ConocoPhillips (COP) 10-Q 2010 Q3 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended           September 30, 2010

or

[  ] 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. Yes [x] No [  ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [x] No [  ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer [x] Accelerated filer [  ] Non-accelerated filer [  ]
(Do not check if a smaller reporting company) Smaller reporting company [  ]

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

The registrant had 1,469,224,505 shares of common stock, $.01 par value, outstanding at September 30, 2010.

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		29
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		34
Item 3. Quantitative and Qualitative Disclosures About Market Risk		53
Item 4. Controls and Procedures		53
Part II – Other Information
Item 1. Legal Proceedings		54
Item 1A. Risk Factors		55
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		55
Item 6. Exhibits		56
Signature		57
EX-12
EX-31.1
EX-31.2
EX-32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

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
	2010			2009		(2)	2010			2009		(2)
Revenues and Other Income
Sales and other operating revenues(1)	$	47,208			40,173			137,715			106,362
Equity in earnings of affiliates		1,004			981			2,960			1,986
Gain on sale of Syncrude		-			-			2,878			-
Other income		1,337			117			1,885			347
Total Revenues and Other Income		49,549			41,271			145,438			108,695
Costs and Expenses
Purchased crude oil, natural gas and products		34,051			28,008			97,660			72,376
Production and operating expenses		2,583			2,534			7,729			7,652
Selling, general and administrative expenses		493			427			1,375			1,378
Exploration expenses		252			386			848			854
Depreciation, depletion and amortization		2,246			2,327			6,844			6,904
Impairments		59			56			1,682			110
Taxes other than income taxes(1)		4,227			4,205			12,511			11,384
Accretion on discounted liabilities		110			96			337			308
Interest and debt expense		264			336			914			914
Foreign currency transaction (gains) losses		(10	)		(17	)		80			(28	)
Total Costs and Expenses		44,275			38,358			129,980			101,852
Income before income taxes		5,274			2,913			15,458			6,843
Provision for income taxes		2,205			1,426			6,094			3,665
Net income		3,069			1,487			9,364			3,178
Less: net income attributable to noncontrolling interests		(14	)		(17	)		(47	)		(49	)
Net Income Attributable to ConocoPhillips	$	3,055			1,470			9,317			3,129
Net Income Attributable to ConocoPhillips Per Share of Common Stock(dollars) (3)
Basic	$	2.06			.98			6.26			2.10
Diluted		2.05			.97			6.21			2.08
Dividends Paid Per Share of Common Stock(dollars)	$	.55			.47			1.60			1.41
Average Common Shares Outstanding(in thousands)
Basic		1,481,522			1,488,352			1,488,024			1,486,922
Diluted		1,493,080			1,498,204			1,499,367			1,496,391
(1)Includes excise taxes on petroleum products sales:	$	3,544			3,538			10,181			9,914

(2)Recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information.

(3)For the purpose of the earnings per share calculation only, 2009 net income attributable to ConocoPhillips has been reduced by $12 million for the excess of the amount paid for the redemption of a noncontrolling interest over its carrying value, which was charged directly to retained earnings.

See Notes to Consolidated Financial Statements.

1

Consolidated Balance Sheet ConocoPhillips

	Millions of Dollars
	September 30			December 31
	2010			2009		*
Assets
Cash and cash equivalents	$	7,996			542
Accounts and notes receivable (net of allowance of $28 million in 2010 and $76 million in 2009)		11,723			11,861
Accounts and notes receivable—related parties		1,755			1,354
Investment in LUKOIL		2,856			-
Inventories		7,741			4,940
Prepaid expenses and other current assets		3,246			2,470
Total Current Assets		35,317			21,167
Investments and long-term receivables		31,182			35,742
Loans and advances—related parties		2,175			2,352
Net properties, plants and equipment		81,460			87,708
Goodwill		3,637			3,638
Intangibles		806			823
Other assets		756			708
Total Assets	$	155,333			152,138
Liabilities
Accounts payable	$	14,148			14,168
Accounts payable—related parties		1,916			1,317
Short-term debt		376			1,728
Accrued income and other taxes		5,186			3,402
Employee benefit obligations		768			846
Other accruals		3,027			2,234
Total Current Liabilities		25,421			23,695
Long-term debt		23,225			26,925
Asset retirement obligations and accrued environmental costs		8,518			8,713
Joint venture acquisition obligation—related party		4,492			5,009
Deferred income taxes		17,286			17,956
Employee benefit obligations		3,732			4,130
Other liabilities and deferred credits		2,742			3,097
Total Liabilities		85,416			89,525
Equity
Common stock (2,500,000,000 shares authorized at $.01 par value)
Issued (2010—1,737,649,139 shares; 2009—1,733,345,558 shares)
Par value		17			17
Capital in excess of par		43,956			43,681
Grantor trusts (at cost: 2010—37,798,903 shares; 2009—38,742,261 shares)		(650	)		(667	)
Treasury stock (at cost: 2010—230,625,731 shares; 2009—208,346,815 shares)		(17,468	)		(16,211	)
Accumulated other comprehensive income		4,405			3,065
Unearned employee compensation		(55	)		(76	)
Retained earnings		39,156			32,214
Total Common Stockholders’ Equity		69,361			62,023
Noncontrolling interests		556			590
Total Equity		69,917			62,613
Total Liabilities and Equity	$	155,333			152,138

*Recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information.

See Notes to Consolidated Financial Statements.

2

Consolidated Statement of Cash Flows ConocoPhillips

	Millions of Dollars
	Nine Months Ended
	September 30
	2010			2009		*
Cash Flows From Operating Activities
Net income	$	9,364			3,178
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization		6,844			6,904
Impairments		1,682			110
Dry hole costs and leasehold impairments		327			471
Accretion on discounted liabilities		337			308
Deferred taxes		(935	)		(872	)
Undistributed equity earnings		(1,642	)		(1,298	)
Gain on asset dispositions		(4,671	)		(88	)
Other		(221	)		(151	)
Working capital adjustments
Decrease (increase) in accounts and notes receivable		323			(94	)
Decrease (increase) in inventories		(2,898	)		(1,026	)
Decrease (increase) in prepaid expenses and other current assets		(459	)		(286	)
Increase (decrease) in accounts payable		401			910
Increase (decrease) in taxes and other accruals		2,402			(681	)
Net Cash Provided by Operating Activities		10,854			7,385
Cash Flows From Investing Activities
Capital expenditures and investments		(6,371	)		(8,176	)
Proceeds from asset dispositions		12,233			938
Long-term advances/loans—related parties		(296	)		(303	)
Collection of advances/loans—related parties		104			62
Other		114			50
Net Cash Provided by (Used in) Investing Activities		5,784			(7,429	)
Cash Flows From Financing Activities
Issuance of debt		96			9,051
Repayment of debt		(5,304	)		(6,027	)
Issuance of company common stock		59			(11	)
Repurchase of company common stock		(1,258	)		-
Dividends paid on company common stock		(2,376	)		(2,090	)
Other		(544	)		(1,091	)
Net Cash Used in Financing Activities		(9,327	)		(168	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents		143			98
Net Change in Cash and Cash Equivalents		7,454			(114	)
Cash and cash equivalents at beginning of period		542			755
Cash and Cash Equivalents at End of Period	$	7,996			641

*Recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information.

See Notes to Consolidated Financial Statements.

3

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. To enhance your understanding of these interim financial statements, see the consolidated financial statements and notes included in our 2009 Annual Report on Form 10-K.

Note 2—Changes in Accounting Principles

LUKOIL Accounting

Effective January 1, 2010, we changed the method used to determine our equity-method share of OAO LUKOIL’s earnings. Prior to 2010, we estimated our LUKOIL equity earnings for the current quarter based on current market indicators, publicly available LUKOIL information and other objective data. This earnings estimation process was necessary because, historically, LUKOIL’s accounting cycle close and preparation of U.S. generally accepted accounting principles financial statements occurred subsequent to our reporting deadline, and for certain periods this timing gap exceeded 93 days. Although Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 323, “Investments—Equity Method and Joint Ventures,” provides that when financial statements of an investee are not sufficiently timely, then the investor should record its share of earnings or loss based on the most recently available financial statements, U.S. Securities and Exchange Commission guidance indicates this timing gap generally should not exceed 93 days. Recently, the timing gap has been reduced to less than 93 days for all reporting periods. Accordingly, we believe it is preferable to implement a change in accounting principle to record our equity-method share of LUKOIL’s earnings on a one-quarter-lag basis, rather than using an earnings estimate for the current quarter, because it improves reporting reliability, while maintaining an acceptable level of relevance.

This change in accounting principle to a one-quarter lag under ASC Topic 323 has been applied retrospectively, by recasting prior period financial information. The following table summarizes the line items affected on the consolidated income statement:

	Millions of Dollars
	Three Months Ended September 30
	2010							2009
	Computed		As		Effect			As				Effect
	with		Reported		of			Originally		As		of
	Estimate		with Lag		Change			Reported		Adjusted		Change
Equity in earnings of affiliates	$	892		1,004		112			1,015		981		(34	)
Other income		1,207		1,337		130			117		117		-
Provision for income taxes		2,247		2,205		(42	)		1,427		1,426		(1	)
Net income		2,785		3,069		284			1,520		1,487		(33	)
Net income attributable to ConocoPhillips		2,771		3,055		284			1,503		1,470		(33	)
Net income attributable to ConocoPhillips per share of common stock (dollars)
Basic	$	1.87		2.06		.19			1.00		.98		(.02	)
Diluted		1.86		2.05		.19			1.00		.97		(.03	)

4

	Millions of Dollars
	Nine Months Ended September 30
	2010							2009
	Computed		As		Effect			As				Effect
	with		Reported		of			Originally		As		of
	Estimate		with Lag		Change			Reported		Adjusted		Change
Equity in earnings of affiliates	$	2,778		2,960		182			2,506		1,986		(520	)
Other income		1,755		1,885		130			347		347		-
Provision for income taxes		6,137		6,094		(43	)		3,673		3,665		(8	)
Net income		9,009		9,364		355			3,690		3,178		(512	)
Net income attributable to ConocoPhillips		8,962		9,317		355			3,641		3,129		(512	)
Net income attributable to ConocoPhillips per share of common stock (dollars)
Basic	$	6.02		6.26		.24			2.44		2.10		(.34	)
Diluted		5.98		6.21		.23			2.43		2.08		(.35	)

The following table summarizes the line items affected on the consolidated balance sheet:

	Millions of Dollars
	September 30, 2010							December 31, 2009
	Computed		As		Effect			As				Effect
	with		Reported		of			Originally		As		of
	Estimate		with Lag		Change			Reported		Adjusted		Change
Investments and long-term receivables	$	31,182		31,182		-			36,192		35,742		(450	)
Deferred income taxes		17,278		17,286		8			17,962		17,956		(6	)
Accumulated other comprehensive income		4,324		4,405		81			3,065		3,065		-
Retained earnings		39,245		39,156		(89	)		32,658		32,214		(444	)

There was no cumulative impact to retained earnings as of January 1, 2009, as a result of the accounting change. This was due to the impairment of our LUKOIL investment during 2008 to its fair market value on December 31, 2008.

5

The following table summarizes the line items affected on the consolidated statement of cash flows:

	Millions of Dollars
	Nine Months Ended September 30
	2010									2009
	Computed			As			Effect			As						Effect
	with			Reported			of			Originally			As			of
	Estimate			with Lag			Change			Reported			Adjusted			Change
Net income	$	9,009			9,364			355			3,690			3,178			(512	)
Deferred taxes		(892	)		(935	)		(43	)		(864	)		(872	)		(8	)
Undistributed equity earnings		(1,460	)		(1,642	)		(182	)		(1,818	)		(1,298	)		520
Gain on asset dispositions		(4,541	)		(4,671	)		(130	)		(88	)		(88	)		-

See Note 6—Investments, Loans and Long-Term Receivables, for additional information relating to our LUKOIL investment.

Transfers of Financial Assets

In June 2009, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 166, “Accounting for Transfers of Financial Assets, an amendment of FASB Statement No. 140,” which was codified into FASB ASC Topic 860, “Transfers and Servicing.” This Statement removes the concept of a qualifying special purpose entity (SPE) and the exception for qualifying SPEs from the consolidation guidance. Additionally, the Statement clarifies the requirements for financial asset transfers eligible for sale accounting. This Statement was effective January 1, 2010, and did not impact our consolidated financial statements.

Variable Interest Entities (VIEs)

Also in June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R),” to address the effects of the elimination of the qualifying SPE concept in SFAS No. 166, and other concerns about the application of key provisions of consolidation guidance for VIEs. This Statement was codified into FASB ASC Topic 810, “Consolidation.” More specifically, Topic 810 requires a qualitative rather than a quantitative approach to determine the primary beneficiary of a VIE, it amends certain guidance pertaining to the determination of the primary beneficiary when related parties are involved, and it amends certain guidance for determining whether an entity is a VIE. Additionally, this Statement requires continuous assessments of whether an enterprise is the primary beneficiary of a VIE. This Statement was effective January 1, 2010, and its adoption did not impact our consolidated financial statements, other than the required disclosures. For additional information, see Note 3—Variable Interest Entities (VIEs).

Note 3—Variable Interest Entities (VIEs)

We hold significant variable interests in VIEs that have not been consolidated because we are not considered the primary beneficiary. Information on these VIEs follows:

We have a 30 percent ownership interest with a 50 percent governance interest in the OOO Naryanmarneftegaz (NMNG) joint venture to develop resources in the Timan-Pechora province of Russia. The NMNG joint venture is a VIE because we and LUKOIL have disproportionate interests, and LUKOIL was a related party at inception of the joint venture. Since LUKOIL is no longer a related party, we do not believe NMNG would be a VIE if reconsidered today. LUKOIL owns 70 percent versus our 30 percent direct interest; therefore, we have determined we are not the primary beneficiary of NMNG, and we use the equity method of accounting for this investment. The funding of NMNG has been provided with equity contributions, primarily for the development of the Yuzhno Khylchuyu (YK) Field. At September 30, 2010, the book value of our investment in the venture was $1,414 million.

6

We have an agreement with Freeport LNG Development, L.P. (Freeport LNG) to participate in a liquefied natural gas (LNG) receiving terminal in Quintana, Texas. We have no ownership in Freeport LNG; however, we own a 50 percent interest in Freeport LNG GP, Inc. (Freeport GP), which serves as the general partner managing the venture. We entered into a credit agreement with Freeport LNG, whereby we agreed to provide loan financing for the construction of the terminal. We also entered into a long-term agreement with Freeport LNG to use 0.9 billion cubic feet per day of regasification capacity. The terminal became operational in June 2008, and we began making payments under the terminal use agreement. Freeport LNG began making loan repayments in September 2008, and the loan balance outstanding as of September 30, 2010, was $663 million. Freeport LNG is a VIE because Freeport GP holds no equity in Freeport LNG, and the limited partners of Freeport LNG do not have any substantive decision making ability. We are not the primary beneficiary because the equity holders of Freeport GP are not related parties and have equally shared power. Neither party has the power to direct the significant activities without the consent of the other party, in which case neither party is considered to be the primary beneficiary. The loan to Freeport LNG is accounted for as a financial asset, and our investment in Freeport GP is accounted for as an equity investment.

