UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

For the quarterly period ended September 30, 2005

OR

For the transition period from                                                   to                                                  

Commission file number 001-32395

ConocoPhillips

(Exact name of registrant as specified in its charter)

600 North Dairy Ashford, Houston, TX 77079

(Address of principal executive offices) (Zip Code)

281-293-1000

(Registrant’s telephone number, including area code)

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes   o   No   ý

The registrant had 1,387,565,073 shares of common stock, $.01 par value, outstanding at September 30, 2005.

CONOCOPHILLIPS

TABLE OF CONTENTS

PART I.  FINANCIAL INFORMATION

Item 1.  FINANCIAL STATEMENTS

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Note 1—Interim Financial Information

The interim-period financial information 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 the consolidated financial statements and notes included in ConocoPhillips’ 2004 Annual Report on Form 10-K.  Certain amounts in the 2004 financial statements included in this report on Form 10-Q have been reclassified to conform to the 2005 presentation.

Note 2—Accounting Policies

Revenue Recognition—Revenues associated with sales 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 transactions commonly called buy/sell contracts, in which physical commodity purchases and sales are simultaneously contracted with the same counterparty to either obtain a different quality or grade of refinery feedstock supply, reposition a commodity (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 customer), or both.

Buy/sell transactions have the same general terms and conditions as typical commercial contracts including: separate title transfer, transfer of risk of loss, separate billing and cash settlement for both the buy and sell sides of the transaction, and non-performance by one party does not relieve the other party of its obligation to perform, except in events of force majeure.  Because buy/sell contracts have similar terms and conditions, we account for these purchase and sale transactions in the consolidated income statement as monetary transactions outside the scope of Accounting Principles Board (APB) Opinion No. 29.

Our buy/sell transactions are similar to the “barrel back” example used in Emerging Issues Task Force (EITF) Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-3.”  Using the “barrel back” example, the EITF concluded that a company’s decision to display buy/sell-type transactions either gross or net on the income statement is a matter of judgment that depends on relevant facts and circumstances.  We apply this judgment based on guidance in EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent” (Issue No. 99-19), which provides indicators for when to report revenues and the associated cost of goods sold gross (i.e., on separate revenue and cost of sales lines in the income statement) or net (i.e., on the same line).  The indicators for gross reporting in Issue No. 99-19 are consistent with many of the characteristics of buy/sell transactions, which support our accounting for buy/sell transactions.

We also believe that the conclusion reached by the Derivatives Implementation Group Statement 133 Implementation Issue No. K1, “Miscellaneous: Determining Whether Separate Transactions Should be Viewed as a Unit,” further supports our judgment that the purchase and sale contracts should be viewed as two separate transactions and not as a single transaction.

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At its September 2005 meeting, the EITF reached a consensus on Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” which encompasses our buy/sell transactions described above.

The EITF concluded that exchanges of finished goods for raw materials or work-in-progress within the same line of business should be recorded gross at fair value because these exchanges culminate the earnings process.  Additionally, the EITF concluded that purchases and sales of inventory with the same counterparty in the same line of business should be recorded net and accounted for as nonmonetary exchanges in accordance with APB Opinion No. 29 if they are entered into “in contemplation” of one another.  The inventory could be raw materials, work-in-progress, or finished goods.

The new guidance is effective prospectively beginning April 1, 2006, for new arrangements entered into, and for modifications or renewals of existing arrangements.  We are reviewing this guidance and believe that any impact to income from continuing operations and net income would result from effects on last-in, first-out (LIFO) inventory valuations and would not be material to our financial statements.

Had this new guidance been effective for the periods reported in this Form 10-Q and depending on the determination of what transactions are affected by the new guidance, we could have been required to reduce sales and other operating revenues for the third quarters of 2005 and 2004 by $5,879 million and $3,863 million, respectively, and for the nine-month 2005 and 2004 periods by $15,284 million and $10,662 million, respectively, with related decreases in purchased crude oil, natural gas and products.

