Edgar Filing: CONOCOPHILLIPS

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 September 30, 2013

		or

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

		For the transition period from to

		Commission file number: 001-32395

ConocoPhillips

(Exact name of registrant as specified in its charter)


Delaware		01-0562944
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

600 North Dairy Ashford, Houston, TX 77079

(Address of principal executive offices) (Zip Code)

281-293-1000

(Registrant’s telephone number, including area code)

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

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

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

Large accelerated filer [X] Accelerated filer [ ] Non-accelerated filer [ ] Smaller reporting company [ ]

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

The registrant had 1,225,098,698 shares of common stock, $.01 par value, outstanding at September 30, 2013.

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
Notes to Consolidated Financial Statements		5
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		54

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

Item 6. Exhibits		56

Signature		57

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS


Consolidated Income Statement		ConocoPhillips


	Millions of Dollars
	Three Months Ended				Nine Months Ended
	September 30				September 30
		2013		2012		2013		2012

Revenues and Other Income
Sales and other operating revenues	$	13,643		14,141		41,159		42,398
Equity in earnings of affiliates		709		412		1,565		1,431
Gain on dispositions		1,069		118		1,222		1,641
Other income		49		42		317		168

Total Revenues and Other Income		15,470		14,713		44,263		45,638

Costs and Expenses
Purchased commodities		5,708		6,357		17,063		18,156
Production and operating expenses		1,962		1,637		5,321		4,998
Selling, general and administrative expenses		249		329		607		890
Exploration expenses		313		215		911		1,155
Depreciation, depletion and amortization		1,902		1,650		5,541		4,801
Impairments		1		-		31		296
Taxes other than income taxes		664		673		2,198		2,668
Accretion on discounted liabilities		106		100		317		308
Interest and debt expense		151		161		420		548
Foreign currency transaction (gains) losses		9		-		(34	)	17

Total Costs and Expenses		11,065		11,122		32,375		33,837

Income from continuing operations before income taxes		4,405		3,591		11,888		11,801
Provision for income taxes		1,966		1,851		5,359		6,162

Income From Continuing Operations		2,439		1,740		6,529		5,639
Income from discontinued operations*		57		73		183		1,418

Net income		2,496		1,813		6,712		7,057
Less: net income attributable to noncontrolling interests		(16	)	(15)		(43	)	(55)

Net Income Attributable to ConocoPhillips	$	2,480		1,798		6,669		7,002

Amounts Attributable to ConocoPhillips Common Shareholders:
Income from continuing operations	$	2,423		1,725		6,486		5,586
Income from discontinued operations		57		73		183		1,416

Net income	$	2,480		1,798		6,669		7,002

Net Income Attributable to ConocoPhillips Per Share of Common Stock (dollars)
Basic
Continuing operations	$	1.96		1.41		5.26		4.47
Discontinued operations		0.05		0.06		0.15		1.13

Net Income Attributable to ConocoPhillips Per Share of Common Stock	$	2.01		1.47		5.41		5.60

Diluted
Continuing operations	$	1.95		1.40		5.23		4.43
Discontinued operations		0.05		0.06		0.15		1.12

Net Income Attributable to ConocoPhillips Per Share of Common Stock	$	2.00		1.46		5.38		5.55

Dividends Paid Per Share of Common Stock (dollars)	$	0.69		0.66		2.01		1.98

Average Common Shares Outstanding (in thousands)
Basic		1,231,054		1,220,462		1,230,027		1,250,641
Diluted		1,240,365		1,229,343		1,238,943		1,260,212

*Net of provision for income taxes on discontinued operations of:	$	*136*		94		*215*		885

See Notes to Consolidated Financial Statements.


Consolidated Statement of Comprehensive Income		ConocoPhillips


	Millions of Dollars
	Three Months Ended				Nine Months Ended
	September 30				September 30
		2013		2012		2013		2012


Net Income	$	2,496		1,813		6,712		7,057
Other comprehensive income (loss)
Defined benefit plans
Prior service cost arising during the period		-		-		-		-
Reclassification adjustment for amortization of prior service credit included in net income		(1	)	(1)		(4	)	(3)

Net change		(1	)	(1)		(4	)	(3)

Net actuarial gain (loss) arising during the period		301		(432)		302		(470)
Reclassification adjustment for amortization of net actuarial losses included in net income		106		189		220		327

Net change		407		(243)		522		(143)
Nonsponsored plans*		-		-		1		5
Income taxes on defined benefit plans		(155	)	94		(197	)	67

Defined benefit plans, net of tax		251		(150)		322		(74)

Unrealized holding gain on securities		-		-		-		1
Income taxes on unrealized holding gain on securities		-		-		-		-

Unrealized gain on securities, net of tax		-		-		-		1

Foreign currency translation adjustments		623		925		(1,705	)	1,244
Reclassification adjustment for loss included in net income		-		(320)		(4	)	(319)
Income taxes on foreign currency translation adjustments		(2	)	7		12		21

Foreign currency translation adjustments, net of tax		621		612		(1,697	)	946

Hedging activities		-		-		-		6
Income taxes on hedging activities		-		-		-		-

Hedging activities, net of tax		-		-		-		6

Other Comprehensive Income (Loss), Net of Tax		872		462		(1,375	)	879

Comprehensive Income		3,368		2,275		5,337		7,936
Less: comprehensive income attributable to noncontrolling interests		(16	)	(15)		(43	)	(55)

Comprehensive Income Attributable to ConocoPhillips	$	3,352		2,260		5,294		7,881

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

See Notes to Consolidated Financial Statements.


Consolidated Balance Sheet		ConocoPhillips


	Millions of Dollars
	September 30			December 31
	2013			2012

Assets
Cash and cash equivalents	$	3,883			3,618
Restricted cash		-			748
Accounts and notes receivable (net of allowance of $9 million in 2013 and $10 million in 2012)		8,191			8,929
Accounts and notes receivable—related parties		214			253
Inventories		1,268			965
Prepaid expenses and other current assets		9,001			9,476

Total Current Assets		22,557			23,989
Investments and long-term receivables		23,792			23,489
Loans and advances—related parties		1,374			1,517
Net properties, plants and equipment (net of accumulated depreciation, depletion and amortization of $63,399 million in 2013 and $58,916 million in 2012)		71,129			67,263
Other assets		908			886

Total Assets	$	119,760			117,144


Liabilities
Accounts payable	$	9,411			9,154
Accounts payable—related parties		922			859
Short-term debt		572			955
Accrued income and other taxes		2,911			3,366
Employee benefit obligations		678			742
Other accruals		1,841			2,367

Total Current Liabilities		16,335			17,443
Long-term debt		21,096			20,770
Asset retirement obligations and accrued environmental costs		9,159			8,947
Joint venture acquisition obligation—related party		2,203			2,810
Deferred income taxes		14,745			13,185
Employee benefit obligations		2,847			3,346
Other liabilities and deferred credits		1,838			2,216

Total Liabilities		68,223			68,717


Equity
Common stock (2,500,000,000 shares authorized at $.01 par value) Issued (2013—1,767,329,371 shares; 2012—1,762,247,949 shares)
Par value		18			18
Capital in excess of par		45,637			45,324
Treasury stock (at cost: 2013—542,230,673 shares; 2012—542,230,673 shares)		(36,780	)		(36,780)
Accumulated other comprehensive income		2,712			4,087
Retained earnings		39,526			35,338

Total Common Stockholders’ Equity		51,113			47,987
Noncontrolling interests		424			440

Total Equity		51,537			48,427

Total Liabilities and Equity	$	119,760			117,144

See Notes to Consolidated Financial Statements.


Consolidated Statement of Cash Flows		ConocoPhillips


	Millions of Dollars
	Nine Months Ended September 30
	2013			2012

Cash Flows From Operating Activities
Net income	$	6,712			7,057
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization		5,541			4,801
Impairments		31			296
Dry hole costs and leasehold impairments		345			703
Accretion on discounted liabilities		317			308
Deferred taxes		1,142			811
Undistributed equity earnings		(585	)		(409)
Gain on dispositions		(1,222	)		(1,641)
Income from discontinued operations		(183	)		(1,418)
Other		(280	)		(53)
Working capital adjustments
Decrease (increase) in accounts and notes receivable		822			(1,762)
Decrease (increase) in inventories		(301	)		1
Decrease (increase) in prepaid expenses and other current assets		(172	)		376
Increase in accounts payable		324			1,024
Decrease in taxes and other accruals		(550	)		(506)

Net cash provided by continuing operating activities		11,941			9,588
Net cash provided by discontinued operations		235			464

Net Cash Provided by Operating Activities		12,176			10,052


Cash Flows From Investing Activities
Capital expenditures and investments		(11,281	)		(10,720)
Proceeds from asset dispositions		3,175			2,088
Net sales of short-term investments		1			597
Collection of advances/loans—related parties		130			100
Other		(51	)		175

Net cash used in continuing investing activities		(8,026	)		(7,760)
Net cash used in discontinued operations		(540	)		(938)

Net Cash Used in Investing Activities		(8,566	)		(8,698)


Cash Flows From Financing Activities
Issuance of debt		-			485
Repayment of debt		(946	)		(1,668)
Special cash distribution from Phillips 66		-			7,818
Change in restricted cash		748			(2,468)
Issuance of company common stock		12			83
Repurchase of company common stock		-			(5,098)
Dividends paid		(2,481	)		(2,469)
Other		(593	)		(547)

Net cash used in continuing financing activities		(3,260	)		(3,864)
Net cash used in discontinued operations		-			(2,019)

Net Cash Used in Financing Activities		(3,260	)		(5,883)


Effect of Exchange Rate Changes on Cash and Cash Equivalents		(85	)		17


Net Change in Cash and Cash Equivalents		265			(4,512)
Cash and cash equivalents at beginning of period		3,618			5,780

Cash and Cash Equivalents at End of Period	$	3,883			1,268

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 2012 Annual Report on Form 10-K.

As a result of our separation of Phillips 66 on April 30, 2012, the results of operations for our former refining, marketing and transportation businesses; most of our former Midstream segment; our former Chemicals segment; and our power generation and certain technology operations included in our former Emerging Businesses segment (collectively, our “Downstream business”), have been classified as discontinued operations for all periods presented. In addition, the results of operations for our interest in the North Caspian Sea Production Sharing Agreement (Kashagan) and our Algerian and Nigerian businesses have been classified as discontinued operations for all periods presented. See Note 3—Discontinued Operations, for additional information. Unless indicated otherwise, the information in the Notes to the Consolidated Financial Statements relates to our continuing operations.

Note 2—Change in Accounting Principles

Effective January 1, 2013, we early adopted, on a prospective basis, Financial Accounting Standards Board (FASB) Accounting Standards Update (ASU) No. 2013-05, “Parent’s Accounting for the Cumulative Translation Adjustment (CTA) upon Derecognition of Certain Subsidiaries or Groups of Assets within a Foreign Entity or of an Investment in a Foreign Entity.” This ASU clarifies that the CTA should not be released into net income unless a parent sells a part of its investment within a foreign entity which represents the complete or substantially complete liquidation of the reporting parent’s investment in the broader foreign entity. The ASU also requires the release of all the related CTA into net income upon gaining control in a step acquisition of an equity method investment that is considered to be a standalone foreign entity, and a pro rata release of the related CTA into net income upon a partial sale of an interest in an equity method investment that is considered to be a standalone foreign entity. There was no impact to our consolidated financial statements from the early adoption of this standard.

Note 3—Discontinued Operations

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. In connection with the separation, Phillips 66 distributed approximately $7.8 billion to us in a special cash distribution. The principal funds from the special cash distribution were designated solely to pay dividends, repurchase common stock, repay debt, or a combination of the foregoing, within twelve months following the distribution. The cash was included in the “Restricted cash” line on our consolidated balance sheet. No balance remained from the cash distribution as of September 30, 2013. We also entered into several agreements with Phillips 66 in order to effect the separation and govern our relationship with Phillips 66.

Sales and other operating revenues and income from discontinued operations related to Phillips 66 for the three- and nine-month periods ended September 30, 2012, were as follows:


	Millions of Dollars
	2012
	Three Months Ended		Nine Months Ended
	September 30		September 30


Sales and other operating revenues from discontinued operations	$	2		62,109


Income from discontinued operations before-tax	$	2		1,792
Income tax expense		-		542

Income from discontinued operations	$	2		1,250

Income from discontinued operations after-tax includes transaction, information systems and other costs incurred to effect the separation of $70 million for the nine-month period ended September 30, 2012. No separation costs were incurred during the first nine months of 2013.

Prior to the separation, commodity sales to and purchases from Phillips 66 were $4,973 million and $166 million, respectively, for the nine-month period ended September 30, 2012. 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.

Other Discontinued Operations

As part of our ongoing asset disposition program, we agreed to sell our interest in Kashagan and our Algerian and Nigerian businesses (collectively, the “Disposition Group”). The Disposition Group was previously part of the Other International operating segment.

On November 26, 2012, we notified government authorities in Kazakhstan and co-venturers of our intent to sell the Company’s 8.4 percent interest in Kashagan to ONGC Videsh Limited (OVL). On July 2, 2013, we received notification from the government of Kazakhstan indicating it is exercising its right to pre-empt the proposed sale to OVL and designating KazMunayGas (KMG) as the entity to acquire the interest. On October 31, 2013, we completed the transaction with KMG for total proceeds of $5.4 billion. We recorded pre-tax impairments of $606 million and $43 million in the fourth quarter of 2012 and the first quarter of 2013, respectively. At September 30, 2013, the carrying value of the net assets related to our interest in Kashagan was $5.3 billion, net of impairments.