Note 4—Inventories

Inventories consisted of the following:

	Millions of Dollars
	September 30		December 31
	2010		2009
Crude oil and petroleum products	$	6,771		3,955
Materials, supplies and other		970		985
	$	7,741		4,940

Inventories valued on the last-in, first-out (LIFO) basis totaled $6,563 million and $3,747 million at September 30, 2010, and December 31, 2009, respectively. The excess of current replacement cost over LIFO cost of inventories amounted to $5,666 million and $5,627 million at September 30, 2010, and December 31, 2009, respectively.

Note 5—Assets Held for Sale

In the fourth quarter of 2009, we announced plans to raise approximately $10 billion from asset sales through the end of 2011. At December 31, 2009, we classified $323 million of Refining and Marketing (R&M) noncurrent assets, primarily investment in equity affiliates, and $75 million of R&M noncurrent deferred income tax liabilities as held for sale. During 2010, these assets and others were sold, and in the third quarter of 2010, additional Exploration and Production (E&P) assets in the United States and Canada met the held for sale criteria. As a result, at September 30, 2010, we classified $638 million of properties, plants and equipment as “Prepaid expenses and other current assets” and $219 million of asset retirement obligations and accrued environmental costs as “Other accruals” on our consolidated balance sheet. We also classified $54 million of deferred income taxes as current. Contingent upon necessary regulatory approvals and negotiation of final contract terms, we expect these assets to be sold by the end of 2010 or early 2011. Excluding the Syncrude sale discussed below, and the gain on the sale of our LUKOIL shares discussed in Note 6—Investments, Loans and Long-Term Receivables, the net before-tax gain from asset dispositions during the nine-month period ended September 30, 2010, was $475 million, and this amount was included in the “Other income” line of our consolidated income statement.

7

On June 25, 2010, we sold our 9.03 percent interest in the Syncrude Canada Ltd. joint venture for $4.6 billion. Syncrude was included in our E&P segment and had synthetic oil proved reserves of 248 million barrels at December 31, 2009. Production in 2009 was 23,000 barrels per day. The $2.9 billion before-tax gain on this disposition was included as a separate line in the “Total Revenues and Other Income” section of our consolidated income statement. The cash proceeds were included in the “Proceeds from asset dispositions” line within the investing cash flow section of our consolidated statement of cash flows. At the time of disposition, Syncrude had a net carrying value of $1.75 billion, which included $1.97 billion of properties, plants and equipment. During fiscal 2010 until its disposition, Syncrude contributed $327 million in intercompany sales and other operating revenues, and generated income before taxes of $127 million and net income of $93 million.

Note 6—Investments, Loans and Long-Term Receivables

LUKOIL

Our average ownership interest in LUKOIL in the second quarter of 2010, used to record our equity-method share of LUKOIL’s second-quarter results on a lag basis, was 19.46 percent. On July 28, 2010, we announced our intention to sell our entire interest in LUKOIL, then consisting of 163,367,629 shares. This decision is being implemented as follows:

• On July 28, 2010, we entered into a stock purchase and option agreement (the Agreement) with a wholly owned subsidiary of LUKOIL, pursuant to which such subsidiary would purchase 64,638,729 shares from us at a price of $53.25 per share, or $3.44 billion in total. This transaction closed on August 16, 2010.

• Also pursuant to the Agreement, the LUKOIL subsidiary had a 60-day option, expiring on September 26, 2010, to purchase any or all of our interest remaining at the time of exercise of the option, at a price of $56 per share. Upon exercise of this option, we sold 42,500,000 shares on September 29, 2010, for proceeds of $2.38 billion.

• Finally, we intend to sell our remaining shares in the open market from time to time, subject to the terms of the Shareholder Agreement, by the end of 2011.

In total, during the third quarter of 2010, we sold 113 million shares of LUKOIL for $6,161 million, realizing a before-tax gain on disposition of $1,219 million, which was included in the “Other income” line of the consolidated income statement. As a result of these sales, our ownership interest has declined to a level at which we are no longer able to exercise significant influence over the operating and financial policies of LUKOIL, and going forward we will no longer account for our remaining investment in LUKOIL using the equity method. We will also no longer report proved reserves or production related to our LUKOIL investment, which were 1,967 million barrels of oil equivalent (BOE) at December 31, 2009, and 437 thousand BOE per day for the nine-month period ended September 30, 2010, respectively.

At September 30, 2010, our remaining 5.9 percent investment in LUKOIL was reclassified from “Investments and long-term receivables” to current assets on our consolidated balance sheet as an available-for-sale equity security and carried at fair value of $2,856 million, reflecting a closing price of LUKOIL shares on the London Stock Exchange of $56.80 per share. The carrying value reflects a pretax unrealized gain over our cost of $663 million. This unrealized gain, net of related income taxes, is reported as a component of accumulated other comprehensive income. The fair value is categorized as Level 1 in the fair value hierarchy. See Note 2—Changes in Accounting Principles, for additional information about accounting for our LUKOIL investment.

8

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, 2010, included the following:

• $663 million in loan financing to Freeport LNG Development, L.P.

• $1,096 million in project financing and an additional $94 million of accrued interest to Qatargas 3.

• $551 million in loan financing to WRB Refining LLC.

The long-term portion of these loans are included in the “Loans and advances—related parties” line on the consolidated balance sheet, while the short-term portion is in “Accounts and notes receivable—related parties.” At September 30, 2010, the Varandey Terminal Company is no longer considered a related party. Accordingly, the long-term portion of this loan is included in the “Investments and long-term receivables” line of the consolidated balance sheet, while the short-term portion is in “Prepaid expenses and other current assets.”

Other Investments

We have investments remeasured at fair value on a recurring basis to support certain nonqualified deferred compensation plans. The fair value of these assets at September 30, 2010, was $315 million, and at December 31, 2009, was $338 million. Substantially the entire value is categorized in Level 1 of the fair value hierarchy. These investments are measured at fair value using a market approach based on quotations from national securities exchanges.

Merey Sweeny, L.P. (MSLP) is a limited partnership that owns a 70,000 barrel-per-day delayed coker and related facilities at the Sweeny Refinery. MSLP processes our long residue, which is produced from heavy sour crude oil, for a processing fee. Fuel-grade petroleum coke is produced as a by-product and becomes the property of MSLP. Prior to August 28, 2009, MSLP was owned 50/50 by us and Petróleos de Venezuela S.A. (PDVSA). Under the agreements that govern the relationships between the partners, certain defaults by PDVSA with respect to supply of crude oil to the Sweeny Refinery gave us the right to acquire PDVSA’s 50 percent ownership interest in MSLP. On August 28, 2009, we exercised that right. PDVSA has initiated arbitration in the International Chamber of Commerce challenging our actions, and this arbitration is underway. We continue to use the equity method of accounting for our investment in MSLP.

Note 7—Properties, Plants and Equipment

Our investment in properties, plants and equipment (PP&E), with the associated accumulated depreciation, depletion and amortization (Accum. DD&A), was:

	Millions of Dollars
	September 30, 2010						December 31, 2009
	Gross		Accum.		Net		Gross		Accum.		Net
	PP&E		DD&A		PP&E		PP&E		DD&A		PP&E
E&P	$	114,281		48,921		65,360		115,224		45,577		69,647
Midstream		126		79		47		123		74		49
R&M		23,294		8,858		14,436		23,047		6,714		16,333
LUKOIL Investment		-		-		-		-		-		-
Chemicals		-		-		-		-		-		-
Emerging Businesses		1,193		342		851		1,198		300		898
Corporate and Other		1,680		914		766		1,650		869		781
	$	140,574		59,114		81,460		141,242		53,534		87,708

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Suspended Wells

The capitalized cost of suspended wells at September 30, 2010, was $1,061 million, an increase of $153 million from $908 million at year-end 2009. For the category of exploratory well costs capitalized for a period greater than one year as of December 31, 2009, no wells were charged to dry hole expense during the first nine months of 2010.

Note 8—Impairments

During the first nine months of 2010 and 2009, we recognized the following before-tax impairment charges:

	Millions of Dollars
	Three Months Ended				Nine Months Ended
	September 30				September 30
	2010		2009		2010		2009
E&P
United States	$	29		-		29		-
International		4		-		5		59
R&M
United States		-		55		17		50
International		-		-		1,600		-
Emerging Businesses		26		-		31		-
Corporate		-		1		-		1
	$	59		56		1,682		110

2010

The nine-month period of 2010 included the $1,502 million impairment of our refinery in Wilhelmshaven, Germany, due to cancelled plans for a project to upgrade the refinery, and a $98 million impairment as a result of our decision to end our participation in a new refinery project in Yanbu Industrial City, Saudi Arabia.

2009

In the second quarter of 2009, we recorded a noncash charge of $51 million before- and after-tax related to the full impairment of our exploration and production investments in Ecuador, due to their expropriation. An arbitration hearing on case merits is scheduled for March 2011, with a decision on case merits expected in December 2011.

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Fair Value Remeasurements

The following table shows the values of assets at September 30, 2010, and December 31, 2009, by major category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition:

	Millions of Dollars
			Fair Value
			Measurements Using
			Level 1		Level 3		Before-Tax
	Fair Value		Inputs		Inputs		Loss
September 30, 2010
Net properties, plants and equipment (held for use)	$	297		-		297		1,588	*
Net properties, plants and equipment (held for sale)		23		23		-		43
December 31, 2009
Net properties, plants and equipment (held for use)	$	210		-		210		385
Net properties, plants and equipment (held for sale)		121		35		86		62
Equity method investments		1,784		-		1,784		286

*Includes a $55 million leasehold impairment charged to exploration expenses.

2010

During 2010, net properties, plants and equipment held for use with a carrying amount of $1,885 million were written down to a fair value of $297 million, resulting in a before-tax loss of $1,588 million. The fair values were determined by the use of internal discounted cash flow models using estimates of future production, prices, costs and a discount rate believed to be consistent with those used by principal market participants and cash flow multiples for similar assets and alternative use.

During 2010, net properties, plants and equipment held for sale with a carrying amount of $64 million were written down to their fair value of $23 million less cost to sell of $2 million for a net $21 million, resulting in a before-tax loss of $43 million. The fair values were primarily determined by binding negotiated selling prices with third parties, with some adjusted for the fair value of certain liabilities retained.

2009

During 2009, net properties, plants and equipment held for use with a carrying amount of $610 million were written down to a fair value of $210 million, resulting in a before-tax loss of $385 million. In addition, certain equity method investments associated with our E&P segment were determined to have a fair value below carrying amount, and the impairment was considered to be other than temporary. These investments with a book value of $2,070 million were written down to a fair value of $1,784 million resulting in a charge of $286 million before-tax, which is included in the “Equity in earnings of affiliates” line of our consolidated income statement. The fair values were determined by the application of an internal discounted cash flow model using estimates of future production, prices, costs and a discount rate believed to be consistent with those used by principal market participants. In addition, the equity investment fair value considered market analysis of certain similar undeveloped properties owned by one of the investees.

Also during 2009, net properties, plants and equipment held for sale with a carrying amount of $178 million were written down to a fair value of $121 million, less cost to sell of $5 million for a net $116 million, resulting in a before-tax loss of $62 million. The fair values were largely based on binding negotiated prices with third parties, with some adjusted for the fair value of certain liabilities retained.

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Note 9—Debt

We have two commercial paper programs supported by our $7.85 billion revolving credit facilities: the ConocoPhillips $6.35 billion program, primarily a funding source for short-term working capital needs, and the ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program, which is used to fund commitments relating to the Qatargas 3 Project. Commercial paper maturities are generally limited to 90 days.

At both September 30, 2010, and December 31, 2009, we had no direct outstanding borrowings under our revolving credit facilities, but $40 million in letters of credit had been issued. In addition, under the two commercial paper programs, there was $1,159 million of commercial paper outstanding at September 30, 2010, compared with $1,300 million at December 31, 2009. Since we had $1,159 million of commercial paper outstanding and had issued $40 million of letters of credit, we had access to $6.7 billion in borrowing capacity under our revolving credit facilities at September 30, 2010.

During the first nine months of 2010, the following debt instruments were repaid prior to their maturity:

• The $400 million 6.68% bonds.

• The $178 million 6.4% bonds.

• The $1,750 million 6.35% bonds.

• The $350 million 5.30% bonds.

• The $750 million remaining balance of the Floating Rate Five-Year Term Notes.

During the first nine months of 2010, the following debt instruments were repaid at their maturity:

• The $150 million 9.875% bonds.

• The $1,264 million 8.75% bonds.

At September 30, 2010, we classified $1,159 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.

Note 10—Joint Venture Acquisition Obligation

We are obligated to contribute $7.5 billion, plus interest, over a 10-year period that began in 2007, to FCCL Partnership. Quarterly principal and interest payments of $237 million began in the second quarter of 2007 and will continue until the balance is paid. Of the principal obligation amount, $686 million was short-term and was included in the “Accounts payable—related parties” line on our September 30, 2010, consolidated balance sheet. The principal portion of these payments, which totaled $491 million in the first nine months of 2010, is included in the “Other” line in the financing activities section of our consolidated statement of cash flows. 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 a capital contribution and is included in the “Capital expenditures and investments” line on our consolidated statement of cash flows.

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Note 11—Noncontrolling Interests

Activity for the equity attributable to noncontrolling interests for the first nine months of 2010 and 2009 was as follows:

	Millions of Dollars
	2010									2009*
	Common			Non-						Common			Non-
	Stockholders’			Controlling			Total			Stockholders’			Controlling			Total
	Equity			Interests			Equity			Equity			Interests			Equity
Balance at January 1	$	62,023			590			62,613			55,165			1,100			56,265
Net income		9,317			47			9,364			3,129			49			3,178
Dividends		(2,376	)		-			(2,376	)		(2,090	)		-			(2,090	)
Repurchase of company common stock		(1,258	)		-			(1,258	)		-			-			-
Distributions to noncontrolling interests		-			(80	)		(80	)		-			(74	)		(74	)
Other changes, net**		1,655			(1	)		1,654			4,795			(488	)		4,307
Balance at September 30	$	69,361			556			69,917			60,999			587			61,586

  *Recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information.

