CONOCOPHILLIPS - Interim / Quarterly Report 2020

UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549

FORM****10-Q

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

For the quarterly period endedSeptember 30, 2020

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

For the transition period fromto

Commission file number:001-32395

ConocoPhillips

(Exact name of registrant as specified in its charter)

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

925 N. Eldridge Parkway

Houston**,TX77079** (Address of principal executive offices) (Zip Code)

281**-**293-1000 (Registrant's telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: Title of each classTrading symbolsName of each exchange on which registered Common Stock, $.01 Par ValueCOPNew York Stock Exchange 7% Debentures due 2029CUSIP—718507BK1New York Stock Exchange

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

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

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

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

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

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

The registrant had1,072,741,643shares of common stock, $.01 par value, outstanding at September 30, 2020.

CONOCOPHILLIPS

TABLE OF CONTENTS

Page Commonly Used Abbreviations………………………………………………………………………...1

Part I—Financial Information

Item 1. Financial Statements Consolidated Income Statement……………………………………………………………………...2 Consolidated Statement of Comprehensive Income………………………………………………….3 Consolidated Balance Sheet………………………………………………………………………….4 Consolidated Statement of Cash Flows……………………………………………………………....5 Notes to Consolidated Financial Statements………………………………………………………....6

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations………………………………………………………………………….32

Item 3. Quantitative and Qualitative Disclosures About Market Risk………………………………....59

Item 4. Controls and Procedures……………………………………………………………………….60

Part II—Other Information

Item 1. Legal Proceedings……………………………………………………………………………...60

Item 1A. Risk Factors………………………………………………………………………………….60

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

Item 6. Exhibits………………………………………………………………………………………...66

Signature…………………………………………………………………………………………………..67

Commonly Used Abbreviations

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

Currencies****Accounting $ or USDU.S. dollarAROasset retirement obligation CADCanadian dollarASCaccounting standards codification EUREuroASUaccounting standards update GBPBritish poundDD&Adepreciation, depletion and amortization Units of MeasurementFASBFinancial Accounting Standards BBLbarrelBoard BCFbillion cubic feetFIFOfirst-in, first-out BOEbarrels of oil equivalentG&Ageneral and administrative MBDthousands of barrels per dayGAAPgenerally accepted accounting MCFthousand cubic feetprinciples MBODthousand barrels of oil per dayLIFOlast-in, first-out MMmillionNPNSnormal purchase normal sale MMBOEmillion barrels of oil equivalentPP&Eproperties, plants and equipment MMBODmillion barrels of oil per daySABstaff accounting bulletin MBOEDthousands of barrels of oilVIEvariable interest entity equivalent per day MMBTUmillion British thermal unitsMiscellaneous MMCFDmillion cubic feet per dayEPAEnvironmental Protection Agency ESGEnvironmental, Social and Corporate Governance IndustryEUEuropean Union CBMcoalbed methaneFERCFederal Energy Regulatory E&Pexploration and productionCommission FEEDfront-end engineering and designGHGgreenhouse gas FPSfloating production systemHSEhealth, safety and environment FPSOfloating production, storage andICCInternational Chamber of offloadingCommerce JOAjoint operating agreementICSIDWorld Bank’s International LNGliquefied natural gasCentre for Settlement of NGLsnatural gas liquidsInvestment Disputes OPECOrganization of PetroleumIRSInternal Revenue Service Exporting CountriesOTCover-the-counter PSCproduction sharing contractNYSENew York Stock Exchange PUDsproved undeveloped reservesSECU.S. Securities and Exchange SAGDsteam-assisted gravity drainageCommission WCSWestern Canada SelectTSRtotal shareholder return WTIWest Texas IntermediateU.K.United Kingdom U.S.United States of America

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

Consolidated Income Statement****ConocoPhillips| | September 30 | | | September 30 | | | --- | --- | --- | --- | --- | --- | | | | 2020 | 2019 | 2020 | 2019 | | Revenues and Other Income | | | | | | | Sales and other operating revenues | **$**4,386 | | 7,756 | 13,293 | 24,859 | | Equity in earnings of affiliates | | 35 | 290 | 346 | 651 | | Gain (loss) on dispositions | | ( 3 ) | 1,785 | 551 | 1,884 | | Other income (loss) | | ( 38 ) | 262 | ( 983 ) | 1,136 | | Total Revenues and Other Income | 4,380 | | 10,093 | 13,207 | 28,530 |

Costs and Expenses
Purchased commodities	1,839		2,710	5,630	9,059
Production and operating expenses		963	1,331	3,183	4,020
Selling, general and administrative expenses		96	87	249	369
Exploration expenses		125	360	410	592
Depreciation, depletion and amortization	1,411		1,566	3,980	4,602
Impairments		2	24	521	26
Taxes other than income taxes		179	237	570	706
Accretion on discounted liabilities		62	86	195	259
Interest and debt expense		200	184	604	582
Foreign currency transaction (gain) loss		( 5 )	( 21 )	( 88 )	19
Other expenses		20	36	7	58
Total Costs and Expenses	4,892		6,600	15,261	20,292
Income (loss) before income taxes		( 512 )	3,493	( 2,054 )	8,238
Income tax provision (benefit)		( 62 )	422	( 171 )	1,724
Net income (loss)		( 450 )	3,071	( 1,883 )	6,514
Less: net income attributable to noncontrolling interests		-	( 15 )	( 46 )	( 45 )
Net Income (Loss) Attributable to ConocoPhillips	$	( 450 )	3,056	( 1,929 )	6,469

of Common Stock	(dollars)
Basic		$( 0.42 )	2.76	( 1.79 )	5.75
Diluted		( 0.42 )	2.74	( 1.79 )	5.72

Average Common Shares Outstanding
Basic	1,077,377	1,108,555	1,079,525	1,124,558
Diluted	1,077,377	1,113,250	1,079,525	1,131,034
See Notes to Consolidated Financial Statements.

Consolidated Statement of Comprehensive Income****ConocoPhillips

Millions of Dollars Three Months EndedNine Months Ended September 30September 30 2020201920202019

**Net Income (Loss)$( 450 )3,071( 1,883 )**6,514| Reclassification adjustment for amortization of prior | | | | | | | | --- | --- | --- | --- | --- | --- | --- | | | service credit included in net income (loss) | ( 8 ) | | ( 8 ) | ( 24 ) | ( 26 ) | | Net actuarial loss arising during the period | | ( 78 ) | ( 149 ) | | ( 73 ) | ( 149 ) | | Reclassification adjustment for amortization of net actuarial | | | | | | | | | losses included in net income (loss) | 45 | | 56 | 81 | 114 | | Nonsponsored plans | | | - | ( 1 ) | - | ( 1 ) | | Income taxes on defined benefit plans | | 10 | | 30 | 3 | 20 | | Defined benefit plans, net of tax | | ( 31 ) | ( 72 ) | | ( 13 ) | ( 42 ) | | Unrealized holding gain on securities | | | - | - | 3 | - | | Income taxes on unrealized holding gain on securities | | | - | - | ( 1 ) | - | | Unrealized holding gain on securities, net of tax | | | - | - | 2 | - | | Foreign currency translation adjustments | | 188 | 247 | | ( 302 ) | 493 | | Income taxes on foreign currency translation adjustments | | 2 | | ( 2 ) | 4 | ( 2 ) | | Foreign currency translation adjustments, net of tax | | 190 | 245 | | ( 298 ) | 491 | | Other Comprehensive Income (Loss), Net of Tax | | 159 | 173 | | ( 309 ) | 449 | | Comprehensive Income (Loss) | | ( 291 ) | 3,244 | ( 2,192 ) | | 6,963 | | Less: comprehensive income attributable to noncontrolling interests | | | -( 15 ) | | ( 46 ) | ( 45 ) | | Comprehensive Income (Loss) Attributable to ConocoPhillips | | $****( 291 ) | 3,229 | ( 2,238 ) | | 6,918 | | See Notes to Consolidated Financial Statements. | | | | | | |

