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Exhibit 99.3

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

CONOCOPHILLIPS

INDEX TO FINANCIAL STATEMENTS

		Page
Report of Management			2
Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements			3
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting			4
Consolidated Income Statement for the years ended December 31, 2011, 2010 and 2009			5
Consolidated Statement of Comprehensive Income for the years ended December  31, 2011, 2010 and 2009			6
Consolidated Balance Sheet at December 31, 2011 and 2010			7
Consolidated Statement of Cash Flows for the years ended December 31, 2011, 2010 and 2009			8
Consolidated Statement of Changes in Equity for the years ended December 31, 2011, 2010 and 2009			9
Notes to Consolidated Financial Statements			10
Supplementary Information
Oil and Gas Operations			67
Selected Quarterly Financial Data			93
Condensed Consolidating Financial Information			94

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Report of Management

Management prepared, and is responsible for, the consolidated financial statements and the other information appearing in this annual report. The consolidated financial statements present fairly the company’s financial position, results of operations and cash flows in conformity with accounting principles generally accepted in the United States. In preparing its consolidated financial statements, the company includes amounts that are based on estimates and judgments management believes are reasonable under the circumstances. The company’s financial statements have been audited by Ernst & Young LLP, an independent registered public accounting firm appointed by the Audit and Finance Committee of the Board of Directors and ratified by stockholders. Management has made available to Ernst & Young LLP all of the company’s financial records and related data, as well as the minutes of stockholders’ and directors’ meetings.

Assessment of Internal Control Over Financial Reporting

Management is also responsible for establishing and maintaining adequate internal control over financial reporting. ConocoPhillips’ internal control system was designed to provide reasonable assurance to the company’s management and directors regarding the preparation and fair presentation of published financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2011. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework. Based on our assessment, we believe the company’s internal control over financial reporting was effective as of December 31, 2011.

Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of December 31, 2011, and their report is included herein.

/s/ James J. Mulva		/s/ Jeff W. Sheets
James J. Mulva		Jeff W. Sheets
Chairman, President and		Senior Vice President, Finance
and Chief Executive Officer		and Chief Financial Officer
February 21, 2012

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Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements

The Board of Directors and Stockholders

ConocoPhillips

We have audited the accompanying consolidated balance sheets of ConocoPhillips as of December 31, 2011 and 2010, and the related consolidated statements of income, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the related condensed consolidating financial information listed in the Index at Item 8 and financial statement schedule listed in Item 15(a). These financial statements, condensed consolidating financial information, and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements, condensed consolidating financial information, and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of ConocoPhillips at December 31, 2011 and 2010, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related condensed consolidating financial information and financial statement schedule, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), ConocoPhillips’ internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 21, 2012 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 21, 2012

except for the matters discussed in Notes 25 and 26,

as to which the date is

December 3, 2012

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Report of Independent Registered Public Accounting Firm on

Internal Control Over Financial Reporting

The Board of Directors and Stockholders

ConocoPhillips

We have audited ConocoPhillips’ internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). ConocoPhillips’ management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included under the heading “Assessment of Internal Control Over Financial Reporting” in the accompanying “Report of Management.” Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, ConocoPhillips maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2011 consolidated financial statements of ConocoPhillips and our report dated February 21, 2012, except for the matters discussed in Notes 25 and 26, as to which the date is December 3, 2012, expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 21, 2012

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Consolidated Income Statement ConocoPhillips

		Millions of Dollars
Years Ended December 31		2011				2010				2009
Revenues and Other Income
Sales and other operating revenues		$	65,756				57,296				48,828
Equity in earnings of affiliates			1,234				1,368				1,439
Gain on dispositions			370				5,563				81
Other income			274				182				257
Total Revenues and Other Income			67,634				64,409				50,605
Costs and Expenses
Purchased commodities			29,975				24,969				21,349
Production and operating expenses			6,742				6,525				6,291
Selling, general and administrative expenses			867				811				664
Exploration expenses			1,066				1,155				1,182
Depreciation, depletion and amortization			7,015				8,169				8,407
Impairments			321				81				469
Taxes other than income taxes			4,021				2,804				1,862
Accretion on discounted liabilities			426				417				389
Interest and debt expense			954				1,167				1,267
Foreign currency transaction (gains) losses			22				(1	)			11
Total Costs and Expenses			51,409				46,097				41,891
Income from continuing operations before income taxes			16,225				18,312				8,714
Provision for income taxes			8,770				7,863				4,917
Income From Continuing Operations			7,455				10,449				3,797
Income from discontinued operations*			5,047				968				695
Net income			12,502				11,417				4,492
Less: net income attributable to noncontrolling interests			(66	)			(59	)			(78	)
Net Income Attributable to ConocoPhillips		$	12,436				11,358				4,414
Amounts Attributable to ConocoPhillips Common Shareholders:
Income from continuing operations		$	7,394				10,395				3,723
Income from discontinued operations			5,042				963				691
Net income		$	12,436				11,358				4,414
Net Income Attributable to ConocoPhillips Per Share of Common Stock (dollars)
Basic
Continuing operations		$	5.38				7.03				2.50
Discontinued operations			3.66				0.65				0.46
Net Income Attributable to ConocoPhillips Per Share of Common Stock		$	9.04				7.68				2.96
Diluted
Continuing operations		$	5.33				6.97				2.48
Discontinued operations			3.64				0.65				0.46
Net Income Attributable to ConocoPhillips Per Share of Common Stock		$	8.97				7.62				2.94
Average Common Shares Outstanding (in thousands)
Basic			1,375,035				1,479,330				1,487,650
Diluted			1,387,100				1,491,067				1,497,608
* Net of provision for income taxes on discontinued operations of:		$	1,729				470				173

See Notes to Consolidated Financial Statements.

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Consolidated Statement of Comprehensive Income ConocoPhillips

		Millions of Dollars
Years Ended December 31		2011				2010				2009
Net Income		$	12,502				11,417				4,492
Other comprehensive income (loss)
Defined benefit plans
Prior service cost (credit) arising during the period			19				(13	)			—
Reclassification adjustment for amortization of prior service cost included in net income			2				15				21
Net change			21				2				21
Net actuarial loss arising during the period			(1,185	)			(9	)			(388	)
Reclassification adjustment for amortization of prior net losses included in net income			226				215				206
Net change			(959	)			206				(182	)
Nonsponsored plans*			(50	)			5				39
Income taxes on defined benefit plans			375				(67	)			52
Defined benefit plans, net of tax			(613	)			146				(70	)
Unrealized holding gain on securities**			8				631				—
Reclassification adjustment for gain included in net income			(255	)			(384	)			—
Income taxes on unrealized holding gain on securities			89				(89	)			—
Unrealized gain on securities, net of tax			(158	)			158				—
Foreign currency translation adjustments			(387	)			1,417				5,092
Reclassification adjustment for gain included in net income			(516	)			—				—
Income taxes on foreign currency translation adjustments			(14	)			(13	)			(85	)
Foreign currency translation adjustments, net of tax			(917	)			1,404				5,007
Hedging activities			1				—				(2	)
Income taxes on hedging activities			—				—				5
Hedging activities, net of tax			1				—				3
Other Comprehensive Income (Loss), Net of Tax			(1,687	)			1,708				4,940
Comprehensive income			10,815				13,125				9,432
Less: comprehensive income attributable to noncontrolling interests			(66	)			(59	)			(78	)
Comprehensive Income Attributable to ConocoPhillips		$	10,749				13,066				9,354

* Plans for which ConocoPhillips is not the primary obligor—primarily those administered by equity affiliates.

** Available-for-sale securities of LUKOIL.

See Notes to Consolidated Financial Statements.

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Consolidated Balance Sheet ConocoPhillips

		Millions of Dollars
At December 31		2011**				2010**
Assets
Cash and cash equivalents		$	5,780				9,454
Short-term investments*			581				973
Accounts and notes receivable (net of allowance of $30 million in 2011 and $32 million in 2010)			14,648				13,787
Accounts and notes receivable—related parties			1,878				2,025
Investment in LUKOIL			—				1,083
Inventories			4,631				5,197
Prepaid expenses and other current assets			2,700				2,141
Total Current Assets			30,218				34,660
Investments and long-term receivables			32,108				31,581
Loans and advances—related parties			1,675				2,180
Net properties, plants and equipment			84,180				82,554
Goodwill			3,332				3,633
Intangibles			745				801
Other assets			972				905
Total Assets		$	153,230				156,314
Liabilities
Accounts payable		$	17,973				16,613
Accounts payable—related parties			1,680				1,786
Short-term debt			1,013				936
Accrued income and other taxes			4,220				4,874
Employee benefit obligations			1,111				1,081
Other accruals			2,071				2,129
Total Current Liabilities			28,068				27,419
Long-term debt			21,610				22,656
Asset retirement obligations and accrued environmental costs			9,329				9,199
Joint venture acquisition obligation—related party			3,582				4,314
Deferred income taxes			18,040				17,320
Employee benefit obligations			4,068				3,683
Other liabilities and deferred credits			2,784				2,599
Total Liabilities			87,481				87,190
Equity
Common stock (2,500,000,000 shares authorized at $.01 par value) Issued (2011—1,749,550,587 shares; 2010—1,740,529,279 shares)
Par value			17				17
Capital in excess of par			44,725				44,132
Grantor trusts (at cost: 2010—36,890,375 shares)			—				(633	)
Treasury stock (at cost: 2011—463,880,628 shares; 2010—272,873,537 shares)			(31,787	)			(20,077	)
Accumulated other comprehensive income			3,246				4,933
Unearned employee compensation			(11	)			(47	)
Retained earnings			49,049				40,252
Total Common Stockholders’ Equity			65,239				68,577
Noncontrolling interests			510				547
Total Equity			65,749				69,124
Total Liabilities and Equity		$	153,230				156,314
*        Includes marketable securities of:		$	232				602

** Certain amounts have been restated to reflect a prior period adjustment. See Note 21—Accumulated Other Comprehensive Income, in the Notes to Consolidated Financial Statements.

See Notes to Consolidated Financial Statements.

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Consolidated Statement of Cash Flows ConocoPhillips

		Millions of Dollars
Years Ended December 31		2011				2010				2009
Cash Flows From Operating Activities
Net income		$	12,502				11,417				4,492
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization			7,015				8,169				8,407
Impairments			321				81				469
Dry hole costs and leasehold impairments			470				477				606
Accretion on discounted liabilities			426				417				389
Deferred taxes			408				(865	)			(1,036	)
Undistributed equity earnings			(126	)			(350	)			(693	)
Gain on dispositions			(370	)			(5,563	)			(81	)
Income from discontinued operations			(5,047	)			(968	)			(695	)
Other			(390	)			(333	)			330
Working capital adjustments
Decrease (increase) in accounts and notes receivable			(983	)			247				1,324
Decrease (increase) in inventories			(73	)			(35	)			83
Decrease (increase) in prepaid expenses and other current assets			(334	)			(14	)			158
Increase (decrease) in accounts payable			1,234				227				(1,340	)
Increase (decrease) in taxes and other accruals			(576	)			1,546				(1,030	)
Net cash provided by continuing operating activities			14,477				14,453				11,383
Net cash provided by discontinued operations			5,169				2,592				1,096
Net Cash Provided by Operating Activities			19,646				17,045				12,479
Cash Flows From Investing Activities
Capital expenditures and investments			(12,244	)			(8,611	)			(8,400	)
Proceeds from asset dispositions			2,192				14,710				512
Net sales (purchases) of short-term investments			400				(982	)			—
Long-term advances/loans—related parties			(9	)			(113	)			(175	)
Collection of advances/loans—related parties			98				95				92
Other			56				218				9
Net cash provided by (used in) continuing investing activities			(9,507	)			5,317				(7,962	)
Net cash provided by (used in) discontinued operations			2,492				(652	)			(1,973	)
Net Cash Provided by (Used in) Investing Activities			(7,015	)			4,665				(9,935	)
Cash Flows From Financing Activities
Issuance of debt			—				118				9,087
Repayment of debt			(934	)			(5,294	)			(7,833	)
Issuance of company common stock			96				133				13
Repurchase of company common stock			(11,123	)			(3,866	)			—
Dividends paid on company common stock			(3,632	)			(3,175	)			(2,832	)
Other			(684	)			(706	)			(1,261	)
Net cash used in continuing financing activities			(16,277	)			(12,790	)			(2,826	)
Net cash used in discontinued operations			(28	)			(29	)			(29	)
Net Cash Used in Financing Activities			(16,305	)			(12,819	)			(2,855	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents			—				21				98
Net Change in Cash and Cash Equivalents			(3,674	)			8,912				(213	)
Cash and cash equivalents at beginning of year			9,454				542				755
Cash and Cash Equivalents at End of Year		$	5,780				9,454				542

See Notes to Consolidated Financial Statements.

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Consolidated Statement of Changes in Equity ConocoPhillips

		Millions of Dollars
		Attributable to ConocoPhillips
		Common Stock																Accum. Other Comprehensive Income (Loss)				Unearned Employee Compensation				Retained Earnings				Noncontrolling Interests				Total
		Par Value				Capital in Excess of Par				Treasury Stock				Grantor Trusts
December 31, 2008*		$	17				43,396				(16,211	)			(702	)			(1,684	)			(102	)			30,452				1,100				56,266
Net income																											4,414				78				4,492
Other comprehensive income																			4,940																4,940
Cash dividends paid on company common stock																											(2,832	)							(2,832	)
Distributions to noncontrolling interests and other																															(588	)			(588	)
Distributed under benefit plans							285								35																				320
Recognition of unearned compensation																							26												26
Other*																			(31	)							35								4
December 31, 2009*			17				43,681				(16,211	)			(667	)			3,225				(76	)			32,069				590				62,628
Net income																											11,358				59				11,417
Other comprehensive income																			1,708																1,708
Cash dividends paid on company common stock																											(3,175	)							(3,175	)
Repurchase of company common stock											(3,866	)																							(3,866	)
Distributions to noncontrolling interests and other																															(102	)			(102	)
Distributed under benefit plans							451								34																				485
Recognition of unearned compensation																							29												29
December 31, 2010*			17				44,132				(20,077	)			(633	)			4,933				(47	)			40,252				547				69,124
Net income																											12,436				66				12,502
Other comprehensive income (loss)																			(1,687	)															(1,687	)
Cash dividends paid on company common stock																											(3,632	)							(3,632	)
Repurchase of company common stock											(11,133	)			10																				(11,123	)
Distributions to noncontrolling interests and other																															(103	)			(103	)
Distributed under benefit plans							593				33				13																				639
Recognition of unearned compensation																							36												36
Transfer to treasury stock											(610	)			610																				—
Other																											(7	)							(7	)
December 31, 2011*		$	17				44,725				(31,787	)			—				3,246				(11	)			49,049				510				65,749

* Certain amounts have been restated to reflect a prior period adjustment. See Note 21—Accumulated Other Comprehensive Income, in the Notes to Consolidated Financial Statements.

See Notes to Consolidated Financial Statements.

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Notes to Consolidated Financial Statements ConocoPhillips

Note 1—Accounting Policies

• Consolidation Principles and Investments—Our consolidated financial statements include the accounts of majority-owned, controlled subsidiaries and variable interest entities where we are the primary beneficiary. The equity method is used to account for investments in affiliates in which we have the ability to exert significant influence over the affiliates’ operating and financial policies. When we do not have the ability to exert significant influence, the investment is either classified as available-for-sale if fair value is readily determinable, or the cost method is used if fair value is not readily determinable. Undivided interests in oil and gas joint ventures, pipelines, natural gas plants and terminals are consolidated on a proportionate basis. Other securities and investments are generally carried at cost.

As a result of our separation of Phillips 66 on April 30, 2012, the results of operations for our former refining, marketing and transportation businesses; most of our former Midstream segment; our former Chemicals segment; and our power generation and certain technology operations included in our former Emerging Businesses segment (collectively, our “Downstream business”), have been classified as discontinued operations for all periods presented. See Note 26—Separation of Downstream Business, for additional information. Additionally, we have realigned our reporting segments following the separation of Phillips 66 and have reflected those changes for all periods presented. We manage our operations through six operating segments, defined by geographic region: Alaska, Lower 48 and Latin America, Canada, Europe, Asia Pacific and Middle East, and Other International. For additional information, see Note 25—Segment Disclosures and Related Information.

• Foreign Currency Translation—Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in accumulated other comprehensive income in common stockholders’ equity. Foreign currency transaction gains and losses are included in current earnings. Most of our foreign operations use their local currency as the functional currency.

• Use of Estimates—The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Actual results could differ from these estimates.

• Revenue Recognition—Revenues associated with sales of crude oil, bitumen, natural gas, liquefied natural gas (LNG), natural gas liquids and other items are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery of goods occurs, either immediately or within a fixed delivery schedule that is reasonable and customary in the industry.

Revenues associated with producing properties in which we have an interest with other producers are recognized based on the actual volumes we sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, which are deemed to be nonrecoverable through remaining production, are recognized as accounts receivable or accounts payable, as appropriate. Cumulative differences between volumes sold and entitlement volumes are generally not significant.

Revenues associated with transactions commonly called buy/sell contracts, in which the purchase and sale of inventory with the same counterparty are entered into “in contemplation” of one another, are combined and reported net (i.e., on the same income statement line).

• Shipping and Handling Costs—We include shipping and handling costs in production and operating expenses for production activities. Transportation costs related to marketing activities are recorded in purchased crude oil, natural gas and products. Freight costs billed to customers were recorded as a component of revenue.

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• Cash Equivalents—Cash equivalents are highly liquid, short-term investments that are readily convertible to known amounts of cash and have original maturities of 90 days or less from their date of purchase. They are carried at cost plus accrued interest, which approximates fair value.

• Short-Term Investments—Investments in bank time deposits and marketable securities (commercial paper and government obligations) with original maturities of greater than 90 days but less than one year are classified as short-term investments. See Note 16—Financial Instruments and Derivative Contracts, for additional information on these held-to-maturity financial instruments.

• Inventories—We have several valuation methods for our various types of inventories and consistently use the following methods for each type of inventory. Crude oil and petroleum products inventories are valued at the lower of cost or market in the aggregate, primarily on the last-in, first-out (LIFO) basis. Any necessary lower-of-cost-or-market write-downs at year end are recorded as permanent adjustments to the LIFO cost basis. LIFO is used to better match current inventory costs with current revenues and to meet tax-conformity requirements. Costs include both direct and indirect expenditures incurred in bringing an item or product to its existing condition and location, but not unusual/nonrecurring costs or research and development costs. Materials, supplies and other miscellaneous inventories, such as tubular goods and well equipment, are valued using various methods, including the weighted-average-cost method, and the first-in, first-out (FIFO) method, consistent with industry practice.

• Fair Value Measurements—We categorize assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1 for the asset or liability, either directly or indirectly through market-corroborated inputs. Level 3 inputs are unobservable inputs for the asset or liability reflecting significant modifications to observable related market data or our assumptions about pricing by market participants.

• Derivative Instruments—Derivative instruments are recorded on the balance sheet at fair value. If the right of offset exists and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the balance sheet and the collateral payable or receivable is netted against derivative assets and derivative liabilities, respectively.

Recognition and classification of the gain or loss that results from recording and adjusting a derivative to fair value depends on the purpose for issuing or holding the derivative. Gains and losses from derivatives not accounted for as hedges are recognized immediately in earnings. For derivative instruments that are designated and qualify as a fair value hedge, the gains or losses from adjusting the derivative to its fair value will be immediately recognized in earnings and, to the extent the hedge is effective, offset the concurrent recognition of changes in the fair value of the hedged item. Gains or losses from derivative instruments that are designated and qualify as a cash flow hedge or hedge of a net investment in a foreign entity are recognized in other comprehensive income and appear on the balance sheet in accumulated other comprehensive income until the hedged transaction is recognized in earnings; however, to the extent the change in the value of the derivative exceeds the change in the anticipated cash flows of the hedged transaction, the excess gains or losses will be recognized immediately in earnings.

• Oil and Gas Exploration and Development—Oil and gas exploration and development costs are accounted for using the successful efforts method of accounting.

Property Acquisition Costs—Oil and gas leasehold acquisition costs are capitalized and included in the balance sheet caption properties, plants and equipment (PP&E). Leasehold impairment is recognized based on exploratory experience and management’s judgment. Upon achievement of all conditions necessary for reserves to be classified as proved, the associated leasehold costs are reclassified to proved properties.

Exploratory Costs—Geological and geophysical costs and the costs of carrying and retaining undeveloped properties are expensed as incurred. Exploratory well costs are capitalized, or “suspended,” on the balance sheet pending further evaluation of whether economically recoverable

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reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. If exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the reserves and the economic and operating viability of the project is being made. For complex exploratory discoveries, it is not unusual to have exploratory wells remain suspended on the balance sheet for several years while we perform additional appraisal drilling and seismic work on the potential oil and gas field or while we seek government or co-venturer approval of development plans or seek environmental permitting. Once all required approvals and permits have been obtained, the projects are moved into the development phase, and the oil and gas resources are designated as proved reserves.

Management reviews suspended well balances quarterly, continuously monitors the results of the additional appraisal drilling and seismic work, and expenses the suspended well costs as dry holes when it judges the potential field does not warrant further investment in the near term. See Note 8—Suspended Wells, for additional information on suspended wells.

Development Costs—Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized.

Depletion and Amortization—Leasehold costs of producing properties are depleted using the unit-of-production method based on estimated proved oil and gas reserves. Amortization of intangible development costs is based on the unit-of-production method using estimated proved developed oil and gas reserves.

• Capitalized Interest—Interest from external borrowings is capitalized on major projects with an expected construction period of one year or longer. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful lives of the assets in the same manner as the underlying assets.

• Intangible Assets Other Than Goodwill—Intangible assets that have finite useful lives are amortized by the straight-line method over their useful lives. Intangible assets that have indefinite useful lives are not amortized but are tested at least annually for impairment. Each reporting period, we evaluate the remaining useful lives of intangible assets not being amortized to determine whether events and circumstances continue to support indefinite useful lives. These indefinite lived intangibles are considered impaired if the fair value of the intangible asset is lower than net book value. The fair value of intangible assets is determined based on quoted market prices in active markets, if available. If quoted market prices are not available, fair value of intangible assets is determined based upon the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants, or upon estimated replacement cost, if expected future cash flows from the intangible asset are not determinable.

• Goodwill—Goodwill resulting from a business combination is not amortized but is tested at least annually for impairment. If the fair value of a reporting unit is less than the recorded book value of the reporting unit’s assets (including goodwill), less liabilities, then a hypothetical purchase price allocation is performed on the reporting unit’s assets and liabilities using the fair value of the reporting unit as the purchase price in the calculation. If the amount of goodwill resulting from this hypothetical purchase price allocation is less than the recorded amount of goodwill, the recorded goodwill is written down to the new amount. The Company’s remaining goodwill resides in its discontinued Downstream business and has been evaluated for impairment on a worldwide basis.

• Depreciation and Amortization—Depreciation and amortization of PP&E on producing hydrocarbon properties and certain pipeline assets (those which are expected to have a declining utilization pattern), are determined by the unit-of-production method. Depreciation and amortization of all other PP&E are determined by either the individual-unit-straight-line method or the group-straight-line method (for those individual units that are highly integrated with other units).

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• Impairment of Properties, Plants and Equipment—PP&E used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group and annually in the fourth quarter following updates to corporate planning assumptions. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value through additional amortization or depreciation provisions and reported as impairments in the periods in which the determination of the impairment is made. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets—generally on a field-by-field basis for exploration and production assets, or at an entire complex level for downstream assets. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or based on a multiple of operating cash flow validated with historical market transactions of similar assets where possible. Long-lived assets committed by management for disposal within one year are accounted for at the lower of amortized cost or fair value, less cost to sell, with fair value determined using a binding negotiated price, if available, or present value of expected future cash flows as previously described.

The expected future cash flows used for impairment reviews and related fair value calculations are based on estimated future production volumes, prices and costs, considering all available evidence at the date of review. If the future production price risk has been hedged, the hedged price is used in the calculations for the period and quantities hedged. The impairment review includes cash flows from proved developed and undeveloped reserves, including any development expenditures necessary to achieve that production. Additionally, when probable reserves exist, an appropriate risk-adjusted amount of these reserves may be included in the impairment calculation.

• Impairment of Investments in Nonconsolidated Entities—Investments in nonconsolidated entities are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred and annually following updates to corporate planning assumptions. When such a condition is judgmentally determined to be other than temporary, the carrying value of the investment is written down to fair value. The fair value of the impaired investment is based on quoted market prices, if available, or upon the present value of expected future cash flows using discount rates believed to be consistent with those used by principal market participants, plus market analysis of comparable assets owned by the investee, if appropriate.

• Maintenance and Repairs—Costs of maintenance and repairs, which are not significant improvements, are expensed when incurred.

• Advertising Costs—Production costs of media advertising are deferred until the first public showing of the advertisement. Advances to secure advertising slots at specific sporting or other events are deferred until the event occurs. All other advertising costs are expensed as incurred, unless the cost has benefits that clearly extend beyond the interim period in which the expenditure is made, in which case the advertising cost is deferred and amortized ratably over the interim periods that clearly benefit from the expenditure.

• Property Dispositions—When complete units of depreciable property are sold, the asset cost and related accumulated depreciation are eliminated, with any gain or loss reflected in the “Gain on dispositions” line of our consolidated income statement. When less than complete units of depreciable property are disposed of or retired, the difference between asset cost and salvage value is charged or credited to accumulated depreciation.

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• Asset Retirement Obligations and Environmental Costs—The fair value of legal obligations to retire and remove long-lived assets are recorded in the period in which the obligation is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, we capitalize this cost by increasing the carrying amount of the related PP&E. Over time the liability is increased for the change in its present value, and the capitalized cost in PP&E is depreciated over the useful life of the related asset. For additional information, see Note 11—Asset Retirement Obligations and Accrued Environmental Costs, for additional information.

Environmental expenditures are expensed or capitalized, depending upon their future economic benefit. Expenditures relating to an existing condition caused by past operations, and those having no future economic benefit, are expensed. Liabilities for environmental expenditures are recorded on an undiscounted basis (unless acquired in a purchase business combination) when environmental assessments or cleanups are probable and the costs can be reasonably estimated. Recoveries of environmental remediation costs from other parties, such as state reimbursement funds, are recorded as assets when their receipt is probable and estimable.

• Guarantees—Fair value of a guarantee is determined and recorded as a liability at the time the guarantee is given. The initial liability is subsequently reduced as we are released from exposure under the guarantee. We amortize the guarantee liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of guarantee. In cases where the guarantee term is indefinite, we reverse the liability when we have information indicating the liability is essentially relieved or amortize it over an appropriate time period as the fair value of our guarantee exposure declines over time. We amortize the guarantee liability to the related income statement line item based on the nature of the guarantee. When it becomes probable that we will have to perform on a guarantee, we accrue a separate liability if it is reasonably estimable, based on the facts and circumstances at that time. We reverse the fair value liability only when there is no further exposure under the guarantee.

• Stock-Based Compensation—We recognize stock-based compensation expense over the shorter of the service period (i.e., the stated period of time required to earn the award) or the period beginning at the start of the service period and ending when an employee first becomes eligible for retirement. We have elected to recognize expense on a straight-line basis over the service period for the entire award, whether the award was granted with ratable or cliff vesting.

