ConocoPhillips (COP) 10-Q 2009 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, 2009
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 [ ] 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]

ConocoPhillips had 1,483,694,303 shares of common stock, $.01 par value, outstanding at September 30, 2009.

CONOCOPHILLIPS

TABLE OF CONTENTS

	Page
Part I – Financial Information
Item 1. Financial Statements
Consolidated Income Statement		1
Consolidated Balance Sheet		2
Consolidated Statement of Cash Flows		3
Notes to Consolidated Financial Statements		4
Supplementary Information—Condensed Consolidating Financial Information		26
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		31
Item 3. Quantitative and Qualitative Disclosures About Market Risk		50
Item 4. Controls and Procedures		50
Part II – Other Information
Item 1. Legal Proceedings		51
Item 1A. Risk Factors		52
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		52
Item 6. Exhibits		53
Signature		54
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

Item 1. FINANCIAL STATEMENTS

Consolidated Income Statement ConocoPhillips

	Millions of Dollars
	Three Months Ended						Nine Months Ended
	September 30						September 30
	2009			2008			2009			2008
Revenues and Other Income
Sales and other operating revenues*	$	40,173			70,044			106,362			196,338
Equity in earnings of affiliates		1,015			1,214			2,506			4,385
Other income		117			115			347			555
Total Revenues and Other Income		41,305			71,373			109,215			201,278
Costs and Expenses
Purchased crude oil, natural gas and products		28,008			49,608			72,376			138,642
Production and operating expenses		2,534			3,059			7,652			8,861
Selling, general and administrative expenses		427			513			1,378			1,668
Exploration expenses		386			267			854			864
Depreciation, depletion and amortization		2,327			2,361			6,904			6,748
Impairments
Expropriated assets		-			-			51			-
Other		56			57			59			82
Taxes other than income taxes*		4,205			5,619			11,384			16,570
Accretion on discounted liabilities		96			114			308			314
Interest and debt expense		336			239			914			656
Foreign currency transaction (gains) losses		(17	)		54			(28	)		11
Total Costs and Expenses		38,358			61,891			101,852			174,416
Income before income taxes		2,947			9,482			7,363			26,862
Provision for income taxes		1,427			4,279			3,673			12,045
Net income		1,520			5,203			3,690			14,817
Less: net income attributable to noncontrolling interests		(17	)		(15	)		(49	)		(51	)
Net Income Attributable to ConocoPhillips	$	1,503			5,188			3,641			14,766
Net Income Attributable to ConocoPhillips Per Share of Common Stock(dollars)**
Basic	$	1.00			3.43			2.44			9.61
Diluted		1.00			3.39			2.43			9.50
Dividends Paid Per Share of Common Stock(dollars)	$	.47			.47			1.41			1.41
Average Common Shares Outstanding(in thousands)
Basic		1,488,352			1,510,897			1,486,922			1,535,932
Diluted		1,498,204			1,528,187			1,496,391			1,554,952
*    Includes excise taxes on petroleum products sales:	$	3,538			4,022			9,914			11,970

** 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.

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Consolidated Balance Sheet ConocoPhillips

	Millions of Dollars
	September 30			December 31
	2009			2008
Assets
Cash and cash equivalents	$	641			755
Accounts and notes receivable (net of allowance of $75 million in 2009 and $61 million in 2008)		10,907			10,892
Accounts and notes receivable—related parties		1,623			1,103
Inventories		6,268			5,095
Prepaid expenses and other current assets		2,814			2,998
Total Current Assets		22,253			20,843
Investments and long-term receivables		35,664			30,926
Loans and advances—related parties		2,186			1,973
Net properties, plants and equipment		87,136			83,947
Goodwill		3,715			3,778
Intangibles		831			846
Other assets		642			552
Total Assets	$	152,427			142,865
Liabilities
Accounts payable	$	13,296			12,852
Accounts payable—related parties		1,566			1,138
Short-term debt		2,796			370
Accrued income and other taxes		3,844			4,273
Employee benefit obligations		741			939
Other accruals		2,413			2,208
Total Current Liabilities		24,656			21,780
Long-term debt		27,662			27,085
Asset retirement obligations and accrued environmental costs		7,836			7,163
Joint venture acquisition obligation—related party		5,177			5,669
Deferred income taxes		18,294			18,167
Employee benefit obligations		3,662			4,127
Other liabilities and deferred credits		3,043			2,609
Total Liabilities		90,330			86,600
Equity
Common stock (2,500,000,000 shares authorized at $.01 par value)
Issued (2009—1,731,876,757 shares; 2008—1,729,264,859 shares)
Par value		17			17
Capital in excess of par		43,583			43,396
Grantor trusts (at cost: 2009—39,835,639 shares; 2008—40,739,129 shares)		(689	)		(702	)
Treasury stock (at cost: 2009 and 2008—208,346,815 shares)		(16,211	)		(16,211	)
Accumulated other comprehensive income (loss)		2,712			(1,875	)
Unearned employee compensation		(83	)		(102	)
Retained earnings		32,181			30,642
Total Common Stockholders’ Equity		61,510			55,165
Noncontrolling interests		587			1,100
Total Equity		62,097			56,265
Total Liabilities and Equity	$	152,427			142,865

See Notes to Consolidated Financial Statements.

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Consolidated Statement of Cash Flows ConocoPhillips

	Millions of Dollars
	Nine Months Ended
	September 30
	2009			2008
Cash Flows From Operating Activities
Net income	$	3,690			14,817
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization		6,904			6,748
Impairments		110			82
Dry hole costs and leasehold impairments		471			399
Accretion on discounted liabilities		308			314
Deferred taxes		(864	)		59
Undistributed equity earnings		(1,818	)		(2,530	)
Gain on asset dispositions		(88	)		(346	)
Other		(151	)		(185	)
Working capital adjustments
Decrease (increase) in accounts and notes receivable		(94	)		(243	)
Decrease (increase) in inventories		(1,026	)		(2,709	)
Decrease (increase) in prepaid expenses and other current assets		(286	)		(689	)
Increase (decrease) in accounts payable		910			1,633
Increase (decrease) in taxes and other accruals		(681	)		2,186
Net Cash Provided by Operating Activities		7,385			19,536
Cash Flows From Investing Activities
Capital expenditures and investments		(8,176	)		(10,535	)
Proceeds from asset dispositions		938			729
Long-term advances/loans—related parties		(303	)		(181	)
Collection of advances/loans—related parties		62			15
Other		50			(186	)
Net Cash Used in Investing Activities		(7,429	)		(10,158	)
Cash Flows From Financing Activities
Issuance of debt		9,051			2,264
Repayment of debt		(6,027	)		(1,857	)
Issuance of company common stock		(11	)		182
Repurchase of company common stock		-			(7,500	)
Dividends paid on company common stock		(2,090	)		(2,159	)
Other		(1,091	)	��	(426	)
Net Cash Used in Financing Activities		(168	)		(9,496	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents		98			(222	)
Net Change in Cash and Cash Equivalents		(114	)		(340	)
Cash and cash equivalents at beginning of period		755			1,456
Cash and Cash Equivalents at End of Period	$	641			1,116

See Notes to Consolidated Financial Statements.

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Notes to Consolidated Financial Statements ConocoPhillips

Note 1—Interim Financial Information

The interim-period financial information presented in the financial statements included in this report is unaudited and includes all known accruals and adjustments, in the opinion of management, necessary for a fair presentation of the consolidated financial position of ConocoPhillips and its results of operations and cash flows for such periods. All such adjustments are of a normal and recurring nature. To enhance your understanding of these interim financial statements, see the consolidated financial statements and notes included in our 2008 Annual Report on Form 10-K.

Note 2—Changes in Accounting Principles

Codification
The Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2009-01 in June 2009. This Update, also issued as FASB Statement of Financial Accounting Standards (SFAS) No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles,” is effective for financial statements issued after September 15, 2009. Update 2009-01 requires that the FASB’s Accounting Standards Codification (ASC) become the sole source of authoritative U.S. generally accepted accounting principles recognized by the FASB for nongovernmental entities. We adopted this Update effective July 1, 2009.

Subsequent Events
Effective April 1, 2009, we adopted FASB SFAS No. 165, “Subsequent Events.” This Statement was codified into FASB ASC Topic 855, “Subsequent Events.” Topic 855 establishes the accounting for, and disclosure of, material events that occur after the balance sheet date, but before the financial statements are issued. In general, these events will be recognized if the condition existed at the date of the balance sheet, but will not be recognized if the condition did not exist at the balance sheet date. Disclosure is required for nonrecognized events if required to keep the financial statements from being misleading. The guidance in this Topic is very similar to previous guidance provided in auditing literature and, therefore, should not result in significant changes in practice. Subsequent events have been evaluated through November 3, 2009, the date our interim financial statements were issued with the filing of our third-quarter 2009 Quarterly Report on Form 10-Q.

Business Combinations
In December 2007, the FASB issued SFAS No. 141 (Revised), “Business Combinations” (SFAS No. 141(R)), which was subsequently amended by FASB Staff Position (FSP) FAS 141(R)-1 in April 2009. This Statement was codified into FASB ASC Topic 805, “Business Combinations.” Topic 805 applies prospectively to all transactions in which an entity obtains control of one or more other businesses on or after January 1, 2009. In general, Topic 805 requires the acquiring entity in a business combination to recognize the fair value of all assets acquired and liabilities assumed in the transaction; establishes the acquisition date as the fair value measurement point; and modifies disclosure requirements. It also modifies the accounting treatment for transaction costs, in-process research and development, restructuring costs, changes in deferred tax asset valuation allowances as a result of a business combination, and changes in income tax uncertainties after the acquisition date. Additionally, effective January 1, 2009, accounting for changes in valuation allowances for acquired deferred tax assets and the resolution of uncertain tax positions for prior business combinations impact tax expense instead of goodwill.

Noncontrolling Interests
Effective January 1, 2009, we implemented SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51.” This Statement was codified into FASB ASC Topic 810, “Consolidation.” Topic 810 requires noncontrolling interests, previously called minority interests, to be presented as a separate item in the equity section of the consolidated balance sheet. It also requires the amount

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of consolidated net income attributable to noncontrolling interests to be clearly presented on the face of the consolidated income statement. Additionally, Topic 810 clarifies that changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation are equity transactions, and that deconsolidation of a subsidiary requires gain or loss recognition in net income based on the fair value on the deconsolidation date. Topic 810 was applied prospectively with the exception of presentation and disclosure requirements, which were applied retrospectively for all periods presented, and did not significantly change the presentation of our consolidated financial statements. Equity attributable to noncontrolling interests decreased from $1,100 million at December 31, 2008, to $587 million at September 30, 2009. The decrease primarily reflects the redemption of the noncontrolling interest in Ashford Energy Capital S.A. during the third quarter of 2009, resulting in Ashford now being wholly owned by us. See Note 3—Variable Interest Entities for additional information on this redemption.

