ConocoPhillips (COP) 10-Q 2016 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, 2016

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 1,239,027,409 shares of common stock, $.01 par value, outstanding at September 30, 2016.

CONOCOPHILLIPS

TABLE OF CONTENTS

	Page
Part I—Financial Information
Item 1. Financial Statements
Consolidated Income Statement		1
Consolidated Statement of Comprehensive Income		2
Consolidated Balance Sheet		3
Consolidated Statement of Cash Flows		4
Notes to Consolidated Financial Statements		5
Supplementary Information—Condensed Consolidating Financial Information		27
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		32
Item 3. Quantitative and Qualitative Disclosures About Market Risk		55
Item 4. Controls and Procedures		55
Part II—Other Information
Item 1. Legal Proceedings		56
Item 1A. Risk Factors		56
Item 6. Exhibits		57
Signature		58

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
	2016			2015			2016			2015
Revenues and Other Income
Sales and other operating revenues	$	6,415			7,262			16,884			23,271
Equity in earnings (losses) of affiliates		(60	)		223			(129	)		686
Gain on dispositions		51			18			202			122
Other income		110			4			149			90
Total Revenues and Other Income		6,516			7,507			17,106			24,169
Costs and Expenses
Purchased commodities		2,819			3,269			7,046			9,736
Production and operating expenses		1,526			1,834			4,325			5,434
Selling, general and administrative expenses		203			293			556			670
Exploration expenses		457			1,061			1,572			2,092
Depreciation, depletion and amortization		2,425			2,271			7,001			6,731
Impairments		123			24			321			118
Taxes other than income taxes		161			206			538			655
Accretion on discounted liabilities		108			122			329			365
Interest and debt expense		335			240			928			652
Foreign currency transaction (gains) losses		13			(72	)		12			(96	)
Total Costs and Expenses		8,170			9,248			22,628			26,357
Loss before income taxes		(1,654	)		(1,741	)		(5,522	)		(2,188	)
Income tax benefit		(628	)		(685	)		(1,982	)		(1,254	)
Net loss		(1,026	)		(1,056	)		(3,540	)		(934	)
Less: net income attributable to noncontrolling interests		(14	)		(15	)		(40	)		(44	)
Net Loss Attributable to ConocoPhillips	$	(1,040	)		(1,071	)		(3,580	)		(978	)
Net Loss Attributable to ConocoPhillips Per Share of Common Stock (dollars)
Basic	$	(0.84	)		(0.87	)		(2.88	)		(0.80	)
Diluted		(0.84	)		(0.87	)		(2.88	)		(0.80	)
Dividends Paid Per Share of Common Stock (dollars)	$	0.25			0.74			0.75			2.20
Average Common Shares Outstanding (in thousands)
Basic		1,245,961			1,242,125			1,245,139			1,241,319
Diluted		1,245,961			1,242,125			1,245,139			1,241,319

See Notes to Consolidated Financial Statements.

1

Consolidated Statement of Comprehensive Income ConocoPhillips

	Millions of Dollars
	Three Months Ended September 30						Nine Months Ended September 30
	2016			2015			2016			2015
Net Loss	$	(1,026	)		(1,056	)		(3,540	)		(934	)
Other comprehensive income (loss)
Defined benefit plans
Prior service credit arising during the period		—			163			—			303
Reclassification adjustment for amortization of prior service credit included in net loss		(7	)		(5	)		(25	)		(9	)
Net actuarial loss arising during the period		(31	)		(231	)		(331	)		(216	)
Reclassification adjustment for amortization of net actuarial losses included in net loss		47			126			229			278
Nonsponsored plans*		2			—			2			—
Income taxes on defined benefit plans		(2	)		(18	)		51			(128	)
Defined benefit plans, net of tax		9			35			(74	)		228
Foreign currency translation adjustments		(82	)		(2,544	)		877			(4,493	)
Income taxes on foreign currency translation adjustments		—			25			—			42
Foreign currency translation adjustments, net of tax		(82	)		(2,519	)		877			(4,451	)
Other Comprehensive Income (Loss), Net of Tax		(73	)		(2,484	)		803			(4,223	)
Comprehensive Loss		(1,099	)		(3,540	)		(2,737	)		(5,157	)
Less: comprehensive income attributable to noncontrolling interests		(14	)		(15	)		(40	)		(44	)
Comprehensive Loss Attributable to ConocoPhillips	$	(1,113	)		(3,555	)		(2,777	)		(5,201	)

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

See Notes to Consolidated Financial Statements.

2

Consolidated Balance Sheet ConocoPhillips

	Millions of Dollars
	September 30			December 31
	2016			2015
Assets
Cash and cash equivalents	$	4,090			2,368
Short-term investments		234			—
Accounts and notes receivable (net of allowance of $6 million in 2016 and $7 million in 2015)		3,163			4,314
Accounts and notes receivable—related parties		157			200
Inventories		1,108			1,124
Prepaid expenses and other current assets		889			783
Total Current Assets		9,641			8,789
Investments and long-term receivables		21,283			20,490
Loans and advances—related parties		581			696
Net properties, plants and equipment (net of accumulated depreciation, depletion and amortization of $72,984 million in 2016 and $70,413 million in 2015)		61,649			66,446
Other assets		1,130			1,063
Total Assets	$	94,284			97,484
Liabilities
Accounts payable	$	3,686			4,895
Accounts payable—related parties		65			38
Short-term debt		1,336			1,427
Accrued income and other taxes		394			499
Employee benefit obligations		757			887
Other accruals		1,299			1,510
Total Current Liabilities		7,537			9,256
Long-term debt		27,353			23,453
Asset retirement obligations and accrued environmental costs		9,820			9,580
Deferred income taxes		9,034			10,999
Employee benefit obligations		2,471			2,286
Other liabilities and deferred credits		1,613			1,828
Total Liabilities		57,828			57,402
Equity
Common stock (2,500,000,000 shares authorized at $.01 par value)
Issued (2016—1,781,258,082 shares; 2015—1,778,226,388 shares)
Par value		18			18
Capital in excess of par		46,480			46,357
Treasury stock (at cost: 2016—542,230,673 shares; 2015—542,230,673 shares)		(36,780	)		(36,780	)
Accumulated other comprehensive loss		(5,444	)		(6,247	)
Retained earnings		31,896			36,414
Total Common Stockholders’ Equity		36,170			39,762
Noncontrolling interests		286			320
Total Equity		36,456			40,082
Total Liabilities and Equity	$	94,284			97,484

See Notes to Consolidated Financial Statements.

3

Consolidated Statement of Cash Flows ConocoPhillips

	Millions of Dollars
	Nine Months Ended September 30
		2016		2015
Cash Flows From Operating Activities
Net loss	$	(3,540	)	(934	)
Adjustments to reconcile net loss to net cash provided by operating activities
Depreciation, depletion and amortization		7,001		6,731
Impairments		321		118
Dry hole costs and leasehold impairments		1,010		1,238
Accretion on discounted liabilities		329		365
Deferred taxes		(2,152	)	(1,284	)
Distributions received greater than equity losses (undistributed equity earnings)		414		(79	)
Gain on dispositions		(202	)	(122	)
Other		(50	)	(259	)
Working capital adjustments
Decrease in accounts and notes receivable		1,112		1,913
Decrease in inventories		22		159
Decrease in prepaid expenses and other current assets		46		255
Decrease in accounts payable		(515	)	(1,618	)
Decrease in taxes and other accruals		(836	)	(507	)
Net Cash Provided by Operating Activities		2,960		5,976
Cash Flows From Investing Activities
Capital expenditures and investments		(3,870	)	(7,913	)
Working capital changes associated with investing activities		(401	)	(842	)
Proceeds from asset dispositions		419		323
Net purchases of short-term investments		(229	)	—
Collection of advances/loans—related parties		108		105
Other		61		298
Net Cash Used in Investing Activities		(3,912	)	(8,029	)
Cash Flows From Financing Activities
Issuance of debt		4,594		2,498
Repayment of debt		(839	)	(92	)
Issuance of company common stock		(52	)	(69	)
Dividends paid		(940	)	(2,741	)
Other		(93	)	(50	)
Net Cash Provided by (Used in) Financing Activities		2,670		(454	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents		4		(142	)
Net Change in Cash and Cash Equivalents		1,722		(2,649	)
Cash and cash equivalents at beginning of period		2,368		5,062
Cash and Cash Equivalents at End of Period	$	4,090		2,413

See Notes to Consolidated Financial Statements.

4

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 2015 Annual Report on Form 10-K.

Effective November 1, 2015, the Other International and historically presented Europe segments were restructured to align with changes to our internal organization structure. The Libya business was moved from the Other International segment to the historically presented Europe segment, which is now renamed Europe and North Africa. 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 19—Segment Disclosures and Related Information.

Note 2—Change in Accounting Principles

We adopted the provisions of Financial Accounting Standards Board (FASB) Accounting Standards Update (ASU) No. 2015-02, “Amendments to the Consolidation Analysis,” beginning January 1, 2016. The ASU amends existing requirements applicable to reporting entities that are required to evaluate whether certain legal entities, including variable interest entities (VIEs), should be consolidated. The adoption of this ASU did not have an impact on our consolidated financial statements and disclosures. See Note 3—Variable Interest Entities, for additional information on our significant VIE.

Note 3—Variable Interest Entities

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

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 liquefied natural gas (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, 2016, 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 6—Investments, Loans and Long-Term Receivables, and Note 11—Guarantees, for additional information.

5

Note 4—Inventories

Inventories consisted of the following:

	Millions of Dollars
	September 30 2016		December 31 2015
Crude oil and natural gas	$	436		406
Materials and supplies		672		718
	$	1,108		1,124

Inventories valued on the last-in, first-out (LIFO) basis totaled $307 million and $317 million at September 30, 2016 and December 31, 2015, respectively. The estimated excess of current replacement cost over LIFO cost of inventories was approximately $62 million and $6 million at September 30, 2016 and December 31, 2015, respectively.

Note 5—Assets Held for Sale, Sold, or Other Planned Dispositions

Assets Sold

All gains or losses are reported before-tax and are included net in the “Gain on dispositions” line on our consolidated income statement.

On April 22, 2016, we sold our interest in the Alaska Beluga River Unit natural gas field in the Cook Inlet for $134 million, net of settlement of gas imbalances and customary adjustments, and recognized a gain on disposition of $56 million. At the time of disposition, the net carrying value of our Beluga River Unit interest, which was included in the Alaska segment, was $78 million, consisting primarily of $100 million of properties, plants and equipment (PP&E) and $19 million of asset retirement obligations (ARO).

Assets Held for Sale

On September 18, 2016, we entered into a definitive agreement to sell our 40 percent interest in South Natuna Sea Block B. The transaction is expected to close in the fourth quarter of 2016. At September 30, 2016, the asset was considered held for sale and a before-tax impairment of $42 million was recorded in the third quarter to reduce the carrying value to fair value of approximately $239 million. We reclassified $162 million of related noncurrent assets, primarily PP&E, to “Prepaid expenses and other current assets” and $50 million of noncurrent liabilities, comprised of employee pension obligations and other liabilities, to “Employee benefit obligations” and “Other accruals,” within current liabilities, on our consolidated balance sheet as of September 30, 2016. Our interest in Block B is included in the Asia Pacific and Middle East segment.

On October 13, 2016, we completed an asset exchange with Bonavista Energy in which we gave up approximately 143,000 net acres of non-core developed properties in central Alberta in exchange for approximately 40,000 net acres of primarily undeveloped properties in northeast British Columbia. The fair value of the transaction was determined to be approximately $69 million. The divested properties, which were included in the Canada segment, were considered held for sale at September 30, 2016, resulting in the recognition of a before-tax impairment of $57 million in the third quarter of 2016 to reduce the carrying value to fair value. We reclassified $65 million of PP&E to “Prepaid expenses and other current assets” and $27 million of noncurrent liabilities, primarily asset retirement obligations, to “Other accruals,” on our consolidated balance sheet as of September 30, 2016.

6

Other Planned Dispositions

On October 28, 2016, we sold our 35 percent interest in three exploration blocks offshore Senegal for approximately $440 million, including net customary adjustments of approximately $90 million. In addition, we provided an indemnification to the buyer for certain potential losses related to the disposition. The three blocks had a net book value of approximately $285 million as of September 30, 2016. Senegal results of operations are reported within our Other International segment.

Note 6—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, 2016, $8.5 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. In October 2016, we reached completion for Train 1, which will reduce our associated guarantee by 60 percent. See Note 11—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, for additional information.

On July 1, 2016, APLNG changed its tax functional currency from Australian dollar to U.S. dollar and translated all APLNG assets and liabilities into U.S. dollar, utilizing the exchange rate as of that date. As a result of this change, we recorded a reduction to our investment in APLNG for the deferred tax effect of $174 million in the “Equity in earnings (losses) of affiliates” line of our consolidated income statement in the third quarter of 2016.

During the third quarter of 2016, the outlook for crude oil prices weakened, and as a result, the estimated fair value of our investment in APLNG declined to an amount below book value. Based on a review of the facts and circumstances surrounding this decline in fair value, we concluded the impairment was not other than temporary under the guidance of FASB Accounting Standards Codification (ASC) Topic 323, “Investments – Equity Method and Joint Ventures.” In reaching this conclusion, we primarily considered: (1) the volatility and uncertainty in commodity markets; (2) the intent and ability of ConocoPhillips to retain our investment in APLNG; (3) the impact of the passage of time on the estimate of fair value; and (4) the short length of time book value has been less than market value (fair value exceeded book value as of June 30, 2016). Fair value has been estimated based on an internal discounted cash flow model using estimates of future production, prices from futures exchanges and pricing service companies, costs, foreign currency rates, and a discount factor believed to be consistent with those used by principal market participants.