**Includes components of other comprehensive income, which are disclosed separately in Note 15—Comprehensive Income.

Note 12—Guarantees

At September 30, 2010, 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 below, 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. In addition, unless otherwise stated, we are not currently performing with any significance under the guarantee and expect future performance to be either immaterial or have only a remote chance of occurrence.

Construction Completion Guarantees

• In December 2005, we issued a construction completion guarantee for 30 percent of the $4 billion in loan facilities of Qatargas 3, which are being used to finance the construction of an LNG train in Qatar. Of the $4 billion in loan facilities, we 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 nonrecourse to ConocoPhillips upon certified completion, which is expected in 2011. At September 30, 2010, the carrying value of the guarantee to third-party lenders was $11 million.

Guarantees of Joint Venture Debt

• At September 30, 2010, we had guarantees outstanding for our portion of joint venture debt obligations, which have terms of up to 15 years. The maximum potential amount of future payments under the guarantees is approximately $80 million. Payment would be required if a joint venture defaults on its debt obligations.

Other Guarantees

• In conjunction with our purchase of a 50 percent ownership interest in Australia Pacific LNG Pty Limited (APLNG) from Origin Energy in October 2008, we agreed to participate, if and when

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requested, in any parent company guarantees that were outstanding at the time we purchased our interest in APLNG. These parent company guarantees cover the obligation of APLNG to deliver natural gas under several sales agreements with remaining terms of 7 to 21 years. Our maximum potential amount of future payments, or cost of volume delivery, under these guarantees is estimated to be $1,572 million ($3,396 million in the event of intentional or reckless breach) at September 2010 exchange rates based on our 50 percent share of the remaining contracted volumes, which could become payable if APLNG fails to meet its obligations under these agreements and the obligations cannot otherwise be mitigated. Future payments are considered unlikely, as the payments, or cost of volume delivery, would only be triggered if APLNG does not have enough natural gas to meet these sales commitments and if the co-venturers do not make necessary equity contributions into APLNG.

• We have other guarantees with maximum future potential payment amounts totaling $440 million, which consist primarily of guarantees to fund the short-term cash liquidity deficits of certain joint ventures, guarantees of minimum charter revenue for two LNG vessels, one small construction completion guarantee, guarantees of the lease payment obligations of a joint venture, and guarantees of the residual value of leased corporate aircraft. These guarantees generally extend up to 14 years or life of the venture.

Indemnifications

Over the years, we have entered into various agreements to sell ownership interests in certain corporations, joint ventures and assets 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, 2010, was $395 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 recorded carrying amount were $245 million of environmental accruals for known contamination that are included in asset retirement obligations and accrued environmental costs at September 30, 2010. For additional information about environmental liabilities, see Note 13—Contingencies and Commitments.

Note 13—Contingencies and Commitments

In the case of all known contingencies (other than those related to income taxes), 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 use 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. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates 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

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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 consolidated 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 account stakeholder and business considerations. 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 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 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 results of operations, capital resources or liquidity, or to those of one of our segments. 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 we adjust our accruals accordingly.

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

We are currently participating in environmental assessments and cleanups at numerous federal Superfund and comparable state sites. After an assessment of environmental exposures for cleanup and other costs, we make accruals on an undiscounted basis (except 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 future costs will be incurred and these costs can be reasonably estimated. At September 30, 2010, our balance sheet included a total environmental accrual of $987 million, compared with $1,017 million at December 31, 2009. We expect to incur a substantial amount 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 that have been scheduled for trial, as well as the pace of settlement discussions in individual matters. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases,

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our legal organization believes there is a remote likelihood 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, 2010, we had performance obligations secured by letters of credit of $1,684 million (of which $40 million was issued under the provisions of our revolving credit facility, and the remainder was issued as direct bank letters of credit) related to various purchase commitments for materials, supplies, services and items of permanent investment incident to the ordinary conduct of business.

Long-Term Throughput Agreements and Take-or-Pay Agreements

Our obligation under throughput agreements to support third-party shipper financing arrangements for a crude oil transportation system commenced during the second quarter of 2010. The aggregate amounts of estimated future payments under these agreements are: 2010—$25 million; 2011—$233 million; 2012—$277 million; 2013—$276 million; 2014—$276 million; and 2015 and after—$4,423 million.

Note 14—Financial Instruments and Derivative Contracts

Derivative Instruments

We use financial and commodity-based derivative contracts to manage exposures to fluctuations in foreign currency exchange rates, commodity prices, and interest rates, or to capture market opportunities. Since we are not currently using cash flow hedge accounting, all gains and losses, realized or unrealized, from derivative contracts have been recognized in the consolidated income statement. Gains and losses from derivative contracts held for trading not directly related to our physical business, whether realized or unrealized, have been reported net in other income.

Purchase and sales contracts for commodities that are readily convertible to cash (e.g., crude oil, natural gas and gasoline) are recorded on the balance sheet as derivatives unless the contracts are for quantities we expect to use or sell over a reasonable period in the normal course of business (i.e., contracts eligible for the normal purchases and normal sales exception). We record most of our contracts to buy or sell natural gas and the majority of our contracts to sell power as derivatives, but we do apply the normal purchases and normal sales exception to certain long-term contracts to sell our natural gas production. We generally apply this normal purchases and normal sales exception to eligible crude oil and refined product commodity purchase and sales contracts; however, we may elect not to apply this exception (e.g., when another derivative instrument will be used to mitigate the risk of the purchase or sales contract but hedge accounting will not be applied, in which case both the purchase or sales contract and the derivative contract mitigating the resulting risk will be recorded on the balance sheet at fair value).

We value our exchange-cleared derivatives using closing prices provided by the exchange as of the balance sheet date, and these are classified as Level 1 in the fair value hierarchy. Over-the-counter (OTC) financial swaps and physical commodity forward purchase and sales contracts are generally valued using quotations provided by brokers and price index developers, such as Platts and Oil Price Information Service. These quotes are corroborated with market data and are classified as Level 2. In certain less liquid markets or for longer-term contracts, forward prices are not as readily available. In these circumstances, OTC swaps and physical commodity purchase and sales contracts are valued using internally developed methodologies that consider historical relationships among various commodities that result in management’s best estimate of fair value. These contracts are classified as Level 3. A contract that is initially classified as Level 3 due to absence or insufficient corroboration of broker quotes over a material portion of the contract will transfer to Level 2 when the portion of the trade having no quotes or insufficient corroboration becomes an insignificant portion of the contract. A contract would also transfer to Level 2 if we began using a corroborated broker quote that has

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become available. Conversely, if a corroborated broker quote ceases to be available or used by us, the contract would transfer from Level 2 to Level 3. There were no transfers in or out of Level 1.

Exchange-cleared financial options are valued using exchange closing prices and are classified as Level 1. Financial OTC and physical commodity options are valued using industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and contractual prices for the underlying instruments, as well as other relevant economic measures. The degree to which these inputs are observable in the forward markets determines whether the options are classified as Level 2 or 3.

We use a mid-market pricing convention (the mid-point between bid and ask prices). When appropriate, valuations are adjusted to reflect credit considerations, generally based on available market evidence.

The fair value hierarchy for our derivative assets and liabilities accounted for at fair value on a recurring basis was:

	Millions of Dollars
	September 30, 2010									December 31, 2009
	Level 1			Level 2		Level 3		Total		Level 1			Level 2		Level 3		Total
Assets
Commodity derivatives	$	2,766			1,109		60		3,935		1,710			1,659		61		3,430
Interest rate derivatives		-			28		-		28		-			-		-		-
Foreign exchange derivatives		-			45		-		45		-			45		-		45
Total assets		2,766			1,182		60		4,008		1,710			1,704		61		3,475
Liabilities
Commodity derivatives		2,989			917		18		3,924		1,797			1,496		24		3,317
Foreign exchange derivatives		-			12		-		12		-			47		-		47
Total liabilities		2,989			929		18		3,936		1,797			1,543		24		3,364
Net assets (liabilities)	$	(223	)		253		42		72		(87	)		161		37		111

The derivative values above are based on analysis of each contract as the fundamental unit of account; therefore, derivative assets and liabilities with the same counterparty are not reflected net where the legal right of offset exists. Gains or losses from contracts in one level may be offset by gains or losses on contracts in another level or by changes in values of physical contracts or positions that are not reflected in the table above.

The fair value of net commodity derivatives classified as Level 3 in the fair value hierarchy changed as follows:

	Millions of Dollars
	Three Months Ended						Nine Months Ended
	September 30						September 30
	2010			2009			2010			2009
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Beginning balance	$	41			74			37			40
Total net gains (losses), realized and unrealized, included in earnings		28			(10	)		60			8
Net purchases, issuances and settlements		(20	)		(20	)		(42	)		(47	)
Transfers into Level 3		-			4			1			65
Transfers out of Level 3		(7	)		(11	)		(14	)		(29	)
Ending balance	$	42			37			42			37

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The amounts of Level 3 gains (losses) included in earnings were:

	Millions of Dollars
	2010									2009
				Purchased									Purchased
	Other			Crude Oil,						Other			Crude Oil,
	Operating			Natural Gas						Operating			Natural Gas
	Revenues			and Products			Total			Revenues			and Products		Total
Three Months Ended September 30
Total gains (losses) included in earnings	$	41			(13	)		28			(10	)		-		(10	)
Change in unrealized gains (losses) relating to assets held at September 30	$	44			1			45			3			-		3
Change in unrealized gains (losses) relating to liabilities held at September 30	$	(10	)		(12	)		(22	)		(16	)		-		(16	)
Nine Months Ended September 30
Total gains (losses) included in earnings	$	95			(35	)		60			8			-		8
Change in unrealized gains (losses) relating to assets held at September 30	$	84			1			85			11			-		11
Change in unrealized gains (losses) relating to liabilities held at September 30	$	(12	)		(21	)		(33	)		(21	)		-		(21	)

Commodity Derivative Contracts—We operate in the worldwide crude oil, refined product, natural gas, natural gas liquids and electric power markets and are exposed to fluctuations in the prices for these commodities. These fluctuations can affect our revenues, as well as the cost of operating, investing and financing activities. Generally, our policy is to remain exposed to the market prices of commodities; however, we use futures, forwards, swaps and options in various markets to balance physical systems, meet customer needs, manage price exposures on specific transactions, and do a limited, immaterial amount of trading not directly related to our physical business. These activities may move our risk profile away from market average prices.

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The fair value of commodity derivative assets and liabilities and the line items where they appear on our consolidated balance sheet were:

	Millions of Dollars
	September 30		December 31
	2010		2009
Assets
Prepaid expenses and other current assets	$	3,695		3,084
Other assets		266		359
Liabilities
Other accruals		3,710		3,006
Other liabilities and deferred credits		240		324

Hedge accounting has not been used for any items in the table. The amounts shown are presented gross (i.e., without netting assets and liabilities with the same counterparty where the right of offset and intent to net exist).

The gains (losses) from commodity derivatives incurred, and the line items where they appear on our consolidated income statement were:

	Millions of Dollars
	Three Months Ended						Nine Months Ended
	September 30						September 30
	2010			2009			2010			2009
Sales and other operating revenues	$	227			727			(430	)		1,118
Other income		3			(4	)		(26	)		21
Purchased crude oil, natural gas and products		(270	)		(599	)		596			(1,554	)

Hedge accounting has not been used for any items in the table.

The table below summarizes our material net exposures resulting from outstanding commodity derivative contracts. These financial and physical derivative contracts are primarily used to manage price exposure on our underlying operations. The underlying exposures may be from non-derivative positions such as inventory volumes or firm natural gas transport contracts. Financial derivative contracts may also offset physical derivative contracts, such as forward sales contracts.

	Open Position
	Long/(Short)
	September 30			December 31
	2010			2009
Commodity
Crude oil, refined products and natural gas liquids (millions of barrels)		(43	)		(16	)
Natural gas and power (billions of cubic feet)
Fixed price		(76	)		(60	)
Basis		(110	)		154

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Interest Rate Derivative Contracts—During the second quarter of 2010, we executed interest rate swaps to synthetically convert $500 million of our 4.60% fixed-rate notes due in 2015 to a London Interbank Offered Rate (LIBOR)-based floating rate. These swaps qualify for and are designated as fair-value hedges using the short-cut method of hedge accounting. The short-cut method permits the assumption that changes in the value of the derivative perfectly offset changes in the value of the debt; therefore, no gain or loss has been recognized due to hedge ineffectiveness.

The fair value of interest rate derivative assets and liabilities and the line items where they appear on our consolidated balance sheet were:

	Millions of Dollars
	September 30		December 31
	2010		2009
Assets
Prepaid expenses and other current assets	$	10		-
Other assets		18		-

Hedge accounting was used for all items in the table. The amounts shown are presented gross.

The (gains) and losses from interest rate derivatives used in a fair-value hedge, losses and (gains) from changes in the fair value of the hedged debt, and the line item where they appear on our consolidated income statement were:

	Millions of Dollars
	Three Months Ended					Nine Months Ended
	September 30					September 30
	2010			2009		2010			2009
Recorded in interest and debt expense
From the interest rate derivatives	$	(14	)		-		(30	)		-
From the hedged debt		12			-		26			-

The extent to which the change in value of the interest rate derivatives differs from the change in value of the hedged debt is an adjustment to recorded interest expense on the fixed-rate debt that effectively results in interest expense for the period being recorded at variable-rate LIBOR.

Foreign Exchange Derivatives—We have foreign currency exchange rate risk resulting from international operations. We do not comprehensively hedge the exposure to movements in currency exchange rates, although we may choose to selectively hedge certain foreign currency exchange rate exposures, such as firm commitments for capital projects or local currency tax payments, dividends, and cash returns from net investments in foreign affiliates to be remitted within the coming year.

The fair value of foreign exchange derivative assets and liabilities, and the line items where they appear on our consolidated balance sheet were:

	Millions of Dollars
	September 30		December 31
	2010		2009
Assets
Prepaid expenses and other current assets	$	44		38
Other assets		1		7
Liabilities
Other accruals		12		40
Other liabilities and deferred credits		-		7

Hedge accounting has not been used for any items in the table. The amounts shown are presented gross.

20

Gains and losses from foreign exchange derivatives, and the line item where they appear on our consolidated income statement were:

	Millions of Dollars
	Three Months Ended				Nine Months Ended
	September 30				September 30
	2010		2009		2010		2009
Foreign exchange transaction (gains) losses	$	18		40		121		(133	)

Hedge accounting has not been used for any items in the table.

We had the following net notional position of outstanding foreign exchange derivatives:

	In Millions
	Notional Currency*
	September 30		December 31
	2010		2009
Foreign Exchange Derivatives
Sell U.S. dollar, buy other currencies**	USD	1,061		3,211
Sell euro, buy British pound	EUR	248		267

  *Denominated in U.S. dollars (USD) and euros (EUR).
**Primarily euro, Canadian dollar, Norwegian krone and British pound.

