UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2005

OR

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                                          to                                                            

 

CONOCOPHILLIPS

TABLE OF CONTENTS

		Page
Part I – Financial Information
Item 1. Financial Statements
Consolidated Income Statement			1
Consolidated Balance Sheet			2
Consolidated Statement of Cash Flows			3
Notes to Consolidated Financial Statements			4
Supplementary Information—Condensed Consolidating Financial Information			24
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			33
Item 3. Quantitative and Qualitative Disclosures About Market Risk			60
Item 4. Controls and Procedures			60
Part II – Other Information
Item 1. Legal Proceedings			61
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			62
Item 4. Submission of Matters to a Vote of Security Holders			63
Item 6. Exhibits			64
Signature			65
Computation of Ratio of Earnings to Fixed Charges
Certification of CEO pursuant to Rule 13a-14a
Certification of CFO pursuant to Rule 13a-14a
Certifications pursuant to Section 1350

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

Consolidated Income Statement		ConocoPhillips

		Millions of Dollars
		Three Months Ended								Six Months Ended
		June 30								June 30
		2005				2004*				2005				2004*
Revenues
Sales and other operating revenues(1)(2)		$	41,808				31,528				79,439				61,341
Equity in earnings of affiliates			701				322				1,754				591
Other income			105				36				339				171
Total Revenues			42,614				31,886				81,532				62,103
Costs and Expenses
Purchased crude oil, natural gas and products(3)			28,523				20,363				54,095				40,098
Production and operating expenses			2,147				1,840				4,099				3,505
Selling, general and administrative expenses			539				516				1,078				984
Exploration expenses			121				163				292				306
Depreciation, depletion and amortization			985				912				2,026				1,830
Property impairments			9				20				31				51
Taxes other than income taxes(1)			4,664				4,428				9,152				8,542
Accretion on discounted liabilities			41				41				89				77
Interest and debt expense			127				159				265				304
Foreign currency transaction losses (gains)			21				(33	)			18				(49	)
Minority interests			5				7				15				21
Total Costs and Expenses			37,182				28,416				71,160				55,669
Income from continuing operations before income taxes			5,432				3,470				10,372				6,434
Provision for income taxes			2,301				1,457				4,318				2,818
Income From Continuing Operations			3,131				2,013				6,054				3,616
Income (loss) from discontinued operations			7				62				(4	)			75
Net Income		$	3,138				2,075				6,050				3,691
Income Per Share of Common Stock (dollars)(4)
Basic
Continuing operations		$	2.24				1.46				4.33				2.63
Discontinued operations			.01				.04				—				.05
Net Income		$	2.25				1.50				4.33				2.68
Diluted
Continuing operations		$	2.21				1.44				4.26				2.60
Discontinued operations			—				.04				—				.05
Net Income		$	2.21				1.48				4.26				2.65
Dividends Paid Per Share of Common Stock (dollars)(4)		$	.31				.22				.56				.43
Average Common Shares Outstanding (in thousands)(4)
Basic			1,396,724				1,379,380				1,397,305				1,375,788
Diluted			1,419,288				1,398,022				1,420,022				1,393,528
(1) Includes excise, value added and other similar taxes on petroleum products sales:			$            4,338				4,172				8,493				7,994
(2) Includes sales related to purchases/sales with the same counterparty:			4,836				3,433				9,405				6,799
(3) Includes purchases related to purchases/sales with the same counterparty:			4,781				3,393				9,278				6,681
(4) Per-share amounts and average number of common shares outstanding in all periods reflect a two-for-one stock split effected as a 100 percent stock dividend on June 1, 2005.
*Certain amounts reclassified to conform to current year presentation.
See Notes to Consolidated Financial Statements.

