UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

(Mark One)

OR

ConocoPhillips

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes    X    No       

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes    X    No       

The registrant had 690,233,100 shares of common stock, $.01 par value, outstanding at September 30, 2004.

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

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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 of Financial Condition and Results of Operations and the consolidated financial statements and notes included in ConocoPhillips’ 2003 Annual Report on Form 10-K. Certain amounts in the 2003 financial statements included in this report on Form 10-Q have been reclassified to conform to ConocoPhillips’ 2004 presentation and restated for the adoption of Financial Accounting Standards Board (FASB) Interpretation No. 46, “Consolidation of Variable Interest Entities,” (FIN 46).

Note 2—Accounting Policies

Revenue Recognition—Revenues associated with the sale of crude oil, natural gas, natural gas liquids, petroleum and chemical products, and other items are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery of goods occurs, either immediately or within a fixed delivery schedule that is reasonable and customary in the industry. Revenues include the sales portion of contracts involving physical commodity purchases and sales necessary either to reposition refinery feedstock supply to address location, quality or grade requirements (for example, where we reposition crude oil feedstock supply by entering into a contract with a counterparty to sell crude oil in one location and purchase it in a different location closer to our refinery) or sales related to purchase for resale activity necessary to supply our wholesale commodity businesses (for example, where we enter into a contract with a counterparty to sell refined products or natural gas volumes at one location and purchase similar volumes at another location closer to our wholesale customer). Our commercial group uses commodity derivative contracts (such as futures and options) in various markets to optimize the value of our supply chain and balance physical systems. In addition to cash settlement prior to contract expiration, exchange traded futures contracts may also be settled by physical delivery of the commodity, providing another source of supply to meet our refinery requirements or marketing demand. See Note 1—Accounting Policies—Derivative Instruments in our 2003 Form 10-K for additional information on our accounting for, and reporting of, commodity derivative contracts.

Revenues from the production of natural gas properties, in which we have an interest with other producers, are recognized based on the actual volumes we sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, which are deemed non-recoverable through remaining production, are recognized as accounts receivable or accounts payable, as appropriate. Cumulative differences between volumes sold and entitlement volumes are generally not significant. Revenues associated with royalty fees from licensed technology are recorded based either upon volumes produced by the licensee or upon the successful completion of all substantive performance requirements related to the installation of licensed technology.

Exploratory Costs—Geological and geophysical costs and the costs of carrying and retaining undeveloped properties are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found of a sufficient quantity to justify completion of the find as a producing well. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. All exploratory wells are evaluated for economic

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viability within one year of well completion. This determination of the success of drilling results, related to areas that do not require a major infrastructure capital expenditure (e.g., a pipeline or an offshore platform), corresponds with the time period of reporting proved oil and gas reserves for the find. Exploratory wells that discover economic reserves that are in areas where a major infrastructure capital expenditure would be required before production could begin, and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory drilling work in the area, remain capitalized as long as the additional exploratory drilling work is under way or firmly planned. In these situations, the well is considered to have found economic reserves if recoverable reserves have been found of a sufficient quantity to justify completion of the find as a producing well, assuming that the major infrastructure capital expenditure had already been made. Once all additional exploratory drilling work has been completed on projects requiring major infrastructure capital expenditures, the economic viability of the overall project is evaluated within one year of the last exploratory well completion. If considered to be economically viable, internal company approvals are then obtained to move the overall project toward a development stage project. If joint-venture partner and government approvals are required before development expenditures can begin, exploratory well costs remain capitalized as long as the company is actively pursuing such approvals and believes such approvals will be obtained. Once all required approvals have been obtained, such projects are moved into development stage status, which corresponds with the time period of reporting proved oil and gas reserves for the find.

Stock-Based Compensation—Effective January 1, 2003, we voluntarily adopted the fair-value accounting method provided under Statement of Financial Accounting Standards (SFAS) No. 123, “Accounting for Stock-Based Compensation.” Using the SFAS No. 123 prospective transition method, we apply the fair-value accounting method and recognize compensation expense equal to the fair-market value on the grant date for all stock options granted or modified after December 31, 2002.

