ConocoPhillips (COP) 10-Q 2007 Q3 Quarterly report

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 endedSeptember 30, 2007                                              

or

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

For the transition period from                    to                                       

Commission file number: 001-32395         
   

ConocoPhillips

(Exact name of registrant as specified in its charter)

Delaware	01-0562944
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

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. Yesþ Noo

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filerþ Accelerated filero Non-accelerated filero

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ

The registrant had 1,599,556,644 shares of common stock, $.01 par value, outstanding at September 30, 2007.

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		26
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		35
Item 3. Quantitative and Qualitative Disclosures About Market Risk		59
Item 4. Controls and Procedures		59
Part II – Other Information
Item 1. Legal Proceedings		60
Item 1A. Risk Factors		61
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		62
Item 5. Other Information		62
Item 6. Exhibits		63
Signature		64
Computation of Ratio of Earnings to Fixed Charges
Certification of Chief Executive Officer
Certification of Chief Financial Officer
Certifications Pursuant to Section 1350

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

Consolidated Income Statement ConocoPhillips

	Millions of Dollars
	Three Months Ended						Nine Months Ended
	September 30						September 30
	2007			2006			2007			2006
Revenues and Other Income
Sales and other operating revenues*	$	46,062			48,076			134,752			142,131
Equity in earnings of affiliates		1,314			1,196			3,749			3,320
Other income		557			313			1,696			537
Total Revenues and Other Income		47,933			49,585			140,197			145,988
Costs and Expenses
Purchased crude oil, natural gas and products		30,862			30,551			88,397			93,454
Production and operating expenses		2,620			2,640			7,669			7,549
Selling, general and administrative expenses		569			650			1,700			1,826
Exploration expenses		218			197			739			443
Depreciation, depletion and amortization		2,052			2,137			6,092			5,282
Impairment—expropriated assets		—			—			4,588			—
Impairments		188			267			285			317
Taxes other than income taxes*		4,583			4,853			13,654			13,661
Accretion on discounted liabilities		81			74			241			207
Interest and debt expense		391			308			1,017			783
Foreign currency transaction gains		(20	)		(50	)		(198	)		(10	)
Minority interests		25			21			65			60
Total Costs and Expenses		41,569			41,648			124,249			123,572
Income before income taxes		6,364			7,937			15,948			22,416
Provision for income taxes		2,691			4,061			8,428			10,063
Net Income	$	3,673			3,876			7,520			12,353
Net Income Per Share of Common Stock(dollars)
Basic	$	2.26			2.35			4.60			7.90
Diluted		2.23			2.31			4.54			7.78
Dividends Paid Per Share of Common Stock(dollars)	$	.41			.36			1.23			1.08
Average Common Shares Outstanding(in thousands)
Basic		1,622,456			1,652,623			1,635,128			1,564,423
Diluted		1,644,267			1,675,839			1,657,244			1,587,892
*Includes excise taxes on petroleum products sales:	$	3,954			4,098			11,864			12,010

See Notes to Consolidated Financial Statements.

1

Consolidated Balance Sheet ConocoPhillips

	Millions of Dollars
	September 30			December 31
	2007			2006
Assets
Cash and cash equivalents	$	1,379			817
Accounts and notes receivable (net of allowance of $64 million in 2007 and $45 million in 2006)		11,867			13,456
Accounts and notes receivable—related parties		1,911			650
Inventories		5,312			5,153
Prepaid expenses and other current assets		3,170			4,990
Total Current Assets		23,639			25,066
Investments and long-term receivables		30,145			19,595
Loans and advances—related parties		1,598			1,118
Net properties, plants and equipment		87,407			86,201
Goodwill		29,374			31,488
Intangibles		899			951
Other assets		365			362
Total Assets	$	173,427			164,781
Liabilities
Accounts payable	$	14,629			14,163
Accounts payable—related parties		1,628			471
Notes payable and long-term debt due within one year		405			4,043
Accrued income and other taxes		4,741			4,407
Employee benefit obligations		740			895
Other accruals		1,935			2,452
Total Current Liabilities		24,078			26,431
Long-term debt		21,471			23,091
Asset retirement obligations and accrued environmental costs		6,561			5,619
Joint venture acquisition obligation—related party		6,445			—
Deferred income taxes		20,924			20,074
Employee benefit obligations		3,419			3,667
Other liabilities and deferred credits		2,416			2,051
Total Liabilities		85,314			80,933
Minority Interests		1,180			1,202
Common Stockholders’ Equity
Common stock (2,500,000,000 shares authorized at $.01 par value)
Issued (2007—1,717,176,211 shares; 2006—1,705,502,609 shares)
Par value		17			17
Capital in excess of par		42,554			41,926
Grantor trusts (at cost: 2007—43,259,722 shares; 2006—44,358,585 shares)		(746	)		(766	)
Treasury stock (at cost: 2007—74,359,845 shares; 2006—15,061,613 shares)		(5,479	)		(964	)
Accumulated other comprehensive income		3,930			1,289
Unearned employee compensation		(133	)		(148	)
Retained earnings		46,790			41,292
Total Common Stockholders’ Equity		86,933			82,646
Total	$	173,427			164,781

See Notes to Consolidated Financial Statements.

2

Consolidated Statement of Cash Flows ConocoPhillips

	Millions of Dollars
	Nine Months Ended
	September 30
	2007			2006
Cash Flows From Operating Activities
Net income	$	7,520			12,353
Adjustments to reconcile net income to net cash provided by operating activities
Non-working capital adjustments
Depreciation, depletion and amortization		6,092			5,282
Impairment—expropriated assets		4,588			—
Impairments		285			317
Dry hole costs and leasehold impairments		355			141
Accretion on discounted liabilities		241			207
Deferred taxes		55			273
Undistributed equity earnings		(1,472	)		(1,007	)
Gain on asset dispositions		(1,316	)		(64	)
Other		28			(296	)
Working capital adjustments*
Decrease in accounts and notes receivable		411			172
Increase in inventories		(334	)		(1,922	)
Decrease (increase) in prepaid expenses and other current assets		430			(669	)
Increase in accounts payable		1,052			181
Decrease (increase) in taxes and other accruals		(305	)		911
Net Cash Provided by Operating Activities		17,630			15,879
Cash Flows From Investing Activities
Acquisition of Burlington Resources Inc.**		—			(14,285	)
Capital expenditures and investments, including dry hole costs**		(7,907	)		(11,513	)
Proceeds from asset dispositions		3,057			246
Long-term advances/loans to affiliates		(449	)		(632	)
Collection of advances/loans to affiliates		66			115
Other		24			—
Net Cash Used in Investing Activities		(5,209	)		(26,069	)
Cash Flows From Financing Activities
Issuance of debt		824			15,263
Repayment of debt		(6,141	)		(4,325	)
Issuance of company common stock		251			145
Repurchase of company common stock		(4,501	)		(675	)
Dividends paid on company common stock		(2,009	)		(1,684	)
Other		(289	)		(123	)
Net Cash Provided by (Used in) Financing Activities		(11,865	)		8,601
Effect of Exchange Rate Changes on Cash and Cash Equivalents		6			71
Net Change in Cash and Cash Equivalents		562			(1,518	)
Cash and cash equivalents at beginning of period		817			2,214
Cash and Cash Equivalents at End of Period	$	1,379			696

*	Net of acquisition and disposition of businesses.
**	Net of cash acquired.

See Notes to Consolidated Financial Statements.

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Notes to Consolidated Financial Statements ConocoPhillips

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, in the opinion of management, 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. The acquisition of Burlington Resources Inc. was reflected in our balance sheet beginning at March 31, 2006, and was reflected in our results of operations beginning April 1, 2006.

To enhance your understanding of these interim financial statements, see the consolidated financial statements and notes included in our 2006 Annual Report on Form 10-K.

Note 2—Changes in Accounting Principles

Effective April 1, 2006, we implemented Emerging Issues Task Force Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” Issue No. 04-13 requires purchases and sales of inventory with the same counterparty and entered into “in contemplation” of one another to be combined and reported net (i.e., on the same income statement line). Exceptions to this are exchanges of finished goods for raw materials or work-in-progress within the same line of business, which are only reported net if the transaction lacks economic substance. The implementation of Issue No. 04-13 did not have a material impact on net income.

The table below shows the actual nine months ended September 30, 2007, sales and other operating revenues, and purchased crude oil, natural gas and products under Issue No. 04-13, and the respective pro forma amounts had this new guidance been effective for the period included in this report prior to April 1, 2006.

	Millions of Dollars
	Nine Months Ended
	September 30
	Actual		Pro Forma
	2007		2006
Sales and other operating revenues	$	134,752		135,474
Purchased crude oil, natural gas and products		88,397		86,797

In June 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (FIN 48). This Interpretation provides guidance on recognition, classification and disclosure concerning uncertain tax liabilities. The evaluation of a tax position requires recognition of a tax benefit if it is more likely than not it will be sustained upon examination. We adopted FIN 48 effective January 1, 2007. The adoption did not have a material impact on our consolidated financial statements.

At January 1, 2007, we had unrecognized tax benefits of $912 million. Included in this balance was $468 million which, if recognized, would affect our effective tax rate.

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We recognize accrued interest related to unrecognized tax benefits in interest expense, and penalties in production and operating expenses. At January 1, 2007, accrued liabilities for interest and penalties totaled $99 million, net of accrued income taxes. See Note 21—Income Taxes, for additional information about income taxes.

Note 3—Acquisition of Burlington Resources Inc.

On March 31, 2006, ConocoPhillips completed the $33.9 billion acquisition of Burlington Resources Inc., an independent exploration and production company that held a substantial position in North American natural gas proved reserves, production and exploratory acreage.

The final allocation of the purchase price to specific assets and liabilities was completed in the first quarter of 2007. It was based on the final outside appraisal of the fair value of Burlington Resources long-lived assets and the conclusion of the fair value determination of all other Burlington Resources assets and liabilities.

The following table summarizes the final purchase price allocation of the fair value of the assets acquired and liabilities assumed as of March 31, 2006:

	Millions
	of Dollars
Cash and cash equivalents	$	3,238
Accounts and notes receivable		1,432
Inventories		229
Prepaid expenses and other current assets		108
Investments and long-term receivables		268
Properties, plants and equipment		28,176
Goodwill		16,787
Intangibles		107
Other assets		46
Total Assets	$	50,391
Accounts payable	$	1,487
Notes payable and long-term debt due within one year		1,009
Accrued income and other taxes		697
Employee benefit obligations—current		248
Other accruals		254
Long-term debt		3,330
Asset retirement obligations		730
Accrued environmental costs		174
Deferred income taxes		7,849
Employee benefit obligations		347
Other liabilities and deferred credits		397
Common stockholders’ equity		33,869
Total Liabilities and Equity	$	50,391

All of the goodwill was assigned to the Worldwide Exploration and Production reporting unit. Of the $16,787 million of goodwill, $7,953 million relates to net deferred tax liabilities arising from differences

5

between the allocated financial bases and deductible tax bases of the acquired assets. None of the goodwill is deductible for tax purposes.

The following table presents pro forma information for the nine months ended September 30, 2006, as if the acquisition had occurred at the beginning of 2006.

	Millions
	of Dollars
Pro Forma
Sales and other operating revenues	$	144,036
Net income		12,747
Net income per share of common stock(dollars)
Basic		7.71
Diluted		7.60

The pro forma information is not intended to reflect the actual results that would have occurred if the companies had been combined during the period presented, nor is it intended to be indicative of the results of operations that may be achieved by ConocoPhillips in the future.

Note 4—Restructuring

In connection with the acquisition of Burlington Resources, we implemented a restructuring program as part of the effort to capture the synergies of combining the two companies. Under this program, we recorded accruals totaling $230 million in 2006 for employee severance payments, site closings, incremental pension benefit costs associated with workforce reductions, and employee relocations. Approximately 600 positions were identified for elimination during 2006, most of which were in the United States. During 2007, an additional 35 positions were identified for elimination.

Of the total accrual, $224 million was reflected in the Burlington Resources purchase price allocation as an assumed liability, and $6 million related to ConocoPhillips was reflected in selling, general and administrative expenses in 2006. The following table summarizes activity related to the non-pension portion of the accrual in the first nine months of 2007:

	Millions
	of Dollars
Balance at December 31, 2006	$	120
Benefit payments		(57	)
Adjustments		17
Balance at September 30, 2007*	$	80

* Includes current liabilities of $35 million. All workforce reductions are expected to be completed by March 2008. Some costs for site closings, continuation of employee benefits, and employee relocations are expected to extend beyond one year from September 30, 2007.

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Note 5—Variable Interest Entities (VIEs)

In June 2006, ConocoPhillips acquired a 24 percent interest in West2East Pipeline LLC (West2East), a company holding a 100 percent interest in Rockies Express Pipeline LLC (Rockies Express). West2East is a VIE, but we are not the primary beneficiary. We use the equity method of accounting for our investment. We issued a guarantee for 24 percent of the $2 billion in credit facilities of Rockies Express. In addition, we have a guarantee for 24 percent of $600 million of Floating Rate Notes due 2009 issued by Rockies Express in September 2007. See Note 13—Guarantees, for additional information.

In June 2005, ConocoPhillips and OAO LUKOIL (LUKOIL) created the OOO Naryanmarneftegaz (NMNG) joint venture to develop resources in the Timan-Pechora province of Russia. The NMNG joint venture is a VIE, but we are not the primary beneficiary. We use the equity method of accounting for this investment. At September 30, 2007, the book value of our investment in the venture was $1,403 million.

See Note 11—Debt, for information about the liquidation of Phillips 66 Capital II.

Note 6—Inventories

Inventories consisted of the following:

	Millions of Dollars
	September 30		December 31
	2007		2006
Crude oil and petroleum products	$	4,500		4,351
Materials, supplies and other		812		802
	$	5,312		5,153

Inventories valued on the last-in, first-out (LIFO) basis totaled $4,156 million and $4,043 million at September 30, 2007, and December 31, 2006, 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 $5,977 million and $4,178 million at September 30, 2007, and December 31, 2006, respectively.

Note 7—Assets Held for Sale

In 2006, we commenced asset rationalization efforts that led to the classification of certain assets as “held for sale” under Statement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Accordingly, at December 31, 2006, we classified $3,051 million of non-current assets and $604 million of non-current liabilities as current assets and current liabilities, respectively.

During the first nine months of 2007, a portion of these held-for-sale assets were sold, additional assets met the held-for-sale criteria, and other assets no longer met the held-for-sale criteria. As a result, at September 30, 2007, we classified $1,352 million of non-current assets as “Prepaid expenses and other current assets” on our consolidated balance sheet and we classified $193 million of non-current liabilities as current liabilities, consisting of $142 million in “Accrued income and other taxes” and $51 million in “Other accruals.” We expect the disposal of these assets to be substantially completed by the end of 2008.

7

The major classes of non-current assets and non-current liabilities held for sale at September 30, 2007, classified as current were:

	Millions
	of Dollars
Assets
Investments and long-term receivables	$	53
Net properties, plants and equipment		1,215
Goodwill		65
Intangibles		2
Other assets		17
Total assets reclassified	$	1,352
Exploration and Production (E&P)	$	214
Refining and Marketing (R&M)		1,138
	$	1,352
Liabilities
Asset retirement obligations and accrued environmental costs	$	28
Deferred income taxes		142
Other liabilities and deferred credits		23
Total liabilities reclassified	$	193
E&P	$	29
R&M		164
	$	193

Note 8—Investments, Loans and Long-Term Receivables

Investments in Venezuela

See the “Expropriated Assets” section of Note 10—Impairments, for information on the complete impairment of our investments in the Hamaca and Petrozuata projects.

