ConocoPhillips (COP) 10-Q 2014 Q3 Quarterly report

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, 2014

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 incorporation or organization)	(I.R.S. Employer Identification No.)

600 North Dairy Ashford, Houston, TX 77079

(Address of principal executive offices)            (Zip Code)

281-293-1000

(Registrant’s telephone number, including area code)

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

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

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

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 1,230,912,872 shares of common stock, $.01 par value, outstanding at September 30, 2014.

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		25
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		30
Item 3. Quantitative and Qualitative Disclosures About Market Risk		51
Item 4. Controls and Procedures		51
Part II—Other Information
Item 1. Legal Proceedings		52
Item 1A. Risk Factors		52
Item 6. Exhibits		53
Signature		54

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

Consolidated Income Statement ConocoPhillips

	Millions of Dollars
	Three Months Ended September 30						Nine Months Ended September 30
	2014			2013			2014			2013
Revenues and Other Income
Sales and other operating revenues	$	12,080			13,643			41,316			41,159
Equity in earnings of affiliates		764			709			2,008			1,565
Gain on dispositions		4			1,069			20			1,222
Other income		69			49			322			317
Total Revenues and Other Income		12,917			15,470			43,666			44,263
Costs and Expenses
Purchased commodities		4,703			5,708			17,325			17,063
Production and operating expenses		2,041			1,962			5,966			5,321
Selling, general and administrative expenses		203			249			603			607
Exploration expenses		459			313			1,272			911
Depreciation, depletion and amortization		2,096			1,902			6,058			5,541
Impairments		108			1			126			31
Taxes other than income taxes		493			664			1,756			2,198
Accretion on discounted liabilities		120			106			357			317
Interest and debt expense		149			151			475			420
Foreign currency transaction (gains) losses		(8	)		9			17			(34	)
Total Costs and Expenses		10,364			11,065			33,955			32,375
Income from continuing operations before income taxes		2,553			4,405			9,711			11,888
Provision for income taxes		904			1,966			3,880			5,359
Income From Continuing Operations		1,649			2,439			5,831			6,529
Income from discontinued operations*		1,078			57			1,131			183
Net income		2,727			2,496			6,962			6,712
Less: net income attributable to noncontrolling interests		(23	)		(16	)		(54	)		(43	)
Net Income Attributable to ConocoPhillips	$	2,704			2,480			6,908			6,669
Amounts Attributable to ConocoPhillips Common Shareholders:
Income from continuing operations	$	1,626			2,423			5,777			6,486
Income from discontinued operations		1,078			57			1,131			183
Net income	$	2,704			2,480			6,908			6,669
Net Income Attributable to ConocoPhillips Per Share of Common Stock (dollars)
Basic
Continuing operations	$	1.31			1.96			4.67			5.26
Discontinued operations		0.87			0.05			0.91			0.15
Net Income Attributable to ConocoPhillips Per Share of Common Stock	$	2.18			2.01			5.58			5.41
Diluted
Continuing operations	$	1.31			1.95			4.63			5.23
Discontinued operations		0.86			0.05			0.91			0.15
Net Income Attributable to ConocoPhillips Per Share of Common Stock	$	2.17			2.00			5.54			5.38
Dividends Paid Per Share of Common Stock (dollars)	$	0.73			0.69			2.11			2.01
Average Common Shares Outstanding (in thousands)
Basic		1,238,234			1,231,054			1,236,431			1,230,027
Diluted		1,247,436			1,240,365			1,246,788			1,238,943
*Net of provision (benefit) for income taxes on discontinued operations of:	$	(6	)		136			16			215

See Notes to Consolidated Financial Statements.

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Consolidated Statement of Comprehensive Income ConocoPhillips

	Millions of Dollars
	Three Months Ended September 30						Nine Months Ended September 30
	2014			2013			2014			2013
Net Income	$	2,727			2,496			6,962			6,712
Other comprehensive income (loss)
Defined benefit plans
Reclassification adjustment for amortization of prior service credit included in net income		(2	)		(1	)		(5	)		(4	)
Net actuarial gain arising during the period		—			301			—			302
Reclassification adjustment for amortization of net actuarial losses included in net income		32			106			98			220
Nonsponsored plans*		—			—			5			1
Income taxes on defined benefit plans		(11	)		(155	)		(34	)		(197	)
Defined benefit plans, net of tax		19			251			64			322
Foreign currency translation adjustments		(1,947	)		623			(1,501	)		(1,705	)
Reclassification adjustment for loss included in net income		—			—			—			(4	)
Income taxes on foreign currency translation adjustments		15			(2	)		20			12
Foreign currency translation adjustments, net of tax		(1,932	)		621			(1,481	)		(1,697	)
Other Comprehensive Income (Loss), Net of Tax		(1,913	)		872			(1,417	)		(1,375	)
Comprehensive Income		814			3,368			5,545			5,337
Less: comprehensive income attributable to noncontrolling interests		(23	)		(16	)		(54	)		(43	)
Comprehensive Income Attributable to ConocoPhillips	$	791			3,352			5,491			5,294

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

See Notes to Consolidated Financial Statements.

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Consolidated Balance Sheet ConocoPhillips

	Millions of Dollars
	September 30			December 31
	2014			2013
Assets
Cash and cash equivalents	$	5,408			6,246
Short-term investments*		374			272
Accounts and notes receivable (net of allowance of $5 million in 2014 and $8 million in 2013)		7,255			8,273
Accounts and notes receivable—related parties		198			214
Inventories		1,330			1,194
Prepaid expenses and other current assets		1,688			2,824
Total Current Assets		16,253			19,023
Investments and long-term receivables		24,615			23,907
Loans and advances—related parties		1,202			1,357
Net properties, plants and equipment (net of accumulated depreciation, depletion and amortization of $70,117 million in 2014 and $65,321 million in 2013)		75,790			72,827
Other assets		1,126			943
Total Assets	$	118,986			118,057
Liabilities
Accounts payable	$	8,647			9,250
Accounts payable—related parties		45			64
Short-term debt		1,688			589
Accrued income and other taxes		1,655			2,713
Employee benefit obligations		713			842
Other accruals		1,393			1,671
Total Current Liabilities		14,141			15,129
Long-term debt		19,499			21,073
Asset retirement obligations and accrued environmental costs		9,803			9,883
Deferred income taxes		16,084			15,220
Employee benefit obligations		2,219			2,459
Other liabilities and deferred credits		1,579			1,801
Total Liabilities		63,325			65,565
Equity
Common stock (2,500,000,000 shares authorized at $.01 par value)
Issued (2014—1,773,143,545 shares; 2013—1,768,169,906 shares)
Par value		18			18
Capital in excess of par		46,000			45,690
Treasury stock (at cost: 2014—542,230,673 shares; 2013—542,230,673 shares)		(36,780	)		(36,780	)
Accumulated other comprehensive income		585			2,002
Retained earnings		45,451			41,160
Total Common Stockholders’ Equity		55,274			52,090
Noncontrolling interests		387			402
Total Equity		55,661			52,492
Total Liabilities and Equity	$	118,986			118,057
*Includes marketable securities of:	$	—			135

See Notes to Consolidated Financial Statements.

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Consolidated Statement of Cash Flows ConocoPhillips

	Millions of Dollars
	Nine Months Ended September 30
	2014			2013
Cash Flows From Operating Activities
Net income	$	6,962			6,712
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization		6,058			5,541
Impairments		126			31
Dry hole costs and leasehold impairments		668			345
Accretion on discounted liabilities		357			317
Deferred taxes		1,024			1,142
Undistributed equity earnings		334			(585	)
Gain on dispositions		(20	)		(1,222	)
Income from discontinued operations		(1,131	)		(183	)
Other		(536	)		(280	)
Working capital adjustments
Decrease in accounts and notes receivable		634			822
Increase in inventories		(162	)		(301	)
Increase in prepaid expenses and other current assets		(189	)		(172	)
Increase (decrease) in accounts payable		(187	)		324
Increase (decrease) in taxes and other accruals		57			(550	)
Net cash provided by continuing operating activities		13,995			11,941
Net cash provided by discontinued operations		143			235
Net Cash Provided by Operating Activities		14,138			12,176
Cash Flows From Investing Activities
Capital expenditures and investments		(12,729	)		(11,281	)
Proceeds from asset dispositions		1,434			3,175
Net sales (purchases) of short-term investments		(109	)		1
Collection of advances/loans—related parties		143			130
Other		(454	)		(51	)
Net cash used in continuing investing activities		(11,715	)		(8,026	)
Net cash used in discontinued operations		(59	)		(540	)
Net Cash Used in Investing Activities		(11,774	)		(8,566	)
Cash Flows From Financing Activities
Repayment of debt		(505	)		(946	)
Change in restricted cash		—			748
Issuance of company common stock		27			12
Dividends paid		(2,618	)		(2,481	)
Other		(20	)		(593	)
Net cash used in continuing financing activities		(3,116	)		(3,260	)
Net cash used in discontinued operations		—			—
Net Cash Used in Financing Activities		(3,116	)		(3,260	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents		(86	)		(85	)
Net Change in Cash and Cash Equivalents		(838	)		265
Cash and cash equivalents at beginning of period		6,246			3,618
Cash and Cash Equivalents at End of Period	$	5,408			3,883

See Notes to Consolidated Financial Statements.

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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 2013 Annual Report on Form 10-K.

Effective April 1, 2014, the Other International segment was restructured to focus on enhancing our capability to operate in emerging and new country business units. As a result, we moved the Latin America and Poland businesses from the historically presented Lower 48 and Latin America segment and the Europe segment to the Other International segment. Certain financial information has been revised for all prior periods presented to reflect the change in the composition of our operating segments. For additional information, see Note 18—Segment Disclosures and Related Information.

The results of operations for our interest in the North Caspian Sea Production Sharing Agreement (Kashagan) and our Algeria and Nigeria businesses have been classified as discontinued operations for all periods presented. See Note 2—Discontinued Operations, for additional information. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to our continuing operations.

Note 2—Discontinued Operations

As part of our asset disposition program, we agreed to sell our interest in Kashagan and our Algeria and Nigeria businesses (collectively, the “Disposition Group”). The Disposition Group was previously part of the Other International operating segment. We completed the sales of Kashagan and our Algeria business in the fourth quarter of 2013 and the sale of our Nigeria business in the third quarter of 2014.

On December 20, 2012, we entered into agreements with affiliates of Oando PLC to sell our Nigeria business. The transaction originally included our upstream affiliates and Phillips (Brass) Limited, which owned a 17 percent interest in the Brass LNG Project. On July 30, 2014, we completed the sale of the upstream affiliates for $1,359 million, inclusive of $550 million deposits previously received. The deposits had been included in the “Other accruals” line on our consolidated balance sheet and in the “Other” line of cash flows from investing activities on our consolidated statement of cash flows. The deposits received included $435 million in 2012, $15 million in 2013, and $100 million in 2014. At closing we also received a $33 million short-term promissory note. We recognized a before-tax gain of $1,052 million, which is included in the “Income from discontinued operations” line on the consolidated income statement. At the time of disposition, the net carrying value of the upstream assets was $307 million, which included $233 million of other current assets, $1,211 million of properties, plants and equipment (PP&E), $298 million of other current liabilities, $14 million of asset retirement obligations (ARO), and $825 million of deferred taxes.

In the first quarter of 2014, we and Oando agreed to terminate the sales agreement for Phillips (Brass) Limited. In July 2014 we transferred our interest in the Brass LNG Project to the remaining shareholders in Brass LNG Limited. The financial impact of the transfer was recorded in the second quarter of 2014 and did not have a material effect on our consolidated financial statements.