Employee stock options granted prior to 2003 continue to be accounted for under Accounting Principles Board (APB) No. 25, “Accounting for Stock Issued to Employees,” and related Interpretations. Because the exercise price of our employee stock options equals the market price of the underlying stock on the date of grant, no compensation expense is generally recognized under APB No. 25. The following table displays pro forma information as if provisions of SFAS No. 123 had been applied to all employee stock options granted:

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Note 3—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. The cumulative effect of the change increased 2003 net income by $145 million (after reduction of income taxes of $21 million).

Consolidation of Variable Interest Entities
In January 2003, the FASB issued 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 December 2003, the FASB issued a revision to FIN 46 to clarify some of the provisions and to exempt certain entities from its guidance. The consolidation requirements of FIN 46, as revised, apply to all special purpose entities for periods ending after December 15, 2003. For all other types of variable interest entities the consolidation requirement applies for periods ending after March 15, 2004.

In the third quarter of 2003, with retroactive application to January 1, 2003, we adopted FIN 46 for variable interest entities (VIEs) involving synthetic leases and certain other financing structures. In the fourth quarter of 2003, also retroactive to January 1, 2003, we made an $18 million adjustment to Cumulative Effect of Changes in Accounting Principles related to our adoption of FIN 46. Accordingly, our financial statements for the nine months of 2003 have been restated from amounts previously reported in the financial statements included in our Form 10-Q for the quarter ended September 30, 2003. The cumulative effect of this adoption of FIN 46 decreased 2003 net income $240 million (after an income tax benefit of $145 million). We consolidated all VIEs in which we concluded that we were the primary beneficiary. In addition, we deconsolidated an entity where we determined we were not the primary beneficiary. The provisions of FIN 46, which became effective for periods ending after March 15, 2004, did not change our analysis of any of the entities we consolidated or deconsolidated in 2003.

In February 2003, we entered into two agreements establishing separate guarantee facilities of $50 million each for two liquefied natural gas ships that were then under construction. Subject to the terms of each facility, we will be required to make payments should the charter revenue generated by the respective 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 two agreements could be up to an aggregate of $100 million. Actual gross payments over the 20 years could exceed that amount to the extent cash is received by us. In September 2003, the first ship was delivered to its owner and the second ship is scheduled for delivery to its owner in 2005. At December 31, 2003, we reported these two entities could potentially be VIEs, but that we had been unable to obtain sufficient information to confirm that the entities were VIEs or to determine if we were the primary beneficiary. In the first quarter of 2004, we received the required information related to the entity associated with the first ship and determined that it was a VIE; however, because we are not the primary beneficiary we did not consolidate the entity. With regard to the second ship, we will have a variable interest in the associated entity once the ship is delivered to its owner in 2005. At that time, we will determine if the entity is a VIE, and if we are the primary beneficiary. We continue to account for these agreements as guarantees and contingent liabilities. See Note 11—Guarantees for additional information.

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Note 4—Discontinued Operations

During 2003 and the first nine months of 2004, we disposed of, or held for sale, certain midstream, refining, and marketing assets, which are classified as discontinued operations. We sold our Mobil-branded marketing assets on the East Coast in two separate transactions in the second quarter of 2004. As a result of these and other smaller transactions, we recorded a net after-tax gain of approximately $116 million in the nine-month 2004 period. Discussions are under way with potential buyers for the remaining marketing assets held for sale.

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

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 includes 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.

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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, which resulted in a gain of $28 million before-tax, $25 million after-tax, in 2003. This non-operating gain is shown in the consolidated statement of income in the line item entitled “Gain on subsidiary equity transactions.”