Derivatives
Effective January 1, 2009, we implemented SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB No. 133.” This Statement was codified into FASB ASC Topic 815, “Derivatives and Hedging.” The amendments to Topic 815 expanded disclosure requirements to provide greater transparency for derivative instruments. Disclosures previously required only for the annual financial statements are now required in interim financial statements. In addition, we now must include an indication of the volume of derivative activity by category (e.g., interest rate, commodity and foreign currency); derivative gains and losses, by category, for the periods presented in the financial statements; and expanded disclosures about credit-risk-related contingent features. See Note 13—Financial Instruments and Derivative Contracts for additional information.

Fair Value Measurement
Following the allowed one-year deferral, effective January 1, 2009, we implemented Topic 820, “Fair Value Measurements and Disclosures” for nonfinancial assets and nonfinancial liabilities measured at fair value on a nonrecurring basis. The implementation covers assets and liabilities measured at fair value in a business combination; impaired properties, plants and equipment, intangible assets and goodwill; initial recognition of asset retirement obligations; and restructuring costs for which we use fair value. In the first nine months of 2009, we did not have a business combination, impairment of goodwill or intangible asset, or restructuring accrual requiring the use of fair value. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of properties, plants and equipment is determined based on the present values of expected future cash flows using inputs reflecting our estimate of a number of variables used by industry participants when valuing similar assets, or based on a multiple of operating cash flow validated with historical market transactions of similar assets where possible. Fair value used in the initial recognition of asset retirement obligations is determined based on the present value of expected future dismantlement costs incorporating our estimate of inputs used by industry participants when valuing similar liabilities. There was no impact to our consolidated financial statements from the implementation of this Topic for nonfinancial assets and liabilities, and we do not expect any significant impact to our future consolidated financial statements, other than additional disclosures.

Equity Method Accounting
In November 2008, the FASB reached a consensus on Emerging Issues Task Force (EITF) Issue No. 08-6, “Equity Method Investment Accounting Considerations” (EITF 08-6). EITF 08-6 was issued to clarify how the application of equity method accounting is affected by SFAS No. 141(R) and SFAS No. 160. EITF 08-6 was codified into FASB ASC Topic 323, “Investments—Equity Method and Joint Ventures.” Topic 323 clarifies that an entity shall continue to use the cost accumulation model for its equity method investments. It also confirms past accounting practices related to the treatment of contingent consideration and the use of the impairment model for equity investments. Additionally, it requires an equity method investor to account for a share issuance by an investee as if the investor had sold a proportionate share of the investment. This Topic was effective January 1, 2009, and applies prospectively.

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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. See Note 20—New Accounting Standards for information affecting the accounting for VIEs effective January 1, 2010.

We own a 24 percent interest in West2East Pipeline LLC, a company holding a 100 percent interest in Rockies Express Pipeline LLC, operated by Kinder Morgan Energy Partners, L.P. Rockies Express is constructing a natural gas pipeline from Colorado to Ohio. West2East is a VIE because a third party has a 49 percent voting interest through the end of the construction of the pipeline, but has no ownership interest. This third party was originally involved in the project, but exited and retained its voting interest to ensure project completion. We have no voting interest during the construction phase, but once the pipeline has been completed, our ownership will increase to 25 percent with a voting interest of 25 percent. Additionally, we have contracted for approximately 22 percent of the pipeline capacity for a 10-year period once the pipeline becomes operational. Construction commenced on the pipeline in 2006. The operator anticipates construction completion in late 2009 and estimates total construction costs between $6.7 billion and $6.8 billion. Our portion is being funded by a combination of equity contributions and a guarantee of debt incurred by Rockies Express. Given our 24 percent ownership and the fact expected returns are shared among the equity holders in proportion to ownership, we are not the primary beneficiary. We use the equity method of accounting for our investment. At September 30, 2009, the book value of our investment in West2East was $739 million.

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 a related party, OAO LUKOIL, have disproportionate interests. When related parties are involved in a VIE, reasonable judgment should take into account the relevant facts and circumstances for the determination of the primary beneficiary. The activities of NMNG are more closely aligned with LUKOIL because they share Russia as a home country, and LUKOIL conducts extensive exploration activities in the same province. Additionally, there are no financial guarantees given by LUKOIL or us, and LUKOIL owns 70 percent, versus our 30 percent direct interest. As a result, 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. Initial production from YK was achieved in June 2008. At September 30, 2009, the book value of our investment in the venture was $2,013 million.

Production from the NMNG joint venture fields is transported via pipeline to LUKOIL’s terminal at Varandey Bay on the Barents Sea and then shipped via tanker to international markets. LUKOIL completed an expansion of the terminal’s gross oil-throughput capacity from 30,000 barrels per day to 240,000 barrels per day, and we participated in the design and financing of the expansion. The terminal entity, Varandey Terminal Company, is a VIE because we and LUKOIL have disproportionate interests. We had an obligation to fund, through loans, 30 percent of the terminal’s expansion costs, but have no governance or direct ownership interest in the terminal. Similar to NMNG, we determined we are not the primary beneficiary for Varandey because of LUKOIL’s ownership, the activities are in LUKOIL’s home country, and LUKOIL is the operator of Varandey. We account for our loan to Varandey as a financial asset. Terminal expansion was completed in June 2008. Principal repayments began in April 2009. The loan balance outstanding as of September 30, 2009, at current exchange rates, was $291 million.

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, 2009, was $723 million. Freeport LNG is a VIE because Freeport GP holds no equity in Freeport LNG, and the limited partners of

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Freeport LNG do not have any substantive decision making ability. We performed an analysis of the expected losses and determined we are not the primary beneficiary. This expected loss analysis took into account that the credit support arrangement requires Freeport LNG to maintain sufficient commercial insurance to mitigate any loan losses. 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.

In the third quarter of 2009, Ashford Energy Capital S.A. redeemed for $500 million, plus accrued dividends, the investment in Ashford held by Cold Spring Finance S.a.r.l. Accordingly, we wholly own Ashford, and it is no longer a VIE. The difference between the redemption amount and the carrying value of the investment was $12 million. The redemption amount was included as a cash outflow in the “Other” line in the financing activities section of our consolidated statement of cash flows.

Note 4—Inventories

Inventories consisted of the following:

	Millions of Dollars
	September 30		December 31
	2009		2008
Crude oil and petroleum products	$	5,270		4,232
Materials, supplies and other		998		863
	$	6,268		5,095

Inventories valued on the last-in, first-out (LIFO) basis totaled $5,049 million and $3,939 million at September 30, 2009, and December 31, 2008, respectively. The remaining inventories are valued under various methods, including first-in, first-out and weighted average. The excess of current replacement cost over LIFO cost of inventories amounted to $4,898 million and $1,959 million at September 30, 2009, and December 31, 2008, respectively.

Note 5—Assets Held for Sale

In June 2009, we signed an agreement to sell our remaining interest in the Keystone Pipeline to TransCanada Corporation. The transaction closed in the third quarter of this year.

Note 6—Investments, Loans and Long-Term Receivables

LUKOIL
Our ownership interest in LUKOIL was 20 percent at September 30, 2009, based on 851 million shares authorized and issued. For financial reporting under U.S. generally accepted accounting principles (GAAP), treasury shares held by LUKOIL are not considered outstanding for determining our equity method ownership interest in LUKOIL. Our ownership interest, based on estimated shares outstanding, was 20.09 percent at September 30, 2009.

At September 30, 2009, the book value of our ordinary share investment in LUKOIL was $6,466 million. Our 20 percent share of the net assets of LUKOIL was estimated to be $10,971 million. A majority of this negative basis difference of $4,505 million is being amortized on a straight-line basis over a 22-year useful life as an increase to equity earnings. On September 30, 2009, the closing price of LUKOIL shares on the London Stock Exchange was $54.20 per share, making the total market value of our LUKOIL investment $9,220 million.

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Because LUKOIL’s accounting cycle close and preparation of U.S. GAAP financial statements occur subsequent to our reporting deadline, our equity earnings are estimated based on current market indicators, publicly available LUKOIL information and other objective data. Once the difference between actual and estimated results is known, an adjustment is recorded. Net income attributable to ConocoPhillips for the third quarter of 2009 included a $33 million positive alignment of our second-quarter estimate of LUKOIL’s results to LUKOIL’s reported results.

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, 2009, included the following:

• $723 million in loan financing to Freeport LNG Development, L.P. for the construction of an LNG receiving terminal, which became operational in June 2008. Freeport began making repayments in September 2008.

• $291 million in loan financing at September 2009 exchange rates to Varandey Terminal Company associated with the costs of a terminal expansion. The terminal expansion was completed in June 2008. Principal repayments began in April 2009.

• $979 million of project financing and an additional $85 million of accrued interest to Qatargas 3, an integrated project to produce and liquefy natural gas from Qatar’s North Field. Our maximum exposure to this financing structure is $1.2 billion.

• $174 million of loan financing to WRB Refining LLC to assist it in meeting its operating and capital spending requirements.

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.”

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, 2009, was $333 million, and substantially the entire value is categorized in Level 1 of the fair value hierarchy.

As disclosed in our 2008 Form 10-K, late in 2008 Petroleos de Venezuela S.A. (PDVSA) notified us that January 2009 crude oil supplies nominated for the Sweeny Refinery for processing through facilities owned by the Merey Sweeny Limited Partnership (MSLP) would not be delivered due to instructions from the Venezuelan government. In subsequent months of 2009, PDVSA failed to supply crude oil and/or delivered crude oil not meeting contractual grade specifications. PDVSA also failed to pay contractually required amounts in connection with their non-delivery or off-spec delivery. As a result, and in accordance with our rights under the contractual agreements governing the ownership of MSLP, on August 28, 2009, we exercised our right to acquire PDVSA’s 50 percent ownership interest in MSLP. Due to the expected legal challenges to this action by PDVSA, we will continue to use the equity method of accounting for our investment in MSLP until any legal challenges are resolved.

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Note 7—Properties, Plants and Equipment

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

	Millions of Dollars
	September 30, 2009						December 31, 2008
	Gross		Accum.		Net		Gross		Accum.		Net
	PP&E		DD&A		PP&E		PP&E		DD&A		PP&E
Exploration and Production (E&P)	$	112,407		43,184		69,223		102,591		35,375		67,216
Midstream		123		73		50		120		70		50
Refining and Marketing (R&M)		22,890		6,662		16,228		21,116		5,962		15,154
LUKOIL Investment		-		-		-		-		-		-
Chemicals		-		-		-		-		-		-
Emerging Businesses		1,172		292		880		1,056		293		763
Corporate and Other		1,603		848		755		1,561		797		764
	$	138,195		51,059		87,136		126,444		42,497		83,947

Suspended Wells
The capitalized cost of suspended wells at September 30, 2009, was $858 million, an increase of $198 million from $660 million at year-end 2008. For the category of exploratory well costs capitalized for a period greater than one year as of December 31, 2008, $29 million was charged to dry hole expense during the first nine months of 2009.

Note 8—Impairments

Expropriated Assets
In April 2008, Burlington Resources, Inc., a wholly owned subsidiary of ConocoPhillips, initiated arbitration before the World Bank’s International Centre for Settlement of Investment Disputes (ICSID) against The Republic of Ecuador and PetroEcuador as a result of their newly-enacted Windfall Profits Tax Law and government-mandated renegotiation of our production sharing contracts. Despite a restraining order issued by the ICSID, Ecuador confiscated Burlington and its co-venturer’s crude oil production and sold the illegally seized crude oil. As a result, our assets in Ecuador were effectively expropriated. Accordingly, 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. In the third quarter of 2009, Ecuador took over operations in Block 7 and 21, formalizing the complete expropriation of our assets.