At September 30, 2016, the fair value of our investment in APLNG was estimated to be $9,906 million, resulting in an unrecognized impairment of $272 million. We will continue to monitor the relationship between the book value and the fair value of APLNG. Should we determine in the future there has been a loss in the book value of our investment that is other than temporary, we would record a noncash impairment of our equity investment, calculated as the total difference between book value and fair value as of the end of the reporting period.

At September 30, 2016, the book value of our equity method investment in APLNG was $10,178 million. The balance is included in the “Investments and long-term receivables” line on our consolidated balance sheet.

FCCL

At September 30, 2016, the book value of our equity method investment in FCCL Partnership was $8,885 million, net of a $1,477 million reduction due to cumulative foreign currency translation effects. The balance is included in the “Investments and long-term receivables” line on our consolidated balance sheet.

7

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. At September 30, 2016, significant loans to affiliated companies included $696 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 7—Suspended Wells and Other Exploration Expenses

The capitalized cost of suspended wells at September 30, 2016, was $1,342 million, an increase of $82 million from $1,260 million at year-end 2015. Two suspended wells in the Gulf of Mexico totaling $100 million were charged to dry hole expense during the first nine months of 2016 relating to exploratory well costs capitalized for a period greater than one year as of December 31, 2015.

In July 2016, we entered into an agreement to terminate our final Gulf of Mexico deepwater drillship contract. The drillship, used to drill our operated deepwater well inventory in the Gulf of Mexico through April 2016, was contracted on a shared, three-year term. Accordingly, we recorded before-tax rig cancellation charges and third party costs of $134 million in our Lower 48 segment in the third quarter of 2016.

These charges are included in the “Exploration expenses” line on our consolidated income statement.

Note 8—Impairments

During the three- and nine-month periods ended September 30, 2016 and 2015, we recognized before-tax impairment charges within the following segments:

	Millions of Dollars
	Three Months Ended September 30				Nine Months Ended September 30
	2016		2015		2016		2015
Alaska	$	—		2		—		9
Lower 48		1		6		61		6
Canada		60		—		60		—
Europe and North Africa		20		9		157		96
Asia Pacific and Middle East		42		6		43		6
Corporate and Other		—		1		—		1
	$	123		24		321		118

In the three- and nine-month periods ended September 30, 2016, our Canada and Asia Pacific and Middle East segments included before-tax impairments of $60 million and $42 million, respectively, primarily related to certain developed properties in central Alberta and offshore Indonesia, which were classified as held for sale at September 30, 2016, and were written down to fair value less costs to sell. Our Europe and North Africa segment included before-tax impairments of $20 million in the three-month period ended September 30, 2016, primarily as a result of a canceled project and lower natural gas prices, both in the United Kingdom. In the nine-month period of 2016, our Europe and North Africa segment included before-tax impairments of $157 million, primarily as a result of lower natural gas prices in the United Kingdom. Our Lower 48 segment included impairments of $61 million before-tax in the nine-month period of 2016, primarily as a result of lower natural gas prices and increased asset retirement obligation estimates.

8

The nine-month period of 2015 included impairments in our Europe and North Africa segment of $96 million, primarily as a result of lower natural gas prices in the United Kingdom.

The charges discussed below are included in the “Exploration expenses” line on our consolidated income statement and are not reflected in the table above.

Exploration expenses in the nine-month period of 2016 were aligned with our decision announced in 2015 to reduce deepwater exploration spending. We recorded a $203 million before-tax impairment for the associated carrying value of our Gibson and Tiber undeveloped leaseholds in deepwater Gulf of Mexico in the second quarter of 2016. Additionally, in the first quarter of 2016, we recorded a $95 million before-tax impairment for the associated carrying value of capitalized undeveloped leasehold costs of the Melmar prospect and a $73 million impairment in our Lower 48 segment, primarily as a result of changes in the estimated market value following the completion of an initial marketing effort.

Note 9—Debt

In the first quarter of 2016, we reduced our revolving credit facility, expiring in June 2019, from $7.0 billion to $6.75 billion. We have two commercial paper programs supported by our $6.75 billion revolving credit facility: the ConocoPhillips $6.25 billion program, primarily a funding source for short-term working capital needs, and the ConocoPhillips Qatar Funding Ltd. $500 million program, which is used to fund commitments relating to QG3. Commercial paper maturities are generally limited to 90 days.

At September 30, 2016 and December 31, 2015, we had no direct outstanding borrowings under the revolving credit facility, with no letters of credit as of September 30, 2016 or December 31, 2015. Under the ConocoPhillips Qatar Funding Ltd. commercial paper program, no commercial paper was outstanding at September 30, 2016, compared with $803 million at December 31, 2015. Since we had no commercial paper outstanding and had issued no letters of credit, we had access to $6.75 billion in borrowing capacity under our revolving credit facility at September 30, 2016.

On October 17, 2016, the $1,250 million 5.625% Notes due 2016 were repaid at maturity.

In March 2016, we issued notes consisting of:

• The $1,250 million of 4.20% Notes due 2021.

• The $1,250 million of 4.95% Notes due 2026.

• The $500 million of 5.95% Notes due 2046.

In addition, on March 18, 2016, we entered into a $1,600 million three-year senior unsecured term loan facility. Borrowings will accrue interest at a base rate or, for certain Eurodollar borrowings, the London Interbank Offered Rate (LIBOR), in each case plus a margin that is set based on our corporate credit ratings. The applicable margin for loans bearing interest based on the base rate ranges from 0.50% to 1.00% and the applicable margin for loans bearing interest based on LIBOR ranges from 1.50% to 2.00%. Based on our current corporate credit ratings, the applicable margin for loans accruing interest at the base rate is 0.50% and the applicable margin for loans accruing interest at LIBOR is 1.50%.

The term loan facility contains customary covenants regarding, among other matters, material compliance with laws and restrictions against certain consolidations, mergers and asset sales and creation of certain liens on our assets and consolidated subsidiaries. The term loan facility also contains financial covenants including a total debt to capitalization ratio, excluding the impacts of certain noncash impairments and foreign currency translation adjustments as defined in the Term Loan Agreement, which may not exceed 65 percent. At September 30, 2016, we were in compliance with this covenant.

9

The term loan facility includes customary events of default (subject to specified cure periods, materiality qualifiers and exceptions), including the failure to pay any interest, principal or fees when due, the failure to perform or the violation of any covenant contained in the term loan facility, the making of materially inaccurate or false representations or warranties, a default on certain material indebtedness, insolvency or bankruptcy, a change of control and the occurrence of material Employee Retirement Income Security Act of 1974 (ERISA) events and certain judgments against us or our material subsidiaries.

We have the right at any time and from time to time to prepay the term loan, in whole or in part, without premium or penalty upon notice to the Administrative Agent.

The net proceeds of the notes and term loan will be used for general corporate purposes.

At September 30, 2016, we had $283 million of certain variable rate demand bonds (VRDBs) outstanding with maturities ranging through 2035. The VRDBs are redeemable at the option of the bondholders on any business day. The VRDBs are included in the “Long-term debt” line on our consolidated balance sheet.

Note 10—Noncontrolling Interests

Activity attributable to common stockholders’ equity and noncontrolling interests for the first nine months of 2016 and 2015 was as follows:

	Millions of Dollars
	2016									2015
	Common Stockholders’ Equity			Non- Controlling Interest			Total Equity			Common Stockholders’ Equity			Non- Controlling Interest			Total Equity
Balance at January 1	$	39,762			320			40,082			51,911			362			52,273
Net income (loss)		(3,580	)		40			(3,540	)		(978	)		44			(934	)
Dividends		(940	)		—			(940	)		(2,741	)		—			(2,741	)
Distributions to noncontrolling interests		—			(75	)		(75	)		—			(62	)		(62	)
Other changes, net*		928			1			929			(3,982	)		1			(3,981	)
Balance at September 30	$	36,170			286			36,456			44,210			345			44,555

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

Note 11—Guarantees

At September 30, 2016, 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 because the fair value of the obligation is immaterial. In addition, unless otherwise stated, we are not currently performing with any significance under the guarantee and expect future performance to be either immaterial or have only a remote chance of occurrence.

10

APLNG Guarantees

At September 30, 2016, we had 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 2016 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 one year. Our maximum potential amount of future payments related to this guarantee is approximately $80 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. Our maximum exposure at September 30, 2016, is $3.2 billion based upon our pro-rata share of the facility used at that date. At September 30, 2016, the carrying value of this guarantee is approximately $114 million. In October 2016, we reached completion for Train 1, which will reduce our maximum potential amount of future payments to $1.3 billion and the carrying amount of the guarantee to approximately $45 million. The remaining guarantee is expected to be released in 2017.

• During the third quarter of 2016, we issued a guarantee for our pro-rata portion of the funds in a project finance reserve account. We estimate the remaining term of this guarantee is 13 years. Our maximum exposure under this guarantee is approximately $100 million and may become payable if an enforcement action is commenced by the project finance lenders against APLNG. At September 30, 2016, the carrying value of this guarantee is approximately $9 million.

• In conjunction with our original purchase of an ownership interest in APLNG from Origin Energy in October 2008, we agreed to reimburse Origin Energy for our share of the existing contingent liability arising under guarantees of an existing obligation of APLNG to deliver natural gas under several sales agreements with remaining terms of 1 to 26 years. Our maximum potential liability for future payments, or cost of volume delivery, under these guarantees is estimated to be $1.0 billion ($1.9 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 29 years or the life of the venture. Our maximum potential amount of future payments related to these guarantees is approximately $170 million and would become payable if APLNG does not perform.

Other Guarantees

We have other guarantees with maximum future potential payment amounts totaling approximately $520 million, which consist primarily of a guarantee of the residual value of a leased office building, guarantees of the residual value of leased corporate aircraft, a guarantee for our portion of a joint venture’s project finance reserve accounts, and a guarantee of minimum charter revenue for an LNG vessel. These guarantees have remaining terms of up to eight years 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 nonperformance 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, 2016, was approximately $90 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, 2016, were approximately $40 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 12—Contingencies and Commitments.

On March 1, 2015, a supplier to one of the refineries included in Phillips 66 as part of the separation of our Downstream businesses formally registered Phillips 66 as a party to the supply agreement, thereby triggering a guarantee we provided at the time of separation. Our maximum potential liability for future payments under this guarantee, which would become payable if Phillips 66 does not perform its contractual obligations under the supply agreement, is approximately $1.5 billion. At September 30, 2016, the carrying value of this guarantee is approximately $98 million and the remaining term is eight years. Because Phillips 66 has indemnified us for losses incurred under this guarantee, we have recorded an indemnification asset from Phillips 66 of approximately $98 million. The recorded indemnification asset amount represents the estimated fair value of the guarantee; however, if we are required to perform under the guarantee, we would expect to recover from Phillips 66 any amounts in excess of that value, provided Phillips 66 is a going concern.

Note 12—Contingencies and Commitments

A number of lawsuits involving a variety of claims arising in the ordinary course of business have been filed 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 but 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 factors such 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.

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Environmental

We are subject to international, federal, state and local environmental laws and regulations. When we prepare our consolidated financial statements, we record accruals for environmental liabilities based on management’s best estimates, using all information that is available at the time. We measure estimates and base liabilities on currently available facts, existing technology, and presently enacted laws and regulations, taking into account stakeholder and business considerations. When measuring environmental liabilities, we also consider our prior experience in remediation of contaminated sites, other companies’ cleanup experience, and data released by the U.S. Environmental Protection Agency (EPA) or other organizations. We consider unasserted claims in our determination of environmental liabilities, and we accrue them in the period they are both probable and reasonably estimable.

Although liability of those potentially responsible for environmental remediation costs is generally joint and several for federal sites and frequently so for other sites, we are usually only one of many companies cited at a particular site. Due to the joint and several liabilities, we could be responsible for all cleanup costs related to any site at which we have been designated as a potentially responsible party. We have been successful to date in sharing cleanup costs with other financially sound companies. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the agency concerned. Prior to actual cleanup, those potentially responsible normally assess the site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or may attain a settlement of liability. Where it appears that other potentially responsible parties may be financially unable to bear their proportional share, we consider this inability in estimating our potential liability, and we adjust our accruals accordingly. As a result of various acquisitions in the past, we assumed certain environmental obligations. Some of these environmental obligations are mitigated by indemnifications made by others for our benefit and some of the indemnifications are subject to dollar 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.

Our balance sheet at both September 30, 2016 and December 31, 2015, included a total environmental accrual of $258 million, for remediation activities in the United States and Canada. We expect to incur a substantial amount of these expenditures within the next 30 years. 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 and tax 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.

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Other Contingencies

We have contingent liabilities resulting from throughput agreements with pipeline and processing companies not associated with financing arrangements. Under these agreements, we may be required to provide any such company with additional funds through advances and penalties for fees related to throughput capacity not utilized. In addition, at September 30, 2016, we had performance obligations secured by letters of credit of $304 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. On October 6, 2016, ConocoPhillips brought a fraudulent transfer action in the U.S. District Court of Delaware against PDVSA, alleging that PDVSA has taken actions to improperly expatriate assets from the United States to Venezuela in an effort to avoid judgment creditors.

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 to determine the damages owed to ConocoPhillips for Ecuador’s actions and to address Ecuador’s counterclaims is complete. We are awaiting the tribunal’s award.

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. 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. We have now reached a settlement with the Timor-Leste government on these disputes.

