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 ~~(gains) losses from~~collar expired during the second quarter of 2019 and we entered into new foreign currency exchange ~~derivatives incurred, and~~forward contracts to sell $1.35 billion CAD at $0.748 CAD against the ~~line item where they appear on our consolidated income statement were:~~U.S. dollar.

   Millions of Dollars
   Three Months Ended
September 30 Nine Months Ended
September 30
   2018 2017 2018 2017


Foreign currency transaction (gains) losses
   $ (2 ) (1 ) (5 ) 2

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

   In Millions
Notional Currency

September 30
2018
   December 31
2017


Foreign Currency Exchange Derivatives

Sell U.S. dollar, buy other currencies*
   USD    1,258    —
Sell British pound, buy euro
   GBP    23    1
Sell Canadian dollar, buy U.S. dollar
   CAD    1,230    1,225

*Primarily British pound.

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 in 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 ofon 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
   2018    2017    2018    2017




Cash
   $ 511    948
Time deposits

Remaining maturities from 1 to 90 days
   2,966    5,004    104    821
Commercial paper

Remaining maturities from 1 to 90 days
   239    373    771    978
Remaining maturities from 91 to 180 days
   —    —    —    74

   $ 3,716    6,325    875    1,873

	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,~~over-the-counter~~ ~~(OTC)~~ 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, ~~2018~~2019 and December 31, ~~2017,~~2018, was ~~$44~~$47 million and ~~$55~~$62 million, respectively. For these instruments, no0 collateral was posted as of September 30, ~~2018~~2019 or December 31, ~~2017.~~ 2018.

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If our credit rating had been downgraded below investment grade on September 30, ~~2018,~~2019, we would be required to post ~~$44~~$45 million of additional collateral, either with cash or letters of credit.

Note ~~15—~~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. ~~At the end of the fourth quarter of 2017, our investment in Cenovus Energy transferred from Level 2 to Level 1 due to the lapsing of trading restrictions.~~ There were no ~~other~~ material transfers between levels during ~~2018~~2019 or ~~2017.~~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 ~~New York Stock Exchange.~~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, 2018								December 31, 2017									Millions of Dollars
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total			September 30, 2019					December 31, 2018
																		Level 1		Level 2	Level 3	Total	Level 1	Level 2	Level 3	Total
Assets																	Assets
Investment in Cenovus Energy	$	2,086		—		—		2,086		1,899		—		—		1,899	Investment in Cenovus Energy	$	1,951	-	-	1,951	1,462	-	-	1,462
Commodity derivatives		186		97		18		301		175		106		30		311	Commodity derivatives		153	86	24	263	236	181	33	450

Total assets	$	2,272		97		18		2,387		2,074		106		30		2,210	Total assets	$	2,104	86	24	2,214	1,698	181	33	1,912


Liabilities																	Liabilities
Commodity derivatives	$	176		103		36		315		158		111		41		310	Commodity derivatives	$	169	82	16	267	225	145	30	400

Total liabilities	$	176		103		36		315		158		111		41		310	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.

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.

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

   Millions of Dollars
   Gross
Amounts
Recognized    Gross
Amounts
Offset    Net
Amounts
Presented    Cash
Collateral
Gross Amounts
without
Right of Setoff
   Net
Amounts


September 30, 2018

Assets
   $ 301    206    95    —    7    88
Liabilities
   315    206    109    2    3    104

December 31, 2017

Assets
   $ 311    186    125    —    4    121
Liabilities
   310    186    124    7    5    112

~~At September 30, 2018 and December 31, 2017, 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 anon-recurring~~ ~~basis:~~

   Millions of Dollars
      Fair Value
Measurements Using
   Fair Value    Level 1
Inputs    Level 3
Inputs
Before-
Tax Loss









Net PP&E (held for sale)

March 31, 2018
   $ 250    —    250    44
September 30, 2018
   $ 201    201    —    43

During the first quarter of 2019, the carrying values of our equity method investments in the Golden Pass LNG Terminal and ~~third quarters of 2018, certain net PP&E held for sale was~~Golden Pass Pipeline were written down to fair ~~value, less costs~~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 ~~sell. In the third quarter,~~have a fair value below its carrying value, and the impairment was ~~determined by its negotiated selling price. In the first quarter, fair value was estimated using information gathered during marketing efforts.~~considered to be other than temporary. For additional information, see Note ~~5—Assets Held for Sale, Dispositions, Acquisitions and Other Planned Transactions.~~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 ~~the~~our consolidated balance sheet approximates fair value.

Accounts and notes receivable (including long-term and related parties): The carrying amount reported on ~~the~~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 ~~the~~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 ~~following table summarizes~~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 ~~net fair~~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 ~~financial instruments (i.e., adjusted where~~certain leased office buildings. For additional information about guarantees, see Note 11—Guarantees. There are no significant restrictions imposed on us by the ~~right~~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 ~~setoff exists~~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 ~~commodity derivatives):~~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.

   Millions of Dollars
   Carrying Amount    Fair Value
   September 30    December 31    September 30    December 31
   2018    2017    2018    2017




Financial assets

Investment in Cenovus Energy
   $ 2,086    1,899    2,086    1,899
Commodity derivatives
   95    125    95    125
Total loans and advances—related parties
   464    586    464    586
Financial liabilities

Total debt, excluding capital leases
   14,201    18,929    16,554    22,435
Commodity derivatives
   107    117    107    117

~~Note 16—Accumulated Other Comprehensive Loss~~

~~Accumulated other comprehensive loss in~~Leases are evaluated for classification as operating or finance leases at the ~~equity section~~commencement date of the lease and right-of-use assets and corresponding liabilities are recognized on our consolidated balance sheet ~~included:~~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.

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


December 31, 2017
   $ (400 ) (58 ) (5,060 ) (5,518 )
Cumulative effect of adopting ASUNo. 2016-01*
   — 58 — 58
Other comprehensive income (loss)
   240 — (222 ) 18

September 30, 2018
   $ (160 ) — (5,282 ) (5,442 )

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 ~~2—Changes in Accounting Principles~~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 following table summarizes reclassifications out of accumulated other comprehensive loss:~~

   Millions of Dollars
   Three Months Ended
September 30    Nine Months Ended
September 30
   2018    2017    2018    2017




Defined benefit plans
   $ 17    26    155    116

The above amounts are included in the computation of net periodic benefit cost and are presented net of tax expense of $6$12 million and ~~$14~~$6 million for the three months ended September 30, ~~2018~~2019 and September 30, ~~2017,~~2018, respectively, and ~~$43~~$22 million and ~~$61~~$43 million for the nine-month periods ended September 30, ~~2018~~2019 and September 30, ~~2017,~~2018, respectively. See Note 18—Employee Benefit Plans, for additional information.

~~Note 17—Cash Flow 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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   Millions of Dollars
   Nine Months Ended
September 30
   2018 2017


Cash Payments

Interest
   $ 584 918
Income taxes
   1,927 574

Net Sales (Purchases) of Short-Term Investments

Short-term investments purchased
   $ (1,705 ) (4,999 )
Short-term investments sold
   2,701 2,416

   $ 996 (2,583 )

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 following items are included in the “Cash Flows From Operating Activities” section of our consolidated statement of cash flows:~~

In the second quarter of 2018, we received a settlement payment of $262 million from the Republic of Ecuador. In the third quarter of 2018, we received a settlement payment of $103 million from PDVSA. For more information see Note 13—Contingencies and Commitments.

~~In the first quarter of 2017, we recognized a $180 million adverse cash impact from the settlement of cross-currency swap transactions.~~

~~Note 18—Employee Benefit Plans~~

~~Pension and Postretirement Plans~~

   Millions of Dollars
   Pension Benefits Other Benefits
   2018 2017 2018 2017


   U.S. Int’l. U.S. Int’l.


Components of Net Periodic Benefit Cost

Three Months Ended September 30

Service cost
   $ 20 20 21 20 — —
Interest cost
   22 26 29 27 2 3
Expected return on plan assets
   (22 ) (38 ) (32 ) (41 ) — —
Amortization of prior service cost (credit)
   — (1 ) 1 (1 ) (9 ) (9 )
Recognized net actuarial loss (gain)
   10 9 17 12 — (1 )
Settlements
   14 — 21 — — —
Curtailments
   — (1 ) — — — —

Net periodic benefit cost
   $ 44 15 57 17 (7 ) (7 )

Nine Months Ended September 30

Service cost
   $ 63 63 67 59 1 1
Interest cost
   76 80 90 78 6 7
Expected return on plan assets
   (91 ) (118 ) (97 ) (119 ) — —
Amortization of prior service cost (credit)
   — (4 ) 3 (4 ) (26 ) (27 )
Recognized net actuarial loss (gain)
   41 27 53 36 (1 ) (2 )
Settlements
   161 — 118 — — —
Curtailments
   — (1 ) — — — —

Net periodic benefit cost
   $ 250 47 234 50 (20 ) (21 )

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 ~~2018,~~2019, we contributed ~~$150~~$174 million to our domestic benefit plans and ~~$130~~$429 million to our international benefit ~~plans.~~plans, including a $324 million contribution made in conjunction with the completion of our sale of two ConocoPhillips U.K. subsidiaries. In ~~2018,~~2019, we expect to contribute approximately ~~$160~~$220 million to our domestic qualified and nonqualified pension and postretirement benefit plans and ~~$160~~$455 million to our international qualified and nonqualified pension and postretirement benefit plans.

~~In June 2018, we purchased a group annuity contract from Prudential~~

During the three-month period ended September 30, 2019, lump-sum benefit payments exceeded the sum of service and ~~transferred approximately $700 million of future benefit obligations from~~interest costs for the fiscal year for the U.S. qualified pension plan ~~to Prudential. The purchase of the group annuity contract was funded directly by plan assets of the~~and a U.S. ~~qualified pension~~nonqualified supplemental retirement plan.

We As a result, we recognized a proportionate share of prior actuarial losses from other comprehensive income as pension settlement expense of ~~$14 million and $161 million during the three- and nine-month periods ended September 30, 2018, respectively.~~$37 million. In conjunction with the recognition of pension settlement expense, the fair market values of ~~the U.S. qualified~~ pension plan assets were updated and the pension benefit ~~obligation~~obligations of the U.S. qualified pension plan ~~was~~and the U.S. nonqualified supplemental retirement plan were remeasured as of ~~June~~September 30, ~~2018.~~2019. At the measurement date, the net pension liability increased by ~~$42 million as~~$108 million. This is primarily a result of a ~~loss on U.S. qualified pension plan assets, offset by a gain on the projected benefit obligation due primarily to an increase~~decrease in the discount rate from ~~3.6~~4.30 percent at December 31, 2018 to ~~4.2~~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.

~~During~~

The sale of two ConocoPhillips U.K. subsidiaries completed during the ~~three-month period ended September 30, 2018,~~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 ~~value~~values of ~~certain international~~ pension plan

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assets were updated, ~~and~~ the pension benefit ~~obligations associated with these plans were remeasured. At the measurement~~

~~date,~~obligation was remeasured, and the net pension ~~liability~~asset decreased by ~~$157~~$43 million, ~~with~~resulting in a corresponding ~~increase~~decrease to other comprehensive ~~income~~income. This is primarily as a result of ~~an increase~~a decrease in the discount rate from ~~2.55~~2.90 percent at December 31, ~~2017,~~2018 to ~~2.95~~1.80 percent at September 30, ~~2018. The reduction~~2019 offset by a decrease in ~~net~~the pension ~~liability resulted in a balance of $146 million associated with an international qualified plan being reclassified to the “Other assets” line on our consolidated balance sheet.~~benefit obligation from curtailment.

Severance Accrual

As a result of staff reductions occurring throughout the year, severance accruals of $35 million and $65 million were recorded during the three- and nine-month periods ended September 30, 2018, respectively. The following table summarizes our severance accrual activity for the nine-month period ended September 30, ~~2018:~~2019:

					Millions of Dollars
	Millions of Dollars

Balance at December 31, 2017	$	53
Balance at December 31, 2018				Balance at December 31, 2018	$	48
Accruals		65		Accruals		(2)
Benefit payments		(38	)	Benefit payments		(22)

Balance at September 30, 2018	$	80

Foreign currency translation adjustments				Foreign currency translation adjustments		(1)
Balance at September 30, 2019				Balance at September 30, 2019	$	23

Of the remaining balance at September 30, ~~2018, $55~~2019, $6 million is classified as short term.

~~Note 19—Related Party Transactions~~

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

~~Significant transactions with our equity affiliates were:~~

   Millions of Dollars
   Three Months Ended
September 30 Nine Months Ended
September 30
   2018 2017 2018 2017


Operating revenues and other income
   $ 27 24 74 83
Purchases
   25 26 74 74
Operating expenses and selling, general and administrative expenses
   13 16 44 42
Net interest (income) expense*
   (4 ) (4 ) (11 ) (10 )

*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.

Note 20—Sales and Other Operating Revenues

~~Transitional Arrangements~~

~~We adopted~~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 ~~provisions~~scope of ASC Topic 606 ~~beginning January 1, 2018, using the modified retrospective approach,~~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 ~~applied to~~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 ~~the standard that had not been completed as of January 1, 2018. Results for reporting periods beginning after January 1, 2018, are presented under~~ ASC Topic ~~606, while prior period amounts are not adjusted~~606. The following disaggregation of revenues is provided in conjunction with Note 21—Segment Disclosures and continue to be reported in accordance with ASC Topic 605. See Note 2—Changes in Accounting Principles for the effect on our consolidated balance sheet and the line items which have been impacted by the adoptionRelated 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

Table of ~~this standard.~~

Contents

The cumulative effect of applying the standard relates solely to certain licensing arrangements where revenue was previously recognized ($61 million in 2011, $146 million in 2015, and $44 million in 2017) based on contractual milestones. Under ASC Topic 606, such revenues are recognized when the customer has the ability to utilize and benefit from its right to use the license. As a result, such historically recognized revenues must be reversed through a cumulative effect adjustment and deferred until such time when the customer has the ability to utilize and benefit from the license. The cumulative effect adjustment relates to contracts that were not substantially completed at the date of implementation.

~~Accounting Policy~~

Revenues associated with the sales of crude oil, bitumen, natural gas, LNG, natural gas liquids and other items are recognized at the point in time when the customer obtains control of the asset. In evaluating when a customer has control of the asset, we primarily consider whether the transfer of legal title and physical delivery has occurred, whether the customer has significant risks and rewards of ownership, and whether the customer has accepted delivery and a right to payment exists. These products are typically sold at prevailing market prices. We allocate variable market-based consideration to deliveries (performance obligations) in the current period as that consideration relates specifically to our efforts to transfer control of current period deliveries to the customer and represents the amount we expect to be entitled to in exchange for the related products. Payment is typically due within 30 days or less.

Practical Expedients

Typically, our commodity sales contracts are less than 12 months in duration; however, in certain ~~commodity sales contracts~~specific cases may ~~carry a~~extend longer, ~~duration,~~ which may ~~extend~~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.

~~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
September 30    Nine Months Ended
September 30
   2018    2017*    2018    2017*




Revenue from contracts with customers
   $ 7,546    4,636    20,834    14,428
Revenue from contracts outside the scope of ASC Topic 606

Physical contracts meeting the definition of a derivative
   1,897    2,050    5,877    6,631
Financial derivative contracts
   6    2    40    (72 )

Consolidated sales and other operating revenues
   $ 9,449    6,688    26,751    20,987

*Under the modified retrospective approach, prior period amounts have not been adjusted upon adoption of ASC Topic 606.

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
September 30    Nine Months Ended
September 30
   2018    2017*    2018    2017*




Revenue from Outside the Scope of ASC Topic 606 by Segment

Lower 48
   $ 1,534    1,563    4,547    4,834
Canada
   87    161    374    680
Europe and North Africa
   276    326    956    1,117

Physical contracts meeting the definition of a derivative
   $ 1,897    2,050    5,877    6,631

*Under the modified retrospective approach, prior period amounts have not been adjusted upon adoption of ASC Topic 606.

