COP 10-Q Quarterly Report June 30, 2012

COP 10-Q Quarter ended June 30, 2012

CONOCOPHILLIPS

10-Qs and 10-Ks

10-Q	Quarter ended March 31, 2025
10-K	Fiscal year ended Dec. 31, 2024
10-Q	Quarter ended Sept. 30, 2024
10-Q	Quarter ended June 30, 2024
10-Q	Quarter ended March 31, 2024
10-K	Fiscal year ended Dec. 31, 2023
10-Q	Quarter ended Sept. 30, 2023
10-Q	Quarter ended June 30, 2023
10-Q	Quarter ended March 31, 2023
10-K	Fiscal year ended Dec. 31, 2022
10-Q	Quarter ended Sept. 30, 2022
10-Q	Quarter ended June 30, 2022
10-Q	Quarter ended March 31, 2022
10-K	Fiscal year ended Dec. 31, 2021
10-Q	Quarter ended Sept. 30, 2021
10-Q	Quarter ended June 30, 2021
10-Q	Quarter ended March 31, 2021
10-K	Fiscal year ended Dec. 31, 2020
10-Q	Quarter ended Sept. 30, 2020
10-Q	Quarter ended June 30, 2020
10-Q	Quarter ended March 31, 2020
10-K	Fiscal year ended Dec. 31, 2019
10-Q	Quarter ended Sept. 30, 2019
10-Q	Quarter ended June 30, 2019
10-Q	Quarter ended March 31, 2019
10-K	Fiscal year ended Dec. 31, 2018
10-Q	Quarter ended Sept. 30, 2018
10-Q	Quarter ended June 30, 2018
10-Q	Quarter ended March 31, 2018
10-K	Fiscal year ended Dec. 31, 2017
10-Q	Quarter ended Sept. 30, 2017
10-Q	Quarter ended June 30, 2017
10-Q	Quarter ended March 31, 2017
10-K	Fiscal year ended Dec. 31, 2016
10-Q	Quarter ended Sept. 30, 2016
10-Q	Quarter ended June 30, 2016
10-Q	Quarter ended March 31, 2016
10-K	Fiscal year ended Dec. 31, 2015
10-Q	Quarter ended Sept. 30, 2015
10-Q	Quarter ended June 30, 2015
10-Q	Quarter ended March 31, 2015
10-K	Fiscal year ended Dec. 31, 2014
10-Q	Quarter ended Sept. 30, 2014
10-Q	Quarter ended June 30, 2014
10-Q	Quarter ended March 31, 2014
10-K	Fiscal year ended Dec. 31, 2013
10-Q	Quarter ended Sept. 30, 2013
10-Q	Quarter ended June 30, 2013
10-Q	Quarter ended March 31, 2013
10-K	Fiscal year ended Dec. 31, 2012
10-Q	Quarter ended Sept. 30, 2012
10-Q	Quarter ended June 30, 2012
10-Q	Quarter ended March 31, 2012
10-K	Fiscal year ended Dec. 31, 2011
10-Q	Quarter ended Sept. 30, 2011
10-Q	Quarter ended June 30, 2011
10-Q	Quarter ended March 31, 2011
10-K	Fiscal year ended Dec. 31, 2010
10-Q	Quarter ended Sept. 30, 2010
10-Q	Quarter ended June 30, 2010
10-Q	Quarter ended March 31, 2010
10-K	Fiscal year ended Dec. 31, 2009

PROXIES

DEF 14A	Filed on March 31, 2025
DEF 14A	Filed on April 1, 2024
DEF 14A	Filed on April 3, 2023
DEF 14A	Filed on March 28, 2022
DEF 14A	Filed on March 29, 2021
DEF 14A	Filed on March 30, 2020
DEF 14A	Filed on April 1, 2019
DEF 14A	Filed on April 2, 2018
DEF 14A	Filed on April 3, 2017
DEF 14A	Filed on March 28, 2016
DEF 14A	Filed on March 27, 2015
DEF 14A	Filed on March 28, 2014
DEF 14A	Filed on March 28, 2013
DEF 14A	Filed on March 28, 2012
DEF 14A	Filed on March 31, 2011
DEF 14A	Filed on March 31, 2010

10-Q 1 d358543d10q.htm FORM 10-Q Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2012

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 001-32395

ConocoPhillips

(Exact name of registrant as specified in its charter)

Delaware

01-0562944

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

600 North Dairy Ashford, Houston, TX 77079

(Address of principal executive offices) (Zip Code)

281-293-1000

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

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

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

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

The registrant had 1,214,549,390 shares of common stock, $.01 par value, outstanding at June 30, 2012.

CONOCOPHILLIPS

TABLE OF CONTENTS


	Page
Part I – Financial Information

Item 1. Financial Statements
Consolidated Income Statement		1
Consolidated Statement of Comprehensive Income		2
Consolidated Balance Sheet		3
Consolidated Statement of Cash Flows		4
Consolidated Statement of Changes in Equity		5
Notes to Consolidated Financial Statements		6
Supplementary Information—Condensed Consolidating Financial Information		27

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		32

Item 3. Quantitative and Qualitative Disclosures About Market Risk		53

Item 4. Controls and Procedures		53

Part II – Other Information

Item 1. Legal Proceedings		54

Item 1A. Risk Factors		55

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		55

Item 6. Exhibits		56

Signature		58

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS


Consolidated Income Statement			ConocoPhillips


	Millions of Dollars
	Three Months Ended June 30						Six Months Ended June 30
	2012			2011			2012			2011

Revenues and Other Income
Sales and other operating revenues	$	13,988			17,176			28,972			32,956
Equity in earnings of affiliates		529			375			1,015			701
Gain on dispositions		583			35			1,523			648
Other income		66			82			126			166

Total Revenues and Other Income		15,166			17,668			31,636			34,471


Costs and Expenses
Purchased commodities		5,758			7,681			11,878			14,639
Production and operating expenses		1,883			1,595			3,521			3,174
Selling, general and administrative expenses		235			203			562			451
Exploration expenses		270			264			949			440
Depreciation, depletion and amortization		1,626			1,846			3,249			3,694
Impairments		82			—			296			—
Taxes other than income taxes		906			1,198			2,007			2,082
Accretion on discounted liabilities		105			107			212			212
Interest and debt expense		197			242			387			499
Foreign currency transaction (gains) losses		15			18			19			25

Total Costs and Expenses		11,077			13,154			23,080			25,216

Income from continuing operations before income taxes		4,089			4,514			8,556			9,255
Provision for income taxes		2,334			2,214			4,560			4,638

Income From Continuing Operations		1,755			2,300			3,996			4,617
Income from discontinued operations		534			1,119			1,248			1,844

Net income		2,289			3,419			5,244			6,461
Less: net income attributable to noncontrolling interests		(22	)		(17	)		(40	)		(31	)

Net Income Attributable to ConocoPhillips	$	2,267			3,402			5,204			6,430


Net Income Attributable to ConocoPhillips Per Share of Common Stock (dollars)
Basic
Continuing operations	$	1.39			1.63			3.13			3.24
Discontinued operations		0.43			0.80			0.98			1.30

Net Income Attributable to ConocoPhillips Per Share of Common Stock	$	1.82			2.43			4.11			4.54

Diluted
Continuing operations	$	1.38			1.62			3.10			3.21
Discontinued operations		0.42			0.79			0.98			1.29

Net Income Attributable to ConocoPhillips Per Share of Common Stock	$	1.80			2.41			4.08			4.50


Dividends Paid Per Share of Common Stock (dollars)	$	0.66			0.66			1.32			1.32


Average Common Shares Outstanding (in thousands)
Basic		1,248,300			1,399,473			1,265,896			1,415,788
Diluted		1,258,189			1,412,147			1,275,667			1,428,760

See Notes to Consolidated Financial Statements.


Consolidated Statement of Comprehensive Income			ConocoPhillips


	Millions of Dollars
	Three Months Ended June 30						Six Months Ended June 30
	2012			2011			2012			2011

Net Income	$	2,289			3,419			5,244			6,461

Other comprehensive income (loss)
Defined benefit plans
Prior service cost arising during the period		—			—			—			—
Reclassification adjustment for amortization of prior service cost (credit) included in net income		(1	)		1			(2	)		1

Net change		(1	)		1			(2	)		1

Net actuarial loss arising during the period		(38	)		—			(38	)		—
Reclassification adjustment for amortization of prior net losses included in net income		60			52			138			103

Net change		22			52			100			103
Nonsponsored plans*		2			5			5			11
Income taxes on defined benefit plans		2			(20	)		(27	)		(40	)

Defined benefit plans, net of tax		25			38			76			75

Unrealized holding gain on securities**		1			—			1			8
Reclassification adjustment for gain included in net income		—			—			—			(255	)
Income taxes on unrealized holding gain on securities		—			—			—			89

Unrealized gain on securities, net of tax		1			—			1			(158	)

Foreign currency translation adjustments		(513	)		549			339			1,463
Reclassification adjustment for gain included in net income		—			—			1			—
Income taxes on foreign currency translation adjustments		13			(9	)		(6	)		(29	)

Foreign currency translation adjustments, net of tax		(500	)		540			334			1,434

Hedging activities		5			—			6			1
Income taxes on hedging activities		—			—			—			—

Hedging activities, net of tax		5			—			6			1

Other Comprehensive Income (Loss), Net of Tax		(469	)		578			417			1,352

Comprehensive Income		1,820			3,997			5,661			7,813
Less: comprehensive income attributable to noncontrolling interests		(22	)		(17	)		(40	)		(31	)

Comprehensive Income Attributable to ConocoPhillips	$	1,798			3,980			5,621			7,782

*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.


Consolidated Balance Sheet		ConocoPhillips


	Millions of Dollars
	June 30 2012			December 31 2011**

Assets
Cash and cash equivalents	$	1,044			5,780
Short-term investments*		—			581
Restricted cash		5,000			—
Accounts and notes receivable (net of allowance of $23 million in 2012 and $30 million in 2011)		7,550			14,648
Accounts and notes receivable—related parties		169			1,878
Inventories		1,178			4,631
Prepaid expenses and other current assets		1,971			2,700

Total Current Assets		16,912			30,218
Investments and long-term receivables		23,372			32,108
Loans and advances—related parties		1,597			1,675
Net properties, plants and equipment (net of accumulated depreciation, depletion and amortization of $57,220 million in 2012 and $65,029 million in 2011)		71,227			84,180
Goodwill		—			3,332
Intangibles		11			745
Other assets		889			972

Total Assets	$	114,008			153,230


Liabilities
Accounts payable	$	8,243			17,973
Accounts payable—related parties		853			1,680
Short-term debt		4,179			1,013
Accrued income and other taxes		2,819			4,220
Employee benefit obligations		594			1,111
Other accruals		1,672			2,071

Total Current Liabilities		18,360			28,068
Long-term debt		18,829			21,610
Asset retirement obligations and accrued environmental costs		8,224			9,329
Joint venture acquisition obligation—related party		3,201			3,582
Deferred income taxes		13,598			18,040
Employee benefit obligations		2,873			4,068
Other liabilities and deferred credits		2,480			2,784

Total Liabilities		67,565			87,481


Equity
Common stock (2,500,000,000 shares authorized at $.01 par value)
Issued (2012—1,754,997,004 shares; 2011—1,749,550,587 shares)
Par value		18			17
Capital in excess of par		45,016			44,725
Treasury stock (at cost: 2012—540,447,614 shares; 2011—463,880,628 shares)		(36,696	)		(31,787	)
Accumulated other comprehensive income		3,877			3,246
Unearned employee compensation		—			(11	)
Retained earnings		33,756			49,049

Total Common Stockholders’ Equity		45,971			65,239
Noncontrolling interests		472			510

Total Equity		46,443			65,749

Total Liabilities and Equity	$	114,008			153,230

*Includes marketable securities of:	*$ —*			232

**Certain amounts have been restated to reflect a prior period adjustment. See Note 16—Accumulated Other Comprehensive Income, in the Notes to Consolidated Financial Statements.

See Notes to Consolidated Financial Statements.


Consolidated Statement of Cash Flows		ConocoPhillips


	Millions of Dollars
	Six Months Ended June 30
	2012			2011

Cash Flows From Operating Activities
Net income	$	5,244			6,461
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization		3,249			3,694
Impairments		296			—
Dry hole costs and leasehold impairments		634			139
Accretion on discounted liabilities		212			212
Deferred taxes		447			(41	)
Undistributed equity earnings		(251	)		(285	)
Gain on dispositions		(1,523	)		(648	)
Income from discontinued operations		(1,248	)		(1,844	)
Other		(100	)		(140	)
Working capital adjustments
Decrease (increase) in accounts and notes receivable		(384	)		(806	)
Decrease (increase) in inventories		31			93
Decrease (increase) in prepaid expenses and other current assets		254			(323	)
Increase (decrease) in accounts payable		52			547
Increase (decrease) in taxes and other accruals		(545	)		(706	)

Net cash provided by continuing operating activities		6,368			6,353
Net cash provided by discontinued operations		164			1,868

Net Cash Provided by Operating Activities		6,532			8,221


Cash Flows From Investing Activities
Capital expenditures and investments		(7,858	)		(5,390	)
Proceeds from asset dispositions		1,566			1,863
Net sales (purchases) of short-term investments		597			(1,594	)
Long-term advances/loans—related parties		6			(3	)
Collection of advances/loans—related parties		48			50
Other		20			32

Net cash used in continuing investing activities		(5,621	)		(5,042	)
Net cash provided by (used in) discontinued operations		(304	)		148

Net Cash Used in Investing Activities		(5,925	)		(4,894	)


Cash Flows From Financing Activities
Issuance of debt		831			—
Repayment of debt		(47	)		(378	)
Special cash distribution from Phillips 66		7,818			—
Change in restricted cash		(5,000	)		—
Issuance of company common stock		45			99
Repurchase of company common stock		(4,949	)		(4,785	)
Dividends paid on company common stock		(1,661	)		(1,861	)
Other		(369	)		(357	)

Net cash used in continuing financing activities		(3,332	)		(7,282	)
Net cash used in discontinued operations		(2,019	)		(14	)

Net Cash Used in Financing Activities		(5,351	)		(7,296	)


Effect of Exchange Rate Changes on Cash and Cash Equivalents		8			20


Net Change in Cash and Cash Equivalents		(4,736	)		(3,949	)
Cash and cash equivalents at beginning of period		5,780			9,454

Cash and Cash Equivalents at End of Period	$	1,044			5,505

See Notes to Consolidated Financial Statements.