EnCana Business Ventures

In October 2006, we announced a business venture with EnCana Corporation (EnCana) to create an integrated North American heavy-oil business. The transaction closed on January 3, 2007, and consists of two 50/50 business ventures, a Canadian upstream general partnership, FCCL Oil Sands Partnership (FCCL), and a U.S. downstream limited liability company, WRB Refining LLC (WRB). We use the equity method of accounting for both entities, with the operating results of our investment in FCCL reflecting its use of the full-cost method of accounting for oil and gas exploration and development activities.

FCCL’s operating assets consist of the Foster Creek and Christina Lake steam-assisted gravity drainage bitumen projects, both located in the eastern flank of the Athabasca oil sands in northeast Alberta. A subsidiary of EnCana is the operator and managing partner of FCCL. We are obligated to contribute $7.5 billion, plus accrued interest, to FCCL over a 10-year period beginning in 2007. For additional information on this obligation, see Note 17—Joint Venture Acquisition Obligation.

WRB’s operating assets consist of the Wood River and Borger refineries, located in Roxana, Illinois, and Borger, Texas, respectively. As a result of our contribution of these two assets to WRB, a basis difference of $5.0 billion was created due to the fair value of the contributed assets recorded by WRB exceeding their

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historic book value. The difference is amortized and recognized as a benefit evenly over a period of 25 years, which is the estimated remaining useful life of the refineries at the closing date. The basis difference at September 30, 2007, was approximately $4.9 billion. We are the operator and managing partner of WRB. EnCana is obligated to contribute $7.5 billion, plus accrued interest, to WRB over a 10-year period beginning in 2007. For the Wood River refinery, operating results are shared 50/50 starting upon formation. For the Borger refinery, we are entitled to 85 percent of the operating results in 2007, 65 percent in 2008, and 50 percent in all years thereafter.

LUKOIL

Our ownership interest in LUKOIL was 20.0 percent at September 30, 2007, based on 851 million issued shares. For financial reporting under U.S. generally accepted accounting principles, treasury shares held by LUKOIL are not considered outstanding for determining our equity-method ownership interest in LUKOIL. Our ownership interest, based on estimated shares outstanding, was 20.5 percent at September 30, 2007.

At September 30, 2007, the book value of our ordinary share investment in LUKOIL was $10,496 million. Our share of the net assets of LUKOIL was estimated to be $7,939 million. This basis difference of $2,557 million is primarily being amortized on a unit-of-production basis and recognized as a reduction of earnings. On September 30, 2007, the closing price of LUKOIL shares on the London Stock Exchange was $83.00 per share, making the total market value of our LUKOIL investment $14,119 million.

Loans to Related Parties

As part of our normal ongoing business operations and consistent with industry practice, we invest and enter into numerous agreements with other parties to pursue business opportunities, which share costs and apportion risks among the parties as governed by the agreements. Included in such activity are loans made to certain affiliated companies. Significant loans to affiliated companies at September 30, 2007, included the following:

• $648 million in loan financing, including $74 million of accrued interest, to Freeport LNG for the construction of a liquefied natural gas (LNG) facility. We expect to provide loan financing of approximately $631 million for the construction of the facility, excluding accrued interest.

• $303 million in loan financing, including $25 million of accrued interest, to Varandey Terminal Company associated with the costs of a terminal expansion. We expect our total obligation for the terminal expansion to be approximately $410 million at current exchange rates, excluding interest to be accrued during construction.

• $608 million of project financing, including $34 million of accrued interest, to Qatargas 3, an integrated project to produce and liquefy natural gas from Qatar’s North field. Our maximum exposure to this financing structure is $1.2 billion, excluding accrued interest.

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Note 9—Properties, Plants and Equipment

The company’s investment in properties, plants and equipment (PP&E), with accumulated depreciation, depletion and amortization (Accum. DD&A), was:

	Millions of Dollars
	September 30, 2007						December 31, 2006
	Gross		Accum.		Net		Gross		Accum.		Net
	PP&E		DD&A		PP&E		PP&E		DD&A		PP&E
E&P	$	99,574		28,799		70,775		88,592		21,102		67,490
Midstream		332		167		165		330		157		173
R&M		19,252		4,506		14,746		22,115		5,199		16,916
LUKOIL Investment		—		—		—		—		—		—
Chemicals		—		—		—		—		—		—
Emerging Businesses		1,167		130		1,037		1,006		98		908
Corporate and Other		1,355		671		684		1,229		515		714
	$	121,680		34,273		87,407		113,272		27,071		86,201

Suspended Wells

The following table reflects the net changes in suspended exploratory well costs during the first nine months of 2007:

	Millions of Dollars
	Nine Months Ended
	September 30, 2007
Beginning balance at January 1	$	537
Additions pending the determination of proved reserves		100
Reclassifications to proved properties		(24	)
Sales of suspended well investment		(22	)
Charged to dry hole expense		(10	)
Ending balance at September 30	$	581

The following table provides an aging of suspended well balances at September 30, 2007, and December 31, 2006:

	Millions of Dollars
	September 30		December 31
	2007		2006
Exploratory well costs capitalized for a period of one year or less	$	167		225
Exploratory well costs capitalized for a period greater than one year		414		312
Ending balance	$	581		537
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year		36		22

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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 after drilling is completed, as of September 30, 2007:

	Millions of Dollars
			Suspended Since
Project	Total		2006		2005		2004		2003		2002		2001
Alpine satellite—Alaska(2)	$	21		—		—		—		—		21		—
Kashagan—Kazakhstan(1)		18		—		—		—		9		—		9
Aktote—Kazakhstan(2)		19		—		—		7		12		—		—
Kairan—Kazakhstan(2)		13		—		—		13		—		—		—
Gumusut—Malaysia(2)		30		—		6		11		13		—		—
Malikai—Malaysia(2)		45		16		19		10		—		—		—
Plataforma Deltana—Venezuela(2)		21		—		6		15		—		—		—
Uge—Nigeria(1)		15		—		15		—		—		—		—
Su Tu Trang—Vietnam(2)		23		7		8		—		8		—		—
Caldita—Australia(1)		33		—		33		—		—		—		—
Enochdhu/Finlaggen—U.K.(1)		11		11		—		—		—		—		—
Humphrey—U.K.(2)		12		12		—		—		—		—		—
Clair—U.K.(1)		17		17		—		—		—		—		—
K4—U.K.(2)		12		12		—		—		—		—		—
West Sak—Alaska(2)		10		6		3		1		—		—		—
Jasmine—U.K.(1)		28		28		—		—		—		—		—
Twenty projects of less than $10 million each(1)(2)		86		36		33		2		11		4		—
Total of 36 projects	$	414		145		123		59		53		25		9

(1)	Additional appraisal wells planned.
(2)	Appraisal drilling complete; costs being incurred to assess development.

Note 10—Impairments

Expropriated Assets

On January 31, 2007, Venezuela’s National Assembly passed a law allowing the president of Venezuela to pass laws on certain matters by decree. On February 26, 2007, the president of Venezuela issued a decree (the Nationalization Decree) mandating the termination of the then-existing structures related to our heavy-oil ventures and oil production risk contracts and the transfer of all rights relating to our heavy-oil ventures and oil production risk contracts to joint ventures (“empresas mixtas”) that will be controlled by the Venezuelan national oil company or its subsidiaries.

On June 26, 2007, we announced we had been unable to reach agreement with respect to our migration to anempresa mixtastructure mandated by the Nationalization Decree. In response, Petróleos de Venezuela S.A. (PDVSA) or its affiliates directly assumed the activities associated with ConocoPhillips’ interests in the Petrozuata and Hamaca heavy-oil ventures and the offshore Corocoro oil development project. Based on Venezuelan statements that the expropriation of our oil interests in Venezuela occurred on June 26, 2007, management determined such expropriation required a complete impairment, under U.S. generally accepted accounting principles, of our investments in the Petrozuata and Hamaca heavy-oil ventures and the offshore Corocoro oil development project. Accordingly, we recorded a non-cash impairment, including allocable goodwill, of $4,588 million before-tax ($4,512 million after-tax) in the second quarter of 2007.

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The impairment included equity-method investments and properties, plants and equipment. Also, this expropriation of our oil interests is viewed as a partial disposition of our Worldwide Exploration and Production reporting unit and, under the guidance in SFAS No. 142, “Goodwill and Other Intangible Assets,” required an allocation of goodwill to the expropriation event. The amount of goodwill impaired as a result of this allocation was $1,925 million.

Negotiations continue between ConocoPhillips and Venezuelan authorities concerning appropriate compensation for the expropriation of the company’s interests. We continue to preserve all our rights with respect to this situation, including our rights under the contracts we signed and under international and Venezuelan law. We continue to evaluate our options in realizing adequate compensation for the value of our oil investments and operations in Venezuela and expect to file a request for international arbitration on November 2, 2007.

We believe the value of our expropriated Venezuelan oil operations substantially exceeds the historical cost-based carrying value plus goodwill allocable to those operations. Although negotiations continue with Venezuelan authorities, it is not possible to predict with any certainty the outcome of these negotiations. Additionally, should we pursue other means of dispute resolution, U.S. generally accepted accounting principles require a claim that is the subject of litigation be presumed to not be probable of realization. Accordingly, any compensation for our expropriated assets was not considered when making the impairment determination, since to do so could result in the recognition of compensation for the expropriation prior to its realization.

At December 31, 2006, we had recorded 1,088 million barrels of oil equivalent of proved reserves related to Petrozuata and Hamaca, and 17 million barrels of oil equivalent of proved reserves related to Corocoro. The loss of proved reserves related to these projects will be reflected as a downward adjustment in our 2007 reserves.

Other Impairments

During the first nine months of 2007 and 2006, we recognized the following net impairments, excluding impairments of expropriated assets:

	Millions of Dollars
	Three Months Ended					Nine Months Ended
	September 30					September 30
	2007			2006		2007			2006
Asset write-downs
E&P
United States	$	—			—		1			40
International		151			7		326			17
R&M
Goodwill and intangible assets		10			130		8			130
Other		21			130		70			130
Corporate		8			—		8			—
Increase in fair value of previously impaired assets—R&M		(2	)		—		(128	)		—
	$	188			267		285			317

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During the third quarter and nine-month period of 2007, we recorded property impairments primarily for:

• The write-down of held-for-sale assets to fair value, less cost to sell.

• Changes in asset retirement obligations for properties at the end of their economic life.

• The write-down of abandoned properties or projects.

In addition and in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the nine-month period of 2007 included a $128 million gain for the subsequent increase in the fair value of certain assets impaired in the prior year to primarily reflect finalized sales agreements. This gain was netted with write-downs into the “Impairments” line of the consolidated income statement.

Impairments during the third quarter of 2006 included $266 million associated with planned asset dispositions in our E&P and R&M segments. Impairments for the nine-month period of 2006 also included a $40 million property impairment as a result of our decision to withdraw an application for a proposed liquefied natural gas regasification terminal. We also impaired properties due to changes in asset retirement obligation estimates for properties at the end of their economic life.

Note 11—Debt

In September 2007, we replaced our $5 billion and $2.5 billion revolving credit facilities with a $7.5 billion revolving credit facility expiring in September 2012. The new facility contains the same terms as the previous facilities. The facility may be used as direct bank borrowings, as support for the ConocoPhillips $7.5 billion commercial paper program, as support for the ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program, or as support for issuances of letters of credit totaling up to $750 million. At September 30, 2007, and December 31, 2006, we had no outstanding borrowings under our credit facilities, but $41 million in letters of credit had been issued at both dates. Under both commercial paper programs, there was $603 million of commercial paper outstanding at September 30, 2007, compared with $2,931 million at December 31, 2006.

At September 30, 2007, we had classified $603 million of short-term debt as long-term debt, based on our ability and intent to refinance the obligation on a long-term basis under our revolving credit facilities.

At December 31, 2006, Phillips 66 Capital II (Trust II), an unconsolidated VIE, had outstanding $350 million of 8% Capital Securities (Capital Securities). The sole asset of Trust II was $361 million of the company’s 8% Junior Subordinated Deferrable Interest Debentures due 2037 (Subordinated Debt Securities II). Effective January 15, 2007, we redeemed the Subordinated Debt Securities II at a premium of $14 million, plus accrued interest, resulting in the immediate redemption of the Capital Securities. Upon redemption of the Capital Securities, Trust II was liquidated.

In January 2007, we redeemed our $153 million 7.25% Notes due 2007 upon their maturity. In February 2007, we reduced our Floating Rate Five-Year Term Note due 2011 from $5 billion to $4 billion, with a subsequent reduction in July 2007 to $3 billion. In April 2007, we redeemed our $1 billion Floating Rate Notes due 2007 upon their maturity.

In May 2007, Polar Tankers, Inc., a wholly owned subsidiary, issued an offering of $645 million 5.951% Notes due 2037. The notes are fully and unconditionally guaranteed by ConocoPhillips and ConocoPhillips Company.

On October 31, 2007, we redeemed $300 million of ConocoPhillips Australia Funding Company’s Floating Rate Notes due 2009 at par plus accrued interest.

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Note 12—Contingencies and Commitments

In the case of all known non-income-tax-related contingencies, we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. 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. In the case of income-tax-related contingencies, we adopted FIN 48, effective January 1, 2007. FIN 48 requires a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain. See Note 2—Changes in Accounting Principles and Note 21—Income Taxes, for additional information about income-tax related contingencies.

Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates that are particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes.

Environmental

We are subject to federal, state and local environmental laws and regulations. These may result in obligations to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various sites. When we prepare our financial statements, we record accruals for environmental liabilities based on management’s best estimates, using all information that is available at the time. We measure estimates and base liabilities on currently available facts, existing technology, and presently enacted laws and regulations, taking into consideration the likely effects of societal and economic factors. When measuring environmental liabilities, we also consider our prior experience in remediation of contaminated sites, other companies’ cleanup experience, and data released by the U.S. Environmental Protection Agency (EPA) or other organizations. We consider unasserted claims in our determination of environmental liabilities and we accrue them in the period that they are both probable and reasonably estimable.

Although liability of those potentially responsible for environmental remediation costs is generally joint and several for federal sites and frequently so for state sites, we are usually only one of many companies cited at a particular site. Due to the joint and several liabilities, we could be responsible for all of the cleanup costs related to any site at which we have been designated as a potentially responsible party. If 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.

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

We are currently participating in environmental assessments and cleanups at numerous federal Superfund and comparable state sites. After an assessment of environmental exposures for cleanup and other costs, we make accruals on an undiscounted basis (except for those acquired 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, 2007, our balance sheet included a total environmental accrual of $1,042 million, compared with $1,062 million at December 31, 2006. 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

Our legal organization applies its 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 those cases which have been scheduled for trial, as well as the 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, our legal organization believes 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 consolidated 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, at September 30, 2007, we had performance obligations secured by letters of credit totaling $1,041 million (of which $41 million was issued under the provisions of our revolving credit facilities, and the remainder was issued as direct bank letters of credit) and various purchase commitments for materials, supplies, services and items of permanent investment incident to the ordinary conduct of business.

See Note 10—Impairments, for additional information about expropriated assets in Venezuela and the contingencies related to receiving adequate compensation for our oil interests in Venezuela.

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Note 13—Guarantees

At September 30, 2007, 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, we have not recognized a liability either because the guarantees were issued prior to December 31, 2002, or because the fair value of the obligation is immaterial.

Construction Completion Guarantees

• In June 2006, we issued a guarantee for 24 percent of the $2 billion in credit facilities of Rockies Express Pipeline LLC (Rockies Express), which will be used to construct a natural gas pipeline across a portion of the United States. At September 30, 2007, Rockies Express had $1,758 million outstanding under the credit facilities, with our 24 percent guarantee equaling $422 million. The maximum potential amount of future payments to third-party lenders under the guarantee is estimated to be $480 million, which could become payable if the credit facility is fully utilized and Rockies Express fails to meet its obligations under the credit agreement. In addition, we also have a guarantee for 24 percent of $600 million of Floating Rate Notes due 2009 issued by Rockies Express in September 2007. It is anticipated that construction completion will be achieved at the end of 2009, and refinancing will take place at that time, making the debt non-recourse. At September 30, 2007, the total carrying value of these guarantees to third-party lenders was $12 million. See Note 5—Variable Interest Entities (VIEs), for additional information.