   Millions of Dollars
   Three Months Ended
September 30    Nine Months Ended
September 30
   2018    2017*    2018    2017*




Revenue from Outside the Scope of ASC Topic 606 by Product

Crude oil
   $ 267    171    843    530
Natural gas
   1,522    1,811    4,775    5,870
Other
   108    68    259    231

Physical contracts meeting the definition of a derivative
   $ 1,897    2,050    5,877    6,631

*Under the modified retrospective approach, prior period amounts have not been adjusted upon adoption of ASC Topic 606.

Receivables and Contract Liabilities

Receivables from Contracts with Customers

At September 30, ~~2018,~~2019, the “Accounts and notes receivable” line on our consolidated balance sheet, ~~included~~includes trade receivables of ~~$3,129~~$2,566 million compared with ~~$2,675~~$2,889 million at December 31, ~~2017,~~2018, and ~~included~~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 ~~with~~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 ~~agreements~~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 January 1, 2018
   $ 251
Contractual payments received*
   81
Revenue recognized
   (148 )

At September 30, 2018
   $ 184

Amounts Recognized in the Consolidated Balance Sheet at September 30, 2018

Current liabilities
   $ 147
Noncurrent liabilities
   37

   $ 184

*Includes $14 million and $81 million for the three- and nine-month periods of 2018, respectively.

For the three- and nine-month periods of 2018, we recognized revenue of $73 million and $148 million, respectively, in the “Sales and other operating revenues” line on our consolidated income statement.

	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, ~~2018,~~2019, as revenue between ~~the remainder of 2018~~2021 and ~~2022 as construction is completed.~~2022.

~~Prior to the adoption of ASC Topic 606, contractual cash payments received would have been recognized as “Sales and other operating revenues” when received.~~

Note 21—Segment Disclosures and Related Information

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and ~~natural gas liquids~~NGLs on a worldwide basis. We manage our operations through ~~six~~6 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 ~~(loss)~~ attributable to ConocoPhillips. Intersegment sales are at prices that approximate market.

~~Analysis~~

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.

Table of ~~Results by Operating Segment~~Contents

   Millions of Dollars
   Three Months Ended
September 30 Nine Months Ended
September 30
   2018 2017* 2018 2017*


Sales and Other Operating Revenues

Alaska
   $ 1,493 932 4,281 3,010

Lower 48
   4,543 3,102 12,347 9,422
Intersegment eliminations
   (14 ) (2 ) (18 ) (7 )

Lower 48
   4,529 3,100 12,329 9,415

Canada
   735 699 2,436 2,357
Intersegment eliminations
   (308 ) (155 ) (853 ) (330 )

Canada
   427 544 1,583 2,027

Europe and North Africa
   1,574 1,110 4,826 3,564
Asia Pacific and Middle East
   1,348 959 3,570 2,877
Corporate and Other
   78 43 162 94

Consolidated sales and other operating revenues
   $ 9,449 6,688 26,751 20,987

Sales and Other Operating Revenues by Geographic Location

United States
   $ 6,025 4,038 16,617 12,440
Australia
   515 323 1,258 1,050
Canada
   427 544 1,583 2,027
China
   262 148 616 511
Indonesia
   234 191 662 554
Libya**
   264 91 802 315
Malaysia
   339 297 1,039 768
Norway
   734 583 2,112 1,751
United Kingdom
   574 437 1,911 1,498
Other foreign countries
   75 36 151 73

Worldwide consolidated
   $ 9,449 6,688 26,751 20,987

Sales and Other Operating Revenues by Product

Crude Oil
   $ 5,277 2,947 14,503 9,387
Natural gas
   2,503 2,496 7,593 7,949
Natural gas liquids
   351 238 847 745
Other***
   1,318 1,007 3,808 2,906

Consolidated sales and other operating revenues by product
   $ 9,449 6,688 26,751 20,987

    *Under the modified retrospective approach, prior period amounts have not been adjusted upon adoption of ASC Topic 606.
  **Included in “Other foreign countries” in prior periods.
***Includes LNG and bitumen.

Net Income (Loss) Attributable to ConocoPhillips

Alaska
   $ 427 103 1,369 291
Lower 48
   513 (97 ) 1,231 (2,995 )
Canada
   34 280 2 2,607
Europe and North Africa
   241 85 776 379
Asia Pacific and Middle East
   577 396 1,504 (1,540 )
Other International
   316 (20 ) 267 (77 )
Corporate and Other
   (247 ) (327 ) (760 ) (1,099 )

Consolidated net income (loss) attributable to ConocoPhillips
   $ 1,861 420 4,389 (2,434 )

	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

   Millions of Dollars
   September 30
2018    December 31
2017


Total Assets

Alaska
   $ 12,688    12,108
Lower 48
   15,308    14,632
Canada
   5,950    6,214
Europe and North Africa
   11,895    11,870
Asia Pacific and Middle East
   16,611    16,985
Other International
   315    97
Corporate and Other
   7,789    11,456

Consolidated total assets
   $ 70,556    73,362

Note 22—Income Taxes

Our effective tax rates for the three- and nine-month periods ended September 30, ~~2018,~~2019, were 3612 percent and 3921 percent, respectively, compared with 3336 percent and 39 percent for the same periods of ~~2017. The amounts of U.S. and foreign income (loss) before income taxes, with a reconciliation of tax at the federal statutory rate with the provision for income taxes were:~~

   Millions of Dollars Percent ofPre-Tax Income (Loss)
   Three Months Ended
September 30 Nine Months Ended
September 30 Three Months Ended
September 30 Nine Months Ended
September 30


   2018 2017 2018 2017 2018 2017 2018 2017


Income (loss) before income taxes

United States
   $ 893 (197 ) 2,799 (5,259 ) 30.7 % (30.2 ) 38.3 133.5
Foreign
   2,013 850 4,502 1,319 69.3 130.2 61.7 (33.5 )

   $ 2,906 653 7,301 (3,940 ) 100.0 % 100.0 100.0 100.0

Federal statutory income tax
   $ 610 228 1,533 (1,379 ) 21.0 % 35.0 21.0 35.0
Non-U.S. effective tax rates
   479 137 1,339 503 16.5 21.0 18.3 (12.8 )
Canada disposition
   — (8 ) — (1,176 ) — (1.2 ) — 29.8
Recovery of outside basis
   (16 ) (118 ) (19 ) (957 ) (0.6 ) (18.1 ) (0.2 ) 24.3
Adjustment to tax reserves
   (3 ) (17 ) 2 764 (0.1 ) (2.6 ) — (19.4 )
Adjustment to valuation allowance
   (29 ) — 13 24 (1.0 ) — 0.2 (0.6 )
APLNG impairment
   — — — 834 — — — (21.2 )
State income tax
   38 14 83 (98 ) 1.3 2.1 1.1 2.5
Enhanced oil recovery credit
   (36 ) (5 ) (73 ) (49 ) (1.3 ) (0.8 ) (1.0 ) 1.2
Other
   (10 ) (14 ) (4 ) (15 ) (0.3 ) (2.2 ) — 0.5

   $ 1,033 217 2,874 (1,549 ) 35.5 % 33.2 39.4 39.3

~~The effective tax rate represents a blend of federal, state and foreign taxes and includes the impact of certain nondeductible items and adjustments to our valuation allowance. The~~2018. The effective tax rate for the three- and ~~nine- month~~nine-month periods ended September 30, ~~2018, also reflects~~2019 is lower than the ~~reduced federal corporate income~~effective tax rate ~~as a result~~for the same periods of 2018 primarily due to the ~~enactment of the Tax Cuts and Jobs Act (the Tax Legislation) in December 2017 and the impact~~recognition of a ~~change~~U.S. capital loss benefit related to the disposition of two of our U.K. subsidiaries, the recognition of tax incentives in ~~the~~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 ~~domestic and foreign earnings.~~U.K. entity disposition.

During the third quarter of ~~2018,~~2019, we ~~recognized $53 million of U.S. Federal~~received final partner approval in the Malaysia Block G to claim certain deepwater tax credits. As a result, we recorded an income tax benefit related to previously unrecognized deferred tax assets associated with the income from the PDVSA settlement agreement. This benefit is included in the “Adjustment to Valuation Allowance” and “Recovery of Outside Basis” lines of the table above. Any future amounts received under the PDVSA settlement should result in nominal U.S. income tax implications due to the availability of unrecognized U.S. tax attributes to offset the receipts. For additional information, see Note 13—Contingencies and Commitments.

$164 million.

~~Our effective tax rate for~~During the three- and nine-month periods ended September 30, ~~2017, was favorably impacted~~2019, our valuation allowance decreased by ~~a tax benefit~~$32 million and $224 million, respectively, compared to increases of ~~$114~~$16 million ~~related~~and $61 million for the same periods of 2018. The change to our ~~prior decision~~valuation allowance between periods relates primarily to ~~exit Nova Scotia deepwater exploration. This benefit is included~~the decrease in the ~~“Recovery of Outside Tax Basis” line of the table above.~~

Our effective tax rate for the nine-month period ended September 30, 2017, was also favorably impacted by a tax benefit of $1,176 million, associated with our 2017 disposition of various assets in Canada.This tax benefit was primarily associated with a deferred tax ~~recovery~~asset related to the ~~Canadian capital gains exclusion component~~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 2017 Canada disposition and the recognition of previously unrealizable Canadian capital asset tax basis. The Canada disposition, along with the associated restructuring of our Canadian operations, may generate anGreater Sunrise Fields.

For additional ~~tax benefit of $822 million. However, since we believe it is not likely we will receive a corresponding cash tax savings, this $822 million benefit has been offset by a full tax reserve.~~

~~The impairment of our APLNG investment in the second quarter of 2017 did not generate a tax benefit. See the “APLNG” section of Note 6—Investments, Loans and Long-Term Receivables, for~~ information on ~~the impairment~~asset dispositions, see Note 5—Asset Dispositions.

Table of ~~our APLNG investment.~~Contents

~~We have not significantly revised the tax accounting impacts of our 2017 provisional estimates under Staff Accounting Bulletin 118 and ASUNo. 2018-05,~~ “Income Taxes” (Topic 740), but we are continuing to gather information and are waiting for further guidance from the Internal Revenue Service, Securities Exchange Commission and FASB on the Tax Legislation.

~~The Tax Legislation subjects a U.S. shareholder to tax on Global IntangibleLow-Taxed~~ ~~Income (GILTI) earned by certain foreign subsidiaries. The FASB Staff Q&A, Topic 740, No. 5, “Accounting for Global IntangibleLow-Taxed~~ Income,” states that an entity can make an accounting policy election to either recognize deferred taxes for temporary basis differences expected to reverse as GILTI in future years or provide for the tax expense related to GILTI in the year the tax is incurred as a period expense only. Given the complexity, we are still evaluating the effects of the GILTI provisions and have not yet determined our accounting policy. At September 30, 2018, the current-year U.S. income tax impact related to GILTI activities is immaterial.

Note 23—New Accounting Standards

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

~~ASUNo. 2016-02~~ ~~was amended in January 2018 by the provisions of ASUNo. 2018-01,~~ ~~“Land Easement Practical Expedient for Transition to Topic 842” (ASUNo. 2018-01),~~ ~~and in July 2018 by the provisions of ASUNo. 2018-10,~~ ~~“Codification Improvements to Topic 842, Leases” (ASUNo. 2018-10).~~ ~~In addition, the FASB issued ASUNo. 2018-11,~~ ~~“Targeted Improvements” (ASUNo. 2018-11),~~ ~~in July 2018 to set forth certain additional practical expedients for lessors and to provide entities with an option to apply the provisions of ASUNo. 2016-02,~~ as amended, to leasing arrangements existing at or entered into after the ASU’s effective date of adoption (the “Optional Transition Method”). Entities that elect to utilize the Optional Transition Method would not apply the provisions of ASU~~No. 2016-02,~~ ~~as amended, to comparative periods presented in the financial statements.~~

~~We plan to adopt ASUNo. 2016-02,~~ as amended, effective January 1, 2019, utilizing the Optional Transition Method. Accordingly, the comparative periods presented in the financial statements prior to January 1, 2019, will be presented pursuant to the existing requirements of FASB ASC Topic 840 and not be adjusted upon the adoption of the ASU. We continue to evaluate the ASU to determine the impact of adoption on our consolidated financial statements and disclosures, accounting policies and systems, business processes, and internal controls. We are currently implementing a third-party lease accounting software solution to facilitate the ongoing accounting and financial reporting requirements of the ASU. We also continue to monitor proposals issued by the FASB to clarify the ASU and certain industry implementation issues.

~~While our evaluation of ASUNo. 2016-02~~ and related implementation activities are ongoing, we expect the adoption of the ASU to have a material impact to our consolidated financial statements. Such impact is expected to relate primarily to our balance sheet, resulting from the initial recognition of lease liabilities and corresponding~~right-of-use~~ ~~assets for our population of operating leases, as well as enhanced disclosure of our leasing arrangements. We also expect the adoption of ASUNo. 2016-02~~ ~~to result in certain changes being made to our existing accounting policies and systems, business processes, and internal controls.~~

In June 2016, the FASB issued ASUNo. 2016-13, “Measurement of Credit Losses on Financial Instruments” (ASUNo. 2016-13), which sets forth the current expected credit loss model, a new forward-looking impairment model for certain financial instruments based on expected losses rather than incurred losses. The ASU is effective for interim and annual periods beginning after December 15, ~~2019, and early adoption of the standard is permitted.~~2019. Entities are required to adopt ASUNo. 2016-13 using a modified retrospective approach, subject to certain limited exceptions. ~~We are currently evaluating the~~The impact of ~~the adoption of~~adopting this ~~ASU.~~

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 ~~ConocoPhillips Canada Funding Company I,~~Burlington Resources LLC, with respect to publicly held debt securities. ConocoPhillips Company is 100 percent owned by ConocoPhillips. ~~ConocoPhillips Canada Funding Company I~~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 ~~ConocoPhillips Canada Funding Company I,~~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 ~~ConocoPhillips Canada Funding Company I~~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 ~~March~~December 2018, ConocoPhillips Canada Funding Company ~~received a $1.2 billion loan repayment from a nonguarantor subsidiary to settle certain accumulated intercompany balances. This transaction had no~~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 on our consolidated financial ~~statements.~~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.

In June 2018, ConocoPhillips received a $2.5 billion return of capital from ConocoPhillips Company to settle certain accumulated intercompany balances. The transaction had no impact on our consolidated financial statements.

In the second quarter of 2018, ConocoPhillips Company received $1.2 billion of loan repayments from a nonguarantor subsidiary to settle certain accumulated intercompany balances. This transaction had no impact on our consolidated financial statements.