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The carrying amounts of the major classes of assets and liabilities associated with the Disposition Group as of December 31, 2013, were as follows:

	Millions of Dollars
Assets
Accounts and notes receivable	$	376
Inventories		9
Prepaid expenses and other current assets		72
Total current assets of discontinued operations		457
Investments and long-term receivables		60
Loans and advances—related parties		7
Net properties, plants and equipment		1,154
Other assets		1
Total assets of discontinued operations	$	1,679
Liabilities
Accounts payable	$	419
Accrued income and other taxes		72
Total current liabilities of discontinued operations		491
Asset retirement obligations and accrued environmental costs		14
Deferred income taxes		765
Total liabilities of discontinued operations	$	1,270

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
	2014			2013		2014		2013
Sales and other operating revenues from discontinued operations	$	161			353		480		892
Income from discontinued operations before-tax	$	1,072			193		1,147		398
Income tax expense (benefit)		(6	)		136		16		215
Income from discontinued operations	$	1,078			57		1,131		183

Note 3—Variable Interest Entities (VIEs)

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

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

We have an agreement with Freeport LNG to participate in a liquefied natural gas (LNG) receiving terminal in Quintana, Texas. We have no ownership in Freeport LNG; however, we own a 50 percent interest in Freeport LNG GP, Inc. (Freeport GP), which serves as the general partner managing the venture. We entered into a credit agreement with Freeport LNG, whereby we agreed to provide loan financing for the construction of the terminal. We also entered into a long-term agreement with Freeport LNG to use 0.9 billion cubic feet per day of regasification capacity, which expires in 2033. When the terminal became operational in June 2008, we began making payments under the terminal use agreement. At September 30, 2014, the prepaid balance of the terminal use agreement was $318 million, which is primarily reflected in the “Other assets” line on our consolidated

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balance sheet. Freeport LNG began making loan repayments in September 2008, and the loan balance outstanding was $460 million at September 30, 2014, and $506 million at December 31, 2013.

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. In July 2014 Freeport LNG received conditional approval from the Federal Energy Regulatory Commission (FERC), and in October 2014, Freeport LNG received FERC’s permission to construct the facility. Upon satisfaction of their project financing conditions, currently expected to occur in the fourth quarter of 2014, we will pay Freeport LNG a termination fee of approximately $520 million. Freeport LNG will repay the outstanding ConocoPhillips loan used by Freeport LNG to partially fund the original construction of the terminal. These transactions, plus miscellaneous items, will result in a one-time net cash outflow of approximately $50 million for us. When the agreement becomes effective, we expect to recognize an after-tax charge to earnings of approximately $520 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 method investment.

Australia Pacific LNG Pty Ltd (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, 2014, 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 5—Investments, Loans and Long-Term Receivables, and Note 10—Guarantees, for additional information.

Note 4—Inventories

Inventories consisted of the following:

	Millions of Dollars
	September 30 2014		December 31 2013
Crude oil and natural gas	$	536		452
Materials, supplies and other		794		742
	$	1,330		1,194

Inventories valued on the last-in, first-out (LIFO) basis totaled $430 million and $343 million at September 30, 2014 and December 31, 2013, respectively. The estimated excess of current replacement cost over LIFO cost

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of inventories was approximately $80 million and $160 million at September 30, 2014 and December 31, 2013, respectively.

Note 5—Investments, Loans and Long-Term Receivables

APLNG

APLNG’s $8.5 billion project finance 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. At September 30, 2014, $8.0 billion had been drawn from the facility. 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 10—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 3—Variable Interest Entities (VIEs), for additional information.

At September 30, 2014, the book value of our equity method investment in APLNG was $12,299 million, which included $829 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.

FCCL

In the first quarter of 2014, we received a $1.3 billion distribution from FCCL Partnership, our 50 percent owned business venture with Cenovus Energy Inc., which is included in the “Undistributed equity earnings” line on our consolidated statement of cash flows.

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, 2014, included the following:

• $460 million in loan financing to Freeport LNG. See Note 3—Variable Interest Entities (VIEs), for additional information.

• $909 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 6—Suspended Wells and Wells in Progress

The capitalized cost of suspended wells at September 30, 2014, was $1,285 million, an increase of $291 million from $994 million at year-end 2013. No suspended wells were charged to dry hole expense during the first nine months of 2014 relating to exploratory well costs capitalized for a period greater than one year as of December 31, 2013.

In November 2014 we will plug and abandon the Kamoxi-1 exploration well, located in Block 36 offshore Angola. The cost of the well, which totaled $183 million pre-tax at September 30, 2014, will be expensed as a dry hole in the fourth quarter of 2014.

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Note 7—Impairments

During the three- and nine-month periods ended September 30, 2014 and 2013, we recognized before-tax impairment charges within the following segments:

	Millions of Dollars
	Three Months Ended September 30				Nine Months Ended September 30
	2014		2013		2014		2013
Alaska	$	3		—		3		—
Lower 48		102		—		119		—
Europe		1		—		1		28
Asia Pacific and Middle East		—		1		—		3
Corporate and Other		2		—		3		—
	$	108		1		126		31

The three- and nine-month periods of 2014 included an impairment in our Lower 48 segment of $102 million, primarily as a result of reduced volume forecasts. We also recorded a $138 million impairment for the undeveloped leasehold costs associated with the same properties, which was included in the “Exploration expenses” line on our consolidated income statement.

The nine-month period of 2013 included an impairment in our Europe segment of $28 million, primarily due to increases in the ARO for the U.K. Don Field, which has ceased production.

In June 2014 we decided not to pursue future development of the Amauligak discovery at this time. Accordingly, we recorded a $145 million before-tax property impairment for the carrying value of capitalized undeveloped leasehold costs associated with our Amauligak, Arctic Islands and other Beaufort properties, located offshore Canada. This impairment is also included in the “Exploration expenses” line on our consolidated income statement.

Note 8—Debt

In June 2014 we refinanced our revolving credit facility from a total of $7.5 billion to $7.0 billion, with a new expiration date of June 2019. Our revolving credit facility may be used for direct bank borrowings, for the issuance of letters of credit totaling up to $500 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 credit 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 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 as administered by ICE Benchmark Administration 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.

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We have two commercial paper programs supported by our $7.0 billion revolving credit facility: the ConocoPhillips $6.1 billion program, primarily a funding source for short-term working capital needs, and the ConocoPhillips Qatar Funding Ltd. $900 million program, which is used to fund commitments relating to QG3. Commercial paper maturities are generally limited to 90 days.

At September 30, 2014 and December 31, 2013, we had no direct outstanding borrowings under the revolving credit facility, with no letters of credit as of September 30, 2014 or December 31, 2013. In addition, under the ConocoPhillips Qatar Funding Ltd. commercial paper program, there was $860 million of commercial paper outstanding at September 30, 2014, compared with $961 million at December 31, 2013. Since we had $860 million of commercial paper outstanding and had issued no letters of credit, we had access to $6.1 billion in borrowing capacity under our revolving credit facility at September 30, 2014.

At September 30, 2014, we classified $752 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 facility.

During the first nine months of 2014, we repaid at maturity the aggregate principal amount of our $400 million 4.75% Notes due 2014. In October 2014 we notified holders of the outstanding $1.5 billion 4.60% Notes due January 2015 that early redemption will occur in November 2014.

During 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. As of September 30, 2014, the value of the capital lease asset and associated obligation for our proportionate interest in the FPS was $930 million. Following the startup of the FPS, which occurred in October 2014, 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.

Note 9—Noncontrolling Interests

Activity attributable to common stockholders’ equity and noncontrolling interests for the first nine months of 2014 and 2013 was as follows:

	Millions of Dollars
	2014									2013
	Common Stockholders’ Equity			Non- Controlling Interest			Total Equity			Common Stockholders’ Equity			Non- Controlling Interest			Total Equity
Balance at January 1	$	52,090			402			52,492			47,987			440			48,427
Net income		6,908			54			6,962			6,669			43			6,712
Dividends		(2,618	)		—			(2,618	)		(2,481	)		—			(2,481	)
Distributions to noncontrolling interests		—			(69	)		(69	)		—			(59	)		(59	)
Other changes, net*		(1,106	)		—			(1,106	)		(1,062	)		—			(1,062	)
Balance at September 30	$	55,274			387			55,661			51,113			424			51,537

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

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Note 10—Guarantees

At September 30, 2014, 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 guarantees and expect future performance to be either immaterial or have only a remote chance of occurrence.

APLNG Guarantees

At September 30, 2014, 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 2014 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 three years. Our maximum potential amount of future payments related to this guarantee is approximately $110 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, 2014, is approximately $3.0 billion based upon our pro-rata share of the facility used at that date. At September 30, 2014, the carrying value of this guarantee is $114 million.

• In conjunction with our original acquisition of an ownership interest in APLNG in October 2008, we agreed to guarantee an existing obligation of APLNG to deliver natural gas under several sales agreements with remaining terms of 2 to 27 years. Our maximum potential amount of future payments, or cost of volume delivery, under these guarantees is estimated to be $1.4 billion (approximately $2.4 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 31 years or the life of the venture. Our maximum potential amount of future payments related to these guarantees is approximately $190 million and would become payable if APLNG does not perform.

Other Guarantees

We have other guarantees with maximum future potential payment amounts totaling approximately $200 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 10 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.

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Indemnifications

Over the years, we have entered into agreements to sell ownership interests in certain corporations, joint ventures and assets that gave rise to qualifying indemnifications. These agreements include indemnifications for taxes, environmental liabilities, employee claims, 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, 2014, was approximately $100 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, 2014, 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 11—Contingencies and Commitments.

On April 30, 2012, the separation of our downstream businesses 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. 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 11—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

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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 limits 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 those acquired in a purchase business combination, which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable future costs will be incurred and these costs can be reasonably estimated. At September 30, 2014, our balance sheet included a total environmental accrual of $366 million, compared with $348 million at December 31, 2013, for remediation activities in the United States 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

We are subject to various lawsuits and claims including but not limited to matters involving oil and gas royalty and severance tax payments, gas measurement and valuation methods, contract disputes, environmental damages, personal injury, and property damage. Our primary exposures for such matters relate to alleged royalty underpayments on certain federal, state and privately owned properties and claims of alleged environmental contamination from historic operations. We will continue to defend ourselves vigorously in these matters.

Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, is required.

Other Contingencies

We have contingent liabilities resulting from throughput agreements with pipeline and processing companies not associated with financing arrangements. Under these agreements, we may be required to provide any such company with additional funds through advances and penalties for fees related to throughput capacity not

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utilized. In addition, at September 30, 2014, we had performance obligations secured by letters of credit of $700 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 anempresa 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. A separate arbitration phase is currently proceeding to determine the damages owed to ConocoPhillips for Venezuela’s actions. On October 10, 2014, we filed a separate arbitration under the rules of the International Chamber of Commerce against PDVSA for contractual compensation related to the Petrozuata and Hamaca heavy crude oil projects.

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 supplemental counterclaims 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 currently proceeding to determine the damages owed to ConocoPhillips for Ecuador’s actions and to address Ecuador’s counterclaims.

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. As of September 2014 ConocoPhillips paid, under protest, tax assessments totaling approximately $237 million, which are primarily recorded in the “Investments and long-term receivables” line on our consolidated balance sheet. The arbitration hearing was conducted in Singapore in June 2014 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. Post-hearing briefs from both parties were filed in August 2014. We are now awaiting the Tribunal’s decision. Future impacts on our business are not known at this time.

Note 12—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.

Our derivative instruments are held at fair value on our consolidated balance sheet. Where these balances have the right of setoff, they are presented on a net basis. 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.

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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 2014		December 31 2013
Assets
Prepaid expenses and other current assets	$	1,003		871
Other assets		79		64
Liabilities
Other accruals		1,006		890
Other liabilities and deferred credits		71		58

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
	2014			2013			2014			2013
Sales and other operating revenues	$	(185	)		61			236			(122	)
Other income		1			—			3			3
Purchased commodities		163			(68	)		(221	)		103

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

	Open Position Long/(Short)
	September 30 2014			December 31 2013
Commodity
Natural gas and power (billions of cubic feet equivalent)
Fixed price		(17	)		(18	)
Basis		24			(10	)

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 programs 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.

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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 2014		December 31 2013
Assets
Prepaid expenses and other current assets	$	2		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
	2014		2013			2014			2013
Foreign currency transaction (gains) losses	$	5		(57	)		(2	)		—

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

	In Millions Notional Currency
	September 30 2014		December 31 2013
Buy U.S. dollar, sell other currencies*	USD	36		6
Buy British pound, sell euro	GBP	50		17

*Primarily 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. These held-to-maturity financial instruments are included in “Cash and cash equivalents” on our consolidated balance sheet if the maturities at the time we made the investments were 90 days or less; otherwise, these investments are included in “Short-term investments” on our consolidated balance sheet.