• In December 2005, we issued a construction completion guarantee for 30 percent of the $4.0 billion in loan facilities of Qatargas 3, which will be used to construct an LNG train in Qatar. Of the $4.0 billion in loan facilities, ConocoPhillips has committed to provide $1.2 billion. The maximum potential amount of future payments to third-party lenders under the guarantee is estimated to be $850 million, which could become payable if the full debt financing is utilized and completion of the Qatargas 3 project is not achieved. The project financing will be non-recourse upon certified completion, which is expected in 2010. At September 30, 2007, the carrying value of the guarantee to the third-party lenders was $11 million. For additional information, see Note 8—Investments, Loans and Long-Term Receivables.

Guarantees of Joint-Venture Debt

• At September 30, 2007, we had guarantees outstanding for our portion of joint-venture debt obligations, which have terms of up to 17 years. The maximum potential amount of future payments under the guarantees is approximately $130 million. Payment would be required if a joint venture defaults on its debt obligations.

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 the venture does not have enough cash to cover operating expenses after setting aside the amount required for debt service over the next 17 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.

• In February 2003, we entered into two agreements establishing separate guarantee facilities of $50 million each for two LNG 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

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	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 $100 million in total. To the extent we receive any such payments, our actual gross payments over the 20 years could exceed that amount. 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.
•	We have guarantees of the residual value of leased corporate aircraft. The maximum potential payment under these guarantees at September 30, 2007, was $150 million.
•	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, guarantees to fund the short-term cash liquidity deficits of certain joint ventures, two small construction completion guarantees, a guarantee associated with a pending lawsuit, guarantees relating to the startup of a refining joint venture, a guarantee supporting a third-party pipeline construction and guarantees of the lease payment obligations of a joint venture. The carrying amount recorded for these other guarantees, at September 30, 2007, was $55 million. These guarantees generally extend up to 15 years and payment would be required only if the dealer, jobber or lessee goes into default, if the joint ventures have cash liquidity issues, if construction projects are not completed, if guaranteed parties default on lease payments, or if an adverse decision occurs in the pending lawsuit.

Indemnifications

Over the years, we have entered into various agreements to sell ownership interests in certain corporations and joint ventures and have sold several assets, including downstream and midstream assets, certain exploration and production assets, and downstream retail and wholesale sites that gave 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 at September 30, 2007, was $457 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 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 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 $280 million of environmental accruals for known contamination that is included in asset retirement obligations and accrued environmental costs at September 30, 2007. For additional information about environmental liabilities, see Note 12—Contingencies and Commitments.

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Note 14—Financial Instruments and Derivative Contracts

Derivative assets and liabilities were:

	Millions of Dollars
	September 30		December 31
	2007		2006
Derivative Assets
Current	$	545		924
Long-term		97		82
	$	642		1,006
Derivative Liabilities
Current	$	533		681
Long-term		58		126
	$	591		807

These derivative assets and liabilities appear as prepaid expenses and other current assets, other assets, other accruals, or other liabilities and deferred credits on the balance sheet.

Note 15—Comprehensive Income

ConocoPhillips’ comprehensive income was as follows:

	Millions of Dollars
	Three Months Ended						Nine Months Ended
	September 30						September 30
	2007			2006			2007			2006
Net income	$	3,673			3,876			7,520			12,353
After-tax changes in:
Defined benefit pension plans
Net prior service cost		5			—			15			—
Net actuarial loss		8			—			38			—
Non-sponsored plans		—			—			(3	)		—
Foreign currency translation adjustments		1,320			(32	)		2,596			906
Hedging activities		(2	)		(5	)		(5	)		2
Comprehensive income	$	5,004			3,839			10,161			13,261

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

	Millions of Dollars
	September 30			December 31
	2007			2006
Defined benefit pension plans	$	(615	)		(665	)
Foreign currency translation adjustments		4,554			1,958
Deferred net hedging loss		(9	)		(4	)
Accumulated other comprehensive income	$	3,930			1,289

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Note 16—Supplemental Cash Flow Information

	Millions of Dollars
	Nine Months Ended
	September 30
	2007		2006
Non-Cash Investing and Financing Activities
Issuance of stock and options for the acquisition of Burlington Resources Inc.	$	—		16,343
Investment in an upstream business venture through issuance of an acquisition obligation		7,313		—
Investment in a downstream business venture through contribution of non-cash assets and liabilities		2,415		—
Cash Payments
Interest	$	650		514
Income taxes		7,969		9,313

Note 17—Joint Venture Acquisition Obligation

On January 3, 2007, we closed on a business venture with EnCana Corporation. As part of this transaction, we expect to add approximately 400 million barrels of oil equivalent to our proved reserves in 2007. In addition, we are obligated to contribute $7.5 billion, plus accrued interest, over a 10-year period, beginning in 2007, to the upstream business venture, FCCL Oil Sands Partnership, formed as a result of the transaction. An initial cash contribution of $188 million was made upon closing in January.

Quarterly principal and interest payments of $237 million began in the second quarter of 2007, and will continue until the balance is paid. This obligation is reflected as a liability on our September 30, 2007, consolidated balance sheet. Of the principal obligation amount, approximately $586 million is short-term and is included in the “Accounts payable—related parties” line on our consolidated balance sheet. The principal portion of these payments is presented on our consolidated statement of cash flows as an other financing activity. Interest accrues at a fixed annual rate of 5.3 percent on the unpaid principal balance. Fifty percent of the quarterly interest payment is reflected as an investment purchase and is included in the “Capital expenditures and investments” line on our consolidated statement of cash flows.

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Note 18—Employee Benefit Plans

Pension and Postretirement Plans

	Millions of Dollars
	Pension Benefits												Other Benefits
	September 30												September 30
Components of Net Periodic Benefit Cost	2007						2006						2007			2006
	U.S.			Int’l.			U.S.			Int’l.
Three Months Ended
Service cost	$	44			25			44			22			3			4
Interest cost		57			41			54			34			12			12
Expected return on plan assets		(51	)		(37	)		(43	)		(31	)		—			—
Amortization of prior service cost		3			1			2			2			3			4
Recognized net actuarial loss (gain)		15			12			22			10			(5	)		(4	)
Net periodic benefit costs	$	68			42			79			37			13			16
Nine Months Ended
Service cost	$	132			73			130			65			10			11
Interest cost		171			120			157			99			34			35
Expected return on plan assets		(153	)		(109	)		(126	)		(91	)		—			—
Amortization of prior service cost		8			5			7			6			10			14
Recognized net actuarial loss (gain)		46			35			66			30			(15	)		(12	)
Net periodic benefit costs	$	204			124			234			109			39			48

During the first nine months of 2007, we contributed $415 million to our domestic qualified and non-qualified plans and $135 million to our international benefit plans. We currently expect to contribute a total of $440 million to our domestic plans and $195 million to our international plans in 2007.

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Note 19—Related Party Transactions

Significant transactions with related parties were:

	Millions of Dollars
	Three Months Ended					Nine Months Ended
	September 30					September 30
	2007		2006		*	2007		2006		*
Revenues and other income (a)	$	2,465		2,391			7,967		6,610
Purchases (b)		4,156		1,966			11,455		5,286
Operating expenses and selling, general and administrative expenses (c)		103		103			309		282
Net interest income (d)		25		2			80		10

*Restated to include additional related party amounts.

(a)	We sold natural gas to DCP Midstream and crude oil to the Malaysian Refining Company Sdn. Bhd (MRC), among others, for processing and marketing. Natural gas liquids, solvents and petrochemical feedstocks were sold to Chevron Phillips Chemical Company LLC (CPChem), gas oil and hydrogen feedstocks were sold to Excel Paralubes, and refined products were sold primarily to CFJ Properties and LUKOIL. Natural gas, crude oil, blendstock and other intermediate products were sold to WRB Refining LLC. We also sold various international marketing companies to LUKOIL in the second quarter of 2007. In addition, we charged several of our affiliates, including CPChem, Merey Sweeny L.P. (MSLP), and Hamaca Holding LLC, (up through June 25, 2007) for the use of common facilities, such as steam generators, waste and water treaters, and warehouse facilities.
(b)	We purchased refined products from WRB Refining. We purchased natural gas and natural gas liquids from DCP Midstream and CPChem for use in our refinery processes and other feedstocks from various affiliates. We purchased crude oil from LUKOIL, upgraded crude oil from Petrozuata C.A. (up through June 25, 2007) and refined products from MRC. We also paid fees to various pipeline equity companies for transporting finished refined products and a price upgrade to MSLP for heavy crude processing. We purchased base oils and fuel products from Excel Paralubes for use in our refinery and specialty businesses.
(c)	We paid processing fees to various affiliates. Additionally, we paid crude oil transportation fees to pipeline equity companies.
(d)	We paid and/or received interest to/from various affiliates, including FCCL Oil Sands Partnership.

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

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Note 20—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 September 30, 2007, our E&P operations were producing in the United States, Norway, the United Kingdom, the Netherlands, Canada, Nigeria, Ecuador, Argentina, offshore Timor Leste in the Timor Sea, Australia, China, Indonesia, Algeria, Libya, Vietnam, and Russia. The E&P segment’s U.S. and international operations are disclosed separately for reporting purposes.
2)	Midstream—This segment gathers, processes and markets natural gas produced by ConocoPhillips and others, and fractionates and markets natural gas liquids, primarily in the United States and Trinidad. The Midstream segment primarily consists of our 50 percent equity investment in DCP Midstream.
3)	R&M—This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia. At September 30, 2007, we owned or had an interest in 12 refineries in the United States, one in the United Kingdom, one in Ireland, two in Germany, 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. At September 30, 2007, our ownership interest was 20 percent, based on issued shares, and 20.5 percent, based on estimated shares outstanding.
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—The Emerging Businesses segment represents our investment in new technologies or businesses outside our normal scope of operations. Activities within this segment are currently focused on power generation and other items, such as carbon-to-liquids, technology solutions, and alternative energy and programs, such as advanced hydrocarbon processes, energy conversion technologies, new petroleum-based products, and renewable fuels.

Corporate and Other includes general corporate overhead, most interest income and expense, restructuring charges, 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.

See Note 2—Changes in Accounting Principles, for information affecting the comparability of sales and other operating revenues presented in the following tables of our segment disclosures.

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Analysis of Results by Operating Segment

	Millions of Dollars
	Three Months Ended						Nine Months Ended
	September 30						September 30
	2007			2006			2007			2006
Sales and Other Operating Revenues
E&P
United States	$	9,416			9,040			27,153			27,157
International		5,559			6,552			17,052			21,076
Intersegment eliminations—U.S.		(1,612	)		(1,564	)		(4,264	)		(4,286	)
Intersegment eliminations—international		(1,927	)		(1,869	)		(4,844	)		(5,244	)
E&P		11,436			12,159			35,097			38,703
Midstream
Total sales		1,182			1,012			3,396			3,212
Intersegment eliminations		(39	)		(265	)		(143	)		(796	)
Midstream		1,143			747			3,253			2,416
R&M
United States		24,369			25,240			69,022			73,681
International		9,178			10,107			27,606			27,819
Intersegment eliminations—U.S.		(113	)		(211	)		(376	)		(612	)
Intersegment eliminations—international		(2	)		(5	)		(7	)		(14	)
R&M		33,432			35,131			96,245			100,874
LUKOIL Investment		—			—			—			—
Chemicals		2			3			8			10
Emerging Businesses
Total sales		150			167			450			483
Intersegment eliminations		(105	)		(133	)		(310	)		(361	)
Emerging Businesses		45			34			140			122
Corporate and Other		4			2			9			6
Consolidated sales and other operating revenues	$	46,062			48,076			134,752			142,131
Net Income (Loss)
E&P
United States	$	1,225			995			3,196			3,476
International		857			909			(1,189	)		4,285
Total E&P		2,082			1,904			2,007			7,761
Midstream		104			169			291			387
R&M
United States		873			1,444			3,648			3,174
International		434			20			1,153			388
Total R&M		1,307			1,464			4,801			3,562
LUKOIL Investment		387			487			1,169			1,123
Chemicals		110			142			260			394
Emerging Businesses		3			11			(10	)		7
Corporate and Other		(320	)		(301	)		(998	)		(881	)
Consolidated net income	$	3,673			3,876			7,520			12,353

23

	Millions of Dollars
	September 30		December 31
	2007		2006
Total Assets
E&P
United States	$	34,550		35,523
International		56,414		48,143
Goodwill		25,617		27,712
Total E&P		116,581		111,378
Midstream		2,026		2,045
R&M
United States		24,737		22,936
International		9,225		9,135
Goodwill		3,757		3,776
Total R&M		37,719		35,847
LUKOIL Investment		10,622		9,564
Chemicals		2,331		2,379
Emerging Businesses		1,104		977
Corporate and Other		3,044		2,591
Consolidated total assets	$	173,427		164,781

Note 21—Income Taxes

Our effective tax rate for the third quarter and first nine months of 2007 was 42 percent and 53 percent, respectively, compared with 51 percent and 45 percent for the same two periods of 2006. The change in the effective tax rate for the third quarter of 2007, versus the third quarter of 2006, was primarily due to a tax rate increase enacted in the United Kingdom in the third quarter of 2006, the effect of our asset rationalization efforts, and a tax rate decrease enacted in Germany in the third quarter of 2007. The change in the effective rate for the nine months of 2007, compared with the same period of 2006, was primarily due to the impact of the expropriation of our oil interests in Venezuela in the second quarter of 2007 (see Note 10—Impairments, for additional information). This impact was partially offset by a higher proportion of income in higher-tax-rate jurisdictions for the first nine months of 2006. The effective tax rate in excess of the domestic federal statutory rate of 35 percent was primarily due to the impact of foreign taxes.

Effective January 1, 2007, we adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109.” See Note 2—Changes in Accounting Principles, for additional information about the adoption of this Interpretation.

Unrecognized tax benefits increased to $1,120 million at September 30, 2007, mainly due to increases occurring in the second quarter related to tax positions taken during the current year. Included in this balance is $676 million which, if recognized, would affect our effective tax rate.

We and our subsidiaries file tax returns in the U.S. Federal jurisdiction and in many foreign and state jurisdictions. Audits in major jurisdictions, including the United States, Canada, Norway and the United Kingdom, are generally complete through 2001. Issues in dispute for audited years and audits for subsequent years are ongoing and in various stages of completion in the many jurisdictions in which we operate around the world. As a consequence, the balance in unrecognized tax benefits can be expected to fluctuate from period to period. It is reasonably possible that such changes could be significant when compared to our total unrecognized tax benefits, but the amount of change is not estimable.

24

Note 22—New Accounting Standards

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This Statement defines fair value, establishes a framework for its measurement and expands disclosures about fair value measurements. We use fair value measurements to measure, among other items, purchased assets and investments, leases, derivative contracts and financial guarantees. We also use them to assess impairment of properties, plants and equipment, intangible assets and goodwill. The Statement does not apply to share-based payment transactions and inventory pricing. We plan to adopt this Statement effective January 1, 2008. We continue to evaluate the Statement, but we do not expect any significant impact to our consolidated financial statements, other than additional disclosures.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115.” This Statement permits an entity to choose to measure financial instruments and certain other items similar to financial instruments at fair value, with all subsequent changes in fair value for the financial instrument reported in earnings. By electing the fair value option in conjunction with a derivative, an entity can achieve an accounting result similar to a fair-value hedge without having to comply with complex hedge accounting rules. We plan to adopt this Statement effective January 1, 2008, and do not expect any significant impact to our consolidated financial statements.