Consolidated Statement of Changes in Equity

ConocoPhillips


	Millions of Dollars
	Attributable to ConocoPhillips
	Common Stock
	Par Value		Capital in Excess of Par		Treasury Stock			Accum. Other Comprehensive Income		Unearned Employee Compensation			Retained Earnings			Noncontrolling Interests			Total

December 31, 2011*	$	17		44,725		(31,787	)		3,246		(11	)		49,049			510			65,749
Net income														5,204			40			5,244
Other comprehensive income									417											417
Cash dividends paid on company common stock														(1,661	)					(1,661	)
Repurchase of company common stock						(4,949	)													(4,949	)
Distributions to noncontrolling interests and other																	(47	)		(47	)
Distributed under benefit plans		1		291		40														332
Recognition of unearned compensation											11									11
Separation of Downstream business									214					(18,855	)		(31	)		(18,672	)
Other														19						19

June 30, 2012	$	18		45,016		(36,696	)		3,877		—			33,756			472			46,443

*Certain amounts have been restated to reflect a prior period adjustment. See Note 16—Accumulated Other Comprehensive Income, in the Notes to Consolidated Financial Statements.

See Notes to Consolidated Financial Statements.


Notes to Consolidated Financial Statements		ConocoPhillips

Note 1—Basis of Presentation

The interim-period financial information presented in the financial statements included in this report is unaudited and, in the opinion of management, includes all known accruals and adjustments necessary for a fair presentation of the consolidated financial position of ConocoPhillips and its results of operations and cash flows for such periods. All such adjustments are of a normal and recurring nature unless otherwise disclosed. Certain notes and other information have been condensed or omitted from the interim financial statements included in this report. Therefore, these financial statements should be read in conjunction with the consolidated financial statements and notes included in our 2011 Annual Report on Form 10-K.

The results of operations for our refining, marketing and transportation businesses; most of our Midstream segment; our Chemicals segment; and our power generation and certain technology operations included in our Emerging Businesses segment (collectively, our “Downstream business”), have been classified as discontinued operations for all periods presented. See Note 2—Separation of Downstream Business, for additional information. Unless indicated otherwise, the information in the Notes to the Consolidated Financial Statements relates to our continuing operations.

Note 2—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.

In connection with the separation, Phillips 66 distributed approximately $7.8 billion to us in a special cash distribution, primarily using the proceeds from the $5.8 billion in Senior Notes issued by Phillips 66 in March 2012, as well as a portion of the 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 (IRS), 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 June 30, 2012, the remaining balance of this cash distribution was $5,000 million and was included in the “Restricted cash” line on our consolidated balance sheet.

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, immediately preceding the separation of our Downstream business on April 30, 2012, excluded from our consolidated balance sheet at June 30, 2012:


	Millions of Dollars
Assets
Cash and cash equivalents	$	3,603
Accounts and notes receivable		7,295
Accounts and notes receivable—related parties		1,501
Inventories		5,017
Prepaid expenses and other current assets		996

Total current assets of discontinued operations		18,412
Investments and long-term receivables		10,826
Loans and advances—related parties		1
Net properties, plants and equipment		15,258
Goodwill		3,330
Intangibles		730
Other assets		95

Total assets of discontinued operations	$	48,652


Liabilities
Accounts payable	$	12,064
Accounts payable—related parties		938
Short-term debt		7,814
Accrued income and other taxes		493
Employee benefit obligations		219
Other accruals		952

Total current liabilities of discontinued operations		22,480
Long-term debt		175
Asset retirement obligations and accrued environmental costs		771
Deferred income taxes		4,990
Employee benefit obligations		1,138
Other liabilities and deferred credits		426

Total liabilities of discontinued operations	$	29,980

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


	Millions of Dollars
	Three Months Ended June 30				Six Months Ended June 30
	2012		2011		2012		2011

Sales and other operating revenues from discontinued operations	$	16,609		52,591		62,107		97,364


Income from discontinued operations before-tax	$	782		1,678		1,790		2,733
Income tax expense		248		559		542		889

Income from discontinued operations	$	534		1,119		1,248		1,844

Income from discontinued operations after-tax includes transaction, information systems and other costs incurred to effect the separation of $26 million and $70 million for the three-month and six-month periods ended June 30, 2012, respectively. No separation costs were incurred during the first six months of 2011.

Prior to the separation, commodity sales to Phillips 66 were $919 million and $4,973 million for the three-month and six-month periods ended June 30, 2012, and $3,842 million and $7,599 million for the three-month and six-month periods ended June 30, 2011. Prior to the separation, commodity purchases from Phillips 66 were $7 million and $166 million for the three-month and six-month periods ended June 30, 2012, and $112 million and $264 million for the three-month and six-month periods ended June 30, 2011. Prior to May 1, 2012, 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.

Note 3—Variable Interest Entities (VIEs)

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

We have an agreement with Freeport LNG Development, L.P. (Freeport LNG) to participate in a liquefied natural gas (LNG) receiving terminal in Quintana, Texas. We have no ownership in Freeport LNG; however, we own a 50 percent interest in Freeport LNG GP, Inc. (Freeport GP), which serves as the general partner managing the venture. We entered into a credit agreement with Freeport LNG, whereby we agreed to provide loan financing for the construction of the terminal. We also entered into a long-term agreement with Freeport LNG to use 0.9 billion cubic feet per day of regasification capacity. The terminal became operational in June 2008, and we began making payments under the terminal use agreement. Freeport LNG began making loan repayments in September 2008, and the loan balance outstanding was $592 million at June 30, 2012, and $612 million at December 31, 2011. 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 consisted of the following:


	Millions of Dollars
	June 30 2012		December 31 2011

Crude oil and petroleum products	$	483		3,633
Materials, supplies and other		695		998

	$	1,178		4,631

Inventories valued on the last-in, first-out (LIFO) basis totaled $315 million and $3,387 million at June 30, 2012, and December 31, 2011, respectively. The estimated excess of current replacement cost over LIFO cost of inventories amounted to approximately $100 million and $8,400 million at June 30, 2012, and December 31, 2011, respectively.

A significant portion of our inventories at December 31, 2011, was related to our Downstream business. See Note 2—Separation of Downstream Business, for additional information.

Note 5—Assets Held for Sale or Sold

In April 2012, we sold our interest in the Statfjord Field and associated satellites, all of which are located in the North Sea, and recognized a gain of $431 million before-tax which was included in the “Gain on dispositions” line of our consolidated income statement. At the time of disposition, the carrying value of our interest, which was included in the Europe segment, included $205 million of properties, plants and equipment (PP&E) and $445 million of asset retirement obligations.

In May 2012, we sold our interest in the North Sea Alba Field and recognized a gain of $155 million before-tax, which was included in the “Gain on dispositions” line on our consolidated income statement. At the time of the disposition, the carrying value of our interest, which was included in our Europe segment, included $160 million of PP&E and $86 million of asset retirement obligations.

Note 6—Investments, Loans and Long-Term Receivables

Australia Pacific LNG

In January 2012, Australia Pacific LNG (APLNG) and China Petrochemical Corporation (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. This agreement, in combination with the binding Heads of Agreement with Kansai Electric Power Co. Inc., signed in November 2011, finalized the marketing of the second train.

In July 2012, we sanctioned the development of the second 4.5-million-tonnes-per-year LNG production train for our APLNG coal seam gas to LNG project. In addition, APLNG signed project financing agreements during the second quarter of 2012, which are subject to certain conditions precedent. APLNG expects to begin drawing on the financing in the fourth quarter of 2012. LNG exports from the second train are expected to commence in early 2016 under binding sales agreements to Sinopec and Kansai. Upon sanctioning of the second train in July and in conjunction with the LNG sales agreement, Sinopec subscribed for additional shares in APLNG, which increased its equity interest from 15 percent to 25 percent. As a result, on July 12, 2012, both our ownership interest and Origin Energy’s ownership interest diluted from 42.5 percent to 37.5 percent. This reduction, along with project financing, lowers our future capital requirements to fund the APLNG Project. We expect to record a loss of approximately $135 million after-tax from the dilution in the third quarter of 2012.

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 made to certain affiliated and non-affiliated companies. Significant loans to affiliated companies at June 30, 2012, included the following:

•

$592 million in loan financing to Freeport LNG.

•

$1,131 million in project financing to Qatar Liquefied Gas Company Limited (3) (QG3).

The long-term portion of these loans is included in the “Loans and advances—related parties” line on our consolidated balance sheet, while the short-term portion is in “Accounts and notes receivable—related parties.”

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

Note 7—Suspended Wells

The capitalized cost of suspended wells at June 30, 2012, was $1,057 million, an increase of $20 million from $1,037 million at year-end 2011. For the category of exploratory well costs capitalized for a period greater than one year as of December 31, 2011, no wells were charged to dry hole expense during the first six months of 2012.

Note 8—Impairments

During the three- and six-month periods of 2012 and 2011, we recognized before-tax impairment charges within the following segments:


	Millions of Dollars
	Three Months Ended June 30				Six Months Ended June 30
	2012		2011		2012		2011

Canada	$	—		—		213		—
Europe		78		—		79		—
Asia Pacific and Middle East		4		—		4		—

	$	82		—		296		—

The three- and six-month periods of 2012 included a $78 million impairment in our Europe segment, primarily due to an increase in the asset retirement obligation for the Don Field in the United Kingdom, which has ceased production. Additionally, the six-month period of 2012 included a $213 million property impairment in our Canada segment for the carrying value of capitalized project development costs associated with our Mackenzie Gas Project. Advancement of the project was suspended indefinitely in the first quarter of 2012 due to a continued decline in market conditions and the lack of acceptable commercial terms. We also recorded a $481 million impairment for the undeveloped leasehold costs associated with the project, which was included in the “Exploration expenses” line on our consolidated income statement. See Note 20—Segment Disclosures and Related Information, for additional information on our segments.

Note 9—Debt

In May 2012, we decreased our total revolving credit facilities from $8.0 billion to $7.5 billion by terminating all commitments under the $500 million credit facility which was due to expire in July 2012.

We have two commercial paper programs supported by our $7.5 billion revolving credit facility: the ConocoPhillips $6.35 billion program, primarily a funding source for short-term working capital needs, and the ConocoPhillips Qatar Funding Ltd. $1.15 billion commercial paper program, which is used to fund commitments relating to the QG3 Project. Commercial paper maturities are generally limited to 90 days.

At both June 30, 2012, and December 31, 2011, we had no direct outstanding borrowings under our revolving credit facilities, with no letters of credit issued as of June 30, 2012, and $40 million as of December 31, 2011. In addition, under the two commercial paper programs, there was $1,929 million of commercial paper outstanding at June 30, 2012, compared with $1,128 million at December 31, 2011. Since we had $1,929 million of commercial paper outstanding and had issued no letters of credit, we had access to $5.6 billion in borrowing capacity under our revolving credit facilities at June 30, 2012.

At June 30, 2012, we classified $1,011 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. In July 2012, irrevocable early redemption notices were issued for settlement with respect to $1.5 billion of outstanding bonds. Accordingly, those bonds with due dates beyond one year were classified as short-term debt on our consolidated balance sheet as of June 30, 2012. Upon settlement in the third quarter of 2012, a before-tax loss on the redemption of approximately $75 million is expected, consisting of a make-whole premium and unamortized issuance costs.

Note 10—Joint Venture Acquisition Obligation

We are obligated to contribute $7.5 billion, plus interest, over a 10-year period that began in 2007, to FCCL Partnership. Quarterly principal and interest payments of $237 million began in the second quarter of 2007, and will continue until the balance is paid. Of the principal obligation amount, approximately $752 million was short-term and was included in the “Accounts payable—related parties” line on our June 30, 2012, consolidated balance sheet. The principal portion of these payments, which totaled $361 million in the first six months of 2012, is included in the “Other” line in the financing activities section on our consolidated statement of cash flows. Interest accrues at a fixed annual rate of 5.3 percent on the unpaid principal balance. Fifty percent of the quarterly interest payment is reflected as a capital contribution and is included in the “Capital expenditures and investments” line on our consolidated statement of cash flows.

Note 11—Noncontrolling Interests

Activity attributable to common stockholders’ equity and noncontrolling interests for the first six months of 2012 and 2011 was as follows:


	Millions of Dollars
	2012									2011
	Common Stockholders’ Equity			Non- Controlling Interest			Total Equity			Common Stockholders’ Equity*			Non- Controlling Interest			Total Equity*

Balance at January 1	$	65,239			510			65,749			68,577			547			69,124
Net income		5,204			40			5,244			6,430			31			6,461
Dividends		(1,661	)		—			(1,661	)		(1,861	)		—			(1,861	)
Repurchase of company common stock		(4,949	)		—			(4,949	)		(4,785	)		—			(4,785	)
Distributions to noncontrolling interests		—			(47	)		(47	)		—			(59	)		(59	)
Separation of Downstream business		(18,641	)		(31	)		(18,672	)		—			—			—
Other changes, net**		779			—			779			1,713			—			1,713

Balance at June 30	$	45,971			472			46,443			70,074			519			70,593

*Certain amounts have been restated to reflect a prior period adjustment. See Note 16—Accumulated Other Comprehensive Income.

**Includes components of other comprehensive income, which are disclosed separately in the Consolidated Statement of Comprehensive Income.

Income from continuing operations and discontinued operations attributable to ConocoPhillips for the three- and six-month periods of 2012 and 2011 were as follows:


	Millions of Dollars
	Three Months Ended June 30			Six Months Ended June 30
		2012	2011		2012	2011

Income from continuing operations	$	1,733	2,284		3,958	4,588
Income from discontinued operations		534	1,118		1,246	1,842

Net Income	$	2,267	3,402		5,204	6,430

Note 12—Guarantees

At June 30, 2012, 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 Guarantee

At June 30, 2012, we have guaranteed the performance of APLNG with regard to a construction contract executed in connection with APLNG’s issuance of the Train 1 Notice to Proceed. Our maximum potential amount of future payments related to this guarantee is approximately $200 million at June 2012 exchange rates based on our 42.5 percent ownership in APLNG and would become payable if APLNG cancels the applicable construction contract and does not perform with respect to the amounts owed to the contractor. See below for additional guarantees of APLNG’s performance.