	Millions of Dollars
	Carrying Amount
	Cash and Cash Equivalents				Short-Term Investments
	September 30 2014		December 31 2013		September 30 2014		December 31 2013
Cash	$	713		636		—		—
Money Market Funds		300		—		—		—
Time deposits
Remaining maturities from 1 to 90 days		3,752		5,336		374		137
Commercial paper
Remaining maturities from 1 to 90 days		643		274		—		135
	$	5,408		6,246		374		272

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Credit Risk

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

The credit risk from our OTC derivative contracts, such as forwards and swaps, derives from the counterparty to the transaction. Individual counterparty exposure is managed within predetermined credit limits and includes the use of cash-call margins 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 transactions administered through the New York Mercantile Exchange or 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, 2014 and December 31, 2013, was $81 million and $57 million, respectively. For these instruments, no collateral was posted as of September 30, 2014 or December 31, 2013. If our credit rating had been lowered one level from its “A” rating (per Standard and Poor’s) on September 30, 2014, we would be required to post $1 million of additional collateral to our counterparties. If we had been downgraded below investment grade, we would be required to post $81 million of additional collateral, either with cash or letters of credit.

Note 13—Fair Value Measurement

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

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

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

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

The classification of an asset or liability is based on the lowest level of input significant to its fair value. Those that are initially classified as Level 3 are subsequently reported as Level 2 when the fair value derived from

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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 during 2014 or 2013.

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 for all periods presented.

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, 2014								December 31, 2013
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Deferred compensation investments	$	300		—		—		300		306		—		—		306
Commodity derivatives		873		197		12		1,082		744		177		10		931
Total assets	$	1,173		197		12		1,382		1,050		177		10		1,237
Liabilities
Commodity derivatives	$	871		190		16		1,077		765		172		7		944
Total liabilities	$	871		190		16		1,077		765		172		7		944

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The following table summarizes those commodity derivative balances subject to the right of setoff as presented on our consolidated balance sheet. We have elected to offset the recognized fair value amounts for multiple derivative instruments executed with the same counterparty in our financial statements when a legal right of offset exists.

	Millions of Dollars
	Gross Amounts Recognized		Gross Amounts Offset		Net Amounts Presented		Cash Collateral		Gross Amounts without Right of Setoff		Net Amounts
September 30, 2014
Assets	$	1,082		955		127		2		15		110
Liabilities		1,077		955		122		10		13		99
December 31, 2013
Assets	$	931		827		104		6		12		86
Liabilities		944		827		117		26		9		82

At September 30, 2014 and December 31, 2013, we did not present any amounts gross on our consolidated balance sheet where we had the right of setoff.

Non-Recurring Fair Value Measurement

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

	Millions of Dollars
			Fair Value Measurements Using
	Fair Value		Level 3 Inputs		Before-Tax Loss
September 30, 2014
Net PP&E (held for use)	$	12		12		102
Net PP&E (unproved property)		38		38		138

Net PP&E held for use was written down to fair value, less costs to sell. The fair value was determined by internal discounted cash flow models using estimates of future production, prices from futures exchanges and pricing service companies, costs and a discount rate believed to be consistent with those used by principal market participants.

Net PP&E unproved property was written down to fair value less costs to sell based on a risk-weighted assessment of indicative offers received.

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 short-term investments: The carrying amount reported on the balance sheet approximates fair value.

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

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• 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 5—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.

• 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.

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 2014		December 31 2013		September 30 2014		December 31 2013
Financial assets
Deferred compensation investments	$	300		306		300		306
Commodity derivatives		125		99		125		99
Total loans and advances—related parties		1,376		1,528		1,509		1,680
Financial liabilities
Total debt, excluding capital leases		20,221		20,740		23,672		23,553
Commodity derivatives		112		92		112		92

Note 14—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, 2013	$	(824	)		2,826			2,002
Other comprehensive income (loss)		64			(1,481	)		(1,417	)
September 30, 2014	$	(760	)		1,345			585

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

The following table summarizes reclassifications out of accumulated other comprehensive income:

	Millions of Dollars
	Three Months Ended September 30				Nine Months Ended September 30
	2014		2013		2014		2013
Defined benefit plans	$	19		65		59		133
Above amounts are included in the computation of net periodic benefit cost and are presented net of tax expense of:	$	11		40		34		83

See Note 16—Employee Benefit Plans, for additional information.

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Note 15—Cash Flow Information

	Millions of Dollars
	Nine Months Ended September 30
	2014			2013
Cash Payments
Interest	$	491			448
Income taxes		3,359			4,050
Net Sales (Purchases) of Short-Term Investments
Short-term investments purchased	$	(876	)		(97	)
Short-term investments sold		767			98
	$	(109	)		1

Note 16—Employee Benefit Plans

Pension and Postretirement Plans

	Millions of Dollars
	Pension Benefits										Other Benefits
	2014					2013					2014			2013
		U.S.		Int’l.			U.S.		Int’l.
Components of Net Periodic Benefit Cost
Three Months Ended September 30
Service cost	$	31		27			35		25			1			—
Interest cost		42		42			35		35			8			8
Expected return on plan assets		(53	)	(45	)		(47	)	(40	)		—			—
Amortization of prior service cost (credit)		1		(2	)		2		(2	)		(1	)		(1	)
Recognized net actuarial loss (gain)		19		14			38		18			(1	)		—
Settlements		—		—			50		—			—			—
Net periodic benefit cost	$	40		36			113		36			7			7
Nine Months Ended September 30
Service cost	$	93		83			104		76			2			2
Interest cost		124		126			107		108			22			20
Expected return on plan assets		(159	)	(137	)		(140	)	(120	)		—			—
Amortization of prior service cost (credit)		4		(6	)		5		(6	)		(3	)		(3	)
Recognized net actuarial loss (gain)		57		43			113		55			(2	)		2
Settlements		—		—			50		—			—			—
Net periodic benefit cost	$	119		109			239		113			19			21

During the first nine months of 2014, we contributed $304 million to our domestic benefit plans and $111 million to our international benefit plans. In 2014 we expect to contribute approximately $320 million to our domestic qualified and nonqualified pension and postretirement benefit plans and $210 million to our international qualified and nonqualified pension and postretirement benefit plans.

During the three months ended September 30, 2013, 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. As a result, we recognized a proportionate share of prior actuarial losses, or pension settlement expense, of $50 million. In

21

conjunction with the recognition of pension settlement expense, the assets and pension benefit obligation of the U.S. 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.

Note 17—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
	2014			2013		2014			2013
Operating revenues and other income	$	32			35		89			74
Purchases		47			48		147			138
Operating expenses and selling, general and administrative expenses*		21			10		53			25
Net interest (income) expense**		(12	)		6		(36	)		22

*2013 has been restated to eliminate certain non-related party transactions.

**We paid interest to, or received interest from, various affiliates. See Note 5—Investments, Loans and Long-Term Receivables, for additional information on loans to affiliated companies.

Note 18—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 primarily defined by geographic region: Alaska, Lower 48, Canada, Europe, Asia Pacific and Middle East, and Other International.

Effective April 1, 2014, the Other International segment was restructured to focus on enhancing our capability to operate in emerging and new country business units. As a result, we moved the Latin America and Poland businesses from the historically presented Lower 48 and Latin America segment and the Europe segment to the Other International segment. Results of operations for the Lower 48, Europe and Other International segments have been revised for all periods presented. There was no impact on our consolidated financial statements, and the impact on our segment presentation was immaterial.

In 2012 we agreed to sell our Nigeria and Algeria businesses and our interest in Kashagan. We sold our Nigeria business in the third quarter of 2014, and we sold Kashagan and our Algeria business in the fourth quarter of 2013. Results for the Disposition Group have been reported as discontinued operations in all periods presented. For additional information, see Note 2—Discontinued Operations.

Corporate and Other represents costs not directly associated with an operating segment, such as most interest expense, corporate overhead and certain technology activities, including licensing revenues. Corporate assets include all cash and cash equivalents and short-term investments.

We evaluate performance and allocate resources based on net income attributable to ConocoPhillips. Intersegment sales are at prices that approximate market.

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Analysis of Results by Operating Segment

	Millions of Dollars
	Three Months Ended September 30						Nine Months Ended September 30
	2014			2013			2014			2013
Sales and Other Operating Revenues
Alaska	$	2,094			2,102			6,687			6,375
Lower 48		5,082			4,938			17,196			14,661
Intersegment eliminations		(28	)		(24	)		(88	)		(79	)
Lower 48		5,054			4,914			17,108			14,582
Canada		1,086			1,264			4,113			3,924
Intersegment eliminations		(128	)		(135	)		(618	)		(448	)
Canada		958			1,129			3,495			3,476
Europe		2,241			3,024			8,195			8,885
Intersegment eliminations		(3	)		—			(47	)		—
Europe		2,238			3,024			8,148			8,885
Asia Pacific and Middle East		1,658			2,196			5,758			6,500
Other International		60			262			65			1,202
Corporate and Other		18			16			55			139
Consolidated sales and other operating revenues	$	12,080			13,643			41,316			41,159
Net Income Attributable to ConocoPhillips
Alaska	$	473			494			1,698			1,719
Lower 48		32			209			621			547
Canada		307			642			845			780
Europe		213			288			819			1,005
Asia Pacific and Middle East		749			741			2,336			2,676
Other International		(18	)		283			74			328
Corporate and Other		(130	)		(234	)		(616	)		(569	)
Discontinued operations		1,078			57			1,131			183
Consolidated net income attributable to ConocoPhillips	$	2,704			2,480			6,908			6,669

	Millions of Dollars
	September 30 2014		December 31 2013
Total Assets
Alaska	$	12,667		11,662
Lower 48		30,749		29,552
Canada		21,963		22,394
Europe		16,968		17,223
Asia Pacific and Middle East		26,276		25,473
Other International		2,190		1,705
Corporate and Other		8,062		8,367
Discontinued operations		111		1,681
Consolidated total assets	$	118,986		118,057

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Note 19—Income Taxes

Our effective tax rates from continuing operations for the third quarter and first nine months of 2014 were 35 percent and 40 percent, respectively, compared with 45 percent for the same periods of 2013. The lower rates were primarily due to a smaller proportion of income in higher tax jurisdictions in 2014 and the election of the fair market value method of apportioning interest expense in the United States. The effective tax rate for the first nine months of 2013 was favorably impacted by the tax resolution associated with the sale of certain western Canada properties which occurred in a prior year.

For the first nine months of 2014, the effective tax rate in excess of the domestic federal statutory rate of 35 percent was primarily due to foreign taxes.

Note 20—New Accounting Standards

In May 2014 the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09, “Revenue from Contracts with Customers,” which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers. This ASU supersedes the revenue recognition requirements in FASB Accounting Standards Codification (ASC) Topic 605, “Revenue Recognition,” and most industry-specific guidance. This ASU sets forth a five-step model for determining when and how revenue is recognized. Under the model, an entity will be required to recognize revenue to depict the transfer of goods or services to a customer at an amount reflecting the consideration it expects to receive in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. The ASU is effective for interim and annual periods beginning after December 15, 2016. Early adoption is not permitted. Entities may choose to adopt the standard using either a full retrospective approach or a modified retrospective approach. We are currently evaluating the impact of the adoption of this ASU.

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Supplementary Information—Condensed Consolidating Financial Information

We have various cross guarantees among ConocoPhillips, ConocoPhillips Company and ConocoPhillips Canada Funding Company I, with respect to publicly held debt securities. ConocoPhillips Company is 100 percent owned by ConocoPhillips. ConocoPhillips Canada Funding Company I is an indirect, 100 percent owned subsidiary of ConocoPhillips Company. ConocoPhillips and ConocoPhillips Company have fully and unconditionally guaranteed the payment obligations of ConocoPhillips Canada Funding Company I, with respect to its 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 and ConocoPhillips Canada Funding Company I (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.

During 2013 ConocoPhillips Australia Funding Company’s guaranteed, publicly held debt was repaid. Beginning in the first quarter of 2014, financial information for ConocoPhillips Australia Funding Company is presented in the “All Other Subsidiaries” column of our condensed consolidating financial information.

In April 2014 ConocoPhillips received a $32 billion dividend from ConocoPhillips Company to settle certain accumulated intercompany balances. This consisted of a $15 billion distribution of earnings and a $17 billion return of capital. The transaction was reflected in the second quarter 2014 Condensed Consolidating Financial Information for ConocoPhillips and ConocoPhillips Company and had no impact on our consolidated financial statements.

