indirect guarantees as of June 30, 2002. 12. MINORITY INTERESTS In April 2002, Gulf Canada completed the redemption of its Series 1 and Series 2 preferred stock. The redemption resulted in a reduction of minority interest of $364. In June 2002, Gulf Canada commenced a tender offer to acquire the remaining 28 percent interest in Gulf Indonesia Resources Limited (Gulf Indonesia) owned by minority shareholders at a price of $13.25 per share, or $329 in the aggregate. As of July 30, 2002, Gulf Canada had acquired 97.1 percent of those shares in the initial offer, which expired on July 19, 2002 and in the subsequent offering period, which expired on July 30, 2002. As a result, Gulf Canada owned a total of 99 percent of the outstanding shares of Gulf Indonesia. Gulf Canada acquired the remaining shares through a compulsory acquisition in July 2002. 13. COMPREHENSIVE INCOME The following sets forth Conoco's comprehensive income for the periods shown:

The local currency is the functional currency for our integrated European and Canadian petroleum operations because it is the currency of the primary economic environment in which those entities operate. For subsidiaries whose functional currency is the local currency, assets and liabilities denominated in local currency are translated into U.S. dollars at the end-of-period exchange rates. The resulting translation adjustment is a component of accumulated other comprehensive loss. Due to the weakening of the dollar in relation to other currencies at June 30, 9 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (UNAUDITED) (DOLLARS IN MILLIONS, EXCEPT PER SHARE) 2002, the U.S. reported amounts of our foreign currency based property, plant and equipment and goodwill increased with an offset to foreign currency translation adjustment in other comprehensive income. During the second quarter and first six months of 2002, Conoco recorded an after-tax loss of $20 ($29 pretax) and $96 ($153 pretax) into other comprehensive income from derivatives. The loss in the second quarter of 2002 includes an after-tax $3 gain in current activity and a $3 after-tax loss reclassification into income related to derivative instruments designated as cash flow hedges of certain forecasted sales of crude oil and natural gas and a net after-tax loss of $20 due to changes in the fair values of derivative instruments designated as cash flow hedges of variable interest rate obligations. The loss for the first six months of 2002 includes an after-tax loss of $85 ($62 after-tax loss in current activity and a $23 after-tax loss reclassification into income) related to derivative instruments designated as cash flow hedges of certain forecasted sales of crude oil and natural gas and a net after-tax loss of $11 due to changes in the fair values of derivative instruments designated as cash flow hedges of variable interest rate obligations. During the 12-month period ended June 30, 2003, a cumulative $6 after-tax gain associated with the forecasted sales of crude oil and natural gas, as well as a portion of the cumulative $16 net after-tax loss related to variable interest rate obligations, is expected to be reclassified into income. During the second quarter and first six months of 2001, Conoco recorded an after-tax gain of $22 ($35 pretax) and $20 ($32 pretax) into other comprehensive income from derivatives. The gain in the second quarter of 2001 includes an after-tax gain of $21 related to derivative instruments designated as cash flow hedges of certain forecasted sales of crude oil and natural gas and a net after-tax gain of $1 due to changes in the fair values of derivative instruments designated as cash flow hedges of variable interest rate obligations. The gain for the first six months of 2001 includes an after-tax gain of $21 related to derivative instruments designated as cash flow hedges of certain forecasted sales of crude oil and natural gas and a net after-tax loss of $1 due to changes in the fair values of derivative instruments designated as cash flow hedges of variable interest rate obligations. The net after-tax loss of $1 for the six months ended 2001 included an after-tax gain of $1, recorded at the date of adoption of SFAS 133, related to a derivative instrument designated as a cash flow hedge of a variable interest rate obligation, an after-tax charge of $2 due to changes in the fair value of this derivative instrument, and an immaterial amount that was reclassified into net income as a result of the settlement of a small portion of the obligation. 14. STOCK COMPENSATION We apply the intrinsic value method of accounting for stock options as prescribed by Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations. Pro forma information regarding changes in net income and earnings per share data (as if the accounting prescribed by SFAS No. 123, "Accounting for Stock-Based Compensation," had been applied) is presented below.

15. OPERATING SEGMENT AND GEOGRAPHIC INFORMATION We have three operating segments that comprise the structure used by senior management to make key operating decisions and assess performance. These are the upstream, downstream and emerging businesses segments. Upstream operating segment activities include exploring for, developing, producing and selling crude oil, natural gas and natural gas liquids; and Syncrude mining operations. Activities of the downstream operating segment include refining crude oil and other feedstocks into petroleum products; buying and selling crude oil and refined products; and transporting, distributing and marketing petroleum products. Emerging businesses operating segment activities include the development of new businesses beyond our traditional operations. Emerging 10 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (UNAUDITED) (DOLLARS IN MILLIONS, EXCEPT PER SHARE) businesses currently is involved in carbon fibers (Conoco Cevolution(R)); natural gas refining, including gas-to-liquids; and international power. Conoco has five reporting segments. Four reporting segments reflect the geographic division between the U.S. and international operations of its upstream and downstream businesses. One reporting segment is for emerging businesses. Corporate includes general corporate expenses, financing costs and other non-operating items and captive insurance operations. We sell our products worldwide. Major products include crude oil, natural gas, Canadian Syncrude and refined products that are sold primarily in the energy and transportation markets. Our sales are not materially dependent on any single customer or small group of customers. Transfers between segments are on the basis of estimated market values.