Guarantees of Joint Venture Debt

At June 30, 2012, 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 $60 million. Payment would be required if a joint venture defaults on its debt obligations.

Other Guarantees

•

In conjunction with our purchase of a 50 percent ownership interest in 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 4 to 19 years. Our maximum potential amount of future payments, or cost of volume delivery, under these guarantees is estimated to be $1,268 million ($2,836 million in the event of intentional or reckless breach) at June 2012 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 approximately $80 million at June 2012 exchange rates based on our 42.5 percent ownership in APLNG and would become payable if APLNG does not perform.

•

We have other guarantees with maximum future potential payment amounts totaling approximately $330 million, which consist primarily of a guarantee to fund the short-term cash liquidity deficit of a joint venture, a guarantee of minimum charter revenue for an LNG vessel, one small construction completion guarantee, 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 12 years or life of the venture.

Indemnifications

Over the years, we have entered into various agreements to sell ownership interests in certain corporations, joint ventures and assets that gave rise to qualifying indemnifications. Agreements associated with these sales include indemnifications for taxes, environmental liabilities, permits and licenses, employee claims, real estate indemnity against tenant defaults, and litigation. The terms of these indemnifications vary greatly. The majority of these indemnifications are related to environmental issues, the term is generally indefinite and the maximum amount of future payments is generally unlimited. The carrying amount recorded for these indemnifications at June 30, 2012, was approximately $80 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 approximately $60 million of environmental accruals for known contamination that are included in asset retirement obligations and accrued environmental costs at June 30, 2012. For additional information about environmental liabilities, see Note 13—Contingencies and Commitments.

In connection with the separation of the Downstream business, the Company entered into an Indemnification and Release Agreement with Phillips 66, see Note 2—Separation of Downstream Business. This agreement provides for cross-indemnities between Phillips 66 and ConocoPhillips and established procedures for handling claims subject to indemnification and related matters. We evaluated the impact of the indemnifications given and the Phillips 66 indemnifications received as of the separation date and concluded those fair values were immaterial.

Note 13—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.

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, 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 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 in respect of sites acquired in a purchase business combination,

which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable future costs will be incurred and these costs can be reasonably estimated. At June 30, 2012, our balance sheet included a total environmental accrual of $440 million, compared with $922 million at December 31, 2011. A significant portion of our environmental contingencies at December 31, 2011, was related to our Downstream business. See Note 2—Separation of Downstream Business, for additional information. We expect to incur a substantial amount of these expenditures within the next 30 years. We have not reduced these accruals for possible insurance recoveries. In the future, we may be involved in additional environmental assessments, cleanups and proceedings.

Legal Proceedings

Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial 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, are 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 June 30, 2012, we had performance obligations secured by letters of credit of $1,035 million (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 different arbitration hearing was held in January 2012 with the International Chamber of Commerce on ConocoPhillips’ separate claims against PDVSA for certain breaches of their Association Agreements prior to the expropriation. The arbitration process is ongoing.

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, and we are awaiting a decision. On April 24, 2012, Ecuador filed a revised supplemental counterclaim asserting environmental damages, which we believe are not material. The arbitration process is ongoing.

Note 14—Derivative and Financial Instruments

Derivative Instruments

We use derivative instruments to manage our exposure to cash flow variability from commodity price risk. We occasionally use derivatives to capture market opportunities based on our industry knowledge. Our commodity business primarily consists of natural gas, crude oil, bitumen, LNG and natural gas liquids.

Our derivative instruments are held at fair value on our consolidated balance sheet. Where these balances have the right of setoff, they are presented net. Related cash flows are recorded as operating activities on the consolidated statement of cash flows. On the consolidated income statement, realized and unrealized gains and losses are recognized either on a gross basis if directly related to our physical business or a net basis if held for trading. Gains and losses related to contracts that meet and are designated with the normal purchase normal sale exception are recognized upon settlement. We generally apply this exception to eligible crude contracts. We do not use hedge accounting for our commodity derivatives.

The following table presents the gross fair values of our commodity derivatives, excluding collateral, and the line items where they would appear on our consolidated balance sheet:


	Millions of Dollars
	June 30 2012		December 31 2011

Assets
Prepaid expenses and other current assets	$	3,074		4,433
Other assets		332		415
Liabilities
Other accruals		3,061		4,350
Other liabilities and deferred credits		362		374

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


	Millions of Dollars
	Three Months Ended June 30					Six Months Ended June 30
		2012		2011			2012		2011

Sales and other operating revenues	$	583		286			17		(131	)
Other income		1		—			(5	)	4
Purchased commodities		(619	)	(286	)		(58	)	130

The table below summarizes our material net exposures resulting from outstanding commodity derivative contracts.


	Open Position Long/(Short)
	June 30			December 31
		2012			2011

Commodity
Crude oil, refined products and natural gas liquids (millions of barrels)		(1	)		(13	)
Natural gas and power (billions of cubic feet equivalent)
Fixed price		(32	)		(57	)
Basis		200			(25	)

Financial Instruments

We have certain financial instruments on the consolidated balance sheet related to interest bearing time deposits and commercial paper. These held-to-maturity financial instruments are included in “Cash and cash equivalents” on our consolidated balance sheet if the maturities at the time we made the investments were 90 days or less; otherwise, these investments are included in “Short-term investments” on our consolidated balance sheet. These balances consisted of the following:


	Millions of Dollars
	Carrying Amount
	Cash and Cash Equivalents				Short-Term Investments
	June 30 2012		December 31 2011		June 30 2012		December 31 2011

Cash	$	641		1,169		—		—

Time Deposits
Remaining maturities from 1 to 90 days		403		4,318		—		349
Commercial Paper
Remaining maturities from 1 to 90 days		—		293		—		232

	$	1,044		5,780		—		581

In conjunction with the separation of our Downstream business, we received a special cash distribution from Phillips 66 of $7,818 million. See Note 2—Separation of Downstream Business, for additional information. At June 30, 2012, the unused amount of the special cash distribution was $5,000 million and is designated as “Restricted cash” on our consolidated balance sheet. At June 30, 2012, the funds in the restricted cash account were invested in U.S. Treasury Bills ($2,650 million), money market funds ($2,200 million) and cash ($150 million), all with maturities within 90 days from June 30, 2012.

Credit Risk

Financial instruments potentially exposed to concentrations of credit risk consist primarily of cash equivalents, over-the-counter (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 or letters of credit 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 and performance 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 June 30, 2012, and December 31, 2011, was $238 million and $237 million, respectively. No collateral was posted for June 30, 2012, and $3 million was posted for December 31, 2011. If our credit rating was lowered one level from its “A” rating (per Standard and Poor’s) on June 30, 2012, 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 $238 million of additional collateral, either with cash or letters of credit.

Note 15—Fair Value Measurement

We carry a portion of our assets and liabilities at fair value that are measured at a reporting date using an exit price (i.e., the price that would be received to sell an asset or paid to transfer a liability) and disclosed according to the quality of valuation inputs under the following hierarchy:

•

Level 1: Quoted prices (unadjusted) in an active market for identical assets or liabilities.

•

Level 2: Inputs other than quoted prices that are directly or indirectly observable.

•

Level 3: Unobservable inputs that are significant to the fair value of assets or liabilities.

The classification of an asset or liability is based on the lowest level of input significant to its fair value. Those that are initially classified as Level 3 are subsequently reported as Level 2 when the fair value derived from unobservable inputs is inconsequential to the overall fair value, or if corroborated market data becomes available. Assets and liabilities that are initially reported as Level 2 are subsequently reported as Level 3 if corroborated market data is no longer available. Transfers occur at the end of the reporting period. There were no material transfers in or out of Level 1.

Recurring Fair Value Measurement

Financial assets and liabilities reported at fair value on a recurring basis primarily include derivative instruments and certain investments to support nonqualified deferred compensation plans. The deferred compensation investments are measured at fair value using unadjusted prices available from national securities exchanges; therefore, these assets are categorized as Level 1 in the fair value hierarchy. Level 1 derivative assets and liabilities primarily represent exchange-traded futures and options that are valued using unadjusted prices available from the underlying exchange. Level 2 derivative assets and liabilities primarily represent OTC swaps, options and forward purchase and sale contracts that are valued using adjusted exchange prices, prices provided by brokers or pricing service companies that are all corroborated by market data. Level 3 derivative assets and liabilities consist of OTC swaps, options and forward purchase and sale contracts that are long term in nature and where a significant portion of fair value is calculated from underlying market data that is not readily available. The derived value uses industry standard methodologies that may consider the historical relationships among various commodities, modeled market prices, time value, volatility factors and other relevant economic measures. The use of these inputs results in management’s best estimate of fair value. As reflected in the table below, Level 3 activity was not material.

The following table summarizes the fair value hierarchy for gross financial assets and liabilities (i.e., unadjusted where the right of setoff exists for commodity derivatives accounted for at fair value on a recurring basis):


	Millions of Dollars
	June 30, 2012								December 31, 2011
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total

Assets
Deferred compensation investments	$	304		—		—		304		336		—		—		336
Commodity derivatives		2,028		1,336		40		3,404		2,807		1,947		72		4,826

Total assets	$	2,332		1,336		40		3,708		3,143		1,947		72		5,162


Liabilities
Commodity derivatives	$	2,157		1,258		6		3,421		2,970		1,722		10		4,702

Total liabilities	$	2,157		1,258		6		3,421		2,970		1,722		10		4,702

Non-Recurring Fair Value Measurement

There were no significant non-recurring fair value measurements as of June 30, 2012.

Reported Fair Value of Financial Instruments

The following are the valuation techniques and methods used to estimate the fair value of financial assets and liabilities reported on the balance sheet:

•

Cash and cash equivalents, restricted cash and short-term investments: The carrying amount reported on the balance sheet approximates fair value.

•

Accounts and notes receivable (including long-term and related parties): The carrying amount reported on the balance sheet approximates fair value. The valuation technique and methods used to estimate the fair value of the current portion of fixed-rate related party loans is consistent with Loans and advances—related parties.

•

Loans and advances—related parties: The carrying amount of floating-rate loans approximates fair value. The fair value of fixed-rate loan activity is measured using market observable data and is categorized as Level 2 in the fair value hierarchy. See Note 6—Investments, Loans and Long-Term Receivables, for additional information.

•

Accounts payable (including related parties) and floating-rate debt: The carrying amount of accounts payable and floating-rate debt reported on the balance sheet approximates fair value. The valuation technique and methods used to estimate the fair value of the current portion of the joint venture acquisition obligation is consistent with the methodology below.

•

Fixed-rate debt: The estimated fair value of fixed-rate debt is measured using prices available from a pricing service that is corroborated by market data; therefore, these liabilities are categorized as Level 2 in the fair value hierarchy.

•

Joint venture acquisition obligation—related party: Fair value is estimated based on the net present value of the future cash flows as a Level 2 fair value, discounted at June 30, 2012, and December 31, 2011, effective yield rates of 1.04 percent and 1.24 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 10—Joint Venture Acquisition Obligation, for additional information.

The following table summarizes the net fair value of financial instruments (i.e., adjusted where the right of setoff exists for commodity derivatives):

Millions of Dollars

Carrying Amount

Fair Value

June 30
2012

December 31

2011

June 30
2012

December 31
2011

Financial assets

Deferred compensation investments

304

336

304

336

Commodity derivatives

489

814

489

814

Total loans and advances—related parties

1,741

1,793

1,941

1,994

Financial liabilities

Total debt, excluding capital leases

22,992

22,592

27,667

27,065

Total joint venture acquisition obligation

3,953

4,314

4,394

4,820

Commodity derivatives

332

446

332

446

At June 30, 2012, commodity derivative assets and liabilities appear net of $28 million of obligations to return cash collateral and $202 million of rights to reclaim cash collateral, respectively. At December 31, 2011, commodity derivative assets and liabilities appear net of no obligations to return cash collateral and $244 million of rights to reclaim cash collateral.

Note 16—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

December 31, 2011*	$	(1,971	)		—		5,223			(6	)		3,246
Other comprehensive income		76			1		334			6			417
Separation of Downstream business		683			—		(469	)		—			214

June 30, 2012	$	(1,212	)		1		5,088			—			3,877

*The beginning balance of retained earnings has been restated primarily to reflect certain intercompany loans as permanently invested in 2004 and prior periods, which resulted in a $160 million increase in Foreign Currency Translation and Accumulated Other Comprehensive Income, a $15 million decrease to Total Liabilities, and a $145 million reduction in Retained Earnings. The impact on net income and earnings per share was deminimis for the three- and six-month periods ended June 30, 2012 and 2011.

There were no items within accumulated other comprehensive income related to noncontrolling interests.

Note 17—Cash Flow Information


	Millions of Dollars
	Six Months Ended June 30
	2012			2011

Cash Payments
Interest	$	383			488
Income taxes		4,696			5,348


Net Sales (Purchases) of Short-Term Investments
Short-term investments purchased	$	(497	)		(4,562	)
Short-term investments sold		1,094			2,968

	$	597			(1,594	)

Note 18—Employee Benefit Plans

In connection with the separation of the Downstream business, ConocoPhillips entered into an Employee Matters Agreement with Phillips 66, see Note 2—Separation of Downstream Business, which provides that employees of Phillips 66 will no longer participate in benefit plans sponsored or maintained by ConocoPhillips. Upon separation, the ConocoPhillips Pension Plan transferred assets and obligations to the Phillips 66 Pension Plan resulting in a net decrease in sponsored pension plan obligations of $1,098 million, a corresponding decrease in deferred income taxes of $335 million and a decrease in other comprehensive income of $570 million.

Pension and Postretirement Plans


	Millions of Dollars
	Pension Benefits												Other Benefits
	2012						2011						2012			2011

	U.S.			Int’l.			U.S.			Int’l.