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

25

	Millions of Dollars
	Three Months Ended September 30, 2014
Income Statement	ConocoPhillips			ConocoPhillips Company			ConocoPhillips Canada Funding Company I			All Other Subsidiaries			Consolidating Adjustments			Total Consolidated
Revenues and Other Income
Sales and other operating revenues	$	—			4,672			—			7,408			—			12,080
Equity in earnings of affiliates		1,722			2,098			—			975			(4,031	)		764
Gain on dispositions		—			2			—			2			—			4
Other income		1			15			—			53			—			69
Intercompany revenues		20			104			72			1,444			(1,640	)		—
Total Revenues and Other Income		1,743			6,891			72			9,882			(5,671	)		12,917
Costs and Expenses
Purchased commodities		—			4,036			—			2,139			(1,472	)		4,703
Production and operating expenses		—			414			—			1,617			10			2,041
Selling, general and administrative expenses		2			136			1			65			(1	)		203
Exploration expenses		—			331			—			128			—			459
Depreciation, depletion and amortization		—			273			—			1,823			—			2,096
Impairments		—			104			—			4			—			108
Taxes other than income taxes		—			69			—			424			—			493
Accretion on discounted liabilities		—			14			—			106			—			120
Interest and debt expense		134			77			58			57			(177	)		149
Foreign currency transaction (gains) losses		33			3			(208	)		164			—			(8	)
Total Costs and Expenses		169			5,457			(149	)		6,527			(1,640	)		10,364
Income from continuing operations before income taxes		1,574			1,434			221			3,355			(4,031	)		2,553
Provision (benefit) for income taxes		(52	)		(288	)		9			1,235			—			904
Income From Continuing Operations		1,626			1,722			212			2,120			(4,031	)		1,649
Income from discontinued operations		1,078			1,078			—			61			(1,139	)		1,078
Net income		2,704			2,800			212			2,181			(5,170	)		2,727
Less: net income attributable to noncontrolling interests		—			—			—			(23	)		—			(23	)
Net Income Attributable to ConocoPhillips	$	2,704			2,800			212			2,158			(5,170	)		2,704
Comprehensive Income Attributable to ConocoPhillips	$	791			887			29			255			(1,171	)		791

	Millions of Dollars
	Three Months Ended September 30, 2013
Income Statement	ConocoPhillips			ConocoPhillips Company			ConocoPhillips Australia Funding Company		ConocoPhillips Canada Funding Company I			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*		2,502			2,548			—		—			647			(4,988	)		709
Gain on dispositions		—			418			—		—			651			—			1,069
Other income		—			29			—		—			20			—			49
Intercompany revenues*		21			106			—		75			1,338			(1,540	)		—
Total Revenues and Other Income		2,523			7,726			—		75			11,674			(6,528	)		15,470
Costs and Expenses
Purchased commodities		—			3,993			—		—			3,047			(1,332	)		5,708
Production and operating expenses		—			385			—		—			1,580			(3	)		1,962
Selling, general and administrative expenses		3			193			—		1			53			(1	)		249
Exploration expenses		—			158			—		—			155			—			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*		156			86			—		58			55			(204	)		151
Foreign currency transaction (gains) losses		(15	)		(1	)		—		72			(47	)		—			9
Total Costs and Expenses		144			5,128			—		131			7,202			(1,540	)		11,065
Income (loss) from continuing operations before income taxes		2,379			2,598			—		(56	)		4,472			(4,988	)		4,405
Provision (benefit) for income taxes		(44	)		96			—		7			1,907			—			1,966
Income (Loss) From Continuing Operations		2,423			2,502			—		(63	)		2,565			(4,988	)		2,439
Income from discontinued operations		57			57			—		—			57			(114	)		57
Net income (loss)		2,480			2,559			—		(63	)		2,622			(5,102	)		2,496
Less: net income attributable to noncontrolling interests		—			—			—		—			(16	)		—			(16	)
Net Income (Loss) Attributable to ConocoPhillips	$	2,480			2,559			—		(63	)		2,606			(5,102	)		2,480
Comprehensive Income Attributable to ConocoPhillips	$	3,352			3,431			—		17			3,212			(6,660	)		3,352

*“Interest and debt expense” for ConocoPhillips was revised to reflect contractually agreed interest rates, with offsetting adjustments in the “Equity in earnings of affiliates” and “Intercompany revenues” lines for ConocoPhillips, ConocoPhillips Company and All Other Subsidiaries. There was no impact to Total Consolidated balances.

26

	Millions of Dollars
	Nine Months Ended September 30, 2014
Income Statement	ConocoPhillips			ConocoPhillips Company			ConocoPhillips Canada Funding Company I			All Other Subsidiaries			Consolidating Adjustments			Total Consolidated
Revenues and Other Income
Sales and other operating revenues	$	—			15,920			—			25,396			—			41,316
Equity in earnings of affiliates		6,053			7,063			—			2,235			(13,343	)		2,008
Gain on dispositions		—			3			—			17			—			20
Other income		1			60			—			261			—			322
Intercompany revenues		59			369			214			4,685			(5,327	)		—
Total Revenues and Other Income		6,113			23,415			214			32,594			(18,670	)		43,666
Costs and Expenses
Purchased commodities		—			13,984			—			8,060			(4,719	)		17,325
Production and operating expenses		—			1,255			—			4,751			(40	)		5,966
Selling, general and administrative expenses		8			416			1			193			(15	)		603
Exploration expenses		—			713			—			559			—			1,272
Depreciation, depletion and amortization		—			776			—			5,282			—			6,058
Impairments		—			122			—			4			—			126
Taxes other than income taxes		—			233			—			1,523			—			1,756
Accretion on discounted liabilities		—			43			—			314			—			357
Interest and debt expense		441			209			174			204			(553	)		475
Foreign currency transaction (gains) losses		36			5			(196	)		172			—			17
Total Costs and Expenses		485			17,756			(21	)		21,062			(5,327	)		33,955
Income from continuing operations before income taxes		5,628			5,659			235			11,532			(13,343	)		9,711
Provision (benefit) for income taxes		(149	)		(394	)		7			4,416			—			3,880
Income From Continuing Operations		5,777			6,053			228			7,116			(13,343	)		5,831
Income from discontinued operations		1,131			1,131			—			114			(1,245	)		1,131
Net income		6,908			7,184			228			7,230			(14,588	)		6,962
Less: net income attributable to noncontrolling interests		—			—			—			(54	)		—			(54	)
Net Income Attributable to ConocoPhillips	$	6,908			7,184			228			7,176			(14,588	)		6,908
Comprehensive Income Attributable to ConocoPhillips	$	5,491			5,767			24			5,730			(11,521	)		5,491

	Millions of Dollars
	Nine Months Ended September 30, 2013
Income Statement	ConocoPhillips			ConocoPhillips Company		ConocoPhillips Australia Funding Company		ConocoPhillips Canada Funding Company I			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*		6,771			7,234		—		—			1,803			(14,243	)		1,565
Gain on dispositions		—			419		—		—			803			—			1,222
Other income		1			237		—		—			79			—			317
Intercompany revenues*		62			341		13		229			3,723			(4,368	)		—
Total Revenues and Other Income		6,834			21,941		13		229			33,857			(18,611	)		44,263
Costs and Expenses
Purchased commodities		—			11,901		—		—			8,868			(3,706	)		17,063
Production and operating expenses		—			1,106		—		—			4,238			(23	)		5,321
Selling, general and administrative expenses		9			443		—		1			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*		467			246		12		176			139			(620	)		420
Foreign currency transaction (gains) losses		26			8		—		(209	)		141			—			(34	)
Total Costs and Expenses		502			15,091		12		(32	)		21,170			(4,368	)		32,375
Income from continuing operations before income taxes		6,332			6,850		1		261			12,687			(14,243	)		11,888
Provision (benefit) for income taxes		(154	)		79		—		28			5,406			—			5,359
Income From Continuing Operations		6,486			6,771		1		233			7,281			(14,243	)		6,529
Income from discontinued operations		183			183		—		—			183			(366	)		183
Net income		6,669			6,954		1		233			7,464			(14,609	)		6,712
Less: net income attributable to noncontrolling interests		—			—		—		—			(43	)		—			(43	)
Net Income Attributable to ConocoPhillips	$	6,669			6,954		1		233			7,421			(14,609	)		6,669
Comprehensive Income Attributable to ConocoPhillips	$	5,294			5,579		1		88			5,747			(11,415	)		5,294

*“Interest and debt expense” for ConocoPhillips was revised to reflect contractually agreed interest rates, with offsetting adjustments in the “Equity in earnings of affiliates” and “Intercompany revenues” lines for ConocoPhillips, ConocoPhillips Company and All Other Subsidiaries. There was no impact to Total Consolidated balances.

27

	Millions of Dollars
	September 30, 2014
Balance Sheet	ConocoPhillips		ConocoPhillips Company		ConocoPhillips Canada Funding Company I			All Other Subsidiaries		Consolidating Adjustments			Total Consolidated
Assets
Cash and cash equivalents	$	—		1,182		239			3,987		—			5,408
Short-term investments		—		—		—			374		—			374
Accounts and notes receivable		22		3,102		17			7,266		(2,954	)		7,453
Inventories		—		248		—			1,082		—			1,330
Prepaid expenses and other current assets		11		626		12			1,086		(47	)		1,688
Total Current Assets		33		5,158		268			13,795		(3,001	)		16,253
Investments, loans and long-term receivables*		60,564		75,338		4,105			36,674		(150,864	)		25,817
Net properties, plants and equipment		—		9,554		—			66,236		—			75,790
Other assets		42		289		144			1,419		(768	)		1,126
Total Assets	$	60,639		90,339		4,517			118,124		(154,633	)		118,986
Liabilities and Stockholders’ Equity
Accounts payable	$	1		4,114		6			7,525		(2,954	)		8,692
Short-term debt		1,498		6		6			178		—			1,688
Accrued income and other taxes		—		83		—			1,572		—			1,655
Employee benefit obligations		—		496		—			217		—			713
Other accruals		115		330		99			896		(47	)		1,393
Total Current Liabilities		1,614		5,029		111			10,388		(3,001	)		14,141
Long-term debt		7,539		5,204		2,976			3,780		—			19,499
Asset retirement obligations and accrued environmental costs		—		1,330		—			8,473		—			9,803
Deferred income taxes		—		663		—			15,429		(8	)		16,084
Employee benefit obligations		—		1,639		—			580		—			2,219
Other liabilities and deferred credits*		2,770		10,942		1,454			19,443		(33,030	)		1,579
Total Liabilities		11,923		24,807		4,541			58,093		(36,039	)		63,325
Retained earnings		38,930		23,893		(1,272	)		19,326		(35,426	)		45,451
Other common stockholders’ equity		9,786		41,639		1,248			40,318		(83,168	)		9,823
Noncontrolling interests		—		—		—			387		—			387
Total Liabilities and Stockholders’ Equity	$	60,639		90,339		4,517			118,124		(154,633	)		118,986
*Includes intercompany loans.

	Millions of Dollars
	December 31, 2013
Balance Sheet	ConocoPhillips		ConocoPhillips Company		ConocoPhillips Australia Funding Company		ConocoPhillips Canada Funding Company I			All Other Subsidiaries		Consolidating Adjustments			Total Consolidated
Assets
Cash and cash equivalents	$	—		2,434		—		229			3,583		—			6,246
Short-term investments		—		—		—		—			272		—			272
Accounts and notes receivable		73		2,122		2		—			9,267		(2,977	)		8,487
Inventories		—		174		—		—			1,020		—			1,194
Prepaid expenses and other current assets		20		535		—		35			2,311		(77	)		2,824
Total Current Assets		93		5,265		2		264			16,453		(3,054	)		19,023
Investments, loans and long-term receivables*		86,836		100,052		—		4,259			34,795		(200,678	)		25,264
Net properties, plants and equipment		—		9,313		—		—			63,514		—			72,827
Other assets		38		260		—		103			1,394		(852	)		943
Total Assets	$	86,967		114,890		2		4,626			116,156		(204,584	)		118,057
Liabilities and Stockholders’ Equity
Accounts payable	$	—		3,388		—		4			8,899		(2,977	)		9,314
Short-term debt		395		4		—		5			185		—			589
Accrued income and other taxes		—		223		—		—			2,517		(27	)		2,713
Employee benefit obligations		—		566		—		—			276		—			842
Other accruals		210		639		—		81			790		(49	)		1,671
Total Current Liabilities		605		4,820		—		90			12,667		(3,053	)		15,129
Long-term debt		9,047		5,208		—		2,980			3,838		—			21,073
Asset retirement obligations and accrued environmental costs		—		1,289		—		—			8,594		—			9,883
Deferred income taxes		94		557		—		—			14,569		—			15,220
Employee benefit obligations		—		1,791		—		—			668		—			2,459
Other liabilities and deferred credits*		31,693		9,422		—		1,603			22,204		(63,121	)		1,801
Total Liabilities		41,439		23,087		—		4,673			62,540		(66,174	)		65,565
Retained earnings		34,636		31,835		—		(1,500	)		12,848		(36,659	)		41,160
Other common stockholders’ equity		10,892		59,968		2		1,453			40,366		(101,751	)		10,930
Noncontrolling interests		—		—		—		—			402		—			402
Total Liabilities and Stockholders’ Equity	$	86,967		114,890		2		4,626			116,156		(204,584	)		118,057
*Includes intercompany loans.