11 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (UNAUDITED) (DOLLARS IN MILLIONS, EXCEPT PER SHARE)

12 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (UNAUDITED) (DOLLARS IN MILLIONS, EXCEPT PER SHARE)

Special items totaling a charge of $11 for the second quarter of 2002 included a $15 charge for expenses related to our planned merger with Phillips and a $2 extraordinary item charge related to premiums incurred on the early repayment of Gulf Canada debt, partially offset by a $6 gain related to a revised insurance recovery estimate in connection with the U.K. Humber refinery explosion and fire in April 2001. In addition to the special items set forth in the previous paragraph, special items of $49 for the first quarter of 2002 included gains of $60 consisting of $19 from the sale of U.S. Permian Basin producing properties, $23 to cumulative effect of accounting changes and insurance proceeds of $18 associated with a discontinued business, partially offset by a $10 charge for expenses related to our planned merger with Phillips and a $1 extraordinary item charge related to premiums incurred on the early repayment of Gulf Canada debt. The $23 cumulative effect of accounting changes was attributable to the two changes in accounting method discussed in footnote 3. The first, a $42 cumulative effect of accounting change, recorded on January 1, 2002, resulted from a change in our method of accounting for the cost of planned major maintenance expenditures from the accrue-in-advance method to the expense-as-incurred method. It included $40 related to downstream for the reversal of planned major maintenance expenses of $22 for U.S. refineries and marine operations and $18 for our international refineries, and $2 attributable to upstream international operations. The second was a $19 transition loss resulting from a cumulative effect of accounting change recorded with our adoption of FASB DIG Interpretations of SFAS 133 as they relate to the January 1, 2002 fair value of certain long-term international gas contracts. Included in net income for international upstream was a $7 loss for the second quarter of 2002 and an $18 gain for the first six months of 2002 related to changes in the fair value of the long-term international gas contracts mentioned in the paragraph above. Special items for the second quarter 2001 included a charge of $54 to record repairs and other costs associated with the U.K. Humber refinery explosion and fire in April 2001. In addition to the special item set forth in the previous paragraph, special items for the first quarter of 2001 included a cumulative transition gain of $37 recorded on January 1, 2001 upon initial adoption of SFAS 133. This cumulative transition gain included a $40 gain in upstream related to changes in the fair value of certain crude oil put options from their purchase date to the January 1, 2001 adoption of SFAS 133 and a $3 charge in U.S. downstream associated with various derivatives. The $40 upstream gain consisted of $8 that was U.S. related and $32 that was related to international operations. Also included in net income for upstream was a $9 expense for the second quarter of 2001 and a $52 expense for the first six months of 2001 related to changes in the fair value of these same crude oil put options. The $9 expense for the second quarter of 2001 consisted of $1 for U.S. operations and $8 for international operations, while the $52 for the first six months of 2001 consisted of $10 for U.S. operations and $42 for international operations. (2) Upstream includes $3,078 at June 30, 2002 and $2,927 at December 31, 2001 of goodwill arising from the third quarter 2001 acquisition of Gulf Canada. The difference reflects foreign currency translation adjustments. In accordance with the requirements of SFAS No. 142, "Goodwill and Other Intangible Assets," which was adopted on January 1, 2002, a test for impairment of this goodwill must be completed annually. As part of this test, $2,053 of the goodwill has been allocated to the international upstream reporting unit and $1,025 has been allocated to the U.S. upstream reporting unit. The first step of this impairment test, which is a comparison of the fair values and net book values of these reporting units, was completed and indicated that goodwill was not impaired. (3) The carrying value of assets held for sale, primarily upstream property, plant and equipment, totaled $220 at June 30, 2002, and $42 at December 31, 2001. 13 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (UNAUDITED) (DOLLARS IN MILLIONS, EXCEPT PER SHARE) 16. CONOCOPHILLIPS MERGER On March 12, 2002, Conoco held a special meeting of stockholders for the purpose of adopting the Agreement and Plan of Merger, dated as of November 18, 2001, by and among Conoco, Phillips Petroleum Company, a Delaware corporation, ConocoPhillips, a Delaware corporation which we refer to as "New Parent," C Merger Corp., a Delaware corporation and a wholly owned subsidiary of New Parent, and P Merger Corp., a Delaware corporation and a wholly owned subsidiary of New Parent. Stockholders approved the proposal. In June 2002, in connection with a possible Federal Trade Commission (FTC) settlement, Conoco initiated the process to sell its Denver refinery. We have engaged investment bankers to assist with preparing for a potential sale and identifying potential buyers. We cannot provide any definitive timeline for the sale to be completed. We, along with Phillips, continue to work closely with the FTC as it reviews documentary materials. We expect the merger to close in the second half of 2002. 14 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (a) FINANCIAL CONDITION LIQUIDITY AND CAPITAL RESOURCES CASH PROVIDED BY OPERATIONS Cash provided by operations in the first six months of 2002 decreased $340 million to $1,283 million from $1,623 million in the first six months of 2001. Cash provided by operations before changes in operating assets and liabilities decreased $1,169 million compared to the first six months of 2001, primarily due to lower natural gas and crude oil prices, as well as weaker downstream margins. Positive changes to net operating assets and liabilities of $829 million were primarily due to the securitization of certain accounts receivable and increased payables partially offset by an increase in other accounts receivable. INVESTING ACTIVITIES CAPITAL EXPENDITURES AND INVESTMENTS