Components of Net Periodic Benefit Cost
Three Months Ended June 30
Service cost	$	42			22			49			25			2			2
Interest cost		48			38			61			44			8			11
Expected return on plan assets		(56	)		(40	)		(70	)		(44	)		—			—
Amortization of prior service cost		2			(2	)		3			—			(1	)		(2	)
Recognized net actuarial (gain) loss		45			15			41			12			—			(2	)

Net periodic benefit costs	$	81			33			84			37			9			9


Six Months Ended June 30
Service cost	$	100			50			113			49			4			5
Interest cost		111			81			123			88			18			21
Expected return on plan assets		(130	)		(83	)		(140	)		(87	)		—			—
Amortization of prior service cost		4			(4	)		5			—			(2	)		(4	)
Recognized net actuarial (gain) loss		104			33			82			23			(1	)		(3	)

Net periodic benefit costs	$	189			77			183			73			19			19

During the first six months of 2012, we contributed $167 million to our domestic benefit plans and $103 million to our international benefit plans. In 2012, we expect to contribute approximately $540 million to our domestic qualified and nonqualified pension and postretirement benefit plans and $210 million to our international qualified and nonqualified pension and postretirement benefit plans.

In addition, pursuant to the Employee Matters Agreement we made certain adjustments to the exercise price and number of our stock-based compensation awards with the intention of preserving the intrinsic value of the awards prior to the separation. Outstanding options to purchase common shares of ConocoPhillips stock that were exercisable prior to the separation were adjusted so the holders of those options would then hold options to purchase common shares of both ConocoPhillips and Phillips 66 stock. Nonexercisable stock options were converted to those of the entity where the employee is working post-separation. In addition, former employee holders and a specified group of holders of stock options and restricted stock units who retired or terminated employment upon or shortly after the separation, received both adjusted ConocoPhillips awards and Phillips 66 awards. ConocoPhillips restricted stock and performance share units awarded for completed performance periods under the Performance Share Program, as well as restricted stock units held by current or former directors, were adjusted to provide holders one restricted share or restricted stock unit of Phillips 66 for every two restricted shares or restricted stock units of ConocoPhillips. Each employee holder of restricted stock and restricted stock units awarded under all other programs were adjusted to provide holders restricted shares or restricted stock units in the company that employs such employee following the separation. Adjustments to our stock-based compensation awards did not have a material impact on compensation expense.

Note 19—Related Party Transactions

Significant transactions with related parties were:


	Millions of Dollars
	Three Months Ended June 30			Six Months Ended June 30
		2012	2011		2012	2011

Operating revenues and other income	$	11	23		35	31
Purchases		93	579		254	950
Operating expenses and selling, general and administrative expenses		41	74		81	149
Net interest expense*		10	16		22	32

* We paid and/or received interest to/from various affiliates, including FCCL Partnership. See Note 6—Investments, Loans and Long-Term Receivables, for additional information on loans to affiliated companies.

Note 20—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 2—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 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. Intersegment sales are at prices that approximate market.

Analysis of Results by Operating Segment


	Millions of Dollars
	Three Months Ended June 30						Six Months Ended June 30
	2012			2011			2012			2011

Sales and Other Operating Revenues
Alaska	$	2,393			2,632			5,130			4,917

Lower 48 and Latin America		4,172			5,977			9,303			11,625
Intersegment eliminations		(41	)		(78	)		(156	)		(164	)

Lower 48 and Latin America		4,131			5,899			9,147			11,461

Canada		1,074			1,509			2,292			3,086
Intersegment eliminations		(77	)		(233	)		(213	)		(528	)

Canada		997			1,276			2,079			2,558

Europe		3,926			4,565			7,528			8,379
Intersegment eliminations		—			—			(72	)		(50	)

Europe		3,926			4,565			7,456			8,329

Asia Pacific and Middle East		1,634			2,330			3,530			4,579
Other International		895			440			1,596			1,043
LUKOIL Investment		—			—			—			—
Corporate and Other		12			34			34			69

Consolidated sales and other operating revenues	$	13,988			17,176			28,972			32,956


Net Income Attributable to ConocoPhillips
Alaska	$	551			492			1,171			1,056
Lower 48 and Latin America		119			337			374			662
Canada		(94	)		101			(643	)		128
Europe		669			533			1,058			999
Asia Pacific and Middle East		772			956			2,510			1,819
Other International		(19	)		79			67			198
LUKOIL Investment		—			—			—			239
Corporate and Other		(265	)		(214	)		(579	)		(513	)
Discontinued operations		534			1,118			1,246			1,842

Consolidated net income attributable to ConocoPhillips	$	2,267			3,402			5,204			6,430


	Millions of Dollars
		June 30 2012	December 31 2011

Total Assets
Alaska	$	11,002	10,723
Lower 48 and Latin America		27,413	25,872
Canada		20,982	20,847
Europe		13,035	12,452
Asia Pacific and Middle East		23,328	22,374
Other International		9,775	9,070
LUKOIL Investment		—	—
Corporate and Other		8,473	8,485
Discontinued operations		—	43,407

Consolidated total assets	$	114,008	153,230

Note 21—Income Taxes

Our effective tax rate from continuing operations for the second quarter of 2012 was 57 percent compared with 49 percent for the second quarter of 2011. The increase was primarily due to a larger proportion of income in higher tax rate jurisdictions in 2012.

Our effective tax rate from continuing operations for the first six months of 2012 was 53 percent compared with 50 percent for the first six months of 2011. The increase was primarily due to a larger proportion of income in higher tax rate jurisdictions and asset impairments in 2012, partially offset by gains on asset dispositions in 2012.

For both the second quarter and the first six months of 2012, the effective tax rate in excess of the domestic federal statutory rate of 35 percent was primarily due to foreign taxes.

In the United Kingdom, legislation was enacted on July 17, 2012, restricting corporate tax relief on decommissioning costs to 50 percent, retroactively effective from March 21, 2012. We anticipate our third quarter 2012 earnings will be reduced by approximately $175 million due to the remeasurement of deferred tax balances.

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.

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


	Millions of Dollars
	Three Months Ended June 30, 2012
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	$	—			4,277		—		—			—			9,711			—			13,988
Equity in earnings of affiliates		2,103			2,467		—		—			—			570			(4,611	)		529
Gain on dispositions		—			—		—		—			—			583			—			583
Other income		—			24		—		—			—			42			—			66
Intercompany revenues		18			245		12		23			9			1,615			(1,922	)		—

Total Revenues and Other Income		2,121			7,013		12		23			9			12,521			(6,533	)		15,166

Costs and Expenses
Purchased commodities		—			3,767		—		—			—			3,287			(1,296	)		5,758
Production and operating expenses		—			337		—		—			—			1,550			(4	)		1,883
Selling, general and administrative expenses		3			167		—		—			—			66			(1	)		235
Exploration expenses		—			96		—		—			—			174			—			270
Depreciation, depletion and amortization		—			204		—		—			—			1,422			—			1,626
Impairments		—			—		—		—			—			82			—			82
Taxes other than income taxes		—			68		—		—			—			838			—			906
Accretion on discounted liabilities		—			13		—		—			—			92			—			105
Interest and debt expense		586			90		11		20			8			103			(621	)		197
Foreign currency transaction (gains) losses		(2	)		54		—		(23	)		(15	)		1			—			15

Total Costs and Expenses		587			4,796		11		(3	)		(7	)		7,615			(1,922	)		11,077

Income from continuing operations before income taxes		1,534			2,217		1		26			16			4,906			(4,611	)		4,089
Provision for income taxes		(199	)		114		1		—			1			2,417			—			2,334

Income From Continuing Operations		1,733			2,103		—		26			15			2,489			(4,611	)		1,755
Income from discontinued operations		534			534		—		—			—			280			(814	)		534

Net income		2,267			2,637		—		26			15			2,769			(5,425	)		2,289
Less: net income attributable to noncontrolling interests		—			—		—		—			—			(22	)		—			(22	)

Net Income Attributable to ConocoPhillips	$	2,267			2,637		—		26			15			2,747			(5,425	)		2,267

Comprehensive Income Attributable to ConocoPhillips	$	2,276			3,168		—		(2	)		4			1,777			(5,425	)		1,798


Income Statement	Three Months Ended June 30, 2011
Revenues and Other Income
Sales and other operating revenues	$	—			5,337		—		—			—			11,839			—			17,176
Equity in earnings of affiliates		2,524			2,208		—		—			—			353			(4,710	)		375
Gain on dispositions		—			—		—		—			—			35			—			35
Other income		—			38		—		—			—			44			—			82
Intercompany revenues		1			566		12		23			8			428			(1,038	)		—

Total Revenues and Other Income		2,525			8,149		12		23			8			12,699			(5,748	)		17,668

Costs and Expenses
Purchased commodities		—			4,558		—		—			—			3,737			(614	)		7,681
Production and operating expenses		—			273		—		—			—			1,335			(13	)		1,595
Selling, general and administrative expenses		4			137		—		—			—			63			(1	)		203
Exploration expenses		—			72		—		—			—			192			—			264
Depreciation, depletion and amortization		—			219		—		—			—			1,627			—			1,846
Taxes other than income taxes		—			73		—		—			—			1,125			—			1,198
Accretion on discounted liabilities		—			11		—		—			—			96			—			107
Interest and debt expense		367			118		11		20			8			128			(410	)		242
Foreign currency transaction (gains) losses		—			1		—		19			11			(13	)		—			18

Total Costs and Expenses		371			5,462		11		39			19			8,290			(1,038	)		13,154

Income from continuing operations before income taxes		2,154			2,687		1		(16	)		(11	)		4,409			(4,710	)		4,514
Provision for income taxes		(129	)		163		1		(2	)		(2	)		2,183			—			2,214

Income (Loss) from Continuing Operations		2,283			2,524		—		(14	)		(9	)		2,226			(4,710	)		2,300
Income from discontinued operations		1,119			1,119		—		—			—			994			(2,113	)		1,119

Net income (loss)		3,402			3,643		—		(14	)		(9	)		3,220			(6,823	)		3,419
Less: net income attributable to noncontrolling interests		—			—		—		—			—			(17	)		—			(17	)

Net Income (Loss) Attributable to ConocoPhillips	$	3,402			3,643		—		(14	)		(9	)		3,203			(6,823	)		3,402

Comprehensive Income Attributable to ConocoPhillips	$	3,402			3,677		—		(4	)		(5	)		3,733			(6,823	)		3,980


	Millions of Dollars
	Six Months Ended June 30, 2012
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	$	—			8,569			—		—			—			20,403			—			28,972
Equity in earnings of affiliates		4,679			5,230			—		—			—			1,028			(9,922	)		1,015
Gain on dispositions		—			—			—		—			—			1,523			—			1,523
Other income		1			55			—		—			—			70			—			126
Intercompany revenues		19			685			23		45			17			2,440			(3,229	)		—

Total Revenues and Other Income		4,699			14,539			23		45			17			25,464			(13,151	)		31,636

Costs and Expenses
Purchased commodities		—			7,574			—		—			—			6,304			(2,000	)		11,878
Production and operating expenses		—			604			—		—			—			2,936			(19	)		3,521
Selling, general and administrative expenses		8			430			—		—			—			133			(9	)		562
Exploration expenses		—			186			—		—			—			763			—			949
Depreciation, depletion and amortization		—			408			—		—			—			2,841			—			3,249
Impairments		—			—			—		—			—			296			—			296
Taxes other than income taxes		—			150			—		—			—			1,857			—			2,007
Accretion on discounted liabilities		—			26			—		—			—			186			—			212
Interest and debt expense		1,126			171			21		39			16			215			(1,201	)		387
Foreign currency transaction (gains) losses		(2	)		26			—		(12	)		1			6			—			19

Total Costs and Expenses		1,132			9,575			21		27			17			15,537			(3,229	)		23,080

Income from continuing operations before income taxes		3,567			4,964			2		18			—			9,927			(9,922	)		8,556
Provision for income taxes		(389	)		285			1		6			—			4,657			—			4,560

Income From Continuing Operations		3,956			4,679			1		12			—			5,270			(9,922	)		3,996
Income from discontinued operations		1,248			1,248			—		—			—			995			(2,243	)		1,248

Net income		5,204			5,927			1		12			—			6,265			(12,165	)		5,244
Less: net income attributable to noncontrolling interests		—			—			—		—			—			(40	)		—			(40	)

Net Income Attributable to ConocoPhillips	$	5,204			5,927			1		12			—			6,225			(12,165	)		5,204

Comprehensive Income Attributable to ConocoPhillips	$	5,213			6,539			1		17			2			6,014			(12,165	)		5,621


Income Statement	Six Months Ended June 30, 2011
Revenues and Other Income
Sales and other operating revenues	$	—			10,319			—		—			—			22,637			—			32,956
Equity in earnings of affiliates		5,034			4,808			—		—			—			639			(9,780	)		701
Gain on dispositions		—			265			—		—			—			383			—			648
Other income		—			69			—		—			—			97			—			166
Intercompany revenues		2			881			23		46			17			1,166			(2,135	)		—

Total Revenues and Other Income		5,036			16,342			23		46			17			24,922			(11,915	)		34,471

Costs and Expenses
Purchased commodities		—			9,070			—		—			—			6,893			(1,324	)		14,639
Production and operating expenses		—			562			—		—			—			2,666			(54	)		3,174
Selling, general and administrative expenses		9			317			—		—			—			133			(8	)		451
Exploration expenses		—			126			—		—			—			314			—			440
Depreciation, depletion and amortization		—			444			—		—			—			3,250			—			3,694
Taxes other than income taxes		—			160			—		—			—			1,922			—			2,082
Accretion on discounted liabilities		—			23			—		—			—			189			—			212
Interest and debt expense		682			237			21		39			16			253			(749	)		499
Foreign currency transaction (gains) losses		—			(16	)		—		56			8			(23	)		—			25

Total Costs and Expenses		691			10,923			21		95			24			15,597			(2,135	)		25,216

Income from continuing operations before income taxes		4,345			5,419			2		(49	)		(7	)		9,325			(9,780	)		9,255
Provision for income taxes		(241	)		385			1		(1	)		8			4,486			—			4,638

Income (Loss) From Continuing Operations		4,586			5,034			1		(48	)		(15	)		4,839			(9,780	)		4,617
Income from discontinued operations		1,844			1,844			—		—			—			1,399			(3,243	)		1,844

Net income (loss)		6,430			6,878			1		(48	)		(15	)		6,238			(13,023	)		6,461
Less: net income attributable to noncontrolling interests		—			—			—		—			—			(31	)		—			(31	)

Net Income (Loss) Attributable to ConocoPhillips	$	6,430			6,878			1		(48	)		(15	)		6,207			(13,023	)		6,430