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Note 13—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 our consolidated statement of cash flows. On our consolidated income statement, realized and unrealized gains and losses are recognized either on a gross basis if directly related to our physical business or a net basis if held for trading. Gains and losses related to contracts that meet and are designated with the normal purchase normal sale exception are recognized upon settlement. We generally apply this exception to eligible crude contracts. We do not use hedge accounting for our commodity derivatives.

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

	Millions of Dollars
	September 30 2016		December 31 2015
Assets
Prepaid expenses and other current assets	$	246		768
Other assets		38		60
Liabilities
Other accruals		247		754
Other liabilities and deferred credits		32		46

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
	2016		2015			2016			2015
Sales and other operating revenues	$	11		89			(155	)		117
Other income		1		—			(1	)		1
Purchased commodities		7		(85	)		136			(88	)

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

	Open Position Long/(Short)
	September 30 2016			December 31 2015
Commodity
Natural gas and power (billions of cubic feet equivalent)
Fixed price		(36	)		(14	)
Basis		21			(17	)

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Foreign Currency Exchange Derivatives

We have foreign currency exchange rate risk resulting from international operations. Our foreign currency exchange derivative activity primarily relates to managing 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.

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 2016		December 31 2015
Assets
Prepaid expenses and other current assets	$	—		47
Liabilities
Other accruals		137		8

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
	2016		2015			2016		2015
Foreign currency transaction (gains) losses	$	35		(17	)		218		(30	)

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

	In Millions Notional  Currency
	September 30 2016		December 31 2015
Sell U.S. dollar, buy other currencies*	USD	14		347
Buy U.S. dollar, sell other currencies**	USD	—		20
Buy British pound, sell other currencies***	GBP	1,073		567

    * Primarily Canadian dollar, Norwegian krone and British pound.

  ** Primarily Canadian dollar.

*** Primarily Canadian dollar and euro.

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.

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	Millions of Dollars
	Carrying Amount
	Cash and Cash Equivalents				Short-Term Investments
	September 30 2016		December 31 2015		September 30 2016		December 31 2015
Cash	$	728		528		—		—
Time deposits
Remaining maturities from 1 to 90 days		3,362		1,840		209		—
Remaining maturities from 91 to 180 days		—		—		25		—
	$	4,090		2,368		234		—

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 to 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.

The aggregate fair value of all derivative instruments with such credit-risk-related contingent features that were in a liability position on September 30, 2016 and December 31, 2015, was $52 million and $158 million, respectively. For these instruments, $1 million of collateral was posted as of September 30, 2016, and $2 million of collateral was posted as of December 31, 2015. If our credit rating had been downgraded below investment grade on September 30, 2016, we would be required to post $51 million of additional collateral, either with cash or letters of credit.

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Note 14—Fair Value Measurement

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

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

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

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

The classification of an asset or liability is based on the lowest level of input significant to its fair value. Those that are initially classified as Level 3 are subsequently reported as Level 2 when the fair value derived from unobservable inputs is inconsequential to the overall fair value, or if corroborated market data becomes available. Assets and liabilities 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 2016 or 2015.

Recurring Fair Value Measurement

Financial assets and liabilities reported at fair value on a recurring basis primarily include commodity derivatives. 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 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, 2016								December 31, 2015
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Commodity derivatives	$	164		94		26		284		516		242		70		828
Total assets	$	164		94		26		284		516		242		70		828
Liabilities
Commodity derivatives	$	161		101		17		279		515		273		12		800
Total liabilities	$	161		101		17		279		515		273		12		800

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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 setoff 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, 2016
Assets	$	284		190		94		—		5		89
Liabilities		279		190		89		6		7		76
December 31, 2015
Assets	$	828		600		228		—		8		220
Liabilities		800		600		200		1		11		188

At September 30, 2016 and December 31, 2015, 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 summarizes the fair value hierarchy by major category and date of remeasurement for assets accounted for at fair value on a non-recurring basis during the year:

	Millions of Dollars
			Fair Value Measurements Using
	Fair Value		Level 1 Inputs		Level 3 Inputs		Before- Tax Loss
September 30, 2016
Net PP&E (held for sale)	$	217		217		—		99
June 30, 2016
Net PP&E (held for use)	$	23		—		23		53
March 31, 2016
Net PP&E (held for use)	$	217		—		217		129

Net PP&E held for sale was written down to fair value, less costs to sell. The fair value of each asset was determined by its negotiated selling price.

Net PP&E held for use is comprised of various producing properties impaired to their individual fair values less costs to sell. The fair values were determined by internal discounted cash flow models using estimates of future production, prices from futures exchanges and pricing service companies, costs, and a discount factor believed to be consistent with those used by principal market participants.

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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.

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

• Accounts payable (including related parties) and floating-rate debt: The carrying amount of accounts payable and floating-rate debt reported on the balance sheet approximates fair value.

• 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		December 31		September 30		December 31
	2016		2015		2016		2015
Financial assets
Commodity derivatives	$	94		228		94		228
Total loans and advances—related parties		698		808		698		808
Financial liabilities
Total debt, excluding capital leases		27,824		24,062		31,046		24,785
Commodity derivatives		83		199		83		199

Note 15—Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss 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, 2015	$	(443	)		(5,804	)		(6,247	)
Other comprehensive income (loss)		(74	)		877	*		803
September 30, 2016	$	(517	)		(4,927	)		(5,444	)

* Foreign Currency Translation is primarily a result of the weakening of the U.S. dollar relative to the Canadian dollar and Norwegian krone.

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

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

	Millions of Dollars
	Three Months Ended September 30				Nine Months Ended September 30
	2016		2015		2016		2015
Defined benefit plans	$	27		77		132		173
Above amounts are included in the computation of net periodic benefit cost and are presented net of tax expense of:	$	13		44		72		96

See Note 17—Employee Benefit Plans, for additional information.

Note 16—Cash Flow Information

	Millions of Dollars
	Nine Months Ended September 30
	2016			2015
Cash Payments (Receipts)
Interest	$	854			633
Income taxes*		(339	)		376
Net Sales (Purchases) of Short-Term Investments
Short-term investments purchased	$	(1,704	)		—
Short-term investments sold		1,475			—
	$	(229	)	��	—

* Net of $569 million and $556 million in 2016 and 2015, respectively, related to refunds received from the Internal Revenue Service.

In May 2015, we liquidated certain deferred compensation investments for proceeds of $267 million, which is included in the “Other” line within “Cash Flows From Investing Activities” on our consolidated statement of cash flows.

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Note 17—Employee Benefit Plans

Pension and Postretirement Plans

	Millions of Dollars
	Pension Benefits												Other Benefits
	2016						2015						2016			2015
	U.S.			Int’l.			U.S.			Int’l.
Components of Net Periodic Benefit Cost
Three Months Ended September 30
Service cost	$	27			19			36			31			—			2
Interest cost		32			30			41			34			3			5
Expected return on plan assets		(34	)		(39	)		(50	)		(44	)		—			—
Amortization of prior service cost (credit)		2			(1	)		1			(1	)		(9	)		(6	)
Recognized net actuarial loss		22			6			27			20			—			—
Settlements		22			—			79			—			—			—
Curtailment loss		14			—			35			—			1			—
Net periodic benefit cost	$	85			15			169			40			(5	)		1
Nine Months Ended September 30
Service cost	$	82			59			108			94			1			3
Interest cost		104			93			120			102			10			19
Expected return on plan assets		(112	)		(121	)		(157	)		(131	)		—			—
Amortization of prior service cost (credit)		4			(4	)		4			(5	)		(26	)		(9	)
Recognized net actuarial loss (gain)		64			20			84			62			(1	)		1
Settlements		149			—			131			—			—			—
Curtailment loss		14			—			35			—			1			—
Net periodic benefit cost	$	305			47			325			122			(15	)		14

During the first nine months of 2016, we contributed $223 million to our domestic benefit plans and $82 million to our international benefit plans. In 2016, we expect to contribute approximately $260 million to our domestic qualified and nonqualified pension and postretirement benefit plans and $130 million to our international qualified and nonqualified pension and postretirement benefit plans.

In conjunction with the recognition of pension settlement expense, the fair market values of pension plan assets were updated, and the pension benefit obligations of the U.S. qualified pension plan and a U.S. nonqualified supplemental retirement plan were remeasured. At the measurement dates, the net pension liability increased by $33 million and $334 million for the three- and nine-month periods ended September 30, 2016, respectively. This is primarily a result of a decrease in the discount rate from 4.5 percent at December 31, 2015, to 3.4 percent for the U.S. qualified pension plan and to 2.8 percent for a U.S. nonqualified supplemental retirement plan at September 30, 2016, resulting in a corresponding decrease to other comprehensive income (loss).

As part of the ongoing restructuring program in the United States, we concluded that actions taken during the three-month period ended September 30, 2016, would result in a significant reduction of future services of active employees in the U.S. qualified pension plan, a U.S. nonqualified supplemental retirement plan and the U.S. other postretirement benefit plan. As a result, we recognized an increase in the benefit obligation and a proportionate share of prior service cost from other comprehensive income (loss) as a curtailment loss of $14 million on the U.S. pension benefit plans and $1 million on the U.S. other postretirement benefit plan during the three-month period ended September 30, 2016.

22

Due to the ongoing restructuring program in the United States, we recognized additional expense of $14 million during the three-month period ended September 30, 2016, associated with employee special termination benefits for certain participants in the U.S. qualified pension plan and a U.S. nonqualified supplemental retirement plan.

Severance Accrual

As a result of the current business environment’s impact on our operating and capital plans, a reduction in our overall employee workforce occurred primarily during the third quarter of 2016. Severance accruals of $119 million and $126 million were recorded during the three- and nine-month periods ended September 30, 2016, respectively. The following table summarizes our severance accrual activity for the nine-month period ended September 30, 2016:

	Millions of Dollars
Balance at December 31, 2015	$	156
Accruals		126
Benefit payments		(130	)
Foreign currency translation adjustments		4
Balance at September 30, 2016	$	156

Of the remaining balance at September 30, 2016, $123 million is classified as short-term.

Note 18—Related Party Transactions

Our related parties primarily include equity method investments and certain trusts for the benefit of employees.

Significant transactions with our equity affiliates were:

	Millions of Dollars
	Three Months Ended September 30						Nine Months Ended September 30
	2016			2015			2016			2015
Operating revenues and other income	$	41			28			96			80
Purchases		26			25			75			72
Operating expenses and selling, general and administrative expenses		20			18			48			53
Net interest (income) expense*		(3	)		(3	)		(9	)		(7	)

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

23

Note 19—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 and North Africa, Asia Pacific and Middle East, and Other International.

Effective November 1, 2015, the Other International and historically presented Europe segments were restructured to align with changes to our internal organization structure. The Libya business was moved from the Other International segment to the historically presented Europe segment, which is now renamed Europe and North Africa. Accordingly, results of operations for the Other International and Europe and North Africa segments have been revised for all prior periods presented. There was no impact on our consolidated financial statements, and the impact on our segment presentation is immaterial.

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 (loss) attributable to ConocoPhillips. Intersegment sales are at prices that approximate market.

Analysis of Results by Operating Segment

	Millions of Dollars
	Three Months Ended September 30						Nine Months Ended September 30
	2016			2015			2016			2015
Sales and Other Operating Revenues
Alaska	$	925			1,067			2,639			3,455
Lower 48		2,993			3,106			7,533			9,421
Intersegment eliminations		(3	)		(15	)		(15	)		(50	)
Lower 48		2,990			3,091			7,518			9,371
Canada		615			576			1,431			1,932
Intersegment eliminations		(73	)		(76	)		(138	)		(265	)
Canada		542			500			1,293			1,667
Europe and North Africa		946			1,480			2,605			4,804
Intersegment eliminations		—			(2	)		—			(3	)
Europe and North Africa		946			1,478			2,605			4,801
Asia Pacific and Middle East		942			1,074			2,676			3,748
Corporate and Other		70			52			153			229
Consolidated sales and other operating revenues	$	6,415			7,262			16,884			23,271
Net Income (Loss) Attributable to ConocoPhillips
Alaska	$	59			53			204			393
Lower 48		(491	)		(852	)		(2,082	)		(1,550	)
Canada		(314	)		(145	)		(783	)		(469	)
Europe and North Africa		163			(5	)		132			667
Asia Pacific and Middle East		(87	)		258			(20	)		981
Other International		(47	)		(42	)		(100	)		(281	)
Corporate and Other		(323	)		(338	)		(931	)		(719	)
Consolidated net loss attributable to ConocoPhillips	$	(1,040	)		(1,071	)		(3,580	)		(978	)

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	Millions of Dollars
	September 30 2016		December 31 2015
Total Assets
Alaska	$	12,548		12,555
Lower 48		23,331		26,932
Canada		17,976		17,221
Europe and North Africa		13,241		13,703
Asia Pacific and Middle East		21,138		22,318
Other International		356		282
Corporate and Other		5,694		4,473
Consolidated total assets	$	94,284		97,484

Note 20—Income Taxes

Our effective tax rates for the third quarter and first nine months of 2016 were positive 38 percent and 36 percent, respectively, compared with 39 percent and 57 percent for the same periods of 2015. The decrease in the effective tax rate for the third quarter of 2016 was primarily due to the effect of the 2016 U.K. tax law change, discussed below, and a shift in the mix of income between high and low tax jurisdictions. The decrease in the effective tax rate for the first nine months of 2016 was primarily due to the absence of the effect of the 2015 U.K. tax law change, discussed below, and the mix of income between high and low tax jurisdictions, partially offset by the recognition of state deferred tax assets, the enactment of the 2016 U.K. tax law change and the absence of the 2015 Canadian tax law change, discussed below.