Total capital expenditures and investments were $1,448 million for the first six months of 2002, an increase of $477 million, or 49 percent, versus capital expenditures and investments of $971 million for the first six months of 2001. The increase was primarily due to higher spending on international upstream acquisitions. Capital expenditures and investments include capitalized exploratory wells but do not include expensed exploration costs. A more detailed description and analysis of capital expenditures and investments by operating segment within the U.S. and international follows below. Upstream Upstream capital expenditures and investments totaled $1,188 million for the first six months of 2002 compared to $700 million for the first six months of 2001. The increase of $488 million, or approximately 70 percent, was primarily the result of acquiring additional interests in Norway and higher spending associated with properties obtained through our acquisition of Gulf Canada Resources Limited (Gulf Canada), now known as Conoco Canada Resources Limited (Conoco Canada). In this document, for ease of reference, we will refer to Conoco Canada as Gulf Canada. 15 United States During the first six months of 2002, Conoco spent $255 million on U.S. capital projects, a decrease of $32 million, or 11 percent, from $287 million in the first six months of 2001. The decrease in expenditures in 2002 versus 2001 was mostly due to decreased drilling activity. International International upstream capital expenditures and investments totaled $933 million in the first six months of 2002, an increase of $520 million, or 126 percent, from $413 million in the first six months of 2001. The increase was primarily the result of acquiring additional interests in Norway and higher spending associated with properties obtained through our Gulf Canada acquisition. Downstream Downstream capital expenditures and investments totaled $131 million in the first six months of 2002, a decrease of $39 million, or 23 percent, versus $170 million in the first six months of 2001, primarily reflecting reduced expenditures in international refining and marketing operations. United States During the first six months of 2002, Conoco spent $63 million on downstream U.S. capital projects, down $4 million, or 6 percent, from $67 million in the first six months of 2001. In the first six months of 2002, a major portion of capital expenditures and investments were for ongoing refining operations and environmental upgrades to our Ponca City refinery. Capital expenditures and investments in the first six months of 2001 were principally related to several small investments in our pipeline and refining operations. International Conoco spent $68 million on downstream international capital projects during the first six months of 2002, down $35 million, or 34 percent, from $103 million in the first six months of 2001. In the first six months of 2002 and 2001, a major portion of capital expenditures and investments were for ongoing refining and marketing operations. Emerging Businesses Emerging businesses capital expenditures and investments totaled $126 million in the first six months of 2002, an increase of $36 million, or 40 percent, compared to $90 million in the first six months of 2001. The increased expenditures during the first six months of 2002 were primarily related to construction costs for the Immingham Combined Heat and Power Cogeneration plant located in the U.K. near our Humber refinery. Capital expenditures do not include construction costs associated with our natural gas refining pilot plant in Ponca City, Oklahoma as these costs were expensed as research and development costs. Corporate Corporate capital expenditures and investments totaled $3 million in the first six months of 2002, a decrease of $8 million, or 73 percent, compared to $11 million in the first six months of 2001. The decreased expenditures during the first six months of 2002 were largely the result of reduced spending on computer infrastructure. PROCEEDS FROM SALES OF ASSETS AND SUBSIDIARIES Proceeds from asset sales amounted to $107 million for the first six months of 2002, an increase of $9 million, or 9 percent, from $98 million in the first six months of 2001. Proceeds in the first six months of 2002 were primarily the result of the sale of Permian Basin producing properties in west Texas and the sale of our interest in the Suilven discovery in the U.K. Proceeds in the first six months of 2001 were primarily the result of the sale of our interest in Arkhangelskgeoldobycha, a Russian exploration and mining company, the sale of retail units and natural gas facilities in the United States and exiting our downstream operation in Spain. 16 FINANCING ACTIVITIES Conoco's ability to maintain and grow its operating income and cash flow is dependent upon continued capital spending to replace depleting assets. Conoco believes its future cash flow from operations and its borrowing capacity should be sufficient to fund its payments of dividends, if any, capital expenditures and working capital requirements and to service debt. At June 30, 2002, Conoco had an unsecured $2,500 million revolving credit facility with a syndicate of U.S. and international banks. The terms consist of a 364-day committed facility in the amount of $1,850 million and a multi-year committed facility in the amount of $650 million, which expires in May 2004. Conoco had no outstanding borrowings under the credit facility at June 30, 2002. On May 2, 2002, Conoco reduced availability under the 364-day facility from $2,350 million to $1,850 million and renewed it for another 364 days. Conoco maintains a $2,500 million U.S. commercial paper program and a euro 1,000 million European commercial paper program that are fully supported by the credit facility. Conoco has the ability to issue commercial paper at any time with maturities not to exceed 270 days. At June 30, 2002, we had $1,198 million of commercial paper outstanding, with a weighted-average interest rate of 2.02 percent. A total of $161 million of the outstanding commercial paper was denominated in foreign currencies but hedged to the dollar. Total Conoco debt was $10,022 million at June 30, 2002, up $630 million versus $9,392 million at December 31, 2001. The total debt-to-capitalization ratio was 55.6 percent at June 30, 2002 and 54.6 percent at December 31, 2001. During the first six months of 2002, Gulf Canada redeemed the remaining $5 million of its 7.125 percent notes due 2011, repurchased a total of $7 million of its 8.25 percent notes due 2017 and redeemed $67 million of 6.45 percent medium-term notes due 2007. The early repayment of this debt resulted in an extraordinary loss of $5 million ($3 million after-tax) for the first six months of 2002. In addition, Gulf Canada completed the redemption of its Series 1 and Series 2 preferred stock. The redemption resulted in a reduction of minority interest of $364 million. On June 25, 2002, the Oklahoma Development Finance Authority issued a $20 million 35-year industrial development bond on behalf of Conoco. The proceeds from the tax-exempt bond offering are being used to fund several capital improvement projects at the Ponca City refinery. In June 2002, Gulf Canada commenced a tender offer to acquire the remaining 28 percent interest in Gulf Indonesia Resources Limited (Gulf Indonesia) owned by minority shareholders at a price of $13.25 per share, or $329 million in the aggregate. As of July 30, 2002, Gulf Canada had acquired 97.1 percent of those shares in the initial offer, which expired on July 19, 2002 and in the subsequent offering period, which expired on July 30, 2002. As a result, Gulf Canada owned a total of 99 percent of the outstanding shares of Gulf Indonesia. Gulf Canada acquired the remaining shares through a compulsory acquisition in July 2002. 17 (b) RESULTS OF OPERATIONS CONSOLIDATED RESULTS