Credit Risk
Financial instruments potentially exposed to concentrations of credit risk consist primarily of cash equivalents, OTC derivative contracts and trade receivables. Our cash equivalents are placed in high-quality commercial paper, money market funds, government debt securities and time deposits with major international banks and financial institutions.

The credit risk from our OTC derivative contracts, such as forwards and swaps, derives from the counterparty to the transaction. Individual counterparty exposure is managed within predetermined credit limits and includes the use of cash-call margins when appropriate, thereby reducing the risk of significant nonperformance. We also use futures contracts, but futures have a negligible credit risk because they are traded on the New York Mercantile Exchange or the IntercontinentalExchange (ICE) Futures.

Our trade receivables result primarily from our petroleum operations and reflect a broad national and international customer base, which limits our exposure to concentrations of credit risk. The majority of these receivables have payment terms of 30 days or less, and we continually monitor this exposure and the creditworthiness of the counterparties. We do not generally require collateral to limit the exposure to loss; however, we will sometimes use letters of credit, prepayments, and master netting arrangements to mitigate credit risk with counterparties that both buy from and sell to us, as these agreements permit the amounts owed by us or owed to others to be offset against amounts due us.

Certain of our derivative instruments contain provisions that require us to post collateral if the derivative exposure exceeds a threshold amount. We have contracts with fixed threshold amounts and other contracts with variable threshold amounts that are contingent on our credit rating. The variable threshold amounts typically decline for lower credit ratings, while both the variable and fixed threshold amounts typically revert to zero if we fall below investment grade. Cash is the primary collateral in all contracts; however, many also permit us to post letters of credit as collateral.

21

The aggregate fair value of all derivative instruments with such credit-risk-related contingent features that were in a liability position on September 30, 2010, and December 31, 2009, was $226 million and $381 million, respectively, for which no collateral was posted in the normal course of business in 2010 and 2009. If our credit rating were lowered one level from its “A” rating (per Standard and Poor’s) on September 30, 2010, we would be required to post no additional collateral to our counterparties. If we were downgraded below investment grade, we would be required to post $226 million of additional collateral, either with cash or letters of credit.

Fair Values of Financial Instruments
We used the following methods and assumptions to estimate the fair value of financial instruments:

• Cash and cash equivalents: The carrying amount reported on the balance sheet approximates fair value.

• Accounts and notes receivable: The carrying amount reported on the balance sheet approximates fair value.

• Investment in LUKOIL shares: See Note 6—Investments, Loans and Long-Term Receivables, for a discussion of the carrying value and fair value of our investment in LUKOIL shares.

• Debt: The carrying amount of our floating-rate debt approximates fair value. The fair value of the fixed-rate debt is estimated based on quoted market prices.

• Fixed-rate 5.3 percent joint venture acquisition obligation: Fair value is estimated based on the net present value of the future cash flows, discounted at a September 30 effective yield rate of 1.63 percent, based on yields of U.S. Treasury securities of similar average duration adjusted for our average credit risk spread and the amortizing nature of the obligation principal. See Note 10—Joint Venture Acquisition Obligation, for additional information.

• Commodity swaps: Fair value is estimated based on forward market prices and approximates the exit price at period end. When forward market prices are not available, they are estimated using the forward prices of a similar commodity with adjustments for differences in quality or location.

• Futures: Fair values are based on quoted market prices obtained from the New York Mercantile Exchange, the ICE Futures, or other traded exchanges.

• Interest rate swap contracts: Fair value is estimated based on a pricing model and market observable interest rate swap curves obtained from a third-party market data provider.

• Forward-exchange contracts: Fair value is estimated by comparing the contract rate to the forward rate in effect on September 30, 2010, and approximates the exit price at that date.

Our commodity derivative and financial instruments were:

	Millions of Dollars
	Carrying Amount				Fair Value
	September 30		December 31		September 30		December 31
	2010		2009		2010		2009
Financial assets
Foreign exchange derivatives	$	45		45		45		45
Interest rate derivatives		28		-		28		-
Commodity derivatives		707		823		707		823
Investment in LUKOIL*		2,856		-		2,856		-
Financial liabilities
Total debt, excluding capital leases		23,561		28,622		27,382		30,565
Joint venture acquisition obligation		5,178		5,669		5,852		6,276
Foreign exchange derivatives		12		47		12		47
Commodity derivatives		471		632		471		632

*Prior to September 30, 2010, our investment in LUKOIL was accounted for using the equity method. See Note 6—Investment, Loans and Long-Term Receivables, for more information.

22

The amounts shown for derivatives in the preceding table are presented net (i.e., assets and liabilities with the same counterparty are netted where the right of offset and intent to net exist). In addition, the September 30, 2010, commodity derivative assets and liabilities appear net of $5 million of obligations to return cash collateral and $230 million of rights to reclaim cash collateral, respectively. The December 31, 2009, commodity derivative assets and liabilities appear net of $70 million of obligations to return cash collateral and $148 million of rights to reclaim cash collateral, respectively. No collateral was deposited or held for the foreign currency derivatives or interest rate derivatives.

Note 15—Comprehensive Income

ConocoPhillips’ comprehensive income was as follows:

	Millions of Dollars
	Three Months Ended						Nine Months Ended
	September 30						September 30
	2010			2009		*	2010			2009		*
Net income	$	3,069			1,487			9,364			3,178
After-tax changes in:
Defined benefit pension plans
Net prior service cost		2			3			6			9
Net actuarial loss		33			33			103			100
Nonsponsored plans		14			4			35			2
Foreign currency translation adjustments		2,052			1,672			774			4,473
Unrealized gain on securities		423			-			423			-
Hedging activities		-			2			(1	)		3
Comprehensive income		5,593			3,201			10,704			7,765
Less: comprehensive income attributable to noncontrolling interests		(14	)		(17	)		(47	)		(49	)
Comprehensive income attributable to ConocoPhillips	$	5,579			3,184			10,657			7,716

*Recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information.

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

	Millions of Dollars
	September 30			December 31
	2010			2009
Defined benefit plans	$	(1,360	)		(1,504	)
Foreign currency translation adjustments		5,350			4,576
Unrealized gain on securities		423			-
Deferred net hedging loss		(8	)		(7	)
Accumulated other comprehensive income	$	4,405			3,065

None of the items within accumulated other comprehensive income relate to noncontrolling interests.

23

Note 16—Cash Flow Information

	Millions of Dollars
	Nine Months Ended
	September 30
	2010		2009
Cash Payments
Interest	$	996		647
Income taxes		6,022		4,807

Note 17—Employee Benefit Plans

Pension and Postretirement Plans

	Millions of Dollars
	Pension Benefits												Other Benefits
Components of Net Periodic Benefit Cost	2010						2009						2010			2009
	U.S.			Int’l.			U.S.			Int’l.
Three Months Ended September 30
Service cost	$	58			22			48			20			3			2
Interest cost		65			42			69			38			11			12
Expected return on plan assets		(56	)		(37	)		(46	)		(33	)		-			-
Amortization of prior service cost		2			-			3			-			-			2
Recognized net actuarial (gain) loss		42			14			47			9			(1	)		(4	)
Net periodic benefit costs	$	111			41			121			34			13			12
Nine Months Ended September 30
Service cost	$	172			67			145			58			8			6
Interest cost		195			126			208			106			34			35
Expected return on plan assets		(168	)		(110	)		(138	)		(92	)		-			-
Amortization of prior service cost		7			-			8			-			2			6
Recognized net actuarial (gain) loss		125			41			140			26			(5	)		(11	)
Net periodic benefit costs	$	331			124			363			98			39			36

During the first nine months of 2010, we contributed $505 million to our domestic benefit plans and $156 million to our international benefit plans.

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Note 18—Related Party Transactions

Significant transactions with related parties were:

	Millions of Dollars
	Three Months Ended				Nine Months Ended
	September 30				September 30
	2010		2009		2010		2009
Operating revenues and other income (a)	$	2,556		1,871		6,540		5,236
Purchases (b)		3,897		3,614		11,245		9,264
Operating expenses and selling, general and administrative expenses (c)		88		85		253		241
Net interest expense (d)		16		19		53		58

(a)	During the third quarter of 2010, we sold a portion of our LUKOIL shares under a stock purchase and option agreement with a wholly owned subsidiary of LUKOIL resulting in a before-tax gain of $1,149 million. We sold natural gas to DCP Midstream, LLC 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. Beginning in the third quarter of 2010, CFJ was no longer considered a related party due to the sale of our interest. Natural gas, crude oil, blendstock and other intermediate products were sold to WRB Refining LLC. In addition, we charged several of our affiliates, including CPChem and MSLP, for the use of common facilities, such as steam generators, waste and water treaters, and warehouse facilities.
(b)	We purchased refined products from WRB. 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 and refined products from MRC. We also paid fees to various pipeline equity companies for transporting finished refined products and natural gas, as well as 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 transportation fees to pipeline equity companies.
(d)	We paid and/or received interest to/from various affiliates, including FCCL Partnership. See Note 6—Investments, Loans and Long-Term Receivables, for additional information on loans to affiliated companies.

Beginning in the fourth quarter of 2010, transactions with LUKOIL and its subsidiaries will no longer be considered related party transactions. See Note 6—Investments, Loans and Long-Term Receivables, for additional information.

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Note 19—Segment Disclosures and Related Information

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

1) E&P—This segment primarily explores for, produces, transports and markets crude oil, bitumen, natural gas and natural gas liquids on a worldwide basis.

2) Midstream—This segment gathers, processes and markets natural gas produced by ConocoPhillips and others, and fractionates and markets natural gas liquids, predominantly in the United States and Trinidad. The Midstream segment primarily consists of our 50 percent equity investment in DCP Midstream, LLC.

3) R&M—This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia.

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, 2010, our ownership interest was 5.9 percent based on issued shares. Our average ownership interest in the second quarter of 2010, used to record our share of LUKOIL’s second-quarter results on a lag basis, was 19.46 percent. See Note 6—Investments, Loans and Long-Term Receivables, for information on sales of LUKOIL shares.

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 Chevron Phillips Chemical Company LLC.

6) Emerging Businesses—This segment represents our investment in new technologies or businesses outside our normal scope of operations.

Corporate and Other includes general corporate overhead, most interest expense and various other corporate activities. Corporate assets include all cash and cash equivalents.

We evaluate performance and allocate resources based on net income attributable to ConocoPhillips. Intersegment sales are at prices that approximate market.

26

Analysis of Results by Operating Segment

	Millions of Dollars
	Three Months Ended						Nine Months Ended
	September 30						September 30
	2010			2009			2010			2009
Sales and Other Operating Revenues
E&P
United States	$	6,983			5,655			22,003			17,148
International		7,416			5,908			20,842			17,607
Intersegment eliminations—U.S.		(1,385	)		(1,225	)		(4,117	)		(3,271	)
Intersegment eliminations—international		(2,007	)		(1,998	)		(5,896	)		(4,783	)
E&P		11,007			8,340			32,832			26,701
Midstream
Total sales		1,609			1,325			5,326			3,220
Intersegment eliminations		(76	)		(76	)		(263	)		(177	)
Midstream		1,533			1,249			5,063			3,043
R&M
United States		23,168			21,070			69,397			52,485
International		11,631			9,637			30,910			24,469
Intersegment eliminations—U.S.		(175	)		(157	)		(563	)		(414	)
Intersegment eliminations—international		(10	)		(18	)		(84	)		(38	)
R&M		34,614			30,532			99,660			76,502
LUKOIL Investment		-			-			-			-
Chemicals		3			2			8			8
Emerging Businesses
Total sales		196			134			590			421
Intersegment eliminations		(153	)		(90	)		(459	)		(331	)
Emerging Businesses		43			44			131			90
Corporate and Other		8			6			21			18
Consolidated sales and other operating revenues	$	47,208			40,173			137,715			106,362

Net Income (Loss) Attributable to ConocoPhillips
E&P
United States	$	563		327		1,856		836
International		1,001		651		5,654		1,567
Total E&P		1,564		978		7,510		2,403
Midstream		77		62		215		216
R&M
United States		199		73		993		133
International		69		26		(1,008	)	119
Total R&M		268		99		(15	)	252
LUKOIL Investment		1,310		512	*	2,226		763	*
Chemicals		132		104		380		194
Emerging Businesses		(20	)	(2	)	(24	)	-
Corporate and Other		(276	)	(283	)	(975	)	(699	)
Consolidated net income attributable to ConocoPhillips	$	3,055		1,470		9,317		3,129

*LUKOIL Investment recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information.

27

	Millions of Dollars
	September 30		December 31
	2010		2009
Total Assets
E&P
United States	$	35,464		36,122
International		62,175		64,831
Total E&P		97,639		100,953
Midstream		2,123		2,054
R&M
United States		26,654		24,963
International		8,747		8,446
Goodwill		3,637		3,638
Total R&M		39,038		37,047
LUKOIL Investment		3,205		6,416	*
Chemicals		2,706		2,451
Emerging Businesses		1,040		1,069
Corporate and Other		9,582		2,148
Consolidated total assets	$	155,333		152,138

*LUKOIL Investment recast to reflect a change inaccounting principle. See Note 2—Changes in Accounting Principles, for more information.

Note 20—Income Taxes

Our effective tax rate for the third quarter and first nine months of 2010 was 42 percent and 39 percent, respectively, compared with 49 percent and 54 percent for the same two periods of 2009. The change in the effective tax rate for the third quarter and first nine months of 2010, versus the same periods of 2009, was primarily due to the effect of asset dispositions in 2010 and a higher proportion of income in higher tax rate jurisdictions in 2009. The effective tax rate in excess of the domestic federal statutory rate of 35 percent was primarily due to foreign taxes.

28

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 nonguarantor 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.

To facilitate the restructuring of certain legal entities within the Canada operating unit, ConocoPhillips Canada Funding Company I (CFC I) entered into a transaction with another wholly owned subsidiary of ConocoPhillips (included in the “All Other Subsidiaries” column) whereby it acquired an investment in certain preferred shares of a Canadian legal entity within the ConocoPhillips group, in exchange for a non-interest-bearing demand note payable. The value ascribed to the preferred shares and note payable represented the redemption price for both. This noncash transaction was effective December 31, 2009. As a result, the balance sheet of CFC I reflects a short-term investment of $2,973 million and a corresponding amount in short-term debt. In January 2010, the preferred shares acquired under the above transaction were resold to the original holder at the same value as the original purchase price, as satisfaction of the obligation under the demand note payable. As these transactions were completed between wholly owned subsidiaries of ConocoPhillips, there is no impact on the consolidated results in either period.

Certain amounts in 2009 have been recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, in the Notes to Consolidated Financial Statements, for more information.