Our Commercial organization uses commodity derivative contracts (such as futures and options) in various markets to optimize the value of our supply chain and to 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.

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 to be 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.

Stock-Based Compensation—Effective January 1, 2003, we voluntarily adopted the fair-value accounting method prescribed by Statement of Financial Accounting Standards (SFAS) No. 123, “Accounting for Stock-Based Compensation.”  We used the prospective transition method, applying the fair-value accounting method and recognizing 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 APB Opinion 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 Opinion 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—Common Stock Split

On April 7, 2005, our Board of Directors declared a 2-for-1 common stock split effected in the form of a 100 percent stock dividend, payable June 1, 2005, to stockholders of record as of May 16, 2005.  The total number of authorized common shares and associated par value per share were unchanged by this action.  Shares and per-share information in the Consolidated Income Statement and Balance Sheet are on an after-split basis for all periods presented.

Note 4—Changes in Accounting Principles

In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 153, “Exchange of Nonmonetary Assets, an amendment of APB Opinion No. 29.”  This amendment eliminates the APB Opinion No. 29 exception for fair value recognition of nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges of nonmonetary assets that do not have commercial substance.  We adopted this guidance on a prospective basis effective July 1, 2005.  There was no impact to our financial statements upon adoption.

In June 2005, the FASB ratified EITF Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights” (Issue No. 04-5).  Issue No. 04-5 adopts a framework for evaluating whether the general partner (or general partners as a group) controls the partnership.  The framework makes it more likely that a single general partner (or a general partner within a general partner group) would have to consolidate the limited partnership regardless of its ownership in the limited partnership.  The new guidance was effective upon ratification for all newly formed limited partnerships and for existing limited partnership agreements that are modified.  The adoption of this portion of the EITF guidance had no impact on our financial statements.  The guidance is effective January 1, 2006, for existing limited partnership agreements that have not been modified.  We are reviewing Issue No. 04-5 to determine the impact, if any, on our financial statements.

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In April 2005, the FASB issued FASB Staff Position (FSP) FAS 19-1, “Accounting for Suspended Well Costs” (FSP FAS 19-1), with application required in the first reporting period beginning after April 4, 2005.  Under early application provisions, we adopted FSP FAS 19-1 effective January 1, 2005.  The adoption of this standard did not impact nine-month 2005 net income.  See Note 8—Properties, Plants and Equipment for additional information.

In December 2004, the FASB issued FSP FAS 109-1, “Application of FASB Statement No. 109, ‘Accounting for Income Taxes,’ to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004,” and FSP 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004” (FSP FAS 109-1 and 109-2).  See Note 20—Income Taxes for additional information.

Consolidation of Variable Interest Entities (VIEs)

In February 2003, we entered into two 20-year agreements establishing separate guarantee facilities of $50 million each for two liquefied natural gas ships that were under construction.  Subject to the terms of the facilities, we will be required to make payments should the charter revenue generated by the ships fall below a certain specified minimum threshold, and we will receive payments to the extent that such revenues exceed those thresholds.  Actual gross payments over the 20 years could exceed $100 million to the extent cash is received by us.  In the first quarter of 2004, we determined the entity associated with the first ship was a VIE, but we were not the primary beneficiary and did not consolidate the entity.  The second ship was delivered to its owner in July 2005.  In the third quarter of 2005, we received the required information related to the entity associated with the second ship and determined that it is a VIE; however, we are not the primary beneficiary and therefore we will not consolidate the entity.  We currently account for these agreements as guarantees and contingent liabilities.  See Note 12—Guarantees for additional information.