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

   Millions of Dollars
   Three Months Ended September 30, 2018
Income Statement    ConocoPhillips ConocoPhillips
Company ConocoPhillips
Canada
Funding
Company I All Other
Subsidiaries Consolidating
Adjustments Total
Consolidated
Revenues and Other Income

Sales and other operating revenues
   $ — 4,330 — 5,119 — 9,449
Equity in earnings of affiliates
   1,903 2,166 — 256 (4,031 ) 294
Gain on dispositions
   — 75 — 38 — 113
Other income
   — (61 ) — 370 — 309
Intercompany revenues
   9 34 42 1,619 (1,704 ) —

Total Revenues and Other Income
   1,912 6,544 42 7,402 (5,735 ) 10,165

Costs and Expenses

Purchased commodities
   — 3,880 — 1,196 (1,546 ) 3,530
Production and operating expenses
   — 298 — 1,085 (16 ) 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 37 63 (142 ) 186
Foreign currency transaction (gains) losses
   (12 ) 3 42 (28 ) — 5
Other expenses
   — 6 — 4 — 10

Total Costs and Expenses
   62 4,673 79 4,149 (1,704 ) 7,259

Income (Loss) before income taxes
   1,850 1,871 (37 ) 3,253 (4,031 ) 2,906
Income tax provision (benefit)
   (11 ) (32 ) 1 1,075 — 1,033

Net income (loss)
   1,861 1,903 (38 ) 2,178 (4,031 ) 1,873
Less: net income attributable to noncontrolling interests
   — — — (12 ) — (12 )

Net Income (Loss) Attributable to ConocoPhillips
   $ 1,861 1,903 (38 ) 2,166 (4,031 ) 1,861

Comprehensive Income Attributable to ConocoPhillips
   $ 2,056 2,098 5 2,330 (4,433 ) 2,056

Income Statement    Three Months Ended September 30, 2017*
Revenues and Other Income

Sales and other operating revenues
   $ — 2,997 — 3,691 — 6,688
Equity in earnings of affiliates
   486 348 — 119 (757 ) 196
Gain (Loss) on dispositions
   — 879 — (633 ) — 246
Other income
   — 12 — 53 — 65
Intercompany revenues
   10 77 43 774 (904 ) —

Total Revenues and Other Income
   496 4,313 43 4,004 (1,661 ) 7,195

Costs and Expenses

Purchased commodities
   — 2,666 — 1,001 (741 ) 2,926
Production and operating expenses
   — 216 — 1,007 (1 ) 1,222
Selling, general and administrative expenses
   2 97 — 11 — 110
Exploration expenses
   — 29 — 44 — 73
Depreciation, depletion and amortization
   — 203 — 1,405 — 1,608
Impairments
   — 1 — 5 — 6
Taxes other than income taxes
   — 29 — 146 — 175
Accretion on discounted liabilities
   — 8 — 81 — 89
Interest and debt expense
   86 169 37 121 (162 ) 251
Foreign currency transaction (gains) losses
   (27 ) 1 77 (46 ) — 5
Other expenses
   50 29 — (2 ) — 77

Total Costs and Expenses
   111 3,448 114 3,773 (904 ) 6,542

Income (Loss) before income taxes
   385 865 (71 ) 231 (757 ) 653
Income tax provision (benefit)
   (35 ) 379 6 (133 ) — 217

Net income (loss)
   420 486 (77 ) 364 (757 ) 436
Less: net income attributable to noncontrolling interests
   — — — (16 ) — (16 )

Net Income (Loss) Attributable to ConocoPhillips
   $ 420 486 (77 ) 348 (757 ) 420

Comprehensive Income Attributable to ConocoPhillips
   $ 1,470 1,536 22 864 (2,422 ) 1,470

*Certain amounts have been reclassifiedIn April 2019, ConocoPhillips received a $1.7 billion return of earnings from ConocoPhillips Company to ~~conform~~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 ~~the current-period presentation resulting from the adoption~~settle certain accumulated intercompany balances. These transactions had no impact on our consolidated financial statements.

Table of ~~ASUNo. 2017-07.~~Contents

~~See Note 2~~—~~Changes in Accounting Principles, for additional information.~~

		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.

Table of Contents

~~See Notes to Consolidated Financial Statements.~~

	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.

Table of Contents

   Millions of Dollars
   Nine Months Ended September 30, 2018
Income Statement    ConocoPhillips ConocoPhillips
Company ConocoPhillips
Canada
Funding
Company I All Other
Subsidiaries Consolidating
Adjustments Total
Consolidated
Revenues and Other Income

Sales and other operating revenues
   $ — 11,774 — 14,977 — 26,751
Equity in earnings of affiliates
   4,562 5,398 — 833 (10,026 ) 767
Gain on dispositions
   — 78 — 97 — 175
Other income
   — 230 — 443 — 673
Intercompany revenues
   28 124 129 4,227 (4,508 ) —

Total Revenues and Other Income
   4,590 17,604 129 20,577 (14,534 ) 28,366

Costs and Expenses

Purchased commodities
   — 10,571 — 3,757 (4,020 ) 10,308
Production and operating expenses
   — 723 — 3,181 (53 ) 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
   219 456 110 192 (430 ) 547
Foreign currency transaction (gains) losses
   22 (6 ) (43 ) 34 — 7
Other expenses
   — 348 — 2 — 350

Total Costs and Expenses
   248 13,020 67 12,238 (4,508 ) 21,065

Income before income taxes
   4,342 4,584 62 8,236 (10,026 ) 7,301
Income tax provision (benefit)
   (47 ) 22 (5 ) 2,904 — 2,874

Net income
   4,389 4,562 67 5,332 (10,026 ) 4,427
Less: net income attributable to noncontrolling interests
   — — — (38 ) — (38 )

Net Income Attributable to ConocoPhillips
   $ 4,389 4,562 67 5,294 (10,026 ) 4,389

Comprehensive Income (Loss) Attributable to ConocoPhillips
   $ 4,407 4,580 (13 ) 5,186 (9,856 ) 4,407

Income Statement    Nine Months Ended September 30, 2017*
Revenues and Other Income

Sales and other operating revenues
   $ — 9,066 — 11,921 — 20,987
Equity in earnings (losses) of affiliates
   (2,092 ) (776 ) — 432 3,010 574
Gain on dispositions
   — 908 — 1,236 — 2,144
Other income
   1 27 — 115 — 143
Intercompany revenues
   39 222 126 2,360 (2,747 ) —

Total Revenues and Other Income
   (2,052 ) 9,447 126 16,064 263 23,848

Costs and Expenses

Purchased commodities
   — 8,068 — 3,229 (2,257 ) 9,040
Production and operating expenses
   — 483 — 3,358 (3 ) 3,838
Selling, general and administrative expenses
   8 244 — 55 (5 ) 302
Exploration expenses
   — 433 — 287 — 720
Depreciation, depletion and amortization
   — 658 — 4,554 — 5,212
Impairments
   — 1,075 — 5,400 — 6,475
Taxes other than income taxes
   — 114 — 490 — 604
Accretion on discounted liabilities
   — 28 — 248 — 276
Interest and debt expense
   340 505 110 399 (482 ) 872
Foreign currency transaction (gains) losses
   (49 ) 3 145 (71 ) — 28
Other expenses
   267 159 — (5 ) — 421

Total Costs and Expenses
   566 11,770 255 17,944 (2,747 ) 27,788

Loss before income taxes
   (2,618 ) (2,323 ) (129 ) (1,880 ) 3,010 (3,940 )
Income tax provision (benefit)
   (184 ) (231 ) 12 (1,146 ) — (1,549 )

Net loss
   (2,434 ) (2,092 ) (141 ) (734 ) 3,010 (2,391 )
Less: net income attributable to noncontrolling interests
   — — — (43 ) — (43 )

Net Loss Attributable to ConocoPhillips
   $ (2,434 ) (2,092 ) (141 ) (777 ) 3,010 (2,434 )

Comprehensive Income (Loss) Attributable to ConocoPhillips
   $ (1,533 ) (1,191 ) 39 (37 ) 1,189 (1,533 )

	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.

*Certain amounts have been reclassified to conform to the current-period presentation resulting from the adoption39

Table of ~~ASUNo. 2017-07.~~Contents

~~See Note 2—Changes in Accounting Principles, for additional information.~~

	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.

Table of Contents

~~See Notes to Consolidated Financial Statements.~~

Item 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

   Millions of Dollars
   September 30, 2018
Balance Sheet    ConocoPhillips ConocoPhillips
Company    ConocoPhillips
Canada
Funding
Company I All Other
Subsidiaries    Consolidating
Adjustments Total
Consolidated
Assets

Cash and cash equivalents
   $ — 16    — 3,700    — 3,716
Short-term investments
   — —    — 875    — 875
Accounts and notes receivable
   6 2,614    1 5,301    (3,423 ) 4,499
Investment in Cenovus Energy
   — 2,086    — —    — 2,086
Inventories
   — 198    — 1,041    — 1,239
Prepaid expenses and other current assets
   — 159    7 2,169    (27 ) 2,308

Total Current Assets
   6 5,073    8 13,086    (3,450 ) 14,723
Investments, loans and long-term receivables*
   31,249 51,482    2,623 20,829    (96,295 ) 9,888
Net properties, plants and equipment
   — 4,495    — 40,709    (468 ) 44,736
Other assets
   19 484    178 1,458    (930 ) 1,209

Total Assets
   $ 31,274 61,534    2,809 76,082    (101,143 ) 70,556

Liabilities and Stockholders’ Equity

Accounts payable
   $ — 3,444    7 3,890    (3,423 ) 3,918
Short-term debt
   (3 ) 12    7 88    (9 ) 95
Accrued income and other taxes
   — 104    — 1,478    — 1,582
Employee benefit obligations
   — 476    — 150    — 626
Other accruals
   57 404    51 695    (27 ) 1,180

Total Current Liabilities
   54 4,440    65 6,301    (3,459 ) 7,401
Long-term debt
   3,790 7,152    1,698 2,740    (478 ) 14,902
Asset retirement obligations and accrued environmental costs
   — 424    — 7,130    — 7,554
Deferred income taxes
   — —    — 5,968    (433 ) 5,535
Employee benefit obligations
   — 1,315    — 440    — 1,755
Other liabilities and deferred credits*
   2,042 11,064    981 7,643    (20,400 ) 1,330

Total Liabilities
   5,886 24,395    2,744 30,222    (24,770 ) 38,477
Retained earnings
   25,972 17,591    (614 ) 16,906    (27,360 ) 32,495
Other common stockholders’ equity
   (584 ) 19,548    679 28,825    (49,013 ) (545 )
Noncontrolling interests
   — —    — 129    — 129

Total Liabilities and Stockholders’ Equity
   $ 31,274 61,534    2,809 76,082    (101,143 ) 70,556

*Includes intercompany loans.

Balance Sheet    December 31, 2017
Assets

Cash and cash equivalents
   $ — 234    4 6,087    — 6,325
Short-term investments
   — —    — 1,873    — 1,873
Accounts and notes receivable
   24 2,255    35 4,870    (2,864 ) 4,320
Investment in Cenovus Energy
   — 1,899    — —    — 1,899
Inventories
   — 163    — 897    — 1,060
Prepaid expenses and other current assets
   1 278    6 779    (29 ) 1,035

Total Current Assets
   25 4,829    45 14,506    (2,893 ) 16,512
Investments, loans and long-term receivables*
   29,400 47,974    2,533 15,050    (84,897 ) 10,060
Net properties, plants and equipment
   — 4,230    — 41,930    (477 ) 45,683
Other assets
   15 1,146    186 1,302    (1,542 ) 1,107

Total Assets
   $ 29,440 58,179    2,764 72,788    (89,809 ) 73,362

Liabilities and Stockholders’ Equity

Accounts payable
   $ — 3,094    1 3,799    (2,864 ) 4,030
Short-term debt
   (5 ) 2,505    7 77    (9 ) 2,575
Accrued income and other taxes
   — 107    — 931    — 1,038
Employee benefit obligations
   — 554    — 171    — 725
Other accruals
   85 314    48 612    (30 ) 1,029

Total Current Liabilities
   80 6,574    56 5,590    (2,903 ) 9,397
Long-term debt
   3,787 9,321    1,703 2,794    (477 ) 17,128
Asset retirement obligations and accrued environmental costs
   — 432    — 7,199    — 7,631
Deferred income taxes
   — —    — 6,263    (981 ) 5,282
Employee benefit obligations
   — 1,335    — 519    — 1,854
Other liabilities and deferred credits*
   1,528 5,229    926 9,215    (15,629 ) 1,269

Total Liabilities
   5,395 22,891    2,685 31,580    (19,990 ) 42,561
Retained earnings
   22,867 13,317    (681 ) 11,958    (18,070 ) 29,391
Other common stockholders’ equity
   1,178 21,971    760 29,056    (51,749 ) 1,216
Noncontrolling interests
   — —    — 194    — 194

Total Liabilities and Stockholders’ Equity
   $ 29,440 58,179    2,764 72,788    (89,809 ) 73,362

*Includes intercompany loans.

   Millions of Dollars
   Nine Months Ended September 30, 2018
Statement of Cash Flows    ConocoPhillips ConocoPhillips
Company ConocoPhillips
Canada
Funding
Company I All Other
Subsidiaries Consolidating
Adjustments Total
Consolidated
Cash Flows From Operating Activities

Net Cash Provided by (Used in) Operating Activities
   $ 2,331 863 (121 ) 8,937 (2,859 ) 9,151

Cash Flows From Investing Activities

Capital expenditures and investments
   — (771 ) — (4,369 ) 7 (5,133 )
Working capital changes associated with investing activities
   — (77 ) — 20 — (57 )
Proceeds from asset dispositions
   — 307 — 199 (112 ) 394
Sales of short-term investments
   — — — 996 — 996
Long-term advances/loans—related parties
   — (36 ) — (127 ) 163 —
Collection of advances/loans—related parties
   — 3,432 — 129 (3,442 ) 119
Intercompany cash management
   514 3,426 — (3,940 ) — —
Other
   — — — 16 — 16

Net Cash Provided by (Used in) Investing Activities
   514 6,281 — (7,076 ) (3,384 ) (3,665 )

Cash Flows From Financing Activities

Issuance of debt
   — 10 117 36 (163 ) —
Repayment of debt
   — (4,865 ) — (3,547 ) 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 ) — — (452 ) 452 (1,009 )
Other
   3 (2,511 ) — (228 ) 2,625 (111 )

Net Cash Provided by (Used in) Financing Activities
   (2,845 ) (7,366 ) 117 (4,191 ) 6,243 (8,042 )

Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash
   — 4 — (44 ) — (40 )

Net Change in Cash, Cash Equivalents and Restricted Cash
   — (218 ) (4 ) (2,374 ) — (2,596 )
Cash, cash equivalents and restricted cash at beginning of period*
   — 234 4 6,298 — 6,536

Cash, Cash Equivalents and Restricted Cash at End of Period
   $ — 16 — 3,924 — 3,940

Statement of Cash Flows    Nine Months Ended September 30, 2017
Cash Flows From Operating Activities

Net Cash Provided by (Used in) Operating Activities
   $ (161 ) 634 22 6,868 (2,767 ) 4,596

Cash Flows From Investing Activities

Capital expenditures and investments
   — (1,230 ) — (2,711 ) 867 (3,074 )
Working capital changes associated with investing activities
   — 36 — (54 ) — (18 )
Proceeds from asset dispositions
   5,000 10,974 — 12,737 (14,971 ) 13,740
Purchases of short-term investments
   — — — (2,583 ) — (2,583 )
Long-term advances/loans—related parties
   — (74 ) — (20 ) 94 —
Collection of advances/loans—related parties
   658 127 — 2,196 (2,866 ) 115
Intercompany cash management
   2,903 (2,474 ) — (429 ) — —
Other
   — — — 51 — 51

Net Cash Provided by Investing Activities
   8,561 7,359 — 9,187 (16,876 ) 8,231

Cash Flows From Financing Activities

Issuance of debt
   — 20 — 74 (94 ) —
Repayment of debt
   (5,459 ) (3,146 ) — (855 ) 2,866 (6,594 )
Issuance of company common stock
   87 — — — (152 ) (65 )
Repurchase of company common stock
   (2,045 ) — — — — (2,045 )
Dividends paid
   (986 ) — — (2,919 ) 2,919 (986 )
Other
   3 (5,000 ) — (9,187 ) 14,104 (80 )

Net Cash Used in Financing Activities
   (8,400 ) (8,126 ) — (12,887 ) 19,643 (9,770 )

Effect of Exchange Rate Changes on Cash and Cash Equivalents
   — 1 — 243 — 244

Net Change in Cash and Cash Equivalents
   — (132 ) 22 3,411 — 3,301
Cash and cash equivalents at beginning of period
   — 358 13 3,239 — 3,610

Cash and Cash Equivalents at End of Period
   $ — 226 35 6,650 — 6,911

*Restated to include $211 million of restricted cash at January 1, 2018. See Note 2—Changes in Accounting Principles for additional information relating to the adoption of ASU~~No. 2016-18.~~

~~Restricted cash totaling $224 million is included in the “Other assets” line of our Consolidated Balance Sheet as of September 30, 2018.~~

~~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 ~~64.~~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 ~~the world’s largest~~an independent ~~exploration~~E&P company with operations and ~~production (E&P) company, based on proved reserves and production of liquids and natural gas.~~activities in 17 countries. Our diverse, low cost of supply portfolio ~~primarily~~ includes resource-rich unconventional plays in North ~~American unconventional assets and oil sands assets in Canada; lower-risk~~America; conventional assets in North America, Europe and North Africa, Asia and Australia; ~~several liquefied natural gas (LNG)~~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 ~~had operations and activities in 17 countries,~~employed approximately ~~11,100 employees~~10,400 people worldwide and had total assets of ~~$71 billion~~$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 ~~September 30, 2018.~~

~~Overview~~

~~While global~~the second quarter, geopolitical tensions in the Middle East, threatening the safe passage of supertankers carrying crude oil ~~prices continued to improve~~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 ~~2018, our~~the world’s oil supply. Our business strategy anticipates prices will remain ~~cyclical.~~ 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; ~~reduce~~maintain debt toat 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 ~~strategically~~ 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.