29

	Millions of Dollars
	Three Months Ended September 30, 2010
							ConocoPhillips		ConocoPhillips			ConocoPhillips
							Australia		Canada			Canada
				ConocoPhillips			Funding		Funding			Funding			All Other			Consolidating			Total
Income Statement	ConocoPhillips			Company			Company		Company I			Company II			Subsidiaries			Adjustments			Consolidated
Revenues and Other Income
Sales and other operating revenues	$	-			28,283			-		-			-			18,925			-			47,208
Equity in earnings of affiliates		3,214			3,728			-		-			-			711			(6,649	)		1,004
Other income (loss)		-			59			-		-			(28	)		1,306			-			1,337
Intercompany revenues		1			439			11		22			8			6,675			(7,156	)		-
Total Revenues and Other Income		3,215			32,509			11		22			(20	)		27,617			(13,805	)		49,549
Costs and Expenses
Purchased crude oil, natural gas and products		-			25,561			-		-			-			15,385			(6,895	)		34,051
Production and operating expenses		-			1,125			-		-			-			1,479			(21	)		2,583
Selling, general and administrative expenses		2			332			-		-			-			160			(1	)		493
Exploration expenses		-			91			-		-			-			161			-			252
Depreciation, depletion and amortization		-			388			-		-			-			1,858			-			2,246
Impairments		-			-			-		-			-			59			-			59
Taxes other than income taxes		-			1,328			-		-			-			2,900			(1	)		4,227
Accretion on discounted liabilities		-			15			-		-			-			95			-			110
Interest and debt expense		243			111			10		19			10			109			(238	)		264
Foreign currency transaction (gains) losses		-			(22	)		-		50			47			(85	)		-			(10	)
Total Costs and Expenses		245			28,929			10		69			57			22,121			(7,156	)		44,275
Income (loss) before income taxes		2,970			3,580			1		(47	)		(77	)		5,496			(6,649	)		5,274
Provision for income taxes		(85	)		366			-		(2	)		(15	)		1,941			-			2,205
Net income (loss)		3,055			3,214			1		(45	)		(62	)		3,555			(6,649	)		3,069
Less: net income attributable to noncontrolling interests		-			-			-		-			-			(14	)		-			(14	)
Net Income (Loss) Attributable to ConocoPhillips	$	3,055			3,214			1		(45	)		(62	)		3,541			(6,649	)		3,055
Income Statement	Three Months Ended September 30, 2009
Revenues and Other Income
Sales and other operating revenues	$	-			24,981			-		-			-			15,192			-			40,173
Equity in earnings of affiliates		1,576			1,695			-		-			-			666			(2,956	)		981
Other income (loss)		1			150			-		-			-			(34	)		-			117
Intercompany revenues		13			264			11		20			12			5,377			(5,697	)		-
Total Revenues and Other Income		1,590			27,090			11		20			12			21,201			(8,653	)		41,271
Costs and Expenses
Purchased crude oil, natural gas and products		-			22,158			-		-			-			11,395			(5,545	)		28,008
Production and operating expenses		-			1,057			-		-			-			1,499			(22	)		2,534
Selling, general and administrative expenses		4			275			-		-			-			143			5			427
Exploration expenses		-			90			-		-			-			296			-			386
Depreciation, depletion and amortization		-			432			-		-			-			1,895			-			2,327
Impairments		-			55			-		-			-			1			-			56
Taxes other than income taxes		-			1,304			-		-			-			2,901			-			4,205
Accretion on discounted liabilities		-			6			-		-			-			90			-			96
Interest and debt expense		173			15			10		19			13			241			(135	)		336
Foreign currency transaction (gains) losses		-			13			-		77			69			(176	)		-			(17	)
Total Costs and Expenses		177			25,405			10		96			82			18,285			(5,697	)		38,358
Income (loss) before income taxes		1,413			1,685			1		(76	)		(70	)		2,916			(2,956	)		2,913
Provision for income taxes		(57	)		109			-		4			(3	)		1,373			-			1,426
Net income (loss)		1,470			1,576			1		(80	)		(67	)		1,543			(2,956	)		1,487
Less: net income attributable to noncontrolling interests		-			-			-		-			-			(17	)		-			(17	)
Net Income (Loss) Attributable to ConocoPhillips	$	1,470			1,576			1		(80	)		(67	)		1,526			(2,956	)		1,470

30

	Millions of Dollars
	Nine Months Ended September 30, 2010
							ConocoPhillips		ConocoPhillips			ConocoPhillips
							Australia		Canada			Canada
				ConocoPhillips			Funding		Funding			Funding			All Other			Consolidating			Total
Income Statement	ConocoPhillips			Company			Company		Company I			Company II			Subsidiaries			Adjustments			Consolidated
Revenues and Other Income
Sales and other operating revenues	$	-			85,619			-		-			-			52,096			-			137,715
Equity in earnings of affiliates		9,751			10,916			-		-			-			2,384			(20,091	)		2,960
Gain on sale of Syncrude		-			(12	)		-		-			-			2,890			-			2,878
Other income (loss)		-			188			-		-			(28	)		1,725			-			1,885
Intercompany revenues		4			713			34		65			58			19,556			(20,430	)		-
Total Revenues and Other Income		9,755			97,424			34		65			30			78,651			(40,521	)		145,438
Costs and Expenses
Purchased crude oil, natural gas and products		-			76,927			-		-			-			40,397			(19,664	)		97,660
Production and operating expenses		-			3,314			-		-			-			4,487			(72	)		7,729
Selling, general and administrative expenses		9			948			-		-			-			445			(27	)		1,375
Exploration expenses		-			188			-		-			-			660			-			848
Depreciation, depletion and amortization		-			1,204			-		-			-			5,640			-			6,844
Impairments		-			17			-		-			-			1,665			-			1,682
Taxes other than income taxes		-			3,901			-		-			-			8,611			(1	)		12,511
Accretion on discounted liabilities		-			46			-		-			-			291			-			337
Interest and debt expense		662			359			31		58			37			433			(666	)		914
Foreign currency transaction (gains) losses		-			13			-		(5	)		(6	)		78			-			80
Total Costs and Expenses		671			86,917			31		53			31			62,707			(20,430	)		129,980
Income (loss) before income taxes		9,084			10,507			3		12			(1	)		15,944			(20,091	)		15,458
Provision for income taxes		(233	)		756			1		11			5			5,554			-			6,094
Net income (loss)		9,317			9,751			2		1			(6	)		10,390			(20,091	)		9,364
Less: net income attributable to noncontrolling interests		-			-			-		-			-			(47	)		-			(47	)
Net Income (Loss) Attributable to ConocoPhillips	$	9,317			9,751			2		1			(6	)		10,343			(20,091	)		9,317
Income Statement	Nine Months Ended September 30, 2009
Revenues and Other Income
Sales and other operating revenues	$	-			64,437			-		-			-			41,925			-			106,362
Equity in earnings of affiliates		3,413			3,726			-		-			-			1,194			(6,347	)		1,986
Other income (loss)		-			469			-		-			-			(122	)		-			347
Intercompany revenues		29			866			40		57			35			12,850			(13,877	)		-
Total Revenues and Other Income		3,442			69,498			40		57			35			55,847			(20,224	)		108,695
Costs and Expenses
Purchased crude oil, natural gas and products		-			56,296			-		-			-			29,331			(13,251	)		72,376
Production and operating expenses		2			3,271			-		-			-			4,452			(73	)		7,652
Selling, general and administrative expenses		12			907			-		-			-			467			(8	)		1,378
Exploration expenses		-			206			-		-			-			648			-			854
Depreciation, depletion and amortization		-			1,272			-		-			-			5,632			-			6,904
Impairments		-			50			-		-			-			60			-			110
Taxes other than income taxes		-			3,671			-		-			-			7,732			(19	)		11,384
Accretion on discounted liabilities		-			43			-		-			-			265			-			308
Interest and debt expense		452			100			36		58			40			754			(526	)		914
Foreign currency transaction (gains) losses		-			(30	)		-		132			178			(308	)		-			(28	)
Total Costs and Expenses		466			65,786			36		190			218			49,033			(13,877	)		101,852
Income (loss) before income taxes		2,976			3,712			4		(133	)		(183	)		6,814			(6,347	)		6,843
Provision for income taxes		(153	)		299			1		6			(20	)		3,532			-			3,665
Net income (loss)		3,129			3,413			3		(139	)		(163	)		3,282			(6,347	)		3,178
Less: net income attributable to noncontrolling interests		-			-			-		-			-			(49	)		-			(49	)
Net Income (Loss) Attributable to ConocoPhillips	$	3,129			3,413			3		(139	)		(163	)		3,233			(6,347	)		3,129

31

	Millions of Dollars
	September 30, 2010
						ConocoPhillips		ConocoPhillips			ConocoPhillips
						Australia		Canada			Canada
				ConocoPhillips		Funding		Funding			Funding			All Other		Consolidating			Total
Balance Sheet	ConocoPhillips			Company		Company		Company I			Company II			Subsidiaries		Adjustments			Consolidated
Assets
Cash and cash equivalents	$	-			174		-		23			4			7,992		(197	)		7,996
Accounts and notes receivable		33			7,692		-		1			-			14,044		(8,292	)		13,478
Investment in LUKOIL		-			-		-		-			-			2,856		-			2,856
Inventories		-			4,490		-		-			-			3,251		-			7,741
Prepaid expenses and other current assets		21			1,065		-		1			-			2,159		-			3,246
Total Current Assets		54			13,421		-		25			4			30,302		(8,489	)		35,317
Investments, loans and long-term receivables*		81,851			106,321		772		1,433			572			48,452		(206,044	)		33,357
Net properties, plants and equipment		-			19,284		-		-			-			62,176		-			81,460
Goodwill		-			3,637		-		-			-			-		-			3,637
Intangibles		-			762		-		-			-			44		-			806
Other assets		65			273		1		3			3			411		-			756
Total Assets	$	81,970			143,698		773		1,461			579			141,385		(214,533	)		155,333
Liabilities and Stockholders’ Equity
Accounts payable	$	-			12,486		1		3			1			11,865		(8,292	)		16,064
Short-term debt		(5	)		354		-		-			-			27		-			376
Accrued income and other taxes		-			527		-		-			8			4,651		-			5,186
Employee benefit obligations		-			522		-		-			-			246		-			768
Other accruals		153			1,359		19		33			14			1,449		-			3,027
Total Current Liabilities		148			15,248		20		36			23			18,238		(8,292	)		25,421
Long-term debt		11,841			3,690		749		1,250			499			5,196		-			23,225
Asset retirement obligations and accrued environmental costs		-			1,406		-		-			-			7,112		-			8,518
Joint venture acquisition obligation		-			-		-		-			-			4,492		-			4,492
Deferred income taxes		-			3,152		-		20			7			14,107		-			17,286
Employee benefit obligations		-			2,771		-		-			-			961		-			3,732
Other liabilities and deferred credits*		7,436			31,263		-		62			5			18,982		(55,006	)		2,742
Total Liabilities		19,425			57,530		769		1,368			534			69,088		(63,298	)		85,416
Retained earnings		32,655			19,358		2		(48	)		(36	)		18,009		(30,784	)		39,156
Other common stockholders’ equity		29,890			66,810		2		141			81			53,732		(120,451	)		30,205
Noncontrolling interests		-			-		-		-			-			556		-			556
Total Liabilities and Stockholders’ Equity	$	81,970			143,698		773		1,461			579			141,385		(214,533	)		155,333
Balance Sheet	December 31, 2009
Assets
Cash and cash equivalents	$	-			122		-		18			1			554		(153	)		542
Accounts and notes receivable		26			6,495		-		-			-			13,712		(7,018	)		13,215
Inventories		-			2,911		-		-			-			2,029		-			4,940
Short-term investments		-			-		-		2,973			-			-		(2,973	)		-
Prepaid expenses and other current assets		13			835		-		4			3			1,621		(6	)		2,470
Total Current Assets		39			10,363		-		2,995			4			17,916		(10,150	)		21,167
Investments, loans and long-term receivables*		70,769			91,643		759		1,376			933			47,886		(175,272	)		38,094
Net properties, plants and equipment		-			19,838		-		-			-			67,870		-			87,708
Goodwill		-			3,638		-		-			-			-		-			3,638
Intangibles		-			770		-		-			-			53		-			823
Other assets		55			240		1		3			4			509		(104	)		708
Total Assets	$	70,863			126,492		760		4,374			941			134,234		(185,526	)		152,138
Liabilities and Stockholders’ Equity
Accounts payable	$	7			11,590		-		1			1			10,904		(7,018	)		15,485
Short-term debt		235			1,286		-		2,973			-			207		(2,973	)		1,728
Accrued income and other taxes		-			298		-		(1	)		-			3,105		-			3,402
Employee benefit obligations		-			588		-		-			-			258		-			846
Other accruals		262			643		9		15			10			1,301		(6	)		2,234
Total Current Liabilities		504			14,405		9		2,988			11			15,775		(9,997	)		23,695
Long-term debt		12,561			4,053		749		1,250			849			7,463		-			26,925
Asset retirement obligations and accrued environmental costs		-			1,406		-		-			-			7,307		-			8,713
Joint venture acquisition obligation		-			-		-		-			-			5,009		-			5,009
Deferred income taxes		(4	)		2,785		-		10			10			15,155		-			17,956
Employee benefit obligations		-			2,960		-		-			-			1,170		-			4,130
Other liabilities and deferred credits*		2,560			25,819		-		68			37			17,296		(42,683	)		3,097
Total Liabilities		15,621			51,428		758		4,316			907			69,175		(52,680	)		89,525
Retained earnings		25,714			9,607		-		(49	)		(30	)		10,240		(13,268	)		32,214
Other common stockholders’ equity		29,528			65,457		2		107			64			54,229		(119,578	)		29,809
Noncontrolling interests		-			-		-		-			-			590		-			590
Total Liabilities and Stockholders’ Equity	$	70,863			126,492		760		4,374			941			134,234		(185,526	)		152,138

*Includes intercompany loans.