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	Millions of Dollars
	Nine Months Ended September 30, 2014
Statement of Cash Flows	ConocoPhillips			ConocoPhillips Company			ConocoPhillips Canada Funding Company I		All Other Subsidiaries			Consolidating Adjustments			Total Consolidated
Cash Flows From Operating Activities
Net cash provided by (used in) continuing operating activities	$	14,722			(146	)		10		14,423			(15,014	)		13,995
Net cash provided by discontinued operations		—			202			—		394			(453	)		143
Net Cash Provided by Operating Activities		14,722			56			10		14,817			(15,467	)		14,138
Cash Flows From Investing Activities
Capital expenditures and investments		—			(3,235	)		—		(11,132	)		1,638			(12,729	)
Proceeds from asset dispositions		16,912			1,386			—		105			(16,969	)		1,434
Net purchases of short-term investments		—			—			—		(109	)		—			(109	)
Long-term advances/loans—related parties		—			(635	)		—		(7	)		642			—
Collection of advances/loans—related parties		—			47			—		112			(16	)		143
Intercompany cash management		(28,922	)		33,392			—		(4,470	)		—			—
Other		—			(429	)		—		(25	)		—			(454	)
Net cash provided by (used in) continuing investing activities		(12,010	)		30,526			—		(15,526	)		(14,705	)		(11,715	)
Net cash provided by (used in) discontinued operations		—			133			—		(59	)		(133	)		(59	)
Net Cash Provided by (Used in) Investing Activities		(12,010	)		30,659			—		(15,585	)		(14,838	)		(11,774	)
Cash Flows From Financing Activities
Issuance of debt		—			—			—		642			(642	)		—
Repayment of debt		(400	)		(16	)		—		(105	)		16			(505	)
Issuance of company common stock		308			—			—		—			(281	)		27
Dividends paid		(2,618	)		(15,088	)		—		(458	)		15,546			(2,618	)
Other		(2	)		(16,863	)		—		1,514			15,331			(20	)
Net cash provided by (used in) continuing financing activities		(2,712	)		(31,967	)		—		1,593			29,970			(3,116	)
Net cash used in discontinued operations		—			—			—		(335	)		335			—
Net Cash Provided by (Used in) Financing Activities		(2,712	)		(31,967	)		—		1,258			30,305			(3,116	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents		—			—			—		(86	)		—			(86	)
Net Change in Cash and Cash Equivalents		—			(1,252	)		10		404			—			(838	)
Cash and cash equivalents at beginning of period		—			2,434			229		3,583			—			6,246
Cash and Cash Equivalents at End of Period	$	—			1,182			239		3,987			—			5,408

	Millions of Dollars
	Nine Months Ended September 30, 2013*
Statement of Cash Flows	ConocoPhillips			ConocoPhillips Company			ConocoPhillips Australia Funding Company			ConocoPhillips Canada Funding Company I			All Other Subsidiaries			Consolidating Adjustments			Total Consolidated
Cash Flows From Operating Activities
Net cash provided by (used in) continuing operating activities	$	(377	)		2,959			(2	)		(1	)		10,978			(1,616	)		11,941
Net cash provided by discontinued operations		—			91			—			—			579			(435	)		235
Net Cash Provided by (Used in) Operating Activities		(377	)		3,050			(2	)		(1	)		11,557			(2,051	)		12,176
Cash Flows From Investing Activities
Capital expenditures and investments		—			(1,456	)		—			—			(9,825	)		—			(11,281	)
Proceeds from asset dispositions		—			581			—			—			2,646			(52	)		3,175
Net sales of short-term investments		—			—			—			—			1			—			1
Long-term advances/loans—related parties		—			(283	)		—			—			(541	)		824			—
Collection of advances/loans—related parties		—			153			750			2			2,026			(2,801	)		130
Intercompany cash management		1,793			(432	)		—			—			(1,361	)		—			—
Other		—			3			—			—			(54	)		—			(51	)
Net cash provided by (used in) continuing investing activities		1,793			(1,434	)		750			2			(7,108	)		(2,029	)		(8,026	)
Net cash used in discontinued operations		—			(52	)		—			—			(540	)		52			(540	)
Net Cash Provided by (Used in) Investing Activities		1,793			(1,486	)		750			2			(7,648	)		(1,977	)		(8,566	)
Cash Flows From Financing Activities
Issuance of debt		—			523			—			—			301			(824	)		—
Repayment of debt		—			(1,939	)		(750	)		—			(1,058	)		2,801			(946	)
Change in restricted cash		748			—			—			—			—			—			748
Issuance of company common stock		313			—			—			—			—			(301	)		12
Dividends paid		(2,481	)		—			(4	)		—			(2,257	)		2,261			(2,481	)
Other		2			39			—			—			(686	)		52			(593	)
Net cash used in continuing financing activities		(1,418	)		(1,377	)		(754	)		—			(3,700	)		3,989			(3,260	)
Net cash used in discontinued operations		—			—			—			—			(39	)		39			—
Net Cash Used in Financing Activities		(1,418	)		(1,377	)		(754	)		—			(3,739	)		4,028			(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	)		1			94			—			265
Cash and cash equivalents at beginning of period		2			12			6			59			3,539			—			3,618
Cash and Cash Equivalents at End of Period	$	—			190			—			60			3,633			—			3,883

*Revised to reflect intercompany cash management activities previously presented as cash flows from continuing operating activities as both continuing activities and discontinued operations in “Cash Flows from Investing Activities” and “Cash Flows From Financing Activities.” There was no impact on Total Consolidated balances.

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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 50.

Due to discontinued operations reporting, 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. For additional information, see Note 2—Discontinued Operations, in the Notes to Consolidated Financial Statements.

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 27 countries. At September 30, 2014, we had approximately 19,000 employees worldwide and total assets of $119 billion.

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 North America, Europe, Asia and Australia; several major international developments; and a growing inventory of global conventional and unconventional exploration prospects. Our value proposition to our shareholders is to deliver 3 to 5 percent production and 3 to 5 percent cash margin growth, normalized based on 2013 prices, achieve ongoing competitive dividends and returns on capital, while keeping our fundamental commitment to safety, operating excellence and environmental stewardship. To achieve these goals, we plan to continue to invest in high-margin developments, optimize our portfolio, apply technical capability and maintain financial flexibility.

In 2013 we successfully achieved the targets we set to sell non-core assets, advance major projects, progress development drilling and exploration programs and maintain a competitive dividend. Our success has enabled us to focus on growth in 2014, which we intend to deliver through investments in our legacy assets, continued success in our development drilling and exploration programs, continued ramp up in our unconventional plays and additional project startups, which include recent startups for Foster Creek Phase F, the Britannia Long-Term Compression Project and the Gumusut floating production system, and the anticipated startup at Kebabangan (KBB) later in 2014. As a result, we expect to deliver our value proposition in 2014. In the third quarter of 2014, we achieved production of 1,495 thousand barrels of oil equivalent per day (MBOED), including production from discontinued operations of 14 MBOED. Excluding Libya, our production from continuing operations was 1,473 MBOED. Adjusted for Libya and downtime, production from continuing operations increased by 62 MBOED, or 4 percent, compared with the third quarter of 2013.

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Consistent with our commitment to offer our shareholders a competitive dividend, in July 2014, our Board of Directors increased our quarterly dividend by 5.8 percent to $0.73 per share. Through September 2014, we generated $14.0 billion in cash from continuing operations, which included a $1.3 billion distribution from our 50 percent owned FCCL Partnership, and we generated $1.4 billion in proceeds from dispositions of non-core assets. We also paid dividends on our common stock of $2.6 billion and ended the quarter with $5.4 billion in cash and cash equivalents.

We participate in a capital-intensive industry. As a result, we invest significant capital 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. In December 2013 we announced a capital budget of $16.7 billion for 2014, and this guidance is unchanged. We funded $12.7 billion of capital expenditures through September 2014. We use a disciplined approach to select the appropriate projects which will provide the most attractive investment opportunities, with a continued focus on organic growth in volumes and margins through higher-margin oil, condensate and LNG projects and limited investment in North American natural gas. As investments have brought more liquids production online, we have experienced a corresponding shift in our production mix. In the nine-month period of 2014, our average liquids production from continuing operations, excluding Libya, increased 6 percent compared with the same period of 2013. As our major capital projects startup, we plan to direct more of our capital to the unconventionals and development drilling programs, while maintaining the flexibility to respond to changing market conditions. In response to recent weakening commodity prices, an assessment of our 2015 capital budget is ongoing.

Basis of Presentation

Effective April 1, 2014, the Other International segment was restructured to focus on enhancing our capability to operate in emerging and new country business units. As a result, we moved the Latin America and Poland businesses from the historically presented Lower 48 and Latin America segment and the Europe segment to the Other International segment. Results of operations for the Lower 48, Europe and Other International segments have been revised for all periods presented. There was no impact on our consolidated financial results, and the impact on our segment presentation was immaterial. For additional information, see Note 18—Segment Disclosures and Related Information, in the Notes to Consolidated Financial Statements.

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, supply disruptions or fears thereof caused by civil unrest or military conflicts, environmental laws, tax regulations, governmental policies and weather-related disruptions. 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 exploration and 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 will provide the financial flexibility to withstand challenging business cycles.

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Our earnings generally correlate with industry price levels for crude oil and natural gas. These are commodity products, the prices of which are subject to factors external to the Company and over which we have no control. The following graph depicts the trend in average benchmark prices for West Texas Intermediate (WTI) crude oil, Dated Brent crude oil and U.S. Henry Hub (HH) natural gas:

Brent crude oil prices averaged $101.85 per barrel in the third quarter of 2014, a decrease of 8 percent compared with $110.32 per barrel in the third quarter of 2013, and a decrease of 7 percent compared with $109.63 per barrel in the second quarter of 2014. Prices have been under pressure due to abundant supply and lower demand growth, particularly in Europe and Asia where economic growth is slowing. Industry crude prices for WTI averaged $97.48 per barrel in the third quarter of 2014, a decrease of 8 percent compared with $105.80 per barrel in the third quarter of 2013, and a decrease of 5 percent compared with $103.05 per barrel in the second quarter of 2014. Strong U.S. refinery runs and new pipeline and rail infrastructure contributed to reducing the discount of WTI relative to global oil prices during the third quarter of 2014. More recently, global crude oil prices have continued to experience the volatility associated with the supply/demand factors which drive commodity prices and margins. In the fourth quarter of 2014, crude oil prices have declined to their lowest levels in the past four years to the low-to-mid $80-per-barrel-range. Recent futures market prices for WTI and Brent are $80 to $90 per barrel, respectively, for years 2015—2018, based on October 23, 2014, futures settlements.

Henry Hub natural gas prices averaged $4.07 per thousand cubic feet (MCF) in the third quarter of 2014, an increase of 14 percent compared with $3.58 per MCF in the third quarter of 2013, and a decrease of 13 percent compared with $4.68 per MCF in the second quarter of 2014. Strong growth in demand in 2014 versus 2013, particularly winter weather-driven demand, pushed natural gas prices higher in 2014. Prices in the third quarter of 2014 declined relative to the second quarter of 2014, as cooler-than-normal summer weather softened demand growth while production grew more quickly.

Our realized bitumen price was $62.49 per barrel in the third quarter of 2014, a decrease of 18 percent compared with $76.06 per barrel in the third quarter of 2013, and a decrease of 5 percent compared with $65.82 per barrel in the second quarter of 2014. Bitumen prices weakened in the third quarter of 2014, compared with the same period of 2013, mainly as a result of increased supply, partly offset by stronger refinery demand, increased rail transportation and pipeline capacity improvements.

Our total average realized price was $64.78 per barrel of oil equivalent (BOE) in the third quarter of 2014, a decrease of 7 percent compared with $69.68 per BOE in the third quarter of 2013, which reflected lower average realized prices for crude oil, bitumen and natural gas liquids. In the first nine months of 2014, our

32

total realized price was $68.71 per BOE compared with $68.36 per BOE in the first nine months of 2013. This reflected higher natural gas, bitumen and natural gas liquids prices, partially offset by lower crude oil prices.