In July 2004, we announced the finalization of our transaction with Freeport LNG Development, L.P. (Freeport LNG) to participate in an LNG receiving terminal in Quintana, Texas.  We have no ownership in Freeport LNG; however, we obtained a 50 percent interest in Freeport LNG GP, Inc., which serves as the general partner managing the venture.  We entered into a credit agreement with Freeport LNG, whereby we will provide loan financing of approximately $600 million for the construction of the terminal.  Through September 30, 2005, we had provided $148 million in financing.  We determined that Freeport LNG is a VIE, and that we are not the primary beneficiary.  We account for our loan to Freeport LNG as a financial asset.

On June 30, 2005, ConocoPhillips and LUKOIL created the OOO Naryanmarneftegaz (NMNG) joint venture to develop resources in the northwest Arctic region of Russia.  We determined that NMNG is a VIE because we and our related party, LUKOIL, have disproportionate interests.  We have a 30 percent ownership interest with a 50 percent governance interest in the joint venture.  We use the equity method of accounting for this investment because we have determined we are not the primary beneficiary.  Our funding for a 30 percent ownership interest amounted to $512 million.  This acquisition price was based on preliminary estimates of capital expenditures and working capital.  Purchase price adjustments are expected to be finalized by the end of the year.  At September 30, 2005, the book value of our investment in the venture was $567 million.

Production from the NMNG joint-venture fields is transported via pipeline to LUKOIL’s existing terminal at Varandey Bay on the Barents Sea and then shipped via tanker to international markets. LUKOIL is expected to complete an expansion of the terminal's capacity in 2007, with ConocoPhillips participating in the design and financing of the expansion.  We determined that the terminal entity, Varandey Terminal Company, is also a VIE because we and our related party, LUKOIL, have disproportionate interests.  We

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have an obligation to fund, through loans, 30 percent of the terminal’s costs, but we will have no governance or ownership interest in the terminal.  We have determined that we are not the primary beneficiary and account for our loan to Varandey Terminal Company as a financial asset.  Through September 30, 2005, we had provided $48 million in loan financing.

Note 5—Discontinued Operations

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

Assets of discontinued operations were primarily properties, plants and equipment, while liabilities of discontinued operations were primarily deferred taxes.

Note 6—Inventories

Inventories consisted of the following:

Inventories valued on a LIFO basis totaled $4,117 million and $2,988 million at September 30, 2005, and December 31, 2004, respectively.  The remainder of our inventories is valued under various methods, including first-in, first-out and weighted average.  The excess of current replacement cost over LIFO cost of inventories amounted to $5,078 million and $2,220 million at September 30, 2005, and December 31, 2004, respectively.

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Note 7—Investments and Long-Term Receivables

LUKOIL

During the third quarter of 2005, we increased our ownership interest in LUKOIL to 14.8 percent at September 30, 2005, from 12.6 percent at June 30, 2005, and 10 percent at December 31, 2004.

At September 30, 2005, the book value of our ordinary share investment in LUKOIL was $4,740 million. Our 14.8 percent share of the net assets of LUKOIL was estimated to be $3,627 million.  This basis difference of $1,113 million is primarily being amortized on a unit-of-production basis.  On September 30, 2005, the closing price of LUKOIL shares on the London Stock Exchange was $57.82 per share, making the aggregate total market value of our LUKOIL investment $7,290 million at that date.

Duke Energy Field Services, LLC (DEFS)

In July 2005, ConocoPhillips and Duke Energy Corporation (Duke) completed the restructuring of their respective ownership levels in DEFS, which resulted in DEFS becoming a jointly controlled venture, owned 50 percent by each company.  This restructuring increased our ownership in DEFS to 50 percent from 30.3 percent through a series of direct and indirect transfers of certain Canadian Midstream assets from DEFS to Duke, a disproportionate cash distribution from DEFS to Duke from the sale of DEFS’ interest in TEPPCO Partners, L.P., and a combined payment by ConocoPhillips to Duke and DEFS of approximately $840 million.  This payment was approximately $230 million higher than previously anticipated because our interest in the Empress plant in Canada was not included in the initial transaction as anticipated due to weather-related damages to the facility.  Subsequently the Empress plant was sold to Duke on August 1, 2005, for approximately $230 million.