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

18 Special items totaling a charge of $11 million for the second quarter of 2002 included a $15 million charge for expenses related to our planned merger with Phillips and a $2 million extraordinary item charge related to premiums incurred on the early repayment of Gulf Canada debt, partially offset by a $6 million gain related to a revised insurance recovery estimate in connection with the U.K. Humber refinery explosion and fire in April 2001. In addition to the special items set forth in the previous paragraph, special items of $49 million for the first quarter of 2002 included gains of $60 million consisting of $19 million from the sale of U.S. Permian Basin producing properties, $23 million to cumulative effect of accounting changes and insurance proceeds of $18 million associated with a discontinued business, partially offset by a $10 million charge for expenses related to our planned merger with Phillips and a $1 million extraordinary item charge related to premiums incurred on the early repayment of Gulf Canada debt. The $23 million cumulative effect of accounting changes was attributable to two changes in accounting method. The first, a $42 million cumulative effect of accounting change, recorded on January 1, 2002, resulted from a change in our method of accounting for the cost of planned major maintenance expenditures from the accrue-in-advance method to the expense-as-incurred method. It included $40 million related to downstream for the reversal of planned major maintenance expenses of $22 million for U.S. refineries and marine operations and $18 million for our international refineries, and $2 million attributable to upstream international operations. The second was a $19 million transition loss resulting from a cumulative effect of accounting change recorded with our adoption of Financial Accounting Standards Board (FASB) Derivative Implementation Group (DIG) Interpretations of Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities," (SFAS 133) as they relate to the January 1, 2002 fair value of certain long-term international gas contracts. Included in net income for international upstream was a $7 million loss for the second quarter of 2002 and an $18 million gain for the first six months of 2002 related to changes in the fair value of the long-term international gas contracts mentioned in the paragraph above. Special items for the second quarter 2001 included a charge of $54 million to record repairs and other costs associated with the U.K. Humber refinery explosion and fire in April 2001. In addition to the special item set forth in the previous paragraph, special items for the first quarter of 2001 included a cumulative transition gain of $37 million recorded on January 1, 2001 upon initial adoption of SFAS 133. This cumulative transition gain included a $40 million gain in upstream related to changes in the fair value of certain crude oil put options from their purchase date to the January 1, 2001 adoption of SFAS 133 and a $3 million charge in U.S. downstream associated with various derivatives. The $40 million upstream gain consisted of $8 million that was U.S. related and $32 million that was related to international operations. Also included in net income for upstream was a $9 million expense for the second quarter of 2001 and a $52 million expense for the first six months of 2001 related to changes in the fair value of these same crude oil put options. The $9 million expense for the second quarter of 2001 consisted of $1 million for U.S. operations and $8 million for international operations, while the $52 million for the first six months of 2001 consisted of $10 million for U.S. operations and $42 million for international operations. SECOND QUARTER 2002 VERSUS SECOND QUARTER 2001 Net income was $130 million in the second quarter of 2002, down 76 percent from $552 million in the second quarter of 2001. Net income before special items was $141 million in the second quarter of 2002, down 77 percent from $606 million in the second quarter of 2001. These decreases predominantly reflected lower natural gas prices, lower refining margins and non-cash charges resulting from adverse currency movements. Partly offsetting these decreases were increased crude oil sales and natural gas volumes resulting from our 2001 Gulf Canada acquisition. Sales and other operating revenues for the second quarter of 2002 were $9,558 million, down 8 percent from $10,377 million in the second quarter of 2001, primarily due to lower crude oil, natural gas and refined product prices. Crude oil and refined product buy/sell and natural gas resale activities in the second quarter of 2002 totaled $2,352 million, down 14 percent compared to $2,743 million in the second quarter of 2001, primarily due to lower natural gas prices and decreased refined product sales volumes. Income from equity affiliates for the second quarter of 2002 was $80 million, up $21 million, or 36 percent, compared to $59 million in the second quarter of 2001. Additional crude oil volumes and higher syncrude oil prices 19 in the second quarter of 2002 from our Petrozuata joint venture drove this improvement, partly offset by the devaluation of the bolivar. Other income for the second quarter of 2002 was $22 million, down $92 million from other income of $114 million in the second quarter of 2001. Unrealized losses of $8 million from the crude oil and natural gas hedges initiated with the Gulf Canada acquisition, as compared to unrealized gains of $38 million in the second quarter of 2001, were the primary reason for this decrease. Also contributing to the decrease was a reduction in income from the Deir Ez Zor Gas project in Syria as we completed a construction