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PART I. FINANCIAL INFORMATION
	Item 1. FINANCIAL STATEMENTS
		Consolidated Income Statement
		Consolidated Balance Sheet
		Consolidated Statement of Cash Flows
		Notes to Consolidated Financial Statements
		Supplementary Information—Condensed Consolidating Financial Information
	Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
	Item 4. CONTROLS AND PROCEDURES
PART II. OTHER INFORMATION
	Item 1. LEGAL PROCEEDINGS
	Item 6. EXHIBITS AND REPORTS ON FORM 8-K
SIGNATURE
INDEX TO EXHIBITS
Computation of Ratio of Earnings to Fixed Charges
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certifications Pursuant to Section 906

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CONOCOPHILLIPS

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PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

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  *  Restated for certain discontinued operations.
**  Net of acquisition and disposition of businesses.

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Note 1—Interim Financial Information

The financial information for the interim periods presented in the financial statements included in this report is unaudited and includes all known accruals and adjustments that, in the opinion of management, are necessary for a fair presentation of the consolidated financial position of ConocoPhillips and its results of operations and cash flows for such periods. All such adjustments are of a normal and recurring nature. These interim financial statements should be read in conjunction with Management’s Discussion and Analysis and the consolidated financial statements and notes included in ConocoPhillips’ 2002 Annual Report on Form 10-K. Certain amounts in the 2002 financial statements have been reclassified to reflect discontinued operations and to conform to ConocoPhillips’ 2003 presentation.

The financial statements reflect the August 30, 2002, merger of Conoco Inc. (Conoco) and Phillips Petroleum Company (Phillips). The transaction was accounted for using the purchase method of accounting as required by Statement of Financial Accounting Standards (SFAS) No. 141, “Business Combinations.” Phillips was designated as the acquirer. Results of operations for the third quarter of 2002 reflect two months of Phillips activity and one month of ConocoPhillips activity, while the first nine months of 2002 reflects eight months of Phillips activity and one month of ConocoPhillips activity.

Note 2—Changes in Accounting Principles

Accounting for Asset Retirement Obligations
Effective January 1, 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” which applies to legal obligations associated with the retirement and removal of long-lived assets. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period when it is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related property, plant and equipment. Over time, the liability is accreted upward for the change in its present value each period, and the initial capitalized cost is depreciated over the useful life of the related asset.

Application of this new accounting principle resulted in an initial increase in net properties, plants and equipment of $1.2 billion and an asset retirement obligation liability increase of $1.1 billion. The cumulative effect of the change increased first quarter 2003 net income by $145 million. The third quarter 2003 effect of the adoption increased income from continuing operations and net income by $8 million, $.01 per basic and diluted share. The effect of adoption on income from continuing operations and net income for the first nine months of 2003 was an increase of $24 million, or $.04 per basic and diluted share.

We have numerous asset removal obligations that we are required to perform under law or contract once an asset is permanently taken out of service. Most of these obligations are not expected to be paid until several years, or decades, in the future and will be funded from general company resources at the time of removal. Our largest individual obligations are related to fixed-base offshore production platforms around the world and to production facilities and pipelines in Alaska.

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SFAS No. 143 calls for measurements of asset retirement obligations to include, as a component of expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties and unforeseeable circumstances inherent in the obligations, sometimes referred to as a market-risk premium. To date, the oil and gas industry has no examples of credit-worthy third parties who are willing to assume this type of risk, for a determinable price, on major oil and gas production facilities and pipelines. Therefore, because determining such a market-risk premium would be an arbitrary process, we have excluded it from our SFAS No. 143 estimates.

During the first nine months of 2003, ConocoPhillips’ overall asset retirement obligation changed as follows:

The following table presents the pro forma effects of the retroactive application of this change in accounting principle. There was no pro forma effect on income from discontinued operations.

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Consolidation of Variable Interest Entities
In January 2003, the Financial Accounting Standards Board (FASB) issued Interpretation No. 46, “Consolidation of Variable Interest Entities,” (FIN 46) to expand existing accounting guidance about when a company should include in its consolidated financial statements the assets, liabilities and activities of another entity. In general, a variable interest entity (VIE) is a corporation, partnership, trust, or any other legal structure used for business purposes that either (a) does not have equity investors with voting rights or (b) has equity investors that do not provide sufficient financial resources for the entity to support its activities. FIN 46 requires a VIE to be consolidated by a company if that company is subject to a majority of the risk of loss from the VIE’s activities, is entitled to receive a majority of the VIE’s residual returns, or both (the company required to consolidate is called the primary beneficiary). It also requires deconsolidation of a VIE if a company is not the primary beneficiary of the VIE. The interpretation also requires disclosures about VIEs that a company does not consolidate, but in which it has a significant variable interest.

The consolidation requirements of FIN 46 applied immediately to VIEs created after January 31, 2003. In accordance with FASB Staff Position No. FIN 46-6, effective October 9, 2003, the consolidation requirements of FIN 46 for VIEs created before February 1, 2003, were deferred to the fourth quarter for calendar-year-end companies. However, early adoption of FIN 46 was permitted for some or all VIEs.

We adopted FIN 46 in the third quarter of 2003, with retroactive application to January 1, 2003, for VIEs involving synthetic leases and certain other financing structures as discussed below. We adopted FIN 46 for such VIEs because our work on these VIEs was complete and we believe the FASB’s potential modifications of FIN 46 interpretive guidance is unlikely to change the primary beneficiary determination for these VIEs. We consolidated all VIEs created prior to February 1, 2003 (except as noted below), in which we concluded we were the primary beneficiary. In addition, we deconsolidated an entity where we determined we were not the primary beneficiary.

The adoption of FIN 46 for VIEs involving synthetic leases and certain other financing structures resulted in the following:

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We consolidated certain VIEs from which we lease certain ocean vessels, airplanes, refining assets, marketing sites and office buildings. The consolidation increased net properties, plants and equipment by $940 million and increased assets of discontinued operations held for sale by $722 million (both are collateral for the debt obligations); increased cash by $225 million; increased debt by $2.4 billion; increased minority interest by $90 million; reduced other accruals by $263 million, and resulted in a cumulative after-tax effect-of-adoption loss that decreased net income and common stockholders’ equity by $258 million. The future minimum rental payments at December 31, 2002, related to our leasing arrangements that are now consolidated under FIN 46, were approximately $500 million, and their guaranteed residual values totaled approximately $1.8 billion. Since these leasing arrangements are now intercompany leases and eliminated in consolidation, they will no longer be included in our non-mineral lease disclosures. Other than certain performance obligations (i.e., make lease payments, provide insurance in some circumstances, etc.) and the residual value guarantees described above, the creditors of the entities above have no recourse to the general credit of ConocoPhillips. In addition, we discontinued hedge accounting for an interest rate swap since it had been designated as a cash flow hedge of the variable interest rate component of a lease with one of the entities now consolidated as a VIE. At September 30, 2003, the fair market value of the swap was $15 million.

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Ashford Energy Capital S.A. continues to be consolidated in our financial statements under the provisions of FIN 46 because we are the primary beneficiary. In December 2001, in order to raise funds for general corporate purposes, Conoco and Cold Spring Finance S.a.r.l. formed Ashford Energy Capital S.A. through the contribution of a $1 billion Conoco subsidiary promissory note and $500 million cash. Through its initial $500 million investment, Cold Spring is entitled to a cumulative annual preferred return, based on three-month LIBOR rates, plus 1.27 percent. In 2008, and each 10-year anniversary thereafter, Cold Spring may elect to remarket their investment in Ashford, and if unsuccessful, could require ConocoPhillips to provide a letter of credit in support of Cold Spring’s investment, or in the event that such letter of credit is not provided, then cause the redemption of their investment in Ashford. Should ConocoPhillips’ credit rating fall below investment grade, Ashford would require a letter of credit to support various term loans, totaling $600 million as of September 30, 2003, made by Ashford to other ConocoPhillips subsidiaries. If the letter of credit is not obtained within 60 days, Cold Spring could cause Ashford to sell the ConocoPhillips subsidiary notes. At September 30, 2003, Ashford held $1.6 billion of ConocoPhillips subsidiary notes. ConocoPhillips reports Cold Spring’s investment as a minority interest because it is not mandatorily redeemable and the entity does not have a specified liquidation date. Other than the obligation to make payment on the subsidiary notes described above, Cold Spring does not have recourse to the general credit of ConocoPhillips.

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Phillips 66 Capital II (Trust) was deconsolidated under the provisions of FIN 46 because ConocoPhillips is not the primary beneficiary. During 1997 in order to raise funds for general corporate purposes, we formed the Trust (a statutory business trust), in which we own all common beneficial interests. The Trust was created for the sole purpose of issuing mandatorily redeemable preferred securities to third-party investors and investing the proceeds thereof in an approximately equivalent amount of subordinated debt securities of ConocoPhillips, which were previously eliminated in consolidation. Application of FIN 46 required deconsolidation of the Trust, which increased debt by $361 million since the 8% Junior Subordinated Deferrable Interest Debentures due 2037 were no longer eliminated in consolidation, and the $350 million of mandatorily redeemable preferred securities were deconsolidated.

The third quarter 2003 effect of the adoption of FIN 46 for VIEs involving synthetic leases and certain other financing structures increased income from continuing operations $13 million, or $.02 per basic and diluted share, and increased net income $35 million, $.05 per basic and diluted share. The effect on income from continuing operations for the nine months of 2003 was an increase of $22 million, or $.03 per basic and diluted share, and the effect on net income for the same period was a decrease of $151 million, or $.22 per basic and diluted share.

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Restated income information for the first and second quarters and six months of 2003 as a result of the adoption of FIN 46 for VIEs involving synthetic leases and certain other financing structures follows:

The adoption of FIN 46 for VIEs involving synthetic leases and certain other financing structures reduced the balance of retained earnings at March 31, 2003, from $6,824 million, as previously reported, to $6,582 million; and reduced retained earnings at June 30, 2003, from $7,670 million, as previously reported, to $7,483 million.

We continue to monitor and assess the FASB’s ongoing modifications of FIN 46 interpretive guidance, which could have an impact on our determinations of VIEs and primary beneficiaries for our interests in joint ventures that hold non-financial assets that were created prior to February 1, 2003. The adoption of FIN 46 for our joint venture entities was deferred under the provisions of FASB Staff Position No. FIN 46-6. Our joint venture interests are in operating entities whose operations include petroleum exploration and production; petroleum refining, marketing, supply and transportation; and natural gas gathering, processing and marketing. As we continue to assess our joint venture entities, we may conclude

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that one or more of our joint venture entities is a VIE and that in some cases we are the primary beneficiary. For our joint venture entities that may be VIEs, we believe that our maximum exposure to loss would be equal to our investment in the entities, plus our potential obligations under our guarantees of their debt. At September 30, 2003, our total investment in these joint venture entities, plus the value of any debt guarantees for these entities was approximately $1 billion. These same entities had gross assets of approximately $4 billion at year-end 2002. We continue to assess FIN 46, but do not anticipate that it will have a material impact on our consolidated results of operations, cash flows or financial position.

The FASB continues to issue interpretive guidance on FIN 46 and has a goal of issuing final modified guidance in the fourth quarter of 2003. If subsequent FASB guidance is different from our current understanding, it is possible that our determination of VIEs and primary beneficiaries could be changed.

Other
Effective January 1, 2003, we adopted SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” The adoption of SFAS No. 145 requires that gains and losses on extinguishments of debt no longer be presented as extraordinary items in the income statement. Accordingly, a loss from the extinguishment of debt of $15 million (after reduction for income taxes of $6 million), previously reported as an extraordinary item in the nine months of 2002, has been reclassified as a $21 million charge to other income with the tax benefit reclassified to provision for income taxes.

In April 2003, the FASB released SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” which we adopted July 1, 2003. The adoption of this standard did not have a material impact on our results of operations or financial position.

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity,” to address the balance sheet classification of certain financial instruments that have characteristics of both liabilities and equity. This statement was immediately effective for all contracts created or modified after May 31, 2003, and became effective July 1, 2003, for all previously existing contracts. On November 7, 2003, the FASB issued FASB Staff Position No. FAS 150-3, which deferred certain provisions of SFAS No. 150. As a result of adopting this new accounting standard in the third quarter of 2003, and the subsequent November 7, 2003, deferral of certain provisions, there was no impact on our financial statements.

Note 3—Merger of Conoco and Phillips

On August 30, 2002, Conoco and Phillips combined their businesses by merging with separate acquisition subsidiaries of ConocoPhillips (the merger). As a result, each company became a wholly owned subsidiary of ConocoPhillips. For accounting purposes, Phillips was treated as the acquirer of Conoco, and ConocoPhillips was treated as the successor of Phillips. Conoco’s operating results have been included in ConocoPhillips’ consolidated financial statements since the merger date.

The $16 billion purchase price attributed to Conoco for accounting purposes was based on an exchange of Conoco common shares for ConocoPhillips common shares. The allocation of the purchase price to specific assets and liabilities was based, in part, upon an outside appraisal of the fair value of Conoco’s assets. The following table summarizes, based on the final purchase price allocation, the fair values of the assets acquired and liabilities assumed as of August 30, 2002:

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Goodwill, land and certain identifiable intangible assets recorded in the acquisition are not subject to amortization, but the goodwill and intangible assets will be tested periodically for impairment as required by SFAS No. 142, “Goodwill and Other Intangible Assets.”