25

Supplementary Information—Condensed Consolidating Financial Information

We have various cross guarantees among ConocoPhillips, ConocoPhillips Company, ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada Funding Company II, with respect to publicly held debt securities. ConocoPhillips Company is wholly owned by ConocoPhillips. ConocoPhillips Australia Funding Company is an indirect, wholly owned subsidiary of ConocoPhillips Company. ConocoPhillips Canada Funding Company I and ConocoPhillips Canada Funding Company II are indirect, wholly owned subsidiaries of ConocoPhillips. ConocoPhillips and ConocoPhillips Company have fully and unconditionally guaranteed the payment obligations of ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada Funding Company II, with respect to their publicly held debt securities. Similarly, ConocoPhillips has fully and unconditionally guaranteed the payment obligations of ConocoPhillips Company with respect to its publicly held debt securities. In addition, 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, ConocoPhillips Company, ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada Funding Company II (in each case, reflecting investments in subsidiaries utilizing the equity method of accounting).

• All other non-guarantor subsidiaries of ConocoPhillips.

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

This condensed consolidating financial information should be read in conjunction with the accompanying consolidated financial statements and notes. Certain prior year amounts have been reclassified to conform to current period presentation.

26

	Millions of Dollars
	Three Months Ended September 30, 2007
							ConocoPhillips
							Australia		ConocoPhillips			ConocoPhillips
				ConocoPhillips			Funding		Canada Funding			Canada Funding			All Other			Consolidating			Total
	ConocoPhillips			Company			Company		Company I			Company II			Subsidiaries			Adjustments			Consolidated
Income Statement
Revenues and Other Income
Sales and other operating revenues	$	—			30,130			—		—			—			15,932			—			46,062
Equity in earnings of affiliates		3,731			3,227			—		—			—			602			(6,246	)		1,314
Other income		—			(74	)		—		—			—			631			—			557
Intercompany revenues		1			814			30		21			13			4,648			(5,527	)		—
Total Revenues and Other Income		3,732			34,097			30		21			13			21,813			(11,773	)		47,933
Costs and Expenses
Purchased crude oil, natural gas and products		—			26,477			—		—			—			9,211			(4,826	)		30,862
Production and operating expenses		—			1,054			—		—			—			1,588			(22	)		2,620
Selling, general and administrative expenses		4			365			—		—			—			212			(12	)		569
Exploration expenses		—			29			—		—			—			189			—			218
Depreciation, depletion and amortization		—			388			—		—			—			1,664			—			2,052
Impairment—expropriated assets		—			—			—		—			—			—			—			—
Impairments		—			16			—		—			—			172			—			188
Taxes other than income taxes		—			1,363			—		—			—			3,291			(71	)		4,583
Accretion on discounted liabilities		—			12			—		—			—			69			—			81
Interest and debt expense		85			236			28		20			14			604			(596	)		391
Foreign currency transaction (gains) losses		—			6			—		83			44			(153	)		—			(20	)
Minority interests		—			—			—		—			—			25			—			25
Total Costs and Expenses		89			29,946			28		103			58			16,872			(5,527	)		41,569
Income (loss) before income taxes		3,643			4,151			2		(82	)		(45	)		4,941			(6,246	)		6,364
Provision for income taxes		(30	)		581			—		11			6			2,123			—			2,691
Net Income (Loss)	$	3,673			3,570			2		(93	)		(51	)		2,818			(6,246	)		3,673

27

	Millions of Dollars
	Three Months Ended September 30, 2006
						ConocoPhillips
				ConocoPhillips		Australia Funding		All Other			Consolidating			Total
	ConocoPhillips			Company		Company		Subsidiaries			Adjustments			Consolidated
Income Statement
Revenues and Other Income
Sales and other operating revenues	$	—			30,727		—		17,349			—			48,076
Equity in earnings of affiliates		3,972			2,460		—		1,005			(6,241	)		1,196
Other income		—			253		—		60			—			313
Intercompany revenues		28			673		38		4,654			(5,393	)		—
Total Revenues and Other Income		4,000			34,113		38		23,068			(11,634	)		49,585
Costs and Expenses
Purchased crude oil, natural gas and products		—			25,463		—		9,977			(4,889	)		30,551
Production and operating expenses		—			1,090		—		1,573			(23	)		2,640
Selling, general and administrative expenses		3			427		—		231			(11	)		650
Exploration expenses		—			18		—		179			—			197
Depreciation, depletion and amortization		—			438		—		1,699			—			2,137
Impairments		—			166		—		101			—			267
Taxes other than income taxes		—			1,498		—		3,423			(68	)		4,853
Accretion on discounted liabilities		—			14		—		60			—			74
Interest and debt expense		172			275		28		235			(402	)		308
Foreign currency transaction gains		—			—		—		(50	)		—			(50	)
Minority interests		—			—		—		21			—			21
Total Costs and Expenses		175			29,389		28		17,449			(5,393	)		41,648
Income before income taxes		3,825			4,724		10		5,619			(6,241	)		7,937
Provision for income taxes		(51	)		934		3		3,175			—			4,061
Net Income	$	3,876			3,790		7		2,444			(6,241	)		3,876

28

	Millions of Dollars
	Nine Months Ended September 30, 2007
							ConocoPhillips
							Australia		ConocoPhillips			ConocoPhillips
				ConocoPhillips			Funding		Canada Funding			Canada Funding			All Other			Consolidating			Total
	ConocoPhillips			Company			Company		Company I			Company II			Subsidiaries			Adjustments			Consolidated
Income Statement
Revenues and Other Income
Sales and other operating revenues	$	—			87,022			—		—			—			47,730			—			134,752
Equity in earnings of affiliates		7,623			6,881			—		—			—			1,927			(12,682	)		3,749
Other income		4			(254	)		—		—			—			1,946			—			1,696
Intercompany revenues		148			2,303			90		60			37			13,215			(15,853	)		—
Total Revenues and Other Income		7,775			95,952			90		60			37			64,818			(28,535	)		140,197
Costs and Expenses
Purchased crude oil, natural gas and products		—			74,279			—		—			—			27,831			(13,713	)		88,397
Production and operating expenses		—			3,249			—		—			—			4,484			(64	)		7,669
Selling, general and administrative expenses		13			1,053			—		—			—			676			(42	)		1,700
Exploration expenses		—			75			—		—			—			664			—			739
Depreciation, depletion and amortization		—			1,111			—		—			—			4,981			—			6,092
Impairment—expropriated assets		—			1,925			—		—			—			2,663			—			4,588
Impairments		—			(8	)		—		—			—			293			—			285
Taxes other than income taxes		—			4,161			—		—			—			9,701			(208	)		13,654
Accretion on discounted liabilities		—			40			—		—			—			201			—			241
Interest and debt expense		296			882			84		58			40			1,483			(1,826	)		1,017
Foreign currency transaction (gains) losses		—			16			—		181			121			(516	)		—			(198	)
Minority interests		—			—			—		—			—			65			—			65
Total Costs and Expenses		309			86,783			84		239			161			52,526			(15,853	)		124,249
Income (loss) before income taxes		7,466			9,169			6		(179	)		(124	)		12,292			(12,682	)		15,948
Provision for income taxes		(54	)		2,255			2		9			4			6,212			—			8,428
Net Income (Loss)	$	7,520			6,914			4		(188	)		(128	)		6,080			(12,682	)		7,520

29

	Millions of Dollars
	Nine Months Ended September 30, 2006
						ConocoPhillips
				ConocoPhillips		Australia Funding		All Other			Consolidating			Total
	ConocoPhillips			Company		Company		Subsidiaries			Adjustments			Consolidated
Income Statement
Revenues and Other Income
Sales and other operating revenues	$	—			90,113		—		52,018			—			142,131
Equity in earnings of affiliates		12,585			8,627		—		2,841			(20,733	)		3,320
Other income		—			302		—		235			—			537
Intercompany revenues		49			1,898		64		11,489			(13,500	)		—
Total Revenues and Other Income		12,634			100,940		64		66,583			(34,233	)		145,988
Costs and Expenses
Purchased crude oil, natural gas and products		—			75,380		—		30,410			(12,336	)		93,454
Production and operating expenses		—			3,493		—		4,129			(73	)		7,549
Selling, general and administrative expenses		13			1,177		—		675			(39	)		1,826
Exploration expenses		—			49		—		394			—			443
Depreciation, depletion and amortization		—			1,276		—		4,006			—			5,282
Impairments		—			204		—		113			—			317
Taxes other than income taxes		—			4,439		—		9,422			(200	)		13,661
Accretion on discounted liabilities		—			43		—		164			—			207
Interest and debt expense		392			656		52		535			(852	)		783
Foreign currency transaction gains		—			—		—		(10	)		—			(10	)
Minority interests		—			—		—		60			—			60
Total Costs and Expenses		405			86,717		52		49,898			(13,500	)		123,572
Income before income taxes		12,229			14,223		12		16,685			(20,733	)		22,416
Provision for income taxes		(124	)		2,357		4		7,826			—			10,063
Net Income	$	12,353			11,866		8		8,859			(20,733	)		12,353

30

	Millions of Dollars
	At September 30, 2007
							ConocoPhillips
							Australia		ConocoPhillips			ConocoPhillips
				ConocoPhillips			Funding		Canada Funding			Canada Funding			All Other		Consolidating			Total
	ConocoPhillips			Company			Company		Company I			Company II			Subsidiaries		Adjustments			Consolidated
Balance Sheet
Assets
Cash and cash equivalents	$	—			73			—		—			1			1,678		(373	)		1,379
Accounts and notes receivable		73			11,200			331		12			4			18,760		(16,602	)		13,778
Inventories		—			2,942			—		—			—			2,374		(4	)		5,312
Prepaid expenses and other current assets		4			825			—		—			—			2,341		—			3,170
Total Current Assets		77			15,040			331		12			5			25,153		(16,979	)		23,639
Investments, loans and long-term receivables*		89,198			79,337			1,700		1,473			997			45,498		(186,460	)		31,743
Net properties, plants and equipment		—			17,198			—		—			—			70,196		13			87,407
Goodwill		—			12,757			—		—			—			16,617		—			29,374
Intangibles		—			813			—		—			—			86		—			899
Other assets		8			147			4		5			5			445		(249	)		365
Total Assets		89,283			125,292			2,035		1,490			1,007			157,995		(203,675	)		173,427
Liabilities and Stockholders’ Equity
Accounts payable		18			18,668			—		9			4			14,160		(16,602	)		16,257
Notes payable and long-term debt due within one year		—			12			300		—			—			93		—			405
Accrued income and other taxes		—			518			—		1			—			4,125		97			4,741
Employee benefit obligations		—			434			—		—			—			305		1			740
Other accruals		45			705			35		33			23			1,096		(2	)		1,935
Total Current Liabilities		63			20,337			335		43			27			19,779		(16,506	)		24,078
Long-term debt		4,393			6,000			1,699		1,250			848			7,281		—			21,471
Asset retirement obligations and accrued environmental costs		—			1,003			—		—			—			5,558		—			6,561
Joint venture acquisition obligation		—			—			—		—			—			6,445		—			6,445
Deferred income taxes		(3	)		3,199			—		26			16			17,675		11			20,924
Employee benefit obligations		—			2,197			—		—			—			1,222		—			3,419
Other liabilities and deferred credits*		4,623			32,473			—		149			100			30,349		(65,278	)		2,416
Total Liabilities		9,076			65,209			2,034		1,468			991			88,309		(81,773	)		85,314
Minority interests		—			(19	)		—		—			—			1,201		(2	)		1,180
Retained earnings		40,268			29,842			1		(159	)		(102	)		33,480		(56,540	)		46,790
Other stockholders’ equity		39,939			30,260			—		181			118			35,005		(65,360	)		40,143
Total	$	89,283			125,292			2,035		1,490			1,007			157,995		(203,675	)		173,427

* Includes intercompany loans.

31

	Millions of Dollars
	At December 31, 2006
							ConocoPhillips
							Australia		ConocoPhillips			ConocoPhillips
				ConocoPhillips			Funding		Canada Funding			Canada Funding			All Other		Consolidating			Total
	ConocoPhillips			Company			Company		Company I			Company II			Subsidiaries		Adjustments			Consolidated
Balance Sheet
Assets
Cash and cash equivalents	$	—			116			—		—			1			1,042		(342	)		817
Accounts and notes receivable		65			13,233			22		10			2			17,224		(16,450	)		14,106
Inventories		—			2,906			—		—			—			2,247		—			5,153
Prepaid expenses and other current assets		11			895			—		10			7			4,067		—			4,990
Total Current Assets		76			17,150			22		20			10			24,580		(16,792	)		25,066
Investments, loans and long-term receivables*		86,292			58,530			2,000		1,241			841			28,372		(156,563	)		20,713
Net properties, plants and equipment		—			19,072			—		—			—			67,122		7			86,201
Goodwill		—			15,226			—		—			—			16,262		—			31,488
Intangibles		—			852			—		—			—			99		—			951
Other assets		10			141			5		35			24			195		(48	)		362
Total Assets		86,378			110,971			2,027		1,296			875			136,630		(173,396	)		164,781
Liabilities and Stockholders’ Equity
Accounts payable		68			16,641			—		5			3			14,367		(16,450	)		14,634
Notes payable and long-term debt due within one year		3,431			525			—		—			—			87		—			4,043
Accrued income and other taxes		—			732			—		—			—			3,577		98			4,407
Employee benefit obligations		—			464			—		—			—			431		—			895
Other accruals		50			804			24		16			10			1,565		(17	)		2,452
Total Current Liabilities		3,549			19,166			24		21			13			20,027		(16,369	)		26,431
Long-term debt		6,521			6,036			1,999		1,250			848			6,437		—			23,091
Asset retirement obligations and accrued environmental costs		—			1,095			—		—			—			4,524		—			5,619
Deferred income taxes		(8	)		2,969			—		16			10			17,086		1			20,074
Employee benefit obligations		—			2,379			—		—			—			1,288		—			3,667
Other liabilities and deferred credits*		29			28,306			—		—			—			22,300		(48,584	)		2,051
Total Liabilities		10,091			59,951			2,023		1,287			871			71,662		(64,952	)		80,933
Minority interests		—			(19	)		—		—			—			1,221		—			1,202
Retained earnings		34,756			22,939			4		29			26			28,029		(44,491	)		41,292
Other stockholders’ equity		41,531			28,100			—		(20	)		(22	)		35,718		(63,953	)		41,354
Total	$	86,378			110,971			2,027		1,296			875			136,630		(173,396	)		164,781

*Includes intercompany loans.