Consolidated Balance Sheet		ConocoPhillips

		Millions of Dollars
		June 30				December 31
		2005				2004
Assets
Cash and cash equivalents		$	1,541				1,387
Accounts and notes receivable (net of allowance of $55 million in 2005 and 2004)			8,607				5,449
Accounts and notes receivable—related parties			403				3,339
Inventories			4,870				3,666
Prepaid expenses and other current assets			1,159				986
Assets of discontinued operations held for sale			167				194
Total Current Assets			16,747				15,021
Investments and long-term receivables			12,569				10,408
Net properties, plants and equipment			51,730				50,902
Goodwill			14,943				14,990
Intangibles			1,051				1,096
Other assets			429				444
Total Assets		$	97,469				92,861
Liabilities
Accounts payable		$	9,875				8,727
Accounts payable—related parties			623				404
Notes payable and long-term debt due within one year			354				632
Accrued income and other taxes			2,840				3,154
Employee benefit obligations			1,119				1,215
Other accruals			1,412				1,351
Liabilities of discontinued operations held for sale			105				103
Total Current Liabilities			16,328				15,586
Long-term debt			13,659				14,370
Asset retirement obligations and accrued environmental costs			3,741				3,894
Deferred income taxes			10,614				10,385
Employee benefit obligations			2,250				2,415
Other liabilities and deferred credits			2,365				2,383
Total Liabilities			48,957				49,033
Minority Interests			1,212				1,105
Common Stockholders’ Equity
Common stock (2,500,000,000 shares authorized at $.01 par value) Issued (2005—1,449,747,674 shares; 2004—1,437,729,662 shares)* Par value*			14				14
Capital in excess of par*			26,550				26,047
Compensation and Benefits Trust (CBT) (at cost: 2005—47,116,283 shares; 2004—48,182,820 shares)			(798	)			(816	)
Treasury stock (at cost: 2005—10,670,000 shares; 2004—0 shares)			(576	)			—
Accumulated other comprehensive income			1,003				1,592
Unearned employee compensation			(292	)			(242	)
Retained earnings			21,399				16,128
Total Common Stockholders’ Equity			47,300				42,723
Total		$	97,469				92,861

Consolidated Statement of Cash Flows		ConocoPhillips

		Millions of Dollars
		Six Months Ended
		June 30
		2005				2004
Cash Flows From Operating Activities
Income from continuing operations		$	6,054				3,616
Adjustments to reconcile income from continuing operations to net cash provided by continuing operations
Non-working capital adjustments
Depreciation, depletion and amortization			2,026				1,830
Property impairments			31				51
Dry hole costs and leasehold impairments			156				192
Accretion on discounted liabilities			89				77
Deferred taxes			492				670
Undistributed equity earnings			(1,219	)			(278	)
Gain on asset dispositions			(242	)			(88	)
Other			(191	)			135
Working capital adjustments
Decrease in aggregate balance of accounts receivable sold			(480	)			(675	)
Decrease (increase) in other accounts and notes receivable			221				(1,319	)
Increase in inventories			(1,280	)			(710	)
Decrease (increase) in prepaid expenses and other current assets			(176	)			44
Increase in accounts payable			1,509				1,045
Decrease in taxes and other accruals			(130	)			(263	)
Net cash provided by continuing operations			6,860				4,327
Net cash provided by (used in) discontinued operations			(3	)			22
Net Cash Provided by Operating Activities			6,857				4,349
Cash Flows From Investing Activities
Capital expenditures and investments, including dry hole costs			(4,947	)			(3,065	)
Proceeds from asset dispositions			308				1,354
Long-term advances/loans to affiliates and other			(119	)			(72	)
Collection of advances/loans to affiliates and other			148				37
Net cash used in continuing operations			(4,610	)			(1,746	)
Net cash used in discontinued operations			—				(2	)
Net Cash Used in Investing Activities			(4,610	)			(1,748	)
Cash Flows From Financing Activities
Issuance of debt			333				—
Repayment of debt			(1,332	)			(2,083	)
Issuance of company common stock			263				207
Repurchase of company common stock			(576	)			—
Dividends paid on common stock			(780	)			(590	)
Other			97				183
Net cash used in continuing operations			(1,995	)			(2,283	)
Net Cash Used in Financing Activities			(1,995	)			(2,283	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents			(98	)			(4	)
Net Change in Cash and Cash Equivalents			154				314
Cash and cash equivalents at beginning of period			1,387				490
Cash and Cash Equivalents at End of Period		$	1,541				804

Notes to Consolidated Financial Statements		ConocoPhillips

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’ 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 wholesale customer), or both.

At its June 2005, March 2005 and November 2004 meetings, the Emerging Issues Task Force (EITF) discussed Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” which addresses accounting issues that arise when one company both sells inventory to, and buys inventory from, another company in the same line of business. The purchase and sale transactions may be pursuant to a single contractual arrangement or separate contractual arrangements, and the inventory purchased or sold may be in the form of raw material, work-in-progress, or finished goods. At issue is whether both the revenue and inventory/cost of sales should be recorded at fair value or whether the transactions should be classified as nonmonetary exchanges subject to the fair value exception of Accounting Principles Board (APB) Opinion No. 29, “Accounting for Nonmonetary Transactions.” Issue No. 04-13 encompasses our buy/sell transactions described above.