Consolidated Balance Sheet****ConocoPhillips| Assets | | | | | | | | --- | --- | --- | --- | --- | --- | --- | | Cash and cash equivalents | | | | $ | 2,490 | 5,088 | | Short-term investments | | | | | 4,032 | 3,028 | | Accounts and notes receivable (net of allowance of $ | | 4and $ | 13, respectively) | | 1,984 | 3,267 | | Accounts and notes receivable—related parties | | | | | 135 | 134 | | Investment in Cenovus Energy | | | | | 809 | 2,111 | | Inventories | | | | | 1,034 | 1,026 | | Prepaid expenses and other current assets | | | | | 575 | 2,259 | | Total Current Assets | | | | 11,059 | | 16,913 | | Investments and long-term receivables | | | | | 8,295 | 8,687 | | Loans and advances—related parties | | | | | 114 | 219 | | Net properties, plants and equipment | | | | | | | | (net of accumulated DD&A of $ | 58,726and $ | 55,477, respectively) | | 41,269 | | 42,269 | | Other assets | | | | | 2,420 | 2,426 | | Total Assets | | | | **$**63,157 | | 70,514 |

Liabilities
Accounts payable	$	2,217	3,176
Accounts payable—related parties		22	24
Short-term debt		482	105
Accrued income and other taxes		339	1,030
Employee benefit obligations		469	663
Other accruals		1,111	2,045
Total Current Liabilities		4,640	7,043
Long-term debt	14,905		14,790
Asset retirement obligations and accrued environmental costs		5,651	5,352
Deferred income taxes		3,854	4,634
Employee benefit obligations		1,661	1,781
Other liabilities and deferred credits		1,663	1,864
Total Liabilities	32,374		35,464

Equity
Common stock (	2,500,000,000	shares authorized at $	0.01	par value)
Issued (2020—	1,798,738,512	shares; 2019—	1,795,652,203	shares)
Par value						18	18
Capital in excess of par						47,113	46,983
Treasury stock (at cost: 2020—		725,996,869	shares; 2019—	710,783,814	shares)	( 47,130 )	( 46,405 )
Accumulated other comprehensive loss						( 5,666 )	( 5,357 )
Retained earnings						36,448	39,742
Total Common Stockholders’ Equity						30,783	34,981
Noncontrolling interests						-	69
Total Equity						30,783	35,050
Total Liabilities and Equity					$	63,157	70,514
See Notes to Consolidated Financial Statements.

Consolidated Statement of Cash Flows****ConocoPhillips

Millions of Dollars Nine Months Ended September 30 20202019| Cash Flows From Operating Activities | | | | | --- | --- | --- | --- | | Net income (loss) | $****( 1,883 ) | | 6,514 | | Adjustments to reconcile net income (loss) to net cash provided by operating | | | | | activities | | | | | Depreciation, depletion and amortization | | 3,980 | 4,602 | | Impairments | | 521 | 26 | | Dry hole costs and leasehold impairments | | 114 | 361 | | Accretion on discounted liabilities | | 195 | 259 | | Deferred taxes | | ( 428 ) | ( 304 ) | | Undistributed equity earnings | | 450 | 260 | | Gain on dispositions | | ( 551 ) | ( 1,884 ) | | Unrealized (gain) loss on investment in Cenovus Energy | | 1,302 | ( 489 ) | | Other | | ( 188 ) | ( 331 ) | | Working capital adjustments | | | | | Decrease in accounts and notes receivable | | 1,132 | 333 | | Increase in inventories | | ( 74 ) | ( 2 ) | | Increase in prepaid expenses and other current assets | | ( 49 ) | ( 29 ) | | Decrease in accounts payable | | ( 583 ) | ( 476 ) | | Decrease in taxes and other accruals | | ( 808 ) | ( 718 ) | | Net Cash Provided by Operating Activities | | 3,130 | 8,122 |

Cash Flows From Investing Activities
Capital expenditures and investments	( 3,657 )	( 5,041 )
Working capital changes associated with investing activities	( 229 )	17
Proceeds from asset dispositions	1,312	2,920
Net purchases of investments	( 1,089 )	( 665 )
Collection of advances/loans—related parties	116	127
Other	( 31 )	( 146 )
Net Cash Used in Investing Activities	( 3,578 )	( 2,788 )

Cash Flows From Financing Activities
Issuance of debt	300	-
Repayment of debt	( 234 )	( 59 )
Issuance of company common stock	( 2 )	( 39 )
Repurchase of company common stock	( 726 )	( 2,751 )
Dividends paid	( 1,367 )	( 1,037 )
Other	( 27 )	( 73 )
Net Cash Used in Financing Activities	( 2,056 )	( 3,959 )

Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash**( 62 )**( 68 )| Net Change in Cash, Cash Equivalents and Restricted Cash | ( 2,566 ) | 1,307 | | --- | --- | --- | | Cash, cash equivalents and restricted cash at beginning of period | 5,362 | 6,151 |

Cash, Cash Equivalents and Restricted Cash at End of Period**$****2,796**7,458 Restricted cash of $ 91 million and $ 215 million are included in the "Prepaid expenses and other current assets" and "Other assets" lines, respectively, of our Consolidated Balance Sheet as of September 30, 2020. Restricted cash of $ 90 million and $ 184 million are included in the "Prepaid expenses and other current assets" and "Other assets" lines, respectively, of our Consolidated Balance Sheet as of December 31, 2019. See Notes to Consolidated Financial Statements.

Notes to Consolidated Financial Statements****ConocoPhillips

Note 1—Basis of Presentation The interim-period financial information presented in the financial statements included in this report is unaudited and, in the opinion of management, includes all known accruals and adjustments necessary for a fair presentation of the consolidated financial position of ConocoPhillips and its results of operations and cash flows for such periods. All such adjustments are of a normal and recurring nature unless otherwise disclosed. Certain notes and other information have been condensed or omitted from the interim financial statements included in this report. Therefore, these financial statements should be read in conjunction with the consolidated financial statements and notes included in our 2019 Annual Report on Form 10-K. The unrealized (gain) loss on investment in Cenovus Energy included on our consolidated statement of cash flows, previously reflected on the line item “Other” within net cash provided by operating activities, has been reclassified in the comparative period to conform with the current period’s presentation.

Note 2—Changes in Accounting Principles We adopted the provisions of FASB ASU No. 2016-13 , “Measurement of Credit Losses on Financial Instruments,” (ASC Topic 326) and its amendments, beginning January 1, 2020 . This ASU, as amended, sets forth the current expected credit loss model, a new forward-looking impairment model for certain financial instruments measured at amortized cost basis based on expected losses rather than incurred losses. This ASU, as amended, which primarily applies to our accounts receivable, also requires credit losses related to available- for-sale debt securities to be recorded through an allowance for credit losses. The adoption of this ASU did not have a material impact to our financial statements. The majority of our receivables are due within 30 days or less. We monitor the credit quality of our counterparties through review of collections, credit ratings, and other analyses. We develop our estimated allowance for credit losses primarily using an aging method and analyses of historical loss rates as well as consideration of current and future conditions that could impact our counterparties’ credit quality and liquidity.

Note 3—Inventories Inventories consisted of the following: Millions of Dollars September 30 December 31 2020 2019 Crude oil and natural gas $ 503 472 Materials and supplies 531 554 $ 1,034 1,026

Inventories valued on the LIFO basis totaled $ 373 million and $ 286 million at September 30, 2020 and December 31, 2019, respectively. Due to a precipitous decline in commodity prices beginning in March this year, we recorded a lower of cost or market adjustment in the first quarter of 2020 of $ 228 million to our crude oil and natural gas inventories. The adjustment was included in the “Purchased commodities” line on our consolidated income statement. Commodity prices have improved since the first quarter.