32

	Millions of Dollars
	Nine Months Ended September 30, 2010
							ConocoPhillips			ConocoPhillips		ConocoPhillips
							Australia			Canada		Canada
				ConocoPhillips			Funding			Funding		Funding			All Other			Consolidating			Total
Statement of Cash Flows	ConocoPhillips			Company			Company			Company I		Company II			Subsidiaries			Adjustments			Consolidated
Cash Flows From Operating Activities
Net Cash Provided by (Used in) Operating Activities	$	4,567			2,616			-			5		(3	)		6,288			(2,619	)		10,854
Cash Flows From Investing Activities
Capital expenditures and investments		-			(1,207	)		-			-		-			(5,487	)		323			(6,371	)
Proceeds from asset dispositions		-			179			-			-		-			12,154			(100	)		12,233
Long-term advances/loans—related parties		-			(335	)		-			-		-			(1,408	)		1,447			(296	)
Collection of advances/loans—related parties		-			79			-			-		384			1,379			(1,738	)		104
Other		-			14			-			-		-			100			-			114
Net Cash Provided by (Used in) Investing Activities		-			(1,270	)		-			-		384			6,738			(68	)		5,784
Cash Flows From Financing Activities
Issuance of debt		-			1,309			-			-		-			234			(1,447	)		96
Repayment of debt		(990	)		(2,645	)		-			-		(378	)		(3,029	)		1,738			(5,304	)
Issuance of company common stock		59			-			-			-		-			-			-			59
Repurchase of company common stock		(1,258	)		-			-			-		-			-			-			(1,258	)
Dividends paid on common stock		(2,376	)		-			-			-		-			(2,575	)		2,575			(2,376	)
Other		(2	)		27			-			-		-			(346	)		(223	)		(544	)
Net Cash Used in Financing Activities		(4,567	)		(1,309	)		-			-		(378	)		(5,716	)		2,643			(9,327	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents		-			15			-			-		-			128			-			143
Net Change in Cash and Cash Equivalents		-			52			-			5		3			7,438			(44	)		7,454
Cash and cash equivalents at beginning of period		-			122			-			18		1			554			(153	)		542
Cash and Cash Equivalents at End of Period	$	-			174			-			23		4			7,992			(197	)		7,996
Statement of Cash Flows	Nine Months Ended September 30, 2009
Cash Flows From Operating Activities
Net Cash Provided by (Used in) Operating Activities	$	(4,739	)		5,941			-			3		-			8,126			(1,946	)		7,385
Cash Flows From Investing Activities
Capital expenditures and investments		-			(2,572	)		-			-		-			(6,150	)		546			(8,176	)
Proceeds from asset dispositions		-			593			-			-		-			664			(319	)		938
Long-term advances/loans—related parties		-			(164	)		-			-		-			(464	)		325			(303	)
Collection of advances/loans—related parties		-			148			950			-		-			3,796			(4,832	)		62
Other		-			19			-			-		-			31			-			50
Net Cash Provided by (Used in) Investing Activities		-			(1,976	)		950			-		-			(2,123	)		(4,280	)		(7,429	)
Cash Flows From Financing Activities
Issuance of debt		8,909			299			-			-		-			168			(325	)		9,051
Repayment of debt		(2,011	)		(4,093	)		(950	)		-		-			(3,805	)		4,832			(6,027	)
Issuance of company common stock		(11	)		-			-			-		-			-			-			(11	)
Dividends paid on common stock		(2,090	)		-			-			-		-			(1,896	)		1,896			(2,090	)
Other		(58	)		6			-			-		-			(812	)		(227	)		(1,091	)
Net Cash Provided by (Used in) Financing Activities		4,739			(3,788	)		(950	)		-		-			(6,345	)		6,176			(168	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents		-			-			-			-		-			98			-			98
Net Change in Cash and Cash Equivalents		-			177			-			3		-			(244	)		(50	)		(114	)
Cash and cash equivalents at beginning of period		-			8			-			10		1			750			(14	)		755
Cash and Cash Equivalents at End of Period	$	-			185			-			13		1			506			(64	)		641

33

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 “forecast,” “intend,” “believe,” “expect,” “plan,” “schedule,” “target,” “should,” “goal,” “may,” “anticipate,” “estimate,” 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 52.

The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to net income (loss) attributable to ConocoPhillips.

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. At September 30, 2010, we had approximately 29,800 employees worldwide and total assets of $155 billion.

Earnings of the company depend largely on the profitability of our Exploration and Production (E&P) and Refining and Marketing (R&M) segments. Crude oil and natural gas prices, along with refining margins, are the most significant factors in our profitability. Earnings in the third quarter of 2010 continued to be positively impacted by strong crude oil prices compared with 2009. The price of West Texas Intermediate (WTI) benchmark crude oil steadily trended upward during 2009 and into the first quarter of 2010 before leveling out in the second and third quarters of 2010. WTI averaged $76.03 per barrel in the third quarter of 2010, compared with $77.78 in the second quarter of 2010 and $68.19 in the third quarter of 2009. Crude prices fell slightly during the third quarter of 2010 due to continued concerns about the strength of the global economic recovery.

Henry Hub natural gas prices averaged $4.38 per million British thermal units in the third quarter of 2010, compared with $4.09 in the second quarter of 2010, and $3.39 in the third quarter of 2009. Natural gas prices increased in the third quarter of 2010 due to warmer than normal temperatures. With the increased demand, storage levels are lower than last year, largely avoiding the production shut-ins seen in 2009. Prices are tempered by continued strong natural gas production, mostly from shale plays in the Lower 48.

E&P earnings were $1,564 million in the third quarter of 2010. This compares with earnings of $4,114 million in the second quarter of 2010 and $978 million in the third quarter of 2009. The decrease in third quarter 2010 earnings, compared with second quarter 2010 earnings, was primarily due to the $2,679 million after-tax gain on sale of our Syncrude oil sands mining operation in the second quarter.

Global refining margins trended downward during the third quarter amid ample supply and despite higher demand. The U.S. benchmark 3:2:1 crack spread decreased by approximately 13 percent in the third quarter of 2010, compared with the second quarter of 2010, while the N.W. Europe benchmark decreased by approximately 15 percent over the same period. Domestic and European refined product demand increased in the third quarter of 2010, but this effect was more than offset by strong refinery runs and resulting high product inventory levels in the Atlantic Basin.

R&M earnings were $268 million in the third quarter of 2010, compared with a loss of $279 million in the second quarter of 2010 and earnings of $99 million in the third quarter of 2009. The loss in the second quarter of 2010 included a $1,103 million after-tax property impairment of our refinery in Wilhelmshaven, Germany.

34

Excluding the impact from the Wilhelmshaven property impairment, R&M earnings in the third quarter of 2010 decreased as a result of lower refining and marketing margins compared with the second quarter of 2010.

RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three- and nine-month periods ended September 30, 2010, is based on a comparison with the corresponding periods of 2009.

Consolidated Results

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

	Millions of Dollars
	Three Months Ended						Nine Months Ended
	September 30						September 30
	2010			2009			2010			2009
Exploration and Production (E&P)	$	1,564			978			7,510			2,403
Midstream		77			62			215			216
Refining and Marketing (R&M)		268			99			(15	)		252
LUKOIL Investment		1,310			512	*		2,226			763	*
Chemicals		132			104			380			194
Emerging Businesses		(20	)		(2	)		(24	)		-
Corporate and Other		(276	)		(283	)		(975	)		(699	)
Net income attributable to ConocoPhillips	$	3,055			1,470			9,317			3,129

*LUKOIL Investment recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information.

Earnings were $3,055 million in the third quarter of 2010, compared with $1,470 million in the third quarter of 2009. For the nine-month periods ended September 30, 2010 and 2009, earnings were $9,317 million and $3,129 million, respectively. The improvement in both periods of 2010 was primarily the result of:

• Higher prices for crude oil, natural gas and natural gas liquids in our E&P segment. Commodity price benefits were somewhat offset by increased production taxes.

• Divestiture of our LUKOIL shares.

• Improved results from our domestic R&M operations, reflecting higher refining margins.

Lower production volumes from our E&P segment partially offset these increases. In addition, results for the nine-month period of 2010 benefitted from the $2,679 million after-tax gain on sale of our 9.03 percent interest in the Syncrude oil sands mining operation. The increases in the nine-month period were partially offset by the $1,103 million after-tax property impairment on our refinery in Wilhelmshaven, Germany.

See the “Segment Results” section for additional information.

Income Statement Analysis

Sales and other operating revenues increased 18 percent in the third quarter of 2010 and 29 percent in the nine-month period, whilepurchased crude oil, natural gas and products increased 22 percent and 35 percent, respectively. These increases were primarily due to higher prices for petroleum products, crude oil, natural gas, natural gas liquids and liquefied natural gas (LNG).

35

Equity in earnings of affiliates increased 49 percent in first nine months of 2010. The increase primarily resulted from:

• Improved earnings from our LUKOIL Investment segment, which primarily resulted from significantly higher refined product and crude oil prices. These increases were partially offset by higher extraction taxes and export tariffs. In addition, equity earnings were not recorded in the first quarter of 2009 under lag accounting, since our LUKOIL investment was written down to fair value at December 31, 2008.

• Improved earnings from Chevron Phillips Chemical Company primarily due to higher margins in the olefins and polyolefins business line.

• Improved earnings from FCCL Partnership due to higher commodity prices and volumes.

• Improved earnings from Merey Sweeny, L.P. as a result of improved margins and volumes.

These increases were partially offset by lower results from WRB Refining LLC primarily due to lower refining margins; lower volumes due to turnarounds and market-driven run reductions; and higher turnaround costs.

Gain on sale of Syncrude was $2,878 million in the nine-month period of 2010, and resulted from the June 2010 sale of our 9.03 percent interest in the Syncrude oil sands mining operation.

Other income increased $1,220 million in the third quarter of 2010 and $1,538 million in the nine-month period of 2010. The increases in both periods primarily reflect the gain on the divestiture of our LUKOIL shares. The increase in the nine-month period also includes the gain on sale of our 50 percent interest in CFJ Properties.

Exploration expenses decreased 35 percent during the third quarter of 2010, primarily as a result of lower dry hole costs.

Taxes other than income taxes increased 10 percent during the nine-month period of 2010, primarily due to higher production taxes as a result of higher crude oil prices and higher excise taxes on petroleum product sales.

Interest expense decreased 21 percent during the third quarter of 2010, primarily due to lower interest expense as a result of lower debt levels.

Impairments increased $1,572 million in the nine-month period of 2010, primarily as a result of the second quarter 2010 impairment of our refinery in Wilhelmshaven, Germany.

See Note 20—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding ourincome tax expense and effective tax rate.

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Segment Results

E&P

	Three Months Ended					Nine Months Ended
	September 30					September 30
	2010		2009			2010		2009
	Millions of Dollars
Net Income (Loss) Attributable to ConocoPhillips
Alaska	$	361		356			1,259		1,004
Lower 48		202		(29	)		597		(168	)
United States		563		327			1,856		836
International		1,001		651			5,654		1,567
	$	1,564		978			7,510		2,403
	Dollars Per Unit
Average Sales Prices
Crude oil and natural gas liquids (per barrel)
United States	$	65.71		59.13			68.19		48.54
International		71.75		64.12			72.72		53.30
Total consolidated operations		69.22		61.93			70.74		51.12
Equity affiliates		72.95		64.31			72.25		54.07
Total E&P		69.45		62.08			70.83		51.29
Synthetic oil (per barrel)
International		-		66.42			77.56		57.16
Bitumen (per barrel)
International		47.96		48.35			50.65		37.02
Equity affiliates		52.38		49.81			52.82		41.63
Total E&P		51.50		49.59			52.48		40.94
Natural gas (per thousand cubic feet)
United States		4.07		2.99			4.40		3.27
International		4.96		4.26			5.22		4.81
Total consolidated operations		4.58		3.69			4.88		4.14
Equity affliliates		2.82		2.57			2.84		2.26
Total E&P		4.53		3.67			4.83		4.10
	Millions of Dollars
Worldwide Exploration Expenses
General administrative; geological and geophysical; and lease rentals	$	130		153			521		383
Leasehold impairment		96		71			180		163
Dry holes		26		162			147		308
	$	252		386			848		854

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	Three Months Ended				Nine Months Ended
	September 30				September 30
	2010		2009		2010		2009
	Thousands of Barrels Daily
Operating Statistics
Crude oil and natural gas liquids produced
Alaska		215		229		228		252
Lower 48		160		168		159		167
United States		375		397		387		419
Canada		40		39		41		41
Europe		207		221		213		240
Asia Pacific/Middle East		144		128		142		131
Africa		80		78		79		77
Other areas		-		-		-		5
Total consolidated operations		846		863		862		913
Equity affiliates
Russia		51		59		54		54
		897		922		916		967
Synthetic oil produced
Consolidated operations—Canada		-		25		15		21
Bitumen produced
Consolidated operations—Canada		10		8		9		7
Equity affiliates—Canada		49		45		50		40
		59		53		59		47
	Millions of Cubic Feet Daily
Natural gas produced*
Alaska		82		105		86		93
Lower 48		1,738		1,938		1,728		1,992
United States		1,820		2,043		1,814		2,085
Canada		974		1,063		1,012		1,101
Europe		731		702		812		850
Asia Pacific/Middle East		748		726		713		719
Africa		158		124		147		119
Total consolidated operations		4,431		4,658		4,498		4,874
Equity affiliates
Asia Pacific/Middle East		134		88		112		86
		4,565		4,746		4,610		4,960

*Represents quantities available for sale. Excludes gas equivalent of natural gas liquids included above.
Equity affiliate statistics exclude our share of LUKOIL, which is reported in the LUKOIL Investment segment.

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The E&P segment explores for, produces, transports and markets crude oil, bitumen, natural gas and natural gas liquids on a worldwide basis. At September 30, 2010, our E&P operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, offshore Timor-Leste in the Timor Sea, Indonesia, China, Vietnam, Libya, Nigeria, Algeria, and Russia. Total E&P production on a barrel-of-oil-equivalent (BOE) basis averaged 1,717,000 BOE per day in the third quarter of 2010, compared with 1,791,000 BOE per day in the third quarter of 2009.

Earnings from our E&P segment were $1,564 million in the third quarter of 2010, compared with earnings of $978 million in the third quarter of 2009. E&P earnings for the first nine months of 2010 and 2009 were $7,510 million and $2,403 million, respectively. Both periods in 2010 benefitted from higher prices for crude oil, natural gas, natural gas liquids and LNG. These increases were partially offset by lower crude oil, natural gas and synthetic oil volumes. The third quarter of 2010 benefitted from lower dry hole costs and higher gains from asset rationalization efforts. The improvement in the nine-month period of 2010 included the $2,679 million after-tax gain on sale of Syncrude and positive foreign currency impacts, which were partially offset by higher petroleum and export taxes as a result of higher prices. See the “Business Environment and Executive Overview” section for additional information on industry crude oil and natural gas prices.

U.S. E&P

Our U.S. E&P operations reported earnings of $563 million in the third quarter of 2010, compared with earnings of $327 million for the same period in 2009. Domestic E&P earnings for the first nine months of 2010 and 2009 were $1,856 million and $836 million, respectively. The increases for both periods in 2010 were primarily the result of higher prices for crude oil, natural gas and natural gas liquids, which were partially offset by lower crude oil and natural gas volumes. In addition, the nine-month period of 2010 benefitted from lower depreciation, depletion and amortization as a result of lower crude oil and natural gas volumes. These increases in the nine-month period were partially offset by higher production taxes, primarily in Alaska, and an unfavorable tax ruling.