Buy/sell transactions have the same general terms and conditions as typical commercial contracts including: separate title transfer, transfer of risk of loss, separate gross 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 APB Opinion No. 29.

Our buy/sell transactions are similar to the “barrel back” example used in 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.

At its March 2005 meeting, the EITF reached a tentative conclusion that exchanges of finished goods for raw materials or work-in-progress within the same line of business should be recorded at fair value because these exchanges culminate the earnings process. At its June 2005 meeting, the EITF reached a tentative conclusion that purchases and sales of inventory with the same party in the same line of business should be combined 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 tentative conclusions were posted to the Financial Accounting Standards Board (FASB) Web site for public comment and are scheduled to be discussed again at the EITF’s September meeting.

Depending on the EITF’s final conclusions, it is possible that we could be required to decrease sales and other operating revenues for second-quarter 2005 and 2004 periods by $4,836 million and $3,433 million, respectively, and six-month 2005 and 2004 periods by $9,405 million and $6,799 million, respectively, with a related decrease in purchased crude oil, natural gas and products on our consolidated income statement. We believe any impact to income from continuing operations and net income would result from LIFO inventory and would not be material to our financial statements.

Our Commercial organization 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.

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 Standard (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:

		Millions of Dollars
		Three Months Ended								Six Months Ended
		June 30								June 30
		2005				2004				2005				2004
Net income, as reported		$	3,138				2,075				6,050				3,691
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects			29				26				68				39
Deduct: Total stock-based employee compensation expense determined under fair-value-based method for all awards, net of related tax effects			(30	)			(28	)			(69	)			(44	)
Pro forma net income		$	3,137				2,073				6,049				3,686
Earnings per share*:
Basic—as reported		$	2.25				1.50				4.33				2.68
Basic—pro forma			2.25				1.50				4.33				2.68
Diluted—as reported			2.21				1.48				4.26				2.65
Diluted—pro forma			2.21				1.48				4.26				2.65

Note 3—Common Stock Split

On April 7, 2005, our Board of Directors declared a 2-for-1 split on our common stock 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 stock shares and associated par value per share was unchanged by this action. Shares and per-share information in the Consolidated Income Statement and Consolidated Balance Sheet presented in this report are on an after-split basis for all periods presented.

Note 4—Changes in Accounting Principles

In April 2005, the Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP) FAS 19-1, “Accounting for Suspended Well Costs,” 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 our six-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.” 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 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. We are currently assessing the entity associated with this ship to determine if the entity is a VIE, and if we are the primary beneficiary. 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 a 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 agreed to provide loan financing to the venture. We determined 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. Through June 30, 2005, we have provided $105 million in loan financing.

On June 30, 2005, ConocoPhillips and LUKOIL created the OOO Naryanmarneftegaz (NMNG) joint venture to develop resources in the northwest Arctic 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 will 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.

Production from the NMNG joint-venture fields is expected to be 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 capacity in 2007, with ConocoPhillips participating in the design and financing of the terminal 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 have an obligation to fund, through loans, 30 percent of the terminal’s costs, but we will have no governance interest in the terminal. We have determined we are not the primary beneficiary and will account for our loan to Varandey Terminal Company as a financial asset. Through June 30, 2005, we had provided $26 million in loan financing.

Note 5—Discontinued Operations

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

		Millions of Dollars
		Three Months Ended								Six Months Ended
		June 30								June 30
		2005				2004				2005				2004
Sales and other operating revenues from discontinued operations		$	89				341				165				919
Income (loss) from discontinued operations before-tax		$	11				82				(6	)			103
Income tax expense (benefit)			4				20				(2	)			28
Income (loss) from discontinued operations		$	7				62				(4	)			75

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:

		Millions of Dollars
		June 30				December 31
		2005				2004
Crude oil and petroleum products		$	4,305				3,147
Materials, supplies and other			565				519
		$	4,870				3,666

Inventories valued on a last-in, first-out (LIFO) basis totaled $4,145 million and $2,988 million at June 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 $4,214 million and $2,220 million at June 30, 2005, and December 31, 2004, respectively.