In the first quarter of 2005, as a part of equity earnings, we recorded our $306 million (after-tax) equity share of the financial gain from DEFS’ sale of its interest in TEPPCO.

At September 30, 2005, the book value of our investment in DEFS was $1,490 million.  Our 50 percent share of the net assets of DEFS was $1,470 million.  This basis difference of $20 million is primarily being amortized on a straight-line basis through 2014 consistent with the remaining estimated useful lives of DEFS’ properties, plants and equipment.

Note 8—Properties, Plants and Equipment

Properties, plants and equipment included the following:

Suspended Wells

In April 2005, the FASB issued FSP FAS 19-1, “Accounting for Suspended Well Costs” (FSP FAS 19-1). This FASB Staff Position was issued to address whether there were circumstances that would permit the continued capitalization of exploratory well costs beyond one year, other than when further exploratory drilling is planned and major capital expenditures would be required to develop the project.

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FSP FAS 19-1 requires the continued capitalization of suspended well costs if the well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing these reserves and the economic and operating viability of the project.  All relevant facts and circumstances should be evaluated in determining whether a company is making sufficient progress assessing the reserves, and FSP FAS 19-1 provides several indicators to assist in this evaluation.  FSP FAS 19-1 prohibits continued capitalization of suspended well costs on the chance that market conditions will change or technology will be developed to make the project economic.  We adopted FSP FAS 19-1 effective January 1, 2005.  There was no impact to our consolidated financial statements from the adoption.

The following table reflects the net changes in suspended exploratory well costs during the first nine months of 2005, as well as for the years 2004 and 2003.

The following table provides an aging of suspended well balances at September 30, 2005, and December 31, 2004 and 2003:

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The following table provides a further aging of those exploratory well costs that have been capitalized for more than one year since the completion of drilling as of September 30, 2005:

(1)       Development decisions pending infrastructure west of Alpine and construction authorization.

(2)       Additional appraisal wells planned.

(3)       Wells in various stages of testing/completion.

(4)       Appraisal drilling complete; costs being incurred to assess development.

Note 9—Property Impairments

During 2005 and 2004, we recorded property impairments related to planned asset dispositions.  The amount of property impairments by segment were:

Note 10—Debt

At September 30, 2005, we had two revolving credit facilities totaling $5 billion, available for use either as direct bank borrowings or as support for the issuance of up to $5 billion in commercial paper, a portion of which could be denominated in other currencies (limited to euro 3 billion equivalent).  The facilities included a $2.5 billion four-year facility expiring in October 2008 and a $2.5 billion five-year facility expiring in October 2009.  In addition, the five-year facility could be used to support issuances of letters of credit totaling up to $750 million.  The facilities were broadly syndicated among financial institutions and did not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or ratings.  The credit agreements did 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.  At September 30, 2005, and December 31, 2004, we had no outstanding borrowings under these facilities, but $62 million and $173 million, respectively, in letters of credit had been issued.  There was no commercial paper outstanding at September 30, 2005, compared with $544 million at December 31, 2004.

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On October 5, 2005, we replaced the two revolving credit facilities discussed above with two new revolving credit facilities totaling $5 billion.  Both facilities expire in October 2010, contain the same provisions as the previous facilities and are available for use as direct bank borrowings or as support for our $5 billion commercial paper program.

In March 2005, we redeemed our $400 million 3.625% Notes due 2007 at par, plus accrued interest.  In conjunction with this redemption, $400 million of interest rate swaps were cancelled.

During the third quarter, we purchased, at market prices, and retired $454 million of various ConocoPhillips bond issues.  These purchases resulted in after-tax losses of $42 million.  In October 2005, we gave notice to redeem the $750 million aggregate principal amount of our 6.35% Notes due 2009 in November 2005.  In conjunction with this redemption, $750 million of interest rate swaps will be cancelled.