32

	Millions of Dollars
	Nine Months Ended September 30, 2007
							ConocoPhillips
							Australia			ConocoPhillips		ConocoPhillips
				ConocoPhillips			Funding			Canada Funding		Canada Funding		All Other			Consolidating			Total
	ConocoPhillips			Company			Company			Company I		Company II		Subsidiaries			Adjustments			Consolidated
Statement of Cash Flows
Cash Flows From Operating Activities
Net Cash Provided by (Used in) Operating Activities	$	11,862			(2,048	)		7			—		—		8,473			(664	)		17,630
Cash Flows From Investing Activities
Acquisition of Burlington Resources Inc.		—			—			—			—		—		—			—			—
Capital expenditures and investments, including dry hole costs		—			(1,821	)		—			—		—		(6,288	)		202			(7,907	)
Proceeds from asset dispositions		—			1,299			—			—		—		2,604			(846	)		3,057
Long-term advances/loans to affiliates		—			(143	)		—			—		—		(2,486	)		2,180			(449	)
Collection of advances/loans to affiliates		—			954			—			—		—		1			(889	)		66
Other		1			22			—			—		—		1			—			24
Net Cash Provided by (Used in) Investing Activities		1			311			—			—		—		(6,168	)		647			(5,209	)
Cash Flows From Financing Activities
Issuance of debt		(36	)		2,179			—			—		—		861			(2,180	)		824
Repayment of debt		(5,564	)		(561	)		—			—		—		(905	)		889			(6,141	)
Issuance of company common stock		251			—			—			—		—		—			—			251
Repurchase of company common stock		(4,501	)		—			—			—		—		—			—			(4,501	)
Dividends paid on company common stock		(2,009	)		—			(7	)		—		—		(626	)		633			(2,009	)
Other		(4	)		76			—			—		—		(1,005	)		644			(289	)
Net Cash Provided by (Used in) Financing Activities		(11,863	)		1,694			(7	)		—		—		(1,675	)		(14	)		(11,865	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents		—			—			—			—		—		6			—			6
Net Change in Cash and Cash Equivalents		—			(43	)		—			—		—		636			(31	)		562
Cash and cash equivalents at beginning of year		—			116			—			—		1		1,042			(342	)		817
Cash and Cash Equivalents at End of Year	$	—			73			—			—		1		1,678			(373	)		1,379

33

	Millions of Dollars
	Nine Months Ended September 30, 2006
							ConocoPhillips
				ConocoPhillips			Australia Funding			All Other			Consolidating			Total
	ConocoPhillips			Company			Company			Subsidiaries			Adjustments			Consolidated
Statement of Cash Flows
Cash Flows From Operating Activities
Net Cash Provided by Operating Activities	$	28,139			2,881			—			5,780			(20,921	)		15,879
Cash Flows From Investing Activities
Acquisition of Burlington Resources Inc.		—			—			—			(14,285	)		—			(14,285	)
Capital expenditures and investments, including dry holes		(17,494	)		(2,760	)		—			(9,404	)		18,145			(11,513	)
Proceeds from asset dispositions		—			4			—			242			—			246
Long-term advances/loans to affiliates and other investments		(14,989	)		(241	)		(1,992	)		(3,771	)		20,361			(632	)
Collection of advances/loans to affiliates		—			2,513			—			1,107			(3,505	)		115
Net Cash Used in Investing Activities		(32,483	)		(484	)		(1,992	)		(26,111	)		35,001			(26,069	)
Cash Flows From Financing Activities
Issuance of debt		12,968			18,369			2,000			2,287			(20,361	)		15,263
Repayment of debt		(6,400	)		(1,259	)		—			(171	)		3,505			(4,325	)
Issuance of company common stock		145			—			—			—			—			145
Repurchase of company common stock		(675	)		—			—			—			—			(675	)
Dividends paid on company common stock		(1,684	)		(20,000	)		(1	)		(748	)		20,749			(1,684	)
Other		(10	)		(58	)		(7	)		18,097			(18,145	)		(123	)
Net Cash Provided by (Used in) Financing Activities		4,344			(2,948	)		1,992			19,465			(14,252	)		8,601
Effect of Exchange Rate Changes on Cash and Cash Equivalents		—			—			—			71			—			71
Net Change in Cash and Cash Equivalents		—			(551	)		—			(795	)		(172	)		(1,518	)
Cash and cash equivalents at beginning of year		—			613			—			1,601			—			2,214
Cash and Cash Equivalents at End of Period	$	—			62			—			806			(172	)		696

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

Management’s Discussion and Analysis contains forward-looking statements including, without limitation, statements relating to our plans, strategies, objectives, expectations, and intentions, that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “intends,” “believes,” “expects,” “plans,” “scheduled,” “anticipates,” “estimates,” and similar expressions identify forward-looking statements. We do not undertake to update, revise or correct any of the forward-looking information. Readers are cautioned that such forward-looking statements should be read in conjunction with the disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995” beginning on page 58.

BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW

ConocoPhillips is an international, integrated energy company. We are the third-largest integrated energy company in the United States, based on market capitalization and proved reserves. At September 30, 2007, we had total assets of $173 billion. Our stock is listed on the New York Stock Exchange under the symbol “COP.”

Our Exploration and Production (E&P) segment had net income of $2,082 million in the third quarter of 2007. This compares with a net loss of $2,404 million in the second quarter of 2007, and net income of $1,904 million in the third quarter of 2006. In the second quarter of 2007, we recorded a non-cash impairment of $4,588 million before-tax ($4,512 million after-tax) related to the expropriation of our oil interests in Venezuela. For additional information, see the “Expropriated Assets” section of Note 10—Impairments, in the Notes to Consolidated Financial Statements.

Crude oil and natural gas prices, along with refining margins, are driven by market factors over which we have no control. The results for the third quarter of 2007, compared with the second quarter of 2007, were impacted by an increase in crude oil prices. Industry crude oil prices for West Texas Intermediate averaged $75.48 per barrel in the third quarter of 2007, or $10.59 per barrel higher than the second quarter of 2007. Crude oil prices were influenced by steady growth in the demand for oil, coupled with supply concerns. Anticipated supply increases were not viewed as sufficient to meet the seasonal demand increase in the second half of the year.

Industry natural gas prices for Henry Hub decreased during the third quarter of 2007 to $6.16 per million British thermal units (MMBTU), down $1.39 per MMBTU from the second quarter of 2007. Natural gas prices trended lower during the third quarter of 2007 as inventory storage levels increased. Liquefied natural gas (LNG) imports into the United States increased during July and August, helping to create the high inventory levels. The United States attracted a higher level of imports than previously expected due to lower natural gas prices in Europe. The decrease in prices due to higher storage levels was partially offset by hurricane concerns, as well as temperatures during August that were higher than anticipated. As hurricane season progressed without any major hurricanes impacting the Gulf of Mexico natural gas production region, Henry Hub prices moved lower.

Our Refining and Marketing segment had net income of $1,307 million in the third quarter of 2007, compared with $2,358 million in the second quarter of 2007, and $1,464 million in the third quarter of 2006. Third-quarter 2007 realized refining and marketing margins were significantly lower than the previous period, as gasoline prices declined and diesel prices did not keep pace with the rise in crude oil prices due to market supply and demand conditions for refined products.

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On January 3, 2007, we closed on the business venture with EnCana Corporation to create an integrated North American heavy-oil business. The venture consists of two 50/50 business ventures, a Canadian upstream general partnership, FCCL Oil Sands Partnership, and a U.S. downstream limited liability company, WRB Refining LLC. We use the equity method of accounting for both entities, and the transaction is reflected in our results of operations beginning in the first quarter of 2007.

On March 31, 2006, we completed the $33.9 billion acquisition of Burlington Resources Inc. (Burlington Resources). This acquisition is reflected in our results of operations beginning in the second quarter of 2006.

In July 2007, we announced plans to repurchase up to $15 billion of our common stock through the end of 2008. We repurchased $2.5 billion of our common stock in the third quarter of 2007 and expect to repurchase $2 billion to $3 billion under this program in the fourth quarter of 2007.

RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three- and nine-month periods ending September 30, 2007, is based on a comparison with the corresponding periods of 2006.

Consolidated Results

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

	Millions of Dollars
	Three Months Ended						Nine Months Ended
	September 30						September 30
	2007			2006			2007			2006
Exploration and Production (E&P)	$	2,082			1,904			2,007			7,761
Midstream		104			169			291			387
Refining and Marketing (R&M)		1,307			1,464			4,801			3,562
LUKOIL Investment		387			487			1,169			1,123
Chemicals		110			142			260			394
Emerging Businesses		3			11			(10	)		7
Corporate and Other		(320	)		(301	)		(998	)		(881	)
Net income	$	3,673			3,876			7,520			12,353

Net income was $3,673 million in the third quarter of 2007, compared with $3,876 million in the third quarter of 2006. For the nine-month periods ended September 30, 2007 and 2006, net income was $7,520 million and $12,353 million, respectively.

The results for the third quarter of 2007 decreased primarily due to lower refining and marketing margins in the R&M segment, as well as lower equity earnings from our investment in LUKOIL. These decreases were partially offset by the net impact of asset rationalization efforts in our E&P and R&M segments, as well as the settlement of retroactive adjustments for crude oil quality differentials on Trans-Alaska Pipeline System shipments (Quality Bank). Additionally, the lower results were partially offset by the impact of changes in tax laws and higher crude oil prices in the E&P segment.

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The lower results in the nine-month period were primarily the result of a complete impairment ($4,512 million after-tax) of our oil interests in Venezuela, resulting from their expropriation in June of 2007. The nine-month period of 2007 benefited from the net impact of asset rationalization efforts, as well as the Alaska Quality Bank settlements.

See the “Segment Results” section for additional information on our segment results.

Income Statement Analysis

Equity in earnings of affiliates increased 10 percent in the third quarter of 2007 and 13 percent in the nine-month period, reflecting results from WRB Refining LLC, our new downstream business venture with EnCana. The improved results for both 2007 periods were partially offset by lower equity earnings from:

• Hamaca and Petrozuata, our heavy-oil joint ventures in Venezuela, primarily due to the expropriation of our oil interests during the second quarter of 2007.

• Chevron Phillips Chemical Company LLC, our chemicals joint venture, due to lower olefins and polyolefins margins.

• DCP Midstream, our midstream joint venture, primarily due to higher operating costs and a positive tax adjustment included in 2006 results.

Earnings from our investment in LUKOIL were lower during the third quarter of 2007 due to an alignment of estimated net income to reported results, as well as higher estimated operating costs.

Other income increased significantly during the third quarter and nine-month period of 2007. The increase in both 2007 periods was primarily due to higher net gains on asset dispositions associated with asset rationalization efforts. In addition, other income increased due to the Alaska Quality Bank settlements. These increases were partially offset by the inclusion of a benefit related to business interruption insurance in 2006 results.

Exploration expenses increased during the first nine months of 2007, partially reflecting the amortization of unproved North American leaseholds obtained in the Burlington Resources acquisition and the impairment of an international exploration license. The increase also reflects higher dry hole costs and geological and geophysical expenses.

Depreciation, depletion and amortization (DD&A) increased 15 percent in the nine-month period of 2007, primarily resulting from the addition of Burlington Resources’ assets in the E&P segment’s depreciable asset base.

Impairment—expropriated assets reflects a non-cash impairment of $4,588 million before-tax related to the expropriation of our oil interests in Venezuela recorded in the second quarter of 2007. For additional information, see the “Expropriated Assets” section of Note 10—Impairments, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

Interest and debt expense increased 27 percent in the third quarter of 2007 and 30 percent in the nine-month period. The increase in both 2007 periods is primarily due to the interest expense component of the Alaska Quality Bank settlements, as well as higher expense associated with the funding requirements for the business venture with EnCana. The increase in the third quarter of 2007 is partially offset by lower average debt levels compared with the third quarter of 2006.

Our effective tax rate for the third quarter and first nine months of 2007 was 42 percent and 53 percent, respectively, compared with 51 percent and 45 percent for the corresponding periods of 2006. The change

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in the effective tax rate for the third quarter of 2007 was primarily due to a tax rate increase enacted in the United Kingdom in the third quarter of 2006, the effect of asset rationalization efforts, and a tax rate decrease enacted in Germany in the third quarter of 2007. The change in the effective rate for the nine-month period was primarily due to the impact of the expropriation of our oil interests in Venezuela in the second quarter of 2007 (see Note 10—Impairments, in the Notes to Consolidated Financial Statements, for additional information). This impact was partially offset by a higher proportion of income in higher-tax-rate jurisdictions for the nine months of 2006.

Foreign currency transaction gains in the first nine months of 2007 primarily reflect the strengthening of the Canadian dollar against the U.S. dollar.

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Segment Results

E&P

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2007		2006		2007			2006
	Millions of Dollars
Net Income (Loss)
Alaska	$	765		425		1,807			1,877
Lower 48		460		570		1,389			1,599
United States		1,225		995		3,196			3,476
International		857		909		(1,189	)		4,285
	$	2,082		1,904		2,007			7,761
	Dollars Per Unit
Average Sales Prices
Crude oil (per barrel)
United States	$	72.00		67.25		62.70			63.05
International		74.03		67.45		65.19			65.27
Total consolidated		73.01		67.37		63.99			64.30
Equity affiliates*		44.60		46.98		44.30			47.36
Worldwide E&P		71.34		65.04		61.80			62.18
Natural gas (per thousand cubic feet)
United States		5.36		5.98		6.01			6.21
International		5.75		5.87		6.24			6.23
Total consolidated		5.56		5.92		6.13			6.22
Equity affiliates*		—		.32		.30			.30
Worldwide E&P		5.56		5.91		6.13			6.21
Natural gas liquids (per barrel)
United States		47.73		42.68		43.34			41.86
International		48.63		44.89		44.21			43.84
Total consolidated		48.09		43.62		43.71			42.78
Equity affiliates*		—		—		—			—
Worldwide E&P		48.09		43.62		43.71			42.78
	Millions of Dollars
Worldwide Exploration Expenses
General administrative; geological and geophysical; and lease rentals	$	144		142		384			302
Leasehold impairment		51		37		196			89
Dry holes		23		18		159			52
	$	218		197		739			443

* Excludes our equity share of LUKOIL reported in the LUKOIL Investment segment.

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	Three Months Ended				Nine Months Ended
	September 30				September 30
	2007		2006		2007		2006
	Thousands of Barrels Daily
Operating Statistics
Crude oil produced
Alaska		241		234		261		265
Lower 48		103		119		104		101
United States		344		353		365		366
Europe		203		240		210		246
Asia Pacific		83		111		91		109
Canada		17		26		19		25
Middle East and Africa		73		126		80		103
Other areas		10		9		10		6
Total consolidated		730		865		775		855
Equity affiliates*
Canada		29		—		27		—
Russia and Caspian		15		15		15		15
Venezuela		—		89		56		102
		774		969		873		972
Natural gas liquids produced
Alaska		15		11		18		18
Lower 48		73		75		71		58
United States		88		86		89		76
Europe		11		11		12		12
Asia Pacific		13		20		13		20
Canada		26		28		29		23
Middle East and Africa		1		1		2		1
		139		146		145		132
	Millions of Cubic Feet Daily
Natural gas produced**
Alaska		116		123		113		150
Lower 48		2,219		2,320		2,210		1,953
United States		2,335		2,443		2,323		2,103
Europe		793		955		932		1,061
Asia Pacific		575		670		592		579
Canada		1,069		1,154		1,118		930
Middle East and Africa		124		134		130		129
Other areas		20		23		21		16
Total consolidated		4,916		5,379		5,116		4,818
Equity affiliates*
Venezuela		—		8		6		9
		4,916		5,387		5,122		4,827

*	Excludes our equity share of LUKOIL reported in the LUKOIL Investment segment.
**	Represents quantities available for sale. Excludes gas equivalent of natural gas liquids shown above.

40

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2007		2006		2007		2006
	Thousands of Barrels Daily
Mining operations
Syncrude produced		27		23		24		20

The E&P segment explores for, produces and markets crude oil, natural gas, and natural gas liquids on a worldwide basis. It also mines deposits of oil sands in Canada to extract the bitumen and upgrade it into a synthetic crude oil. At September 30, 2007, our E&P operations were producing in the United States, Norway, the United Kingdom, the Netherlands, Canada, Nigeria, Ecuador, Argentina, offshore Timor Leste in the Timor Sea, Australia, China, Indonesia, Algeria, Libya, Vietnam, and Russia.

Net income for the E&P segment increased 9 percent in the third quarter of 2007, primarily due to the negative impact of changes in tax laws on the results for the third quarter of 2006. The increase also resulted from higher crude oil prices and a net benefit associated with asset rationalization efforts. In addition, the third quarter of 2007 was impacted by the Quality Bank settlements. These increases were partially offset by lower crude oil and natural gas production, as well as lower natural gas prices and higher operating costs.