• Income Taxes—Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial reporting basis and the tax basis of our assets and liabilities, except for deferred taxes on income considered to be permanently reinvested in certain foreign subsidiaries and foreign corporate joint ventures. Allowable tax credits are applied currently as reductions of the provision for income taxes. Interest related to unrecognized tax benefits is reflected in interest expense, and penalties in production and operating expenses.

• Taxes Collected from Customers and Remitted to Governmental Authorities—Excise taxes are reported gross within sales and other operating revenues and taxes other than income taxes, while other sales and value-added taxes are recorded net in taxes other than income taxes.

• Net Income Per Share of Common Stock—Basic net income per share of common stock is calculated based upon the daily weighted-average number of common shares outstanding during the year, including unallocated shares held by the stock savings feature of the ConocoPhillips Savings Plan. Also, this calculation includes fully vested stock and unit awards that have not been issued. Diluted net income per share of common stock includes the above, plus unvested stock, unit or option awards granted under our compensation plans and vested but unexercised stock options, but only to the extent these instruments dilute net income per share. For the purpose of the 2009 earnings per share calculation, net income attributable to ConocoPhillips was reduced by $12 million for the excess of the amount paid for the redemption of a noncontrolling interest over its carrying value, which was charged directly to retained earnings. Treasury stock and shares held by grantor trusts are excluded from the daily weighted-average number of common shares outstanding in both calculations.

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Note 2—Changes in Accounting Principles

Comprehensive Income

Effective December 31, 2011, we early adopted Financial Accounting Standards Board (FASB) Accounting Standards Update (ASU) No. 2011-05, “Presentation of Comprehensive Income.” This ASU amends FASB Accounting Standards Codification (ASC) Topic 220, “Comprehensive Income,” by requiring a more prominent presentation of the components of other comprehensive income. We elected the two-statement approach presenting other comprehensive income in a separate statement immediately following the income statement. On December 23, 2011, the FASB issued ASU 2011-12, “Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in ASU No. 2011-05.” ASU 2011-12 defers the ASU 2011-05 requirement to present items reclassified into net income from other comprehensive income. This deferral only impacted the presentation requirement on the consolidated income statement.

Note 3—Variable Interest Entities (VIEs)

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

We have an agreement with Freeport LNG Development, L.P. (Freeport LNG) to participate in an LNG receiving terminal in Quintana, Texas. We have no ownership in Freeport LNG; however, we own a 50 percent interest in Freeport LNG GP, Inc. (Freeport GP), which serves as the general partner managing the venture. We entered into a credit agreement with Freeport LNG, whereby we agreed to provide loan financing for the construction of the terminal. We also entered into a long-term agreement with Freeport LNG to use 0.9 billion cubic feet per day of regasification capacity. The terminal became operational in June 2008, and we began making payments under the terminal use agreement. Freeport LNG began making loan repayments in September 2008, and the loan balance outstanding as of December 31, 2011, was $612 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 performed an analysis of the expected losses and determined we are not the primary beneficiary. This expected loss analysis took into account that the credit support arrangement requires Freeport LNG to maintain sufficient commercial insurance to mitigate any loan losses. The loan to Freeport LNG is accounted for as a financial asset, and our investment in Freeport GP is accounted for as an equity investment.

Note 4—Inventories

Inventories at December 31 were:

		Millions of Dollars
		2011				2010
Crude oil and petroleum products		$	3,633				4,254
Materials, supplies and other			998				943
		$	4,631				5,197

Inventories valued on the LIFO basis totaled $3,387 million and $4,051 million at December 31, 2011 and 2010, respectively. The estimated excess of current replacement cost over LIFO cost of inventories amounted to approximately $8,400 million and $6,800 million at December 31, 2011 and 2010, respectively. In 2011, a liquidation of LIFO inventory values increased net income attributable to ConocoPhillips $160 million, of which $155 million was attributable to the discontinued R&M segment.

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Note 5—Assets Held for Sale or Sold

In December 2011, we sold our ownership interests in Colonial Pipeline Company and Seaway Crude Pipeline Company. The total carrying value of these assets, which were included in our discontinued R&M segment, was $348 million, which included $104 million of investment in equity affiliates and $244 million of allocated goodwill. The $1,661 million before-tax gain on these dispositions was included in the “Income from discontinued operations” line of our consolidated income statement.

In June 2010, we sold our 9.03 percent interest in the Syncrude Canada Ltd. joint venture for $4.6 billion. The $2.9 billion before-tax gain was included in the “Gain on dispositions” line of our consolidated income statement. At the time of disposition, Syncrude had a net carrying value of $1.75 billion, which included $1.97 billion of PP&E.

In February 2012, we signed definitive agreements to sell our Vietnam business for $1.29 billion, excluding customary working capital adjustments. The transaction is expected to close in the first half of 2012. At December 31, 2011, this business had a net carrying value of approximately $150 million, which included PP&E of $350 million.

See Note 6—Investments, Loans and Long-Term Receivables, for information on the disposition of our investment in OAO LUKOIL during 2010 and 2011.

Note 6—Investments, Loans and Long-Term Receivables

Components of investments, loans and long-term receivables at December 31 were:

		Millions of Dollars
		2011				2010
Equity investments		$	30,985				30,055
Loans and advances—related parties			1,675				2,180
Long-term receivables			559				922
Other investments			564				604
		$	33,783				33,761

Equity Investments

Affiliated companies in which we had a significant equity investment at December 31, 2011, included:

• Australia Pacific LNG (APLNG)—42.5 percent owned joint venture with Origin Energy (42.5 percent) and China Petrochemical Corporation (Sinopec) (15 percent)—to develop coalbed methane production from the Bowen and Surat basins in Queensland, Australia, as well as process and export LNG.

• FCCL Partnership—50 percent owned business venture with Cenovus Energy Inc.—produces bitumen in the Athabasca oil sands in northeastern Alberta and sells the bitumen blend.

• WRB Refining LP (discontinued operations)—50 percent owned business venture with Cenovus—owns the Wood River and Borger refineries, which process crude oil into refined products.

• Qatar Liquefied Gas Company Limited 3 (QG3)—30 percent owned joint venture with affiliates of Qatar Petroleum (68.5 percent) and Mitsui & Co., Ltd. (1.5 percent)—produces and liquefies natural gas from Qatar’s North Field.

• DCP Midstream, LLC (discontinued operations)—50 percent owned joint venture with Spectra Energy—owns and operates gas plants, gathering systems, storage facilities and fractionation plants.

• Chevron Phillips Chemical Company LLC (CPChem) (discontinued operations)—50 percent owned joint venture with Chevron Corporation—manufactures and markets petrochemicals and plastics.

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Summarized 100 percent financial information for equity method investments in affiliated companies, combined, was as follows (information includes LUKOIL until loss of significant influence):

		Millions of Dollars
		2011				2010				2009
Revenues		$	77,263				105,589				128,881
Income before income taxes			11,958				11,250				12,121
Net income			11,089				9,495				9,145
Current assets			21,530				14,039				36,139
Noncurrent assets			76,300				79,411				126,163
Current liabilities			9,708				9,325				22,483
Noncurrent liabilities			22,993				24,412				30,960

Our share of income taxes incurred directly by the equity companies is reported in equity in earnings of affiliates, and as such is not included in income taxes in our consolidated financial statements.

At December 31, 2011, retained earnings included $2,814 million related to the undistributed earnings of affiliated companies. Dividends received from affiliates were $3,670 million, $2,282 million and $1,727 million in 2011, 2010 and 2009, respectively.

APLNG

In 2008, we closed on a transaction with Origin Energy, an integrated Australian energy company, to further enhance our long-term Australasian natural gas business. APLNG is focused on coalbed methane production from the Bowen and Surat basins in Queensland, Australia, and LNG processing and export sales. This transaction gives us access to coalbed methane resources in Australia and enhances our LNG position with the expected creation of an additional LNG hub targeting the Asia Pacific markets. Origin is the operator of APLNG’s production and pipeline system, while we will operate the LNG facility.

In April 2011, APLNG and Sinopec signed definitive agreements for APLNG to supply up to 4.3 million tonnes of LNG per year for 20 years. The agreements also specified terms under which Sinopec subscribed for a 15 percent equity interest in APLNG, with both our ownership interest and Origin Energy’s ownership interest diluting to 42.5 percent. The Subscription Agreement was completed in August 2011, and we recorded a loss on disposition of $279 million before- and after-tax from the dilution. The book value of our investment in APLNG was reduced by $795 million, and we reduced the currency translation adjustment associated with our investment by $516 million.

In November 2011, APLNG signed a binding Heads of Agreement with Japan-based Kansai Electric for the sale of approximately 1 million tonnes of LNG per year for 20 years. Under the terms of the agreement, Kansai Electric will be supplied LNG beginning in mid-2016. The agreement is also subject to a final investment decision on the second LNG train, which is expected in the first half of 2012.

In January 2012, APLNG and Sinopec signed an amendment to their existing LNG sales agreement for the sale and purchase of an additional 3.3 million tonnes of LNG per year through 2035, subject to a final investment decision on the second LNG train. This agreement, in combination with the Kansai Electric agreement, finalizes the marketing of the second train. In conjunction with the LNG sale, the parties have also agreed for Sinopec to subscribe for additional shares in APLNG, which will raise its equity interest from 15 percent to 25 percent. As a result, both our ownership interest and Origin Energy’s ownership interest would dilute from 42.5 percent to 37.5 percent. We expect to record a loss of approximately $135 million after-tax from the dilution.

At December 31, 2011, the book value of our equity method investment in APLNG was $9,467 million, which includes $2,716 million of cumulative translation effects due to a strengthening Australian dollar relative to the U.S. dollar. Our 42.5 percent share of the historical cost basis net assets of APLNG on its books under U.S. generally accepted accounting principles was $2,380 million, resulting in a basis difference of $7,087 million on our books. The amortizable portion of the basis difference, $5,192 million associated with PP&E, has been allocated on a relative fair value basis to individual exploration and production license areas owned by

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APLNG, most of which are not currently in production. Any future additional payments are expected to be allocated in a similar manner. Each exploration license area will periodically be reviewed for any indicators of potential impairment, which, if required, would result in acceleration of basis difference amortization. As the joint venture begins producing natural gas from each license, we amortize the basis difference allocated to that license using the unit-of-production method. Included in net income attributable to ConocoPhillips for 2011, 2010 and 2009 was after-tax expense of $17 million, $5 million and $4 million, respectively, representing the amortization of this basis difference on currently producing licenses.

FCCL and WRB

We have two 50/50 North American heavy oil business ventures with Cenovus Energy Inc.: FCCL Partnership, a Canadian upstream general partnership, and WRB Refining LP, a U.S. downstream limited partnership. We use the equity method of accounting for both entities, with the operating results of our investment in FCCL reflecting the use of the successful efforts method of accounting for oil and gas exploration and development activities.

At December 31, 2011, the book value of our investment in FCCL was $9,044 million. FCCL’s operating assets consist of the Foster Creek and Christina Lake steam-assisted gravity drainage bitumen projects, both located in the eastern flank of the Athabasca oil sands in northeastern Alberta. Cenovus is the operator and managing partner of FCCL. We are obligated to contribute $7.5 billion, plus accrued interest, to FCCL over a 10-year period that began in 2007. For additional information on this obligation, see Note 13—Joint Venture Acquisition Obligation.

At December 31, 2011, the book value of our investment in WRB was $3,722 million. WRB’s operating assets consist of the Wood River and Borger refineries, located in Roxana, Illinois, and Borger, Texas, respectively. As a result of our contribution of these two assets to WRB, a basis difference was created due to the fair value of the contributed assets recorded by WRB exceeding their historical book value. The difference is primarily amortized and recognized as a benefit evenly over a period of 26 years, which was the estimated remaining useful life of the refineries’ PP&E at the closing date. The basis difference at December 31, 2011, was $3,918 million. Equity earnings included in discontinued operations in 2011, 2010 and 2009 were increased by $185 million, $243 million and $209 million, respectively, due to amortization of the basis difference. We are the operator and managing partner of WRB. Cenovus is obligated to contribute $7.5 billion, plus accrued interest, to WRB over a 10-year period that began in 2007.

QG3

QG3 is a joint venture that owns an integrated large-scale LNG project located in Qatar. We provided project financing, with a current outstanding balance of $1,159 million as described below under “Loans and Long-term Receivables.” At December 31, 2011, the book value of our equity method investment in QG3 was $931 million. We have terminal and pipeline use agreements with Golden Pass LNG Terminal and affiliated Golden Pass Pipeline near Port Arthur, Texas, in which we have a 12.4 percent interest, intended to provide us with terminal and pipeline capacity for the receipt, storage and regasification of LNG purchased from QG3. However, currently the LNG from QG3 is being sold to markets outside of the United States.

DCP Midstream

DCP Midstream owns and operates gas plants, gathering systems, storage facilities and fractionation plants. At December 31, 2011, the book value of our equity method investment in DCP Midstream was $927 million. DCP Midstream markets a portion of its natural gas liquids to us and CPChem under a supply agreement that continues at the current volume commitment with a primary term ending December 31, 2014. This purchase commitment is on an “if-produced, will-purchase” basis and so has no fixed production schedule, but has had, and is expected over the remaining term of the contract to have, a relatively stable purchase pattern. Natural gas liquids are purchased under this agreement at various published market index prices, less transportation and fractionation fees.

CPChem

CPChem manufactures and markets petrochemicals and plastics. At December 31, 2011, the book value of our equity method investment in CPChem was $2,998 million. We have multiple supply and purchase agreements in place with CPChem, ranging in initial terms from one to 99 years, with extension options. These agreements cover sales and purchases of refined products, solvents, and petrochemical and natural gas liquids feedstocks, as well as fuel oils and gases. Delivery quantities vary by product, and are generally on an “if-produced, will-purchase” basis. All products are purchased and sold under specified pricing formulas based on various published pricing indices.

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In anticipation of the separation of our Downstream business (including CPChem), we reached agreement with Chevron Corporation regarding CPChem that provides for CPChem to: (i) prior to the separation, suspend all cash distributions to its owners and accumulate its excess cash; and (ii) after the separation, use the accumulated cash and its excess cash flow to pay down $1 billion of its outstanding fixed-rate bonds on an accelerated basis. During this period of bond repayment, CPChem is not required to make any cash distributions to its owners.

LUKOIL

LUKOIL is an integrated energy company headquartered in Russia. We completed the disposition of our interest in LUKOIL during the first quarter of 2011, realizing a before-tax gain of $360 million, which was included in the “Gain on dispositions” line of our consolidated income statement, and cash proceeds of $1,243 million. Our ownership interest was 2.25 percent at December 31, 2010, and 20 percent at December 31, 2009.

On July 28, 2010, we announced our intention to sell our entire interest in LUKOIL, then consisting of 163.4 million shares. This decision was 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 purchased 64.6 million shares from us at a price of $53.25 per share, or $3,442 million in total. This transaction closed on August 16, 2010.

• Also pursuant to the Agreement, the LUKOIL subsidiary had a 60-day option, expiring on September 26, 2010, to purchase any or all of our interest remaining at the time of exercise of the option, at a price of $56 per share. Upon exercise of this option, we sold 42.5 million shares on September 29, 2010, for proceeds of $2,380 million.

• Finally, we sold our remaining shares in the open market subject to the terms of the Shareholder Agreement, with the final disposition of all shares occurring in the first quarter of 2011. The cost basis for shares sold was average cost.

During the third quarter of 2010, our ownership interest declined to a level at which we were no longer able to exercise significant influence over the operating and financial policies of LUKOIL. Accordingly, at the end of the third quarter of 2010, we stopped applying the equity method of accounting for our remaining investment in LUKOIL, and we reclassified the investment from “Investments and long-term receivables” to current assets on our consolidated balance sheet as an available-for-sale equity security.

In total, during 2010, we sold 151 million shares of LUKOIL for $8,345 million, realizing a before-tax gain on disposition of $1,749 million, which was included in the “Gain on dispositions” line of our consolidated income statement. Included in these amounts were sales proceeds of $1,793 million and a realized before-tax gain of $437 million incurred subsequent to classifying the investment as available-for-sale. The cost basis for shares sold is average cost.

At December 31, 2010, our then remaining investment in LUKOIL was carried at fair value of $1,083 million, reflecting a closing price of LUKOIL American Depositary Receipts (ADRs) on the London Stock Exchange of $56.50 per share. The carrying value reflected a pre-tax unrealized gain over our cost basis of $247 million. This unrealized gain, net of related income taxes, was reported as a component of accumulated other comprehensive income. The fair value was categorized as Level 1 in the fair value hierarchy.

While applying the equity method of accounting, a negative basis difference existed which was primarily amortized on a straight-line basis over a 22-year useful life as an increase to equity earnings. Equity earnings in 2010 and 2009 were increased $155 million and $157 million, respectively, due to amortization of this basis difference.

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Loans and Long-Term Receivables

As part of our normal ongoing business operations and consistent with industry practice, we enter into numerous agreements with other parties to pursue business opportunities. Included in such activity are loans and long-term receivables to certain affiliated and non-affiliated companies. Loans are recorded when cash is transferred or seller financing is provided to the affiliated or non-affiliated company pursuant to a loan agreement. The loan balance will increase as interest is earned on the outstanding loan balance and will decrease as interest and principal payments are received. Interest is earned at the loan agreement’s stated interest rate. Loans and long-term receivables are assessed for impairment when events indicate the loan balance may not be fully recovered.

At December 31, 2011, significant loans to affiliated companies include the following:

• $612 million in loan financing to Freeport LNG Development, L.P. for the construction of an LNG receiving terminal that became operational in June 2008. Freeport began making repayments in 2008 and is required to continue making repayments through full repayment of the loan in 2026. Repayment by Freeport is supported by “process-or-pay” capacity service payments made by us to Freeport under our terminal use agreement.

• $1,159 million in project financing to QG3. We own a 30 percent interest in QG3, for which we use the equity method of accounting. The other participants in the project are affiliates of Qatar Petroleum and Mitsui. QG3 secured project financing of $4.0 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. On December 15, 2011, QG3 achieved financial completion and all project loan facilities became nonrecourse to the project participants. Bi-annual repayments began in January 2011 and will extend through July 2022.

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.”

WRB Refining LP fully repaid its outstanding loans from us with payments of $550 million in 2011.

In November 2011, a long-term loan to a non-affiliated company related to seller financing of U.S. retail marketing assets was refinanced, which resulted in a receipt of $365 million. As part of the refinancing, we provided loan guarantees in support of $191 million of the total refinancing.

Long-term receivables and the long-term portion of these loans are included in the “Investments and long-term receivables” line on the consolidated balance sheet, while the short-term portion related to non-affiliate loans is in “Accounts and notes receivable.”

Other

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 December 31, 2011, was $336 million, and at December 31, 2010, was $325 million. Substantially the entire value is categorized in Level 1 of the fair value hierarchy. These investments are measured at fair value using a market approach based on quotations from national securities exchanges.

Merey Sweeny, L.P. (MSLP) owns a delayed coker and related facilities at the Sweeny Refinery. MSLP processes our long residue, which is produced from heavy sour crude oil, for a processing fee. Fuel-grade petroleum coke is produced as a by-product and becomes the property of MSLP. Prior to August 28, 2009, MSLP was owned 50/50 by us and Petróleos de Venezuela S.A. (PDVSA). Under the agreements that govern the relationships between the partners, certain defaults by PDVSA with respect to supply of crude oil to the Sweeny Refinery gave us the right to acquire PDVSA’s 50 percent ownership interest in MSLP, which we exercised on August 28, 2009. PDVSA has initiated arbitration with the International Chamber of Commerce challenging the exercise of the call right and claiming it was invalid. The arbitral tribunal is scheduled to hold hearings on the merits of the dispute in December 2012. We continue to use the equity method of accounting for our investment in MSLP.

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Note 7—Properties, Plants and Equipment

PP&E is recorded at cost. Oil and gas assets are mainly depreciated on a unit-of-production basis, so depreciable life will vary by field. In the discontinued R&M segment, investments in refining manufacturing facilities are generally depreciated on a straight-line basis over a 25-year life, and pipeline assets over a 45-year life. The company’s investment in PP&E, with accumulated depreciation, depletion and amortization (Accum. DD&A), at December 31 was:

		Millions of Dollars
		2011												2010
		Gross PP&E				Accum. DD&A				Net PP&E				Gross PP&E				Accum. DD&A				Net PP&E
E&P		$	124,111				55,565				68,546				116,805				50,501				66,304
Midstream			135				86				49				128				80				48
R&M			22,096				8,128				13,968				23,579				8,999				14,580
LUKOIL Investment			—				—				—				—				—				—
Chemicals			—				—				—				—				—				—
Emerging Businesses			1,023				220				803				981				161				820
Corporate and Other			1,844				1,030				814				1,732				930				802
		$	149,209				65,029				84,180				143,225				60,671				82,554

Note 8—Suspended Wells

The following table reflects the net changes in suspended exploratory well costs during 2011, 2010 and 2009:

		Millions of Dollars
		2011				2010				2009
Beginning balance at January 1		$	1,013				908				660
Additions pending the determination of proved reserves			96				216				342
Reclassifications to proved properties			(72	)			(106	)			(39	)
Sales of suspended well investment			—				(4	)			(21	)
Charged to dry hole expense			—				(1	)			(34	)
Ending balance at December 31		$	1,037				1,013				908

The following table provides an aging of suspended well balances at December 31, 2011, 2010 and 2009:

		Millions of Dollars
		2011				2010				2009
Exploratory well costs capitalized for a period of one year or less		$	115				220				319
Exploratory well costs capitalized for a period greater than one year			922				793				589
Ending balance		$	1,037				1,013				908
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year			40				40				34

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The following table provides a further aging of those exploratory well costs that have been capitalized for more than one year since the completion of drilling as of December 31, 2011:

		Millions of Dollars
						Suspended Since
Project		Total				2008-2010				2005-2007				2001-2004
Aktote—Kazakhstan(2)		$	19				—				—				19
Alpine Satellite—Alaska(2)			21				—				—				21
Browse Basin—Australia(1)			216				216				—				—
Caldita/Barossa—Australia(1)			77				—				77				—
Fiord West—Alaska(2)			16				16				—				—
Harrison—U.K.(2)			15				—				15				—
Kairan—Kazakhstan(2)			27				—				14				13
Kalamkas—Kazakhstan(1)			14				5				5				4
Kashagan—Kazakhstan(1)			44				19				15				10
Malikai—Malaysia(2)			52				—				40				12
NPR-A—Alaska(2)			17				17				—				—
Petai—Malaysia(2)			30				19				11				—
Point Thomson—Alaska(2)			37				37				—				—
Rak More—Kazakhstan(1)			22				22				—				—
Saleski—Canada(1)			14				14				—				—
Shenandoah—Lower 48(1)			43				43				—				—
Sunrise 3—Australia(2)			13				13				—				—
Surmont III and beyond—Canada(1)			26				6				18				2
Su tu Nau—Vietnam(2)			18				9				9				—
Thornbury—Canada(1)			19				19				—				—
Tiber—Lower 48(1)			40				40				—				—
Titan—Norway(2)			11				11				—				—
Ubah—Malaysia(2)			34				34				—				—
Uge—Nigeria(1)			29				15				14				—
Sixteen projects of $10 million or less each(1)(2)			68				34				32				2
Total of 40 projects		$	922				589				250				83

(1) Additional appraisal wells planned.

(2) Appraisal drilling complete; costs being incurred to assess development.

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Note 9—Goodwill and Intangibles

Goodwill

Changes in the carrying amount of goodwill were as follows:

		Millions of Dollars
		2011												2010
		E&P*				R&M*				Total				E&P*				R&M*				Total
Balance as of January 1
Goodwill		$	25,443				3,633				29,076				25,443				3,638				29,081
Accumulated impairment losses			(25,443	)			—				(25,443	)			(25,443	)			—				(25,443	)
			—				3,633				3,633				—				3,638				3,638
Goodwill allocated to assets held for sale or sold			—				(273	)			(273	)			—				—				—
Tax and other adjustments			—				(28	)			(28	)			—				(5	)			(5	)
Balance as of December 31
Goodwill			25,443				3,332				28,775				25,443				3,633				29,076
Accumulated impairment losses			(25,443	)			—				(25,443	)			(25,443	)			—				(25,443	)
		$	—				3,332				3,332				—				3,633				3,633

* E&P represents continuing operations, and R&M represents discontinued operations.

Intangible Assets

Information at December 31 on the carrying value of intangible assets follows:

		Millions of Dollars
		Gross Carrying Amount
		2011				2010
Indefinite-Lived Intangible Assets
Trade names and trademarks		$	494				494
Refinery air and operating permits			207				245
		$	701				739

At year-end 2011, our amortized intangible asset balance was $44 million, compared with $62 million at year-end 2010. Amortization expense was not material for 2011 and 2010, and is not expected to be material in future years.

Note 10—Impairments

During 2011, 2010 and 2009, we recognized the following before-tax impairment charges:

		Millions of Dollars
		2011				2010				2009
Alaska		$	2				6				—
Lower 48 and Latin America			71				19				56
Canada			253				13				296
Europe			(37	)			43				104
Asia Pacific and Middle East			—				—				12
Corporate			32				—				1
		$	321				81				469

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Before-tax impairment charges included in discontinued operations for 2011, 2010 and 2009 were $471 million, $1,699 million and $66 million, respectively.

2011

During 2011, in our discontinued Downstream business, we recorded a $467 million impairment of our refinery and associated pipelines and terminals in Trainer, Pennsylvania. In September 2011, we announced plans to seek a buyer for the refinery and have idled the facility. If unable to sell the refinery, we expect to permanently close the plant by the end of the first quarter of 2012. Additionally, we recorded property impairments of $288 million, primarily in our Lower 48 and Latin America and Canada segments, largely as a result of lower natural gas price assumptions and reduced volume forecasts.

2010

During 2010, in our discontinued Downstream business, we recorded a $1,514 million impairment of our refinery in Wilhelmshaven, Germany, due to canceled plans for a project to upgrade the refinery, as well as a $98 million impairment as a result of our decision to end our participation in a new refinery project in Yanbu Industrial City, Saudi Arabia. We also recorded various property impairments of $81 million, primarily in our Europe and Lower 48 and Latin America segments.

2009

During 2009, we recorded property impairments of $417 million, mostly in our Lower 48 and Latin America, Canada and Europe segments, as a result of lower natural gas price assumptions, reduced volume forecasts, and higher royalty, operating costs and capital expenditure assumptions. Additionally, we recorded a noncash charge of $51 million before- and after-tax related to the full impairment of our exploration and production investments in Ecuador, due to their expropriation. An arbitration hearing on case merits occurred in March 2011, and the arbitration process is ongoing. Property impairments of $66 million in our discontinued Downstream business, primarily associated with planned asset dispositions, were also recorded during 2009.

Fair Value Remeasurements

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

		Millions of Dollars
						Fair Value Measurements Using												Before-Tax Loss Included in Discontinued Operations
		Fair Value*				Level 1 Inputs				Level 3 Inputs				Before-Tax Loss
Year ended December 31, 2011
Net PP&E (held for use)		$	162				—				162				265				1
Equity method investments			274				—				274				399				4
Cost method investments			2				2				—				8				—
Year ended December 31, 2010
Net PP&E (held for use)		$	307				—				307				1,604	**			1,508
Net PP&E (held for sale)			23				5				18				43				43
Equity method investments			735				—				735				645				—

* Represents the fair value at the time of the impairment.