ConocoPhillips has not yet determined the assignment of Conoco goodwill to specific reporting units, but plans to do so by the end of 2003. Currently, Conoco goodwill is being reported as part of the Corporate and Other reporting segment. Included in the $12,745 million of goodwill is $3,859 million attributable to recording a net liability required under purchase accounting for deferred taxes. This and the remaining goodwill of $8,886 million will ultimately be assigned to reporting units based on the benefits received by the units from the synergies and strategic advantages of the merger. None of the goodwill is deductible for tax purposes. During the first nine months of 2003, the balance of goodwill was adjusted upward by $666 million, primarily due to revisions in properties, plants and equipment, and assumed contingent liabilities.

Note 4—Discontinued Operations

During 2002 and the first nine months of 2003, we disposed of, or had committed to a plan to dispose of, certain U.S. retail and wholesale marketing assets, certain U.S. refining and related assets, certain U.S. midstream natural gas gathering and processing assets, and exploration and production assets in the

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Netherlands. Certain of these planned dispositions were mandated by the FTC as a condition of the merger. For reporting purposes, these operations are classified as discontinued operations, and in Note 17—Segment Disclosures and Related Information, these operations are included in Corporate and Other.

FTC-Mandated Divestitures
In the fourth quarter of 2002, we sold our propane terminal assets at Jefferson City, Missouri, and East St. Louis, Illinois.

In the second quarter of 2003 we sold:

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our Woods Cross business unit, which includes the Woods Cross, Utah, refinery; the Utah, Idaho, Montana, and Wyoming Phillips-branded motor fuel marketing operations (both retail and wholesale) and associated assets; and a refined products terminal in Spokane, Washington; and

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certain midstream natural gas gathering and processing assets in southeast New Mexico, and certain midstream natural gas gathering assets in West Texas.

In the third quarter of 2003, we sold our Commerce City, Colorado, refinery, and related crude oil pipelines, and our Colorado Phillips-branded motor fuel marketing operations (both retail and wholesale).

All asset dispositions mandated by the FTC as a condition of the merger have been completed.

Other Dispositions
In the fourth quarter of 2002, we committed to a plan to dispose of 3,200 marketing sites that did not fit into our long-range plans. In the third quarter of 2003, we concluded the sale of all of our Exxon-branded marketing assets in New York and New England, including contracts with independent dealers and marketers. Approximately 230 of the 3,200 sites were included in this package.

We signed an agreement in October 2003 to sell The Circle K Corporation and its subsidiaries. The transaction would include 1,663 retail marketing outlets in 16 states and the Circle K brand, as well as the assignment of the franchise relationship with more than 350 franchised and licensed stores. Closing of the transaction is subject to government and regulatory reviews as appropriate for a transaction of this type, and is expected in the fourth quarter of 2003. Discussions are under way with potential buyers on the remaining packages, and we expect to complete the sales of these assets in the first half of 2004.

Sales and other operating revenues and income (loss) from discontinued operations were as follows:

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The major classes of assets and liabilities of discontinued operations held for sale were as follows:

Note 5—Subsidiary Equity Transactions

ConocoPhillips, through various affiliates, and its unaffiliated co-venturers received final approvals from authorities in June 2003 to proceed with the natural gas development phase of the Bayu-Undan project in the Timor Sea. The natural gas development phase of the project will include a pipeline from the offshore Bayu-Undan field to Darwin, Australia, and a liquefied natural gas facility, also located in Darwin. The pipeline portion of the project is owned and operated by an unincorporated joint venture, while the liquefied natural gas facility is owned and operated by Darwin LNG Pty Ltd (DLNG). Both of these entities are consolidated subsidiaries of ConocoPhillips.

In June 2003, as part of a broad Bayu-Undan ownership interest re-alignment with co-venturers, these entities issued equity and sold interests to the co-venturers (as described below), which resulted in a gain of $28 million before-tax, $25 million after-tax, in the second quarter of 2003. This non-operating gain is shown in the consolidated statement of income in the line item entitled “Gain on subsidiary equity transactions.”

DLNG—DLNG issued 118.9 million shares of stock, valued at 1 Australian dollar per share, to co-venturers for 118.9 million Australian dollars ($76.2 million U.S. dollars), reducing our ownership interest in DLNG from 100 percent to 56.72 percent. The transaction resulted in a before-tax gain of $21 million in the consolidated financial statements. Deferred income taxes were not recognized because this was an issuance of common stock and therefore not taxable.

Unincorporated Pipeline Joint Venture—The co-venturers purchased pro-rata interests in the pipeline assets held by ConocoPhillips Pipeline Australia Pty Ltd for $26.6 million U.S. dollars and contributed the purchased assets to the unincorporated joint venture, reducing our ownership interest from 100 percent to 56.72 percent. The transaction resulted in a before-tax gain of $7 million. A deferred tax liability of $1.3 million was recorded in connection with the transaction.

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Note 6—Stock-Based Compensation

Effective January 1, 2003, ConocoPhillips adopted the fair-value accounting method of SFAS No. 123, “Accounting for Stock-Based Compensation.” Using the prospective transition method, we recognize compensation expense using the fair-value accounting method for all stock options granted or modified after December 31, 2002, whereas we continue to account for options granted prior to 2003 in accordance with Accounting Principles Board (APB) No. 25, “Accounting for Stock Issued to Employees,” and related Interpretations. The following table illustrates the effect on net income and earnings per share as if the fair-value-based method had been applied to all outstanding and unvested awards in each period.

The pro forma total stock-based employee compensation expense determined using the fair-value-based method was higher during the first nine months of 2002, compared with the same period in 2003, due to the accelerated vesting of options triggered by the March 2002 shareholder approval of the merger.

Note 7—Inventories

Inventories consisted of the following:

Inventories valued on a last-in, first-out (LIFO) basis totaled $3,421 million and $3,349 million at September 30, 2003, and December 31, 2002, respectively. The excess of current replacement cost over LIFO cost of inventories amounted to $948 million and $1,083 million at September 30, 2003, and December 31, 2002, respectively.

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Note 8—Properties, Plants and Equipment

Properties, plants and equipment included the following:

Property Impairments—In the third quarter of 2003, we recorded property impairments of $18 million before-tax, $10 million after-tax, all related to planned dispositions in our E&P segment. For the first nine months of 2003, we recorded property impairments totaling $192 million before-tax, $71 million after-tax. Of these year-to-date amounts, $187 million and $68 million, respectively, were related to our E&P segment. The remainder related to the Corporate and Other reporting segment. In addition to impairments resulting from planned dispositions, the nine-month period also had impairments resulting from producing properties that failed to meet the recoverability test under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” as well as international tax law changes affecting asset removal costs.

Note 9—Restructuring

In 2002, as a result of the merger, we began a restructuring program to capture the benefits of combining Conoco and Phillips by eliminating redundancies, consolidating assets, and sharing common services and functions across regions. As a result, we recognized an estimated restructuring liability for anticipated employee severance payments and incremental pension and medical plan benefit costs associated with work force reductions, site closings, and Conoco employee relocations. In the first nine months of 2003, as individual components of the restructuring program were finalized, we recorded an additional $316 million for severance-related benefits, site closings, Conoco employee relocation costs, and pension and other postretirement benefits. Of this total, $109 million was reflected as a purchase price adjustment in the consolidated financial statements and $207 million was reflected in selling, general and administrative expense and production and operating expense. Included in the total additional accruals of $316 million was a $92 million expense related to pension and other postretirement benefits that will be paid in conjunction with other retirement benefits over a number of future years. This is reported as part of our employee benefit plan obligations. A roll-forward of activity during the first nine months of 2003 is provided below for the non-pension portion of the accrual, which primarily consists of severance-related benefits to be provided to approximately 3,900 employees worldwide, most of whom are in the United States, as well as other merger related expenses.

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The restructuring liability at September 30 of $304 million is expected to be expended by the end of the first quarter of 2004; except for $59 million, classified as long-term. The remaining $245 million is included in other accruals in the current liabilities section of the balance sheet. Approximately 1,825 employees were terminated during the first nine months of 2003 and approximately 2,600 employees have been terminated since the restructuring program was implemented.

Note 10—Debt

At September 30, 2003, we had three bank credit facilities in place, totaling $4 billion, available for use either as direct bank borrowings or as support for the issuance of up to $4 billion in commercial paper, a portion of which may be denominated in other currencies (limited to euro 3 billion equivalent). The facilities included a $2 billion, 364-day revolving credit facility expiring on October 14, 2003, and two revolving credit facilities totaling $2 billion expiring in October 2006. At September 30, 2003, we had no debt outstanding under these credit facilities, but had $624 million in commercial paper outstanding, of which $50 million was denominated in foreign currencies. The commercial paper is supported 100 percent by the credit facilities and the amount approximates fair value. Effective October 14, 2003, we entered into two new revolving credit facilities, replacing the $2 billion 364-day facility that expired on that same date. The new revolving credit facilities are a $1.5 billion 364-day facility and a $500 million five-year facility. One of our Norwegian subsidiaries has two $300 million revolving credit facilities that expire in June 2004, under which no borrowings were outstanding at September 30, 2003.

In the third quarter of 2003, the adoption of FIN 46 “Consolidation of Variable Interest Entities,” for VIEs involving synthetic leases and certain other financing structures, was made and retroactively applied to January 1, 2003. The application of FIN 46 increased our balance sheet debt by approximately $2.8 billion. With the adoption of FIN 46:

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The Phillips 66 Capital Trust II (Trust) is no longer consolidated, which removed $350 million of mandatorily redeemable preferred securities from the consolidated balance sheet and added to long-term debt $361 million of 8% Junior Subordinated Deferrable Interest Debentures due 2037. Previously this debt was eliminated in consolidation; and

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VIEs involving synthetic leases and certain other financing structures in which we are the primary beneficiary were consolidated retroactively as of January 1, 2003, which increased consolidated debt approximately $2.4 billion. Of this $2.4 billion, approximately $1.4 billion was associated with approximately 1,000 retail store sites, the majority of which we have sold or plan to sell, and two office buildings that are also part of our divestiture plan.

The $2.4 billion in debt at January 1, 2003, was comprised of the following:

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$90 million Tosco Trust 2000-E 8.78% Senior Secured Notes due 2010;

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$245 million Tosco Trust 2000-E 8.58% Senior Secured Notes due 2010;

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$199 million Arctic Funding, Limited Partnership 6.85% Senior Secured Note due 2011;

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$100 million of floating rate aviation equipment lease obligations having a final maturity in 2004;

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$489 million of various fixed and floating rate ocean vessel lease obligations having final maturities from 2004 to 2005;

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$1,138 million of floating rate marketing lease obligations having final maturities from 2003 to 2006; and

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$160 million of floating rate refining equipment lease obligations having a final maturity in 2006.

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See Note 2—Changes in Accounting Principles, for additional information about FIN 46.

During the first nine months of 2003, in addition to reducing our commercial paper balance outstanding from $1.5 billion at December 31, 2002, to $624 million at September 30, 2003, we paid off the following notes and debt facilities as they were called or matured and funded the payments with cash from operating activities and proceeds from asset dispositions:

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$250 million 8.49% Notes due 2023, at 104.245 percent;

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$181 million SRW Cogeneration Limited Partnership note;

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$100 million 6.65% Notes that matured on March 1, 2003;

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$250 million 7.92% Notes due in 2023, at 103.96 percent;

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$500 million Floating Rate Notes due April 15, 2003;

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$150 million 8.25% Mortgage Bonds due May 15, 2003;

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$90 million Tosco Trust 2000-E 8.78% Senior Secured Notes due 2010;

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$245 million Tosco Trust 2000-E 8.58% Senior Secured Notes due 2010;

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$895 million of floating rate marketing lease obligations having maturities in 2003 and 2005; and

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$173 million of 7.6% ocean vessel lease obligations having a final maturity in 2004.

In October 2003, we paid the following debt facilities:

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$95 million of floating rate marketing lease obligations having a final maturity in 2004; and

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$98 million of floating rate aviation equipment lease obligations having a final maturity in 2004.

In November 2003, we called and paid our $250 million 7.20% Notes due 2023, at 103.60 percent, and gave notice on an additional $127 million of floating rate marketing lease obligations having final maturities in 2004 and 2006.

Also, in October and November 2003, we executed certain interest rate swaps that had the effect of converting $1.5 billion of debt from fixed to floating rate. These swaps qualify for hedge accounting under SFAS 133, “Accounting for Derivative Instruments and Hedging Activities.”

Note 11—Contingencies

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; and claims for damages resulting from leaking underground storage tanks, or other accidental releases, with related toxic tort claims. As a result of Conoco’s separation agreement with DuPont, we also have assumed responsibility for current and future claims related to certain discontinued chemicals and agricultural chemicals businesses operated by Conoco in the past. In general, the effect on future financial results is not subject to reasonable estimation because considerable uncertainty exists. The ultimate liabilities resulting from such lawsuits and claims may be material to results of operations in the period in which they are recognized.