Note 4—Asset Acquisitions and Dispositions Asset Acquisition In August 2020, we completed the acquisition of additional Montney acreage in Canada from Kelt Exploration Ltd. for $ 382 million after customary adjustments, plus the assumption of $ 31 million in financing obligations associated with partially owned infrastructure. This acquisition consisted primarily of undeveloped properties and included 140,000 net acres in the liquids-rich Inga Fireweed asset Montney zone, which is directly adjacent to our existing Montney position. The transaction increases our Montney acreage position to 295,000 net acres with a 100 percent working interest. This agreement was accounted for as an asset acquisition resulting in the recognition of $ 490 million of PP&E; $ 77 million of ARO and accrued environmental costs; and $ 31 million of financing obligations recorded primarily to long-term debt. Results of operations for the Montney are reported in our Canada segment. Assets Sold In May 2020, we completed the divestiture of our subsidiaries that held our Australia-West assets and operations, and based on an effective date of January 1, 2019, we received proceeds of $ 765 million with an additional $ 200 million due upon final investment decision of the proposed Barossa development project. In the nine-month period of 2020, we recognized a before-tax gain of $ 587 million related to this transaction. At the time of disposition, the net carrying value of the subsidiaries sold was approximately $ 0.2 billion, excluding $ 0.5 billion of cash. The net carrying value consisted primarily of $ 1.3 billion of PP&E and $ 0.1 billion of other current assets offset by $ 0.7 billion of ARO, $ 0.3 billion of deferred tax liabilities, and $ 0.2 billion of other liabilities. The before-tax earnings associated with the subsidiaries sold, including the gain on disposition noted above, were $ 851 million and $ 222 million for the nine-month periods ended September 30, 2020 and 2019, respectively. Production from the beginning of the year through the disposition date in May 2020 averaged 43 MBOED. Results of operations for the subsidiaries sold are reported in our Asia Pacific segment. In March 2020, we completed the sale of our Niobrara interests for approximately $ 359 million after customary adjustments and recognized a before-tax loss on disposition of $ 38 million. At the time of disposition, our interest in Niobrara had a net carrying value of $ 397 million, consisting primarily of $ 433 million of PP&E and $ 34 million of ARO. The before-tax earnings associated with our interests in Niobrara, including the loss on disposition, were a loss of $ 22 million and $ 7 million for the nine-month periods ended September 30, 2020 and 2019, respectively. In February 2020, we sold our Waddell Ranch interests in the Permian Basin for $ 184 million after customary adjustments. No gain or loss was recognized on the sale. Production from the disposed Niobrara and Waddell Ranch interests in our Lower 48 segment averaged 15 MBOED in 2019.

Note 5—Investments, Loans and Long-Term Receivables Australia Pacific LNG Pty Ltd (APLNG) APLNG executed project financing agreements for an $ 8.5 billion project finance facility in 2012. The $ 8.5 billion project finance facility was initially composed of financing agreements executed by APLNG with the Export-Import Bank of the United States for approximately $ 2.9 billion, the Export-Import Bank of China for approximately $ 2.7 billion, and a syndicate of Australian and international commercial banks for approximately $ 2.9 billion. All amounts were drawn from the facility. APLNG made its first principal and interest repayment in March 2017 and is scheduled to make bi-annual payments until March 2029 . APLNG made a voluntary repayment of $ 1.4 billion to the Export-Import Bank of China in September 2018. At the same time, APLNG obtained a United States Private Placement (USPP) bond facility of $ 1.4 billion. APLNG made its first interest payment related to this facility in March 2019, and principal payments are scheduled to commence in September 2023, with bi-annual payments due on the facility until September 2030 .

During the first quarter of 2019, APLNG refinanced $ 3.2 billion of existing project finance debt through two transactions. As a result of the first transaction, APLNG obtained a commercial bank facility of $ 2.6 billion. APLNG made its first principal and interest repayment in September 2019 with bi-annual payments due on the facility until March 2028 . Through the second transaction, APLNG obtained a USPP bond facility of $ 0.6 billion. APLNG made its first interest payment in September 2019, and principal payments are scheduled to commence in September 2023, with bi-annual payments due on the facility until September 2030. In conjunction with the $ 3.2 billion debt obtained during the first quarter of 2019 to refinance existing project finance debt, APLNG made voluntary repayments of $ 2.2 billion and $ 1.0 billion to a syndicate of Australian and international commercial banks and the Export-Import Bank of China, respectively. At September 30, 2020, a balance of $ 6.2 billion was outstanding on the facilities. See Note 11—Guarantees, for additional information. At September 30, 2020, the carrying value of our equity method investment in APLNG was $ 6,877 million. The balance is included in the “Investments and long-term receivables” line on our consolidated balance sheet. Loans and Long-Term Receivables As part of our normal ongoing business operations, and consistent with industry practice, we enter into numerous agreements with other parties to pursue business opportunities. Included in such activity are loans made to certain affiliated and non-affiliated companies. At September 30, 2020, significant loans to affiliated companies included $ 219 million in project financing to Qatar Liquefied Gas Company Limited (3). On our consolidated balance sheet, the long-term portion of these loans is included in the “Loans and advances—related parties” line, while the short-term portion is in the “Accounts and notes receivable—related parties” line.

Note 6—Investment in Cenovus Energy On May 17, 2017, we completed the sale of our 50 percent nonoperated interest in the FCCL Partnership, as well as the majority of our western Canada gas assets, to Cenovus Energy. Consideration for the transaction included 208 million Cenovus Energy common shares, which, at closing, approximated 16.9 percent of issued and outstanding Cenovus Energy common stock. The fair value and cost basis of our investment in 208 million Cenovus Energy common shares was $ 1.96 billion based on a price of $ 9.41 per share on the NYSE on the closing date. At September 30, 2020, the investment included on our consolidated balance sheet was $ 809 million and is carried at fair value. The fair value of the 208 million Cenovus Energy common shares reflects the closing price of $ 3.89 per share on the NYSE on the last trading day of the quarter, a decrease of $ 1.30 billion from its fair value of $ 2.11 billion at year-end 2019. For the three- and nine-month periods ended September 30, 2020, we recorded an unrealized loss of $ 162 million and $ 1.30 billion, respectively. For the three- and nine-month periods ended September 30, 2019, we recorded an unrealized gain of $ 116 million and $ 489 million, respectively. The unrealized gains and losses are recorded within the “Other income (loss)” line of our consolidated income statement and are related to the shares held at the reporting date. See Note 14—Fair Value Measurement, for additional information. Subject to market conditions, we intend to decrease our investment over time through market transactions, private agreements or otherwise.

Note 7—Suspended Wells The capitalized cost of suspended wells at September 30, 2020, was $ 711 million, a decrease of $ 309 million from year-end 2019 primarily related to our Australia-West divestiture. See Note 4—Asset Acquisitions and Dispositions, for additional information. Of the well costs capitalized for more than one year as of December 31, 2019, $ 20 million was charged to dry hole expense during the first nine months of 2020 primarily for one suspended well in the Kamunsu East Field offshore Malaysia.

Note 8—Impairments During the three- and nine-month periods ended September 30, 2020 and 2019, we recognized before-tax impairment charges within the following segments: Millions of Dollars Three Months Ended Nine Months Ended September 30 September 30 2020 2019 2020 2019 Lower 48 $ 1 22 514 22 Europe, Middle East and North Africa 1 2 7 4 $ 2 24 521 26

We perform impairment reviews when triggering events arise that may impact the fair value of our assets or investments. We observed volatility in commodity prices during the first nine-months of 2020. A decline in commodity prices beginning in March prompted us to evaluate the recoverability of the carrying value of our assets and whether an other than temporary impairment occurred for investments in our portfolio. For certain non-core natural gas assets in the Lower 48, a significant decrease in the outlook for current and long-term natural gas prices resulted in a decline in the estimated fair values to amounts below carrying value. Accordingly, in the first quarter of 2020, we recorded impairments of $ 511 million related to these non-core natural gas assets, primarily for the Wind River Basin operations area consisting of developed properties in the Madden Field and the Lost Cabin Gas Plant, which were written down to fair value. See Note 14—Fair Value Measurement, for additional information. A sustained decline in the current and long-term outlook on commodity prices could trigger additional impairment reviews and possibly result in future impairment charges. The charges discussed below are included in the “Exploration expenses” line on our consolidated income statement and are not reflected in the table above. We recorded a before-tax impairment in the first quarter of 2020 of $ 31 million in our Asia Pacific segment related to the associated carrying value of capitalized undeveloped leasehold costs for the Kamunsu East Field in Malaysia that is no longer in our development plans. In the third quarter of 2019, we recorded a before-tax impairment of $ 141 million in our Lower 48 segment for the associated carrying value of capitalized undeveloped leasehold costs due to our decision to discontinue exploration activities in the Central Louisiana Austin Chalk trend.