Key Operating and Financial Highlights

• Increased quarterly dividend by 5.8 percent in July.

• Third-quarter production of 1,473 MBOED from continuing operations, excluding Libya, represents 4 percent growth year-over-year when adjusted for downtime.

• Eagle Ford and Bakken combined production increased by 33 percent compared with third-quarter 2013.

• First production achieved from Foster Creek Phase F and the Britannia Long-Term Compression Project in September, as well as the Gumusut floating production system in October.

• Major turnarounds completed in the Alaska, Canada, Europe, and Asia Pacific and Middle East segments.

• Major project preparations continue for startup at KBB in the fourth quarter of 2014, and Eldfisk II, Surmont 2 and APLNG in 2015.

• Oil discovered at the FAN-1 exploration well, offshore Senegal.

• Exploration and appraisal activity continues with unconventional activities in the Lower 48, Canada and Poland, and conventional drilling in Angola, Australia, the Gulf of Mexico and Senegal.

• Completed the sale of the Nigerian upstream business in July for net proceeds of $1.4 billion, inclusive of deposits previously received.

Outlook

Production and Capital Guidance

We are on track to meet our value proposition in 2014. Full-year 2014 production from continuing operations, excluding Libya, is expected to be approximately 1,525 to 1,535 MBOED. Fourth-quarter 2014 production guidance from continuing operations, excluding Libya, is being adjusted to reflect anticipated impacts from the absence of ramp gas sales from Australia Pacific LNG Pty Ltd (APLNG) to a third-party LNG project, temporary third-party infrastructure constraints in Malaysia and value-driven ethane rejection in the Lower 48. Fourth-quarter production guidance is 1,545 to 1,575 MBOED.

We intend to release guidance on our 2015 capital expenditures in December 2014.

Freeport LNG

We have a long-term agreement with Freeport LNG Development, L.P. to use 0.9 billion cubic feet per day of regasification capacity at Freeport’s 1.5-billion-cubic-feet-per-day LNG receiving terminal in Quintana, Texas. In July 2013 we and Freeport LNG agreed to terminate this agreement, 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. In July 2014 Freeport LNG received conditional approval from the Federal Energy Regulatory Commission (FERC), and in October 2014 Freeport LNG received FERC’s permission to construct the facility. Upon satisfaction of their project financing conditions, currently expected to occur in the fourth quarter of 2014, we will pay Freeport LNG a termination fee of approximately $520 million. Freeport LNG will repay the outstanding ConocoPhillips loan used by Freeport LNG to partially fund the original construction of the terminal. These transactions, plus miscellaneous items, will result in a one-time net cash outflow of approximately $50 million for us. When the agreement becomes effective, we also expect to recognize an after-tax charge to earnings of approximately $520 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 million to $60 million per year in operating costs over the next 19 years. For additional information, see Note 3—Variable Interest Entities (VIEs), in the Notes to Consolidated Financial Statements.

33

RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three- and nine-month periods ended September 30, 2014, is based on a comparison with the corresponding periods of 2013.

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
	2014			2013			2014			2013
Alaska	$	473			494			1,698			1,719
Lower 48		32			209			621			547
Canada		307			642			845			780
Europe		213			288			819			1,005
Asia Pacific and Middle East		772			757			2,390			2,719
Other International		(18	)		283			74			328
Corporate and Other		(130	)		(234	)		(616	)		(569	)
Income from continuing operations	$	1,649			2,439			5,831			6,529

Earnings for ConocoPhillips decreased 32 percent in the third quarter of 2014, and earnings for the nine-month period ended September 30, 2014, decreased 11 percent. The decrease in earnings in both periods of 2014 primarily resulted from:

• Lower gains from asset sales. Gains realized in both periods of 2014 were not material. Gains realized in the third quarter and nine-month period of 2013 were approximately $777 million after-tax and $1,118 million after-tax, respectively.

• Lower crude oil prices.

• Higher operating expenses.

• Higher impairments.

• Lower LNG sales volumes, largely as a result of planned maintenance in Australia.

• Higher depreciation, depletion and amortization (DD&A) expenses, mainly due to higher volumes in the Lower 48 and Europe, partly offset by lower volumes in Canada.

These items were partially offset by:

• Higher crude oil and bitumen sales volumes and a continued portfolio shift toward liquids.

• Higher recognition of net gains associated with pending claims and settlements. The third quarter and nine-month period of 2014 included net gains of $105 million after-tax and $204 million after-tax, respectively, compared with net expenses of $116 million after-tax and net gains of $118 million after-tax for the comparable periods of 2013.

• Lower production taxes in Alaska, which mainly resulted from higher capital spending and lower production volumes.

In addition, lower bitumen prices contributed to the decrease in earnings in the third quarter of 2014.

Earnings in the nine-month period of 2014 also benefitted from higher prices for natural gas, bitumen, LNG and natural gas liquids, as well as improved marketing of third-party North American natural gas volumes. These additional benefits were partly offset by an $83 million after-tax loss related to releases of capacity on transportation and storage capacity agreements.

See the “Segment Results” section for additional information.

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Income Statement Analysis

Sales and other operating revenues decreased 11 percent in the third quarter of 2014, mainly as a result of lower prices for crude oil and bitumen and lower LNG volumes, partly offset by higher crude oil and bitumen volumes.

Equity in earnings of affiliates increased 28 percent in the nine-month period of 2014, primarily as a result of higher earnings from FCCL Partnership due to higher bitumen volumes and prices.

Gain on dispositions decreased $1,065 million in the third quarter and $1,202 million in the nine-month period of 2014. Gains realized in both periods of 2014 were not material. Gains realized in the third quarter of 2013 primarily resulted from the disposition of our Clyden undeveloped oil sands leasehold in Canada and the disposition of our 39 percent equity interest in Phoenix Park, located in Trinidad and Tobago. Additional gains realized in the nine-month period of 2013 mainly resulted from the disposition of our interest in the Interconnector Pipeline in Europe and certain properties located in southwest Louisiana, partly offset by a loss on the disposition of the majority of our producing zones located in the Cedar Creek Anticline in the Lower 48.

Purchased commodities decreased 18 percent in the third quarter of 2014, largely as a result of lower natural gas prices in Europe and lower purchased natural gas volumes, partly offset by higher natural gas prices, in North America.

Production and operating expenses increased 12 percent in the nine-month period of 2014, primarily as a result of increased drilling and maintenance activity, mostly in the Lower 48, Australia, Alaska and Europe, in addition to the absence of the 2013 benefit of a $142 million accrual reduction related to the Federal Energy Regulatory Commission (FERC) approval of cost allocation (pooling) agreements with the remaining owners of the Trans-Alaska Pipeline System (TAPS). These increases were partly offset by the absence of a $155 million charge resulting from a settlement in the Asia Pacific and Middle East segment in 2013.

Exploration expenses increased 47 percent in the third quarter and 40 percent in the nine-month period of 2014. Both periods of 2014 were impacted by higher impairments of undeveloped leasehold costs. Higher dry hole costs, mostly associated with the Gulf of Mexico, also contributed to the increase in the nine-month period of 2014. For additional information on the impairments, see Note 7—Impairments, in the Notes to Consolidated Financial Statements.

DD&A increased 10 percent in the third quarter and 9 percent in the nine-month period of 2014. The increase in both periods of 2014 was mostly associated with higher production volumes in the United Kingdom and the Lower 48, partly offset by lower unit-of-production rates in Canada associated with year-end 2013 price-related reserve revisions and lower natural gas production volumes.

Impairments increased $107 million in the third quarter and $95 million in the nine-month period of 2014. For additional information, see Note 7—Impairments, in the Notes to Consolidated Financial Statements.

Taxes other than income taxes decreased 26 percent in the third quarter and 20 percent in the nine-month period of 2014, mainly as a result of lower production taxes due to higher capital spending and lower crude oil production volumes and prices in Alaska.

Interest and debt expense increased 13 percent in the nine-month period of 2014, primarily due to lower capitalized interest on projects, partly offset by lower interest expense from lower average debt levels and a $28 million benefit associated with interest on a favorable tax settlement.

See Note 19—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding ourprovision for income taxes and effective tax rate.

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Summary Operating Statistics

	Three Months Ended September 30				Nine Months Ended September 30
	2014		2013		2014		2013
Average Net Production
Crude oil (MBD)*		561		552		585		587
Natural gas liquids (MBD)		157		156		161		158
Bitumen (MBD)		124		107		125		105
Natural gas (MMCFD)**		3,833		3,930		3,911		3,963
Total Production (MBOED)		1,481		1,470		1,523		1,511
	Dollars Per Unit
Average Sales Prices
Crude oil (per barrel)	$	96.63		106.60		100.56		104.20
Natural gas liquids (per barrel)		37.83		41.14		41.46		40.64
Bitumen (per barrel)		62.49		76.06		61.65		57.08
Natural gas (per thousand cubic feet)		5.96		5.99		6.77		6.14
	Millions of Dollars
Exploration Expenses
General administrative, geological and geophysical, and lease rentals	$	194		180		604		566
Leasehold impairment		179		32		414		142
Dry holes		86		101		254		203
	$	459		313		1,272		911

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, 2014, 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, including Libya, increased 1 percent in both the third quarter and the nine-month period of 2014, while average liquids production increased 3 percent and 2 percent over the corresponding periods in 2013. The increase in total average production for both periods of 2014 primarily resulted from additional production from major developments, mainly from shale plays in the Lower 48 and the ramp up of production from Jasmine in the United Kingdom and Christina Lake in Canada, and increased drilling programs, mostly in the Lower 48, western Canada and China. These increases were largely offset by normal field decline, higher planned downtime, shut-in Libya production due to the closure of the Es Sider crude oil export terminal, and unfavorable market impacts. Adjusted for Libya and downtime, production from continuing operations increased by 62 MBOED, or 4 percent, compared with the third quarter of 2013.

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Segment Results

Alaska

	Three Months Ended September 30				Nine Months Ended September 30
	2014		2013		2014		2013
Income From Continuing Operations (millions of dollars)	$	473		494		1,698		1,719
Average Net Production
Crude oil (MBD)		139		161		162		176
Natural gas liquids (MBD)		8		11		13		15
Natural gas (MMCFD)		48		35		50		43
Total Production (MBOED)		155		178		183		198
Average Sales Prices
Crude oil (dollars per barrel)	$	102.36		110.95		106.06		109.14
Natural gas (dollars per thousand cubic feet)		5.47		4.09		5.55		4.56

The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids, natural gas and LNG. As of September 30, 2014, Alaska contributed 20 percent of our worldwide liquids production and 1 percent of our natural gas production.

Alaska earnings decreased 4 percent in the third quarter and 1 percent in the nine-month period of 2014 compared with the same periods of 2013. The decrease in both periods of 2014 was largely due to lower crude oil prices and volumes and higher operating expenses. These reductions to earnings were partly offset by lower production taxes, which resulted from higher 2014 capital spending and lower crude oil production volumes, and higher LNG sales.

The decrease in earnings in the nine-month period of 2014 was also attributable to the absence of a $97 million after-tax benefit associated with a FERC ruling in 2013. In 2012 the major owners of 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 FERC approved the proposed settlement and pooling agreement without modification. As a result, we reduced a related accrual in the second quarter of 2013, which decreased our production and operating expenses by $97 million after-tax.

Average production decreased 13 percent in the third quarter and 8 percent in the nine-month period of 2014, compared with the corresponding periods of 2013. The reduction in both periods of 2014 was mainly due to higher planned maintenance and normal field decline, partly offset by lower unplanned downtime.

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Lower 48

	Three Months Ended September 30				Nine Months Ended September 30
	2014		2013		2014		2013
Income From Continuing Operations (millions of dollars)	$	32		209		621		547
Average Net Production
Crude oil (MBD)		191		153		184		149
Natural gas liquids (MBD)		104		94		99		91
Natural gas (MMCFD)		1,485		1,511		1,482		1,490
Total Production (MBOED)		543		499		530		488
Average Sales Prices
Crude oil (dollars per barrel)	$	87.91		100.25		91.02		95.92
Natural gas liquids (dollars per barrel)		30.67		32.57		32.51		30.52
Natural gas (dollars per thousand cubic feet)		3.96		3.39		4.48		3.48

As of September 30, 2014, the Lower 48 contributed 32 percent of our worldwide liquids production and 38 percent of our natural gas production. The Lower 48 segment consists of operations located in the U.S. Lower 48 states and exploration activities in the Gulf of Mexico.