Net income for the E&P segment was $2,007 million in the nine-month period of 2007, compared with net income of $7,761 million in the corresponding period of 2006. In the second quarter of 2007, we recorded a non-cash impairment of $4,588 million before-tax ($4,512 million after-tax) related to the expropriation of our oil interests in Venezuela. For additional information, see the “Expropriated Assets” section of Note 10—Impairments, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference. The results for the nine-month period reflect this impairment of expropriated assets in Venezuela, as well as higher DD&A expense, operating costs and taxes, and lower realized crude oil and natural gas prices. These decreases were partially offset by a net benefit from asset rationalization efforts and net foreign exchange gains.

See the “Business Environment and Executive Overview” section for additional information on industry crude oil and natural gas prices.

U.S. E&P

Net income from our U.S. E&P operations increased 23 percent in the third quarter of 2007, primarily due to higher crude oil prices and sales volumes, as well as the Alaska Quality Bank settlements recorded in the third quarter of 2007. These increases were partially offset by lower natural gas prices and production, higher operating costs, and higher production taxes in Alaska.

Net income for the first nine months of 2007 decreased 8 percent, primarily due to higher operating costs, lower crude oil and natural gas prices, and higher production taxes in Alaska. These decreases were partially offset by higher gas production, as well as the Alaska Quality Bank settlements recorded in 2007. In addition, results included gains on the sale of assets in Alaska and the Gulf of Mexico.

U.S. E&P production on a barrel-of-oil-equivalent (BOE) basis averaged 821,000 BOE per day in the third quarter of 2007, a decrease of 3 percent from 846,000 BOE per day in the third quarter of 2006. Production was impacted in 2007 by normal field decline, offset slightly by less downtime in Alaska and new production from satellite fields in Alaska.

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International E&P

Net income from our international E&P operations decreased 6 percent in the third quarter of 2007. The decrease in net income was primarily due to lower crude oil production and, to a lesser extent, lower natural gas production. In addition, the results reflect higher operating costs and a decrease in natural gas prices. These decreases were partially offset by a U.K. tax increase enacted in the third quarter of 2006, as well as higher crude oil prices and a net benefit from asset rationalization efforts.

Our international E&P operations reported a net loss of $1,189 million in the nine-month period of 2007, compared with net income of $4,285 million in the corresponding period of 2006. The results were impacted by the impairment of expropriated assets, lower crude oil production, and higher operating costs. These decreases were partially offset by a net benefit from asset rationalization efforts and higher natural gas production.

International E&P production averaged 911,000 BOE per day in the third quarter of 2007, a decrease of 22 percent from 1,167,000 BOE per day in the third quarter of 2006. Production was impacted by the expropriation of our Venezuelan oil projects, our exit from Dubai, planned and unplanned downtime in Australia and the North Sea, production sharing contract impacts, and the effect of asset dispositions. These decreases were slightly offset by production volumes from our upstream business venture with EnCana.

Estimated production for the first six months of 2007 at Petrozuata and Hamaca was 83,000 net barrels per day of crude oil after application of disproportionate OPEC restrictions imposed by the Venezuelan government for January through mid-May, 2007. The estimated net loss attributable to our Venezuelan operations for the first six months of 2007 was $4,393 million, including the $4,512 million (after-tax) impairment of our expropriated Venezuelan oil assets.

ConocoPhillips’ 40 percent interest in Block 2 of Plataforma Deltana, a natural gas region on Venezuela’s continental shelf, was not included in the Nationalization Decree. We continue to evaluate our opportunities for commercial development of Block 2.

In October of 2007, the president of Ecuador issued a decree increasing the amount of government royalty entitlement on crude oil production to 99 percent of any increase in the price of crude oil above a contractual reference price. This decree was published into law effective October 18, 2007. We are currently evaluating the impact of this law on our operations.

Our Canadian Syncrude mining operations produced 27,000 barrels per day in the third quarter of 2007, compared with 23,000 barrels per day in the third quarter of 2006.

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Midstream

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2007		2006		2007		2006
	Millions of Dollars
Net Income*	$	104		169		291		387
*Includes DCP Midstream-related net income:	$	90		128		216		312
	Dollars Per Barrel
Average Sales Prices
U.S. natural gas liquids*
Consolidated	$	48.62		44.10		43.85		41.16
Equity		47.73		43.00		42.86		40.49

* Prices are based on index prices from the Mont Belvieu and Conway market hubs that are weighted by natural gas liquids component and location mix.

	Thousands of Barrels Daily
Operating Statistics
Natural gas liquids extracted*		216	210	208	209
Natural gas liquids fractionated**		168	138	173	143

*	Includes our share of equity affiliates.
**	Excludes DCP Midstream.

The Midstream segment purchases raw natural gas from producers and gathers natural gas through an extensive network of pipeline gathering systems. The natural gas is then processed to extract natural gas liquids from the raw gas stream. The remaining “residue” gas is marketed to electrical utilities, industrial users, and gas marketing companies. Most of the natural gas liquids are fractionated—separated into individual components like ethane, butane and propane—and marketed as chemical feedstock, fuel, or blendstock. The Midstream segment consists of our equity investment in DCP Midstream, LLC, as well as our other natural gas gathering and processing operations, and natural gas liquids fractionation and marketing businesses, primarily in the United States and Trinidad.

Net income from the Midstream segment decreased 38 percent in the third quarter of 2007 and 25 percent in the first nine months of 2007, primarily due to a positive tax adjustment included in the 2006 results. In addition, the results for both 2007 periods reflect a gradual shift in natural gas purchase contract terms that are more favorable to natural gas producers. Earnings from DCP Midstream were lower in both 2007 periods, primarily due to increased operating costs, mainly repairs, maintenance and asset integrity work. These decreases were slightly offset by higher natural gas liquids prices.

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R&M

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2007		2006		2007		2006
	Millions of Dollars
Net Income
United States	$	873		1,444		3,648		3,174
International		434		20		1,153		388
	$	1,307		1,464		4,801		3,562

	Dollars Per Gallon
U.S. Average Sales Prices*
Gasoline
Wholesale	$	2.32	2.27	2.23	2.13
Retail		2.43	2.46	2.38	2.28
Distillates—wholesale		2.36	2.31	2.18	2.15

*Excludes excise taxes.

	Thousands of Barrels Daily
Operating Statistics
Refining operations*
United States
Crude oil capacity**		2,037		2,208	2,034		2,208
Crude oil runs		1,980		2,127	1,938		1,990
Capacity utilization (percent)		97	%	96	95	%	90
Refinery production		2,177		2,334	2,139		2,173
International
Crude oil capacity**		687		693	693		637
Crude oil runs		574		617	616		586
Capacity utilization (percent)		84	%	89	89	%	92
Refinery production		593		643	634		613
Worldwide
Crude oil capacity**		2,724		2,901	2,727		2,845
Crude oil runs		2,554		2,744	2,554		2,576
Capacity utilization (percent)		94	%	95	94	%	91
Refinery production		2,770		2,977	2,773		2,786

*	Includes our share of equity affiliates, except for our share of LUKOIL, which is reported in the LUKOIL Investment segment.
**	Weighted-average crude oil capacity for the three-and nine-month periods. Actual capacity at September 30, 2007 and 2006, was 2,037,000 and 2,208,000 barrels per day, respectively, for our domestic refineries, 669,000 and 693,000 barrels per day, respectively, for our international refineries and 2,706,000 and 2,901,000 barrels per day, respectively, worldwide.

Petroleum products sales volumes
United States
Gasoline	1,212	1,369	1,256	1,309
Distillates	869	848	853	827
Other products	439	519	473	530
	2,520	2,736	2,582	2,666
International	629	749	694	772
	3,149	3,485	3,276	3,438

44

The R&M segment’s operations encompass refining crude oil and other feedstocks into petroleum products (such as gasoline, distillates and aviation fuels); buying, selling and transporting crude oil; and buying, transporting, distributing and marketing petroleum products. R&M has operations mainly in the United States, Europe and Asia Pacific.

Net income from the R&M segment decreased 11 percent in the third quarter of 2007, primarily due to lower realized refining and marketing margins and a business interruption insurance benefit recognized in the prior year. This decrease was further attributed to the net impact of our contribution of assets to WRB Refining LLC (WRB), our downstream business venture with EnCana. These decreases were largely offset by a net benefit from asset rationalization efforts and the impact of a tax law change in Germany.

Net income for the first nine months of 2007 increased 35 percent. This increase was primarily due to a net benefit from asset rationalization efforts, higher Gulf and East Coast refining volumes, higher realized refining and marketing margins, and the tax law change in Germany. The increase was partially offset by the net impact of the contribution of assets to WRB, as well as the business interruption insurance benefit recognized in the prior year.

U.S. R&M

Net income from our U.S. R&M operations decreased 40 percent in the third quarter of 2007, primarily due to lower refining and marketing margins. In addition, net income decreased due to the inclusion of a benefit related to business interruption insurance in the results for 2006, as well as the net impact of our contribution of assets to WRB. These decreases were slightly offset by a net benefit from asset rationalization efforts.

Net income for the first nine months of 2007 increased 15 percent, primarily due to higher Gulf and East Coast refining volumes, higher realized refining and marketing margins and a net benefit from asset rationalization efforts. The increase was partially offset by the net impact associated with the contribution of assets to WRB and the inclusion of a benefit related to business interruption insurance in 2006 results.

Our U.S. refining capacity utilization rate was 97 percent in the third quarter of 2007, a slight improvement from the third-quarter 2006 rate of 96 percent.

International R&M

Net income from our international R&M operations was $434 million in the third quarter of 2007 and $1,153 million in the first nine months of 2007, compared with net income of $20 million and $388 million, respectively, in the corresponding periods of 2006. The increases in both 2007 periods were primarily due to a net benefit from asset rationalization efforts, as well as a tax law change in Germany during the third quarter of 2007. The results for the first nine months of 2007 also benefited from a slight increase in refining and marketing margins. The increase in the third quarter of 2007 was slightly offset by lower refining and marketing margins.

Our international refining capacity utilization rate was 84 percent in the third quarter of 2007, compared with 89 percent in the third quarter of 2006. The Wilhelmshaven refinery in Germany was temporarily shut down during the month of August due to economic conditions.

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LUKOIL Investment

	Millions of Dollars
	Three Months Ended				Nine Months Ended
	September 30				September 30
	2007		2006		2007		2006
Net Income	$	387		487		1,169		1,123
Operating Statistics*
Net crude oil production (thousands of barrels daily)		390		388		404		347
Net natural gas production (millions of cubic feet daily)		249		288		278		244
Net refinery crude oil processed (thousands of barrels daily)		226		164		210		165

*Represents our net share of our estimate of LUKOIL’s production and processing.

This segment represents our investment in the ordinary shares of LUKOIL, an international, integrated oil and gas company headquartered in Russia, which we account for under the equity method. As of September 30, 2007, our ownership interest in LUKOIL was 20 percent based on 851 million issued shares. Our ownership interest based on estimated shares outstanding, used for equity-method accounting, was 20.5 percent at September 30, 2007.

Because LUKOIL’s accounting cycle close and preparation of U.S. generally accepted accounting principles financial statements occur subsequent to our reporting deadline, our equity earnings and statistics for our LUKOIL investment are estimated, based on current market indicators, historical production and cost trends of LUKOIL, and other objective data. Once the difference between actual and estimated results is known, an adjustment is recorded. This estimate-to-actual adjustment will be a recurring component of future period results.

In addition to our estimate of our equity share of LUKOIL’s earnings, this segment reflects the amortization of the basis difference between our equity interest in the net assets of LUKOIL and the historical cost of our investment in LUKOIL, and also includes the costs associated with our employees seconded to LUKOIL and accruals for dividend withholding taxes.

Net income from the LUKOIL Investment segment decreased 21 percent in the third quarter of 2007, primarily due to an alignment of estimated net income to reported results, as well as higher estimated operating costs. These decreases were partially offset by higher estimated volumes and petroleum product prices, as well as an increase in our equity ownership.

Net income for the first nine months of 2007 increased 4 percent, primarily due to higher estimated volumes, an increase in our equity ownership, and higher estimated petroleum product prices. These increases were partially offset by the alignment of estimated net income to reported results, as well as higher estimated operating costs.

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Chemicals

	Millions of Dollars
	Three Months Ended				Nine Months Ended
	September 30				September 30
	2007		2006		2007		2006
Net Income	$	110		142		260		394

The Chemicals segment consists of our 50 percent interest in Chevron Phillips Chemical Company LLC (CPChem), which we account for under the equity method. CPChem uses natural gas liquids and other feedstocks to produce petrochemicals. These products are then marketed and sold, or used as feedstocks to produce plastics and commodity chemicals.

Net income from the Chemicals segment decreased 23 percent in the third quarter of 2007, primarily due to lower olefins and polyolefins margins and, to a lesser extent, lower margins from aromatics and styrenics.

Net income for the first nine months of 2007 decreased 34 percent, reflecting lower margins from olefins and polyolefins and higher expense resulting from planned turnarounds and unplanned maintenance at certain facilities.

Emerging Businesses

	Millions of Dollars
	Three Months Ended						Nine Months Ended
	September 30						September 30
	2007			2006			2007			2006
Net Income (Loss)
Power	$	21			26			33			60
Other		(18	)		(15	)		(43	)		(53	)
	$	3			11			(10	)		7

The Emerging Businesses segment represents our investment in new technologies or businesses outside our normal scope of operations. Activities within this segment are currently focused on power generation and other items, such as carbon-to-liquids, technology solutions, and alternative energy and programs, such as advanced hydrocarbon processes, energy conversion technologies, new petroleum-based products, and renewable fuels.

The Emerging Businesses segment reported net income of $3 million in the third quarter of 2007, compared with net income of $11 million in the corresponding quarter of 2006. The first nine months of 2007 resulted in a net loss of $10 million, compared with net income of $7 million in the first nine months of 2006. Both periods reflect lower margins from the Immingham power plant in the United Kingdom.

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Corporate and Other

	Millions of Dollars
	Three Months Ended						Nine Months Ended
	September 30						September 30
	2007			2006			2007			2006
Net Income (Loss)
Net interest	$	(195	)		(242	)		(663	)		(602	)
Corporate general and administrative expenses		(49	)		(35	)		(126	)		(100	)
Acquisition/merger-related costs		(11	)		(32	)		(40	)		(76	)
Other		(65	)		8			(169	)		(103	)
	$	(320	)		(301	)		(998	)		(881	)

Net interest consists of interest and financing expense, net of interest income and capitalized interest, as well as premiums incurred on the early retirement of debt. Net interest decreased 19 percent in the third quarter of 2007, primarily due to lower average debt levels, as well as higher amounts of interest being capitalized. These items were slightly offset by the net impact of the interest components of the Quality Bank settlements. Net interest increased 10 percent in the first nine months of 2007, primarily due to the net impact of the Quality Bank settlements and a premium on the early retirement of debt, partially offset by higher amounts of interest being capitalized.

Corporate general and administrative expenses increased 40 percent in the third quarter of 2007 and 26 percent in the first nine months of 2007. The increase in both periods was primarily due to increased benefit-related expenses.

Acquisition/merger-related costs include seismic relicensing and other transition costs associated with the Burlington Resources acquisition.

The category “Other” includes certain foreign currency transaction gains and losses, and environmental costs associated with sites no longer in operation. Results from Other were primarily impacted by foreign currency losses in 2007.

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CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators

	Millions of Dollars
	At September 30			At December 31
	2007			2006
Notes payable and long-term debt due within one year	$	405			4,043
Total debt*	$	21,876			27,134
Minority interests	$	1,180			1,202
Common stockholders’ equity	$	86,933			82,646
Percent of total debt to capital**		20	%		24
Percent of floating-rate debt to total debt		27	%		41

*	Total debt includes notes payable and long-term debt due within one year, and long-term debt, as shown on our consolidated balance sheet.
**Capital includes total debt, minority interests and common stockholders’ equity.