In the United Kingdom, legislation was enacted on September 15, 2016, to decrease the overall U.K. upstream corporation tax rate from 50 percent to 40 percent effective January 1, 2016. As a result, a $138 million net tax benefit resulting from re-measurement of deferred tax liabilities at January 1, 2016 and application of the new rate through September 30, 2016, is reflected in the “Income tax benefit” line on our consolidated income statement.

During the second quarter of 2016, previously unrecognized state deferred tax assets were recognized. As a result, a $68 million tax benefit is reflected in the “Income tax benefit” line on our consolidated income statement.

In the United Kingdom, legislation was enacted on March 26, 2015, to decrease the overall U.K. upstream corporation tax rate from 62 percent to 50 percent effective January 1, 2015. As a result, a $555 million net tax benefit for revaluing the U.K. deferred tax liability is reflected in the “Income tax benefit” line on our consolidated income statement.

In Canada, legislation was enacted on June 29, 2015, to increase the overall Canadian corporation tax rate from 25 percent to 27 percent effective July 1, 2015. As a result, a $129 million net tax expense for revaluing the Canadian deferred tax liability is reflected in the “Income tax benefit” line on our consolidated income statement.

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Note 21—New Accounting Standards

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers” (ASU No. 2014-09), 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 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.

In August 2015, the FASB issued ASU No. 2015-14, “Deferral of the Effective Date,” which defers the effective date of ASU No. 2014-09. The ASU is now effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted for interim and annual periods beginning after December 15, 2016. Entities may choose to adopt the standard using either a full retrospective approach or a modified retrospective approach.

ASU No. 2014-09 was amended in March 2016 by the provisions of ASU No. 2016-08, “Principal versus Agent Considerations (Reporting Revenue Gross versus Net),” in April 2016 by the provisions of ASU No. 2016-10, “Identifying Performance Obligations and Licensing,” and in May 2016 by the provisions of ASU No. 2016-12, “Narrow-Scope Improvements and Practical Expedients.” We are currently evaluating the impact of the adoption of ASU No. 2014-09, as amended, and continue to monitor proposals issued by the FASB to clarify the ASU.

In February 2016, the FASB issued ASU No. 2016-02, “Leases” (ASU No. 2016-02), which establishes comprehensive accounting and financial reporting requirements for leasing arrangements. This ASU supersedes the existing requirements in FASB ASC Topic 840, “Leases,” and requires lessees to recognize substantially all lease assets and lease liabilities on the balance sheet. The provisions of ASU No. 2016-02 also modify the definition of a lease and outline requirements for recognition, measurement, presentation, and disclosure of leasing arrangements by both lessees and lessors. The ASU is effective for interim and annual periods beginning after December 15, 2018, and early adoption of the standard is permitted. Entities are required to adopt the ASU using a modified retrospective approach, subject to certain optional practical expedients, and apply the provisions of ASU No. 2016-02 to leasing arrangements existing at or entered into after the earliest comparative period presented in the financial statements. We are currently evaluating the impact of the adoption of this ASU.

In June 2016, the FASB issued ASU No. 2016-13, “Measurement of Credit Losses on Financial Instruments” (ASU No. 2016-13), which sets forth the current expected credit loss model, a new forward-looking impairment model for certain financial instruments based on expected losses rather than incurred losses. The ASU is effective for interim and annual periods beginning after December 15, 2019, and early adoption of the standard is permitted. Entities are required to adopt ASU No. 2016-13 using a modified retrospective approach, subject to certain limited exceptions. 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.

In February 2016, ConocoPhillips received a $2.3 billion return of capital from ConocoPhillips Company to settle certain accumulated intercompany balances. The transaction had no impact on our consolidated financial statements.

In October 2016, ConocoPhillips Canada Funding Company I repaid $1.25 billion of external debt. This transaction will be reflected in the full-year 2016 condensed consolidating financial statements.

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

27

	Millions of Dollars
	Three Months Ended September 30, 2016
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	$	—			2,933			—			3,482			—			6,415
Equity in losses of affiliates		(958	)		(397	)		—			(26	)		1,321			(60	)
Gain on dispositions		—			11			—			40			—			51
Other income		1			3			—			106			—			110
Intercompany revenues		18			71			60			793			(942	)		—
Total Revenues and Other Income		(939	)		2,621			60			4,395			379			6,516
Costs and Expenses
Purchased commodities		—			2,563			—			1,024			(768	)		2,819
Production and operating expenses		—			324			—			1,207			(5	)		1,526
Selling, general and administrative expenses		2			158			—			43			—			203
Exploration expenses		—			192			—			265			—			457
Depreciation, depletion and amortization		—			351			—			2,074			—			2,425
Impairments		—			—			—			123			—			123
Taxes other than income taxes		—			26			—			135			—			161
Accretion on discounted liabilities		—			11			—			97			—			108
Interest and debt expense		135			159			56			154			(169	)		335
Foreign currency transaction (gains) losses		8			—			(26	)		31			—			13
Total Costs and Expenses		145			3,784			30			5,153			(942	)		8,170
Income (loss) before income taxes		(1,084	)		(1,163	)		30			(758	)		1,321			(1,654	)
Income tax benefit		(44	)		(205	)		(4	)		(375	)		—			(628	)
Net income (loss)		(1,040	)		(958	)		34			(383	)		1,321			(1,026	)
Less: net income attributable to noncontrolling interests		—			—			—			(14	)		—			(14	)
Net Income (Loss) Attributable to ConocoPhillips	$	(1,040	)		(958	)		34			(397	)		1,321			(1,040	)
Comprehensive Loss Attributable to ConocoPhillips	$	(1,113	)		(1,031	)		(10	)		(460	)		1,501			(1,113	)
Income Statement	Three Months Ended September 30, 2015
Revenues and Other Income
Sales and other operating revenues	$	—			2,954			—			4,308			—			7,262
Equity in earnings (losses) of affiliates		(973	)		(19	)		—			559			656			223
Gain on dispositions		—			5			—			13			—			18
Other income (loss)		(1	)		(8	)		—			13			—			4
Intercompany revenues		19			81			60			862			(1,022	)		—
Total Revenues and Other Income		(955	)		3,013			60			5,755			(366	)		7,507
Costs and Expenses
Purchased commodities		—			2,623			—			1,501			(855	)		3,269
Production and operating expenses		—			390			—			1,447			(3	)		1,834
Selling, general and administrative expenses		1			239			—			53			—			293
Exploration expenses		—			761			—			300			—			1,061
Depreciation, depletion and amortization		—			322			—			1,949			—			2,271
Impairments		—			1			—			23			—			24
Taxes other than income taxes		—			38			—			168			—			206
Accretion on discounted liabilities		—			14			—			108			—			122
Interest and debt expense		121			113			57			113			(164	)		240
Foreign currency transaction (gains) losses		47			—			(359	)		240			—			(72	)
Total Costs and Expenses		169			4,501			(302	)		5,902			(1,022	)		9,248
Income (loss) before income taxes		(1,124	)		(1,488	)		362			(147	)		656			(1,741	)
Income tax provision (benefit)		(53	)		(515	)		27			(144	)		—			(685	)
Net income (loss)		(1,071	)		(973	)		335			(3	)		656			(1,056	)
Less: net income attributable to noncontrolling interests		—			—			—			(15	)		—			(15	)
Net Income (Loss) Attributable to ConocoPhillips	$	(1,071	)		(973	)		335			(18	)		656			(1,071	)
Comprehensive Income (Loss) Attributable to ConocoPhillips	$	(3,555	)		(3,457	)		70			(2,507	)		5,894			(3,555	)

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	Millions of Dollars
	Nine Months Ended September 30, 2016
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	$	—			7,289			—			9,595			—			16,884
Equity in losses of affiliates		(3,388	)		(1,168	)		—			(325	)		4,752			(129	)
Gain on dispositions		—			96			—			106			—			202
Other income (loss)		1			(2	)		—			150			—			149
Intercompany revenues		62			220			176			2,246			(2,704	)		—
Total Revenues and Other Income		(3,325	)		6,435			176			11,772			2,048			17,106
Costs and Expenses
Purchased commodities		—			6,409			—			2,585			(1,948	)		7,046
Production and operating expenses		—			1,065			—			3,502			(242	)		4,325
Selling, general and administrative expenses		7			448			—			107			(6	)		556
Exploration expenses		—			1,174			—			398			—			1,572
Depreciation, depletion and amortization		—			914			—			6,087			—			7,001
Impairments		—			41			—			280			—			321
Taxes other than income taxes		—			122			—			416			—			538
Accretion on discounted liabilities		—			35			—			294			—			329
Interest and debt expense		385			457			168			426			(508	)		928
Foreign currency transaction (gains) losses		(34	)		2			207			(163	)		—			12
Total Costs and Expenses		358			10,667			375			13,932			(2,704	)		22,628
Loss before income taxes		(3,683	)		(4,232	)		(199	)		(2,160	)		4,752			(5,522	)
Income tax benefit		(103	)		(844	)		(3	)		(1,032	)		—			(1,982	)
Net loss		(3,580	)		(3,388	)		(196	)		(1,128	)		4,752			(3,540	)
Less: net income attributable to noncontrolling interests		—			—			—			(40	)		—			(40	)
Net Loss Attributable to ConocoPhillips	$	(3,580	)		(3,388	)		(196	)		(1,168	)		4,752			(3,580	)
Comprehensive Loss Attributable to ConocoPhillips	$	(2,777	)		(2,585	)		(6	)		(230	)		2,821			(2,777	)
Income Statement	Nine Months Ended September 30, 2015
Revenues and Other Income
Sales and other operating revenues	$	—			8,989			—			14,282			—			23,271
Equity in earnings (losses) of affiliates		(712	)		1,009			—			1,275			(886	)		686
Gain on dispositions		—			38			—			84			—			122
Other income (loss)		(1	)		9			—			82			—			90
Intercompany revenues		56			261			187			2,657			(3,161	)		—
Total Revenues and Other Income		(657	)		10,306			187			18,380			(4,047	)		24,169
Costs and Expenses
Purchased commodities		—			7,751			—			4,605			(2,620	)		9,736
Production and operating expenses		—			1,185			—			4,286			(37	)		5,434
Selling, general and administrative expenses		7			521			—			151			(9	)		670
Exploration expenses		—			1,104			—			988			—			2,092
Depreciation, depletion and amortization		—			882			—			5,849			—			6,731
Impairments		—			1			—			117			—			118
Taxes other than income taxes		—			157			—			498			—			655
Accretion on discounted liabilities		—			43			—			322			—			365
Interest and debt expense		363			325			171			288			(495	)		652
Foreign currency transaction (gains) losses		94			—			(591	)		401			—			(96	)
Total Costs and Expenses		464			11,969			(420	)		17,505			(3,161	)		26,357
Income (loss) before income taxes		(1,121	)		(1,663	)		607			875			(886	)		(2,188	)
Income tax provision (benefit)		(143	)		(951	)		18			(178	)		—			(1,254	)
Net income (loss)		(978	)		(712	)		589			1,053			(886	)		(934	)
Less: net income attributable to noncontrolling interests		—			—			—			(44	)		—			(44	)
Net Income (Loss) Attributable to ConocoPhillips	$	(978	)		(712	)		589			1,009			(886	)		(978	)
Comprehensive Income (Loss) Attributable to ConocoPhillips	$	(5,201	)		(4,935	)		67			(3,393	)		8,261			(5,201	)

29

	Millions of Dollars
	September 30, 2016
Balance Sheet	ConocoPhillips			ConocoPhillips Company			ConocoPhillips Canada Funding Company I			All Other Subsidiaries		Consolidating Adjustments			Total Consolidated
Assets
Cash and cash equivalents	$	—			275			11			3,804		—			4,090
Short-term investments		—			—			—			234		—			234
Accounts and notes receivable		15			1,678			23			5,315		(3,711	)		3,320
Inventories		—			115			—			993		—			1,108
Prepaid expenses and other current assets		1			222			182			684		(200	)		889
Total Current Assets		16			2,290			216			11,030		(3,911	)		9,641
Investments, loans and long-term receivables*		38,921			64,440			3,489			31,283		(116,269	)		21,864
Net properties, plants and equipment		—			6,609			—			55,040		—			61,649
Other assets		8			2,182			235			1,328		(2,623	)		1,130
Total Assets	$	38,945			75,521			3,940			98,681		(122,803	)		94,284
Liabilities and Stockholders’ Equity
Accounts payable	$	—			4,013			8			3,441		(3,711	)		3,751
Short-term debt		(10	)		(2	)		1,256			92		—			1,336
Accrued income and other taxes		—			86			—			308		—			394
Employee benefit obligations		—			500			—			257		—			757
Other accruals		101			351			82			966		(201	)		1,299
Total Current Liabilities		91			4,948			1,346			5,064		(3,912	)		7,537
Long-term debt		9,123			13,635			1,711			2,884		—			27,353
Asset retirement obligations and accrued environmental costs		—			1,042			—			8,778		—			9,820
Deferred income taxes		—			—			—			11,086		(2,052	)		9,034
Employee benefit obligations		—			2,023			—			448		—			2,471
Other liabilities and deferred credits*		122			10,084			807			18,664		(28,064	)		1,613
Total Liabilities		9,336			31,732			3,864			46,924		(34,028	)		57,828
Retained earnings (losses)		25,373			13,979			(585	)		12,764		(19,635	)		31,896
Other common stockholders’ equity		4,236			29,810			661			38,707		(69,140	)		4,274
Noncontrolling interests		—			—			—			286		—			286
Total Liabilities and Stockholders’ Equity	$	38,945			75,521			3,940			98,681		(122,803	)		94,284
*Includes intercompany loans.
Balance Sheet	December 31, 2015
Assets
Cash and cash equivalents	$	—			4			15			2,349		—			2,368
Accounts and notes receivable		21			2,905			21			7,228		(5,661	)		4,514
Inventories		—			142			—			982		—			1,124
Prepaid expenses and other current assets		2			206			252			589		(266	)		783
Total Current Assets		23			3,257			288			11,148		(5,927	)		8,789
Investments, loans and long-term receivables*		43,532			64,015			3,264			27,839		(117,464	)		21,186
Net properties, plants and equipment		—			8,110			—			58,336		—			66,446
Other assets		7			950			233			1,158		(1,285	)		1,063
Total Assets	$	43,562			76,332			3,785			98,481		(124,676	)		97,484
Liabilities and Stockholders’ Equity
Accounts payable	$	—			5,684			13			4,897		(5,661	)		4,933
Short-term debt		(9	)		1			1,255			180		—			1,427
Accrued income and other taxes		—			62			—			437		—			499
Employee benefit obligations		—			629			—			258		—			887
Other accruals		170			465			52			1,087		(264	)		1,510
Total Current Liabilities		161			6,841			1,320			6,859		(5,925	)		9,256
Long-term debt		7,518			10,660			1,716			3,559		—			23,453
Asset retirement obligations and accrued environmental costs		—			1,107			—			8,473		—			9,580
Deferred income taxes		—			—			—			11,814		(815	)		10,999
Employee benefit obligations		—			1,760			—			526		—			2,286
Other liabilities and deferred credits*		2,681			7,291			667			15,181		(23,992	)		1,828
Total Liabilities		10,360			27,659			3,703			46,412		(30,732	)		57,402
Retained earnings (losses)		29,892			17,366			(389	)		15,177		(25,632	)		36,414
Other common stockholders’ equity		3,310			31,307			471			36,572		(68,312	)		3,348
Noncontrolling interests		—			—			—			320		—			320
Total Liabilities and Stockholders’ Equity	$	43,562			76,332			3,785			98,481		(124,676	)		97,484
*Includes intercompany loans.

