10-Q

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		June 30, 2010
or
[   ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from   to 

Commission file number: 001-32395

ConocoPhillips

(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization) 01-0562944
(I.R.S. Employer
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]

The registrant had 1,483,363,225 shares of common stock, $.01 par value, outstanding at June 30, 2010.

CONOCOPHILLIPS

TABLE OF CONTENTS

	Page
Part I – Financial Information
Item 1.  Financial Statements
Consolidated Income Statement	1
Consolidated Balance Sheet	2
Consolidated Statement of Cash Flows	3
Notes to Consolidated Financial Statements	4
Supplementary Information—Condensed Consolidating Financial Information	27
Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 3.  Quantitative and Qualitative Disclosures About Market Risk	52
Item 4.  Controls and Procedures	52
Part II – Other Information
Item 1.  Legal Proceedings	53
Item 1A.  Risk Factors	55
Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds	55
Item 6.  Exhibits	56
Signature	57
EX-12
EX-31.1
EX-31.2
EX-32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

Consolidated Income Statement ConocoPhillips

	Millions of Dollars
	Three Months Ended						Six Months Ended
	June 30						June 30
	2010			2009		(2)	2010			2009		(2)
Revenues and Other Income
Sales and other operating revenues (1)	$	45,686			35,448			90,507			66,189
Equity in earnings of affiliates		1,088			632			1,956			1,005
Gain on sale of Syncrude		2,878			-			2,878			-
Other income		475			106			548			230
Total Revenues and Other Income		50,127			36,186			95,889			67,424
Costs and Expenses
Purchased crude oil, natural gas and products		32,088			24,609			63,609			44,368
Production and operating expenses		2,619			2,573			5,146			5,118
Selling, general and administrative expenses		438			476			882			951
Exploration expenses		213			243			596			468
Depreciation, depletion and amortization		2,280			2,347			4,598			4,577
Impairments		1,532			51			1,623			54
Taxes other than income taxes(1)		4,247			3,715			8,284			7,179
Accretion on discounted liabilities		113			108			227			212
Interest and debt expense		349			268			650			578
Foreign currency transaction (gains) losses		54			(142	)		90			(11	)
Total Costs and Expenses		43,933			34,248			85,705			63,494
Income before income taxes		6,194			1,938			10,184			3,930
Provision for income taxes		2,011			1,063			3,889			2,239
Net income		4,183			875			6,295			1,691
Less: net income attributable to noncontrolling interests		(19	)		(16	)		(33	)		(32	)
Net Income Attributable to ConocoPhillips	$	4,164			859			6,262			1,659
Net Income Attributable to ConocoPhillips Per Share of Common Stock (dollars)
Basic	$	2.79			.58			4.20			1.12
Diluted		2.77			.57			4.17			1.11
Dividends Paid Per Share of Common Stock (dollars)	$	.55			.47			1.05			.94
Average Common Shares Outstanding (in thousands)
Basic		1,489,814			1,486,496			1,491,329			1,486,195
Diluted		1,501,257			1,495,700			1,502,529			1,495,474
(1)Includes excise taxes on petroleum products sales:	$	3,417			3,316			6,637			6,376

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

See Notes to Consolidated Financial Statements.

1

Consolidated Balance Sheet ConocoPhillips

	Millions of Dollars
	June 30			December 31
	2010			2009		*
Assets
Cash and cash equivalents	$	4,120			542
Accounts and notes receivable (net of allowance of $77 million in 2010 and $76 million in 2009)		11,074			11,861
Accounts and notes receivable—related parties		2,123			1,354
Inventories		7,119			4,940
Prepaid expenses and other current assets		2,230			2,470
Total Current Assets		26,666			21,167
Investments and long-term receivables		35,957			35,742
Loans and advances—related parties		2,394			2,352
Net properties, plants and equipment		81,269			87,708
Goodwill		3,638			3,638
Intangibles		808			823
Other assets		724			708
Total Assets	$	151,456			152,138
Liabilities
Accounts payable	$	13,683			14,168
Accounts payable—related parties		1,693			1,317
Short-term debt		3,082			1,728
Accrued income and other taxes		4,508			3,402
Employee benefit obligations		667			846
Other accruals		2,035			2,234
Total Current Liabilities		25,668			23,695
Long-term debt		23,197			26,925
Asset retirement obligations and accrued environmental costs		8,389			8,713
Joint venture acquisition obligation—related party		4,666			5,009
Deferred income taxes		17,012			17,956
Employee benefit obligations		3,836			4,130
Other liabilities and deferred credits		2,743			3,097
Total Liabilities		85,511			89,525
Equity
Common stock (2,500,000,000 shares authorized at $.01 par value)
Issued (2010—1,736,403,629 shares; 2009—1,733,345,558 shares)
Par value		17			17
Capital in excess of par		43,869			43,681
Grantor trusts (at cost: 2010—37,798,903 shares; 2009—38,742,261 shares)		(650	)		(667	)
Treasury stock (at cost: 2010—215,241,501 shares; 2009—208,346,815 shares)		(16,601	)		(16,211	)
Accumulated other comprehensive income		1,881			3,065
Unearned employee compensation		(62	)		(76	)
Retained earnings		36,917			32,214
Total Common Stockholders’ Equity		65,371			62,023
Noncontrolling interests		574			590
Total Equity		65,945			62,613
Total Liabilities and Equity	$	151,456			152,138

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

See Notes to Consolidated Financial Statements.

2

Consolidated Statement of Cash Flows ConocoPhillips

	Millions of Dollars
	Six Months Ended
	June 30
	2010			2009		*
Cash Flows From Operating Activities
Net income	$	6,295			1,691
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization		4,598			4,577
Impairments		1,623			54
Dry hole costs and leasehold impairments		205			238
Accretion on discounted liabilities		227			212
Deferred taxes		(543	)		(603	)
Undistributed equity earnings		(1,189	)		(606	)
Gain on asset dispositions		(3,273	)		(36	)
Other		(543	)		175
Working capital adjustments
Decrease (increase) in accounts and notes receivable		671			65
Decrease (increase) in inventories		(2,401	)		(973	)
Decrease (increase) in prepaid expenses and other current assets		(89	)		(435	)
Increase (decrease) in accounts payable		(106	)		1,020
Increase (decrease) in taxes and other accruals		1,040			(927	)
Net Cash Provided by Operating Activities		6,515			4,452
Cash Flows From Investing Activities
Capital expenditures and investments		(4,080	)		(5,578	)
Proceeds from asset dispositions		5,943			232
Long-term advances/loans—related parties		(269	)		(121	)
Collection of advances/loans—related parties		80			36
Other		9			(77	)
Net Cash Provided by (Used in) Investing Activities		1,683			(5,508	)
Cash Flows From Financing Activities
Issuance of debt		65			9,029
Repayment of debt		(2,435	)		(6,109	)
Issuance of company common stock		35			(21	)
Repurchase of company common stock		(390	)		-
Dividends paid on company common stock		(1,560	)		(1,393	)
Other		(355	)		(406	)
Net Cash Provided by (Used in) Financing Activities		(4,640	)		1,100
Effect of Exchange Rate Changes on Cash and Cash Equivalents		20			89
Net Change in Cash and Cash Equivalents		3,578			133
Cash and cash equivalents at beginning of period		542			755
Cash and Cash Equivalents at End of Period	$	4,120			888

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

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 2009 Annual Report on Form 10-K.

Note 2—Changes in Accounting Principles

LUKOIL Accounting

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

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

	Millions of Dollars
	Three Months Ended June 30
	2010							2009
	Computed		As		Effect			As				Effect
	with		Reported		of			Originally		As		of
	Estimate		with Lag		Change			Reported		Adjusted		Change
Equity in earnings of affiliates	$	1,135		1,088		(47	)		1,076		632		(444	)
Provision for income taxes		2,013		2,011		(2	)		1,068		1,063		(5	)
Net Income		4,228		4,183		(45	)		1,314		875		(439	)
Net Income Attributable to ConocoPhillips		4,209		4,164		(45	)		1,298		859		(439	)
Net Income Attributable to ConocoPhillips Per Share of Common Stock (dollars)
Basic	$	2.82		2.79		(.03	)		.87		.58		(.29	)
Diluted		2.80		2.77		(.03	)		.87		.57		(.30	)

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	Millions of Dollars
	Six Months Ended June 30
	2010							2009
	Computed		As		Effect			As				Effect
	with		Reported		of			Originally		As		of
	Estimate		with Lag		Change			Reported		Adjusted		Change
Equity in earnings of affiliates	$	1,886		1,956		70			1,491		1,005		(486	)
Provision for income taxes		3,890		3,889		(1	)		2,246		2,239		(7	)
Net Income		6,224		6,295		71			2,170		1,691		(479	)
Net Income Attributable to ConocoPhillips		6,191		6,262		71			2,138		1,659		(479	)
Net Income Attributable to ConocoPhillips Per Share of Common Stock (dollars)
Basic	$	4.15		4.20		.05			1.44		1.12		(.32	)
Diluted		4.12		4.17		.05			1.43		1.11		(.32	)

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

	Millions of Dollars
	June 30, 2010							December 31, 2009
	Computed		As		Effect			As				Effect
	with		Reported		of			Originally		As		of
	Estimate		with Lag		Change			Reported		Adjusted		Change
Investments and long-term receivables	$	36,337		35,957		(380	)		36,192		35,742		(450	)
Deferred income taxes		17,019		17,012		(7	)		17,962		17,956		(6	)
Retained earnings		37,290		36,917		(373	)		32,658		32,214		(444	)

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

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

	Millions of Dollars
	Six Months Ended June 30
	2010									2009
	Computed			As			Effect			As						Effect
	with			Reported			of			Originally			As			of
	Estimate			with Lag			Change			Reported			Adjusted			Change
Net income	$	6,224			6,295			71			2,170			1,691			(479	)
Deferred taxes		(542	)		(543	)		(1	)		(596	)		(603	)		(7	)
Undistributed equity earnings		(1,119	)		(1,189	)		(70	)		(1,092	)		(606	)		486

5

Transfers of Financial Assets

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

Variable Interest Entities (VIEs)

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

Note 3—Variable Interest Entities (VIEs)

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

We have a 30 percent ownership interest with a 50 percent governance interest in the OOO Naryanmarneftegaz (NMNG) joint venture to develop resources in the Timan-Pechora province of Russia. The NMNG joint venture is a VIE because we and a related party, OAO LUKOIL, have disproportionate interests. When related parties are involved in a VIE and neither party has the power to direct the activities of the VIE without the consent of the other party, 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 and production 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. At June 30, 2010, the book value of our investment in the venture was $1,495 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. We determined we are not the primary beneficiary for Varandey because LUKOIL has the power to direct the activities that most influence Varandey’s economic performance. We account for our loan to Varandey as a financial asset. Principal repayments began in April 2009. The loan balance outstanding as of June 30, 2010, at current exchange rates, was $246 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

6

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 June 30, 2010, was $676 million. Freeport LNG is a VIE because Freeport GP holds no equity in Freeport LNG, and the limited partners of Freeport LNG do not have any substantive decision making ability. We are not the primary beneficiary because the equity holders of Freeport GP are not related parties and have equally shared power. Neither party has the power to direct the significant activities without the consent of the other party, in which case neither party is considered to be the primary beneficiary. The loan to Freeport LNG is accounted for as a financial asset, and our investment in Freeport GP is accounted for as an equity investment.

Note 4—Inventories

Inventories consisted of the following:

	Millions of Dollars
	June 30		December 31
	2010		2009
Crude oil and petroleum products	$	6,151		3,955
Materials, supplies and other		968		985
	$	7,119		4,940

Inventories valued on the last-in, first-out (LIFO) basis totaled $5,941 million and $3,747 million at June 30, 2010, and December 31, 2009, respectively. The excess of current replacement cost over LIFO cost of inventories amounted to $5,328 million and $5,627 million at June 30, 2010, and December 31, 2009, respectively.

Note 5—Assets Held for Sale

During the second quarter of 2010, we sold our interest in CFJ Properties, a joint venture which owned and operated Flying J-branded truck travel plazas. The sale resulted in a before-tax gain of $234 million, which is included in the “Other income” line of the consolidated income statement. At June 30, 2010, we no longer had any significant assets or liabilities classified as held for sale.