Other Impairments
In the third quarter of 2009, long-lived assets held for sale in the R&M segment with a carrying amount of $140 million were written down to their fair value of $92 million, less cost to sell of $5 million, resulting in a before-tax impairment of $53 million. The fair value is a Level 3 measurement in the fair value hierarchy based on a binding negotiated price with a third party, adjusted for the fair value of certain liabilities retained, and subject to management approval.

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Note 9—Debt

In February 2009, we issued $1.5 billion of 4.75% Notes due 2014, $2.25 billion of 5.75% Notes due 2019, and $2.25 billion of 6.50% Notes due 2039. In addition, in May 2009, we issued $1.5 billion of 4.60% Notes due 2015, $1.0 billion of 6.00% Notes due 2020 and an additional $500 million of 6.50% Notes due 2039. The proceeds from the notes were primarily used to reduce outstanding commercial paper balances and for general corporate purposes.

During the first nine months of 2009, we used proceeds from the issuance of commercial paper to redeem $284 million of 6.375% Notes and $950 million of Floating Rate Notes upon their maturity.

At September 30, 2009, 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. The facilities may be used as direct bank borrowings, as support for the ConocoPhillips $6.35 billion commercial paper program, as support for the ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program, or as support for issuances of letters of credit totaling up to $750 million. At both September 30, 2009, and December 31, 2008, we had no outstanding borrowings under the credit facilities, but $40 million in letters of credit had been issued. Under both ConocoPhillips commercial paper programs, $2,342 million of commercial paper was outstanding at September 30, 2009, compared with $6,933 million at December 31, 2008.

Since we had $2,342 million of commercial paper outstanding and had issued $40 million of letters of credit, we had access to $5.5 billion in borrowing capacity under our revolving credit facilities at September 30, 2009.

At September 30, 2009, we classified $1,037 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 facility.

Note 10—Joint Venture Acquisition Obligation

We are obligated to contribute $7.5 billion, plus interest, over a 10-year period, beginning 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, approximately $651 million was short-term and was included in the “Accounts payable—related parties” line on our September 30, 2009, consolidated balance sheet. The principal portion of these payments, which totaled $466 million in the first nine months of 2009, are 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.

Note 11—Guarantees

At September 30, 2009, 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

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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, expected in 2011. At September 30, 2009, the carrying value of the guarantee to third-party lenders was $11 million.

Guarantees of Joint Venture Debt

• In June 2006, we issued a guarantee for 24 percent of $2 billion in credit facilities of Rockies Express Pipeline LLC, operated by Kinder Morgan Energy Partners, L.P. At September 30, 2009, Rockies Express had $1,871 million outstanding under the credit facilities, with our 24 percent guarantee equaling $449 million. The maximum potential amount of future payments to third-party lenders under the guarantee is estimated to be $480 million, which could become payable if the credit facilities are fully utilized and Rockies Express fails to meet its obligations under the credit agreement. The operator anticipates construction completion in late 2009. Refinancing of the $2 billion credit facility, which will make the debt nonrecourse to ConocoPhillips, is expected to begin at that time. At September 30, 2009, the total carrying value of this guarantee to third-party lenders was $11 million.

• At September 30, 2009, we had guarantees outstanding for our portion of joint venture debt obligations, which have terms of up to 16 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 (APLNG) from Origin Energy in October 2008, we agreed to participate, if and when 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 eight to 22 years. Our maximum potential amount of future payments, or cost of volume delivery, under these guarantees is estimated to be $930 million ($1,940 million in the event of intentional or reckless breach) 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 partners do not make necessary equity contributions into APLNG.

• We have other guarantees with maximum future potential payment amounts totaling $520 million, which consist primarily of dealer and jobber loan guarantees to support our marketing business, guarantees to fund the short-term cash liquidity deficits of certain joint ventures, a guarantee of minimum charter revenue for two LNG vessels, one small construction completion guarantee, guarantees relating to the startup of a refining joint venture, guarantees of the lease payment obligations of a joint venture, and guarantees of the residual value of leased corporate aircraft. At September 30, 2009, the carrying value of these guarantees to third-party lenders was $1 million. These guarantees generally extend up to 15 years or life of the venture.

In the third quarter of 2009, we sold our remaining ownership interest in four Keystone Pipeline entities (Keystone) to TransCanada Corporation. As a result, we no longer have any financial guarantees related to Keystone.

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

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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, 2009, was $415 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 $254 million of environmental accruals for known contamination that are included in asset retirement obligations and accrued environmental costs at September 30, 2009. For additional information about environmental liabilities, see Note 12—Contingencies and Commitments.

Note 12—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 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 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 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

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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 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 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 for those acquired in a purchase business combination, which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable future costs will be incurred and these costs can be reasonably estimated. At September 30, 2009, our consolidated balance sheet included a total environmental accrual of $1,001 million, compared with $979 million at December 31, 2008. We expect to incur the majority of these expenditures within the next 30 years. We have not reduced these accruals for possible insurance recoveries. In the future, we may be involved in additional environmental assessments, cleanups and proceedings.

Legal Proceedings
Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases 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 our cases, 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, 2009, we had performance obligations secured by letters of credit of $2,087 million (of which $40 million was issued under the provisions of our revolving credit facilities, 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.

Note 13—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 exploit market opportunities. Since we are not currently using 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.

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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 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 sale 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 sale 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 sale 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.

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, 2009												December 31, 2008
	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Assets
Commodity derivatives	$	3,542			2,086			55			5,683			4,994			2,874			112			7,980
Foreign exchange derivatives		-			67			-			67			-			97			-			97
Total assets		3,542			2,153			55			5,750			4,994			2,971			112			8,077
Liabilities
Commodity derivatives		(3,678	)		(1,767	)		(18	)		(5,463	)		(5,221	)		(2,497	)		(72	)		(7,790	)
Foreign exchange derivatives		-			(63	)		-			(63	)		-			(93	)		-			(93	)
Total liabilities		(3,678	)		(1,830	)		(18	)		(5,526	)		(5,221	)		(2,590	)		(72	)		(7,883	)
Net assets (liabilities)	$	(136	)		323			37			224			(227	)		381			40			194

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.

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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
	2009			2008			2009			2008
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Beginning balance	$	74			(56	)		40			(34	)
Total net gains (losses), realized and unrealized, included in earnings		(10	)		45			8			(8	)
Net purchases, issuances and settlements		(20	)		20			(47	)		44
Net transfers in (out) of Level 3		(7	)		3			36			10
Ending balance	$	37			12			37			12

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

	Millions of Dollars
	2009								2008
				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	$	(10	)		-		(10	)		55			(10	)		45
Change in unrealized gains (losses) relating to assets held at September 30	$	3			-		3			16			-			16
Change in unrealized gains (losses) relating to liabilities held at September 30	$	(16	)		-		(16	)		(9	)		(7	)		(16	)
Nine Months Ended September 30
Total gains (losses) included in earnings	$	8			-		8			(3	)		(5	)		(8	)
Change in unrealized gains (losses) relating to assets held at September 30	$	11			-		11			8			-			8
Change in unrealized gains (losses) relating to liabilities held at September 30	$	(21	)		-		(21	)		(4	)		(5	)		(9	)

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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 our 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.

The fair value of commodity derivative assets and liabilities at September 30, 2009, and the line items where they appear on our consolidated balance sheet were:

	Millions
	of Dollars
Assets
Prepaid expenses and other current assets	$	5,254
Other assets		440
Liabilities
Other accruals		5,102
Other liabilities and deferred credits		372

Hedge accounting has not been used for any items inthe table unless specified otherwise. 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 during the three- and nine-month periods ended September 30, 2009, 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
Sales and other operating revenues	$	727			1,118
Other income		(4	)		21
Purchased crude oil, natural gas and products		(599	)		(1,554	)

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

The table below summarizes our material net exposures as of September 30, 2009, 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)
Commodity
Crude oil, refined products and natural gas liquids (millions of barrels)		(43	)
Natural gas, power and carbon dioxide emissions (billions of cubic feet)
Flat price		(68	)
Basis		135

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Currency Exchange Rate Derivative Contracts—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 and dividends.

The fair value of foreign currency derivative assets and liabilities open at September 30, 2009, and the line items where they appear on our consolidated balance sheet were:

		Millions
	of Dollars
Assets
Prepaid expenses and other current assets		$	60
Other assets			7
Liabilities
Other accruals			48
Other liabilities and deferred credits			15

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

Gains and losses from foreign currency derivatives during the three- and nine-month periods ended September 30, 2009, 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
Foreign currency transaction (gains) losses	$	40		(133	)

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

As of September 30, 2009, we had the following net position of outstanding foreign currency swap contracts, entered into primarily to hedge price exposure in our international operations.

	In Millions
	Notional*
Foreign Currency Swaps
Sell U.S. dollar, buy other currencies**	USD	3,462
Buy British pound, sell euro	GBP	251

*Denominated in U.S. dollars (USD) and British pounds (GBP).

**Primarily euro (EUR), Canadian dollar (CAD), Norwegian krone (NOK), and British pound (GBP).

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

The credit risk from our over-the-counter derivative contracts, such as forwards and swaps, derives from the counterparty to the transaction, typically a major bank or financial institution. 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 ICE Futures.

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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.

The aggregate fair value of all derivative instruments with such credit-risk-related contingent features that were in a liability position on September 30, 2009, was $365 million, for which no collateral was posted. If our credit rating were lowered one level from its “A” rating (per Standard and Poors) on September 30, 2009, 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 $365 million of additional collateral, either in the form of 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, 2009, effective yield rate of 2.91 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.

• 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.

• Forward-exchange contracts: Fair value is estimated by comparing the contract rate to the forward rate in effect on September 30, 2009, and approximates the exit price at that date.

Certain of our commodity derivative and financial instruments at September 30, 2009, were:

	Millions of Dollars
	Carrying Amount			Fair Value
Financial assets
Foreign currency derivatives		$	67		67
Commodity derivatives			1,166		1,166
Financial liabilities
Total debt, excluding capital leases			30,436		32,565
Joint venture acquisition obligation			5,828		6,410
Foreign currency derivatives			63		63
Commodity derivatives			863		863

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 commodity

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derivative assets appear net of $85 million of obligations to return cash collateral, while the commodity derivative liabilities appear net of $168 million of rights to reclaim cash collateral. No collateral was deposited or held for the foreign currency derivatives.