Note 9—Debt Our debt balance as of September 30, 2020 was $ 15,387 million compared with $ 14,895 million at December 31, 2019. Our revolving credit facility provides a total commitment of $ 6.0 billion and expires in May 2023 . Our revolving credit facility may be used for direct bank borrowings, the issuance of letters of credit totaling up to $ 500 million, or as support for our commercial paper program. Our commercial paper program consists of the ConocoPhillips Company $ 6.0 billion program, primarily a funding source for short-term working capital needs. Commercial paper maturities are generally limited to 90 days . We issued $ 300 million of commercial paper in the third quarter of 2020, which is included in short-term debt on our consolidated balance sheet. With $ 300 million of commercial paper outstanding and no direct borrowings or letters of credit, we had $ 5.7 billion in available capacity under the revolving credit facility at September 30, 2020. We had no direct outstanding borrowings, letters of credit, nor outstanding commercial paper as of December 31, 2019. In October 2020, S&P affirmed its “A” rating on our senior long-term debt and revised its outlook to “stable” from “negative,” Fitch affirmed its rating of “A” with a “stable” outlook and Moody’s affirmed its rating of “A3” with a “stable” outlook. At September 30, 2020, we had $ 283 million of certain variable rate demand bonds (VRDBs) outstanding with maturities ranging through 2035. The VRDBs are redeemable at the option of the bondholders on any business day. If they are ever redeemed, we have the ability and intent to refinance on a long-term basis, therefore, the VRDBs are included in the “Long-term debt” line on our consolidated balance sheet.

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, 2020 Balances at June 30, 2020 $ 18 47,079 ( 47,130 ) ( 5,825 ) 37,351 31,493 Net loss ( 450 ) ( 450 ) Other comprehensive income 159 159 Dividends paid ($ 0.42 per common share) ( 454 ) ( 454 ) Distributed under benefit plans 34 34 Other 1 1 Balances at September 30, 2020 $ 18 47,113 ( 47,130 ) ( 5,666 ) 36,448 30,783 For the nine months ended September 30, 2020 Balances at December 31, 2019 $ 18 46,983 ( 46,405 ) ( 5,357 ) 39,742 69 35,050 Net income (loss) ( 1,929 ) 46 ( 1,883 ) Other comprehensive loss ( 309 ) ( 309 ) Dividends paid ($ 1.26 per common share) ( 1,367 ) ( 1,367 ) Repurchase of company common stock ( 726 ) ( 726 ) Distributions to noncontrolling interests and other ( 32 ) ( 32 ) Disposition ( 84 ) ( 84 ) Distributed under benefit plans 130 130 Other 1 2 1 4 Balances at September 30, 2020 $ 18 47,113 ( 47,130 ) ( 5,666 ) 36,448 - 30,783 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 *Cumulative effect of the adoption of ASU No. 2018-02, "Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income."

Note 11—Guarantees At September 30, 2020, we were liable for certain contingent obligations under various contractual arrangements as described below. We recognize a liability, at inception, for the fair value of our obligation as a guarantor for newly issued or modified guarantees. Unless the carrying amount of the liability is noted below, we have not recognized a liability because the fair value of the obligation is immaterial. In addition, unless otherwise stated, we are not currently performing with any significance under the guarantee and expect future performance to be either immaterial or have only a remote chance of occurrence. APLNG Guarantees At September 30, 2020, we had outstanding multiple guarantees in connection with our 37.5 percent ownership interest in APLNG. The following is a description of the guarantees with values calculated utilizing September 2020 exchange rates: ● During the third quarter of 2016, we issued a guarantee to facilitate the withdrawal of our pro-rata portion of the funds in a project finance reserve account. We estimate the remaining term of this guarantee is 10 years . Our maximum exposure under this guarantee is approximately $ 170 million and may become payable if an enforcement action is commenced by the project finance lenders against APLNG. At September 30, 2020, the carrying value of this guarantee was approximately $ 14 million. ● In conjunction with our original purchase of an ownership interest in APLNG from Origin Energy in October 2008, we agreed to reimburse Origin Energy for our share of the existing contingent liability arising under guarantees of an existing obligation of APLNG to deliver natural gas under several sales agreements with remaining terms of 1 to 22 years . Our maximum potential liability for future payments, or cost of volume delivery, under these guarantees is estimated to be $ 720 million ($ 1.3 billion in the event of intentional or reckless breach), and would become payable if APLNG fails to meet its obligations under these agreements and the obligations cannot otherwise be mitigated. Future payments are considered unlikely, as the payments, or cost of volume delivery, would only be triggered if APLNG does not have enough natural gas to meet these sales commitments and if the co-venturers do not make necessary equity contributions into APLNG. ● We have guaranteed the performance of APLNG with regard to certain other contracts executed in connection with the project’s continued development. The guarantees have remaining terms of 16 to 25 years or the life of the venture . Our maximum potential amount of future payments related to these guarantees is approximately $ 120 million and would become payable if APLNG does not perform. At September 30, 2020, the carrying value of these guarantees was approximately $ 7 million. Other Guarantees We have other guarantees with maximum future potential payment amounts totaling approximately $ 750 million, which consist primarily of guarantees of the residual value of leased office buildings, guarantees of the residual value of corporate aircrafts, and a guarantee for our portion of a joint venture’s project finance reserve accounts. These guarantees have remaining terms of 1 to 5 years and would become payable if certain asset values are lower than guaranteed amounts at the end of the lease or contract term, business conditions decline at guaranteed entities, or as a result of nonperformance of contractual terms by guaranteed parties. At September 30, 2020, the carrying value of these guarantees was approximately $ 11 million. Indemnifications Over the years, we have entered into agreements to sell ownership interests in certain legal entities, joint ventures and assets that gave rise to qualifying indemnifications. These agreements include indemnifications for taxes and environmental liabilities. The majority of these indemnifications are related to tax issues and the majority of these expire in 2021. Those related to environmental issues have terms that are generally indefinite and the maximum amounts of future payments are generally unlimited. The carrying amount recorded for these indemnification obligations at September 30, 2020, was approximately $ 50 million. We amortize the

indemnification liability over the relevant time period the indemnity is in effect, if one exists, based on the facts and circumstances surrounding each type of indemnity. In cases where the indemnification term is indefinite, we will reverse the liability when we have information the liability is essentially relieved or amortize the liability over an appropriate time period as the fair value of our indemnification exposure declines. Although it is reasonably possible future payments may exceed amounts recorded, due to the nature of the indemnifications, it is not possible to make a reasonable estimate of the maximum potential amount of future payments. For additional information about environmental liabilities, see Note 12—Contingencies and Commitments.

Note 12—Contingencies and Commitments A number of lawsuits involving a variety of claims arising in the ordinary course of business have been filed against ConocoPhillips. We also may be required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active and inactive sites. We regularly assess the need for accounting recognition or disclosure of these contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the low end of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. We accrue receivables for insurance or other third-party recoveries when applicable. With respect to income tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain. Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes.