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

2011

During 2011, net PP&E held for use with a carrying amount of $427 million was written down to a fair value of $162 million, resulting in a before-tax loss of $265 million. The fair values were determined by the use of internal discounted cash flow models using estimates of future production, prices, costs and a discount rate believed to be consistent with those used by principal market participants and cash flow multiples for similar assets and alternative use.

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Also during 2011, certain equity method investments were determined to have fair values below their carrying amount, and the impairments were considered to be other than temporary. This primarily included an investment associated with our Other International segment with a book value of $651 million, which was written down to its fair value of $256 million, resulting in a charge of $395 million before-tax. This was included in the “Equity in earnings of affiliates” line of our consolidated income statement. The fair value was determined by the application of an internal discounted cash flow model using estimates of future production, prices, costs and a discount rate believed to be consistent with those used by principal market participants. In addition, the fair value was determined by the comparison of market data for certain similar undeveloped properties.

2010

During 2010, in our discontinued Downstream business, net PP&E held for use with a carrying amount of $1,911 million was written down to a fair value of $307 million, resulting in a before-tax loss of $1,604 million. The fair values were determined by the use of internal discounted cash flow models using estimates of future production, prices, costs and a discount rate believed to be consistent with those used by principal market participants and cash flow multiples for similar assets and alternative use.

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

In addition, an equity method investment associated with our Other International segment was determined to have a fair value below carrying amount, and the impairment was considered to be other than temporary. This investment with a book value of $1,380 million was written down to its fair value of $735 million, resulting in a charge of $645 million before-tax, which was included in the “Equity in earnings of affiliates” line of our consolidated income statement. The fair value was determined by the application of an internal discounted cash flow model using estimates of future production, prices, costs and a discount rate believed to be consistent with those used by principal market participants. In addition, the equity investment fair value was determined by the comparison of market data for certain similar undeveloped properties.

Note 11—Asset Retirement Obligations and Accrued Environmental Costs

Asset retirement obligations and accrued environmental costs at December 31 were:

		Millions of Dollars
		2011				2010
Asset retirement obligations		$	8,920				8,776
Accrued environmental costs			922				994
Total asset retirement obligations and accrued environmental costs			9,842				9,770
Asset retirement obligations and accrued environmental costs due within one year*			(513	)			(571	)
Long-term asset retirement obligations and accrued environmental costs		$	9,329				9,199

* Classified as a current liability on the balance sheet, under the caption “Other accruals.”

Asset Retirement Obligations

We record the fair value of a liability for an asset retirement obligation when it is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, we capitalize the associated asset retirement cost by increasing the carrying amount of the related PP&E. Over time, the liability increases for the change in its present value, while the capitalized cost depreciates over the useful life of the related asset.

We have numerous asset removal obligations that we are required to perform under law or contract once an asset is permanently taken out of service. Most of these obligations are not expected to be paid until several years, or decades, in the future and will be funded from general company resources at the time of removal.

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Our largest individual obligations involve plugging and abandonment of wells, removal and disposal of offshore oil and gas platforms around the world, oil and gas production facilities and pipelines in Alaska, and asbestos abatement at refineries.

During 2011 and 2010, our overall asset retirement obligation changed as follows:

		Millions of Dollars
		2011				2010
Balance at January 1		$	8,776				8,295
Accretion of discount			435				422
New obligations			153				64
Changes in estimates of existing obligations			29				744
Spending on existing obligations			(327	)			(314	)
Property dispositions			(60	)			(394	)
Foreign currency translation			(86	)			(41	)
Balance at December 31		$	8,920				8,776

Accrued Environmental Costs

Total accrued environmental costs at December 31, 2011 and 2010, were $922 million and $994 million, respectively. The 2011 decrease in total accrued environmental costs is due to payments and settlements during the year exceeding new accruals, accrual adjustments and accretion.

We had accrued environmental costs of $571 million and $624 million at December 31, 2011 and 2010, respectively, primarily related to cleanup at domestic refineries and underground storage tanks at U.S. service stations, and remediation activities required by Canada and the state of Alaska at exploration and production sites. We had also accrued in Corporate and Other $274 million and $278 million of environmental costs associated with nonoperator sites at December 31, 2011 and 2010, respectively. In addition, $77 million and $92 million were included at both December 31, 2011 and 2010, respectively, where the company has been named a potentially responsible party under the Federal Comprehensive Environmental Response, Compensation and Liability Act, or similar state laws. Accrued environmental liabilities are expected to be paid over periods extending up to 30 years.

Because a large portion of the accrued environmental costs were acquired in various business combinations, they are discounted obligations. Expected expenditures for acquired environmental obligations are discounted using a weighted-average 5 percent discount factor, resulting in an accrued balance for acquired environmental liabilities of $427 million at December 31, 2011. The expected future undiscounted payments related to the portion of the accrued environmental costs that have been discounted are: $58 million in 2012, $44 million in 2013, $22 million in 2014, $19 million in 2015, $20 million in 2016, and $373 million for all future years after 2016.

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Note 12—Debt

Long-term debt at December 31 was:

		Millions of Dollars
		2011				2010
9.375% Notes due 2011		$	—				328
9.125% Debentures due 2021			150				150
8.20% Debentures due 2025			150				150
8.125% Notes due 2030			600				600
7.9% Debentures due 2047			100				100
7.8% Debentures due 2027			300				300
7.68% Notes due 2012			7				15
7.65% Debentures due 2023			88				88
7.625% Debentures due 2013			100				100
7.40% Notes due 2031			500				500
7.375% Debentures due 2029			92				92
7.25% Notes due 2031			500				500
7.20% Notes due 2031			575				575
7% Debentures due 2029			200				200
6.95% Notes due 2029			1,549				1,549
6.875% Debentures due 2026			67				67
6.65% Debentures due 2018			297				297
6.50% Notes due 2011			—				500
6.50% Notes due 2039			2,250				2,250
6.50% Notes due 2039			500				500
6.00% Notes due 2020			1,000				1,000
5.951% Notes due 2037			645				645
5.95% Notes due 2036			500				500
5.90% Notes due 2032			505				505
5.90% Notes due 2038			600				600
5.75% Notes due 2019			2,250				2,250
5.625% Notes due 2016			1,250				1,250
5.50% Notes due 2013			750				750
5.20% Notes due 2018			500				500
4.75% Notes due 2012			897				897
4.75% Notes due 2014			1,500				1,500
4.60% Notes due 2015			1,500				1,500
4.40% Notes due 2013			400				400
Commercial paper at 0.34% – 0.341% at year-end 2011 and 0.14% – 0.34% at year-end 2010			1,128				1,182
Industrial Development Bonds due 2012 through 2038 at 0.08% – 5.75% at year-end 2011 and 0.33% – 5.75% at year-end 2010			252				252
Guarantee of savings plan bank loan payable due 2015 at 2.29% at year-end 2011 and 2.06% at year-end 2010			15				64
Note payable to Merey Sweeny, L.P. due 2020 at 7% (related party)			133				144
Marine Terminal Revenue Refunding Bonds due 2031 at 0.08% – 0.15% at year-end 2011 and 0.33% – 0.48% at year-end 2010			265				265
Other			28				31
Debt at face value			22,143				23,096
Capitalized leases			31				39
Net unamortized premiums and discounts			449				457
Total debt			22,623				23,592
Short-term debt			(1,013	)			(936	)
Long-term debt		$	21,610				22,656

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Maturities of long-term borrowings, inclusive of net unamortized premiums and discounts, in 2012 through 2016 are: $1,013 million, $1,275 million, $1,527 million, $1,571 million and $2,364 million, respectively. At December 31, 2011, we classified $1,058 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.

During 2011, the following debt instruments were repaid at their maturity:

• The $328 million 9.375% Debentures due 2011.

• The $500 million 6.50% Notes due 2011.

In August 2011, we increased our revolving credit facilities from $7.85 billion to $8.0 billion by replacing our $7.35 billion revolving credit facility with a $7.5 billion facility expiring in August 2016. We also have 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.

We have two commercial paper programs: 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 December 31, 2011 and 2010, we had no direct outstanding borrowings under the revolving credit facilities, but $40 million in letters of credit had been issued. In addition, under the two commercial paper programs, there was $1,128 million of commercial paper outstanding at December 31, 2011, compared with $1,182 million at December 31, 2010. Since we had $1,128 million of commercial paper outstanding and had issued $40 million of letters of credit, we had access to $6.8 billion in borrowing capacity under our revolving credit facilities at December 31, 2011.

Note 13—Joint Venture Acquisition Obligation

In 2007, we closed on a business venture with Cenovus. As a part of the transaction, we are obligated to contribute $7.5 billion, plus interest, over a 10-year period that began in 2007, to the upstream business venture, FCCL Partnership, formed as a result of the transaction.

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, $732 million was short-term and was included in the “Accounts payable—related parties” line on our December 31, 2011, consolidated balance sheet. The principal portion of these payments, which totaled $695 million in 2011, is included in the “Other” line in the financing activities section of our consolidated statement of cash flows. Interest accrues at a fixed annual rate of 5.3 percent on the unpaid principal balance. Fifty percent of the quarterly interest payment is reflected as a capital contribution and is included in the “Capital expenditures and investments” line on our consolidated statement of cash flows.

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Note 14—Guarantees

At December 31, 2011, we were liable for certain contingent obligations under various contractual arrangements as described below. We recognize a liability, at inception, for the fair value of our obligation as a guarantor for newly issued or modified guarantees. Unless the carrying amount of the liability is noted below, we have not recognized a liability either because the guarantees were issued prior to December 31, 2002, or because the fair value of the obligation is immaterial. In addition, unless otherwise stated we are not currently performing with any significance under the guarantee and expect future performance to be either immaterial or have only a remote chance of occurrence.

Construction Completion Guarantees

In December 2005, we issued a construction completion guarantee for 30 percent of the $4.0 billion in loan facilities of Qatargas 3, which are being used to finance the construction of an LNG train in Qatar. Of the $4.0 billion in loan facilities, we committed to provide $1.2 billion. Effective December 15, 2011, the project achieved financial completion, the financing became nonrecourse to ConocoPhillips and our guarantee was released.

Guarantees of Joint Venture Debt

At December 31, 2011, we had guarantees outstanding for our portion of joint venture debt obligations, which have terms of up to 24 years. The maximum potential amount of future payments under the guarantees is approximately $100 million. Payment would be required if a joint venture defaults on its debt obligations.

Other Guarantees

• In conjunction with our purchase of an ownership interest in 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 5 to 20 years. Our maximum potential amount of future payments, or cost of volume delivery, under these guarantees is estimated to be $1,261 million ($2,820 million in the event of intentional or reckless breach) at December 2011 exchange rates based on our 42.5 percent share of the remaining contracted volumes, which could become payable if APLNG fails to meet its obligations under these agreements and the obligations cannot otherwise be mitigated. Future payments are considered unlikely, as the payments, or cost of volume delivery, would only be triggered if APLNG does not have enough natural gas to meet these sales commitments and if the co-venturers do not make necessary equity contributions into APLNG. Additionally, we have guaranteed the performance of APLNG with regard to certain contracts executed in connection with APLNG’s issuance of the Train 1 Notice to Proceed. Our maximum potential amount of future payments related to these guarantees is estimated to be $171 million at December 2011 exchange rates based on our 42.5 percent ownership in APLNG.

• We have other guarantees with maximum future potential payment amounts totaling $450 million, which consist primarily of guarantees to fund the short-term cash liquidity deficits of certain joint ventures, a guarantee of minimum charter revenue for two LNG vessels, one small construction completion guarantee, guarantees relating to the startup of a refining joint venture, guarantees of the lease payment obligations of a joint venture, guarantees of the residual value of leased corporate aircraft, and guarantees of the performance of a business partner or some of its customers. These guarantees generally extend up to 13 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

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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 December 31, 2011, was $362 million. We amortize the indemnification liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of indemnity. In cases where the indemnification term is indefinite, we will reverse the liability when we have information the liability is essentially relieved or amortize the liability over an appropriate time period as the fair value of our indemnification exposure declines. Although it is reasonably possible future payments may exceed amounts recorded, due to the nature of the indemnifications, it is not possible to make a reasonable estimate of the maximum potential amount of future payments. Included in the recorded carrying amount were $218 million of environmental accruals for known contamination that are included in asset retirement obligations and accrued environmental costs at December 31, 2011. For additional information about environmental liabilities, see Note 15—Contingencies and Commitments.

Note 15—Contingencies and Commitments

A number of lawsuits involving a variety of claims have been made against ConocoPhillips that arise in the ordinary course of business. We also may be required 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 active and inactive sites. We regularly assess the need for accounting recognition or disclosure of these contingencies. 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. See Note 20—Income Taxes, for additional information about income-tax-related contingencies.

Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our 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 international, federal, state and local environmental laws and regulations. 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. 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,

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those potentially responsible normally assess the site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or may attain a settlement of liability. Where it appears that other potentially responsible parties may be financially unable to bear their proportional share, we consider this inability in estimating our potential liability, and we adjust our accruals accordingly. As a result of various acquisitions in the past, we assumed certain environmental obligations. Some of these environmental obligations are mitigated by indemnifications made by others for our benefit and some of the indemnifications are subject to dollar limits and time limits.

We 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. We have not reduced these accruals for possible insurance recoveries. In the future, we may be involved in additional environmental assessments, cleanups and proceedings. See Note 11—Asset Retirement Obligations and Accrued Environmental Costs, for a summary of our accrued environmental liabilities.

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 and/or mediation. 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 regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, is required.

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 December 31, 2011, we had performance obligations secured by letters of credit of $1,954 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.

In 2007, we announced we had been unable to reach agreement with respect to our migration to an empresa mixta structure mandated by the Venezuelan government’s Nationalization Decree. As a result, Venezuela’s national oil company, Petróleos de Venezuela S.A. (PDVSA), or its affiliates, directly assumed control over ConocoPhillips’ interests in the Petrozuata and Hamaca heavy oil ventures and the offshore Corocoro development project. In response to this expropriation, we filed a request for international arbitration on November 2, 2007, with the World Bank’s International Centre for Settlement of Investment Disputes (ICSID). An arbitration hearing was held before an ICSID tribunal during the summer of 2010, and we are currently awaiting an interim decision on key legal and factual issues. A separate arbitration hearing was held in January 2012 before the International Chamber of Commerce on ConocoPhillips’ separate claims against PDVSA for certain breaches of their Association Agreements prior to the expropriation.

In 2008, Burlington Resources, Inc., a wholly owned subsidiary of ConocoPhillips, initiated arbitration before ICSID against The Republic of Ecuador, 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 ICSID, Ecuador confiscated the crude oil production of Burlington and its co-venturer and sold the illegally seized crude oil. In 2009, Ecuador took over operations in Blocks 7 and 21, fully expropriating our assets. In June 2010, the ICSID tribunal concluded it has jurisdiction to hear the expropriation claim. An arbitration hearing on case merits occurred in March 2011. On September 30, 2011, Ecuador filed a supplemental counterclaim asserting environmental damages, which we believe will not be material. The arbitration process is ongoing. For additional information, see Note 10—Impairments.

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

We have certain throughput agreements and take-or-pay agreements in support of financing arrangements. The agreements typically provide for natural gas or crude oil transportation to be used in the ordinary course of the company’s business. The aggregate amounts of estimated payments under these various agreements are: 2012—$468 million; 2013—$467 million; 2014—$467 million; 2015—$458 million; 2016—$364 million; and 2017 and after—$4,890 million. Total payments under the agreements were $429 million in 2011, $216 million in 2010 and $114 million in 2009.

Note 16—Financial Instruments and Derivative Contracts

Financial Instruments

We invest excess cash in financial instruments with maturities based on our cash forecasts for the various currency pools we manage. The maturities of these investments may from time to time extend beyond 90 days. The types of financial instruments in which we currently invest include:

• Time deposits: Interest bearing deposits placed with approved financial institutions.

• Commercial paper: Unsecured promissory notes issued by a corporation, commercial bank, or government agency purchased at a discount, maturing at par.

• Government or government agency obligations: Negotiable debt obligations issued by a government or government agency.

These financial instruments appear in the “Cash and cash equivalents” line of our consolidated balance sheet if the maturities at the time we made the investments were 90 days or less; otherwise, these held-to-maturity investments are included in the “Short-term investments” line. At December 31, we held the following financial instruments:

		Millions of Dollars
		Carrying Amount
		Cash and Cash Equivalents								Short-Term Investments*
		2011				2010				2011				2010
Cash		$	1,169				1,284				—				—
Time Deposits
Remaining maturities from 1 to 90 days			4,318				6,154				349				302
Remaining maturities from 91 to 180 days			—				—				—				69
Commercial Paper
Remaining maturities from 1 to 90 days			293				1,566				232				525
Remaining maturities from 91 to 180 days			—				—				—				—
Government Obligations
Remaining maturities from 1 to 90 days			—				450				—				77
Remaining maturities from 91 to 180 days			—				—				—				—
		$	5,780				9,454				581				973

* Carrying value approximates fair value.

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 with fixed minimum notional volumes 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 eligible for and we elect the normal purchases and normal sales exception (i.e., contracts to purchase or sell quantities we expect to use or sell over a reasonable period in the normal course of business). 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-traded 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. Where exchange-provided prices are adjusted, non-exchange quotes are used, or when the instrument lacks sufficient liquidity, we generally classify those exchange-cleared contracts as Level 2. 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 material transfers in or out of 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.

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

		Millions of Dollars
		December 31, 2011																December 31, 2010
		Level 1				Level 2				Level 3				Total				Level 1				Level 2				Level 3				Total
Assets
Commodity derivatives*		$	2,807				1,947				72				4,826				1,456				1,744				63				3,263
Interest rate derivatives			—				31				—				31				—				20				—				20
Foreign currency exchange derivatives			—				13				—				13				—				15				—				15
Total assets			2,807				1,991				72				4,870				1,456				1,779				63				3,298
Liabilities
Commodity derivatives*			2,970				1,722				10				4,702				1,611				1,737				36				3,384
Foreign currency exchange derivatives			—				23				—				23				—				9				—				9
Total liabilities			2,970				1,745				10				4,725				1,611				1,746				36				3,393
Net assets (liabilities)		$	(163	)			246				62				145				(155	)			33				27				(95	)

* 2010 has been reclassified to conform to current-year presentation.

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 right of setoff 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.

As reflected in the table above, Level 3 activity was not material.

Commodity Derivative Contracts—We operate in the worldwide crude oil, bitumen, refined product, natural gas, LNG, 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. We also use the market knowledge gained from these activities to capture market opportunities such as moving physical commodities to more profitable locations, storing commodities to capture seasonal or time premiums, and blending commodities to capture quality upgrades. Derivatives may be used to optimize these activities which 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
		2011				2010
Assets
Prepaid expenses and other current assets		$	4,433				3,073
Other assets			415				211
Liabilities
Other accruals			4,350				3,212
Other liabilities and deferred credits			374				193

Hedge accounting has not been used for any item in the table. The amounts shown are presented gross (i.e., without netting assets and liabilities with the same counterparty where the right of setoff exists).

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

		Millions of Dollars
		2011				2010				2009
Sales and other operating revenues		$	907				(964	)			1,717
Other income			(9	)			(5	)			4
Purchased commodities			(729	)			915				(1,502	)
Income from discontinued operations			(446	)			(139	)			(854	)

Hedge accounting has not been used for any item 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 exposures 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.

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		Open Position Long /(Short)
		2011				2010
Commodity
Crude oil, refined products and natural gas liquids (millions of barrels)			(13	)			(16	)
Natural gas and power (billions of cubic feet equivalent)
Fixed price			(57	)			(69	)
Basis			(25	)			(43	)

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 floating rate based on the London Interbank Offered Rate (LIBOR). 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 adjustments to the fair values of the interest rate swaps and hedged debt have not been material.

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

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

		Millions of Dollars
		2011				2010
Assets
Prepaid expenses and other current assets		$	12				14
Other assets			1				1
Liabilities
Other accruals			23				7
Other liabilities and deferred credits			—				2

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

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

		Millions of Dollars
		2011				2010				2009
Foreign currency transaction (gains) losses		$	(9	)			115				(107	)
Income from discontinued operations			(5	)			3				(14	)

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

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

		In Millions
		Notional Currency*
		2011				2010
Foreign Currency Exchange Derivatives
Sell U.S. dollar, buy other currencies**		USD	1,949				569
Sell euro, buy other currencies***		EUR	61				253

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

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

*** Primarily Norwegian krone and British pound.

Credit Risk

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

The credit risk from our OTC derivative contracts, such as forwards and swaps, derives from the counterparty to the transaction. Individual counterparty exposure is managed within predetermined credit limits and includes the use of cash-call margins when appropriate, thereby reducing the risk of significant nonperformance. We also use futures, swaps and option contracts that have a negligible credit risk because these trades are cleared with an exchange clearinghouse and subject to mandatory margin requirements until settled; however, we are exposed to the credit risk of those exchange brokers for receivables arising from daily margin cash calls, as well as for cash deposited to meet initial margin requirements.

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 December 31, 2011, was $237 million, for which $3 million of collateral was posted. If our credit rating were lowered one level from its “A” rating (per Standard and Poor’s) on

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December 31, 2011, 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 $234 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, cash equivalents and short-term investments: 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: We completed the disposition of our interest in LUKOIL during the first quarter of 2011. At December 31, 2010, our investment in LUKOIL was carried at fair value of $1,083 million, reflecting a closing price of LUKOIL ADRs on the London Stock Exchange of $56.50 per share.

• 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 December 31, 2011, and December 31, 2010, using effective yield rates of 1.24 percent and 1.87 percent, respectively, 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 13—Joint Venture Acquisition Obligation, for additional information.

• Commodity swaps: Fair value is estimated based on forward market prices and approximates the exit price at period end. When forward market prices are not available, fair value is 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 IntercontinentalExchange (ICE) Futures, or other traded exchanges.

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

• Forward-exchange contracts: Fair values are estimated by comparing the contract rate to the forward rates in effect at the end of the respective reporting periods, and approximate the exit prices at those dates.

Our commodity derivative and financial instruments were:

		Millions of Dollars
		Carrying Amount								Fair Value
		2011				2010				2011				2010
Financial Assets
Foreign currency exchange derivatives		$	13				15				13				15
Interest rate derivatives			31				20				31				20
Commodity derivatives			814				624				814				624
Investment in LUKOIL			—				1,083				—				1,083
Financial Liabilities
Total debt, excluding capital leases			22,592				23,553				27,065				26,144
Joint venture acquisition obligation			4,314				5,009				4,820				5,600
Foreign currency exchange derivatives			23				9				23				9
Commodity derivatives			446				426				446				426

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 setoff exists). In addition, the December 31, 2011, commodity derivative assets and liabilities appear net of no obligations to return cash collateral and $244 million of rights

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to reclaim cash collateral. The December 31, 2010, commodity derivative assets and liabilities appear net of $5 million of obligations to return cash collateral and $324 million of rights to reclaim cash collateral, respectively. No collateral was deposited or held for the foreign currency derivatives or interest rate derivatives.

Note 17—Equity

Common Stock

The changes in our shares of common stock, as categorized in the equity section of the balance sheet, were:

		Shares
		2011				2010				2009
Issued
Beginning of year			1,740,529,279				1,733,345,558				1,729,264,859
Distributed under benefit plans			9,021,308				7,183,721				4,080,699
End of year			1,749,550,587				1,740,529,279				1,733,345,558
Held in Treasury
Beginning of year			272,873,537				208,346,815				208,346,815
Repurchase of common stock			155,453,382				64,526,722				—
Distributed under benefit plans			(475,696	)			—				—
Transfer from grantor trust			36,029,405				—				—
End of year			463,880,628				272,873,537				208,346,815
Held in Grantor Trusts
Beginning of year			36,890,375				38,742,261				40,739,129
Repurchase of common stock			(157,470	)			—				—
Distributed under benefit plans			(703,500	)			(1,776,873	)			(2,018,692	)
Transfer to treasury stock			(36,029,405	)			—				—
Other			—				(75,013	)			21,824
End of year			—				36,890,375				38,742,261

Preferred Stock

We have authorized 500 million shares of preferred stock, par value $.01 per share, none of which was issued or outstanding at December 31, 2011 or 2010.

Noncontrolling Interests

At December 31, 2011 and 2010, we had outstanding $510 million and $547 million, respectively, of equity in less-than-wholly owned consolidated subsidiaries held by noncontrolling interest owners. The noncontrolling interest amounts are primarily related to operating joint ventures we control. The largest of these, amounting to $482 million and $520 million at December 31, 2011, and 2010, respectively, was related to Darwin LNG operations, located in Australia’s Northern Territory.

Preferred Share Purchase Rights

In 2002, our Board of Directors authorized and declared a dividend of one preferred share purchase right for each common share outstanding, and authorized and directed the issuance of one right per common share for any newly issued shares. The rights have certain anti-takeover effects. The rights will cause substantial dilution to a person or group that attempts to acquire ConocoPhillips on terms not approved by the Board of Directors. However, since the rights may either be redeemed or otherwise made inapplicable by ConocoPhillips prior to an acquirer obtaining beneficial ownership of 15 percent or more of ConocoPhillips’ common stock, the rights should not interfere with any merger or business combination approved by the Board of Directors prior to that occurrence. The rights, which expire June 30, 2012, will be exercisable only if a person or group acquires 15 percent or more of the company’s common stock or commences a tender offer that would result in ownership of 15 percent or more of the common stock. Each right would entitle stockholders

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to buy one one-hundredth of a share of preferred stock at an exercise price of $300. If an acquirer obtains 15 percent or more of ConocoPhillips’ common stock, then each right will be adjusted so that it will entitle the holder (other than the acquirer, whose rights will become void) to purchase, for the then exercise price, a number of shares of ConocoPhillips’ common stock equal in value to two times the exercise price of the right. In addition, the rights enable holders to purchase the stock of an acquiring company at a discount, depending on specific circumstances. We may redeem the rights in whole, but not in part, for one cent per right.

Note 18—Non-Mineral Leases

The company leases ocean transport vessels, tugboats, barges, pipelines, railcars, corporate aircraft, service stations, drilling equipment, computers, office buildings and other facilities and equipment. Certain leases include escalation clauses for adjusting rental payments to reflect changes in price indices, as well as renewal options and/or options to purchase the leased property for the fair market value at the end of the lease term. There are no significant restrictions imposed on us by the leasing agreements with regard to dividends, asset dispositions or borrowing ability. Leased assets under capital leases were not significant in any period presented.

At December 31, 2011, future minimum rental payments due under noncancelable leases related to continuing and discontinued operations were:

		Millions of Dollars
2012		$	767
2013			519
2014			382
2015			300
2016			202
Remaining years			591
Total			2,761
Less income from subleases			132	*
Net minimum operating lease payments		$	2,629

* Includes $64 million related to subleases to related parties.

Operating lease rental expense included in continuing operations for the years ended December 31 was:

		Millions of Dollars
		2011				2010				2009
Total rentals*		$	304				267				259
Less sublease rentals			(14	)			(14	)			(18	)
		$	290				253				241

* Includes $29 million, $16 million and $15 million of contingent rentals in 2011, 2010 and 2009, respectively. Contingent rentals primarily are related to drilling equipment and are based on usage or volume of product sold.