Note 14—Comprehensive Income

ConocoPhillips’ comprehensive income was as follows:

	Millions of Dollars
	Three Months Ended						Nine Months Ended
	September 30						September 30
	2009			2008			2009			2008
Net income	$	1,520			5,203			3,690			14,817
After-tax changes in:
Defined benefit pension plans
Net prior service cost		3			7			9			(3	)
Net actuarial loss		33			10			100			17
Nonsponsored plans		4			4			2			8
Foreign currency translation adjustments		1,672			(1,584	)		4,473			(1,841	)
Hedging activities		2			1			3			1
Comprehensive income		3,234			3,641			8,277			12,999
Less: comprehensive income attributable to noncontrolling interests		(17	)		(15	)		(49	)		(51	)
Comprehensive income attributable to ConocoPhillips	$	3,217			3,626			8,228			12,948

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

	Millions of Dollars
	September 30			December 31
	2009			2008
Defined benefit pension plans	$	(1,323	)		(1,434	)
Foreign currency translation adjustments		4,042			(431	)
Deferred net hedging loss		(7	)		(10	)
Accumulated other comprehensive income (loss)	$	2,712			(1,875	)

None of the items within accumulated other comprehensive income (loss) related to noncontrolling interests.

Note 15—Cash Flow Information

	Millions of Dollars
	Nine Months Ended
	September 30
	2009		2008
Cash Payments
Interest	$	647		475
Income taxes		4,807		10,250

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Note 16—Employee Benefit Plans

Pension and Postretirement Plans

	Millions of Dollars
	Pension Benefits												Other Benefits
Components of Net Periodic Benefit Cost	2009						2008						2009			2008
	U.S.			Int’l.			U.S.			Int’l.
Three Months Ended September 30
Service cost	$	48			20			46			24			2			2
Interest cost		69			38			61			44			12			8
Expected return on plan assets		(46	)		(33	)		(55	)		(45	)		-			-
Amortization of prior service cost		3			-			4			-			2			3
Recognized net actuarial (gain) loss		47			9			15			3			(4	)		(3	)
Net periodic benefit costs	$	121			34			71			26			12			10
Nine Months Ended September 30
Service cost	$	145			58			140			71			6			9
Interest cost		208			106			185			134			35			36
Expected return on plan assets		(138	)		(92	)		(167	)		(134	)		-			-
Amortization of prior service cost		8			-			8			-			6			8
Recognized net actuarial (gain) loss		140			26			48			9			(11	)		(13	)
Net periodic benefit costs	$	363			98			214			80			36			40

During the first nine months of 2009, we contributed $721 million to our domestic benefit plans and $116 million to our international benefit plans. We currently expect to make additional contributions of approximately $29 million to our domestic benefit plans and $24 million to our international benefit plans for totals of $750 million and $140 million, respectively, in 2009.

Severance Accrual
As a result of the current business environment’s impact on our operating and capital plans, a reduction in our overall employee work force is occurring during 2009. Various business units and staff groups recorded accruals in the fourth quarter of 2008 for severance and related employee benefits totaling $162 million. The following table summarizes our severance accrual activity:

	Millions of Dollars
	September 30			December 31
	2009			2008
Beginning balance	$	162			-
Accruals		5			162
Benefit payments		(72	)		-
Accrual reversals		(64	)		-
Ending balance	$	31			162

The remaining balance at September 30, 2009, of $31 million is classified as short-term.

20

Note 17—Related Party Transactions

Significant transactions with related parties were:

	Millions of Dollars
	Three Months Ended				Nine Months Ended
	September 30				September 30
	2009		2008		2009		2008
Operating revenues and other income (a)	$	1,871		3,944		5,236		11,115
Purchases (b)		3,614		6,038		9,264		16,129
Operating expenses and selling, general and administrative expenses (c)		85		142		241		385
Net interest expense (d)		19		15		58		55

(a)	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. 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 Merey Sweeny, L.P. (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 Refining. We purchased natural gas and natural gas liquids from DCP Midstream and CPChem for use in our refinery processes and other feedstocks from various affiliates. We purchased crude oil from LUKOIL 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 crude oil 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.

21

Note 18—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, 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 OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. At September 30, 2009, our ownership interest was 20 percent based on issued shares and 20.09 percent based on estimated shares outstanding.
5)	Chemicals—This segment manufactures and markets petrochemicals and plastics on a worldwide basis. The Chemicals segment consists of our 50 percent equity investment in 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.

22

Analysis of Results by Operating Segment

	Millions of Dollars
	Three Months Ended						Nine Months Ended
	September 30						September 30
	2009			2008			2009			2008
Sales and Other Operating Revenues
E&P
United States	$	5,655			15,320			17,148			42,831
International		5,908			10,333			17,607			27,245
Intersegment eliminations—U.S.		(1,225	)		(2,263	)		(3,271	)		(6,900	)
Intersegment eliminations—international		(1,998	)		(3,005	)		(4,783	)		(8,852	)
E&P		8,340			20,385			26,701			54,324
Midstream
Total sales		1,325			2,112			3,220			5,854
Intersegment eliminations		(76	)		(52	)		(177	)		(171	)
Midstream		1,249			2,060			3,043			5,683
R&M
United States		21,070			33,778			52,485			97,989
International		9,637			14,065			24,469			38,960
Intersegment eliminations—U.S.		(157	)		(293	)		(414	)		(797	)
Intersegment eliminations—international		(18	)		(17	)		(38	)		(37	)
R&M		30,532			47,533			76,502			136,115
LUKOIL Investment		-			-			-			-
Chemicals		2			2			8			8
Emerging Businesses
Total sales		134			303			421			791
Intersegment eliminations		(90	)		(244	)		(331	)		(600	)
Emerging Businesses		44			59			90			191
Corporate and Other		6			5			18			17
Consolidated sales and other operating revenues	$	40,173			70,044			106,362			196,338
Net Income (Loss) Attributable to ConocoPhillips
E&P
United States	$	327			1,606			836			4,807
International		651			2,322			1,567			6,007
Total E&P		978			3,928			2,403			10,814
Midstream		62			173			216			472
R&M
United States		73			524			133			1,546
International		26			325			119			487
Total R&M		99			849			252			2,033
LUKOIL Investment		545			438			1,275			1,922
Chemicals		104			46			194			116
Emerging Businesses		(2	)		35			-			55
Corporate and Other		(283	)		(281	)		(699	)		(646	)
Consolidated net income attributable to ConocoPhillips	$	1,503			5,188			3,641			14,766

23

	Millions of Dollars
	September 30		December 31
	2009		2008
Total Assets
E&P
United States	$	35,773		36,962
International		63,642		58,912
Total E&P		99,415		95,874
Midstream		1,956		1,455
R&M
United States		25,277		22,554
International		9,604		7,942
Goodwill		3,715		3,778
Total R&M		38,596		34,274
LUKOIL Investment		6,696		5,455
Chemicals		2,400		2,217
Emerging Businesses		1,072		924
Corporate and Other		2,292		2,666
Consolidated total assets	$	152,427		142,865

Note 19—Income Taxes

Our effective tax rates for the third quarter and first nine months of 2009 were 48 percent and 50 percent, respectively, compared with 45 percent for each of the same two periods of 2008. The change in the effective tax rate for the third quarter and nine-month periods of 2009, versus the corresponding periods of 2008, was primarily due to a higher proportion of income earned in higher tax jurisdictions in 2009. The effective tax rate in excess of the domestic federal statutory rate of 35 percent was primarily due to foreign taxes.

Note 20—New Accounting Standards

In June 2009, the FASB issued SFAS No. 166, “Accounting for Transfers of Financial Assets, an amendment of FASB Statement No. 140.” This Statement will be codified primarily 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 is effective January 1, 2010, and we do not expect any significant impact to our consolidated financial statements.

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 will be codified primarily into FASB ASC Topic 810, “Consolidation.” More specifically, SFAS No. 167 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 is effective January 1, 2010. We are currently evaluating the impact on our consolidated financial statements.

24

In December 2008, the FASB issued FSP FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets,” to improve the transparency associated with disclosures about the plan assets of a defined benefit pension or other postretirement plan. This Statement was codified into FASB ASC Topic 715, “Compensation—Retirement Benefits.” Topic 715 requires the disclosure of each major asset category at fair value using the fair value hierarchy. This Topic is effective for annual financial statements beginning with the 2009 fiscal year, but will not impact our consolidated financial statements, other than requiring additional disclosures.

25

Supplementary Information—Condensed Consolidating Financial Information

We have various cross guarantees among ConocoPhillips, ConocoPhillips Company, ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada Funding Company II, with respect to publicly held debt securities. ConocoPhillips Company is wholly owned by ConocoPhillips. ConocoPhillips Australia Funding Company is an indirect, wholly owned subsidiary of ConocoPhillips Company. ConocoPhillips Canada Funding Company I and ConocoPhillips Canada Funding Company II are indirect, wholly owned subsidiaries of ConocoPhillips. ConocoPhillips and ConocoPhillips Company have fully and unconditionally guaranteed the payment obligations of ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada Funding Company II, with respect to their publicly held debt securities. Similarly, ConocoPhillips has fully and unconditionally guaranteed the payment obligations of ConocoPhillips Company with respect to its publicly held debt securities. In addition, ConocoPhillips Company has fully and unconditionally guaranteed the payment obligations of ConocoPhillips with respect to its publicly held debt securities. All guarantees are joint and several. The following condensed consolidating financial information presents the results of operations, financial position and cash flows for:

• ConocoPhillips, ConocoPhillips Company, ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada Funding Company II (in each case, reflecting investments in subsidiaries utilizing the equity method of accounting).

• All other 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.

26

	Millions of Dollars
	Three Months Ended September 30, 2009
						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	$	-			24,981		-		-			-			15,192			-			40,173
Equity in earnings of affiliates		1,609			1,728		-		-			-			700			(3,022	)		1,015
Other income (loss)		1			150		-		-			-			(34	)		-			117
Intercompany revenues		13			264		11		20			12			5,377			(5,697	)		-
Total Revenues and Other Income		1,623			27,123		11		20			12			21,235			(8,719	)		41,305
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		1,446			1,718		1		(76	)		(70	)		2,950			(3,022	)		2,947
Provision for income taxes		(57	)		109		-		4			(3	)		1,374			-			1,427
Net income (loss)		1,503			1,609		1		(80	)		(67	)		1,576			(3,022	)		1,520
Less: net income attributable to noncontrolling interests		-			-		-		-			-			(17	)		-			(17	)
Net Income (Loss) Attributable to ConocoPhillips	$	1,503			1,609		1		(80	)		(67	)		1,559			(3,022	)		1,503
Income Statement	Three Months Ended September 30, 2008
Revenues and Other Income
Sales and other operating revenues	$	-			45,549		-		-			-			24,495			-			70,044
Equity in earnings of affiliates		5,256			3,856		-		-			-			1,181			(9,079	)		1,214
Other income (loss)		(1	)		135		-		-			-			(19	)		-			115
Intercompany revenues		1			1,166		20		22			14			9,720			(10,943	)		-
Total Revenues and Other Income		5,256			50,706		20		22			14			35,377			(20,022	)		71,373
Costs and Expenses
Purchased crude oil, natural gas and products		-			41,990		-		-			-			18,180			(10,562	)		49,608
Production and operating expenses		-			1,243		-		-			-			1,841			(25	)		3,059
Selling, general and administrative expenses		7			339		-		-			-			180			(13	)		513
Exploration expenses		-			31		-		-			-			236			-			267
Depreciation, depletion and amortization		-			393		-		-			-			1,968			-			2,361
Impairments		-			-		-		-			-			57			-			57
Taxes other than income taxes		-			1,280		-		-			-			4,396			(57	)		5,619
Accretion on discounted liabilities		-			14		-		-			-			100			-			114
Interest and debt expense		97			132		17		19			14			246			(286	)		239
Foreign currency transaction (gains) losses		-			18		-		(71	)		(99	)		206			-			54
Total Costs and Expenses		104			45,440		17		(52	)		(85	)		27,410			(10,943	)		61,891
Income before income taxes		5,152			5,266		3		74			99			7,967			(9,079	)		9,482
Provision for income taxes		(36	)		618		1		7			17			3,672			-			4,279
Net income		5,188			4,648		2		67			82			4,295			(9,079	)		5,203
Less: net income attributable to noncontrolling interests		-			-		-		-			-			(15	)		-			(15	)
Net Income Attributable to ConocoPhillips	$	5,188			4,648		2		67			82			4,280			(9,079	)		5,188