Note 7—Investments and Long-Term Receivables

8

Duke Energy Field Services, LLC (DEFS)

On July 1, 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 as our interest in the Empress plant in Canada was not included in the initial transaction as anticipated due to weather-related damages. However, the Empress plant was sold to Duke on August 1, 2005. We remain responsible for the repair of weather-related damages.

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

Note 8—Properties, Plants and Equipment

Properties, plants and equipment included the following:

		Millions of Dollars
		June 30				December 31
		2005				2004
Properties, plants and equipment		$	71,442				69,151
Accumulated depreciation, depletion and amortization			(19,712	)			(18,249	)
Net properties, plants and equipment		$	51,730				50,902

Suspended Wells

In April 2005, the FASB issued FSP FAS 19-1, “Accounting for Suspended Well Costs” (FSP 19-1). This FASB Staff Position was issued to address whether there are 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.

FSP 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 the 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 19-1 provides several indicators to assist in this evaluation. FSP 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 19-1 effective January 1, 2005. There was no impact to our consolidated financial statements from the adoption of this FSP.

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

		Millions of Dollars
		Six Months
		Ended				Year				Year
		June 30, 2005				2004				2003
Beginning balance at January 1		$	347				403				221
Additions pending the determination of proved reserves			64				142				217
Reclassifications to proved properties			(59	)			(112	)			(6	)
Charged to dry hole expense			(82	)			(86	)			(29	)
Ending balance		$	270				347				403

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

		Millions of Dollars
		June 30				December 31
		2005				2004				2003
Capitalized exploratory well costs that have been capitalized for a period of one year or less		$	136				142				217
Capitalized exploratory well costs that have been capitalized for a period greater than one year			134				205				186
Ending balance		$	270				347				403
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year			14				16				12

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 June 30, 2005:

		Millions of Dollars
		Suspended Since
Project		Total				2004				2003				2002				200l
Alpine satellite—Alaska (1)		$	21				—				—				21				—
Kashagan—Republic of Kazakhstan (2)			18				—				9				—				9
Aktote—Republic of Kazakhstan (4)			12				—				12				—				—
Gumusut—Malaysia (4)			12				—				12				—				—
Foothills of Western Alberta—Canada (3)			11				11				—				—				—
Su Tu Trang—Vietnam (2)			10				—				10				—				—
Eight projects of less than $10 million each (2)(4)			50				8				19				14				9
Total of 14 projects		$	134				19				62				35				18

Note 9—Property Impairments

In the second quarter and six-month periods of 2005 and 2004, we recorded property impairments related to planned dispositions in our Midstream, Exploration and Production (E&P) and Refining and Marketing (R&M) segments. The amount of property impairments by segment were:

		Millions of Dollars
		Three Months Ended								Six Months Ended
		June 30								June 30
		2005				2004				2005				2004
Exploration and Production		$	1				4				1				8
Midstream			9				16				30				36
Refining and Marketing			(1	)			—				—				7
		$	9				20				31				51

Note 10—Debt

At June 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 may 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 may be used to support issuances of letters of credit totaling up to $750 million. The facilities are broadly syndicated among 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. At June 30, 2005, and December 31, 2004, we had no outstanding borrowings under these facilities, but $62 million in letters of credit had been issued. There was no commercial paper outstanding at June 30, 2005, compared with $544 million at December 31, 2004.

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.

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 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 June 30, 2005, our balance sheet included a total environmental accrual of $1,020 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 June 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 related to the guarantee.

Construction Completion Guarantees

•

We have a construction completion guarantee related to our share of debt held by Hamaca Holding LLC, used to construct the joint-venture project in Venezuela. The maximum potential amount of future payments under the guarantee is estimated to be $360 million, which could be called due if completion certification is not achieved by the Guaranteed Project Completion Date. The required 90-day Lender’s Reliability Test is currently underway and is a key to achieving project completion certification. If any issue arises during the 90-day Lender’s Reliability Test, we expect the Guaranteed Project Completion Date (currently October 1, 2005) to be extended to at least December 1, 2005, because of force majeure events that occurred during the construction period. In addition, other completion certification requirements remain outstanding at this time. These certification requirements may be resolved satisfactorily so that completion certification can be achieved; however, it is reasonably 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 June 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 $240 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. In September 2003, the first ship was delivered to its owner and the second ship was delivered to its owner in July 2005.
	•		We have other guarantees with maximum future potential payment amounts totaling $350 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 June 30, 2005, was $22 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, 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, 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 June 30, 2005, was $461 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 $344 million of environmental accruals for known contamination that is included in asset retirement obligations and accrued environmental costs at June 30, 2005. For additional information about environmental liabilities, see Note 11—Contingencies and Commitments.