On December 18, 2012, we entered into an agreement with Pertamina to sell our wholly owned subsidiary, ConocoPhillips Algeria Ltd., for a total of $1.75 billion plus customary adjustments. The transaction is targeted to close by the end of 2013. We received a deposit of $175 million in December 2012. The deposit is refundable in the event our co-venturer exercises its preemptive rights, which have been waived, or government approval is not received. At September 30, 2013, the net carrying value of our Algerian assets was $714 million.

On December 20, 2012, we entered into agreements with affiliates of Oando PLC to sell our Nigerian business unit. This included its upstream affiliates and Phillips (Brass) Limited, which owns a 17 percent interest in the Brass LNG Project. Brass LNG plans to construct an LNG facility in the Niger Delta. In September 2013, we agreed to extend the outside date, or the date the sales agreements may terminate, for our Nigerian upstream affiliates to November 30, 2013, in order to provide additional time for Oando to obtain financing. This sale is expected to generate proceeds of $1.65 billion plus customary adjustments. We received a deposit of $435 million in December 2012 and may retain the deposit if closing does not occur due to default by the buyer or failure to obtain all consents required under Nigerian petroleum laws. In September 2013, we also agreed to extend the date for closing the sale of our interest in Brass LNG to the first quarter of 2014, subject to certain conditions. The sale of Brass LNG would generate proceeds of $105 million plus customary adjustments. At September 30, 2013, the net carrying value of our Nigerian assets was $371 million.

At September 30, 2013, each component of the Disposition Group met the criteria to be classified as held for sale. Accordingly, we classified $11 million of loans and advances to related parties in the “Accounts and notes receivable—related parties” line and $7,421 million of noncurrent assets in the “Prepaid expenses and other current assets” line of our consolidated balance sheet. In addition, we classified $905 million of noncurrent liabilities in the “Accrued income and other taxes” line and $136 million of asset retirement obligations in the “Other accruals” line of our consolidated balance sheet. The carrying amounts of the major classes of assets and liabilities associated with the Disposition Group were as follows:


	Millions of Dollars
	September 30		December 31
	2013		2012


Assets
Accounts and notes receivable	$	364		268
Accounts and notes receivable—related parties		1		1
Inventories		56		44
Prepaid expenses and other current assets		103		220

Total current assets of discontinued operations		524		533
Investments and long-term receivables		300		272
Loans and advances—related parties		11		29
Net properties, plants and equipment		7,119		6,629
Other assets		2		4

Total assets of discontinued operations	$	7,956		7,467

Liabilities
Accounts payable	$	432		471
Accrued income and other taxes		70		125

Total current liabilities of discontinued operations		502		596
Asset retirement obligations and accrued environmental costs		136		131
Deferred income taxes		905		759

Total liabilities of discontinued operations	$	1,543		1,486

Sales and other operating revenues and income from discontinued operations related to the Disposition Group were as follows:


	Millions of Dollars
	Three Months Ended September 30				Nine Months Ended September 30
	2013		2012		2013		2012


Sales and other operating revenues from discontinued operations	$	353		380		892		1,095

Income from discontinued operations before-tax	$	193		165		398		511
Income tax expense		136		94		215		343

Income from discontinued operations	$	57		71		183		168

Note 4—Variable Interest Entities (VIEs)

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

Freeport LNG Development, L.P. (Freeport LNG)

We have an agreement with Freeport LNG to participate in an LNG receiving terminal in Quintana, Texas. We have no ownership in Freeport LNG; however, we own a 50 percent interest in Freeport LNG GP, Inc. (Freeport GP), which serves as the general partner managing the venture. We entered into a credit agreement with Freeport LNG, whereby we agreed to provide loan financing for the construction of the terminal. We also entered into a long-term agreement with Freeport LNG to use 0.9 billion cubic feet per day of regasification capacity, which expires in 2033. The terminal became operational in June 2008, and we began making payments under the terminal use agreement. At September 30, 2013, the prepaid balance of the terminal use agreement was $269 million, which is primarily reflected in the “Other assets” line on our consolidated balance sheet. Freeport LNG began making loan repayments in September 2008, and the loan balance outstanding was $522 million at September 30, 2013, and $565 million at December 31, 2012.

In July 2013, we reached an agreement with Freeport LNG to terminate our long-term agreement at the Freeport LNG Terminal, subject to Freeport LNG obtaining regulatory approval and project financing for an LNG liquefaction and export facility in Texas, in which we are not a participant. Upon satisfaction of these conditions, currently expected to occur by the end of the first quarter of 2014, we will pay Freeport LNG a termination fee of approximately $600 million. Freeport LNG will repay the outstanding ConocoPhillips loan used by Freeport to partially fund the original construction of the terminal. When the agreement becomes effective, we expect to recognize an after-tax charge to earnings of approximately $540 million. At that time, our terminal regasification capacity will be reduced from 0.9 billion cubic feet per day to 0.4 billion cubic feet per day, until July 1, 2016, at which time it will be reduced to zero.

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. Since we do not have the unilateral power to direct the key activities which most significantly impact its economic performance, we are not the primary beneficiary of Freeport LNG. These key activities primarily involve or relate to operating and maintaining the terminal. We also 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.

Australia Pacific LNG (APLNG)

APLNG is considered a VIE, as it has entered into certain contractual arrangements that provide it with additional forms of subordinated financial support. We are not the primary beneficiary of APLNG because we share with Origin Energy and China Petrochemical Corporation (Sinopec) the power to direct the key activities of APLNG that most significantly impact its economic performance, which involve activities related to the production and commercialization of coalbed methane, as well as LNG processing and export marketing. As a result, we do not consolidate APLNG, and it is accounted for as an equity method investment.

As of September 30, 2013, we have not provided any financial support to APLNG other than amounts previously contractually required. Unless we elect otherwise, we have no requirement to provide liquidity or purchase the assets of APLNG. See Note 7—Investments, Loans and Long-Term Receivables, and Note 13—Guarantees, for additional information.

Note 5—Inventories

Inventories consisted of the following:


	Millions of Dollars
	September 30 2013		December 31 2012


Crude oil and petroleum products	$	506		244
Materials, supplies and other		762		721

	$	1,268		965

Inventories valued on the last-in, first-out (LIFO) basis totaled $374 million and $147 million at September 30, 2013, and December 31, 2012, respectively. The estimated excess of current replacement cost over LIFO cost of inventories was approximately $140 million at September 30, 2013, and $200 million at December 31, 2012.

Note 6—Assets Held for Sale or Sold

Our interest in Kashagan and the Algerian and Nigerian business units were considered held for sale at September 30, 2013. These assets are classified as discontinued operations. See Note 3—Discontinued Operations, for additional information.

In March 2013, we sold the majority of our properties in the Cedar Creek Anticline for $989 million and recognized a before-tax loss on disposition of $49 million, which was included in the “Gain on dispositions” line on our consolidated income statement for the nine-month period ended September 30, 2013. At the time of the disposition, the carrying value of our interest, which was included in the Lower 48 and Latin America segment, was $1,038 million, which included $1,066 million of properties, plants and equipment (PP&E) and $28 million of asset retirement obligations.

In June 2013, we sold a portion of our working interests in the Browse and Canning basins for $402 million. Because we retained a working interest in the unproved properties, proceeds were treated as a reduction of the carrying value of PP&E with no gain or loss on disposition recognized. Prior to the partial disposition, the carrying value of the PP&E associated with our interests, included in our Asia Pacific and Middle East segment, was $486 million.

In August 2013, we sold our interest in the Clyden undeveloped oil sands leasehold for $724 million and recognized a before-tax gain on disposition of $614 million, which was included in the “Gain on dispositions” line on our consolidated income statement for the three- and nine-month periods ended September 30, 2013. At the time of the disposition, the carrying value of our interest in Clyden, which was included in the Canada segment, was $110 million and was classified as PP&E.

In August 2013, we also sold our 39 percent interest in Phoenix Park Gas Processors Limited for $593 million and recognized a before-tax gain on disposition of $417 million, which was included in the “Gain on dispositions” line on our consolidated income statement for the three- and nine-month periods ended September 30, 2013. At the time of the disposition, the carrying value of our equity investment in Phoenix Park, which was included in our Lower 48 and Latin America segment, was $176 million.

Note 7—Investments, Loans and Long-Term Receivables

APLNG

In the fourth quarter of 2012, APLNG satisfied all conditions precedent to drawdown from the $8.5 billion project finance facility. The facility consists of financing agreements executed by APLNG with the Export-Import Bank of the United States for approximately $2.9 billion, the Export-Import Bank of China for approximately $2.7 billion, and a syndicate of Australian and international commercial banks for approximately $2.9 billion. In connection with the execution of the project financing, we provided a completion guarantee for our pro-rata share of the project finance facility until the project achieves financial completion. See Note 13—Guarantees, for additional information.

APLNG is considered a VIE, as it has entered into certain contractual arrangements that provide it with additional forms of subordinated financial support. See Note 4—Variable Interest Entities (VIEs), for additional information.

At September 30, 2013, the book value of our equity method investment in APLNG was $10,526 million, which included $1,601 million of cumulative translation effects due to strengthening of the Australian dollar relative to the U.S. dollar over time, and is included in the “Investments and long-term receivables” line on our consolidated balance sheet.

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 September 30, 2013, included the following:

•

$522 million in loan financing to Freeport LNG. See Note 4—Variable Interest Entities (VIEs), for additional information.

•

$1,005 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.”

Note 8—Suspended Wells

The capitalized cost of suspended wells at September 30, 2013, was $1,066 million, an increase of $28 million from $1,038 million at year-end 2012. No suspended wells were charged to dry hole expense during the first nine months of 2013 relating to exploratory well costs capitalized for a period greater than one year as of December 31, 2012.

Note 9—Impairments

During the three- and nine-month periods ended September 30, 2013 and 2012, we recognized before-tax impairment charges within the following segments:


	Millions of Dollars
	Three Months Ended September 30				Nine Months Ended September 30
	2013		2012		2013		2012


Canada	$	-		-		-		213
Europe		-		-		28		79
Asia Pacific and Middle East		1		-		3		4

	$	1		-		31		296

The nine-month periods of 2013 and 2012 included impairments in our Europe segment of $28 million and $79 million, respectively, primarily due to increases in the asset retirement obligation for the U.K. Don Field, which has ceased production. Additionally, the nine-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.

Note 10—Debt

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 program, which is used to fund commitments relating to QG3. Commercial paper maturities are generally limited to 90 days.

At September 30, 2013, and December 31, 2012, we had no direct outstanding borrowings or letters of credit issued under our revolving credit facilities. In addition, under the ConocoPhillips Qatar Funding Ltd. commercial paper program, there was $961 million of commercial paper outstanding at September 30, 2013, compared with $1,055 million at December 31, 2012. Since we had $961 million of commercial paper outstanding and had issued no letters of credit, we had access to $6.5 billion in borrowing capacity under our revolving credit facilities at September 30, 2013.

At September 30, 2013, we classified $865 million of short-term debt as long-term debt, based on our ability and intent to refinance the obligation on a long-term basis under our revolving credit facilities.

During the first nine months of 2013, we repaid the following debt instruments at maturity:

•

The $100 million 7.625% Debentures due 2013.

•

The $750 million 5.50% Notes due 2013.

During the second quarter of 2013, a lease of a semi-submersible floating production system (FPS) commenced for the Gumusut development, located in Malaysia, in which we are a co-venturer. The FPS lease provides for an initial noncancelable term of 15 years, a subsequent 5-year cancelable term with no required lease payments, and an additional 5-year term with terms and conditions to be agreed at a later date. The lease has no ongoing purchase options or escalation clauses. Certain contingent rental payments may be incurred if actual commissioning costs exceed provisioned amounts. The lease does not impose any significant restrictions concerning dividends, debt or further leasing activities.

A capital lease asset and a capital lease obligation of $906 million were recognized for our proportionate interest in the FPS. The value of the capital lease asset and associated obligation are based on the present value of the future minimum lease payments using our pre-tax incremental borrowing rate of 3.58 percent for debt with similar terms. Following the startup of the FPS, the capital lease asset will be depreciated over a period consistent with the estimated proved reserves of Gumusut using the unit-of-production method with the associated depreciation included in the “Depreciation, depletion and amortization” line on our consolidated income statement. Future minimum lease payments under the capital lease are $46 million for the remainder of 2013, $78 million per year for 2014 through 2017, and $814 million for all years thereafter.

Note 11—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 $803 million was short-term and was included in the “Accounts payable—related parties” line on our September 30, 2013, consolidated balance sheet. The principal portion of these payments, which totaled $575 million in the first nine months of 2013, 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 12—Noncontrolling Interests

Activity attributable to common stockholders’ equity and noncontrolling interests for the first nine months of 2013 and 2012 was as follows:


	Millions of Dollars
	2013						2012
	Common Stockholders’ Equity		Non- Controlling Interest		Total Equity		Common Stockholders’ Equity		Non- Controlling Interest		Total Equity


Balance at January 1	$	47,987		440		48,427		65,239		510		65,749
Net income		6,669		43		6,712		7,002		55		7,057
Dividends		(2,481)		-		(2,481)		(2,469)		-		(2,469)
Repurchase of company common stock		-		-		-		(5,098)		-		(5,098)
Distributions to noncontrolling interests		-		(59)		(59)		-		(63)		(63)
Separation of Downstream business		-		-		-		(18,623)		(31)		(18,654)
Other changes, net*		(1,062)		-		(1,062)		1,355		-		1,355

Balance at September 30	$	51,113		424		51,537		47,406		471		47,877

*Includes components of other comprehensive income, which are disclosed separately in our consolidated statement of comprehensive income.