27

	Millions of Dollars
	Nine Months Ended September 30, 2009
							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	$	-			64,437			-		-			-			41,925			-			106,362
Equity in earnings of affiliates		3,925			4,238			-		-			-			1,714			(7,371	)		2,506
Other income (loss)		-			469			-		-			-			(122	)		-			347
Intercompany revenues		29			866			40		57			35			12,850			(13,877	)		-
Total Revenues and Other Income		3,954			70,010			40		57			35			56,367			(21,248	)		109,215
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		3,488			4,224			4		(133	)		(183	)		7,334			(7,371	)		7,363
Provision for income taxes		(153	)		299			1		6			(20	)		3,540			-			3,673
Net income (loss)		3,641			3,925			3		(139	)		(163	)		3,794			(7,371	)		3,690
Less: net income attributable to noncontrolling interests		-			-			-		-			-			(49	)		-			(49	)
Net Income (Loss) Attributable to ConocoPhillips	$	3,641			3,925			3		(139	)		(163	)		3,745			(7,371	)		3,641
Income Statement	Nine Months Ended September 30, 2008
Revenues and Other Income
Sales and other operating revenues	$	-			128,145			-		-			-			68,193			-			196,338
Equity in earnings of affiliates		14,907			10,713			-		-			-			3,935			(25,170	)		4,385
Other income (loss)		(2	)		622			-		-			-			(65	)		-			555
Intercompany revenues		25			2,798			63		67			41			25,463			(28,457	)		-
Total Revenues and Other Income		14,930			142,278			63		67			41			97,526			(53,627	)		201,278
Costs and Expenses
Purchased crude oil, natural gas and products		-			117,520			-		-			-			48,363			(27,241	)		138,642
Production and operating expenses		-			3,690			-		-			-			5,266			(95	)		8,861
Selling, general and administrative expenses		14			1,124			-		-			-			576			(46	)		1,668
Exploration expenses		-			131			-		-			-			733			-			864
Depreciation, depletion and amortization		-			1,144			-		-			-			5,604			-			6,748
Impairments		-			21			-		-			-			61			-			82
Taxes other than income taxes		-			3,819			-		-			-			12,927			(176	)		16,570
Accretion on discounted liabilities		-			43			-		-			-			271			-			314
Interest and debt expense		225			457			57		58			40			718			(899	)		656
Foreign currency transaction (gains) losses		-			16			-		(85	)		(106	)		186			-			11
Total Costs and Expenses		239			127,965			57		(27	)		(66	)		74,705			(28,457	)		174,416
Income before income taxes		14,691			14,313			6		94			107			22,821			(25,170	)		26,862
Provision for income taxes		(75	)		1,605			2		(6	)		4			10,515			-			12,045
Net income		14,766			12,708			4		100			103			12,306			(25,170	)		14,817
Less: net income attributable to noncontrolling interests		-			-			-		-			-			(51	)		-			(51	)
Net Income Attributable to ConocoPhillips	$	14,766			12,708			4		100			103			12,255			(25,170	)		14,766

28

	Millions of Dollars
	September 30, 2009
						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	$	-			185		-			13			1			506		(64	)		641
Accounts and notes receivable		25			5,849		-			-			-			12,911		(6,255	)		12,530
Inventories		-			3,566		-			-			-			2,702		-			6,268
Prepaid expenses and other current assets		11			1,219		-			6			4			1,583		(9	)		2,814
Total Current Assets		36			10,819		-			19			5			17,702		(6,328	)		22,253
Investments, loans and long-term receivables*		69,534			87,167		770			1,363			925			48,112		(170,021	)		37,850
Net properties, plants and equipment		-			19,675		-			-			-			67,461		-			87,136
Goodwill		-			3,715		-			-			-			-		-			3,715
Intangibles		-			773		-			-			-			58		-			831
Other assets		56			218		2			4			20			400		(58	)		642
Total Assets	$	69,626			122,367		772			1,386			950			133,733		(176,407	)		152,427
Liabilities and Equity
Accounts payable	$	1			10,036		2			3			2			11,073		(6,255	)		14,862
Short-term debt		1,300			1,282		-			-			-			214		-			2,796
Accrued income and other taxes		-			399		-			(2	)		(1	)		3,448		-			3,844
Employee benefit obligations		-			518		-			-			-			223		-			741
Other accruals		172			814		19			32			22			1,363		(9	)		2,413
Total Current Liabilities		1,473			13,049		21			33			23			16,321		(6,264	)		24,656
Long-term debt		13,310			4,061		749			1,250			849			7,443		-			27,662
Asset retirement obligations and accrued environmental costs		-			1,164		-			-			-			6,672		-			7,836
Joint venture acquisition obligation		-			-		-			-			-			5,177		-			5,177
Deferred income taxes		(4	)		2,573		-			14			15			15,696		-			18,294
Employee benefit obligations		-			2,862		-			-			-			800		-			3,662
Other liabilities and deferred credits*		125			24,846		-			27			15			16,285		(38,255	)		3,043
Total Liabilities		14,904			48,555		770			1,324			902			68,394		(44,519	)		90,330
Retained earnings		25,668			8,717		-			(14	)		4			9,082		(11,276	)		32,181
Other common stockholders’ equity		29,054			65,095		2			76			44			55,670		(120,612	)		29,329
Noncontrolling interests		-			-		-			-			-			587		-			587
Total Liabilities and Equity	$	69,626			122,367		772			1,386			950			133,733		(176,407	)		152,427
*Includes intercompany loans.
Balance Sheet	December 31, 2008
Assets
Cash and cash equivalents	$	-			8		-			10			1			750		(14	)		755
Accounts and notes receivable		13			10,541		15			-			-			21,314		(19,888	)		11,995
Inventories		-			2,909		-			-			-			2,287		(101	)		5,095
Prepaid expenses and other current assets		10			1,170		-			14			10			1,794		-			2,998
Total Current Assets		23			14,628		15			24			11			26,145		(20,003	)		20,843
Investments, loans and long-term receivables*		61,144			83,645		1,699			1,183			802			44,629		(160,203	)		32,899
Net properties, plants and equipment		-			19,017		-			-			-			64,928		2			83,947
Goodwill		-			3,778		-			-			-			-		-			3,778
Intangibles		-			784		-			-			-			62		-			846
Other assets		13			243		2			109			183			286		(284	)		552
Total Assets	$	61,180			122,095		1,716			1,316			996			136,050		(180,488	)		142,865
Liabilities and Equity
Accounts payable	$	-			17,566		-			2			1			16,309		(19,888	)		13,990
Short-term debt		-			301		950			-			-			68		(949	)		370
Accrued income and other taxes		-			233		-			(1	)		(1	)		4,042		-			4,273
Employee benefit obligations		-			702		-			-			-			237		-			939
Other accruals		25			883		18			15			10			1,280		(23	)		2,208
Total Current Liabilities		25			19,685		968			16			10			21,936		(20,860	)		21,780
Long-term debt		7,703			5,364		749			1,250			848			10,221		950			27,085
Asset retirement obligations and accrued environmental costs		-			1,101		-			-			-			6,062		-			7,163
Joint venture acquisition obligation		-			-		-			-			-			5,669		-			5,669
Deferred income taxes		(4	)		2,882		-			9			34			15,258		(12	)		18,167
Employee benefit obligations		-			3,367		-			-			-			760		-			4,127
Other liabilities and deferred credits*		4,954			24,609		-			-			-			16,976		(43,930	)		2,609
Total Liabilities		12,678			57,008		1,717			1,275			892			76,882		(63,852	)		86,600
Retained earnings		24,130			4,792		(3	)		125			167			7,234		(5,803	)		30,642
Other common stockholders’ equity		24,372			60,295		2			(84	)		(63	)		50,834		(110,833	)		24,523
Noncontrolling interests		-			-		-			-			-			1,100		-			1,100
Total Liabilities and Equity	$	61,180			122,095		1,716			1,316			996			136,050		(180,488	)		142,865

*Includes intercompany loans.

29

	Millions of Dollars
	Nine Months Ended September 30, 2009
							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	$	(4,739	)		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 company 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
Statement of Cash Flows	Nine Months Ended September 30, 2008
Cash Flows From Operating Activities
Net Cash Provided by (Used in) Operating Activities	$	8,852			1,769			6			(1	)		-		11,922			(3,012	)		19,536
Cash Flows From Investing Activities
Capital expenditures and investments		-			(3,901	)		-			-			-		(7,341	)		707			(10,535	)
Proceeds from asset dispositions		-			251			-			-			-		658			(180	)		729
Long-term advances/loans—related parties		-			(400	)		-			-			-		(2,812	)		3,031			(181	)
Collection of advances/loans—related parties		-			224			-			-			-		12			(221	)		15
Other		-			(183	)		-			-			-		(3	)		-			(186	)
Net Cash Provided by (Used in) Investing Activities		-			(4,009	)		-			-			-		(9,486	)		3,337			(10,158	)
Cash Flows From Financing Activities
Issuance of debt		2,136			2,671			-			-			-		488			(3,031	)		2,264
Repayment of debt		(1,500	)		(350	)		-			-			-		(228	)		221			(1,857	)
Issuance of company common stock		182			-			-			-			-		-			-			182
Repurchase of company common stock		(7,500	)		-			-			-			-		-			-			(7,500	)
Dividends paid on company common stock		(2,159	)		-			(6	)		-			-		(3,134	)		3,140			(2,159	)
Other		(11	)		126			-			-			-		(14	)		(527	)		(426	)
Net Cash Provided by (Used in) Financing Activities		(8,852	)		2,447			(6	)		-			-		(2,888	)		(197	)		(9,496	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents		-			(158	)		-			-			-		(64	)		-			(222	)
Net Change in Cash and Cash Equivalents		-			49			-			(1	)		-		(516	)		128			(340	)
Cash and cash equivalents at beginning of period		-			195			-			7			1		1,626			(373	)		1,456
Cash and Cash Equivalents at End of Period	$	-			244			-			6			1		1,110			(245	)		1,116

30

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

Management’s Discussion and Analysis contains forward-looking statements including, without limitation, statements relating to our plans, strategies, objectives, expectations, and intentions, that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “intends,” “believes,” “expects,” “plans,” “scheduled,” “should,” “anticipates,” “estimates,” and similar expressions identify forward-looking statements. We do not undertake to update, revise or correct any of the forward-looking information. Readers are cautioned that such forward-looking statements should be read in conjunction with the disclosures under the heading “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995” beginning on page 49.