Note 13—Financial Instruments and Derivative Contracts

In June 2005, we acquired two limited-term, fixed-volume overriding royalty interests in Utah and the San Juan Basin related to our 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.

Note 14—Comprehensive Income

ConocoPhillips’ comprehensive income was as follows:

		Millions of Dollars
		Three Months Ended								Six Months Ended
		June 30								June 30
		2005				2004				2005				2004
Net income		$	3,138				2,075				6,050				3,691
After-tax changes in:
Minimum pension liability adjustment			—				—				(1	)			(1	)
Foreign currency translation adjustments			(336	)			48				(592	)			24
Unrealized loss on securities			—				(1	)			(1	)			—
Hedging activities			5				5				5				5
		$	2,807				2,127				5,461				3,719

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

		Millions of Dollars
		June 30				December 31
		2005				2004
Minimum pension liability adjustment		$	(68	)			(67	)
Foreign currency translation adjustments			1,070				1,662
Unrealized gain on securities			5				6
Deferred net hedging loss			(4	)			(9	)
		$	1,003				1,592

Note 15—Supplemental Cash Flow Information

		Millions of Dollars
		Six Months Ended
		June 30
		2005				2004
Non-Cash Investing and Financing Activities
Investment in properties, plants and equipment of businesses through the assumption of non-cash liabilities*		$	261				—
Fair market value of properties, plants and equipment received in a nonmonetary exchange transaction			138				—
Cash Payments
Interest		$	269				322
Income taxes			3,681				1,825

*See Note 13—Financial Instruments and Derivative Contracts for additional information.

Note 16—Sales of Receivables

At December 31, 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. At December 31, 2004, the QSPE had issued beneficial interests to the bank-sponsored entities of $480 million. 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, which we do not consolidate. Furthermore, except as discussed below, 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. 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.

By January 31, 2005, all of the beneficial interests held by the bank-sponsored entities had matured; therefore, in accordance with SFAS No. 140, the operating results and cash flows of the QSPE subsequent to this maturity have been consolidated with our financial statements, and the assets and liabilities of the QSPE are included in our June 30, 2005 balance sheet. The revolving-period securitization arrangement expires in September 2005, and at this time we have no plans to renew the arrangement.

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

		Millions of Dollars
		2005				2004
Receivables sold at beginning of year		$	480				1,200
New receivables sold			960				5,025
Cash collections remitted			(1,440	)			(5,700	)
Receivables sold at June 30		$	—				525
Discounts and other fees paid on revolving balances		$	2				4

Note 17—Employee Benefit Plans

		Millions of Dollars
		Pension Benefits																Other Benefits
Three Months Ended		June 30																June 30
		2005								2004								2005				2004
		U.S.				Int’l.				U.S.				Int’l.
Components of Net Periodic Benefit Cost
Service cost		$	38				19				38				18				5				6
Interest cost			44				32				43				27				12				14
Expected return on plan assets			(32	)			(28	)			(26	)			(22	)			—				—
Amortization of prior service cost			1				2				1				1				5				5
Recognized net actuarial loss (gain)			13				8				13				10				(1	)			3
Net periodic benefit costs		$	64				33				69				34				21				28

		Millions of Dollars
		Pension Benefits																Other Benefits
Six Months Ended		June 30																June 30
		2005								2004								2005				2004
		U.S.				Int’l.				U.S.				Int’l.
Components of Net Periodic Benefit Cost
Service cost		$	76				37				75				34				10				11
Interest cost			87				64				87				55				25				29
Expected return on plan assets			(63	)			(56	)			(52	)			(45	)			—				—
Amortization of prior service cost			2				4				2				3				10				10
Recognized net actuarial loss (gain)			27				17				26				20				(2	)			5
Net periodic benefit costs		$	129				66				138				67				43				55

We recognized pension settlement losses of $6 million in the first six months of 2004 due to high levels of lump-sum elections by new retirees in certain plans. Of this amount, $2 million was recognized in the second quarter of 2004.

During the first six months of 2005, we contributed $220 million to our domestic qualified and non-qualified benefit plans and $82 million to international qualified and non-qualified benefit plans.