Environmental We are subject to international, federal, state and local environmental laws and regulations. When we prepare our consolidated financial statements, we record accruals for environmental liabilities based on management’s best estimates, using all information that is available at the time. We measure estimates and base liabilities on currently available facts, existing technology, and presently enacted laws and regulations, taking into account stakeholder and business considerations. When measuring environmental liabilities, we also consider our prior experience in remediation of contaminated sites, other companies’ cleanup experience, and data released by the U.S. EPA or other organizations. We consider unasserted claims in our determination of environmental liabilities, and we accrue them in the period they are both probable and reasonably estimable. Although liability of those potentially responsible for environmental remediation costs is generally joint and several for federal sites and frequently so for other sites, we are usually only one of many companies cited at a particular site. Due to the joint and several liabilities, we could be responsible for all cleanup costs related to any site at which we have been designated as a potentially responsible party. We have been successful to date in sharing cleanup costs with other financially sound companies. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the agency concerned. Prior to actual cleanup, those potentially responsible normally assess the site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or may attain a settlement of liability. Where it appears that other potentially responsible parties may be financially unable to bear their proportional share, we consider this inability in estimating our potential liability, and we adjust our accruals accordingly.

As a result of various acquisitions in the past, we assumed certain environmental obligations. Some of these environmental obligations are mitigated by indemnifications made by others for our benefit, and some of the indemnifications are subject to dollar limits and time limits. We are currently participating in environmental assessments and cleanups at numerous federal Superfund and comparable state and international sites. After an assessment of environmental exposures for cleanup and other costs, we make accruals on an undiscounted basis (except those acquired in a purchase business combination, which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable future costs will be incurred and these costs can be reasonably estimated. We have not reduced these accruals for possible insurance recoveries. At September 30, 2020, our balance sheet included a total environmental accrual of $ 177 million, compared with $ 171 million at December 31, 2019, for remediation activities in the U.S. and Canada. We expect to incur a substantial amount of these expenditures within the next 30 years . In the future, we may be involved in additional environmental assessments, cleanups and proceedings.

Legal Proceedings We are subject to various lawsuits and claims including but not limited to matters involving oil and gas royalty and severance tax payments, gas measurement and valuation methods, contract disputes, environmental damages, climate change, personal injury, and property damage. Our primary exposures for such matters relate to alleged royalty and tax underpayments on certain federal, state and privately owned properties and claims of alleged environmental contamination from historic operations. We will continue to defend ourselves vigorously in these matters. Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, is required.

Other Contingencies We have contingent liabilities resulting from throughput agreements with pipeline and processing companies not associated with financing arrangements. Under these agreements, we may be required to provide any such company with additional funds through advances and penalties for fees related to throughput capacity not utilized. In addition, at September 30, 2020, we had performance obligations secured by letters of credit of $ 240 million (issued as direct bank letters of credit) related to various purchase commitments for materials, supplies, commercial activities and services incident to the ordinary conduct of business. In 2007, ConocoPhillips was unable to reach agreement with respect to the empresa mixta structure mandated by the Venezuelan government’s Nationalization Decree. As a result, Venezuela’s national oil company, Petróleos de Venezuela, S.A. (PDVSA), or its affiliates, directly assumed control over ConocoPhillips’ interests in the Petrozuata and Hamaca heavy oil ventures and the offshore Corocoro development project. In response to this expropriation, ConocoPhillips initiated international arbitration on November 2, 2007, with the ICSID. On September 3, 2013, an ICSID arbitration tribunal held that Venezuela unlawfully expropriated ConocoPhillips’ significant oil investments in June 2007. On January 17, 2017, the Tribunal reconfirmed the decision that the expropriation was unlawful. In March 2019, the Tribunal unanimously ordered the government of Venezuela to pay ConocoPhillips approximately $ 8.7 billion in compensation for the government’s unlawful expropriation of the company’s investments in Venezuela in 2007. ConocoPhillips has filed a request for recognition of the award in several jurisdictions. On August 29, 2019, the ICSID Tribunal issued a decision rectifying the award and reducing it by approximately $ 227 million. The award now stands at $ 8.5 billion plus interest. The government of Venezuela sought annulment of the award, which automatically stayed enforcement of the award. Annulment proceedings are underway.

In 2014, ConocoPhillips filed a separate and independent arbitration under the rules of the ICC against PDVSA under the contracts that had established the Petrozuata and Hamaca projects. The ICC Tribunal issued an award in April 2018, finding that PDVSA owed ConocoPhillips approximately $ 2 billion under their agreements in connection with the expropriation of the projects and other pre-expropriation fiscal measures. In August 2018, ConocoPhillips entered into a settlement with PDVSA to recover the full amount of this ICC award, plus interest through the payment period, including initial payments totaling approximately $ 500 million within a period of 90 days from the time of signing of the settlement agreement. The balance of the settlement is to be paid quarterly over a period of four and a half years. To date, ConocoPhillips has received approximately $ 754 million. Per the settlement, PDVSA recognized the ICC award as a judgment in various jurisdictions, and ConocoPhillips agreed to suspend its legal enforcement actions. ConocoPhillips sent notices of default to PDVSA on October 14 and November 12, 2019, and to date PDVSA has failed to cure its breach. As a result, ConocoPhillips has resumed legal enforcement actions. ConocoPhillips has ensured that the settlement and any actions taken in enforcement thereof meet all appropriate U.S. regulatory requirements, including those related to any applicable sanctions imposed by the U.S. against Venezuela. In 2016, ConocoPhillips filed a separate and independent arbitration under the rules of the ICC against PDVSA under the contracts that had established the Corocoro Project. On August 2, 2019, the ICC Tribunal awarded ConocoPhillips approximately $ 33 million plus interest under the Corocoro contracts. ConocoPhillips is seeking recognition and enforcement of the award in various jurisdictions. ConocoPhillips has ensured that all the actions related to the award meet all appropriate U.S. regulatory requirements, including those related to any applicable sanctions imposed by the U.S. against Venezuela. The Office of Natural Resources Revenue (ONRR) has conducted audits of ConocoPhillips’ payment of royalties on federal lands and has issued multiple orders to pay additional royalties to the federal government. ConocoPhillips has appealed these orders and strongly objects to the ONRR claims. The appeals are pending with the Interior Board of Land Appeals (IBLA), except for one order that is the subject of a lawsuit ConocoPhillips filed in 2016 in New Mexico federal court after its appeal was denied by the IBLA. Beginning in 2017, cities, counties, governments and other entities in several states in the U.S. have filed lawsuits against oil and gas companies, including ConocoPhillips, seeking compensatory damages and equitable relief to abate alleged climate change impacts. Additional lawsuits with similar allegations are expected to be filed. The amounts claimed by plaintiffs are unspecified and the legal and factual issues involved in these cases are unprecedented. ConocoPhillips believes these lawsuits are factually and legally meritless and are an inappropriate vehicle to address the challenges associated with climate change and will vigorously defend against such lawsuits. Several Louisiana parishes and the State of Louisiana have filed 43 lawsuits under Louisiana’s State and Local Coastal Resources Management Act (SLCRMA) against oil and gas companies, including ConocoPhillips, seeking compensatory damages for contamination and erosion of the Louisiana coastline allegedly caused by historical oil and gas operations. ConocoPhillips entities are defendants in 22 of the lawsuits and will vigorously defend against them. Because Plaintiffs’ SLCRMA theories are unprecedented, there is uncertainty about these claims (both as to scope and damages) and any potential financial impact on the company. In 2016, ConocoPhillips, through its subsidiary, The Louisiana Land and Exploration Company LLC, submitted claims as the largest private wetlands owner in Louisiana within the settlement claims administration process related to the oil spill in the Gulf of Mexico in April 2010. In July 2020, the claims administrator issued an award to the company which, after fees and expenses, totaled approximately $ 90 million, which was received in the third quarter of 2020. In October 2020, the Bureau of Safety and Environmental Enforcement (BSEE) ordered the prior owners of Outer Continental Shelf (OCS) Lease P-0166, including ConocoPhillips, to decommission the lease facilities, including two offshore platforms located near Carpinteria, California. This order was sent after the current owner of OCS Lease P-0166 relinquished the lease and abandoned the lease platforms and facilities. Phillips Petroleum Company, a legacy company of ConocoPhillips, held a 25 percent interest in this lease and operated

these facilities, but sold its interest approximately 30 years ago. ConocoPhillips has not had any connection to the operation or production on this lease since that time. ConocoPhillips plans to challenge the order.