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In the case of all known contingencies, we accrue a liability when the loss is probable and the amount is reasonably estimable. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. Based on currently available information, we believe 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 our financial statements.

As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates that are particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our 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—We are 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 we prepare our financial statements, we record accruals for environmental liabilities based on management’s best estimates, using all information that is available at the time. We measure estimates and base liabilities on currently available facts, existing technology, and presently enacted laws and regulations, taking into consideration the likely effects of societal and economic factors. When measuring environmental liabilities, we also consider our prior experience in remediation of contaminated sites, other companies’ cleanup experience, and data released by the U.S. Environmental Protection Agency (EPA) or other organizations. We consider unasserted claims in our determination of environmental liabilities and we accrue them in the period that they are both probable and reasonably estimable.

Although liability of those potentially responsible for environmental remediation costs is generally joint and several for federal sites and frequently so for state sites, we are usually only one of many companies cited at a particular site. Due to the joint and several liabilities, we could be responsible for all of the cleanup costs related to any site at which we have been designated as a potentially responsible party. If ConocoPhillips were solely responsible, the costs, in some cases, could be material to our, or one of our segments’, operations, capital resources or liquidity. However, settlements and costs incurred in matters that previously have been resolved have not been material to our results of operations or financial condition. We have been successful to date in sharing cleanup costs with other financially sound companies. Many of the sites at which we are 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 may attain a settlement of liability. Where it appears that other potentially responsible parties may be financially unable to bear their proportional share, we consider this inability in estimating our potential liability and we adjust our accruals accordingly.

As a result of various acquisitions in the past, we assumed certain environmental obligations. Some of these environmental obligations are mitigated by indemnifications made by others for our benefit and some of the indemnifications are subject to dollar limits and time limits. We have not recorded accruals for any potential contingent liabilities that we expect to be funded by the prior owners under these indemnifications.

We are currently participating in environmental assessments and cleanups at numerous federal Superfund and comparable state sites. After an assessment of environmental exposures for cleanup and other costs,

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we make accruals on an undiscounted basis (except those for environmental indemnifications or those assumed in a purchase business combination, which we record such costs on a discounted basis) for planned investigation and remediation activities for sites where it is probable that future costs will be incurred and these costs can be reasonably estimated. We expect to incur the majority of these expenditures within the next 30 years. We have not reduced these accruals for possible insurance recoveries. In the future, we may be involved in additional environmental assessments, cleanups and proceedings. At September 30, 2003, ConocoPhillips’ balance sheet included a total environmental accrual from continuing operations of $1,101 million, compared with $743 million at December 31, 2002. The increase in the accrual from year-end 2002, primarily resulted from evaluation of Conoco environmental liabilities during the purchase price allocation period. The accrued environmental liabilities assumed in the merger are discounted obligations. The expected expenditures of $318 million are discounted using a weighted average 5 percent discount factor, resulting in an additional accrued balance of $240 million. The expected expenditures for these additional accruals, adjusted for inflation, are: $49 million in 2003, $81 million in 2004, $40 million in 2005, $24 million in 2006, and $14 million in 2007. The remaining expenditures in all future years after 2007 for these additional accruals are expected to total $110 million.

Other Legal Proceedings—We are 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—We have contingent liabilities resulting from throughput agreements with pipeline and processing companies. Under these agreements, we 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. In addition, we have various purchase commitments for materials, supplies, services and items of permanent investment incident to the ordinary conduct of business.

Note 12—Guarantees

At September 30, 2003, we were liable for certain contingent obligations under various contractual arrangements as described below. We are required to recognize a liability at inception for the fair value of our obligation as a guarantor for guarantees issued or modified after December 31, 2002. Unless the carrying amount of the liability is noted, we have not recognized a liability either because the guarantees were issued prior to December 31, 2002, or because the fair value of the obligation is immaterial.

Construction Completion Guarantees

•

We have a construction completion guarantee related to debt and bond financing arrangements secured by the Merey Sweeny, L.P. (MSLP) joint-venture project at the Sweeny refinery in Old Ocean, Texas. The maximum potential amount of future payments under the guarantee, including joint-and-several debt at its gross amount, is estimated to be $407 million, assuming that completion certification is not achieved. Of this amount, $204 million is attributable to Petroleos de Venezuela S.A. (PDVSA), which has an indirect 50 percent interest in MSLP, and which is jointly-and-severally liable for the debt. If completion certification is not attained by June 2004, the full debt balance becomes due. The debt becomes non-recourse upon completion certification.

•

We also issued a construction completion guarantee related to debt financing arrangements for the Hamaca Holding LLC joint-venture project in Venezuela. The maximum potential amount of future payments under the guarantee is estimated to be $441 million, which could be payable if the full debt financing capacity is utilized and startup and completion of the Hamaca project is not achieved by October 1, 2005. The project financing debt will be non-recourse upon startup and completion certification.

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Guarantees of Joint-Venture Debt

•

At September 30, 2003, we had guarantees of about $348 million outstanding for our portion of joint-venture debt obligations, which have terms of up to 24 years. We have recognized an $11 million liability related to these guaranteed debt obligations. Payment will be required if a joint venture defaults on its debt obligations.

Other Guarantees

•

In addition to the construction completion guarantee explained above, the MSLP agreement also requires the partners in the venture to pay cash calls as required to meet the minimum operating requirements of the venture, in the event revenues do not cover expenses over the next 20 years. Our maximum potential future payments under the agreement are estimated to be $303 million, assuming MSLP does not earn any revenue over the entire period and fixed costs cannot be reduced. To the extent revenue is generated by the venture or fixed costs are reduced, future required payments would be reduced accordingly.

•

We have also guaranteed certain potential payments related to our interest in a drillship, which is operated by a joint venture. Potential payments could be required for the guaranteed residual value amount and the amount due under an interest rate hedging agreement. The maximum potential future payments under the agreements are estimated to be approximately $97 million.

•

In February 2003, we entered into two agreements establishing separate guarantee facilities for $50 million each for two LNG vessels. Under each such facility, we will be required to make payments should the charter revenue generated by the relevant ship fall below certain specified minimum thresholds, and we will receive payments to the extent that such revenues exceed those thresholds. The net maximum future payments over the 20-year terms of the agreements could be up to $100 million. In the event the two ships are sold or a total loss occurs, we also may have recourse to the sales or insurance proceeds to recoup payments made under the guarantee facilities. Based on the current market view of both long-term and short-term shipping capacity, rates, and utilization probability, we estimated the fair value of the liability to be immaterial.

•

We have other guarantees totaling $169 million, which consist primarily of dealer and jobber loan guarantees to support our marketing business, a guarantee supporting a lease assignment on a corporate aircraft, a guarantee associated with a pending lawsuit and guarantees of lease payment obligations for a joint venture. These guarantees generally extend up to 15 years and payment would only be required if the dealer, jobber or lessee goes into default.

Indemnifications

•

Over the years, we have entered into various agreements to sell ownership interests in certain corporations and joint ventures. In addition, we entered into a Tax Sharing Agreement in 1998 related to Conoco’s separation from DuPont. These agreements typically include indemnifications for additional taxes determined to be due under the relevant tax law, in connection with operations for years prior to the sale or separation. Generally, the obligation extends until the related tax years are closed. The maximum potential amount of future payments under the indemnifications is the amount of additional tax determined to be due under relevant tax law and the various agreements. There are no material outstanding claims that have been asserted under these agreements.

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•

During the first nine months of 2003, we sold several assets, such as FTC-mandated downstream and midstream assets, upstream non-producing leasehold, and downstream retail and wholesale sites, giving rise to qualifying indemnifications. We recognized an $8 million liability associated with these indemnifications. Arrangements associated with these sales include indemnifications for taxes, environmental liabilities, permits and licenses, employee claims and litigation. The maximum potential payout under these arrangements totals $330 million. Certain environmental indemnifications are not subject to this limitation. Payments for these environmental indemnifications would be equal to the remediation costs for assets sold. All probable and estimable environmental liabilities for known contamination associated with these assets have been accrued under SFAS No. 5, “Accounting For Contingencies.” Included in accrued dismantlement, removal and environmental costs at September 30, 2003, were environmental accruals totaling $23 million associated with assets sold during the first nine months of 2003. For additional information about environmental liabilities, see Note 11—Contingencies.

•

As part of our normal ongoing business operations and consistent with generally accepted and recognized industry practice, we enter into numerous agreements with other parties, which apportion future risks among the parties to the transaction or relationship governed by the agreements. One method of apportioning risk is the inclusion of provisions requiring one party to indemnify the other against losses that might otherwise be incurred by the other party in the future. Many of our agreements contain an indemnity or indemnities that require us to perform certain acts, such as remediation, as a result of the occurrence of a triggering event or condition. In some instances we indemnify third parties against losses resulting from certain events or conditions that arise out of the operations of our equity affiliates.

The nature of these numerous indemnity obligations are diverse and each has different terms, business purposes, and triggering events or conditions. Consistent with customary business practice, any particular indemnity obligation incurred is the result of a negotiated transaction or contractual relationship for which we have accepted a certain level of risk in return for a financial or other type of benefit. In addition, the indemnities in each agreement vary widely in their definitions of both triggering events and the resulting obligations contingent on those triggering events.

With regard to indemnifications, our risk management philosophy is to limit risk in any transaction or relationship to the maximum extent reasonable in relation to commercial and other considerations. Before accepting any indemnity obligation, we make an informed risk management decision considering, among other things, the remoteness of the possibility that the triggering event will occur, the potential costs to perform under any resulting indemnity obligation, possible actions to reduce the likelihood of a triggering event or to reduce the costs of performing under the indemnity obligation, whether we are indemnified by an unrelated third party, insurance coverage that may be available to offset the cost of the indemnity obligation, and the benefits from the transaction or relationship.

Because many or most of our indemnity obligations are not limited in duration or potential monetary exposure, we cannot calculate the maximum potential amount of future payments that could be paid under our indemnity obligations stemming from all our existing agreements. We have disclosed significant contractual matters, including, but not limited to, indemnity obligations, which are reasonably possible to have a material impact on our financial performance. We also accrue for contingent liabilities, including those arising out of indemnity obligations, when a loss is probable and the amounts can be reasonably estimated (see Note 11—Contingencies). We are not aware of the occurrence of any triggering event or condition that would have a material adverse impact on our financial statements as a result of an indemnity obligation relating to such triggering event or condition.

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Note 13—Comprehensive Income

ConocoPhillips’ comprehensive income (loss) was as follows:

Accumulated other comprehensive income (loss) in the equity section of the balance sheet included:

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Note 14—Supplemental Cash Flow Information

For additional information related to the implementation of FIN 46 and SFAS No. 143, see Note 2—Changes in Accounting Principles.

Note 15—Sales of Receivables

At September 30, 2003, ConocoPhillips had sold certain credit card and trade receivables to a Qualifying Special Purpose Entity (QSPE) in a revolving-period securitization arrangement. This arrangement provides for us to sell, and the QSPE to purchase, certain receivables and for the QSPE to then issue beneficial interests of up to $1.2 billion to five bank-sponsored entities. We retain beneficial interests in the QSPE that are subordinate to the beneficial interests issued to the bank-sponsored entities. Our beneficial interests, reported on the balance sheet in accounts and notes receivable-related parties, were $793 million at September 30, 2003, and $1.3 billion at December 31, 2002. We also retain servicing responsibility related to the sold receivables, the fair value of which approximates adequate compensation for the servicing costs incurred.

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In the first nine months of 2003 and 2002, total cash flows received from and paid under securitization arrangements were as follows:

* New receivables sold and cash collections remitted under these ongoing revolving securitization arrangements have been revised due to correction of disclosure calculations.

At December 31, 2002, we had sold $264 million of receivables under a factoring arrangement that included a recourse obligation to repurchase uncollected receivables. At September 30, 2003, no receivables were outstanding under similar arrangements.

Note 16—Related Party Transactions

Significant transactions with related parties were:

(a)

Our Exploration and Production (E&P) segment sells natural gas to Duke Energy Field Services, LLC (DEFS) and crude oil to the Malaysian Refining Company Sdn. Bhd (Melaka), among others, for processing and marketing. Natural gas liquids, solvents and petrochemical feedstocks are sold to Chevron Phillips Chemical Company LLC (CPChem) and refined products are sold primarily to CFJ Properties. Also, we charge several of our affiliates including CPChem, MSLP, Hamaca Holding LLC, and Venture Coke Company for the use of common facilities, such as steam generators, waste and water treaters, and warehouse facilities.

(b)

We purchase natural gas and natural gas liquids from DEFS and CPChem for use in our refinery processes and other feedstocks from various affiliates. We purchase crude oil from Petrozuata C.A. and refined products from Melaka. We also pay fees to various pipeline equity companies for transporting finished refined products.

(c)

We pay processing fees to various affiliates, the most significant being MSLP. Additionally, we pay contract drilling fees to deepwater drillship affiliates, crude oil transportation fees to pipeline equity companies, and commissions to the receivable monetization companies.

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(d)

We pay and/or receive interest to/from various affiliates including the receivable monetization companies and MSLP.