Earnings from the Lower 48 decreased 85 percent in the third quarter and increased 14 percent in the nine-month period of 2014 compared with the same periods of 2013. Earnings in both periods of 2014 were largely impacted by a $151 million after-tax impairment as a result of reduced volume forecasts on proved properties and the associated undeveloped leasehold costs; lower crude oil prices; higher DD&A, mostly due to higher crude oil production; higher operating and exploration costs; and higher production taxes. These decreases were partially offset by higher crude oil and natural gas liquids volumes and higher natural gas prices.

Additional benefits to earnings in the nine-month period of 2014 included approximately $100 million after-tax from marketing third-party natural gas volumes, the absence of the $52 million after-tax loss recognized in the nine-month period of 2013 from the disposition of the majority of our producing zones in the Cedar Creek Anticline, and higher natural gas liquids prices. These increases in the nine-month period of 2014 were partially offset by an $83 million after-tax loss recognized upon the release of underutilized transportation and storage capacity at rates below our contractual rates, a $35 million after-tax legal accrual, and the absence of a $69 million after-tax gain on the 2013 disposition of certain properties in southwest Louisiana.

Dry hole expenses were also higher in the nine-month period of 2014 compared with the same period of 2013. Dry hole costs in the nine-month period of 2014 were approximately $130 million after-tax, primarily for the nonoperated Coronado wildcat and appraisal wells and the Deep Nansen wildcat well in the Gulf of Mexico, compared with approximately $90 million after-tax in the nine-month period of 2013 for the Thorn and Ardennes wells, also located in the Gulf of Mexico.

Rising U.S. production and an increase in pipeline capacity to the Gulf Coast have put downward pressure on Gulf Coast crude oil prices. Prices for Permian Basin crude oil production have been impacted by production increases exceeding pipeline offtake additions. Our average realized prices in the Lower 48 have historically correlated with WTI prices; however, in the second half of 2013, our Lower 48 crude differential versus WTI began to widen. In the third quarter of 2014, our average realized crude oil price of $87.91 per barrel was 10 percent less than WTI of $97.48 per barrel. Current market dynamics indicate this crude differential may remain relatively wide in the near-term.

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Total average production in the Lower 48 increased 9 percent in both the third quarter and the nine-month period of 2014. Average crude oil production increased 25 percent and 23 percent over the same periods, respectively. The increases in both periods of 2014 were mainly attributable to new production, primarily from the Eagle Ford and Bakken, and improved drilling and well performance. These increases in production were partially offset by normal field decline. In addition, higher unplanned downtime and the impact from asset dispositions partly offset the increase in the nine-month period of 2014.

Canada

	Three Months Ended September 30				Nine Months Ended September 30
	2014		2013		2014		2013
Income From Continuing Operations (millions of dollars)	$	307		642		845		780
Average Net Production
Crude oil (MBD)		13		13		13		14
Natural gas liquids (MBD)		21		25		24		25
Bitumen (MBD)
Consolidated operations		9		13		12		12
Equity affiliates		115		94		113		93
Total bitumen		124		107		125		105
Natural gas (MMCFD)		707		775		709		790
Total Production (MBOED)		276		274		280		276
Average Sales Prices
Crude oil (dollars per barrel)	$	82.48		91.81		83.00		81.71
Natural gas liquids (dollars per barrel)		45.29		46.90		49.53		47.07
Bitumen (dollars per barrel)
Consolidated operations		64.95		76.90		64.95		59.18
Equity affiliates		62.30		75.93		61.30		56.79
Total bitumen		62.49		76.06		61.65		57.08
Natural gas (dollars per thousand cubic feet)		3.50		2.42		4.47		2.86

Our Canadian operations mainly consist of natural gas fields in western Canada and oil sands developments in the Athabasca Region of northeastern Alberta. As of September 30, 2014, Canada contributed 19 percent of our worldwide liquids production and 18 percent of our natural gas production.

Canada earnings decreased 52 percent in the third quarter and increased 8 percent in the nine-month period of 2014 compared with the corresponding periods of 2013. Earnings in both periods of 2014 were largely impacted by lower gains from asset sales, as a result of the $461 million after-tax gain on disposition of our Clyden undeveloped oil sands leasehold in the third quarter of 2013, partly offset by higher bitumen volumes, higher natural gas prices and lower DD&A from western Canada. The lower DD&A mainly resulted from lower unit-of-production rates related to year-end 2013 price-related reserve revisions and lower natural gas production volumes. Both periods of 2014 also included a $47 million tax benefit resulting from a favorable tax settlement. Lower bitumen prices also contributed to the reduction in earnings in the third quarter of 2014.

Additional benefits to earnings in the nine-month period of 2014 included higher bitumen prices. The increases to earnings in the nine-month period of 2014 were partly offset by the absence of the 2013 recognition of a $224 million tax benefit, which related to the favorable tax resolution associated with the sale of certain western Canada properties in a prior year, and the $109 million after-tax impairment of undeveloped

39

leasehold costs associated with the offshore Amauligak discovery, Arctic Islands and other Beaufort properties. The impairment resulted from our decision not to pursue future development at this time; however, we remain committed to the potential of the area as technology develops and the price environment improves. Lower natural gas volumes also partially offset the increase in earnings in the nine-month period of 2014.

For additional information on the Amauligak impairment, see Note 7—Impairments, in the Notes to Consolidated Financial Statements.

Total average production increased 1 percent in both the third quarter and nine-month period of 2014, while bitumen production increased 16 percent and 19 percent over the same periods, respectively. Increases in total production in both periods of 2014 were mainly attributable to the continued ramp-up of production from Christina Lake Phase E in FCCL and improved drilling and well performance. These increases were partly offset by normal field decline. Higher planned maintenance also partially offset the increase in the third quarter of 2014, while higher royalty impacts, which resulted from higher prices, partly offset the increase in the nine-month period of 2014.

Europe

	Three Months Ended September 30				Nine Months Ended September 30
	2014		2013		2014		2013
Income From Continuing Operations (millions of dollars)	$	213		288		819		1,005
Average Net Production
Crude oil (MBD)		119		111		126		112
Natural gas liquids (MBD)		8		5		8		5
Natural gas (MMCFD)		404		357		452		409
Total Production (MBOED)		194		176		209		185
Average Sales Prices
Crude oil (dollars per barrel)	$	103.17		112.28		107.79		110.40
Natural gas liquids (dollars per barrel)		54.47		57.36		57.62		56.28
Natural gas (dollars per thousand cubic feet)		7.86		10.48		9.32		10.53

The Europe segment consists of operations principally located in the Norwegian and U.K. sectors of the North Sea, as well as exploration activities in Greenland. As of September 30, 2014, our Europe operations contributed 15 percent of our worldwide liquids production and 12 percent of our natural gas production.

Earnings for Europe decreased 26 percent in the third quarter and 19 percent in the nine-month period of 2014 compared with the same periods of 2013. The decrease in earnings in both periods of 2014 was primarily due to higher DD&A, which mostly resulted from increased production volumes from Jasmine. Higher volumes were offset by lower prices in the third quarter of 2014. In the nine-month period of 2014, lower gains from asset dispositions, mostly due to the absence of the $83 million after-tax gain on the disposition of our interest in the Interconnector Pipeline in 2013; lower prices; and higher taxes and operating expenses were nearly offset by higher volumes.

Average production increased 10 percent in the third quarter and 13 percent in the nine-month period of 2014, mostly due to the continued ramp-up of production from Jasmine, the Rivers Acid Plant in the East Irish Sea and Ekofisk South, improved drilling and well performance in Norway and lower planned downtime. These increases were partly offset by normal field decline. Higher unplanned downtime also partly offset the increase in the third quarter of 2014.

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Asia Pacific and Middle East

	Three Months Ended September 30				Nine Months Ended September 30
	2014		2013		2014		2013
Income From Continuing Operations (millions of dollars)	$	772		757		2,390		2,719
Average Net Production
Crude oil (MBD)
Consolidated operations		72		77		78		82
Equity affiliates		15		16		15		15
Total crude oil		87		93		93		97
Natural gas liquids (MBD)
Consolidated operations		8		13		10		14
Equity affiliates		8		8		7		8
Total natural gas liquids		16		21		17		22
Natural gas (MMCFD)
Consolidated operations		670		712		715		707
Equity affiliates		518		507		501		494
Total natural gas		1,188		1,219		1,216		1,201
Total Production (MBOED)		301		317		314		320
Average Sales Prices
Crude oil (dollars per barrel)
Consolidated operations	$	99.07		105.43		103.28		104.30
Equity affiliates		104.09		105.78		106.57		104.51
Total crude oil		99.92		105.48		103.82		104.33
Natural gas liquids (dollars per barrel)
Consolidated operations		69.69		71.35		73.97		72.38
Equity affiliates		67.13		69.90		71.51		70.68
Total natural gas liquids		68.48		70.76		72.96		71.74
Natural gas (dollars per thousand cubic feet)
Consolidated operations		9.39		10.81		10.03		10.87
Equity affiliates		9.11		9.35		9.97		9.18
Total natural gas		9.26		10.21		10.00		10.18

The Asia Pacific and Middle East segment has operations in China, Indonesia, Malaysia, Australia, Timor-Leste and Qatar, as well as exploration activities in Bangladesh and Brunei. As of September 30, 2014, Asia Pacific and Middle East contributed 13 percent of our worldwide liquids production and 31 percent of our natural gas production.

Asia Pacific and Middle East earnings increased 2 percent in the third quarter and decreased 12 percent in the nine-month period of 2014 compared with the same periods of 2013. The increase in third-quarter 2014 earnings was mainly due to the absence of a $116 million after-tax charge in 2013 associated with the Bohai Bay seepage incidents, largely offset by lower volumes. Lower prices and higher operating expenses were nearly offset by higher equity earnings, mostly due to a $60 million tax benefit from foreign currency exchange rate movements; lower taxes; and a $30 million after-tax benefit resulting from a legal settlement.

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The reduction in earnings in the nine-month period of 2014 was mainly due to lower volumes, primarily LNG and crude oil, and higher operating expenses, mostly as a result of major planned maintenance at our Bayu-Undan Field and Darwin LNG facility in Australia. Lower natural gas prices also contributed to the decrease in earnings. These decreases were partially offset by higher LNG prices and lower taxes. The 2014 benefits from the absence of the $116 million after-tax charge in 2013 related to Bohai Bay and the $30 million after-tax legal settlement in 2014 were offset by the absence of a $146 million after-tax insurance settlement received in 2013, also associated with the Bohai Bay seepage incidents.

Average production decreased 5 percent in the third quarter and 2 percent in the nine-month period of 2014 compared with the same periods of 2013. The decrease in both periods of 2014 was largely attributable to normal field decline and major planned maintenance at Bayu-Undan and Darwin LNG, partially offset by higher production, mainly from China, Indonesia and Malaysia.

KBB Update

We expect first gas for KBB in November 2014; however, our production rate will be significantly constrained, pending repairs on a third-party pipeline. We expect peak production by mid-2015.

Other International

	Three Months Ended					Nine Months Ended
	September 30					September 30
	2014			2013		2014		2013
Income (Loss) From Continuing Operations(millions of dollars)	$	(18	)		283		74		328
Average Net Production*
Crude oil (MBD)
Consolidated operations		8			17		3		34
Equity affiliates		4			4		4		5
Total crude oil		12			21		7		39
Natural gas (MMCFD)		1			33		2		30
Total Production(MBOED)		12			26		7		44
Average Sales Prices*
Crude oil (dollars per barrel)
Consolidated operations	$	95.22			107.49		95.82		107.21
Equity affiliates		66.47			75.90		68.96		73.66
Total crude oil		83.22			100.85		77.62		103.20
Natural gas (dollars per thousand cubic feet)		—			5.92		6.44		5.20

The Other International segment includes operations in Libya and Russia, as well as exploration activities in Colombia, Poland, Angola, Senegal and Azerbaijan. As of September 30, 2014, Other International contributed 1 percent of our worldwide liquids production.