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	Millions of Dollars
	Nine Months Ended September 30, 2016
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) Operating Activities	$	(315	)		(124	)		(4	)		4,307			(904	)		2,960
Cash Flows From Investing Activities
Capital expenditures and investments		—			(889	)		—			(3,382	)		401			(3,870	)
Working capital changes associated with investing activities		—			(135	)		—			(266	)		—			(401	)
Proceeds from asset dispositions		2,300			175			—			275			(2,331	)		419
Purchases of short-term investments		—			—			—			(229	)		—			(229	)
Long-term advances/loans—related parties		—			(803	)		—			—			803			—
Collection of advances/loans—related parties		—			60			—			1,072			(1,024	)		108
Intercompany cash management		(2,767	)		2,272			—			495			—			—
Other		—			3			—			58			—			61
Net Cash Provided by (Used in) Investing Activities		(467	)		683			—			(1,977	)		(2,151	)		(3,912	)
Cash Flows From Financing Activities
Issuance of debt		1,600			2,994			—			803			(803	)		4,594
Repayment of debt		—			(964	)		—			(899	)		1,024			(839	)
Issuance of company common stock		122			—			—			—			(174	)		(52	)
Dividends paid		(940	)		—			—			(1,078	)		1,078			(940	)
Other		—			(2,318	)		—			295			1,930			(93	)
Net Cash Provided by (Used in) Financing Activities		782			(288	)		—			(879	)		3,055			2,670
Effect of Exchange Rate Changes on Cash and Cash Equivalents		—			—			—			4			—			4
Net Change in Cash and Cash Equivalents		—			271			(4	)		1,455			—			1,722
Cash and cash equivalents at beginning of period		—			4			15			2,349			—			2,368
Cash and Cash Equivalents at End of Period	$	—			275			11			3,804			—			4,090
Statement of Cash Flows	Nine Months Ended September 30, 2015
Cash Flows From Operating Activities
Net Cash Provided by (Used in) Operating Activities	$	(263	)		(110	)		2			6,165			182			5,976
Cash Flows From Investing Activities
Capital expenditures and investments		—			(2,346	)		—			(6,640	)		1,073			(7,913	)
Working capital changes associated with investing activities		—			(15	)		—			(827	)		—			(842	)
Proceeds from asset dispositions		2,000			190			—			232			(2,099	)		323
Long-term advances/loans—related parties		—			(248	)		—			(1,973	)		2,221			—
Collection of advances/loans—related parties		—			—			—			205			(100	)		105
Intercompany cash management		764			(892	)		—			128			—			—
Other		—			297			—			1			—			298
Net Cash Provided by (Used in) Investing Activities		2,764			(3,014	)		—			(8,874	)		1,095			(8,029	)
Cash Flows From Financing Activities
Issuance of debt		—			4,471			—			248			(2,221	)		2,498
Repayment of debt		—			(100	)		—			(92	)		100			(92	)
Issuance of company common stock		237			—			—			—			(306	)		(69	)
Dividends paid		(2,741	)		—			—			(124	)		124			(2,741	)
Other		3			(1,994	)		—			915			1,026			(50	)
Net Cash Provided by (Used in) Financing Activities		(2,501	)		2,377			—			947			(1,277	)		(454	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents		—			—			—			(142	)		—			(142	)
Net Change in Cash and Cash Equivalents		—			(747	)		2			(1,904	)		—			(2,649	)
Cash and cash equivalents at beginning of period		—			770			7			4,285			—			5,062
Cash and Cash Equivalents at End of Period	$	—			23			9			2,381			—			2,413

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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 54.

The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to net income (loss) attributable to ConocoPhillips.

BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW

ConocoPhillips is the world’s largest independent exploration and production (E&P) company, based on proved reserves and production of liquids and natural gas. Headquartered in Houston, Texas, we had operations and activities in 20 countries, approximately 14,900 employees worldwide and total assets of $94 billion as of September 30, 2016.

Overview

We are an independent E&P company focused on exploring for, developing and producing crude oil and natural gas globally. We have a diverse, low cost of supply resource base and a unique set of producing assets that includes legacy assets in North America, Europe and Asia; North American tight oil assets; resource-rich oil sands assets in Canada; and liquefied natural gas (LNG) assets in Asia Pacific, the Middle East and Alaska. Our value proposition, which combines our unique portfolio attributes with prudent capital allocation principles, includes shareholder distributions; maintaining a strong investment grade balance sheet, which includes reducing debt levels; and exercising disciplined growth on an absolute or a per-share basis.

The energy landscape continues to be challenged. Global production oversupply has caused continued weakness in commodity prices in 2016, following a year of weak prices in 2015. Ongoing uncertainty around the timing of a price recovery, coupled with tightening credit capacity across the industry, caused us to take actions to preserve our balance sheet strength and mitigate the impacts of possible prolonged weak prices.

During the first quarter of 2016, we reduced our quarterly dividend by 66 percent, to $0.25 per share, issued $3.0 billion of debt and obtained a $1.6 billion three-year term loan to secure sufficient cash and liquidity through the downturn. We revised our 2016 operating plan, reducing our capital expenditures guidance from $6.4 billion in February to $5.5 billion in July, and further reduced our guidance to $5.2 billion in October 2016, primarily due to lower costs and deferrals across the portfolio, as well as reduced deepwater exploration activity. Realized commodity prices improved relative to the first quarter of 2016, and on October 17, 2016, $1.25 billion of Notes due were repaid at maturity.

We continue to stay focused on safely executing our capital program and remaining attentive to our costs. We produced 1,557 thousand barrels of oil equivalent per day (MBOED) in the third quarter of 2016, an increase of 3 MBOED compared with the same period of 2015. Production increased as growth from major projects and development programs, as well as improved well performance and lower planned downtime exceeded

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impacts from normal field decline and dispositions. When adjusted for 53 MBOED from dispositions and downtime, production increased 56 MBOED, or 4 percent, compared with the third quarter of 2015. We also saw continued strong operational performance across our portfolio, including the achievement of first production at APLNG Train 2 in Australia, as well as completion of project finance tests for Train 1 in October 2016. We continue to pursue sustainable operating cost reductions within our business. Operating costs include production and operating expense; selling, general and administrative expense; and exploration general and administrative, geological and geophysical, lease rental and other expense.

Our 2016 capital program is focused on maintaining our asset integrity, completing several projects that are underway and pursuing development programs, primarily around legacy conventional assets. We have significantly reduced activity levels in the North American tight oil plays, including the Eagle Ford, Bakken, Permian, Niobrara and Montney. However, we retain the flexibility to adjust investment levels in these and other assets, as appropriate.

In the nine-month period of 2016, we generated approximately $419 million in proceeds from non-core asset dispositions. We continue to monitor the market and evaluate opportunities to high-grade our portfolio. We have stated an intention to exit deepwater exploration, and that process is underway. We are also willing to pursue other non-core asset dispositions where we can achieve an acceptable value in the market.

We believe we are taking prudent actions across the business to withstand price uncertainty and ongoing volatility. We have exercised significant capital flexibility, lowered our operating cost structure, reduced our dividend, and continued to optimize our asset base. We believe these actions, in combination with our strong execution of the business, will allow us to manage through this current period of low commodity prices and to deliver stronger performance when prices recover.

Basis of Presentation

Effective November 1, 2015, the Other International and historically presented Europe segments were restructured to align with changes to our internal organization structure. The Libya business was moved from the Other International segment to the historically presented Europe segment, which is now renamed Europe and North Africa. Accordingly, results of operations for the Other International and Europe and North Africa segments have been revised for all prior periods presented. There was no impact on our consolidated financial statements, and the impact on our segment presentation is immaterial. For additional information, see Note 19—Segment Disclosures and Related Information, in the Notes to Consolidated Financial Statements.

Business Environment

In the first half of 2014, strong crude oil prices were supported by geopolitical tensions impacting supplies, as well as global oil demand growth. This was followed by an abrupt decline in prices beginning in the third quarter of 2014, as surging production growth from U.S. tight oil and the decision by the Organization of Petroleum Exporting Countries (OPEC) to target market share outweighed fears of supply disruptions. These developments, combined with lower forecasts for global oil demand growth, caused crude oil prices to plummet to near five-year lows at the end of 2014. As global inventories grew due to the ensuing supply surplus, prices continued even lower, and reached a ten-year quarterly low average of $33.89 per barrel for Brent crude oil in the first quarter of 2016. Prices began rising in the second quarter of 2016 due to supply disruptions, lower non-OPEC production and robust growth in demand, but remain lower than the corresponding period of 2015.

The energy industry has periodically experienced this type of extreme volatility due to fluctuating supply and demand conditions. Commodity prices are the most significant factor impacting our profitability and the related reinvestment of operating cash flows into our business. Among other dynamics that could influence world energy markets and commodity prices are global economic health, supply disruptions or fears thereof caused by civil unrest or military conflicts, actions taken by OPEC or other producers, environmental laws, tax regulations, governmental policies and weather-related changes in demand. North America’s energy landscape has been transformed from resource scarcity to an abundance of supply, primarily due to advances in

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technology responsible for the rapid growth of tight oil production, successful exploration, and rising production from the Canadian oil sands. Our strategy is to sustainably lower our cost structure and maintain a strong balance sheet while utilizing a diverse and low-cost portfolio that will provide the financial flexibility to withstand challenging business cycles.

Our earnings and operating cash flows generally correlate with industry price levels for crude oil and natural gas, 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 $45.85 per barrel in the third quarter of 2016, a decrease of 9 percent compared with $50.26 per barrel in the third quarter of 2015, and an increase of 1 percent compared with $45.57 in the second quarter of 2016. Industry crude prices for WTI averaged $44.88 per barrel in the third quarter of 2016, a decrease of 3 percent compared with $46.37 per barrel in the third quarter of 2015, and a decrease of 1 percent compared with $45.48 in the second quarter of 2016. Global oil prices remained below prior year levels but firmed in the third quarter of 2016 as market supply and demand fundamentals continued to trend towards rebalancing, and in response to talks among OPEC members and Russia of a production freeze or cut later this year.

Henry Hub natural gas prices averaged $2.81 per million British thermal units (MMBTU) in the third quarter of 2016, an increase of 1 percent compared with $2.77 per MMBTU in the third quarter of 2015, and an increase of 44 percent compared with $1.95 per MMBTU in the second quarter of 2016. Prices improved relative to the second quarter of 2016 as a result of growth in demand for natural gas coupled with reduced production.

Our realized bitumen price was $17.82 per barrel in the third quarter of 2016, an increase of 4 percent compared with $17.12 per barrel for the same period of 2015, primarily due to lower diluent costs. Compared with $18.11 per barrel in the second quarter of 2016, our third-quarter 2016 realized bitumen price decreased 2 percent primarily due to lower WTI prices and a higher Western Canada Select benchmark price differential to WTI.

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Our total average realized price was $29.78 per barrel of oil equivalent (BOE) in the third quarter of 2016, a decrease of 9 percent compared with $32.87 per BOE in the third quarter of 2015, reflecting lower average realized prices for crude oil and natural gas, partly offset by increased bitumen and natural gas liquids prices. In the first nine months of 2016, our total realized price was $26.84 per BOE, a decrease of 26 percent compared with $36.27 per BOE in the first nine months of 2015. This reflected lower average realized prices for all commodities.

Key Operating and Financial Summary

Significant items during the third quarter of 2016 included the following:

• Achieved third-quarter production of 1,557 MBOED; increasing the midpoint of full-year production guidance to 1,565 MBOED.