Note 13—Derivative and Financial Instruments We use futures, forwards, swaps and options in various markets to meet our customer needs, capture market opportunities and manage foreign exchange currency risk. Commodity Derivative Instruments Our commodity business primarily consists of natural gas, crude oil, bitumen, LNG and NGLs. Commodity derivative instruments are held at fair value on our consolidated balance sheet. Where these balances have the right of setoff, they are presented on a net basis. Related cash flows are recorded as operating activities on our consolidated statement of cash flows. On our consolidated income statement, realized and unrealized gains and losses are recognized either on a gross basis if directly related to our physical business or a net basis if held for trading. Gains and losses related to contracts that meet and are designated with the NPNS exception are recognized upon settlement. We generally apply this exception to eligible crude contracts. We do not elect hedge accounting for our commodity derivatives.

The following table presents the gross fair values of our commodity derivatives, excluding collateral, and the line items where they appear on our consolidated balance sheet: Millions of Dollars September 30 December 31 2020 2019 Assets Prepaid expenses and other current assets $ 273 288 Other assets 28 34 Liabilities Other accruals 258 283 Other liabilities and deferred credits 19 28

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 2020 2019 2020 2019 Sales and other operating revenues $ 33 4 30 68 Other income (loss) ( 2 ) 3 3 4 Purchased commodities ( 27 ) ( 9 ) ( 29 ) ( 60 )

The table below summarizes our material net exposures resulting from outstanding commodity derivative contracts: Open Position Long/(Short) September 30 December 31 2020 2019 Commodity Natural gas and power (billions of cubic feet equivalent) Fixed price ( 9 ) ( 5 ) Basis ( 50 ) ( 23 )

Foreign Currency Exchange Derivatives We have foreign currency exchange rate risk resulting from international operations. Our foreign currency exchange derivative activity primarily relates to managing our cash-related foreign currency exchange rate exposures, such as firm commitments for capital programs or local currency tax payments, dividends and cash returns from net investments in foreign affiliates, and investments in equity securities. Our foreign currency exchange derivative instruments are held at fair value on our consolidated balance sheet. Related cash flows are recorded as operating activities on our consolidated statement of cash flows. We do not elect hedge accounting on our foreign currency exchange derivatives.

The following table presents the gross fair values of our foreign currency exchange derivatives, excluding collateral, and the line items where they appear on our consolidated balance sheet: Millions of Dollars September 30 December 31 2020 2019 Assets Prepaid expenses and other current assets $ 16 1 Liabilities Other accruals - 20 Other liabilities and deferred credits - 8

The (gains) losses from foreign currency exchange derivatives incurred, and the line item where they appear on our consolidated income statement were: Millions of Dollars Three Months Ended Nine Months Ended September 30 September 30 2020 2019 2020 2019 Foreign currency transaction (gain) loss $ 7 ( 24 ) ( 55 ) ( 3 )

We had the following net notional position of outstanding foreign currency exchange derivatives: In Millions Notional Currency September 30 December 31 2020 2019 Foreign Currency Exchange Derivatives Buy GBP, sell EUR GBP 3 4 Sell CAD, buy USD CAD 416 1,337

In the second quarter of 2019, we entered into foreign currency exchange contracts to sell CAD 1.35 billion at CAD 0.748 against the USD . In the first quarter of 2020, we entered into forward currency exchange contracts to buy CAD 0.9 billion at CAD 0.718 against the USD

Financial Instruments We invest in financial instruments with maturities based on our cash forecasts for the various accounts and currency pools we manage. The types of financial instruments in which we currently invest include: ● Time deposits: Interest bearing deposits placed with financial institutions for a predetermined amount of time. ● Demand deposits: Interest bearing deposits placed with financial institutions. Deposited funds can be withdrawn without notice. ● Commercial paper: Unsecured promissory notes issued by a corporation, commercial bank or government agency purchased at a discount to mature at par. ● U.S. government or government agency obligations: Securities issued by the U.S. government or U.S. government agencies. ● Foreign government obligations: Securities issued by foreign governments. ● Corporate bonds: Unsecured debt securities issued by corporations. ● Asset-backed securities: Collateralized debt securities.

The following investments are carried on our consolidated balance sheet at cost, plus accrued interest: Millions of Dollars Carrying Amount Cash and Cash Equivalents Short-Term Investments September 30 December 31 September 30 December 31 2020 2019 2020 2019 Cash $ 545 759 Demand Deposits 1,182 1,483 Time Deposits Remaining maturities from 1 to 90 days 755 2,030 2,961 1,395 Remaining maturities from 91 to 180 days - - 741 465 Remaining maturities within one year - - 7 - Commercial Paper Remaining maturities from 1 to 90 days - 413 50 1,069 U.S. Government Obligations Remaining maturities from 1 to 90 days 5 394 - - $ 2,487 5,079 3,759 2,929

The following investments in debt securities classified as available for sale are carried on our consolidated balance sheet at fair value: Millions of Dollars Carrying Amount Cash and Cash Equivalents Short-Term Investments Investments and Long-Term Receivables September 30 2020 December 31 2019 September 30 2020 December 31 2019 September 30 2020 December 31 2019 Corporate Bonds Maturities within one year $ - 1 157 59 - - Maturities greater than one year through five years - - - - 128 99 Commercial Paper Maturities within one year 3 8 108 30 - - U.S. Government Obligations Maturities within one year - - 8 10 - - Maturities greater than one year through five years - - - - 13 15 U.S. Government Agency Obligations Maturities greater than one year through five years - - - - 17 - Foreign Government Obligations Maturities greater than one year through five years - - - - 2 - Asset-backed Securities Maturities greater than one year through five years - - - - 46 19 $ 3 9 273 99 206 133

The following table summarizes the amortized cost basis and fair value of investments in debt securities classified as available for sale: Millions of Dollars September 30, 2020 December 31, 2019 Amortized Cost Basis Fair Value Amortized Cost Basis Fair Value Major Security Type Corporate bonds $ 283 285 159 159 Commercial paper 111 111 38 38 U.S. government obligations 21 21 25 25 U.S. government agency obligations 17 17 - - Foreign government obligations 2 2 - - Asset-backed securities 46 46 19 19 $ 480 482 241 241

As of September 30, 2020 and December 31, 2019, total unrealized losses for debt securities classified as available for sale with net losses were negligible. Additionally, as of September 30, 2020 and December 31, 2019, investments in these debt securities in an unrealized loss position for which an allowance for credit losses has not been recorded were negligible.

For the three- and nine-month periods ended September 30, 2020, proceeds from sales and redemptions of investments in debt securities classified as available for sale were $ 109 million and $ 298 million, respectively. Gross realized gains and losses included in earnings from those sales and redemptions were negligible. The cost of securities sold and redeemed is determined using the specific identification method.

Credit Risk Financial instruments potentially exposed to concentrations of credit risk consist primarily of cash equivalents, short-term investments, long-term investments in debt securities, 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, time deposits with major international banks and financial institutions, and high-quality corporate bonds. Our long-term investments in debt securities are placed in high-quality corporate bonds, U.S. government and government agency obligations, foreign government obligations, and asset-backed securities. 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. Our collateral requirements will depend on the creditworthiness of our counterparties. At our option, we may require collateral to limit the exposure to loss including, letters of credit, prepayments and surety bonds, as well as 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, 2020 and December 31, 2019, was $ 20 million and $ 79 million, respectively. For these instruments, no collateral was posted as of September 30, 2020 or December 31, 2019. If our credit rating had been downgraded below investment grade on September 30, 2020, we would have been required to post $ 16 million of additional collateral, either with cash or letters of credit.

Note 14—Fair Value Measurement We carry a portion of our assets and liabilities at fair value measured at the 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 hierarchy 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. There were no material transfers into or out of Level 3 during 2020 or 2019.