At the end of 2004, we estimated that during 2005, we would contribute approximately $410 million to our domestic qualified and non-qualified plans and $140 million to our international benefits plans. We presently anticipate 2005 contributions to be $540 million to our domestic plans and $145 million to our international plans.

Note 18—Related Party Transactions

Significant transactions with related parties were:

		Millions of Dollars
		Three Months Ended								Six Months Ended
		June 30								June 30
		2005				2004				2005				2004
Operating revenues (a)		$	1,833				1,273				3,478				2,359
Purchases (b)			1,496				1,101				2,652				2,125
Operating expenses and selling, general and administrative expenses (c)			198				198				444				334
Net interest income (d)			9				8				19				15

(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), gas oil and hydrogen feedstocks are sold to Excel Paralubes, and refined products are sold primarily to CFJ Properties and Getty Petroleum Marketing, Inc. (a subsidiary of LUKOIL). 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. We purchase base oils and fuel products from Excel Paralubes for use in our refinery and specialty businesses.
(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, prior to consolidation, the receivables securitization QSPE.

Elimination amounts related to our equity percentage share of profit or loss on the above transactions were not material.

Note 19—Segment Disclosures and Related Information

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

1)

E&P—This segment primarily explores for, produces and markets crude oil, natural gas, and natural gas liquids on a worldwide basis. At June 30, 2005, our E&P operations were 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 equity investment in DEFS. Through June 30, 2005, our equity ownership in DEFS was 30.3 percent. Effective July 1, 2005, we increased our ownership interest to 50 percent.
	3)		R&M—This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia. At June 30, 2005, 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)		LUKOIL Investment—This segment represents our investment in the ordinary shares of LUKOIL, an international, integrated oil and gas company headquartered in Russia. In October 2004, we closed on a transaction to acquire 7.6 percent of LUKOIL’s shares held by the Russian government. During the remainder of 2004, we increased our ownership to 10.0 percent. During the first six months of 2005, we increased our ownership to 12.6 percent.
	5)		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.
	6)		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; interest income and expense; discontinued operations; restructuring charges; 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 at prices that approximate market.

Analysis of Results by Operating Segment

		Millions of Dollars
		Three Months Ended								Six Months Ended
		June 30								June 30
		2005				2004				2005				2004
Sales and Other Operating Revenues
E&P
United States		$	7,493				5,646				14,525				11,213
International			4,331				3,668				9,238				7,707
Intersegment eliminations-U.S.			(979	)			(697	)			(1,891	)			(1,359	)
Intersegment eliminations-international			(995	)			(1,021	)			(1,992	)			(1,959	)
E&P			9,850				7,596				19,880				15,602
Midstream
Total sales			850				700				1,871				1,939
Intersegment eliminations			(197	)			(184	)			(427	)			(537	)
Midstream			653				516				1,444				1,402
R&M
United States			24,021				17,391				43,976				32,818
International			7,296				6,078				14,155				11,617
Intersegment eliminations-U.S.			(150	)			(97	)			(237	)			(192	)
Intersegment eliminations-international			(4	)			—				(6	)			(1	)
R&M			31,163				23,372				57,888				44,242
LUKOIL Investment			—				—				—				—
Chemicals			4				3				7				7
Emerging Businesses			134				39				215				85
Corporate and Other			4				2				5				3
Consolidated Sales and Other Operating Revenues		$	41,808				31,528				79,439				61,341
Net Income (Loss)
E&P
United States		$	966				671				1,858				1,306
International			963				683				1,858				1,305
Total E&P			1,929				1,354				3,716				2,611
Midstream			68				42				453				97
R&M
United States			936				734				1,506				1,137
International			174				84				304				145
Total R&M			1,110				818				1,810				1,282
LUKOIL Investment			148				—				258				—
Chemicals			63				46				196				85
Emerging Businesses			(8	)			(29	)			(16	)			(51	)
Corporate and Other			(172	)			(156	)			(367	)			(333	)
Consolidated Net Income		$	3,138				2,075				6,050				3,691

		Millions of Dollars
		June 30				December 31
		2005				2004
Total Assets
E&P
United States		$	16,676				16,105
International			27,288				26,481
Goodwill			11,043				11,090
Total E&P			55,007				53,676
Midstream			1,671				1,293
R&M
United States			20,735				19,180
International			6,036				5,834
Goodwill			3,900				3,900
Total R&M			30,671				28,914
LUKOIL Investment			3,738				2,723
Chemicals			2,352				2,221
Emerging Businesses			897				972
Corporate and Other			3,133				3,062
Consolidated Total Assets		$	97,469				92,861