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Note 19—Employee Benefit Plans

Pension and Postretirement Plans

An analysis of the projected benefit obligations for our pension plans and accumulated benefit obligations for our postretirement health and life insurance plans follows:

		Millions of Dollars
		Pension Benefits																Other Benefits
		2011								2010								2011				2010
		U.S.				Int’l.				U.S.				Int’l.
Change in Benefit Obligation
Benefit obligation at January 1		$	5,539				3,206				5,042				3,101				862				839
Service cost			225				98				229				90				10				11
Interest cost			247				178				260				169				42				46
Plan participant contributions			—				5				—				4				23				20
Government subsidy			—				—				—				—				4				—
Plan amendments			—				(53	)			12				—				35				—
Actuarial loss			642				195				305				59				20				14
Benefits paid			(478	)			(116	)			(309	)			(115	)			(68	)			(70	)
Curtailment			—				—				—				(1	)			—				—
Foreign currency exchange rate change			—				(29	)			—				(101	)			(2	)			2
Benefit obligation at December 31*		$	6,175				3,484				5,539				3,206				926				862
*Accumulated  benefit obligation portion of above at December 31:		$	5,363				2,939				4,905				2,711
Change in Fair Value of Plan Assets
Fair value of plan assets at January 1		$	3,890				2,581				3,144				2,281				—				—
Actual return on plan assets			64				53				458				259				—				—
Company contributions			673				226				597				216				41				50
Plan participant contributions			—				5				—				4				23				20
Government subsidy			—				—				—				—				4				—
Benefits paid			(478	)			(116	)			(309	)			(115	)			(68	)			(70	)
Curtailment			—				—				—				(1	)			—				—
Foreign currency exchange rate change			—				(27	)			—				(63	)			—				—
Fair value of plan assets at December 31		$	4,149				2,722				3,890				2,581				—				—
Funded Status		$	(2,026	)			(762	)			(1,649	)			(625	)			(926	)			(862	)

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		Millions of Dollars
		Pension Benefits																Other Benefits
		2011								2010								2011				2010
		U.S.				Int’l.				U.S.				Int’l.
Amounts Recognized in the Consolidated Balance Sheet at December 31
Noncurrent assets		$	—				94				—				156				—				—
Current liabilities			(118	)			(5	)			(74	)			(4	)			(62	)			(51	)
Noncurrent liabilities			(1,908	)			(851	)			(1,575	)			(777	)			(864	)			(811	)
Total recognized		$	(2,026	)			(762	)			(1,649	)			(625	)			(926	)			(862	)
Weighted-Average Assumptions Used to Determine Benefit Obligations at December 31
Discount rate			4.30	%			4.90				4.65				5.40				4.40				5.00
Rate of compensation increase			4.25				4.30				4.00				4.10				—				—
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31
Discount rate			4.65	%			5.40				5.35				5.80				5.00				5.60
Expected return on plan assets			7.00				6.40				7.00				6.50				—				—
Rate of compensation increase			4.00				4.10				4.00				4.50				—				—

For both U.S. and international pensions, the overall expected long-term rate of return is developed from the expected future return of each asset class, weighted by the expected allocation of pension assets to that asset class. We rely on a variety of independent market forecasts in developing the expected rate of return for each class of assets.

Included in accumulated other comprehensive income at December 31 were the following before-tax amounts that had not been recognized in net periodic benefit cost:

		Millions of Dollars
		Pension Benefits																Other Benefits
		2011								2010								2011				2010
		U.S.				Int’l.				U.S.				Int’l.
Unrecognized net actuarial loss (gain)		$	2,240				705				1,567				444				(26	)			(51	)
Unrecognized prior service cost (credit)			52				(78	)			61				(25	)			(13	)			(54	)

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		Millions of Dollars
		Pension Benefits																Other Benefits
		2011								2010								2011				2010
		U.S.				Int’l.				U.S.				Int’l.
Sources of Change in Other Comprehensive Income
Net gain (loss) arising during the period		$	(858	)			(307	)			(70	)			75				(20	)			(14	)
Amortization of (gain) loss included in income			185				46				167				55				(5	)			(7	)
Net change during the period		$	(673	)			(261	)			97				130				(25	)			(21	)
Prior service (cost) credit arising during the period		$	—				53				(12	)			(1	)			(34	)			—
Amortization of prior service cost (credit) included in income			9				—				10				2				(7	)			3
Net change during the period		$	9				53				(2	)			1				(41	)			3

Amounts included in accumulated other comprehensive income at December 31, 2011, that are expected to be amortized into net periodic postretirement cost during 2012 are provided below:

		Millions of Dollars
		Pension Benefits								Other Benefits
		U.S.				Int’l.
Unrecognized net actuarial loss (gain)		$	235				71				(3	)
Unrecognized prior service cost			9				(9	)			(4	)

For our tax-qualified pension plans with projected benefit obligations in excess of plan assets, the projected benefit obligation, the accumulated benefit obligation, and the fair value of plan assets were $8,481 million, $7,377 million, and $6,098 million, respectively, at December 31, 2011, and $7,661 million, $6,718 million, and $5,706 million, respectively, at December 31, 2010.

For our unfunded nonqualified key employee supplemental pension plans, the projected benefit obligation and the accumulated benefit obligation were $499 million and $374 million, respectively, at December 31, 2011, and were $479 million and $407 million, respectively, at December 31, 2010.

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The components of net periodic benefit cost related to continuing and discontinued operations of all defined benefit plans are presented in the following table:

		Millions of Dollars
		Pension Benefits																								Other Benefits
		2011								2010								2009								2011				2010				2009
		U.S.				Int’l.				U.S.				Int’l.				U.S.				Int’l.
Components of Net Periodic Benefit Cost
Service cost		$	225				98				229				90				194				79				10				11				9
Interest cost			247				178				260				169				277				144				42				46				47
Expected return on plan assets			(280	)			(175	)			(224	)			(147	)			(184	)			(125	)			—				—				—
Amortization of prior service cost (credit)			9				—				10				2				11				1				(7	)			3				9
Recognized net actuarial loss (gain)			165				46				167				55				186				35				(5	)			(7	)			(15	)
Net periodic benefit cost		$	366				147				442				169				484				134				40				53				50

We recognized pension settlement losses of $21 million in 2011 and $15 million in 2009. None were recognized in 2010.

We recognized special termination benefits of $5 million in 2009. None were recognized in 2011 and 2010.

In determining net pension and other postretirement benefit costs, we amortize prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plan. For net actuarial gains and losses, we amortize 10 percent of the unamortized balance each year.

We have multiple nonpension postretirement benefit plans for health and life insurance. The health care plans are contributory and subject to various cost sharing features, with participant and company contributions adjusted annually; the life insurance plans are noncontributory. The measurement of the accumulated postretirement benefit obligation assumes a health care cost trend rate of 7.75 percent in 2012 that declines to 5 percent by 2023. A one-percentage-point change in the assumed health care cost trend rate would be immaterial to ConocoPhillips.

Plan Assets—We follow a policy of broadly diversifying pension plan assets across asset classes, investment managers, and individual holdings. As a result, our plan assets have no significant concentrations of credit risk. Asset classes that are considered appropriate include U.S. equities, non-U.S. equities, U.S. fixed income, non-U.S. fixed income, real estate and private equity investments. Plan fiduciaries may consider and add other asset classes to the investment program from time to time. The target allocations for plan assets are 56 percent equity securities, 35 percent debt securities, 6 percent real estate and 3 percent in all other types of investments. Generally, the investments in the plans are publicly traded, therefore minimizing liquidity risk in the portfolio.

Following is a description of the valuation methodologies used for the pension plan assets. There have been no changes in the methodologies used at December 31, 2011 and 2010.

• Fair values of equity securities and government debt securities categorized in Level 1 are primarily based on quoted market prices.

• Fair values of corporate debt securities, agency and mortgage-backed securities and government debt securities categorized in Level 2 are estimated using recently executed transactions and market price quotations. If there have been no market transactions in a particular fixed income security, its fair market value is calculated by pricing models that benchmark the security against other securities with actual market prices. When observable price quotations are not available, fair value is based on pricing models that use something other than actual market prices (e.g., observable inputs such as benchmark yields, reported trades and issuer spreads for similar securities), and these securities are categorized in Level 3 of the fair value hierarchy.

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• Fair values of investments in common/collective trusts are determined by the issuer of each fund based on the fair value of the underlying assets.

• Fair values of mutual funds are valued based on quoted market prices, which represent the net asset value of shares held.

• Cash is valued at cost, which approximates fair value. Fair values of cash equivalents categorized in Level 2 are valued using observable yield curves, discounting and interest rates.

• Fair values of exchange-traded derivatives classified in Level 1 are based on quoted market prices. For other derivatives classified in Level 2, the values are generally calculated from pricing models with market input parameters from third-party sources.

• Private equity funds are valued at net asset value as determined by the issuer based on the fair value of the underlying assets.

• Fair values of insurance contracts are valued at the present value of the future benefit payments owed by the insurance company to the Plans’ participants.

• Fair values of real estate investments are valued using real estate valuation techniques and other methods that include reference to third-party sources and sales comparables where available.

• A portion of U.S. pension plan assets is held as a participating interest in an insurance annuity contract. This participating interest is calculated as the market value of investments held under this contract, less the accumulated benefit obligation covered by the contract. The participation interest is classified as Level 3 in the fair value hierarchy as the fair value is determined via a combination of comparison to quoted market prices and estimation using recently executed transactions and market price quotations for contract assets, and an actuarial present value computation for contract obligations. At December 31, 2011, the participating interest in the annuity contract was valued at $144 million and consisted of $391 million in debt securities, less $247 million for the accumulated benefit obligation covered by the contract. At December 31, 2010, the participating interest in the annuity contract was valued at $92 million and consisted of $357 million in debt securities, less $265 million for the accumulated benefit obligation covered by the contract. The net change from 2010 to 2011 is due to an increase in the fair market value of the underlying investments of $34 million and a decrease in the present value of the contract obligation of $18 million. The participating interest is not available for meeting general pension benefit obligations in the near term. No future company contributions are required and no new benefits are being accrued under this insurance annuity contract.

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The fair values of our pension plan assets at December 31, by asset class were as follows:

		Millions of Dollars
		U.S.																International
		Level 1				Level 2				Level 3				Total				Level 1				Level 2				Level 3				Total
2011
Equity Securities
U.S.		$	1,251				—				—				1,251				413				—				—				413
International			803				—				—				803				413				—				—				413
Common/collective trusts			—				634				—				634				—				234				—				234
Mutual funds			—				—				—				—				246				—				—				246
Debt Securities
Government			311				81				—				392				532				—				—				532
Corporate			—				551				3				554				—				122				1				123
Agency and mortgage-backed securities			—				105				—				105				—				43				—				43
Common/collective trusts			—				249				—				249				—				346				—				346
Mutual funds			—				—				—				—				130				—				—				130
Cash and cash equivalents			—				—				—				—				32				26				—				58
Private equity funds			—				—				4				4				—				—				13				13
Derivatives			—				—				—				—				—				11				—				11
Insurance contracts			—				—				—				—				—				—				15				15
Real estate			—				—				—				—				—				—				139				139
Total*		$	2,365				1,620				7				3,992				1,766				782				168				2,716

* Excludes the participating interest in the annuity contract with a net asset value of $144 million and net receivables related to security transactions of $19 million.

2010
Equity Securities
U.S.		$	1,250				—				—				1,250				378				—				—				378
International			818				—				—				818				498				—				—				498
Common/collective trusts			—				635				—				635				—				246				—				246
Mutual funds			—				—				—				—				282				—				—				282
Debt Securities
Government			251				56				—				307				390				—				—				390
Corporate			—				420				3				423				—				171				2				173
Agency and mortgage-backed securities			—				81				—				81				—				—				—				—
Common/collective trusts			—				270				—				270				—				329				—				329
Mutual funds			—				—				—				—				122				—				—				122
Cash and cash equivalents			—				—				—				—				9				10				—				19
Private equity funds			—				—				6				6				—				—				8				8
Derivatives			—				—				—				—				—				12				—				12
Insurance contracts			—				—				—				—				—				—				16				16
Real estate			—				—				—				—				—				—				101				101
Total*		$	2,319				1,462				9				3,790				1,679				768				127				2,574

* Excludes the participating interest in the annuity contract with a net asset value of $92 million and net receivables related to security transactions of $15 million.

As reflected in the table above, Level 3 activity was not material.

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Our funding policy for U.S. plans is to contribute at least the minimum required by the Employee Retirement Income Security Act of 1974 and the Internal Revenue Code of 1986, as amended. Contributions to foreign plans are dependent upon local laws and tax regulations. In 2012, we expect to contribute approximately $690 million to our domestic qualified and nonqualified pension and postretirement benefit plans and $235 million to our international qualified and nonqualified pension and postretirement benefit plans.

The following benefit payments, which are exclusive of amounts to be paid from the participating annuity contract and which reflect expected future service, as appropriate, are expected to be paid:

		Millions of Dollars
		Pension Benefits								Other Benefits
		U.S.				Int’l.
2012		$	577				110				63
2013			501				113				64
2014			524				121				67
2015			553				129				70
2016			598				134				72
2017-2021			3,206				794				385

Defined Contribution Plans

Most U.S. employees are eligible to participate in the ConocoPhillips Savings Plan (CPSP). Employees can deposit up to 75 percent of their eligible pay up to the statutory limit ($16,500 in 2011) in the thrift feature of the CPSP to a choice of approximately 39 investment funds. ConocoPhillips matches contribution deposits, up to 1.25 percent of eligible pay. Company contributions charged to expense related to continuing and discontinued operations for the CPSP and predecessor plans, excluding the stock savings feature (discussed below), were $25 million in 2011, $24 million in 2010, and $23 million in 2009.

The stock savings feature of the CPSP is a leveraged employee stock ownership plan. Employees may elect to participate in the stock savings feature by contributing 1 percent of eligible pay and receiving an allocation of shares of common stock proportionate to the amount of contribution.

In 1990, the Long-Term Stock Savings Plan of Phillips Petroleum Company (now the stock savings feature of the CPSP) borrowed funds that were used to purchase previously unissued shares of company common stock. Since the company guarantees the CPSP’s borrowings, the unpaid balance is reported as a liability of the company and unearned compensation is shown as a reduction of common stockholders’ equity. Dividends on all shares are charged against retained earnings. The debt is serviced by the CPSP from company contributions and dividends received on certain shares of common stock held by the plan, including all unallocated shares. The shares held by the stock savings feature of the CPSP are released for allocation to participant accounts based on debt service payments on CPSP borrowings. In addition, during the period from 2012 through 2014, when no debt principal payments are scheduled to occur, we have committed to make direct contributions of stock to the stock savings feature of the CPSP, or make prepayments on CPSP borrowings, to ensure a certain minimum level of stock allocation to participant accounts.

We recognize interest expense as incurred and compensation expense based on the fair market value of the stock contributed or on the cost of the unallocated shares released, using the shares-allocated method. We recognized total CPSP expense related to continuing and discontinued operations to the stock savings feature of $77 million, $92 million and $83 million in 2011, 2010 and 2009, respectively, all of which was compensation expense. In 2011, we made cash contributions to the CPSP of $4 million. No cash contributions were made in 2010 and 2009. In 2011, 2010 and 2009, we contributed 660,755 shares, 1,776,873 shares and 2,018,692 shares, respectively, of company common stock from the Compensation and Benefits Trust. The shares had a fair market value of $84 million, $103 million and $94 million, respectively. Also in 2011, we contributed 475,696 shares of company common stock from Treasury stock. Dividends used to service debt were $45 million, $41 million and $39 million in 2011, 2010 and 2009, respectively. These dividends reduced the amount of compensation expense recognized each period. Interest incurred on the CPSP debt in 2011, 2010 and 2009 was $1 million, $2 million and $2 million, respectively.

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The total CPSP stock savings feature shares as of December 31 were:

		2011				2010
Unallocated shares			811,963				3,385,778
Allocated shares			19,315,372				19,198,502
Total shares			20,127,335				22,584,280

The fair value of unallocated shares at December 31, 2011 and 2010, was $59 million and $231 million, respectively.

We have several defined contribution plans for our international employees, each with its own terms and eligibility depending on location. Total compensation expense related to continuing and discontinued operations recognized for these international plans was approximately $56 million in 2011, $52 million in 2010 and $51 million in 2009.

Share-Based Compensation Plans

The 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (the Plan) was approved by shareholders in May 2011. Over its 10-year life, the Plan allows the issuance of up to 100 million shares of our common stock for compensation to our employees, directors and consultants; however, as of the effective date of the Plan, (i) any shares of common stock available for future awards under the prior plans and (ii) any shares of common stock represented by awards granted under the prior plans that are forfeited, expire or are canceled without delivery of shares of common stock or which result in the forfeiture of shares of common stock back to the company shall be available for awards under the Plan, and no new awards shall be granted under the prior plans. Of the 100 million shares available for issuance under the Plan, no more than 40 million shares of common stock are available for incentive stock options, and no more than 40 million shares are available for awards in stock.

Our share-based compensation programs generally provide accelerated vesting (i.e., a waiver of the remaining period of service required to earn an award) for awards held by employees at the time of their retirement. For share-based awards granted prior to our adoption of Statement of Financial Accounting Standards No. 123(R), codified into FASB ASC Topic 718, “Compensation—Stock Compensation,” we recognize expense over the period of time during which the employee earns the award, accelerating the recognition of expense only when an employee actually retires. For share-based awards granted after our adoption of ASC 718 on January 1, 2006, we recognize share-based compensation expense over the shorter of the service period (i.e., the stated period of time required to earn the award); or the period beginning at the start of the service period and ending when an employee first becomes eligible for retirement, but not less than six months, as this is the minimum period of time required for an award to not be subject to forfeiture.

Some of our share-based awards vest ratably (i.e., portions of the award vest at different times) while some of our awards cliff vest (i.e., all of the award vests at the same time). For awards granted prior to our adoption of ASC 718 that vest ratably, we recognize expense on a straight-line basis over the service period for each separate vesting portion of the award (i.e., as if the award was multiple awards with different requisite service periods). For share-based awards granted after our adoption of ASC 718, we recognize expense on a straight-line basis over the service period for the entire award, whether the award was granted with ratable or cliff vesting.

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Total share-based compensation expense recognized in income related to continuing and discontinued operations and the associated tax benefit for the years ended December 31, were as follows:

		Millions of Dollars
		2011				2010				2009
Compensation cost		$	246				211				121
Tax benefit			86				78				42

Stock Options—Stock options granted under the provisions of the Plan and earlier plans permit purchase of our common stock at exercise prices equivalent to the average market price of the stock on the date the options were granted. The options have terms of 10 years and generally vest ratably, with one-third of the options awarded vesting and becoming exercisable on each anniversary date following the date of grant. Options awarded to employees already eligible for retirement vest within six months of the grant date, but those options do not become exercisable until the end of the normal vesting period.

The following summarizes our stock option activity for the three years ended December 31, 2011:

						Weighted-				Weighted-Average				Millions of Dollars
		Options				Average Exercise  Price				Grant-Date Fair Value				Aggregate Intrinsic Value
Outstanding at December 31, 2008			36,615,753			$	35.65
Granted			3,311,200				45.47			$	11.18
Exercised			(2,919,118	)			24.10							$	67
Forfeited			(332,941	)			52.04
Expired or canceled			(241,421	)			63.49
Outstanding at December 31, 2009			36,433,473			$	37.13
Granted			3,040,500				48.39			$	11.70
Exercised			(6,401,483	)			29.08							$	183
Forfeited			(255,889	)			48.42
Expired or canceled			(204,727	)			58.94
Outstanding at December 31, 2010			32,611,874			$	39.54
Granted			1,907,000				70.13			$	16.70
Exercised			(10,022,685	)			30.08							$	416
Forfeited			(82,434	)			62.26
Expired or canceled			(41,704	)			51.60
Outstanding at December 31, 2011			24,372,051			$	45.73
Vested at December 31, 2011			22,214,254			$	44.49							$	611
Exercisable at December 31, 2011			19,666,959			$	43.19							$	564

The weighted-average remaining contractual term of vested options and exercisable options at December 31, 2011, was 3.95 years and 3.4 years, respectively.

During 2011, we received $197 million in cash and realized a tax benefit related to continuing and discontinued operations of $119 million from the exercise of options. At December 31, 2011, the remaining unrecognized compensation expense from unvested options was $16 million, which will be recognized over a weighted-average period of 19 months, the longest period being 25 months.

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The significant assumptions used to calculate the fair market values of the options granted over the past three years, as calculated using the Black-Scholes-Merton option-pricing model, were as follows:

		2011				2010				2009
Assumptions used
Risk-free interest rate			3.10	%			3.23				2.90
Dividend yield			4.00	%			4.00				3.50
Volatility factor			33.40	%			33.80				32.90
Expected life (years)			6.87				6.65				6.53

The ranges in the assumptions used were as follows:

		2011								2010								2009
		High				Low				High				Low				High				Low
Ranges used
Risk-free interest rate			3.10	%			3.10				3.23				3.23				2.90				2.90
Dividend yield			4.00				4.00				4.00				4.00				3.50				3.50
Volatility factor			33.40				33.40				33.80				33.80				32.90				32.90

We calculate volatility using the most recent ConocoPhillips end-of-week closing stock prices spanning a period equal to the expected life of the options granted. We periodically calculate the average period of time lapsed between grant dates and exercise dates of past grants to estimate the expected life of new option grants.

Stock Unit Program—Generally, restricted stock units are granted annually under the provisions of the Plan and vest ratably, with one-third of the units vesting in 36 months, one-third vesting in 48 months, and the final third vesting 60 months from the date of grant. In addition to these regularly scheduled annual awards, restricted stock units are also granted ad hoc to attract or retain key personnel, and the terms and conditions under which these restricted stock units vest vary by award. Upon vesting, the units are settled by issuing one share of ConocoPhillips common stock per unit. Units awarded to employees already eligible for retirement vest within six months of the grant date, but those units are not issued as shares until the end of the normal vesting period. Until issued as stock, most recipients of the units receive a quarterly cash payment of a dividend equivalent that is charged to expense. The grant date fair value of these units is deemed equal to the average ConocoPhillips stock price on the date of grant. The grant date fair market value of units that do not receive a dividend equivalent while unvested is deemed equal to the average ConocoPhillips stock price on the grant date, less the net present value of the dividends that will not be received.

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The following summarizes our stock unit activity for the three years ended December 31, 2011:

						Weighted-Average				Millions of Dollars
		Stock Units				Grant-Date Fair Value				Total Fair Value
Outstanding at December 31, 2008			5,927,698			$	61.14
Granted			2,910,095				43.41
Forfeited			(207,932	)			51.84
Issued			(1,910,309	)						$	88
Outstanding at December 31, 2009			6,719,552			$	57.08
Granted			2,890,010				46.38
Forfeited			(233,212	)			53.11
Issued			(1,573,487	)						$	79
Outstanding at December 31, 2010			7,802,863			$	53.04
Granted			2,746,045				67.54
Forfeited			(299,531	)			56.43
Issued			(1,520,419	)						$	109
Outstanding at December 31, 2011			8,728,958			$	55.41
Not Vested at December 31, 2011			6,175,477			$	55.93

At December 31, 2011, the remaining unrecognized compensation cost from the unvested units was $188 million, which will be recognized over a weighted-average period of 30 months, the longest period being 100 months.

Performance Share Program—Under the Plan, we also annually grant to senior management restricted performance share units (PSUs) that do not vest until either (i) with respect to awards for performance periods beginning before 2009, the employee becomes eligible for retirement by reaching age 55 with five years of service or (ii) with respect to awards for performance periods beginning in 2009, five years after the grant date of the award (although recipients can elect to defer the lapsing of restrictions until retirement after reaching age 55 with five years of service), so we recognize compensation expense for these awards beginning on the date of grant and ending on the date the PSUs are scheduled to vest. Since these awards are authorized three years prior to the grant date, for employees eligible for such retirement by or shortly after the grant date, we recognize compensation expense over the period beginning on the date of authorization and ending on the date of grant. These PSUs are settled by issuing one share of ConocoPhillips common stock per unit. Until issued as stock, recipients of the PSUs receive a quarterly cash payment of a dividend equivalent that is charged to expense. In its current form, the first grant of PSUs under this program was in 2006.

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The following summarizes our Performance Share Program activity for the three years ended December 31, 2011:

		Performance				Weighted-Average				Millions of Dollars
		Share Units				Grant-Date Fair Value				Total Fair Value
Outstanding at December 31, 2008			3,176,178			$	68.13
Granted			659,812				45.47
Forfeited			(23,670	)			65.00
Issued			(407,442	)						$	19
Outstanding at December 31, 2009			3,404,878			$	64.63
Granted			317,072				48.39
Forfeited			(53,243	)			62.66
Issued			(234,121	)						$	12
Outstanding at December 31, 2010			3,434,586			$	63.43
Granted			615,780				70.57
Forfeited			(23,240	)			63.18
Issued			(509,365	)						$	37
Outstanding at December 31, 2011			3,517,761			$	64.35
Not Vested at December 31, 2011			1,063,982			$	64.16

At December 31, 2011, the remaining unrecognized compensation cost from unvested Performance Share awards was $27 million, which will be recognized over a weighted-average period of 46 months, the longest period being 15 years.

Other—In addition to the above active programs, we have outstanding shares of restricted stock and restricted stock units that were either issued to replace awards held by employees of companies we acquired or issued as part of a compensation program that has been discontinued. Generally, the recipients of the restricted shares or units receive a quarterly dividend or dividend equivalent.

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The following summarizes the aggregate activity of these restricted shares and units for the three years ended December 31, 2011:

						Weighted-Average				Millions of Dollars
		Stock Units				Grant-Date Fair Value				Total Fair Value
Outstanding at December 31, 2008			3,364,020			$	36.75
Granted			78,299				45.72
Issued			(204,160	)						$	10
Canceled			(101,642	)			52.91
Outstanding at December 31, 2009			3,136,517			$	35.11
Granted			73,395				53.33
Issued			(181,035	)						$	9
Canceled			(58,441	)			44.23
Outstanding at December 31, 2010			2,970,436			$	34.06
Granted			76,642				70.25
Issued			(139,523	)						$	10
Canceled			(319,640	)			30.90
Outstanding at December 31, 2011			2,587,915			$	33.49
Not Vested at December 31, 2011			—

At December 31, 2011, there was no remaining unrecognized compensation cost from the unvested units.

Compensation and Benefits Trust

The Compensation and Benefits Trust (CBT) was an irrevocable grantor trust, administered by an independent trustee and designed to acquire, hold and distribute shares of our common stock to fund certain future compensation and benefit obligations of the company. The trustee voted shares held by the CBT in accordance with voting directions from eligible employees, as specified in a trust agreement with the trustee. We sold 58.4 million shares of previously unissued company common stock to the CBT in 1995 for $37 million of cash, previously contributed to the CBT by us, and a promissory note from the CBT to us of $952 million. The CBT was consolidated by ConocoPhillips; therefore, the cash contribution and promissory note were eliminated in consolidation. Shares held by the CBT were valued at cost and did not affect earnings per share or total common stockholders’ equity until after they were transferred out of the CBT. In 2010, 1,776,873 shares were transferred out of the CBT.

In August 2011, all of the approximately 36 million shares of company common stock held by the CBT were transferred to ConocoPhillips, and those shares are now held as non-voting treasury stock. Because the CBT was consolidated by us, the transfer of its shares from “Grantor trusts” to “Treasury stock” in the equity section of our balance sheet was recorded at the shares’ historical carrying value of $610 million. This transfer did not affect total equity, shares outstanding or earnings per share. The CBT no longer holds any assets. Two smaller grantor trusts also disposed of all their shares of company stock during 2011.