• Continued efficiencies further reducing 2016 capital expenditures guidance from $5.5 billion to $5.2 billion; shifting capital from major projects to Lower 48 tight oil plays.

• Safely executed third-quarter major turnaround activity in Europe and Alaska.

• First production achieved at APLNG Train 2 in Australia.

• Signed sale and purchase agreement for Block B in Indonesia.

• Completed transaction for the sale of exploration blocks offshore Senegal in October.

• Repaid $1.25 billion of maturing debt in October.

Outlook

Capital and Production Guidance

Guidance for capital expenditures has been lowered to $5.2 billion versus prior guidance of $5.5 billion.

We increased the midpoint of full-year 2016 production guidance to 1,565 MBOED, reflecting a range of 1,560 to 1,570 MBOED on strong year-to-date performance across Lower 48, Europe and Asia Pacific. Fourth-quarter 2016 production guidance is 1,555 to 1,595 MBOED. Production guidance excludes Libya.

Marketing Activities

In line with our objective to continuously optimize our portfolio, we are currently marketing certain non-core assets. We expect to generate approximately $1 billion in proceeds in 2016 from asset sales.

Reserve Replacement

Proved reserve estimates require economic production based on historical 12-month, first-of-month, average prices and current costs. Therefore, as prices and cost levels change, the estimate of proved reserves also changes. Generally, our proved reserves decrease as prices decline and increase as prices rise. Based on 2016 commodity prices, significant reductions to our proved reserves can be expected at year-end 2016, primarily related to proved undeveloped reserves associated with the oil sands assets in our Canada segment. However, we do not expect negative price-related reserve revisions to materially impact current plans for development of these assets. Reserve estimates are subject to change based on commodity prices for the remainder of 2016, as well as development and production costs, capital spending levels, timing of project approvals and other factors.

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RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three- and nine-month periods ended September 30, 2016, is based on a comparison with the corresponding periods of 2015.

Consolidated Results

A summary of the company’s net income (loss) attributable to ConocoPhillips by business segment follows:

	Millions of Dollars
	Three Months Ended September 30						Nine Months Ended September 30
	2016			2015			2016			2015
Alaska	$	59			53			204			393
Lower 48		(491	)		(852	)		(2,082	)		(1,550	)
Canada		(314	)		(145	)		(783	)		(469	)
Europe and North Africa		163			(5	)		132			667
Asia Pacific and Middle East		(87	)		258			(20	)		981
Other International		(47	)		(42	)		(100	)		(281	)
Corporate and Other		(323	)		(338	)		(931	)		(719	)
Net loss attributable to ConocoPhillips	$	(1,040	)		(1,071	)		(3,580	)		(978	)

Net loss attributable to ConocoPhillips was $1,040 million in the third quarter of 2016, compared with $1,071 million in the third quarter of 2015. The reduction in loss was mainly due to:

• Lower exploration expenses, mainly due to the absence of 2015 after-tax charges of $246 million related to the termination of our Gulf of Mexico deepwater drillship contract with Ensco and $154 million for the write-down of Gulf of Mexico leases for which we had no plans to conduct further activity.

• Lower production and operating expenses.

• A $138 million net deferred tax benefit resulting from a change in the U.K. tax rate.

• Lower restructuring charges.

These reductions in loss were partly offset by:

• Lower average realized commodity price.

• Lower equity earnings, primarily driven by a 2016 deferred tax charge of $174 million resulting from the change of the tax functional currency for Australia Pacific LNG Pty Ltd (APLNG) to U.S. dollar, as well as increased depreciation, depletion and amortization (DD&A) expense.

• A $119 million after-tax dry hole cost charged to the Cheshire well in Nova Scotia in 2016.

• Foreign currency impacts, primarily in our Asia Pacific and Middle East segment.

• Rig cancellation and related third party costs of $87 million after-tax for our final Gulf of Mexico deepwater drillship contract.

Net loss attributable to ConocoPhillips was $3,580 million in the nine-month period of 2016, compared with $978 million in the corresponding period of 2015. The increase in loss was primarily due to lower commodity prices.

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In addition to the items discussed for the third quarter of 2016, the nine-month increase in loss was further impacted by:

• The absence of a $555 million net deferred tax benefit resulting from a change in the U.K. tax rate in the first quarter of 2015.

• Higher interest and debt expense.

• Higher DD&A expense primarily due to price-related reserve revisions.

In addition to the items discussed for the third quarter of 2016, the nine-month increase in loss was partly offset by reduced feedstock cost at Darwin LNG and the absence of a $129 million deferred tax charge from increased corporate tax rates in Canada in the second quarter of 2015.

See the “Segment Results” section for additional information.

Income Statement Analysis

Sales and other operating revenues decreased 12 percent in the third quarter and 27 percent in the nine-month period of 2016, mainly as a result of lower crude oil and natural gas prices in the third quarter, and lower prices across all commodities in the nine-month period. Additionally, sales and other operating revenues decreased due to lower natural gas sales volumes, partly offset by increased bitumen sales volumes in both periods of 2016.

Equity in earnings (losses) of affiliates decreased 127 percent in the third quarter and 119 percent in the nine-month period of 2016. The decrease in the third quarter was primarily as a result of a 2016 deferred tax charge of $174 million resulting from a tax functional currency change, as well as increased DD&A mainly driven by higher volumes, both at APLNG. Additionally, earnings were lower from APLNG, Qatar Liquefied Gas Company Limited (3) (QG3) and the FCCL Partnership in the nine-month period of 2016, due to reduced commodity prices. The decrease in earnings was partly offset by higher sales volumes at APLNG and FCCL in both periods, as well as lower production taxes at QG3.

Other income was $110 million in the third quarter of 2016, compared with $4 million in the same period of 2015, primarily as a result of a $76 million before-tax damage claim settlement in our Lower 48 segment, as well as higher interest income.

Purchased commodities decreased 14 percent in the third quarter and 28 percent in the nine-month period of 2016, largely as a result of lower natural gas prices.

Production and operating expenses decreased 17 percent in the third quarter and 20 percent in the nine-month period of 2016, primarily as a result of lower operating expense activity levels, reduced headcount, dispositions of non-core assets and favorable foreign currency impacts.

Selling, general and administrative (SG&A) expenses decreased 17 percent in the nine-month period of 2016, primarily due to lower restructuring costs, partially offset by higher compensation and benefits expenses.

Exploration expenses decreased 57 percent in the third quarter and 25 percent in the nine-month period of 2016. Exploration expenses decreased primarily as a result of the absence of third-quarter 2015 before-tax charges of $383 million, mainly recorded to other exploration expense, for the Gulf of Mexico deepwater drillship and related contract termination costs, and $240 million for the write-down of Gulf of Mexico leases for which we had no plans to conduct further activity. The absence of a $105 million before-tax charge in the third quarter of 2015 to relinquish our Palangkaraya Production Sharing Contract in Indonesia, as well as lower general administrative and geological and geophysical expense further contributed to the decrease. The decrease in exploration expenses was partly offset by before-tax charges of $164 million and $134 million in the third quarter of 2016 for a dry hole in Nova Scotia and rig cancellation-related costs for our final Gulf of Mexico deepwater drillship contract, respectively.

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Impairments increased 172 percent in the nine-month period of 2016. For additional information, see Note 8—Impairments, in the Notes to Consolidated Financial Statements.

Taxes other than income taxes decreased 18 percent in the nine-month period of 2016, primarily as a result of lower property taxes in our Lower 48 and Alaska segments. Taxes other than income taxes were further reduced due to lower production taxes, mainly in our Lower 48 segment, given reduced commodity prices.

Interest and debt expense increased 40 percent in the third quarter and 42 percent in the nine-month period of 2016, primarily due to lower capitalized interest and increased debt.

Foreign currency transaction (gains) losses decreased 113 percent in the nine-month period of 2016, primarily due to the impact of the Malaysian ringgit strengthening in 2016 on the remeasurement of certain accounts.

See Note 20—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding ourincome tax benefit and effective tax rate.

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Summary Operating Statistics

	Three Months Ended September 30				Nine Months Ended September 30
	2016		2015		2016		2015
Average Net Production
Crude oil (MBD)*		586		577		598		602
Natural gas liquids (MBD)		148		156		146		157
Bitumen (MBD)		193		157		173		150
Natural gas (MMCFD)**		3,777		3,984		3,855		4,059
Total Production (MBOED)		1,557		1,554		1,560		1,586
	Dollars Per Unit
Average Sales Prices
Crude oil (per barrel)	$	43.21		46.41		38.97		50.83
Natural gas liquids (per barrel)		16.18		15.54		15.04		18.24
Bitumen (per barrel)***		17.82		17.12		12.65		21.74
Natural gas (per thousand cubic feet)		3.05		3.87		2.85		4.16
	Millions of Dollars
Exploration Expenses
General administrative, geological and geophysical, lease rental, and other	$	270		536		562		854
Leasehold impairment		24		377		418		662
Dry holes		163		148		592		576
	$	457		1,061		1,572		2,092

    *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.

***2015 has been restated to conform to current period presentation.

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. At September 30, 2016, our operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, Timor-Leste, Indonesia, China, Malaysia, Qatar and Libya.

Total production from operations remained essentially flat in the third quarter and decreased 2 percent in the nine-month period of 2016. The decrease in total average production in the nine-month period of 2016 primarily resulted from normal field decline and the loss of 71 MBOED mainly attributable to the dispositions of several non-core assets in the Lower 48, western Canada and the sale of our interest in the Polar Lights Company. The decrease in production was partly offset by additional production from major developments, including tight oil plays in the Lower 48; APLNG in Australia; the Western North Slope in Alaska; the Greater Ekofisk Area in Norway; and the Greater Britannia projects in the U.K. Improved drilling and well performance in Canada, the Lower 48, Norway, and China, as well as improved recoveries from production sharing contracts in Asia Pacific and Middle East also partly offset the decrease in production. In the third quarter of 2016, we achieved production of 1,557 MBOED. Adjusted for downtime and dispositions of 53 MBOED, our production increased 56 MBOED, or 4 percent, compared with the third quarter of 2015.

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Segment Results

Alaska

	Three Months Ended September 30				Nine Months Ended September 30
	2016		2015		2016		2015
Net Income Attributable to ConocoPhillips(millions of dollars)	$	59		53		204		393
Average Net Production
Crude oil (MBD)		148		144		160		154
Natural gas liquids (MBD)		11		10		12		12
Natural gas (MMCFD)		18		34		28		42
Total Production(MBOED)		162		160		177		173
Average Sales Prices
Crude oil (dollars per barrel)	$	43.43		50.48		39.69		54.18
Natural gas (dollars per thousand cubic feet)		6.95		4.26		5.20		4.35

The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids, natural gas and LNG. As of September 30, 2016, Alaska contributed 19 percent of our worldwide liquids production and 1 percent of our worldwide natural gas production.

Earnings from Alaska increased 11 percent in the third quarter and decreased 48 percent in the nine-month period of 2016. The increase in earnings in the third quarter was primarily due to reduced production and operating expenses from lower maintenance costs and general and administrative expenses, as well as higher crude oil sales volumes. The earnings increase was partly offset by lower crude oil prices.

The earnings decrease in the nine-month period of 2016 was mainly due to lower crude oil prices and higher DD&A expense as a result of capital additions, price-related reserve revisions and increased production volumes. The decrease was partly offset by reduced production and operating expenses; enhanced oil recovery tax credits; a $57 million after-tax impact for the recognition of state deferred tax assets and a $36 million after-tax gain on the sale of our interest in the Alaska Beluga River Unit natural gas field, both in the second quarter of 2016.

Average production increased 1 percent in the third quarter and 2 percent in the nine-month period of 2016, compared with the corresponding periods of 2015, primarily due to new production from the Alpine CD5 drill site and strong well performance in the Greater Prudhoe Area. The production increase in both periods of 2016 was partly offset by normal field decline and unplanned downtime in the third quarter of 2016.

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Lower 48

	Three Months Ended September 30						Nine Months Ended September 30
	2016			2015			2016			2015
Net Loss Attributable to ConocoPhillips(millions of dollars)	$	(491	)		(852	)		(2,082	)		(1,550	)
Average Net Production
Crude oil (MBD)		195			213			201			207
Natural gas liquids (MBD)		92			95			89			95
Natural gas (MMCFD)		1,224			1,457			1,228			1,487
Total Production(MBOED)		491			551			495			550
Average Sales Prices
Crude oil (dollars per barrel)	$	40.09			41.56			35.54			44.84
Natural gas liquids (dollars per barrel)		14.57			12.55			12.93			14.45
Natural gas (dollars per thousand cubic feet)		2.59			2.65			2.03			2.54

The Lower 48 segment consists of operations located in the U.S. Lower 48 states, as well as producing properties and exploration activities in the Gulf of Mexico. As of September 30, 2016, the Lower 48 contributed 32 percent of our worldwide liquids production and 32 percent of our worldwide natural gas production.

Earnings from Lower 48 increased 42 percent in the third quarter of 2016 primarily due to:

• Lower exploration expenses, including the absence of after-tax charges of $246 million related to the termination of our Gulf of Mexico deepwater drillship contract with Ensco and $154 million for the write-down of Gulf of Mexico leases for which we had no plans to conduct further activity, both in the third quarter of 2015, as well as lower dry hole costs.

• Lower production and operating expenses, mainly as a result of reduced activity and cost efficiencies.

• A $48 million after-tax damage claim settlement.

The increase was partly offset by lower crude oil and natural gas sales volumes, as well as rig cancellation and related third party costs of $87 million after-tax for our final Gulf of Mexico deepwater drillship contract.