Comprehensive Income Attributable to ConocoPhillips	$	6,430			6,971			1		1			5			7,397			(13,023	)		7,782


	Millions of Dollars
	June 30, 2012
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	$	—			12		3		44			1			984		—			1,044
Restricted cash		5,000			—		—		—			—			—		—			5,000
Accounts and notes receivable		68			6,262		—		—			—			12,332		(10,943	)		7,719
Inventories		—			196		—		—			—			982		—			1,178
Prepaid expenses and other current assets		20			1,318		—		1			—			1,147		(515	)		1,971

Total Current Assets		5,088			7,788		3		45			1			15,445		(11,458	)		16,912
Investments, loans and long-term receivables*		76,771			117,652		760		1,422			568			44,923		(217,127	)		24,969
Net properties, plants and equipment		—			8,416		—		—			—			62,811		—			71,227
Intangibles		—			9		—		—			—			2		—			11
Other assets		62			206		—		2			3			616		—			889

Total Assets	$	81,921			134,071		763		1,469			572			123,797		(228,585	)		114,008

Liabilities and Stockholders’ Equity
Accounts payable	$	—			14,521		—		—			—			5,494		(10,919	)		9,096
Short-term debt		3,222			4		750		—			—			203		—			4,179
Accrued income and other taxes		—			315		—		4			—			3,039		(539	)		2,819
Employee benefit obligations		—			417		—		—			—			177		—			594
Other accruals		244			259		9		15			6			1,139		—			1,672

Total Current Liabilities		3,466			15,516		759		19			6			10,052		(11,458	)		18,360
Long-term debt		9,453			3,220		—		1,250			499			4,407		—			18,829
Asset retirement obligations and accrued environmental costs		—			1,235		—		—			—			6,989		—			8,224
Joint venture acquisition obligation		—			—		—		—			—			3,201		—			3,201
Deferred income taxes		55			274		—		15			9			13,245		—			13,598
Employee benefit obligations		—			2,164		—		—			—			709		—			2,873
Other liabilities and deferred credits*		29,629			24,887		—		92			30			16,519		(68,677	)		2,480

Total Liabilities		42,603			47,296		759		1,376			544			55,122		(80,135	)		67,565
Retained earnings		27,378			20,276		2		(58	)		(55	)		29,920		(43,707	)		33,756
Other common stockholders’ equity		11,940			66,499		2		151			83			38,283		(104,743	)		12,215
Noncontrolling interests		—			—		—		—			—			472		—			472

Total Liabilities and Stockholders’ Equity	$	81,921			134,071		763		1,469			572			123,797		(228,585	)		114,008


Balance Sheet	December 31, 2011**
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.

**Certain amounts have been restated to reflect a prior period adjustment. See Note 16—Accumulated Other Comprehensive Income, in the Notes to Consolidated Financial Statements.


	Millions of Dollars
	Six Months Ended June 30, 2012
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 continuing operating activities	$	3,221			8,449			2		7			—			4,227			(9538	)		6,368
Net cash provided by (used in) discontinued operations		—			285			—		—			—			(121	)		—			164

Net Cash Provided by Operating Activities		3,221			8,734			2		7			—			4,106			(9,538	)		6,532

Cash Flows From Investing Activities
Capital expenditures and investments		(317	)		(5,217	)		—		—			—			(7,009	)		4,685			(7,858	)
Proceeds from asset dispositions		14			1			—		—			—			1,565			(14	)		1,566
Net purchases of short-term investments		—			—			—		—			—			597			—			597
Long-term advances/loans—related parties		—			—			—		—			—			(2,900	)		2,906			6
Collection of advances/loans—related parties		—			102			—		—			—			28			(82	)		48
Other		—			4			—		—			—			16			—			20

Net cash used in continuing investing activities		(303	)		(5,110	)		—		—			—			(7,703	)		7,495			(5,621	)
Net cash provided by (used in) discontinued operations		—			(232	)		—		—			—			8,028			(8,100	)		(304	)

Net Cash Provided by (Used in) Investing Activities		(303	)		(5,342	)		—		—			—			325			(605	)		(5,925	)

Cash Flows From Financing Activities
Issuance of debt		831			3,000			—		—			—			6			(3,006	)		831
Repayment of debt		—			(8,215	)		—		—			—			(113	)		8,281			(47	)
Special cash distribution from Phillips 66		7,818			—			—		—			—			—			—			7,818
Change in restricted cash		(5,000	)		—			—		—			—			—			—			(5,000	)
Issuance of company common stock		45			—			—		—			—			—			—			45
Repurchase of company common stock		(4,949	)		—			—		—			—			—			—			(4,949	)
Dividends paid on common stock		(1,661	)		—			—		—			—			(4,082	)		4,082			(1,661	)
Other		(2	)		41			—		—			—			(408	)		—			(369	)

Net cash used in continuing financing activities		(2,918	)		(5,174	)		—		—			—			(4,597	)		9,357			(3,332	)
Net cash used in discontinued operations		—			(227	)		—		—			—			(2,578	)		786			(2,019	)

Net Cash Used in Financing Activities		(2,918	)		(5,401	)		—		—			—			(7,175	)		10,143			(5,351	)

Effect of Exchange Rate Changes on Cash and Cash Equivalents		—			(7	)		—		—			—			15			—			8

Net Change in Cash and Cash Equivalents		—			(2,016	)		2		7			—			(2,729	)		—			(4,736	)
Cash and cash equivalents at beginning of period		—			2,028			1		37			1			3,713			—			5,780

Cash and Cash Equivalents at End of Period	$	—			12			3		44			1			984			—			1,044


Statement of Cash Flows	Six Months Ended June 30, 2011
Cash Flows From Operating Activities
Net cash provided by (used in) continuing operating activities	$	6,548			(1,033	)		2		6			(6	)		3,671			(2,835	)		6,353
Net cash provided by (used in) discontinued operations		—			(162	)		—		—			—			2,031			(1	)		1,868

Net Cash Provided by (Used in) Operating Activities		6,548			(1,195	)		2		6			(6	)		5,702			(2,836	)		8,221

Cash Flows From Investing Activities
Capital expenditures and investments		—			(512	)		—		—			—			(4,877	)		(1	)		(5,390	)
Proceeds from asset dispositions		—			321			—		—			—			1,542			—			1,863
Net purchases of short-term investments					—			—		—			—			(1,594	)		—			(1,594	)
Long-term advances/loans—related parties		—			(14	)		—		(4	)		—			(2,077	)		2,092			(3	)
Collection of advances/loans—related parties		—			311			—		—			—			1,476			(1,737	)		50
Other		—			5			—		—			—			25			2			32

Net cash provided by (used in) continuing investing activities		—			111			—		(4	)		—			(5,505	)		356			(5,042	)
Net cash provided by (used in) discontinued operations		—			158			—		—			—			(10	)		—			148

Net Cash Provided by (Used in) Investing Activities		—			269			—		(4	)		—			(5,515	)		356			(4,894	)

Cash Flows From Financing Activities
Issuance of debt		—			2,073			—		—			4			15			(2,092	)		—
Repayment of debt		—			(1,805	)		—		—			—			(318	)		1,745			(378	)
Issuance of company common stock		99			—			—		—			—			—			—			99
Repurchase of company common stock		(4,785	)		—			—		—			—			—			—			(4,785	)
Dividends paid on common stock		(1,861	)		—			—		—			—			(2,553	)		2,553			(1,861	)
Other		(1	)		45			—		—			—			(401	)		—			(357	)

Net cash provided by (used in) continuing financing activities		(6,548	)		313			—		—			4			(3,257	)		2,206			(7,282	)
Net cash provided by (used in) discontinued operations		—			—			—		—			—			(288	)		274			(14	)

Net Cash Provided by (Used in) Financing Activities		(6,548	)		313			—		—			4			(3,545	)		2,480			(7,296	)

Effect of Exchange Rate Changes on Cash and Cash Equivalents		—			(10	)		—		—			—			30			—			20

Net Change in Cash and Cash Equivalents		—			(623	)		2		2			(2	)		(3,328	)		—			(3,949	)
Cash and cash equivalents at beginning of period		—			718			—		29			4			8,703			—			9,454

Cash and Cash Equivalents at End of Period	$	—			95			2		31			2			5,375			—			5,505

Item 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis is the company’s analysis of its financial performance and of significant trends that may affect future performance. It should be read in conjunction with the financial statements and notes. It contains forward-looking statements including, without limitation, statements relating to the company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the company’s disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on page 52.

Due to the separation of our downstream businesses on April 30, 2012, which is reported as discontinued operations, income (loss) from continuing operations is more representative of ConocoPhillips as an independent exploration and production company. The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to income (loss) from continuing operations.

BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW

ConocoPhillips is the world’s largest independent exploration and production (E&P) company, based on proved reserves and production of liquids and natural gas. Headquartered in Houston, Texas, we have operations in 30 countries. At June 30, 2012, we had approximately 16,500 employees worldwide and total assets of $114 billion.

The Separation

On April 30, 2012, we completed the separation of our downstream businesses into an independent, publicly traded company, Phillips 66. Our refining, marketing and transportation businesses, most of our Midstream segment, our Chemicals segment, as well as our power generation and certain technology operations included in our Emerging Businesses segment, were transferred to Phillips 66. Results of operations related to Phillips 66 have been classified as discontinued operations in all periods presented in this Form 10-Q. For additional information, see Note 2—Separation of Downstream Business, in the Notes to Consolidated Financial Statements.

Business Environment

As an independent E&P company, we are now solely focused on our core business of exploring for, developing and producing oil and natural gas globally. Our commitment to safety and environmental stewardship, operating excellence and financial responsibility has not changed. As part of our strategic plan, we will continue to focus on improving our financial position and increasing shareholder returns through production and margin growth, portfolio optimization and maintaining sector-leading dividend distributions. In order to remain competitive, we must continually develop and replenish a portfolio of projects which offer attractive financial returns on our investment. We plan to continue to evaluate our assets regularly to determine whether they fit our strategic plans or should be sold or otherwise disposed, and we remain on track to raise $8–$10 billion from noncore asset sales during 2012 and 2013. For the first half of 2012, we have generated proceeds of approximately $1.6 billion as part of this asset disposition program, which mainly included the sale of the Vietnam business and the Alba and Statfjord fields in the North Sea.

Because we participate in a capital-intensive industry, we must often invest significant capital dollars to acquire acreage, explore for new oil and gas fields, develop newly discovered fields and maintain existing fields. We expect our capital spending will be approximately $16 billion in 2012. Over the next five years, we plan to execute a disciplined capital program of approximately $15 billion per year, supporting our reserve replacement target of more than 100 percent. From 2013 forward, we expect to generate 3 to 5 percent annual production volume and margin growth from major development projects already underway in the United States, Canada, United Kingdom and Norwegian North Sea, Malaysia and Australia.

The most significant factors impacting our profitability and related reinvestment of our operating cash flows into our business are the prices for crude oil and natural gas. The prices for these commodity products are subject to factors external to our company, over which we have no control. These prices are supply- and demand-based and can be very volatile; therefore, our strategy is to maintain a core portfolio of low-risk, high-return projects from legacy assets, coupled with a portfolio of projects which offer growth opportunities, such as unconventional plays, deepwater and arctic drilling and liquefied natural gas (LNG).

The following table depicts the average benchmark prices for West Texas Intermediate (WTI) crude oil, Dated Brent crude oil and U.S. Henry Hub natural gas:


	Dollars Per Unit
	Three Months Ended June 30				Six Months Ended June 30
	2012		2011		2012		2011

Market Indicators
WTI (per barrel)	$	93.44		102.44		98.21		98.21
Dated Brent (per barrel)		108.19		117.36		113.34		111.16
U.S. Henry Hub first of month (per million British thermal units)		2.21		4.32		2.47		4.21

Industry crude prices for WTI decreased 9 percent in the second quarter of 2012, compared with the second quarter of 2011, and remained flat in the first six months of 2012, compared with the first six months of 2011, while Brent prices decreased 8 percent in the second quarter of 2012 and increased 2 percent in the first six months of 2012. Global oil prices weakened during the second quarter of 2012, as production expanded and demand eased slightly, largely due to concerns about continued slow economic growth in much of the world and the European sovereign debt crisis. WTI traded at a discount to Brent throughout 2011 and 2012, mainly due to high inventory levels and excess crude supply in the U.S. Midcontinent market.

Henry Hub natural gas prices decreased 49 percent in the second quarter of 2012, compared with the second quarter of 2011, and 41 percent in the first six months of 2012. U.S. natural gas prices remained depressed in 2012, mainly due to high inventory levels, a warmer-than-normal winter and sustained production from shale plays. Prolonged low U.S. natural gas prices could have an adverse effect on our results of operations. The expansion in shale production has also helped boost supplies of natural gas liquids, resulting in downward pressure on natural gas liquids prices in the United States. As a result, our domestic realized natural gas liquids price declined 19 percent in the first half of 2012, compared with the same period of 2011.

Key Operating and Financial Highlights

Significant highlights during the second quarter of 2012 included the following:

•

On April 30, 2012, we completed the separation of our downstream businesses, creating two independent energy companies, ConocoPhillips and Phillips 66.

•

Achieved production of 1.54 million barrels of oil equivalent per day and generated earnings of $1,755 million in the second quarter of 2012.

•

Repurchased 52 million ConocoPhillips shares, representing 4 percent of our outstanding shares.

•

Paid a quarterly dividend of 66 cents per share, consistent with pre-separation dividends.

•

Continued progress on North American unconventional programs.

•

Initiated exploratory drilling and acquired additional leases in deepwater Gulf of Mexico.

•

Progressed the Australia Pacific LNG Project with sanction of the second train in early July 2012.

•

Completed the disposition of the Alba and Statfjord fields.

Outlook

Our production for the third quarter of 2012 is estimated to be 1.475 million to 1.525 million barrels of oil equivalent per day (BOED). We expect third-quarter production will be negatively impacted by planned downtime in Alaska and Canada. Our full-year production estimate is now 1.565 million to 1.585 million BOED. Other factors which may impact production include the timing of asset dispositions and the pace of production ramp-up at the Peng Lai fields in Bohai Bay.

RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three- and six-month periods ended June 30, 2012, is based on a comparison with the corresponding period of 2011.