Table of Contents

In the ~~first nine months~~third quarter of ~~the year,~~2019, we ~~took significant actions resulting in substantial progress~~continued to deliver on our priorities. We ~~increased our quarterly dividend by 7.5~~achieved production growth of 8 percent ~~to $0.285 per share; reduced our debt by $4.7 billion, achieving our debt reduction target 18 months ahead~~on a total BOE basis compared with the third quarter of plan and received credit rating upgrades from Fitch and Moody’s; repurchased 31.4 million shares of our common stock totaling $2.1 billion; and added to our low cost of supply resource base by increasing our legacy asset position in Alaska through one closed and one announced transaction.

~~In July~~ 2018, we announced an expansion of the planned 2018 share repurchase program from $2 billion to $3 billion. We expect to fully fund this year’s $3 billion program, as well as our dividend and capital expenditures, with ~~cash provided by operating activities.~~higher value oil volumes growing 12 percent. Cash provided by operating activities ~~for the first nine months~~ of ~~2018 was $9.2~~$2.3 billion ~~which~~ exceeded capital expenditures and investments of ~~$5.1 billion, including $0.5~~$1.7 billion. After distributing $0.3 billion of ~~acquisition capital;~~ dividends ~~of $1.0 billion;~~to shareholders and ~~share repurchases of $2.1 billion.~~

~~The 2018 expansion to $3 billion, combined with the $3~~repurchasing $0.7 billion of ~~shares repurchased during 2016~~our common stock, we ended the quarter with cash, cash equivalents and 2017, will fully utilize our Board of Directors’ previous share repurchase authorization of $6 billion. As a result, in July 2018 our Board authorized an additional $9 billion for share repurchases, bringing the total program authorization to $15 billion.

~~In October 2018, we announced a dividend increase for the second time this year, an additional 7 percent, resulting in a quarterly dividend rate of $0.305 per share.~~

In the second quarter of 2018, we obtained regulatory approvals to complete the transaction with Anadarko Petroleum Corporation to acquire its 22 percent nonoperated interest in the Western North Slope of Alaska, as well as its interest in the Alpine Pipeline, for $386 million, after customary adjustments. Full-year 2017 production associated with this interest was 11 thousand barrels of oil equivalent per day (MBOED). In addition, we now have 100 percent interest in approximately 1.2 million acres of exploration and development lands, including the Willow discovery.

In the third quarter of 2018, we entered into agreements with BP to acquire their nonoperated interest in the Greater Kuparuk Area and Kuparuk Transportation Company (Kuparuk Assets) in Alaska, and to sell a ConocoPhillips subsidiary to BP, which will hold 16.5 percent of our 24 percent interest in the~~BP-operated~~ ~~Clair Field in the United Kingdom. Both transactions are subject to regulatory approval and are expected to close simultaneously in late 2018. Full-year 2017 production andyear-end~~ 2017 proved reserves associated with the 16.5 percent interest in the Clair Field were approximately 3 MBOED and approximately 40 million barrels of oil equivalent (MMBOE), respectively. Full-year 2017 production and~~year-end~~ 2017 proved reserves associated with the 39.2 percent interest in the Greater Kuparuk Area were approximately 38 MBOED and 190 MMBOE, respectively. Excluding customary adjustments, the transactions are expected to berestricted cash ~~neutral. Depending on the timing of regulatory approvals, we anticipate recognizing a noncash gain of between $0.5~~totaling $7.5 billion and ~~$1.0~~$0.9 billion ~~on completion~~ of ~~the sale of the ConocoPhillips subsidiary holding 16.5 percent of the Clair Field, after customary adjustments and foreign exchange impacts.~~

short-term investments. In ~~October 2018,~~July, we announced an ~~agreement~~increase to ~~sell~~ our 30expected 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 ~~interest in the Greater Sunrise Fields for $350 million, prior~~ to ~~customary adjustments, to the government~~$0.42 per share and announced planned 2020 share buybacks of Timor-Leste, with an expected closing date of early 2019. The transaction is conditional on the funding approval from the Timor-Leste Council of Ministers and National Parliament. The interest to be sold is undeveloped property in the Timor Sea located between Australia and Timor-Leste. No production or reserve impacts are associated with the sale. Proceeds from this transaction will be used for general corporate purposes.$3 billion.

For more information regarding the accounting impacts of these transactions, see Note 5—Assets Held for Sale, Dispositions, Acquisitions and Other Planned Transactions, in the Notes to Consolidated Financial Statements.

In the third quarter of 2018, we entered into a settlement agreement with Petroleos de Venezuela, S.A. (PDVSA) to recover approximately $2 billion, which reflects the full amount awarded to ConocoPhillips by an arbitral tribunal constituted under the rules of the International Chamber of Commerce (ICC). PDVSA has agreed to recognize the ICC judgment and to make payments over the next four and a half years. During the quarter, we recognized in other income $345 million, consisting of $242 million in commodity inventory and $103 million in cash, related to this settlement. For more information, see Note 4—Inventories and Note 13—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

Operationally, we ~~continue to focus~~remain focused on safely executing our ~~capital program~~operating plan and ~~remaining~~staying attentive to our costs. Production excluding Libya was ~~1,224~~1,322 MBOED in the third quarter of ~~2018,~~2019, an increase of 2298 MBOED compared with the same period of ~~2017.~~2018. Our underlying production, which excludes Libya and the ~~third-quarter~~net volume impact from closed dispositions and acquisitions of ~~dispositions of approximately 50~~58 MBOED in ~~2017,~~2019 and 43 MBOED in 2018, increased ~~6 percent~~83 MBOED compared with the ~~same period~~third quarter of ~~2017. Underlying production~~2018. Production on a per debt-adjusted share basis grew by 286 percent compared with the third quarter of ~~2017.~~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.

~~Business Environment~~

~~Global oil market fundamentals continued to strengthen~~In the second quarter of 2019, we completed the sale of our 30 percent interest in the ~~third~~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 ~~2018. Crude~~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 ~~improved~~have ranged from a low of $53 per barrel to a high of $75 per barrel in the ~~period because~~first nine months of ~~supply disruptions and strong global oil demand.~~

2019. The energy industry has periodically experienced volatility due to fluctuatingsupply-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, ~~or otherwise,~~ actions taken by ~~the Organization of Petroleum Exporting Countries (OPEC),~~OPEC, environmental laws, tax regulations, governmental policies and weather-related disruptions. ~~North America’s energy landscape has been transformed from resource scarcity to an abundance of supply, primarily due to~~

~~advances in technology responsible for the rapid growth of tight oil production, successful exploration and rising production from the Canadian oil sands.~~ 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 ~~West Texas Intermediate (WTI)~~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, ~~an increase~~and a decrease of 4410 percent compared with ~~$52.09~~$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 ~~2017, and an increase~~2019, a decrease of 119 percent compared with ~~$74.35 per barrel in the second quarter of 2018. Crude oil prices for WTI averaged~~ $69.71 per barrel in the third quarter of 2018, ~~an increase~~and a decrease of 456 percent compared with ~~$48.16 per barrel in the third quarter of 2017, and an increase of 3 percent compared with $67.99~~$59.80 per barrel in the second quarter of ~~2018. Prices improved relative to the same period a year ago due to strong oil demand and global supply disruptions.~~

Henry Hub natural gas prices averaged $2.91 per million British thermal units (MMBTU) in the third quarter of 2018, a decrease of 3 percent compared with $2.99 per MMBTU in the third quarter of 2017, and an increase of 4 percent compared with $2.80 per MMBTU in the second quarter of 2018.2019. Prices decreased relative to the same period of ~~2017~~2018 primarily due to ~~higher~~macroeconomic demand concerns.

Henry Hub natural gas ~~production~~prices averaged $2.23 per MMBTU in the ~~contiguous United States.~~

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 ~~increased~~decreased from ~~$24.19~~$34.15 per barrel in the third quarter of ~~2017~~2018 to ~~$34.15~~$32.54 per barrel in the same period of ~~2018,~~2019, primarily due to ~~improvements~~declines in the WTI benchmark price, ~~and reduced blend ratios at Surmont from use of condensate diluent, partially~~which were partly offset by improvements in the ~~widening of the Western Canada Select (WCS) differential.~~WCS differential to WTI at Hardisty and lower diluent costs. Compared with ~~$32.38~~$37.20 per barrel in the second quarter of ~~2018,~~2019, our third quarter ~~2018~~2019 realized bitumen price ~~increased~~decreased due to ~~improvements~~ reductions

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in the WTI benchmark price ~~as well as reduced blend ratios~~and a widening WCS differential to WTI at ~~Surmont. The improvement in our realized bitumen price was~~Hardisty, partly offset by ~~turnarounds~~lower diluent costs. The WCS differential to WTI at Hardisty decreased in ~~U.S. midcontinent refineries, particularly during the latter part of~~ the third quarter ~~resulting~~of 2019, compared to the second quarter of 2019, due to increased production attributable to easing of curtailment levels in ~~reduced demand for Canadian heavy crude~~Canada and ~~contributing to a weakerWCS-WTI~~ ~~Edmonton differential versus the prior quarter.~~upstream producers returning from turnarounds.

Our total average realized price was ~~$57.71 per barrel of oil equivalent (BOE) in the third quarter of 2018, an increase of 46 percent compared with $39.49~~$47.07 per BOE in the third quarter of ~~2017 and a 6 percent increase~~2019, compared with $57.71 per BOE in the ~~second~~third quarter of 2018 ~~primarily reflecting higher average realizations for crude~~due to lower realized oil, natural gas and ~~LNG sales, and a more liquids weighted portfolio.~~NGL prices.

Key Operating and Financial Summary

Significant items during the third quarter of ~~2018~~2019 included the following:

Cash provided by operating activities was ~~$3.4~~$2.3 billion and exceeded capital expenditures and investments ~~dividends~~of $1.7 billion.

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

Third-quarter production excluding Libya of ~~1,224~~1,322 MBOED; year-over-year underlying production ~~excluding the impact of closed dispositions~~ grew 67 percent overall and 286 percent on a ~~production per~~ debt-adjusted share basis.

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

~~During the quarter, achieved first production from Bohai Phase 3~~Executed turnarounds in Alaska, Malaysia and ~~from the final phase of drilling at Bayu-Undan.~~Norway.

Ended the quarter with cash, cash equivalents and restricted cash totaling ~~$3.9~~$7.5 billion and short-term investments of $0.9 billion.

Completed the U.K. divestiture, generating $2.2 billion ~~equating~~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 ~~$4.8 billion.~~regulatory and other approvals.

~~Repurchased $0.9 billion of common shares outstanding, bringingyear-to-date~~ ~~repurchases to $2.1 billion.~~

~~Reached~~Announced a ~~settlement agreement with PDVSA to recover an arbitration award of approximately $2 billion; recognized cash and commodities totaling $345 million~~38 percent increase in the ~~quarter, with the remainder of the approximately $500 million~~quarterly dividend to $0.42 per share, and $3 billion in ~~initial payments due~~planned 2020 share repurchases.

Discontinued exploration activities in the ~~fourth quarter.~~

~~Announced Barnett~~Central Louisiana Austin Chalk trend and ~~Greater Sunrise dispositions for $580~~recognized $186 million ~~before customary adjustments.~~

~~Received credit rating upgrades from Fitch~~after-tax in leasehold impairment and ~~Moody’s.~~

~~In October, announced a quarterly dividend increase of 7 percent to 30.5 cents per share.~~

~~Outlook~~dry hole expenses.

Outlook

Production and Capital Guidance

Fourth-quarter ~~2018~~2019 production is expected to be ~~1,275~~1,265 to ~~1,315 MBOED, reflecting~~1,305 MBOED. The guidance excludes Libya and reflects the ~~completion~~impacts from the completed U.K. disposition.

Capital expenditures are expected to be $6.3 billion versus our original budget of ~~seasonal turnarounds~~$6.1 billion, attributable to additional appraisal drilling in Alaska and ~~growth from several conventional project startups and ongoing development~~the addition of a drilling rig in the ~~unconventionals.~~Eagle Ford at mid-year 2019. This guidance ~~includes impacts expected from the previously~~excludes approximately $0.3 billion for opportunistic acquisitions completed or announced ~~Barnett disposition~~ and ~~excludes Libya.~~

~~Full-year 2018~~results in total capital expenditures and investments ~~are expected to be~~of $6.6 billion in 2018. The company’s 2018 operated capital scope remains unchanged, excluding acquisition-related activity. However, the company is adjusting its capital expenditures guidance to $6.1 billion from the original $5.5 billion budget. This guidancebillion. Guidance also excludes obligations under the previously announced ~~$0.4 billionbolt-on~~ ~~acquisition in~~PSC extension awarded by the ~~Alaska Western North Slope and $0.1 billion to acquire additional acreage in the Montney in Canada.~~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, ~~2018,~~2019, is based on a comparison with the corresponding periods of ~~2017.~~2018.

Consolidated Results

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


													Millions of Dollars
	Millions of Dollars												Three Months Ended			Nine Months Ended
	Three Months Ended September 30						Nine Months Ended September 30						September 30			September 30
	2018			2017			2018			2017				2019	2018	2019	2018

Alaska	$	427			103			1,369			291		$	306	427	1,152	1,369
Lower 48		513			(97	)		1,231			(2,995	)		26	513	425	1,231
Canada		34			280			2			2,607			51	34	273	2
Europe and North Africa		241			85			776			379			2,001	241	2,615	776
Asia Pacific and Middle East		577			396			1,504			(1,540	)		613	577	1,655	1,504
Other International		316			(20	)		267			(77	)		73	316	285	267
Corporate and Other		(247	)		(327	)		(760	)		(1,099	)		(14)	(247)	64	(760)

Net income (loss) attributable to ConocoPhillips	$	1,861			420			4,389			(2,434	)

Net income attributable to ConocoPhillips													$	3,056	1,861	6,469	4,389

Net income attributable to ConocoPhillips in the third quarter of ~~2018~~2019 increased ~~$1,441 million.~~$1.2 billion. Earnings were positively impacted by:

~~Higher realized commodity prices.~~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.~~

~~Recognition of $325 millionafter-tax~~ ~~from a settlement agreement with PDVSA.~~

~~Lower depreciation, depletion and amortization (DD&A) expense, mainly~~volumes due to ~~lowerunit-of-production~~ ~~rates~~growth in the Lower 48 unconventionals and from ~~reserve additions~~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 ~~disposition impacts.~~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 ~~2018~~2019 net income increases were partly offset by:

~~The absence of a $190 millionafter-tax~~ ~~gain in the third quarter of 2017 for funds received in relation to environmental claims related to certain Canadian assets sold in 2017.~~Lower realized crude oil, NGL and natural gas prices.