In addition to the items discussed above for the third quarter of 2016, earnings from Lower 48 decreased 34 percent in the nine-month period primarily due to:

• Lower commodity prices.

• Higher dry hole costs including after-tax charges in deepwater Gulf of Mexico of $162 million in the second quarter for our Gibson and Tiber wells and $83 million, mainly in the first quarter, associated with our Melmar well.

• Unproved property impairment expenses in 2016, including after-tax charges in deepwater Gulf of Mexico of $132 million for our Gibson and Tiber leaseholds in the second quarter and $62 million for the Melmar prospect in the first quarter.

• Higher DD&A, primarily from price-related reserve revisions.

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In addition to the items discussed for the third quarter of 2016, the earnings decrease in the nine-month period was partly offset by the absence of a $61 million after-tax dry hole charge in the first quarter of 2015 for the Harrier well in the Gulf of Mexico, and a $38 million after-tax gain from the disposition of non-core assets and lease exchanges in the second quarter of 2016.

In the third quarter of 2016, our average realized crude oil price of $40.09 per barrel was 11 percent less than WTI of $44.88 per barrel. The differential is driven primarily by local market dynamics in the Gulf Coast and Bakken, and may remain relatively wide in the near term.

Total average production decreased 11 percent in the third quarter and 10 percent in the nine-month period of 2016, while average crude oil production decreased 8 percent and 3 percent over the corresponding periods of 2016. The decrease in total production in both periods was mainly attributable to normal field decline and the disposition of non-core properties in East Texas and North Louisiana, as well as South Texas. The reduction was partly offset by new production and well performance, primarily from Eagle Ford, Bakken and the Permian Basin.

Canada

	Three Months Ended September 30						Nine Months Ended September 30
	2016			2015			2016			2015
Net Loss Attributable to ConocoPhillips(millions of dollars)	$	(314	)		(145	)		(783	)		(469	)
Average Net Production
Crude oil (MBD)		7			12			8			13
Natural gas liquids (MBD)		23			27			23			26
Bitumen (MBD)
Consolidated operations		41			12			29			12
Equity affiliates		152			145			144			138
Total bitumen		193			157			173			150
Natural gas (MMCFD)		517			712			538			739
Total Production(MBOED)		309			315			294			312
Average Sales Prices
Crude oil (dollars per barrel)	$	37.50			38.44			33.47			40.71
Natural gas liquids (dollars per barrel)		14.99			14.50			13.41			17.30
Bitumen (dollars per barrel)
Consolidated operations*		15.73			16.54			11.36			23.74
Equity affiliates		18.39			17.16			12.91			21.57
Total bitumen*		17.82			17.12			12.65			21.74
Natural gas (dollars per thousand cubic feet)		1.71			1.94			1.28			2.01

*2015 has been restated to conform to current period presentation.

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, 2016, Canada contributed 22 percent of our worldwide liquids production and 14 percent of our worldwide natural gas production.

Earnings from Canada decreased 117 percent in the third quarter and 67 percent in the nine-month period of 2016. The earnings decrease in the third quarter of 2016 was primarily due to a $119 million after-tax dry hole charge for the Cheshire well in Nova Scotia; higher DD&A expense, mainly from price-related reserve

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revisions; and a $42 million after-tax impairment charge related to certain developed properties in central Alberta which were written down to fair value less costs to sell. The third quarter earnings decrease was partly offset by a $32 million after-tax gain on the sale of our 30 percent working interest in an exploration license in the Flemish Pass Basin, offshore Newfoundland, in the third quarter of 2016.

In addition to the items discussed above for the third quarter of 2016, earnings decreased in the nine-month period due to lower bitumen and natural gas prices. The nine-month earnings decrease was partly offset by the absence of the $136 million impact of a 2 percent increase in Alberta corporate tax rates on deferred taxes in the second quarter of 2015, as well as lower operating costs, mainly due to reduced general and administrative expense and the disposition of non-core assets in western Canada.

Total average production decreased 2 percent in the third quarter and 6 percent in the nine-month period of 2016, while bitumen production increased 23 percent and 15 percent over the corresponding periods of 2016. The decrease in total production was mainly attributable to the disposition of non-core assets in western Canada, normal field decline and unplanned downtime from the precautionary shut down of Surmont for nearby forest fires beginning in the second quarter of 2016. The production decrease was partly offset by strong well performance in western Canada, Surmont and FCCL. Surmont has fully recovered from the forest fire impacts.

Europe and North Africa

	Three Months Ended September 30					Nine Months Ended September 30
	2016		2015			2016		2015
Net Income (Loss) Attributable to ConocoPhillips(millions of dollars)	$	163		(5	)		132		667
Average Net Production
Crude oil (MBD)		121		116			117		119
Natural gas liquids (MBD)		6		7			6		7
Natural gas (MMCFD)		358		415			441		464
Total Production(MBOED)		187		192			196		203
Average Sales Prices
Crude oil (dollars per barrel)	$	46.59		49.86			42.39		55.65
Natural gas liquids (dollars per barrel)		21.38		24.74			20.86		28.20
Natural gas (dollars per thousand cubic feet)		4.13		7.11			4.53		7.58

The Europe and North Africa segment consists of operations principally located in the Norwegian and U.K. sectors of the North Sea, the Norwegian Sea, and Libya. As of September 30, 2016, our Europe and North Africa operations contributed 13 percent of our worldwide liquids production and 11 percent of our worldwide natural gas production.

Earnings for Europe and North Africa operations increased $168 million in the third quarter and decreased $535 million in the nine-month period of 2016, compared with the corresponding periods of 2015. The earnings increase in the third quarter was primarily due to a $138 million net deferred tax benefit as a result of a change in the U.K. tax rate enacted in September 2016, and lower DD&A expense in the United Kingdom driven by reduced rate, as a result of completed depreciation on the Brodgar H3 tie-back well in 2015, and lower volumes. The earnings increase was partly offset by lower natural gas and crude oil prices.

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In the nine-month period of 2016, earnings decreased mainly due to the absence of a $555 million net deferred tax benefit as a result of a change in the U.K. tax rate, effective at the beginning of 2015; lower crude oil and natural gas prices; and higher proved property impairments in the United Kingdom, mainly in the first quarter of 2016. The decrease in earnings was partly offset by lower DD&A expense in the United Kingdom and reduced operating expenses across the segment.

Average production decreased 3 percent in the third quarter and the nine-month period of 2016. The decrease in the third quarter of 2016 was mainly due to normal field decline, partly offset by improved drilling and well performance in Norway. In addition to the items discussed above for the third quarter of 2016, new production from the Greater Ekofisk Area and the Greater Britannia Area further offset the production decrease in the nine-month period of 2016. Libya production remained largely shut in, as the Es Sider crude oil export terminal closure continued throughout the third quarter of 2016. In October 2016, production resumed in Libya. We expect a gradual ramp-up in activity.

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Asia Pacific and Middle East

	Three Months Ended September 30					Nine Months Ended September 30
	2016			2015		2016			2015
Net Income (Loss) Attributable to ConocoPhillips(millions of dollars)	$	(87	)		258		(20	)		981
Average Net Production
Crude oil (MBD)
Consolidated operations		100			73		98			90
Equity affiliates		15			15		14			15
Total crude oil		115			88		112			105
Natural gas liquids (MBD)
Consolidated operations		8			9		8			9
Equity affiliates		8			8		8			8
Total natural gas liquids		16			17		16			17
Natural gas (MMCFD)
Consolidated operations		712			698		737			709
Equity affiliates		948			668		883			618
Total natural gas		1,660			1,366		1,620			1,327
Total Production(MBOED)		408			332		398			344
Average Sales Prices
Crude oil (dollars per barrel)
Consolidated operations	$	44.27			46.81		40.33			52.88
Equity affiliates		44.78			50.68		41.94			55.66
Total crude oil		44.34			47.38		40.53			53.26
Natural gas liquids (dollars per barrel)
Consolidated operations		25.84			32.26		27.66			38.12
Equity affiliates		25.12			31.26		27.25			36.05
Total natural gas liquids		25.50			31.79		27.46			37.20
Natural gas (dollars per thousand cubic feet)
Consolidated operations		4.42			5.97		4.20			6.56
Equity affiliates		2.90			4.37		2.90			5.31
Total natural gas		3.55			5.19		3.50			5.98

The Asia Pacific and Middle East segment has operations in China, Indonesia, Malaysia, Australia, Timor-Leste and Qatar, as well as exploration activities in Brunei. As of September 30, 2016, Asia Pacific and Middle East contributed 14 percent of our worldwide liquids production and 42 percent of our worldwide natural gas production.

Earnings decreased 134 percent in the third quarter and 102 percent in the nine-month period of 2016. The decrease in earnings in both periods was primarily due to lower prices for all commodities and adverse tax-related foreign exchange impacts. Lower equity earnings from APLNG, as a result of higher DD&A expense from APLNG Train 1 coming online, and a third-quarter 2016 deferred tax charge of $174 million resulting from the change of our APLNG tax functional currency, further reduced earnings in both periods. The earnings

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decrease was partly offset by higher sales volumes; lower production taxes; reduced feedstock costs at Darwin LNG; lower maintenance costs, general and administrative spend, and transportation expenses across the segment; and reduced dry hole costs.

Average production increased 23 percent in the third quarter and 16 percent in the nine-month period of 2016. The production increase in both periods of 2016 was mainly attributable to new production from the ramp-up of APLNG in Australia and the Kebabangan gas field in Malaysia, improved drilling and well performance in China, and increased recoveries from production sharing contracts in Indonesia. The production increases were partially offset by normal field decline across the segment.

Asset Disposition Update

In September 2016, we entered into a definitive agreement to sell our 40 percent interest in South Natuna Sea Block B. The transaction is expected to close in the fourth quarter of 2016. The net carrying value of our interest as of September 30, 2016, was approximately $239 million. See Note 5—Assets Held for Sale, Sold, or Other Planned Dispositions, in the Notes to Consolidated Financial Statements, for additional information regarding our asset dispositions.

Other International

	Three Months Ended September 30						Nine Months Ended September 30
	2016			2015			2016			2015
Net Loss Attributable to ConocoPhillips(millions of dollars)	$	(47	)		(42	)		(100	)		(281	)
Average Net Production
Crude oil (MBD)
Equity affiliates		—			4			—			4
Total Production(MBOED)		—			4			—			4
Average Sales Prices
Crude oil (dollars per barrel)
Equity affiliates	$	—			35.11			—			38.78

The Other International segment consists of exploration activities in Colombia, Chile, Senegal and Angola. As of September 30, 2016, Other International did not contribute to our worldwide liquids production due to the sale of our 50 percent interest in the Polar Lights Company in the fourth quarter of 2015.

Other International operations reported losses of $47 million in the third quarter and $100 million in the nine-month period of 2016, compared with losses of $42 million and $281 million in the same periods of 2015. The third quarter decrease in earnings was primarily due to lower volumes from the sale of our interest in the Polar Lights Company in December 2015 and the absence of 2015 tax deductions from ceasing certain operations in Africa, partly offset by lower exploration expenses.

The earnings increase in the nine-month period of 2016 was primarily due to lower exploration expenses driven by the absence of the $81 million after-tax dry hole expense for the Omosi-1 well in the first quarter of 2015, as well as the absence of the $75 million after-tax Angola Block 37 leasehold impairment, the $59 million after-tax dry hole expense for the Vali-1 well, and the $32 million after-tax Poland leasehold impairment, all in the second quarter of 2015. The nine-month earnings increase was partly offset by lower volumes from the sale of our interest in the Polar Lights Company in December 2015 and the absence of a $28 million tax deduction associated with ceasing operations in Peru in the second quarter of 2015.

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Exploration Update

In June 2016, we entered into an agreement with Empresa Nacional Del Petroleo (ENAP) to acquire an additional 44 percent participating interest in the onshore Coiron Block located in the Magallanes Basin in southern Chile where we already had 5 percent participation. Assignment of the additional participating interest to ConocoPhillips was approved by the Chilean Ministry of Energy and is subject to approval by the Controller General of Chile. ENAP holds the remaining 51 percent participating interest and will continue to be the operator.

On October 28, 2016, we sold our 35 percent interest in three exploration blocks offshore Senegal for approximately $440 million, including net customary adjustments of approximately $90 million. In addition, we provided an indemnification to the buyer for certain potential losses related to the disposition. The three blocks had a net book value of approximately $285 million as of September 30, 2016. See Note 5—Assets Held for Sale, Sold, or Other Planned Dispositions, in the Notes to Consolidated Financial Statements, for information regarding our asset dispositions.

Corporate and Other

	Millions of Dollars
	Three Months Ended September 30						Nine Months Ended September 30
	2016			2015			2016			2015
Net Income (Loss) Attributable to ConocoPhillips
Net interest	$	(258	)		(176	)		(714	)		(492	)
Corporate general and administrative expenses		(54	)		(71	)		(211	)		(163	)
Technology		44			3			66			75
Other		(55	)		(94	)		(72	)		(139	)
	$	(323	)		(338	)		(931	)		(719	)

Net interest consists of interest and financing expense, net of interest income and capitalized interest. Net interest increased 47 percent in the third quarter and 45 percent in the nine-month period of 2016, primarily due to lower capitalized interest on projects and increased debt, and impacts from the fair market value of apportioning interest expense in the United States.

Corporate general and administrative expenses decreased 24 percent in the third quarter but increased 29 percent in the nine-month period of 2016. The third quarter decrease was mainly due to a $40 million reduction in pension settlement cost compared with the third quarter of 2015, partly offset by increased compensation and benefit expenses. Corporate general and administrative expenses increased in the nine-month period of 2016 mainly due to increased compensation and benefit expenses.