Consolidated Results

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. Our LUKOIL Investment represents our prior investment in the ordinary shares of OAO LUKOIL, which was sold 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 related to the separation and certain technology activities, net of licensing revenues.

A summary of income (loss) from continuing operations by business segment follows:


	Millions of Dollars
	Three Months Ended June 30						Six Months Ended June 30
	2012			2011			2012			2011

Alaska	$	551			492			1,171			1,056
Lower 48 and Latin America		119			337			374			662
Canada		(94	)		101			(643	)		128
Europe		669			533			1,058			999
Asia Pacific and Middle East		794			972			2,548			1,848
Other International		(19	)		79			67			198
LUKOIL Investment		—			—			—			239
Corporate and Other		(265	)		(214	)		(579	)		(513	)

Income from continuing operations	$	1,755			2,300			3,996			4,617

Earnings for ConocoPhillips decreased 24 percent in the second quarter of 2012, while earnings for the six-month period ended June 30, 2012, decreased 13 percent. Lower earnings in the second quarter of 2012 primarily resulted from:

•

Lower volumes, largely due to reduced production in China, dispositions and planned downtime.

•

Lower prices.

•

Higher operating expenses, including an $89 million after-tax charge related to the Bohai Bay settlement.

These items were partially offset by:

•

Higher gains from asset sales of $281 million after-tax, compared with gains of $27 million after-tax in the second quarter of 2011.

•

Lower production taxes and depreciation, depletion and amortization (DD&A) expenses, mainly as a result of lower volumes.

The decrease in earnings for the six-month period of 2012 was primarily due to:

•

Lower volumes, largely due to reduced production in China, dispositions and planned downtime.

•

Higher impairments. Non-cash impairments for the six-month period of 2012 totaled $550 million after-tax.

•

Lower natural gas prices.

•

Higher operating expenses, which included the $89 million after-tax charge related to the Bohai Bay settlement and $73 million of after-tax separation costs.

These items were partially offset by:

•

Higher gains from asset sales of $1,220 million after-tax, compared with gains of $419 million after-tax in the comparative period of 2011.

•

Lower DD&A expenses, mainly as a result of lower volumes.

•

Higher crude oil and LNG prices.

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

Income Statement Analysis

Sales and other operating revenues for the second quarter and six-month period of 2012 decreased 19 percent and 12 percent, respectively, mainly due to lower crude oil, natural gas and LNG volumes and lower natural gas prices. Lower crude oil prices also contributed to the decrease in the second quarter of 2012.

Equity in earnings of affiliates for the second quarter and six-month period of 2012 increased 41 percent and 45 percent, respectively. The increases in both periods primarily resulted from:

•

Improved earnings from Qatar Liquefied Gas Company Limited (3) (QG3), primarily due to higher LNG prices and a $72 million tax-related adjustment.

•

The absence of the $83 million before-tax write-off of our investment associated with the cancellation of the Denali gas pipeline project in the second quarter of 2011.

These increases in equity earnings were partially offset by lower earnings from Naryanmarneftegaz (NMNG), largely due to lower volumes. Additionally, FCCL Partnership experienced lower earnings in the second quarter of 2012, primarily as a result of lower bitumen prices, partially offset by higher volumes.

Gain on dispositions for the second quarter and six-month period of 2012 were $583 million and $1,523 million, respectively, compared with gains of $35 million and $648 million for the respective periods in 2011. Gains realized in both periods of 2012 included the disposition of our Statfjord and Alba fields located in the North Sea. Additionally, gains realized in the six-month period of 2012 mainly included the disposition of our Vietnam business, partially offset by the sale of certain E&P assets located in the Lower 48 and the remaining divestiture of our LUKOIL shares in the six-month period of 2011.

Purchased commodities decreased 25 percent and 19 percent in the second quarter and six-month period of 2012, respectively, largely as a result of lower U.S. natural gas prices, partly offset by higher purchased volumes.

Production and operating expenses increased 18 percent in the second quarter and 11 percent in the six-month period of 2012, mostly due to increased operating expenses in China and planned downtime at our Bayu-Undan Field and Darwin LNG facility.

Selling, general and administrative expenses increased 16 percent and 25 percent in the second quarter and six-month period of 2012, mainly as a result of ongoing costs associated with the separation of Phillips 66.

Exploration expenses increased $509 million in the six-month period of 2012. The increase was mostly due to the impairment of undeveloped leasehold costs associated with the Mackenzie Gas Project as a result of the indefinite suspension of the project in the first quarter of 2012.

DD&A decreased 12 percent in both the second quarter and six-month period of 2012. The decreases were mainly due to lower production volumes as a result of asset dispositions and lower production in China, partially offset by higher production volumes in the Lower 48.

Impairments for the second quarter of 2012 increased $82 million, primarily due to an increase in the asset retirement obligation for the Don Field in the United Kingdom, which has ceased production. Impairments in the six-month period of 2012 increased $296 million, mainly due to the $213 million impairment of capitalized project development costs associated with the Mackenzie Gas Project in the first quarter of 2012, as well as the Don Field impairment.

Taxes other than income taxes decreased 24 percent in the second quarter 2012, primarily due to lower production taxes as a result of lower crude oil prices and volumes.

Interest and debt expense for the second quarter and six-month period of 2012 decreased 19 percent and 22 percent, respectively, primarily due to higher capitalized interest on projects and lower interest expense due to lower debt levels.

See Note 21—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our provision for income taxes and effective tax rate.

Summary Operating Statistics


	Three Months Ended June 30				Six Months Ended June 30
	2012		2011		2012		2011

Average Net Production
Crude oil (MBD)*		608		668		629		692
Natural gas liquids (MBD)		154		146		160		145
Bitumen (MBD)		88		67		86		66
Natural gas (MMCFD)**		4,153		4,552		4,287		4,611


Total Production (MBOED)***		1,542		1,640		1,590		1,672


		Dollars Per Unit
Average Sales Prices
Crude oil (per barrel)	$	105.56		112.95		108.95		105.42
Natural gas liquids (per barrel)		43.55		56.88		48.90		54.62
Bitumen (per barrel)		51.38		65.74		55.89		60.44
Natural gas (per thousand cubic feet)		4.41		5.50		4.61		5.36


		Millions of Dollars
Exploration Expenses
General administrative; geological and geophysical; and lease rentals	$	154		175		315		301
Leasehold impairment		52		41		564		82
Dry holes		64		48		70		57

	$	270		264		949		440

*Thousands of barrels per day.

**Millions of cubic feet per day. Represents quantities available for sale and excludes gas equivalent of natural gas liquids included above.

***Thousands of barrels of oil equivalent per day.

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. At June 30, 2012, our operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, offshore Timor-Leste in the Timor Sea, Indonesia, China, Libya, Nigeria, Algeria, Qatar and Russia.

Total production averaged 1,542 MBOED in the second quarter of 2012, a decrease of 6 percent compared with the second quarter of 2011. Production for the six-month period of 2012 averaged 1,590 MBOED, down 5 percent from the corresponding period of 2011. The decreases in both periods of 2012 primarily resulted from normal field decline, dispositions, reduced production in China and natural gas curtailments in North America. In addition, higher downtime in the second quarter of 2012 contributed to the decrease in production. These decreases were partly offset by additional production from major projects, mainly from FCCL and shale plays in the Lower 48, the ramp-up of activity in Libya following a period of civil unrest in 2011, and increased drilling programs.

Segment Results

Alaska


	Three Months Ended June 30				Six Months Ended June 30
	2012		2011		2012		2011

Income from Continuing Operations (millions of dollars)	$	551		492		1,171		1,056


Average Net Production
Crude oil (MBD)		190		207		199		203
Natural gas liquids (MBD)		16		16		17		16
Natural gas (MMCFD)		56		62		57		65


Total Production (MBOED)		215		233		226		230


Average Sales Prices
Crude oil (dollars per barrel)	$	112.38		113.75		112.28		104.26
Natural gas (dollars per thousand cubic feet)		3.93		4.66		4.31		4.28

The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids, natural gas and LNG. As of June 30, 2012, Alaska contributed 25 percent of our worldwide liquids production and 1 percent of our natural gas production.

Our Alaska operations reported earnings of $551 million in the second quarter of 2012, a 12 percent increase compared with the same period in 2011. Earnings for the six-month period of 2012 were $1,171 million, an 11 percent increase compared with the same period in 2011. Earnings in both the second quarter and six-month period of 2012 benefitted from additional sales of LNG, in addition to the absence of the $54 million after-tax impairment of our investment associated with the cancellation of the Denali gas pipeline project in the second quarter of 2011. In addition, second quarter 2012 earnings improved due to lower production taxes, mainly as a result of lower crude oil production. These increases were partially offset by lower crude oil volumes and higher operating expenses. Earnings in the six-month period of 2012 increased primarily as a result of higher crude oil prices and lower DD&A, partially offset by increased production taxes, lower crude oil volumes and higher operating expenses.

Production averaged 215 MBOED in the second quarter of 2012, a decrease of 8 percent compared with the second quarter of 2011. Production for the six-month period of 2012 was 226 MBOED, a 2 percent decrease compared with the corresponding period in 2011. The decreases in both periods of 2012 were mainly due to normal field decline, partly offset by increased drilling activity on the Western North Slope. Additionally, the six-month period of 2012 experienced less unplanned downtime.

Lower 48 and Latin America


	Three Months Ended June 30				Six Months Ended June 30
	2012		2011		2012		2011

Income from Continuing Operations (millions of dollars)	$	119		337		374		662


Average Net Production
Crude oil (MBD)		115		88		116		86
Natural gas liquids (MBD)		83		72		83		69
Natural gas (MMCFD)		1,456		1,589		1,479		1,556


Total Production (MBOED)		441		425		446		414


Average Sales Prices
Crude oil (dollars per barrel)	$	89.61		99.70		94.34		94.05
Natural gas liquids (dollars per barrel)		34.62		51.45		39.79		48.82
Natural gas (dollars per thousand cubic feet)		2.10		4.22		2.38		4.16

As of June 30, 2012, Lower 48 and Latin America contributed 23 percent of our worldwide liquids production and 34 percent of our natural gas production. The Lower 48 and Latin America segment primarily consists of operations located in the U.S. Lower 48 states. Also included in this segment is our 39 percent equity interest in Phoenix Park Gas Processors Limited, which processes natural gas in Trinidad and markets natural gas liquids in the Atlantic Basin, and the Wingate fractionation plant located in Gallup, New Mexico.

Lower 48 and Latin America operations reported earnings of $119 million in the second quarter of 2012, a 65 percent decrease compared with the same period in 2011. Earnings for the six-month period of 2012 were $374 million, a 44 percent decrease compared with the same period in 2011. The decreases for both periods of 2012 were primarily the result of lower natural gas and natural gas liquids prices, higher DD&A and operating expenses, partially offset by higher crude oil and natural gas liquids volumes. Lower gains from asset dispositions also contributed to the decrease in earnings for the six-month period of 2012.

Lower 48 production averaged 441 MBOED in the second quarter of 2012, a 4 percent increase compared with the second quarter of 2011. Production for the six-month period of 2012 was 446 MBOED, an 8 percent increase compared with the same period in 2011. The increases in both periods of 2012 were mainly due to new production, primarily from the Eagle Ford, Bakken and Permian areas, and improved drilling and well performance, partially offset by normal field decline. The six-month period of 2012 also experienced higher unplanned downtime.

Canada


	Three Months Ended June 30					Six Months Ended June 30
	2012			2011		2012			2011

Income (Loss) from Continuing Operations (millions of dollars)	$	(94	)		101		(643	)		128


Average Net Production
Crude oil (MBD)		14			11		13			12
Natural gas liquids (MBD)		22			25		24			25
Bitumen (MBD)
Consolidated operations		11			8		11			9
Equity affiliates		77			59		75			57

Total bitumen		88			67		86			66
Natural gas (MMCFD)		864			947		864			946


Total Production (MBOED)		268			262		267			261


Average Sales Prices
Crude oil (dollars per barrel)	$	74.76			94.19		79.09			86.07
Natural gas liquids (dollars per barrel)		48.66			60.23		51.60			57.27
Bitumen (dollars per barrel)
Consolidated operations		54.75			56.91		59.55			51.99
Equity affiliates		50.85			67.05		55.34			61.90
Total bitumen		51.38			65.74		55.89			60.44
Natural gas (dollars per thousand cubic feet)		1.61			3.74		1.79			3.67

Our Canadian operations comprise mainly natural gas fields in western Canada and oil sands projects in the Athabasca Region of northeastern Alberta. As of June 30, 2012, Canada contributed 14 percent of our worldwide liquids production and 20 percent of our natural gas production.

Canada operations reported losses of $94 million and $643 million in the second quarter and six-month period of 2012, reductions of $195 million and $771 million, respectively. Earnings in the six-month period of 2012 were impacted by the $520 million after-tax impairment of the Mackenzie Gas Project and associated undeveloped leaseholds. In addition, the decreases in both periods of 2012 mainly reflected lower natural gas and bitumen prices, lower natural gas volumes and lower gains from asset dispositions. These decreases were partially offset by higher bitumen volumes and lower DD&A.

Average production increased 2 percent in the second quarter and six-month period of 2012. The increases in both periods were largely due to the ramp-up of production from Christina Lake Phase C in our FCCL venture and lower planned and unplanned downtime, partly offset by the impact of asset dispositions and natural gas curtailments.

FCCL

In May 2012, we received approval from the Alberta government to proceed with the Narrows Lake oil sands project. Initial production is anticipated in 2017.

Europe


	Three Months Ended June 30				Six Months Ended June 30
	2012		2011		2012		2011

Income from Continuing Operations (millions of dollars)	$	669		533		1,058		999


Average Net Production
Crude oil (MBD)		138		168		147		176
Natural gas liquids (MBD)		8		12		9		12
Natural gas (MMCFD)		540		587		586		669


Total Production (MBOED)		236		278		254		300


Average Sales Prices
Crude oil (dollars per barrel)	$	109.89		117.40		115.35		111.26
Natural gas liquids (dollars per barrel)		54.81		60.04		56.80		59.87
Natural gas (dollars per thousand cubic feet)		9.52		9.57		9.77		9.02

The Europe segment consists of operations principally located in the Norwegian and U.K. sectors of the North Sea, as well as exploration activities in Poland and Greenland. As of June 30, 2012, our Europe operations contributed 18 percent of our worldwide liquids production and 14 percent of our natural gas production.