~~The absence of a $114 million tax benefit in the third quarter of 2017~~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 ~~exit Nova Scotia deepwater exploration.~~discontinue exploration activities in the Central Louisiana Austin Chalk trend.

~~Higher production and operating expenses, primarily due to higher maintenance and wellwork.~~45

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Net income attributable to ConocoPhillips in the nine-month period ended September 30, ~~2018,~~2019, increased ~~$6,823 million.~~

$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 ~~a $2.5 billionafter-tax~~ ~~impairment~~premiums on debt retirements totaling $195 million after-tax.

A $164 million income tax benefit related to deepwater incentive tax credits recognized ~~in the second quarter~~for Malaysia Block G.

Increased earnings of ~~2017,~~$115 million related to the ~~sale~~settlement of ~~our interests in the San Juan Basin~~certain tax disputes and ~~the marketing of our Barnett asset.~~

~~The absence of a $2.4 billion before- andafter-tax~~ ~~impairment of our equity investment in Australia Pacific LNG Pty Ltd (APLNG), recognized in the second quarter of 2017.~~

~~Higher realized commodity prices.~~

~~Lower DD&A expense, mainly due to lowerunit-of-production~~ ~~rates from reserve additions and disposition impacts.~~

~~Recognition of $325 millionafter-tax~~ ~~from a settlement agreement with PDVSA.~~

enhanced oil recovery credits.

~~Lower exploration expenses, primarily due to the absence of first quarter 2017 charges in our Lower 48 and Other International segments.~~

~~Lower interest and debt expense because of a lower debt balance.~~

~~Higher equity earnings in Qatar Liquefied Gas Company Limited (3) (QG3) and APLNG, primarily due to higher realized LNG prices, and higher sales volumes from QG3.~~

~~A $109 millionafter-tax~~ ~~benefit, including interest, in the first quarter of 2018, resulting from an accrual reduction due to a transportation cost ruling in Alaska by the Federal Energy Regulatory Commission (FERC).~~

Earnings in the nine-month period ended September 30, ~~2018,~~2019, were negatively impacted by:

~~The absence~~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 ~~$1.6 billion~~leasehold impairment and dry hole costs associated with our decision to discontinue exploration activities in~~after-tax~~ ~~gains related~~ 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 ~~the sale~~impairments of ~~certain Canadian assets~~equity method investments in ~~2017.~~our Lower 48 segment of $120 million after-tax in 2019.

The absence of a ~~$996~~$109 million ~~deferred tax~~after-tax benefit ~~in the first quarter of 2017~~from an accrual reduction related to a transportation cost ruling by the ~~disposition of certain Canadian assets.~~FERC.

~~Lower sales volumes, primarily due to dispositions in our Lower 48 and Canada segments in 2017 and normal field decline.~~

See the “Segment Results” section for additional information.

Income Statement Analysis

Sales and other operating revenues for the three- and nine-month periods of ~~2018 increased 41~~2019 decreased 18 percent and 277 percent, respectively, mainly due to lower realized crude oil, NGL and natural gas prices, partly offset by higher ~~realized prices across all commodities. In~~sales volumes of crude oil in the Lower 48 and Alaska.

Equity in earnings of affiliates for the nine-month period of ~~2018, these increases were partly offset by lower sales volumes,~~2019 decreased $116 million, primarily due to impairments of equity method investments in our ~~Canada and~~ Lower 48 ~~segments, due~~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 ~~2017 disposition activity.~~Consolidated Financial Statements.

~~Equity~~

Gain on dispositions increased $1.7 billion in ~~earnings of affiliates~~ ~~for~~ the three- and nine-month periods of ~~2018 increased 50 percent and 34 percent, respectively,~~2019, primarily due to ~~higher earnings from QG3 and APLNG as~~ a ~~result~~$1.8 billion before-tax gain associated with the completion of ~~higher LNG prices for both affiliates and higher sales volumes from QG3. The absence~~the sale of ~~equity in earnings from FCCL following~~two ConocoPhillips U.K. subsidiaries to Chrysaor E&P Limited. For additional information related to our U.K. disposition, ~~to Cenovus Energy in the second quarter of 2017 partly offset the increase in nine-month 2018 earnings.~~see Note 5—Asset Dispositions.

~~Gain on dispositions~~

Other income for the ~~third quarter~~nine-month period of ~~2018 decreased $133~~2019 increased $463 million, primarily due to ~~the absence of~~ a ~~$281~~$302 millionbefore-tax gain related to the sale of certain Canadian assets recognized in the third quarter of 2017, partly offset by a gain on an unproved property exchange in the Lower 48 in the third quarter of 2018. Gain on dispositions in the nine-month period of 2018 decreased $2.0 billion, primarily due to the absence of a $2.1 billion~~before-tax~~ gain on the 2017 Canadian asset sale. For more information on dispositions, see Note 5—Assets Held for Sale, Dispositions, Acquisitions and Other Planned Transactions, in the Notes to Consolidated Financial Statements.

~~Other income~~ ~~for the third quarter of 2018 increased $244 million, primarily due to recognizing $345 million related to a settlement agreement with PDVSA, partly offset by a $73 millionbefore-tax~~ net unrealized loss on our Cenovus Energy common shares. In the nine-month period of 2018, other income increased $530 million primarily due to recognizing $345 million related to the settlement agreement with PDVSA referenced above, as well as a $187 million~~before-tax~~ higher unrealized gain on our Cenovus Energy common shares.

~~For discussion of our PDVSA settlement, see Note 4—Inventories and Note 13—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.~~

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 ~~2018 increased 21~~2019 decreased 23 percent and 1412 percent, respectively, primarily due to ~~higher~~lower crude oil ~~prices~~ and ~~higher crude volumes purchased, partly offset by lower~~ natural gas ~~prices during the nine-month period.~~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 ~~2018~~2019 increased ~~$145~~$257 million and ~~$13~~$325 million, respectively, primarily due to ~~costs associated with~~ higher ~~underlying production volumes as well as higher maintenance~~leasehold impairment and ~~wellwork, largely offset by lower costs from disposition impacts in our Canada and Lower 48 segments during the nine-month period of 2018.~~

~~Exploration expenses~~ ~~decreased $453 million in the nine-month period of 2018, primarily due to the absence of first quarter 2017~~ dry hole ~~and leasehold impairment costs of $342 million associated with the Shenandoah prospect in deepwater Gulf of Mexico as well as the absence of a $43 millionbefore-tax~~ ~~charge for the cancellation of our Athena drilling rig contract and other rig stacking~~ costs in our ~~Other International~~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 ~~2018 decreased 7~~2019 increased 5 percent and 176 percent, respectively, mainly due to ~~lowerunit-of-production~~ ~~rates from reserve additions and disposition impacts~~higher production volumes in ~~our Canada and~~the Lower 48 ~~segments,~~and Alaska, partly offset by ~~increased underlying production volumes.~~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.

~~Impairments~~

Other expenses decreased ~~$6.4 billion~~$292 million in the nine-month period of ~~2018, mainly~~2019, primarily due to the absence of ~~second quarter 2017 impairments of $3.3 billion~~a $206 million before-tax expense for ~~our interests in the San Juan Basin~~premiums on early debt retirements and ~~$0.6 billionbefore-tax~~ ~~for our interests in the Barnett, both in our Lower 48 segment, as well as a $2.4 billion before- andafter-tax~~ ~~impairment of our equity investment in APLNG. For additional information, see Note 9—Impairments, in the Notes to Consolidated Financial Statements.~~lower pension settlement expense.

~~Taxes other than income taxes~~ for the three- and nine-month periods of 2018 increased $137 million and $164 million, respectively, primarily due to higher production taxes in Alaska and the Lower 48 corresponding with higher realized commodity prices.

~~Interest and debt expense~~ ~~decreased $65 million and $325 million in the three- and nine-month periods of 2018, respectively, because of lower debt balances.~~

See Note 22—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding ourincome tax provision ~~(benefit)~~ 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.

~~Summary Operating Statistics~~

   Three Months Ended
September 30 Nine Months Ended
September 30
   2018    2017 2018    2017


Average Net Production

Crude oil (MBD)⁽¹⁾
   635    582 632    591
Natural gas liquids (MBD)
   106    95 102    119
Bitumen (MBD)
   65    63 65    140
Natural gas (MMCFD)⁽²⁾
   2,732    2,918 2,771    3,405

Total Production(MBOED)⁽³⁾
   1,261    1,226 1,261    1,418

   Dollars Per Unit
Average Sales Prices

Crude oil (per barrel)
   73.05    49.39 69.74    49.51
Natural gas liquids (per barrel)
   35.14    23.82 31.31    23.25
Bitumen (per barrel)
   34.15    24.19 26.46    22.25
Natural gas (per thousand cubic feet)
   5.81    4.11 5.37    3.91

   Millions of Dollars
Exploration Expenses

General administrative, geological and geophysical, lease rental, and other
   $ 75    66 ⁽⁴⁾   203    285 ⁽⁴⁾
Leasehold impairment
   16    10 36    81
Dry holes
   12    (3 ) 28    354

   $ 103    73 ⁽⁴⁾   267    720 ⁽⁴⁾

~~(1) Thousands of barrels per day.~~

~~(2) Millions of cubic feet per day. Represents quantities available for sale and excludes gas equivalent of natural gas liquids included above.~~

~~(3) Thousands of barrels of oil equivalent per day.~~

~~(4) Certain amounts have been reclassified to conform to the current period presentation as a result of the adoption of ASUNo. 2017-07.~~ ~~See Note 2—Changes in Accounting Principles, in the Notes to Consolidated Financial Statements, for additional information.~~

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and ~~natural gas liquids~~NGLs on a worldwide basis. ~~At September 30, 2018,~~During the third quarter of 2019, our operations were producing in the ~~United States,~~U.S., Norway, the ~~United Kingdom,~~U.K., Canada, Australia, Timor-Leste, Indonesia, China, Malaysia, Qatar and Libya.

Total production increased 35105 MBOED or 38 percent in the third quarter of ~~2018,~~2019, primarily due to:

New wells online in the Lower ~~48,~~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 ~~China.~~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.

~~The absence~~48

Table of ~~Hurricane Harvey impacts on our Lower 48 segment~~Contents

Total production increased 92 MBOED or 7 percent in the ~~third quarter~~nine-month period of ~~2017.~~2019, primarily due to:

~~The continuedramp-up~~

New wells online in ~~Libya.~~the Lower 48.

An increased interest in the Western North Slope (WNS) and GKA of Alaska following ~~our second quarter 2018 acquisition.~~

~~The increase~~acquisitions closed in ~~third quarter 2018~~2018.

Higher production ~~was partly offset by:~~

~~Normal field decline.~~

~~Disposition impacts~~ in ~~the Lower 48 from the sale of San Juan and other noncore assets in 2017.~~

~~Higher unplanned downtime, mainly in the Lower 48 and Malaysia.~~

~~Total production decreased 157 MBOED or 11 percent in the nine-month period of 2018, primarily~~Norway due ~~to:~~

~~Disposition impacts from asset sales in Canada~~to drilling activity and the ~~Lower 48.~~

~~Normal field decline.~~

~~Higher unplanned downtime related to a third-party pipeline outage~~startup of Aasta Hansteen in ~~Malaysia.~~December 2018.

The ~~decrease~~increase in production during the nine-month period of ~~2018~~2019 was partly offset by:

~~New wells online~~Normal field decline.

Disposition impacts from ~~tight oil plays~~non-core asset sales, primarily in the Lower ~~48, Malikai~~48.

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

~~Improved drilling and well performance in Alaska, Lower 48, Norway and China.~~

~~The continuedramp-up~~ ~~in Libya.~~

Production excluding Libya was ~~1,224~~1,322 MBOED in the third quarter of ~~2018,~~2019, an increase of 2298 MBOED ~~compared with the same period of 2017.~~or 8 percent. Our underlying production, which excludes Libya and the ~~third-quarter~~net volume impact from closed dispositions and acquisitions of ~~dispositions of approximately 50~~58 MBOED in ~~2017,~~2019 and 43 MBOED in 2018, increased ~~6 percent compared with~~83 MBOED or 7 percent.

Production excluding Libya was 1,310 MBOED in the ~~same~~nine-month period of ~~2017.~~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.

Table of Contents

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

~~Segment Results~~

~~Alaska~~

   Three Months Ended
September 30    Nine Months Ended
September 30
   2018    2017    2018    2017




Net Income Attributable to ConocoPhillips(millions of dollars)
   $ 427    103    1,369    291

Average Net Production

Crude oil (MBD)
   152    154    165    166
Natural gas liquids (MBD)
   12    11    14    14
Natural gas (MMCFD)
   5    5    6    7

Total Production(MBOED)
   165    166    180    181

Average Sales Prices

Crude oil (dollars per barrel)
   $ 76.47    50.53    72.44    50.81
Natural gas (dollars per thousand cubic feet)
   2.52    4.55    2.51    2.77

The Alaska segment primarily explores for, produces, transports and markets crude oil, ~~natural gas liquids~~NGLs and natural gas. As of September 30, ~~2018,~~2019, Alaska contributed 2224 percent of our worldwide liquids production and less than 1 percent of our worldwide natural gas production.

Earnings from Alaska for the ~~three-~~third quarter of 2019 decreased $121 million, primarily because of lower realized crude oil prices, the absence of enhanced oil recovery credits, and ~~nine-month periods ended September 30, 2018, increased $324 million~~higher DD&A and ~~$1,078 million, respectively, compared~~production and operating expenses associated with higher production volumes. Partly offsetting the ~~corresponding periods in 2017. The increase~~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 ~~both periods was~~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 ~~higher realized crude oil prices. Additionally, earnings~~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 ~~2018 were improved~~2019, primarily due to acquiring incremental interests in WNS during the ~~absence of a $110 millionafter-tax~~ ~~impairment related to our small interest in the Point Thomson Unit, recognized in the first~~second quarter of ~~2017; lower DD&A expense from reserve additions;~~2018 and ~~a $79 millionafter-tax~~ ~~benefit resulting from an accrual reduction due to a transportation cost ruling by~~incremental interests in GKA during the ~~FERC, recorded in the first~~fourth quarter of 2018.

~~Average~~ These acquisitions increased production ~~was down 1~~by a combined 41 MBOED in the ~~three- and~~ nine-month ~~periods~~period of ~~2018 compared with~~2019. Production also increased in the ~~corresponding periods in 2017, primarily~~nine-month period of 2019 due to ~~higher~~lower planned ~~downtime and normal field decline,~~downtime. These production increases were partly offset by ~~production increases from improved drilling and well performance.~~ normal field decline.

Acquisition Update

In the third quarter of ~~2018, production included 8 MBOED due to the acquisition in the Western North Slope discussed below.~~

~~Acquisitions~~

~~During the second quarter of 2018,~~2019, we ~~obtained regulatory approvals and~~ completed the ~~transaction we entered into with Anadarko Petroleum Corporation to acquire its 22 percent nonoperated interest in~~previously announced Nuna discovery acreage acquisition for approximately $100 million, expanding the ~~Western North Slope~~Kuparuk River Unit and leveraging legacy infrastructure.

Table of Alaska, as well as its interest in the Alpine Pipeline, for $386 million, after customary adjustments. In 2017, the net production associated with this interest was 11 MBOED. In addition, we now have 100 percent interest in approximately 1.2 million acres of exploration and development lands, including the Willow discovery.Contents

In July 2018, we entered into agreements with BP to acquire their nonoperated interest in the Greater Kuparuk Area and Kuparuk Transportation Company in Alaska, and to sell a ConocoPhillips subsidiary to BP, which will hold 16.5 percent of our 24 percent interest in the~~BP-operated~~ ~~Clair Field in the United Kingdom. Both transactions are subject to regulatory approvals and are expected to close simultaneously in 2018. Full-year 2017 production andyear-end~~ ~~2017 proved reserves associated with the 39.2 percent interest in the Greater Kuparuk Area were approximately 38 MBOED and 190 MMBOE, respectively.~~

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

~~See Note 5—Assets Held for Sale, Dispositions, Acquisitions and Other Planned Transactions in the Notes to Consolidated Financial Statements, for additional information.~~

~~Lower 48~~

   Three Months Ended
September 30 Nine Months Ended
September 30
   2018    2017 2018    2017


Net Income (Loss) Attributable to ConocoPhillips(millions of dollars)
   $ 513    (97 ) 1,231    (2,995 )

Average Net Production

Crude oil (MBD)
   240    175 218    176
Natural gas liquids (MBD)
   73    64 68    73
Natural gas (MMCFD)
   608    765 589    1,007

Total Production (MBOED)
   414    366 384    417

Average Sales Prices

Crude oil (dollars per barrel)
   $ 67.73    45.29 65.38    44.84
Natural gas liquids (dollars per barrel)
   32.17    20.72 28.06    20.55
Natural gas (dollars per thousand cubic feet)
   2.80    2.63 2.63    2.74

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, ~~2018,~~2019, the Lower 48 contributed 3739 percent of our worldwide liquids production and 21 percent of our worldwide natural gas production.

Earnings from the Lower 48 for the ~~three-~~third quarter of 2019 decreased $487 million, primarily due to lower realized crude oil, NGL and ~~nine-month periods~~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 ~~2018~~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 ~~$610 million and $4,226 million, respectively, compared with corresponding periods~~production volumes. Partly offsetting the decrease in ~~2017. Both periods benefitted from higher realized~~earnings was increased crude oil and NGL ~~prices and higher crude oil sales volumes. Earnings~~volumes in the ~~third quarter of 2018 also increased due to a $44 millionafter-tax~~ ~~gain related to an undeveloped property exchange.~~Eagle Ford, Bakken and Delaware in the Permian Basin.

~~Earnings in~~

In the nine-month period of ~~2018 increased~~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 ~~absence~~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 ~~second quarter 2017 impairments totaling $2.5 billionafter-tax~~ ~~for~~ our interests in the ~~San Juan Basin~~Golden Pass LNG Terminal and Golden Pass Pipeline in the ~~Barnett; lower DD&A expense, primarily due~~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 ~~reserve additions and asset disposition impacts, partly offset by higher underlying volumes; and lower exploration expenses. Exploration expenses were lower, mainly due~~our impairment of MWCC, see Note 3—Variable Interest Entities in the Notes to Consolidated Financial Statements. For more information related to the ~~absence~~sale of ~~first quarter 2017 dry hole~~our interests in Golden Pass LNG Terminal and ~~impairment charges of $189 millionafter-tax~~Golden Pass Pipeline, see Note 5—Asset Dispositions and ~~$33 millionafter-tax,~~ ~~respectively, for multiple Shenandoah wells and associated leases.~~Note 14—Fair Value Measurement in the Notes to Consolidated Financial Statements.

Total average production ~~for~~increased 55 MBOED and 60 MBOED in the three- and nine-month periods of ~~2018, adjusted for dispositions and Hurricane Harvey, increased approximately 27 percent and 22 percent, respectively. These underlying production increases were~~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. ~~Disposition impacts from the sale of San Juan and other noncore asset sales were approximately 50 MBOED and 105~~Additionally, production decreased by 12 MBOED in the three- and nine-month periods of ~~2017, respectively. Production~~2019 due to non-core dispositions in 2018.

Table of Contents

Asset Disposition Update

In January 2019, we entered into agreements to sell our 12.4 percent ownership interests in the ~~third quarter~~Golden Pass LNG Terminal and Golden Pass Pipeline. We have also entered into agreements to amend our contractual obligations for retaining use of ~~2017 was impacted by 15 MBOED from Hurricane Harvey.~~

~~Asset Dispositions Update~~

Inthe facilities. As a result of entering into these agreements, we recognized a before-tax impairment of $60 million in the first quarter of ~~2018, we completed the sale of certain properties~~2019 which is included in the ~~Lower 48 segment for net proceeds~~“Equity in earnings of ~~$112 million. No gain or loss was recognized~~affiliates” line on ~~the sale.~~our consolidated income statement. In the second quarter of ~~2018,~~2019, we completed the ~~sale of a package of largely undeveloped acreage for net proceeds of $105 million. No gain or~~

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.

loss was recognized on the sale. In the third quarter of 2018, we completed a noncash exchange of undeveloped acreage in the Lower 48 segment. This transaction was recorded at fair value resulting in the recognition of a $44 million~~after-tax~~ ~~gain.~~

In the third quarter of 2018, we signed a definitive agreement to sell our interest in the Barnett for approximately $230 million, plus customary adjustments. Full-year 2017 production associated with the Barnett averaged 10 MBOED, of which approximately 55 percent was natural gas and 45 percent was natural gas liquids.~~After-tax~~ impairment charges of $33 million and $68 million were recognized in the three- and nine-month periods of 2018, respectively, to reduce the carrying value to fair value less costs to sell. The transaction is expected to close by~~year-end~~ ~~2018.~~

~~See Note 5—Assets Held for Sale, Dispositions, Acquisitions and Other Planned Transactions in the Notes to Consolidated Financial Statements, for additional information.~~

~~Acquisition~~

During the fourth quarter of 2017, we acquired approximately 200,000 net acres of early life-cycle unconventional acreage in the Austin Chalk play in central Louisiana for approximately $200 million. We began an exploration drilling program in the fourth quarter of 2018.

~~Canada~~

   Three Months Ended
September 30    Nine Months Ended
September 30
   2018    2017    2018    2017




Net Income Attributable to ConocoPhillips(millions of dollars)
   $ 34    280    2    2,607

Average Net Production

Crude oil (MBD)
   1    1    1    3
Natural gas liquids (MBD)
   2    1    1    12
Bitumen (MBD)

Consolidated operations
   65    63    65    56
Equity affiliates
   —    —    —    84

Total bitumen
   65    63    65    140
Natural gas (MMCFD)
   12    10    13    246

Total Production(MBOED)
   70    67    69    196

Average Sales Prices

Crude oil (dollars per barrel)
   $ —    —    —    43.46
Natural gas liquids (dollars per barrel)
   —    —    —    21.44
Bitumen (dollars per barrel)*

Consolidated operations
   34.15    24.19    26.46    19.93
Equity affiliates
   —    —    —    23.83
Total bitumen
   34.15    24.19    26.46    22.25
Natural gas (dollars per thousand cubic feet)
   —    —    —    1.95

*Average prices for sales of bitumen produced during 2018 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, ~~2018,~~2019, Canada contributed 87 percent of our worldwide liquids production and less than 1 percent of our worldwide natural gas production.

Earnings from Canada ~~decreased $246~~increased $17 million in the third quarter of ~~2018 compared with the corresponding period in 2017,~~2019, primarily because of lower DD&A expense due to ~~the absence of a $190~~lower rates from reserve additions and lower production and operating expenses. Earnings increased $271 million~~after-tax~~ gain for funds received in relation to environmental claims related to disposition activity and the absence of a $114 million tax benefit related to our decision to exit Nova Scotia, both recognized in the third quarter of 2017. Partly offsetting these impacts were higher realized bitumen prices.

~~Earnings from Canada decreased $2.6 billion~~ in the nine-month period of ~~2018 compared with~~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 ~~corresponding~~nine-month period increase in ~~2017,~~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 absence of earnings associated with certain Canadian assets, including our interest in the FCCL Partnership, sold to Cenovus Energy in the second quarter of 2017. The nine-month period of 2017 included $1.6 billion in~~after-tax~~ ~~gains, $1.0 billion in deferred tax benefits, and equity earnings in the FCCL Partnership.~~

For additional information on the 2017 Canada disposition, see Note 5—Assets Held for Sale, Dispositions, Acquisitions and Other Planned Transactions and Note 7—Investment in Cenovus Energy, in the Notes to Consolidated Financial Statements.

~~Total average~~Alberta government which impacted production ~~increased 4 percent~~ in the third quarter ~~of 2018, primarily due~~by 3 MBOED. The curtailment measure, which began in January 2019, is intended to ~~lower planned downtime~~strengthen the WCS differential to WTI at Hardisty and ~~improved drilling and well performance.~~is currently anticipated to expire in December 2020. Total average production decreased ~~65 percent~~7 MBOED in the nine-month period of ~~2018,~~2019, primarily due to ~~our 2017 Canada disposition, partly offset by new wells online at~~a 4 MBOED impact from a planned turnaround in Surmont and ~~Montney.~~3 MBOED related to a mandated production curtailment.

Table of Contents

~~Acquisition~~

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

In February 2018, we acquired approximately 34,500 net acres of undeveloped land in the Montney in Canada for a net purchase price of approximately $120 million. The additional acreage is adjacent to our existing position in the liquids-rich portion of the Montney.

~~Europe and North Africa~~

   Three Months Ended
September 30    Nine Months Ended
September 30
   2018    2017    2018    2017




Net Income Attributable to ConocoPhillips(millions of dollars)
   $ 241    85    776    379

Average Net Production

Crude oil (MBD)
   145    141    147    139
Natural gas liquids (MBD)
   8    7    8    8
Natural gas (MMCFD)
   452    408    502    475

Total Production(MBOED)
   229    216    240    227

Average Sales Prices

Crude oil (dollars per barrel)
   $ 76.54    51.05    71.38    51.90
Natural gas liquids (dollars per barrel)
   38.80    31.16    37.75    29.69
Natural gas (dollars per thousand cubic feet)
   7.62    5.09    7.40    5.34

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, ~~2018,~~2019, our Europe and North Africa operations contributed 1917 percent of our worldwide liquids production and 1819 percent of our worldwide natural gas production.

Earnings for Europe and North Africa increased by ~~$156 million and $397 million~~approximately $1.8 billion in the three- and nine-month periods of ~~2018, respectively, compared with the corresponding periods in 2017,~~2019, primarily due to ~~higher realized crude oil and natural gas prices and lower DD&A expense due~~a gain associated with the completion of the sale of two ConocoPhillips U.K. subsidiaries to ~~reserve additions. Additionally, earnings in the~~Chrysaor E&P Limited. The nine-month period ~~of 2018 increased by $31 million~~gain associated with this sale was approximately $2.1 billion after-tax, ~~because~~ comprised of a ~~reduction to impairment due to decreased asset retirement obligation estimates for a certain field in the United Kingdom which was impaired in prior years, offset by the absence of a $41 million~~U.S. tax benefit ~~in Norway,~~of $234 million, recorded in the second quarter, related to the recognition of ~~2017.~~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 63 percent in ~~both~~ the ~~three- and nine-month periods~~third quarter of ~~2018 compared with the corresponding periods in 2017,~~2019, primarily due to ~~higher production in Libya, improved drilling and well performance and~~ new wells online in Norway and the ~~United Kingdom. These increases~~U.K., including the rampup of production at Aasta Hansteen in Norway, and lower unplanned downtime. Partly offsetting this increase in production, ~~were partly offset by~~was normal field decline and ~~the final cessation of production in several producing gas fields~~planned turnarounds in the ~~Southern North Sea~~U.K. and Norway. Average production decreased 1 percent in the ~~third quarter of 2018. Full-year 2017 average net production in the Southern North Sea was 46 million cubic feet a day or 8 MBOED.~~

~~Libya production wasshut-in~~ ~~frommid-June~~ ~~2018 through the end of the second quarter because of the Es Sider crude oil export terminal closure following a~~nine-month period of ~~civil unrest. Exports resumed in July 2018.~~2019.

~~Disposition~~

Asset Disposition Update

In ~~July 2018,~~April 2019, we entered into ~~agreements~~an agreement to sell two ConocoPhillips U.K. subsidiaries to Chrysaor E&P Limited for $2.675 billion plus interest and customary adjustments, with ~~BP to acquire their nonoperated interest~~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 ~~Greater Kuparuk Area and Kuparuk Transportation Company in Alaska, and to sell a ConocoPhillips subsidiary to BP, which will hold 16.5 percent~~U.K. In the first nine months of ~~our 24 percent interest in~~2019, production associated with the~~BP-operated~~ Clair Field in the United Kingdom. Both transactions are subject to regulatory approvals and are expected to close simultaneously in 2018. Excluding customary adjustments, the transactions are expected to be cash neutral. Full-year 2017 production and~~year-end~~ ~~2017 proved~~ U.K. assets sold was 68 MBOED. Year-end 2018 reserves associated with the ~~16.5 percent interest~~U.K. assets sold were 99 MMBOE.For additional information, see Note 5—Asset Dispositions in the ~~Clair Field were approximately 3 MBOED and 40 MMBOE, respectively. Depending on the timing~~Notes to Consolidated Financial Statements.

Table of ~~regulatory approvals, we anticipate recognizing a noncash gain of between $0.5 billion to $1.0 billion on completion of the sale of the~~

Contents

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

ConocoPhillips subsidiary holding 16.5 percent of the Clair Field, after customary adjustments and foreign exchange impacts. See Note 5—Assets Held for Sale, Dispositions, Acquisitions and Other Planned Transactions, for additional information.

~~Asia Pacific and Middle East~~

   Three Months Ended
September 30    Nine Months Ended
September 30
   2018    2017    2018    2017




Net Income (Loss) Attributable to ConocoPhillips(millions of dollars)
   $ 577    396    1,504    (1,540 )

Average Net Production

Crude oil (MBD)

Consolidated operations
   84    97    87    93
Equity affiliates
   13    14    14    14

Total crude oil
   97    111    101    107

Natural gas liquids (MBD)

Consolidated operations
   3    4    3    5
Equity affiliates
   8    8    8    7

Total natural gas liquids
   11    12    11    12

Natural gas (MMCFD)

Consolidated operations
   630    690    617    673
Equity affiliates
   1,025    1,040    1,044    997

Total natural gas
   1,655    1,730    1,661    1,670

Total Production(MBOED)
   383    411    388    397

Average Sales Prices

Crude oil (dollars per barrel)

Consolidated operations
   $ 74.78    52.06    71.98    51.73
Equity affiliates
   76.62    52.29    73.00    52.87
Total crude oil
   75.02    52.10    72.13    51.88
Natural gas liquids (dollars per barrel)

Consolidated operations
   52.30    35.74    48.15    38.28
Equity affiliates
   49.71    35.94    45.74    37.59
Total natural gas liquids
   50.71    35.86    46.48    37.84
Natural gas (dollars per thousand cubic feet)

Consolidated operations
   6.53    4.63    5.88    4.87
Equity affiliates
   6.35    4.51    5.70    4.28
Total natural gas
   6.42    4.56    5.76    4.52

The Asia Pacific and Middle East segment has operations in China, Indonesia, Malaysia, Australia, Timor-Leste and ~~Qatar, as well as exploration activities in Brunei.~~Qatar. As of September 30, ~~2018,~~2019, Asia Pacific and Middle East contributed 1413 percent of our worldwide liquids production and 6160 percent of our worldwide natural gas production.

Earnings increased ~~$181 million and $3,044~~$36 million in the ~~three-~~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 ~~nine-month periods of 2018, respectively, compared with the corresponding periods in 2017. Both periods benefitted from higher realized~~natural gas prices, and ~~improved equity earnings from APLNG~~lower crude oil and ~~QG3,~~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, ~~for both periods~~

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 ~~higher sales volumes from QG3 during~~lower unplanned downtime. Partly offsetting this production increase was normal field decline. In the nine-month period of ~~2018. Additionally, the nine-month period of 2018 was improved due to the absence of a $2,384 million before- andafter-tax~~ ~~charge for the impairment of our APLNG investment, recorded in~~2019, average production increased 1 percent.

Asset Dispositions Update

In the second quarter of ~~2017. See~~2019, we recognized an after-tax gain of $52 million upon completion of the ~~“APLNG” section~~sale of ~~Note 6—Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements, for information on the impairment of our APLNG investment.~~

Average production decreased 7 percent and 2 percent in the three- and nine-month periods of 2018, respectively, compared with the corresponding periods in 2017. In both periods, production decreased due to normal field decline; unplanned downtime in Malaysia related to the rupture of a third-party pipeline which carries gas production from the Kebabangan gas field in Malaysia; and production curtailment in Qatar. These impacts were partly offset by an infill drilling program in China and new wells online at Malakai in Malaysia.

~~Asset Disposition Update~~

~~In October 2018, we announced an agreement to sell~~ our 30 percent interest in the Greater Sunrise Fields ~~for $350 million, prior to customary adjustments,~~ to the government of Timor-Leste with an expected closing date in early 2019. The transaction is conditional on funding approval from the Timor-Leste Council of Ministers and National Parliament, as well as regulatory approvals and partner~~pre-emption~~ ~~rights. The interest to be sold is undeveloped property in the Timor Sea located between Australia and Timor-Leste.~~for $350 million. No production or reserve impacts ~~are~~were associated with the sale.

~~Other International~~

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.

   Three Months Ended
September 30 Nine Months Ended
September 30
   2018    2017 2018    2017


Net Income (Loss) Attributable to ConocoPhillips(millions of dollars)
   $ 316    (20 ) 267    (77 )

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 ~~primarily~~ consists of exploration activities in Colombia, Chile and ~~Chile.~~Argentina.

Earnings from our Other International ~~segment increased $336 million and $344~~operations decreased $243 million in the ~~three- and nine-month periods~~third quarter of ~~2018, respectively, compared with the corresponding periods in 2017. The increase in earnings is~~2019, primarily due to ~~recognizing $325~~$239 million less after-tax in other income ~~under~~related to a settlement ~~agreement~~award with PDVSA associated with prior ~~operations.~~operations in Venezuela. See Note ~~4—Inventories and Note 13—~~12—Contingencies and Commitments in the Notes to Consolidated Financial Statements, for additional information.

~~Additionally,~~

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 ~~nine-month period~~central Argentine province of ~~2018, earnings increased due to~~Neuquén. As part of the ~~absence of~~transaction, we will acquire a ~~$28 millionafter-tax~~ ~~charge for the cancellation of our Athena drilling rig contract and rig stacking costs in Angola,~~45 percent interest in the ~~first quarter of 2017. Partially offsetting this increase in earnings, was a $34 million tax settlement charge, recognized~~Aguada Federal Block situated in the ~~first quarter~~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.

Table of ~~2018, associated with prior operations in Nigeria.~~

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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)

~~Corporate and Other~~

   Millions of Dollars
   Three Months Ended
September 30 Nine Months Ended
September 30
   2018 2017 2018 2017


Net Loss Attributable to ConocoPhillips

Net interest
   $ (174 ) (176 ) (508 ) (603 )
Corporate general and administrative expenses
   (36 ) (42 )* (139 ) (132 )*
Technology
   64 20 117 29
Other
   (101 ) (129 )* (230 ) (393 )*

   $ (247 ) (327 ) (760 ) (1,099 )

*Certain amounts have been reclassified to reflect the adoption of ASU~~No. 2017-07.~~ ~~See Note 2—Changes in Accounting Principles, in the Notes to Consolidated Financial Statements, for additional information.~~

Net interest consists of interest and financing expense, net of interest income and capitalized interest. Net interest ~~was reduced~~decreased by ~~$2 million and $95~~$51 million in the ~~three-~~third quarter of 2019, primarily due the settlement of certain tax disputes and higher interest income. In the nine-month ~~periods ended September 30, 2018, respectively. Both periods benefitted from less~~period of 2019, net interest decreased by $58 million, primarily due to lower interest from ~~lower debt balances and higher capitalized interest on projects,~~the settlement of certain tax disputes, partly offset by ~~impacts~~higher interest from the ~~fair market value method~~absence of apportioning interest expense in the United States, and reduced tax benefit on interest expense following the Tax Cuts and Jobs Act (Tax Legislation), which lowered the U.S. corporate income tax rate from 35 percent to 21 percent effective January 1, 2018. The nine-month period of 2018 benefitted from lower interest due to an accrual reduction ~~given~~related to a transportation cost ruling by the ~~FERC in the first quarter of 2018, and higher interest income.~~FERC.

Corporate ~~general and administrative~~G&A expenses include compensation programs and staff costs. These expenses decreased by $6$2 million and increased by $7$9 million in the three- and nine-month periods of ~~2018, respectively.~~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, ~~and~~ oil sands, ~~as well as~~enhanced oil recovery, and LNG. Earnings from Technology ~~increased $44~~decreased $21 million and ~~$88~~increased $12 million in the three- and nine-month periods of ~~2018,~~2019, respectively, primarily due to ~~higher~~changes in licensing ~~revenues. See Note 20—Sales and Other Operating Revenues, in the Notes to Consolidated Financial Statements, for additional information.~~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. ~~Losses in~~ “Other” ~~decreased~~increased by ~~$28~~$201 million in the third quarter of ~~2018,~~2019, primarily due to ~~lower taxes and the absence of premiums associated with the early retirement of debt, both recognized in the third quarter of 2017, partly offset by~~ an unrealized ~~loss~~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. ~~Losses in “Other” decreased by $163 million in~~In the nine-month period of ~~2018,~~2019, “Other” increased by $763 million primarily due to ana $328 million larger after-tax unrealized gain on our Cenovus Energy common shares, ~~and lower~~the absence of $195 million after-tax related to premiums ~~associated with the~~on early retirement of debt, ~~partly offset by higher~~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.

~~CAPITAL RESOURCES AND LIQUIDITY~~

~~Financial Indicators~~

   Millions of Dollars
   September 30
2018 December 31
2017


Short-term debt
   $ 95 2,575
Total debt
   14,997 19,703
Total equity
   32,079 30,801
Percent of total debt to capital*
   32 % 39
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 ~~2018,~~2019, the primary uses of our available cash were ~~$5,133~~$5,041 million to support our ongoing capital expenditures and investments program, ~~$4,970 million to reduce debt, $2,073~~$2,751 million to repurchase common stock, and ~~$1,009~~$1,037 million to pay dividends. During the ~~first nine months of 2018,~~nine-month period, our cash, cash equivalents and restricted cash ~~decreased~~increased by ~~$2,596~~$1,307 million to ~~$3,940~~$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 ~~$9,151~~$8,122 million for the first nine months of ~~2018,~~2019, compared with ~~$4,596~~$9,151 million for the corresponding period of ~~2017.~~2018. The ~~increase was~~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 ~~realized prices across all commodities.~~ 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 ~~natural gas liquids.~~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 ~~2018~~2019 were ~~$394~~$2,920 million compared with ~~$13,740~~$394 million for the corresponding period of ~~2017.~~ 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 ~~segment~~ for ~~net~~ proceeds of $317 million and received ~~$50~~$64 million of contingent payments from Cenovus Energy. ~~In the first nine months of 2017, we completed several dispositions including the sale of certain Canadian assets to Cenovus Energy for cash proceeds of $11 billion, the sale of our interests~~

See Note 5—Asset Dispositions in the ~~San Juan Basin~~Notes to Consolidated Financial Statements for proceeds of $2.5 billion in cash after customary adjustments, and the sale of our interest in the Panhandle assets for $178 million in cash after customary adjustments. All cash deposits and proceeds from asset dispositions are included in the “Cash Flows From Investing Activities” section of our consolidated statement of cash flows. For more information on asset dispositions, see Note 5—Assets Held for Sale, Dispositions, Acquisitions and Other Planned Transactions.additional information.

Commercial Paper and Credit Facilities

~~In May 2018, we refinanced our~~We have a revolving credit facility ~~from a total aggregate principal of $6.75 billion to~~totaling $6.0 billion, ~~with a new expiration date of~~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 ~~our~~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 ~~in programs in place~~ at September 30, ~~2018~~2019 or December 31, ~~2017.~~2018. We had no direct outstanding borrowings or letters of credit under the revolving credit facility at September 30, ~~2018 and~~2019 or December 31, ~~2017.~~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, ~~2018.~~2019.

~~In August 2018, Fitch upgraded our long-term debt rating from“A-”~~ to “A” and adjusted their outlook for our debt from “positive” to “stable.” In September 2018, Moody’s Investors Services upgraded their rating on our long-term debt from “Baa1” to “A3” and adjusted their outlook for our debt from “positive” to “stable.” As of September 30, 2018, Standard & Poor’s rating for our long-term debt was~~“A-”~~ with a “stable” outlook. We do not have any ratings triggers on any of our corporate debt that would cause an automatic default, and thereby impact our access to liquidity, in the event of a downgrade of our credit rating. If our credit rating were downgraded, it could increase the cost of corporate debt available to us and restrict our access to the commercial paper markets. If our credit rating were to deteriorate to a level prohibiting us from accessing the commercial paper market, we would still be able to access funds under our revolving credit facility.

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, ~~2018~~2019 and December 31, ~~2017,~~2018, we had direct bank letters of credit of ~~$275~~$221 million and ~~$338~~$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. ~~Securities and Exchange Commission (SEC)~~SEC under which we ~~as a well-known seasoned issuer,~~ have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.

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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 ~~12—~~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, ~~2018,~~2019, was $15 billion, ~~which~~unchanged from December 31, 2018.

On January 30, 2019, we announced ~~as our stated debt target in November 2017. We achieved that goal in the second quarter of 2018, significantly earlier than the original target date ofyear-end~~ ~~2019. The $15 billion debt balance is~~ a ~~decrease of $4.7 billion from the balance at December 31, 2017.~~

~~In the first quarter of 2018, we redeemed or repurchased a total of $2,650 million of debt as described below:~~

~~4.20% Notes due 2021 with remaining principal of $1.0 billion.~~

~~2.875% Notes due 2021 with principal of $750 million.~~

~~2.2% Notes due 2020 with principal of $500 million.~~

~~8.125% Notes due 2030 with principal of $600 million (partial repurchase of $210 million).~~

~~7.8% Notes due 2027 with principal of $300 million (partial repurchase of $97 million).~~

~~7.9% Notes due 2047 with principal of $100 million (partial repurchase of $40 million).~~

~~9.125% Notes due 2021 with principal of $150 million (partial repurchase of $27 million).~~

~~8.20% Notes due 2025 with principal of $150 million (partial repurchase of $16 million).~~

~~7.65% Notes due 2023 with principal of $88 million (partial repurchase of $10 million).~~

~~In the second quarter of 2018, we repurchased a total of $1,800 million of debt as described below:~~

~~2.4% Notes due 2022 with principal of $1.0 billion (partial repurchase of $671 million).~~

~~3.35% Notes due 2024 with principal of $1.0 billion (partial repurchase of $574 million).~~

~~3.35% Notes due 2025 with principal of $500 million (partial repurchase of $301 million).~~

~~4.15% Notes due 2034 with principal of $500 million (partial repurchase of $254 million).~~

~~During the first six months of 2018, we incurred net premiums above book value to redeem or repurchase these debt instruments of $208 million.~~

In the second quarter of 2018, we also repaid the $250 million floating rate note due in 2018 at its natural maturity. For information on debt, see Note 10—Debt, in the Notes to Consolidated Financial Statements.

~~On February 1, 2018, we announced an increase in the quarterly dividend to $0.285 per share, compared with the previous~~ quarterly dividend of ~~$0.265~~$0.305 per share. The dividend was paid on March 1, ~~2018,~~2019, to stockholders of record at the close of business on February ~~12, 2018.~~11, 2019. On May ~~4, 2018,~~1, 2019, we announced a quarterly dividend of ~~$0.285~~$0.305 per share. The dividend was paid on June ~~1, 2018,~~3, 2019, to stockholders of record at the close of business on May ~~14, 2018.~~13, 2019. On July 11, ~~2018,~~2019, we announced a quarterly dividend of ~~$0.285~~$0.305 per share. The dividend

was paid on September ~~4, 2018,~~3, 2019, to stockholders of record at the close of business on July ~~23, 2018.~~22, 2019. On October ~~5, 2018,~~7, 2019, we announced a 738 percent increase in the quarterly dividend to ~~$0.305~~$0.42 per ~~share,~~share. The dividend is payable on December ~~3, 2018,~~2, 2019, to stockholders of record at the close of business on October ~~15, 2018.~~17, 2019.

In late 2016, we initiated our current share repurchase program. As of ~~June 30,~~July 12, 2018, we had announced a total authorization to repurchase ~~a total of $6~~$15 billion of our common stock. We repurchased $3 billion in 2017 and ~~plan to repurchase~~ $3 billion in 2018. WeOf the remaining authorization, we expect ~~the 2018 program~~ to ~~be funded with cash from operations. On July 12, 2018, we announced an authorization of an additional $9~~repurchase $3.5 billion in ~~share~~2019 and $3 billion in 2020. Whether we undertake these additional repurchases ~~bringing~~is ultimately subject to numerous considerations, market conditions and other factors. See the ~~total program authorization~~“Our ability to ~~$15 billion.~~

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 97156 million shares at a cost of ~~$5.2~~$8.9 billion through September 30, ~~2018.~~2019.

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~~Capital Expenditures~~

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

   Millions of Dollars
   Nine Months Ended
September 30
   2018    2017


Alaska
   $ 1,034    636
Lower 48
   2,475    1,234
Canada
   318    180
Europe and North Africa
   678    657
Asia Pacific and Middle East
   493    316
Other International
   6    17
Corporate and Other
   129    34

Capital expenditures and investments
   $ 5,133    3,074

During the first nine months of ~~2018,~~2019, capital expenditures and investments supported key exploration and development programs, primarily:

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

~~Leasehold acquisition~~Basin, and ~~exploration, appraisal~~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 ~~Europe, including~~Norway and the ~~Greater Ekofisk Area, Clair Ridge and Aasta Hansteen.~~U.K.

~~Leasehold acquisition, optimization~~Optimization of oil sands development and appraisal activities in liquids-rich plays in Canada.

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

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 ~~appraisal activities~~the addition of a drilling rig in ~~Malaysia.~~

~~Total~~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 ~~for all activity is expected to be~~of $6.6 billion. The company’s 2018 operated capital scope remains unchanged, excluding acquisition-related activity. However, the company is adjusting its capital expenditures guidance to $6.1 billion from the original $5.5 billion budget. This guidanceGuidance also excludes obligations under the previously announced ~~$0.4 billionbolt-on~~ ~~acquisition in~~PSC extension awarded by the ~~Alaska Western North Slope and $0.1 billion to acquire additional acreage in the Montney in Canada.~~

Government of Indonesia.

~~Contingencies~~

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 toincome-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.

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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 ~~13—~~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.

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

~~Environmental~~

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 ~~61–63~~65–67 of our ~~2017~~2018 Annual Report on Form10-K.

We occasionally receive requests for information or notices of potential liability from the ~~Environmental Protection Agency (EPA)~~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, ~~2018,~~2019, there were 1415 sites around the United States in which we were identified as a potentially responsible party under CERCLA and comparable state laws.

At September 30, ~~2018,~~2019, our balance sheet included a total environmental accrual of ~~$170~~$163 million, compared with ~~$180~~$178 million at December 31, ~~2017,~~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

~~There~~Continuing political and social attention to the issue of global climate change has ~~been~~resulted in a broad range of proposed or promulgated state, national and international laws focusing on ~~greenhouse gas (GHG)~~GHG reduction. These proposed or promulgated laws apply or could apply in countries where we have interests or may have interests in the future. Laws in this field continue to evolve, and while it is not possible to accurately estimate either a timetable for implementation or our future compliance costs relating to implementation, such laws, if enacted, could have a material impact on our results of operations and financial condition. Examples of legislation and precursors for possible regulation that do or could affect our operations include the EPA’s announcement on March 29, 2010 (published as “Interpretation of Regulations that Determine Pollutants Covered by Clean Air Act Permitting Programs,” 75 Fed. Reg. 17004 (April 2, 2010)) and theinclude:

The EPA’s and U.S. Department of Transportation’s joint promulgation of a Final Rule on April 1, 2010, that ~~trigger~~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 ~~63–64~~67–69 of our ~~2017~~2018 Annual Report on Form10-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/or~~and a state ~~governments~~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.

~~NEW ACCOUNTING STANDARDS~~

~~In February 2016,~~ Lawsuits filed by other cities and counties in California and Washington are currently stayed pending resolution of the ~~Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU)No. 2016-02,~~ ~~“Leases” (ASUNo. 2016-02),~~ ~~which establishes comprehensive accounting~~appeals brought by the Cities of San Francisco and ~~financial reporting requirements~~Oakland to the U.S. Court of Appeals for ~~leasing arrangements. This ASU supersedes~~ the ~~existing requirements~~Ninth Circuit. Rulings in ~~FASB Accounting Standards Codification (ASC) Topic 840, “Leases” (FASB ASC Topic 840),~~lawsuits filed in Maryland and ~~requires lessees to recognize substantially all lease assets and lease liabilities~~Rhode Island, on the ~~balance sheet. The provisions~~issue of~~ASU No. 2016-02~~ ~~also modify~~ whether the definition of a lease and outline requirements for recognition, measurement, presentation, and disclosure of leasing arrangements by both lessees and lessors. The ASU is effective for interim and annual periods beginning after December 15, 2018, and early adoption of the standard is permitted. Entitiesmatters should proceed in state or federal court, are ~~required to adopt the ASU using a modified retrospective approach, subject to certain optional practical expedients, and apply the provisions of ASUNo. 2016-02~~ ~~to leasing arrangements existing at or entered into after the earliest comparative period presented in the financial statements.~~

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 ~~adoption~~Fifth Circuit Court of Appeals on the ~~ASU. We continue to evaluate the ASU to determine the impact~~issue of adoption on our consolidated financial statements and disclosures, accounting policies and systems, business processes, and internal controls. We are currently implementing a third-party lease accounting software solution to facilitate the ongoing accounting and financial reporting requirementswhether they will proceed in federal or state court. ConocoPhillips will vigorously defend against these lawsuits.

Table of ~~the ASU. We also continue to monitor proposals issued by the FASB to clarify the ASU and certain industry implementation issues.~~Contents

~~While our evaluation of ASUNo. 2016-02~~ and related implementation activities are ongoing, we expect the adoption of the ASU to have a material impact to our consolidated financial statements. Such impact is expected to relate primarily to our balance sheet, resulting from the initial recognition of lease liabilities and corresponding~~right-of-use~~ ~~assets for our population of operating leases, as well as enhanced disclosure of our leasing arrangements. We also expect the adoption of ASUNo. 2016-02~~ to result in certain changes being made to our existing accounting policies and systems, business processes, and internal controls. For additional information, see Note 23—New Accounting Standards, in the Notes to Consolidated Financial Statements.

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

This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs and plans, and objectives of management for future operations, are forward-looking statements. Examples of forward-looking statements contained in this report include our expected production growth and outlook on the business environment generally, our expected capital budget and capital expenditures, and discussions concerning future dividends. You can often identify our forward-looking statements by the words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions.

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

Fluctuations in crude oil, bitumen, natural gas, LNG and ~~natural gas liquids~~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 ~~natural gas liquids,~~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 ~~exploration and production~~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 ~~natural gas liquids.~~NGLs.

Inability to timely obtain or maintain permits, including those necessary for construction, drilling and/or ~~development; failure to comply with applicable laws and regulations;~~development, or inability to make capital expenditures required to maintain compliance with any necessary permits or applicable laws or ~~regulations; or inability to timely complete acquisitions or dispositions.~~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, ~~natural gas liquids~~NGLs and any materials or products (such as aluminum and steel) used in the operation of our business.

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

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.~~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 ~~natural gas liquids~~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 ~~exploration and production~~E&P industry.

Any limitations on our access to capital or increase in our cost of capital, ~~related to~~including as a result of illiquidity or uncertainty in ~~the~~ 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.

~~Our inability to obtain economical financing for development, construction or modification of facilities and general corporate purposes.~~

The operation and financing of our joint ventures.

The ability of our customers and other contractual counterparties to satisfy their obligations to ~~us.~~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 inability to collect payments when due under our settlement agreement with PDVSA.~~

The factors generally described in Item 1A—Risk Factors in our ~~2017~~2018 Annual Report on Form10-K and any additional risks described in our other filings with the SEC.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

~~Item 3.~~

~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK~~

Information about market risks for the nine months ended September 30, ~~2018,~~2019, does not differ materially from that discussed under Item 7A in our ~~2017~~2018 Annual Report on Form10-K.

~~Item 4.~~

~~CONTROLS AND PROCEDURES~~

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, ~~2018,~~2019, with the participation of our management, our Chairman and Chief Executive Officer (principal executive officer) and our Executive Vice President ~~Finance, Commercial~~ and Chief Financial Officer ~~(principal~~

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(principal financial officer) carried out an evaluation, pursuant to Rule13a-15(b) of the Act, of ConocoPhillips’ disclosure controls and procedures (as defined in Rule13a-15(e) of the Act). Based upon that evaluation, our Chairman and Chief Executive Officer and our Executive Vice President ~~Finance, Commercial~~ and Chief Financial Officer concluded our disclosure controls and procedures were operating effectively as of September 30, ~~2018.~~2019.

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

PART II. OTHER INFORMATION

~~Item 1.~~

~~LEGAL PROCEEDINGS~~

~~The following is a description of reportable~~Item 1. LEGAL PROCEEDINGS

There are no new material legal proceedings including those involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment for this reporting period. The following proceedings include those matters that arose during the third quarter of 2018 and anyor material developments with respect to matters previously ~~reported~~disclosed in ~~ConocoPhillips’ 2017~~Item 3 of our 2018 Annual Report onForm 10-K. ~~While~~ it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings were to be decided adversely to ConocoPhillips, we expect there would be no material effect on our consolidated financial position. Nevertheless, such proceedings are reported pursuant to U.S. Securities and Exchange Commission regulations.

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

Item 1A. RISK FACTORS

~~Matters Previously Reported—Phillips 66~~

In October 2016, after Phillips 66 received a Notice of Intent to Sue from the Sierra Club, Phillips 66 entered into a voluntary settlement with the Illinois Environmental Protection Agency for alleged violations of wastewater requirements at the Wood River Refinery. The settlement involves certain capital projects and payment of $125,000. After the settlement was filed with the Court for final approval, the Sierra Club sought and was granted approval to intervene in the case. The settlement and a first modification were entered by the Court, but the Sierra Club still sought to reopen and challenge the settlement. On February 9, 2018, the Court denied the Sierra Club’s motion to reopen the settlement. The Sierra Club did not appeal the Court’s denial and the matter is resolved.

~~Matters Previously Reported—ConocoPhillips~~

On March 22, 2018, an investigator with the Alberta Energy Regulator issued to ConocoPhillips Canada a preliminary notice recommending that the regulator issue an administrative penalty of $180,000 CAD in connection with an estimated 2,400 barrel condensate release discovered on June 9, 2016. The release was from a transmission pipeline leading from the ConocoPhillips Resthaven gas plant located south of Grande Cache, Alberta. A formal administrative penalty of $180,000 CAD was assessed and paid in the second quarter of 2018.

On June 28, 2018, the Texas Commission on Environmental Quality issued a Proposed Agreed Order to ConocoPhillips Company to resolve alleged violations of the Texas Health & Safety Code and/or Commission Rules occurring in 2015 through 2017 at a formerly owned gas injection plant in Howard County, Texas, through the payment of a penalty of $457,750 and the implementation of measures designed to prevent a reoccurrence. The company will work with the Commission to promptly resolve this matter.

~~Item 1A.~~

~~RISK FACTORS~~

There have been no material changes from the risk factors disclosed in Item 1A of our ~~2017~~2018 Annual Report on Form10-K.

~~Item 2.~~

~~UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS~~

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.

            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

July1-31, 2018
   4,395,553    $ 70.49    4,395,553    $ 10,418
August1-31, 2018
   2,802,475    71.73    2,802,475    10,217
September1-30, 2018
   5,629,071    74.00    5,629,071    9,801

Total
   12,827,099    $ 72.30    12,827,099    $ 9,801

*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 ~~double our share~~ repurchase ~~program to $6~~an additional $3 billion of common stock through ~~2019, with $3 billion allocated and purchased in 2017, and the remainder allocated evenly to 2018 and~~ 2019. ~~On February 1, 2018, we announced the acceleration of our previously stated 2018 share repurchases from $1.5 billion to $2 billion.~~ On July 12, 2018, we announced plans to further accelerate our 2018 share repurchases to $3 billion. The 2018 expansion to $3 billion, combined with the $3 billion of shares repurchased during 2016 and 2017, will fully utilize the Board of Directors’ existing share repurchasean authorization of ~~$6 billion. As a result, our Board has authorized~~ 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 ~~2017~~2018 Annual Report on Form10-K.

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Item 6. EXHIBITS

~~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.
12*		~~Computation of Ratio of Earnings to Fixed Charges.~~
31.1*
31.1*		Certification of Chief Executive Officer pursuant to Rule13a-14(a) under the Securities Exchange Act of 1934.

31.2*		Certification of Chief Financial Officer pursuant to Rule13a-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.~~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/ Glenda M. Schwarz~~
~~Glenda M. Schwarz~~


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

October 31, 2019

~~October 30, 2018~~67

☐
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

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 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)

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


		Page

Commonly Used Abbreviations		1

Part I—Financial Information


Item 1. Financial Statements
Consolidated Income Statement				1	2
Consolidated Statement of Comprehensive Income				2	3
Consolidated Balance Sheet				3	4
Consolidated Statement of Cash Flows				4	5
Notes to Consolidated Financial Statements				5	6
Supplementary Information—Condensed Consolidating Financial Information				35
	36

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations				40
	41

Item 3. Quantitative and Qualitative Disclosures About Market Risk				65
	64

Item 4. Controls and Procedures				65
	64

Part II—Other Information


Item 1. Legal Proceedings				66
	65

Item 1A. Risk Factors				67
	65

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds				67
	65

Item 6. Exhibits				68
	66
~~Signature~~
Signature		69	67

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


Consolidated Statement of Comprehensive Income			ConocoPhillips


Notes to Consolidated Financial Statements			ConocoPhillips


	Millions of Dollars
	December 31 2017			ASC Topic 606 Adjustments			ASU No. 2016-01 Adjustments			January 1 2018

Liabilities
Other accruals	$	1,029			104			—			1,133
Total current liabilities		9,397			104			—			9,501
Deferred income taxes		5,282			(31	)		—			5,251
Other liabilities and deferred credits		1,269			147			—			1,416
Total liabilities		42,561			220			—			42,781


Equity
Accumulated other comprehensive loss	$	(5,518	)		—			58			(5,460	)
Retained earnings		29,391			(220	)		(58	)		29,113
Total common stockholders’ equity		30,607			(220	)		—			30,387
Total equity		30,801			(220	)		—			30,581


	Millions of Dollars
	Previously Reported		Effect of Change Higher/(Lower)			As Revised

Three Months Ended September 30, 2017
Production and operating expenses	$	1,224		(2	)		1,222
Selling, general and administrative expenses		132		(22	)		110
Exploration expenses		75		(2	)		73
Other expenses		51		26			77

Nine Months Ended September 30, 2017
Production and operating expenses	$	3,849		(11	)		3,838
Selling, general and administrative expenses		423		(121	)		302
Exploration expenses		724		(4	)		720
Other expenses		285		136			421

	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 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


	Millions of Dollars
	September 30 2018		December 31 2017


Crude oil and natural gas	$	673		512
Materials and supplies		566		548

	$	1,239		1,060


~~Consolidated Income Statement~~			~~ConocoPhillips~~

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.

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

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


	Open Position Long/(Short)
	September 30 2018			December 31 2017

Commodity
Natural gas and power (billions of cubic feet equivalent)
Fixed price		(19	)		(29	)
Basis		5			12


	In Millions Notional Currency
	September 30 2018		December 31 2017


Foreign Currency Exchange Derivatives
Sell U.S. dollar, buy other currencies*	USD	1,258		—
Sell British pound, buy euro	GBP	23		1
Sell Canadian dollar, buy U.S. dollar	CAD	1,230		1,225


	Millions of Dollars
	Gross Amounts Recognized		Gross Amounts Offset		Net Amounts Presented		Cash Collateral		Gross Amounts without Right of Setoff		Net Amounts

September 30, 2018
Assets	$	301		206		95		—		7		88
Liabilities		315		206		109		2		3		104


December 31, 2017
Assets	$	311		186		125		—		4		121
Liabilities		310		186		124		7		5		112


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


December 31, 2017	$	(400	)		(58	)		(5,060	)		(5,518	)
Cumulative effect of adopting ASUNo. 2016-01*		—			58			—			58
Other comprehensive income (loss)		240			—			(222	)		18

September 30, 2018	$	(160	)		—			(5,282	)		(5,442	)


	Millions of Dollars

Contract Liabilities
At January 1, 2018	$	251
Contractual payments received*		81
Revenue recognized		(148	)

At September 30, 2018	$	184


Amounts Recognized in the Consolidated Balance Sheet at September 30, 2018
Current liabilities	$	147
Noncurrent liabilities		37

	$	184


	Millions of Dollars												Percent ofPre-Tax Income (Loss)
	Three Months Ended September 30						Nine Months Ended September 30						Three Months Ended September 30						Nine Months Ended September 30

	2018			2017			2018			2017			2018			2017			2018			2017

Income (loss) before income taxes
United States	$	893			(197	)		2,799			(5,259	)		30.7	%		(30.2	)		38.3			133.5
Foreign		2,013			850			4,502			1,319			69.3			130.2			61.7			(33.5	)

	$	2,906			653			7,301			(3,940	)		100.0	%		100.0			100.0			100.0


Federal statutory income tax	$	610			228			1,533			(1,379	)		21.0	%		35.0			21.0			35.0
Non-U.S. effective tax rates		479			137			1,339			503			16.5			21.0			18.3			(12.8	)
Canada disposition		—			(8	)		—			(1,176	)		—			(1.2	)		—			29.8
Recovery of outside basis		(16	)		(118	)		(19	)		(957	)		(0.6	)		(18.1	)		(0.2	)		24.3
Adjustment to tax reserves		(3	)		(17	)		2			764			(0.1	)		(2.6	)		—			(19.4	)
Adjustment to valuation allowance		(29	)		—			13			24			(1.0	)		—			0.2			(0.6	)
APLNG impairment		—			—			—			834			—			—			—			(21.2	)
State income tax		38			14			83			(98	)		1.3			2.1			1.1			2.5
Enhanced oil recovery credit		(36	)		(5	)		(73	)		(49	)		(1.3	)		(0.8	)		(1.0	)		1.2
Other		(10	)		(14	)		(4	)		(15	)		(0.3	)		(2.2	)		—			0.5

	$	1,033			217			2,874			(1,549	)		35.5	%		33.2			39.4			39.3


							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


July1-31, 2018		4,395,553	$	70.49		4,395,553	$	10,418
August1-31, 2018		2,802,475		71.73		2,802,475		10,217
September1-30, 2018		5,629,071		74.00		5,629,071		9,801

Total		12,827,099	$	72.30		12,827,099	$	9,801

~~Large accelerated filer~~

~~Accelerated filer~~

~~Non-accelerated filer~~

~~Smaller reporting company~~

~~Emerging growth company~~