Elimination of our equity percentage share of profit or loss on the above transactions was not material.

Note 17—Segment Disclosures and Related Information

We have organized our reporting structure based on the grouping of similar products and services, resulting in five operating segments:

(1)

Exploration and Production (E&P)—This segment primarily explores for and produces crude oil, natural gas and natural gas liquids on a worldwide basis. At September 30, 2003, E&P was producing in the United States, the Norwegian and U.K. sectors of the North Sea, Canada, Nigeria, Venezuela, the Timor Sea, offshore Australia and China, Indonesia, the United Arab Emirates, Vietnam, Russia, and Ecuador. The E&P segment’s U.S. and international operations are disclosed separately for reporting purposes.

(2)

Midstream—Through both consolidated and equity interests, this segment gathers and processes natural gas produced by ConocoPhillips and others, and fractionates and markets natural gas liquids, primarily in the United States, Canada and Trinidad. The Midstream segment includes our 30.3 percent equity investment in DEFS.

(3)

Refining and Marketing (R&M)—This segment refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia. At September 30, 2003, we owned 12 refineries in the United States; one in the United Kingdom; one in Ireland; and had equity interests in one refinery in Germany, two in the Czech Republic, and one in Malaysia. The R&M segment’s U.S. and international operations are disclosed separately for reporting purposes.

(4)

Chemicals—This segment manufactures and markets petrochemicals and plastics on a worldwide basis. The Chemicals segment consists primarily of our 50 percent equity investment in CPChem.

(5)

Emerging Businesses—This segment includes the development of new businesses beyond our traditional operations. Emerging Businesses includes natural gas-to-liquids technology, technology solutions, power generation and other emerging technologies.

Corporate and Other includes general corporate overhead, all interest income and expense, preferred dividend requirements of capital trusts, discontinued operations, restructuring charges and goodwill resulting from the merger, certain eliminations, and various other corporate activities. Corporate assets include all cash and cash equivalents.

We evaluate performance and allocate resources based on, among other items, net income. Intersegment sales are recorded at prices that approximate market value.

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Analysis of Results by Operating Segment

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Note 18—Income Taxes

ConocoPhillips’ effective tax rate for both the third quarter and first nine months of 2003 was 46 percent, compared with 124 percent and 86 percent for the same periods a year ago. Contributing to the lower tax rate in the nine months of 2003, compared with the corresponding period in 2002, was the one-time impact of tax law changes in certain international jurisdictions. In addition, both of the 2002 periods were impacted by a write-off of purchased in-process research and development costs without a corresponding tax benefit and the nine-month period of 2002 was impacted by the partial impairment of an exploration prospect without a corresponding tax benefit. The effective tax rate in excess of the domestic federal statutory rate of 35 percent was generally due to foreign taxes in excess of the domestic federal statutory rate.

Note 19—New Accounting Standard

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity,” to address the balance sheet classification of certain financial instruments that have characteristics of both liabilities and equity. The statement is already effective for all contracts created or modified after May 31, 2003, and was originally intended to become effective July 1, 2003, for all previously existing contracts. However, on November 7, 2003, the FASB issued an indefinite deferral of certain provisions of SFAS No. 150. We will continue to monitor and assess the FASB’s modifications to SFAS No. 150, but do not anticipate that it will have a material impact on our financial statements.

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Note 20—Subsequent Events

In October and early November 2003, we executed certain interest rate swaps that had the effect of converting $1.5 billion of debt from fixed to floating rate. Under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” these swaps were designated as hedging the exposure to changes in the fair value of all of the company’s 3.625% Notes due 2007, all of the 6.35% Notes due 2009, and $350 million of the 4.75% Notes due 2012. These swaps qualify for the shortcut method of hedge accounting, so over the term of the swaps we will not recognize gain or loss due to ineffectiveness in the hedge.

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Supplementary Information—Condensed Consolidating Financial Information

In connection with the merger of ConocoPhillips Holding Company (formerly named Conoco Inc.) and ConocoPhillips Company (formerly named Phillips Petroleum Company) with wholly owned subsidiaries of ConocoPhillips, and to simplify our credit structure, we have established various cross guarantees between ConocoPhillips, ConocoPhillips Holding Company, and ConocoPhillips Company. With the new organizational structure, ConocoPhillips Company is the direct or indirect parent of former Conoco and Phillips subsidiaries and is wholly owned by ConocoPhillips Holding Company, which is wholly owned by ConocoPhillips. ConocoPhillips and ConocoPhillips Holding Company have fully and unconditionally guaranteed the payment obligations of ConocoPhillips Company with respect to its publicly held debt securities. Similarly, ConocoPhillips and ConocoPhillips Company have fully and unconditionally guaranteed the payment obligations of ConocoPhillips Holding Company with respect to the publicly held debt securities of ConocoPhillips Holding Company. In addition, ConocoPhillips Company and ConocoPhillips Holding Company have fully and unconditionally guaranteed the payment obligations of ConocoPhillips with respect to its publicly held debt securities. All guarantees are joint and several. The following condensed consolidating financial information presents the results of operations, financial position and cash flows for:

•

ConocoPhillips, ConocoPhillips Holding Company, and ConocoPhillips Company (in each case, reflecting investments in subsidiaries utilizing the equity method of accounting);

•

All other non-guarantor subsidiaries of ConocoPhillips Holding Company and ConocoPhillips Company; and

•

The consolidating adjustments necessary to present ConocoPhillips’ results on a consolidated basis.

Effective June 30, 2003, Bayway Refining Company and Marcus Hook Refining Company were merged into ConocoPhillips Company. Previously reported prior period information has been restated to reflect this reorganization of companies under common control.

This condensed consolidating financial information should be read in conjunction with our accompanying consolidated financial statements and notes.

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Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis contains forward-looking statements including, without limitation, statements relating to our plans, strategies, objectives, expectations, and intentions, 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 63.

RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three- and nine-month periods ending September 30, 2003, is based on a comparison with the corresponding periods of 2002. The merger of Conoco Inc. (Conoco) and Phillips Petroleum Company (Phillips) on August 30, 2002, impacts the comparability of the 2003 periods with the corresponding 2002 periods.

Conoco and Phillips Merger

On August 30, 2002, Conoco and Phillips combined their businesses by merging with wholly owned subsidiaries of a new company named ConocoPhillips (the merger). The merger was accounted for using the purchase method of accounting, with Phillips designated as the acquirer for accounting purposes. Because Phillips was designated as the acquirer, it is treated as the predecessor to ConocoPhillips and its operations and results are presented in this quarterly report for all periods prior to the close of the merger. From the merger date forward, the operations and results of ConocoPhillips reflect the combined operations of the two companies. For additional information on the merger, see Note 3—Merger of Conoco and Phillips, in the Notes to Consolidated Financial Statements.

Consolidated Results

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A summary of net income (loss) by business segment follows:

Net income was $1,306 million in the third quarter of 2003, compared with a net loss of $116 million in the third quarter of 2002. Net income was $3,695 million in the nine-month period ending September 30, 2003, compared with $133 million in the corresponding period of 2002. The improved results in both periods primarily were due to:

•

increased E&P and R&M production volumes as a result of the merger;

•

higher crude oil and natural gas prices in our E&P segment;

•

improved refining and marketing margins in our R&M segment; and

•

lower merger-related expenses in the 2003 periods, compared with the 2002 periods.

See the “Segment Results” section for additional information on our E&P and R&M results, as well as our other reporting segments.

Income Statement Analysis

Sales and other operating revenues increased 79 percent in the third quarter of 2003, and 135 percent in the nine-month period. The increases were attributable to both higher sales volumes and sales prices of key products such as crude oil, natural gas, automotive gasoline and distillates. Most of the sales volume increases were the result of the merger, while market factors led to increased sales prices of key products.

Equity in earnings of affiliates increased 109 percent in the third quarter of 2003, and 183 percent in the nine-month period. Our share of earnings from affiliates acquired in the merger accounted for the majority of the increased equity earnings. Of these, our E&P joint ventures in Canada (Petrovera) and Venezuela (Petrozuata), along with CFJ Properties in our R&M segment, provided the most equity earnings. Of those equity affiliates included in the results of both years, our equity earnings from Duke Energy Field Services, LLC improved on higher natural gas liquids prices, and our earnings from Hamaca, an E&P joint venture in Venezuela, increased due to increased crude oil production.

Other income increased 138 percent in the third quarter of 2003, and 178 percent in the nine-month period. The increase in the third quarter of 2003 mainly was attributable to higher net gains on asset dispositions. In addition, the increase in the nine-month period of 2003 was also attributable to insurance demutualization benefits. See the Corporate and Other section of “Segment Results” for additional information on the insurance benefits.

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Purchased crude oil and products increased 70 percent in the third quarter of 2003, and 124 percent in the nine-month period. The increase in both periods was attributable to higher purchase volumes and purchase prices of petroleum products such as automotive gasoline and distillates, as well as higher purchase volumes and purchase prices for crude oil, which is used as a feedstock in our refineries. Most of the purchase volume increases were the result of the merger, while market factors led to increased purchase prices of key products.

Production and operating expenses increased 44 percent in the third quarter of 2003 and 75 percent in the nine-month period, while selling, general and administrative expenses decreased 31 percent in the third quarter and increased 26 percent in the nine-month period. The increases primarily reflect the larger size of our operations and staff following the merger. Selling, general and administrative costs in the third quarter of 2003 were less than the third quarter of 2002 due to the expensing of $246 million of in-process research and development costs in 2002 in connection with the merger.

Exploration expenses increased 55 percent in the third quarter of 2003, and 24 percent in the nine-month period. The increase in the third quarter of 2003 reflects the increased size of our exploration program following the merger, as well as higher dry hole costs. In the first quarter of 2002, we recognized a $77 million partial impairment of our leasehold investment in deepwater Block 34, offshore Angola. The absence of such a significant item in the first nine months of 2003 contributed to the lower percentage increase in the nine-month period.

Depreciation, depletion and amortization increased 57 percent in the third quarter of 2003, and 92 percent in the nine-month period. The increases mainly were the result of our increased depreciable base of properties, plants and equipment after the merger.

Property impairments increased significantly in the third quarter and first nine months of 2003. The 2003 impairments were recorded as a result of asset status changes from held-for-use to held-for-sale, producing properties that failed to meet the recoverability test under Statement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” as well as tax law changes in Norway affecting asset removal costs. See Note 8—Properties, Plants and Equipment, in the Notes to Consolidated Financial Statements, for additional information.

Taxes other than income taxes increased 120 percent in the third quarter of 2003, and 199 percent in the nine-month period. The increases in both periods reflect higher excise taxes due to increased petroleum products sales volumes, higher production taxes due to increased crude oil production, and increased property and payroll taxes, as a result of the merger. Higher prices for crude oil and petroleum products also contributed to the increases.

Accretion on discounted liabilities increased 550 percent in the third quarter of 2003, and 529 percent in the nine-month period. Both increases reflect accretion expense on environmental liabilities assumed in the merger and discounted obligations associated with the retirement and removal of long-lived assets that became effective January 1, 2003. See Note 2—Changes in Accounting Principles, in the Notes to Consolidated Financial Statements, for additional information.

Interest and debt expense increased 42 percent in the third quarter of 2003, and 86 percent in the nine-month period. Both increases were due mainly to higher debt levels following the merger, as well as the impact of Financial Accounting Standards Board Interpretation No. 46, “Consolidation of Variable Interest Entities,” (FIN 46). The adoption of FIN 46 for variable interest entities (VIEs) involving synthetic leases and certain other financing structures, with retroactive application to January 1, 2003, resulted in increased debt on our balance sheet, which resulted in higher interest expense in the 2003 periods. See Note 2—

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Changes in Accounting Principles, and Note 10—Debt, in the Notes to Consolidated Financial Statements, for additional information.

Our effective tax rate for the third quarter of 2003 was 46 percent, compared with 124 percent for the same period in 2002. Our effective tax rate for the first nine months of 2003 was 46 percent, compared with 86 percent for the corresponding period of 2002. The lower effective tax rates in the 2003 periods primarily were the result of the one-time impact of tax law changes in certain international jurisdictions and a higher proportion of income in lower-tax-rate jurisdictions. Contributing to the higher effective tax rate in both 2002 periods was a write-off of purchased in-process research and development costs without a corresponding tax benefit. In addition, the higher effective tax rate in the first nine months of 2002 reflects the partial impairment of an exploration prospect without a corresponding tax benefit.

We recognized foreign currency losses in both 2003 periods, while in both 2002 periods we incurred foreign currency gains. Minority interests and preferred dividend requirements of capital trusts were lower in the 2003 periods, primarily because of the adoption of FIN 46, with retroactive application to January 1, 2003, that deconsolidated the capital trust and removed the preferred dividend expense, with a corresponding increase in interest expense.

In the second quarter of 2003, we recognized a $28 million gain on subsidiary equity transactions related to our E&P Bayu-Undan development in the Timor Sea. See Note 5—Subsidiary Equity Transactions, in the Notes to Consolidated Financial Statements, for additional information.

Income from discontinued operations was $57 million in the third quarter of 2003, compared with a net loss of $42 million in the third quarter of 2002. For the nine-month periods, income from discontinued operations was $201 million in 2003, compared with a net loss of $7 million in 2002. The improvement in the 2003 periods reflects the addition of assets classified as discontinued following the merger, as well as higher marketing margins and reduced depreciation expense. For additional information about discontinued operations, see Note 4—Discontinued Operations, in the Notes to Consolidated Financial Statements.

We adopted Financial Accounting Standards Board Statement No. 143, “Accounting for Asset Retirement Obligations,” (SFAS No. 143) effective January 1, 2003. As a result, we recognized a benefit of $145 million for the cumulative effect of this accounting change in the first quarter of 2003. Also, with retroactive application to January 1, 2003, we adopted FIN 46 for VIEs involving synthetic leases and certain other financing structures created prior to February 1, 2003. This resulted in a charge of $258 million for the cumulative effect of this accounting change. For additional information on these accounting changes, see Note 2—Changes in Accounting Principles, in the Notes to Consolidated Financial Statements.

Restructuring Accruals

As a result of the merger, we began a restructuring program in September 2002 to capture the benefits of combining Conoco and Phillips by eliminating redundancies, consolidating assets, and sharing common services and functions across regions. We expect the restructuring program to be completed by the end of the first quarter of 2004. From September 2002 through September 30, 2003, approximately 3,900 positions worldwide had been identified for elimination. Of this total, approximately 2,600 employees had been terminated by September 30, 2003. The information in Note 9—Restructuring, in the Notes to Consolidated Financial Statements, is incorporated herein by reference.

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Segment Results

E&P

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

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Net income from our E&P segment increased 110 percent in the third quarter of 2003, and 250 percent in the nine-month period. The improvements in both 2003 periods reflect higher production volumes, primarily due to the merger, higher crude oil and natural gas prices, and increased gains from asset sales. These items were partially offset by increased production and operating expenses; depreciation, depletion and amortization; and taxes other than income taxes; all reflecting the larger size and scope of our operations following the merger.

In addition, the nine-month 2003 period included international tax benefits recognized in the second quarter of 2003, and the adoption of SFAS No. 143 and the adoption of FIN 46 for VIEs involving synthetic leases and certain other financing structures. The net cumulative effect of these two accounting changes increased E&P’s net income by $129 million in the first quarter and first nine months of 2003.

Our average worldwide crude oil sales price was $27.00 per barrel in the third quarter of 2003, compared with $25.97 in the third quarter of 2002. Our average crude oil price was higher for the nine-month period as well, averaging $27.55 per barrel in 2003, compared with $23.43 per barrel in 2002. We also benefited from higher natural gas prices, with our average worldwide price increasing from $2.49 per thousand cubic feet in the third quarter of 2002 to $3.80 in the third quarter of 2003. See the “Outlook” section for additional discussion of crude oil and natural gas prices.

U.S. E&P

Net income from our U.S. E&P operations increased 78 percent in the third quarter of 2003, and 154 percent in the nine-month period. The majority of the increase in both periods resulted from higher crude oil and natural gas prices. Increased production volumes following the merger accounted for the remaining increase, after considering the corresponding increases that go along with higher production, such as higher production taxes; production and operating expenses; and depreciation, depletion and amortization. Our U.S. E&P operations recognized a net benefit of $142 million for the cumulative effect of adopting SFAS No. 143 and FIN 46 in the first quarter and first nine months of 2003.

U.S. E&P production on a barrel-of-oil-equivalent basis averaged 646,000 barrels per day in the third quarter of 2003, compared with 678,000 barrels per day in the second quarter of 2003. The 5 percent decrease primarily was due to asset dispositions, seasonal declines in Alaska, and normal field declines in the Lower 48 states.

International E&P

Net income from our international E&P operations increased 173 percent in the third quarter and 608 percent in the first nine months of 2003. Increased production volumes following the merger accounted for the majority of the increase in both periods, after considering the corresponding increases that go along with higher production, such as higher production taxes; production and operating expenses; and depreciation, depletion and amortization. Higher crude oil and natural gas prices contributed to the remaining increase.

Our international E&P operations recognized a charge of $13 million for the cumulative effect of adopting SFAS No. 143 and FIN 46 in the first quarter of 2003. Included in international E&P’s net income in the third quarter of 2003 were foreign currency transaction losses of $12 million, compared with losses of $6 million in the third quarter of 2002. The nine-month period of 2003 included foreign currency transaction losses of $28 million, while the corresponding period of 2002 had losses of $11 million.

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International E&P’s net income in the nine-month period of 2003 was also favorably impacted by two items:

•

In Norway, the Norway Removal Grant Act (1986) was repealed in the second quarter of 2003. Prior to its repeal, this Act required the Norwegian government to contribute to the cost of removing offshore oil and gas production facilities. Now, the co-venturers in the facilities must fund all removal costs, but can deduct the removal costs, as incurred, under the Petroleum Tax Act at the marginal tax rate in effect at the time of removal. These changes required us: to recognize an additional liability for the government’s share, prior to repeal of the Act, of the future removal costs, with a corresponding increase in properties, plants and equipment (PP&E); and to establish a net deferred tax asset for the temporary differences between the financial basis and tax basis of all of our Norway removal assets and liabilities. Some of the increases in PP&E were on shut-in fields, which led to immediate impairments of those properties. The overall impact on the nine-month results was a net after-tax benefit of $87 million.

•

In the Timor Sea region, ConocoPhillips and its co-venturers received final approvals from authorities to proceed with the natural gas development phase of the Bayu-Undan project in the second quarter of 2003. This approval allowed a broad ownership interest re-alignment among the co-venturers to proceed, which included our sale of a 10 percent interest in the project and the issuance of equity by previously wholly owned subsidiaries. In addition, the ratification of the Australia/Timor-Lesté treaty lowered the company’s deferred tax liability position. The net result of these events was an after-tax benefit of $51 million in the nine-month period of 2003. See Note 5—Subsidiary Equity Transactions, in the Notes to Consolidated Financial Statements, for additional information.

International E&P production on a barrel-of-oil-equivalent basis averaged 888,000 barrels per day in the third quarter of 2003, compared with 939,000 barrels per day in the second quarter. The 5 percent decrease mainly was due to seasonal maintenance activities in the North Sea, partly offset by increased natural gas production in Canada and Indonesia.

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Midstream

Our Midstream segment consists of a 30.3 percent interest in Duke Energy Field Services, LLC (DEFS), as well as our other natural gas gathering and processing operations, and natural gas liquids fractionation and marketing businesses, primarily in the United States, Canada and Trinidad.

Net income from our Midstream segment increased 182 percent in the third quarter of 2003, and 149 percent in the nine-month period. The increases primarily were attributable to improved results from DEFS and the addition of midstream operations following the merger. DEFS’ results mainly increased because of higher natural gas liquids prices.

Included in the Midstream segment’s net income was a benefit of $9 million in the third quarter of 2003, the same as the third quarter of 2002, representing the amortization of the excess amount of our 30.3 percent equity interest in the net assets of DEFS over the book value of our investment in DEFS. The nine-month periods for both years included $27 million for the basis difference.

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R&M

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Net income from our R&M segment increased substantially in the third quarter and nine-month period of 2003. The improved results in both periods primarily were due to significantly higher U.S. refining margins. Industry refining margins improved because increases in petroleum product prices outpaced the increase in crude oil feedstock costs. See the “Outlook” section for additional discussion of refining margins.

The addition of refining and marketing assets in the merger also contributed to the higher 2003 earnings, as did increased wholesale gasoline margins. The nine-month period of 2003 included a net charge of $125 million for the cumulative effect of the adoption of FIN 46 for VIEs involving synthetic leases and certain other financing structures, retroactive to January 1, 2003.

Our refineries produced 2,735,000 barrels per day of petroleum products in the third quarter of 2003, compared with 1,973,000 barrels per day in the third quarter of 2002. The increase reflects the addition of production from refineries acquired in the merger.

U.S. R&M

Net income from our U.S. R&M operations increased significantly in the third quarter and first nine months of 2003. The improved results in both periods mainly were due to significantly higher refining margins. Industry refining margins improved because increases in petroleum product prices outpaced the increase in crude oil feedstock costs. See the “Outlook” section for additional discussion of refining margins.

The addition of refining and marketing assets in the merger also contributed to the higher 2003 earnings, as did increased wholesale gasoline margins. The nine-month period of 2003 included a net charge of $124 million for the cumulative effect of the adoption of FIN 46 for VIEs involving synthetic leases and certain other financing structures, retroactive to January 1, 2003.

Our U.S. crude oil capacity utilization rate was 96 percent in the third quarter of 2003, compared with 98 percent in the second quarter of 2003. The decrease mainly was due to a fire in July 2003 at our Ponca City refinery in Oklahoma. The fire resulted in portions of the facility being shut down, leading to reduced throughput.

International R&M

Net income from our international R&M operations increased substantially in the third quarter and nine-month period of 2003. Both improvements were due to the larger size and scope of our international refining operations following the merger.

Our international crude oil capacity utilization rate was 88 percent in the third quarter of 2003, compared with 85 percent in the second quarter of 2003. The improvement in the third quarter reflects scheduled and unscheduled downtime at our Humber refinery in the United Kingdom in the second quarter of 2003.

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Chemicals

The Chemicals segment consists of our 50 percent interest in Chevron Phillips Chemical Company LLC (CPChem), which we account for using the equity method of accounting. Net income from the Chemicals segment increased $4 million in the third quarter of 2003. Net loss for the first nine months of 2003 was $4 million, compared with a net loss of $1 million in the same period of 2002.

As the results in both years indicate, the chemicals industry continues to be challenged to effectively utilize capacity, manage costs and improve margins in an adverse economic environment. Global economic slowdown in the last several years has reduced overall chemical demand, which has led to excess production capacity in the industry and pressured margins on key product lines. The chemicals industry is also impacted by higher energy prices, which negatively affects both utility and feedstock costs.

Emerging Businesses

The Emerging Businesses segment includes the development of new businesses outside our traditional operations. Emerging Businesses incurred a net loss of $18 million in the third quarter of 2003, compared with a net loss of $262 million in the third quarter of 2002. Emerging Businesses incurred a net loss of $75 million in the first nine months of 2003, compared with a net loss of $270 million in the corresponding period of 2002. The net losses in both 2003 periods were lower than those in 2002 as a result of a $246 million write-off of purchased in-process research and development costs in the third quarter of 2002 related to the merger.

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Corporate and Other

Net interest after-tax represents interest expense, net of interest income and capitalized interest, as well as premiums incurred on the early retirement of debt. Net interest increased 61 percent in the third quarter of 2003, and 86 percent in the nine-month period. The increase in both 2003 periods mainly was due to our higher debt levels following the merger, as well as the impact of the adoption of FIN 46 for VIEs involving synthetic leases and certain other financing structures in the third quarter, retroactive to January 1, 2003. FIN 46 increased balance sheet debt, which resulted in higher interest expense. See Note 2—Changes in Accounting Principles, in the Notes to Consolidated Financial Statements, for additional information.

After-tax corporate general and administrative expenses increased slightly in the third quarter of 2003, but were unchanged in the nine-month period. Expenses in 2003 were impacted by the merger, as well as the expensing of stock options. Beginning in 2003, on a prospective basis, we elected to use the fair-value accounting method provided for under SFAS No. 123, “Accounting for Stock-Based Compensation.” See Note 6—Stock-Based Compensation, in the Notes to Consolidated Financial Statements, for additional information. Both 2003 periods benefited from increased allocations of certain of our staff costs to the operating segments. The increased corporate allocations did not have a material impact on the operating segments’ results.

Income from discontinued operations was $57 million in the third quarter of 2003, compared with a loss of $42 million in the third quarter of 2002. For the nine-month periods, income from discontinued operations was $201 million in 2003, compared with a loss of $7 million in 2002. The improvement in the 2003 periods reflects the addition of assets classified as discontinued subsequent to the merger, as well as higher marketing margins and reduced depreciation expense.

On an after-tax basis, merger-related costs were $41 million in the third quarter of 2003, and $183 million in the nine-month period. Included in these costs were employee relocation expenses, transition labor costs, and other charges directly associated with the merger. Also included in the nine-month 2003 period was a charge of $39 million due to the accelerated recognition of certain pension costs due to the number of employees who elected to take lump-sum pension settlements when they retired in association with the merger. Merger-related costs in the third quarter and first nine months of 2002 were $221 million and $224 million, respectively.

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The category “Other” consists primarily of items not directly associated with the operating segments on a stand-alone basis, including certain foreign currency transaction gains and losses, and environmental costs associated with sites no longer in operation. Results from Other were lower in the third quarter of 2003, compared with the third quarter of 2002, primarily due to increased environmental costs. Results from Other were improved in the first nine months of 2003 because we recognized an after-tax gain of $34 million in the first quarter of 2003, representing beneficial interests we had in certain insurance companies as a result of the conversion of those companies from mutual companies to stock companies, a process known as demutualization. These beneficial interests arose from our prior purchase and ownership of various insurance policies and contracts issued by the mutual companies. Prior to the demutualizations, our mutual ownership interests in these insurance companies were not recognized because the ownership interests in the mutual companies were neither capable of valuation nor marketable. Included in Other in the third quarter of 2003 was a net foreign currency transaction gain of $2 million, after-tax, compared with a net gain of $5 million in the third quarter of 2002. The nine-month period of 2003 included a net foreign currency transaction gain of $21 million, while the corresponding period of 2002 had a net gain of $13 million.

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CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators

Significant Sources of Capital

During the first nine months of 2003, cash of $7,368 million was provided by operating activities, an increase of $4,382 million from the same period of 2002. The increase in cash provided by operating activities was primarily due to: higher crude oil, natural gas liquids and natural gas prices, combined with increased production as a result of the addition of the Conoco assets; higher refining margins; and higher marketing margins. Working capital changes increased cash flow from operating activities $704 million for the nine months of 2003, compared with a positive effect of $836 million for the nine months of 2002. The $132 million decrease in working capital changes was primarily due to a decrease in accounts payable and a decrease in taxes and other accruals. These items were partially offset by a decrease in accounts and notes receivables and a decrease in prepaid expenses and other current assets. Cash from operating activities provided by discontinued operations amounted to $181 million, compared with $118 million in the first nine months of 2002.

To meet our liquidity requirements, including funding our capital program, paying dividends and repaying debt, we look to a variety of funding sources, primarily cash from operating activities. As we previously disclosed, we also anticipate raising funds during 2003 through 2004 from the sale of assets, including those assets required to be sold by the Federal Trade Commission, as well as a substantial portion of our U.S. retail marketing sites. See Note 4—Discontinued Operations, in the Notes to Consolidated Financial Statements, for additional information. We also plan to raise funds from the sale of non-strategic E&P properties. Through the first nine months of 2003, we raised approximately $1.5 billion from asset sales and anticipate raising approximately $1.3 billion more on transactions expected to close by the end of 2003.

While the stability of our cash flows from operating activities benefits from geographic diversity and the effects of upstream and downstream integration, our 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 make tax payments and purchase crude oil, natural gas and petroleum products. Our primary funding

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source for short-term working capital needs is a $4 billion commercial paper program, a portion of which may be denominated in other currencies (limited to euro 3 billion equivalent). Commercial paper maturities are generally kept within 90 days. At September 30, 2003, ConocoPhillips had $624 million of commercial paper outstanding, of which $50 million was denominated in foreign currencies, compared with $1,517 million of commercial paper outstanding at December 31, 2002, of which $206 million was denominated in foreign currencies.

At September 30, 2003, we had a $2 billion 364-day revolving credit facility expiring on October 14, 2003, and two revolving credit facilities totaling $2 billion expiring in October 2006 that supported our $4 billion commercial paper program. There were no outstanding borrowings under any of these facilities at September 30, 2003. Effective October 14, 2003, we entered into two new revolving credit facilities, replacing the $2 billion 364-day facility that expired on that same date. The new revolving credit facilities are a $1.5 billion 364-day facility and $500 million five-year facility. One of our Norwegian subsidiaries has two $300 million revolving credit facilities that expire in June 2004, under which no borrowings were outstanding as of September 30, 2003.

In September 2003, we combined our credit card and trade receivables monetization programs into one program. As a result, the number of Qualifying Special Purpose Entities (QSPEs) used to account for our receivable monetization facility was reduced from two to one and the maximum level of senior beneficial interests that can be issued to third-party beneficial interest holders was reduced from $1.5 billion to $1.2 billion. We retain beneficial interests in this QSPE that are subordinate to the beneficial interests issued to bank-sponsored entities. At September 30, 2003, and December 31, 2002, $1.2 billion and $1.3 billion, respectively, of senior beneficial interests in the QSPEs were issued and outstanding to the bank-sponsored entities. Our retained interests, which are reported on the balance sheet in accounts and notes receivable—related parties, were $793 million at September 30, 2003, and $1.3 billion at December 31, 2002. See Note 15—Sales of Receivables, in the Notes to Consolidated Financial Statements, for additional information.

Other Financing and Off-Balance Sheet Arrangements

In the third quarter of 2003, the adoption of Financial Accounting Standards Board (FASB) Interpretation No. 46, “Consolidation of Variable Interest Entities,” (FIN 46) for VIEs involving synthetic leases and certain other financing structures and the adoption of Statement of Financial Accounting Standards (SFAS) No. 150, “Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity,” affected the accounting and reporting for certain entities in which we have interests.

The application of FIN 46 increased our balance sheet debt approximately $2.8 billion. With the adoption of FIN 46:

•

The Phillips 66 Capital Trust II (Trust) is no longer consolidated, which removed $350 million of mandatorily redeemable preferred securities from the consolidated balance sheet and added to long-term debt $361 million of 8% Junior Subordinated Deferrable Interest Debentures due 2037. Previously this debt was eliminated in consolidation; and

•

VIEs involving synthetic leases and certain other financing structures in which we are the primary beneficiary were consolidated with retroactive application beginning January 1, 2003, which increased consolidated debt approximately $2.4 billion.

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With the adoption of SFAS No. 150:

•

The $502 million Ashford Energy Capital S.A. minority interest was unchanged because it is not mandatorily redeemable and the entity does not have a required liquidation date.

•

The $141 million net minority interest in Conoco Corporate Holdings L.P. was also unchanged due to FASB Staff Position No. FAS 150-3 issued November 7, 2003, which indefinitely deferred certain provisions of SFAS No. 150.

See Note 2—Changes in Accounting Principles and Note 10—Debt, in the Notes to Consolidated Financial Statements, for more information.

Capital Requirements

For information about our capital expenditures and investments, see “Capital Spending” below.

Our balance sheet debt at the end of the third quarter was $18.7 billion. This reflects debt reductions of approximately $1.4 billion during the third quarter of 2003, as well as accounting changes that increased balance sheet debt approximately $2.8 billion as a result of the adoption of FIN 46. See Other Financing and Off-Balance Sheet arrangements under Capital Resources and Liquidity in Management’s Discussion and Analysis, and Note 2—Changes in Accounting Principles and Note 10—Debt, in the Notes to Consolidated Financial Statements, for additional information.

In the first nine months of 2003, in addition to reducing our commercial paper, we paid the following notes or debt facilities as they were called or matured and funded the payments with cash from operating activities and proceeds from asset dispositions:

•

$250 million 8.49% Notes due 2023, at 104.245 percent;

•

$181 million SRW Cogeneration Limited Partnership note;

•

$100 million 6.65% Notes that matured on March 1, 2003;

•

$250 million 7.92% Notes due in 2023 at 103.96 percent;

•

$500 million Floating Rate Notes due April 15, 2003;

•

$150 million 8.25% Mortgage Bonds due May 15, 2003;

•

$90 million Tosco Trust 2000-E 8.78% Senior Secured Notes due 2010;

•

$245 million Tosco Trust 2000-E 8.58% Senior Secured Notes due 2010;

•

$895 million of floating rate marketing lease obligations having maturities in 2003 and 2005; and

•

$173 million of 7.6% ocean vessel lease obligations having a final maturity in 2004.

In October 2003, we paid the following debt facilities:

•

$95 million of floating rate marketing lease obligations having a final maturity in 2004; and

•

$98 million of floating rate aviation equipment lease obligations having a final maturity in 2004.

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In November 2003, we called and paid our $250 million 7.20% Notes due 2023, at 103.60 percent, and gave notice on an additional $127 million of floating rate marketing lease obligations having final maturities in 2004 and 2006.

Also, in October 2003, we announced a new quarterly dividend rate of 43 cents per share for our common stock, an increase of 7.5 percent. The dividend is payable December 1, 2003, to stockholders of record at the close of business October 31, 2003.

Capital Expenditures and Investments

E&P

We continue with the construction of our double-hulled Endeavour Class tankers, which are used in transporting Alaskan crude oil to the U.S. West Coast. A third tanker, the Polar Discovery, was delivered for service in September 2003. We expect to add a new Endeavour Class tanker to our fleet each year through 2005.

In the first quarter of 2003, we completed the purchase of Amerada Hess’ 1.5 percent interest in the Trans-Alaska Pipeline System (TAPS), increasing our ownership in TAPS to 28.2 percent interest.

Also in Alaska, we continued development drilling in the Kuparuk and West Sak fields in the Greater Kuparuk Area, the Borealis field in the Greater Prudhoe Bay Area, and the Alpine field. In addition, we plan to increase oil production capacity at the Alpine field. The Alpine Capacity Expansion Project Phase I is expected to start up in 2004. The project will increase both water and gas handling capacities, both of which are important for oil production and maintaining reservoir pressure.

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In the Lower 48, we continued to explore and develop our acreage positions in the deepwater Gulf of Mexico, South Texas, the San Juan Basin, the Permian Basin, and the Texas Panhandle. In the Gulf of Mexico, development drilling is ongoing in the Magnolia and Princess fields, and appraisal drilling is under way on the K-2 discovery. In January 2003, we began construction of the Magnolia tension-leg platform, and we expect completion in 12 months. Production from Magnolia is anticipated to startup in late 2004. Total development of the project is 60 percent complete with 40 percent of the budgeted capital expenditures spent to date. We are the operator of the Magnolia project with a 75 percent interest.

Elsewhere in the Lower 48, in February 2003, we began drilling the Lorien exploration well in the Gulf of Mexico on Green Canyon Block 199, which was declared a discovery in July. The well has been temporarily suspended, pending further appraisal of the hydrocarbon zone. We are the operator with a 65 percent interest.

In the U.K. and Norwegian sectors of the North Sea, we continued with several exploration and development projects, with the largest expenditures on the Clair field. We expect first production from Clair in late 2004. Late in the third quarter of 2003, we and our co-venturers began oil production from the Grane field in the Norwegian North Sea. Net peak production of approximately 14,000 barrels per day is anticipated in 2005.

In Indonesia, we completed the successful test of the North Sumpal-1 well in the Sakakemang Block located in South Sumatra, and continued on the construction of the South Jambi gas project in the South Jambi B Block also located in South Sumatra. In addition, we continue to develop the offshore Belanak and other fields in the Block B Production Sharing Contract (PSC), for which a floating production storage and offloading vessel is under construction. The vessel is expected to be completed in the first half of 2005.

In China’s Bohai Bay, we continued with planning and design for Phase II of the Peng Lai 19-3 development. Phase II includes multiple wellhead platforms, central processing facilities, and a floating storage and offloading facility. We are developing, in conjunction with Phase II, the Peng Lai 25-6 oil field, located three miles east of Peng Lai 19-3. We also drilled exploration wells on the Peng Lai 19-9 prospect and the Peng Lai 13-1 prospect, which resulted in two discoveries. The Peng Lai 19-9-1 well is located two miles east of the Peng Lai 19-3 oil field and along with adjacent structures will be a part of the Phase II development. The Peng Lai 13-1-1 well is located 18 miles north of the Peng Lai 19-3 field and requires further appraisal.

In the Timor Sea, we continued with development activities associated with the Bayu-Undan gas recycle and gas development projects. We continued to drill future production wells and have installed all major facilities, including two production, processing and living quarters platforms and an unmanned production platform. A multi-product floating, storage and offloading vessel will be connected to the production facilities during the fourth quarter of 2003. Initial production is expected in early 2004 with anticipated full capacity of 62,000 net barrels per day of condensate and gas liquids being reached in the third quarter of 2004. We have also received approval of the gas development plan for the Bayu-Undan project from the Timor Sea Designated Authority, concluded fiscal and legal provisions with the government of Timor-Lesté, and executed new PSC arrangements with the Designated Authority. The gas development project includes a liquefied natural gas (LNG) plant, including a pipeline to Darwin, Australia. The first LNG cargo from the three million-ton-per-year facility is scheduled for delivery in early 2006. During the third quarter of 2003, construction of the LNG facility and the pipeline began. In June 2003, we sold what currently equates to a 10.08 percent interest in the unitized Bayu-Undan field; purchased other interests that currently equate to a 2.65 percent interest in the field; sold a 43.3 percent interest in the Bayu-Undan pipeline under construction; and sold a 43.3 percent interest in Darwin LNG Pty Ltd (owner of the LNG plant to be constructed). The net result is that ConocoPhillips retains a 56.72 percent controlling interest in the integrated project.

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In Vietnam, we began production in late October 2003 in the southwest area of the Su Tu Den field in Block 15-1 in the Cuu Long Basin. In addition, we are currently evaluating the commerciality of the Su Tu Vang fields and the northeast portion of the Su Tu Den field. In Block 15-2 (Rang Dong field), while the field is in full production, field facilities are being upgraded to include a utilities-living quarters platform; a gas lift, water injection, gas export platform; and water injection pipelines to existing facilities. These upgrades are anticipated to be operational in the fourth quarter of 2003.

At our Hamaca project in Venezuela, we continued with activities required to produce, transport and upgrade 8.6-degree API extra-heavy crude into marketable synthetic crude oil. Total current production is approximately 80,000 gross barrels of heavy crude oil per day, 26,000 net. We anticipate completing the construction of the upgrader in the second half of 2004, with peak capacity of extra-heavy crude in the 180,000 gross barrels per day range.

We continued with development of the Stage III expansion-mining project in the Canadian province of Alberta, which is expected to increase our Canadian Syncrude production. The Aurora Train 2 project (the new mine) started up in late October 2003. The upgrader expansion project is expected to start up in mid-2005.

In the Caspian Sea, we exercised our pre-emptive rights related to British Gas’ sale of their share in the North Caspian License that includes the Kashagan field offshore Kazakhstan. The transaction is expected to close in late 2003 or early 2004, at which time our interest in the license will increase from 8.33 percent to 10.185 percent.

R&M

The polypropylene plant at the Bayway refinery in Linden, New Jersey, began operations in March 2003, utilizing propylene feedstock from the refinery to make up to 775 million pounds of polypropylene per year. This plant is managed and reported as part of the R&M operating segment.

At our Ferndale, Washington, refinery, we completed construction of a new fluid catalytic cracking unit, which commenced initial operations in March 2003. We expect the unit to improve gasoline production from each barrel of crude oil input.

In the United States, we continue to expend funds related to clean fuels, safety and environmental projects. We continue to work on refinery projects at our refineries in Ponca City, Oklahoma; Ferndale, Washington; and Roxana, Illinois, to produce the low-sulfur gasoline required by the Environmental Protection Agency (EPA). We expect to complete these projects by year-end. We are also investing in a new diesel hydrotreater at the Rodeo facility of our San Francisco area refinery that will produce reformulated California highway diesel an estimated one-and-a-half years ahead of the June 2006 deadline.

In July 2003, we completed the acquisition of certain refining assets in Hartford, Illinois. The operations of these assets are being integrated into the operations of our nearby Wood River refinery.

Internationally we continue to invest in our ongoing refining and marketing operations, including a replacement reformer at our Humber refinery in the United Kingdom and marketing growth in select countries in Europe and Asia.

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Emerging Businesses

We continued to spend funds in 2003 on construction of our Immingham combined heat and power cogeneration plant near our Humber refinery in the United Kingdom. At the end of the third quarter, construction of the facility was approximately 90 percent complete. We expect the plant to become operational in 2004.

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, we believe that the chance 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 our financial statements.

Environmental

ConocoPhillips and each of our various businesses are subject to the same numerous international, federal, state, and local environmental laws and regulations, as are other companies in the petroleum exploration and production; and refining, marketing and transportation of crude oil and refined products businesses. The most significant of these environmental laws and regulations include, among others, the:

•

Federal Clean Air Act, which governs air emissions;

•

Federal Clean Water Act, which governs discharges to water bodies;

•

Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), which imposes liability on generators, transporters, and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatened to occur;

•

Federal Resource Conservation and Recovery Act (RCRA), which governs the treatment, storage, and disposal of solid waste;

•

Federal Oil Pollution Act of 1990 (OPA90) under which owners and operators of onshore facilities and pipelines, lessees or permittees of an area in which an offshore facility is located, and owners and operators of vessels are liable for removal costs and damages that result from a discharge of oil into navigable waters of the United States;

•

Federal Emergency Planning and Community Right-to-Know Act (EPCRA) which requires facilities to report toxic chemical inventories with local emergency planning committees and responses departments;

•

Federal Safe Drinking Water Act which governs the disposal of wastewater in underground injection wells; and

•

U.S. Department of the Interior regulations, which relate to offshore oil and gas operations in U.S. waters and impose liability for the cost of pollution cleanup resulting from operations, as well as potential liability for pollution damages.

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These laws and their implementing regulations set limits on emissions and, in the case of discharges to water, establish water quality limits. They also, in most cases, require permits in association with new or modified operations. These permits can require an applicant to collect substantial information in connection with the application process, which can be expensive and time-consuming. In addition, there can be delays associated with notice and comment periods and the agency’s processing of the application. Many of the delays associated with the permitting process are beyond the control of the applicant.

Many states and foreign countries where we operate also have, or are developing, similar environmental laws and regulations governing these same types of activities. While similar, in some cases these regulations may impose additional, or more stringent, requirements that can add to the cost and difficulty of marketing or transporting products across state and international borders.

The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor easily determinable as new standards, such as air emission standards, water quality standards and stricter fuel regulations, continue to evolve. However, environmental laws and regulations are expected to continue to have an increasing impact on our operations in the United States and in most of the countries in which we operate. Notable areas of potential impacts include air emission compliance and remediation obligations in the United States. Under the Clean Air Act, the U.S. Environmental Protection Agency (EPA) has promulgated a number of stringent limits on air emissions and established a federally mandated operating permit program. Violations of the Clean Air Act and most other environmental laws and regulations are enforceable with civil and criminal sanctions.

The EPA has also promulgated specific rules governing the sulfur content of gasoline, known generically as the “Tier II Sulfur Rules,” which become applicable to our gasoline as early as 2004. To meet the requirements, we are implementing a compliance strategy that relies on the use of a combination of technologies, including our proprietary S Zorb technology. The estimated costs for implementing our strategy will be included in future budgeting for refinery compliance.

The EPA has also promulgated rules regarding the sulfur content in highway diesel fuel, which become applicable in 2006. In April 2003, the EPA proposed a rule regarding emissions from non-road diesel engines and limiting non-road diesel fuel sulfur content. If promulgated, this rule would significantly reduce non-road diesel fuel sulfur content limits as early as 2007. We are currently evaluating S Zorb systems for removing sulfur from diesel fuel in special applications. The refining industry is actively considering several advanced and conventional technologies for complying with these rules. Because the non-road rule is not final, we are still evaluating and developing capital strategies for future compliance and we cannot provide precise cost estimates at this time.

Additional areas of potential air-related impact are the proposed revisions to the National Ambient Air Quality Standards (NAAQS) and the Kyoto Protocol. In July 1997, the EPA promulgated more stringent revisions to the NAAQS for ozone and particulate matter. Since that time, final adoption of these revisions has been the subject of litigation (American Trucking Association, Inc. et al. v. United States Environmental Protection Agency) that eventually reached the U.S. Supreme Court during the fall of 2000. In February 2001, the U.S. Supreme Court remanded this matter, in part, to the EPA to address the implementation provisions relating to the revised ozone NAAQS. If adopted, the revised NAAQS could result in substantial future environmental expenditures for ConocoPhillips.

In 1997, an international conference on global warming concluded an agreement, known as the Kyoto Protocol, which called for reductions of certain emissions that contribute to increases in atmospheric greenhouse gas concentrations. The United States has not ratified the treaty codifying the Kyoto Protocol but may in the future. In addition, other countries where we have interests, or may have interests in the

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future, have made commitments to the Kyoto Protocol and are in various stages of formulating applicable regulations. Currently, it is not possible to accurately estimate the costs that we could incur to comply with such regulations, but such expenditures could be substantial.

We also are subject to certain laws and regulations relating to environmental remediation obligations associated with current and past operations. Such laws and regulations include CERCLA and RCRA and their state equivalents. Remediation obligations include cleanup responsibility arising from petroleum releases from underground storage tanks located at numerous past and present ConocoPhillips-owned and/or operated petroleum-marketing outlets throughout the United States. Federal and state laws require that contamination caused by such underground storage tank releases be assessed and remediated to meet applicable standards. In addition to other cleanup standards, many states have adopted cleanup criteria for methyl tertiary-butyl ether (MTBE) for both soil and groundwater. MTBE standards continue to evolve, and future environmental expenditures associated with the remediation of MTBE-contaminated underground storage tank sites could be substantial.

At RCRA permitted facilities, we are required to assess environmental conditions. If conditions warrant, we may be required to remediate contamination caused by prior operations. In contrast to CERCLA, which is often referred to as “Superfund,” the cost of corrective action activities under RCRA corrective action programs typically is borne solely by ConocoPhillips. Over the next decade, we anticipate that significant ongoing expenditures for RCRA remediation activities may be required, but such annual expenditures for the near term are not expected to vary significantly from the range of such expenditures we have experienced over the past few years. Longer term, expenditures are subject to considerable uncertainty and may fluctuate significantly.

We from time to time receive requests for information or notices of potential liability from the EPA and state environmental agencies alleging that we are a potentially responsible party under CERCLA or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain wastes attributable to our past operations. As of December 31, 2002, we reported we had been notified of potential liability under CERCLA and comparable state laws at 58 sites around the United States. At September 30, 2003, we had resolved four of these sites but had received six new notices of potential liability, leaving 60 sites where we have been notified of potential liability.

For most Superfund sites, our potential liability will be significantly less than the total site remediation costs because the percentage of waste attributable to us, versus that attributable to all other potentially responsible parties is relatively low. Although liability of those potentially responsible is generally joint and several for federal sites and frequently so for state sites, other potentially responsible parties at sites where we are a party typically have had the financial strength to meet their obligations, and where they have not, or where potentially responsible parties could not be located, our share of liability has not increased materially. Many of the sites at which we are 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, we may have no liability or attain a settlement of liability. Actual cleanup costs generally occur after the parties obtain EPA or equivalent state agency approval. There are relatively few sites where we are a major participant, and given the timing and amounts of anticipated expenditures, neither the cost of remediation at those sites nor such costs at all CERCLA sites, in the aggregate, is expected to have a material adverse effect on our competitive or financial condition.

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Remediation Accruals

We accrue for remediation activities when it is probable that a liability has been incurred and reasonable estimates of the liability can be made. These accrued liabilities are not reduced for potential recoveries from insurers or other third parties and are not discounted (except, if assumed in a purchase business combination, we record such costs on a discounted basis). Many of these liabilities result from CERCLA, RCRA and similar state laws that require us to undertake certain investigative and remedial activities at sites where we conduct, or once conducted, operations or at sites where ConocoPhillips-generated waste was disposed. The accrual also includes a number of sites we have identified that may require environmental remediation, but which are not currently the subject of CERCLA, RCRA or state enforcement activities. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the future, we may incur significant costs under both CERCLA and RCRA. Considerable uncertainty exists with respect to these costs, and under adverse changes in circumstances, potential liability may exceed amounts accrued as of September 30, 2003.

Remediation activities vary substantially in duration and cost from site to site, depending on the mix of unique site characteristics, evolving remediation technologies, diverse regulatory agencies and enforcement policies, and the presence or absence of potentially liable third parties. Therefore, it is difficult to develop reasonable estimates of future site remediation costs.

At September 30, 2003, our balance sheet included a total environmental accrual related to continuing operations of $1,101 million, compared with $743 million at December 31, 2002. The increase in accruals from year-end 2002, primarily resulted from evaluation of Conoco environmental liabilities during the purchase price allocation period. Final purchase price adjustments were recognized in the third quarter of 2003. We expect to incur the majority of these expenditures within the next 30 years.

Notwithstanding any of the foregoing, and as with other companies engaged in similar businesses, environmental costs and liabilities are inherent in our operations and products, and there can be no assurance that material costs and liabilities will not be incurred. However, we currently do not expect any material adverse affect upon our results of operations or financial position as a result of compliance with environmental laws and regulations.

OUTLOOK

In December 2002, we committed to and initiated a plan to sell a substantial portion of our U.S. retail marketing sites. We are actively marketing these assets in packages. We are in discussions with potential buyers and expect to complete the sale of the majority of these sites in 2003. These transactions will reduce our U.S. workforce by 18,500 employees. Included in this total are approximately 1,425 transportation and non-store marketing employees who will be entitled to approximately $68 million in previously accrued severance payments. In September 2003, we completed the sale of certain retail and dealer marketing sites in the Northeast. In early October 2003, we signed an agreement with Alimentation Couche-Tard Inc., a Canadian company, to sell our ownership of the capital stock of The Circle K Corporation. The sale includes 1,663 retail marketing outlets in 16 states and the Circle K brand, as well as the assignment of the franchise relationship with more than 350 franchised and licensed stores. As part of the agreement we will continue to supply approximately 1.2 billion gallons of gasoline per year for the next two to five years at market-based pricing. The transaction is subject to certain government and regulatory reviews, and is expected to close in the fourth quarter of 2003.

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In February 2003, the Venezuelan government implemented a currency exchange control regime. The government has published legal instruments supporting the controls, one of which establishes official exchange rates for the U.S. dollar. Changes in the exchange rate could have a significant impact on our Venezuelan operations.

During the second quarter of 2003, draft legislation was introduced in the Canadian Parliament regarding federal tax rate reductions for oil and gas producers and was enacted in November 2003. We expect to recognize a significant earnings benefit upon revaluation of our deferred tax liability in the fourth quarter of 2003, the amount of which will be determined after a thorough evaluation and review of the legislation, currently being undertaken, has been completed.

In March 2003, our Board of Directors approved a plan to further develop the Ekofisk Area in the Norwegian North Sea to increase the recovery of oil and gas from the area by improving the area’s processing capacity and reliability. Our co-venturers have also approved the plan for the further development of PL018. The Ekofisk growth project consists of two interrelated components: the construction and installation of a new platform, named Ekofisk 2/4 M and an increase in capacity from existing facilities. The Ekofisk 2/4 M platform will be a steel wellhead and process platform that will be located southeast of the existing Ekofisk 2/4 J platform and will have 30 well slots, a high-pressure separator, equipment for produced water treatment, and risers for tie-in of future projects. We expect to complete and install the steel jacket in 2004 and the topsides early in the summer of 2005. Additional production from this development is anticipated to begin in the fall of 2005. We are modifying the existing Ekofisk Complex and four additional platforms to increase processing capacity.

In April 2003, the Control Committee, comprised of representatives of the Venezuelan Ministry of Energy and Mines, Petroleos de Venezuela S. A. (PDVSA), and co-venturers, approved Phase I of the development plan for the Corocoro field in Venezuela’s Gulf of Paria West area. We are the operator and currently hold a 50 percent working interest in the Gulf of Paria West Block. Under the terms of the Gulf of Paria West Block profit sharing agreement with the Venezuelan government, Corporación Venezolana de Petróleo (a subsidiary of PDVSA) has elected to acquire a 35 percent participating interest in the Corocoro discovery, which will reduce our working interest to 32.5 percent. Bids for the major capital construction elements of Phase I of the Corocoro development are being evaluated. In September 2003, we acquired a 37.5 percent interest in the Gulf of Paria East Block. A portion of the Corocoro discovery extends onto this Block.

In May 2003, we received regulatory approval from the Alberta Energy and Utilities Board for our Surmont oil sands project in Northern Alberta, Canada. We are the operator of the Surmont lease with a 43.5 percent interest. In October 2003, ConocoPhillips’ Board of Directors approved our share of the project, with a provision to proceed at a higher share, up to 100 percent, in the event a partner or partners do not elect to proceed. Partner approval is expected and they must provide their election by mid-December 2003. First oil production could begin in the second half of 2006.

Also, in June 2003, we and our co-venturers in the Mackenzie Gas Project in Canada announced that funding and participation agreements have been reached and a Preliminary Information Package (PIP) was submitted to relevant regulatory authorities. The Mackenzie Gas Project involves natural gas production facilities, compression and gathering pipelines in the Mackenzie Delta area, and a pipeline system in the Mackenzie River Valley. The filing of the PIP is a key step in the process leading to the submission of applications for the development of the natural gas fields and pipeline facilities. Regulatory applications could be filed in 2004.

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In July 2003, we announced that we had signed a Heads of Agreement with Qatar Petroleum for the development of Qatargas 3, a large-scale LNG project located in Qatar and servicing the U.S. natural gas market. The agreement provides the framework for the necessary agreements and the completion of key feasibility studies. Qatargas 3 would be an integrated project, jointly owned by Qatar Petroleum and ConocoPhillips, consisting of facilities to produce and liquefy gas from Qatar’s North field. The LNG would be shipped from Qatar and we would be responsible for regasification and marketing it within the United States. Average daily gas sales volumes are projected to be approximately 1 billion cubic feet per day with startup anticipated to be in the 2008-2009 timeframe.

On July 21, 2003, we experienced a fire at our 194,000 barrel-per-day refinery in Ponca City, Oklahoma. The fire involved a gas processing unit, an 85,000 barrel-per-day crude distillation unit and a desulfurization unit. The refinery ran at reduced rates through the remainder of the third quarter, losing about 65,000 barrels per day of crude oil throughput in the quarter. In mid-October, the No. 1 crude unit came back on line at reduced rates. Restoration of the refinery to full capacity should occur by the end of November 2003.

In late October 2003, we signed a Heads of Agreement with the Nigerian National Petroleum Corporation, ENI and ChevronTexaco to conduct front-end engineering and design (FEED) work for an LNG facility to be constructed in Nigeria’s central Niger Delta. The participants have agreed to form an incorporated joint venture, Brass LNG Limited, to undertake the project. The FEED studies are expected to be completed in 2004, and the facility is targeted to be operational at the end of 2008.

In E&P, we expect our worldwide production for the fourth quarter of 2003 to be above our third quarter level, primarily because of seasonal increases in the United Kingdom, Norway and Alaska, as well as a full quarter’s production from the Grane field in the Norwegian North Sea and the startup of production in the Su Tu Den field in Vietnam.

In R&M, we expect our average refinery crude oil utilization rate for the fourth quarter of 2003 to exceed 90 percent.

Crude oil and natural gas prices are subject to external factors over which we have no control, such as global economic conditions, political events, demand growth, inventory levels, weather, competing fuels prices and availability of supply. Crude oil prices rose slightly in the third quarter to very high levels due to the slower-than-expected return of Iraqi crude production to the market, while other Organization of Petroleum Exporting Countries (OPEC) members exercised significant production discipline to make room for Iraqi crude. Flat OPEC production in the face of a sharp seasonal rise in oil product demand resulted in oil inventories remaining at exceptionally low levels during the third quarter. These same factors, bolstered by a substantial OPEC production cut scheduled for November 1 could keep prices elevated through the remainder of the year. U.S. natural gas prices weakened moderately during the third quarter from the very strong levels experienced during the second quarter due to a significant buildup of natural gas inventories as mild weather, weak industrial demand and fuel switching reduced natural gas demand at the same time that high prices and the startup of a mothballed regasification terminal significantly increased LNG imports to the United States. However, natural gas prices rose moderately at the end of the third quarter, reflecting continuing concerns about the adequacy of supplies this winter.

Refining margins are subject to movements in the price of crude oil and other feedstocks, and the prices of petroleum products, which are subject to market factors over which we have no control, such as the U.S. and global economies; government regulations; military, political and social conditions in oil producing countries; seasonal factors that affect demand, such as the summer driving months; and the levels of refining output and product inventories. U.S. refining margins rose in the third quarter versus the second

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quarter but improved margins were partially offset by weaker marketing margins. U.S. refining margins rose in the third quarter due to strong gasoline demand in August and an unusual number of refined product supply disruptions, including refinery outages in the Midwest caused by the power blackout on August 14, 2003. Marketing margins weakened in the third quarter because street prices could not keep pace with the strengthening of refined product supply costs. The sustainability of current refining and marketing margins depends on the continued recovery of the global economy and oil demand growth.

CAUTIONARY STATEMENT FOR THE PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

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

We have based the forward-looking statements relating to ConocoPhillips’ operations on its current expectations, estimates and projections about ConocoPhillips and the industries in which it operates in general. We caution you that these statements are not guarantees of future performance and involve risks, uncertainties and assumptions that we cannot predict. In addition, we have based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, ConocoPhillips’ actual outcomes and results may differ materially from what we have expressed or forecast in the forward-looking statements. Any differences could result from a variety of factors, including the following:

•

fluctuations in crude oil, natural gas and natural gas liquids prices, refining and marketing margins and margins for ConocoPhillips’ chemicals business;

•

changes in the business, operations, results and prospects of ConocoPhillips;

•

the operation and financing of ConocoPhillips’ midstream and chemicals joint ventures;

•

potential failure to realize fully or within the expected time frame the expected cost savings and synergies from the combination of Conoco and Phillips;

•

costs or difficulties related to the integration of the businesses of Conoco and Phillips, as well as the continued integration of businesses recently acquired by each of them;

•

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;

•

unsuccessful exploratory drilling activities;

•

failure of new products and services to achieve market acceptance;

•

unexpected cost increases or technical difficulties in constructing or modifying facilities for exploration and production projects, manufacturing or refining;

•

unexpected difficulties in manufacturing or refining ConocoPhillips’ refined products, including synthetic crude oil, and chemicals products;

•

lack of, or disruptions in, adequate and reliable transportation for ConocoPhillips’ crude oil, natural gas, natural gas liquids and refined products;

•

inability to timely obtain or maintain permits, comply with government regulations or make capital expenditures required to maintain compliance;

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•

failure to complete definitive agreements and feasibility studies and to timely complete construction and related facilities, for announced and future LNG projects;

•

potential disruption or interruption of ConocoPhillips’ facilities due to accidents, political events or terrorism;

•

international monetary conditions and exchange controls;

•

liability for remedial actions, including removal and reclamation obligations, under environmental regulations;

•

liability resulting from litigation;

•

general domestic and international economic and political conditions, including armed hostilities and governmental disputes over territorial boundaries;

•

changes in tax and other laws or regulations applicable to ConocoPhillips’ business; and

•

inability to obtain economical financing for exploration and development projects, construction or modification of facilities and general corporate purposes.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information about market risks for the three and nine months ended September 30, 2003, does not differ materially from that discussed under Item 7A of ConocoPhillips’ Annual Report on Form 10-K for the year ended December 31, 2002; however, during October and November we executed certain interest rate swaps to convert $1.5 billion of debt from fixed to floating rate in order to increase the company’s exposure to floating interest rates. Had these swaps been in place at September 30, 2003, our percent of floating-rate debt to total debt would have been 19 percent. These swaps qualify for hedge accounting under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.”

Item 4. CONTROLS AND PROCEDURES

As of September 30, 2003, with the participation of our management, our President and Chief Executive Officer and our Executive Vice President, Finance, and Chief Financial Officer carried out an evaluation of the effectiveness of the design and operation of ConocoPhillips’ disclosure controls and procedures pursuant to Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended. Based upon that evaluation, our President and Chief Executive Officer and our Executive Vice President, Finance, and Chief Financial Officer concluded that our disclosure controls and procedures were operating effectively as of September 30, 2003.

There have been no changes in our internal control over financial reporting, as defined in Rule 13a-15(f) of the Securities Exchange Act, that occurred during the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

There have been no material developments with respect to the legal proceedings previously reported in our 2002 Annual Report on Form 10-K or 2003 Second Quarter Report on Form 10-Q.

On August 24, 2003, the Contra Costa County District Attorney’s Office in California issued a demand letter to ConocoPhillips seeking civil penalties in the amount of $524,000 for 31 alleged violations of the Bay Area Air Quality Management District regulations at the company’s Rodeo facility of the San Francisco area refinery. These alleged violations cover the period from mid-2001 through August 2003. We are currently working with the Contra Costa County District Attorney’s Office towards a negotiated resolution of this matter.

On September 17, 2003, the United States Environmental Protection Agency (U.S. EPA) Region 10 notified ConocoPhillips of its intent to assess civil penalties for alleged National Pollution Discharge Elimination System (NPDES) permit violations at the company’s Tyonek offshore platform located near Cook Inlet, Alaska. Although U.S. EPA Region 10 has not yet assessed or sought a specific penalty amount, we believe that such penalty, if assessed, could be in excess of $100,000. The alleged violations arise from the company’s July 2003 NPDES self-disclosure report to U.S. EPA Region 10. We are currently working with U.S. EPA Region 10 towards a negotiated resolution of this matter.

In December 2002, the Louisiana Department of Environmental Quality (LDEQ) notified ConocoPhillips of its intent to assess civil penalties for over 120 alleged regulatory violations at various Circle K stores in the Baton Rouge, Louisiana area. On October 6, 2003, the LDEQ notified ConocoPhillips that the civil penalty assessment for these alleged violations is $189,659. We are currently working with the LDEQ towards a negotiated resolution of this matter.

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; and claims for damages resulting from leaking underground storage tanks, or other accidental releases, with related toxic tort claims. As a result of Conoco’s separation agreement with DuPont, we also have assumed responsibility for current and future claims related to certain discontinued chemicals and agricultural chemicals businesses operated by Conoco in the past. In general, the effect on future financial results is not subject to reasonable estimation because considerable uncertainty exists. The ultimate liabilities resulting from such lawsuits and claims may be material to results of operations in the period in which they are recognized.

Item 6. EXHIBITS AND REPORTS ON FORM 8-K

Exhibits

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Reports on Form 8-K

During the three months ended September 30, 2003, ConocoPhillips furnished the following Current Report on Form 8-K:

•

Current Report furnished July 30, 2003, reporting Item 7 and Item 12.

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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.

November 11, 2003

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INDEX TO EXHIBITS

Exhibit
Number		Description
12		Computation of Ratio of Earnings to Fixed Charges.
31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32		Certifications Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

Exhibit 12

CONOCOPHILLIPS AND CONSOLIDATED SUBSIDIARIES
TOTAL ENTERPRISE

Computation of Ratio of Earnings to Fixed Charges

    *Includes amortization of capitalized interest totaling approximately $19 million in 2003 and $22 million in 2002.
  **Restated for discontinued operations
***2003 reflects the impact of FIN 46.

Earnings available for fixed charges include, if any, our equity in losses of companies owned less than fifty percent and having debt for which the company is contingently liable. Fixed charges include our proportionate share, if any, of interest relating to the contingent debt.

Earnings available for fixed charges include, if any, 100 percent of the losses of companies owned greater than fifty percent that have debt for which we are contingently liable. Fixed charges include 100 percent of interest and capitalized interest, if any, relating to the contingent debt.

 

Exhibit 31.1

CERTIFICATIONS

I, J. J. Mulva, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of ConocoPhillips;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c)

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

 

Exhibit 31.2

CERTIFICATIONS

I, John A. Carrig, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of ConocoPhillips;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c)

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

 

Exhibit 32

CERTIFICATIONS PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED
PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

     In connection with the Quarterly Report of ConocoPhillips (the company) on Form 10-Q for the period ending September 30, 2003, as filed with the U.S. Securities and Exchange Commission on the date hereof (the Report), each of the undersigned hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to their knowledge:

(1)

The Report fully complies with the requirements of Sections 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the company.