Earnings for our Europe operations were $669 million in the second quarter of 2012, a 26 percent increase compared with the same period in 2011. Earnings for the six-month period of 2012 were $1,058 million, a 6 percent increase compared with the same period in 2011. The increases for both periods of 2012 were primarily the result of the $285 million after-tax gain on sale of our interests in the Statfjord and Alba fields, lower DD&A and gains on foreign currency transactions. These increases were partially offset by lower crude oil and natural gas volumes, higher taxes and the $30 million after-tax impairment of the non-producing Don Field in the United Kingdom due to an increase in the asset retirement obligation. In addition, earnings in the second quarter of 2012 were impacted by lower crude oil prices, while earnings for the six-month period of 2012 benefitted from improved crude oil and natural gas prices.

Average production decreased 15 percent in the second quarter and six-month period of 2012. The decreases in both periods of 2012 were primarily due to field decline, dispositions and unplanned downtime, partly offset by lower planned downtime.

In December 2011, we entered into an agreement to sell our interests in the MacCulloch and Nicol fields in the United Kingdom. The sales of these interests are expected to close in the third quarter of 2012.

U.K. Tax Legislation

Asia Pacific and Middle East


	Three Months Ended June 30				Six Months Ended June 30
	2012		2011		2012		2011

Income from Continuing Operations (millions of dollars)	$	794		972		2,548		1,848


Average Net Production
Crude oil (MBD)
Consolidated Operations		54		117		57		122
Equity Affiliates		15		16		16		16

Total crude oil		69		133		73		138


Natural gas liquids (MBD)
Consolidated Operations		14		11		15		12
Equity Affiliates		7		8		8		7

Total natural gas liquids		21		19		23		19


Natural gas (MMCFD)
Consolidated Operations		587		694		642		706
Equity Affiliates		491		521		498		514

Total natural gas		1,078		1,215		1,140		1,220


Total Production (MBOED)		270		354		286		360


Average Sales Prices
Crude oil (dollars per barrel)
Consolidated Operations	$	109.12		116.69		113.29		108.76
Equity Affiliates		104.55		111.51		110.41		107.16
Total crude oil		108.16		116.03		112.67		108.59
Natural gas liquids (dollars per barrel)
Consolidated Operations		71.39		78.23		81.17		75.59
Equity Affiliates		70.28		73.49		78.81		73.01
Total natural gas liquids		71.00		76.39		80.42		74.56
Natural gas (dollars per thousand cubic feet)
Consolidated Operations		11.47		9.80		10.89		9.30
Equity Affiliates		2.79		3.28		2.68		2.94
Total natural gas		7.52		7.00		7.30		6.62

The Asia Pacific and Middle East segment has producing operations in China, Indonesia, Australia, the Timor Sea and Qatar, as well as exploration activities in Malaysia, Bangladesh and Brunei. As of June 30, 2012, Asia Pacific and Middle East contributed 11 percent of our worldwide liquids production and 27 percent of our natural gas production.

Asia Pacific and Middle East operations reported earnings of $794 million in the second quarter of 2012, an 18 percent decrease compared with the same period in 2011. Earnings for the six-month period of 2012 were $2,548 million, a 38 percent increase compared with the same period in 2011. Earnings for both periods of 2012 were mainly impacted by lower crude oil volumes, primarily in China and also as a result of our Vietnam disposition, lower LNG volumes, higher taxes, higher operating expenses and an $89 million after-tax charge related to the Bohai Bay settlement with the China State Oceanic Administration. These decreases in earnings were partially offset by significantly higher LNG prices, lower DD&A and a $72 million tax-related adjustment. Additionally, earnings in the six-month period of 2012 benefitted from the $931 million after-tax gain on sale of our Vietnam business.

Due to the three-month LNG pricing lag, we expect to see lower earnings from LNG cargo sales in the third quarter of 2012.

Production averaged 270 MBOED in the second quarter of 2012, a decrease of 24 percent compared to the second quarter of 2011. For the six-month period of 2012, production averaged 286 MBOED, a decrease of 21 percent. The decreases in both periods of 2012 were largely due to lower production in China, the disposition of our Vietnam business and planned downtime at our Bayu-Undan Field and Darwin LNG facility.

APLNG

In July 2012, we sanctioned the development of a second 4.5-million-tonnes-per-year LNG production train for our Australia Pacific LNG (APLNG) coal seam gas to LNG project in Queensland, Australia. In addition, APLNG signed project financing agreements during the second quarter of 2012, which are subject to certain conditions precedent. APLNG expects to begin drawing on the financing in the fourth quarter of 2012. LNG exports from the second train are expected to commence in early 2016 under binding sales agreements to China Petrochemical Corporation (Sinopec) and Kansai Electric Power Co., Inc. Upon sanctioning of the second train in July and in conjunction with the LNG sales agreement, Sinopec subscribed for additional shares in APLNG, which increased its equity interest from 15 percent to 25 percent. As a result, on July 12, 2012, both our ownership interest and Origin Energy’s ownership interest diluted from 42.5 percent to 37.5 percent. This reduction, along with project financing, lowers our future capital requirements to fund the APLNG Project. We expect to record a loss of approximately $135 million after-tax from the dilution in the third quarter of 2012. We plan to evaluate opportunities to further reduce our ownership interest in APLNG.

China—Bohai Bay

At the end of the second quarter of 2012, Peng Lai’s net production was approximately 36 MBOED. We continue to seek approval for our revised overall development plan, while we increase oil offtake under an interim operations resumption plan.

Other International


	Three Months Ended June 30					Six Months Ended June 30
	2012			2011		2012		2011

Income (Loss) from Continuing Operations (millions of dollars)	$	(19	)		79		67		198


Average Net Production
Crude oil (MBD)
Consolidated Operations		66			29		64		43
Equity Affiliates		16			32		17		35

Total crude oil		82			61		81		78

Natural gas liquids (MBD)		4			2		4		3
Natural gas (MMCFD)		159			152		161		155


Total Production (MBOED)		112			88		111		107


Average Sales Prices
Crude oil (dollars per barrel)
Consolidated Operations	$	109.33			121.24		114.39		109.71
Equity Affiliates		94.11			106.87		101.31		102.11
Total crude oil		106.71			114.00		111.55		106.26
Natural gas liquids (dollars per barrel)		15.34			12.88		13.85		13.44
Natural gas (dollars per thousand cubic feet)		2.45			2.10		2.48		2.10

The Other International segment includes producing operations in Nigeria, Libya, Algeria and Russia, as well as exploration activities in Angola and the Caspian Sea. As of June 30, 2012, Other International contributed 10 percent of our worldwide liquids production and 4 percent of our natural gas production.

Other International operations reported a loss of $19 million in the second quarter of 2012, a decrease of $98 million compared with the same period in 2011. Earnings for the six-month period of 2012 were $67 million, a 66 percent decrease compared with the same period in 2011. The decreases for both periods of 2012 were primarily the result of lower crude oil volumes in Russia, partially offset by lower taxes. Earnings in the second quarter of 2012 were also impacted by lower crude oil prices.

Production averaged 112 MBOED in the second quarter of 2012, a 27 percent increase compared with the second quarter of 2011. Production for the six-month period of 2012 averaged 111 MBOED, an increase of 4 percent over the comparative period of 2011. The increases in both periods of 2012 were mostly due to the ramp-up of production in Libya following a period of civil unrest in 2011, partly offset by field decline in Russia.

LUKOIL Investment


	Millions of Dollars
	Three Months Ended June 30				Six Months Ended June 30
	2012		2011		2012		2011


Income From Continuing Operations	$	—		—		—		239

This segment represents our former investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. We sold our remaining interest in LUKOIL in the first quarter of 2011.

Corporate and Other


	Millions of Dollars
	Three Months Ended June 30						Six Months Ended June 30
	2012			2011			2012			2011

Income (Loss) From Continuing Operations
Net interest	$	(128	)		(175	)		(289	)		(364	)
Corporate general and administrative expenses		(44	)		(43	)		(118	)		(104	)
Technology		(22	)		(3	)		(40	)		(1	)
Separation costs		(40	)		—			(73	)		—
Other		(31	)		7			(59	)		(44	)

	$	(265	)		(214	)		(579	)		(513	)

Net interest consists of interest and financing expense, net of interest income and capitalized interest, as well as premiums incurred on the early retirement of debt. Net interest decreased 27 percent in the second quarter of 2012 and 21 percent in the first six months of 2012. The decrease in both periods was primarily due to higher capitalized interest on projects and lower interest expense due to lower debt levels, partly offset by lower interest income.

Corporate general and administrative expenses increased 13 percent in the six-month period of 2012, mainly due to higher contributions and advertising expenses.

Technology includes our investment in new technologies or businesses, net of licensing revenues. Activities are focused on heavy oil and oil sands, unconventional reservoirs, subsurface technology, liquefied natural gas, arctic and deepwater, as well as sustainability technology. Technology expenses increased $19 million and $39 million in the second quarter and six-month period of 2012, respectively. The increases in both periods of 2012 were largely due to lower licensing revenues. Higher project expenses also contributed to the increase in the six-month period of 2012.

Separation costs consist of ongoing expenses related to the separation of our downstream businesses into a stand-alone, publicly traded company, Phillips 66. Expenses incurred in the second quarter and the six-month period of 2012 primarily included costs related to compensation and benefit plans.

The category “Other” includes certain foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation, and other costs not directly associated with an operating segment. “Other” expenses increased $38 million in the second quarter and $15 million in the six-month period of 2012, mostly due to higher environmental expenses and foreign currency transaction losses, compared with foreign currency transaction gains in the prior-year periods.

Our Corporate and Other costs are estimated to be $1.0 billion for the full-year 2012.

CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators


	Millions of Dollars
	June 30 2012			December 31 2011

Short-term debt	$	4,179			1,013
Total debt		23,008			22,623
Total equity*		46,443			65,749
Percent of total debt to capital**		33	%		26
Percent of floating-rate debt to total debt***		12	%		10

*Certain amounts have been restated to reflect a prior period adjustment. See Note 16—Accumulated Other Comprehensive Income, in the Notes to Consolidated Financial Statements.
**Capital includes total debt and total equity.
***Includes effect of interest rate swaps.

To meet our short- and long-term liquidity requirements, we look to a variety of funding sources. Cash generated from continuing operating activities is the primary source of funding. In addition, during the first six months of 2012, we received $1,566 million in proceeds from asset sales and $7,818 million from a special cash distribution from Phillips 66, primarily using the proceeds from the $5.8 billion in Senior Notes issued by Phillips 66 in March 2012, as well as a portion of the 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. The proceeds from the special cash distribution will be used solely to pay dividends, repurchase common stock, repay debt, or a combination of the foregoing, in each case within twelve months following the distribution. At June 30, 2012, the remaining balance of this cash distribution was $5,000 million and was included in the “Restricted cash” line on our consolidated balance sheet. During the first half of 2012, available cash was used to support our ongoing capital expenditures and investments program, repurchase common stock and pay dividends. Total dividends paid on our common stock during the first six months of 2012 were $1,661 million. During the first half of 2012, cash and cash equivalents decreased by $4,736 million to $1,044 million.

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

Significant Sources of Capital

Operating Activities

Cash provided by continuing operating activities was $6,368 million for the first six months of 2012, compared with $6,353 million for the first six months of 2011.

While the stability of our cash flows from operating activities benefits from geographic diversity, our short- and long-term operating cash flows are highly dependent upon prices for crude oil, bitumen, natural gas, LNG and natural gas liquids. Prices and margins in our industry are typically volatile, and are driven by market conditions over which we have no control. Absent other mitigating factors, as these prices and margins fluctuate, we would expect a corresponding change in our operating cash flows.

The level of our production volumes also impacts our cash flows. These production levels are impacted by such factors as acquisitions and dispositions of fields, field production decline rates, new technologies, operating efficiency, weather conditions, the addition of proved reserves through exploratory success, and their

timely and cost-effective development. While we actively manage these factors, production levels can cause variability in cash flows, although generally this variability has not been as significant as that caused by commodity prices.

Asset Sales

Proceeds from asset sales during the first six months of 2012 were $1.6 billion, primarily from the sale of our Vietnam business and the sale of our interest in the Statfjord and Alba fields in the North Sea. This compares with proceeds of $1.9 billion in the first six months of 2011, which mainly included the sale of our remaining interest in LUKOIL and certain properties located in the Lower 48. We plan to raise up to an additional $8 billion from asset sales over the next 12 months.

Commercial Paper and Credit Facilities

In May 2012, we decreased our total revolving credit facilities from $8.0 billion to $7.5 billion by terminating all commitments under the $500 million credit facility, which was due to expire in July 2012. At June 30, 2012, we had a revolving credit facility totaling $7.5 billion expiring in August 2016. Our revolving credit facility 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 facility is broadly syndicated among financial institutions and does not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or ratings. The facility agreement contains 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 agreement calls for commitment fees on available, but unused, amounts. The agreement also contains early termination rights if our current directors or their approved successors cease to be a majority of the Board of Directors.

Our primary funding source for short-term working capital needs is the ConocoPhillips $6.35 billion commercial paper program. Commercial paper maturities are generally limited to 90 days. We also have the ConocoPhillips Qatar Funding Ltd. $1.15 billion commercial paper program, which is used to fund commitments relating to the QG3 Project. At June 30, 2012, and December 31, 2011, we had no direct borrowings under the revolving credit facilities, with no letters of credit issued at June 30, 2012, and $40 million at December 31, 2011. In addition, under the two ConocoPhillips commercial paper programs, $1,929 million of commercial paper was outstanding at June 30, 2012, compared with $1,128 million at December 31, 2011. Since we had $1,929 million of commercial paper outstanding and had issued no letters of credit, we had access to $5.6 billion in borrowing capacity under our revolving credit facilities at June 30, 2012.

Shelf Registration

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

Off-Balance Sheet Arrangements

As part of our normal ongoing business operations and consistent with normal industry practice, we enter into numerous agreements with other parties to pursue business opportunities, which share costs and apportion risks among the parties as governed by the agreements.