Note 20—Income Taxes

Our effective tax rate for the second quarter and first six months of 2005 was 42 percent, compared with 42 percent and 44 percent for the same periods a year ago. While there was not a change in the effective tax rate for the second quarter of 2005, versus the same period in 2004, there was a lower proportion of income in higher tax rate jurisdictions that offset the effect of international tax law changes in 2004. The change in the effective tax rate for the first six months of 2005, versus the same period in 2004, was due to the utilization of capital loss carryforwards that previously had a full valuation allowance and a lower proportion of income in higher tax rate jurisdictions that more than offset the effect of international tax law changes in 2004. The effective tax rate in excess of the domestic federal statutory rate of 35 percent was primarily due to foreign taxes.

One of the provisions of the American Jobs Creation Act of 2004 was a special deduction for qualifying manufacturing activities. While the legislation is still undergoing clarifications, under guidance from FSP 109-1, we included the estimated impact as a current benefit, which was not material to the company’s effective tax rate, and it did not have any impact on our assessment of the need for possible valuation allowances.

Another provision of the American Jobs Creation Act of 2004 was a special one-time provision allowing earnings of controlled foreign companies to be repatriated at a reduced tax rate. At this point, our investigation into our response to the legislation is preliminary, as we await additional and final clarifying legislation and guidance from the government. Because of the uncertainties related to this legislation, and as provided by FSP 109-2, we elected to defer our decision on potentially altering our current plans on permanently reinvesting in certain foreign subsidiaries and foreign corporate joint ventures. We expect final guidance to be issued and our investigation into our response to the legislation to be completed late in 2005.

Note 21—New Accounting Standards and Emerging Issues

In June 2005, the FASB ratified Emerging Issues Task Force (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 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 guidance is effective January 1, 2006, for existing limited partnership agreements that are not modified. We are reviewing Issue No. 04-5 to determine the impact, if any, on our financial statements.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3.” Among other changes, this Statement requires retrospective application for voluntary changes in accounting principle, unless it is impractical to do so. Guidance is provided on how to account for changes when retrospective application is impractical. This Statement is effective on a prospective basis beginning January 1, 2006.

In March 2005, the FASB issued FASB Interpretation 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47). This Interpretation clarifies that an entity is required to recognize a liability for a legal obligation to perform asset retirement activities when the retirement is conditional on a future event and if the liability’s fair value can be reasonably estimated. If the liability’s fair value cannot be reasonably estimated, then the entity must disclose (a) a description of the obligation, (b) the fact that a liability has not been recognized because the fair value cannot be reasonably estimated, and (c) the reasons why the fair value cannot be reasonably estimated. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. We are required to implement this Interpretation in the fourth quarter of 2005 and are currently studying its provisions to determine the impact, if any, on our financial statements.

In December 2004, the 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. This Statement is effective on a prospective basis beginning July 1, 2005.

Also in December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment,” (SFAS 123(R)), which supercedes APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and replaces SFAS No. 123, “Accounting for Stock-Based Compensation,” which we adopted at the beginning of 2003. SFAS 123(R) prescribes the accounting for a wide range of share-based compensation arrangements, including share options, restricted share plans, performance-based awards, share appreciation rights, and employee share purchase plans, and generally requires the fair value of share-based awards to be expensed in the income statement. For ConocoPhillips, this Statement provided for an effective date of third-quarter 2005; however, in April 2005, the Securities and Exchange Commission approved a new rule that delayed the effective date until January 1, 2006. We plan to adopt the provisions of this Statement January 1, 2006. We are studying the provisions of this new pronouncement to determine the impact, if any, on our financial statements. For more information on our adoption of SFAS No. 123 and its effect on net income, see Note 2—Accounting Policies.

In November 2004, the FASB issued SFAS No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4.” This Statement requires that items, such as abnormal idle facility expense, excessive spoilage, double freight, and handling costs, be recognized as a current-period charge. We are required to implement this Statement in the first quarter of 2006. We are analyzing the provisions of this Statement to determine the effects, if any, on our financial statements.

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.