To meet our short- and long-term liquidity requirements, we look to a variety of funding sources. Cash generated from operating activities is the primary source of funding. In addition, during the first nine months of 2007, we raised $3,057 million from the sale of assets. During the first nine months, available cash was used to support our ongoing capital expenditures and investments program, repurchase shares of our common stock, repay debt, provide loan financing to certain equity affiliates, pay dividends, and meet the funding requirements related to the business venture with EnCana Corporation (EnCana), which closed January 3, 2007. Total dividends paid on our common stock during the first nine months were $2,009 million. During the first nine months of 2007, cash and cash equivalents increased $562 million to $1,379 million.

In addition to cash flows from operating activities and proceeds from asset sales, we rely on our cash balance, commercial paper and credit facility programs, and our shelf registration statements, to support our short- and long-term liquidity requirements. We anticipate these sources of liquidity will be adequate to meet our funding requirements through 2008, including our capital spending program, our share repurchase programs, dividend payments, required debt payments and the funding requirements related to our business venture with EnCana.

Significant Sources of Capital

Operating Activities

During the first nine months of 2007, cash of $17,630 million was provided by operating activities, an 11 percent increase from cash from operations of $15,879 million in the corresponding period of 2006. Contributing to the increase was a lower inventory build in the 2007 period, partially related to the formation of the WRB downstream business venture; the impact of the Burlington Resources acquisition late in the first quarter of 2006; and higher U.S. refining and marketing margins in 2007. These positive factors were partially offset by the absence of dividends from our Venezuelan operations in 2007 and lower crude oil and natural gas prices.

While the stability of our cash flows from operating activities benefits from geographic diversity and the effects of upstream and downstream integration, our short- and long-term operating cash flows are highly dependent upon prices for crude oil, natural gas and natural gas liquids, as well as refining and marketing margins. During the first nine months of 2007 and 2006, we benefited from favorable crude oil and

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natural gas prices, as well as refining margins. The sustainability of these prices and margins is driven by market conditions over which we have no control. Absent other mitigating factors, as these prices and margins fluctuate, we would expect a corresponding change in our operating cash flows.

The level of our production volumes of crude oil, natural gas and natural gas liquids also impacts our cash flows. These production levels are impacted by such factors as acquisitions and dispositions of fields, field production decline rates, new technologies, operating efficiency, weather conditions, the addition of proved reserves through exploratory success, and the timely and cost-effective development of those proved reserves. While we actively manage certain of these factors, production levels can cause variability in cash flows, although historically this variability has not been as significant as that experienced with commodity prices.

In addition, the level and quality of output from our refineries impacts our cash flows. The output at our refineries is impacted by such factors as operating efficiency, maintenance turnarounds, feedstock availability and weather conditions. We actively manage the operations of our refineries and, typically, any variability in their operations has not been as significant to cash flows as that experienced with refining margins.

In 2006, we received approximately $1.1 billion in distributions from two heavy-oil projects in Venezuela. The majority of these distributions represented operating results from previous years. We did not receive a distribution related to these projects in the first nine months of 2007. See the “Outlook” section for additional discussion concerning our operations in Venezuela.

Asset Sales

Proceeds from asset sales during the first nine months of 2007 were $3,057 million, compared with $246 million for the same period of 2006. The increase is mainly due to our ongoing asset rationalization efforts.

Commercial Paper and Credit Facilities

In September 2007, we replaced our $5 billion and $2.5 billion revolving credit facilities with a $7.5 billion revolving credit facility expiring in September 2012. The new facility contains the same terms as the previous facilities. The facility may be used as direct bank borrowings, as support for the ConocoPhillips $7.5 billion commercial paper program, as support for the ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program, or as support for issuances of letters of credit totaling up to $750 million. At September 30, 2007, and December 31, 2006, we had no outstanding borrowings under our credit facilities, but $41 million in letters of credit had been issued at both dates. Under both commercial paper programs, there was $603 million of commercial paper outstanding at September 30, 2007, compared with $2,931 million at December 31, 2006.

At September 30, 2007, our primary funding source for short-term working capital needs was the ConocoPhillips $7.5 billion commercial paper program, a portion of which may be denominated in other currencies (limited to euro 3 billion equivalent). Commercial paper maturities are generally limited to 90 days. Based on $603 million of commercial paper outstanding and $41 million of issued letters of credit, we had access to $6.9 billion in unused borrowing capacity under our revolving credit facility at September 30, 2007.

In October 2007, Standard and Poors’ Rating Service and Fitch both increased their ratings on our senior long-term debt and our short-term debt. Standard and Poors increased our long-term rating from “A-” to “A” and our short-term rating from “A-2” to “A-1.” Fitch increased our long-term rating from “A-” to “A” and our short-term rating from “F2” to “F1.”

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Shelf Registrations

We have a universal shelf registration statement on file with the SEC under which we, as a well-known seasoned issuer, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.

We also have on file with the SEC a shelf registration statement under which ConocoPhillips Canada Funding Company I and ConocoPhillips Canada Funding Company II, both wholly owned subsidiaries, could issue an indeterminate amount of senior debt securities, fully and unconditionally guaranteed by ConocoPhillips and ConocoPhillips Company.

Minority Interests

At September 30, 2007, we had outstanding $1,180 million of equity in less than wholly owned consolidated subsidiaries held by minority interest owners, including a minority interest of $508 million in Ashford Energy Capital S.A. and a minority interest of $646 million related to Darwin LNG, located in northern Australia.

Off-Balance Sheet Arrangements

As part of our normal ongoing business operations and consistent with industry practice, we enter into numerous agreements with other parties to pursue business opportunities, which share costs and apportion risks among the parties as governed by the agreements. At September 30, 2007, we were liable for certain contingent obligations under the following contractual arrangements:

• Qatargas 3:Qatargas 3 is an integrated project to produce and liquefy natural gas from Qatar’s North field. We own a 30 percent interest in the project. Our interest is held through a jointly owned company, Qatar Liquefied Gas Company Limited (3), for which we use the equity method of accounting. Qatargas 3 secured project financing of $4 billion in December 2005, consisting of $1.3 billion of loans from export credit agencies (ECA), $1.5 billion from commercial banks, and $1.2 billion from ConocoPhillips. The ConocoPhillips loan facilities have substantially the same terms as the ECA and commercial bank facilities. Prior to project completion certification, all loans, including the ConocoPhillips loan facilities, are guaranteed by the participants, based on their respective ownership interests. Accordingly, our maximum exposure to this financing structure is $1.2 billion, excluding accrued interest. Upon completion certification, which is expected in 2010, all project loan facilities, including the ConocoPhillips loan facilities, will become non-recourse to the project participants. At September 30, 2007, Qatargas 3 had $2.0 billion outstanding under all the loan facilities, of which ConocoPhillips provided $608 million, including $34 million of accrued interest.

• Rockies Express Pipeline LLC:In June 2006, we issued a guarantee for 24 percent of the $2.0 billion in credit facilities of Rockies Express Pipeline LLC (Rockies Express), which will be used to construct a natural gas pipeline across a portion of the United States. The maximum potential amount of future payments to third-party lenders under the guarantee is estimated to be $480 million, which could become payable if the credit facility is fully utilized and Rockies Express fails to meet its obligations under the credit agreement. At September 30, 2007, Rockies Express had $1,758 million outstanding under the credit facilities, with our 24 percent guarantee equaling $422 million. In addition, we have a 24 percent guarantee on $600 million of Floating Rate Notes due 2009 issued by Rockies Express in September 2007. It is anticipated that construction completion will be achieved at the end of 2009, and refinancing will take place at that time, making the debt non-recourse.

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•     Other: At September 30, 2007, we had guarantees outstanding for our portion of joint-venture debt obligations, which have terms of up to 17 years. The maximum potential amount of future payments under the guarantees was approximately $130 million. Payment would be required if a joint venture defaults on its debt obligations.

For additional information about guarantees, see Note 13—Guarantees, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

Capital Requirements

Our debt balance at September 30, 2007, was $21.9 billion, a decrease of $5.3 billion during the first nine months of 2007.

On February 9, 2007, we announced plans to repurchase $4 billion of our common stock in 2007. On July 9, 2007, we announced plans to repurchase up to $15 billion of our common stock through the end of 2008. This amount included $2 billion remaining under the $4 billion program announced in February 2007. During the first nine months of 2007, we repurchased 59.3 million shares of our common stock at a cost of $4.5 billion, including 177,000 shares at a cost of $14 million from a consolidated Burlington Resources grantor trust. We anticipate fourth-quarter 2007 share repurchases to be $2 billion to $3 billion.

In December 2005, we entered into a credit agreement with Qatargas 3 to provide loan financing of approximately $1.2 billion, excluding accrued interest for the construction of an LNG train in Qatar. This financing will represent 30 percent of the project’s total debt financing. Through September 30, 2007, we had provided $608 million in loan financing, including $34 million of accrued interest. See the “Off-Balance Sheet Arrangements” section for additional information on Qatargas 3.

In 2004, we finalized our transaction with Freeport LNG Development, L.P. (Freeport LNG) to participate in an LNG receiving terminal in Quintana, Texas. We entered into a credit agreement with Freeport LNG to provide loan financing of approximately $631 million, excluding accrued interest for the construction of the facility, which began in early 2005. Through September 30, 2007, we had provided $648 million in loan financing, including $74 million of accrued interest.

In the fall of 2004, ConocoPhillips and LUKOIL agreed to the expansion of the Varandey terminal as part of our investment in the OOO Naryanmarneftegaz (NMNG) joint venture. We have an obligation to provide loan financing to Varandey Terminal Company for 30 percent of the costs of the terminal expansion, but we will have no governance or ownership interest in the terminal. We estimate our total loan obligation for the terminal expansion to be approximately $410 million at current exchange rates, excluding interest to be accrued during construction. This amount will be adjusted as the project’s cost estimate and schedule are updated and the ruble exchange rate fluctuates. Through September 30, 2007, we had provided $303 million in loan financing, including $25 million of accrued interest.

Our loans to Qatargas 3, Freeport LNG and Varandey Terminal Company are included in the “Loans and advances—related parties” line on our consolidated balance sheet.

On January 3, 2007, we closed on the previously announced business venture with EnCana. As part of this transaction, we are obligated to contribute $7.5 billion, plus accrued interest, over a 10-year period beginning in 2007, to the upstream business venture formed as a result of the transaction. An initial cash contribution of $188 million was made upon closing in January. Quarterly principal and interest payments of $237 million began in the second quarter of 2007, and will continue until the balance is paid. This obligation is reflected as a liability on our September 30, 2007, consolidated balance sheet. Of the principal obligation amount, approximately $586 million is short-term and is included in the “Accounts

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payable—related parties” line on our consolidated balance sheet. The principal portion of these payments is presented on our consolidated statement of cash flows as an other financing activity. Interest accrues at a fixed annual rate of 5.3 percent on the unpaid principal balance. Fifty percent of the quarterly interest payment is reflected as an investment purchase and is included in the “Capital expenditures and investments” line on our consolidated statement of cash flows.

Effective January 15, 2007, we redeemed the 8% Junior Subordinated Deferrable Interest Debentures due 2037, at a premium of $14 million, plus accrued interest. This redemption resulted in the immediate redemption by Phillips 66 Capital II of $350 million of 8% Capital Securities. See Note 11—Debt, in the Notes to Consolidated Financial Statements, for additional information.

Also, in January 2007, we redeemed our $153 million 7.25% Notes due 2007 upon their maturity. In February 2007, we reduced our Floating Rate Five-Year Term Note due 2011 from $5 billion to $4 billion, with a subsequent reduction in July 2007 to $3 billion. In April 2007, we redeemed our $1 billion Floating Rate Notes due 2007 upon their maturity.

In May 2007, Polar Tankers Inc., a wholly owned subsidiary, issued an offering of $645 million 5.951% Notes due 2037. The notes are fully and unconditionally guaranteed by ConocoPhillips and ConocoPhillips Company.

On October 31, 2007, we redeemed $300 million of ConocoPhillips Australia Funding Company’s Floating Rate Notes due 2009 at par plus accrued interest.

Contractual Obligations

Our contractual purchase obligations at September 30, 2007, were estimated to be $118 billion, an increase of $25 billion from the amount reported at December 31, 2006, of $93 billion. The increase primarily results from the EnCana joint venture acquisition obligation, as well as mostly higher crude oil, natural gas and NGL prices, and commodity derivative positions.

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Capital Spending

Capital Expenditures and Investments

	Millions of Dollars
	Nine Months Ended
	September 30
	2007		2006
E&P
United States—Alaska	$	471		615
United States—Lower 48		2,085		1,388
International		4,339		4,829
		6,895		6,832
Midstream		2		2
R&M
United States		617		1,128
International		135		1,356
		752		2,484
LUKOIL Investment		—		1,962
Chemicals		—		—
Emerging Businesses		127		46
Corporate and Other		131		187
	$	7,907		11,513
United States	$	3,306		3,358
International		4,601		8,155
	$	7,907		11,513

E&P

UNITED STATES

Alaska

During the first nine months of 2007, we continued development drilling in the Greater Kuparuk Area (including the West Sak development), the Greater Prudhoe Area, and the Alpine field and Alpine satellite fields. Work on a project to upgrade the Trans-Alaska Pipeline System pump stations continued with the first pump station placed on line in February 2007.

Lower 48 States

Onshore, we focused on natural gas developments in the San Juan Basin of New Mexico, the Lobo Trend of South Texas, the Bossier and Cotton Valley Trends of East Texas and North Louisiana, the Barnett Shale Trend of North Texas, and the Anadarko Basin of western Oklahoma. We also continue to pursue oil development in the Williston Basin of Montana and North Dakota, as well as oil and gas developments in southern Louisiana and in the Permian Basin of West Texas. In addition, we invested funds on a new gas development project in the Piceance Basin of northwest Colorado.

Offshore, expenditures were primarily focused on the Ursa development in the Gulf of Mexico.

CANADA

During the first nine months of 2007, we continued with the development of our Surmont heavy-oil project, where steam injection began in the second quarter, and initial production began in October of

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2007. We also continued the development of our conventional oil and gas reserves in western Canada. In addition, we invested approximately $284 million related to our initial cash contribution and quarterly interest payments to the upstream business venture with EnCana. See Note 17—Joint Venture Acquisition Obligation, in the Notes to Consolidated Financial Statements, for additional information.

EUROPE

In the U.K. and Norwegian sectors of the North Sea, funds were invested during the first nine months of 2007 for development of the Britannia satellite fields, Callanish and Brodgar, where production is expected to begin in 2008; the Alvheim project, where production is scheduled to begin in the first quarter of 2008; the Statfjord Late-Life Project, where production began in October 2007; and continued development of the Ekofisk Area.

MIDDLE EAST AND AFRICA

Libya

During the first nine months of 2007, funds were expended to continue the development of the Waha concessions.

Qatar

In Qatar, work continued on Qatargas 3, an integrated project to produce and liquefy natural gas from Qatar’s North field.

Algeria

In Algeria, during the first nine months of 2007, funds were invested in three fields in Block 405A, the Menzel Lejmat North field, the Ourhoud field, and the EMK (El Merk) oil field unit.

RUSSIA AND CASPIAN

Russia

Through OOO Naryanmarneftegaz, a joint venture with LUKOIL, we are working to develop the Yuzhno Khylchuyu field in the northern part of Russia’s Timan-Pechora province.

Caspian

We continued to participate in construction activities to develop the Kashagan field on the Kazakhstan shelf in the Caspian Sea. Kashagan Phase I Development is in the execution phase, aiming for first production in 2010. The revised Kashagan Development Plan was submitted to the Republic of Kazakhstan Authority at the end of June 2007, incorporating reconfigured offshore design and related cost increases and schedule delays. In August, the Republic of Kazakhstan triggered dispute proceedings under the North Caspian Sea Production Sharing Agreement. In October, Kazakhstan enacted a revised subsoil law allowing termination of contracts that violate national security. Negotiations are currently under way in order to reach a resolution.