Note 13—Guarantees

At September 30, 2013, 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.

APLNG Guarantees

At September 30, 2013, we have outstanding multiple guarantees in connection with our 37.5 percent ownership interest in APLNG. The following is a description of the guarantees with values calculated utilizing September 2013 exchange rates:

•

We have guaranteed APLNG’s performance with regard to a construction contract executed in connection with APLNG’s issuance of the Train 1 and Train 2 Notices to Proceed. We estimate the remaining term of this guarantee is four years. Our maximum potential amount of future payments related to this guarantee is approximately $150 million and would become payable if APLNG cancels the applicable construction contract and does not perform with respect to the amounts owed to the contractor.

•

We have issued a construction completion guarantee related to the third-party project financing secured by APLNG. Our maximum potential amount of future payments under the guarantee is estimated to be $3.2 billion, which could be payable if the full debt financing capacity is utilized and completion of the project is not achieved. Our guarantee of the project financing will be released upon meeting certain completion tests with milestones, which we estimate would occur beginning in 2016. Our maximum exposure at September 30, 2013, is $2.5 billion based upon our pro-rata share of the facility used at that date. At September 30, 2013, the carrying value of this guarantee is approximately $114 million.

•

In conjunction with our original purchase of an ownership interest in APLNG from Origin Energy in October 2008, we agreed to guarantee an existing obligation of APLNG to deliver natural gas under several sales agreements with remaining terms of 3 to 18 years. Our maximum potential amount of future payments, or cost of volume delivery, under these guarantees is estimated to be $1.0 billion ($2.1 billion in the event of intentional or reckless breach), and would 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.

•

We have guaranteed the performance of APLNG with regard to certain other contracts executed in connection with the project’s continued development. The guarantees have remaining terms of up to 32 years or the life of the venture. Our maximum potential amount of future payments related to these guarantees is approximately $200 million and would become payable if APLNG does not perform.

Other Guarantees

We have other guarantees with maximum future potential payment amounts totaling approximately $270 million, which consist primarily of guarantees of the residual value of leased corporate aircraft, guarantees to fund the short-term cash liquidity deficit of two joint ventures, a guarantee for our portion of a joint venture’s debt obligations and a guarantee of minimum charter revenue for an LNG vessel. These guarantees have remaining terms of up to 11 years or the life of the venture and would become payable if, upon sale, certain asset values are lower than guaranteed amounts, business conditions decline at guaranteed entities, or as a result of non-performance of contractual terms by guaranteed parties.

Indemnifications

Over the years, we have entered into various lease agreements or agreements to sell ownership interests in certain corporations, joint ventures and assets that gave rise to qualifying indemnifications. Agreements associated with these leases and 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 September 30, 2013, was approximately $60 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 at September 30, 2013, were approximately $50 million of environmental accruals for known contamination that are included in the “Asset retirement obligations and accrued environmental costs” line on our consolidated balance sheet. For additional information about environmental liabilities, see Note 14—Contingencies and Commitments.

In connection with the separation of the Downstream business, the Company entered into an Indemnification and Release Agreement with Phillips 66. This agreement provided 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 14—Contingencies and Commitments

A number of lawsuits involving a variety of claims arising in the ordinary course of business have been made against ConocoPhillips. 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. With respect to 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 other 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 agency 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 and international 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 September 30, 2013, our balance sheet included a total environmental accrual of $355 million, compared with $364 million at December 31, 2012, for remediation activities in the U.S. and Canada. 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 September 30, 2013, we had performance obligations secured by letters of credit of $809 million (issued as direct bank letters of credit) related to various purchase commitments for materials, supplies, commercial activities and services 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. On September 3, 2013, an ICSID arbitration tribunal held that Venezuela unlawfully expropriated ConocoPhillips’ significant oil investments in June 2007. An additional arbitration phase is now proceeding to determine the amount of damages owed to ConocoPhillips for Venezuela’s actions.

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 the ICSID tribunal, Ecuador confiscated the crude oil production of Burlington and its co-venturer and sold the 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. On April 24, 2012, Ecuador filed a supplemental counterclaim asserting environmental damages, which we believe are not material. The ICSID tribunal issued a decision on liability on December 14, 2012, in favor of Burlington, finding that Ecuador’s seizure of Blocks 7 and 21 was an unlawful expropriation in violation of the Ecuador-U.S. Bilateral Investment Treaty. An additional arbitration phase is now proceeding to determine the damages owed to ConocoPhillips for Ecuador’s actions.

ConocoPhillips served a Notice of Arbitration on the Timor-Leste Minister of Finance in October 2012 for outstanding disputes related to a series of tax assessments. Between December 2010 and September 2013, ConocoPhillips paid, under protest, tax assessments totaling approximately $232 million, which are primarily recorded in the “Investments and long-term receivables” line on our consolidated balance sheet. The arbitration will be conducted in Singapore under the United Nations Commission on International Trade Laws (UNCITRAL) arbitration rules, pursuant to the terms of the Tax Stability Agreement with the Timor-Leste government. The arbitration process is currently underway. Future impacts on our business are not known at this time.

Note 15—Derivative and Financial Instruments

Derivative Instruments

We use futures, forwards, swaps and options in various markets to meet our customer needs and capture market opportunities. Our commodity business primarily consists of natural gas, crude oil, bitumen, LNG and natural gas liquids. Under our current business model, we are not required to register as a Swap Dealer or Major Swap Participant.

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 our 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 appear on our consolidated balance sheet:


	Millions of Dollars
	September 30		December 31
	2013		2012

Assets
Prepaid expenses and other current assets	$	871		1,538
Other assets		74		105
Liabilities
Other accruals		882		1,509
Other liabilities and deferred credits		71		99

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 September 30					Nine Months Ended September 30

	2013			2012		2013		2012


Sales and other operating revenues	$	61			(217)		(122)		(357)
Other income		-			3		3		(2)
Purchased commodities		(68	)		184		103		288

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


	Open Position Long/(Short)
	September 30			December 31
	2013			2012


Natural gas and power (billions of cubic feet equivalent)
Fixed price		(29	)		(48)
Basis		(11	)		125

Foreign Currency Exchange Derivatives

We have foreign currency exchange rate risk resulting from international operations. Our foreign currency exchange derivative activity primarily consists of transactions designed to mitigate our cash-related and foreign currency exchange rate exposures, such as firm commitments for capital projects or local currency tax payments, dividends, and cash returns from net investments in foreign affiliates. We do not elect hedge accounting on our foreign currency exchange derivatives.

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


	Millions of Dollars
	September 30		December 31
	2013		2012


Assets
Prepaid expenses and other current assets	$	12		32
Liabilities
Other accruals		1		2
Other liabilities and deferred credits		-		1

The (gains) losses from foreign currency exchange derivatives incurred, and the line item where they appear on our consolidated income statement were:


	Millions of Dollars
	Three Months Ended September 30				Nine Months Ended September 30
		2013		2012		2013	2012


Foreign currency transaction (gains) losses	$	(57	)	(39)		-	(129)

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


	In Millions
	Notional Currency
		September 30		December 31
		2013		2012


Sell U.S. dollar, buy other currencies*	USD		1,133		2,573
Buy U.S. dollar, sell other currencies**	USD		-		140
Buy British pound, sell euro	GBP		15		-
Buy euro, sell British pound	EUR		-		96

*Primarily

Norwegian krone, British pound and Canadian dollar.

**Primarily

euro, Canadian dollar and Norwegian krone.

Financial Instruments

We have certain financial instruments on our consolidated balance sheet related to interest bearing time deposits and commercial paper. The following held-to-maturity financial instruments are included in “Cash and cash equivalents” on our consolidated balance sheet:


	Millions of Dollars
	September 30 2013		December 31 2012


Cash	$	759		829
Time Deposits		3,124		2,789

	$	3,883		3,618

In conjunction with the separation of our Downstream business, we received a special cash distribution from Phillips 66. See Note 3—Discontinued Operations, for additional information. The balance of the special cash distribution was zero at September 30, 2013, and $748 million at December 31, 2012, and was included in “Restricted cash” on our consolidated balance sheet. At December 31, 2012, the funds in the restricted cash account were invested in money market funds with maturities within 90 days from December 31, 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 are placed in high-quality commercial paper, money market funds, government debt securities and time deposits with major international banks and financial institutions.

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

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

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

The aggregate fair value of all derivative instruments with such credit-risk-related contingent features that were in a liability position on September 30, 2013, and December 31, 2012, was $83 million and $130 million, respectively. For these instruments, no collateral was posted as of September 30, 2013, or December 31, 2012. If our credit rating had been lowered one level from its “A” rating (per Standard and Poor’s) on September 30, 2013, we would be required to post no additional collateral to our counterparties. If we had been downgraded below investment grade, we would be required to post $83 million of additional collateral, either with cash or letters of credit.

Note 16—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 which 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 commodity derivatives 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. 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
	September 30, 2013								December 31, 2012
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total

Assets
Deferred compensation investments	$	297		-		-		297		305		-		-		305
Commodity derivatives		718		213		11		942		1,052		567		18		1,637

Total assets	$	1,015		213		11		1,239		1,357		567		18		1,942


Liabilities
Commodity derivatives	$	724		218		8		950		1,031		567		4		1,602

Total liabilities	$	724		218		8		950		1,031		567		4		1,602

The following table summarizes those commodity derivative balances subject to the right of setoff as presented on our consolidated balance sheet:

Millions of Dollars

Gross

Net Amounts

Amounts

Excluding

Cash

Subject

Recognized

Offset

Collateral

to Setoff

September 30, 2013

Assets

928

815

113

102

Liabilities

941

815

126

105

December 31, 2012

Assets

1,621

1,403

218

189

Liabilities

1,588

1,403

185

169

At September 30, 2013, and December 31, 2012, we did not present any amounts gross on our consolidated balance sheet where we had the right of setoff.

Reported Fair Values of Financial Instruments

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

•

Cash and cash equivalents and restricted cash: 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 7—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. At September 30, 2013, and December 31, 2012, effective yield rates were 0.74 percent and 0.7 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 11—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

September 30

December 31

September 30

December 31

2013

2012

2013

2012

Financial assets

Deferred compensation investments

297

305

297

305

Commodity derivatives

119

221

119

221

Total loans and advances—related parties

1,545

1,697

1,707

1,916

Financial liabilities

Total debt, excluding capital leases

20,746

21,709

23,642

26,349

Total joint venture acquisition obligation

3,006

3,582

3,274

3,968

Commodity derivatives

117

199

117

199

Note 17—Accumulated Other Comprehensive Income

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


	Millions of Dollars
	Defined Benefit Plans			Foreign Currency Translation			Accumulated Other Comprehensive Income (Loss)


December 31, 2012	$	(1,425	)		5,512			4,087
Other comprehensive income (loss)		322			(1,697	)		(1,375	)

September 30, 2013	$	(1,103	)		3,815			2,712

The following table summarizes reclassifications out of accumulated other comprehensive income during the three- and nine-month periods ended September 30, 2013:


	Millions of Dollars
	2013
	Three Months Ended September 30		Nine Months Ended September 30


Defined Benefit Plans	$	65		133

Above amounts are included in the computation of net periodic benefit cost and are presented net of tax expense of $40 million and $83 million for the three- and nine-month periods ended September 30, 2013, respectively. See Note 19—Employee Benefit Plans, for additional information.

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

Note 18—Cash Flow Information


	Millions of Dollars
	Nine Months Ended September 30
	2013		2012


Cash Payments
Interest	$	448		596
Income taxes		4,050		6,010


Net Sales (Purchases) of Short-Term Investments
Short-term investments purchased	$	(97)		(497)
Short-term investments sold		98		1,094

	$	1		597

During the second quarter of 2013, we recognized a capital lease asset, a non-cash investing activity, and incurred a capital lease obligation, a non-cash financing activity, for $906 million. For more information about this capital lease obligation, see Note 10—Debt.

Note 19—Employee Benefit Plans

Pension and Postretirement Plans


	Millions of Dollars
	Pension Benefits								Other Benefits
	2013				2012				2013		2012

	U.S.		Int’l.		U.S.		Int’l.

Components of Net Periodic Benefit Cost
Three Months Ended September 30
Service cost	$	35		25		33		20		-		1
Interest cost		35		35		39		35		8		8
Expected return on plan assets		(47)		(40)		(47)		(37)		-		-
Amortization of prior service cost (credit)		2		(2)		1		(2)		(1)		(1)
Recognized net actuarial loss		38		18		41		13		-		-
Settlements		50		-		137		-		-		-

Net periodic benefit cost	$	113		36		204		29		7		8


Nine Months Ended September 30
Service cost	$	104		76		133		70		2		5
Interest cost		107		108		150		116		20		26
Expected return on plan assets		(140)		(120)		(177)		(120)		-		-
Amortization of prior service cost (credit)		5		(6)		5		(6)		(3)		(3)
Recognized net actuarial loss (gain)		113		55		145		46		2		(1)
Settlements		50		-		137		-		-		-

Net periodic benefit cost	$	239		113		393		106		21		27

In connection with the separation of the Downstream business on April 30, 2012, ConocoPhillips entered into an Employee Matters Agreement with Phillips 66 which provides that employees of Phillips 66 will no longer participate in benefit plans sponsored or maintained by ConocoPhillips upon separation. As such, changes in net periodic benefit cost included in the table above primarily relate to the employees of Phillips 66 no longer participating in the ConocoPhillips benefit plans for the nine-month period ended September 30, 2013.

During the first nine months of 2013, we contributed $231 million to our domestic benefit plans and $155 million to our international benefit plans.