Recurring Fair Value Measurement Financial assets and liabilities reported at fair value on a recurring basis primarily include our investment in Cenovus Energy common shares, our investments in debt securities classified as available for sale, and commodity derivatives. ● Level 1 derivative assets and liabilities primarily represent exchange-traded futures and options that are valued using unadjusted prices available from the underlying exchange. Level 1 also includes our investment in common shares of Cenovus Energy, which is valued using quotes for shares on the NYSE, and our investments in U.S. government obligations classified as available for sale debt securities, which are valued using exchange prices. ● 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 2 also includes our investments in debt securities classified as available for sale including investments in corporate bonds, commercial paper, asset-backed securities, U.S. government agency obligations and foreign government obligations that are valued using pricing provided by brokers or pricing service companies that are corroborated with 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, 2020 December 31, 2019 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets Investment in Cenovus Energy $ 809 - - 809 2,111 - - 2,111 Investments in debt securities 21 461 - 482 25 216 - 241 Commodity derivatives 173 117 11 301 172 114 36 322 Total assets $ 1,003 578 11 1,592 2,308 330 36 2,674 Liabilities Commodity derivatives $ 173 89 15 277 174 115 22 311 Total liabilities $ 173 89 15 277 174 115 22 311

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, 2020 Assets $ 301 1 300 204 96 5 91 Liabilities 277 - 277 204 73 7 66 December 31, 2019 Assets $ 322 3 319 193 126 4 122 Liabilities 311 4 307 193 114 12 102 At September 30, 2020 and December 31, 2019, we did not present any amounts gross on our consolidated balance sheet where we had the right of setoff.

Non-Recurring Fair Value Measurement The following table summarizes the fair value hierarchy by major category and date of remeasurement for assets accounted for at fair value on a non-recurring basis: Millions of Dollars Fair Value Measurement Using Fair Value Level 3 Inputs Before-Tax Loss Net PP&E (held for use) March 31, 2020 $ 77 77 510

During the first quarter of 2020 , the estimated fair value of our assets in the Wind River Basin operations area declined to an amount below the carrying value. The Wind River Basin operations area consists of certain developed natural gas properties in the Madden Field and the Lost Cabin Gas Plant and is included in our Lower 48 segment. The carrying value was written down to fair value. The fair value was estimated based on an internal discounted cash flow model using estimates of future production, an outlook of future prices using a combination of exchanges (short-term) and external pricing services companies (long-term), future operating costs and capital expenditures, and a discount rate believed to be consistent with those used by principal market participants. The range and arithmetic average of significant unobservable inputs used in the Level 3 fair value measurement were as follows:

Fair Value (Millions of Dollars) Valuation Technique Unobservable Inputs Range (Arithmetic Average) March 31, 2020 Wind River Basin $ 77 Discounted cash flow Natural gas production (MMCFD) 8.4 - 55.2 ( 22.9 ) Natural gas price outlook* ($/MMBTU) $ 2.67 - $ 9.17 ($ 5.68 ) Discount rate** 7.9 % - 9.1 % ( 8.3 %) *Henry Hub natural gas price outlook based on external pricing service companies' outlooks for years 2022-2034; future prices escalated at 2.2 % annually after year 2034. **Determined as the weighted average cost of capital of a group of peer companies, adjusted for risks where appropriate.

Reported Fair Values of Financial Instruments We used the following methods and assumptions to estimate the fair value of financial instruments: ● Cash and cash equivalents and short-term investments: The carrying amount reported on the balance sheet approximates fair value. For those investments classified as available for sale debt securities, the carrying amount reported on the balance sheet is fair value. ● Accounts and notes receivable (including long-term and related parties): The carrying amount reported on the balance sheet approximates fair value. The valuation technique and methods used to estimate the fair value of the current portion of fixed-rate related party loans is consistent with Loans and advances—related parties. ● Investment in Cenovus Energy: See Note 6—Investment in Cenovus Energy for a discussion of the carrying value and fair value of our investment in Cenovus Energy common shares. ● Investments in debt securities classified as available for sale: The fair value of investments in debt securities categorized as Level 1 in the fair value hierarchy is measured using exchange prices. The fair value of investments in debt securities categorized as Level 2 in the fair value hierarchy is measured using pricing provided by brokers or pricing service companies that are corroborated with market data. See Note 13—Derivatives and Financial Instruments, for additional information. ● Loans and advances—related parties: The carrying amount of floating-rate loans approximates fair value. The fair value of fixed-rate loan activity is measured using market observable data and is categorized as Level 2 in the fair value hierarchy. See Note 5—Investments, Loans and Long-Term Receivables, for additional information. ● Accounts payable (including related parties) and floating-rate debt: The carrying amount of accounts payable and floating-rate debt reported on the balance sheet approximates fair value. ● Fixed-rate debt: The estimated fair value of fixed-rate debt is measured using prices available from a pricing service that is corroborated by market data; therefore, these liabilities are categorized as Level 2 in the fair value hierarchy. ● Commercial paper: The carrying amount of our commercial paper instruments approximates fair value and is reported on the balance sheet as short-term debt. See Note 9—Debt, for additional information.

The following table summarizes the net fair value of financial instruments (i.e., adjusted where the right of setoff exists for commodity derivatives): Millions of Dollars Carrying Amount Fair Value September 30 December 31 September 30 December 31 2020 2019 2020 2019 Financial assets Investment in Cenovus Energy $ 809 2,111 809 2,111 Commodity derivatives 92 125 92 125 Investments in debt securities 482 241 482 241 Total loans and advances—related parties 219 339 219 339 Financial liabilities Total debt, excluding finance leases 14,482 14,175 18,827 18,108 Commodity derivatives 66 106 66 106

Note 15—Accumulated Other Comprehensive Loss Accumulated other comprehensive loss in the equity section of our consolidated balance sheet included: Millions of Dollars Defined Benefit Plans Net Unrealized Gain on Securities Foreign Currency Translation Accumulated Other Comprehensive Loss December 31, 2019 $ ( 350 ) - ( 5,007 ) ( 5,357 ) Other comprehensive income (loss) ( 13 ) 2 ( 298 ) ( 309 ) September 30, 2020 $ ( 363 ) 2 ( 5,305 ) ( 5,666 )

The following table summarizes reclassifications out of accumulated other comprehensive loss and into net income (loss): Millions of Dollars Three Months Ended Nine Months Ended September 30 September 30 2020 2019 2020 2019 Defined benefit plans $ 30 36 46 66

The above amounts are included in the computation of net periodic benefit cost and are presented net of tax expense of $ 7 million and $ 12 million for the three-month periods ended September 30, 2020 and September 30, 2019, respectively, and $ 11 million and $ 22 million for the nine-month periods ended September 30, 2020 and September 30, 2019, respectively. See Note 17—Employee Benefit Plans, for additional information.

Note 16—Cash Flow Information Millions of Dollars Nine Months Ended September 30 2020 2019 Cash Payments Interest $ 591 614 Income taxes 803 2,210 Net Sales (Purchases) of Investments Short-term investments purchased $ ( 9,662 ) ( 1,894 ) Short-term investments sold 8,776 1,229 Long-term investments purchased ( 271 ) - Long-term investments sold 68 - $ ( 1,089 ) ( 665 )

Note 17—Employee Benefit Plans Pension and Postretirement Plans Millions of Dollars Pension Benefits Other Benefits 2020 2019 2020 2019 U.S. Int'l. U.S. Int'l. Components of Net Periodic Benefit Cost Three Months Ended September 30 Service cost $ 21 14 20 19 1 1 Interest cost 17 21 21 25 2 1 Expected return on plan assets ( 21 ) ( 37 ) ( 18 ) ( 34 ) - - Amortization of prior service credit - ( 1 ) - - ( 7 ) ( 7 ) Recognized net actuarial loss (gain) 12 5 13 7 1 ( 1 ) Settlements 27 - 37 - - - Curtailments - - - ( 1 ) - - Net periodic benefit cost $ 56 2 73 16 ( 3 ) ( 6 ) Nine Months Ended September 30 Service cost $ 63 41 59 56 2 1 Interest cost 51 63 63 77 5 6 Expected return on plan assets ( 63 ) ( 108 ) ( 54 ) ( 104 ) - - Amortization of prior service credit - ( 1 ) - ( 1 ) ( 23 ) ( 24 ) Recognized net actuarial loss (gain) 37 16 39 23 1 ( 2 ) Settlements 28 ( 1 ) 54 - - - Curtailments - - - ( 1 ) - - Net periodic benefit cost $ 116 10 161 50 ( 15 ) ( 19 )

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 2020, we contributed $ 87 million to our domestic benefit plans and $ 57 million to our international benefit plans. In 2020, we expect to contribute a total of approximately $ 135 million to our domestic qualified and nonqualified pension and postretirement benefit plans and $ 65 million to our international qualified and nonqualified pension and postretirement benefit plans.