U.S. E&P production averaged 678,000 BOE per day in the third quarter of 2010, a decrease of 8 percent from 737,000 BOE in the third quarter of 2009. The decrease was primarily due to field decline and unplanned downtime, which was partially offset by new production.

International E&P

International E&P earnings were $1,001 million in the third quarter of 2010, or $350 million higher than the same period in 2009. International E&P earnings for the first nine months of 2010 and 2009 were $5,654 million and $1,567 million, respectively. Results for both periods in 2010 were influenced by higher crude oil, natural gas and LNG prices, which were partially offset by lower synthetic oil volumes. The increase in the nine-month period included the gain on sale of our Syncrude oil sands mining operation, in addition to positive foreign currency impacts. These increases were partially offset by higher petroleum and export taxes as a result of higher prices, and the $93 million after-tax write-off of project costs resulting from our decision to end participation in the Shah Gas Field Project in Abu Dhabi.

International E&P production averaged 1,039,000 BOE per day in the third quarter of 2010, a decrease of 1 percent from 1,054,000 BOE in the third quarter of 2009. The decrease was largely due to field decline, the sale of Syncrude and the impact of higher prices on production sharing arrangements. These decreases were mostly offset by production from major projects, primarily in China, Canada, Australia and Indonesia.

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Midstream

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2010		2009		2010		2009
	Millions of Dollars
Net Income Attributable to ConocoPhillips*	$	77		62		215		216
*Includes DCP Midstream-related earnings:	$	39		26		123		128
	Dollars Per Barrel
Average Sales Prices
U.S. natural gas liquids*
Consolidated	$	40.55		34.66		44.23		30.23
Equity affiliates		36.66		28.89		40.14		26.26
*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		198		194		192		185
Natural gas liquids fractionated**		134		164		150		166

  *Includes our share of equity affiliates, except LUKOIL, which is reported in the LUKOIL Investment segment.

**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 50 percent equity investment in DCP Midstream, LLC, as well as our other natural gas gathering and processing operations, and natural gas liquids fractionation, trading and marketing businesses, primarily in the United States and Trinidad.

Midstream earnings were $77 million in the third quarter of 2010, or $15 million higher than the same period in 2009. Midstream earnings for the first nine months of 2010 were $215 million, or $1 million lower than the same period in 2009. Both periods of 2010 were positively impacted by higher natural gas liquids prices. The nine-month period of 2010 also benefitted from improved volumes from our equity affiliate, Phoenix Park Gas Processors Limited. These increases in the nine-month period were partially offset by higher operating expenses resulting from higher turnaround activity. In addition, results for the nine-month period of 2009 included the recognition of an $88 million after-tax benefit, which resulted from a DCP Midstream subsidiary converting subordinated units to common units.

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R&M

	Three Months Ended					Nine Months Ended
	September 30					September 30
	2010			2009		2010			2009
	Millions of Dollars
Net Income (Loss) Attributable to ConocoPhillips
United States	$	199			73		993			133
International		69			26		(1,008	)		119
	$	268			99		(15	)		252
	Dollars Per Gallon
U.S. Average Wholesale Prices*
Gasoline	$	2.21			2.04		2.21			1.77
Distillates		2.24			1.90		2.23			1.66
*Excludes excise taxes.
	Thousands of Barrels Daily
Operating Statistics
Refining operations*
United States
Crude oil capacity		1,986			1,986		1,986			1,986
Crude oil runs		1,833			1,841		1,830			1,762
Capacity utilization (percent)		92	%		93		92			89
Refinery production		1,992			2,017		1,998			1,918
International
Crude oil capacity		671			671		671			671
Crude oil runs		399			541		362			531
Capacity utilization (percent)		60	%		81		54			79
Refinery production		407			548		370			541
Worldwide
Crude oil capacity		2,657			2,657		2,657			2,657
Crude oil runs		2,232			2,382		2,192			2,293
Capacity utilization (percent)		84	%		90		82			86
Refinery production		2,399			2,565		2,368			2,459
Petroleum products sales volumes
United States
Gasoline		1,103			1,188		1,122			1,136
Distillates		874			906		868			860
Other products		432			420		395			375
		2,409			2,514		2,385			2,371
International		697			626		602			622
		3,106			3,140		2,987			2,993
*Includes our share of equity affiliates, except LUKOIL, which is reported in the LUKOIL Investment segment.

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Our R&M segment refines crude oil and other feedstocks into petroleum products (such as gasoline, distillates and aviation fuels); buys, sells and transports crude oil; and buys, transports, distributes and markets petroleum products. R&M has operations mainly in the United States, Europe and the Asia Pacific Region.

R&M reported earnings of $268 million in the third quarter of 2010, compared with earnings of $99 million in the corresponding period of 2009. The increase in 2010 was primarily the result of improved domestic refining margins, and to a lesser extent, positive tax and foreign currency exchange impacts. These increases were partially offset by lower marketing margins.

For the first nine months of 2010, R&M reported a loss of $15 million, compared with earnings of $252 million for the same period in 2009. The loss in the nine-month period of 2010 was primarily due to the $1,103 million after-tax property impairment of our refinery in Wilhelmshaven, Germany, which occurred in the second quarter of 2010. Excluding the impact from the Wilhelmshaven property impairment, R&M experienced an improvement in earnings for the nine-month period of 2010 due to improved global refining margins. Additionally, results included a $113 million after-tax gain on the sale of CFJ, lower domestic operating expenses and the absence of a $72 million after-tax Keystone Pipeline impairment recorded in the second quarter of 2009. These increases were slightly offset by negative foreign currency exchange impacts. See the “Business Environment and Executive Overview” section for additional information on industry refining margins.

U.S. R&M
Earnings from U.S. R&M were $199 million in the third quarter of 2010 and $993 million in the nine-month period of 2010, compared with earnings of $73 million and $133 million for the respective periods in 2009. The increases in both periods of 2010 primarily resulted from improved refining margins and positive tax impacts. The improvement in the third quarter of 2010 was partially offset by lower marketing margins, lower volumes, largely due to the sale of CFJ, and higher operating expenses. The nine-month period of 2010 benefitted from the gain on sale of CFJ, the absence of the 2009 Keystone Pipeline impairment, higher refining and marketing volumes and lower operating costs.

Our U.S. refining crude oil capacity utilization rate was 92 percent in the third quarter of 2010, compared with 93 percent in the third quarter of 2009.

International R&M
International R&M reported earnings of $69 million in the third quarter of 2010 and a loss of $1,008 million for the nine-month period of 2010, compared with earnings of $26 million and $119 million for the respective periods in 2009. The increase in the third quarter of 2010 was influenced by positive tax and foreign currency exchange impacts, which were partially offset by lower refining margins. Results for the nine-month period of 2010 included the Wilhelmshaven impairment and a $29 million after-tax impairment resulting from our decision to end participation in the Yanbu Refinery Project. Excluding these impairments, earnings were improved by higher refining and marketing margins, partially offset by lower foreign currency impacts.

Our international refining crude oil capacity utilization rate was 60 percent in the third quarter of 2010, compared with 81 percent in the third quarter of 2009. The current year rate primarily reflects run reductions at Wilhelmshaven in response to market conditions, partially offset by lower turnaround activity.

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LUKOIL Investment

	Million of Dollars
	Three Months Ended					Nine Months Ended
	September 30					September 30
	2010		2009		*	2010		2009		*
Net Income Attributable to ConocoPhillips	$	1,310		512			2,226		763
Operating Statistics
Crude oil production (thousands of barrels daily)		366		386			380		388
Natural gas produced (millions of cubic feet daily)		338		273			339		301
Refinery crude oil processed (thousands of barrels daily)		263		250			252		235
*Recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles, for more information.

This segment represents our investment in OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. Our average ownership interest in the second quarter of 2010, used to record our share of LUKOIL’s second-quarter results on a lag basis, was 19.46 percent.

Effective January 1, 2010, we changed the method used to determine our equity-method share of LUKOIL’s earnings. Prior to 2010, we estimated our LUKOIL equity earnings for the current quarter based on current market indicators, publicly available LUKOIL information and other objective data. We currently record our equity-method share of LUKOIL’s actual earnings on a one-quarter-lag basis, rather than using an earnings estimate for the current quarter. This change in accounting principle has been applied retrospectively, by recasting prior period financial information. The performance metrics are also reported on a one-quarter-lag basis. See Note 2—Changes in Accounting Principles, in the Notes to Consolidated Financial Statements, for more information.

In addition to our equity share of LUKOIL’s earnings, segment results include the amortization of the basis difference between our equity interest in the net assets of LUKOIL and the book value of our investment and gains from the divestiture of our LUKOIL shares. The segment also includes the costs associated with our employees seconded to LUKOIL.

On July 28, 2010, we announced our intention to sell our entire interest in LUKOIL. During the third quarter of 2010, we sold 113 million shares of LUKOIL for $6,161 million, realizing a before-tax gain on disposition of $1,219 million. As a result of these sales, our ownership interest has declined to a level at which we are no longer able to exercise significant influence over the operating and financial policies of LUKOIL. As of September 30, 2010, our ownership interest in LUKOIL was 5.9 percent based on authorized and issued shares. After the third quarter of 2010, we will no longer account for our remaining investment in LUKOIL using the equity method. In addition, we will no longer report proved reserves or production related to our LUKOIL investment, which were 1,967 million BOE at December 31, 2009, and 437 thousand BOE per day for the nine-month period ended September 30, 2010, respectively. See Note 6—Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements, for more information.

LUKOIL segment earnings increased $798 million in the third quarter of 2010. This increase primarily resulted from the $874 million after-tax gain on our LUKOIL shares sold during the third quarter of 2010. Earnings for the nine-month period of 2010 increased $1,463 million, which was primarily due to the $973 million after-tax gain on our LUKOIL shares sold during the nine-month period of 2010. In addition, for the nine-month period of 2009, equity earnings from LUKOIL were not recorded in the first quarter, since our LUKOIL investment was written down in the fourth quarter of 2008 to its fair value at December 31, 2008.

Beginning in the fourth quarter of 2010, since we will no longer record equity earnings from LUKOIL, our earnings from the LUKOIL Investment segment will primarily reflect only the realized gain on future

43

share sales as we reduce our ownership interest. The total unrealized gain in those shares at September 30, 2010, based on a closing price of LUKOIL shares on the London Stock Exchange of $56.80 per share, was $423 million after-tax, and this amount was included in accumulated other comprehensive income.

Chemicals

	Millions of Dollars
	Three Months Ended				Nine Months Ended
	September 30				September 30
	2010		2009		2010		2009
Net Income Attributable to ConocoPhillips	$	132		104		380		194

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.

Earnings from the Chemicals segment increased 27 percent in the third quarter of 2010, and 96 percent in the nine-month period of 2010. The increases in both periods primarily resulted from substantially higher margins in the olefins and polyolefins business line, partially offset by higher operating costs. Additionally, the improvement in the third quarter of 2010 was partially offset by lower margins in the specialties, aromatics and styrenics business line. Earnings in the nine-month period also benefitted from higher margins in the specialties, aromatics and styrenics business line, in addition to higher volumes from both business lines.

Emerging Businesses

	Millions of Dollars
	Three Months Ended						Nine Months Ended
	September 30						September 30
	2010			2009			2010			2009
Net Income (Loss) Attributable to ConocoPhillips
Power	$	8			22			54			73
Other		(28	)		(24	)		(78	)		(73	)
	$	(20	)		(2	)		(24	)		-

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 innovation of new technologies, such as those related to conventional and nonconventional hydrocarbon recovery (including heavy oil), refining, alternative energy, biofuels and the environment.

The Emerging Businesses segment reported a loss of $20 million in the third quarter of 2010, compared with a loss of $2 million in the same quarter of 2009. Losses for the first nine months of 2010 were $24 million. Emerging Businesses broke even in the corresponding period of 2009. The decrease in earnings in the third quarter of 2010 was primarily due to lower domestic power generation results, which included an impairment of a facility in connection with its planned sale, partially offset by improved international power generation results. The decrease for the nine-month period of 2010 was mainly due to lower domestic and international power generation results. The Emerging Businesses segment incurred higher technology development expenses in both 2010 periods.

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Corporate and Other

	Millions of Dollars
	Three Months Ended						Nine Months Ended
	September 30						September 30
	2010			2009			2010			2009
Net Income (Loss) Attributable to ConocoPhillips
Net interest	$	(285	)		(245	)		(761	)		(610	)
Corporate general and administrative expenses		(37	)		(5	)		(120	)		(77	)
Other		46			(33	)		(94	)		(12	)
	$	(276	)		(283	)		(975	)		(699	)

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 increased 16 percent in the third quarter of 2010 and 25 percent in the first nine months of 2010. The increase in both periods was primarily due to a $114 million after-tax premium on early debt retirement. In addition, the increase in the third quarter of 2010 was partially offset by lower interest expense due to lower debt levels. Corporate general and administrative expenses increased $32 million in the third quarter of 2010 and $43 million in the nine-month period, primarily as a result of costs related to compensation plans. The category “Other” includes certain foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation, and other costs not directly associated with an operating segment. Changes in the “Other” category primarily reflect foreign currency transaction gains in the third quarter of 2010, while the nine-month period of 2010 primarily reflects foreign currency transaction losses.

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CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators

	Millions of Dollars
	September 30			December 31
	2010			2009
Short-term debt	$	376			1,728
Total debt*	$	23,601			28,653
Total equity	$	69,917			62,613	**
Percent of total debt to capital***		25	%		31
Percent of floating-rate debt to total debt		10	%		9

*	Total debt includes short-term and long-term debt, as shown on our consolidated balance sheet.
**	Recast to reflect a change in accounting principles. See Note 2—Changes in Accounting Principles, for more information.
***	Capital includes total debt and total 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 nine-month period of 2010, we raised $12.2 billion in proceeds from assets sales. During the first nine months of 2010, available cash was used to support our ongoing capital expenditures and investments program, provide loan financing to certain equity affiliates, pay dividends, and meet the funding requirements to FCCL Partnership. Total dividends paid on our common stock during the first nine months were $2,376 million. During the first nine months of 2010, cash and cash equivalents increased $7,454 million to $7,996 million.

In addition to cash flows from operating activities and proceeds from asset sales, we rely on our commercial paper and credit facility programs, and our shelf registration statement to support our short- and long-term liquidity requirements. We believe current cash and short-term investment balances and cash generated by operations, together with access to external sources of funds as described below in the “Significant Sources of Capital” section, will be sufficient to meet our funding requirements in the near and long term, including our capital spending program, dividend payments, required debt payments and the funding requirements to FCCL.