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

Capital Requirements

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

Our debt balance at June 30, 2012, was $23.0 billion, an increase of $385 million from the balance at December 31, 2011. Our short-term debt balance at June 30, 2012, increased $3.2 billion compared to December 31, 2011, as a result of normal maturities and early redemption notices. In July 2012, make-whole redemption notices were issued on bonds totaling $1.5 billion, and the bonds will be repaid in August 2012. Upon settlement in the third quarter of 2012, a before-tax loss on the redemption of approximately $75 million is expected, consisting of a make-whole premium and unamortized issuance costs.

We are obligated to contribute $7.5 billion, plus interest, over a 10-year period that began in 2007, to FCCL. Quarterly principal and interest payments of $237 million began in the second quarter of 2007 and will continue until the balance is paid. Of the principal obligation amount, approximately $752 million was short-term and was included in the “Accounts payable—related parties” line on our June 30, 2012, consolidated balance sheet. The principal portion of these payments, which totaled $361 million in the first six months of 2012, 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.

In May 2012, we announced a dividend of 66 cents per share. The dividend was paid June 1, 2012, to stockholders of record at the close of business on May 21, 2012. Additionally, in July 2012, we announced a dividend of 66 cents per share. The dividend will be paid September 4, 2012, to stockholders of record at the close of business on July 23, 2012.

On December 2, 2011, our Board of Directors authorized the purchase of up to an additional $10 billion of our common stock over the subsequent two years. Since our share repurchase programs began in 2010, share repurchases totaled 297 million shares at a cost of $19.9 billion through June 30, 2012. Future share repurchases will be made opportunistically, contingent upon commodity prices and proceeds from asset dispositions.

Capital Spending

Capital Expenditures and Investments


	Millions of Dollars
	Six Months Ended June 30
	2012		2011

Alaska	$	388		391
Lower 48 and Latin America		2,555		1,535
Canada		1,057		728
Europe		1,357		929
Asia Pacific and Middle East		1,585		1,183
Other International		805		552
LUKOIL		—		—
Corporate and Other		111		72

	$	7,858		5,390

United States	$	3,053		1,997
International		4,805		3,393

	$	7,858		5,390

During the first six months of 2012, capital expenditures supported key exploration and development projects, primarily:

•

Oil and natural gas exploration and development activities in the Lower 48, including the Eagle Ford, Bakken and North Barnett shale plays, as well as the Permian and San Juan basins.

•

Exploration leases and wells in deepwater Gulf of Mexico.

•

Alaska development activities related to existing producing fields.

•

Oil sands projects and ongoing liquids-focused projects in Canada.

•

Further development of coalbed methane projects associated with the APLNG joint venture in Australia.

•

Continued development of Bohai Bay in China, new fields offshore Malaysia and ongoing exploration and development activity offshore Indonesia and Australia.

•

In Europe, development activities in the Ekofisk, Jasmine and Clair Ridge areas.

•

The Kashagan Field in the Caspian Sea.

•

Leasehold acquisitions in Angola.

Contingencies

Legal Matters

Environmental

We are subject to the same numerous international, federal, state and local environmental laws and regulations as other companies in our industry. For a discussion of the most significant of these environmental laws and regulations, including those with associated remediation obligations, see the “Environmental” section in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 64, 65 and 66 of our 2011 Annual Report on Form 10-K.

We occasionally receive requests for information or notices of potential liability from the Environmental Protection Agency (EPA) and state environmental agencies alleging that we are a potentially responsible party under the Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain wastes attributable to our past operations. As of December 31, 2011, we reported we had been notified of potential liability under CERCLA and comparable state laws at 74 sites around the United States. During the quarter ended June 30, 2012, we resolved 2 sites and transferred 61 sites to Phillips 66, bringing the number to 11 unresolved sites with potential liability.

At June 30, 2012, our balance sheet included a total environmental accrual of $440 million, compared with $922 million at December 31, 2011. A significant portion of our environmental contingencies at December 31, 2011, was related to our Downstream business. We expect to incur a substantial amount of these expenditures within the next 30 years.

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

Climate Change

There has been a broad range of proposed or promulgated state, national and international laws focusing on greenhouse gas (GHG) reduction. These proposed or promulgated laws apply or could apply in countries where we have interests or may have interests in the future. Laws in this field continue to evolve, and while it is not possible to accurately estimate either a timetable for implementation or our future compliance costs relating to implementation, such laws, if enacted, could have a material impact on our results of operations and financial condition. Examples of legislation and precursors for possible regulation that do or could affect our operations include the EPA’s announcement on March 29, 2010 (published as “Interpretation of Regulations that Determine Pollutants Covered by Clean Air Act Permitting Programs,” 75 Fed. Reg. 17004 (April 2, 2010)), and the EPA’s and U.S. Department of Transportation’s joint promulgation of a Final Rule on April 1, 2010, that trigger regulation of GHGs under the Clean Air Act, may trigger more climate-based claims for damages, and may result in longer agency review time for development projects.

For other examples of legislation or precursors for possible regulation that do or could affect our operations, see the “Climate Change” section in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 66 and 67 of our 2011 Annual Report on Form 10-K.

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

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

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

•

Fluctuations in crude oil, bitumen, natural gas, LNG and natural gas liquids prices.

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

International monetary conditions and exchange controls.

•

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

•

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

•

Liability resulting from litigation.

•

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

•

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

•

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

•

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

•

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

•

The factors generally described in Item 1A—Risk Factors in our 2011 Annual Report on Form 10-K.

Item 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information about market risks for the six months ended June 30, 2012, does not differ materially from that discussed under Item 7A in our 2011 Annual Report on Form 10-K.

Item 4.

CONTROLS AND PROCEDURES

As of June 30, 2012, with the participation of our management, our Chairman, President and Chief Executive Officer (principal executive officer) and our Executive Vice President, Finance and Chief Financial Officer (principal financial officer) carried out an evaluation, pursuant to Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the Act), of ConocoPhillips’ disclosure controls and procedures (as defined in Rule 13a-15(e) of the Act). Based upon that evaluation, our Chairman, President and Chief Executive Officer and our Executive Vice President, Finance and Chief Financial Officer concluded that our disclosure controls and procedures were operating effectively as of June 30, 2012.

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

PART II. OTHER INFORMATION

Item 1.

LEGAL PROCEEDINGS

The following is a description of reportable legal proceedings including those involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment for this reporting period. The following proceedings include those matters that arose during the second quarter of 2012 and any material developments with respect to matters previously reported in ConocoPhillips’ 2011 Annual Report on Form 10-K. While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings was decided adversely to ConocoPhillips, we expect there would be no material effect on our consolidated financial position. Nevertheless, such proceedings are reported pursuant to the U.S. Securities and Exchange Commission regulations.

On April 30, 2012, the separation of our Downstream business was completed, creating two independent energy companies: ConocoPhillips and Phillips 66. In connection with the separation, we entered into an Indemnification and Release Agreement which provides for cross-indemnities between Phillips 66 and us and established procedures for handling claims subject to indemnification and related matters, such as legal proceedings. We have included matters where we remain a party to a proceeding relating to Phillips 66, in accordance with SEC regulations. We do not expect any of those matters to result in a net claim against us.

New Matters

The North Dakota Department of Health has requested all the operators in the Bakken Pool area, including ConocoPhillips, enter into an Administrative Consent Agreement to resolve alleged historic violations of the state’s air emission regulations. The state is proposing a penalty of $2,000 per well drilled in the Bakken Pool which would result in total penalty to the company of over $100,000. ConocoPhillips is working with the state to resolve this matter.

In May 2012, the Illinois Attorney General’s office filed and served a Complaint against ConocoPhillips with respect to operations at the Phillips 66 Wood River Refinery alleging violations of the Illinois groundwater standards and a third-party’s hazardous waste permit. The Complaint seeks as relief remediation of area groundwater, compliance with the hazardous waste permit, enhanced pipeline and tank integrity measures, additional spill reporting, and yet-to-be specified amounts for fines and penalties. Phillips 66 is working with the Illinois Environmental Protection Agency and Attorney General’s office to resolve these allegations.

On March 7, 2012, the Bay Area Air Quality Management District (the District) issued a $302,500 demand to settle five Notices of Violation (NOVs) issued between 2008 and 2010 to the Phillips 66 Rodeo Refinery. The NOVs allege non-compliance with the District rules and/or facility permit conditions. Phillips 66 is working with the District to resolve this matter.

Item 1A.

RISK FACTORS

There have been no material changes from the risk factors disclosed in Item 1A of our 2011 Annual Report on Form 10-K.

Item 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Issuer Purchases of Equity Securities


							Millions of Dollars
Period	Total Number of Shares Purchased*		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs**		Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs

April 1-30, 2012		13,448,067	$	74.35		13,447,011	$	7,101
May 1-31, 2012		18,635,601		53.66		18,634,689		6,101
June 1-30, 2012		19,638,159		53.47		19,638,159		5,051

Total		51,721,827	$	58.97		51,719,859

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

On December 2, 2011, we announced a share repurchase program for up to $10 billion of common stock over the next two years. Acquisitions for the share repurchase program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Repurchases may be increased, decreased or discontinued at any time without prior notice. Shares of stock repurchased under the plan are held as treasury shares.

Item 6.

EXHIBITS


		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	Exhibit Number	Filing Date	SEC File No.

2.1	Separation and Distribution Agreement Between ConocoPhillips and Phillips 66, dated April 26, 2012.	8-K	2.1	05/01/12	001-32395

10.1	Indemnification and Release Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012.	8-K	10.1	05/01/12	001-32395

10.2	Intellectual Property Assignment and License Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012.	8-K	10.2	05/01/12	001-32395

10.3	Tax Sharing Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012.	8-K	10.3	05/01/12	001-32395

10.4	Employee Matters Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012.	8-K	10.4	05/01/12	001-32395

10.5	Transition Services Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012.	8-K	10.5	05/01/12	001-32395

10.6*	Form of Restricted Stock Units Agreement under the ConocoPhillips Restricted Stock Program, dated April 4, 2012.

10.7*	Form of Restricted Stock Award Agreement under the ConocoPhillips Restricted Stock Program, dated May 8, 2012.

10.8*	Amendment and Restatement of Annex to Nonqualified Deferred Compensation Arrangements of ConocoPhillips.

10.9*	Amendment and Restatement of the Burlington Resources Inc. Management Supplemental Benefits Plan.

10.10*	Amendment, Change of Sponsorship, and Restatement of Certain Nonqualified Deferred Compensation Plans of ConocoPhillips.

10.11.1*	Amendment and Restatement of Defined Contribution Make-Up Plan of ConocoPhillips - Title I.

10.11.2*	Amendment and Restatement of Defined Contribution Make-Up Plan of ConocoPhillips - Title II.

10.12.1*	Amendment and Restatement of Key Employee Deferred Compensation Plan of ConocoPhillips - Title I.

10.12.2*	Amendment and Restatement of Key Employee Deferred Compensation Plan of ConocoPhillips - Title II.


		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	Exhibit Number	Filing Date	SEC File No.

10.13*	Amendment and Restatement of Key Employee Supplemental Retirement Plan of ConocoPhillips.

10.14*	Amendment and Restatement of ConocoPhillips Supplemental Executive Retirement Plan.

12*	Computation of Ratio of Earnings to Fixed Charges.

31.1*	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

31.2*	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

32*	Certifications pursuant to 18 U.S.C. Section 1350.

99.2	Opinion of Wachtell, Lipton, Rosen & Katz concerning certain tax matters relating to the Distribution and certain related transactions.	8-K	99.2	05/01/12	001-32395

101.INS*	XBRL Instance Document.

101.SCH*	XBRL Schema Document.

101.CAL*	XBRL Calculation Linkbase Document.

101.LAB*	XBRL Labels Linkbase Document.

101.PRE*	XBRL Presentation Linkbase Document.

101.DEF*	XBRL Definition Linkbase Document.

* Filed herewith.

SIGNATURE

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

CONOCOPHILLIPS

/s/ Glenda M. Schwarz

Glenda M. Schwarz

Vice President and Controller

(Chief Accounting and Duly Authorized Officer)

July 31, 2012

TABLE OF CONTENTS

Part I. Financial Informationprint Item 1. Financial Statementsprint Note 1 Basis Of Presentationprint Note 2 Separation Of Downstream Businessprint Note 3 Variable Interest Entities (vies)print Note 4 Inventoriesprint Note 5 Assets Held For Sale Or Soldprint Note 6 Investments, Loans and Long-term Receivablesprint Note 7 Suspended Wellsprint Note 8 Impairmentsprint Note 9 Debtprint Note 10 Joint Venture Acquisition Obligationprint Note 11 Noncontrolling Interestsprint Note 12 Guaranteesprint Note 13 Contingencies and Commitmentsprint Note 14 Derivative and Financial Instrumentsprint Note 15 Fair Value Measurementprint Note 16 Accumulated Other Comprehensive Incomeprint Note 17 Cash Flow Informationprint Note 18 Employee Benefit Plansprint Note 19 Related Party Transactionsprint Note 20 Segment Disclosures and Related Informationprint Note 21 Income Taxesprint Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operationsprint Item 3. Quantitative and Qualitative Disclosures About Market Riskprint Item 4. Controls and Proceduresprint Part II. Other Informationprint Item 1. Legal Proceedingsprint Item 1A. Risk Factorsprint Item 2. Unregistered Sales Of Equity Securities and Use Of Proceedsprint Item 6. Exhibitsprint

Customer name	Ticker
Adams Resources & Energy, Inc.	AE
Avery Dennison Corporation	AVY
CMS Energy Corporation	CMS
Cooper Tire & Rubber Company	CTB
EQT Corporation	EQT
FirstEnergy Corp.	FE
FMC Corporation	FMC
First Trust New Opportunities MLP & Energy Fund	FPL
The Goodyear Tire & Rubber Company	GT
H.B. Fuller Company	FUL
Johnson Controls International plc	JCI
NiSource Inc.	NI
Olin Corporation	OLN
ONEOK, Inc.	OKE
PPL Corporation	PPL

Supplier name	Ticker
Thermo Fisher Scientific Inc.	TMO
Xcel Energy Inc.	XEL
Air Products and Chemicals, Inc.	APD
Exxon Mobil Corporation	XOM
Raytheon Technologies Corporation	RTX
Chevron Corporation	CVX
Danaher Corporation	DHR
Canaan Inc.	CAN

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company