Other International earnings decreased $301 million in the third quarter and $254 million in the nine-month period of 2014 compared with the same periods of 2013. The decrease in both periods of 2014 was primarily due to the absence of the $288 million after-tax gain recognized on the 2013 disposition of our equity investment in Phoenix Park Processors Limited, located in Trinidad and Tobago. Additionally, earnings in the nine-month period of 2014 were impacted by lower volumes from Libya and lower earnings from equity affiliates, which mostly resulted from the Phoenix Park disposition. The reduction in earnings in the nine-

42

month period of 2014 was partially offset by the recognition of other income of $154 million after-tax associated with the favorable resolution of a contingent liability.

Average production decreased 54 percent in the third quarter and 84 percent in the nine-month period of 2014 compared with the same periods in 2013. The decreases primarily resulted from the shutdown of the Es Sider crude oil export terminal in Libya, which began at the end of July 2013. Although the Es Sider Terminal reopened in the third quarter of 2014 and production and liftings have resumed, we continue to monitor developments in Libya.

Venezuela Arbitration

In October 2014 we filed for arbitration under the rules of the International Chamber of Commerce (ICC) against Petroleos de Venezuela (PDVSA), the Venezuela state oil company, for contractual compensation related to the Petrozuata and Hamaca heavy crude oil projects. The ICC arbitration is a separate and independent legal action from the investment treaty arbitration against the government of Venezuela, which is pending before an arbitral tribunal under the World Bank’s International Centre for Settlement for Investment Disputes. For additional information, see Note 11—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

Exploration Update

In November 2014 we will plug and abandon the Kamoxi-1 exploration well, located in Block 36 offshore Angola. As a result, we plan to record an approximately $140 million after-tax charge to dry hole expense in the fourth quarter of 2014, which includes estimated costs through November 2014. After plugging Kamoxi-1, we expect to spud a well in adjacent Block 37, which will be the second wildcat in our planned four-well exploration program in the Kwanza Basin.

In October 2014 we announced oil was discovered at the FAN-1 well, offshore Senegal. Further evaluation is required to determine commerciality.

Asset Dispositions

In July 2014 we sold our Nigeria upstream affiliates, and we transferred our 17 percent interest in the Brass LNG Project to the remaining shareholders in Brass LNG Limited. In 2013, we sold our Algeria business and our interest in Kashagan. Results of operations related to Nigeria, Algeria and Kashagan have been classified as discontinued operations in all periods presented in this Form 10-Q. For additional information, see Note 2—Discontinued Operations, in the Notes to Consolidated Financial Statements.

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Corporate and Other

	Millions of Dollars
	Three Months Ended						Nine Months Ended
	September 30						September 30
	2014			2013			2014			2013
Income (Loss) From Continuing Operations
Net interest	$	(36	)		(124	)		(357	)		(359	)
Corporate general and administrative expenses		(51	)		(77	)		(133	)		(147	)
Technology		(26	)		(26	)		(74	)		7
Other		(17	)		(7	)		(52	)		(70	)
	$	(130	)		(234	)		(616	)		(569	)

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 71 percent in the third quarter of 2014 compared with the same period in 2013, primarily as a result of a $93 million tax benefit associated with the election of the fair market value method of apportioning interest expense in the United States, as well as a $28 million after-tax benefit associated with interest on a favorable tax settlement. These improvements were partly offset by lower capitalized interest on projects. In the nine-month period of 2014, these tax benefits were largely offset by lower capitalized interest on projects sold or completed.

Corporate general and administrative expenses decreased 34 percent in the third quarter of 2014, mainly due to lower pension settlement expense. Pension settlement expense incurred in the third quarter of 2013 was $31 million after-tax. We did not incur pension settlement expense in the third quarter of 2014.

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, LNG, and subsurface, arctic and deepwater technologies, with an underlying commitment to environmental responsibility. Losses from Technology were $74 million in the nine-month period of 2014, compared with earnings of $7 million in the same period of 2013. The reduction in earnings primarily resulted from lower licensing revenues and higher research and development expenses.

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 improved 26 percent in the nine-month period of 2014 compared with the same period of 2013. This improvement was mainly due to foreign currency transaction gains, compared with foreign currency transaction losses in the same period of 2013.

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CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators

	Millions of Dollars
	September 30 2014			December 31 2013
Short-term debt	$	1,688			589
Total debt		21,187			21,662
Total equity		55,661			52,492
Percent of total debt to capital*		28	%		29
Percent of floating-rate debt to total debt**		8	%		8
*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. During the first nine months of 2014, the primary uses of our available cash were $12,729 million to support our ongoing capital expenditures and investments program, $2,618 million to pay dividends and $505 million to repay debt. During the first nine months of 2014, cash and cash equivalents decreased by $838 million, to $5,408 million.

In addition to cash flows from operating activities, 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, and required debt payments.

Significant Sources of Capital

Operating Activities

Cash provided by continuing operating activities was $13,995 million for the first nine months of 2014, compared with $11,941 million for the corresponding period of 2013, a 17 percent increase. The increase was primarily due to the $1.3 billion distribution from FCCL in the first quarter of 2014 and lower tax payments due to a smaller proportion of income in higher tax jurisdictions in 2014. The distribution from FCCL resulted from our $2.8 billion prepayment of the remaining joint venture acquisition obligation in 2013, which substantially increased the financial flexibility of our 50 percent owned FCCL Partnership. We do not expect this individually significant distribution to recur in the future under current economic conditions.

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 have historically been 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 absolute production volumes, as well as product and location mix, impacts our cash flows. Production levels are impacted by such factors as acquisitions and dispositions of fields, field production decline rates, new technologies, operating efficiencies, 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.

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Asset Sales

On July 30, 2014, we sold our Nigeria upstream affiliates for net proceeds of $1.4 billion, after customary adjustments, inclusive of deposits previously received. In 2013 we sold our Algeria business and our interest in Kashagan. Results of operations related to Nigeria, Algeria and Kashagan have been classified as discontinued operations in all periods presented in this Form 10-Q. For additional information, see Note 2—Discontinued Operations, in the Notes to Consolidated Financial Statements. We continue to evaluate opportunities to further optimize the portfolio.

Commercial Paper and Credit Facilities

In June 2014 we refinanced our revolving credit facility from a total of $7.5 billion to $7.0 billion, with a new expiration date of June 2019. Our revolving credit facility may be used for direct bank borrowings, for the issuance of letters of credit totaling up to $500 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 credit 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 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 as administered by ICE Benchmark Administration 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 $6.1 billion commercial paper program. Commercial paper maturities are generally limited to 90 days. We also have the ConocoPhillips Qatar Funding Ltd. $900 million commercial paper program, which is used to fund commitments relating to Qatar Liquefied Gas Company Limited (3). At both September 30, 2014 and December 31, 2013, we had no direct borrowings or letters of credit issued under the revolving credit facility. In addition, under the ConocoPhillips Qatar Funding Ltd. commercial paper programs, $860 million of commercial paper was outstanding at September 30, 2014, compared with $961 million at December 31, 2013. Since we had $860 million of commercial paper outstanding and had issued no letters of credit, we had access to $6.1 billion in borrowing capacity under our revolving credit facility at September 30, 2014.

Certain of our project-related contracts and derivative instruments contain provisions requiring us to post collateral. Many of these contracts and instruments permit us to post either cash or letters of credit as collateral. At September 30, 2014 and December 31, 2013, we had direct bank letters of credit of $700 million and $827 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 10—Guarantees, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

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Capital Requirements

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

Our debt balance at September 30, 2014, was $21.2 billion, a decrease of $475 million from the balance at December 31, 2013. Our short-term debt balance at September 30, 2014, increased $1.1 billion compared with December 31, 2013, primarily as a result of the timing of scheduled maturities. During the first nine months of 2014, we repaid notes at maturity totaling $400 million. In October 2014 we notified holders of the outstanding $1.5 billion 4.60% Notes due January 2015 that early redemption will occur in November 2014. For more information, see Note 8—Debt, in the Notes to Consolidated Financial Statements.

In July 2014 we announced a 5.8 percent increase in the quarterly dividend rate to 73 cents per share. The dividend was paid September 2, 2014, to stockholders of record at the close of business on July 21, 2014. In October 2014 we announced a dividend of 73 cents per share. The dividend will be paid December 1, 2014, to stockholders of record at the close of business on October 14, 2014.

Capital Spending

	Millions of Dollars
	Nine Months Ended September 30
	2014		2013
Alaska	$	1,174		836
Lower 48		4,353		3,885
Canada		1,750		1,602
Europe		1,912		2,326
Asia Pacific and Middle East		3,019		2,306
Other International		403		229
Corporate and Other		118		97
Capital expenditures and investments from continuing operations	$	12,729		11,281
Discontinued operations in Kashagan, Nigeria and Algeria	$	59		540
Joint venture acquisition obligation (principal)—Canada		—		575
Capital Program	$	12,788		12,396

During the first nine months of 2014, capital expenditures and investments from continuing operations supported key exploration and development programs, primarily:

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

• Development of coalbed methane projects associated with the APLNG joint venture in Australia.

• Oil sands development and ongoing liquids-rich plays in Canada.

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

• Alaska activities related to development in the Greater Kuparuk Area and the Greater Prudhoe Area, as well as exploration and development activities in the Western North Slope.

• Exploration and appraisal drilling in deepwater Gulf of Mexico.

• Continued development of offshore fields in Malaysia and Indonesia and ongoing exploration, appraisal and development activity offshore Australia and China.

• Exploration activities in Angola and Senegal.

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Contingencies

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. For information on other contingencies, see Note 11—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

Legal Matters

We are subject to various lawsuits and claims including but not limited to matters involving oil and gas royalty and severance tax payments, gas measurement and valuation methods, contract disputes, environmental damages, personal injury, and property damage. Our primary exposures for such matters relate to alleged royalty underpayments on certain federal, state and privately owned properties and claims of alleged environmental contamination from historic operations. We will continue to defend ourselves vigorously in these matters.

Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, is required.

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 63–65 of our 2013 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

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costs at various sites that typically are not owned by us, but allegedly contain wastes attributable to our past operations. As of December 31, 2013, we reported we had been notified of potential liability under CERCLA and comparable state laws at 15 sites around the United States. As of September 30, 2014, there was no change in the number of sites.

At September 30, 2014, our balance sheet included a total environmental accrual of $366 million, compared with $348 million at December 31, 2013, for remediation activities in the United States 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 upon our results of operations or financial position as a result of compliance with current environmental laws and regulations.

Climate Change

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

For other examples of legislation or precursors for possible regulation 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 65–66 of our 2013 Annual Report on Form 10-K.

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

This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can identify our forward-looking statements by the words “anticipate,” “estimate,” “believe,” “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, bitumen, natural gas, LNG and natural gas liquids.

• 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, cyber attacks or infrastructure constraints or disruptions.

• 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 and 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, execute asset dispositions.

• 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 2013 Annual Report on Form 10-K.

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information about market risks for the nine months ended September 30, 2014, does not differ materially from that discussed under Item 7A in our 2013 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, 2014, 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, 2014.

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

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PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

The following is a description of reportable legal proceedings including those involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment for this reporting period. The following proceedings include those matters that arose during the third quarter of 2014 and any material developments with respect to matters previously reported in ConocoPhillips’ 2013 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 businesses 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 or have subsequently become 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.

Matters previously reported—ConocoPhillips

The New Mexico Environment Department issued four Notices of Violation (NOVs) to ConocoPhillips alleging a total of 16 individual violations for failure to comply with air emission recordkeeping, reporting and testing requirements at various natural gas compression operations in northwestern New Mexico. These violations were alleged to have occurred between 2006 and 2012. ConocoPhillips worked with the agency and has resolved these NOVs by paying a penalty of $189,658.

Matters previously reported—Phillips 66

On May 19, 2010, the Lake Charles Refinery received a Consolidated Compliance Order and Notice of Potential Penalty from the Louisiana Department of Environmental Quality (LDEQ) alleging various violations of applicable air emission regulations, as well as certain provisions of the consent decree in Civil Action No. H-01-4430. Phillips 66 has resolved the consent decree issues and is working with the LDEQ to resolve the remaining allegations.

Item 1A. RISK FACTORS

There have been no material changes from the risk factors disclosed in Item 1A of our 2013 Annual Report on Form 10-K.

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Item 6. EXHIBITS

10.1*	Form of Key Employee Award Terms and Conditions, as part of the ConocoPhillips Targeted Variable Long Term Incentive Program of ConocoPhillips, granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated September 15, 2014.
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.

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SIGNATURE

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

CONOCOPHILLIPS

/s/ Glenda M. Schwarz

Glenda M. Schwarz

Vice President and Controller

(Chief Accounting and Duly Authorized Officer)

November 4, 2014

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