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, 2009, we had approximately 30,100 employees and total assets of $152 billion.

The energy industry continued to be characterized by economic volatility during the third quarter and first nine months of 2009. The price of West Texas Intermediate (WTI) benchmark crude oil peaked during mid-2008 at almost $150 per barrel, and fell sharply throughout the remainder of the year to the low-$30-per-barrel range. Since the end of 2008, crude oil prices have trended upward, with WTI averaging $68.19 per barrel in the third quarter of 2009, or $8.65 higher than the second quarter of 2009. The improvement in crude oil prices during 2009 was influenced by expectations of stabilization and eventual recovery of the world economy.

In the United States, industry natural gas prices for Henry Hub decreased during the third quarter of 2009, averaging $3.39 per million British thermal units, down $0.12 compared with the second quarter of 2009, and down $6.86 compared with the third quarter of 2008. Domestic natural gas prices trended downward mostly due to continued strong natural gas production in the Lower 48, primarily as a result of unconventional natural gas production, and lower demand due to the U.S. recession. As a result of the changes in supply and demand, natural gas storage levels are higher than both the five-year average and the levels at the end of the third quarter of 2008.

Against this economic backdrop, our Exploration and Production (E&P) segment had earnings of $978 million in the third quarter of 2009. This compares with E&P earnings of $725 million in the second quarter of 2009 and $3,928 million in the third quarter of 2008.

Global refining margins remained weak in the third quarter of 2009, as demand, particularly for distillates, continued to be suppressed by the global economic slowdown. In addition, the compressed differential in prices for high-quality crude oil, compared with those of lower-quality crude oil, reduced margins for those refineries configured to capitalize on the ability to process lower-quality crudes. Weak refining margins significantly impacted our Refining and Marketing (R&M) segment, which reported earnings of $99 million in the third quarter of 2009, compared with a loss of $52 million in the second quarter of 2009 and earnings of $849 million in the third quarter of 2008.

Our LUKOIL Investment segment had earnings of $545 million in the third quarter of 2009, compared with $682 million in the second quarter of 2009, and $438 million in the third quarter of 2008. For the nine-month periods, our equity earnings from LUKOIL were $1,275 million in 2009, compared with $1,922 million in 2008. These results indicate LUKOIL was also negatively impacted by lower commodity prices and refining margins.

31

RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three- and nine-month periods ended September 30, 2009, is based on a comparison with the corresponding periods of 2008.

Consolidated Results

A summary of earnings (loss) by business segment follows:

	Millions of Dollars
	Three Months Ended						Nine Months Ended
	September 30						September 30
	2009			2008			2009			2008
Exploration and Production (E&P)	$	978			3,928			2,403			10,814
Midstream		62			173			216			472
Refining and Marketing (R&M)		99			849			252			2,033
LUKOIL Investment		545			438			1,275			1,922
Chemicals		104			46			194			116
Emerging Businesses		(2	)		35			-			55
Corporate and Other		(283	)		(281	)		(699	)		(646	)
Net income attributable to ConocoPhillips	$	1,503			5,188			3,641			14,766

Earnings were $1,503 million in the third quarter of 2009, compared with $5,188 million in the third quarter of 2008. For the nine-month periods ended September 30, 2009 and 2008, earnings were $3,641 million and $14,766 million, respectively. The decrease from both 2008 periods was primarily the result of:

• Substantially lower prices for crude oil, natural gas and natural gas liquids in our E&P segment.

• Lower results from our R&M segment, reflecting lower refining margins.

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

Income Statement Analysis

Sales and other operating revenues decreased 43 percent in the third quarter of 2009 and 46 percent in the nine-month period, whilepurchased crude oil, natural gas and products decreased 44 percent and 48 percent, respectively. These decreases were mainly the result of significantly lower prices for petroleum products, crude oil, natural gas and natural gas liquids.

Equity in earnings of affiliates decreased 16 percent in the third quarter of 2009, primarily due to reduced earnings from DCP Midstream, LLC. Equity earnings decreased 43 percent in the nine-month period, reflecting reduced earnings from LUKOIL; DCP Midstream; FCCL Partnership; Merey Sweeny, L.P. (MSLP); Malaysian Refining Company Sdn. Bhd.; and WRB Refining LLC. The decreases were mainly the result of lower commodity prices and refining margins.

Other income decreased 37 percent during the first nine months of 2009. The decrease was primarily due to 2008 gains related to asset dispositions in our E&P and R&M segments.

Production and operating expenses decreased 17 percent in the third quarter of 2009 and 14 percent in the nine-month period. Contributing to these decreases were lower utilities costs, favorable foreign exchange impacts, and our emphasis on cost reduction.

32

Selling, general and administrative expenses decreased 17 percent in both comparative periods of 2009, mostly due to reduced expenses as a result of disposition of U.S. and international marketing assets.

Exploration expenses increased 45 percent in the third quarter of 2009, predominantly due to higher dry hole costs.

Taxes other than income taxes decreased 25 percent in the third quarter of 2009 and 31 percent in the nine-month period, primarily due to lower production taxes resulting from lower crude oil prices, as well as reduced excise taxes on petroleum product sales.

Interest and debt expense increased 41 percent and 39 percent in the third quarter and first nine months of 2009 as a result of a higher average debt level, partially offset by lower interest rates. Interest expense also increased in the nine month period as a result of lower capitalized interest.

33

Segment Results

E&P

	Three Months Ended					Nine Months Ended
	September 30					September 30
	2009			2008		2009			2008
	Millions of Dollars
Net Income (Loss) Attributable to ConocoPhillips
Alaska	$	356			556		1,004			1,859
Lower 48		(29	)		1,050		(168	)		2,948
United States		327			1,606		836			4,807
International		651			2,322		1,567			6,007
	$	978			3,928		2,403			10,814
	Dollars Per Unit
Average Sales Prices
Crude oil (per barrel)
United States	$	66.22			118.90		53.43			110.26
International		67.56			110.84		55.85			108.94
Total consolidated		67.01			114.20		54.80			109.53
Equity affiliates*		58.07			88.32		48.85			81.74
Worldwide E&P		65.92			112.19		54.15			107.84
Natural gas (per thousand cubic feet)
United States		2.99			8.64		3.27			8.66
International		4.26			9.13		4.81			9.14
Total consolidated		3.69			8.91		4.14			8.93
Equity affiliates*		2.57			-		2.26			-
Worldwide E&P		3.67			8.91		4.10			8.93
Natural gas liquids (per barrel)
United States		32.45			68.84		28.28			64.53
International		37.48			68.78		33.06			67.46
Total consolidated		34.62			68.81		30.33			65.85
Worldwide E&P		34.62			68.81		30.33			65.85
	Millions of Dollars
Worldwide Exploration Expenses
General administrative; geological and geophysical; and lease rentals	$	153			149		383			465
Leasehold impairment		71			60		163			179
Dry holes		162			58		308			220
	$	386			267		854			864

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

34

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2009		2008		2009		2008
	Thousands of Barrels Daily
Operating Statistics
Crude oil produced
Alaska		218		218		236		239
Lower 48		91		85		92		92
United States		309		303		328		331
Europe		207		221		223		205
Asia Pacific		110		87		114		88
Canada		24		25		24		24
Middle East and Africa		75		73		75		78
Other areas		-		9		5		9
Total consolidated		725		718		769		735
Equity affiliates*
Canada		45		32		40		29
Russia and Caspian		59		31		54		21
		829		781		863		785
Natural gas liquids produced
Alaska		11		13		16		16
Lower 48		77		74		75		73
United States		88		87		91		89
Europe		14		15		17		19
Asia Pacific		18		19		17		17
Canada		23		24		24		25
Middle East and Africa		3		3		2		3
		146		148		151		153
	Millions of Cubic Feet Daily
Natural gas produced**
Alaska		105		102		93		100
Lower 48		1,938		1,971		1,992		1,989
United States		2,043		2,073		2,085		2,089
Europe		702		847		850		918
Asia Pacific		726		648		719		617
Canada		1,063		1,061		1,101		1,072
Middle East and Africa		124		122		119		114
Other areas		-		18		-		19
Total consolidated		4,658		4,769		4,874		4,829
Equity affiliates*
Asia Pacific		88		-		86		-
		4,746		4,769		4,960		4,829
	Thousands of Barrels Daily
Mining operations
Syncrude produced		25		24		21		21

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

35

The E&P segment explores for, produces, transports and markets crude oil, natural gas and natural gas liquids on a worldwide basis. It also mines deposits of oil sands in Canada to extract bitumen and upgrade it into a synthetic crude oil. At September 30, 2009, 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.

Earnings from the E&P segment decreased 75 percent and 78 percent in the third quarter and first nine months of 2009, primarily due to substantially lower crude oil, natural gas and natural gas liquids prices. This decrease was partially offset by lower Alaska and Lower 48 production taxes due to lower prices, higher international volumes and improved operating costs. See the “Business Environment and Executive Overview” section for additional information on industry crude oil and natural gas prices.

U.S. E&P
Earnings from our U.S. E&P operations decreased 80 percent in the third quarter and 83 percent in the first nine months of 2009 due to significantly lower crude oil, natural gas and natural gas liquids prices, partially offset by lower production taxes and lower operating costs.

U.S. E&P production on a barrel-of-oil-equivalent (BOE) basis averaged 737,000 BOE per day in the third quarter of 2009; this compares with 736,000 in the third quarter of 2008. Less unplanned downtime and improved well performance were mostly offset by field decline.

International E&P
Earnings from our international E&P operations decreased 72 percent in the third quarter and 74 percent in the first nine months of 2009, primarily as a result of significantly lower crude oil, natural gas and natural gas liquids prices, partially offset by higher volumes and lower operating costs.

International E&P production averaged 1,029,000 BOE per day in the third quarter of 2009, an increase of 4 percent from 988,000 in the third quarter of 2008. The increase was predominantly due to new production in China, Russia, Australia, Canada, Vietnam, the United Kingdom and Norway. In addition, production increased due to less unplanned downtime and impacts from the royalty framework in Alberta, Canada. These increases were partially offset by field decline and planned downtime. Our Syncrude mining operations produced 25,000 barrels per day in the third quarter of 2009, compared with 24,000 barrels per day in the third quarter of 2008.

36

Midstream

	Three Months Ended				Nine Months Ended
	September 30				September 30
	2009		2008		2009		2008
	Millions of Dollars
Net Income Attributable to ConocoPhillips*	$	62		173		216		472
* Includes DCP Midstream-related earnings:	$	26		153		128		408
	Dollars Per Barrel
Average Sales Prices
U.S. natural gas liquids*
Consolidated	$	34.66		67.39		30.23		65.23
Equity affiliates		28.89		60.46		26.26		59.82
* 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		194		176		185		190
Natural gas liquids fractionated**		164		181		166		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 and marketing businesses, primarily in the United States and Trinidad.

Earnings from the Midstream segment decreased 64 percent and 54 percent in the third quarter and first nine months of 2009. The decrease in the third quarter was primarily due to lower natural gas liquids prices experienced by equity affiliates DCP Midstream and Phoenix Park Gas Processors Limited, slightly offset by higher volumes. Earnings for the nine-month period of 2009 were also impacted by lower natural gas liquids prices, partially offset by the recognition of an $88 million after-tax benefit in the first quarter of 2009 resulting from a DCP Midstream subsidiary converting subordinated units to common units.