contract in 2001. Cost of goods sold for the second quarter of 2002 totaled $5,739 million, a decrease of $605 million, or 10 percent, compared to $6,344 million in the first quarter of 2001, primarily due to the decrease in natural gas prices and lower refinery feedstock costs. Operating expenses for the second quarter of 2002 were $783 million, up 12 percent, or $83 million, compared to $700 million for the first quarter of 2001. This increase was primarily due to our Gulf Canada acquisition. Exploration expenses for the second quarter of 2002 totaled $106 million, an increase of $50 million, or 89 percent, compared to $56 million from the first quarter of 2001, reflecting higher exploration expenses due to our Gulf Canada acquisition. Depreciation, depletion and amortization (DD&A) for the second quarter of 2002 totaled $466 million, an increase of $128 million, or 38 percent, compared to $338 million in the first quarter of 2001. The increase was principally due to changes in rates and field mix and the volumes associated with the Gulf Canada acquisition. Income tax expense for the second quarter of 2002 totaled $166 million, down 70 percent, compared to $549 million for the second quarter of 2001, as a result of lower pretax income. The effective tax rate, approximately 56 percent in the second quarter of 2002 compared to 50 percent in the first quarter of 2001, was higher primarily due to a significantly higher portion of pretax income being generated in countries with higher effective tax rates. FIRST SIX MONTHS 2002 VERSUS FIRST SIX MONTHS 2001 Conoco had net income of $234 million in the first six months of 2002, down $971 million, or 81 percent, from $1,205 million in the first six months of 2001. Net income before special items was $196 million in the first six months of 2002, down 84 percent from $1,222 million in the first six months of 2001. These decreases predominantly reflected lower natural gas and crude oil prices, weaker downstream margins, a non-cash charge for the mark-to-market portion of crude oil and natural gas hedges associated with the Gulf Canada acquisition and non-cash charges resulting from adverse currency movements. Partly offsetting these decreases were increased crude oil sales and natural gas volumes resulting from our 2001 Gulf Canada acquisition. Sales and other operating revenues for the first six months of 2002 were $17,556 million, down 16 percent from $21,002 million in the first six months of 2001, primarily due to lower crude oil, natural gas and refined product prices. Crude oil and refined product buy/sell and natural gas resale activities in the first six months of 2002 totaled $3,919 million, down 30 percent compared to $5,575 million in the first six months of 2001, primarily due to lower crude oil, natural gas and refined product prices and decreased refined product sales volumes. Income from equity affiliates for the first six months of 2002 was $116 million, up $36 million, or 45 percent, compared to $80 million in the first six months of 2001. Additional crude oil volumes, higher syncrude oil prices and lower costs in the first six months of 2002 from our Petrozuata joint venture drove this improvement, partly offset by the devaluation of the bolivar. Other income for the first six months of 2002 was $7 million, down $138 million from other income of $145 million in the first six months of 2001. Unrealized losses of $170 million from the crude oil and natural gas hedges initiated with the Gulf Canada acquisition, as compared to unrealized gains of $38 million in the first six months of 2001, were the primary reason for this decrease. Also contributing to the decrease was a reduction in income from the Deir Ez Zor Gas project in Syria as we completed a construction contract in 2001. Partially offsetting these losses was a gain in the first six months of 2002 related to changes in the fair value of long-term gas contracts from adopting FASB DIG Interpretations of SFAS 133. Other income for the first six months of 2001 also included unrealized losses related to the change during the six-month period in the market value of crude oil put options as a result of the implementation of SFAS 133. 20 Cost of goods sold for the first six months of 2002 totaled $10,207 million, a decrease of $2,756 million, or 21 percent, compared to $12,963 million in the first six months of 2001, primarily due to the decrease in natural gas prices and lower refinery feedstock costs. Operating expenses for the first six months of 2002 were $1,475 million, up 12 percent, or $161 million, compared to $1,314 million for the first six months of 2001. This increase was primarily due to our Gulf Canada acquisition. Exploration expenses for the first six months of 2002 totaled $176 million, an increase of $83 million, or 89 percent, compared to $93 million from the first six months of 2001, reflecting higher exploration expenses due to our Gulf Canada acquisition and higher dry hole costs. DD&A for the first six months of 2002 totaled $932 million, an increase of $241 million, or 35 percent, compared to $691 million in the first six months of 2001. The increase was principally due to changes in rates and field mix and the volumes associated with the Gulf Canada acquisition. Income tax expense for the first six months of 2002 totaled $301 million, down 72 percent, compared to $1,078 million for the first six months of 2001, as a result of lower pretax income. The effective tax rate, approximately 58 percent in the first six months of 2002 compared to 48 percent in the first six months of 2001, was higher primarily due to a significantly higher portion of pretax income being generated in countries with higher effective tax rates. UPSTREAM SEGMENT RESULTS