During the three months ended September 30, 2013, we concluded that lump-sum benefit payments will exceed the sum of service and interest costs for the plan year for the U.S. qualified pension plan. As a result, we recognized a proportionate share of prior actuarial losses, or pension settlement expense, of $50 million. In conjunction with the recognition of pension settlement expense, the assets and pension benefit obligation of the qualified pension plan were remeasured. At the measurement date, the net pension liability decreased $301 million to $725 million, resulting in a corresponding increase to other comprehensive income.

During the three months ended September 30, 2012, we concluded that lump-sum benefit payments would exceed the sum of service and interest costs for the plan year for the U.S. qualified pension plan and U.S. non-qualified supplemental retirement plan. As a result, we recognized a proportionate share of prior actuarial losses, or pension settlement expense, of $137 million. In conjunction with the recognition of pension settlement expense, the assets and pension benefit obligation of the qualified pension plan were remeasured. At the measurement date, the net pension liability increased $432 million to $1,283 million, resulting in a corresponding decrease to other comprehensive income.

Note 20—Related Party Transactions

We consider our equity method investments to be related parties. Significant transactions with related parties were:


	Millions of Dollars
	Three Months Ended September 30				Nine Months Ended September 30
	2013		2012		2013		2012


Operating revenues and other income	$	35		9		74		42
Purchases*		48		92		138		228
Operating expenses and selling, general and administrative expenses		52		52		141		133
Net interest expense**		6		8		22		30

*2012 has been restated to include certain related party transactions.

**We paid interest to, or received interest from, various affiliates, including FCCL Partnership. See Note 7—Investments, Loans and Long-

Term Receivables and Note 11—Joint Venture Acquisition Obligation, for additional information on loans to affiliated companies.

Note 21—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.

On April 30, 2012, our Downstream business was separated into a stand-alone, publicly traded corporation, Phillips 66. In 2012, we also agreed to sell our Nigerian and Algerian businesses and our interest in Kashagan. Accordingly, results for these operations have 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 3—Discontinued Operations.

Corporate and Other represents costs not directly associated with an operating segment, such as most interest expense, corporate overhead, costs associated with the separation and certain technology activities, net of licensing revenues. Corporate assets include all cash and cash equivalents 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 September 30					Nine Months Ended September 30
	2013			2012		2013			2012


Sales and Other Operating Revenues
Alaska	$	2,102			2,005		6,375			7,135

Lower 48 and Latin America		4,938			4,807		14,661			14,110
Intersegment eliminations		(24	)		(40)		(79	)		(196)

Lower 48 and Latin America		4,914			4,767		14,582			13,914

Canada		1,264			1,288		3,924			3,580
Intersegment eliminations		(135	)		(117)		(448	)		(330)

Canada		1,129			1,171		3,476			3,250

Europe		3,024			3,285		8,885			10,813
Intersegment eliminations		-			-		-			(72)

Europe		3,024			3,285		8,885			10,741

Asia Pacific and Middle East		2,196			2,167		6,500			5,697
Intersegment eliminations		-			(41)		-			(41)

Asia Pacific and Middle East		2,196			2,126		6,500			5,656

Other International		262			686		1,202			1,569
Corporate and Other		16			101		139			133

Consolidated sales and other operating revenues	$	13,643			14,141		41,159			42,398


Net Income Attributable to ConocoPhillips
Alaska	$	494			535		1,719			1,706
Lower 48 and Latin America		498			182		878			556
Canada		642			(31)		780			(674)
Europe		284			132		976			1,190
Asia Pacific and Middle East		741			669		2,676			3,179
Other International		(2	)		492		26			456
Corporate and Other		(234	)		(254)		(569	)		(827)
Discontinued operations		57			73		183			1,416

Consolidated net income attributable to ConocoPhillips	$	2,480			1,798		6,669			7,002


	Millions of Dollars
	September 30 2013		December 31 2012

Total Assets
Alaska	$	11,587		10,950
Lower 48 and Latin America		29,018		28,895
Canada		22,794		22,308
Europe		16,275		15,562
Asia Pacific and Middle East		24,695		23,721
Other International		1,515		1,418
Corporate and Other		5,920		6,823
Discontinued operations		7,956		7,467

Consolidated total assets	$	119,760		117,144

Note 22—Income Taxes

Our effective tax rates from continuing operations were 45 percent for both the third quarter and first nine months of 2013, compared with 52 percent for the corresponding periods of 2012. The lower rates were primarily due to a smaller proportion of income in higher tax jurisdictions in 2013, as well as tax expense recognized in the third quarter of 2012 associated with a change in U.K. tax legislation. Additionally, the tax rate for the first nine months of 2013 reflected a favorable tax resolution associated with the sale of certain western Canada properties, which occurred in a prior year.

During the first nine months of 2013, unrecognized tax benefits decreased $220 million to $652 million at September 30, 2013, mainly due to the favorable tax resolution noted above. Included in this balance is $419 million which, if recognized, would impact our effective tax rate.

For both the third quarter and the first nine months of 2013, the effective tax rate in excess of the domestic federal statutory rate of 35 percent was primarily due to foreign taxes.

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.

Subsequent to September 30, 2013, we completed a legal amalgamation of ConocoPhillips Canada Funding Company I, ConocoPhillips Canada Funding Company II and Burlington Resources Finance Company, with the amalgamated company continuing as ConocoPhillips Canada Funding Company I. The amalgamation did not significantly change the nature of the outstanding debt of these entities or the terms of parental guarantees, which remain full and unconditional, as well as joint and several. We do not expect the amalgamation to impact our consolidated financial position, results of operations or cash flows.


	Millions of Dollars
	Three Months Ended September 30, 2013
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	$	-			4,625			-		-			-			9,018			-			13,643
Equity in earnings of affiliates		2,804			3,065			-		-			-			676			(5,836	)		709
Gain on dispositions		-			418			-		-			-			651			-			1,069
Other income		-			29			-		-			-			20			-			49
Intercompany revenues		21			27			-		22			8			1,864			(1,942	)		-

Total Revenues and Other Income		2,825			8,164			-		22			8			12,229			(7,778	)		15,470


Costs and Expenses
Purchased commodities		-			3,994			-		-			-			3,046			(1,332	)		5,708
Production and operating expenses		-			360			-		-			-			1,605			(3	)		1,962
Selling, general and administrative expenses		3			194			-		-			-			53			(1	)		249
Exploration expenses		-			157			-		-			-			156			-			313
Depreciation, depletion and amortization		-			245			-		-			-			1,657			-			1,902
Impairments		-			-			-		-			-			1			-			1
Taxes other than income taxes		-			55			-		-			-			609			-			664
Accretion on discounted liabilities		-			14			-		-			-			92			-			106
Interest and debt expense		618			85			-		19			8			27			(606	)		151
Foreign currency transaction (gains) losses		(15	)		(1	)		-		32			5			(12	)		-			9

Total Costs and Expenses		606			5,103			-		51			13			7,234			(1,942	)		11,065

Income (loss) from continuing operations before income taxes		2,219			3,061			-		(29	)		(5	)		4,995			(5,836	)		4,405
Provision for income taxes		(204	)		257			-		(1	)		1			1,913			-			1,966

Income (Loss) From Continuing Operations		2,423			2,804			-		(28	)		(6	)		3,082			(5,836	)		2,439
Income from discontinued operations		57			57			-		-			-			57			(114	)		57

Net income (loss)		2,480			2,861			-		(28	)		(6	)		3,139			(5,950	)		2,496
Less: net income attributable to noncontrolling interests		-			-			-		-			-			(16	)		-			(16)

Net Income (Loss) Attributable to ConocoPhillips	$	2,480			2,861			-		(28	)		(6	)		3,123			(5,950	)		2,480


Comprehensive Income (Loss) Attributable to ConocoPhillips	$	3,352			3,733			-		(2	)		5			3,729			(7,465	)		3,352


Income Statement	Three Months Ended September 30, 2012

Revenues and Other Income
Sales and other operating revenues	$	-			4,028			-		-			-			10,113			-			14,141
Equity in earnings of affiliates		2,098			2,485			-		-			-			332			(4,503	)		412
Gain on dispositions		-			3			-		-			-			115			-			118
Other income (loss)		(78	)		100			-		-			-			20			-			42
Intercompany revenues		21			94			11		22			8			751			(907	)		-

Total Revenues and Other Income		2,041			6,710			11		22			8			11,331			(5,410	)		14,713


Costs and Expenses
Purchased commodities		-			3,470			-		-			-			3,258			(371	)		6,357
Production and operating expenses		-			313			-		-			-			1,326			(2	)		1,637
Selling, general and administrative expenses		2			260			-		-			-			67			-			329
Exploration expenses		-			101			-		-			-			114			-			215
Depreciation, depletion and amortization		-			197			-		-			-			1,453			-			1,650
Taxes other than income taxes		-			57			-		-			-			616			-			673
Accretion on discounted liabilities		-			13			-		-			-			87			-			100
Interest and debt expense		542			76			10		19			8			40			(534	)		161
Foreign currency transaction (gains) losses		(28	)		(7	)		-		46			46			(57	)		-			-

Total Costs and Expenses		516			4,480			10		65			54			6,904			(907	)		11,122

Income (loss) from continuing operations before income taxes		1,525			2,230			1		(43	)		(46	)		4,427			(4,503	)		3,591
Provision for income taxes		(200	)		132			-		1			(6	)		1,924			-			1,851

Income (Loss) From Continuing Operations		1,725			2,098			1		(44	)		(40	)		2,503			(4,503	)		1,740
Income from discontinued operations		73			73			-		-			-			70			(143	)		73

Net income (loss)		1,798			2,171			1		(44	)		(40	)		2,573			(4,646	)		1,813
Less: net income attributable to noncontrolling interests		-			-			-		-			-			(15	)		-			(15)

Net Income (Loss) Attributable to ConocoPhillips	$	1,798			2,171			1		(44	)		(40	)		2,558			(4,646	)		1,798


Comprehensive Income (Loss) Attributable to ConocoPhillips	$	2,260			2,633			1		7			(20	)		3,280			(5,901	)		2,260


	Millions of Dollars
	Nine Months Ended September 30, 2013
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	$	-			13,710		-		-			-			27,449			-			41,159
Equity in earnings of affiliates		7,644			8,750		-		-			-			1,639			(16,468	)		1,565
Gain on dispositions		-			419		-		-			-			803			-			1,222
Other income		1			237		-		-			-			79			-			317
Intercompany revenues		62			108		13		66			25			5,258			(5,532	)		-

Total Revenues and Other Income		7,707			23,224		13		66			25			35,228			(22,000	)		44,263


Costs and Expenses
Purchased commodities		-			11,901		-		-			-			8,868			(3,706	)		17,063
Production and operating expenses		-			1,047		-		-			-			4,297			(23	)		5,321
Selling, general and administrative expenses		9			444		-		-			-			173			(19	)		607
Exploration expenses		-			491		-		-			-			420			-			911
Depreciation, depletion and amortization		-			674		-		-			-			4,867			-			5,541
Impairments		-			-		-		-			-			31			-			31
Taxes other than income taxes		-			180		-		-			-			2,018			-			2,198
Accretion on discounted liabilities		-			42		-		-			-			275			-			317
Interest and debt expense		1,809			245		12		58			24			56			(1,784	)		420
Foreign currency transaction (gains) losses		26			8		-		(38	)		(25	)		(5	)		-			(34)

Total Costs and Expenses		1,844			15,032		12		20			(1	)		21,000			(5,532	)		32,375

Income from continuing operations before income taxes		5,863			8,192		1		46			26			14,228			(16,468	)		11,888
Provision for income taxes		(623	)		548		-		1			2			5,431			-			5,359

Income From Continuing Operations		6,486			7,644		1		45			24			8,797			(16,468	)		6,529
Income from discontinued operations		183			183		-		-			-			183			(366	)		183

Net income		6,669			7,827		1		45			24			8,980			(16,834	)		6,712
Less: net income attributable to noncontrolling interests		-			-		-		-			-			(43	)		-			(43)

Net Income Attributable to ConocoPhillips	$	6,669			7,827		1		45			24			8,937			(16,834	)		6,669


Comprehensive Income (Loss) Attributable to ConocoPhillips	$	5,294			6,452		1		(1	)		6			7,263			(13,721	)		5,294


Income Statement	Nine Months Ended September 30, 2012

Revenues and Other Income
Sales and other operating revenues	$	-			12,598		-		-			-			29,800			-			42,398
Equity in earnings of affiliates		6,680			7,617		-		-			-			1,365			(14,231	)		1,431
Gain on dispositions		-			3		-		-			-			1,638			-			1,641
Other income (loss)		(77	)		155		-		-			-			90			-			168
Intercompany revenues		40			779		34		67			25			3,192			(4,137	)		-

Total Revenues and Other Income		6,643			21,152		34		67			25			36,085			(18,368	)		45,638


Costs and Expenses
Purchased commodities		-			11,044		-		-			-			9,484			(2,372	)		18,156
Production and operating expenses		-			917		-		-			-			4,102			(21	)		4,998
Selling, general and administrative expenses		10			690		-		-			-			199			(9	)		890
Exploration expenses		-			287		-		-			-			868			-			1,155
Depreciation, depletion and amortization		-			605		-		-			-			4,196			-			4,801
Impairments		-			-		-		-			-			296			-			296
Taxes other than income taxes		-			207		-		-			-			2,461			-			2,668
Accretion on discounted liabilities		-			39		-		-			-			269			-			308
Interest and debt expense		1,668			247		31		58			24			255			(1,735	)		548
Foreign currency transaction (gains) losses		(30	)		19		-		34			47			(53	)		-			17

Total Costs and Expenses		1,648			14,055		31		92			71			22,077			(4,137	)		33,837