37

R&M

	Three Months Ended					Nine Months Ended
	September 30					September 30
	2009			2008		2009		2008
	Millions of Dollars
Net Income Attributable to ConocoPhillips
United States	$	73			524		133		1,546
International		26			325		119		487
	$	99			849		252		2,033
	Dollars Per Gallon
U.S. Average Wholesale Prices*
Gasoline	$	2.04			3.21		1.77		3.00
Distillates		1.90			3.56		1.66		3.41
* Excludes excise taxes.
	Thousands of Barrels Daily
Operating Statistics
Refining operations*
United States
Crude oil capacity		1,986			2,008		1,986		2,008
Crude oil processed		1,841			1,813		1,762		1,837
Capacity utilization (percent)		93	%		90		89		91
Refinery production		2,017			1,975		1,918		2,020
International
Crude oil capacity		671			670		671		670
Crude oil processed		541			505		531		557
Capacity utilization (percent)		81	%		75		79		83
Refinery production		548			523		541		562
Worldwide
Crude oil capacity		2,657			2,678		2,657		2,678
Crude oil processed		2,382			2,318		2,293		2,394
Capacity utilization (percent)		90	%		87		86		89
Refinery production		2,565			2,498		2,459		2,582
* Includes our share of equity affiliates, except LUKOIL, which is reported in the LUKOIL Investment segment.
Petroleum products sales volumes
United States
Gasoline		1,188			1,089		1,136		1,095
Distillates		906			858		860		880
Other products		420			365		375		384
		2,514			2,312		2,371		2,359
International		626			634		622		645
		3,140			2,946		2,993		3,004

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

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R&M reported earnings of $99 million during the third quarter of 2009, compared with earnings of $849 million in the same period of 2008. The decrease in earnings was primarily due to lower U.S. and international refining margins and lower international marketing margins, partially offset by positive foreign currency exchange impacts and lower domestic utility costs.

R&M’s earnings for the first nine months of 2009 and 2008 were $252 million and $2,033 million, respectively. Earnings decreased primarily as a result of significantly lower U.S. and international refining margins, lower refining and marketing volumes, lower international marketing margins and a lower net benefit from asset rationalization efforts. These decreases were partially offset by lower utilities and maintenance costs and positive foreign currency exchange impacts.

U.S. R&M
In the third quarter of 2009, our U.S. R&M operations reported earnings of $73 million, compared with earnings of $524 million in the same period of 2008. Earnings for the first nine months of 2009 and 2008 were $133 million and $1,546 million, respectively.

Our U.S. refining capacity utilization rate was 93 percent in the third quarter of 2009, compared with 90 percent in the same quarter of 2008. The current-year rate was mainly affected by run reductions due to market conditions, while the prior-year rate was impacted by downtime associated with hurricanes.

International R&M
International R&M reported earnings of $26 million in the third quarter of 2009 and earnings of $119 million in the first nine months of 2009. This compares with earnings of $325 million and $487 million for the corresponding periods of 2008.

Our international refining capacity utilization rate was 81 percent in the third quarter of 2009, compared with 75 percent in the same quarter of 2008. The utilization rate for both periods reflects run reductions in response to current market conditions. In addition, the prior-year rate was impacted by turnaround activity.

LUKOIL Investment

	Millions of Dollars
	Three Months Ended				Nine Months Ended
	September 30				September 30
	2009		2008		2009		2008
Net Income Attributable to ConocoPhillips	$	545		438		1,275		1,922
Operating Statistics*
Net crude oil produced (thousands of barrels daily)		382		371		388		384
Net natural gas produced (millions of cubic feet daily)		253		303		281		356
Net refinery crude oil processed (thousands of barrels daily)		273		228		241		222

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

This segment represents our investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia, which we account for under the equity method. As of September 30, 2009, our ownership interest in LUKOIL was 20 percent based on authorized and issued shares. Our ownership interest based on estimated shares outstanding, used for equity method accounting, was 20.09 percent.

Because LUKOIL’s accounting cycle close and preparation of U.S. generally accepted accounting principles financial statements occur subsequent to our reporting deadline, our equity earnings and statistics for our LUKOIL investment are estimated based on current market indicators, publicly available LUKOIL information and other objective data. Once the difference between actual and estimated results is known, an adjustment is

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recorded. This estimate-to-actual adjustment will be a recurring component of future period results. In addition to our estimated equity share of LUKOIL’s earnings, this segment reflects the amortization of the basis difference between our equity interest in the net assets of LUKOIL and the book value of our investment, and also includes the costs associated with our employees seconded to LUKOIL.

Earnings from the LUKOIL Investment segment increased 24 percent in the third quarter of 2009, primarily due to lower extraction tax and export tariff rates and improved volumes, partially offset by lower refined products and crude oil prices. Earnings for the nine-month period decreased 34 percent, primarily due to lower prices, partially offset by lower extraction tax and export tariff rates and improved volumes. Results for both comparative periods included a benefit from basis difference amortization, in addition to a third-quarter 2009 $33 million positive alignment of second-quarter estimated earnings to LUKOIL’s reported results, compared with a $101 million negative alignment in the third quarter of 2008.

Chemicals

	Millions of Dollars
	Three Months Ended				Nine Months Ended
	September 30				September 30
	2009		2008		2009		2008
Net Income Attributable to ConocoPhillips	$	104		46		194		116

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 were $104 million in the third quarter of 2009, compared with $46 million in the third quarter of 2008. Chemicals earnings were $194 million in the first nine months of 2009, compared with $116 million in 2008. The increase for both comparative periods is primarily due to lower utility and other operating costs, partially offset by lower margins in the olefins and polyolefins business line. In addition, third-quarter earnings benefitted from higher margins in the specialties, aromatics and styrenics business line.

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Emerging Businesses

	Millions of Dollars
	Three Months Ended						Nine Months Ended
	September 30						September 30
	2009			2008			2009			2008
Net Income (Loss) Attributable to ConocoPhillips
Power	$	22			53			73			106
Other		(24	)		(18	)		(73	)		(51	)
	$	(2	)		35			-			55

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.

Losses from the Emerging Businesses segment were $2 million in the third quarter of 2009, compared with earnings of $35 million in the same quarter of 2008. Emerging Businesses broke even in the first nine months of 2009, compared with $55 million in earnings in the nine-month period of 2008. The decline in both periods was primarily due to lower international power results. The nine-month period of 2009 was also impacted by higher technology development expenses.

Corporate and Other

	Millions of Dollars
	Three Months Ended						Nine Months Ended
	September 30						September 30
	2009			2008			2009			2008
Net Income (Loss) Attributable to ConocoPhillips
Net interest	$	(245	)		(149	)		(610	)		(376	)
Corporate general and administrative expenses		(5	)		(41	)		(77	)		(153	)
Other		(33	)		(91	)		(12	)		(117	)
	$	(283	)		(281	)		(699	)		(646	)

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 64 percent in the third quarter of 2009 and 62 percent in the first nine months of 2009. The increase in both comparative periods was primarily due to higher average debt levels, partially offset by lower interest rates. Capitalized interest was also lower in the nine-month period of 2009. Corporate general and administrative expenses decreased 88 percent in the third quarter of 2009 and 50 percent in the first nine months of 2009 due to decreased costs related to compensation plans and overhead. 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 reflect higher foreign currency transaction gains in both comparative periods.

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CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators

	Millions of Dollars
	September 30			December 31
	2009			2008
Short-term debt	$	2,796			370
Total debt*	$	30,458			27,455
Total equity	$	62,097			56,265
Percent of total debt to capital**		33	%		33
Percent of floating-rate debt to total debt		15	%		37

*	Total debt includes short- and long-term debt, as shown on our consolidated balance sheet.
**	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 first nine months of 2009, we issued $9 billion of long-term notes, and we raised $938 million in proceeds from asset sales. During the first nine months of 2009, available cash was primarily used to support our ongoing capital expenditures and investments program, repay commercial paper and other debt, pay dividends, and meet the funding requirements to FCCL Partnership. Total dividends paid on our common stock during the first nine months of 2009 were $2,090 million. During the first nine months of 2009, cash and cash equivalents decreased $114 million to $641 million.

In addition to cash flows from operating activities and proceeds from asset sales, we rely on our commercial paper and credit facility program, and our shelf registration statement to support our short- and long-term liquidity requirements. The credit markets, including the commercial paper markets in the United States, have recently experienced adverse conditions. Although we have not been materially impacted by these conditions, continuing volatility in the credit markets may increase costs associated with issuing commercial paper or other debt instruments due to increased spreads over relevant interest rate benchmarks. Such volatility may also affect our ability, the ability of our joint ventures and equity affiliates, and the ability of third parties with whom we seek to do business, to access those credit markets. Notwithstanding these adverse market conditions, 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 2009, cash of $7,385 million was provided by operating activities, a 62 percent decrease from cash from operations of $19,536 million in the corresponding period of 2008. The decline was primarily due to significantly lower commodity prices and refining margins.

While the stability of our cash flows from operating activities benefits from geographic diversity and the effects of upstream and downstream integration, our short- and long-term operating cash flows are highly dependent upon prices for crude oil, natural gas and natural gas liquids, as well as refining and marketing margins. During the first nine months of 2009, crude oil and natural gas prices, as well as refining margins, were significantly lower than in the same period of 2008. These prices and margins 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

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production decline rates, new technologies, operating efficiency, weather conditions, and new discoveries 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.

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 2009 were $938 million, compared with $729 million in the same period of 2008. In the third quarter of 2009, we closed on the sale of our ownership interest in the Keystone Pipeline. In January of 2009, we closed on the sale of a large part of our remaining U.S. retail marketing assets, which included seller financing in the form of a $370 million five-year note and letters of credit totaling $54 million.

In October 2009, we announced a plan to raise approximately $10 billion from asset dispositions over the next two years. We will work to identify the assets and begin marketing efforts over the near term, with disposition candidates across the company’s operations being considered. Proceeds would be targeted toward debt reduction.

Commercial Paper and Credit Facilities
At September 30, 2009, 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 scheduled to expire in July 2012. The facilities may be used as direct bank borrowings, as support for the ConocoPhillips $6.35 billion commercial paper program, as support for the ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program, or as support for issuances of letters of credit totaling up to $750 million. At both September 30, 2009, and December 31, 2008, we had no outstanding borrowings under the credit facilities, but $40 million in letters of credit had been issued. Under both ConocoPhillips commercial paper programs, $2,342 million of commercial paper was outstanding at September 30, 2009, compared with $6,933 million at December 31, 2008.

At September 30, 2009, our primary funding source for short-term working capital needs was the ConocoPhillips $6.35 billion commercial paper program. Commercial paper maturities are generally limited to 90 days. The ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program is used to fund commitments relating to the Qatargas 3 project. Since we had $2,342 million of commercial paper outstanding and had issued $40 million of letters of credit, we had access to $5.5 billion in borrowing capacity under our revolving credit facilities at September 30, 2009.