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

7

Note 6—Investments, Loans and Long-Term Receivables

LUKOIL

Our ownership interest in LUKOIL was 19.21 percent at June 30, 2010, based on 851 million shares authorized and issued. Our average ownership interest in the first quarter of 2010, used to record our share of LUKOIL’s first-quarter results on a lag basis, was 20.09 percent. During the second quarter of 2010, we sold 6.7 million shares of LUKOIL, resulting in cash proceeds of $391 million and a net gain on disposition of $99 million, which is included in the “Other income” line of the consolidated income statement.

At June 30, 2010, the book value of our ordinary share investment in LUKOIL was $6,695 million reflecting the recognition of our equity-method share of LUKOIL’s earnings on a one-quarter-lag basis. Our investment book value is lower than our share of the net assets of LUKOIL by approximately $4,234 million. A majority of this negative basis difference is being amortized on a straight-line basis over a 22-year useful life as an increase to equity earnings. On June 30, 2010, the closing price of LUKOIL shares on the London Stock Exchange was $51.90 per share, making the total market value of our LUKOIL investment $8,479 million. For additional information about accounting for our LUKOIL investment, see Note 2—Changes in Accounting Principles.

On July 28, 2010, we announced our intention to sell our entire interest in LUKOIL, then consisting of 163,367,629 shares. This decision will be implemented as follows:

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

• Also pursuant to the Agreement, the LUKOIL subsidiary has a 60-day option, expiring on September 26, 2010, to purchase any or all of our interest remaining at the time of exercise of the option, at a price of $56 per share.

• Finally, to the extent all of our remaining interest is not purchased pursuant to the 60-day option, we intend to sell our remaining interest in the open market from time to time, subject to the terms of the Shareholder Agreement, by the end of 2011.

We will continue to use the equity-method of accounting for our interest in LUKOIL until we determine we no longer have significant influence over the operating and financial policies of LUKOIL. Making this determination will involve judgment based on an on-going evaluation of current facts and circumstances, but based on the various voting rights and powers we have under our Shareholder Agreement with LUKOIL and the cumulative stockholder voting rules in Russia, we believe it is likely we would lose significant influence once our ownership interest falls below approximately 10 percent. At the point in the future when we cease using equity-method accounting, we would no longer record equity earnings related to LUKOIL, we would cease to report our share of LUKOIL’s upstream production and proved reserves in our supplemental oil and gas disclosures, and our available-for-sale investment in LUKOIL’s shares would be marked to market each period, with the corresponding gains and losses recorded to other comprehensive income until the shares are sold.

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 June 30, 2010, included the following:

• $676 million in loan financing to Freeport LNG Development, L.P.

• $246 million in loan financing at June 2010 exchange rates to Varandey Terminal Company.

• $1,064 million in project financing and an additional $93 million of accrued interest to Qatargas 3.

• $550 million in loan financing to WRB Refining LLC.

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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 June 30, 2010, was $304 million, and substantially the entire value is categorized in Level 1 of the fair value hierarchy. These investments are measured at fair value using a market approach based on quotations from national securities exchanges.

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

Note 7—Properties, Plants and Equipment

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

	Millions of Dollars
	June 30, 2010						December 31, 2009
	Gross		Accum.		Net		Gross		Accum.		Net
	PP&E		DD&A		PP&E		PP&E		DD&A		PP&E
E&P	$	112,753		47,367		65,386		115,224		45,577		69,647
Midstream		124		77		47		123		74		49
R&M		22,648		8,405		14,243		23,047		6,714		16,333
LUKOIL Investment		-		-		-		-		-		-
Chemicals		-		-		-		-		-		-
Emerging Businesses		1,109		298		811		1,198		300		898
Corporate and Other		1,684		902		782		1,650		869		781
	$	138,318		57,049		81,269		141,242		53,534		87,708

Suspended Wells

The capitalized cost of suspended wells at June 30, 2010, was $1,002 million, an increase of $94 million from $908 million at year-end 2009. For the category of exploratory well costs capitalized for a period greater than one year as of December 31, 2009, no wells were charged to dry hole expense during the first six months of 2010.

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Note 8—Impairments

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

	Millions of Dollars
	Three Months Ended				Six Months Ended
	June 30				June 30
	2010		2009		2010		2009
E&P
United States	$	-		-		-		-
International		1		51		1		59
R&M
United States		14		-		17		(5	)
International		1,512		-		1,600		-
Emerging Businesses		5		-		5		-
	$	1,532		51		1,623		54

2010
In the second quarter of 2010, due to ongoing unfavorable market conditions and consistent with our strategy of maintaining capital discipline and reducing our downstream portfolio over time, we cancelled plans for a project to upgrade our refinery in Wilhelmshaven, Germany. As a result, the sum of the undiscounted pretax cash flows was less than the carrying value; therefore, the carrying value of $1,764 million was written down to estimated fair value resulting in a before-tax impairment of $1,500 million. The Level 3 fair value was determined considering a discounted cash flow model, cash flow multiples for similar assets and alternative use. The six-month period of 2010 also included a before-tax property impairment of $100 million in international R&M to write-off capitalized project costs, as a result of our decision to end our participation in a new refinery project in Yanbu Industrial City, Saudi Arabia.

2009
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 the 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 the crude oil production of Burlington and its co-venturer 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 Blocks 7 and 21, formalizing the complete expropriation of our assets. In June 2010, the ICSID tribunal concluded it has jurisdiction to hear Burlington’s expropriation claim. A hearing on case merits is scheduled for October 2010, with a decision on case merits expected in June 2011.

Note 9—Debt

We have two commercial paper programs supported by our $7.85 billion revolving credit facilities: the ConocoPhillips $6.35 billion program, primarily a funding source for short-term working capital needs, and the ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program, which is used to fund commitments relating to the Qatargas 3 Project. Commercial paper maturities are generally limited to 90 days. At both June 30, 2010 and December 31, 2009, we had no direct outstanding borrowings under our revolving credit facilities, but $40 million in letters of credit had been issued. In addition, under the two commercial paper programs, there was $1,126 million of commercial paper outstanding at June 30, 2010, compared with $1,300 million at December 31, 2009. Since we had $1,126 million of commercial paper outstanding and had

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issued $40 million of letters of credit, we had access to $6.7 billion in borrowing capacity under our revolving credit facilities at June 30, 2010.

During the quarter, the $1,264 million 8.75% and the $150 million 9.875% bonds were repaid at their maturity. Additionally, the remaining $750 million balance of the Floating Rate Five-Year Term Notes was repaid prior to maturity.

At June 30, 2010, we classified $1,126 million of short-term debt as long-term debt, based on our ability and intent to refinance the obligation on a long-term basis under our revolving credit facilities. Additionally, irrevocable early redemption notices were issued early in the third quarter of 2010 for $2,678 million of bonds. Accordingly, these bonds with due dates beyond one year were classified as short-term debt in our consolidated balance sheet.

Note 10—Joint Venture Acquisition Obligation

We are obligated to contribute $7.5 billion, plus interest, over a 10-year period that began in 2007, to FCCL Partnership. Quarterly principal and interest payments of $237 million began in the second quarter of 2007 and will continue until the balance is paid. Of the principal obligation amount, approximately $677 million was short-term and was included in the “Accounts payable—related parties” line on our June 30, 2010, consolidated balance sheet. The principal portion of these payments, which totaled $325 million in the first six months of 2010, is included in the “Other” line in the financing activities section of our consolidated statement of cash flows. Interest accrues at a fixed annual rate of 5.3 percent on the unpaid principal balance. Fifty percent of the quarterly interest payment is reflected as a capital contribution and is included in the “Capital expenditures and investments” line on our consolidated statement of cash flows.

Note 11—Noncontrolling Interests

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

	Millions of Dollars
	2010									2009*
	Common			Non-						Common			Non-
	Stockholders’			Controlling			Total			Stockholders’			Controlling			Total
	Equity			Interests			Equity			Equity			Interests			Equity
Balance at January 1	$	62,023			590			62,613			55,165			1,100			56,265
Net income		6,262			33			6,295			1,659			32			1,691
Dividends		(1,560	)		-			(1,560	)		(1,393	)		-			(1,393	)
Distributions to noncontrolling interests		-			(48	)		(48	)		-			(54	)		(54	)
Other changes, net**		(1,354	)		(1	)		(1,355	)		3,020			-			3,020
Balance at June 30	$	65,371			574			65,945			58,451			1,078			59,529

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

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

Note 12—Guarantees

At June 30, 2010, we were liable for certain contingent obligations under various contractual arrangements as described below. We recognize a liability, at inception, for the fair value of our obligation as a guarantor for newly issued or modified guarantees. Unless the carrying amount of the liability is noted below, we have not recognized a liability either because the guarantees were issued prior to December 31, 2002, or because the fair

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

Construction Completion Guarantees

• In December 2005, we issued a construction completion guarantee for 30 percent of the $4 billion in loan facilities of Qatargas 3, which are being used to finance the construction of an LNG train in Qatar. Of the $4 billion in loan facilities, we committed to provide $1.2 billion. The maximum potential amount of future payments to third-party lenders under the guarantee is estimated to be $850 million, which could become payable if the full debt financing is utilized and completion of the Qatargas 3 Project is not achieved. The project financing will be nonrecourse to ConocoPhillips upon certified completion, which is expected in 2011. At June 30, 2010, the carrying value of the guarantee to third-party lenders was $11 million.

Guarantees of Joint Venture Debt

• In the second quarter of 2010, the credit facilities of Rockies Express Pipeline LLC were reduced, and our guarantee was released.

• At June 30, 2010, we had guarantees outstanding for our portion of joint venture debt obligations, which have terms of up to 15 years. The maximum potential amount of future payments under the guarantees is approximately $70 million. Payment would be required if a joint venture defaults on its debt obligations.

Other Guarantees

• In conjunction with our purchase of a 50 percent ownership interest in Australia Pacific LNG Pty Limited (APLNG) from Origin Energy in October 2008, we agreed to participate, if and when requested, in any parent company guarantees that were outstanding at the time we purchased our interest in APLNG. These parent company guarantees cover the obligation of APLNG to deliver natural gas under several sales agreements with remaining terms of 7 to 21 years. Our maximum potential amount of future payments, or cost of volume delivery, under these guarantees is estimated to be $1,366 million ($2,951 million in the event of intentional or reckless breach) at June 2010 exchange rates based on our 50 percent share of the remaining contracted volumes, which could become payable if APLNG fails to meet its obligations under these agreements and the obligations cannot otherwise be mitigated. Future payments are considered unlikely, as the payments, or cost of volume delivery, would only be triggered if APLNG does not have enough natural gas to meet these sales commitments and if the partners do not make necessary equity contributions into APLNG.

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

Indemnifications

Over the years, we have entered into various agreements to sell ownership interests in certain corporations, joint ventures and assets that gave rise to qualifying indemnifications. Agreements associated with these sales include indemnifications for taxes, environmental liabilities, permits and licenses, employee claims, real estate indemnity against tenant defaults, and litigation. The terms of these indemnifications vary greatly. The majority of these indemnifications are related to environmental issues, the term is generally indefinite and the maximum amount of future payments is generally unlimited. The carrying amount recorded for these indemnifications at June 30, 2010, was $406 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.

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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 $251 million of environmental accruals for known contamination that are included in asset retirement obligations and accrued environmental costs at June 30, 2010. For additional information about environmental liabilities, see Note 13—Contingencies and Commitments.

Note 13—Contingencies and Commitments

In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the case of income-tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain.

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

Environmental

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

Although liability of those potentially responsible for environmental remediation costs is generally joint and several for federal sites and frequently so for state sites, we are usually only one of many companies cited at a particular site. Due to the joint and several liabilities, we could be responsible for all cleanup costs related to any site at which we have been designated as a potentially responsible party. If we were solely responsible, the costs, in some cases, could be material to our results of operations, capital resources or liquidity, or to those of one of our segments. However, settlements and costs incurred in matters that previously have been resolved have not been material to our results of operations or financial condition. We have been successful to date in sharing cleanup costs with other financially sound companies. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess the site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or may attain a settlement of liability.

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Where it appears that other potentially responsible parties may be financially unable to bear their proportional share, we consider this inability in estimating our potential liability, and we adjust our accruals accordingly.

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

We are currently participating in environmental assessments and cleanups at numerous federal Superfund and comparable state sites. After an assessment of environmental exposures for cleanup and other costs, we make accruals on an undiscounted basis (except those acquired in a purchase business combination, which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable future costs will be incurred and these costs can be reasonably estimated. At June 30, 2010, our balance sheet included a total environmental accrual of $971 million, compared with $1,017 million at December 31, 2009. We expect to incur a substantial amount of these expenditures within the next 30 years. We have not reduced these accruals for possible insurance recoveries. In the future, we may be involved in additional environmental assessments, cleanups and proceedings.

Legal Proceedings

Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial, as well as the pace of settlement discussions in individual matters. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, 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 June 30, 2010, we had performance obligations secured by letters of credit of $2,038 million (of which $40 million was issued under the provisions of our revolving credit facility, and the remainder was issued as direct bank letters of credit) related to various purchase commitments for materials, supplies, services and items of permanent investment incident to the ordinary conduct of business.

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

Our obligation under throughput agreements to support third-party shipper financing arrangements for a crude oil transportation system commenced during the second quarter of 2010. The aggregate amounts of estimated payments under these agreements are: 2010—$50 million; 2011—$211 million; 2012—$248 million; 2013—$247 million; 2014—$247 million; and 2015 and after—$3,958 million.

Note 14—Financial Instruments and Derivative Contracts

Derivative Instruments

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

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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 and the majority of our contracts to sell power as derivatives, but we do apply the normal purchases and normal sales exception to certain long-term contracts to sell our natural gas production. We generally apply this normal purchases and normal sales exception to eligible crude oil and refined product commodity purchase and sales contracts; however, we may elect not to apply this exception (e.g., when another derivative instrument will be used to mitigate the risk of the purchase or sales contract but hedge accounting will not be applied, in which case both the purchase or sales contract and the derivative contract mitigating the resulting risk will be recorded on the balance sheet at fair value).

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

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

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

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

	Millions of Dollars
	June 30, 2010												December 31, 2009
	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Assets
Commodity derivatives	$	2,775			1,603			62			4,440			1,710			1,659			61			3,430
Interest rate derivatives		-			16			-			16			-			-			-			-
Foreign exchange derivatives		-			57			-			57			-			45			-			45
Total assets		2,775			1,676			62			4,513			1,710			1,704			61			3,475
Liabilities
Commodity derivatives		(2,838	)		(1,399	)		(21	)		(4,258	)		(1,797	)		(1,496	)		(24	)		(3,317	)
Foreign exchange derivatives		-			(18	)		-			(18	)		-			(47	)		-			(47	)
Total liabilities		(2,838	)		(1,417	)		(21	)		(4,276	)		(1,797	)		(1,543	)		(24	)		(3,364	)
Net assets (liabilities)	$	(63	)		259			41			237			(87	)		161			37			111

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

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

	Millions of Dollars
	Three Months Ended						Six Months Ended
	June 30						June 30
	2010			2009			2010			2009
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Beginning balance	$	60			96			37			40
Total net gains (losses), realized and unrealized, included in earnings		-			(8	)		32			18
Net purchases, issuances and settlements		(19	)		(17	)		(22	)		(27	)
Transfers into Level 3		1			20			1			61
Transfers out of Level 3		(1	)		(17	)		(7	)		(18	)
Ending balance	$	41			74			41			74

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

	Millions of Dollars
	2010									2009
				Purchased									Purchased
	Other			Crude Oil,						Other			Crude Oil,
	Operating			Natural Gas						Operating			Natural Gas
	Revenues			and Products			Total			Revenues			and Products			Total
Three Months Ended June 30
Total gains (losses) included in earnings	$	10			(10	)		-			(8	)		-			(8	)
Change in unrealized gains (losses) relating to assets held at June 30	$	31			1			32			3			-			3
Change in unrealized gains (losses) relating to liabilities held at June 30	$	(19	)		(9	)		(28	)		(9	)		-			(9	)
Six Months Ended June 30
Total gains (losses) included in earnings	$	54			(22	)		32			19			(1	)		18
Change in unrealized gains (losses) relating to assets held at June 30	$	64			1			65			21			-			21
Change in unrealized gains (losses) relating to liabilities held at June 30	$	(16	)		(17	)		(33	)		(10	)		-			(10	)

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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 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 and the line items where they appear on our consolidated balance sheet were:

	Millions of Dollars
	June 30		December 31
	2010		2009
Assets
Prepaid expenses and other current assets	$	4,124		3,084
Other assets		320		359
Liabilities
Other accruals		3,931		3,006
Other liabilities and deferred credits		331		324

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

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

	Millions of Dollars
	Three Months Ended						Six Months Ended
	June 30						June 30
	2010			2009			2010			2009
Sales and other operating revenues	$	(1,139	)		(182	)		(657	)		391
Other income		(20	)		14			(30	)		22
Purchased crude oil, natural gas and products		1,373			(443	)		866			(955	)

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

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

	Open Position
	Long/(Short)
	June 30			December 31
	2010			2009
Commodity
Crude oil, refined products and natural gas liquids (millions of barrels)		(35	)		(16	)
Natural gas and power (billions of cubic feet)
Fixed price		(85	)		(60	)
Basis		123			154

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

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

	Millions of Dollars
	June 30		December 31
	2010		2009
Assets
Prepaid expenses and other current assets	$	7		-
Other assets		9		-

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

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

	Millions of Dollars
	Three Months Ended					Six Months Ended
	June 30					June 30
	2010			2009		2010			2009
Recorded in interest and debt expense
From the interest rate derivatives	$	(16	)		-		(16	)		-
From the hedged debt		14			-		14			-

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

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, dividends, and cash returns from net investments in foreign affiliates to be remitted within the coming year.

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

	Millions of Dollars
	June 30		December 31
	2010		2009
Assets
Prepaid expenses and other current assets	$	50		38
Other assets		7		7
Liabilities
Other accruals		18		40
Other liabilities and deferred credits		-		7

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

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

	Millions of Dollars
	Three Months Ended					Six Months Ended
	June 30					June 30
	2010		2009			2010		2009
Foreign currency transaction (gains) losses	$	57		(166	)		103		(172	)

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

We had the following net position of outstanding foreign currency swap contracts:

	In Millions
	Notional Currency*
		June 30		December 31
		2010		2009
Foreign Currency Swaps
Sell U.S. dollar, buy other currencies**	USD		1,647		3,211
Buy British pound, sell euro	EUR		285		267

  *Denominated in U.S. dollars (USD) and euros (EUR).

**Primarily euro, Canadian dollar, Norwegian krone and British pound.

Credit Risk

Financial instruments potentially exposed to concentrations of credit risk consist primarily of cash equivalents, 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 IntercontinentalExchange (ICE) Futures.

19

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

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

The aggregate fair value of all derivative instruments with such credit-risk-related contingent features that were in a liability position on June 30, 2010, and December 31, 2009, was $272 million and $381 million, respectively, for which no collateral was posted in the normal course of business in 2010 and 2009. If our credit rating were lowered one level from its “A” rating (per Standard and Poor’s) on June 30, 2010, we would be required to post no additional collateral to our counterparties. If we were downgraded below investment grade, we would be required to post $272 million of additional collateral, either with cash or letters of credit.

Fair Values of Financial Instruments

We used the following methods and assumptions to estimate the fair value of financial instruments:

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

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

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

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

• Fixed-rate 5.3 percent joint venture acquisition obligation: Fair value is estimated based on the net present value of the future cash flows, discounted at a June 30 effective yield rate of 2.25 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 June 30, 2010, and approximates the exit price at that date.

20

Certain of our commodity derivative and financial instruments were:

	Millions of Dollars
	Carrying Amount				Fair Value
	June 30		December 31		June 30		December 31
	2010		2009		2010		2009
Financial assets
Foreign currency derivatives	$	57		45		57		45
Interest rate derivatives		16		-		16		-
Commodity derivatives		702		823		702		823
Financial liabilities
Total debt, excluding capital leases		26,243		28,622		29,312		30,565
Joint venture acquisition obligation		5,343		5,669		5,949		6,276
Foreign currency derivatives		18		47		18		47
Commodity derivatives		441		632		441		632

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 June 30, 2010, commodity derivative assets and liabilities appear net of $133 million of obligations to return cash collateral and $212 million of rights to reclaim cash collateral, respectively. The December 31, 2009, commodity derivative assets and liabilities appear net of $70 million of obligations to return cash collateral and $148 million of rights to reclaim cash collateral, respectively. No collateral was deposited or held for the foreign currency derivatives or interest rate derivatives.

Note 15—Comprehensive Income

ConocoPhillips’ comprehensive income was as follows:

	Millions of Dollars
	Three Months Ended						Six Months Ended
	June 30						June 30
	2010			2009		*	2010			2009		*
Net income	$	4,183			875			6,295			1,691
After-tax changes in:
Defined benefit pension plans
Net prior service cost		2			3			4			6
Net actuarial loss		35			33			70			67
Non-sponsored plans		19			(1	)		21			(2	)
Foreign currency translation adjustments		(1,449	)		3,079			(1,278	)		2,801
Hedging activities		(1	)		2			(1	)		1
Comprehensive income		2,789			3,991			5,111			4,564
Less: comprehensive income attributable to noncontrolling interests		(19	)		(16	)		(33	)		(32	)
Comprehensive income attributable to ConocoPhillips	$	2,770			3,975			5,078			4,532

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

21

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

	Millions of Dollars
	June 30			December 31
	2010			2009
Defined benefit plans	$	(1,409	)		(1,504	)
Foreign currency translation adjustments		3,298			4,576
Deferred net hedging loss		(8	)		(7	)
Accumulated other comprehensive income	$	1,881			3,065

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

Note 16—Cash Flow Information

	Millions of Dollars
	Six Months Ended
	June 30
	2010		2009
Cash Payments
Interest	$	660		416
Income taxes		3,925		3,271

Note 17—Employee Benefit Plans

Pension and Postretirement Plans

	Millions of Dollars
	Pension Benefits												Other Benefits
Components of Net Periodic Benefit Cost	2010						2009						2010			2009
	U.S.			Int’l.			U.S.			Int’l.
Three Months Ended June 30
Service cost	$	57			22			49			18			2			2
Interest cost		65			41			70			35			12			11
Expected return on plan assets		(56	)		(35	)		(46	)		(30	)		-			-
Amortization of prior service cost		3			-			2			-			1			2
Recognized net actuarial (gain) loss		41			13			46			9			(2	)		(3	)
Net periodic benefit costs	$	110			41			121			32			13			12
Six Months Ended June 30
Service cost	$	114			45			97			38			5			4
Interest cost		130			84			139			68			23			23
Expected return on plan assets		(112	)		(73	)		(92	)		(59	)		-			-
Amortization of prior service cost		5			-			5			-			2			4
Recognized net actuarial (gain) loss		83			27			93			17			(4	)		(7	)
Net periodic benefit costs	$	220			83			242			64			26			24

During the first six months of 2010, we contributed $265 million to our domestic benefit plans and $104 million to our international benefit plans.

22

Note 18—Related Party Transactions

Significant transactions with related parties were:

	Millions of Dollars
	Three Months Ended				Six Months Ended
	June 30				June 30
	2010		2009		2010		2009
Operating revenues (a)	$	2,050		1,892		3,984		3,365
Purchases (b)		3,909		3,168		7,348		5,650
Operating expenses and selling, general and administrative expenses (c)		84		71		165		157
Net interest expense (d)		18		20		37		39

(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 MSLP, for the use of common facilities, such as steam generators, waste and water treaters, and warehouse facilities.
(b)	We purchased refined products from WRB. We purchased natural gas and natural gas liquids from DCP Midstream and CPChem for use in our refinery processes and other feedstocks from various affiliates. We purchased crude oil from LUKOIL and refined products from MRC. We also paid fees to various pipeline equity companies for transporting finished refined products and natural gas, as well as a price upgrade to MSLP for heavy crude processing. We purchased base oils and fuel products from Excel Paralubes for use in our refinery and specialty businesses.
(c)	We paid processing fees to various affiliates. Additionally, we paid transportation fees to pipeline equity companies.
(d)	We paid and/or received interest to/from various affiliates, including FCCL Partnership. See Note 6—Investments, Loans and Long-Term Receivables, for additional information on loans to affiliated companies.

Note 19—Segment Disclosures and Related Information

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

1)	E&P—This segment primarily explores for, produces, transports and markets crude oil, bitumen, natural gas and natural gas liquids on a worldwide basis.
2)	Midstream—This segment gathers, processes and markets natural gas produced by ConocoPhillips and others, and fractionates and markets natural gas liquids, predominantly in the United States and Trinidad. The Midstream segment primarily consists of our 50 percent equity investment in DCP Midstream, LLC.
3)	R&M—This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia.

23

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 June 30, 2010, our ownership interest was 19.21 percent based on issued shares. Our average ownership interest in the first quarter of 2010, used to record our share of LUKOIL’s first-quarter results on a lag basis, was 20.09 percent.
5)	Chemicals—This segment manufactures and markets petrochemicals and plastics on a worldwide basis. The Chemicals segment consists of our 50 percent equity investment in 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.

24

Analysis of Results by Operating Segment

	Millions of Dollars
	Three Months Ended						Six Months Ended
	June 30						June 30
	2010			2009			2010			2009
Sales and Other Operating Revenues
E&P
United States	$	6,828			5,397			15,020			11,493
International		5,966			5,048			13,426			11,699
Intersegment eliminations—U.S.		(1,357	)		(1,187	)		(2,732	)		(2,046	)
Intersegment eliminations—international		(1,993	)		(1,397	)		(3,889	)		(2,785	)
E&P		9,444			7,861			21,825			18,361
Midstream
Total sales		1,639			973			3,717			1,895
Intersegment eliminations		(71	)		(53	)		(187	)		(101	)
Midstream		1,568			920			3,530			1,794
R&M
United States		24,516			18,415			46,229			31,416
International		10,366			8,368			19,279			14,832
Intersegment eliminations—U.S.		(190	)		(140	)		(388	)		(257	)
Intersegment eliminations—international		(61	)		(12	)		(74	)		(21	)
R&M		34,631			26,631			65,046			45,970
LUKOIL Investment		-			-			-			-
Chemicals		2			3			5			6
Emerging Businesses
Total sales		179			133			394			287
Intersegment eliminations		(147	)		(104	)		(306	)		(241	)
Emerging Businesses		32			29			88			46
Corporate and Other		9			4			13			12
Consolidated sales and other operating revenues	$	45,686			35,448			90,507			66,189

Net Income (Loss) Attributable to ConocoPhillips
E&P
United States	$	536		336		1,293		509
International		3,578		389		4,653		916
Total E&P		4,114		725		5,946		1,425
Midstream		61		31		138		154
R&M
United States		782		(38	)	794		60
International		(1,061	)	(14	)	(1,077	)	93
Total R&M		(279	)	(52	)	(283	)	153
LUKOIL Investment		529		243	*	916		251	*
Chemicals		138		67		248		90
Emerging Businesses		(10	)	2		(4	)	2
Corporate and Other		(389	)	(157	)	(699	)	(416	)
Consolidated net income attributable to ConocoPhillips	$	4,164		859		6,262		1,659

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

25

	Millions of Dollars
	June 30		December 31
	2010		2009
Total Assets
E&P
United States	$	35,436		36,122
International		59,691		64,831
Total E&P		95,127		100,953
Midstream		1,892		2,054
R&M
United States		26,384		24,963
International		7,829		8,446
Goodwill		3,638		3,638
Total R&M		37,851		37,047
LUKOIL Investment		6,968		6,416	*
Chemicals		2,735		2,451
Emerging Businesses		984		1,069
Corporate and Other		5,899		2,148
Consolidated total assets	$	151,456		152,138

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

Note 20—Income Taxes

Our effective tax rate for the second quarter and first six months of 2010 was 32 percent and 38 percent, respectively, compared with 55 percent and 57 percent for the same two periods of 2009. The change in the effective tax rate for the second quarter and first six months of 2010, versus the same periods of 2009, was primarily due to the June 2010 disposition of our interest in Syncrude and a higher proportion of income in higher tax rate jurisdictions in 2009, offset in part by the June 2010 impairment of our Wilhelmshaven Refinery. For periods in which the effective tax rate was in excess of the domestic federal statutory rate of 35 percent, it was primarily due to foreign taxes.

26

Supplementary Information—Condensed Consolidating Financial Information

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

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

• All other nonguarantor subsidiaries of ConocoPhillips.

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

This condensed consolidating financial information should be read in conjunction with the accompanying consolidated financial statements and notes.

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

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

27

	Millions of Dollars
	Three Months Ended June 30, 2010
							ConocoPhillips		ConocoPhillips			ConocoPhillips
							Australia		Canada			Canada
				ConocoPhillips			Funding		Funding			Funding			All Other			Consolidating			Total
Income Statement	ConocoPhillips			Company			Company		Company I			Company II			Subsidiaries			Adjustments			Consolidated
Revenues and Other Income
Sales and other operating revenues	$	-			29,414			-		-			-			16,272			-			45,686
Equity in earnings of affiliates		4,305			4,868			-		-			-			995			(9,080	)		1,088
Gain on sale of Syncrude		-			(12	)		-		-			-			2,890			-			2,878
Other income		-			43			-		-			-			432			-			475
Intercompany revenues		2			7			12		22			37			7,411			(7,491	)		-
Total Revenues and Other Income		4,307			34,320			12		22			37			28,000			(16,571	)		50,127
Costs and Expenses
Purchased crude oil, natural gas and products		-			26,239			-		-			-			13,061			(7,212	)		32,088
Production and operating expenses		-			1,084			-		-			-			1,558			(23	)		2,619
Selling, general and administrative expenses		3			294			-		-			-			160			(19	)		438
Exploration expenses		-			56			-		-			-			157			-			213
Depreciation, depletion and amortization		-			397			-		-			-			1,883			-			2,280
Impairments		-			14			-		-			-			1,518			-			1,532
Taxes other than income taxes		-			1,364			-		-			-			2,883			-			4,247
Accretion on discounted liabilities		-			16			-		-			-			97			-			113
Interest and debt expense		216			235			11		20			14			90			(237	)		349
Foreign currency transaction (gains) losses		-			5			-		(86	)		(102	)		237			-			54
Total Costs and Expenses		219			29,704			11		(66	)		(88	)		21,644			(7,491	)		43,933
Income before income taxes		4,088			4,616			1		88			125			6,356			(9,080	)		6,194
Provision for income taxes		(76	)		311			1		10			25			1,740			-			2,011
Net income		4,164			4,305			-		78			100			4,616			(9,080	)		4,183
Less: net income attributable to noncontrolling interests		-			-			-		-			-			(19	)		-			(19	)
Net Income Attributable to ConocoPhillips	$	4,164			4,305			-		78			100			4,597			(9,080	)		4,164
	Millions of Dollars
	Three Months Ended June 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	$	-			21,922			-		-			-			13,526			-			35,448
Equity in earnings of affiliates		948			1,116			-		-			-			289			(1,721	)		632
Other income (loss)		1			116			-		-			-			(11	)		-			106
Intercompany revenues		15			220			12		19			12			3,969			(4,247	)		-
Total Revenues and Other Income		964			23,374			12		19			12			17,773			(5,968	)		36,186
Costs and Expenses
Purchased crude oil, natural gas and products		-			19,297			-		-			-			9,349			(4,037	)		24,609
Production and operating expenses		-			1,120			-		-			-			1,478			(25	)		2,573
Selling, general and administrative expenses		5			309			-		(1	)		(1	)		167			(3	)		476
Exploration expenses		-			51			-		-			-			192			-			243
Depreciation, depletion and amortization		-			415			-		-			-			1,932			-			2,347
Impairments		-			-			-		-			-			51			-			51
Taxes other than income taxes		-			1,212			-		-			-			2,504			(1	)		3,715
Accretion on discounted liabilities		-			19			-		-			-			89			-			108
Interest and debt expense		149			16			11		20			14			239			(181	)		268
Foreign currency transaction (gains) losses		-			(50	)		-		93			116			(301	)		-			(142	)
Total Costs and Expenses		154			22,389			11		112			129			15,700			(4,247	)		34,248
Income (loss) before income taxes		810			985			1		(93	)		(117	)		2,073			(1,721	)		1,938
Provision for income taxes		(49	)		37			-		1			(13	)		1,087			-			1,063
Net income (loss)		859			948			1		(94	)		(104	)		986			(1,721	)		875
Less: net income attributable to noncontrolling interests		-			-			-		-			-			(16	)		-			(16	)
Net Income (Loss) Attributable to ConocoPhillips	$	859			948			1		(94	)		(104	)		970			(1,721	)		859

28

	Millions of Dollars
	Six Months Ended June 30, 2010
							ConocoPhillips		ConocoPhillips			ConocoPhillips
							Australia		Canada			Canada
				ConocoPhillips			Funding		Funding			Funding			All Other			Consolidating			Total
Income Statement	ConocoPhillips			Company			Company		Company I			Company II			Subsidiaries			Adjustments			Consolidated
Revenues and Other Income
Sales and other operating revenues	$	-			57,336			-		-			-			33,171			-			90,507
Equity in earnings of affiliates		6,537			7,188			-		-			-			1,673			(13,442	)		1,956
Gain on sale of Syncrude		-			(12	)		-		-			-			2,890			-			2,878
Other income		-			129			-		-			-			419			-			548
Intercompany revenues		3			274			23		43			50			12,881			(13,274	)		-
Total Revenues and Other Income		6,540			64,915			23		43			50			51,034			(26,716	)		95,889
Costs and Expenses
Purchased crude oil, natural gas and products		-			51,366			-		-			-			25,012			(12,769	)		63,609
Production and operating expenses		-			2,189			-		-			-			3,008			(51	)		5,146
Selling, general and administrative expenses		7			616			-		-			-			285			(26	)		882
Exploration expenses		-			97			-		-			-			499			-			596
Depreciation, depletion and amortization		-			816			-		-			-			3,782			-			4,598
Impairments		-			17			-		-			-			1,606			-			1,623
Taxes other than income taxes		-			2,573			-		-			-			5,711			-			8,284
Accretion on discounted liabilities		-			31			-		-			-			196			-			227
Interest and debt expense		419			248			21		39			27			324			(428	)		650
Foreign currency transaction (gains) losses		-			35			-		(55	)		(53	)		163			-			90
Total Costs and Expenses		426			57,988			21		(16	)		(26	)		40,586			(13,274	)		85,705
Income before income taxes		6,114			6,927			2		59			76			10,448			(13,442	)		10,184
Provision for income taxes		(148	)		390			1		13			20			3,613			-			3,889
Net income		6,262			6,537			1		46			56			6,835			(13,442	)		6,295
Less: net income attributable to noncontrolling interests		-			-			-		-			-			(33	)		-			(33	)
Net Income Attributable to ConocoPhillips	$	6,262			6,537			1		46			56			6,802			(13,442	)		6,262
	Millions of Dollars
	Six Months Ended June 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	$	-			39,456			-		-			-			26,733			-			66,189
Equity in earnings of affiliates		1,837			2,031			-		-			-			528			(3,391	)		1,005
Other income (loss)		(1	)		319			-		-			-			(88	)		-			230
Intercompany revenues		16			602			29		37			23			7,473			(8,180	)		-
Total Revenues and Other Income		1,852			42,408			29		37			23			34,646			(11,571	)		67,424
Costs and Expenses
Purchased crude oil, natural gas and products		-			34,138			-		-			-			17,936			(7,706	)		44,368
Production and operating expenses		2			2,214			-		-			-			2,953			(51	)		5,118
Selling, general and administrative expenses		8			632			-		-			-			324			(13	)		951
Exploration expenses		-			116			-		-			-			352			-			468
Depreciation, depletion and amortization		-			840			-		-			-			3,737			-			4,577
Impairments		-			(5	)		-		-			-			59			-			54
Taxes other than income taxes		-			2,367			-		-			-			4,831			(19	)		7,179
Accretion on discounted liabilities		-			37			-		-			-			175			-			212
Interest and debt expense		279			85			26		39			27			513			(391	)		578
Foreign currency transaction (gains) losses		-			(43	)		-		55			109			(132	)		-			(11	)
Total Costs and Expenses		289			40,381			26		94			136			30,748			(8,180	)		63,494
Income (loss) before income taxes		1,563			2,027			3		(57	)		(113	)		3,898			(3,391	)		3,930
Provision for income taxes		(96	)		190			1		2			(17	)		2,159			-			2,239
Net income (loss)		1,659			1,837			2		(59	)		(96	)		1,739			(3,391	)		1,691
Less: net income attributable to noncontrolling interests		-			-			-		-			-			(32	)		-			(32	)
Net Income (Loss) Attributable to ConocoPhillips	$	1,659			1,837			2		(59	)		(96	)		1,707			(3,391	)		1,659

29

	Millions of Dollars
	June 30, 2010
						ConocoPhillips		ConocoPhillips			ConocoPhillips
						Australia		Canada			Canada
				ConocoPhillips		Funding		Funding			Funding			All Other		Consolidating			Total
Balance Sheet	ConocoPhillips			Company		Company		Company I			Company II			Subsidiaries		Adjustments			Consolidated
Assets
Cash and cash equivalents	$	-			664		-		23			412			6,025		(3,004	)		4,120
Accounts and notes receivable		24			7,220		-		-			-			11,944		(5,991	)		13,197
Inventories		-			4,104		-		-			-			3,015		-			7,119
Short-term investments		-			-		-		-			-			-		-			-
Prepaid expenses and other current assets		18			880		-		1			1			1,330		-			2,230
Total Current Assets		42			12,868		-		24			413			22,314		(8,995	)		26,666
Investments, loans and long-term receivables*		76,121			97,578		761		1,366			563			46,475		(184,513	)		38,351
Net properties, plants and equipment		-			19,421		-		-			-			61,848		-			81,269
Goodwill		-			3,638		-		-			-			-		-			3,638
Intangibles		-			764		-		-			-			44		-			808
Other assets		59			262		1		3			3			396		-			724
Total Assets	$	76,222			134,531		762		1,393			979			131,077		(193,508	)		151,456
Liabilities and Stockholders’ Equity
Accounts payable	$	-			13,513		1		2			1			7,850		(5,991	)		15,376
Short-term debt		(5	)		351		-		-			350			2,386		-			3,082
Accrued income and other taxes		-			386		-		(1	)		7			4,116		-			4,508
Employee benefit obligations		-			465		-		-			-			202		-			667
Other accruals		242			598		9		15			9			1,162		-			2,035
Total Current Liabilities		237			15,313		10		16			367			15,716		(5,991	)		25,668
Long-term debt		11,828			3,702		749		1,250			499			5,169		-			23,197
Asset retirement obligations and accrued environmental costs		-			1,400		-		-			-			6,989		-			8,389
Joint venture acquisition obligation		-			-		-		-			-			4,666		-			4,666
Deferred income taxes		(1	)		3,444		-		22			23			13,524		-			17,012
Employee benefit obligations		-			2,914		-		-			-			922		-			3,836
Other liabilities and deferred credits*		5,587			27,328		-		10			-			16,753		(46,935	)		2,743
Total Liabilities		17,651			54,101		759		1,298			889			63,739		(52,926	)		85,511
Retained earnings		30,416			16,144		1		(3	)		26			16,155		(25,822	)		36,917
Other common stockholders’ equity		28,155			64,286		2		98			64			50,609		(114,760	)		28,454
Noncontrolling interests		-			-		-		-			-			574		-			574
Total Liabilities and Stockholders’ Equity	$	76,222			134,531		762		1,393			979			131,077		(193,508	)		151,456
Balance Sheet	December 31, 2009
Assets
Cash and cash equivalents	$	-			122		-		18			1			554		(153	)		542
Accounts and notes receivable		26			6,495		-		-			-			13,712		(7,018	)		13,215
Inventories		-			2,911		-		-			-			2,029		-			4,940
Short-term investments		-			-		-		2,973			-			-		(2,973	)		-
Prepaid expenses and other current assets		13			835		-		4			3			1,621		(6	)		2,470
Total Current Assets		39			10,363		-		2,995			4			17,916		(10,150	)		21,167
Investments, loans and long-term receivables*		70,769			91,643		759		1,376			933			47,886		(175,272	)		38,094
Net properties, plants and equipment		-			19,838		-		-			-			67,870		-			87,708
Goodwill		-			3,638		-		-			-			-		-			3,638
Intangibles		-			770		-		-			-			53		-			823
Other assets		55			240		1		3			4			509		(104	)		708
Total Assets	$	70,863			126,492		760		4,374			941			134,234		(185,526	)		152,138
Liabilities and Stockholders’ Equity
Accounts payable	$	7			11,590		-		1			1			10,904		(7,018	)		15,485
Short-term debt		235			1,286		-		2,973			-			207		(2,973	)		1,728
Accrued income and other taxes		-			298		-		(1	)		-			3,105		-			3,402
Employee benefit obligations		-			588		-		-			-			258		-			846
Other accruals		262			643		9		15			10			1,301		(6	)		2,234
Total Current Liabilities		504			14,405		9		2,988			11			15,775		(9,997	)		23,695
Long-term debt		12,561			4,053		749		1,250			849			7,463		-			26,925
Asset retirement obligations and accrued environmental costs		-			1,406		-		-			-			7,307		-			8,713
Joint venture acquisition obligation		-			-		-		-			-			5,009		-			5,009
Deferred income taxes		(4	)		2,785		-		10			10			15,155		-			17,956
Employee benefit obligations		-			2,960		-		-			-			1,170		-			4,130
Other liabilities and deferred credits*		2,560			25,819		-		68			37			17,296		(42,683	)		3,097
Total Liabilities		15,621			51,428		758		4,316			907			69,175		(52,680	)		89,525
Retained earnings		25,714			9,607		-		(49	)		(30	)		10,240		(13,268	)		32,214
Other common stockholders’ equity		29,528			65,457		2		107			64			54,229		(119,578	)		29,809
Noncontrolling interests		-			-		-		-			-			590		-			590
Total Liabilities and Stockholders’ Equity	$	70,863			126,492		760		4,374			941			134,234		(185,526	)		152,138

*Includes intercompany loans.

30

	Millions of Dollars
	Six Months Ended June 30, 2010
							ConocoPhillips			ConocoPhillips		ConocoPhillips
							Australia			Canada		Canada
				ConocoPhillips			Funding			Funding		Funding		All Other			Consolidating			Total
Statement of Cash Flows	ConocoPhillips			Company			Company			Company I		Company II		Subsidiaries			Adjustments			Consolidated
Cash Flows From Operating Activities
Net Cash Provided by Operating Activities	$	2,906			4,090			-			5		27		3,227			(3,740	)		6,515
Cash Flows From Investing Activities
Capital expenditures and investments		-			(853	)		-			-		-		(3,549	)		322			(4,080	)
Proceeds from asset dispositions		-			165			-			-		-		5,877			(99	)		5,943
Long-term advances/loans—related parties		-			(335	)		-			-		-		(66	)		132			(269	)
Collection of advances/loans—related parties		-			71			-			-		384		1,363			(1,738	)		80
Other		-			-			-			-		-		9			-			9
Net Cash Provided by (Used in) Investing Activities		-			(952	)		-			-		384		3,634			(1,383	)		1,683
Cash Flows From Financing Activities
Issuance of debt		-			-			-			-		-		197			(132	)		65
Repayment of debt		(990	)		(2,629	)		-			-		-		(554	)		1,738			(2,435	)
Issuance of company common stock		35			-			-			-		-		-			-			35
Repurchase of company common stock		(390	)		-			-			-		-		-			-			(390	)
Dividends paid on common stock		(1,560	)		-			-			-		-		(889	)		889			(1,560	)
Other		(1	)		18			-			-		-		(149	)		(223	)		(355	)
Net Cash Provided by (Used in) Financing Activities		(2,906	)		(2,611	)		-			-		-		(1,395	)		2,272			(4,640	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents		-			15			-			-		-		5			-			20
Net Change in Cash and Cash Equivalents		-			542			-			5		411		5,471			(2,851	)		3,578
Cash and cash equivalents at beginning of period		-			122			-			18		1		554			(153	)		542
Cash and Cash Equivalents at End of Period	$	-			664			-			23		412		6,025			(3,004	)		4,120
	Millions of Dollars
	Six Months Ended June 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	$	(5,340	)		5,976			-			4		-		5,669			(1,857	)		4,452
Cash Flows From Investing Activities
Capital expenditures and investments		-			(1,779	)		-			-		-		(4,035	)		236			(5,578	)
Proceeds from asset dispositions		-			5			-			-		-		227			-			232
Long-term advances/loans—related parties		-			11			-			-		-		(136	)		4			(121	)
Collection of advances/loans—related parties		-			97			950			-		-		3,783			(4,794	)		36
Other		-			(107	)		-			-		-		30			-			(77	)
Net Cash Provided by (Used in) Investing Activities		-			(1,773	)		950			-		-		(131	)		(4,554	)		(5,508	)
Cash Flows From Financing Activities
Issuance of debt		8,910			-			-			-		-		123			(4	)		9,029
Repayment of debt		(2,109	)		(4,081	)		(950	)		-		-		(3,763	)		4,794			(6,109	)
Issuance of company common stock		(21	)		-			-			-		-		-			-			(21	)
Dividends paid on common stock		(1,393	)		-			-			-		-		(1,871	)		1,871			(1,393	)
Other		(47	)		2			-			-		-		(125	)		(236	)		(406	)
Net Cash Provided by (Used in) Financing Activities		5,340			(4,079	)		(950	)		-		-		(5,636	)		6,425			1,100
Effect of Exchange Rate Changes on Cash and Cash Equivalents		-			-			-			-		-		89			-			89
Net Change in Cash and Cash Equivalents		-			124			-			4		-		(9	)		14			133
Cash and cash equivalents at beginning of period		-			8			-			10		1		750			(14	)		755
Cash and Cash Equivalents at End of Period	$	-			132			-			14		1		741			-			888

31

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

Management’s Discussion and Analysis contains forward-looking statements including, without limitation, statements relating to our plans, strategies, objectives, expectations, and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “forecast,” “intend,” “believe,” “expect,” “plan,” “schedule,” “target,” “should,” “goal,” “may,” “anticipate,” “estimate,” and similar expressions identify forward-looking statements. We do not undertake to update, revise or correct any of the forward-looking information. Readers are cautioned that such forward-looking statements should be read in conjunction with the disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995” beginning on page 51.

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 June 30, 2010, we had approximately 29,900 employees worldwide and total assets of $151 billion.

Earnings in the second quarter of 2010 were positively impacted by strong crude oil prices compared with 2009. The price of West Texas Intermediate (WTI) benchmark crude oil steadily trended upward during 2009 and into the first quarter of 2010 before leveling out in the second quarter of 2010. WTI averaged $77.78 per barrel in the second quarter of 2010, or $18.24 higher than the second quarter of 2009, and in-line with the first quarter of 2010. Crude prices fell slightly during the second quarter of 2010 due to continued concerns about the strength of the global economic recovery.

Henry Hub natural gas prices averaged $4.09 per million British thermal units in the second quarter of 2010, or $0.58 higher than second quarter 2009, and $1.21 lower than the first quarter of 2010. The decrease in natural gas prices during 2010 resulted from the return to normal weather after a colder-than-normal January and February, continued robust storage inventory levels and strong domestic production.

Our Exploration and Production (E&P) segment had earnings of $4,114 million in the second quarter of 2010. This compares with earnings of $1,832 million in the first quarter of 2010 and $725 million in the second quarter of 2009. The increase in the second quarter of 2010 was primarily due to the $2,679 million after-tax gain on sale of our Syncrude oil sands mining operation and substantially higher crude oil, natural gas and natural gas liquids prices.

Global refining margins continued to improve into the second quarter of 2010. The U.S. benchmark 3:2:1 crack spread increased by almost 50 percent in the second quarter of 2010, compared with the first quarter of 2010, while the N.W. Europe benchmark increased by approximately 25 percent. Domestic refined product demand increased due to improved economic conditions. European refining margins also improved, as refinery shutdowns for planned maintenance, in addition to unexpected outages, resulted in constrained supply and thereby contributed to conditions which helped increase crack spreads.

Our Refining and Marketing (R&M) segment benefited from the improved market conditions; however, we reported a loss of $279 million in the second quarter of 2010, compared with a loss of $4 million in the first quarter of 2010 and a loss of $52 million in the second quarter of 2009. The loss in the second quarter of 2010 was the result of the $1,103 million after-tax property impairment of our refinery in Wilhelmshaven, Germany.

32

RESULTS OF OPERATIONS

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

Consolidated Results

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

	Millions of Dollars
	Three Months Ended						Six Months Ended
	June 30						June 30
	2010			2009			2010			2009
Exploration and Production (E&P)	$	4,114			725			5,946			1,425
Midstream		61			31			138			154
Refining and Marketing (R&M)		(279	)		(52	)		(283	)		153
LUKOIL Investment		529			243	*		916			251	*
Chemicals		138			67			248			90
Emerging Businesses		(10	)		2			(4	)		2
Corporate and Other		(389	)		(157	)		(699	)		(416	)
Net income attributable to ConocoPhillips	$	4,164			859			6,262			1,659

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

Earnings were $4,164 million in the second quarter of 2010, compared with $859 million in the second quarter of 2009. For the six-month periods ended June 30, 2010 and 2009, earnings were $6,262 million and $1,659 million, respectively. The improvement in both periods of 2010 was primarily the result of:

• The $2,679 million after-tax gain on sale of our 9.03 percent interest in the Syncrude oil sands mining operation.

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

• Improved earnings from our LUKOIL Investment segment, primarily resulting from increased equity earnings. For the six-month period of 2009, equity earnings were not recorded in the first quarter, since our LUKOIL investment was written down to fair value at December 31, 2008.

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

These increases were partially offset by:

• The $1,103 million after-tax property impairment on our refinery in Wilhelmshaven, Germany, recorded in the second quarter of 2010.

• Lower production volumes from our E&P segment.

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

Income Statement Analysis

Sales and other operating revenues increased 29 percent in the second quarter of 2010 and 37 percent in the six-month period, while purchased crude oil, natural gas and products increased 30 percent and 43 percent, respectively. These increases were primarily due to significantly higher prices for petroleum products, crude oil and natural gas liquids.

33

Equity in earnings of affiliates increased 72 percent in the second quarter of 2010 and 95 percent in the six-month period. The increases in both periods primarily resulted from:

• Improved earnings from LUKOIL as a result of higher prices, partially offset by higher extraction taxes and export tariffs.

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

In addition, equity earnings for the six-month period of 2010 were influenced by:

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

• Lower results from WRB Refining LLC primarily due to lower margins and lower volumes.

• Improved earnings from our LUKOIL Investment segment. Equity earnings were not recorded in the first quarter of 2009 under lag accounting, since our LUKOIL investment was written down to fair value at December 31, 2008.

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

Other income increased $369 million in the second quarter of 2010 and $318 million in the six-month period of 2010. The increases in both periods reflect the gain on sale of our 50 percent interest in CFJ Properties, our 50/50 joint venture with Flying J, in addition to the gain on the divestiture of our LUKOIL shares, which began during the second quarter of 2010.

Impairments increased $1,481 million in the second quarter of 2010 and $1,569 million in the six-month period of 2010. The increases in both periods primarily reflect the second quarter 2010 impairment of our refinery in Wilhelmshaven, Germany.

Taxes other than income taxes increased 14 percent during the second quarter of 2010 and 15 percent in the six-month period of 2010, primarily due to higher production taxes as a result of higher crude oil prices and higher excise taxes on petroleum product sales.

Interest expense increased 30 percent during the second quarter of 2010 and 12 percent in the six-month period of 2010. The increases in both periods were primarily due to higher average fixed debt levels and higher net interest expense associated with tax rulings.

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

34

Segment Results

E&P

	Three Months Ended					Six Months Ended
	June 30					June 30
	2010		2009			2010		2009
	Millions of Dollars
Net Income (Loss) Attributable to ConocoPhillips
Alaska	$	381		404			898		648
Lower 48		155		(68	)		395		(139	)
United States		536		336			1,293		509
International		3,578		389			4,653		916
	$	4,114		725			5,946		1,425
	Dollars Per Unit
Average Sales Prices
Crude oil and natural gas liquids (per barrel)
United States	$	68.15		49.86			69.31		43.77
International		73.34		53.52			73.20		47.85
Total consolidated operations		71.00		51.77			71.46		45.94
Equity affiliates		72.46		55.44			71.89		48.28
Total E&P		71.09		51.98			71.49		46.07
Synthetic oil (per barrel)
International		76.60		58.71			77.56		51.14
Bitumen (per barrel)
International		45.81		40.65			52.68		30.00
Equity affiliates		49.73		46.90			53.04		36.69
Total E&P		49.19		46.10			52.99		35.70
Natural gas (per thousand cubic feet)
United States		3.94		3.00			4.57		3.41
International		4.95		4.27			5.34		5.07
Total consolidated operations		4.53		3.72			5.03		4.35
Equity affliliates		3.02		2.10			2.86		2.10
Total E&P		4.50		3.69			4.98		4.31
	Millions of Dollars
Worldwide Exploration Expenses
General administrative; geological and geophysical; and lease rentals	$	141		128			391		230
Leasehold impairment		44		49			84		92
Dry holes		28		66			121		146
	$	213		243			596		468

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	Three Months Ended				Six Months Ended
	June 30				June 30
	2010		2009		2010		2009
	Thousands of Barrels Daily
Operating Statistics
Crude oil and natural gas liquids produced
Alaska		221		252		234		263
Lower 48		161		170		159		166
United States		382		422		393		429
Canada		42		41		41		42
Europe		198		240		217		250
Asia Pacific/Middle East		136		126		140		133
Africa		79		76		78		76
Other areas		-		7		-		8
Total consolidated operations		837		912		869		938
Equity affiliates
Russia		56		55		56		52
		893		967		925		990
Synthetic oil produced
Consolidated operations—Canada		25		16		23		20
Bitumen produced
Consolidated operations—Canada		10		6		9		6
Equity affiliates—Canada		48		41		50		38
		58		47		59		44
	Millions of Cubic Feet Daily
Natural gas produced*
Alaska		82		83		88		88
Lower 48		1,740		2,012		1,722		2,020
United States		1,822		2,095		1,810		2,108
Canada		1,043		1,174		1,032		1,120
Europe		749		849		854		924
Asia Pacific/Middle East		673		721		695		717
Africa		144		118		141		115
Total consolidated operations		4,431		4,957		4,532		4,984
Equity affiliates
Asia Pacific/Middle East		110		94		101		85
		4,541		5,051		4,633		5,069

*Represents quantities available for sale. Excludes gas equivalent of natural gas liquids included above.

Equity affiliate statistics exclude our share of LUKOIL, which is reported in the LUKOIL Investment segment.

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The E&P segment explores for, produces, transports and markets crude oil, bitumen, natural gas and natural gas liquids on a worldwide basis. At June 30, 2010, our E&P operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, offshore Timor-Leste in the Timor Sea, Indonesia, China, Vietnam, Libya, Nigeria, Algeria, and Russia. Total E&P production on a barrel-of-equivalent (BOE) basis averaged 1,733,000 BOE per day in the second quarter of 2010, compared with 1,872,000 BOE in the second quarter of 2009.

Earnings from our E&P segment were $4,114 million in the second quarter of 2010, compared with earnings of $725 million in the second quarter of 2009. E&P earnings for the first six months of 2010 and 2009 were $5,946 million and $1,425 million, respectively. The increases for both periods in 2010 were primarily due to the $2,679 million after-tax gain on sale of our Syncrude oil sands mining operation in June 2010 and higher crude oil, natural gas and natural gas liquids prices. These increases were partially offset by higher production taxes, as a result of higher prices, and lower crude oil and natural gas volumes. See the “Business Environment and Executive Overview” section for additional information on industry crude oil and natural gas prices.

U.S. E&P
Our U.S. E&P operations reported earnings of $536 million in the second quarter of 2010, compared with earnings of $336 million for the same period in 2009. Domestic E&P earnings for the first six months of 2010 and 2009 were $1,293 million and $509 million, respectively. The increases for both periods in 2010 were primarily the result of higher crude oil and natural gas prices, which were partially offset by higher production taxes in Alaska, lower crude oil and natural gas volumes, and an unfavorable tax ruling.

U.S. E&P production averaged 686,000 BOE per day in the second quarter of 2010, a decrease of 11 percent from 771,000 BOE in the second quarter of 2009. The decrease was primarily due to field decline and unplanned downtime, which was partially offset by new production.

International E&P
International E&P earnings were $3,578 million in the second quarter of 2010, or $3,189 million higher than the comparative period in 2009. International earnings for the first six months of 2010 and 2009 were $4,653 million and $916 million, respectively. In addition to the gain on sale of our Syncrude oil sands mining operation, results for both periods were influenced by higher crude oil, natural gas and natural gas liquids prices. These increases were partially offset by higher petroleum and export taxes, as a result of higher prices. Results for the six-month period of 2010 were also negatively impacted by the $85 million after-tax write-off of project costs resulting from our decision to end participation in the Shah Gas Field Project in Abu Dhabi.

International E&P production averaged 1,047,000 BOE per day in the second quarter of 2010, a decrease of 5 percent from 1,101,000 BOE in the second quarter of 2009. The decrease was largely due to field decline and planned downtime, which was slightly offset by production from new developments primarily in China, Canada and Indonesia.

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Midstream

	Three Months Ended				Six Months Ended
	June 30				June 30
	2010		2009		2010		2009
	Millions of Dollars
Net Income Attributable to ConocoPhillips*	$	61		31		138		154
*Includes DCP Midstream-related earnings:	$	31		12		84		102

	Dollars Per Barrel
Average Sales Prices
U.S. natural gas liquids*
Consolidated	$	43.21	29.99	46.07	28.01
Equity affiliates		38.11	26.02	41.88	24.94

*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		190	188	188	180
Natural gas liquids fractionated**		156	174	158	167

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

**Excludes DCP Midstream.

The Midstream segment purchases raw natural gas from producers and gathers natural gas through an extensive network of pipeline gathering systems. The natural gas is then processed to extract natural gas liquids from the raw gas stream. The remaining “residue” gas is marketed to electrical utilities, industrial users, and gas marketing companies. Most of the natural gas liquids are fractionated—separated into individual components like ethane, butane and propane—and marketed as chemical feedstock, fuel or blendstock. The Midstream segment consists of our 50 percent equity investment in DCP Midstream, LLC, as well as our other natural gas gathering and processing operations, and natural gas liquids fractionation, trading and marketing businesses, primarily in the United States and Trinidad.

Earnings from the Midstream segment increased 97 percent in the second quarter of 2010 and decreased 10 percent during the first six months of 2010. Both periods were positively impacted by significantly higher natural gas liquids prices, as well as improved volumes from our equity affiliate, Phoenix Park Gas Processors Limited. These increases were slightly offset by lower marketing and trading results and higher operating costs resulting from increased turnaround activity in the second quarter of 2010. In addition, results for the six-month period of 2009 included the recognition of an $88 million after-tax benefit, which resulted from a DCP Midstream subsidiary converting subordinated units to common units.

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R&M

	Three Months Ended						Six Months Ended
	June 30						June 30
	2010			2009			2010			2009
	Millions of Dollars
Net Income (Loss) Attributable to ConocoPhillips
United States	$	782			(38	)		794			60
International		(1,061	)		(14	)		(1,077	)		93
	$	(279	)		(52	)		(283	)		153
	Dollars Per Gallon
U.S. Average Wholesale Prices*
Gasoline	$	2.25			1.84			2.21			1.62
Distillates		2.28			1.67			2.22			1.54

*Excludes excise taxes.

	Thousands of Barrels Daily
Operating Statistics
Refining operations*
United States
Crude oil capacity		1,986		1,986	1,986	1,986
Crude oil runs		1,913		1,852	1,828	1,721
Capacity utilization (percent)		96	%	93	92	87
Refinery production		2,100		2,018	2,000	1,868
International
Crude oil capacity		671		671	671	671
Crude oil runs		362		485	343	526
Capacity utilization (percent)		54	%	72	51	78
Refinery production		364		499	351	537
Worldwide
Crude oil capacity		2,657		2,657	2,657	2,657
Crude oil runs		2,275		2,337	2,171	2,247
Capacity utilization (percent)		86	%	88	82	85
Refinery production		2,464		2,517	2,351	2,405
Petroleum products sales volumes
United States
Gasoline		1,170		1,180	1,131	1,109
Distillates		921		924	864	837
Other products		387		378	377	353
		2,478		2,482	2,372	2,299
International		566		630	555	619
		3,044		3,112	2,927	2,918

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

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

R&M reported a loss of $279 million in the second quarter of 2010, compared with a loss of $52 million in the corresponding period of 2009. For the first six months of 2010, R&M reported a loss of $283 million, compared with earnings of $153 million for the same period in 2009. Our losses in the 2010 periods were largely due to a $1,103 million after-tax property impairment to our refinery in Wilhelmshaven, Germany, which was recorded in the second quarter of 2010. For additional information, see Note 8—Impairments, in the Notes to Consolidated Financial Statements.

Excluding the impact from the Wilhelmshaven property impairment, R&M experienced an improvement in earnings for both 2010 periods due to significantly improved global refining and marketing margins. Results also included a $116 million after-tax gain on the sale of CFJ Properties, our 50/50 joint venture with Flying J, lower domestic operating expenses, the absence of a $72 million after-tax Keystone Pipeline impairment recorded in the second quarter of 2009 and higher volumes. These increases were partially offset by negative foreign currency impacts. See the “Business Environment and Executive Overview” section for additional information on industry refining margins.

U.S. R&M
U.S. R&M reported earnings of $782 million in the second quarter of 2010 and earnings of $794 million for the first six months of 2010, compared with a loss of $38 million and earnings of $60 million for the respective periods in 2009. The increases in both periods primarily resulted from improved refining and marketing margins, the gain on sale of CFJ, the 2009 Keystone Pipeline impairment and higher refining and marketing volumes. In addition, lower operating costs contributed to the improvement for the six-month period of 2010.

Our U.S. refining crude oil capacity utilization rate was 96 percent in the second quarter of 2010, compared with 93 percent in the second quarter of 2009. The increase was primarily due to less unplanned downtime and lower turnaround activity.

International R&M
International R&M reported a loss of $1,061 million in the second quarter of 2010 and a loss of $1,077 million for the six-month period of 2010, compared with a loss of $14 million and earnings of $93 million for the respective periods in 2009. The decreases in both periods were primarily due to the Wilhelmshaven impairment and negative foreign currency impacts, which were partially offset by improved refining and marketing margins. The six-month period of 2010 also included a $29 million after-tax impairment resulting from our decision to end participation in the Yanbu Refinery Project, in addition to lower refining volumes.

Our international refining crude oil capacity utilization rate was 54 percent in the second quarter of 2010, compared with 72 percent in the second quarter of 2009. The current year rate primarily reflects increased run reductions at Wilhelmshaven in response to market conditions and higher unplanned downtime, partially offset by lower turnaround activity.

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LUKOIL Investment

	Million of Dollars
	Three Months Ended					Six Months Ended
	June 30					June 30
	2010		2009		*	2010		2009		*
Net Income Attributable to ConocoPhillips	$	529		243			916		251
Operating Statistics
Crude oil production (thousands of barrels daily)		382		385			386		389
Natural gas produced (millions of cubic feet daily)		368		297			340		315
Refinery crude oil processed (thousands of barrels daily)		248		231			247		228

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

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 June 30, 2010, our ownership interest in LUKOIL was 19.21 percent based on authorized and issued shares. Our average ownership interest in the first quarter of 2010, used to record our share of LUKOIL’s first-quarter results on a lag basis, was 20.09 percent.

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

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

LUKOIL segment earnings were $529 million in the second quarter of 2010, compared with earnings of $243 million in the second quarter of 2009. Earnings for the six-month period of 2010 were $916 million, compared with earnings of $251 million in the corresponding period of 2009. The increase in the second quarter of 2010 was primarily the result of significantly higher refined product and crude oil prices and the $99 million gain on the sale of 6.7 million shares of our LUKOIL investment in the second quarter of 2010. These increases were partially offset by higher extraction taxes and export tariffs. In addition, for the six-month period of 2009, equity earnings from LUKOIL were not recorded in the first quarter, since our LUKOIL investment was written down in the fourth quarter of 2008 to its fair value at December 31, 2008.

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Chemicals

	Millions of Dollars
	Three Months Ended				Six Months Ended
	June 30				June 30
	2010		2009		2010		2009
Net Income Attributable to ConocoPhillips	$	138		67		248		90

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 $138 million in the second quarter of 2010, compared with $67 million in the second quarter of 2009. Chemicals earnings were $248 million in the first half of 2010, compared with $90 million in 2009. The increase in both periods reflects higher margins primarily in the olefins and polyolefins business line, and to a lesser extent, the specialties, aromatics and styrenics business line. These increases were partially offset by higher operating costs primarily resulting from increased turnaround activity in the second quarter of 2010.

Emerging Businesses

	Millions of Dollars
	Three Months Ended						Six Months Ended
	June 30						June 30
	2010			2009			2010			2009
Net Income (Loss) Attributable to ConocoPhillips
Power	$	17			27			46			51
Other		(27	)		(25	)		(50	)		(49	)
	$	(10	)		2			(4	)		2

The Emerging Businesses segment represents our investment in new technologies or businesses outside our normal scope of operations. Activities within this segment are currently focused on power generation and innovation of new technologies, such as those related to conventional and nonconventional hydrocarbon recovery (including heavy oil), refining, alternative energy, biofuels and the environment.

The Emerging Businesses segment reported a loss of $10 million in the second quarter of 2010, compared with earnings of $2 million in the same quarter of 2009. Losses for the first six months of 2010 were $4 million, compared with earnings of $2 million in the first six months of 2009. The decrease in earnings in the second quarter was primarily due to lower domestic and international power generation results. The decrease for the six-month period was mainly due to lower international power generation results, partially offset by improved domestic power generation results.

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Corporate and Other

	Millions of Dollars
	Three Months Ended						Six Months Ended
	June 30						June 30
	2010			2009			2010			2009
Net Income (Loss) Attributable to ConocoPhillips
Net interest	$	(254	)		(175	)		(476	)		(365	)
Corporate general and administrative expenses		(47	)		(31	)		(83	)		(72	)
Other		(88	)		49			(140	)		21
	$	(389	)		(157	)		(699	)		(416	)

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 45 percent in the second quarter of 2010 and 30 percent in the first six months of 2010. The increase in both periods was primarily due to higher average fixed debt levels and higher net interest expense associated with tax rulings. Corporate general and administrative expenses increased 52 percent in the second quarter of 2010 and 15 percent in the six-month period. The increase in the second quarter of 2010 was primarily due to costs related to compensation plans, in addition to timing of association dues and charitable contributions. The increase in the six-month period of 2010 was primarily the result of compensation plan costs. The category “Other” includes certain foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation, and other costs not directly associated with an operating segment. Changes in the “Other” category primarily reflect higher foreign currency transaction losses in both 2010 periods.

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CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators

	Millions of Dollars
	June 30			December 31
	2010			2009
Short-term debt	$	3,082			1,728
Total debt*	$	26,279			28,653
Total equity	$	65,945			62,613	**
Percent of total debt to capital***		28	%		31
Percent of floating-rate debt to total debt		8	%		9

    *Total debt includes short-term and long-term debt, as shown on our consolidated balance sheet.

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

***Capital includes total debt and total equity.

To meet our short- and long-term liquidity requirements, we look to a variety of funding sources. Cash generated from operating activities is the primary source of funding. During the second quarter of 2010, available cash was used to support our ongoing capital expenditures and investments program, provide loan financing to certain equity affiliates, pay dividends, and meet the funding requirements to FCCL Partnership. Total dividends paid on our common stock during the first six months were $1,560 million. During the first half of 2010, cash and cash equivalents increased $3,578 million to $4,120 million.

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

Significant Sources of Capital

Operating Activities
During the first six months of 2010, cash of $6,515 million was provided by operating activities, a 46 percent increase from cash from operations of $4,452 million in the corresponding period of 2009. The improvement was primarily due to higher commodity prices and improved refining and marketing margins, partially offset by a discretionary inventory build.

While the stability of our cash flows from operating activities benefits from geographic diversity and the effects of upstream and downstream integration, our short- and long-term operating cash flows are highly dependent upon prices for crude oil, natural gas and natural gas liquids, as well as refining and marketing margins. During the first six months of 2010, crude oil and natural gas prices were higher than in the same period of 2009. Prices and margins in our industry are typically volatile, and are driven by market conditions over which we have no control. Absent other mitigating factors, as these prices and margins fluctuate, we would expect a corresponding change in our operating cash flows.

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

44

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 six months of 2010 totaled $5.9 billion, which included $4.6 billion from the sale of our 9.03 percent interest in the Syncrude Canada Ltd. joint venture (Syncrude). In addition, proceeds included the sale of our interest in CFJ Properties and the sale of a portion of our interest in LUKOIL. We plan to raise an additional $4 billion to $5 billion through the end of 2011, as part of our previously-announced $10 billion asset disposition program. Proceeds from this program are primarily targeted toward debt reduction.

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

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

Our primary funding source for short-term working capital needs is the ConocoPhillips $6.35 billion commercial paper program. Commercial paper maturities are generally limited to 90 days. We also have the ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program, which is used to fund commitments relating to the Qatargas 3 Project. At June 30, 2010, and December 31, 2009, we had no direct borrowings under the revolving credit facilities, but $40 million in letters of credit had been issued at both periods. In addition, under the two ConocoPhillips commercial paper programs, $1,126 million of commercial paper was outstanding at June 30, 2010, compared with $1,300 million at December 31, 2009. Since we had $1,126 million of commercial paper outstanding and had issued $40 million of letters of credit, we had access to $6.7 billion in borrowing capacity under our revolving credit facilities at June 30, 2010.

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

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Off-Balance Sheet Arrangements

As part of our normal ongoing business operations and consistent with normal industry practice, we enter into numerous agreements with other parties to pursue business opportunities, which share costs and apportion risks among the parties as governed by the agreements. At June 30, 2010, 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. The other participants in the project are affiliates of Qatar Petroleum (68.5 percent) and Mitsui & Co., Ltd. (1.5 percent). Our interest is held through a jointly owned company, Qatar Liquefied Gas Company Limited (3), for which we use the equity method of accounting. Qatargas 3 secured project financing of $4 billion in December 2005, consisting of $1.3 billion of loans from export credit agencies (ECA), $1.5 billion from commercial banks, and $1.2 billion from ConocoPhillips. The ConocoPhillips loan facilities have substantially the same terms as the ECA and commercial bank facilities. Prior to project completion certification, all loans, including the ConocoPhillips loan facilities, are guaranteed by the participants, based on their respective ownership interests. Accordingly, our maximum exposure to this financing structure is $1.2 billion. Upon completion certification, currently expected in 2011, all project loan facilities, including the ConocoPhillips loan facilities, will become nonrecourse to the project participants. At June 30, 2010, Qatargas 3 had approximately $3.9 billion outstanding under all the loan facilities, of which ConocoPhillips provided $1.1 billion, and an additional $93 million of accrued interest.

• Rockies Express Pipeline: In the second quarter of 2010, the credit facilities of Rockies Express Pipeline LLC were reduced, and our guarantee was released.

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

Capital Requirements

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

Our debt balance at June 30, 2010, was $26.3 billion, a decrease of $2.4 billion from the balance at December 31, 2009. In July, make-whole redemption notices were issued on bonds totaling $2.7 billion, and the bonds were repaid in August.

We are obligated to contribute $7.5 billion, plus interest, over a 10-year period that began in 2007, to FCCL. Quarterly principal and interest payments of $237 million began in the second quarter of 2007 and will continue until the balance is paid. Of the principal obligation amount, approximately $677 million was short-term and was included in the “Accounts payable—related parties” line on our June 30, 2010, consolidated balance sheet. The principal portion of these payments, which totaled $325 million in the first six months of 2010, is included in the “Other” line in the financing activities section of our consolidated statement of cash flows. Interest accrues at a fixed annual rate of 5.3 percent on the unpaid principal balance. Fifty percent of the quarterly interest payment is reflected as a capital contribution and is included in the “Capital expenditures and investments” line on our consolidated statement of cash flows.

We have provided loan financing to WRB Refining LLC, to assist it in meeting its operating and capital spending requirements. At June 30, 2010, $550 million of such financing was outstanding and $400 million was classified as long term.

In July 2010, we announced a quarterly dividend of 55 cents per share. The dividend is payable September 1, 2010, to stockholders of record at the close of business August 2, 2010.

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On March 24, 2010, we announced plans to purchase up to $5 billion of our common stock over the subsequent two years. Repurchase of shares began in April and totaled 6,894,686 shares at a cost of $390 million, through June 30, 2010.

Capital Spending

Capital Expenditures and Investments

	Millions of Dollars
	Six Months Ended
	June 30
	2010		2009
E&P
United States—Alaska	$	375		481
United States—Lower 48		604		1,451
International		2,616		2,503
		3,595		4,435
Midstream		-		4
R&M
United States		289		826
International		129		193
		418		1,019
LUKOIL Investment		-		-
Chemicals		-		-
Emerging Businesses		5		73
Corporate and Other		62		47
	$	4,080		5,578
United States	$	1,330		2,819
International		2,750		2,759
	$	4,080		5,578

E&P

Our E&P capital expenditures and investments budget for 2010 has been increased by $0.5 billion, to $9.4 billion. Capital spending for E&P during the first six months of 2010 totaled $3.6 billion. The expenditures supported key exploration and development projects including:

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

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

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

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

• Qatargas 3 Project in Qatar.

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

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

• The Kashagan Field in the Caspian Sea.

• Onshore developments in Nigeria and Algeria.

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

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R&M

Capital spending for R&M during the first six months of 2010 totaled $418 million and included projects related to sustaining and improving the existing business with a focus on safety, regulatory compliance and reliability.

Contingencies

Legal and Tax Matters
We accrue a liability for known contingencies (other than those related to income taxes) when a loss is probable and the amounts can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. In the case of income-tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain. Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements.

Environmental
We are subject to the same numerous international, federal, state and local environmental laws and regulations as other companies in the petroleum exploration and production, refining, and crude oil and refined product marketing and transportation businesses. For a discussion of the most significant of these environmental laws and regulations, including those with associated remediation obligations, see the “Environmental” section in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 58, 59 and 60 of our 2009 Annual Report on Form 10-K.

We, from time to time, receive requests for information or notices of potential liability from the Environmental Protection Agency (EPA) and state environmental agencies alleging that we are a potentially responsible party under the Federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain wastes attributable to our past operations. As of December 31, 2009, we reported we had been notified of potential liability under CERCLA and comparable state laws at 65 sites around the United States. At June 30, 2010, we were notified of four new sites and re-opened two sites bringing the number to 71 unresolved sites with potential liability.

At June 30, 2010, our balance sheet included a total environmental accrual of $971 million, compared with $1,017 million at December 31, 2009. We expect to incur a substantial amount of these expenditures within the next 30 years.

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

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

48

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

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

OUTLOOK

On May 27, 2010, in response to the Deepwater Horizon incident in the Gulf of Mexico (GOM), the U.S. Department of the Interior (DOI) issued a six-month drilling moratorium on new deepwater wells in the Outer Continental Shelf (OCS). Although a U.S. federal appeals court has upheld a lower court’s decision to lift the drilling ban, an ongoing appeals process is underway. In addition, on July 12, 2010, the DOI issued a second drilling moratorium for drilling from floating rigs, which will be in effect until November 30, 2010. A lawsuit has also been filed against this second moratorium. The U.S. Government has also implemented a number of regulatory requirements on drilling activities and has proposed legislation to impose further restrictions on drilling. As a result of this uncertain regulatory climate, our planned exploration and appraisal drilling on deepwater prospects in the GOM have been delayed. There are no material impacts to our near-term production. Future impacts of these regulatory proposals on our business are not known at this time.

In order to improve industry spill response, we recently announced plans to partner with Exxon Mobil Corp., Chevron Corp. and Royal Dutch Shell PLC to develop a new oil spill containment system. We plan to build and deploy a rapid response system that will be available to capture and contain oil in the event of a potential future underwater well blowout in the deepwater GOM. The four companies will form a non-profit organization, the Marine Well Containment Company, to operate and maintain this system.

In a February 2008 lease sale conducted by the DOI under the OCS Lands Act, we successfully bid, and were awarded 10-year-primary-term leases on 98 blocks in the Chukchi Sea, for total bid payments of $506 million. Various special interest groups have brought two separate lawsuits challenging (1) the DOI’s entire OCS leasing program, and (2) the Chukchi Sea lease sale conducted by the DOI under that program. In the first suit, the Court ordered the DOI to reconsider one aspect of its OCS leasing program. The draft revised program was issued on March 31, 2010, and affirmed the 2008 Chukchi Sea lease sale as part of the 2007-2012 program, but removed any future lease sales for the Alaska OCS in that program. The draft revised program was subject to public comment until May 3, 2010, but issuance of the final decision has been delayed due to the large volume of comments received.

In the second suit, on July 21, 2010, the federal district court issued a decision finding two flaws in the Bureau of Ocean Energy Management, Regulation, and Enforcement’s environmental review, remanding the matter to the agency for further proceedings, and enjoining any activities under the leases until the remand is complete. The court issued the final judgment on the decision on July 22, 2010, and that judgment is subject to appeal for 60 days after issuance. Our plans for drilling an exploration well on our Chukchi Sea leases are under review in light of the court’s decision.

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On July 28, 2010, we announced our intention to sell our entire interest in LUKOIL, then consisting of 163,367,629 shares. This decision will be implemented as follows:

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

• Also pursuant to the Agreement, the LUKOIL subsidiary has a 60-day option, expiring on September 26, 2010, to purchase any or all of our interest remaining at the time of exercise of the option, at a price of $56 per share.

• Finally, to the extent all of our remaining interest is not purchased pursuant to the 60-day option, we intend to sell our remaining interest in the open market from time to time, subject to the terms of the Shareholder Agreement, by the end of 2011.

We expect to use the proceeds from these transactions primarily to repurchase ConocoPhillips common stock.

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

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

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

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

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

• Unsuccessful exploratory drilling activities or the inability to obtain access to exploratory acreage.

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

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

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

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

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

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

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

• International monetary conditions and exchange controls.

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

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

• Liability resulting from litigation.

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

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

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

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

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

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

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

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Item 4. CONTROLS AND PROCEDURES

As of June 30, 2010, with the participation of our management, our Chairman and Chief Executive Officer (principal executive officer) and our Senior Vice President, Finance and Chief Financial Officer (principal financial officer) carried out an evaluation, pursuant to Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the Act), of the effectiveness of the design and operation of ConocoPhillips’ disclosure controls and procedures (as defined in Rule 13a-15(e) of the Act). Based upon that evaluation, our Chairman and Chief Executive Officer and our Senior Vice President, Finance and Chief Financial Officer concluded that our disclosure controls and procedures were operating effectively as of June 30, 2010.

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

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PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

The following is a description of reportable legal proceedings including those involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment for this reporting period. The following proceedings include those matters that arose during the second quarter of 2010 and any material developments with respect to matters previously reported in ConocoPhillips’ 2009 Annual Report on Form 10-K or first-quarter 2010 Quarterly Report on Form 10-Q. Material developments to the previously reported matters have been included in the descriptions below. While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings was decided adversely to ConocoPhillips, we expect there would be no material effect on our consolidated financial position. Nevertheless, such proceedings are reported pursuant to the 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 that could be subject to a request for stipulated penalties. If a specific request for stipulated penalties meeting the reporting threshold set forth in SEC rules is made pursuant to these decrees based on a given reported exceedance, we will separately report that matter and the amount of the proposed penalty.

New Matters
On May 19, 2010, the Lake Charles Louisiana Refinery received a Consolidated Compliance Order and Notice of Potential Penalty from the Louisiana Department of Environmental Quality (LDEQ) alleging various violations of applicable air emission regulations, as well as certain provisions of the consent decree in Civil Action No. H-01-4430. ConocoPhillips will work with the LDEQ to resolve this matter.

Matters Previously Reported
On February 26, 2009, we received a $159,000 demand from the South Coast Air Quality Management District to settle seven Notices of Violation for alleged violations of air pollution control regulations at the Los Angeles Refinery. We have resolved this matter with a settlement payment of $125,000.

Polar Tankers, Inc. and ConocoPhillips paid $588,000, with no admission of liability, for a natural resource damage assessment associated with a 2004 spill in Puget Sound. The trustees intend to use the funds on restoration projects in the area.

In 2009, ConocoPhillips notified the EPA and the U.S. Department of Justice (DOJ) that it had self-identified certain compliance issues related to Benzene Waste Operations National Emission Standard for Hazardous Air Pollutants requirements at its Trainer, Pennsylvania and Borger, Texas facilities. On January 6, 2010, the DOJ provided its initial penalty demand for this matter as part of our confidential settlement negotiations. ConocoPhillips has reached an agreement with the EPA and DOJ regarding an appropriate penalty amount, which will be reflected in the third amendment to the consent decree in Civil Action No. H-05-258 (the agreed-upon penalty amount remains confidential until that time).

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

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Item 1A. RISK FACTORS

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

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

Issuer Purchases of Equity Securities

									Millions of Dollars
						Total Number of			Approximate Dollar
						Shares Purchased			Value of Shares
						as Part of Publicly			that May Yet Be
	Total Number of			Average Price		Announced Plans			Purchased Under the
Period	Shares Purchased		*	Paid per Share		or Programs		**	Plans or Programs
April 1-30, 2010		4,548,943		$	56.93		4,455,000		$	4,746
May 1-31, 2010		2,445,006			55.99		2,439,686			4,610
June 1-30, 2010		-			-		-			4,610
Total		6,993,949		$	56.60		6,894,686

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

**On March 24, 2010, we announced plans to purchase up to $5 billion of our common stock over the subsequent two years. Acquisitions for the share repurchase program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Repurchases may be increased, decreased or discontinued at any time without prior notice. Shares of stock repurchased under the plan are held as treasury shares.

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Item 6. EXHIBITS

10	Amended Agreement, dated July 28, 2010, to the Shareholder Agreement, dated September 29, 2004, by and between ConocoPhillips and LUKOIL (incorporated by reference to Exhibit 99.2 to the Current Report of ConocoPhillips on Form 8-K filed on July 28, 2010; File No. 001-32395).
12	Computation of Ratio of Earnings to Fixed Charges.
31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
32	Certifications pursuant to 18 U.S.C. Section 1350.
101.INS	XBRL Instance Document.
101.SCH	XBRL Schema Document.
101.CAL	XBRL Calculation Linkbase Document.
101.LAB	XBRL Labels Linkbase Document.
101.PRE	XBRL Presentation Linkbase Document.
101.DEF	XBRL Definition Linkbase Document.

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SIGNATURE

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

	CONOCOPHILLIPS
	/s/ Glenda M. Schwarz
	Glenda M. Schwarz
	Vice President and Controller
	(Chief Accounting and Duly Authorized Officer)
August 4, 2010

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EX-12

Exhibit 12

CONOCOPHILLIPS AND CONSOLIDATED SUBSIDIARIES
TOTAL ENTERPRISE

Computation of Ratio of Earnings to Fixed Charges

	Millions of Dollars
	Six Months Ended
	June 30
	2010			2009		**
Earnings Available for Fixed Charges
Income from continuing operations before income taxes and noncontrolling interests that have not incurred fixed charges	$	10,154			3,907
Distributions less than equity in earnings of affiliates		(1,189	)		(606	)
Fixed charges, excluding capitalized interest*		859			781
	$	9,824			4,082
Fixed Charges
Interest and debt expense, excluding capitalized interest	$	650			578
Capitalized interest		239			249
Interest portion of rental expense		102			103
	$	991			930
Ratio of Earnings to Fixed Charges		9.9			4.4

  *Includes amortization of capitalized interest totaling approximately $107 million in 2010 and $99 million in 2009.

**Recast to reflect a change in accounting principle. See Note 2—Changes in Accounting Principles in the company’s Quarterly Report on Form 10-Q for the period ended June 30, 2010, for more information.

EX-31.1

Exhibit 31.1

CERTIFICATION

I, James J. Mulva, certify that:

1. I have reviewed this quarterly report on Form 10-Q of ConocoPhillips;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

August 4, 2010

/s/ James J. Mulva

James J. Mulva

Chairman and

Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Sigmund L. Cornelius, certify that:

1. I have reviewed this quarterly report on Form 10-Q of ConocoPhillips;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

August 4, 2010

/s/ Sigmund L. Cornelius

Sigmund L. Cornelius

Senior Vice President, Finance and

Chief Financial Officer

EX-32

Exhibit 32

CERTIFICATIONS PURSUANT TO 18 U.S.C. SECTION 1350

          In connection with the Quarterly Report of ConocoPhillips (the company) on Form 10-Q for the period ended June 30, 2010, as filed with the U.S. Securities and Exchange Commission on the date hereof (the Report), each of the undersigned hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to their knowledge:

(1) The Report fully complies with the requirements of Sections 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the company.

August 4, 2010

/s/ James J. Mulva

James J. Mulva

Chairman and

Chief Executive Officer

/s/ Sigmund L. Cornelius

Sigmund L. Cornelius

Senior Vice President, Finance and

Chief Financial Officer