ASIA PACIFIC

Indonesia

During the first nine months of 2007, we continued to invest funds on the development of the Belanak, Kerisi, Hiu, Belut, and Suban Phase II projects.

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China

Work continued on the development of Phase II of the Peng Lai 19-3 field, as well as concurrent development of the nearby Peng Lai 25-6 field in 2007.

R&M

In the United States, we expended funds during the first nine months of 2007 related to sustaining and improving the existing business with a focus on reliability, energy efficiency, capital maintenance and regulatory compliance. Work also continued on projects to increase crude oil capacity, expand conversion capability and increase clean product yield. An expansion at our Ferndale refinery resulted in a 4 percent increase in the refinery’s crude oil capacity and improved energy efficiency. In addition, we commissioned a new coker at the Borger refinery, part of WRB Refining LLC, our downstream business venture with EnCana.

Internationally, our focus during the first nine months of 2007 was on projects related to reliability, safety and the environment.

Emerging Businesses

In October 2007, we purchased a 50 percent interest in Sweeny Cogeneration LP (SCLP). SCLP provides steam and electric power to the Sweeny refinery complex with any excess power sold into the market. We will account for this joint venture using the equity method of accounting.

Contingencies

Legal and Tax Matters

We accrue for non-income-tax-related contingencies when a loss is probable and the amounts can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. In the case of income-tax-related contingencies, we adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (FIN 48), effective January 1, 2007. FIN 48 requires a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain. Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements.

Environmental

We are subject to the same numerous international, federal, state, and local environmental laws and regulations, as are other companies in the petroleum exploration and production, refining and crude oil and refined product marketing and transportation businesses. For a discussion of the most significant of these environmental laws and regulations, including those with associated remediation obligations, see the “Environmental” section in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 85 through 88 of our 2006 Form 10-K.

We, from time to time, receive requests for information or notices of potential liability from the Environmental Protection Agency and state environmental agencies alleging that we are a potentially responsible party under the Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly

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contain wastes attributable to our past operations. As of December 31, 2006, we reported we had been notified of potential liability under CERCLA and comparable state laws at 64 sites around the United States. At September 30, 2007, we had resolved five of these sites and had received five new notices of potential liability, leaving 64 unresolved sites where we have been notified of potential liability.

At September 30, 2007, our balance sheet included a total environmental accrual of $1,042 million, compared with $1,062 million at December 31, 2006. We expect to incur a substantial majority of these expenditures within the next 30 years.

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

NEW ACCOUNTING STANDARDS

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This Statement defines fair value, establishes a framework for its measurement and expands disclosures about fair value measurements. We use fair value measurements to measure, among other items, purchased assets and investments, leases, derivative contracts and financial guarantees. We also use them to assess impairment of properties, plants and equipment, intangible assets and goodwill. The Statement does not apply to share-based payment transactions and inventory pricing. We plan to adopt this Statement effective January 1, 2008. We continue to evaluate the Statement, but we do not expect any significant impact to our consolidated financial statements, other than additional disclosures.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115.” This Statement permits an entity to choose to measure financial instruments and certain other items similar to financial instruments at fair value, with all subsequent changes in fair value for the financial instrument reported in earnings. By electing the fair value option in conjunction with a derivative, an entity can achieve an accounting result similar to a fair-value hedge without having to comply with complex hedge accounting rules. We plan to adopt this Statement effective January 1, 2008, and we do not expect any significant impact to our consolidated financial statements.

OUTLOOK

Alaska

A special session of the Alaskan legislature began in October 2007 at the request of the governor to review Alaska’s petroleum profits tax. The governor submitted a bill proposing changes to the current production tax system. If adopted by the legislature, those changes would substantially increase taxes paid by Alaska oil producers.

Venezuela

Negotiations continue between ConocoPhillips and Venezuelan authorities concerning appropriate compensation for the expropriation of the company’s oil interests. We continue to preserve all our rights with respect to this situation, including our rights under the contracts we signed and under international and Venezuelan law. We continue to evaluate our options in realizing adequate compensation for the

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value of our oil investments and operations in Venezuela and expect to file a request for international arbitration on November 2, 2007.

Canada

On October 25, 2007, the Alberta government announced a new royalty regime for the province’s non-renewable energy resources. The new royalty regime will use a sliding scale system based on price and volume and is designed to increase the government’s royalty share. The new regime is effective January 1, 2009. We are currently evaluating the impact of this royalty change on our Canadian operations.

Other

In E&P, we expect our fourth-quarter 2007 production to be 50,000 to 60,000 barrels of oil equivalent per day higher than the level in the third quarter of 2007 due to normal seasonality and the completion of our summer maintenance program.

In R&M, we expect our crude oil capacity utilization in the fourth quarter of 2007 to be in the mid-90 percent range.

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

This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can identify our forward-looking statements by the words “anticipate,” “estimate,” “believe,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “should,” “will,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions.

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

• Fluctuations in crude oil, natural gas and natural gas liquids prices, refining and marketing margins and margins for our chemicals business.

• The operation and financing of our midstream and chemicals joint ventures.

• Potential failure or delays in achieving expected reserve or production levels from existing and future oil and gas development projects due to operating hazards, drilling risks and the inherent uncertainties in predicting oil and gas reserves and oil and gas reservoir performance.

• Unsuccessful exploratory drilling activities.

• Failure of new products and services to achieve market acceptance.

• Unexpected changes in costs or technical requirements for constructing, modifying or operating facilities for exploration and production projects, manufacturing or refining.

• Unexpected technological or commercial difficulties in manufacturing, refining, or transporting our products, including synthetic crude oil and chemicals products.

• Lack of, or disruptions in, adequate and reliable transportation for our crude oil, natural gas, natural gas liquids, LNG and refined products.

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• Inability to timely obtain or maintain permits, including those necessary for construction of LNG terminals or regasification facilities, comply with government regulations, or make capital expenditures required to maintain compliance.

• Failure to complete definitive agreements and feasibility studies for, and to timely complete construction of, announced and future LNG and refinery projects and related facilities.

• Potential disruption or interruption of our operations due to accidents, extraordinary weather events, civil unrest, political events or terrorism.

• International monetary conditions and exchange controls.

• Liability for remedial actions, including removal and reclamation obligations, under environmental regulations.

• Liability resulting from litigation.

• General domestic and international economic and political developments, including armed hostilities, expropriation of assets, changes in governmental policies relating to crude oil, natural gas, natural gas liquids or refined product pricing and taxation, other political, economic or diplomatic developments, and international monetary fluctuations.

• Changes in tax and other laws, regulations (including alternative energy mandates), or royalty rules applicable to our business.

• Inability to obtain economical financing for projects, construction or modification of facilities and general corporate purposes.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information about market risks for the nine months ended September 30, 2007, does not differ materially from that discussed under Item 7A of ConocoPhillips’ Annual Report on Form 10-K for the year ended December 31, 2006.

Item 4. CONTROLS AND PROCEDURES

As of September 30, 2007, with the participation of our management, our Chairman, President and Chief Executive Officer (principal executive officer) and our Executive Vice President, Finance, and Chief Financial Officer (principal financial officer) carried out an evaluation, pursuant to Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the Act), of the effectiveness of the design and operation of ConocoPhillips’ disclosure controls and procedures (as defined in Rule 13a-15(e) of the Act). Based upon that evaluation, our Chairman, President and Chief Executive Officer and our Executive Vice President, Finance, and Chief Financial Officer concluded that our disclosure controls and procedures were operating effectively as of September 30, 2007.

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

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PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

The following is a description of reportable legal proceedings including those involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment for this reporting period.  The following proceedings include those matters that arose during the third quarter of 2007 and any material developments with respect to those matters previously reported in ConocoPhillips’ 2006 Form 10-K or first or second-quarter 2007 Form 10-Qs.  While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings were decided adversely to ConocoPhillips, we expect there would be no material effect on our consolidated financial position.  Nevertheless, such proceedings are reported pursuant to the U.S. Securities and Exchange Commission’s regulations.

Our U.S. refineries are implementing two separate consent decrees, regarding alleged violations of the Federal Clean Air Act, with the U.S. Environmental Protection Agency (EPA), six states and one local air pollution agency. Some of the requirements and limitations contained in the decree provide for stipulated penalties for violations. Stipulated penalties under the decrees are not automatic, but must be requested by one of the agency signatories. As part of periodic reports under the decree and/or other reports required by permits or regulations, we occasionally report matters which could be subject to request for stipulated penalties. If a specific request for stipulated penalties meeting the reporting threshold set forth in U.S. Securities and Exchange Commission rules is made pursuant to these decrees based on a given reported exceedance, we will separately report that matter and the amount of the proposed penalty.

New Matters

The South Coast Air Quality Management District (SCAQMD) conducted an audit of the Los Angeles refinery to assess compliance with applicable local, state, and federal regulations related to fugitive emissions. As a result of the audit, SCAQMD issued three Notices of Violations (NOVs) alleging multiple counts of non-compliance. SCAQMD has not yet specified a penalty for these alleged violations. We are currently assessing these allegations and expect to work with SCAQMD toward a resolution of these NOVs.

On September 25, 2007, the Sweeny refinery received a draft order to resolve a July 6, 2007, Notice of Enforcement (NOE) relating to alleged violations of the Texas Clean Air Act. The allegations relate to compliance with limitations contained in the refinery’s Title V operating permit and one emission event. The draft order proposes a penalty of $294,300. We are evaluating the draft order and expect to work with the agency to resolve the matter.

In October 2007, we received a Complaint from the U.S. EPA alleging violations of the Clean Water Act related to a 2006 oil spill at our Bayway refinery and proposing a penalty of $156,000. We have begun discussions with the EPA to settle this matter and will work with the agency to resolve this matter.

Matters Previously Reported

In March 2007, the Sweeny refinery received a series of NOEs from the Texas Commission on Environmental Quality (TCEQ). These NOEs generally relate to emission events such as flaring and other unplanned releases. The TCEQ proposed a penalty of $487,120 in a draft order received August 30, 2007. We expect to work with the TCEQ toward a resolution of this matter.

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On November 9, 2006, the Bay Area Air Quality Management District (BAAQMD) issued a demand seeking civil penalties for 33 NOVs between October 2005 and October 2006. The NOVs alleged violations of various BAAQMD regulations or permit requirements at our San Francisco area refinery. During the third quarter of 2007, we settled this matter with a payment of $185,500 to BAAQMD.

In March 2005, ConocoPhillips Pipe Line Company (CPPL) received a Notice of Probable Violation and Proposed Civil Penalty from the Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (DOT) alleging violation of DOT operation and safety regulations at certain facilities in Kansas, Missouri, Illinois, Indiana, Wyoming and Nebraska. DOT is proposing penalties in the amount of $184,500. An information hearing was held on September 24, 2007. CPPL will provide additional information in support of its position. A DOT ruling is not anticipated until the first quarter of 2008.

In July 2004, Polar Tankers, Inc. notified the U.S. Coast Guard of possible environmental violations onboard the vessel Polar Discovery.  On June 29, 2005, the U.S. Attorney’s office in Anchorage issued a subpoena to Polar Tankers for records regarding the possible environmental violations onboard that vessel. Polar Tankers and the U.S. Attorney’s office in Anchorage settled the matter on October 23, 2007, with the filing of a plea agreement. Under the agreement, Polar Tankers pled guilty to one count of failing to properly maintain an oil record book, agreed to the payment of a $500,000 fine and a payment of $2 million to the National Fish and Wildlife Foundation. Polar Tankers further agreed to implement an enhanced environmental compliance program monitored by an independent third party during a three-year probation period.

In August 2004, Polar Tankers, Inc. self-reported to the U.S. Coast Guard that a company employee had disclosed to management potential environmental violations onboard the vessel Polar Alaska.  The potential violations related to allegations that certain actions may have resulted in the discharge of one or more wastewater streams potentially having concentrations of oil exceeding an applicable regulatory limit of 15 parts per million.  On September 1, 2004, the U.S. Attorney’s office in Anchorage issued a subpoena to ConocoPhillips Company and Polar Tankers for records relating to the company’s report of potential violations. As part of the plea agreement relating to the Polar Discovery, the U.S. Attorney declined prosecution of this matter.

Item 1A. RISK FACTORS

There have been no material changes from the risk factors disclosed in the “Risk Factors” section of our Annual Report on Form 10-K for the year ended December 31, 2006.

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Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Issuer Purchases of Equity Securities

									Millions of Dollars
						Total Number of			Approximate Dollar
						Shares Purchased			Value of Shares
						as Part of Publicly			that May Yet Be
	Total Number of			Average Price		Announced Plans			Purchased Under the
Period	Shares Purchased		*	Paid per Share		or Programs		**	Plans or Programs		**
July 1-31, 2007		3,388,555		$	84.51		3,385,700		$	14,821
August 1-31, 2007		14,596,063			79.18		14,595,700			13,665
September 1-30, 2007		12,623,357			84.65		12,613,100			12,598
Total		30,607,975		$	82.03		30,594,500

*

Includes the repurchase of common shares from company employees in connection with the company’s broad-based employee incentive plans.

**

On January 12, 2007, we announced a stock repurchase program that provided for the repurchase of up to $1 billion of the company’s common stock. On February 9, 2007, we announced plans to repurchase $4 billion of our common stock in 2007, including the $1 billion announced on January 12, 2007. On July 9, 2007, we announced plans to repurchase up to $15 billion of the company’s common stock through the end of 2008, which includes the $2 billion remaining under the previously announced $4 billion stock buyout authorization. Acquisitions for the share repurchase programs are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Repurchases may be increased, decreased or discontinued at any time without prior notice. Shares of stock repurchased under the plans are held as treasury shares.

Item 5. OTHER INFORMATION

The following information is filed herewith in lieu of including on Form 8-K in Item 5.02, “Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers.”

On October 26, 2007, Randy L. Limbacher, president, Exploration & Production — Americas, gave the Company notice that he would be departing ConocoPhillips effective October 31, 2007. In recognition of Mr. Limbacher’s service to the Company following our acquisition of Burlington Resources Inc., the Compensation Committee of the Board of Directors approved the following with respect to Mr. Limbacher’s compensation arrangements: (i) continuing eligibility for consideration under the Performance Share Program (on a pro-rata basis for periods in which he participated more than 12 months); (ii) continuing eligibility for consideration under the 2007 Variable Cash Incentive Program (on a pro-rata basis); and (iii) the following modifications to the terms of Mr. Limbacher’s equity awards:

• Vesting of 18,929 shares of restricted stock granted April 4, 2006, which were scheduled to vest on April 4, 2008.

• Vesting of 12,261 shares of restricted stock granted January 25, 2006, which were scheduled to vest on January 25, 2009.

• With respect to the January 25, 2006, award of 43,275 options to purchase shares of ConocoPhillips common stock with an exercise price of $62.9925, the unvested portion of the award will become exercisable concurrent with Mr. Limbacher’s departure date and the award will remain exercisable until October 31, 2010.

In making the foregoing decisions, the Compensation Committee considered Mr. Limbacher’s agreement to waive the right to severance payments under the Burlington Resources Executive Change in Control Severance Plan.

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Item 6. EXHIBITS

Exhibits

12	Computation of Ratio of Earnings to Fixed Charges.
31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
32	Certifications pursuant to 18 U.S.C. Section 1350.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

CONOCOPHILLIPS

/s/ Rand C. Berney

Rand C. Berney

Vice President and Controller

(Chief Accounting and Duly Authorized Officer)

October 31, 2007

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INDEX TO EXHIBITS

Exhibits

12	Computation of Ratio of Earnings to Fixed Charges.
31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
32	Certifications pursuant to 18 U.S.C. Section 1350.