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Note 20—Income Taxes

Income taxes charged to income from continuing operations were:

		Millions of Dollars
		2011				2010				2009
Income Taxes
Federal
Current		$	1,073				1,240				289
Deferred			264				126				257
Foreign
Current			6,966				7,289				5,366
Deferred			49				(1,058	)			(1,082	)
State and local
Current			317				260				99
Deferred			101				6				(12	)
		$	8,770				7,863				4,917

Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for tax purposes. Major components of deferred tax liabilities and assets at December 31 were:

		Millions of Dollars
		2011				2010
Deferred Tax Liabilities
PP&E and intangibles		$	21,159				20,344
Investment in joint ventures			2,943				2,201
Inventory			—				43
Partnership income deferral			363				434
Other			703				571
Total deferred tax liabilities			25,168				23,593
Deferred Tax Assets
Benefit plan accruals			2,063				1,691
Asset retirement obligations and accrued environmental costs			4,254				3,971
Inventory			43				—
Deferred state income tax			299				257
Other financial accruals and deferrals			618				394
Loss and credit carryforwards			1,608				1,344
Other			692				717
Total deferred tax assets			9,577				8,374
Less valuation allowance			(1,487	)			(1,400	)
Net deferred tax assets			8,090				6,974
Net deferred tax liabilities		$	17,078				16,619

Current assets, long-term assets, current liabilities and long-term liabilities included deferred taxes of $788 million, $183 million, $9 million and $18,040 million, respectively, at December 31, 2011, and $562 million, $160 million, $21 million and $17,320 million, respectively, at December 31, 2010.

We have loss and credit carryovers in multiple taxing jurisdictions. These attributes generally expire between 2012 and 2031 with some carryovers having indefinite carryforward periods.

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Valuation allowances have been established to reduce deferred tax assets to an amount that will, more likely than not, be realized. During 2011, valuation allowances increased a total of $87 million. This reflects increases of $174 million primarily related to U.S. foreign tax credit and foreign loss carryforwards, partially offset by decreases of $87 million, primarily related to utilization of U.S. foreign tax credit and state loss carryforwards, currency effects and asset relinquishment. Based on our historical taxable income, expectations for the future, and available tax-planning strategies, management expects remaining net deferred tax assets will be realized as offsets to reversing deferred tax liabilities and as offsets to the tax consequences of future taxable income.

At December 31, 2011 and 2010, income considered to be permanently reinvested in certain foreign subsidiaries and foreign corporate joint ventures totaled approximately $4,227 million and $4,134 million, respectively. Deferred income taxes have not been provided on this income, as we do not plan to initiate any action that would require the payment of income taxes. It is not practicable to estimate the amount of additional tax that might be payable on this foreign income if distributed.

The following table shows a reconciliation of the beginning and ending unrecognized tax benefits for 2011, 2010 and 2009:

		Millions of Dollars
		2011				2010				2009
Balance at January 1		$	1,125				1,208				1,068
Additions based on tax positions related to the current year			46				63				18
Additions for tax positions of prior years			145				344				177
Reductions for tax positions of prior years			(35	)			(199	)			(33	)
Settlements			(206	)			(215	)			(19	)
Lapse of statute			(4	)			(76	)			(3	)
Balance at December 31		$	1,071				1,125				1,208

Included in the balance of unrecognized tax benefits for 2011, 2010 and 2009 were $815 million, $914 million and $931 million, respectively, which, if recognized, would affect our effective tax rate.

At December 31, 2011, 2010 and 2009, accrued liabilities for interest and penalties totaled $141 million, $171 million and $166 million, respectively, net of accrued income taxes. Interest and penalties resulted in a charge to earnings in 2011 of $10 million, a benefit to earnings in 2010 of $2 million, and a charge to earnings in 2009 of $18 million.

We and our subsidiaries file tax returns in the U.S. federal jurisdiction and in many foreign and state jurisdictions. Audits in major jurisdictions are generally complete as follows: United Kingdom (2008), Canada (2005), United States (2006) and Norway (2010). Issues in dispute for audited years and audits for subsequent years are ongoing and in various stages of completion in the many jurisdictions in which we operate around the world. As a consequence, the balance in unrecognized tax benefits can be expected to fluctuate from period to period. It is reasonably possible such changes could be significant when compared with our total unrecognized tax benefits, but the amount of change is not estimable.

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The amounts of U.S. and foreign income from continuing operations before income taxes, with a reconciliation of tax at the federal statutory rate with the provision for income taxes, were:

														Percent of
		Millions of Dollars												Pretax Income
		2011				2010				2009				2011				2010				2009
Income from continuing operations before income taxes
United States		$	4,703				3,810				2,218				29.0				20.8				25.5
Foreign			11,522				14,502				6,496				71.0				79.2				74.5
		$	16,225				18,312				8,714				100.0	%			100.0				100.0
Federal statutory income tax		$	5,679				6,409				3,050				35.0	%			35.0				35.0
Foreign taxes in excess of federal statutory rate			2,924				1,375				1,902				18.0				7.5				21.8
Federal manufacturing deduction			(73	)			(75	)			(40	)			(0.4	)			(0.4	)			(0.5	)
State income tax			272				173				57				1.7				0.9				0.7
Other			(32	)			(19	)			(52	)			(0.2	)			(0.1	)			(0.6	)
		$	8,770				7,863				4,917				54.1	%			42.9				56.4

The change in the effective tax rate from 2010 to 2011, as well as from 2009 to 2010, was primarily due to tax benefits associated with asset dispositions occurring in 2010.

In the United Kingdom, legislation was enacted on July 19, 2011, which increased the supplementary corporate tax rate applicable to U.K. Upstream activity from 20 to 32 percent, retroactively effective from March 24, 2011. This resulted in the overall U.K. corporate rate increasing from 50 percent to 62 percent. The enactment resulted in increased income tax expense of $316 million in 2011. This is comprised of $106 million due to remeasurement of U.K. deferred tax liabilities, and $210 million to reflect the new rate from March 24, 2011, through the end of the year. Statutory tax rate changes did not have a significant impact on our income tax expense in 2010 or 2009.

Note 21—Accumulated Other Comprehensive Income

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

		Millions of Dollars
		Defined Benefit Plans				Net Unrealized Gain on Securities				Foreign Currency Translation				Hedging				Accumulated Other Comprehensive Income (Loss)
December 31, 2008*		$	(1,434	)			—				(240	)			(10	)			(1,684	)
Other comprehensive income			(70	)			—				5,007				3				4,940
Other*			—				—				(31	)			—				(31	)
December 31, 2009*			(1,504	)			—				4,736				(7	)			3,225
Other comprehensive income			146				158				1,404				—				1,708
December 31, 2010*			(1,358	)			158				6,140				(7	)			4,933
Other comprehensive income (loss)			(613	)			(158	)			(917	)			1				(1,687	)
December 31, 2011		$	(1,971	)			—				5,223				(6	)			3,246

* Retained earnings has been restated to reflect certain intercompany loans as permanently invested, which resulted in a $191 million increase in Foreign Currency Translation and Accumulated Other Comprehensive Income, a $1 million decrease to Total Liabilities, and a $190 million reduction in Retained Earnings at December 31, 2008. The impact on net income and earnings per share was de minimis for all periods presented.

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Note 22—Cash Flow Information

Amounts included in continuing operations for the years ended December 31 were:

		Millions of Dollars
		2011				2010				2009
Noncash Investing and Financing Activities
Increase in PP&E related to an increase in asset retirement obligations		$	182				808				974
Cash Payments
Interest		$	919				1,120				1,052
Income taxes			10,285				8,262				6,377
Net Sales (Purchases) of Short-Term Investments
Short-term investments purchased		$	(6,744	)			(982	)			—
Short-term investments sold			7,144				—				—
		$	400				(982	)			—

Note 23—Other Financial Information

Amounts included in continuing operations for the years ended December 31 were:

		Millions of Dollars
		Except Per Share Amounts
		2011				2010				2009
Interest and Debt Expense
Incurred
Debt		$	1,230				1,401				1,470
Other			212				237				269
Capitalized			(488	)			(471	)			(472	)
Expensed*		$	954				1,167				1,267

* Pretax interest expense of $18 million, $20 million and $22 million for the years 2011, 2010 and 2009, respectively, are included in discontinued operations and relates to short- and long-term debt included in the separation of the Downstream business. See Note 26—Separation of Downstream Business.

Other Income
Interest income		$	170				135				166
Other, net			104				47				91
		$	274				182				257
Research and Development Expenditures—expensed		$	193				172				121
Advertising Expenses		$	29				8				12
Shipping and Handling Costs*		$	1,417				1,387				1,213

* Amounts included in production and operating expenses.

Cash Dividends paid per common share		$	2.64				2.15				1.91
Foreign Currency Transaction (Gains) Losses—after-tax
Alaska		$	—				—				—
Lower 48 and Latin America			—				1				—
Canada			(3	)			10				(28	)
Europe			7				20				86
Asia Pacific and Middle East			(23	)			(96	)			26
Other International			3				4				27
LUKOIL Investment			(1	)			15				(20	)
Corporate and Other			(16	)			7				(94	)
		$	(33	)			(39	)			(3	)

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Note 24—Related Party Transactions

Significant transactions with related parties included in continuing operations were:

		Millions of Dollars
		2011				2010				2009
Operating revenues and other income (a)		$	49				18				16
Gain on dispositions (b)			—				1,149				—
Purchases (c)			327				656				814
Operating expenses and selling, general and administrative expenses (d)			233				238				229
Net interest expense (e)			61				75				84

(a) We sold natural gas to DCP Midstream and crude oil to the Malaysian Refining Company Sdn. Bhd. (MRC), among others, for processing and marketing. Natural gas liquids, solvents and petrochemical feedstocks were sold to CPChem, gas oil and hydrogen feedstocks were sold to Excel Paralubes and refined products were sold primarily to CFJ Properties and LUKOIL. Beginning in the third quarter of 2010, CFJ was no longer considered a related party due to the sale of our interest. Natural gas, crude oil, blendstock and other intermediate products were sold to WRB. 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. Amounts related to discontinued operations entities and excluded from the table above for the years 2011, 2010 and 2009 totaled $8,304 million, $7,315 million and $7,184 million, respectively.

(b) In 2011, we sold the Seaway Products Pipeline to DCP Midstream for cash proceeds of $400 million, resulting in a before-tax gain of $156 million, which is included in discontinued operations and excluded from the table above. During 2010, we sold a portion of our LUKOIL shares under a stock purchase and option agreement with a wholly owned subsidiary of LUKOIL, resulting in a before-tax gain of $1,149 million.

(c) 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. Amounts related to discontinued operations entities and excluded from the table above for the years 2011, 2010 and 2009 totaled $20,369 million, $15,163 million and $11,965 million, respectively.

(d) We paid processing fees to various affiliates. Additionally, we paid transportation fees to pipeline equity companies. Amounts related to discontinued operations entities and excluded from the table above for the years 2011, 2010 and 2009 totaled $159 million, $106 million and $93 million, respectively.

(e) We paid and/or received interest to/from various affiliates, including FCCL. See Note 6—Investments, Loans and Long-Term Receivables, for additional information on loans to affiliated companies. Amounts related to discontinued operations entities and excluded from the table above totaled $10 million in net interest expense for 2011 and net interest income of $2 million and $10 million for 2010 and 2009, respectively.

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

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Note 25—Segment Disclosures and Related Information

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. We manage our operations through six operating segments, which are defined by geographic region: Alaska, Lower 48 and Latin America, Canada, Europe, Asia Pacific and Middle East, and Other International. This is a change in our reportable segments, and, as a result, all prior periods presented have been restated.

On April 30, 2012, our Downstream business was separated into a stand-alone, publicly traded corporation, Phillips 66, and has been reported as discontinued operations in all periods presented. Commodity sales to Phillips 66, which were previously eliminated in consolidation prior to the separation, are now reported as third-party sales. For additional information, see Note 26—Separation of Downstream Business.

Our LUKOIL Investment represents our prior investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. We completed the divestiture of our entire interest in LUKOIL in the first quarter of 2011.

Corporate and Other represents costs not directly associated with an operating segment, such as most interest expense, corporate overhead, ongoing costs associated with the separation of the Downstream business and certain technology activities, net of licensing revenues. Corporate assets include all cash and cash equivalents, short-term investments and restricted cash.

We evaluate performance and allocate resources based on net income attributable to ConocoPhillips. Segment accounting policies are the same as those in Note 1—Accounting Policies. Intersegment sales are at prices that approximate market.

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Analysis of Results by Operating Segment

		Millions of Dollars
		2011				2010				2009
Sales and Other Operating Revenues
Alaska		$	9,533				7,462				6,428
Lower 48 and Latin America			23,507				21,980				18,303
Intersegment eliminations			(283	)			(180	)			(150	)
Lower 48 and Latin America			23,224				21,800				18,153
Canada			6,270				6,147				5,412
Intersegment eliminations			(944	)			(797	)			(703	)
Canada			5,326				5,350				4,709
Europe			17,119				12,819				11,852
Intersegment eliminations			(50	)			(17	)			—
Europe			17,069				12,802				11,852
Asia Pacific and Middle East			8,665				7,161				5,463
Intersegment eliminations			(1	)			(1	)			—
Asia Pacific and Middle East			8,664				7,160				5,463
Other International			1,781				2,624				2,184
LUKOIL Investment			—				—				—
Corporate and Other			159				98				39
Consolidated sales and other operating revenues		$	65,756				57,296				48,828
Depreciation, Depletion, Amortization and Impairments
Alaska		$	578				626				694
Lower 48 and Latin America			2,228				2,286				2,718
Canada			1,758				1,680				1,985
Europe			1,405				2,049				2,111
Asia Pacific and Middle East			1,063				1,329				1,050
Other International			196				209				210
LUKOIL Investment			—				—				—
Corporate and Other			108				71				108
Consolidated depreciation, depletion, amortization and impairments		$	7,336				8,250				8,876

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		Millions of Dollars
		2011				2010				2009
Equity in Earnings of Affiliates
Alaska		$	(77	)			8				(38	)
Lower 48 and Latin America			99				80				32
Canada			677				505				344
Europe			46				41				30
Asia Pacific and Middle East			819				(17	)			(68	)
Other International			(329	)			(540	)			(73	)
LUKOIL Investment			—				1,295				1,219
Corporate and Other			(1	)			(4	)			(7	)
Consolidated equity in earnings of affiliates		$	1,234				1,368				1,439
Income Taxes
Alaska		$	1,171				1,017				823
Lower 48 and Latin America			741				595				(37	)
Canada			(45	)			215				(237	)
Europe			4,459				3,118				2,272
Asia Pacific and Middle East			1,887				1,340				1,111
Other International			709				1,451				1,173
LUKOIL Investment			123				505				12
Corporate and Other			(275	)			(378	)			(200	)
Consolidated income taxes		$	8,770				7,863				4,917
Net Income Attributable to ConocoPhillips
Alaska		$	1,984				1,727				1,534
Lower 48 and Latin America			1,288				1,029				(73	)
Canada			91				2,902				(257	)
Europe			1,830				1,703				1,119
Asia Pacific and Middle East			3,032				2,099				1,322
Other International			(94	)			(261	)			20
LUKOIL Investment			239				2,513				1,219
Corporate and Other			(976	)			(1,317	)			(1,161	)
Discontinued operations			5,042				963				691
Consolidated net income attributable to ConocoPhillips		$	12,436				11,358				4,414

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		Millions of Dollars
		2011				2010				2009
Investments In and Advances To Affiliates
Alaska		$	58				143				117
Lower 48 and Latin America			1,168				1,190				1,184
Canada			9,045				8,675				8,320
Europe			195				211				204
Asia Pacific and Middle East			11,571				11,335				9,145
Other International			381				828				1,978
LUKOIL Investment			—				—				6,411
Corporate and Other			9				—				—
Discontinued operations			10,233				9,853				9,273
Consolidated investments in and advances to affiliates		$	32,660				32,235				36,632
Total Assets
Alaska		$	10,723				10,832				10,449
Lower 48 and Latin America			25,872				24,213				25,098
Canada			20,847				21,168				23,559
Europe			12,452				11,335				12,589
Asia Pacific and Middle East			22,374				21,853				20,206
Other International			9,070				8,675				8,431
LUKOIL Investment			—				1,129				6,416
Corporate and Other			8,485				11,974				1,994
Discontinued operations			43,407				45,135				43,396
Consolidated total assets		$	153,230				156,314				152,138
Capital Expenditures and Investments
Alaska		$	774				729				810
Lower 48 and Latin America			3,882				1,790				2,035
Canada			1,761				1,356				1,176
Europe			2,222				1,190				1,144
Asia Pacific and Middle East			2,325				2,157				2,100
Other International			1,038				1,203				1,001
LUKOIL Investment			—				—				—
Corporate and Other			242				186				134
Consolidated capital expenditures and investments		$	12,244				8,611				8,400

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		Millions of Dollars
		2011				2010				2009
Interest Income and Expense
Interest income
Corporate		$	94				54				75
Lower 48 and Latin America			51				54				59
Asia Pacific and Middle East			7				8				10
Other International			18				19				22
Interest and debt expense
Corporate		$	832				1,027				1,111
Canada			122				140				156

Geographic Information

		Millions of Dollars
		Sales and Other Operating Revenues*												Long-Lived Assets**
		2011				2010				2009				2011				2010				2009
United States		$	32,790				29,305				24,591				33,750				32,246				32,841
Australia***			3,458				2,789				2,229				12,572				12,461				10,729
Canada			5,326				5,350				4,709				20,083				20,439				22,451
China			2,154				1,870				1,076				2,449				2,656				2,849
Indonesia			2,076				1,696				1,419				1,726				1,745				2,072
Norway			5,755				4,692				4,101				5,918				5,664				5,797
Russia			—				—				—				341				815				8,383
United Kingdom			11,314				8,110				7,751				3,257				2,975				3,768
Other foreign countries			2,883				3,484				2,952				11,465				10,265				8,704
Discontinued operations			—				—				—				25,279				25,523				26,746
Worldwide consolidated		$	65,756				57,296				48,828				116,840				114,789				124,340

* Sales and other operating revenues are attributable to countries based on the location of the operations generating the revenues.

** Defined as net PP&E plus investments in and advances to affiliated companies.

*** Includes amounts related to the joint petroleum development area with shared ownership held by Australia and Timor-Leste.

Note 26—Separation of Downstream Business

On April 30, 2012, the separation of our Downstream business was completed, creating two independent energy companies: ConocoPhillips and Phillips 66. After the close of the New York Stock Exchange on April 30, 2012, the shareholders of record as of 5:00 p.m. Eastern time on April 16, 2012 (the Record Date), received one share of Phillips 66 common stock for every two ConocoPhillips common shares held as of the Record Date. As such, the income statement, statement of cash flows and certain footnotes included herein have been revised to present Phillips 66 as discontinued operations. See Note 1—Accounting Policies, Note 10—Impairments, Note 16—Financial Instruments and Derivative Contracts, Note 18—Non-Mineral Leases, Note 20—Income Taxes, Note 22—Cash Flow Information, Note 23—Other Financial Information, and Note 24—Related Party Transactions, for revised presentation of results of operations, as applicable.

In connection with the separation, Phillips 66 distributed approximately $7.8 billion to us in a special cash distribution, primarily using the proceeds from $5.8 billion in Senior Notes issued by Phillips 66 in March 2012, as well as a portion of approximately $3.6 billion in cash transferred to Phillips 66 at separation, comprised of funds received from the $2.0 billion term loan entered into by Phillips 66 immediately prior to the separation, and approximately $1.6 billion of cash held by Phillips 66 subsidiaries. Pursuant to the private letter ruling from the Internal Revenue Service, the principal funds from the special cash distribution will be used solely to pay dividends, repurchase common stock, repay debt, or a combination of the foregoing, within twelve months following the distribution. At September 30, 2012, the remaining balance of the cash distribution was $2,468 million.

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In order to effect the separation and govern our relationship with Phillips 66 after the separation, we entered into a Separation and Distribution Agreement, an Indemnification and Release Agreement, an Intellectual Property Assignment and License Agreement, a Tax Sharing Agreement, an Employee Matters Agreement and a Transition Services Agreement. The Separation and Distribution Agreement governs the separation of the Downstream business, the transfer of assets and other matters related to our relationship with Phillips 66. The Indemnification and Release Agreement provides for cross-indemnities between Phillips 66 and us and established procedures for handling claims subject to indemnification and related matters. The Intellectual Property Assignment and License Agreement governs the allocation of intellectual property rights and assets between Phillips 66 and us.

The Tax Sharing Agreement governs the respective rights, responsibilities and obligations of Phillips 66 and ConocoPhillips with respect to taxes, tax attributes, tax returns, tax proceedings and certain other tax matters. In addition, the Tax Sharing Agreement imposed certain restrictions on Phillips 66 and its subsidiaries (including restrictions on share issuances, business combinations, sales of assets and similar transactions) that are designed to preserve the tax-free status of the distribution and certain related transactions. The Tax Sharing Agreement sets forth the obligations of Phillips 66 and us as to the filing of tax returns, the administration of tax proceedings and assistance and cooperation on tax matters.

The Employee Matters Agreement governs the compensation and employee benefit obligations with respect to the current and former employees and non-employee directors of Phillips 66 and ConocoPhillips, and generally allocates liabilities and responsibilities relating to employee compensation, benefit plans and programs. The Employee Matters Agreement provides that employees of Phillips 66 will no longer participate in benefit plans sponsored or maintained by ConocoPhillips. In addition, the Employee Matters Agreement provides that each of the parties will be responsible for their respective current employees and compensation plans for such current employees, and we will be responsible for all liabilities relating to former employees. The Employee Matters Agreement sets forth the general principles relating to employee matters and also addresses any special circumstances during the transition period. The Employee Matters Agreement also provides that (i) the distribution does not constitute a change in control under existing plans, programs, agreements or arrangements, and (ii) the distribution and the assignment, transfer or continuation of the employment of employees with another entity will not constitute a severance event under the applicable plans, programs, agreements or arrangements.

The Transition Services Agreement sets forth the terms on which we will provide Phillips 66, and Phillips 66 will provide to us, certain services or functions Phillips 66 and ConocoPhillips historically have shared. Transition services include administrative, payroll, human resources, data processing, environmental health and safety, financial audit support, financial transaction support, and other support services, information technology systems and various other corporate services. The agreement provides for the provision of specified transition services, generally for a period of up to 12 months, with a possible extension of 6 months (an aggregate of 18 months), on a cost or a cost-plus basis.

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The following table presents the carrying value of the major categories of assets and liabilities of Phillips 66, included in our consolidated balance sheet at December 31, 2011 and 2010:

		Millions of Dollars
		2011				2010
Assets
Cash and cash equivalents		$	—				—
Accounts and notes receivable			8,353				8,362
Accounts and notes receivable—related parties			1,671				1,849
Inventories			3,403				4,062
Prepaid expenses and other current assets			443				352
Total current assets of discontinued operations			13,870				14,625
Investments and long-term receivables			10,304				9,917
Loans and advances—related parties			1				401
Net properties, plants and equipment			15,047				15,670
Goodwill			3,332				3,633
Intangibles			732				777
Other assets			121				112
Total assets of discontinued operations		$	43,407				45,135
Liabilities
Accounts payable		$	10,007				9,816
Accounts payable—related parties			785				937
Short-term debt			30				29
Accrued income and other taxes			967				995
Employee benefit obligations			76				98
Other accruals			411				452
Total current liabilities of discontinued operations			12,276				12,327
Long-term debt			361				388
Asset retirement obligations and accrued environmental costs			787				802
Deferred income taxes			5,533				4,698
Employee benefit obligations			1,057				702
Other liabilities and deferred credits			417				274
Total liabilities of discontinued operations		$	20,431				19,191

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

		Millions of Dollars
		2011				2010				2009
Sales and other operating revenues from discontinued operations		$	196,068				146,542				112,675
Income from discontinued operations before-tax		$	6,776				1,438				868
Income tax expense			1,729				470				173
Income from discontinued operations		$	5,047				968				695

Income from discontinued operations after-tax includes transaction, information systems and other costs incurred to effect the separation of $17 million year ended December 31, 2011.

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Prior to the separation, commodity sales to Phillips 66 were $15,822 million for the year ended December 31, 2011; $13,412 million for the year ended December 31, 2010; and $11,424 million for the year ended December 31, 2009. Prior to the separation, commodity purchases from Phillips 66 were $516 million for the year ended December 31, 2011; $479 million for the year ended December 31, 2010; and $606 million for the year ended December 31, 2009. Prior to the separation, commodity sales and related costs were eliminated in consolidation between ConocoPhillips and Phillips 66. Beginning May 1, 2012, these revenues and costs represent third-party transactions with Phillips 66. Although we expect certain transactions related to the sale and purchase of crude oil, natural gas and products to continue in the future with Phillips 66, the expected continuing cash flows are not considered significant; thus, the operations and cash flows of our former Downstream business are considered to be eliminated from our ongoing operations.

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Oil and Gas Operations (Unaudited)

The following Supplementary Information on Oil and Gas Operations has not been updated to reflect discontinued operations or the realignment of our reporting segments.

In accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification Topic 932, “Extractive Activities—Oil and Gas,” and regulations of the U.S. Securities and Exchange Commission (SEC), we are making certain supplemental disclosures about our oil and gas exploration and production operations.

These disclosures include information about our consolidated oil and gas activities and our proportionate share of our equity affiliates’ oil and gas activities, covering both those in our Exploration and Production (E&P) operations, as well as in our LUKOIL Investment segment. As a result, for periods prior to 2011, amounts reported as equity affiliates in Oil and Gas Operations may differ from those shown in the individual segment disclosures reported elsewhere in this report.

Our proved reserves include estimated quantities related to production sharing contracts (PSCs), which are reported under the “economic interest” method and are subject to fluctuations in commodity prices; recoverable operating expenses; and capital costs. If costs remain stable, reserve quantities attributable to recovery of costs will change inversely to changes in commodity prices. For example, if prices increase, then our applicable reserve quantities would decline. At December 31, 2011, approximately 10 percent of our total proved reserves were under PSCs, primarily in our Asia Pacific/Middle East geographic reporting area.

Our disclosures by geographic area include the United States, Canada, Europe (primarily Norway and the United Kingdom), Russia, Asia Pacific/Middle East, Africa and Other Areas. Other Areas primarily consists of the Caspian Region.

In the following disclosures, the synthetic oil classification included our past Syncrude mining operations, and the bitumen classification includes our Surmont operations and the FCCL Partnership. In June 2010, we sold our interest in the Syncrude Canada Ltd. joint venture; accordingly, as of December 31, 2010, we no longer held synthetic oil reserves.

On July 28, 2010, we announced our intention to sell our entire interest in LUKOIL over a period of time through the end of 2011. As a result of this sell down of our interest, at the end of the third quarter of 2010 we ceased using equity-method accounting for our investment in LUKOIL. Accordingly, the supplemental oil and gas disclosures reflect activity for LUKOIL through June 30, 2010, which, on a lag basis, results in three quarters of activity being included in the year 2010 (the fourth quarter of 2009 and the first two quarters of 2010). Since the proved reserves tables are not on a lag basis, they reflect activity for the first three quarters of 2010, at which point LUKOIL’s reserves were removed from our reserve quantities.