Note 11—Contingencies and Commitments

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.

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

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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 for 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, 2005, our balance sheet included a total environmental accrual of $996 million, compared with $1,061 million at December 31, 2004.  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.

Legal Proceedings—We apply our knowledge, experience, and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us.  Our process facilitates the early evaluation and quantification of potential exposures in individual cases.  This process also enables us to track trial settings, as well as the status and pace of settlement discussions in individual matters.  Based on our professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, we believe that there is only a remote likelihood 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.

Other Contingencies—We have contingent liabilities resulting from throughput agreements with pipeline and processing companies not associated with financing arrangements.  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.  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 12—Guarantees

At September 30, 2005, we were liable for certain contingent obligations under various contractual arrangements as described below.  We recognize a liability, at inception, for the fair value of our obligation as a guarantor for newly issued or modified guarantees.  Unless the carrying amount of the liability is noted, no liability has been recorded for the guarantee.

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Construction Completion Guarantees

•                  We have a construction completion guarantee related to our share of the debt held by Hamaca Holding LLC, which was used to construct the joint-venture project in Venezuela.  The maximum potential amount of future payments under the guarantee is estimated to be $370 million. The original Guaranteed Project Completion Date of October 1, 2005, has been extended to December 31, 2005, because of force majeure events that occurred during the construction period. The guarantee therefore remains in place, and can be called due if completion certification is not achieved by the revised date. Outstanding certification requirements may be resolved satisfactorily so that completion certification can be achieved; however, it remains possible that the construction completion guarantee may not be fully released or the debt could be called due if the issues are not satisfactorily resolved.

Guarantees of Joint-Venture Debt

•                  At September 30, 2005, we had guarantees outstanding for our portion of joint-venture debt obligations, which have terms of up to 20 years.  The maximum potential amount of future payments under the guarantees is approximately $230 million.  Payment would be required if a joint venture defaults on its debt obligations.  Included in these outstanding guarantees was $98 million associated with the Polar Lights Company joint venture in Russia.

Other Guarantees

•                  The Merey Sweeny, L.P. (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 19 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.

•                  In February 2003, we entered into two agreements establishing separate guarantee facilities for $50 million each for two liquefied natural gas ships.  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.  See Note 4—Changes in Accounting Principles for additional information.

•                  We have other guarantees with maximum future potential payment amounts totaling $320 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, two small construction completion guarantees, 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, 2005, was $23 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

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liquidity issues, if the pipeline joint venture has revenue below a certain threshold, if construction projects are not completed, if guaranteed parties default on lease payments, 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 and 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, 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, 2005, was $452 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 reasonable estimate of the maximum potential amount of future payments.  Included in the carrying amount recorded were $338 million of environmental accruals for known contamination that is included in asset retirement obligations and accrued environmental costs at September 30, 2005.  For additional information about environmental liabilities, see Note 11—Contingencies and Commitments.

Note 13—Financial Instruments and Derivative Contracts

Derivative assets and liabilities were:

In June 2005, we acquired two limited-term, fixed-volume overriding royalty interests in Utah and the San Juan Basin related to our natural gas production.  As part of the acquisition, we assumed related commodity swaps with a negative fair value of $261 million at June 30, 2005.  In late June and early July, we entered into additional commodity swaps to offset essentially all of the exposure from the assumed swaps.  At September 30, 2005, the commodity swaps assumed in the acquisition had a negative fair value of $424 million, and the commodity swaps entered to offset the resulting exposure had a positive fair value

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of $187 million.  Although these commodity swaps contributed to the increase in derivative assets and liabilities from December 31, 2004, to September 30, 2005, price movements, particularly price increases in natural gas, during the third quarter were primarily responsible for the increase.

Note 14—Comprehensive Income

ConocoPhillips’ comprehensive income was as follows: