CONOCOPHILLIPS - Quarter Report: 2019 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)
[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2019

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.)

925 N. Eldridge Parkway

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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes [x] No [ ]

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

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

Emerging growth company [ ]

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]

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

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading symbols	Name of each exchange on which registered
Common Stock, $.01 Par Value	COP	New York Stock Exchange
7% Debentures due 2029	CUSIP – 718507BK1	New York Stock Exchange

The registrant had 1,097,268,667 shares of common stock, $.01 par value, outstanding at September 30, 2019.

Table of Contents

CONOCOPHILLIPS

TABLE OF CONTENTS

		Page
Commonly Used Abbreviations		1

Part I—Financial Information

Item 1. Financial Statements
Consolidated Income Statement		2
Consolidated Statement of Comprehensive Income		3
Consolidated Balance Sheet		4
Consolidated Statement of Cash Flows		5
Notes to Consolidated Financial Statements		6
Supplementary Information—Condensed Consolidating Financial Information		36

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		41

Item 3. Quantitative and Qualitative Disclosures About Market Risk		64

Item 4. Controls and Procedures		64

Part II—Other Information

Item 1. Legal Proceedings		65

Item 1A. Risk Factors		65

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		65

Item 6. Exhibits		66

Signature		67

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Commonly Used Abbreviations

The following industry-specific, accounting and other terms, and abbreviations may be commonly used in this report.

Currencies		Accounting
$	U.S. dollar	ARO	asset retirement obligation
CAD	Canadian dollar	ASC	accounting standards codification
GBP	British pound	ASU	accounting standards update
		DD&A	depreciation, depletion and
Units of Measurement			amortization
BOE	barrels of oil equivalent	FASB	Financial Accounting Standards
MBD	thousands of barrels per day		Board
MCF	thousand cubic feet	FIFO	first-in, first-out
MMBOE	million barrels of oil equivalent	G&A	general and administrative
MBOED	thousands of barrels of oil	GAAP	generally accepted accounting
	equivalent per day		principles
MMBTU	million British thermal units	LIFO	last-in, first-out
MMCFD	million cubic feet per day	NPNS	normal purchase normal sale
		PP&E	properties, plants and equipment
Industry		SAB	staff accounting bulletin
CBM	coalbed methane	VIE	variable interest entity
E&P	exploration and production
FEED	front-end engineering and design	Miscellaneous
FPS	floating production system	EPA	Environmental Protection Agency
FPSO	floating production, storage and	EU	European Union
	offloading	FERC	Federal Energy Regulatory
JOA	joint operating agreement		Commission
LNG	liquefied natural gas	GHG	greenhouse gas
NGLs	natural gas liquids	HSE	health, safety and environment
OPEC	Organization of Petroleum	ICC	International Chamber of
	Exporting Countries		Commerce
PSC	production sharing contract	ICSID	World Bank’s International
PUDs	proved undeveloped reserves		Centre for Settlement of
SAGD	steam-assisted gravity drainage		Investment Disputes
WCS	Western Canada Select	IRS	Internal Revenue Service
WTI	West Texas Intermediate	OTC	over-the-counter
		NYSE	New York Stock Exchange
		SEC	U.S. Securities and Exchange
			Commission
		TSR	total shareholder return
		U.K.	United Kingdom
		U.S.	United States of America

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PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

Consolidated Income Statement

ConocoPhillips

			Millions of Dollars
			Three Months Ended			Nine Months Ended
			September 30			September 30
			2019		2018	2019	2018
Revenues and Other Income
Sales and other operating revenues			$	7,756	9,449	24,859	26,751
Equity in earnings of affiliates				290	294	651	767
Gain on dispositions				1,785	113	1,884	175
Other income				262	309	1,136	673
		Total Revenues and Other Income		10,093	10,165	28,530	28,366

Costs and Expenses
Purchased commodities				2,710	3,530	9,059	10,308
Production and operating expenses				1,331	1,367	4,020	3,851
Selling, general and administrative expenses				87	119	369	336
Exploration expenses				360	103	592	267
Depreciation, depletion and amortization				1,566	1,494	4,602	4,344
Impairments				24	44	26	21
Taxes other than income taxes				237	312	706	768
Accretion on discounted liabilities				86	89	259	266
Interest and debt expense				184	186	582	547
Foreign currency transaction (gains) losses				(21)	5	19	7
Other expenses				36	10	58	350
		Total Costs and Expenses		6,600	7,259	20,292	21,065
Income before income taxes				3,493	2,906	8,238	7,301
Income tax provision				422	1,033	1,724	2,874
Net income				3,071	1,873	6,514	4,427
Less: net income attributable to noncontrolling interests				(15)	(12)	(45)	(38)
Net Income Attributable to ConocoPhillips			$	3,056	1,861	6,469	4,389


Net Income Attributable to ConocoPhillips Per Share
	of Common Stock (dollars)
Basic			$	2.76	1.60	5.75	3.74
Diluted				2.74	1.59	5.72	3.72

Average Common Shares Outstanding (in thousands)
Basic				1,108,555	1,163,033	1,124,558	1,171,673
Diluted				1,113,250	1,172,694	1,131,034	1,180,774
See Notes to Consolidated Financial Statements.

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Consolidated Statement of Comprehensive Income

ConocoPhillips

				Millions of Dollars
				Three Months Ended			Nine Months Ended
				September 30			September 30
				2019		2018	2019	2018

Net Income				$	3,071	1,873	6,514	4,427
Other comprehensive income
	Defined benefit plans
		Reclassification adjustment for amortization of prior
			service credit included in net income		(8)	(10)	(26)	(30)
		Net actuarial gain (loss) arising during the period			(149)	187	(149)	145
		Reclassification adjustment for amortization of net actuarial
			losses included in net income		56	33	114	228
		Nonsponsored plans			(1)	-	(1)	(1)
		Income taxes on defined benefit plans			30	(74)	20	(102)
		Defined benefit plans, net of tax			(72)	136	(42)	240
	Foreign currency translation adjustments				247	59	493	(222)
	Income taxes on foreign currency translation adjustments				(2)	-	(2)	-
		Foreign currency translation adjustments, net of tax			245	59	491	(222)
Other Comprehensive Income, Net of Tax					173	195	449	18
Comprehensive Income					3,244	2,068	6,963	4,445
Less: comprehensive income attributable to noncontrolling interests					(15)	(12)	(45)	(38)
Comprehensive Income Attributable to ConocoPhillips				$	3,229	2,056	6,918	4,407
See Notes to Consolidated Financial Statements.

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Consolidated Balance Sheet

ConocoPhillips

				Millions of Dollars
				September 30		December 31
					2019	2018
Assets
Cash and cash equivalents				$	7,193	5,915
Short-term investments					908	248
Accounts and notes receivable (net of allowance of $12 million in 2019
	and $25 million in 2018)				3,478	3,920
Accounts and notes receivable—related parties					138	147
Investment in Cenovus Energy					1,951	1,462
Inventories					955	1,007
Prepaid expenses and other current assets					594	575
			Total Current Assets		15,217	13,274
Investments and long-term receivables					8,916	9,329
Loans and advances—related parties					219	335
Net properties, plants and equipment (net of accumulated depreciation, depletion
	and amortization of $60,014 million in 2019 and $64,899 million in 2018)				43,814	45,698
Other assets					2,174	1,344
Total Assets				$	70,340	69,980

Liabilities
Accounts payable				$	3,148	3,863
Accounts payable—related parties					23	32
Short-term debt					121	112
Accrued income and other taxes					1,077	1,320
Employee benefit obligations					543	809
Other accruals					1,030	1,259
			Total Current Liabilities		5,942	7,395
Long-term debt					14,799	14,856
Asset retirement obligations and accrued environmental costs					6,087	7,688
Deferred income taxes					4,693	5,021
Employee benefit obligations					1,786	1,764
Other liabilities and deferred credits					1,794	1,192
Total Liabilities					35,101	37,916

Equity
Common stock (2,500,000,000 shares authorized at $ 0.010 par value)
		Issued (2019—1,795,243,745 shares; 2018—1,791,637,434 shares)
			Par value		18	18
			Capital in excess of par		46,954	46,879
		Treasury stock (at cost: 2019—697,975,078 shares; 2018—653,288,213 shares)			(45,656)	(42,905)
Accumulated other comprehensive loss					(5,654)	(6,063)
Retained earnings					39,484	34,010
			Total Common Stockholders’ Equity		35,146	31,939
Noncontrolling interests					93	125
Total Equity					35,239	32,064
Total Liabilities and Equity				$	70,340	69,980
See Notes to Consolidated Financial Statements.

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Consolidated Statement of Cash Flows

ConocoPhillips

				Millions of Dollars
			Nine Months Ended
			September 30
			2019		2018
Cash Flows From Operating Activities
Net income			$	6,514	4,427
Adjustments to reconcile net income to net cash provided by operating
	activities
	Depreciation, depletion and amortization			4,602	4,344
	Impairments			26	21
	Dry hole costs and leasehold impairments			361	64
	Accretion on discounted liabilities			259	266
	Deferred taxes			(304)	398
	Undistributed equity earnings			260	(11)
	Gain on dispositions			(1,884)	(175)
	Other			(820)	(223)
	Working capital adjustments
		Decrease (increase) in accounts and notes receivable		333	(147)
		Increase in inventories		(2)	(165)
		Increase in prepaid expenses and other current assets		(29)	(51)
		Decrease in accounts payable		(476)	(43)
		Increase (decrease) in taxes and other accruals		(718)	446
Net Cash Provided by Operating Activities				8,122	9,151

Cash Flows From Investing Activities
Capital expenditures and investments				(5,041)	(5,133)
Working capital changes associated with investing activities				17	(57)
Proceeds from asset dispositions				2,920	394
Net sales (purchases) of short-term investments				(665)	996
Collection of advances/loans—related parties				127	119
Other				(146)	16
Net Cash Used in Investing Activities				(2,788)	(3,665)

Cash Flows From Financing Activities
Repayment of debt				(59)	(4,970)
Issuance of company common stock				(39)	121
Repurchase of company common stock				(2,751)	(2,073)
Dividends paid				(1,037)	(1,009)
Other				(73)	(111)
Net Cash Used in Financing Activities				(3,959)	(8,042)

Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted
	Cash			(68)	(40)

Net Change in Cash, Cash Equivalents and Restricted Cash				1,307	(2,596)
Cash, cash equivalents and restricted cash at beginning of period				6,151	6,536
Cash, Cash Equivalents and Restricted Cash at End of Period			$	7,458	3,940

Restricted cash of $89 million and $176 million are included in the "Prepaid expenses and other current assets" and "Other assets" lines, respectively, of our Consolidated Balance Sheet as of September 30, 2019.

Restricted cash totaling $236 million is included in the "Other assets" line of our Consolidated Balance Sheet as of December 31, 2018.

See Notes to Consolidated Financial Statements.

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Notes to Consolidated Financial Statements	ConocoPhillips

Note 1—Basis of Presentation

The interim-period financial information presented in the financial statements included in this report is unaudited and, in the opinion of management, includes all known accruals and adjustments necessary for a fair presentation of the consolidated financial position of ConocoPhillips and its results of operations and cash flows for such periods. All such adjustments are of a normal and recurring nature unless otherwise disclosed. Certain notes and other information have been condensed or omitted from the interim financial statements included in this report. Therefore, these financial statements should be read in conjunction with the consolidated financial statements and notes included in our 2018 Annual Report on Form 10-K.

Note 2—Changes in Accounting Principles

We adopted the provisions of FASB ASU No. 2016-02, “Leases,” and its amendments set forth by the provisions of ASU No. 2018-01, “Land Easement Practical Expedient for Transition to Topic 842,” ASU No. 2018-10, “Codification Improvements to Topic 842, Leases,” ASU No. 2018-11, “Targeted Improvements,” ASU No. 2018-20, “Narrow-Scope Improvements for Lessors,” and ASU No. 2019-01, “Codification Improvements,” collectively FASB ASC Topic 842, “Leases” (ASC Topic 842), beginning January 1, 2019.

ASC Topic 842 establishes comprehensive accounting and financial reporting requirements for leasing arrangements, supersedes the existing requirements in FASB ASC Topic 840, “Leases” (ASC Topic 840), and requires lessees to recognize substantially all lease assets and lease liabilities on the balance sheet. The provisions of ASC Topic 842 also modify the definition of a lease and outline requirements for recognition, measurement, presentation and disclosure of leasing arrangements by both lessees and lessors.

We adopted ASC Topic 842 using the modified retrospective approach and elected to utilize the Optional Transition Method, which permits us to apply the provisions of ASC Topic 842 to leasing arrangements existing at or entered into after January 1, 2019, and present in our financial statements comparative periods prior to January 1, 2019 under the historical requirements of ASC Topic 840. In addition, we elected to adopt the package of optional transition-related practical expedients, which among other things, allows us to carry forward certain historical conclusions reached under ASC Topic 840 regarding lease identification, classification, and the accounting treatment of initial direct costs. Furthermore, we elected not to record assets and liabilities on our consolidated balance sheet for new or existing lease arrangements with terms of 12 months or less.

The primary impact of applying ASC Topic 842 is the initial recognition of $998 million of lease liabilities and corresponding right-of-use assets on our consolidated balance sheet as of January 1, 2019, for leases classified as operating leases under ASC Topic 840, as well as enhanced disclosure of our leasing arrangements. Our accounting treatment for finance leases remains unchanged. In addition, there is no cumulative effect to retained earnings or other components of equity recognized as of January 1, 2019, and the adoption of ASC Topic 842 did not impact the presentation of our consolidated income statement or statement of cash flows. See Note 15—Non-Mineral Leases for additional information related to the adoption of ASC Topic 842.

We adopted the provisions of FASB ASU No. 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income,” beginning January 1, 2019. The ASU allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act, eliminating the stranded tax effects. The cumulative effect to our consolidated balance sheet at January 1, 2019 for the adoption of ASU No. 2018-02 was as follows:

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	Millions of Dollars
		December 31	ASU No. 2018-02	January 1
		2018	Adjustments	2019
Equity
Accumulated other comprehensive loss	$	(6,063)	(40)	(6,103)
Retained earnings		34,010	40	34,050
For additional information regarding the impact of the adoption of ASU No. 2018-02, see Note 16—Accumulated Other Comprehensive Loss.

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 VIEs 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 CBM, as well as LNG processing and export marketing. As a result, we do not consolidate APLNG, and it is accounted for as an equity method investment.

As of September 30, 2019, 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.

Marine Well Containment Company, LLC (MWCC)

MWCC provides well containment equipment and technology and related services in the deepwater U.S. Gulf of Mexico. Its principal activities involve the development and maintenance of rapid-response hydrocarbon well containment systems that are deployable in the Gulf of Mexico on a call-out basis. We have a 10 percent ownership interest in MWCC, and it is accounted for as an equity method investment because MWCC is a limited liability company in which we are a Founding Member and exercise significant influence through our permanent seat on the ten-member Executive Committee responsible for overseeing the affairs of MWCC. In 2016, MWCC executed a $154 million term loan financing arrangement with an external financial institution whose terms required the financing be secured by letters of credit provided by certain owners of MWCC, including ConocoPhillips. In connection with the financing transaction, we issued a letter of credit of $22 million which can be drawn upon in the event of a default by MWCC on its obligation to repay the proceeds of the term loan. MWCC is considered a VIE, as it has entered into arrangements that provide it with additional forms of subordinated financial support. We are not the primary beneficiary and do not consolidate MWCC because we share the power to govern the business and operation of the company and to undertake certain obligations that most significantly impact its economic performance with nine other unaffiliated owners of MWCC.

Based on inputs related to the fair value of MWCC observed in the second quarter of 2019, we reduced the carrying value of our equity method investment in MWCC to $30 million and recorded a before-tax impairment of $95 million which is included in the “Equity in earnings of affiliates” line on our consolidated income statement. For additional information see Note 14—Fair Value Measurement.

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At September 30, 2019, the carrying value of our equity method investment in MWCC was $27 million. We have not provided any financial support to MWCC other than amounts previously contractually required. Unless we elect otherwise, we have no requirement to provide liquidity or purchase the assets of MWCC.

Note 4—Inventories

Inventories consisted of the following:

	Millions of Dollars
	September 30		December 31
		2019	2018

Crude oil and natural gas	$	399	432
Materials and supplies		556	575
	$	955	1,007

Inventories valued on the LIFO basis totaled $230 million and $292 million at September 30, 2019 and December 31, 2018, respectively. The estimated excess of current replacement cost over LIFO cost of inventories was $115 million and $75 million at September 30, 2019 and December 31, 2018, respectively.

Note 5—Asset Dispositions

Asset Dispositions

In April 2019, we entered into an agreement to sell two ConocoPhillips U.K. subsidiaries to Chrysaor E&P Limited for $2.675 billion plus interest and customary adjustments, with an effective date of January 1, 2018. On September 30, 2019, we completed the sale for proceeds of $2.2 billion. In the nine-month period of 2019, we recorded a $1.8 billion before-tax and $2.1 billion after-tax gain associated with this transaction. Together the subsidiaries sold indirectly held our exploration and production assets in the U.K. At the time of disposition, the net carrying value was approximately $0.4 billion, consisting primarily of $1.6 billion of PP&E, $0.5 billion of cumulative foreign currency translation adjustments, and $0.2 billion of deferred tax assets, offset by $1.8 billion of ARO and negative $0.1 billion of working capital. The before-tax earnings associated with the subsidiaries sold were $0.6 billion and $0.4 billion for the nine-month periods of 2018 and 2019, respectively. Results of operations for the U.K. are reported within our Europe and North Africa segment.

In the second quarter of 2019, we recognized an after-tax gain of $52 million upon the closing of the sale of our 30 percent interest in the Greater Sunrise Fields to the government of Timor-Leste for $350 million. The Greater Sunrise Fields were included in our Asia Pacific and Middle East segment.

In January 2019, we entered into agreements to sell our 12.4 percent ownership interests in the Golden Pass LNG Terminal and Golden Pass Pipeline. We also entered into agreements to amend our contractual obligations for retaining use of the facilities. As a result of entering into these agreements, we recorded a before-tax impairment of $60 million in the first quarter of 2019 which is included in the “Equity in earnings of affiliates” line on our consolidated income statement. We completed the sale in the second quarter of 2019. Results of operations for these assets are reported in our Lower 48 segment. See Note 14—Fair Value Measurement for additional information.

In the second quarter of 2017, we completed the sale of our 50 percent nonoperated interest in the Foster Creek Christina Lake (FCCL) Partnership, as well as the majority of our western Canada gas assets to Cenovus Energy.

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Consideration for the transaction included a five-year uncapped contingent payment. The contingent payment, calculated on a quarterly basis, is $6 million CAD for every $1 CAD by which the WCS quarterly average crude price exceeds $52 CAD per barrel. Contingent payments received during the five-year period are recorded as “Gain on dispositions” on our consolidated income statement and reflected in our Canada segment. We recorded gains on dispositions for these contingent payments of $95 million and $104 million in the nine-month periods of 2018 and 2019, respectively.

Planned Disposition

In October 2019, we announced an agreement to sell the subsidiaries that hold our Australia-West assets and operations to Santos for $1.39 billion, plus customary adjustments, with an effective date of January 1, 2019. In addition, we will receive a payment of $75 million upon final investment decision of the Barossa development project. These subsidiaries hold our 37.5 percent interest in the Barossa Project and Caldita Field, our 56.9 percent interest in the Darwin LNG Facility and Bayu-Undan Field, our 40 percent interest in the Greater Poseidon Fields, and our 50 percent interest in the Athena Field. At September 30, 2019, the net carrying value was approximately $0.6 billion, consisting primarily of $1.2 billion of PP&E and $0.2 billion of cash and working capital, offset by $0.6 billion of ARO and $0.2 billion of deferred tax liabilities. This transaction met held for sale criteria in October 2019 and is expected to be completed in the first quarter of 2020, subject to regulatory approvals and other specific conditions precedent. Results of operations for the subsidiaries to be sold are reported within our Asia Pacific and Middle East segment.

Note 6—Investments, Loans and Long-Term Receivables

APLNG

APLNG executed project financing agreements for an $8.5 billion project finance facility in 2012. The $8.5 billion project finance facility was initially composed 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. All amounts have been drawn from the facility. APLNG made its first principal and interest repayment in March 2017 and is scheduled to make bi-annual payments until March 2029.

APLNG made a voluntary repayment of $1.4 billion to the Export-Import Bank of China in September 2018. At the same time, APLNG obtained a United States Private Placement (USPP) bond facility of $1.4 billion. APLNG made its first interest payment related to this facility in March 2019, and principal payments are scheduled to commence in September 2023, with bi-annual payments due on the facility until September 2030.

During the first quarter of 2019, APLNG refinanced $3.2 billion of existing project finance debt through two transactions. As a result of the first transaction, APLNG obtained a commercial bank facility of $2.6 billion. APLNG made its first principal and interest repayment in September 2019 with bi-annual payments due on the facility until March 2028. Through the second transaction, APLNG obtained a USPP bond facility of $0.6 billion. APLNG made its first interest payment in September 2019, and principal payments are scheduled to commence in September 2023, with bi-annual payments due on the facility until September 2030.

In conjunction with the $3.2 billion debt obtained during the first quarter of 2019 to refinance existing project finance debt, APLNG made voluntary repayments of $2.2 billion and $1.0 billion to a syndicate of Australian and international commercial banks and the Export-Import Bank of China, respectively.

At September 30, 2019, a balance of $6.7 billion was outstanding on the facilities. 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.

At September 30, 2019, the carrying value of our equity method investment in APLNG was $7,410 million. The balance is included in the “Investments and long-term receivables” line on our consolidated balance sheet.

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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, 2019, significant loans to affiliated companies included $335 million in project financing to Qatar Liquefied Gas Company Limited (3) (QG3).

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

Note 7—Investment in Cenovus Energy

On May 17, 2017, we completed the sale of our 50 percent nonoperated interest in the FCCL Partnership, as well as the majority of our western Canada gas assets to Cenovus Energy. Consideration for the transaction included 208 million Cenovus Energy common shares, which, at closing, approximated 16.9 percent of issued and outstanding Cenovus common stock. The fair value and cost basis of our investment in 208 million Cenovus Energy common shares was $1.96 billion based on a price of $9.41 per share on the NYSE on the closing date.

Our investment on our consolidated balance sheet as of September 30, 2019, is carried at fair value of $1.95 billion, reflecting the closing price of Cenovus Energy shares on the NYSE of $9.38 per share on the last trading day of the quarter, an increase of $116 million from $1.84 billion at the end of the second quarter of 2019 and an increase of $489 million from $1.46 billion at year-end 2018. The increase in fair value represents the net unrealized gain recorded within the “Other income” line of our consolidated income statement in the first nine months of 2019 relating to the shares held at the reporting date. See Note 14—Fair Value Measurement, for additional information. Subject to market conditions, we intend to decrease our investment over time through market transactions, private agreements or otherwise.

Note 8—Suspended Wells and Exploration Expenses

The capitalized cost of suspended wells at September 30, 2019, was $973 million, an increase of $117 million from $856 million at year-end 2018. No suspended wells were charged to dry hole expense during the first nine months of 2019 relating to exploratory well costs capitalized for a period greater than one year as of December 31, 2018.

In the third quarter of 2019, we recorded before-tax dry hole expenses of $98 million and a before-tax impairment of $141 million for the associated carrying value of capitalized undeveloped leasehold costs due to our decision to discontinue exploration activities in the Central Louisiana Austin Chalk trend. These charges are included in our Lower 48 segment and in the “Exploration expenses” line on our consolidated income statement.

Note 9—Debt

Our revolving credit facility provides a total commitment of $6.0 billion and expires in May 2023. 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 program. Our commercial paper program consists of the ConocoPhillips Company $6.0 billion program, primarily a funding source for short-term working capital needs. Commercial paper maturities are generally limited to 90 days.

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December 31, 2018. Since we had no commercial paper outstanding and had issued no letters of credit, we had access to $6.0 billion in borrowing capacity under our revolving credit facility at September 30, 2019.

At September 30, 2019, 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. If they are ever redeemed, we intend to refinance on a long-term basis, therefore, the VRDBs are included in the “Long-term debt” line on our consolidated balance sheet.

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Note 10—Changes in Equity

	Millions of Dollars
	Attributable to ConocoPhillips
	Common Stock
	Par Value		Capital in Excess of Par	Treasury Stock	Accum. Other Comprehensive Income (Loss)		Retained Earnings	Non-Controlling Interests	Total
For the three months ended September 30, 2019
Balances at June 30, 2019	$	18	46,922	(44,906)		(5,827)	36,769	98	33,074
Net income							3,056	15	3,071
Other comprehensive income						173			173
Dividends paid ($ 0.31 ) per common share							(341)		(341)
Repurchase of company common stock				(749)					(749)
Distributions to noncontrolling interests and other								(20)	(20)
Distributed under benefit plans			32						32
Other				(1)					(1)
Balances at September 30, 2019	$	18	46,954	(45,656)		(5,654)	39,484	93	35,239

For the nine months ended September 30, 2019
Balances at December 31, 2018	$	18	46,879	(42,905)		(6,063)	34,010	125	32,064
Net income							6,469	45	6,514
Other comprehensive income						449			449
Dividends paid ($ 0.92 ) per common share							(1,037)		(1,037)
Repurchase of company common stock				(2,751)					(2,751)
Distributions to noncontrolling interests and other								(80)	(80)
Distributed under benefit plans			75						75
Changes in Accounting Principles*						(40)	40		-
Other							2	3	5
Balances at September 30, 2019	$	18	46,954	(45,656)		(5,654)	39,484	93	35,239
*See Note 2—Changes in Accounting Principles for additional information.


	Millions of Dollars
	Attributable to ConocoPhillips
	Common Stock
	Par Value		Capital in Excess of Par	Treasury Stock		Accum. Other Comprehensive Income (Loss)	Retained Earnings	Non-Controlling Interests	Total
For the three months ended September 30, 2018
Balances at June 30, 2018	$	18	46,746	(41,052)		(5,637)	30,967	180	31,222
Net income							1,861	12	1,873
Other comprehensive income						195			195
Dividends paid ($ 0.29 ) per common share							(334)		(334)
Repurchase of company common stock				(927)					(927)
Distributions to noncontrolling interests and other								(63)	(63)
Distributed under benefit plans			112					.	112
Other							1		1
Balances at September 30, 2018	$	18	46,858	(41,979)		(5,442)	32,495	129	32,079

For the nine months ended September 30, 2018
Balances at December 31, 2017	$	18	46,622	(39,906)		(5,518)	29,391	194	30,801
Net income							4,389	38	4,427
Other comprehensive income						18			18
Dividends paid ($ 0.86 ) per common share							(1,009)		(1,009)
Repurchase of company common stock				(2,073)					(2,073)
Distributions to noncontrolling interests and other								(105)	(105)
Distributed under benefit plans			236						236
Changes in Accounting Principles*						58	(278)		(220)
Other							2	2	4
Balances at September 30, 2018	$	18	46,858	(41,979)		(5,442)	32,495	129	32,079
*Cumulative effect of the adoption of ASC Topic 606, “Revenue from Contracts with Customers,” and ASU No. 2016-01, “Recognition and Measurement of Financial Assets and Liabilities,” at January 1, 2018.

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Note 11—Guarantees

At September 30, 2019, 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.

APLNG Guarantees

At September 30, 2019, 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 2019 exchange rates:

During the third quarter of 2016, we issued a guarantee to facilitate the withdrawal of our pro-rata portion of the funds in a project finance reserve account. We estimate the remaining term of this guarantee is 11 years. Our maximum exposure under this guarantee is approximately $170 million and may become payable if an enforcement action is commenced by the project finance lenders against APLNG. At September 30, 2019, the carrying value of this guarantee was approximately $14 million. For additional information, see Note 6—Investments, Loans and Long-Term Receivables.

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 up to 23 years. Our maximum potential liability for future payments, or cost of volume delivery, under these guarantees is estimated to be $720 million ($1.3 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 26 years or the life of the venture. Our maximum potential amount of future payments related to these guarantees is approximately $130 million and would become payable if APLNG does not perform.

Other Guarantees

We have other guarantees with maximum future potential payment amounts totaling approximately $800 million, which consist primarily of guarantees of the residual value of leased office buildings, guarantees of the residual value of corporate aircraft, and a guarantee for our portion of a joint venture’s project finance reserve accounts. These guarantees have remaining terms of up to three 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.

In conjunction with the disposition of our two U.K. subsidiaries to Chrysaor E&P Limited, we will temporarily continue to support various guarantees and letters of credit which were provided for the benefit of entities that are now affiliates of Chrysaor E&P Limited. Our maximum potential payment exposure under these obligations is approximately $148 million. Chrysaor E&P Limited has agreed to fully indemnify ConocoPhillips for any losses suffered by us related to these obligations.

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

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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, 2019, 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, 2019, were approximately $30 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.

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 and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. With respect to income tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain.

Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes.

Environmental

We are subject to international, federal, state and local environmental laws and regulations. When we prepare our consolidated financial statements, we record accruals for environmental liabilities based on management’s best estimates, using all information that is available at the time. We measure estimates and base liabilities on currently available facts, existing technology, and presently enacted laws and regulations, taking into account stakeholder and business considerations. When measuring environmental liabilities, we also consider our prior experience in remediation of contaminated sites, other companies’ cleanup experience, and data released by the U.S. 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

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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. We have not reduced these accruals for possible insurance recoveries.

At September 30, 2019, our consolidated balance sheet included a total environmental accrual of $163 million, compared with $178 million at December 31, 2018, 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.

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, 2019, we had performance obligations secured by letters of credit of $221 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, ConocoPhillips was unable to reach agreement with respect to the empresa mixta structure mandated by the Venezuelan government’s Nationalization Decree. As a result, Venezuela’s national oil company, Petróleos de Venezuela, S.A. (PDVSA), or its affiliates, directly assumed control over ConocoPhillips’ interests in the Petrozuata and Hamaca heavy oil ventures and the offshore Corocoro development project. In response to this expropriation, ConocoPhillips initiated international arbitration on November 2, 2007, with the ICSID. On September 3, 2013, an ICSID arbitration tribunal held that Venezuela unlawfully expropriated ConocoPhillips’ significant oil investments in June 2007. On January 17, 2017, the Tribunal reconfirmed the decision that the expropriation was unlawful. In March 2019, the Tribunal unanimously ordered the

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government of Venezuela to pay ConocoPhillips approximately $8.7 billion in compensation for the government’s unlawful expropriation of the company’s investments in Venezuela in 2007. ConocoPhillips has filed a request for recognition of the award in several jurisdictions. On August 29, 2019, the ICSID Tribunal issued a decision rectifying the award and reducing it by approximately $227 million. The award now stands at $8.5 billion plus interest. The government of Venezuela has announced that it intends to seek annulment of the award.

In 2014, ConocoPhillips filed a separate and independent arbitration under the rules of the ICC against PDVSA under the contracts that had established the Petrozuata and Hamaca projects. The ICC Tribunal issued an award in April 2018, finding that PDVSA owed ConocoPhillips approximately $2 billion under their agreements in connection with the expropriation of the projects and other pre-expropriation fiscal measures. In August 2018, ConocoPhillips entered into a settlement with PDVSA to recover the full amount of this ICC award, plus interest through the payment period, including initial payments totaling approximately $500 million within a period of 90 days from the time of signing of the settlement agreement. The balance of the settlement is to be paid quarterly over a period of four and a half years. To date, ConocoPhillips has received approximately $754 million. Per the settlement, PDVSA recognized the ICC award as a judgment in various jurisdictions, and ConocoPhillips agreed to suspend its legal enforcement actions. The company is taking steps to secure payment of an outstanding amount of approximately $12 million from the initial payment obligation. ConocoPhillips has ensured that the settlement and any actions thereof meet all appropriate U.S. regulatory requirements, including those related to any applicable sanctions imposed by the U.S. against Venezuela.

In 2016, ConocoPhillips filed a separate and independent arbitration under the rules of the ICC against PDVSA under the contracts that had established the Corocoro project. On August 2, 2019, the ICC Tribunal awarded ConocoPhillips approximately $55 million under the Corocoro contracts.

In February 2017, the ICSID Tribunal unanimously awarded Burlington Resources, Inc., a wholly owned subsidiary of ConocoPhillips, $380 million for Ecuador’s unlawful expropriation of Burlington’s investment in Blocks 7 and 21, in breach of the U.S.-Ecuador Bilateral Investment Treaty. The tribunal also issued a separate decision finding Ecuador to be entitled to $42 million for environmental and infrastructure counterclaims. In December 2017, Burlington and Ecuador entered into a settlement agreement by which Ecuador paid Burlington $337 million in two installments. The first installment of $75 million was paid in December 2017, and the second installment of $262 million was paid in April 2018. The settlement included an offset for the counterclaims decision, of which Burlington is entitled to a contribution from Perenco Ecuador Limited, its co-venturer and consortium operator, pursuant to a joint and several liability provision in the JOA. In September 2019, a separate ICSID Tribunal issued an award in the Perenco arbitration, ordering Perenco to pay an additional $54 million to Ecuador for its environmental counterclaim. Burlington and Perenco will reconcile their shares of the environmental and infrastructure counterclaims according to their JOA participating interests, and we expect Burlington’s share will be immaterial.

In June 2017, FAR Ltd. initiated arbitration before the ICC against ConocoPhillips Senegal B.V., now Woodside Senegal B.V., in connection with the sale of ConocoPhillips Senegal B.V. to Woodside Energy Holdings (Senegal) Limited in 2016. This arbitration is ongoing.

In late 2017, ConocoPhillips (U.K.) Limited (CPUKL) initiated United Nations Commission on International Trade and Law (UNCITRAL) arbitration against Vietnam in accordance with the U.K.-Vietnam Bilateral Investment Treaty relating to a tax dispute arising from the 2012 sale of ConocoPhillips (U.K.) Cuu Long Limited and ConocoPhillips (U.K.) Gama Limited. While the arbitration remains pending, the parties reached an agreement in principle in October 2019 to amicably resolve this dispute.

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courts and appeals are pending. Lawsuits filed by other cities and counties in California and Washington are currently stayed pending resolution of the appeals brought by the Cities of San Francisco and Oakland to the U.S. Court of Appeals for the Ninth Circuit. Rulings in lawsuits filed in Maryland and Rhode Island, on the issue of whether the matters should proceed in state or federal court, are on appeal to the U.S. Court of Appeals for the Fourth Circuit and First Circuit, respectively.

Several Louisiana parishes and individual landowners have filed lawsuits against oil and gas companies, including ConocoPhillips, seeking compensatory damages in connection with historical oil and gas operations in Louisiana. All parish lawsuits are stayed pending an appeal to the Fifth Circuit Court of Appeals on the issue of whether they will proceed in federal or state court. ConocoPhillips will vigorously defend against these lawsuits.

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 NGLs.

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 NPNS exception are recognized upon settlement. We generally apply this exception to eligible crude contracts. We do not use hedge accounting for our commodity derivatives.

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

	Millions of Dollars
	September 30		December 31
	2019		2018
Assets
Prepaid expenses and other current assets	$	224	410
Other assets		39	40
Liabilities
Other accruals		236	370
Other liabilities and deferred credits		31	30

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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			Nine Months Ended
	September 30			September 30
	2019		2018	2019	2018

Sales and other operating revenues	$	4	(29)	68	(6)
Other income		3	3	4	12
Purchased commodities		(9)	18	(60)	15

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

	Open Position
	Long/(Short)
	September 30		December 31
	2019		2018
Commodity
Natural gas and power (billions of cubic feet equivalent)
Fixed price		(17)	(17)
Basis		(28)	(1)

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 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, and investments in equity securities. We do not elect hedge accounting on our foreign currency exchange derivatives.

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

	Millions of Dollars
	September 30		December 31
	2019		2018
Assets
Prepaid expenses and other current assets	$	1	7
Liabilities
Other accruals		4	6
Other liabilities and deferred credits		5	-

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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			Nine Months Ended
	September 30			September 30
	2019		2018	2019	2018

Foreign currency transaction (gains) losses	$	(24)	(2)	(3)	(5)

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

	In Millions
	Notional Currency
		September 30	December 31
	2019		2018
Foreign Currency Exchange Derivatives
Buy U.S. dollar, sell Norwegian krone	USD	18	-
Sell British pound, buy Euro	GBP	1	-
Sell U.S. dollar, buy British pound	USD	-	805
Sell British pound, buy other currencies*	GBP	-	21
Sell Canadian dollar, buy U.S. dollar	CAD	1,347	1,242
*Primarily euro and Norwegian krone.

In December 2017, we entered into foreign exchange zero cost collars buying the right to sell $1.25 billion CAD at $0.707 CAD and selling the right to buy $1.25 billion CAD at $0.842 CAD against the U.S. dollar. The collar expired during the second quarter of 2019 and we entered into new foreign currency exchange forward contracts to sell $1.35 billion CAD at $0.748 CAD against the U.S. dollar.

Financial Instruments

We invest excess cash in financial instruments with maturities based on our cash forecasts for the various currency pools we manage. The maturities of these investments may from time to time extend beyond 90 days. The types of financial instruments in which we currently invest include:

Time deposits: Interest bearing deposits placed with approved financial institutions.

Commercial paper: Unsecured promissory notes issued by a corporation, commercial bank or government agency purchased at a discount to mature at par.

Government or government agency obligations: Short-term securities issued by the U.S. government or U.S. government agencies.

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

	Millions of Dollars
	Carrying Amount
	Cash and Cash Equivalents			Short-Term Investments
	September 30		December 31	September 30	December 31
	2019		2018	2019	2018

Cash	$	651	876
Time deposits
Remaining maturities from 1 to 90 days		3,650	3,509	384	-
Remaining maturities more than 90 days				450	-
Commercial paper
Remaining maturities from 1 to 90 days		1,550	229	74	248
Government obligations
Remaining maturities from 1 to 90 days		1,342	1,301	-	-
	$	7,193	5,915	908	248

Credit Risk

Financial instruments potentially exposed to concentrations of credit risk consist primarily of cash equivalents, short-term investments, OTC derivative contracts and trade receivables. Our cash equivalents and short-term investments are placed in high-quality commercial paper, government 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, swaps and options, 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, 2019 and December 31, 2018, was $47 million and $62 million, respectively. For these instruments, no collateral was posted as of September 30, 2019 or December 31, 2018.

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If our credit rating had been downgraded below investment grade on September 30, 2019, we would be required to post $45 million of additional collateral, either with cash or letters of credit.

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 between levels during 2019 or 2018.

Recurring Fair Value Measurement

Financial assets and liabilities reported at fair value on a recurring basis primarily include our investment in Cenovus Energy shares and 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 1 also includes our investment in common shares of Cenovus Energy, which is valued using quotes for shares on the NYSE. 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, 2019					December 31, 2018
	Level 1		Level 2	Level 3	Total	Level 1	Level 2	Level 3	Total
Assets
Investment in Cenovus Energy	$	1,951	-	-	1,951	1,462	-	-	1,462
Commodity derivatives		153	86	24	263	236	181	33	450
Total assets	$	2,104	86	24	2,214	1,698	181	33	1,912

Liabilities
Commodity derivatives	$	169	82	16	267	225	145	30	400
Total liabilities	$	169	82	16	267	225	145	30	400

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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
				Amounts Subject to Right of Setoff
	Gross		Amounts Not		Gross	Net
	Amounts		Subject to	Gross	Amounts	Amounts	Cash	Net
	Recognized		Right of Setoff	Amounts	Offset	Presented	Collateral	Amounts
September 30, 2019
Assets	$	263	7	256	171	85	-	85
Liabilities		267	-	267	171	96	21	75

December 31, 2018
Assets	$	450	9	441	280	161	-	161
Liabilities		400	4	396	280	116	10	106


At September 30, 2019 and December 31, 2018, 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:

	Millions of Dollars
			Fair Value Measurements Using
	Fair Value		Level 1 Inputs	Level 2 Inputs	Before-Tax Loss
Equity method investments
March 31, 2019	$	171	171	-	60
May 31, 2019		30	-	30	95

During the first quarter of 2019, the carrying values of our equity method investments in the Golden Pass LNG Terminal and Golden Pass Pipeline were written down to fair value. The fair values were determined by negotiated selling prices. For additional information, see Note 5—Asset Dispositions.

During the second quarter of 2019, our equity method investment in MWCC was determined to have a fair value below its carrying value, and the impairment was considered to be other than temporary. For additional information, see Note 3—Variable Interest Entities.

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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 our consolidated balance sheet approximates fair value.

Accounts and notes receivable (including long-term and related parties): The carrying amount reported on our consolidated 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.

Investment in Cenovus Energy shares: See Note 7—Investment in Cenovus Energy, for a discussion of the carrying value and fair value of our investment in Cenovus Energy shares.

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 our consolidated 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
	2019		2018	2019	2018
Financial assets
Investment in Cenovus Energy	$	1,951	1,462	1,951	1,462
Commodity derivatives		92	170	92	170
Total loans and advances—related parties		336	468	336	468
Financial liabilities
Total debt, excluding finance (capital) leases		14,179	14,191	18,131	16,147
Commodity derivatives		75	110	75	110

Note 15—Non-Mineral Leases

The company primarily leases office buildings and drilling equipment, as well as ocean transport vessels, tugboats, corporate aircraft, and other facilities and equipment. Certain leases include escalation clauses for adjusting rental payments to reflect changes in price indices and other leases include payment provisions that vary based on the nature of usage of the leased asset. Additionally, the company has executed certain leases that provide it with the option to extend or renew the term of the lease, terminate the lease prior to the end of the lease term, or purchase the leased asset as of the end of the lease term. In other cases, the company has executed lease agreements that require it to guarantee the residual value of certain leased office buildings. For additional information about guarantees, see Note 11—Guarantees. There are no significant restrictions imposed on us by the lease agreements with regard to dividends, asset dispositions or borrowing ability.

Certain arrangements may contain both lease and non-lease components and we determine if an arrangement is or contains a lease at contract inception. Only the lease components of these contractual arrangements are subject to the provisions of ASC Topic 842, and any non-lease components are subject to other applicable accounting guidance; however,

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we have elected to adopt the optional practical expedient not to separate lease components apart from non-lease components for accounting purposes. This policy election has been adopted for each of the company’s leased asset classes existing as of the effective date and subject to the transition provisions of ASC Topic 842 and will be applied to all new or modified leases executed on or after January 1, 2019. For contractual arrangements executed in subsequent periods involving a new leased asset class, the company will determine at contract inception whether it will apply the optional practical expedient to the new leased asset class.

Leases are evaluated for classification as operating or finance leases at the commencement date of the lease and right-of-use assets and corresponding liabilities are recognized on our consolidated balance sheet based on the present value of future lease payments relating to the use of the underlying asset during the lease term. Future lease payments include variable lease payments that depend upon an index or rate using the index or rate at the commencement date and probable amounts owed under residual value guarantees. The amount of future lease payments may be increased to include additional payments related to lease extension, termination, and/or purchase options when the company has determined, at or subsequent to lease commencement, generally due to limited asset availability or operating commitments, it is reasonably certain of exercising such options. We use our incremental borrowing rate as the discount rate in determining the present value of future lease payments, unless the interest rate implicit in the lease arrangement is readily determinable. Lease payments that vary subsequent to the commencement date based on future usage levels, the nature of leased asset activities, or certain other contingencies are not included in the measurement of lease right-of-use assets and corresponding liabilities. We have elected not to record assets and liabilities on our consolidated balance sheet for lease arrangements with terms of 12 months or less.

We often enter into leasing arrangements acting in the capacity as operator for and/or on behalf of certain oil and gas joint ventures of undivided interests. If the lease arrangement can be legally enforced only against us as operator and there is no separate arrangement to sublease the underlying leased asset to our coventurers, we recognize at lease commencement a right-of-use asset and corresponding lease liability on our consolidated balance sheet on a gross basis. While we record lease costs on a gross basis in our consolidated income statement and statement of cash flows, such costs are offset by the reimbursement we receive from our coventurers for their share of the lease cost as the underlying leased asset is utilized in joint venture activities. As a result, lease cost is presented in our consolidated income statement and statement of cash flows on a proportional basis. If we are a nonoperating coventurer, we recognize a right-of-use asset and corresponding lease liability only if we were a specified contractual party to the lease arrangement and the arrangement could be legally enforced against us. In this circumstance, we would recognize both the right-of-use asset and corresponding lease liability on our consolidated balance sheet on a proportional basis consistent with our undivided interest ownership in the related joint venture.

The company has historically recorded certain finance leases executed by investee companies accounted for under the proportionate consolidation method of accounting on its consolidated balance sheet on a proportional basis consistent with its ownership interest in the investee company. In addition, the company has historically recorded finance lease assets and liabilities associated with certain oil and gas joint ventures on a proportional basis pursuant to accounting guidance applicable prior to January 1, 2019. As of December 31, 2018, $420 million of finance lease assets (net of accumulated DD&A) and $688 million of finance lease liabilities were recorded on our consolidated balance sheet associated with these leases. In accordance with the transition provisions of ASC Topic 842, and since we have elected to adopt the package of optional transition-related practical expedients, the historical accounting treatment for these leases has been carried forward and is subject to reconsideration upon the modification or other required reassessment of the arrangements prior to lease term expiration.

In connection with our adoption of ASC Topic 842, we have recorded on our consolidated balance sheet $57 million of operating leases executed by investee companies accounted for under the proportionate consolidation method of accounting on a proportional basis consistent with our ownership interest in the investee company.

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The following tables summarize the finance leases amounts that were reflected on our consolidated balance sheet as of December 31, 2018, the operating leases impact of adopting ASC Topic 842, and the right-of-use asset and lease liability balances reflected for both operating and finance leases on our consolidated balance sheet as of September 30, 2019:

		Millions of Dollars
		Carrying Amount
		Operating Leases		Finance Leases
Amounts recognized in line items in our Consolidated
Balance Sheet upon adoption of ASC Topic 842

Right-of-Use Assets
Properties, plants and equipment
Gross			$	1,044
Accumulated depreciation, depletion and amortization				(550)
Net properties, plants and equipment as of December 31, 2018			$	494

Adoption of ASC Topic 842 as of January 1, 2019	$	998

Lease Liabilities
Short-term debt			$	79
Long-term debt				698
Total finance leases debt as of December 31, 2018			$	777

Adoption of ASC Topic 842 as of January 1, 2019	$	998

Amounts recognized in line items in our Consolidated
Balance Sheet at September 30, 2019

Right-of-Use Assets
Properties, plants and equipment
Gross			$	1,069
Accumulated depreciation, depletion and amortization				(634)
Net properties, plants and equipment^*			$	435
Other assets^**	$	805

* Includes proportionately consolidated finance lease assets (net of accumulated depreciation, depletion and amortization) of $359 million. **As a result of the sale of two ConocoPhillips U.K. subsidiaries, right-of-use assets decreased approximately $0.2 billion in the third quarter of 2019. See Note 5–Asset Dispositions for additional information.

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		Millions of Dollars
		Carrying Amount
		Operating Leases		Finance Leases
Lease Liabilities
Short-term debt^*			$	86
Other accruals	$	249
Long-term debt^*				656
Other liabilities and deferred credits		556
Total lease liabilities^**	$	805		742

*Short-term debt and long-term debt include proportionately consolidated finance lease liabilities of $55 million and $595 million, respectively. **As a result of the sale of two ConocoPhillips U.K. subsidiaries, lease liabilities decreased approximately $0.2 billion in the third quarter of 2019. See Note 5–Asset Dispositions for additional information.

The following table summarizes our lease costs:
	Millions of Dollars
	Three Months Ended		Nine Months Ended
	September 30, 2019		September 30, 2019
Lease Cost^*
Operating lease cost	$	99		265
Finance lease cost
Amortization of right-of-use assets		27		84
Interest on lease liabilities		9		28
Short-term lease cost^**		26		57
Total lease cost^***	$	161		434

*The amounts presented in the table above have not been adjusted to reflect amounts recovered or reimbursed from oil and gas coventurers.

**Short-term leases are not recorded on our consolidated balance sheet. Our future short-term lease commitments amount to $72 million, of

which $41 million is related to leases whose terms have not yet commenced as of September 30, 2019.

***Variable lease cost and sublease income are immaterial for the periods presented and therefore are not included in the table above.

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The following table summarizes the lease terms and discount rates:
		September 30, 2019
Lease Term and Discount Rate
Weighted-average term (years)
Operating leases		5.77
Finance leases		8.91

Weighted-average discount rate (percent)
Operating leases		3.33
Finance leases		5.61


The following table summarizes other lease information:

		Millions of Dollars
		Nine Months Ended
		September 30, 2019
Other Information^*
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	152
Operating cash flows from finance leases		29
Financing cash flows from finance leases		59

Right-of-use assets obtained in exchange for operating lease liabilities	$	300
Right-of-use assets obtained in exchange for finance lease liabilities		26
*The amounts presented in the table above have not been adjusted to reflect amounts recovered or reimbursed from oil and gas coventurers. In addition, pursuant to other applicable accounting guidance, lease payments made in connection with preparing another asset for its intended use are reported in the "Cash Flows From Investing Activities" section of our consolidated statement of cash flows.


The following table summarizes future lease payments for operating and finance leases at September 30, 2019:

		Millions of Dollars
		Operating Leases	Finance Leases
Maturity of Lease Liabilities
2019	$	77	31
2020		252	120
2021		190	103
2022		105	102
2023		69	88
Remaining years		195	465
Total^*		888	909
Less: portion representing imputed interest		(83)	(167)
Total lease liabilities	$	805	742
*Future lease payments for operating and finance leases commencing on or after January 1, 2019, also include payments related to non-lease components in accordance with our election to adopt the optional practical expedient not to separate lease components apart from non-lease components for accounting purposes. In addition, future payments related to operating and finance leases proportionately consolidated by the company have been included in the table on a proportionate basis consistent with our respective ownership interest in the underlying investee company or oil and gas venture.

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At December 31, 2018, future undiscounted minimum rental payments due under noncancelable operating
leases pursuant to ASC Topic 840 were:

		Millions of Dollars

2019	$	248
2020		425
2021		136
2022		319
2023		54
Remaining years		212
Total		1,394
Less: income from subleases		(7)
Net minimum operating lease payments	$	1,387

At December 31, 2018, future minimum payments due under finance (capital) leases pursuant to
ASC Topic 840 were:

		Millions of Dollars

2019	$	118
2020		116
2021		100
2022		98
2023		87
Remaining years		453
Total		972
Less: portion representing imputed interest		(195)
Capital lease obligations	$	777

Note 16—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, 2018	$	(361)	(5,702)	(6,063)
Cumulative effect of adopting ASU No. 2018-02*		(40)	-	(40)
Other comprehensive income (loss)		(42)	491	449
September 30, 2019	$	(443)	(5,211)	(5,654)
*See Note 2—Changes in Accounting Principles for additional information.

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In the third quarter of 2019, we recognized $483 million of foreign currency translation adjustments related to the completion of our sale of two ConocoPhillips U.K. subsidiaries. For additional information related to this disposition, see Note 5—Asset Dispositions.

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

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

	Millions of Dollars
	Three Months Ended			Nine Months Ended
	September 30			September 30
	2019		2018	2019	2018

Defined benefit plans	$	36	17	66	155

The above amounts are included in the computation of net periodic benefit cost and are presented net of tax expense of $12 million and $6 million for the three months ended September 30, 2019 and September 30, 2018, respectively, and $22 million and $43 million for the nine-month periods ended September 30, 2019 and September 30, 2018, respectively. See Note 18—Employee Benefit Plans, for additional information.

Note 17—Cash Flow Information
	Millions of Dollars
	Nine Months Ended
	September 30
		2019	2018
Cash Payments
Interest	$	614	584
Income taxes		2,210	1,927

Net Sales (Purchases) of Short-Term Investments
Short-term investments purchased	$	(1,894)	(1,705)
Short-term investments sold		1,229	2,701
	$	(665)	996

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Note 18—Employee Benefit Plans

Pension and Postretirement Plans
	Millions of Dollars
	Pension Benefits					Other Benefits
	2019			2018		2019	2018
		U.S.	Int'l.	U.S.	Int'l.
Components of Net Periodic Benefit Cost
Three Months Ended September 30
Service cost	$	20	19	20	20	1	-
Interest cost		21	25	22	26	1	2
Expected return on plan assets		(18)	(34)	(22)	(38)	-	-
Amortization of prior service credit		-	-	-	(1)	(7)	(9)
Recognized net actuarial loss (gain)		13	7	10	9	(1)	-
Settlements		37	-	14	-	-	-
Curtailments		-	(1)	-	(1)	-	-
Net periodic benefit cost	$	73	16	44	15	(6)	(7)

Nine Months Ended September 30
Service cost	$	59	56	63	63	1	1
Interest cost		63	77	76	80	6	6
Expected return on plan assets		(54)	(104)	(91)	(118)	-	-
Amortization of prior service credit		-	(1)	-	(4)	(24)	(26)
Recognized net actuarial loss (gain)		39	23	41	27	(2)	(1)
Settlements		54	-	161	-	-	-
Curtailments		-	(1)	-	(1)	-	-
Net periodic benefit cost	$	161	50	250	47	(19)	(20)

The components of net periodic benefit cost, other than the service cost component, are included in the “Other expenses” line item on our consolidated income statement.

During the first nine months of 2019, we contributed $174 million to our domestic benefit plans and $429 million to our international benefit plans, including a $324 million contribution made in conjunction with the completion of our sale of two ConocoPhillips U.K. subsidiaries. In 2019, we expect to contribute approximately $220 million to our domestic qualified and nonqualified pension and postretirement benefit plans and $455 million to our international qualified and nonqualified pension and postretirement benefit plans.

During the three-month period ended September 30, 2019, lump-sum benefit payments exceeded the sum of service and interest costs for the fiscal year for the U.S. qualified pension plan and a U.S. nonqualified supplemental retirement plan. As a result, we recognized a proportionate share of prior actuarial losses from other comprehensive income as pension settlement expense of $37 million. 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 the U.S. nonqualified supplemental retirement plan were remeasured as of September 30, 2019. At the measurement date, the net pension liability increased by $108 million. This is primarily a result of a decrease in the discount rate from 4.30 percent at December 31, 2018 to 3.10 percent at September 30, 2019 for the U.S. qualified pension plan and from 4.05 percent at December 31, 2018 to 2.80 percent at September 30, 2019 for the U.S. nonqualified supplemental retirement plan, resulting in a corresponding decrease to other comprehensive income.

The sale of two ConocoPhillips U.K. subsidiaries completed during the third quarter of 2019 led to a significant reduction of future services of active employees in certain international pension plans, resulting in a curtailment. In conjunction with the recognition of the curtailment, the fair market values of pension plan

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assets were updated, the pension benefit obligation was remeasured, and the net pension asset decreased by $43 million, resulting in a corresponding decrease to other comprehensive income. This is primarily a result of a decrease in the discount rate from 2.90 percent at December 31, 2018 to 1.80 percent at September 30, 2019 offset by a decrease in the pension benefit obligation from curtailment.

Severance Accrual

The following table summarizes our severance accrual activity for the nine-month period ended September 30, 2019:

	Millions of Dollars

Balance at December 31, 2018	$	48
Accruals		(2)
Benefit payments		(22)
Foreign currency translation adjustments		(1)
Balance at September 30, 2019	$	23

Of the remaining balance at September 30, 2019, $6 million is classified as short term.

Note 19—Related Party Transactions

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

Significant transactions with our related parties were:

		Millions of Dollars
		Three Months Ended			Nine Months Ended
		September 30			September 30
		2019		2018	2019	2018

Operating revenues and other income		$	23	27	70	74
Purchases			-	25	38	74
Operating expenses and selling, general and administrative
	expenses		19	13	47	44
Net interest (income) expense*			(3)	(4)	(10)	(11)
*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.

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Note 20—Sales and Other Operating Revenues

Revenue from Contracts with Customers

The following table provides further disaggregation of our consolidated sales and other operating revenues:

	Millions of Dollars
	Three Months Ended			Nine Months Ended
	September 30			September 30
	2019		2018	2019	2018

Revenue from contracts with customers	$	6,240	7,546	19,932	20,834
Revenue from contracts outside the scope of ASC Topic 606
Physical contracts meeting the definition of a derivative		1,529	1,897	4,981	5,877
Financial derivative contracts		(13)	6	(54)	40
Consolidated sales and other operating revenues	$	7,756	9,449	24,859	26,751

Revenues from contracts outside the scope of ASC Topic 606 relate primarily to physical gas contracts at market prices which qualify as derivatives accounted for under ASC Topic 815, “Derivatives and Hedging,” and for which we have not elected NPNS. There is no significant difference in contractual terms or the policy for recognition of revenue from these contracts and those within the scope of ASC Topic 606. The following disaggregation of revenues is provided in conjunction with Note 21—Segment Disclosures and Related Information:

		Millions of Dollars
		Three Months Ended			Nine Months Ended
		September 30			September 30
		2019		2018	2019	2018
Revenue from Outside the Scope of ASC Topic 606
	by Segment
Lower 48		$	1,099	1,534	3,823	4,547
Canada			86	87	427	374
Europe and North Africa			344	276	731	956
Physical contracts meeting the definition of a derivative		$	1,529	1,897	4,981	5,877

		Millions of Dollars
		Three Months Ended			Nine Months Ended
		September 30			September 30
		2019		2018	2019	2018
Revenue from Outside the Scope of ASC Topic 606
	by Product
Crude oil		$	266	267	619	843
Natural gas			1,159	1,522	4,022	4,775
Other			104	108	340	259
Physical contracts meeting the definition of a derivative		$	1,529	1,897	4,981	5,877

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Practical Expedients

Typically, our commodity sales contracts are less than 12 months in duration; however, in certain specific cases may extend longer, which may be out to the end of field life. We have long-term commodity sales contracts which use prevailing market prices at the time of delivery, and under these contracts, the market-based variable consideration for each performance obligation (i.e., delivery of commodity) is allocated to each wholly unsatisfied performance obligation within the contract. Accordingly, we have applied the practical expedient allowed in ASC Topic 606 and do not disclose the aggregate amount of the transaction price allocated to performance obligations or when we expect to recognize revenues that are unsatisfied (or partially unsatisfied) as of the end of the reporting period.

Receivables and Contract Liabilities

Receivables from Contracts with Customers

At September 30, 2019, the “Accounts and notes receivable” line on our consolidated balance sheet, includes trade receivables of $2,566 million compared with $2,889 million at December 31, 2018, and includes both contracts with customers within the scope of ASC Topic 606 and those that are outside the scope of ASC Topic 606. We typically receive payment within 30 days or less (depending on the terms of the invoice) once delivery is made. Revenues that are outside the scope of ASC Topic 606 relate primarily to physical gas sales contracts at market prices for which we do not elect NPNS and are therefore accounted for as a derivative under ASC Topic 815. There is little distinction in the nature of the customer or credit quality of trade receivables associated with gas sold under contracts for which NPNS has not been elected compared to trade receivables where NPNS has been elected.

Contract Liabilities from Contracts with Customers

We have entered into contractual arrangements where we license our proprietary technology to customers related to the optimization process for operating LNG plants. The contracts typically provide for negotiated payments to be made at stated milestones. The payments are not directly related to our performance under the contract and are recorded as deferred revenue to be recognized as revenue when the customer can utilize and benefit from their right to use the license. Payments are received in installments over the construction period.

	Millions of Dollars
Contract Liabilities
At December 31, 2018	$	206
Contractual payments received		73
Revenue recognized		(199)
At September 30, 2019	$	80

Amounts Recognized in the Consolidated Balance Sheet at September 30, 2019
Noncurrent liabilities	$	80
	$	80

We expect to recognize the contract liabilities as of September 30, 2019, as revenue between 2021 and 2022.

Note 21—Segment Disclosures and Related Information

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs 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.

Corporate and Other represents income and 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.

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

Analysis of Results by Operating Segment
	Millions of Dollars
	Three Months Ended			Nine Months Ended
	September 30			September 30
		2019	2018	2019	2018
Sales and Other Operating Revenues
Alaska	$	1,296	1,493	4,129	4,281
Lower 48		3,728	4,543	11,690	12,347
Intersegment eliminations		(10)	(14)	(33)	(18)
Lower 48		3,718	4,529	11,657	12,329
Canada		633	735	2,173	2,436
Intersegment eliminations		(273)	(308)	(858)	(853)
Canada		360	427	1,315	1,583
Europe and North Africa		1,225	1,574	4,084	4,826
Asia Pacific and Middle East		1,085	1,348	3,458	3,570
Corporate and Other		72	78	216	162
Consolidated sales and other operating revenues	$	7,756	9,449	24,859	26,751

Sales and Other Operating Revenues by Geographic Location
United States	$	5,085	6,025	15,996	16,617
Australia		412	515	1,282	1,258
Canada		360	427	1,315	1,583
China		191	262	593	616
Indonesia		223	234	654	662
Libya		288	264	809	802
Malaysia		258	339	928	1,039
Norway		632	734	1,781	2,112
United Kingdom		305	574	1,494	1,911
Other foreign countries		2	75	7	151
Worldwide consolidated	$	7,756	9,449	24,859	26,751

Sales and Other Operating Revenues by Product
Crude Oil	$	4,612	5,277	14,006	14,503
Natural gas		1,799	2,503	6,717	7,593
Natural gas liquids		156	351	607	847
Other*		1,189	1,318	3,529	3,808
Consolidated sales and other operating revenues by product	$	7,756	9,449	24,859	26,751
*Includes LNG and bitumen.

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	Millions of Dollars
	Three Months Ended			Nine Months Ended
		September 30		September 30
		2019	2018	2019	2018
Net Income Attributable to ConocoPhillips
Alaska	$	306	427	1,152	1,369
Lower 48		26	513	425	1,231
Canada		51	34	273	2
Europe and North Africa		2,001	241	2,615	776
Asia Pacific and Middle East		613	577	1,655	1,504
Other International		73	316	285	267
Corporate and Other		(14)	(247)	64	(760)
Consolidated net income attributable to ConocoPhillips	$	3,056	1,861	6,469	4,389

	Millions of Dollars
	September 30		December 31
	2019		2018
Total Assets
Alaska	$	15,513	14,648
Lower 48		14,601	14,888
Canada		6,196	5,748
Europe and North Africa		7,941	9,883
Asia Pacific and Middle East		15,091	16,151
Other International		89	89
Corporate and Other		10,909	8,573
Consolidated total assets	$	70,340	69,980

Note 22—Income Taxes

Our effective tax rates for the three- and nine-month periods ended September 30, 2019, were 12 percent and 21 percent, respectively, compared with 36 percent and 39 percent for the same periods of 2018. The effective tax rate for the three- and nine-month periods ended September 30, 2019 is lower than the effective tax rate for the same periods of 2018 primarily due to the recognition of a U.S. capital loss benefit related to the disposition of two of our U.K. subsidiaries, the recognition of tax incentives in Malaysia, a reduction in our valuation allowance for 2019, and changes in our mix of income between higher and lower tax jurisdictions.

During the three- and nine-month periods ended September 30, 2019, we recognized a U.S. tax benefit of $28 million and $262 million, respectively, related to the recognition of a U.S. capital loss benefit on our U.K. entity disposition.

During the third quarter of 2019, we received final partner approval in the Malaysia Block G to claim certain deepwater tax credits. As a result, we recorded an income tax benefit of $164 million.

During the three- and nine-month periods ended September 30, 2019, our valuation allowance decreased by $32 million and $224 million, respectively, compared to increases of $16 million and $61 million for the same periods of 2018. The change to our valuation allowance between periods relates primarily to the decrease in the deferred tax asset related to the increase in the fair value measurement of our Cenovus Energy common shares as well as recognition and realization of deferred tax assets due to the disposition of the Greater Sunrise Fields.

For additional information on asset dispositions, see Note 5—Asset Dispositions.

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Note 23—New Accounting Standards

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. Entities are required to adopt ASU No. 2016-13 using a modified retrospective approach, subject to certain limited exceptions. The impact of adopting this ASU is not expected to be material to our financial statements.

Supplementary Information—Condensed Consolidating Financial Information

We have various cross guarantees among ConocoPhillips, ConocoPhillips Company and Burlington Resources LLC, with respect to publicly held debt securities. ConocoPhillips Company is 100 percent owned by ConocoPhillips. Burlington Resources LLC is an indirect, 100 percent owned subsidiary of ConocoPhillips Company. ConocoPhillips and/or ConocoPhillips Company have fully and unconditionally guaranteed the payment obligations of Burlington Resources LLC, 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 Burlington Resources LLC (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 December 2018, ConocoPhillips Canada Funding Company I’s guaranteed, publicly held debt securities were assumed by Burlington Resources LLC. The assumption did not significantly change the nature of the outstanding debt or the terms of the parental guarantees, which remain full and unconditional, as well as joint and several. The assumption did not impact our consolidated financial position, results of operations or cash flows. Financial information for ConocoPhillips Canada Funding Company I is presented in the “All Other Subsidiaries” column of our condensed consolidating financial information. The prior year comparative periods have been restated to reflect the current period condensed consolidating financial information presentation.

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

In April 2019, ConocoPhillips received a $1.7 billion return of earnings from ConocoPhillips Company to settle certain accumulated intercompany balances. This transaction had no impact on our consolidated financial statements.

In April 2019, ConocoPhillips Company received a $3.3 billion return of earnings from nonguarantor subsidiaries to settle certain accumulated intercompany balances. These transactions had no impact on our consolidated financial statements.

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		Millions of Dollars
		Three Months Ended September 30, 2019
Income Statement		ConocoPhillips	ConocoPhillips Company	Burlington Resources LLC	All Other Subsidiaries	Consolidating Adjustments	Total Consolidated

Revenues and Other Income
Sales and other operating revenues	$	-	3,493	-	4,263	-	7,756
Equity in earnings of affiliates		3,114	728	461	288	(4,301)	290
Gain (loss) on dispositions		-	2,695	-	(910)	-	1,785
Other income		-	136	2	124	-	262
Intercompany revenues		-	34	10	1,323	(1,367)	-
Total Revenues and Other Income		3,114	7,086	473	5,088	(5,668)	10,093

Costs and Expenses
Purchased commodities		-	3,078	-	884	(1,252)	2,710
Production and operating expenses		-	290	-	1,091	(50)	1,331
Selling, general and administrative expenses		1	60	-	26	-	87
Exploration expenses		-	295	-	65	-	360
Depreciation, depletion and amortization		-	159	-	1,407	-	1,566
Impairments		-	12	-	12	-	24
Taxes other than income taxes		-	28	-	209	-	237
Accretion on discounted liabilities		-	4	-	82	-	86
Interest and debt expense		72	109	34	34	(65)	184
Foreign currency transaction (gains) losses		-	(6)	-	(15)	-	(21)
Other expenses		-	35	-	1	-	36
Total Costs and Expenses		73	4,064	34	3,796	(1,367)	6,600
Income before income taxes		3,041	3,022	439	1,292	(4,301)	3,493
Income tax provision (benefit)		(15)	(92)	(5)	534	-	422
Net income		3,056	3,114	444	758	(4,301)	3,071
Less: net income attributable to noncontrolling interests		-	-	-	(15)	-	(15)
Net Income Attributable to ConocoPhillips	$	3,056	3,114	444	743	(4,301)	3,056

Comprehensive Income Attributable to ConocoPhillips	$	3,229	3,287	384	939	(4,610)	3,229


Income Statement		Three Months Ended September 30, 2018

Revenues and Other Income
Sales and other operating revenues	$	-	4,330	-	5,119	-	9,449
Equity in earnings of affiliates		1,903	2,166	481	294	(4,550)	294
Gain on dispositions		-	75	-	38	-	113
Other income (loss)		-	(61)	-	370	-	309
Intercompany revenues		9	34	15	1,597	(1,655)	-
Total Revenues and Other Income		1,912	6,544	496	7,418	(6,205)	10,165

Costs and Expenses
Purchased commodities		-	3,880	-	1,197	(1,547)	3,530
Production and operating expenses		-	298	-	1,084	(15)	1,367
Selling, general and administrative expenses		2	99	-	18	-	119
Exploration expenses		-	41	-	62	-	103
Depreciation, depletion and amortization		-	152	-	1,342	-	1,494
Impairments		-	1	-	43	-	44
Taxes other than income taxes		-	33	-	279	-	312
Accretion on discounted liabilities		-	4	-	85	-	89
Interest and debt expense		72	156	10	41	(93)	186
Foreign currency transaction (gains) losses		(12)	3	(42)	56	-	5
Other expenses		-	6	-	4	-	10
Total Costs and Expenses		62	4,673	(32)	4,211	(1,655)	7,259
Income before income taxes		1,850	1,871	528	3,207	(4,550)	2,906
Income tax provision (benefit)		(11)	(32)	(6)	1,082	-	1,033
Net income		1,861	1,903	534	2,125	(4,550)	1,873
Less: net income attributable to noncontrolling interests		-	-	-	(12)	-	(12)
Net Income Attributable to ConocoPhillips	$	1,861	1,903	534	2,113	(4,550)	1,861

Comprehensive Income Attributable to ConocoPhillips	$	2,056	2,098	612	2,277	(4,987)	2,056
See Notes to Consolidated Financial Statements.

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	Millions of Dollars
	Nine Months Ended September 30, 2019
Income Statement	ConocoPhillips		ConocoPhillips Company	Burlington Resources LLC	All Other Subsidiaries	Consolidating Adjustments	Total Consolidated

Revenues and Other Income
Sales and other operating revenues	$	-	10,961	-	13,898	-	24,859
Equity in earnings of affiliates		6,641	4,438	1,467	647	(12,542)	651
Gain (loss) on dispositions		-	2,700	-	(816)	-	1,884
Other income		1	688	3	444	-	1,136
Intercompany revenues		-	83	33	4,266	(4,382)	-
Total Revenues and Other Income		6,642	18,870	1,503	18,439	(16,924)	28,530

Costs and Expenses
Purchased commodities		-	9,699	-	3,134	(3,774)	9,059
Production and operating expenses		1	1,127	1	3,295	(404)	4,020
Selling, general and administrative expenses		7	272	-	95	(5)	369
Exploration expenses		-	389	-	203	-	592
Depreciation, depletion and amortization		-	443	-	4,159	-	4,602
Impairments		-	12	-	14	-	26
Taxes other than income taxes		-	107	-	599	-	706
Accretion on discounted liabilities		-	12	-	247	-	259
Interest and debt expense		211	401	100	69	(199)	582
Foreign currency transaction (gains) losses		-	23	-	(4)	-	19
Other expenses		-	60	-	(2)	-	58
Total Costs and Expenses		219	12,545	101	11,809	(4,382)	20,292
Income before income taxes		6,423	6,325	1,402	6,630	(12,542)	8,238
Income tax provision (benefit)		(46)	(316)	(14)	2,100	-	1,724
Net income		6,469	6,641	1,416	4,530	(12,542)	6,514
Less: net income attributable to noncontrolling interests		-	-	-	(45)	-	(45)
Net Income Attributable to ConocoPhillips	$	6,469	6,641	1,416	4,485	(12,542)	6,469

Comprehensive Income Attributable to ConocoPhillips	$	6,918	7,090	1,588	4,937	(13,615)	6,918


Income Statement	Nine Months Ended September 30, 2018

Revenues and Other Income
Sales and other operating revenues	$	-	11,774	-	14,977	-	26,751
Equity in earnings of affiliates		4,562	5,398	1,360	766	(11,319)	767
Gain on dispositions		-	78	-	97	-	175
Other income		-	230	-	443	-	673
Intercompany revenues		28	124	28	4,188	(4,368)	-
Total Revenues and Other Income		4,590	17,604	1,388	20,471	(15,687)	28,366

Costs and Expenses
Purchased commodities		-	10,571	-	3,758	(4,021)	10,308
Production and operating expenses		-	723	4	3,182	(58)	3,851
Selling, general and administrative expenses		7	254	-	80	(5)	336
Exploration expenses		-	132	-	135	-	267
Depreciation, depletion and amortization		-	427	-	3,917	-	4,344
Impairments		-	(9)	-	30	-	21
Taxes other than income taxes		-	111	-	657	-	768
Accretion on discounted liabilities		-	13	-	253	-	266
Interest and debt expense		219	456	35	121	(284)	547
Foreign currency transaction (gains) losses		22	(6)	38	(47)	-	7
Other expenses		-	348	6	(4)	-	350
Total Costs and Expenses		248	13,020	83	12,082	(4,368)	21,065
Income before income taxes		4,342	4,584	1,305	8,389	(11,319)	7,301
Income tax provision (benefit)		(47)	22	(25)	2,924	-	2,874
Net income		4,389	4,562	1,330	5,465	(11,319)	4,427
Less: net income attributable to noncontrolling interests		-	-	-	(38)	-	(38)
Net Income Attributable to ConocoPhillips	$	4,389	4,562	1,330	5,427	(11,319)	4,389

Comprehensive Income Attributable to ConocoPhillips	$	4,407	4,580	1,149	5,319	(11,048)	4,407
See Notes to Consolidated Financial Statements.

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	Millions of Dollars
	September 30, 2019
Balance Sheet	ConocoPhillips		ConocoPhillips Company	Burlington Resources LLC	All Other Subsidiaries	Consolidating Adjustments	Total Consolidated

Assets
Cash and cash equivalents	$	-	3,450	-	3,743	-	7,193
Short-term investments		-	400	-	508	-	908
Accounts and notes receivable		5	1,905	2	4,518	(2,814)	3,616
Investment in Cenovus Energy		-	1,951	-	-	-	1,951
Inventories		-	141	-	814	-	955
Prepaid expenses and other current assets		-	188	-	406	-	594
Total Current Assets		5	8,035	2	9,989	(2,814)	15,217
Investments, loans and long-term receivables*		35,374	50,862	16,169	16,666	(109,936)	9,135
Net properties, plants and equipment		-	3,822	-	39,992	-	43,814
Other assets		4	933	227	2,003	(993)	2,174
Total Assets	$	35,383	63,652	16,398	68,650	(113,743)	70,340

Liabilities and Stockholders’ Equity
Accounts payable	$	-	2,869	-	3,116	(2,814)	3,171
Short-term debt		(3)	3	14	107	-	121
Accrued income and other taxes		-	56	-	1,021	-	1,077
Employee benefit obligations		-	415	-	128	-	543
Other accruals		56	348	38	588	-	1,030
Total Current Liabilities		53	3,691	52	4,960	(2,814)	5,942
Long-term debt		3,793	6,671	2,132	2,203	-	14,799
Asset retirement obligations and accrued environmental costs		-	410	-	5,677	-	6,087
Deferred income taxes		-	-	-	5,686	(993)	4,693
Employee benefit obligations		-	1,373	-	413	-	1,786
Other liabilities and deferred credits*		2,949	9,598	989	9,169	(20,911)	1,794
Total Liabilities		6,795	21,743	3,173	28,108	(24,718)	35,101
Retained earnings		32,926	23,494	2,467	11,876	(31,279)	39,484
Other common stockholders’ equity		(4,338)	18,415	10,758	28,573	(57,746)	(4,338)
Noncontrolling interests		-	-	-	93	-	93
Total Liabilities and Stockholders’ Equity	$	35,383	63,652	16,398	68,650	(113,743)	70,340
*Includes intercompany loans.


Balance Sheet	December 31, 2018

Assets
Cash and cash equivalents	$	-	1,428	-	4,487	-	5,915
Short-term investments		-	-	-	248	-	248
Accounts and notes receivable		28	5,646	78	6,707	(8,392)	4,067
Investment in Cenovus Energy		-	1,462	-	-	-	1,462
Inventories		-	184	-	823	-	1,007
Prepaid expenses and other current assets		1	267	-	307	-	575
Total Current Assets		29	8,987	78	12,572	(8,392)	13,274
Investments, loans and long-term receivables*		29,942	47,062	15,199	16,926	(99,465)	9,664
Net properties, plants and equipment		-	4,367	-	41,796	(465)	45,698
Other assets		4	642	227	1,269	(798)	1,344
Total Assets	$	29,975	61,058	15,504	72,563	(109,120)	69,980

Liabilities and Stockholders’ Equity
Accounts payable	$	-	5,098	76	7,113	(8,392)	3,895
Short-term debt		(3)	12	13	99	(9)	112
Accrued income and other taxes		-	85	-	1,235	-	1,320
Employee benefit obligations		-	638	-	171	-	809
Other accruals		85	587	35	552	-	1,259
Total Current Liabilities		82	6,420	124	9,170	(8,401)	7,395
Long-term debt		3,791	7,151	2,143	2,249	(478)	14,856
Asset retirement obligations and accrued environmental costs		-	415	-	7,273	-	7,688
Deferred income taxes		-	-	-	5,819	(798)	5,021
Employee benefit obligations		-	1,340	-	424	-	1,764
Other liabilities and deferred credits*		725	9,277	839	8,126	(17,775)	1,192
Total Liabilities		4,598	24,603	3,106	33,061	(27,452)	37,916
Retained earnings		27,512	18,511	1,113	9,764	(22,890)	34,010
Other common stockholders’ equity		(2,135)	17,944	11,285	29,613	(58,778)	(2,071)
Noncontrolling interests		-	-	-	125	-	125
Total Liabilities and Stockholders’ Equity	$	29,975	61,058	15,504	72,563	(109,120)	69,980
*Includes intercompany loans. See Notes to Consolidated Financial Statements.

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	Millions of Dollars
	Nine Months Ended September 30, 2019
Statement of Cash Flows		ConocoPhillips	ConocoPhillips Company	Burlington Resources LLC	All Other Subsidiaries	Consolidating Adjustments	Total Consolidated

Cash Flows From Operating Activities
Net Cash Provided by (Used in) Operating Activities	$	1,486	6,408	(56)	6,662	(6,378)	8,122

Cash Flows From Investing Activities
Capital expenditures and investments		-	(2,308)	-	(4,329)	1,596	(5,041)
Working capital changes associated with investing activities		-	76	-	(59)	-	17
Proceeds from asset dispositions		-	2,732	763	1,026	(1,601)	2,920
Sales (purchases) of short-term investments		-	(400)	-	(265)	-	(665)
Long-term advances/loans—related parties		-	(810)	-	-	810	-
Collection of advances/loans—related parties		-	141	-	147	(161)	127
Intercompany cash management		2,224	(1,970)	56	(310)	-	-
Other		-	(149)	-	3	-	(146)
Net Cash Provided by (Used in) Investing Activities		2,224	(2,688)	819	(3,787)	644	(2,788)

Cash Flows From Financing Activities
Issuance of debt		-	-	-	810	(810)	-
Repayment of debt		-	(21)	-	(199)	161	(59)
Issuance of company common stock		75	-	-	-	(114)	(39)
Repurchase of company common stock		(2,751)	-	-	-	-	(2,751)
Dividends paid		(1,037)	(1,660)	-	(4,832)	6,492	(1,037)
Other		3	-	(763)	682	5	(73)
Net Cash Used in Financing Activities		(3,710)	(1,681)	(763)	(3,539)	5,734	(3,959)

Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash		-	(12)	-	(56)	-	(68)

Net Change in Cash, Cash Equivalents and Restricted Cash		-	2,027	-	(720)	-	1,307
Cash, cash equivalents and restricted cash at beginning of period*		-	1,428	-	4,723	-	6,151
Cash, Cash Equivalents and Restricted Cash at End of Period	$	-	3,455	-	4,003	-	7,458


Statement of Cash Flows	Nine Months Ended September 30, 2018*

Cash Flows From Operating Activities
Net Cash Provided by (Used in) Operating Activities	$	(169)	791	818	8,762	(1,051)	9,151

Cash Flows From Investing Activities
Capital expenditures and investments		-	(771)	(12)	(4,369)	19	(5,133)
Working capital changes associated with investing activities		-	(77)	-	20	-	(57)
Proceeds from asset dispositions		2,500	379	1,926	199	(4,610)	394
Sales of short-term investments		-	-	-	996	-	996
Long-term advances/loans—related parties		-	(36)	(117)	(10)	163	-
Collection of advances/loans—related parties		-	3,432	-	129	(3,442)	119
Intercompany cash management		514	3,426	(2,564)	(1,376)	-	-
Other		-	-	-	16	-	16
Net Cash Provided by (Used in) Investing Activities		3,014	6,353	(767)	(4,395)	(7,870)	(3,665)

Cash Flows From Financing Activities
Issuance of debt		-	10	-	153	(163)	-
Repayment of debt		-	(4,865)	(53)	(3,494)	3,442	(4,970)
Issuance of company common stock		234	-	-	-	(113)	121
Repurchase of company common stock		(2,073)	-	-	-	-	(2,073)
Dividends paid		(1,009)	-	-	(1,217)	1,217	(1,009)
Other		3	(2,511)	-	(2,141)	4,538	(111)
Net Cash Used in Financing Activities		(2,845)	(7,366)	(53)	(6,699)	8,921	(8,042)

Effect of Exchange Rate Changes on Cash and Cash Equivalents		-	4	-	(44)	-	(40)

Net Change in Cash and Cash Equivalents		-	(218)	(2)	(2,376)	-	(2,596)
Cash and cash equivalents at beginning of period		-	234	3	6,299	-	6,536
Cash and Cash Equivalents at End of Period	$	-	16	1	3,923	-	3,940
*Revised to reclassify certain intercompany distributions from Operating Activities to 'Proceeds from asset dispositions' within Investing Activities based on the nature of the distributions. There was no impact to Total Consolidated results.
See Notes to Consolidated Financial Statements.

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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 63.

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 an independent E&P company with operations and activities in 17 countries. Our diverse, low cost of supply portfolio includes resource-rich unconventional plays in North America; conventional assets in North America, Europe and North Africa, Asia and Australia; LNG developments; oil sands assets in Canada; and an inventory of global conventional and unconventional exploration prospects. Headquartered in Houston, Texas, at September 30, 2019, we employed approximately 10,400 people worldwide and had total assets of $70 billion.

Overview

Global oil prices have been volatile in 2019. Optimism about worldwide economic growth during the first quarter turned to pessimism in the second quarter as trade disputes dampened growth forecasts. At the end of the second quarter, geopolitical tensions in the Middle East, threatening the safe passage of supertankers carrying crude oil through the Persian Gulf, revived oil prices. Worldwide economic growth concerns returned in the third quarter to depress prices, only to be reversed again by geopolitical tensions in the Middle East, as oilfield infrastructure in Saudi Arabia was attacked, temporarily disrupting approximately five percent of the world’s oil supply. Our business strategy anticipates prices will remain volatile and is designed to be resilient in lower price environments, with significant upside during periods of higher prices. Portfolio diversification and optimization, debt reduction and disciplined capital investment have positioned our company to navigate through periods of volatile energy prices.

Our value proposition principles, namely, to focus on returns, maintain financial strength, grow our dividend and pursue disciplined growth, are being executed in accordance with our priorities for allocating cash flows from the business. These priorities are: invest capital at a level that maintains flat production volumes and pays our existing dividend; grow our existing dividend; maintain debt at a level we believe is sufficient to maintain a strong investment grade credit rating through price cycles; repurchase shares to provide value to our shareholders; and invest capital to grow our cash from operations. We believe our commitment to our value proposition, as evidenced by the results discussed below, positions us for success in an environment of price uncertainty and ongoing volatility.

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In the third quarter of 2019, we continued to deliver on our priorities. We achieved production growth of 8 percent on a total BOE basis compared with the third quarter of 2018, with higher value oil volumes growing 12 percent. Cash provided by operating activities of $2.3 billion exceeded capital expenditures and investments of $1.7 billion. After distributing $0.3 billion of dividends to shareholders and repurchasing $0.7 billion of our common stock, we ended the quarter with cash, cash equivalents and restricted cash totaling $7.5 billion and $0.9 billion of short-term investments. In July, we announced an increase to our expected full-year 2019 share repurchases to $3.5 billion, an increase of $0.5 billion from previously stated plans. In October, we announced an increase to our quarterly dividend of 38 percent to $0.42 per share and announced planned 2020 share buybacks of $3 billion.

Operationally, we remain focused on safely executing our operating plan and staying attentive to our costs. Production excluding Libya was 1,322 MBOED in the third quarter of 2019, an increase of 98 MBOED compared with the same period of 2018. Our underlying production, which excludes Libya and the net volume impact from closed dispositions and acquisitions of 58 MBOED in 2019 and 43 MBOED in 2018, increased 83 MBOED compared with the third quarter of 2018. Production on a per debt-adjusted share basis grew by 6 percent compared with the third quarter of 2018. Production per debt-adjusted share is calculated on an underlying production basis using ending period debt divided by ending share price plus ending shares outstanding. We believe production per debt-adjusted share is useful to investors as it provides a consistent view of production on a total equity basis by converting debt to equity and allows for comparison across peer companies.

In the second quarter of 2019, we completed the sale of our 30 percent interest in the Greater Sunrise Fields to the government of Timor-Leste for $350 million, and recognized an after-tax gain of $52 million. No production or reserve impacts were associated with the sale. The Greater Sunrise Fields were included in our Asia Pacific and Middle East segment.

In April 2019, we entered into an agreement to sell two ConocoPhillips U.K. subsidiaries to Chrysaor E&P Limited for $2.675 billion plus interest and customary adjustments, with an effective date of January 1, 2018. On September 30, 2019, we completed the sale for proceeds of $2.2 billion. In the nine-month period of 2019, we recorded a $1.8 billion before-tax and $2.1 billion after-tax gain associated with this transaction. Together the subsidiaries sold indirectly held our exploration and production assets in the U.K. In the first nine months of 2019, production associated with the U.K. assets sold was 68 MBOED. Year-end 2018 reserves associated with the U.K. assets sold was 99 MMBOE. Results of operations for the U.K. are reported within our Europe and North Africa segment.

In October 2019, we announced an agreement to sell the subsidiaries that hold our Australia-West assets and operations to Santos for $1.39 billion, plus customary adjustments, with an effective date of January 1, 2019. In addition, we will receive a payment of $75 million upon final investment decision of the Barossa development project. These subsidiaries hold our 37.5 percent interest in the Barossa Project and Caldita Field, our 56.9 percent interest in the Darwin LNG Facility and Bayu-Undan Field, our 40 percent interest in the Greater Poseidon Fields, and our 50 percent interest in the Athena Field. This transaction is expected to be completed in the first quarter of 2020, subject to regulatory approvals and other specific conditions precedent. In the first nine months of 2019, production associated with the Australia-West assets to be sold was 49 MBOED. Year-end 2018 reserves associated with these assets were 38 MMBOE. We will retain our 37.5 percent interest in the Australia Pacific LNG project and operatorship of that project’s LNG facility. Results of operations for the subsidiaries to be sold are reported within our Asia Pacific and Middle East segment.

For additional information on our dispositions, see Note 5—Asset Dispositions in the Notes to Consolidated Financial Statements. Proceeds from these transactions will be used for general corporate purposes.

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Business Environment

Dated Brent crude oil prices have ranged from a low of $53 per barrel to a high of $75 per barrel in the first nine months of 2019. The energy industry has periodically experienced volatility due to fluctuating supply-and-demand conditions. Commodity prices are the most significant factor impacting our profitability and 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, environmental laws, tax regulations, governmental policies and weather-related disruptions. Our strategy is to create value through price cycles by delivering on the financial and operational priorities that underpin our value proposition.

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 WTI crude oil at Cushing, Dated Brent crude oil and Henry Hub natural gas:

MarketChart

Brent crude oil prices averaged $61.94 per barrel in the third quarter of 2019, a decrease of 18 percent compared with $75.27 per barrel in the third quarter of 2018, and a decrease of 10 percent compared with $68.82 per barrel in the second quarter of 2019. Crude oil prices for WTI averaged $56.44 per barrel in the third quarter of 2019, a decrease of 19 percent compared with $69.71 per barrel in the third quarter of 2018, and a decrease of 6 percent compared with $59.80 per barrel in the second quarter of 2019. Prices decreased relative to the same period of 2018 primarily due to macroeconomic demand concerns.

Henry Hub natural gas prices averaged $2.23 per MMBTU in the third quarter of 2019, a decrease of 23 percent compared with $2.91 per MMBTU in the third quarter of 2018, and a decrease of 16 percent compared with $2.64 per MMBTU in the second quarter of 2019. Prices decreased relative to the same period of 2018 due to seasonally mild weather reducing demand and growing U.S. natural gas production.

Our realized bitumen price decreased from $34.15 per barrel in the third quarter of 2018 to $32.54 per barrel in the same period of 2019, primarily due to declines in the WTI benchmark price, which were partly offset by improvements in the WCS differential to WTI at Hardisty and lower diluent costs. Compared with $37.20 per barrel in the second quarter of 2019, our third quarter 2019 realized bitumen price decreased due to reductions

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in the WTI benchmark price and a widening WCS differential to WTI at Hardisty, partly offset by lower diluent costs. The WCS differential to WTI at Hardisty decreased in the third quarter of 2019, compared to the second quarter of 2019, due to increased production attributable to easing of curtailment levels in Canada and upstream producers returning from turnarounds.

Our total average realized price was $47.07 per BOE in the third quarter of 2019, compared with $57.71 per BOE in the third quarter of 2018 due to lower realized oil, natural gas and NGL prices.

Key Operating and Financial Summary

Significant items during the third quarter of 2019 included the following:

Cash provided by operating activities was $2.3 billion and exceeded capital expenditures and investments of $1.7 billion.

Repurchased $0.75 billion of shares and paid $0.34 billion in dividends.

Third-quarter production excluding Libya of 1,322 MBOED; year-over-year underlying production grew 7 percent overall and 6 percent on a debt-adjusted share basis.

Increased production from the Lower 48 Big 3 unconventional plays—Eagle Ford, Bakken and Delaware—by 21 percent year-over-year.

Executed turnarounds in Alaska, Malaysia and Norway.

Ended the quarter with cash, cash equivalents and restricted cash totaling $7.5 billion and short-term investments of $0.9 billion.

Completed the U.K. divestiture, generating $2.2 billion in proceeds.

Completed the previously announced Alaska Nuna discovery acreage acquisition for approximately $0.1 billion.

Announced the Australia-West divestiture agreement for $1.4 billion, plus customary closing adjustments, subject to regulatory and other approvals.

Announced a 38 percent increase in the quarterly dividend to $0.42 per share, and $3 billion in planned 2020 share repurchases.

Discontinued exploration activities in the Central Louisiana Austin Chalk trend and recognized $186 million after-tax in leasehold impairment and dry hole expenses.

Outlook

Production and Capital Guidance

Fourth-quarter 2019 production is expected to be 1,265 to 1,305 MBOED. The guidance excludes Libya and reflects the impacts from the completed U.K. disposition.

Capital expenditures are expected to be $6.3 billion versus our original budget of $6.1 billion, attributable to additional appraisal drilling in Alaska and the addition of a drilling rig in the Eagle Ford at mid-year 2019. This guidance excludes approximately $0.3 billion for opportunistic acquisitions completed or announced and results in total capital expenditures and investments of $6.6 billion. Guidance also excludes obligations under the previously announced PSC extension awarded by the Government of Indonesia.

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RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three- and nine-month periods ended September 30, 2019, is based on a comparison with the corresponding periods of 2018.

Consolidated Results

A summary of the company's net income attributable to ConocoPhillips by business segment follows:


	Millions of Dollars
	Three Months Ended			Nine Months Ended
	September 30			September 30
		2019	2018	2019	2018

Alaska	$	306	427	1,152	1,369
Lower 48		26	513	425	1,231
Canada		51	34	273	2
Europe and North Africa		2,001	241	2,615	776
Asia Pacific and Middle East		613	577	1,655	1,504
Other International		73	316	285	267
Corporate and Other		(14)	(247)	64	(760)
Net income attributable to ConocoPhillips	$	3,056	1,861	6,469	4,389

Net income attributable to ConocoPhillips in the third quarter of 2019 increased $1.2 billion. Earnings were positively impacted by:

A $1.8 billion after-tax gain associated with the completion of the sale of two ConocoPhillips U.K. subsidiaries to Chrysaor E&P Limited.

Higher crude oil sales volumes due to growth in the Lower 48 unconventionals and from the acquisition of incremental interests in operated assets in Alaska during the fourth quarter of 2018.

An unrealized gain of $116 million after-tax on our Cenovus Energy (CVE) common shares in the third quarter of 2019, and the absence of a $57 million after-tax unrealized loss on those shares in the third quarter of 2018.

A $164 million income tax benefit related to deepwater incentive tax credits recognized for Malaysia Block G.

Third quarter 2019 net income increases were partly offset by:

Lower realized crude oil, NGL and natural gas prices.

Lower other income related to our settlement agreement with Petróleos de Venezuela, S.A. (PDVSA) of $239 million after-tax.

Higher exploration expenses, primarily in our Lower 48 segment due to $186 million after-tax of leasehold impairment and dry hole costs associated with our decision to discontinue exploration activities in the Central Louisiana Austin Chalk trend.

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Net income attributable to ConocoPhillips in the nine-month period ended September 30, 2019, increased

$2.1 billion. Earnings were positively impacted by:

A $2.1 billion after-tax gain associated with the completion of the sale of two ConocoPhillips U.K. subsidiaries to Chrysaor E&P Limited.

Higher crude oil sales volumes due to growth in the Lower 48 unconventionals and from the acquisition of incremental interests in operated assets in Alaska during the second and fourth quarters of 2018.

A $328 million higher after-tax unrealized gain on our Cenovus Energy common shares reflected in other income.

The absence of premiums on debt retirements totaling $195 million after-tax.

A $164 million income tax benefit related to deepwater incentive tax credits recognized for Malaysia Block G.

Increased earnings of $115 million related to the settlement of certain tax disputes and enhanced oil recovery credits.

Earnings in the nine-month period ended September 30, 2019, were negatively impacted by:

Lower realized crude oil, NGL and natural gas prices.

Higher exploration expenses, primarily in our Lower 48 segment due to $194 million after-tax of leasehold impairment and dry hole costs associated with our decision to discontinue exploration activities in the Central Louisiana Austin Chalk trend.

Higher DD&A associated with increased production volumes, primarily in the Lower 48 and Alaska.

Higher production and operating expenses associated with increased production volumes, primarily in the Lower 48 and Alaska.

Lower equity in earnings of affiliates, primarily due to impairments of equity method investments in our Lower 48 segment of $120 million after-tax in 2019.

The absence of a $109 million after-tax benefit from an accrual reduction related to a transportation cost ruling by the FERC.

See the “Segment Results” section for additional information.

Income Statement Analysis

Sales and other operating revenues for the three- and nine-month periods of 2019 decreased 18 percent and 7 percent, respectively, mainly due to lower realized crude oil, NGL and natural gas prices, partly offset by higher sales volumes of crude oil in the Lower 48 and Alaska.

Equity in earnings of affiliates for the nine-month period of 2019 decreased $116 million, primarily due to impairments of equity method investments in our Lower 48 segment of $95 million in the second quarter of 2019 and $60 million in the first quarter of 2019. For more information, see Note 5—Asset Dispositions and Note 3—Variable Interest Entities, in the Notes to Consolidated Financial Statements.

Gain on dispositions increased $1.7 billion in the three- and nine-month periods of 2019, primarily due to a $1.8 billion before-tax gain associated with the completion of the sale of two ConocoPhillips U.K. subsidiaries to Chrysaor E&P Limited. For additional information related to our U.K. disposition, see Note 5—Asset Dispositions.

Other income for the nine-month period of 2019 increased $463 million, primarily due to a $302 million before-tax higher unrealized gain on our Cenovus Energy common shares.

For discussion of our Cenovus Energy shares, see Note 7—Investment in Cenovus Energy, in the Notes to Consolidated Financial Statements.

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Purchased commodities for the three- and nine-month periods of 2019 decreased 23 percent and 12 percent, respectively, primarily due to lower crude oil and natural gas prices.

Production and operating expenses for the nine-month period of 2019 increased $169 million or 4 percent, mainly due to costs associated with higher production volumes, primarily in the Lower 48 and Alaska.

Exploration expenses for the three- and nine-month periods of 2019 increased $257 million and $325 million, respectively, primarily due to higher leasehold impairment and dry hole costs in our Lower 48 segment. In the third quarter of 2019, we recorded a $141 million before-tax leasehold impairment expense due to our decision to discontinue exploration activities in the Central Louisiana Austin Chalk trend. Dry hole costs in the Lower 48 increased by approximately $120 million before-tax in the third quarter, primarily related to this play.

DD&A for the three- and nine-month periods of 2019 increased 5 percent and 6 percent, respectively, mainly due to higher production volumes in the Lower 48 and Alaska, partly offset by lower expense in our Europe and North Africa segment due to the cessation of DD&A for our disposed U.K. assets. We ceased DD&A for our disposed U.K. subsidiaries in the second quarter of 2019 when these assets became held-for-sale. For more information regarding the completed U.K. divestiture, see Note 5—Asset Dispositions.

Other expenses decreased $292 million in the nine-month period of 2019, primarily due to the absence of a $206 million before-tax expense for premiums on early debt retirements and lower pension settlement expense.

See Note 22—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our income tax provision and effective tax rate.

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Summary Operating Statistics

		Three Months Ended			Nine Months Ended
		September 30			September 30
		2019		2018	2019	2018
Average Net Production
Crude oil (MBD)			710	635	709	632
Natural gas liquids (MBD)			114	106	114	102
Bitumen (MBD)			63	65	59	65
Natural gas (MMCFD)*			2,871	2,732	2,826	2,771

Total Production (MBOED)			1,366	1,261	1,353	1,261

		Dollars Per Unit
Average Sales Prices
Crude oil (per barrel)		$	59.57	73.05	61.26	69.74
Natural gas liquids (per barrel)			15.59	35.14	20.24	31.31
Bitumen (per barrel)			32.54	34.15	34.11	26.46
Natural gas (per thousand cubic feet)			4.74	5.81	5.17	5.37

		Millions of Dollars
Exploration Expenses
General administrative, geological and geophysical,
	lease rental, and other	$	67	75	231	203
Leasehold impairment			154	16	196	36
Dry holes			139	12	165	28
		$	360	103	592	267
*Represents quantities available for sale and excludes gas equivalent of natural gas liquids included above.

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on a worldwide basis. During the third quarter of 2019, our operations were producing in the U.S., Norway, the U.K., Canada, Australia, Timor-Leste, Indonesia, China, Malaysia, Qatar and Libya.

Total production increased 105 MBOED or 8 percent in the third quarter of 2019, primarily due to:

New wells online in the Lower 48.

An increased interest in the Greater Kuparuk Area (GKA) of Alaska following an acquisition closed in the fourth quarter of 2018.

Higher production in Norway due to drilling activity and the startup of Aasta Hansteen in December 2018.

Lower unplanned downtime, primarily in the U.K. and Malaysia.

The increase in third quarter 2019 production was partly offset by:

Normal field decline.

Disposition impacts from non-core asset sales, primarily in the Lower 48.

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Total production increased 92 MBOED or 7 percent in the nine-month period of 2019, primarily due to:

New wells online in the Lower 48.

An increased interest in the Western North Slope (WNS) and GKA of Alaska following acquisitions closed in 2018.

Higher production in Norway due to drilling activity and the startup of Aasta Hansteen in December 2018.

The increase in production during the nine-month period of 2019 was partly offset by:

Normal field decline.

Disposition impacts from non-core asset sales, primarily in the Lower 48.

Planned turnarounds at the Greater Ekofisk Area in Norway, QG3 in Qatar and Surmont in Canada.

Production excluding Libya was 1,322 MBOED in the third quarter of 2019, an increase of 98 MBOED or 8 percent. Our underlying production, which excludes Libya and the net volume impact from closed dispositions and acquisitions of 58 MBOED in 2019 and 43 MBOED in 2018, increased 83 MBOED or 7 percent.

Production excluding Libya was 1,310 MBOED in the nine-month period of 2019, an increase of 90 MBOED or 7 percent. Our underlying production, which excludes Libya and the net volume impact from closed dispositions and acquisitions of 67 MBOED in 2019 and 47 MBOED in 2018, increased 69 MBOED or 6 percent.

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Segment Results

Alaska

	Three Months Ended			Nine Months Ended
	September 30			September 30
	2019		2018	2019	2018

Net Income Attributable to ConocoPhillips
(millions of dollars)	$	306	427	1,152	1,369

Average Net Production
Crude oil (MBD)		190	152	200	165
Natural gas liquids (MBD)		11	12	15	14
Natural gas (MMCFD)		6	5	7	6

Total Production (MBOED)		202	165	216	180

Average Sales Prices
Crude oil (dollars per barrel)	$	62.78	76.47	64.34	72.44
Natural gas (dollars per thousand cubic feet)		3.01	2.52	3.23	2.51

The Alaska segment primarily explores for, produces, transports and markets crude oil, NGLs and natural gas. As of September 30, 2019, Alaska contributed 24 percent of our worldwide liquids production and less than 1 percent of our worldwide natural gas production.

Earnings from Alaska for the third quarter of 2019 decreased $121 million, primarily because of lower realized crude oil prices, the absence of enhanced oil recovery credits, and higher DD&A and production and operating expenses associated with higher production volumes. Partly offsetting the decrease in earnings was higher crude oil sales volumes due to an increased interest in GKA following an acquisition completed in the fourth quarter of 2018.

Earnings from Alaska for the nine-month period of 2019 decreased $217 million, primarily because of lower realized crude oil prices, higher production and operating expenses and DD&A associated with higher production volumes, and lower enhanced oil recovery credits. Partly offsetting the decrease in earnings were higher crude oil sales volumes due to increased interests in the WNS and GKA following acquisitions completed in 2018.

Average production increased 37 MBOED in the third quarter of 2019, primarily due to acquiring incremental interests in GKA during the fourth quarter of 2018, which increased production 35 MBOED in the current period. Production also increased in the third quarter due to lower planned downtime, partly offset by normal field decline. Average production increased 36 MBOED in the nine-month period of 2019, primarily due to acquiring incremental interests in WNS during the second quarter of 2018 and incremental interests in GKA during the fourth quarter of 2018. These acquisitions increased production by a combined 41 MBOED in the nine-month period of 2019. Production also increased in the nine-month period of 2019 due to lower planned downtime. These production increases were partly offset by normal field decline.

Acquisition Update

In the third quarter of 2019, we completed the previously announced Nuna discovery acreage acquisition for approximately $100 million, expanding the Kuparuk River Unit and leveraging legacy infrastructure.

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Lower 48

	Three Months Ended			Nine Months Ended
	September 30			September 30
	2019		2018	2019	2018

Net Income Attributable to ConocoPhillips
(millions of dollars)	$	26	513	425	1,231

Average Net Production
Crude oil (MBD)		277	240	264	218
Natural gas liquids (MBD)		84	73	80	68
Natural gas (MMCFD)		649	608	604	589

Total Production (MBOED)		469	414	444	384

Average Sales Prices
Crude oil (dollars per barrel)	$	54.38	67.73	55.63	65.38
Natural gas liquids (dollars per barrel)		13.04	32.17	17.03	28.06
Natural gas (dollars per thousand cubic feet)		1.80	2.80	2.19	2.63

The Lower 48 segment consists of operations located in the U.S. Lower 48 states, as well as producing properties in the Gulf of Mexico. As of September 30, 2019, the Lower 48 contributed 39 percent of our worldwide liquids production and 21 percent of our worldwide natural gas production.

Earnings from the Lower 48 for the third quarter of 2019 decreased $487 million, primarily due to lower realized crude oil, NGL and natural gas prices and higher exploration expenses associated with our decision to discontinue exploration activities in the Central Louisiana Austin Chalk trend. In the third quarter, we recorded approximately $186 million after-tax of exploration expenses related to this play comprised of leasehold impairment and dry hole costs. Additionally, earnings were lower in the third quarter due to higher DD&A, primarily associated with increased production volumes. Partly offsetting the decrease in earnings was increased crude oil and NGL volumes in the Eagle Ford, Bakken and Delaware in the Permian Basin.

In the nine-month period of 2019, earnings decreased $806 million, primarily due to lower realized crude oil, NGL and natural gas prices; higher DD&A associated with increased production volumes; higher exploration expenses, primarily due to $194 million of leasehold impairment and dry hole costs associated with our decision to discontinue exploration activities in the Central Louisiana Austin Chalk trend; higher production and operating expenses associated with higher production volumes; and lower earnings in equity affiliates. Earnings in equity affiliates were reduced due to a $47 million after-tax impairment associated with the sale of our interests in the Golden Pass LNG Terminal and Golden Pass Pipeline in the first quarter of 2019 and a $73 million after-tax impairment associated with our investment in the MWCC in the second quarter of 2019. Partly offsetting the decrease in earnings was increased crude oil and NGL volumes in the Eagle Ford, Bakken and Delaware in the Permian Basin.

For additional information related to our impairment of MWCC, see Note 3—Variable Interest Entities in the Notes to Consolidated Financial Statements. For more information related to the sale of our interests in Golden Pass LNG Terminal and Golden Pass Pipeline, see Note 5—Asset Dispositions and Note 14—Fair Value Measurement in the Notes to Consolidated Financial Statements.

Total average production increased 55 MBOED and 60 MBOED in the three- and nine-month periods of 2019, respectively, primarily due to new production from unconventional assets in Eagle Ford, Bakken and Delaware in the Permian Basin, partly offset by normal field decline. Additionally, production decreased by 12 MBOED in the three- and nine-month periods of 2019 due to non-core dispositions in 2018.

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Asset Disposition Update

In January 2019, we entered into agreements to sell our 12.4 percent ownership interests in the Golden Pass LNG Terminal and Golden Pass Pipeline. We have also entered into agreements to amend our contractual obligations for retaining use of the facilities. As a result of entering into these agreements, we recognized a before-tax impairment of $60 million in the first quarter of 2019 which is included in the “Equity in earnings of affiliates” line on our consolidated income statement. In the second quarter of 2019, we completed the sale.

Canada

	Three Months Ended			Nine Months Ended
	September 30			September 30
	2019		2018	2019	2018

Net Income Attributable to ConocoPhillips
(millions of dollars)	$	51	34	273	2

Average Net Production
Crude oil (MBD)		1	1	1	1
Natural gas liquids (MBD)		-	2	-	1
Bitumen (MBD)		63	65	59	65
Natural gas (MMCFD)		9	12	8	13

Total Production (MBOED)		66	70	62	69

Average Sales Prices
Bitumen (dollars per barrel)*		32.54	34.15	34.11	26.46
*Average prices for sales of bitumen excludes additional value realized from the purchase and sale of third-party volumes for optimization of our pipeline capacity between Canada and the U.S. Gulf Coast.

Our Canadian operations mainly consist of an oil sands development in the Athabasca Region of northeastern Alberta and a liquids-rich unconventional play in western Canada. As of September 30, 2019, Canada contributed 7 percent of our worldwide liquids production and less than 1 percent of our worldwide natural gas production.

Earnings from Canada increased $17 million in the third quarter of 2019, primarily because of lower DD&A expense due to lower rates from reserve additions and lower production and operating expenses. Earnings increased $271 million in the nine-month period of 2019, mainly due to higher realized bitumen prices; lower DD&A expense due to lower rates from reserve additions; a $68 million tax benefit primarily comprised of a previously unrecognizable tax basis related to a tax settlement; lower production and operating expenses; and a $25 million tax benefit due to a four year phased four percent reduction in Alberta’s corporate income tax rate. Partly offsetting the nine-month period increase in earnings were lower sales volumes due to a planned turnaround at Surmont and a mandated production curtailment imposed by the Alberta government in January 2019.

Total average production decreased 4 MBOED in the three-month period of 2019, primarily due to a mandated production curtailment imposed by the Alberta government which impacted production in the third quarter by 3 MBOED. The curtailment measure, which began in January 2019, is intended to strengthen the WCS differential to WTI at Hardisty and is currently anticipated to expire in December 2020. Total average production decreased 7 MBOED in the nine-month period of 2019, primarily due to a 4 MBOED impact from a planned turnaround in Surmont and 3 MBOED related to a mandated production curtailment.

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Europe and North Africa

	Three Months Ended			Nine Months Ended
	September 30			September 30
	2019		2018	2019	2018

Net Income Attributable to ConocoPhillips
(millions of dollars)	$	2,001	241	2,615	776

Average Net Production
Crude oil (MBD)		149	145	143	147
Natural gas liquids (MBD)		7	8	7	8
Natural gas (MMCFD)		473	452	531	502

Total Production (MBOED)		235	229	238	240

Average Sales Prices
Crude oil (dollars per barrel)	$	63.47	76.54	65.17	71.38
Natural gas liquids (dollars per barrel)		23.20	38.80	28.65	37.75
Natural gas (dollars per thousand cubic feet)		3.60	7.62	4.98	7.40

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, 2019, our Europe and North Africa operations contributed 17 percent of our worldwide liquids production and 19 percent of our worldwide natural gas production.

Earnings for Europe and North Africa increased by approximately $1.8 billion in the three- and nine-month periods of 2019, primarily due to a gain associated with the completion of the sale of two ConocoPhillips U.K. subsidiaries to Chrysaor E&P Limited. The nine-month period gain associated with this sale was approximately $2.1 billion after-tax, comprised of a U.S. tax benefit of $234 million, recorded in the second quarter, related to the recognition of U.S. tax basis in our U.K. subsidiaries to be sold, and an additional $1.8 billion upon completion of the sale in the third quarter recognized as gain on dispositions. Earnings in both periods also increased due to the cessation of DD&A in the second quarter of 2019 for our disposed U.K. subsidiaries when these assets became held-for-sale. Partly offsetting the increase in earnings were lower realized natural gas and crude oil prices.

Average production increased 3 percent in the third quarter of 2019, primarily due to new wells online in Norway and the U.K., including the rampup of production at Aasta Hansteen in Norway, and lower unplanned downtime. Partly offsetting this increase in production, was normal field decline and planned turnarounds in the U.K. and Norway. Average production decreased 1 percent in the nine-month period of 2019.

Asset Disposition Update

In April 2019, we entered into an agreement to sell two ConocoPhillips U.K. subsidiaries to Chrysaor E&P Limited for $2.675 billion plus interest and customary adjustments, with an effective date of January 1, 2018. On September 30, 2019, we completed the sale for proceeds of $2.2 billion. In the nine-month period of 2019, we recorded a $1.8 billion before-tax and $2.1 billion after-tax gain associated with this transaction. Together the subsidiaries sold indirectly held our exploration and production assets in the U.K. In the first nine months of 2019, production associated with the U.K. assets sold was 68 MBOED. Year-end 2018 reserves associated with the U.K. assets sold were 99 MMBOE. For additional information, see Note 5—Asset Dispositions in the Notes to Consolidated Financial Statements.

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Asia Pacific and Middle East

		Three Months Ended			Nine Months Ended
		September 30			September 30
		2019		2018	2019	2018

Net Income Attributable to ConocoPhillips
	(millions of dollars)	$	613	577	1,655	1,504

Average Net Production
Crude oil (MBD)
	Consolidated operations		79	84	88	87
	Equity affiliates		14	13	13	14
	Total crude oil		93	97	101	101

Natural gas liquids (MBD)
	Consolidated operations		4	3	4	3
	Equity affiliates		8	8	8	8
	Total natural gas liquids		12	11	12	11

Natural gas (MMCFD)
	Consolidated operations		658	630	633	617
	Equity affiliates		1,076	1,025	1,043	1,044
	Total natural gas		1,734	1,655	1,676	1,661

Total Production (MBOED)			394	383	393	388

Average Sales Prices
Crude oil (dollars per barrel)
	Consolidated operations	$	62.01	74.78	64.75	71.98
	Equity affiliates		59.91	76.62	61.23	73.00
	Total crude oil		61.69	75.02	64.28	72.13
Natural gas liquids (dollars per barrel)
	Consolidated operations		30.13	52.30	38.13	48.15
	Equity affiliates		30.18	49.71	36.49	45.74
	Total natural gas liquids		30.17	50.71	37.04	46.48
Natural gas (dollars per thousand cubic feet)
	Consolidated operations		5.78	6.53	6.01	5.88
	Equity affiliates		6.40	6.35	6.48	5.70
	Total natural gas		6.17	6.42	6.31	5.76

The Asia Pacific and Middle East segment has operations in China, Indonesia, Malaysia, Australia, Timor-Leste and Qatar. As of September 30, 2019, Asia Pacific and Middle East contributed 13 percent of our worldwide liquids production and 60 percent of our worldwide natural gas production.

Earnings increased $36 million in the third quarter of 2019, primarily due to a $164 million income tax benefit related to deepwater incentive tax credits from the Malaysia Block G, partly offset by lower realized crude oil, NGL and natural gas prices, and lower crude oil and LNG sales volumes. Earnings increased $151 million in the nine-month period of 2019, primarily due to a $164 million income tax benefit related to deepwater incentive tax credits from the Malaysia Block G, higher realized LNG prices, and a $52 million after-tax gain on disposition of our interest in the Greater Sunrise Fields. Partly offsetting this increase in earnings were lower realized crude oil prices and lower LNG sales volumes.

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Average production increased 11 MBOED in the third quarter of 2019, primarily due to new production from Malaysia, including first oil from Gumusut Phase 2; new wells online in China; and lower unplanned downtime. Partly offsetting this production increase was normal field decline. In the nine-month period of 2019, average production increased 1 percent.

Asset Dispositions Update

In the second quarter of 2019, we recognized an after-tax gain of $52 million upon completion of the sale of our 30 percent interest in the Greater Sunrise Fields to the government of Timor-Leste for $350 million. No production or reserve impacts were associated with the sale.

In October 2019, we announced an agreement to sell the subsidiaries that hold our Australia-West assets and operations to Santos for $1.39 billion, plus customary adjustments, with an effective date of January 1, 2019. In addition, we will receive a payment of $75 million upon final investment decision of the Barossa development project. These subsidiaries hold our 37.5 percent interest in the Barossa Project and Caldita Field, our 56.9 percent interest in the Darwin LNG Facility and Bayu-Undan Field, our 40 percent interest in the Greater Poseidon Fields, and our 50 percent interest in the Athena Field. This transaction is expected to be completed in the first quarter of 2020, subject to regulatory approvals and other specific conditions precedent. In the first nine months of 2019, production associated with the Australia-West assets to be sold was 49 MBOED. Year-end 2018 reserves associated with these assets were 38 MMBOE. We will retain our 37.5 percent interest in the Australia Pacific LNG project and operatorship of that project’s LNG facility.

See Note 5—Asset Dispositions in the Notes to Consolidated Financial Statements, for additional information related to these dispositions.

Other International

	Three Months Ended			Nine Months Ended
	September 30			September 30
	2019		2018	2019	2018

Net Income Attributable to ConocoPhillips
(millions of dollars)	$	73	316	285	267

The Other International segment consists of exploration activities in Colombia, Chile and Argentina.

Earnings from our Other International operations decreased $243 million in the third quarter of 2019, primarily due to $239 million less after-tax other income related to a settlement award with PDVSA associated with prior operations in Venezuela. See Note 12—Contingencies and Commitments in the Notes to Consolidated Financial Statements, for additional information.

Exploration Update

In July 2019, we entered into an agreement with Wintershall Dea to jointly develop the Aguada Federal and Bandurria Norte blocks in the central Argentine province of Neuquén. As part of the transaction, we will acquire a 45 percent interest in the Aguada Federal Block situated in the Neuquén Basin, Wintershall Dea will retain a 45 percent interest as operator, and the remaining 10 percent interest will be held by Gas y Petroleo del Neuquen S.A. (GyP). In the nearby Bandurria Norte Block, we will acquire a 50 percent interest, with Wintershall Dea retaining the other 50 percent as operator. This transaction is expected to close in 2019, subject to approval by the relevant authorities.

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Corporate and Other

	Millions of Dollars
	Three Months Ended			Nine Months Ended
	September 30			September 30
	2019		2018	2019	2018
Net Income (Loss) Attributable to ConocoPhillips
Net interest	$	(123)	(174)	(450)	(508)
Corporate general and administrative expenses		(34)	(36)	(148)	(139)
Technology		43	64	129	117
Other		100	(101)	533	(230)
	$	(14)	(247)	64	(760)

Net interest consists of interest and financing expense, net of interest income and capitalized interest. Net interest decreased by $51 million in the third quarter of 2019, primarily due the settlement of certain tax disputes and higher interest income. In the nine-month period of 2019, net interest decreased by $58 million, primarily due to lower interest from the settlement of certain tax disputes, partly offset by higher interest from the absence of an accrual reduction related to a transportation cost ruling by the FERC.

Corporate G&A expenses include compensation programs and staff costs. These expenses decreased by $2 million and increased by $9 million in the three- and nine-month periods of 2019, respectively, primarily due to costs associated with certain compensation programs.

Technology includes our investment in new technologies or businesses, as well as licensing revenues. Activities are focused on both conventional and tight oil reservoirs, shale gas, heavy oil, oil sands, enhanced oil recovery, and LNG. Earnings from Technology decreased $21 million and increased $12 million in the three- and nine-month periods of 2019, respectively, primarily due to changes in licensing revenues recognized between periods.

The category “Other” includes certain foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation, other costs not directly associated with an operating segment, premiums incurred on the early retirement of debt, unrealized holding gains or losses on equity securities, and pension settlement expense. “Other” increased by $201 million in the third quarter of 2019, primarily due to an unrealized gain of $116 million after-tax on our CVE common shares in the third quarter of 2019, and the absence of a $57 million after-tax unrealized loss on those shares in the third quarter of 2018. In the nine-month period of 2019, “Other” increased by $763 million primarily due to a $328 million larger after-tax unrealized gain on our Cenovus Energy common shares, the absence of $195 million after-tax related to premiums on early retirement of debt, and lower pension settlement expense.

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CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators
		Millions of Dollars
	September 30			December 31
		2019		2018

Short-term debt	$	121		112
Total debt		14,920		14,968
Total equity		35,239		32,064
Percent of total debt to capital*		30	%	32
Percent of floating-rate debt to total debt		5	%	5
*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, our commercial paper and credit facility programs, and our ability to sell securities using our shelf registration statement. During the first nine months of 2019, the primary uses of our available cash were $5,041 million to support our ongoing capital expenditures and investments program, $2,751 million to repurchase common stock, and $1,037 million to pay dividends. During the nine-month period, our cash, cash equivalents and restricted cash increased by $1,307 million to $7,458 million.

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 $8,122 million for the first nine months of 2019, compared with $9,151 million for the corresponding period of 2018. The decrease is primarily due to lower prices and a pension contribution made in conjunction with the sale of two U.K. subsidiaries, partially offset by higher volumes.

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 NGLs. 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.

To maintain or grow our production volumes, we must continue to add to our proved reserve base. As we undertake cash prioritization efforts, our reserve replacement efforts could be delayed thus limiting our ability to replace depleted reserves.

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Investing Activities

Proceeds from asset sales for the first nine months of 2019 were $2,920 million compared with $394 million for the corresponding period of 2018.

In the nine-month period of 2019, we completed the sale of several assets including our 30 percent interest in the Greater Sunrise Fields for $350 million and $77 million of contingent payments from Cenovus Energy. In the third quarter of 2019, we completed the sale of two ConocoPhillips U.K. subsidiaries to Chrysaor E&P Limited for $2.2 billion.

In October 2019, we announced an agreement to sell the subsidiaries that hold our Australia-West assets and operations to Santos for $1.39 billion, plus customary adjustments. In addition, we will receive a payment of $75 million upon final investment decision of the Barossa development project. The transaction is subject to regulatory approval and other specific conditions precedent and is expected to be completed in the first quarter of 2020.

In the first nine months of 2018, we completed the sale of several properties in the Lower 48 for proceeds of $317 million and received $64 million of contingent payments from Cenovus Energy.

See Note 5—Asset Dispositions in the Notes to Consolidated Financial Statements for additional information.

Commercial Paper and Credit Facilities

We have a revolving credit facility totaling $6.0 billion, expiring in May 2023. 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 program. 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.

The revolving credit facility supports the ConocoPhillips Company $6.0 billion commercial paper program, which is primarily a funding source for short-term working capital needs. Commercial paper maturities are generally limited to 90 days.

We had no commercial paper outstanding at September 30, 2019 or December 31, 2018. We had no direct outstanding borrowings or letters of credit under the revolving credit facility at September 30, 2019 or December 31, 2018. Since we had no commercial paper outstanding and had issued no letters of credit, we had access to $6.0 billion in borrowing capacity under our revolving credit facility at September 30, 2019.

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, 2019 and December 31, 2018, we had direct bank letters of credit of $221 million and $323 million, respectively, which secured performance obligations related to various purchase commitments incident to the ordinary conduct of business. In the event of 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. SEC under which we have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.

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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, 2019, was $15 billion, unchanged from December 31, 2018.

On January 30, 2019, we announced a quarterly dividend of $0.305 per share. The dividend was paid on March 1, 2019, to stockholders of record at the close of business on February 11, 2019. On May 1, 2019, we announced a quarterly dividend of $0.305 per share. The dividend was paid on June 3, 2019, to stockholders of record at the close of business on May 13, 2019. On July 11, 2019, we announced a quarterly dividend of $0.305 per share. The dividend was paid on September 3, 2019, to stockholders of record at the close of business on July 22, 2019. On October 7, 2019, we announced a 38 percent increase in the quarterly dividend to $0.42 per share. The dividend is payable on December 2, 2019, to stockholders of record at the close of business on October 17, 2019.

In late 2016, we initiated our current share repurchase program. As of July 12, 2018, we had announced a total authorization to repurchase $15 billion of our common stock. We repurchased $3 billion in 2017 and $3 billion in 2018. Of the remaining authorization, we expect to repurchase $3.5 billion in 2019 and $3 billion in 2020. Whether we undertake these additional repurchases is ultimately subject to numerous considerations, market conditions and other factors. See the “Our ability to declare and pay dividends and repurchase shares is subject to certain considerations” section in Risk Factors on pages 20-21 of our 2018 Annual Report on Form 10-K for additional information. Since our share repurchase program began in November 2016, we have repurchased 156 million shares at a cost of $8.9 billion through September 30, 2019.

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Capital Expenditures

	Millions of Dollars
	Nine Months Ended
	September 30
		2019	2018

Alaska	$	1,207	1,034
Lower 48		2,613	2,475
Canada		315	318
Europe and North Africa		537	678
Asia Pacific and Middle East		322	493
Other International		1	6
Corporate and Other		46	129
Capital expenditures and investments	$	5,041	5,133

During the first nine months of 2019, capital expenditures and investments supported key exploration and development programs, primarily:

Development, appraisal and exploration activities in the Lower 48, including Eagle Ford, Delaware in the Permian Basin, and Bakken.

Appraisal and development activities in Alaska related to the Western North Slope; development activities in the Greater Kuparuk Area and the Greater Prudhoe Area; leasehold acquisition in the Greater Kuparuk Area.

Development activities across assets in Norway and the U.K.

Optimization of oil sands development and appraisal activities in liquids-rich plays in Canada.

Continued development in China, Malaysia, Australia, and Indonesia.

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.

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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 and Tax 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.

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 65–67 of our 2018 Annual Report on Form 10-K.

We occasionally receive requests for information or notices of potential liability from the 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, 2019, there were 15 sites around the United States in which we were identified as a potentially responsible party under CERCLA and comparable state laws.

At September 30, 2019, our balance sheet included a total environmental accrual of $163 million, compared with $178 million at December 31, 2018, 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

Continuing political and social attention to the issue of global climate change has resulted in a broad range of proposed or promulgated state, national and international laws focusing on 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 and U.S. Department of Transportation’s joint promulgation of a Final Rule on April 1, 2010, that triggered 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.

Colorado’s HB-19 1261, approved May 30, 2019, introducing statewide goals to reduce 2025 GHG emissions by at least 26 percent, 2030 GHG emissions by at least 50 percent, and 2050 GHG emissions by at least 90 percent of the levels of GHG emissions that existed in 2005.

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 67–69 of our 2018 Annual Report on Form 10-K.

In December 2018, we became a Founding Member of the Climate Leadership Council (CLC), an international policy institute founded in collaboration with business and environmental interests to develop a carbon dividend plan. Participation in the CLC provides another opportunity for ongoing dialogue about carbon pricing and framing the issues in alignment with our public policy principles. We also belong to and fund Americans For Carbon Dividends, the education and advocacy branch of the CLC.

In 2017 and 2018, cities, counties, and a state government in California, New York, Washington, Rhode Island and Maryland, as well as the Pacific Coast Federation of Fishermen’s Association, Inc., have filed lawsuits against oil and gas companies, including ConocoPhillips, seeking compensatory damages and equitable relief to abate alleged climate change impacts. ConocoPhillips is vigorously defending against these lawsuits. The lawsuits brought by the Cities of San Francisco, Oakland and New York have been dismissed by the district courts and appeals are pending. Lawsuits filed by other cities and counties in California and Washington are currently stayed pending resolution of the appeals brought by the Cities of San Francisco and Oakland to the U.S. Court of Appeals for the Ninth Circuit. Rulings in lawsuits filed in Maryland and Rhode Island, on the issue of whether the matters should proceed in state or federal court, are on appeal to the U.S. Court of Appeals for the Fourth Circuit and First Circuit, respectively.

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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 NGLs prices, including a prolonged decline in these prices relative to historical or future expected levels.

The impact of significant declines in prices for crude oil, bitumen, natural gas, LNG and NGLs, 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.

Reductions in reserves replacement rates, whether as a result of the 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 E&P 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 NGLs.

Inability to timely obtain or maintain permits, including those necessary for construction, drilling and/or development, 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 complete construction of, announced and future exploration and production and LNG development in a timely manner (if at all) or on budget.

Potential disruption or interruption of our operations due to accidents, extraordinary weather events, civil unrest, political events, war, terrorism, cyber attacks, and information technology failures, constraints or disruptions.

Changes in international monetary conditions and foreign currency exchange rate fluctuations.

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Changes in international trade relationships, including the imposition of trade restrictions or tariffs relating to crude oil, bitumen, natural gas, LNG, NGLs and any materials or products (such as aluminum and steel) used in the operation of our business.

Substantial investment in and development use of, competing or 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 or our failure to comply with applicable laws and regulations.

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 NGLs pricing, regulation or taxation; the impact of and uncertainty surrounding the U.K.’s decision to withdraw from the EU; 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, including changes resulting from the implementation and interpretation of the Tax Cuts and Jobs Act.

Competition and consolidation in the oil and gas E&P industry.

Any limitations on our access to capital or increase in our cost of capital, including as a result of illiquidity or uncertainty in domestic or international financial markets.

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

Potential failure to obtain, or delays in obtaining, any necessary regulatory approvals for asset dispositions or acquisitions, or that such approvals may require modification to the terms of the transactions or the operation of our remaining business.

Potential disruption of our operations as a result of asset dispositions or acquisitions, including the diversion of management time and attention.

Our inability to deploy the net proceeds from any asset dispositions we undertake in the manner and timeframe we currently anticipate, if at all.

Our inability to liquidate the common stock issued to us by Cenovus Energy as part of our sale of certain assets in western Canada at prices we deem acceptable, or at all.

The operation and financing of our joint ventures.

The ability of our customers and other contractual counterparties to satisfy their obligations to us, including our ability to collect payments when due from the government of Venezuela or PDVSA.

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

The factors generally described in Item 1A—Risk Factors in our 2018 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, 2019, does not differ materially from that discussed under Item 7A in our 2018 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, 2019, with the participation of our management, our Chairman and Chief Executive Officer (principal executive officer) and our Executive Vice President and Chief Financial Officer

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(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 and Chief Financial Officer concluded our disclosure controls and procedures were operating effectively as of September 30, 2019.

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

PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

There are no new material legal proceedings or material developments with respect to matters previously disclosed in Item 3 of our 2018 Annual Report on Form 10-K.

Item 1A. RISK FACTORS

There have been no material changes from the risk factors disclosed in Item 1A of our 2018 Annual Report on Form 10-K.

Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Issuer Purchases of Equity Securities

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

July 1-31, 2019		4,273,085		$	60.38	4,273,085	$	6,615
August 1-31, 2019		4,792,186			53.76	4,792,186		6,358
September 1-30, 2019		4,128,552			56.73	4,128,552		6,124
		13,193,823		$	56.83	13,193,823
*There were no repurchases of common stock from company employees in connection with the company's broad-based employee incentive plans.

On November 10, 2016, we announced plans to purchase up to $3 billion of our common stock through 2019. On March 29, 2017, we announced plans to repurchase an additional $3 billion of common stock through 2019. On July 12, 2018, we announced an authorization of an additional $9 billion for share repurchases at any time or from time to time (whether before, on or after December 31, 2019) bringing the total program authorization to $15 billion. As of September 30, 2019, approximately $6.1 billion remained available for purchase under the program. Acquisitions for the share repurchase program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Repurchases may be increased, decreased or discontinued at any time without prior notice. Shares of stock repurchased under the plan are held as treasury shares. See the “Our ability to declare and pay dividends and repurchase shares is subject to certain considerations” section in Risk Factors on pages 20–21 of our 2018 Annual Report on Form 10-K.

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Item 6. EXHIBITS


10.1*	Form of Key Employee Award Terms and Conditions, as part of the ConocoPhillips Targeted Variable Long Term Incentive Program, granted under the 2014 Omnibus Stock and Performance and Incentive Plan of ConocoPhillips, dated September 23, 2019.

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*	Inline XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

101.SCH*	Inline XBRL Schema Document.

101.CAL*	Inline XBRL Calculation Linkbase Document.

101.LAB*	Inline XBRL Labels Linkbase Document.

101.PRE*	Inline XBRL Presentation Linkbase Document.

101.DEF*	Inline XBRL Definition Linkbase Document.

104*	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

* 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/ Catherine A. Brooks
	Catherine A. Brooks Vice President and Controller (Chief Accounting and Duly Authorized Officer)

October 31, 2019