Income (loss) from continuing operations before income taxes		4,995			7,097		3		(25	)		(46	)		14,008			(14,231	)		11,801
Provision for income taxes		(589	)		417		1		7			(6	)		6,332			-			6,162

Income (Loss) From Continuing Operations		5,584			6,680		2		(32	)		(40	)		7,676			(14,231	)		5,639
Income from discontinued operations		1,418			1,418		-		-			-			1,162			(2,580	)		1,418

Net income (loss)		7,002			8,098		2		(32	)		(40	)		8,838			(16,811	)		7,057
Less: net income attributable to noncontrolling interests		-			-		-		-			-			(55	)		-			(55)

Net Income (Loss) Attributable to ConocoPhillips	$	7,002			8,098		2		(32	)		(40	)		8,783			(16,811	)		7,002


Comprehensive Income (Loss) Attributable to ConocoPhillips	$	7,881			8,968		2		24			(18	)		9,356			(18,332	)		7,881


	Millions of Dollars
	September 30, 2013
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	$	-			190		-		54			2			3,637		-			3,883
Accounts and notes receivable		67			2,002		2		-			-			9,996		(3,662	)		8,405
Inventories		-			217		-		-			-			1,051		-			1,268
Prepaid expenses and other current assets		17			458		-		1			-			8,525		-			9,001

Total Current Assets		84			2,867		2		55			2			23,209		(3,662	)		22,557
Investments, loans and long-term receivables*		87,333			122,246		-		1,428			568			45,949		(232,358	)		25,166
Net properties, plants and equipment		-			9,082		-		-			-			62,047		-			71,129
Other assets		39			254		-		1			3			611		-			908

Total Assets	$	87,456			134,449		2		1,484			573			131,816		(236,020	)		119,760


Liabilities and Stockholders’ Equity
Accounts payable	$	-			4,164		-		3			1			9,827		(3,662	)		10,333
Short-term debt		395			4		-		-			-			173		-			572
Accrued income and other taxes		-			173		-		6			-			2,732		-			2,911
Employee benefit obligations		-			461		-		-			-			217		-			678
Other accruals		119			623		-		32			14			1,053		-			1,841

Total Current Liabilities		514			5,425		-		41			15			14,002		(3,662	)		16,335
Long-term debt		9,049			5,210		-		1,250			499			5,088		-			21,096
Asset retirement obligations and accrued environmental costs		-			1,270		-		-			-			7,889		-			9,159
Joint venture acquisition obligation		-			-		-		-			-			2,203		-			2,203
Deferred income taxes		54			320		-		14			9			14,348		-			14,745
Employee benefit obligations		-			2,049		-		-			-			798		-			2,847
Other liabilities and deferred credits*		33,564			22,942		-		79			24			17,778		(72,549	)		1,838

Total Liabilities		43,181			37,216		-		1,384			547			62,106		(76,211	)		68,223
Retained earnings		32,964			31,925		-		(34	)		(51	)		37,440		(62,718	)		39,526
Other common stockholders’ equity		11,311			65,308		2		134			77			31,846		(97,091	)		11,587
Noncontrolling interests		-			-		-		-			-			424		-			424

Total Liabilities and Stockholders’ Equity	$	87,456			134,449		2		1,484			573			131,816		(236,020	)		119,760


Balance Sheet	December 31, 2012

Assets
Cash and cash equivalents	$	2			12		6		50			2			3,546		-			3,618
Restricted cash		748			-		-		-			-			-		-			748
Accounts and notes receivable**		64			2,711		-		-			-			11,494		(5,087	)		9,182
Inventories		-			57		-		-			-			908		-			965
Prepaid expenses and other current assets		19			847		-		1			-			8,609		-			9,476

Total Current Assets		833			3,627		6		51			2			24,557		(5,087	)		23,989
Investments, loans and long-term receivables*		80,910			114,314		759		1,455			578			44,739		(217,749	)		25,006
Net properties, plants and equipment		-			8,771		-		-			-			58,492		-			67,263
Other assets		55			216		-		2			3			610		-			886

Total Assets	$	81,798			126,928		765		1,508			583			128,398		(222,836	)		117,144


Liabilities and Stockholders’ Equity
Accounts payable**	$	-			5,531		-		4			1			9,564		(5,087	)		10,013
Short-term debt		(5	)		4		750		-			-			206		-			955
Accrued income and other taxes		-			104		-		3			-			3,259		-			3,366
Employee benefit obligations		-			485		-		-			-			257		-			742
Other accruals		209			636		9		15			4			1,494		-			2,367

Total Current Liabilities		204			6,760		759		22			5			14,780		(5,087	)		17,443
Long-term debt		9,453			5,215		-		1,250			499			4,353		-			20,770
Asset retirement obligations and accrued environmental costs		-			1,250		-		-			-			7,697		-			8,947
Joint venture acquisition obligation		-			-		-		-			-			2,810		-			2,810
Deferred income taxes		15			598		-		16			7			12,549		-			13,185
Employee benefit obligations		-			2,464		-		-			-			882		-			3,346
Other liabilities and deferred credits*		30,938			19,916		-		117			50			21,174		(69,979	)		2,216

Total Liabilities		40,610			36,203		759		1,405			561			64,245		(75,066	)		68,717
Retained earnings		28,815			24,041		4		(78	)		(73	)		30,778		(48,149	)		35,338
Other common stockholders’ equity		12,373			66,684		2		181			95			32,935		(99,621	)		12,649
Noncontrolling interests		-			-		-		-			-			440		-			440

Total Liabilities and Stockholders’ Equity	$	81,798			126,928		765		1,508			583			128,398		(222,836	)		117,144

*Includes intercompany loans.

**Revised to conform to current-year presentation in the ConocoPhillips Company and All Other Subsidiaries columns at December 31, 2012. There was no impact to Total Consolidated balances.


	Millions of Dollars
Statement of Cash Flows	Nine Months Ended September 30, 2013
	ConocoPhillips			ConocoPhillips Company			ConocoPhillips Australia Funding Company			ConocoPhillips Canada Funding Company I		ConocoPhillips Canada Funding Company II		All Other Subsidiaries			Consolidating Adjustments			Total Consolidated
Cash Flows From Operating Activities
Net cash provided by (used in) continuing operating activities	$	1,717			2,618			(2	)		4		-		9,559			(1,955	)		11,941
Net cash provided by discontinued operations		-			-			-			-		-		631			(396	)		235

Net Cash Provided by (Used in) Operating Activities		1,717			2,618			(2	)		4		-		10,190			(2,351	)		12,176


Cash Flows From Investing Activities
Capital expenditures and investments		-			(1,795	)		-			-		-		(9,825	)		339			(11,281)
Proceeds from asset dispositions		-			581			-			-		-		2,646			(52	)		3,175
Net purchases of short-term investments		-			-			-			-		-		1			-			1
Long-term advances/loans—related parties		-			(283	)		-			-		-		(715	)		998			-
Collection of advances/loans—related parties		-			266			750			-		-		2,026			(2,912	)		130
Other		-			3			-			-		-		(54	)		-			(51)

Net cash provided by (used in) continuing investing activities		-			(1,228	)		750			-		-		(5,921	)		(1,627	)		(8,026)
Net cash used in discontinued operations		-			-			-			-		-		(540	)		-			(540)

Net Cash Provided by (Used in) Investing Activities		-			(1,228	)		750			-		-		(6,461	)		(1,627	)		(8,566)


Cash Flows From Financing Activities
Issuance of debt		-			697			-			-		-		301			(998	)		-
Repayment of debt		-			(1,939	)		(750	)		-		-		(1,169	)		2,912			(946)
Change in restricted cash		748			-			-			-		-		-			-			748
Issuance of company common stock		12			-			-			-		-		-			-			12
Dividends paid		(2,481	)		-			(4	)		-		-		(2,257	)		2,261			(2,481)
Other		2			39			-			-		-		(346	)		(288	)		(593)

Net cash used in continuing financing activities		(1,719	)		(1,203	)		(754	)		-		-		(3,471	)		3,887			(3,260)
Net cash used in discontinued operations		-			-			-			-		-		(91	)		91			-

Net Cash Used in Financing Activities		(1,719	)		(1,203	)		(754	)		-		-		(3,562	)		3,978			(3,260)


Effect of Exchange Rate Changes on Cash and Cash Equivalents		-			(9	)		-			-		-		(76	)		-			(85)

Net Change in Cash and Cash Equivalents		(2	)		178			(6	)		4		-		91			-			265
Cash and cash equivalents at beginning of period		2			12			6			50		2		3,546			-			3,618

Cash and Cash Equivalents at End of Period	$	-			190			-			54		2		3,637			-			3,883


Statement of Cash Flows	Nine Months Ended September 30, 2012

Cash Flows From Operating Activities
Net cash provided by continuing operating activities	$	3,530			12,271			2			7		-		4,247			(10,469	)		9,588
Net cash provided by (used in) discontinued operations		-			479			-			-		-		(15	)		-			464

Net Cash Provided by Operating Activities		3,530			12,750			2			7		-		4,232			(10,469	)		10,052


Cash Flows From Investing Activities
Capital expenditures and investments		(317	)		(5,558	)		-			-		-		(9,531	)		4,686			(10,720)
Proceeds from asset dispositions		14			933			-			-		-		2,086			(945	)		2,088
Net sales of short-term investments		-			-			-			-		-		597			-			597
Long-term advances/loans—related parties		-			(74	)		-			-		-		(2,881	)		2,955			-
Collection of advances/loans—related parties		-			133			-			-		-		1,092			(1,125	)		100
Other		-			4			-			-		-		171			-			175

Net cash used in continuing investing activities		(303	)		(4,562	)		-			-		-		(8,466	)		5,571			(7,760)
Net cash provided by (used in) discontinued operations		-			(232	)		-			-		-		7,395			(8,101	)		(938)

Net Cash Used in Investing Activities		(303	)		(4,794	)		-			-		-		(1,071	)		(2,530	)		(8,698)


Cash Flows From Financing Activities
Issuance of debt		485			3,000			-			-		-		55			(3,055	)		485
Repayment of debt		(1,576	)		(9,241	)		-			-		-		(177	)		9,326			(1,668)
Special cash distribution from Phillips 66		7,818			-			-			-		-		-			-			7,818
Change in restricted cash		(2,468	)		-			-			-		-		-			-			(2,468)
Issuance of company common stock		83			-			-			-		-		-			-			83
Repurchase of company common stock		(5,098	)		-			-			-		-		-			-			(5,098)
Dividends paid		(2,469	)		-			-			-		-		(4,822	)		4,822			(2,469)
Other		(1	)		63			-			-		-		(1,540	)		931			(547)

Net cash used in continuing financing activities		(3,226	)		(6,178	)		-			-		-		(6,484	)		12,024			(3,864)
Net cash provided by (used in) discontinued operations		-			(3,786	)		-			-		-		792			975			(2,019)

Net Cash Used in Financing Activities		(3,226	)		(9,964	)		-			-		-		(5,692	)		12,999			(5,883)


Effect of Exchange Rate Changes on Cash and Cash Equivalents		-			(8	)		-			-		-		25			-			17

Net Change in Cash and Cash Equivalents		1			(2,016	)		2			7		-		(2,506	)		-			(4,512)
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	$	1			12			3			44		1		1,207			-			1,268

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 in 2012, the sale of our interest in the North Caspian Sea Production Sharing Agreement (Kashagan) on October 31, 2013, and the intention to sell our Nigerian and Algerian businesses, which are all reported as discontinued operations, income (loss) from continuing operations is more representative of ConocoPhillips’ earnings. 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 production and proved reserves. Headquartered in Houston, Texas, we have operations and activities in 29 countries. At September 30, 2013, we had approximately 18,000 employees worldwide and total assets of $120 billion.

Discontinued Operations

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 (collectively, our “Downstream business”), were transferred to Phillips 66. As part of our asset disposition program, in the fourth quarter of 2012, we agreed to sell our interest in Kashagan and our Nigerian and Algerian businesses. Results of operations related to Phillips 66, Kashagan, Nigeria and Algeria have been classified as discontinued operations in all periods presented in this Form 10-Q. For additional information, see Note 3—Discontinued Operations, in the Notes to Consolidated Financial Statements.

Overview

We are an independent E&P company focused on exploring for, developing and producing crude oil and natural gas globally. Our asset base reflects our legacy as a major company with a strategic focus on higher-margin developments. Our diverse portfolio primarily includes resource-rich North American shale and oil sands assets; lower-risk legacy assets in Alaska, Europe, Asia and Australia; several major international developments; and a growing conventional and unconventional inventory of global exploration prospects. Our value proposition to our shareholders is to deliver production and cash margin growth, competitive returns on capital, and a compelling dividend, while keeping our fundamental commitment to safety, operating excellence and environmental stewardship. We expect to achieve this value proposition through optimizing our portfolio, investing in high-margin developments, applying technical capability and maintaining financial flexibility.

In the third quarter of 2013, we achieved production of 1,514 thousand barrels of oil equivalent per day (MBOED), including production from discontinued operations of 44 MBOED. Consistent with our commitment to offer our shareholders a compelling dividend, in July 2013, our Board of Directors increased our quarterly dividend by 4.5 percent to $0.69 per share. Through September 2013, we generated $11.9 billion in cash from continuing operations, paid dividends on our common stock of $2.5 billion, funded an $11.9 billion capital program and continued to progress the asset disposition program.

During the first nine months of 2013, we received proceeds from dispositions of $3.2 billion, which mainly resulted from:

•

The sale of our Clyden undeveloped oil sands leasehold, located in Canada.

