v2.4.0.6

Separation of Downstream Business

12 Months Ended

Dec. 31, 2011

Separation of Downstream Business

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.

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.

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.

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.

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.

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.

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

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.

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

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.

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

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.

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.

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.

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.

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

		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

		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

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.

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

		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.

		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.

										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

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.

		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.

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

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.

		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.

		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.

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.

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

X

- Definition

The entire disclosure for the facts and circumstances leading to the separation, manner and timing of separation, amounts of revenues and pretax profit or loss reported in discontinued operations, and carrying value of the assets and liabilities comprising the disposal group.

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