Technology includes our investment in new technologies or businesses, as well as licensing revenues. Activities are focused on tight oil reservoirs, heavy oil and oil sands, as well as LNG. Earnings from Technology increased $41 million in the third quarter of 2016, compared with the same period of 2015. The increase was primarily due to higher licensing revenues and lower spend on emerging businesses. Earnings from Technology decreased $9 million in the nine-month period of 2016, compared with the same period of 2015, mainly due to a $31 million reduction in licensing revenues in the nine-month period of 2016 compared with the corresponding period of 2015.

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 decreased $39 million in the third quarter and $67 million in the nine-month period of 2016, compared with the corresponding periods of 2015. Other expenses decreased in both periods primarily due to lower restructuring costs and favorable foreign currency impacts, partly offset by the absence of a third-quarter 2015 tax benefit.

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CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators

	Millions of Dollars
	September 30 2016			December 31 2015
Short-term debt	$	1,336			1,427
Total debt		28,689			24,880
Total equity		36,456			40,082
Percent of total debt to capital*		44	%		38
Percent of floating-rate debt to total debt		9	%		7

*Capital includes total debt and total equity.

To meet our short- and long-term liquidity requirements, we look to a variety of funding sources, including cash generated from operating activities. During the first nine months of 2016, we issued $4,594 million of new debt consisting of a three-year term loan and fixed rate notes. The primary uses of our available cash were $3,870 million to support our ongoing capital expenditures and investments program, $940 million to pay dividends, $803 million to repay outstanding commercial paper, and $229 million net purchases of short-term investments. On October 17, 2016, the $1,250 million of Notes due 2016 were repaid at maturity. During the first nine months of 2016, cash and cash equivalents increased by $1,722 million to $4,090 million.

We rely on cash flows from operating activities, proceeds from asset sales, our commercial paper and credit facility programs, and our shelf registration statement to support 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 operating activities was $2,960 million for the first nine months of 2016, compared with $5,976 million for the corresponding period of 2015, a 50 percent decrease. The decrease was primarily due to lower prices across all commodities. Cash flows from operating activities were positively impacted by the $569 million and $556 million tax refunds received from the Internal Revenue Service during the first nine months of 2016 and 2015, respectively.

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 the volatile crude oil and natural gas price environment, which may impact investment decisions; the effects of price changes on production sharing and variable-royalty contracts; acquisition and disposition of fields; field production decline rates; new technologies; operating efficiencies; timing of startups and major turnarounds; political instability; weather-related disruptions; and 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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To maintain or grow our production volumes, we must continue to add to our proved reserve base. As we undertake cash conservation efforts, our reserve replacement efforts could be delayed thus limiting our ability to replace depleted reserves.

Investing Activities

Proceeds from asset sales for the first nine months of 2016 were $419 million compared with $323 million for the corresponding period of 2015. On October 28, 2016, we sold our 35 percent interest in three exploration blocks offshore Senegal. Additionally, we have entered into an agreement to sell our 40 percent interest in South Natuna Sea Block B in Indonesia. We continue to optimize our asset portfolio by focusing on assets which offer the highest returns and growth potential, while selling non-core assets. For additional information, see Note 5—Assets Held for Sale, Sold, or Other Planned Dispositions, in the Notes to Consolidated Financial Statements, and the Outlook section within Management’s Discussion and Analysis.

In May 2015, we liquidated certain deferred compensation investments for proceeds of $267 million, which is included in the “Other” line within “Cash Flows From Investing Activities” on our consolidated statement of cash flows. We do not expect further material liquidations associated with deferred compensation investments.

Commercial Paper and Credit Facilities

On March 28, 2016, we reduced our revolving credit facility, expiring in June 2019, from $7.0 billion to $6.75 billion. Our revolving credit facility may be used for direct bank borrowings, 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 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 $6.25 billion commercial paper program. Commercial paper maturities are generally limited to 90 days. We also have the ConocoPhillips Qatar Funding Ltd. $500 million commercial paper program, which is used to fund commitments relating to QG3. At both September 30, 2016 and December 31, 2015, we had no direct borrowings or letters of credit issued under the revolving credit facility. Under the ConocoPhillips Qatar Funding Ltd. commercial paper program, no commercial paper was outstanding at September 30, 2016, compared with $803 million at December 31, 2015. Since we had no commercial paper outstanding and had issued no letters of credit, we had access to $6.75 billion in borrowing capacity under our revolving credit facility at September 30, 2016.

Due to the significant decline in commodity prices during 2015, and the expectation these prices could remain depressed in the near future, the major ratings agencies conducted a review of the oil and gas industry. As a result of this review, our credit ratings, along with several other companies in the oil and gas industry, were downgraded. In the first quarter of 2016, Moody’s Investors Service downgraded our senior long-term debt ratings to “Baa2” from “A2,” with a negative outlook and our short-term commercial paper ratings to“Prime-2” from“Prime-1” and Fitch downgraded our long-term debt ratings to“A-” from “A” with a negative outlook and our short-term commercial paper ratings to “F2” from “F1.” In the second quarter of 2016, Standard and Poor’s downgraded our senior long-term debt ratings to“A-” from “A,” with a negative outlook and our short-term commercial paper ratings to “A-2” from “A-1.” We do not have any ratings triggers on any of our corporate debt that would cause an automatic default, and thereby impact our access to liquidity, in the event of a further downgrade of our credit rating. If our credit rating were to deteriorate to a level prohibiting us from accessing the commercial paper market, we would still be able to access funds under our revolving credit facility.

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Certain of our project-related contracts, commercial 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, 2016 and December 31, 2015, we had direct bank letters of credit of $304 million and $340 million, respectively, which secured performance obligations related to various purchase commitments incident to the ordinary conduct of business. In the event of further credit ratings downgrades, we may be required to post additional letters of credit.

Shelf Registration

We have a universal shelf registration statement on file with the U.S. Securities and Exchange Commission (SEC) 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 11—Guarantees, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

Capital Requirements

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

Our debt balance at September 30, 2016, was $28.7 billion, an increase of $3.8 billion from the balance at December 31, 2015, primarily as a result of obtaining a $1.6 billion three-year term loan and the issuance of $3.0 billion in new fixed rate notes, both in March 2016, partially offset by the $803 million repayment of outstanding commercial paper. Our short-term debt balance at September 30, 2016, decreased $91 million compared with December 31, 2015, primarily as a result of the timing of scheduled maturities. On October 17, 2016, the $1,250 million of Notes due 2016 were repaid at maturity. For more information, see Note 9—Debt, in the Notes to Consolidated Financial Statements.

To preserve our balance sheet strength and provide financial flexibility through the current downturn, we announced a reduction in the quarterly dividend in the first quarter of 2016. In July 2016, we announced a dividend of $0.25 per share. The dividend was paid September 1, 2016, to stockholders of record at the close of business on July 25, 2016. In October 2016, we announced a dividend of $0.25 per share. The dividend will be paid December 1, 2016, to stockholders of record at the close of business on October 17, 2016.

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Capital Expenditures

	Millions of Dollars
	Nine Months Ended September 30
	2016		2015
Alaska	$	702		1,085
Lower 48		992		3,010
Canada		553		887
Europe and North Africa		801		1,231
Asia Pacific and Middle East		700		1,471
Other International		81		138
Corporate and Other		41		91
Capital expenditures and investments	$	3,870		7,913

During the first nine months of 2016, capital expenditures and investments supported key exploration and development programs, primarily:

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

• Major project expenditures associated with the APLNG joint venture in Australia.

• Continued oil sands development, ongoing liquids-rich plays in Canada, and exploration activities in Nova Scotia.

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

• Development activities, in Europe, including the Greater Ekofisk, Aasta Hansteen, Clair Ridge and Greater Britannia areas.

• Exploration and appraisal drilling in deepwater Gulf of Mexico.

• Continued development in Malaysia, Indonesia and China.

We revised our 2016 operating plan, reducing our capital expenditures guidance from $6.4 billion in February to $5.5 billion in July, and further reduced our guidance to $5.2 billion in October 2016, primarily due to lower costs and deferrals across the portfolio, as well as reduced deepwater exploration activity.

Contingencies

A number of lawsuits involving a variety of claims arising in the ordinary course of business have been filed 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

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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 12—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 and tax 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 62–64 of our 2015 Annual Report on Form 10-K.

We occasionally receive requests for information or notices of potential liability from the Environmental Protection Agency (EPA) and state environmental agencies alleging that we are a potentially responsible party under the Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain waste attributable to our past operations. As of September 30, 2016, there were 14 sites around the United States in which we were identified as a potentially responsible party under CERCLA and comparable state laws.

Our balance sheet at both September 30, 2016 and December 31, 2015, included a total environmental accrual of $258 million, 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.

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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 64–66 of our 2015 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. All statements other than statements of historical fact included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs and plans, and objectives of management for future operations, are forward-looking statements. Examples of forward-looking statements contained in this report include our expected production growth and outlook on the business environment generally, our expected capital budget and capital expenditures, and discussions concerning future dividends. You can often 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, but not limited to, the following:

• Fluctuations in crude oil, bitumen, natural gas, LNG and natural gas liquids prices, including a prolonged decline in these prices relative to historical or future expected levels.

• The impact of recent, significant declines in prices for crude oil, bitumen, natural gas, LNG and natural gas liquids, which may result in recognition of impairment costs on our long-lived assets, leaseholds and nonconsolidated equity investments.

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

• Inability to maintain reserves replacement rates consistent with prior periods, whether as a result of the recent, significant declines in commodity prices or otherwise.

• 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.

• Legislative and regulatory initiatives addressing environmental concerns, including initiatives addressing the impact of global climate change or further regulating hydraulic fracturing, methane emissions, flaring or water disposal.

• 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; failure to comply with applicable laws and regulations; or inability to make capital expenditures required to maintain compliance with any necessary permits or applicable laws or regulations.

• 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, war, terrorism, cyber attacks or infrastructure constraints or disruptions.

• Changes in international monetary conditions and exchange controls, including changes in foreign currency exchange rates.

• Reduced demand for our products or the use of competing energy products, including alternative energy sources.

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• Substantial investment in and development of alternative energy sources, including 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; and other political, economic or diplomatic developments.

• Volatility in the commodity futures markets.

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

• Competition in the oil and gas exploration and production industry.

• Any limitations on our access to capital or increase in our cost of capital related to illiquidity or uncertainty in the domestic or international financial markets.

• Our inability to execute asset dispositions or delays in the completion of any asset dispositions we elect to pursue.

• Our 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 ability of our customers and other contractual counterparties to satisfy their obligations to us.

• Our inability to realize anticipated cost savings and expenditure reductions.

• The factors generally described in Item 1A—Risk Factors in our 2015 Annual Report on Form 10-K and any additional risks described in our other filings with the SEC.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information about market risks for the nine months ended September 30, 2016, does not differ materially from that discussed under Item 7A in our 2015 Annual Report on Form 10-K.

Item 4. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures designed to ensure 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, 2016, with the participation of our management, our Chairman and Chief Executive Officer (principal executive officer) and our Executive Vice President, Finance, Commercial 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, Commercial and Chief Financial Officer concluded our disclosure controls and procedures were operating effectively as of September 30, 2016.

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 2016 and any material developments with respect to matters previously reported in ConocoPhillips’ 2015 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 U.S. Securities and Exchange Commission regulations.

Matters previously reported—ConocoPhillips

On July 13, 2016, ConocoPhillips received a Notice of Violation (NOV) and Settlement Offer from the Southern Ute Indian Tribe’s Environmental Programs Division (Division) alleging violations of certain regulations, permit conditions and a previous Consent Decree governing the operation of two glycol dehydration units at our Ute Compressor Station in La Plata County, Colorado. Specifically, the Division alleges that we failed to meet emission control system requirements and to conduct quarterly performance testing. We have resolved this matter with the Division.

Matters previously reported—Phillips 66

Phillips 66 provided a $793,250 settlement payment to the Bay Area Quality Management District (Bay Area AQMD) to resolve 87 NOVs issued between 2010 and 2014. Most of these NOVs resulted from self-disclosed violations of regulatory and/or permit requirements at the Rodeo refining facility. The matters discussed below are now resolved.

On October 15, 2012, the Bay Area AQMD issued a $313,000 demand to settle 13 other NOVs issued in 2010 and 2011 with respect to alleged violations of regulatory and/or permit requirements at the Phillips 66 Rodeo Refinery.

On July 8, 2014, the Bay Area AQMD issued a $175,000 demand to settle 18 NOVs issued in 2010 with respect to alleged violations of regulatory and/or permit requirements at the Phillips 66 Rodeo Refinery.

On July 8, 2014, the Bay Area AQMD issued a $259,000 demand to settle 20 NOVs issued in 2011 with respect to alleged violations of regulatory and/or permit requirements at the Phillips 66 Rodeo Refinery.

Item 1A. RISK FACTORS

There have been no material changes from the risk factors disclosed in Item 1A of our 2015 Annual Report on Form 10-K.

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Item 6. EXHIBITS

12*	Computation of Ratio of Earnings to Fixed Charges.
31.1*	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
31.2*	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
32*	Certifications pursuant to 18 U.S.C. Section 1350.
101.INS*	XBRL Instance Document.
101.SCH*	XBRL Schema Document.
101.CAL*	XBRL Calculation Linkbase Document.
101.LAB*	XBRL Labels Linkbase Document.
101.PRE*	XBRL Presentation Linkbase Document.
101.DEF*	XBRL Definition Linkbase Document.

*Filed herewith.

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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 1, 2016

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