•

The disposition of our 39 percent equity investment in Phoenix Park Gas Processors Limited, located in Trinidad and Tobago.

•

The sale of certain properties in the Cedar Creek Anticline, located in North Dakota and Montana.

•

The disposition of a portion of our working interests in the Poseidon discovery in the Browse Basin and the Goldwyer Shale in the Canning Basin.

•

The disposition of certain properties located in southwest Louisiana.

•

The sale of our 10 percent interest in the Interconnector Pipeline, located in Europe.

On October 31, 2013, we received additional proceeds of $5.4 billion from the disposition of our 8.4 percent interest in Kashagan. As part of our 2012–2013 disposition program, we have generated $10.7 billion in proceeds through October 31, 2013, which has exceeded our goal of raising $8–$10 billion in proceeds from disposition of non-strategic assets during 2012 and 2013. The previously announced sales of Nigeria, excluding Brass LNG, and Algeria are targeted to close by the end of 2013 and generate approximately $3.4 billion in proceeds, plus customary adjustments. The sale of Brass LNG is targeted to close in the first quarter of 2014 and would generate approximately $105 million in proceeds.

Because we participate in a capital-intensive industry, we make significant investments to acquire acreage, explore for new oil and gas fields, develop newly discovered fields, maintain existing fields, and construct pipelines and liquefied natural gas (LNG) facilities. We expect our full-year 2013 capital program will be approximately $16 billion for continuing operations and $0.6 billion for discontinued operations. We use a disciplined approach to select the appropriate projects which will provide the most attractive investment opportunities, with a continued focus on higher-margin liquids plays and limited investment in North American conventional natural gas. As investments bring more liquids production online, we expect a corresponding shift in our production mix. However, there are often long lead times from the time we make an investment to the time the investment is operational and begins generating financial returns. In the near-term, we plan to fund a portion of our capital program with the proceeds from asset dispositions. Over the next five years, our investment in high-margin developments should position us to deliver 3 to 5 percent annual production volume and margin growth, enabling us to fund our capital program organically.

Business Environment

The business environment for the energy industry has historically experienced many challenges which have influenced our operations and profitability, largely due to factors beyond our control, such as the global financial crisis and recession which began in 2008, geopolitical events or fears thereof, environmental laws, tax regulations, governmental policies, and weather-related disruptions. More recently, North America’s energy landscape has been transformed from resource scarcity to an abundance of supply, as a result of advances in technology responsible for the rapid growth of shale production, successful development in the deepwater Gulf of Mexico and rising production from the Canadian oil sands. These dynamics generally influence world energy markets and commodity prices. The most significant factor impacting our profitability and related reinvestment of operating cash flows into our business is commodity prices, which can be very volatile; therefore, our strategy is to maintain a strong balance sheet with a diverse portfolio of assets, which we believe will provide the financial flexibility to withstand challenging business cycles.

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
September 30

Nine Months Ended
September 30

2013

2012

2013

2012

Market Indicators

WTI (per barrel)

105.80

92.11

98.07

96.18

Dated Brent (per barrel)

110.32

109.61

108.44

112.09

U.S. Henry Hub first of month (per million British thermal units)

3.58

2.80

3.67

2.58

Industry crude prices for WTI increased 15 percent in the third quarter of 2013, compared with the same period in 2012, as new infrastructure allowed increased movement of physical barrels away from Cushing, Oklahoma, and toward the U.S. Gulf Coast refining centers. Brent prices remained relatively flat in the third quarter of 2013, as growth in global oil demand was met by rising production, primarily stemming from U.S. oil production.

Henry Hub natural gas prices increased 28 percent in the third quarter of 2013, compared with the same period in 2012, as storage inventories were much lower in 2013.

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 17 percent in the first nine months of 2013, compared with the same period of 2012. Bitumen prices continued to strengthen during the third quarter of 2013, as a result of fewer infrastructure constraints downstream of the Hardisty Terminal, which have more than offset the increase in supplies. Our realized bitumen price was $76.06 per barrel in the third quarter of 2013, an increase of 34 percent compared with the third quarter of 2012.

Key Operating and Financial Highlights

Significant highlights during the third quarter of 2013 included the following:

•

Achieved third-quarter guidance with production of 1,514 MBOED, including continuing operations of 1,470 MBOED, which reflects two months of disruptions in Libya, and discontinued operations of 44 MBOED.

•

Successfully completed major turnarounds and tie-in activities as planned.

•

Eagle Ford, Bakken and Permian production increased 40 percent compared with third-quarter 2012.

•

Started up major projects at Christina Lake Phase E in July and Ekofisk South in October, with final preparations underway for full-field startup at Gumusut, Jasmine and Siakap North-Petai.

•

High level of exploration activity continues with drilling in the Gulf of Mexico, Australia’s Browse Basin, and unconventional plays in Canada and the Lower 48.

•

Completed sale of Clyden and our interest in Phoenix Park.

Outlook

Fourth-quarter production from continuing operations is expected to be 1,485 to 1,525 MBOED, which reflects a 50 MBOED reduction for the assumed closure of the Es Sider crude oil export terminal in Libya for the entire quarter. Full-year 2013 production from continuing operations is expected to be 1,505 to 1,515 MBOED. Full-year production from discontinued operations is expected to be 35 to 45 MBOED.

Freeport LNG

In July 2013, we reached agreement with Freeport LNG to terminate our long-term agreement at the Freeport LNG Terminal, subject to Freeport LNG obtaining regulatory approval and project financing for an LNG liquefaction and export facility in Texas, in which we are not a participant. Upon satisfaction of these conditions, currently expected to occur by the end of the first quarter of 2014, we will pay Freeport LNG a termination fee of approximately $600 million. Freeport LNG will repay the outstanding ConocoPhillips loan used by Freeport to partially fund the original construction of the terminal. These transactions, plus miscellaneous items, will result in a net cash outflow of approximately $80 million for us. When the agreement becomes effective, we also expect to recognize an after-tax charge to earnings of approximately $540 million. At that time, our terminal regasification capacity will be reduced from 0.9 billion cubic feet per day to 0.4 billion cubic feet per day, until July 1, 2016, at which time it will be reduced to zero. As a result of this transaction, we anticipate saving approximately $50 to $60 million per year in operating costs over the next 19 years. For additional information, see Note 4—Variable Interest Entities (VIEs), in the Notes to Consolidated Financial Statements.

RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three- and nine-month periods ended September 30, 2013, is based on a comparison with the corresponding periods of 2012.

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


	Millions of Dollars
	Three Months Ended September 30					Nine Months Ended September 30
	2013			2012		2013			2012


Alaska	$	494			535		1,719			1,706
Lower 48 and Latin America		498			182		878			556
Canada		642			(31)		780			(674)
Europe		284			132		976			1,190
Asia Pacific and Middle East		757			684		2,719			3,232
Other International		(2	)		492		26			456
Corporate and Other		(234	)		(254)		(569	)		(827)

Income from continuing operations	$	2,439			1,740		6,529			5,639

Earnings for ConocoPhillips increased 40 percent in the third quarter of 2013, while earnings for the nine-month period ended September 30, 2013, increased 16 percent. The improvements in the third quarter of 2013 primarily resulted from:

•

Higher gains from asset sales. Gains realized in the third quarter of 2013 were $777 million after-tax, compared with gains of $336 million after-tax in the third quarter of 2012.

•

Higher commodity prices.

•

A higher proportion of production in higher-margin areas and a continued portfolio shift toward liquids.

•

The absence of $170 million in additional income tax expense, as a result of legislation enacted in the United Kingdom in 2012.

These items were partially offset by:

•

Higher depreciation, depletion and amortization (DD&A) expenses, mainly due to higher volumes in the Lower 48.

•

Higher operating expenses, mainly due to a $116 million after-tax charge related to a pending settlement in the Asia Pacific and Middle East segment, as well as increased production volumes and activity in the Lower 48 and the Asia Pacific region.

The increase in earnings in the nine-month period of 2013 was primarily due to:

•

Lower impairments. Non-cash impairments for the nine-month period of 2013 totaled $20 million after-tax, compared with $550 million after-tax in the nine-month period of 2012.

•

A higher proportion of production in higher-margin areas and a continued portfolio shift toward liquids.

•

Higher natural gas prices.

•

Lower production taxes, primarily as a result of lower production volumes and prices and higher capital spending in Alaska.

•

The favorable resolution of pending claims and settlements of $234 million after-tax.

•

Absence of the 2012 U.K. tax increase of $170 million and separation costs of $80 million after-tax.

These items were partially offset by:

•

Higher DD&A expenses, mainly due to higher volumes in the Lower 48 and China.

•

Lower gains from asset sales. Gains realized in the nine-month period of 2013 were $1,118 million after-tax, compared with gains of $1,557 million after-tax in the nine-month period of 2012.

•

Lower crude oil, natural gas liquids and LNG prices.

•

Higher operating expenses, which included a $116 million after-tax charge related to a pending settlement in Asia Pacific and Middle East, and higher dry hole expenses.

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

Income Statement Analysis

Equity in earnings of affiliates increased 72 percent in third quarter and 9 percent in the nine-month period of 2013. The increases primarily resulted from:

•

Higher earnings from FCCL Partnership, mainly as a result of higher bitumen prices and volumes.

•

Higher earnings from Qatar Liquefied Gas Company Limited (3) (QG3), largely due to higher LNG volumes.

Gain on dispositions increased $951 million in the third quarter and decreased $419 million in the nine-month period of 2013. Gains realized in the third quarter of 2013 primarily resulted from the disposition of our Clyden undeveloped oil sands leasehold and the disposition of our 39 percent equity interest in Phoenix Park. Gains realized in the third quarter of 2012 mostly resulted from the disposition of our equity investment in Naryanmarneftegaz (NMNG), partly offset by the loss on further dilution of our equity interest in Australia Pacific LNG (APLNG) from 42.5 percent to 37.5 percent.

Additional gains realized in the nine-month period of 2013 mainly resulted from the disposition of our interest in the Interconnector Pipeline, partly offset by a loss on the disposition of certain properties located in the Cedar Creek Anticline. Gains in the nine-month period of 2012 also included the $937 million gain on sale of our Vietnam business and the gain on sale of the Statfjord and Alba fields located in the North Sea.

Other income increased 89 percent in the nine-month period of 2013, largely as a result of a $150 million insurance settlement associated with the Bohai Bay seepage incidents.

Purchased commodities decreased 10 percent in the third quarter and 6 percent in the nine-month period of 2013, largely as a result of lower purchased natural gas volumes, partly offset by higher natural gas prices.

Production and operating expenses increased 20 percent in the third quarter and 6 percent in the nine-month period of 2013, primarily as a result of increased drilling activity and production volumes, mostly in the Lower 48, in addition to a charge related to a pending settlement in Asia Pacific and Middle East.

Selling, general and administrative expenses decreased 24 percent in the third quarter and 32 percent in the nine-month period of 2013, mainly due to lower pension settlement expense. The nine-month period of 2013 also benefitted from the absence of separation costs, as well as lower costs related to compensation and benefit plans. For additional information, see Note 19—Employee Benefit Plans, in the Notes to Consolidated Financial Statements.

Exploration expenses increased 46 percent in the third quarter and decreased 21 percent in the nine-month period of 2013. Both periods of 2013 were impacted by higher dry hole costs. The nine-month period of 2012 also included the $481 million impairment of undeveloped leasehold costs associated with the Mackenzie Gas Project as a result of the indefinite suspension of the project.

DD&A increased 15 percent in both the third quarter and nine-month period of 2013. The increase was mostly associated with higher production volumes in the Lower 48. In addition, higher production volumes in China contributed to the increase in the nine-month period of 2013.

Impairments decreased 90 percent in the nine-month period of 2013. The nine-month period of 2012 included a $213 million impairment of capitalized project development costs associated with the Mackenzie Gas Project, in addition to an increase in the asset retirement obligation for the U.K. Don Field, which has ceased production. For additional information, see Note 9—Impairments, in the Notes to Consolidated Financial Statements.

Taxes other than income taxes decreased 18 percent in the nine-month period of 2013, mainly as a result of lower production taxes due to lower crude oil production volumes and prices and higher capital spending in Alaska.

Interest and debt expense decreased 23 percent in the nine-month period of 2013, primarily due to lower interest expense from lower average debt levels and higher capitalized interest on projects.

See Note 22—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 September 30				Nine Months Ended September 30
	2013		2012		2013		2012

Average Net Production
Crude oil (MBD)*		552		553		587		587
Natural gas liquids (MBD)		156		151		158		155
Bitumen (MBD)		107		92		105		88
Natural gas (MMCFD)**		3,930		4,037		3,963		4,100


Total Production (MBOED)		1,470		1,470		1,511		1,514


	Dollars Per Unit
Average Sales Prices
Crude oil (per barrel)	$	106.60		102.54		104.20		106.66
Natural gas liquids (per barrel)		41.14		41.08		40.64		46.84
Bitumen (per barrel)		76.06		56.86		57.08		56.23
Natural gas (per thousand cubic feet)		5.99		5.28		6.14		5.38


	Millions of Dollars
Exploration Expenses
General administrative; geological and geophysical; and lease rentals	$	180		146		566		452
Leasehold impairment		32		63		142		627
Dry holes		101		6		203		76

	$	313		215		911		1,155

Excludes discontinued operations.

*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.

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. At September 30, 2013, our continuing operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, Timor-Leste, Indonesia, China, Malaysia, Qatar, Libya and Russia.