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. Under this SEC shelf registration, in February 2009, we issued $1.5 billion of 4.75% Notes due 2014, $2.25 billion of 5.75% Notes due 2019, and $2.25 billion of 6.50% Notes due 2039. In addition, in May 2009, we issued $1.5 billion of 4.60% Notes due 2015, $1.0 billion of 6.00% Notes due 2020 and an additional $500 million of 6.50% Notes due 2039. The proceeds from the sale of these notes were primarily used to reduce outstanding commercial paper balances and for general corporate purposes.

Noncontrolling Interests
At September 30, 2009, and December 31, 2008, we had $587 million and $1,100 million, respectively, of equity in less than wholly owned consolidated subsidiaries held by noncontrolling interest owners. The decline from year-end 2008 was primarily due to Ashford Energy Capital S.A. redeeming for $500 million,

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plus accrued dividends, the investment in Ashford held by Cold Spring Finance S.a.r.l. in the third quarter of 2009. The remaining noncontrolling interests at September 30, 2009, primarily represent operating joint ventures we control. The largest of these, amounting to $560 million, was related to Darwin liquefied natural gas (LNG) operations, located in Australia’s Northern Territory.

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, 2009, we were liable for certain contingent obligations under the following contractual arrangements:

• 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. 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, 2009, Qatargas 3 had approximately $3.5 billion outstanding under all the loan facilities, of which ConocoPhillips provided $979 million, and an additional $85 million of accrued interest.

• Rockies Express Pipeline:In June 2006, we issued a guarantee for 24 percent of $2 billion in credit facilities issued to Rockies Express Pipeline LLC, operated by Kinder Morgan Energy Partners, L.P. The maximum potential amount of future payments to third-party lenders under the guarantee is estimated to be $480 million, which could become payable if the credit facilities are fully utilized and Rockies Express fails to meet its obligations under the credit agreement. At September 30, 2009, Rockies Express had $1,871 million outstanding under the credit facilities, with our 24 percent guarantee equaling $449 million. The operator anticipates construction completion in late 2009. Refinancing of the $2 billion credit facility, which will make the debt nonrecourse to ConocoPhillips, is expected to begin at that time. Construction cost estimates have increased significantly from original projections, and additional increases or other changes related to the investment may impact whether an other-than-temporary impairment of our equity investment is required.

For additional information about guarantees, see Note 11—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.

During the first nine months of 2009, we used proceeds from the issuance of commercial paper to redeem $284 million of 6.375% Notes and $950 million of Floating Rate Notes upon their maturity. Our debt balance at September 30, 2009, was $30.5 billion, an increase of $3.0 billion from the balance at December 31, 2008.

We are obligated to contribute $7.5 billion, plus interest, over a 10-year period, beginning 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, approximately $651 million was short-term and was included in the “Accounts payable—related parties” line on our September 30, 2009, consolidated balance sheet. The principal portion of these payments, which totaled $466 million in the first nine months of 2009, is included in the “Other” line in the financing activities section of our consolidated

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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.

In December 2005, we entered into a credit agreement with Qatargas 3, whereby we will provide loan financing of approximately $1.2 billion for the construction of an LNG train in Qatar. This financing will represent 30 percent of the project’s total debt financing. Through September 30, 2009, we had provided $979 million in loan financing, and an additional $85 million of accrued interest. See the “Off-Balance Sheet Arrangements” section for additional information on Qatargas 3.

We have provided loan financing to WRB Refining LLC, to assist it in meeting its operating and capital spending requirements. At September 30, 2009, $174 million of such financing was outstanding, of which $150 million was classified as long-term.

In October 2009, we announced a quarterly dividend of $0.50 per share, a 6 percent increase over the prior dividend rate. The dividend is payable December 1, 2009, to shareholders of record at the close of business on October 30, 2009. Also in October, we announced a preliminary 2010 capital program budget of $11 billion, which includes capital expenditures and investments, as well as principal contributions on a joint venture acquisition obligation.

Capital Spending

Capital Expenditures and Investments

	Millions of Dollars
	Nine Months Ended
	September 30
	2009		2008
E&P
United States—Alaska	$	638		1,083
United States—Lower 48		2,124		2,887
International		3,875		4,733
		6,637		8,703
Midstream		4		-
R&M
United States		1,079		1,092
International		292		455
		1,371		1,547
LUKOIL Investment		-		-
Chemicals		-		-
Emerging Businesses		89		137
Corporate and Other		75		148
	$	8,176		10,535
United States	$	3,930		5,210
International		4,246		5,325
	$	8,176		10,535

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E&P

Capital spending for E&P during the first nine months of 2009 totaled $6,637 million. The expenditures supported key exploration and development projects including:

• Alaska activities related to development drilling in the Greater Kuparuk Area, the Greater Prudhoe Bay Area, the Western North Slope (including satellite field prospects) and the Cook Inlet Area; and exploration.

• Oil and natural gas developments in the Lower 48, including New Mexico, Texas, Louisiana, Oklahoma, Montana, North Dakota, Wyoming, and offshore in the Gulf of Mexico.

• Investment in West2East Pipeline LLC, a company holding a 100 percent interest in Rockies Express Pipeline LLC.

• Oil sands projects, primarily those associated with FCCL, and ongoing natural gas projects in Canada.

• In the North Sea, the Greater Ekofisk Area, and various southern and central North Sea assets.

• An integrated project to produce and liquefy natural gas from Qatar’s North Field.

• The Kashagan Field in the Caspian Sea, offshore Kazakhstan.

• Advancement of coalbed methane projects in Australia associated with the Australia Pacific LNG joint venture.

• The Peng Lai 19-3 development in China’s Bohai Bay.

• The Browse Basin exploration drilling program, northwest shelf, offshore Australia.

• The Gumusut Field offshore Malaysia.

• The North Belut Field in Block B, as well as other projects offshore Block B and onshore South Sumatra in Indonesia.

• Fields offshore Vietnam.

• Onshore developments in Nigeria.

R&M

Capital spending for R&M during the first nine months of 2009 totaled $1,371 million and included projects to meet environmental standards and improve the operating integrity, safety and energy efficiency of processing units. Capital also was spent on refinery upgrade projects to expand conversion capability and increase clean product yield.

Major project activities included:

• Expansion of a hydrocracker at the Rodeo facility of our San Francisco Refinery.

• Design activities toward the upgrade of the Wilhelmshaven Refinery.

• U.S. programs aimed at reliability, maintenance and air emission reductions.

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

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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 63 through 65 of our 2008 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 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, 2008, 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, 2009, we resolved and closed one site, re-opened one site, and received one notice of potential liability, leaving 66 unresolved sites where we have been notified of potential liability.

At September 30, 2009, our balance sheet included a total environmental accrual of $1,001 million, compared with $979 million at December 31, 2008. 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 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 they are likely to be increasingly widespread and stringent, at this stage it is not possible to accurately estimate either a timetable for implementation or our future compliance costs relating to implementation. Compliance with changes in laws, regulations and obligations that create a GHG emission trading scheme or GHG reduction policies generally could significantly increase costs or reduce demand for fossil energy derived products. For 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 65 through 66 of our 2008 Annual Report on Form 10-K.

NEW ACCOUNTING STANDARDS

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.” This Statement will be codified primarily 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 is effective January 1, 2010, and we do not expect any significant impact to our consolidated financial statements.

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 will be codified primarily into FASB ASC Topic 810, “Consolidation.” More specifically, SFAS No. 167 requires a qualitative rather than a quantitative approach to determine the primary beneficiary of a variable interest entity (VIE), it amends certain guidance pertaining to the determination of the primary beneficiary when related

47

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 is effective January 1, 2010. We are currently evaluating the impact on our consolidated financial statements.

In December 2008, the FASB issued FASB Staff Position (FSP) FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets,” to improve the transparency associated with disclosures about the plan assets of a defined benefit pension or other postretirement plan. This Statement was codified into FASB ASC Topic 715, “Compensation—Retirement Benefits.” Topic 715 requires the disclosure of each major asset category at fair value using the fair value hierarchy. This topic is effective for annual financial statements beginning with the 2009 fiscal year, but will not impact our consolidated financial statements, other than requiring additional disclosures.

OUTLOOK

In E&P, we anticipate our fourth quarter 2009 production will be higher than the third quarter of 2009, and we expect full-year 2009 E&P production to be more than 3 percent higher than that for full-year 2008. In R&M, we expect our crude oil capacity utilization rate for the full year of 2009 to be in the mid-80-percent range, as a result of planned maintenance at several facilities and the potential for ongoing weak margins.

Natural gas prices, particularly in North America, have continued to trend downward in 2009, as have worldwide refining margins. In conjunction with our long-range planning efforts, we perform an annual review for property impairments in the fourth quarter. We also evaluate our equity investments for other-than-temporary impairment. During the fourth quarter, as we finalize our commodity price, refining margin, and foreign exchange rate outlook, as well as capital spending and operating plan assumptions, and the determination of year-end hydrocarbon reserves, it is reasonably possible non-cash impairments of some of our properties and equity investments may be required. Although it is too early to provide a reliable estimate of the possible financial impact of these trends and uncertainties, at certain natural gas price and refining margin forecasts, and foreign exchange rate assumptions, this impact could be significant.

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

• Unsuccessful exploratory drilling activities 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.

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• 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.

• Limited access to capital or significantly higher cost of capital related to illiquidity or 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 2008 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, 2009, does not differ materially from that discussed under Item 7A in our 2008 Annual Report on Form 10-K.

Item 4. CONTROLS AND PROCEDURES

As of September 30, 2009, 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, 2009.

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 2009 and any material developments with respect to matters previously reported in ConocoPhillips’ 2008 Annual Report on Form 10-K or first- and second-quarter 2009 Quarterly Reports on Form 10-Q. While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings were decided adversely to ConocoPhillips, we expect there would be no material effect on our consolidated financial position. Nevertheless, such proceedings are reported pursuant to the U.S. Securities and Exchange Commission’s (SEC) 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 which 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.

Matters Previously Reported
The South Coast Air Quality Management District (SCAQMD) conducted an audit of the Los Angeles Refinery in August 2008 to assess compliance with applicable local, state and federal regulations related to fugitive emissions. As a result of the audit, on August 28, 2008, SCAQMD issued five Notice of Violations (NOVs) alleging noncompliance. SCAQMD assessed a penalty of $85,000 for three of the NOVs, which we have paid. On July 6, 2009, SCAQMD issued a demand to settle one of the two remaining NOVs, along with a demand to settle seven additional NOVs issued in 2008 and 2009 that allege violations of SCAQMD and other air pollution control regulations. We and SCAQMD have settled these NOVs for $132,500.

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Item 1A. RISK FACTORS

There have been no material changes from the risk factors disclosed in Item 1A of our 2008 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, 2009		112,299			$      39.98		-		$      -
August 1-31, 2009		-			-		-		-
September 1-30, 2009		8,046			46.47		-		-
Total		120,345			$      40.42		-

*Represents the repurchase of common shares from company employees in connection with the company’s broad-basedemployee incentive plans.

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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.DEF	XBRL Definition Linkbase Document
101.LAB	XBRL Labels Linkbase Document
101.PRE	XBRL Presentation 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 3, 2009

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