Reserves Governance

The recording and reporting of proved reserves are governed by criteria established by regulations of the SEC and FASB. Proved reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved reserves are further classified as either developed or undeveloped. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

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We have a companywide, comprehensive, SEC-compliant internal policy that governs the determination and reporting of proved reserves. This policy is applied by the geologists and reservoir engineers in our E&P business units around the world. As part of our internal control process, each business unit’s reserves are reviewed annually by an internal team which is headed by the company’s Manager of Reserves Compliance and Reporting. This team, composed of internal reservoir engineers, geologists and finance personnel, reviews the business units’ reserves for adherence to SEC guidelines and company policy through on-site visits and review of documentation. In addition to providing independent reviews, this internal team also ensures reserves are calculated using consistent and appropriate standards and procedures. This team is independent of business unit line management and is responsible for reporting its findings to senior management and our internal audit group. The team is responsible for communicating our reserves policy and procedures and is available for internal peer reviews and consultation on major projects or technical issues throughout the year. All of our proved reserves held by consolidated companies and our share of equity affiliates have been estimated by ConocoPhillips.

The technical person primarily responsible for overseeing the preparation of the company’s reserve estimates is the Manager of Reserves Compliance and Reporting. This individual is a petroleum engineer with a bachelor’s degree in petroleum engineering. He is an active member of the Society of Petroleum Engineers (SPE) with over 30 years of oil and gas industry experience, including drilling and production engineering assignments in several field locations. He is currently serving a three-year term on the Oil & Gas Reserves Committee of the SPE and has held positions of increasing responsibility in reservoir engineering, reserves reporting and compliance, and business management.

During 2011, our processes and controls used to assess over 90 percent of proved reserves as of December 31, 2011, were reviewed by DeGolyer and MacNaughton (D&M), a third-party petroleum engineering consulting firm. The purpose of their review was to assess whether the adequacy and effectiveness of our internal processes and controls used to determine estimates of proved reserves are in accordance with SEC regulations. In such review, ConocoPhillips’ technical staff presented D&M with an overview of the reserves data, as well as the methods and assumptions used in estimating reserves. The data presented included pertinent seismic information, geologic maps, well logs, production tests, material balance calculations, reservoir simulation models, well performance data, operating procedures and relevant economic criteria. Management’s intent in retaining D&M to review its processes and controls was to provide objective third-party input on these processes and controls. D&M’s opinion was that the general processes and controls employed by ConocoPhillips in estimating its December 31, 2011, proved reserves for the properties reviewed are in accordance with the SEC reserves definitions. D&M’s report was included as Exhibit 99 of our Annual Report on Form 10-K for the year ended December 31, 2011.

Engineering estimates of the quantities of proved reserves are inherently imprecise. See the “Critical Accounting Estimates” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional discussion of the sensitivities surrounding these estimates.

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Proved Reserves

Years Ended December 31		Crude Oil and Natural Gas Liquids
		Millions of Barrels
		Alaska				Lower 48				Total U.S.				Canada				Europe				Russia				Asia Pacific/ Middle East				Africa				Other Areas				Total
Developed and Undeveloped
Consolidated operations
End of 2008			1,202				726				1,928				93				552				—				364				282				121				3,340
Revisions			84				1				85				—				29				—				(12	)			10				(8	)			104
Improved recovery			13				2				15				—				—				—				2				—				—				17
Purchases			—				—				—				—				—				—				—				—				—				—
Extensions and discoveries			14				17				31				3				7				—				26				3				—				70
Production			(93	)			(60	)			(153	)			(15	)			(87	)			—				(48	)			(28	)			—				(331	)
Sales			—				(1	)			(1	)			—				—				—				—				—				(5	)			(6	)
End of 2009			1,220				685				1,905				81				501				—				332				267				108				3,194
Revisions			81				8				89				15				28				—				7				21				—				160
Improved recovery			51				2				53				—				—				—				5				—				—				58
Purchases			—				1				1				—				—				—				—				—				—				1
Extensions and discoveries			17				30				47				4				18				—				7				10				—				86
Production			(84	)			(55	)			(139	)			(14	)			(78	)			—				(51	)			(28	)			—				(310	)
Sales			—				(22	)			(22	)			(6	)			—				—				—				—				—				(28	)
End of 2010			1,285				649				1,934				80				469				—				300				270				108				3,161
Revisions			70				45				115				10				(3	)			—				(7	)			5				—				120
Improved recovery			14				3				17				1				51				—				13				—				—				82
Purchases			—				1				1				—				—				—				—				—				—				1
Extensions and discoveries			21				68				89				4				102				—				8				—				—				203
Production			(79	)			(60	)			(139	)			(13	)			(64	)			—				(41	)			(14	)			—				(271	)
Sales			—				(8	)			(8	)			(1	)			—				—				—				—				—				(9	)
End of 2011			1,311				698				2,009				81				555				—				273				261				108				3,287
Equity affiliates
End of 2008			—				—				—				—				—				1,568				109				—				—				1,677
Revisions			—				—				—				—				—				33				(3	)			—				—				30
Improved recovery			—				—				—				—				—				54				—				—				—				54
Purchases			—				—				—				—				—				21				—				—				—				21
Extensions and discoveries			—				—				—				—				—				94				—				—				—				94
Production			—				—				—				—				—				(166	)			—				—				—				(166	)
Sales			—				—				—				—				—				—				—				—				—				—
End of 2009			—				—				—				—				—				1,604				106				—				—				1,710
Revisions			—				—				—				—				—				6				51				—				—				57
Improved recovery			—				—				—				—				—				—				—				—				—				—
Purchases			—				—				—				—				—				—				—				—				—				—
Extensions and discoveries			—				—				—				—				—				—				—				—				—				—
Production			—				—				—				—				—				(114	)			(1	)			—				—				(115	)
Sales			—				—				—				—				—				(1,421	)			—				—				—				(1,421	)
End of 2010			—				—				—				—				—				75				156				—				—				231
Revisions			—				—				—				—				—				(37	)			—				—				—				(37	)
Improved recovery			—				—				—				—				—				—				—				—				—				—
Purchases			—				—				—				—				—				—				—				—				—				—
Extensions and discoveries			—				—				—				—				—				—				—				—				—				—
Production			—				—				—				—				—				(11	)			(8	)			—				—				(19	)
Sales			—				—				—				—				—				—				—				—				—				—
End of 2011			—				—				—				—				—				27				148				—				—				175
Total company
End of 2008			1,202				726				1,928				93				552				1,568				473				282				121				5,017
End of 2009			1,220				685				1,905				81				501				1,604				438				267				108				4,904
End of 2010			1,285				649				1,934				80				469				75				456				270				108				3,392
End of 2011			1,311				698				2,009				81				555				27				421				261				108				3,462

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Years Ended December 31		Crude Oil and Natural Gas Liquids
		Millions of Barrels
		Alaska				Lower 48				Total U.S.				Canada				Europe				Russia				Asia Pacific/ Middle East				Africa				Other Areas				Total
Developed
Consolidated operations
End of 2008			1,104				572				1,676				85				342				—				217				264				6				2,590
End of 2009			1,130				558				1,688				77				312				—				221				246				—				2,544
End of 2010			1,155				534				1,689				75				290				—				218				251				—				2,523
End of 2011			1,182				564				1,746				74				317				—				187				248				—				2,572
Equity affiliates
End of 2008			—				—				—				—				—				1,228				—				—				—				1,228
End of 2009			—				—				—				—				—				1,213				—				—				—				1,213
End of 2010			—				—				—				—				—				73				156				—				—				229
End of 2011			—				—				—				—				—				27				148				—				—				175
Undeveloped
Consolidated operations
End of 2008			98				154				252				8				210				—				147				18				115				750
End of 2009			90				127				217				4				189				—				111				21				108				650
End of 2010			130				115				245				5				179				—				82				19				108				638
End of 2011			129				134				263				7				238				—				86				13				108				715
Equity affiliates
End of 2008			—				—				—				—				—				340				109				—				—				449
End of 2009			—				—				—				—				—				391				106				—				—				497
End of 2010			—				—				—				—				—				2				—				—				—				2
End of 2011			—				—				—				—				—				—				—				—				—				—

Notable changes in proved crude oil and natural gas liquids reserves in the three years ended December 31, 2011, included:

• Revisions: In 2009, revisions in Alaska were primarily due to higher prices in 2009, versus 2008.

• Extensions and discoveries: In 2011, extensions and discoveries in Europe were primarily due to the sanctioning of the Ekofisk South and Clair Ridge development projects in the North Sea.

• Sales: In 2010, for our equity affiliates in Russia, sales were primarily due to the disposition of our interest in LUKOIL.

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Years Ended December 31		Natural Gas
		Billions of Cubic Feet
		Alaska				Lower 48				Total U.S.				Canada				Europe				Russia				Asia Pacific/ Middle East				Africa				Other Areas				Total
Developed and Undeveloped
Consolidated operations
End of 2008			2,488				8,432				10,920				2,614				2,303				—				3,237				998				88				20,160
Revisions			400				126				526				(23	)			19				—				(94	)			(2	)			(32	)			394
Improved recovery			3				—				3				—				—				—				—				—				—				3
Purchases			—				—				—				2				—				—				—				—				—				2
Extensions and discoveries			—				146				146				95				24				—				54				—				—				319
Production			(111	)			(739	)			(850	)			(388	)			(337	)			—				(285	)			(46	)			—				(1,906	)
Sales			—				(3	)			(3	)			(4	)			—				—				—				—				—				(7	)
End of 2009			2,780				7,962				10,742				2,296				2,009				—				2,912				950				56				18,965
Revisions			155				365				520				309				86				—				(39	)			36				—				912
Improved recovery			24				1				25				—				—				—				—				—				—				25
Purchases			—				9				9				—				—				—				—				—				—				9
Extensions and discoveries			4				122				126				84				89				—				24				—				—				323
Production			(101	)			(663	)			(764	)			(358	)			(323	)			—				(289	)			(60	)			—				(1,794	)
Sales			—				(179	)			(179	)			(26	)			—				—				—				—				—				(205	)
End of 2010			2,862				7,617				10,479				2,305				1,861				—				2,608				926				56				18,235
Revisions			186				15				201				134				70				—				(8	)			9				—				406
Improved recovery			1				5				6				—				53				—				—				—				—				59
Purchases			—				7				7				1				—				—				—				—				—				8
Extensions and discoveries			3				171				174				78				158				—				192				—				—				602
Production			(92	)			(616	)			(708	)			(338	)			(246	)			—				(277	)			(63	)			—				(1,632	)
Sales			—				(11	)			(11	)			(67	)			—				—				—				—				—				(78	)
End of 2011			2,960				7,188				10,148				2,113				1,896				—				2,515				872				56				17,600
Equity affiliates
End of 2008			—				—				—				—				—				2,269				2,519				—				—				4,788
Revisions			—				—				—				—				—				436				(203	)			—				—				233
Improved recovery			—				—				—				—				—				—				—				—				—				—
Purchases			—				—				—				—				—				25				—				—				—				25
Extensions and discoveries			—				—				—				—				—				89				294				—				—				383
Production			—				—				—				—				—				(114	)			(33	)			—				—				(147	)
Sales			—				—				—				—				—				—				—				—				—				—
End of 2009			—				—				—				—				—				2,705				2,577				—				—				5,282
Revisions			—				—				—				—				—				19				683				—				—				702
Improved recovery			—				—				—				—				—				—				—				—				—				—
Purchases			—				—				—				—				—				—				—				—				—				—
Extensions and discoveries			—				—				—				—				—				—				269				—				—				269
Production			—				—				—				—				—				(91	)			(65	)			—				—				(156	)
Sales			—				—				—				—				—				(2,616	)			—				—				—				(2,616	)
End of 2010			—				—				—				—				—				17				3,464				—				—				3,481
Revisions			—				—				—				—				—				(11	)			(76	)			—				—				(87	)
Improved recovery			—				—				—				—				—				—				—				—				—				—
Purchases			—				—				—				—				—				—				—				—				—				—
Extensions and discoveries			—				—				—				—				—				—				259				—				—				259
Production			—				—				—				—				—				(2	)			(184	)			—				—				(186	)
Sales			—				—				—				—				—				—				(151	)			—				—				(151	)
End of 2011			—				—				—				—				—				4				3,312				—				—				3,316
Total company
End of 2008			2,488				8,432				10,920				2,614				2,303				2,269				5,756				998				88				24,948
End of 2009			2,780				7,962				10,742				2,296				2,009				2,705				5,489				950				56				24,247
End of 2010			2,862				7,617				10,479				2,305				1,861				17				6,072				926				56				21,716
End of 2011			2,960				7,188				10,148				2,113				1,896				4				5,827				872				56				20,916

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Years Ended December 31		Natural Gas
		Billions of Cubic Feet
		Alaska				Lower 48				Total U.S.				Canada				Europe				Russia				Asia Pacific/ Middle East				Africa				Other Areas				Total
Developed
Consolidated operations
End of 2008			2,413				6,875				9,288				2,272				2,036				—				2,877				936				—				17,409
End of 2009			2,744				6,633				9,377				2,173				1,772				—				2,537				889				—				16,748
End of 2010			2,785				6,399				9,184				2,134				1,529				—				2,136				865				—				15,848
End of 2011			2,907				6,194				9,101				1,932				1,439				—				1,932				738				—				15,142
Equity affiliates
End of 2008			—				—				—				—				—				1,458				361				—				—				1,819
End of 2009			—				—				—				—				—				1,506				307				—				—				1,813
End of 2010			—				—				—				—				—				17				3,114				—				—				3,131
End of 2011			—				—				—				—				—				4				2,943				—				—				2,947
Undeveloped
Consolidated operations
End of 2008			75				1,557				1,632				342				267				—				360				62				88				2,751
End of 2009			36				1,329				1,365				123				237				—				375				61				56				2,217
End of 2010			77				1,218				1,295				171				332				—				472				61				56				2,387
End of 2011			53				994				1,047				181				457				—				583				134				56				2,458
Equity affiliates
End of 2008			—				—				—				—				—				811				2,158				—				—				2,969
End of 2009			—				—				—				—				—				1,199				2,270				—				—				3,469
End of 2010			—				—				—				—				—				—				350				—				—				350
End of 2011			—				—				—				—				—				—				369				—				—				369

Natural gas production in the reserves table may differ from gas production (delivered for sale) in our statistics disclosure, primarily because the quantities above include gas consumed at the lease.

Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.

Notable changes in proved natural gas reserves in the three years ended December 31, 2011, included:

• Revisions: In 2010, revisions in Alaska, Lower 48 and Canada were primarily due to higher prices in 2010, versus 2009, as well as improved well performance. In 2009, revisions in Alaska were primarily due to higher prices in 2009, versus 2008. In 2009, for our equity affiliate operations in Asia Pacific/Middle East, revisions resulted from modified coalbed methane drilling plans in Australia. In Russia, revisions were attributable to positive performance in various LUKOIL fields.

• Extensions and discoveries: In 2011, for our equity affiliate operations in Asia Pacific/Middle East, extensions and discoveries were primarily due to ongoing development drilling onshore Australia associated with the APLNG Project. In 2010, extensions and discoveries in Lower 48 and Canada were primarily due to continued drilling success in various fields. In 2009, for our equity affiliate operations in Asia Pacific/Middle East, extensions and discoveries primarily resulted from drilling success in Australia related to a coalbed methane project.

• Sales: In 2010, for our equity affiliates in Russia, sales were primarily due to the disposition of our interest in LUKOIL.

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Years Ended December 31		Other Products
		Millions of Barrels
		Synthetic Oil				Bitumen
		Canada				Canada
Developed and Undeveloped
Consolidated operations
End of 2008			—				100
Revisions			256				152
Improved recovery			—				—
Purchases			—				—
Extensions and discoveries			—				167
Production			(8	)			(2	)
Sales			—				—
End of 2009			248				417
Revisions			—				42
Improved recovery			—				—
Purchases			—				—
Extensions and discoveries			—				—
Production			(4	)			(4	)
Sales			(244	)			—
End of 2010			—				455
Revisions			—				(1	)
Improved recovery			—				—
Purchases			—				—
Extensions and discoveries			—				79
Production			—				(3	)
Sales			—				—
End of 2011			—				530
Equity affiliates
End of 2008			—				700
Revisions			—				(87	)
Improved recovery			—				—
Purchases			—				—
Extensions and discoveries			—				118
Production			—				(15	)
Sales			—				—
End of 2009			—				716
Revisions			—				13
Improved recovery			—				—
Purchases			—				—
Extensions and discoveries			—				133
Production			—				(18	)
Sales			—				—
End of 2010			—				844
Revisions			—				(101	)
Improved recovery			—				—
Purchases			—				—
Extensions and discoveries			—				187
Production			—				(21	)
Sales			—				—
End of 2011			—				909
Total company
End of 2008			—				800
End of 2009			248				1,133
End of 2010			—				1,299
End of 2011			—				1,439

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Years Ended December 31		Other Products
		Millions of Barrels
		Synthetic Oil				Bitumen
		Canada				Canada
Developed
Consolidated operations
End of 2008			—				24
End of 2009			248				24
End of 2010			—				34
End of 2011			—				29
Equity affiliates
End of 2008			—				105
End of 2009			—				116
End of 2010			—				142
End of 2011			—				131
Undeveloped
Consolidated operations
End of 2008			—				76
End of 2009			—				393
End of 2010			—				421
End of 2011			—				501
Equity affiliates
End of 2008			—				595
End of 2009			—				600
End of 2010			—				702
End of 2011			—				778

Notable changes in proved synthetic oil and bitumen reserves in the three years ended December 31, 2011, included:

• Revisions: In 2011, for our bitumen equity operations, revisions were primarily due to new subsurface interpretations, as well as the effects of higher prices on sliding scale royalty provisions. In 2009, for synthetic oil consolidated operations, revisions reflect our Syncrude Canada Ltd. operations. For our bitumen consolidated operations, revisions primarily were related to the sanction of the Surmont Phase II Project. For our bitumen equity affiliate operations, revisions were mainly the result of the effect of higher prices on sliding scale royalty provisions.

• Extensions and discoveries: In 2011, for our consolidated operations, extensions and discoveries were related to continued development of Surmont. For our equity affiliate operations, extensions and discoveries were related to the sanctioning of new projects in FCCL. In 2009, for our bitumen consolidated operations, extensions and discoveries were related to the sanction of the Surmont Phase II Project. In 2010 and 2009, for our equity affiliate operations, extensions and discoveries mainly reflect the continued development of FCCL.

• Sales: In 2010, for synthetic oil consolidated operations, sales reflect the disposition of our interest in Syncrude.

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Years Ended December 31		Total Proved Reserves
		Millions of Barrels of Oil Equivalent
		Alaska				Lower 48				Total U.S.				Canada				Europe				Russia				Asia Pacific/ Middle East				Africa				Other Areas				Total
Developed and Undeveloped
Consolidated operations
End of 2008			1,617				2,131				3,748				629				936				—				904				448				135				6,800
Revisions			151				22				173				404				32				—				(28	)			10				(13	)			578
Improved recovery			14				2				16				—				—				—				2				—				—				18
Purchases			—				—				—				—				—				—				—				—				—				—
Extensions and discoveries			14				41				55				186				11				—				35				3				—				290
Production			(112	)			(183	)			(295	)			(89	)			(143	)			—				(96	)			(36	)			—				(659	)
Sales			—				(1	)			(1	)			(1	)			—				—				—				—				(5	)			(7	)
End of 2009			1,684				2,012				3,696				1,129				836				—				817				425				117				7,020
Revisions			107				68				175				109				42				—				1				27				—				354
Improved recovery			55				2				57				—				—				—				5				—				—				62
Purchases			—				2				2				—				—				—				—				—				—				2
Extensions and discoveries			17				51				68				18				33				—				11				10				—				140
Production			(101	)			(165	)			(266	)			(82	)			(132	)			—				(99	)			(38	)			—				(617	)
Sales			—				(52	)			(52	)			(254	)			—				—				—				—				—				(306	)
End of 2010			1,762				1,918				3,680				920				779				—				735				424				117				6,655
Revisions			101				48				149				31				8				—				(9	)			7				—				186
Improved recovery			14				4				18				1				60				—				13				—				—				92
Purchases			—				2				2				—				—				—				—				—				—				2
Extensions and discoveries			21				97				118				97				128				—				40				—				—				383
Production			(94	)			(163	)			(257	)			(73	)			(105	)			—				(86	)			(25	)			—				(546	)
Sales			—				(10	)			(10	)			(12	)			—				—				—				—				—				(22	)
End of 2011			1,804				1,896				3,700				964				870				—				693				406				117				6,750
Equity affiliates
End of 2008			—				—				—				700				—				1,946				529				—				—				3,175
Revisions			—				—				—				(87	)			—				106				(37	)			—				—				(18	)
Improved recovery			—				—				—				—				—				54				—				—				—				54
Purchases			—				—				—				—				—				25				—				—				—				25
Extensions and discoveries			—				—				—				118				—				109				49				—				—				276
Production			—				—				—				(15	)			—				(185	)			(6	)			—				—				(206	)
Sales			—				—				—				—				—				—				—				—				—				—
End of 2009			—				—				—				716				—				2,055				535				—				—				3,306
Revisions			—				—				—				13				—				9				165				—				—				187
Improved recovery			—				—				—				—				—				—				—				—				—				—
Purchases			—				—				—				—				—				—				—				—				—				—
Extensions and discoveries			—				—				—				133				—				—				45				—				—				178
Production			—				—				—				(18	)			—				(129	)			(12	)			—				—				(159	)
Sales			—				—				—				—				—				(1,857	)*			—				—				—				(1,857	)
End of 2010			—				—				—				844				—				78				733				—				—				1,655
Revisions			—				—				—				(101	)			—				(39	)			(12	)			—				—				(152	)
Improved recovery			—				—				—				—				—				—				—				—				—				—
Purchases			—				—				—				—				—				—				—				—				—				—
Extensions and discoveries			—				—				—				187				—				—				43				—				—				230
Production			—				—				—				(21	)			—				(11	)			(39	)			—				—				(71	)
Sales			—				—				—				—				—				—				(25	)			—				—				(25	)
End of 2011			—				—				—				909				—				28				700				—				—				1,637
Total company
End of 2008			1,617				2,131				3,748				1,329				936				1,946				1,433				448				135				9,975
End of 2009			1,684				2,012				3,696				1,845				836				2,055				1,352				425				117				10,326
End of 2010			1,762				1,918				3,680				1,764				779				78				1,468				424				117				8,310
End of 2011			1,804				1,896				3,700				1,873				870				28				1,393				406				117				8,387

* Includes 594 million barrels of oil equivalent due to the cessation of equity accounting.

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Years Ended December 31		Total Proved Reserves
		Millions of Barrels of Oil Equivalent
		Alaska				Lower 48				Total U.S.				Canada				Europe				Russia				Asia Pacific/ Middle East				Africa				Other Areas				Total
Developed
Consolidated operations
End of 2008			1,506				1,718				3,224				488				681				—				697				420				6				5,516
End of 2009			1,588				1,663				3,251				711				608				—				644				394				—				5,608
End of 2010			1,619				1,601				3,220				465				545				—				574				396				—				5,200
End of 2011			1,666				1,597				3,263				425				556				—				510				371				—				5,125
Equity affiliates
End of 2008			—				—				—				105				—				1,471				60				—				—				1,636
End of 2009			—				—				—				116				—				1,464				51				—				—				1,631
End of 2010			—				—				—				142				—				76				675				—				—				893
End of 2011			—				—				—				131				—				28				638				—				—				797
Undeveloped
Consolidated operations
End of 2008			111				413				524				141				255				—				207				28				129				1,284
End of 2009			96				349				445				418				228				—				173				31				117				1,412
End of 2010			143				317				460				455				234				—				161				28				117				1,455
End of 2011			138				299				437				539				314				—				183				35				117				1,625
Equity affiliates
End of 2008			—				—				—				595				—				475				469				—				—				1,539
End of 2009			—				—				—				600				—				591				484				—				—				1,675
End of 2010			—				—				—				702				—				2				58				—				—				762
End of 2011			—				—				—				778				—				—				62				—				—				840

Natural gas reserves are converted to barrels of oil equivalent (BOE) based on a 6:1 ratio: six thousand cubic feet of natural gas converts to one BOE.

Proved Undeveloped Reserves

We had 2,465 million BOE of proved undeveloped reserves at year-end 2011, compared with 2,217 million BOE at year-end 2010. We converted 210 million BOE of undeveloped reserves to developed during 2011 as we achieved startup of major development projects. In addition, we added 458 million BOE of undeveloped reserves in 2011 mainly through exploratory success and revisions. As a result, at December 31, 2011, our proved undeveloped reserves represented 29 percent of total proved reserves, compared with 27 percent at December 31, 2010. Costs incurred for the year ended December 31, 2011, relating to the development of proved undeveloped reserves were $4.5 billion.

Approximately 70 percent of our proved undeveloped reserves at year-end 2011 were associated with eight major development areas. Seven of the major development areas are currently producing and are expected to have proved undeveloped reserves convert to developed over time as development activities continue and/or production facilities are expanded or upgraded, and include:

• FCCL oil sands—Foster Creek and Christina Lake in Canada.

• The Surmont oil sands project in Canada.

• The Ekofisk Field in the North Sea.

• Certain fields in the Lower 48 and Alaska.

The remaining major project, the Kashagan Field in Kazakhstan, will have proved undeveloped reserves convert to developed as this project begins production.

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At the end of 2011, we did not have any material amounts of proved undeveloped reserves in individual fields or countries that have remained undeveloped for five years or more. However, our largest concentrations of proved undeveloped reserves at year-end 2011 are located in the Athabasca oil sands in Canada, consisting of the FCCL and Surmont steam-assisted gravity drainage (SAGD) projects. The majority of our proved undeveloped reserves in this area were first recorded in 2006 and 2007, and we expect a material portion of these reserves will remain undeveloped for more than five years.

Our SAGD projects are large, multi-year projects with steady, long-term production at consistent levels. The associated reserves are expected to be developed over many years as additional well pairs are drilled across the extensive resource base to maintain throughput at the central processing facilities.

Results of Operations

The company’s results of operations from oil and gas activities for the years 2011, 2010 and 2009 are shown in the following tables. Additional information about selected line items within the results of operations tables is shown below:

• Other revenues include gains and losses from asset sales, certain amounts resulting from the purchase and sale of hydrocarbons, and other miscellaneous income.

• Taxes other than income taxes include production, property and other non-income taxes.

• Depreciation of support equipment is reclassified as applicable.

• Transportation costs include costs to transport our produced hydrocarbons to their points of sale, as well as processing fees paid to process natural gas to natural gas liquids. The profit element of transportation operations in which we have an ownership interest are deemed to be outside oil and gas producing activities. The net income of the transportation operations is included in other earnings.

• Other related expenses include foreign currency transaction gains and losses, and other miscellaneous expenses.

• Other earnings include non-oil and gas activities within E&P, such as pipeline and marine operations, liquefied natural gas operations, and crude oil and gas marketing activities.