Significant Sources of Capital

Operating Activities
During the first nine months of 2010, cash of $10,854 million was provided by operating activities, a 47 percent increase from cash from operations of $7,385 million in the corresponding period of 2009. The improvement was primarily due to higher commodity prices and improved refining and marketing margins, partially offset by a discretionary inventory build.

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 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 2010, crude oil and natural gas prices were higher than in the same period of 2009. Prices and margins in our industry are typically volatile, and are 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 their timely and cost-effective development. While we actively manage these factors, production levels can cause variability in cash flows, although historically this variability has not been as significant as that caused by commodity prices.

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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, market conditions, 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 caused by refining margins.

Asset Sales
Proceeds from asset sales during the first nine months of 2010 totaled $12.2 billion, which included $4.6 billion from the second-quarter 2010 sale of our 9.03 percent interest in the Syncrude Canada Ltd. joint venture and $6.4 billion from the year-to-date sale of a portion of our interest in LUKOIL. In addition, proceeds included the second-quarter 2010 sale of our interest in CFJ Properties. We plan to raise an additional $4 billion to $5 billion through the end of 2011, as part of our previously announced $10 billion asset disposition program. The sale of our LUKOIL interest is not included in this program.

Commercial Paper and Credit Facilities
At September 30, 2010, we had two revolving credit facilities totaling $7.85 billion, consisting of a $7.35 billion facility expiring in September 2012 and a $500 million facility expiring in July 2012. Our revolving credit facilities may be used as direct bank borrowings, as support for issuances of letters of credit totaling up to $750 million, or as support for our commercial paper programs. The revolving credit facilities are broadly syndicated among financial institutions and do not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or ratings. The facility agreements contain a cross-default provision relating to the failure to pay principal or interest on other debt obligations of $200 million or more by ConocoPhillips, or by any of its consolidated subsidiaries.

Credit facility borrowings may bear interest at a margin above rates offered by certain designated banks in the London interbank market or at a margin above the overnight federal funds rate or prime rates offered by certain designated banks in the United States. The agreements call for commitment fees on available, but unused, amounts. The agreements also contain early termination rights if our current directors or their approved successors cease to be a majority of the Board of Directors.

Our primary funding source for short-term working capital needs is the ConocoPhillips $6.35 billion commercial paper program. Commercial paper maturities are generally limited to 90 days. We also have the ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program, which is used to fund commitments relating to the Qatargas 3 Project. At September 30, 2010, and December 31, 2009, we had no direct borrowings under the revolving credit facilities, but $40 million in letters of credit had been issued in both periods. In addition, under the two ConocoPhillips commercial paper programs, $1,159 million of commercial paper was outstanding at September 30, 2010, compared with $1,300 million at December 31, 2009. Since we had $1,159 million of commercial paper outstanding and had issued $40 million of letters of credit, we had access to $6.7 billion in borrowing capacity under our revolving credit facilities at September 30, 2010.

Shelf Registration
We have a universal shelf registration statement on file with the U.S. Securities and Exchange Commission (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.

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Off-Balance Sheet Arrangements

As part of our normal ongoing business operations and consistent with normal 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, 2010, we were liable for certain contingent obligations under our agreement with Qatargas 3.

We own a 30 percent interest in Qatargas 3, an integrated project to produce and liquefy natural gas from Qatar’s North Field. The other participants in the project are affiliates of Qatar Petroleum (68.5 percent) and Mitsui & Co., Ltd. (1.5 percent). 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. Upon completion certification, currently expected in 2011, all project loan facilities, including the ConocoPhillips loan facilities, will become nonrecourse to the project participants. At September 30, 2010, Qatargas 3 had approximately $4 billion outstanding under all the loan facilities, including the $1.2 billion loan from ConocoPhillips.

For additional information about guarantees, see Note 12—Guarantees, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

Capital Requirements

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

Our debt balance at September 30, 2010, was $23.6 billion, a decrease of $5.1 billion from the balance at December 31, 2009.

We are obligated to contribute $7.5 billion, plus interest, over a 10-year period that began in 2007, to FCCL. Quarterly principal and interest payments of $237 million began in the second quarter of 2007 and will continue until the balance is paid. Of the principal obligation amount, $686 million was short-term and was included in the “Accounts payable—related parties” line on our September 30, 2010, consolidated balance sheet. The principal portion of these payments, which totaled $491 million in the first nine months of 2010, is included in the “Other” line in the financing activities section of our consolidated statement of cash flows. 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 a capital contribution and is included in the “Capital expenditures and investments” line on our consolidated statement of cash flows.

We have provided loan financing to WRB Refining LLC, to assist it in meeting its operating and capital spending requirements. At September 30, 2010, $551 million of such financing was outstanding and $400 million was classified as long term.

In October 2010, we announced a quarterly dividend of 55 cents per share. The dividend is payable December 1, 2010, to stockholders of record at the close of business October 29, 2010.

On March 24, 2010, we announced plans to purchase up to $5 billion of our common stock over the subsequent two years. Repurchase of shares began in April and totaled 22,278,916 shares at a cost of $1.3 billion, through September 30, 2010. Additionally, at the end of the quarter we had a cash balance of $8 billion, a significant portion of which is expected to be directed toward the repurchase of common stock.

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Capital Spending

Capital Expenditures and Investments

	Millions of Dollars
	Nine Months Ended
	September 30
	2010		2009
E&P
United States—Alaska	$	544		638
United States—Lower 48		1,041		2,124
International		4,022		3,875
		5,607		6,637
Midstream		1		4
R&M
United States		479		1,079
International		180		292
		659		1,371
LUKOIL Investment		-		-
Chemicals		-		-
Emerging Businesses		7		89
Corporate and Other		97		75
	$	6,371		8,176
United States	$	2,162		3,930
International		4,209		4,246
	$	6,371		8,176

We expect our 2010 capital program, which includes capital expenditures and investments, loans to certain affiliated companies and principal contributions related to funding our portion of the FCCL business venture, to be $10 billion to $11 billion.

E&P

Capital spending for E&P during the first nine months of 2010 totaled $5.6 billion. The expenditures supported key exploration and development projects including:

• Oil and natural gas developments in the Lower 48, including San Juan and Permian Basins, Bakken and Barnett trends.

• Alaska activities related to the Prudhoe Bay and Kuparuk Fields, as well as the Alpine Field and satellites on the Western North Slope.

• Oil sands projects and ongoing oil and natural gas projects in Canada.

• Further development of coalbed methane projects associated with the Australia Pacific LNG Pty Limited joint venture in Australia.

• Qatargas 3 Project in Qatar.

• In Asia Pacific, Bohai Bay in China, Bayu Undan in the Timor Sea, new fields offshore Malaysia and the Darwin LNG facility in Australia.

• In the North Sea, the Ekofisk Area and development of the Jasmine discovery in the J Block.

• The Kashagan Field in the Caspian Sea.

• Onshore developments in Nigeria and Algeria.

• Exploration activities in Australia’s Browse Basin, offshore eastern Canada, Lower 48’s Eagle Ford shale, Poland, Malaysia and Vietnam.

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R&M
Capital spending for R&M during the first nine months of 2010 totaled $659 million and included projects related to sustaining and improving the existing business with a focus on safety, regulatory compliance and reliability.

Contingencies

Legal and Tax Matters
We accrue a liability for known contingencies (other than those related to income taxes) 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 use 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 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 58, 59 and 60 of our 2009 Annual Report on Form 10-K.

We, from time to time, receive requests for information or notices of potential liability from the Environmental Protection Agency (EPA) 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 contain wastes attributable to our past operations. As of December 31, 2009, we reported we had been notified of potential liability under CERCLA and comparable state laws at 65 sites around the United States. At September 30, 2010, we were notified of six new sites, re-opened three sites and settled one site, bringing the number to 73 unresolved sites with potential liability.

At September 30, 2010, our balance sheet included a total environmental accrual of $987 million, compared with $1,017 million at December 31, 2009. We expect to incur a substantial amount 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 concerns 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 current environmental laws and regulations.

Climate Change
There has been a broad range of proposed or promulgated state, national and international laws focusing on greenhouse gas (GHG) reduction. These proposed or promulgated laws apply or could apply in countries where we have interests or may have interests in the future. Laws in this field continue to evolve, and while it is not possible to accurately estimate either a timetable for implementation or our future compliance costs relating to implementation, such laws, if enacted, could have a material impact on our results of operations and financial condition. Examples from 2010 of legislation and precursors for possible regulation that do or could affect our operations include the EPA’s announcement on March 29, 2010 (published as “Interpretation of Regulations that Determine Pollutants Covered by Clean Air Act Permitting Programs,” 75 Fed. Reg. 17004 (April 2, 2010)), and the EPA’s and U.S. Department of Transportation’s joint promulgation of a Final Rule on

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April 1, 2010, which triggers regulation of GHGs under the Clean Air Act, may trigger more climate-based claims for damages, and may result in longer agency review time for development projects to determine the extent of climate change.

Both of the above referenced announcements are subject to pending legal challenges, and we continue to monitor these legal proceedings and other regulatory actions for potential impacts on our operations. For other examples of legislation or precursors for possible regulation that do or could affect our operations, see the “Climate Change” section in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 60 and 61 of our 2009 Annual Report on Form 10-K.

OUTLOOK

In May 2010, in response to the Deepwater Horizon incident in the Gulf of Mexico (GOM), the U.S. Department of the Interior (DOI) issued a six-month drilling moratorium on new deepwater wells in the Outer Continental Shelf (OCS), which was later overturned by a federal district court. A second drilling moratorium was issued in July 2010, and was scheduled to expire on November 30, 2010. On October 12, 2010, the DOI lifted the ban, citing new regulatory requirements which would reduce the risks associated with deepwater drilling. The new rules are aimed at improving safety and environmental standards and include strengthened requirements on safety equipment, well control systems, blowout prevention practices and emergency response on offshore oil and gas operations. As a result, we are currently evaluating the impact on our exploration prospects in the GOM. There are no material impacts to our near-term production.

The drilling moratorium did not affect any activities on our Chukchi Sea leases. However, due to continued pending litigation, our plans for drilling an exploration well on our Chukchi Sea leases remain under review.

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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 on our current expectations, estimates and projections about ourselves and the industries in which we operate in general. We caution you these statements are not guarantees of future performance as they involve assumptions that, while made in good faith, may prove to be incorrect, and involve risks and uncertainties 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.

• Potential failures 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 or the inability to obtain access to exploratory acreage.

• 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, manufacturing, refining or transportation projects.

• 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.

• Inability to timely obtain or maintain permits, including those necessary for construction of LNG terminals or regasification facilities, or refinery projects; 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 exploration and production, LNG, refinery and transportation projects.

• 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.

• Substantial investment or reduced demand for products as a result of existing or future environmental rules and regulations.

• 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, regulation or 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.

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• Limited access to capital or significantly higher cost of capital related to uncertainty in the domestic or international financial markets.

• Delays in, or our inability to implement, our recently announced asset disposition plan.

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

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

• The factors generally described in Item 1A—Risk Factors in our 2009 Annual Report on Form 10-K.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information about market risks for the nine months ended September 30, 2010, does not differ materially from that discussed under Item 7A in our 2009 Annual Report on Form 10-K.

Item 4. CONTROLS AND PROCEDURES

As of September 30, 2010, with the participation of our management, our Chairman and Chief Executive Officer (principal executive officer) and our Senior 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 and Chief Executive Officer and our Senior Vice President, Finance and Chief Financial Officer concluded that our disclosure controls and procedures were operating effectively as of September 30, 2010.

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 2010 and any material developments with respect to matters previously reported in ConocoPhillips’ 2009 Annual Report on Form 10-K or first- and second-quarter 2010 Quarterly Reports on Form 10-Q. Material developments to the previously reported matters have been included in the descriptions below. While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings was 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 SEC’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 decrees 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 decrees or other reports required by permits or regulations, we occasionally report matters that could be subject to a request for stipulated penalties. If a specific request for stipulated penalties meeting the reporting threshold set forth in SEC 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
On September 23, 2010, the Los Angeles County Fire Department Health and Hazardous Materials Division (HHMD) issued a proposed penalty of $127,000 to ConocoPhillips. The penalty pertains to alleged violations of hazardous waste regulations at the Los Angeles Refinery noted by HHMD during its refinery compliance inspections in November and December 2009. ConocoPhillips is working with HHMD to resolve this matter.

Matters Previously Reported
On December 17, 2009, the San Francisco Regional Water Quality Control Board’s enforcement staff (SFRWQCB) issued an Administrative Civil Liability Complaint alleging 18 exceedances of the Rodeo facility’s effluent permit that occurred during 2008 and 2009. The Complaint seeks a penalty of $490,000. Since that time, SFRWQCB and ConocoPhillips agreed to include 14 additional exceedances that occurred in 2009 as part of the overall settlement. The SFRWQCB and ConocoPhillips reached an agreement to settle the 32 exceedances for a total payment of $600,000 (consisting of a $310,000 penalty payment; funding of a Supplemental Environmental Project in the amount of $190,000; and credit towards Enhanced Compliance Actions to improve the refinery’s wastewater treatment plant operations in the amount of $100,000). The settlement agreement was subject to a 30-day public comment period prior to final approval by the SFRWQCB, which expired in the third quarter of 2010. The SFRWQCB has given its final approval and the settlement payments have been completed.

In March 2005, ConocoPhillips Pipe Line Company (CPPL) received a Notice of Potential Violation from the U.S. Department of Transportation (USDOT) alleging violation of USDOT operation and safety regulations at certain facilities in Kansas, Missouri, Illinois, Indiana, Wyoming and Nebraska. USDOT proposed penalties in the amount of $184,500. An information hearing was held on September 24, 2007. On September 13, 2010, USDOT issued a Final Order with a reduced penalty of $39,000, which the Company will pay as final resolution of this matter.

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Item 1A. RISK FACTORS

There have been no material changes from the risk factors disclosed in Item 1A of our 2009 Annual Report on Form 10-K.

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, 2010		2,330		$	54.51		-		$	4,610
August 1-31, 2010		14,503,169			56.38		14,500,000			3,792
September 1-30, 2010		891,815			56.54		884,230			3,742
Total		15,397,314		$	56.39		15,384,230

*

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

**

On March 24, 2010, we announced plans to purchase up to $5 billion of our common stock over the subsequent two years. Acquisitions for the share repurchase program 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 plan are held as treasury shares.

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Item 6. 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.
101.INS	XBRL Instance Document.
101.SCH	XBRL Schema Document.
101.CAL	XBRL Calculation Linkbase Document.
101.LAB	XBRL Labels Linkbase Document.
101.PRE	XBRL Presentation Linkbase Document.
101.DEF	XBRL Definition Linkbase Document.

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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/ Glenda M. Schwarz

Glenda M. Schwarz

Vice President and Controller

(Chief Accounting and Duly Authorized Officer)

November 2, 2010

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