Total production from continuing operations remained flat in both the third quarter and nine-month period of 2013, compared with the corresponding periods of 2012, while average liquids production increased 2 percent over the same periods. Production increased in both periods of 2013 due to new production from major developments, mainly from the Lower 48, Christina Lake in Canada, and Malaysia; higher production in China; and increased drilling programs, mostly in western Canada, the Lower 48 and Norway. However, these increases were offset by normal field decline, the impact of the disruption in Libya, due to the closure of the Es Sider crude oil export terminal, and asset dispositions. Excluding dispositions, downtime and the impact from the closure of the Es Sider Terminal in Libya, production grew by 29 MBOED, or 2 percent, compared with the third quarter of 2012, and 51 MBOED, or 3 percent, compared with the nine-month period of 2012.

Segment Results

Alaska


	Three Months Ended September 30				Nine Months Ended September 30
	2013		2012		2013		2012


Income From Continuing Operations (millions of dollars)	$	494		535		1,719		1,706


Average Net Production
Crude oil (MBD)		161		157		176		185
Natural gas liquids (MBD)		11		10		15		15
Natural gas (MMCFD)		35		51		43		55


Total Production (MBOED)		178		176		198		209


Average Sales Prices
Crude oil (dollars per barrel)	$	110.95		106.53		109.14		110.54
Natural gas (dollars per thousand cubic feet)		4.09		3.97		4.56		4.21

The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids and natural gas. As of September 30, 2013, Alaska contributed 22 percent of our worldwide liquids production and 1 percent of our natural gas production.

Alaska’s earnings decreased 8 percent in the third quarter and increased 1 percent in the nine-month period of 2013, compared with the same periods of 2012. The decrease in earnings in the third quarter of 2013 was mostly due to lower crude oil sales volumes, partly offset by higher crude oil prices and lower production taxes. The increase in earnings in the nine-month period of 2013 was mainly due to lower production taxes, which resulted from lower prices, higher 2013 capital spending and lower crude oil production volumes. Earnings also improved in the nine-month period of 2013 due to the impact of a ruling by the Federal Energy Regulatory Commission (FERC), as more fully described below. These increases to earnings were nearly offset by lower crude oil and LNG sales volumes and lower crude oil prices.

In 2012, the major owners of Trans-Alaska Pipeline System (TAPS) filed a proposed settlement with FERC to resolve pooling disputes prior to August 2012 and establish a voluntary pooling agreement to pool costs prospectively from August 2012. In July 2013, the FERC approved the proposed settlement and pooling agreement without modification. Under the terms of the agreements, we paid the other remaining owners of TAPS $355 million, including interest, in the third quarter of 2013. As a result of FERC approval of these agreements, we reduced a related accrual in the second quarter of 2013, which decreased our production and operating expenses by $97 million after-tax. The FERC ruling approving these agreements has been appealed by certain parties to the Court of Appeals for the District of Columbia.

Average production increased 1 percent in the third quarter and decreased 5 percent in the nine-month period of 2013. The increase in the third quarter of 2013 was mainly due to less turnaround activity, partly offset by normal field decline. The reduction in the nine-month period of 2013 was mostly due to normal field decline, partly offset by lower planned maintenance.

Chukchi Sea

In April 2013, we announced our 2014 Chukchi Sea exploration drilling plans are on hold given the uncertainties of evolving federal regulatory requirements and operational permitting standards. Once these requirements are clarified and better defined, we will re-evaluate our Chukchi Sea drilling plans.

Lower 48 and Latin America


	Three Months Ended September 30				Nine Months Ended September 30
	2013		2012		2013		2012


Income From Continuing Operations (millions of dollars)	$	498		182		878		556


Average Net Production
Crude oil (MBD)		153		124		149		119
Natural gas liquids (MBD)		94		87		91		85
Natural gas (MMCFD)		1,511		1,507		1,490		1,489


Total Production (MBOED)		499		462		488		452


Average Sales Prices
Crude oil (dollars per barrel)	$	100.25		90.06		95.92		92.84
Natural gas liquids (dollars per barrel)		32.57		31.40		30.52		36.89
Natural gas (dollars per thousand cubic feet)		3.39		2.64		3.48		2.47

As of September 30, 2013, Lower 48 and Latin America contributed 28 percent of our worldwide liquids production and 38 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, as well as exploration activities in the Gulf of Mexico and Colombia.

Lower 48 and Latin America operations reported earnings of $498 million in the third quarter of 2013, a 174 percent increase compared with the same period in 2012. Earnings for the nine-month period of 2013 were $878 million, a 58 percent increase compared with the same period in 2012. Earnings for both periods of 2013 largely benefitted from the $288 million after-tax gain on disposition of our equity investment in Phoenix Park, higher crude oil volumes and higher crude oil and natural gas prices. These increases to earnings were partially offset by higher DD&A, due to higher crude oil production. Higher operating expenses and a $48 million after-tax charge for the Ardennes dry hole, located in the Gulf of Mexico, also partly offset the increase to earnings.

Earnings in the nine-month period of 2013 were also negatively impacted by lower natural gas liquids prices, the Thorn dry hole, located in the Gulf of Mexico, and related leasehold impairment of $68 million after-tax, and the $52 million after-tax loss on disposition of certain Cedar Creek Anticline properties. These decreases were partially offset by a $69 million after-tax gain on disposition of certain properties in southwest Louisiana.

Total average production in the Lower 48 increased 8 percent in both the third quarter and nine-month period of 2013. Average liquids production increased 17 percent and 18 percent in the third quarter and first nine months of 2013, respectively. New production, primarily from the Eagle Ford, Bakken and Permian areas, and improved drilling and well performance more than offset normal field decline and the impact from dispositions. Higher unplanned downtime also partially offset the increases in production in both periods of 2013.

Venezuela Arbitration

In September 2013, the World Bank’s International Centre for Settlement of Investment Disputes (ICSID) arbitration tribunal ruled Venezuela unlawfully expropriated ConocoPhillips’ significant oil investments in the Petrozuata and Hamaca heavy crude oil projects and the offshore Corocoro development project in June 2007. An additional arbitration phase is currently proceeding to determine the amount of damages owed to ConocoPhillips for Venezuela’s actions. For additional information, see Note 14—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

Canada


	Three Months Ended September 30				Nine Months Ended September 30
	2013		2012		2013		2012


Income (Loss) From Continuing Operations (millions of dollars)	$	642		(31)		780		(674)


Average Net Production
Crude oil (MBD)		13		14		14		13
Natural gas liquids (MBD)		25		25		25		24
Bitumen (MBD)
Consolidated operations		13		12		12		11
Equity affiliates		94		80		93		77

Total bitumen		107		92		105		88
Natural gas (MMCFD)		775		874		790		867


Total Production (MBOED)		274		277		276		270


Average Sales Prices
Crude oil (dollars per barrel)	$	91.81		77.19		81.71		78.44
Natural gas liquids (dollars per barrel)		46.90		45.31		47.07		49.43
Bitumen (dollars per barrel)
Consolidated operations		76.90		56.23		59.18		58.41
Equity affiliates		75.93		56.95		56.79		55.90
Total bitumen		76.06		56.86		57.08		56.23
Natural gas (dollars per thousand cubic feet)		2.42		2.05		2.86		1.88

Our Canadian operations comprise mainly natural gas fields in western Canada and oil sands projects in the Athabasca Region of northeastern Alberta. As of September 30, 2013, Canada contributed 17 percent of our worldwide liquids production and 20 percent of our natural gas production.

Canada operations reported earnings of $642 million in the third quarter and $780 million in the nine-month period of 2013, compared with losses of $31 million and $674 million in the corresponding periods of 2012, respectively. Earnings in both periods of 2013 largely benefitted from the $461 million after-tax gain on disposition of our Clyden undeveloped oil sands leasehold and higher bitumen volumes. Higher bitumen prices also contributed to the increase in earnings in the third quarter of 2013. Additionally, earnings for the nine-month period of 2013 benefitted from the absence of a $520 million after-tax impairment of the Mackenzie Gas Project and associated undeveloped leaseholds in 2012, as well as the recognition of additional income of $224 million related to the favorable tax resolution associated with the sale of certain western Canada properties in a prior year. Higher natural gas prices also contributed to the increase in earnings in the nine-month period of 2013.

Total average production decreased 1 percent in the third quarter and increased 2 percent in the nine-month period of 2013, while average liquids production increased 11 percent and 15 percent over the same periods, respectively. Increased production from Christina Lake Phase D, new production from Christina Lake Phase E, new wells in western Canada and lower royalty impacts more than offset normal field decline in both periods of 2013. However, higher planned and unplanned maintenance more than offset these improvements in the third quarter of 2013. In the nine-month period of 2013, lower natural gas curtailments also contributed to the increases, which were partly offset by higher planned and unplanned maintenance.

Europe


	Three Months Ended September 30				Nine Months Ended September 30
	2013		2012		2013		2012


Income From Continuing Operations (millions of dollars)	$	284		132		976		1,190


Average Net Production
Crude oil (MBD)		111		117		112		137
Natural gas liquids (MBD)		5		5		5		8
Natural gas (MMCFD)		357		414		409		529


Total Production (MBOED)		176		191		185		233


Average Sales Prices
Crude oil (dollars per barrel)	$	112.28		109.67		110.40		113.69
Natural gas liquids (dollars per barrel)		57.36		57.62		56.28		56.97
Natural gas (dollars per thousand cubic feet)		10.48		8.87		10.53		9.53

The Europe segment consists of operations principally located in Norway and the United Kingdom, as well as exploration activities in Poland and Greenland. As of September 30, 2013, our Europe operations contributed 14 percent of our worldwide liquids production and 10 percent of our natural gas production.

Europe operations reported earnings of $284 million in the third quarter of 2013, a 115 percent increase compared with the same period in 2012. Earnings for the nine-month period of 2013 were $976 million, an 18 percent decrease compared with the same period in 2012. The increase in earnings in the third quarter of 2013 was primarily due to the absence of the recognition of $170 million in additional income tax expense in the third quarter of 2012, as a result of legislation enacted in the United Kingdom, which restricted corporate tax relief on decommissioning costs to 50 percent.

The decrease in earnings for the nine-month period of 2013 was mainly the result of lower crude oil and natural gas volumes and lower gains from asset dispositions. Gains realized in the nine-month period of 2012 included the $285 million after-tax gain on sale of our interests in the Statfjord and Alba fields, compared with the $83 million after-tax gain on sale of our interest in the Interconnector Pipeline in 2013. These decreases were partly offset by the absence of the $170 million U.K. tax increase in 2012, higher gains from foreign currency transactions and lower impairments.

Average production decreased 8 percent in the third quarter and 21 percent in the nine-month period of 2013, primarily due to normal field decline, partially offset by improved drilling and well performance in Norway. Major planned maintenance at Greater Ekofisk, higher unplanned downtime, mostly in the East Irish Sea, and asset dispositions also contributed to the decrease in production in the nine-month period of 2013.

Ekofisk South Update

In October 2013, we achieved first oil production from the Ekofisk South development in the Norwegian North Sea. Ekofisk South includes the planned drilling of 35 new production and eight water injection wells. One well is currently producing, and drilling is underway on additional wells, with production expected to ramp up over the next four years. A second development, Eldfisk II, is scheduled to start up by early 2015. Ekofisk South, along with Eldfisk II and other developments offshore Norway, are expected to add approximately 60 MBOED of net production by 2017.

Asia Pacific and Middle East


	Three Months Ended September 30				Nine Months Ended September 30
	2013		2012		2013		2012


Income From Continuing Operations (millions of dollars)	$	757		684		2,719		3,232


Average Net Production
Crude oil (MBD)
Consolidated operations		77		75		82		63
Equity affiliates		16		14		15		15

Total crude oil		93		89		97		78


Natural gas liquids (MBD)
Consolidated operations		13		17		14		16
Equity affiliates		8		7		8		7

Total natural gas liquids		21		24		22		23


Natural gas (MMCFD)
Consolidated operations		712		709		707		664
Equity affiliates		507		449		494		482

Total natural gas		1,219		1,158		1,201		1,146


Total Production (MBOED)		317		306		320		293


Average Sales Prices
Crude oil (dollars per barrel)
Consolidated operations	$	105.43		105.12		104.30		110.19
Equity affiliates		105.78		101.75		104.51		107.86
Total crude oil		105.48		104.60		104.33		109.74
Natural gas liquids (dollars per barrel)
Consolidated operations		71.35		71.06		72.38		77.60
Equity affiliates		69.90		62.18		70.68		73.67
Total natural gas liquids		70.76		68.60		71.74		76.40
Natural gas (dollars per thousand cubic feet)
Consolidated operations		10.81		10.64		10.87		10.80
Equity affiliates*		9.35		8.66		9.18		8.76
Total natural gas*		10.21		9.88		10.18		9.94

*Amounts for 2012 have been restated to conform to current-year presentation.

The Asia Pacific and Middle East segment has producing operations in China, Indonesia, Malaysia, Australia, Timor-Leste and Qatar, as well as exploration activities in Bangladesh and Brunei. As of September 30, 2013, Asia Pacific and Middle East contributed 14 percent of our worldwide liquids production and 30 percent of our natural gas production.

Asia Pacific and Middle East operations reported earnings of $757 million in the third quarter of 2013, an 11 percent increase compared with the same period in 2012. Earnings for the nine-month period of 2013 were $2,719 million, a 16 percent decrease compared with the same period in 2012. Earnings in both periods of 2013 largely benefitted from higher crude oil and LNG volumes, as well as the absence of a $133 million after-tax loss recognized in the third quarter of 2012 due to the further dilution of our equity interest in APLNG from 42.5 percent to 37.5 percent. These increases were partially offset by a $116 million after-tax charge associated with a pending settlement, lower LNG prices and higher operating expenses, production taxes and DD&A.