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Results of Operations

		Millions of Dollars
Year Ended December 31, 2011		Alaska				Lower 48				Total U.S.				Canada				Europe				Russia				Asia Pacific/ Middle East				Africa				Other Areas				Total
Consolidated operations
Sales		$	4,319				3,513				7,832				2,123				5,233				—				5,901				1,486				—				22,575
Transfers			3,869				3,283				7,152				176				3,854				—				932				54				—				12,168
Other revenues			(46	)			303				257				138				(16	)			—				(264	)			30				16				161
Total revenues			8,142				7,099				15,241				2,437				9,071				—				6,569				1,570				16				34,904
Production costs excluding taxes			1,023				1,286				2,309				781				956				—				742				266				—				5,054
Taxes other than income taxes			2,721				520				3,241				65				4				1				543				23				—				3,877
Exploration expenses			36				368				404				177				201				—				192				51				54				1,079
Depreciation, depletion and amortization			468				2,113				2,581				1,504				1,407				1				940				188				—				6,621
Impairments			2				71				73				253				(38	)			—				—				—				—				288
Transportation costs			609				432				1,041				128				273				—				120				27				—				1,589
Other related expenses			49				60				109				55				63				20				87				(7	)			56				383
Accretion			59				58				117				50				203				—				23				2				1				396
			3,175				2,191				5,366				(576	)			6,002				(22	)			3,922				1,020				(95	)			15,617
Provision for income taxes			1,167				755				1,922				(194	)			4,355				3				1,844				722				(23	)			8,629
Results of operations for producing activities			2,008				1,436				3,444				(382	)			1,647				(25	)			2,078				298				(72	)			6,988
Other earnings			(25	)			(165	)			(190	)			(32	)			248				11				191				11				7				246
Net income (loss) attributable to ConocoPhillips		$	1,983				1,271				3,254				(414	)			1,895				(14	)			2,269				309				(65	)			7,234
Equity affiliates
Sales		$	—				—				—				1,295				—				1,107				956				—				—				3,358
Transfers			—				—				—				—				—				—				365				—				—				365
Other revenues			—				—				—				6				—				—				6				—				—				12
Total revenues			—				—				—				1,301				—				1,107				1,327				—				—				3,735
Production costs excluding taxes			—				—				—				367				—				72				108				—				—				547
Taxes other than income taxes			—				—				—				5				—				750				187				—				—				942
Exploration expenses			—				—				—				36				—				1				2				—				—				39
Depreciation, depletion and amortization			—				—				—				209				—				52				128				—				—				389
Impairments			—				—				—				—				—				395				—				—				—				395
Transportation costs			—				—				—				—				—				139				133				—				—				272
Other related expenses			—				—				—				3				—				—				41				—				—				44
Accretion			—				—				—				4				—				1				3				—				—				8
			—				—				—				677				—				(303	)			725				—				—				1,099
Provision for income taxes			—				—				—				159				—				18				32				—				—				209
Results of operations for producing activities			—				—				—				518				—				(321	)			693				—				—				890
Other earnings			—				—				—				—				—				238				119				—				—				357
Net income (loss) attributable to ConocoPhillips		$	—				—				—				518				—				(83	)			812				—				—				1,247

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		Millions of Dollars
Year Ended December 31, 2010		Alaska				Lower 48				Total U.S.				Canada				Europe				Russia				Asia Pacific/ Middle East				Africa				Other Areas				Total
Consolidated operations
Sales		$	3,645				3,600				7,245				2,379				5,967				—				4,958				1,743				—				22,292
Transfers			2,693				2,389				5,082				246				2,278				—				770				450				—				8,826
Other revenues			—				559				559				3,216				142				—				55				172				18				4,162
Total revenues			6,338				6,548				12,886				5,841				8,387				—				5,783				2,365				18				35,280
Production costs excluding taxes			849				1,230				2,079				873				1,004				—				538				296				—				4,790
Taxes other than income taxes			1,570				498				2,068				74				6				1				355				18				1				2,523
Exploration expenses			37				292				329				295				146				2				260				29				101				1,162
Depreciation, depletion and amortization			529				2,231				2,760				1,666				1,972				2				1,206				202				—				7,808
Impairments			4				19				23				13				43				—				—				—				—				79
Transportation costs			528				424				952				134				281				—				119				23				—				1,509
Other related expenses			(38	)			112				74				41				42				17				(48	)			(10	)			62				178
Accretion			58				55				113				50				192				—				24				—				4				383
			2,801				1,687				4,488				2,695				4,701				(22	)			3,329				1,807				(150	)			16,848
Provision for income taxes			1,014				555				1,569				108				3,066				(23	)			1,361				1,458				(28	)			7,511
Results of operations for producing activities			1,787				1,132				2,919				2,587				1,635				1				1,968				349				(122	)			9,337
Other earnings			(52	)			(99	)			(151	)			(72	)			76				16				139				29				8				45
Net income (loss) attributable to ConocoPhillips		$	1,735				1,033				2,768				2,515				1,711				17				2,107				378				(114	)			9,382
Equity affiliates
Sales		$	—				—				—				955				—				5,189				249				—				—				6,393
Transfers			—				—				—				—				—				1,876				—				—				—				1,876
Other revenues			—				—				—				7				—				1,219				10				—				—				1,236
Total revenues			—				—				—				962				—				8,284				259				—				—				9,505
Production costs excluding taxes			—				—				—				265				—				544				59				—				—				868
Taxes other than income taxes			—				—				—				4				—				3,463				42				—				—				3,509
Exploration expenses			—				—				—				—				—				61				(2	)			—				—				59
Depreciation, depletion and amortization			—				—				—				190				—				568				55				—				—				813
Impairments			—				—				—				—				—				645				—				—				—				645
Transportation costs			—				—				—				—				—				784				25				—				—				809
Other related expenses			—				—				—				(3	)			—				—				44				—				—				41
Accretion			—				—				—				2				—				7				2				—				—				11
			—				—				—				504				—				2,212				34				—				—				2,750
Provision for income taxes			—				—				—				128				—				647				(25	)			—				—				750
Results of operations for producing activities			—				—				—				376				—				1,565				59				—				—				2,000
Other earnings			—				—				—				—				—				405				(86	)			—				—				319
Net income (loss) attributable to ConocoPhillips		$	—				—				—				376				—				1,970				(27	)			—				—				2,319

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		Millions of Dollars
Year Ended December 31, 2009		Alaska				Lower 48				Total U.S.				Canada				Europe				Russia				Asia Pacific/ Middle East				Africa				Other Areas				Total
Consolidated operations
Sales		$	3,353				3,144				6,497				2,179				4,995				—				3,830				1,562				11				19,074
Transfers			2,261				1,937				4,198				345				2,305				—				500				257				—				7,605
Other revenues			30				54				84				168				(66	)			—				10				136				54				386
Total revenues			5,644				5,135				10,779				2,692				7,234				—				4,340				1,955				65				27,065
Production costs excluding taxes			864				1,266				2,130				1,011				1,048				—				445				270				8				4,912
Taxes other than income taxes			1,135				422				1,557				75				3				1				165				17				7				1,825
Exploration expenses			74				426				500				201				156				4				212				32				75				1,180
Depreciation, depletion and amortization			611				2,615				3,226				1,689				2,016				2				910				201				11				8,055
Impairments			—				5				5				296				104				—				12				—				51				468
Transportation costs			548				392				940				135				267				—				111				24				5				1,482
Other related expenses			251				60				311				(3	)			62				3				121				23				14				531
Accretion			49				55				104				41				191				—				19				3				3				361
			2,112				(106	)			2,006				(753	)			3,387				(10	)			2,345				1,385				(109	)			8,251
Provision for income taxes			716				(79	)			637				(309	)			2,280				(3	)			1,093				1,186				(21	)			4,863
Results of operations for producing activities			1,396				(27	)			1,369				(444	)			1,107				(7	)			1,252				199				(88	)			3,388
Other earnings			144				(10	)			134				(91	)			(59	)			(5	)			132				4				(1	)			114
Net income (loss) attributable to ConocoPhillips		$	1,540				(37	)			1,503				(535	)			1,048				(12	)			1,384				203				(89	)			3,502
Equity affiliates
Sales		$	—				—				—				713				—				3,783				74				—				—				4,570
Transfers			—				—				—				—				—				1,946				—				—				—				1,946
Other revenues			—				—				—				(2	)			—				—				1				—				—				(1	)
Total revenues			—				—				—				711				—				5,729				75				—				—				6,515
Production costs excluding taxes			—				—				—				213				—				501				26				—				—				740
Taxes other than income taxes			—				—				—				3				—				2,270				4				—				—				2,277
Exploration expenses			—				—				—				—				—				37				2				—				—				39
Depreciation, depletion and amortization			—				—				—				133				—				455				21				—				—				609
Impairments			—				—				—				—				—				83				—				—				—				83
Transportation costs			—				—				—				—				—				703				3				—				—				706
Other related expenses			—				—				—				17				—				3				1				—				—				21
Accretion			—				—				—				1				—				6				1				—				—				8
			—				—				—				344				—				1,671				17				—				—				2,032
Provision for income taxes			—				—				—				89				—				326				9				—				—				424
Results of operations for producing activities			—				—				—				255				—				1,345				8				—				—				1,608
Other earnings			—				—				—				—				—				(201	)			(86	)			—				—				(287	)
Net income (loss) attributable to ConocoPhillips		$	—				—				—				255				—				1,144				(78	)			—				—				1,321

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Statistics

Net Production		2011				2010				2009
		Thousands of Barrels Daily
Crude Oil and Natural Gas Liquids
Consolidated operations
Alaska			215				230				252
Lower 48			168				160				166
United States			383				390				418
Canada			38				38				40
Europe			175				211				241
Asia Pacific/Middle East			111				140				132
Africa			40				79				78
Other areas			—				—				4
Total consolidated operations			747				858				913
Equity affiliates
Russia			29				336				443
Asia Pacific/Middle East			23				3				—
Total equity affiliates			52				339				443
Total company			799				1,197				1,356
Synthetic Oil
Consolidated operations—Canada			—				12				23
Bitumen
Consolidated operations—Canada			10				10				7
Equity affiliates—Canada			57				49				43
Total company			67				59				50
		Millions of Cubic Feet Daily
Natural Gas*
Consolidated operations
Alaska			61				82				94
Lower 48			1,556				1,695				1,927
United States			1,617				1,777				2,021
Canada			928				984				1,062
Europe			626				815				876
Asia Pacific/Middle East			695				712				713
Africa			158				149				121
Total consolidated operations			4,024				4,437				4,793
Equity affiliates
Russia			—				254				295
Asia Pacific/Middle East			492				169				84
Total equity affiliates			492				423				379
Total company			4,516				4,860				5,172

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

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Average Sales Prices		2011				2010				2009
Crude Oil and Natural Gas Liquids Per Barrel
Consolidated operations
Alaska		$	105.95				78.61				59.23
Lower 48			74.09				57.69				44.12
United States			91.77				69.73				53.21
Canada			66.07				55.70				41.76
Europe			108.58				77.35				58.92
Asia Pacific/Middle East			105.94				75.50				57.59
Africa			102.75				76.80				60.83
Other areas			—				—				32.01
Total international			102.68				74.95				57.40
Total consolidated operations			97.12				72.63				55.47
Equity affiliates
Russia			101.62				56.65				43.19
Asia Pacific/Middle East			94.67				83.82				—
Total equity affiliates			98.60				56.87				43.19
Synthetic Oil Per Barrel
Consolidated operations—Canada		$	—				77.56				62.01
Bitumen Per Barrel
Consolidated operations—Canada		$	55.16				51.10				39.67
Equity affiliates—Canada			63.93				53.43				45.69
Natural Gas Per Thousand Cubic Feet
Consolidated operations
Alaska		$	4.56				4.62				5.33
Lower 48			3.99				4.25				3.42
United States			4.01				4.27				3.50
Canada			3.46				3.74				3.33
Europe			9.26				6.94				6.81
Asia Pacific/Middle East			9.82				7.39				6.00
Africa			2.24				1.81				1.56
Total international			6.73				5.60				5.06
Total consolidated operations			5.64				5.07				4.40
Equity affiliates
Russia			—				1.18				1.16
Asia Pacific/Middle East			2.89				2.79				2.35
Total equity affiliates			2.89				1.82				1.43

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		2011				2010				2009
Average Production Costs Per Barrel of Oil Equivalent*
Consolidated operations
Alaska		$	12.45				9.55				8.84
Lower 48			8.24				7.62				7.12
United States			9.70				8.30				7.73
Canada			10.56				10.68				11.21
Europe			9.38				7.93				7.42
Asia Pacific/Middle East			8.96				5.70				4.86
Africa			10.99				7.81				7.54
Other areas			—				—				5.48
Total international			9.70				7.96				7.72
Total consolidated operations			9.70				8.10				7.73
Equity affiliates
Canada			17.64				14.82				13.57
Russia			6.80				3.94				3.74
Asia Pacific/Middle East			2.82				5.19				5.09
Total equity affiliates			7.85				5.19				4.54
Average Production Costs Per Barrel—Bitumen
Consolidated operations—Canada		$	27.12				19.45				30.92
Equity affiliates—Canada			17.64				14.82				13.57
Taxes Other Than Income Taxes Per Barrel of Oil Equivalent*
Consolidated operations
Alaska		$	33.11				17.65				11.62
Lower 48			3.33				3.08				2.37
United States			13.61				8.26				5.65
Canada			.88				.91				.83
Europe			.04				.05				.02
Asia Pacific/Middle East			6.56				3.76				1.80
Africa			.95				.47				.47
Other areas			—				—				4.79
Total international			2.25				1.34				.74
Total consolidated operations			7.44				4.27				2.87
Equity affiliates
Canada			.24				.22				.19
Russia			70.85				25.08				17.46
Asia Pacific/Middle East			4.88				3.69				.78
Total equity affiliates			13.51				20.97				15.69
Depreciation, Depletion and Amortization Per Barrel of Oil Equivalent*
Consolidated operations
Alaska		$	5.69				5.95				6.25
Lower 48			13.55				13.81				14.71
United States			10.84				11.02				11.71
Canada			20.33				20.38				18.73
Europe			13.80				15.58				14.27
Asia Pacific/Middle East			11.35				12.77				9.94
Africa			7.76				5.33				5.61
Other areas			—				—				7.53
Total international			14.28				14.82				13.40
Total consolidated operations			12.71				13.21				12.67
Equity affiliates
Canada			10.05				10.62				8.47
Russia			4.91				4.11				3.24
Asia Pacific/Middle East			3.34				4.83				4.11
Total equity affiliates			5.58				4.86				3.67

* Includes bitumen.

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		Productive												Dry
Net Wells Completed(1)		2011				2010				2009				2011				2010				2009
Exploratory(2)
Consolidated operations
Alaska			—				—				—				—				—				2
Lower 48			98				23				33				5				1				14
United States			98				23				33				5				1				16
Canada			8				15				17				3				7				19
Europe			1				1				1				*				*				2
Asia Pacific/Middle East			1				3				3				1				1				3
Africa			*				1				*				*				*				*
Total consolidated operations			108				43				54				9				9				40
Equity affiliates
Russia			—				—				1				—				—				—
Asia Pacific/Middle East			5				2				—				—				—				—
Total equity affiliates(3)			5				2				1				—				—				—
Includes extension wells of:			98				23				40				3				1				29
		Productive												Dry
		2011				2010				2009				2011				2010				2009
Development
Consolidated operations
Alaska			41				47				47				—				*				—
Lower 48			350				269				592				4				2				4
United States			391				316				639				4				2				4
Canada			146				186				227				1				12				20
Europe			4				6				9				—				—				—
Asia Pacific/Middle East			30				59				47				—				*				—
Africa			5				9				3				—				—				—
Total consolidated operations			576				576				925				5				14				24
Equity affiliates
Canada			157				112				61				—				—				—
Russia			3				2				6				—				—				*
Asia Pacific/Middle East			9				25				28				1				—				—
Total equity affiliates(3)			169				139				95				1				—				*

(1) Excludes farmout arrangements.

(2) Includes extension wells, as well as other types of exploratory wells. Extension exploratory wells are either wells drilled in areas near or offsetting current production, or wells drilled in areas that have not yet achieved a well density and production history to achieve statistical certainty of results. These are classified as exploratory wells because proved reserves cannot be attributed to these locations.

(3) Excludes LUKOIL.

* Our total proportionate interest was less than one.

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										Productive(2)
		In Progress(1)								Oil								Gas
Wells at December 31, 2011		Gross				Net				Gross				Net				Gross				Net
Consolidated operations
Alaska			24				12				1,902				860				35				22
Lower 48			296				218				9,133				4,393				24,793				15,624
United States			320				230				11,035				5,253				24,828				15,646
Canada			306	(3)			211	(3)			1,630				971				12,895				7,593
Europe			25				5				609				109				271				109
Asia Pacific/Middle East			62				25				467				200				114				52
Africa			103				17				1,151				201				12				2
Other areas			46				4				—				—				—				—
Total consolidated operations			862				492				14,892				6,734				38,120				23,402
Equity affiliates
Canada			15				8				242				121				—				—
Russia			8				2				107				38				2				1
Asia Pacific/Middle East			1,015				220				—				—				521				140
Total equity affiliates			1,038				230				349				159				523				141

(1) Includes wells that have been temporarily suspended.

(2) Includes 5,883 gross and 3,734 net multiple completion wells.

(3) Includes 246 gross and 165 net stratigraphic test wells for oil sands projects.

		Thousands of Acres
		Developed								Undeveloped
Acreage at December 31, 2011		Gross				Net				Gross				Net
Consolidated operations
Alaska			650				329				1,440				1,197
Lower 48			7,012				5,244				10,286				8,790
United States			7,662				5,573				11,726				9,987
Canada			6,543				4,240				6,412				4,379
Europe			862				242				3,008				1,177
Asia Pacific/Middle East			4,123				1,777				19,585				11,989
Africa			528				132				14,730				2,575
Other areas			—				—				11,066				4,251
Total consolidated operations			19,718				11,964				66,527				34,358
Equity affiliates
Canada			33				14				588				243
Russia			291				90				1,173				476
Asia Pacific/Middle East			1,129				250				8,140				2,750
Total equity affiliates			1,453				354				9,901				3,469

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Costs Incurred

		Millions of Dollars
Years Ended December 31		Alaska				Lower 48				Total U.S.				Canada				Europe				Russia				Asia Pacific/ Middle East				Africa				Other Areas				Total
2011
Consolidated operations
Unproved property acquisition		$	1				577				578				145				—				—				—				—				—				723
Proved property acquisition			—				10				10				—				—				—				36				—				—				46
			1				587				588				145				—				—				36				—				—				769
Exploration			84				1,031				1,115				269				201				1				226				63				88				1,963
Development			499				2,633				3,132				1,347				2,123				—				949				263				726				8,540
		$	584				4,251				4,835				1,761				2,324				1				1,211				326				814				11,272
Equity affiliates
Unproved property acquisition		$	—				—				—				—				—				—				484				—				—				484
Proved property acquisition			—				—				—				—				—				—				—				—				—				—
			—				—				—				—				—				—				484				—				—				484
Exploration			—				—				—				64				—				1				100				—				—				165
Development			—				—				—				911				—				43				632				—				—				1,586
		$	—				—				—				975				—				44				1,216				—				—				2,235
2010
Consolidated operations
Unproved property acquisition		$	(26	)			286				260				113				9				—				—				—				—				382
Proved property acquisition			—				100				100				1				—				—				—				—				—				101
			(26	)			386				360				114				9				—				—				—				—				483
Exploration			119				487				606				269				144				3				356				45				143				1,566
Development			588				1,439				2,027				927				1,351				—				858				375				729				6,267
		$	681				2,312				2,993				1,310				1,504				3				1,214				420				872				8,316
Equity affiliates
Unproved property acquisition*		$	—				—				—				81				—				15				379				—				—				475
Proved property acquisition*			—				—				—				—				—				173				—				—				—				173
			—				—				—				81				—				188				379				—				—				648
Exploration			—				—				—				—				—				92				123				—				—				215
Development			—				—				—				621				—				751				403				—				—				1,775
		$	—				—				—				702				—				1,031				905				—				—				2,638

* Amounts in Asia Pacific/Middle East were reclassified between “Unproved property acquisition” and “Proved property acquisition.” Total acquisition costs were unchanged.

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		Millions of Dollars
Years Ended December 31		Alaska				Lower 48				Total U.S.				Canada				Europe				Russia				Asia Pacific/ Middle East				Africa				Other Areas				Total
2009
Consolidated operations
Unproved property acquisition		$	—				78				78				62				5				—				30				—				55				230
Proved property acquisition			1				6				7				7				—				—				—				—				—				14
			1				84				85				69				5				—				30				—				55				244
Exploration			137				476				613				251				184				4				342				33				90				1,517
Development			790				1,726				2,516				1,114				1,108				—				1,244				240				685				6,907
		$	928				2,286				3,214				1,434				1,297				4				1,616				273				830				8,668
Equity affiliates
Unproved property acquisition*		$	—				—				—				—				—				18				219				—				—				237
Proved property acquisition*			—				—				—				—				—				176				—				—				—				176
			—				—				—				—				—				194				219				—				—				413
Exploration			—				—				—				—				—				62				53				—				—				115
Development			—				—				—				446				—				820				376				—				—				1,642
		$	—				—				—				446				—				1,076				648				—				—				2,170

* Amounts in Asia Pacific/Middle East were reclassified between “Unproved property acquisition” and “Proved property acquisition.” Total acquisition costs were unchanged.

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Capitalized Costs

		Millions of Dollars
At December 31		Alaska				Lower 48				Total U.S.				Canada				Europe				Russia				Asia Pacific/ Middle East				Africa				Other Areas				Total
2011
Consolidated operations
Proved properties		$	12,770				34,939				47,709				19,578				22,948				8				12,284				3,867				4,650				111,044
Unproved properties			1,528				2,574				4,102				1,986				289				1				1,026				174				268				7,846
			14,298				37,513				51,811				21,564				23,237				9				13,310				4,041				4,918				118,890
Accumulated depreciation, depletion and amortization			6,237				15,464				21,701				10,599				14,451				7				5,626				1,559				12				53,955
		$	8,061				22,049				30,110				10,965				8,786				2				7,684				2,482				4,906				64,935
Equity affiliates
Proved properties		$	—				—				—				5,774				—				1,966				2,870				—				—				10,610
Unproved properties			—				—				—				1,657				—				146				7,182				—				—				8,985
			—				—				—				7,431				—				2,112				10,052				—				—				19,595
Accumulated depreciation, depletion and amortization			—				—				—				764				—				1,902				184				—				—				2,850
		$	—				—				—				6,667				—				210				9,868				—				—				16,745
2010
Consolidated operations
Proved properties		$	12,268				32,076				44,344				20,037				21,547				9				11,199				3,595				3,921				104,652
Unproved properties			1,471				1,700				3,171				1,930				328				1				1,113				163				249				6,955
			13,739				33,776				47,515				21,967				21,875				10				12,312				3,758				4,170				111,607
Accumulated depreciation, depletion and amortization			5,758				13,362				19,120				10,281				13,636				7				4,690				1,370				10				49,114
		$	7,981				20,414				28,395				11,686				8,239				3				7,622				2,388				4,160				62,493
Equity affiliates
Proved properties		$	—				—				—				4,812				—				1,923				2,320				—				—				9,055
Unproved properties			—				—				—				1,794				—				146				8,144				—				—				10,084
			—				—				—				6,606				—				2,069				10,464				—				—				19,139
Accumulated depreciation, depletion and amortization			—				—				—				512				—				1,584				84				—				—				2,180
		$	—				—				—				6,094				—				485				10,380				—				—				16,959

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Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities

In accordance with SEC and FASB requirements, amounts were computed using 12-month average prices and end-of-year costs (adjusted only for existing contractual changes), appropriate statutory tax rates and a prescribed 10 percent discount factor. Twelve-month average prices are calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. For all years, continuation of year-end economic conditions was assumed. The calculations were based on estimates of proved reserves, which are revised over time as new data becomes available. Probable or possible reserves, which may become proved in the future, were not considered. The calculations also require assumptions as to the timing of future production of proved reserves, and the timing and amount of future development, including dismantlement, and production costs.

While due care was taken in its preparation, we do not represent that this data is the fair value of our oil and gas properties, or a fair estimate of the present value of cash flows to be obtained from their development and production.

Discounted Future Net Cash Flows

		Millions of Dollars
		Alaska				Lower 48				Total U.S.				Canada				Europe				Russia				Asia Pacific/ Middle East				Africa				Other Areas				Total
2011
Consolidated operations
Future cash inflows		$	143,652				73,807				217,459				40,581				78,250				—				49,936				33,017				11,891				431,134
Less:
Future production and transportation costs*			75,771				32,766				108,537				19,148				17,166				—				14,380				4,113				3,768				167,112
Future development costs			11,385				7,519				18,904				13,393				16,986				—				3,051				885				2,080				55,299
Future income tax provisions			20,512				11,771				32,283				2,060				29,853				—				11,967				23,825				990				100,978
Future net cash flows			35,984				21,751				57,735				5,980				14,245				—				20,538				4,194				5,053				107,745
10 percent annual discount			19,233				9,643				28,876				4,025				5,372				—				6,649				1,522				3,712				50,156
Discounted future net cash flows		$	16,751				12,108				28,859				1,955				8,873				—				13,889				2,672				1,341				57,589
Equity affiliates
Future cash inflows		$	—				—				—				53,618				—				2,786				43,327				—				—				99,731
Less:
Future production and transportation costs*			—				—				—				16,405				—				2,765				24,702				—				—				43,872
Future development costs			—				—				—				7,163				—				36				905				—				—				8,104
Future income tax provisions			—				—				—				7,574				—				3				3,705				—				—				11,282
Future net cash flows			—				—				—				22,476				—				(18	)			14,015				—				—				36,473
10 percent annual discount			—				—				—				14,662				—				(39	)			7,217				—				—				21,840
Discounted future net cash flows		$	—				—				—				7,814				—				21				6,798				—				—				14,633
Total company
Discounted future net cash flows		$	16,751				12,108				28,859				9,769				8,873				21				20,687				2,672				1,341				72,222

* Includes taxes other than income taxes.

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		Millions of Dollars
		Alaska				Lower 48*				Total U.S.				Canada				Europe				Russia				Asia Pacific/ Middle East				Africa				Other Areas				Total
2010
Consolidated operations
Future cash inflows		$	102,743				68,949				171,692				38,083				49,270				—				37,673				24,487				8,466				329,671
Less:
Future production and transportation costs**			57,899				29,749				87,648				16,753				12,899				—				10,480				4,142				3,007				134,929
Future development costs			8,792				7,752				16,544				11,161				10,295				—				2,226				1,133				3,050				44,409
Future income tax provisions			13,383				10,953				24,336				2,416				16,765				—				9,211				16,217				384				69,329
Future net cash flows			22,669				20,495				43,164				7,753				9,311				—				15,756				2,995				2,025				81,004
10 percent annual discount			10,723				10,046				20,769				3,890				2,597				—				4,889				1,025				2,368				35,538
Discounted future net cash flows		$	11,946				10,449				22,395				3,863				6,714				—				10,867				1,970				(343	)			45,466
Equity affiliates
Future cash inflows		$	—				—				—				47,169				—				5,610				32,845				—				—				85,624
Less:
Future production and transportation costs**			—				—				—				16,492				—				4,809				21,036				—				—				42,337
Future development costs			—				—				—				4,684				—				85				295				—				—				5,064
Future income tax provisions			—				—				—				6,649				—				(80	)			2,082				—				—				8,651
Future net cash flows			—				—				—				19,344				—				796				9,432				—				—				29,572
10 percent annual discount			—				—				—				13,453				—				293				4,732				—				—				18,478
Discounted future net cash flows		$	—				—				—				5,891				—				503				4,700				—				—				11,094
Total company
Discounted future net cash flows		$	11,946				10,449				22,395				9,754				6,714				503				15,567				1,970				(343	)			56,560

* Certain amounts have been restated to remove future development costs related to probable reserves.