The following table sets forth for Conoco, including equity affiliates, average sales prices per barrel of crude oil and condensate sold and average sales prices per thousand cubic feet (mcf) of natural gas sold.

---------- (1) There were no hedging effects on realized prices in the first six months of 2001. The following table sets forth for Conoco the average sales price per barrel of Canadian Syncrude sold from the Canadian Syncrude project in Canada.

SECOND QUARTER 2002 VERSUS SECOND QUARTER 2001 Upstream earnings before special items were $273 million in the second quarter of 2002, down 45 percent from $493 million in the second quarter of 2001, driven by lower natural gas prices. Increased international production partly offset the fall in prices. U.S. upstream earnings before special items was $57 million in the second quarter of 2002, down $192 million from $249 million in the comparable period of 2001, reflecting much lower natural gas prices and decreased volumes due to dispositions. The second quarter 2001 results also benefited from higher natural gas transportation and storage margins and unrealized mark-to-market gains on commodity hedges. International upstream earnings before special items were $216 million, a decrease of 11 percent from $244 million in the comparable period in 2001. The decrease was principally attributable to lower natural gas prices, higher overhead and operating expenses, DD&A and exploration expenses, partly offset by increased crude oil and natural gas volumes. Conoco's worldwide net realized crude oil price, including equity affiliates, was $22.45 per barrel for the second quarter of 2002, down $1.37 per barrel, or 6 percent, from $23.82 per barrel in the second quarter of 2001. Worldwide net realized natural gas prices, including equity affiliates, averaged $2.83 per mcf for the second quarter of 2002, compared with $3.89 per mcf in the same period in 2001, a decrease of 27 percent. Worldwide petroleum liquids production, including our share of equity affiliates, but excluding Canadian Syncrude, in the second quarter of 2002 was 428,000 barrels per day versus 384,000 barrels per day in the second quarter of 2001, an 11 percent increase. U.S. petroleum liquids production was down 22 percent as a result of asset dispositions in 2001. International petroleum liquids production increased 19 percent to 372,000 barrels per day due to the Gulf Canada acquisition and increases in Venezuela. Canadian Syncrude production for the second quarter of 2002 was 20,000 barrels per day. Worldwide natural gas production, including our share of equity affiliates, in the second quarter of 2002 was up 36 percent to 2,326 million cubic feet (mmcf) per day from 1,716 mmcf per day in the second quarter of 2001. U.S. natural gas production was down 14 percent while international natural gas production was up 82 percent. The international increase was mainly due to our Gulf Canada acquisition and increases in Norway, while the U.S. decline was attributable to asset dispositions in 2001 and rig count reductions in the south Texas Lobo field. 22 Worldwide refined product sales for upstream in the second quarter of 2002 were 276,000 barrels per day, up 78 percent from the second quarter of 2001, primarily due to additional volumes available for sale. Additionally, during the second quarter 2002, Conoco sold 6.3 billion cubic feet (bcf) of natural gas per day in North America, including third party purchases of 3.2 bcf per day versus the second quarter sales in 2001 of 3.8 bcf per day, including third party purchases of 1.6 bcf per day. FIRST SIX MONTHS 2002 VERSUS FIRST SIX MONTHS 2001 Upstream earnings before special items were $428 million in the first six months of 2002, down 60 percent from $1,073 million in the first six months of 2001, driven by significantly weaker worldwide natural gas and crude oil prices, unrealized mark-to-market losses from open crude oil and natural gas hedges and higher costs, mainly reflecting the addition of Gulf Canada operations. Increased international production partly offset the fall in prices and higher costs. U.S. upstream earnings before special items was $22 million in the first six months of 2002, down $551 million from $573 million in the comparable period of 2001, reflecting lower crude oil and natural gas prices, the non-cash charge for the unrealized mark-to-market portion of open crude oil and natural gas hedges associated with the Gulf Canada acquisition, as well as lower crude oil and natural gas volumes. International upstream earnings before special items were $406 million, a decrease of 19 percent from $500 million in the comparable period in 2001. The decline was primarily attributable to lower crude oil and natural gas prices, higher overhead and operating expenses, DD&A and exploration expenses, partly offset by increased crude oil and natural gas volumes. Conoco's worldwide net realized crude oil price, including equity affiliates, was $20.57 per barrel for the first six months of 2002, down $2.94 per barrel, or 13 percent, from $23.51 per barrel in the first six months of 2001. Worldwide net realized natural gas prices, including equity affiliates, averaged $2.81 per mcf for the first six months of 2002, compared with $4.61 per mcf in the same period in 2001, a decrease of 39 percent. Worldwide petroleum liquids production, including our share of equity affiliates, but excluding Canadian Syncrude, in the first six months of 2002 was 434,000 barrels per day versus 382,000 barrels per day in the first six months of 2001, a 14 percent increase. U.S. petroleum liquids production was down 22 percent as a result of asset dispositions in 2001. International petroleum liquids production increased 22 percent to 377,000 barrels per day due to the Gulf Canada acquisition and increases in Norway and Venezuela, partly offset by declines in the U.K. Canadian Syncrude production for the first six months of 2002 was 21,000 barrels per day. Worldwide natural gas production, including our share of equity affiliates, in the first six months of 2002 was up 33 percent to 2,355 mmcf per day from 1,768 mmcf per day in the first six months of 2001. U.S. natural gas production was down 12 percent while international natural gas production was up 73 percent. The international increase was mainly due to our Gulf Canada acquisition and increases in Norway, while the U.S. decline was attributable to asset dispositions in 2001, rig count reductions in the south Texas Lobo field and natural field decline. Worldwide refined product sales for upstream in the first six months of 2002 were 262,000 barrels per day, up 49 percent from the first six months of 2001, primarily due to additional volumes available for sale. Additionally, during the first six months of 2002, Conoco sold 5.5 bcf of natural gas per day in North America, including third party purchases of 2.8 bcf per day versus the first six months sales in 2001 of 3.7 bcf per day, including third party purchases of 1.5 bcf per day. DOWNSTREAM SEGMENT RESULTS