Emerging Issues

At a November 2004 meeting and subsequent meetings, the EITF continued to discuss Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” which addresses accounting issues that arise when one company both sells inventory to and buys inventory from another company in the same line of business. For additional information, see the Revenue Recognition section of Note 2—Accounting Policies.

Supplementary Information—Condensed Consolidating Financial Information

We have various cross guarantees among ConocoPhillips and ConocoPhillips Company with respect to publicly held debt securities. ConocoPhillips Company is wholly owned by ConocoPhillips. ConocoPhillips has fully and unconditionally guaranteed the payment obligations of ConocoPhillips Company with respect to its publicly held debt securities. Similarly, ConocoPhillips Company has 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 and ConocoPhillips Company (in each case, reflecting investments in subsidiaries utilizing the equity method of accounting).
	•		All other non-guarantor subsidiaries of ConocoPhillips Company.
	•		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.

Effective January 1, 2005, ConocoPhillips Holding Company was merged into ConocoPhillips Company. Previously reported prior period information has been restated to reflect this reorganization of companies under common control.

		Millions of Dollars
		Three Months Ended June 30, 2005
						ConocoPhillips				All Other				Consolidating				Total
Income Statement		ConocoPhillips				Company				Subsidiaries				Adjustments				Consolidated
Revenues
Sales and other operating revenues		$	—				28,832				12,976				—				41,808
Equity in earnings of affiliates			3,142				2,207				577				(5,225	)			701
Other income			—				97				8				—				105
Intercompany revenues			8				447				2,261				(2,716	)			—
Total Revenues			3,150				31,583				15,822				(7,941	)			42,614
Costs and Expenses
Purchased crude oil, natural gas and products			—				24,173				6,731				(2,381	)			28,523
Production and operating expenses			—				1,131				1,028				(12	)			2,147
Selling, general and administrative expenses			5				334				204				(4	)			539
Exploration expenses			—				25				96				—				121
Depreciation, depletion and amortization			—				321				664				—				985
Property impairments			—				(2	)			11				—				9
Taxes other than income taxes			—				1,519				3,255				(110	)			4,664
Accretion on discounted liabilities			—				9				32				—				41
Interest and debt expense			26				226				84				(209	)			127
Foreign currency transaction losses (gains)			—				6				15				—				21
Minority interests			—				—				5				—				5
Total Costs and Expenses			31				27,742				12,125				(2,716	)			37,182
Income from continuing operations before income taxes			3,119				3,841				3,697				(5,225	)			5,432
Provision for income taxes			(12	)			699				1,614				—				2,301
Income from continuing operations			3,131				3,142				2,083				(5,225	)			3,131
Income (loss) from discontinued operations			7				7				—				(7	)			7
Net Income		$	3,138				3,149				2,083				(5,232	)			3,138

		Millions of Dollars
		Three Months Ended June 30, 2004
						ConocoPhillips				All Other				Consolidating				Total
Income Statement		ConocoPhillips				Company				Subsidiaries				Adjustments				Consolidated
Revenues
Sales and other operating revenues		$	—				21,046				10,482				—				31,528
Equity in earnings of affiliates			2,011				1,292				274				(3,255	)			322
Other income			—				57				(21	)			—				36
Intercompany revenues			21				372				1,586				(1,979	)			—
Total Revenues			2,032				22,767				12,321				(5,234	)			31,886
Costs and Expenses
Purchased crude oil, natural gas and products			—				16,898				5,336				(1,871	)			20,363
Production and operating expenses			—				1,001				849				(10	)			1,840
Selling, general and administrative expenses			2				348				169				(3	)			516
Exploration expenses			—				32				131				—				163
Depreciation, depletion and amortization			—				277				635				—				912
Property impairments			—				—				20				—				20
Taxes other than income taxes			—				1,570				2,858				—				4,428
Accretion on discounted liabilities			—				9				32				—				41
Interest and debt expense			22				177				55				(95	)			159
Foreign currency transaction losses (gains)			—				7				(40	)			—				(33	)
Minority interests			—				—				7				—				7
Total Costs and Expenses			24				20,319				10,052				(1,979	)			28,416
Income from continuing operations before income taxes			2,008				2,448				2,269				(3,255	)			3,470
Provision for income taxes			(5	)			437				1,025				—				1,457
Income from continuing operations			2,013				2,011				1,244				(3,255	)			2,013
Income from discontinued operations			62				62				31				(93	)			62
Net Income		$	2,075				2,073				1,275				(3,348	)			2,075