Note 6—Inventories

Inventories consisted of the following:

Inventories valued on a last-in, first-out (LIFO) basis totaled $3,665 million and $3,224 million at September 30, 2004, and December 31, 2003, respectively. The remainder of our inventories are valued under various methods, including first-in, first-out and weighted average. The excess of current replacement cost over LIFO cost of inventories was $3,629 million and $1,421 million at September 30, 2004, and December 31, 2003, respectively.

Note 7—Properties, Plants and Equipment

Properties, plants and equipment included the following:

E&P properties, plants and equipment at September 30, 2004, and December 31, 2003, included approximately $9.7 billion and $10.5 billion, respectively, of mineral rights to extract oil and gas, net of accumulated depletion.

Property Impairments—In the third quarter and first nine months of 2004, we recorded property impairments related to planned dispositions in our Midstream, Exploration and Production (E&P) and Refining and Marketing (R&M) segments. In the third quarter and first nine months of 2003, we recorded property impairments as a result of planned asset dispositions, unsuccessful development drilling results, and Norway tax law changes dealing with the treatment of asset removal costs. The amount of property impairments by segment were:

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Note 8—Restructuring

As a result of the 2002 merger of Conoco Inc. and Phillips Petroleum Company that formed ConocoPhillips, we recognized an estimated restructuring liability for anticipated employee severance payments and incremental pension and medical plan benefit costs associated with workforce reductions, site closings, and Conoco employee relocations. In connection with this program, we recorded accruals in 2002 of $770 million and in 2003, as individual components of the restructuring program were finalized, we recorded an additional $350 million, of which $316 million was accrued in the first nine months of 2003, including $91 million in the third quarter. Included in the total 2002 and 2003 accruals of $1,120 million was a $290 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. Of the $316 million accrued in the first nine months of 2003, $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 accruals of $316 million was a $92 million expense related to pension and other postretirement benefits. In the first nine months of 2004, we recorded additional accruals totaling $34 million, of which $28 million was reflected in the consolidated financial statements as selling, general and administrative expense and production and operating expense, and $6 million was reflected as foreign currency translation adjustment. Included in the total accruals of $34 million was a $4 million expense related to pension and postretirement benefits. A roll-forward of activity during the first nine months of 2004 is provided below for the non-pension portion of the accruals, which primarily consists of severance-related benefits to be provided based on agreed upon payment schedules to approximately 3,950 employees worldwide, most of whom are in the United States, as well as other merger-related expenses.

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The ending accrual balance at September 30, 2004, is expected to be extinguished within one year, except for $57 million, which is classified as long-term. Approximately 950 employees were terminated during the first nine months of 2004, and essentially all 3,950 employee terminations under the restructuring program have now been completed.

Note 9—Debt

At September 30, 2004, we had four 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 $1.5 billion, 364-day revolving credit facility expiring on October 13, 2004; two revolving credit facilities totaling $2 billion expiring in October 2006; and a $500 million five-year facility expiring in October 2008. At September 30, 2004, we had no debt outstanding under these credit facilities, but had $1 billion of commercial paper outstanding, compared with $709 million of commercial paper at December 31, 2003. The commercial paper is supported 100 percent by the credit facilities and the amount approximates fair value. One of our Norwegian subsidiaries had two $300 million revolving credit facilities that expired in June 2004, which were not renewed.

On October 12, 2004, we replaced the four bank credit facilities noted above with two facilities totaling $5 billion and increased our commercial paper program from $4 billion to $5 billion. The facilities include a $2.5 billion four-year facility expiring in October 2008 and a $2.5 billion five-year facility expiring in October 2009. Both facilities are available for use as direct bank borrowings or as support for our $5 billion commercial paper program. In addition, the five-year facility may be used to support issuances of letters of credit totaling up to $750 million. The facilities are syndicated among 40 financial institutions and do not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or ratings. The credit agreements do contain a cross-default provision relating to our, or any of our consolidated subsidiaries’, failure to pay principal or interest on other debt obligations of $200 million or more.

During the first nine months of 2004, we paid off the $1,350 million aggregate principal amount of our 5.90% Notes due 2004 when they matured in April, and in August, we redeemed the $1,150 million aggregate principal amount of our 8.5% Notes due 2005 at a premium of $58 million plus accrued interest.

On October 14, 2004, we amended and restated the ConocoPhillips Savings Plan term loan. This loan will require repayment in semi-annual installments beginning in 2009 and continuing through 2015. Under this loan, any participating bank in the syndicate of lenders may cease to participate on December 4, 2009, by giving not less than 180 days’ prior notice to the ConocoPhillips Savings Plan and the company. At September 30, 2004, $259 million was outstanding under this term loan.

Note 10—Contingencies

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.

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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 also consider unasserted claims in our determination of environmental liabilities and we accrue them in the period that they become 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 we were solely responsible, the costs, in some cases, could be material to our, or one of our segments’, results of 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, we 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 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 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, we make accruals on an undiscounted basis (except those assumed in a purchase business combination, which we record 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. At September 30, 2004, ConocoPhillips’ balance sheet included a total environmental accrual of $1,148 million, compared with $1,119 million at December 31, 2003. 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.

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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 performance obligations that are secured by unused letters of credit and various purchase commitments for materials, supplies, services and items of permanent investment incident to the ordinary conduct of business.

Note 11—Guarantees

At September 30, 2004, 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

	•		In May 2004, the Merey Sweeny, L.P. (MSLP) joint-venture project at the Sweeny refinery in Old Ocean, Texas, achieved completion certification. As a result, the previously disclosed construction completion guarantee related to the debt and bond financing arrangements secured by MSLP expired and the debt became non-recourse to ConocoPhillips.
	•		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 $420 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.

Guarantees of Joint-Venture Debt

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At September 30, 2004, we had guarantees of about $275 million outstanding for our portion of joint-venture debt obligations, which have terms of up to 20 years. Included in these outstanding guarantees was $95 million associated with the Polar Lights Company joint venture in Russia. Payment will be required if the joint venture defaults on its debt obligations.

Other Guarantees

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The MSLP joint-venture project agreement requires the partners in the venture to pay cash calls to cover operating expenses in the event that the venture does not have enough cash to cover operating expenses after setting aside the amount required for debt service over the next 20 years. Although there is no maximum limit stated in the agreement, the intent is to cover short-term cash deficiencies should they occur. Our maximum potential future payments under the agreement are currently estimated to be $100 million, assuming such a shortfall exists at some point in the future due to an extended operational disruption. If such an operational disruption did occur, MSLP has business interruption insurance and would be entitled to insurance proceeds subject to deductibles and certain limits.

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	•		In February 2003, we entered into two agreements establishing separate guarantee facilities for $50 million each for two liquefied natural gas vessels. Subject to the terms of each such facility, we will be required to make payments should the charter revenue generated by the respective 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 that we may have to make over the 20-year terms of the two agreements could be up to an aggregate of $100 million. Actual gross payments over the 20 years could exceed that amount to the extent cash is received by us. In the event either ship is 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. At the time of the agreement, based on the then current market view of both long-term and short-term shipping capacity, rates and utilization probability, we estimated the fair value of the liability under these guarantee facilities to be immaterial. In September 2003, the first ship was delivered to its owner and the second ship is scheduled for delivery to its owner in 2005. With respect to the first ship, the amount drawn under the guarantee facility at September 30, 2004, was less than $1 million.
	•		We have other guarantees totaling $310 million, which consist primarily of dealer and jobber loan guarantees to support our marketing business, a guarantee to fund the short-term cash liquidity deficits of a lubricants joint venture, a guaranteed revenue deficiency payment to a pipeline joint venture, a guarantee supporting a lease assignment on a corporate aircraft, a guarantee associated with a pending lawsuit and guarantees of the lease payment obligations of a joint venture. The carrying amount recorded for these other guarantees, as of September 30, 2004, was $13 million. These guarantees generally extend up to 15 years and payment would only be required if the dealer, jobber or lessee goes into default, if the lubricants joint venture has cash liquidity issues, if the pipeline joint venture has revenue below a certain threshold, or if an adverse decision occurs in the lawsuit.