SECOND QUARTER 2002 VERSUS SECOND QUARTER 2001 Downstream earnings before special items were $31 million for the second quarter of 2002, a decrease of $196 million, or 86 percent, from $227 million in the comparable period in 2001 due to significantly lower refining margins. U.S. downstream earnings before special items were a loss of $16 million for the second quarter of 2002, down $237 million from $221 million in the second quarter of 2001. The decrease was primarily attributable to very weak refining spreads, reduced discounts for heavy crude oil and lower marketing margins. International downstream earnings before special items were $47 million for the second quarter of 2002, up $41 million from $6 million in the comparable period in 2001, primarily reflecting higher refining volumes and improved marketing margins. In 2001, the Humber refinery did not operate for most of the second quarter. Worldwide refined product sales in the second quarter of 2002 were 1,274,000 barrels per day, down 3 percent from the second quarter of 2001, principally due to reduced demand in the U.S. FIRST SIX MONTHS 2002 VERSUS FIRST SIX MONTHS 2001 Downstream earnings before special items were $50 million for the first six months of 2002, a decrease of $301 million, or 86 percent, from $351 million in the comparable period in 2001 due to much lower refining margins in all regions, partially offset by improved co-product margins caused by lower crude oil prices. U.S. downstream earnings before special items were a loss of $7 million for the first six months of 2002, down $299 million from $292 million in the first six months of 2001. The decrease was predominantly attributable to very weak refining margins, lower marketing margins and reduced price discounts for heavy oil. International downstream earnings before special items were $57 million for the first six months of 2002, down $2 million, or 3 percent, from $59 million in the comparable period in 2001, primarily reflecting weak European and Asian refining and marketing margins, partly offset by increased refining volumes. Worldwide refined product sales in the first six months of 2002 were 1,225,000 barrels per day, down 5 percent from the first six months of 2001, primarily due to reduced demand in the U.S. EMERGING BUSINESSES SEGMENT RESULTS

SECOND QUARTER 2002 VERSUS SECOND QUARTER 2001 Emerging businesses operating losses were $30 million for the second quarter of 2002, an increase of $13 million compared to $17 million in the second quarter of 2001, principally due to construction expenses for the natural gas refining pilot plant in Ponca City, Oklahoma, scheduled for completion in the fourth quarter of 2002. FIRST SIX MONTHS 2002 VERSUS FIRST SIX MONTHS 2001 Emerging businesses operating losses were $57 million for the first six months of 2002, an increase of $23 million compared to $34 million in the first six months of 2001, principally due to construction expenses for the natural gas refining pilot plant in Ponca City, Oklahoma, scheduled for completion in the fourth quarter of 2002. 24 CORPORATE SEGMENT RESULTS

SECOND QUARTER 2002 VERSUS SECOND QUARTER 2001 Corporate operating losses before special items were $32 million for the second quarter of 2002, an increase of $1 million compared to $31 million in the second quarter of 2001, mainly due to higher minority interest costs. FIRST SIX MONTHS 2002 VERSUS FIRST SIX MONTHS 2001 Corporate operating losses before special items were $67 million for the second quarter of 2002, an increase of $12 million compared to $55 million in the second quarter of 2001, mainly due to higher minority interest costs as well as slightly higher technology, aviation and legal costs. INTEREST AND OTHER NON-OPERATING EXPENSES NET OF TAX

SECOND QUARTER 2002 VERSUS SECOND QUARTER 2001 Interest and other non-operating expenses before special items for the second quarter of 2002 amounted to $101 million, an increase of $35 million, or 53 percent, compared to $66 million in the comparable period in 2001. This increase is primarily attributable to the increased effect of adverse foreign currency movements and an increase in pre-tax interest expense resulting from additional debt incurred to acquire Gulf Canada, partially offset by higher interest income. FIRST SIX MONTHS 2002 VERSUS FIRST SIX MONTHS 2001 Interest and other non-operating expenses before special items for the first six months of 2002 amounted to $158 million, an increase of $45 million, or 40 percent, compared to $113 million in the comparable period in 2001. This increase is primarily attributable to the increased effect of adverse foreign currency movements and an increase in pre-tax interest expense resulting from additional debt incurred to acquire Gulf Canada partially offset by higher interest income. TAX MATTERS During July 2002, the U.K. government enacted changes to their tax laws applicable to income from the production of oil and gas, including a 10 percent supplementary charge to corporation taxes on North Sea profits. As a result of the changes in the law, we estimate a one-time deferred tax charge of approximately $125 million will be recorded during the third quarter. In addition we estimate an ongoing increase in U.K. taxes of $40 million to $50 million annually, dependent on the level of future North Sea income. 25 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK MARKET RISKS Changes in commodity price risk, foreign currency risk and interest rate risk for the period ended June 30, 2002, are summarized below. COMMODITY PRICE RISK The fair value gain or loss of outstanding derivative commodity instruments and the change in the fair value that would be expected from a 10 percent adverse price change are shown in the following table:

---------- (1) Includes derivative instruments that can be settled in cash or by physical delivery of the commodity. (2) Includes collars with a $24.04 floor price and a $26.54 cap price (West Texas Intermediate equivalent) on 54.5 million barrels for the period October 2001 through December 2002. Includes swaps at $25.30 on 18.3 million barrels for the period October 2001 through December 2002. (3) Includes collars with a $4.00 floor price and a $4.60 cap price (NYMEX equivalent) on approximately 120,000 mmbtu per day for the period October 2001 through December 2002. In August 2002, these contracts were settled at their fair value of $64 million. Includes swaps at $4.02 on approximately 100,000 mmbtu per day for the period October 2001 through December 2002. In late July 2002, all swaps were closed out with the exception of the period November through December 2002 at a fair value of $52 million. The fair values of the futures contracts are based on publicly quoted market prices obtained from the New York Mercantile Exchange (NYMEX) or the International Petroleum Exchange of London. The fair values of swaps and other over-the-counter instruments are estimated based on quoted market prices of comparable contracts and approximate the gain or loss that would have been realized if the contracts had been closed out at the end of the period. 26 Price-risk sensitivities were calculated by assuming an across-the-board 10 percent adverse change in prices regardless of term or historical relationships between the contractual price of the instrument and the underlying commodity price. In the event of an actual 10 percent change in prompt month crude oil or natural gas prices, the fair value of Conoco's derivative portfolio would typically change less than that shown in the table due to lower volatility in out-month prices. EXCHANGE AND NON-EXCHANGE TRADED CONTRACTS ACCOUNTED FOR AT FAIR VALUE

---------- (1) Reduction in the January 1, 2002 fair value of certain long-term international gas contracts resulting from the application of FASB DIG Interpretations of SFAS 133.