In addition, the decrease in earnings in the nine-month period of 2013 was mainly due to the absence of the $937 million after-tax Vietnam gain on disposition in 2012, lower crude oil prices and the absence of a $72 million tax-related adjustment in 2012. These decreases were partly offset by a $146 million after-tax insurance settlement associated with the Bohai Bay seepage incidents, as well as the absence of an $89 million after-tax charge related to the Bohai Bay settlement with the China State Oceanic Administration in 2012.

Production averaged 317 MBOED in the third quarter of 2013, an increase of 4 percent compared with the third quarter of 2012. For the nine-month period of 2013, production averaged 320 MBOED, a 9 percent increase over the corresponding period of 2012. The increase in both periods of 2013 was largely due to:

•

Increased production in Bohai Bay, China.

•

New production from Panyu in the South China Sea.

•

The continued ramp-up of production in Malaysia.

•

Lower unplanned downtime in Qatar.

These increases were partly offset by normal field decline. The nine-month period of 2013 also benefitted from lower planned downtime, mainly from our Bayu-Undan Field and Darwin LNG facility, partially offset by the Vietnam disposition.

China—Bohai Bay

During 2012, ConocoPhillips reached agreements with China’s Ministry of Agriculture and China’s State Oceanic Administration to resolve claims related to two separate seepage incidents which occurred near the Peng Lai 19-3 Platforms B and C in 2011. During the third quarter of 2013, we recognized an after-tax charge of $116 million for amounts previously paid by ConocoPhillips as operator. We do not anticipate further significant charges related to the 2011 seepage incidents.

Other International


	Three Months Ended September 30					Nine Months Ended September 30
	2013			2012		2013		2012


Income (Loss) From Continuing Operations (millions of dollars)*	$	(2	)		492		26		456


Average Net Production*
Crude oil (MBD)
Consolidated operations		17			41		34		40
Equity affiliates		4			11		5		15

Total crude oil		21			52		39		55


Natural gas (MMCFD)		33			33		30		14


Total Production (MBOED)		26			58		44		57


Average Sales Prices*
Crude oil (dollars per barrel)
Consolidated operations	$	107.49			108.00		107.21		111.00
Equity affiliates		75.90			90.02		73.66		98.75
Total crude oil		100.85			105.22		103.20		107.88
Natural gas (dollars per thousand cubic feet)		5.92			6.77		5.20		5.82

*Prior

periods have been restated to exclude discontinued operations.

The Other International segment includes producing operations in Libya and Russia, as well as exploration activities in Angola and Azerbaijan. As of September 30, 2013, Other International contributed 5 percent of our worldwide liquids production and 1 percent of our natural gas production.

Other International operations reported a loss of $2 million in the third quarter and earnings of $26 million in the nine-month period of 2013, compared with earnings of $492 million and $456 million in the same periods of 2012, respectively. The decreases in earnings for both periods of 2013 were primarily the result of the absence of the $443 million after-tax gain on disposition of our interest in Naryanmarneftegaz (NMNG) in Russia in 2012. Lower dry hole expenses partly offset the decrease in the nine-month period of 2013.

Average production decreased 55 percent in the third quarter and 23 percent in the nine-month period of 2013, compared with the same periods in 2012. The decrease in the third quarter of 2013 was primarily due to the shutdown of the Es Sider crude oil export terminal in Libya at the end of July 2013. The disposition of our interest in NMNG in 2012 also contributed to the decrease. The reduction in the nine-month period of 2013 was mainly due to the NMNG disposition, as well as the shutdown of Es Sider. This was partly offset by higher production from Libya during the first six months of 2013, compared with the ramp-up of production in 2012 following their period of civil unrest. Es Sider is not expected to re-open in the fourth quarter of 2013. Accordingly, we expect production from Libya will be negligible in the fourth quarter of 2013.

Asset Dispositions

In 2012, we announced our intention to sell our 8.4 percent interest in Kashagan and our Algerian and Nigerian businesses. Results of operations related to Kashagan, Nigeria and Algeria have been classified as discontinued operations in all periods presented in this Form 10-Q. On October 31, 2013, we sold our 8.4 percent interest in Kashagan and received proceeds of $5.4 billion. The Nigeria and Algeria transactions, excluding Brass LNG, are targeted to close by the end of 2013, and the Brass LNG transaction is targeted to close in the first quarter of 2014. All are subject to customary governmental approvals. For additional information, see Note 3—Discontinued Operations, in the Notes to Consolidated Financial Statements.

Corporate and Other


	Millions of Dollars
	Three Months Ended September 30					Nine Months Ended September 30
	2013			2012		2013			2012

Income (Loss) From Continuing Operations
Net interest	$	(124	)		(214)		(359	)		(535)
Corporate general and administrative expenses		(77	)		(128)		(147	)		(246)
Technology		(26	)		46		7			6
Separation costs		-			(7)		-			(80)
Other		(7	)		49		(70	)		28

	$	(234	)		(254)		(569	)		(827)

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 42 percent in the third quarter and 33 percent in the nine-month period of 2013. The decreases in both periods of 2013 were mainly due to the absence of a $68 million after-tax premium on early debt retirement in 2012, lower interest expense on lower average debt levels, higher capitalized interest on projects and higher interest income.

Corporate general and administrative expenses decreased 40 percent in the third quarter and nine-month period of 2013, mostly due to lower pension settlement expense. Pension settlement expense incurred in the third quarter of 2013 was $31 million after-tax, compared with $82 million after-tax in the third quarter of 2012. Lower costs related to compensation and benefit plans and lower corporate contributions also contributed to the decrease in the nine-month period of 2013.

Technology includes our investment in new technologies or businesses, as well as licensing revenues received. 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 incurred a loss of $26 million in the third quarter and earnings of $7 million in the nine-month period of 2013, compared with earnings of $46 million and $6 million in the same periods of 2012, respectively. The decrease in the third quarter of 2013 was mainly due to lower licensing revenues.

Separation costs consist of expenses related to the separation of our Downstream business into a stand-alone, publicly traded company, Phillips 66.

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 $56 million in the third quarter and $98 million in the nine-month period of 2013, primarily as a result of foreign currency transaction losses, compared with foreign currency transaction gains in both periods of 2012, and the absence of a $39 million after-tax settlement which benefitted 2012, partially offset by lower environmental expenses. Various tax-related adjustments also contributed to the increase in “Other” expenses in the nine-month period of 2013.

CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators


	Millions of Dollars

	September 30 2013		December 31 2012


Short-term debt	$	572		955
Total debt		21,668		21,725
Total equity		51,537		48,427
Percent of total debt to capital*		30 %		31
Percent of floating-rate debt to total debt**		8 %		9

*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 nine months of 2013, we received $3,175 million in proceeds from asset sales. We used the remaining $748 million of our restricted cash balance, received in connection with the separation of Phillips 66, solely to pay dividends. During the first nine months of 2013, the primary uses of our available cash were $11,281 million to support our ongoing capital expenditures and investments program, $2,481 million to pay dividends and $946 million to repay debt. During the first nine months of 2013, cash and cash equivalents increased by $265 million to $3,883 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 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 $11,941 million for the first nine months of 2013, compared with $9,588 million for the corresponding period of 2012, a 25 percent increase. The increase was primarily due to lower income taxes from a smaller proportion of income in higher tax jurisdictions in 2013, lower production taxes, and benefits from the timing of working capital changes.

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 nine months of 2013 were $3,175 million, primarily from the sale of the majority of our properties in the Cedar Creek Anticline, the sale of our interest in the Clyden undeveloped oil sands leasehold, the sale of our 39 percent equity interest in Phoenix Park and the sale of a portion of our working interests in the Browse and Canning basins. This compares with proceeds of $2,088 million in the first nine months of 2012, primarily from the sale of our Vietnam business, the sale of our equity interest in NMNG and the sale of our interest in the Statfjord and Alba fields in the North Sea. On October 31, 2013, we received additional proceeds of $5.4 billion for the disposition of our 8.4 percent interest in Kashagan. We have announced additional asset sales of approximately $3.4 billion which are targeted to close by the end of 2013. We continue to evaluate opportunities to further optimize the portfolio.

Commercial Paper and Credit Facilities

At September 30, 2013, 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 QG3. At both September 30, 2013, and December 31, 2012, we had no direct borrowings or letters of credit issued under the revolving credit facilities. In addition, under the ConocoPhillips Qatar Funding Ltd. commercial paper programs, $961 million of commercial paper was outstanding at September 30, 2013, compared with $1,055 million at December 31, 2012. Since we had $961 million of commercial paper outstanding and had issued no letters of credit, we had access to $6.5 billion in borrowing capacity under our revolving credit facilities at September 30, 2013.

Certain of our project-related contracts and derivative instruments contain provisions requiring us to post collateral. Although cash is the primary form of collateral, many of these contracts and instruments permit us to post letters of credit. At September 30, 2013, and December 31, 2012, we had direct bank letters of credit of $809 million and $852 million, respectively, which secured performance obligations related to various purchase commitments incident to the ordinary conduct of business.

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 13—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 both September 30, 2013, and December 31, 2012, was $21.7 billion. In April 2013, we repaid bonds at maturity totaling $850 million. In June 2013, we incurred a capital lease obligation of $906 million. For more information, see Note 10—Debt, in the Notes to Consolidated Financial Statements.

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 $803 million was short-term and was included in the “Accounts payable—related parties” line on our September 30, 2013, consolidated balance sheet. The principal portion of these payments, which totaled $575 million in the first nine months of 2013, 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.

In July 2013, we announced a 4.5 percent increase in the quarterly dividend rate to 69 cents per share. The dividend was paid September 3, 2013, to stockholders of record at the close of business on July 22, 2013. Additionally, in October 2013, we announced a dividend of 69 cents per share. The dividend will be paid December 2, 2013, to stockholders of record at the close of business on October 15, 2013.

Capital Spending


	Millions of Dollars

	Nine Months Ended September 30

	2013		2012


Alaska	$	836		596
Lower 48 and Latin America		3,901		3,894
Canada		1,602		1,550
Europe		2,347		2,095
Asia Pacific and Middle East		2,306		2,053
Other International		192		399
Corporate and Other		97		133

Capital expenditures and investments from continuing operations	$	11,281		10,720

Discontinued operations in Kashagan, Nigeria and Algeria	$	540		635
Joint venture acquisition obligation (principal)—Canada		575		546

Capital Program	$	12,396		11,901

During the first nine months of 2013, capital expenditures and investments from continuing operations supported key exploration and development programs, primarily:

•

Oil and natural gas exploration and development activities in the Lower 48, including the Eagle Ford, Bakken, other shale plays, and the Permian Basin.

•

Oil sands development and ongoing liquids-focused plays in Canada.

•

Exploration leases and wells in deepwater Gulf of Mexico.

•

Continued development of new fields offshore Malaysia and ongoing exploration and development activity onshore and offshore Indonesia and Australia, including our investment in the APLNG joint venture.

•

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

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 58–60 of our 2012 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, 2012, we reported we had been notified of potential liability under CERCLA and comparable state laws at 11 sites around the United States. As of September 30, 2013, we had been notified of 4 new sites, increasing the number of unresolved sites with potential liability to 15 sites.

At September 30, 2013, our balance sheet included a total environmental accrual of $355 million, compared with $364 million at December 31, 2012, for remediation activities in the U.S. and Canada. 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, to the extent 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 and factors on which the ultimate impact on our financial performance will depend, see the “Climate Change” section in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 60–62 of our 2012 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 developments 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 exploration and production facilities.

•

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, 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 development.

•

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 development, construction or modification of facilities and general corporate purposes.

•

The operation and financing of our joint ventures.

•

The factors generally described in Item 1A—Risk Factors in our 2012 Annual Report on Form 10-K.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information about market risks for the nine months ended September 30, 2013, does not differ materially from that discussed under Item 7A in our 2012 Annual Report on Form 10-K.

Item 4. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in reports we file or submit under the Securities Exchange Act of 1934, as amended (the Act), is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and that such information is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. As of September 30, 2013, with the participation of our management, our Chairman 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 Act, of ConocoPhillips’ disclosure controls and procedures (as defined in Rule 13a-15(e) of the Act). Based upon that evaluation, our Chairman and Chief Executive Officer and our Executive Vice President, Finance and Chief Financial Officer concluded that our disclosure controls and procedures were operating effectively as of September 30, 2013.

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 third quarter of 2013 and any material developments with respect to matters previously reported in ConocoPhillips’ 2012 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 were to be 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 (SEC) 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

On September 26, 2013, ConocoPhillips Alaska, Inc., received a notice of violation from the North Slope Borough, a local governmental authority, alleging that the Company violated a condition of the permit for tundra travel when vehicles used by one of the Company’s contractors caused damage to tundra within the authority’s jurisdiction when traveling pursuant to the permit. In October 2013, ConocoPhillips and the North Slope Borough agreed to a full resolution of the matter on terms that included a gross penalty amount of $188,000, which has been paid.

Item 1A. RISK FACTORS

There have been no material changes from the risk factors disclosed in Item 1A of our 2012 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


July 1-31, 2013		2,288		$ 64.81		-		$ 4,901
August 1-31, 2013		-		-		-		4,901
September 1-30, 2013		5,916		70.68		-		4,901

Total		8,204		$ 69.04		-

*	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


12*		Computation of Ratio of Earnings to Fixed Charges.

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

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

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

101.INS*		XBRL Instance Document.

101.SCH*		XBRL Schema Document.

101.CAL*		XBRL Calculation Linkbase Document.

101.LAB*		XBRL Labels Linkbase Document.

101.PRE*		XBRL Presentation Linkbase Document.

101.DEF*		XBRL Definition Linkbase Document.

*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)

November 5, 2013