** Includes taxes other than income taxes.

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		Millions of Dollars
		Alaska				Lower 48				Total U.S.				Canada				Europe				Russia				Asia Pacific/ Middle East				Africa				Other Areas				Total
2009
Consolidated operations
Future cash inflows		$	74,359				51,007				125,366				45,965				41,832				—				31,276				19,618				6,416				270,473
Less:
Future production and transportation costs*			44,789				32,491				77,280				23,625				13,559				—				9,058				3,832				2,071				129,425
Future development costs			7,829				8,350				16,179				12,769				10,369				—				2,284				1,142				3,879				46,622
Future income tax provisions			7,519				2,992				10,511				2,183				10,676				—				7,288				12,396				71				43,125
Future net cash flows			14,222				7,174				21,396				7,388				7,228				—				12,646				2,248				395				51,301
10 percent annual discount			6,474				2,300				8,774				3,703				1,878				—				4,108				879				1,566				20,908
Discounted future net cash flows		$	7,748				4,874				12,622				3,685				5,350				—				8,538				1,369				(1,171	)			30,393
Equity affiliates
Future cash inflows		$	—				—				—				36,540				—				69,277				19,420				—				—				125,237
Less:
Future production and transportation costs*			—				—				—				13,689				—				49,874				13,891				—				—				77,454
Future development costs			—				—				—				4,481				—				7,795				350				—				—				12,626
Future income tax provisions			—				—				—				4,785				—				2,265				694				—				—				7,744
Future net cash flows			—				—				—				13,585				—				9,343				4,485				—				—				27,413
10 percent annual discount			—				—				—				9,512				—				4,002				2,018				—				—				15,532
Discounted future net cash flows		$	—				—				—				4,073				—				5,341				2,467				—				—				11,881
Total company
Discounted future net cash flows		$	7,748				4,874				12,622				7,758				5,350				5,341				11,005				1,369				(1,171	)			42,274

* Includes taxes other than income taxes.

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Sources of Change in Discounted Future Net Cash Flows

		Millions of Dollars
		Consolidated Operations												Equity Affiliates												Total Company
		2011				2010*				2009				2011				2010				2009				2011				2010*				2009
Discounted future net cash flows at the beginning of the year		$	45,466				30,393				24,548				11,094				11,881				3,033				56,560				42,274				27,581
Changes during the year
Revenues less production and transportation costs for the year**			(24,223	)			(22,296	)			(18,460	)			(1,962	)			(3,083	)			(2,793	)			(26,185	)			(25,379	)			(21,253	)
Net change in prices, and production and transportation costs**			38,161				39,532				19,208				4,685				3,478				14,386				42,846				43,010				33,594
Extensions, discoveries and improved recovery, less estimated future costs			8,730				4,517				2,312				832				297				1,342				9,562				4,814				3,654
Development costs for the year			8,428				5,617				6,148				1,488				1,758				1,623				9,916				7,375				7,771
Changes in estimated future development costs			(8,374	)			(2,917	)			(7,036	)			(1,508	)			(129	)			(2,197	)			(9,882	)			(3,046	)			(9,233	)
Purchases of reserves in place, less estimated future costs			19				19				3				—				—				96				19				19				99
Sales of reserves in place, less estimated future costs			(390	)			(3,729	)			(75	)			(234	)			(5,405	)			—				(624	)			(9,134	)			(75	)
Revisions of previous quantity estimates***			(1,938	)			3,062				5,149				491				372				(1,597	)			(1,447	)			3,434				3,552
Accretion of discount			7,710				5,000				3,972				1,284				1,404				365				8,994				6,404				4,337
Net change in income taxes			(16,000	)			(13,732	)			(5,376	)			(1,537	)			521				(2,377	)			(17,537	)			(13,211	)			(7,753	)
Total changes			12,123				15,073				5,845				3,539				(787	)			8,848				15,662				14,286				14,693
Discounted future net cash flows at year end		$	57,589				45,466				30,393				14,633				11,094				11,881				72,222				56,560				42,274

* Certain amounts have been restated to remove future development costs related to probable reserves.

** Includes taxes other than income taxes.

*** Includes amounts resulting from changes in the timing of production.

• The net change in prices, and production and transportation costs is the beginning-of-year reserve-production forecast multiplied by the net annual change in the per-unit sales price, and production and transportation cost, discounted at 10 percent.

• Purchases and sales of reserves in place, along with extensions, discoveries and improved recovery, are calculated using production forecasts of the applicable reserve quantities for the year multiplied by the 12-month average sales prices, less future estimated costs, discounted at 10 percent.

• The accretion of discount is 10 percent of the prior year’s discounted future cash inflows, less future production, transportation and development costs.

• The net change in income taxes is the annual change in the discounted future income tax provisions.

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Selected Quarterly Financial Data (Unaudited)

		Millions of Dollars
		Sales and				Income From Continuing												Per Share of Common Stock
		Other Operating				Operations Before				Net				Net Income Attributable to				Net Income Attributable to ConocoPhillips
		Revenues				Income Taxes				Income				ConocoPhillips				Basic				Diluted
2011
First		$	15,780				4,741				3,042				3,028				2.11				2.09
Second			17,176				4,514				3,419				3,402				2.43				2.41
Third			16,506				3,605				2,631				2,616				1.93				1.91
Fourth			16,294				3,365				3,410				3,390				2.58				2.56
2010
First		$	15,752				3,874				2,112				2,098				1.41				1.40
Second			12,873				6,081				4,183				4,164				2.79				2.77
Third			14,484				4,617				3,069				3,055				2.06				2.05
Fourth			14,187				3,740				2,053				2,041				1.40				1.39

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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 100 percent owned by ConocoPhillips. ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I and ConocoPhillips Canada Funding Company II are indirect, 100 percent-owned subsidiaries of ConocoPhillips Company. 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.

In February 2009, we filed a universal shelf registration statement with the SEC under which ConocoPhillips, as a well-known seasoned issuer, has the ability to issue and sell an indeterminate amount of various types of debt and equity securities, with certain debt securities guaranteed by ConocoPhillips Company. Also as part of that registration statement, ConocoPhillips Trust I and ConocoPhillips Trust II have the ability to issue and sell preferred trust securities, guaranteed by ConocoPhillips. ConocoPhillips Trust I and ConocoPhillips Trust II have not issued any trust-preferred securities under this registration statement, and thus have no assets or liabilities. Accordingly, columns for these two trusts are not included in the condensed consolidating financial information.

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

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		Millions of Dollars
		Year Ended December 31, 2011
Income Statement		ConocoPhillips				ConocoPhillips Company				ConocoPhillips Australia Funding Company				ConocoPhillips Canada Funding Company I				ConocoPhillips Canada Funding Company II				All Other Subsidiaries				Consolidating Adjustments				Total Consolidated
Revenues and Other Income
Sales and other operating revenues		$	—				20,606				—				—				—				45,150				—				65,756
Equity in earnings of affiliates			8,431				8,512				—				—				—				1,288				(16,997	)			1,234
Gain on dispositions			—				261				—				—				—				109				—				370
Other income			—				98				—				—				—				176				—				274
Intercompany revenues			4				1,346				46				91				35				2,683				(4,205	)			—
Total Revenues and Other Income			8,435				30,823				46				91				35				49,406				(21,202	)			67,634
Costs and Expenses
Purchased commodities			—				17,944				—				—				—				14,465				(2,434	)			29,975
Production and operating expenses			—				1,126				—				—				—				5,679				(63	)			6,742
Selling, general and administrative expenses			13				607				—				—				—				256				(9	)			867
Exploration expenses			—				333				—				—				—				733				—				1,066
Depreciation, depletion and amortization			—				867				—				—				—				6,148				—				7,015
Impairments			—				38				—				—				—				283				—				321
Taxes other than income taxes			—				292				—				—				—				3,729				—				4,021
Accretion on discounted liabilities			—				48				—				—				—				378				—				426
Interest and debt expense			1,594				448				42				77				32				460				(1,699	)			954
Foreign currency transaction (gains) losses			—				(16	)			—				(10	)			(35	)			83				—				22
Total Costs and Expenses			1,607				21,687				42				67				(3	)			32,214				(4,205	)			51,409
Income before income taxes			6,828				9,136				4				24				38				17,192				(16,997	)			16,225
Provision for income taxes			(561	)			705				1				(1	)			12				8,614				—				8,770
Income From Continuing Operations			7,389				8,431				3				25				26				8,578				(16,997	)			7,455
Income from discontinued operations			5,047				5,047				—				—				—				4,601				(9,648	)			5,047
Net income			12,436				13,478				3				25				26				13,179				(26,645	)			12,502
Less: net income (loss) attributable to noncontrolling interests			—				—				—				—				—				(66	)			—				(66	)
Net Income Attributable to ConocoPhillips		$	12,436				13,478				3				25				26				13,113				(26,645	)			12,436
Comprehensive Income (Loss) Attributable to ConocoPhillips		$	10,749				11,791				3				(6	)			14				11,901				(23,703	)			10,749
Income Statement		Year Ended December 31, 2010
Revenues and Other Income
Sales and other operating revenues		$	—				21,531				—				—				—				35,765				—				57,296
Equity in earnings of affiliates			11,009				11,381				—				—				—				1,278				(22,300	)			1,368
Gain on dispositions			—				370				—				—				—				5,193				—				5,563
Other income (loss)			1				191				—				—				(28	)			18				—				182
Intercompany revenues			5				661				46				86				66				3,886				(4,750	)			—
Total Revenues and Other Income			11,015				34,134				46				86				38				46,140				(27,050	)			64,409
Costs and Expenses
Purchased commodities			—				18,587				—				—				—				9,958				(3,576	)			24,969
Production and operating expenses			—				1,328				—				—				—				5,221				(24	)			6,525
Selling, general and administrative expenses			12				603				—				—				—				223				(27	)			811
Exploration expenses			—				247				—				—				—				908				—				1,155
Depreciation, depletion and amortization			—				978				—				—				—				7,191				—				8,169
Impairments			—				—				—				—				—				81				—				81
Taxes other than income taxes			—				293				—				—				—				2,511				—				2,804
Accretion on discounted liabilities			—				41				—				—				—				376				—				417
Interest and debt expense			946				502				42				77				45				678				(1,123	)			1,167
Foreign currency transaction (gains) losses			—				23				—				47				50				(121	)			—				(1	)
Total Costs and Expenses			958				22,602				42				124				95				27,026				(4,750	)			46,097
Income (loss) before income taxes			10,057				11,532				4				(38	)			(57	)			19,114				(22,300	)			18,312
Provision for income taxes			(333	)			523				1				7				(6	)			7,671				—				7,863
Income From Continuing Operations			10,390				11,009				3				(45	)			(51	)			11,443				(22,300	)			10,449
Income from discontinued operations			968				968				—				—				—				1,204				(2,172	)			968
Net income (loss)			11,358				11,977				3				(45	)			(51	)			12,647				(24,472	)			11,417
Less: net income attributable to noncontrolling interests			—				—				—				—				—				(59	)			—				(59	)
Net Income (Loss) Attributable to ConocoPhillips		$	11,358				11,977				3				(45	)			(51	)			12,588				(24,472	)			11,358
Comprehensive Income (Loss) Attributable to ConocoPhillips		$	13,066				13,685				3				24				(19	)			14,279				(27,972	)			13,066

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		Millions of Dollars
		Year Ended December 31, 2009
Income Statement		ConocoPhillips				ConocoPhillips Company				ConocoPhillips Australia Funding Company				ConocoPhillips Canada Funding Company I				ConocoPhillips Canada Funding Company II				All Other Subsidiaries				Consolidating Adjustments				Total Consolidated
Revenues and Other Income
Sales and other operating revenues		$	—				17,614				—				—				—				31,214				—				48,828
Equity in earnings of affiliates			4,120				4,744				—				—				—				1,071				(8,496	)			1,439
Gain on dispositions			—				4				—				—				—				77				—				81
Other income			—				111				—				—				—				146				—				257
Intercompany revenues			31				937				52				78				48				2,708				(3,854	)			—
Total Revenues and Other Income			4,151				23,410				52				78				48				35,216				(12,350	)			50,605
Costs and Expenses
Purchased commodities			—				15,343				—				—				—				9,132				(3,126	)			21,349
Production and operating expenses			2				1,205				—				—				—				5,110				(26	)			6,291
Selling, general and administrative expenses			15				421				—				—				—				239				(11	)			664
Exploration expenses			—				295				—				—				—				887				—				1,182
Depreciation, depletion and amortization			—				1,124				—				—				—				7,283				—				8,407
Impairments			—				1				—				—				—				468				—				469
Taxes other than income taxes			—				259				—				—				—				1,603				—				1,862
Accretion on discounted liabilities			—				33				—				—				—				356				—				389
Interest and debt expense			631				387				47				77				53				763				(691	)			1,267
Foreign currency transaction (gains) losses			—				(36	)			—				171				216				(340	)			—				11
Total Costs and Expenses			648				19,032				47				248				269				25,501				(3,854	)			41,891
Income (loss) before income taxes			3,503				4,378				5				(170	)			(221	)			9,715				(8,496	)			8,714
Provision for income taxes			(216	)			258				2				4				(24	)			4,893				—				4,917
Income (Loss) from Continuing Operations			3,719				4,120				3				(174	)			(197	)			4,822				(8,496	)			3,797
Income from discontinued operations			695				695				—				—				—				218				(913	)			695
Net income (loss)			4,414				4,815				3				(174	)			(197	)			5,040				(9,409	)			4,492
Less: net income attributable to noncontrolling interests			—				—				—				—				—				(78	)			—				(78	)
Net Income (Loss) Attributable to ConocoPhillips		$	4,414				4,815				3				(174	)			(197	)			4,962				(9,409	)			4,414
Comprehensive Income (Loss) Attributable to ConocoPhillips		$	9,354				9,755				3				16				(68	)			9,661				(19,367	)			9,354

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		Millions of Dollars
		At December 31, 2011**
Balance Sheet		ConocoPhillips				ConocoPhillips Company				ConocoPhillips Australia Funding Company				ConocoPhillips Canada Funding Company I				ConocoPhillips Canada Funding Company II				All Other Subsidiaries				Consolidating Adjustments				Total Consolidated
Assets
Cash and cash equivalents		$	—				2,028				1				37				1				3,713				—				5,780
Short-term investments			—				—				—				—				—				581				—				581
Accounts and notes receivable			60				9,186				—				—				—				20,898				(13,618	)			16,526
Inventories			—				2,239				—				—				—				2,392				—				4,631
Prepaid expenses and other current assets			22				1,090				—				1				—				1,587				—				2,700
Total Current Assets			82				14,543				1				38				1				29,171				(13,618	)			30,218
Investments, loans and long-term receivables*			96,284				135,618				760				1,417				565				59,651				(260,512	)			33,783
Net properties, plants and equipment			—				19,595				—				—				—				64,585				—				84,180
Goodwill			—				3,332				—				—				—				—				—				3,332
Intangibles			—				722				—				—				—				23				—				745
Other assets			64				301				—				2				3				602				—				972
Total Assets		$	96,430				174,111				761				1,457				569				154,032				(274,130	)			153,230
Liabilities and Stockholders’ Equity
Accounts payable		$	10				18,747				—				1				1				14,512				(13,618	)			19,653
Short-term debt			892				27				—				—				—				94				—				1,013
Accrued income and other taxes			—				315				—				2				—				3,903				—				4,220
Employee benefit obligations			—				835				—				—				—				276				—				1,111
Other accruals			244				634				9				14				6				1,164				—				2,071
Total Current Liabilities			1,146				20,558				9				17				7				19,949				(13,618	)			28,068
Long-term debt			10,951				3,599				749				1,250				498				4,563				—				21,610
Asset retirement obligations and accrued environmental costs			—				1,766				—				—				—				7,563				—				9,329
Joint venture acquisition obligation			—				—				—				—				—				3,582				—				3,582
Deferred income taxes			(5	)			3,982				—				11				9				14,043				—				18,040
Employee benefit obligations			—				3,092				—				—				—				976				—				4,068
Other liabilities and deferred credits*			25,959				40,479				—				104				29				20,047				(83,834	)			2,784
Total Liabilities			38,051				73,476				758				1,382				543				70,723				(97,452	)			87,481
Retained earnings			42,550				34,921				1				(70	)			(55	)			29,821				(58,119	)			49,049
Other common stockholders’ equity			15,829				65,714				2				145				81				52,978				(118,559	)			16,190
Noncontrolling interests			—				—				—				—				—				510				—				510
Total Liabilities and Stockholders’ Equity		$	96,430				174,111				761				1,457				569				154,032				(274,130	)			153,230
*      Includes intercompany loans.
Balance Sheet		At December 31, 2010**
Assets
Cash and cash equivalents		$	—				718				—				29				4				8,703				—				9,454
Short-term investments			—				—				—				—				—				973				—				973
Accounts and notes receivable			36				9,126				1				—				—				16,625				(9,976	)			15,812
Investments in LUKOIL			—				—				—				—				—				1,083				—				1,083
Inventories			—				3,121				—				—				—				2,076				—				5,197
Prepaid expenses and other current assets			23				824				—				2				—				1,292				—				2,141
Total Current Assets			59				13,789				1				31				4				30,752				(9,976	)			34,660
Investments, loans and long-term receivables*			84,461				112,008				762				1,445				577				50,563				(216,055	)			33,761
Net properties, plants and equipment			—				19,524				—				—				—				63,030				—				82,554
Goodwill			—				3,633				—				—				—				—				—				3,633
Intangibles			—				760				—				—				—				41				—				801
Other assets			55				254				1				3				3				589				—				905
Total Assets		$	84,575				149,968				764				1,479				584				144,975				(226,031	)			156,314
Liabilities and Stockholders’ Equity
Accounts payable		$	—				14,939				—				2				—				13,434				(9,976	)			18,399
Short-term debt			(5	)			354				—				—				—				587				—				936
Accrued income and other taxes			—				431				—				—				6				4,437				—				4,874
Employee benefit obligations			—				773				—				—				—				308				—				1,081
Other accruals			242				620				9				15				6				1,237				—				2,129
Total Current Liabilities			237				17,117				9				17				12				20,003				(9,976	)			27,419
Long-term debt			11,832				3,674				750				1,250				499				4,651				—				22,656
Asset retirement obligations and accrued environmental costs			—				1,686				—				—				—				7,513				—				9,199
Joint venture acquisition obligation			—				—				—				—				—				4,314				—				4,314
Deferred income taxes			(1	)			3,659				—				16				(2	)			13,648				—				17,320
Employee benefit obligations			—				2,779				—				—				—				904				—				3,683
Other liabilities and deferred credits*			10,752				32,268				—				114				61				19,169				(59,765	)			2,599
Total Liabilities			22,820				61,183				759				1,397				570				70,202				(69,741	)			87,190
Retained earnings			33,753				21,440				3				(94	)			(81	)			20,055				(34,824	)			40,252
Other common stockholders’ equity			28,002				67,345				2				176				95				54,171				(121,466	)			28,325
Noncontrolling interests			—				—				—				—				—				547				—				547
Total Liabilities and Stockholders’ Equity		$	84,575				149,968				764				1,479				584				144,975				(226,031	)			156,314

* Includes intercompany loans.

** Certain amounts have been restated to reflect a prior period adjustment. See Note 21—Accumulated Other Comprehensive Income, in the Notes to Consolidated Financial Statements.

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		Millions of Dollars
		Year Ended December 31, 2011
Statement of Cash Flows		ConocoPhillips				ConocoPhillips Company				ConocoPhillips Australia Funding Company				ConocoPhillips Canada Funding Company I				ConocoPhillips Canada Funding Company II				All Other Subsidiaries				Consolidating Adjustments				Total Consolidated
Cash Flows From Operating Activities
Net cash provided by (used in) continuing operating activities		$	14,669				(1,805	)			1				13				(7	)			4,950				(3,344	)			14,477
Net cash provided by (used in) discontinued operations			—				(2,359	)			—				—				—				7,528				—				5,169
Net Cash Provided by (Used in) Operating Activities		$	14,669				(4,164	)			1				13				(7	)			12,478				(3,344	)			19,646
Cash Flows From Investing Activities
Capital expenditures and investments			—				(1,504	)			—				—				—				(10,740	)			—				(12,244	)
Proceeds from asset dispositions			—				318				—				—				—				1,874				—				2,192
Net purchases of short-term investments			—				—				—				—				—				400				—				400
Long-term advances/loans—related parties			—				(916	)			—				(4	)			—				(4,562	)			5,473				(9	)
Collection of advances/loans—related parties			—				993				—				—				—				8,340				(9,235	)			98
Other			—				6				—				—				—				50				—				56
Net cash used in continuing investing activities			—				(1,103	)			—				(4	)			—				(4,638	)			(3,762	)			(9,507	)
Net cash provided by (used in) discontinued operations			—				2,376				—				—				—				(8,084	)			8,200				2,492
Net Cash Provided by (Used in) Investing Activities			—				1,273				—				(4	)			—				(12,722	)			4,438				(7,015	)
Cash Flows From Financing Activities
Issuance of debt			—				12,758				—				—				4				827				(13,589	)			—
Repayment of debt			—				(8,657	)			—				—				—				(1,426	)			9,149				(934	)
Issuance of company common stock			96				—				—				—				—				—				—				96
Repurchase of company common stock			(11,123	)			—				—				—				—				—				—				(11,123	)
Dividends paid on common stock			(3,633	)			—				—				—				—				(3,051	)			3,052				(3,632	)
Other			(9	)			119				—				—				—				(794	)			—				(684	)
Net cash provided by (used in) continuing financing activities			(14,669	)			4,220				—				—				4				(4,444	)			(1,388	)			(16,277	)
Net cash used in discontinued operations			—				(18	)			—				—				—				(304	)			294				(28	)
Net Cash Provided by (Used in) Financing Activities			(14,669	)			4,202				—				—				4				(4,748	)			(1,094	)			(16,305	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents			—				(1	)			—				—				—				1				—				—
Net Change in Cash and Cash Equivalents			—				1,310				1				9				(3	)			(4,991	)			—				(3,674	)
Cash and cash equivalents at beginning of year			—				718				—				29				4				8,703				—				9,454
Cash and Cash Equivalents at End of Year		$	—				2,028				1				38				1				3,712				—				5,780
Statement of Cash Flows		Year Ended December 31, 2010
Cash Flows From Operating Activities
Net cash provided by (used in) continuing operating activities		$	7,901				1,962				—				11				(3	)			7,095				(2,513	)			14,453
Net cash provided by discontinued operations			—				349				—				—				—				2,243				—				2,592
Net Cash Provided by (Used in) Operating Activities		$	7,901				2,311				—				11				(3	)			9,338				(2,513	)			17,045
Cash Flows From Investing Activities
Capital expenditures and investments			—				(1,120	)			—				—				—				(7,814	)			323				(8,611	)
Proceeds from asset dispositions			—				789				—				—				—				14,020				(99	)			14,710
Net purchases of short-term investments			—				—				—				—				—				(982	)			—				(982	)
Long-term advances/loans—related parties			—				(135	)			—				—				—				(2,279	)			2,301				(113	)
Collection of advances/loans—related parties			—				87				—				—				384				1,379				(1,755	)			95
Other			—				28				—				—				—				190				—				218
Net cash provided by (used in) continuing investing activities			—				(351	)			—				—				384				4,514				770				5,317
Net cash provided by (used in) discontinued operations			—				(931	)			—				—				—				279				—				(652	)
Net Cash Provided by (Used in) Investing Activities			—				(1,282	)			—				—				384				4,793				770				4,665
Cash Flows From Financing Activities
Issuance of debt			—				2,159				—				—				—				260				(2,301	)			118
Repayment of debt			(990	)			(2,642	)			—				—				(378	)			(3,039	)			1,755				(5,294	)
Issuance of company common stock			133				—				—				—				—				—				—				133
Repurchase of company common stock			(3,866	)			—				—				—				—				—				—				(3,866	)
Dividends paid on common stock			(3,175	)			—				—				—				—				(2,666	)			2,666				(3,175	)
Other			(3	)			52				—				—				—				(782	)			27				(706	)
Net cash used in continuing financing activities			(7,901	)			(431	)			—				—				(378	)			(6,227	)			2,147				(12,790	)
Net cash provided by (used in) discontinued operations			—				(18	)			—				—				—				240				(251	)			(29	)
Net Cash Used in Financing Activities			(7,901	)			(449	)			—				—				(378	)			(5,987	)			1,896				(12,819	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents			—				16				—				—				—				5				—				21
Net Change in Cash and Cash Equivalents			—				596				—				11				3				8,149				153				8,912
Cash and cash equivalents at beginning of year			—				122				—				18				1				554				(153	)			542
Cash and Cash Equivalents at End of Year		$	—				718				—				29				4				8,703				—				9,454

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		Millions of Dollars
		Year Ended December 31, 2009
Statement of Cash Flows		ConocoPhillips				ConocoPhillips Company				ConocoPhillips Australia Funding Company				ConocoPhillips Canada Funding Company I				ConocoPhillips Canada Funding Company II				All Other Subsidiaries				Consolidating Adjustments				Total Consolidated
Cash Flows From Operating Activities
Net cash provided by (used in) continuing operating activities		$	(2,205	)			5,181				—				8				—				10,483				(2,084	)			11,383
Net cash provided by (used in) discontinued operations			—				1,270				—				—				—				(174	)			—				1,096
Net Cash Provided by (Used in) Operating Activities		$	(2,205	)			6,451				—				8				—				10,309				(2,084	)			12,479
Cash Flows From Investing Activities
Capital expenditures and investments			—				(1,890	)			—				—				—				(7,190	)			680				(8,400	)
Proceeds from asset dispositions			—				314				—				—				—				517				(319	)			512
Long-term advances/loans—related parties			—				(75	)			—				—				—				(3,312	)			3,212				(175	)
Collection of advances/loans—related parties			—				168				950				—				—				6,438				(7,464	)			92
Other			—				—				—				—				—				9				—				9
Net cash provided by (used in) continuing investing activities			—				(1,483	)			950				—				—				(3,538	)			(3,891	)			(7,962	)
Net cash used in discontinued operations			—				(1,256	)			—				—				—				(717	)			—				(1,973	)
Net Cash Provided by (Used in) Investing Activities			—				(2,739	)			950				—				—				(4,255	)			(3,891	)			(9,935	)
Cash Flows From Financing Activities
Issuance of debt			8,909				3,122				—				—				—				269				(3,213	)			9,087
Repayment of debt			(3,826	)			(6,727	)			(950	)			—				—				(3,794	)			7,464				(7,833	)
Issuance of company common stock			13				—				—				—				—				—				—				13
Dividends paid on common stock			(2,832	)			—				—				—				—				(1,945	)			1,945				(2,832	)
Other			(59	)			18				—				—				—				(1,179	)			(41	)			(1,261	)
Net cash provided by (used in) continuing financing activities			2,205				(3,587	)			(950	)			—				—				(6,649	)			6,155				(2,826	)
Net cash provided by (used in) discontinued operations			—				(11	)			—				—				—				301				(319	)			(29	)
Net Cash Provided by (Used in) Financing Activities			2,205				(3,598	)			(950	)			—				—				(6,348	)			5,836				(2,855	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents			—				—				—				—				—				98				—				98
Net Change in Cash and Cash Equivalents			—				114				—				8				—				(196	)			(139	)			(213	)
Cash and cash equivalents at beginning of year			—				8				—				10				1				750				(14	)			755
Cash and Cash Equivalents at End of Year		$	—				122				—				18				1				554				(153	)			542

99