FOREIGN CURRENCY RISK At June 30, 2002, Conoco had $161 million in foreign currency swaps associated with our European commercial paper program. At December 31, 2001, the U.S. dollar equivalent of all non-U.S. dollar notes outstanding was $29 million, all of which were swapped to the U.S. dollar. At June 30, 2002, we had open foreign currency exchange derivative instruments with a notional value of $631 million related to future foreign currency purchases. At December 31, 2001, we had open foreign currency exchange derivative instruments with a notional value of $9 million related to forward currency sales. The fair value of outstanding foreign currency hedges and the change in the fair value that would be expected from a 10 percent adverse foreign currency rate change are shown in the following table: 27

Price-risk sensitivities were calculated by assuming an across-the-board 10 percent adverse change in foreign currency rates. INTEREST RATE RISK The fair value gain or loss of outstanding interest rate swaps and the change in fair value that would be expected from a 10 percent adverse interest rate change are shown in the following table:

28 PART II OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS There have been no material developments with respect to the legal proceedings previously reported in the 2001 Annual Report on Form 10-K and the first quarter 2002 report on Form 10-Q, except as described below. An accrual of $112 million was recorded during the fourth quarter of 2001 for a litigation settlement related to certain discontinued chemicals businesses for which we assumed responsibility for claims as a result of the separation agreement with DuPont. As of the end of July 2002, we paid $109 million of the accrual, with the remainder to be paid during August 2002. Additionally, to date we have recovered insurance proceeds of $28 million related to this claim. We are subject to various lawsuits and claims including but not limited to: actions challenging oil and gas royalty and severance tax payments; actions related to gas measurement and valuation methods; actions related to joint interest billings to operating agreement partners; claims for damages resulting from leaking underground storage tanks; and related toxic tort claims. As a result of the separation agreement with DuPont, we also have assumed responsibility for current and future claims related to certain discontinued chemicals and agricultural chemicals businesses operated by Conoco in the past. In general, the effect on future financial results is not subject to reasonable estimation because considerable uncertainty exists. The ultimate liabilities resulting from such lawsuits and claims may be material to results of operations and cash flows in the period in which they are recognized. Conoco reached agreement with the U.S. Department of Interior on the drilling moratorium on the Destin Dome properties offshore Florida. Under the terms of the agreement, Conoco will relinquish its interest in the properties in exchange for $46 million paid by the U.S. government. This will result in an estimated gain of approximately $11 million in the third quarter of 2002. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Conoco's annual meeting of stockholders was held on May 21, 2002 for the purpose of (1) electing three directors and (2) ratifying the appointment of PricewaterhouseCoopers LLP as Conoco's independent public accountants for 2002. 1. Election of Directors Stockholders elected Ruth R. Harkin, Frank A. McPherson and General Charles C. Krulak, each for a three-year term expiring at the 2005 Annual Meeting. The vote tabulation for each individual director was as follows:

Directors continuing in office were Archie W. Dunham, William K. Reilly, Franklin A. Thomas, Richard H. Auchinleck, Kenneth M. Duberstein, William R. Rhodes and A. R. "Tony" Sanchez, Jr. 2. Proposal ratifying the appointment of PricewaterhouseCoopers LLP as Conoco's independent public accountants for 2002. For................................................................. 529,879,275 Against............................................................. 19,849,771 Abstain............................................................. 429,892

29 ITEM 5. OTHER INFORMATION DISCLOSURE REGARDING FORWARD-LOOKING INFORMATION This quarterly report on Form 10-Q includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can identify our forward-looking statements by the words "expects," "anticipates," "intends," "plans," "projects," "believes," "estimates," "will," "should," and similar expressions. We have based the forward-looking statements relating to our operations on our current expectations and on estimates and projections about Conoco and the petroleum industry in general. We caution you that these statements are not guarantees of future performance and involve risks, uncertainties and assumptions that we cannot predict with certainty. In addition, we have based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, our actual outcomes and results may differ materially from what we have expressed or forecasted in the forward-looking statements. Any differences could result from a variety of factors including the following: o fluctuations in crude oil and natural gas prices and refining and marketing margins; o changes in our business, operations, results and prospects; o potential failure or delays in achieving expected reserve or production levels from existing and future oil and gas development projects due to operating hazards, drilling risks and the inherent uncertainties in predicting oil and gas reserves and oil and gas reservoir performance; o unsuccessful exploratory and development drilling activities; o failure of new products and services to achieve market acceptance; o unexpected cost increases or technical difficulties in constructing or modifying company manufacturing and refining facilities; o unexpected difficulties in mining, manufacturing, transporting or refining synthetic crude oil; o ability to meet government regulations; o potential disruption or interruption of our production facilities due to accidents, political events or terrorism; o international monetary conditions and exchange controls; o liability for remedial actions under environmental regulations; o liability resulting from litigation; o general domestic and international economic and political conditions, including armed hostilities and terrorism; or o changes in tax and other laws or regulations applicable to our business. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) EXHIBITS The exhibit index filed with this Form 10-Q is on page 32. (b) REPORTS ON FORM 8-K None. 30 SIGNATURE 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, thereunto duly authorized. CONOCO INC. (Registrant) By: /s/ W. DAVID WELCH ---------------------------------- Vice President, Controller and Principal Accounting Officer Date: August 9, 2002 31 EXHIBIT INDEX

* Filed herein. 32

CONOCO INC /DE 10-Q