Indemnifications

	•		Over the years, we have entered into various agreements to sell ownership interests in certain corporations and joint ventures. 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. 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 arrangements.
	•		During 2003 and the first nine months of 2004, we sold several assets, including FTC-mandated sales of downstream and midstream assets, certain exploration and production assets, and downstream retail and wholesale sites, giving rise to qualifying indemnifications. Agreements associated with these sales include indemnifications for taxes, environmental liabilities, underground storage tank repairs or replacements, permits and licenses, employee claims, real estate indemnity against tenant defaults, and litigation. The terms of these indemnifications vary greatly. The majority of these indemnifications are related to environmental issues, the term is generally indefinite and the maximum amount of future payments is generally unlimited. The carrying amount recorded for these indemnifications, as of September 30, 2004, was $240 million. We amortize the indemnification liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of indemnity. In cases where the indemnification term is indefinite, we will reverse the liability when we have information that the liability is essentially relieved or amortize the liability over an appropriate time period as the fair value of our indemnification exposure declines. Although it is reasonably possible that future payments may exceed amounts recorded, due to the nature of the indemnifications, it is not possible to make a

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			reasonable estimate of the maximum potential amount of future payments. Included in the carrying amount recorded were $121 million of environmental accruals for known contamination that is included in asset retirement obligations and accrued environmental costs at September 30, 2004. For additional information about environmental liabilities, see Note 10—Contingencies.
	•		As part of our normal ongoing business operations and consistent with 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 cost 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 of our indemnity obligations are not limited in duration or potential monetary exposure, we cannot calculate a reasonable estimate of the maximum potential amount of future payments that might have to be paid under indemnity obligations stemming from our existing agreements. The carrying amount recorded for these indemnifications, as of September 30, 2004, was $236 million, which is for known contamination and is included in asset retirement obligations and accrued environmental costs. For additional information about environmental liabilities and contingencies, see Note 10—Contingencies.

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Note 12—Comprehensive Income

ConocoPhillips’ comprehensive income was as follows:

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

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Note 13—Supplemental Cash Flow Information

Note 14—Sales of Receivables

At September 30, 2004, certain credit card and trade receivables had been sold 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. All five bank-sponsored entities are multi-seller conduits with access to the commercial paper market and purchase interests in similar receivables from numerous other companies unrelated to us. We have no ownership interests, nor any variable interests, in any of the bank-sponsored entities. As a result, we do not consolidate any of these entities. Furthermore, we do not consolidate the QSPE because it meets the requirements of SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” to be excluded from the consolidated financial statements of ConocoPhillips.

At September 30, 2004, and December 31, 2003, the QSPE had issued beneficial interests to the bank-sponsored entities of $600 million and $1.2 billion, respectively. The receivables transferred to the QSPE met the isolation and other requirements of SFAS No. 140 to be accounted for as sales and were accounted for accordingly.

We retain beneficial interests in the QSPE that are subordinate to the beneficial interests issued to the bank-sponsored entities. These retained interests, which are reported on the balance sheet in accounts and notes receivable—related parties, were $2.4 billion at September 30, 2004, and $1.3 billion at December 31, 2003. We also retain servicing responsibility related to the sold receivables, which gives us certain rights and abilities, the fair value of which approximates the fair value of the liability incurred for continuing to service the receivables. The carrying value of our subordinated beneficial interests in the QSPE approximates fair market value due to the very short term of the underlying assets, which makes fair value stress testing for disclosure purposes unnecessary.

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Total cash flows received from and paid under the securitization arrangements were as follows:

The decrease in cash flow activity in 2004 was primarily due to reductions in the average level of beneficial interests issued to the bank-sponsored entities.

At December 31, 2003, we had sold $226 million of receivables under factoring arrangements. We retained servicing responsibility related to those sold receivables, which gave us certain benefits, the fair value of which approximated the fair value of the liability incurred for continuing to service the receivables. At September 30, 2004, we had no receivables outstanding under similar arrangements.

Note 15—Employee Benefit Plans

Pension and Postretirement Plans

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We recognized pension settlement losses of $9 million and $93 million in the first nine months of 2004 and 2003, respectively, due to high levels of lump-sum elections by new retirees in certain plans. Of these amounts, $1 million and $11 million were recognized in the third quarters of 2004 and 2003, respectively.

In December 2003, the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (Act) was signed into law. The Act introduced a prescription drug benefit under Medicare (Medicare Part D), as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. In May 2004, the FASB released Staff Position FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003,” which requires that we reflect the effect of the Act in our third quarter 2004 financial statements. We have determined, based on available regulatory guidance, that the prescription drug benefits provided by our retiree medical plan are not actuarially equivalent to the Medicare Part D benefit. Consequently, the federal subsidy will have no impact on the calculation of our medical plan liability or expense. We continue to evaluate the impact of the legislation on our benefit plan design.

In our second quarter 2004 Report on Form 10-Q, we disclosed that our 2004 contributions were expected to be approximately $425 million to our domestic qualified and non-qualified benefit plans and $125 million to our international qualified and non-qualified benefit plans. We now anticipate contributing $440 million to our domestic plans and $135 million to our international plans in 2004.

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, and Hamaca Holding LLC 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 upgraded 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 and a price upgrade to MSLP for heavy crude processing.

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(c)		We pay processing fees to various affiliates. Additionally, we pay crude oil transportation fees to pipeline equity companies.
(d)		We pay and/or receive interest to/from various affiliates including the receivables securitization QSPE.

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, 2004, E&P was producing in the United States, Norway, the United Kingdom, Canada, Nigeria, Venezuela, offshore Timor Leste in the Timor Sea, Australia, China, Indonesia, the United Arab Emirates, Vietnam, and Russia. 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 purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia. At September 30, 2004, 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 of our 50 percent equity investment in CPChem.
(5)		Emerging Businesses—This segment encompasses the development of new businesses beyond our traditional operations. Emerging Businesses includes new technologies related to natural gas conversion into clean fuels and related products (gas-to-liquids), technology solutions, power generation and emerging technologies.

Corporate and Other includes general corporate overhead, all interest income and expense, discontinued operations, restructuring charges 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 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

Our effective tax rates for the third quarter and first nine months of 2004 were 45 percent and 44 percent, respectively, compared with 46 percent for the same periods a year ago. There were not any material changes in the effective tax rate between the third quarter of 2004 and the third quarter 2003. The reduction in the effective tax rate for the first nine months of 2004, versus the same period in 2003, was mainly due to the impact of a higher proportion of income in lower tax rate jurisdictions. The effective tax rate in excess of the domestic federal statutory rate of 35 percent was primarily due to foreign taxes in excess of the domestic federal statutory rate.

Note 19—Minority Interests

On July 8, 2004, we retired the minority interest in Conoco Corporate Holdings L.P. The minority limited partner in Conoco Corporate Holdings L.P., a limited-life entity, was entitled to a cumulative annual 7.86 percent priority return on its investment. That net minority interest was $141 million at June 30, 2004, and December 31, 2003.

Note 20—New Accounting Standards

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, already effective for contracts created or modified after May 31, 2003, was originally intended to become effective July 1, 2003, for all contracts existing at May 31, 2003. However, on November 7, 2003, the FASB issued an indefinite deferral of certain provisions of SFAS No. 150. We continue to monitor and assess the FASB’s modifications of SFAS No. 150, but do not anticipate any material impact to our financial statements.

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In December 2003, the FASB revised and reissued SFAS No. 132 (revised 2003), “Employer’s Disclosures about Pensions and Other Postretirement Benefits—an amendment of FASB Statements No. 87, 88 and 106.” While requiring certain new disclosures, the revised Statement does not change the measurement or recognition of employee benefit plans. We adopted the provisions of the Statement effective December 2003, except for certain provisions regarding disclosure of information about estimated future benefit payments, which are not required until the fourth quarter of 2004.

In January 2004 and May 2004, the FASB issued FASB Staff Position Nos. 106-1 and 106-2, respectively, regarding accounting and disclosure requirements related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003. See Note 15—Employee Benefit Plans for additional information.

In March 2004, the EITF reached a consensus on Issue 03-6, “Participating Securities and the Two-Class Method under FASB Statement No. 128, Earnings per Share.” The EITF explained how to determine whether a security should be considered a “participating security” for purposes of computing earnings per share and how earnings should be allocated to a participating security when using the two-class method for computing basic earnings per share. The adoption of this standard in the second quarter of 2004 did not have a material effect on our earnings per share calculations for the periods presented in this report.

In April 2004, the FASB issued FASB Staff Position Nos. FAS 141-1 and FAS 142-1, which amended SFAS No. 141, “Business Combinations,” and SFAS No. 142, “Goodwill and Other Intangible Assets,” to remove mineral rights as an example of an intangible asset. In September 2004, the FASB issued FASB Staff Position No. 142-2, which confirmed that the scope exception in paragraph 8(b) of SFAS No. 142 extends to the disclosure provision for oil-and-gas producing entities. The effective date for this FASB Staff Position is October 1, 2004. See Note 7—Properties, Plants and Equipment for additional information.

Note 21—Subsequent Events

On September 29, 2004, we made a joint announcement with LUKOIL, an international integrated oil and gas company headquartered in Russia, of an agreement to form a broad-based strategic alliance, whereby we would become a strategic equity investor in LUKOIL. Together, we also announced our intention to form a joint venture between the two companies to develop resources in the northern part of Russia’s Timan-Pechora oil and gas province and the intention of the two companies to jointly seek the right to develop the West Qurna oil field in Iraq.

In the announcement, we disclosed that we were the successful bidder in an auction of 7.6 percent of LUKOIL’s authorized and issued ordinary shares held by the Russian government for a price of $1,988 million, or $30.76 per share. The transaction closed on October 7, 2004. We expect, however, to increase our ownership in LUKOIL to approximately 10 percent by the end of 2004 if market conditions permit. Under the Shareholder Agreement between the two companies, we will have proportional membership on the LUKOIL Board of Directors (Board) and LUKOIL will propose for shareholder approval amendments to its corporate charter that will require unanimous Board consent for certain key decisions. We expect that one of our nominees will be elected to the LUKOIL Board in early 2005. In addition, the Shareholder Agreement allows us to increase our ownership interest in LUKOIL to 20 percent and limits our ability to sell our LUKOIL shares for a period of four years except in certain circumstances.

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Under the terms of the joint-venture arrangements, we will pay an acquisition price to LUKOIL of approximately $370 million for a 30 percent economic interest in the joint venture to develop oil and gas resources in the northern part of Russia’s Timan-Pechora province, together with an additional payment for LUKOIL’s 30 percent share of working capital and its 30 percent share of capital investments in the joint-venture fields from January 1, 2004. Under the joint-venture arrangements, we will have a 50 percent voting interest. The exact amount of the acquisition price will be established at closing, which is anticipated in the first quarter of 2005.

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Supplementary Information—Condensed Consolidating Financial Information

We have various cross guarantees among ConocoPhillips, ConocoPhillips Holding Company, and ConocoPhillips Company with respect to publicly held debt securities. ConocoPhillips Company 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 its publicly held debt securities. 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.

This condensed consolidating financial information should be read in conjunction with the accompanying consolidated financial statements and notes. Certain amounts in 2003 have been restated for the adoption of FIN 46 and reclassified to conform to the current year presentation.

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