During the three-month period ended September 30, 2020, lump-sum benefit payments exceeded the sum of service and interest costs for the year for the U.S. qualified pension plan. As a result, we recognized a proportionate share of prior actuarial losses from other comprehensive income as pension settlement expense of $ 27 million. In conjunction with the recognition of pension settlement expense, the fair market values of the pension plan assets were updated and the pension benefit obligation of the plan was remeasured as of September 30, 2020. At the measurement date, the net pension liability increased by $ 78 million, resulting in a corresponding decrease to other comprehensive loss. This is primarily a result of a decrease in the discount rate and reduced long-term lump sum rate assumptions offset by better actual return on assets compared with the expected return.

Note 18—Related Party Transactions Our related parties primarily include equity method investments and certain trusts for the benefit of employees. For disclosures on trusts for the benefit of employees, see Note 17—Employee Benefit Plans. Significant transactions with our equity affiliates were: Millions of Dollars Three Months Ended Nine Months Ended September 30 September 30 2020 2019 2020 2019 Operating revenues and other income $ 21 23 59 70 Purchases - - - 38 Operating expenses and selling, general and administrative expenses 16 19 43 47 Net interest income* ( 1 ) ( 3 ) ( 5 ) ( 10 ) *We paid interest to, or received interest from, various affiliates. See Note 5—Investments, Loans and Long-Term Receivables, for additional information on loans to affiliated companies.

Note 19—Sales and Other Operating Revenues Revenue from Contracts with Customers The following table provides further disaggregation of our consolidated sales and other operating revenues:

Millions of Dollars Three Months Ended Nine Months Ended September 30 September 30 2020 2019 2020 2019 Revenue from contracts with customers $ 3,078 6,240 9,908 19,932 Revenue from contracts outside the scope of ASC Topic 606 Physical contracts meeting the definition of a derivative 1,280 1,529 3,432 4,981 Financial derivative contracts 28 ( 13 ) ( 47 ) ( 54 ) Consolidated sales and other operating revenues $ 4,386 7,756 13,293 24,859

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 20—Segment Disclosures and Related Information:

Millions of Dollars Three Months Ended Nine Months Ended September 30 September 30 2020 2019 2020 2019 Revenue from Outside the Scope of ASC Topic 606 by Segment Lower 48 $ 1,018 1,099 2,692 3,823 Canada 152 86 452 427 Europe, Middle East and North Africa 110 344 288 731 Physical contracts meeting the definition of a derivative $ 1,280 1,529 3,432 4,981

Millions of Dollars Three Months Ended Nine Months Ended September 30 September 30 2020 2019 2020 2019 Revenue from Outside the Scope of ASC Topic 606 by Product Crude oil $ 100 266 218 619 Natural gas 1,042 1,159 2,895 4,022 Other 138 104 319 340 Physical contracts meeting the definition of a derivative $ 1,280 1,529 3,432 4,981

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

Receivables and Contract Liabilities Receivables from Contracts with Customers At September 30, 2020, the “Accounts and notes receivable” line on our consolidated balance sheet, includes trade receivables of $ 1,338 million compared with $ 2,372 million at December 31, 2019, and includes both contracts with customers within the scope of ASC Topic 606 and those that are outside the scope of ASC Topic 606. We typically receive payment within 30 days or less (depending on the terms of the invoice) once delivery is made. Revenues that are outside the scope of ASC Topic 606 relate primarily to physical gas sales contracts at market prices for which we do not elect NPNS and are therefore accounted for as a derivative under ASC Topic 815. There is little distinction in the nature of the customer or credit quality of trade receivables associated with gas sold under contracts for which NPNS has not been elected compared to trade receivables where NPNS has been elected.

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

Millions of Dollars Contract Liabilities At December 31, 2019 $ 80 Contractual payments received 8 At September 30, 2020 $ 88 Amounts Recognized in the Consolidated Balance Sheet at September 30, 2020 Current liabilities $ 47 Noncurrent liabilities 41 $ 88

We expect to recognize the contract liabilities as of September 30, 2020, as revenue during 2021 and 2022. There were no revenues recognized for the three- and nine-month periods ended September 30, 2020.

Note 20—Segment Disclosures and Related Information We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on a worldwide basis. We manage our operations through six operating segments, which are primarily defined by geographic region: Alaska; Lower 48; Canada; Europe, Middle East and North Africa; Asia Pacific 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. We evaluate performance and allocate resources based on net income (loss) attributable to ConocoPhillips. Intersegment sales are at prices that approximate market.

Effective with the third quarter of 2020, we have restructured our segments to align with changes to our internal organization. The Middle East business was realigned from the Asia Pacific and Middle East segment to the Europe and North Africa segment. The segments have been renamed the Asia Pacific segment and the Europe, Middle East and North Africa segment. We have revised segment information disclosures and segment performance metrics presented within our results of operations for the current and prior comparative periods.

Analysis of Results by Operating Segment Millions of Dollars Three Months Ended Nine Months Ended September 30 September 30 2020 2019 2020 2019 Sales and Other Operating Revenues Alaska $ 864 1,296 2,396 4,129 Intersegment eliminations ( 30 ) - ( 11 ) - Alaska 834 1,296 2,385 4,129 Lower 48 2,323 3,728 6,859 11,690 Intersegment eliminations ( 9 ) ( 10 ) ( 47 ) ( 33 ) Lower 48 2,314 3,718 6,812 11,657 Canada 348 633 1,026 2,173 Intersegment eliminations ( 20 ) ( 273 ) ( 200 ) ( 858 ) Canada 328 360 826 1,315 Europe, Middle East and North Africa 432 1,225 1,320 4,084 Asia Pacific 477 1,085 1,930 3,458 Other International 1 - 5 - Corporate and Other - 72 15 216 Consolidated sales and other operating revenues $ 4,386 7,756 13,293 24,859 Sales and Other Operating Revenues by Geographic Location (1) United States $ 3,148 5,085 9,209 15,996 Australia - 412 605 1,282 Canada 328 360 826 1,315 China 161 191 374 593 Indonesia 167 223 503 654 Libya 6 288 50 809 Malaysia 148 258 447 928 Norway 358 632 1,046 1,781 United Kingdom 68 305 224 1,494 Other foreign countries 2 2 9 7 Worldwide consolidated $ 4,386 7,756 13,293 24,859 Sales and Other Operating Revenues by Product Crude oil $ 2,321 4,612 6,981 14,006 Natural gas 1,509 1,799 4,354 6,717 Natural gas liquids 129 156 364 607 Other (2) 427 1,189 1,594 3,529 Consolidated sales and other operating revenues by product $ 4,386 7,756 13,293 24,859 (1) Sales and other operating revenues are attributable to countries based on the location of the selling operation. (2) Includes LNG and bitumen.

Millions of Dollars Three Months Ended Nine Months Ended September 30 September 30 2020 2019 2020 2019 Net Income (Loss) Attributable to ConocoPhillips Alaska $ ( 16 ) 306 ( 76 ) 1,152 Lower 48 ( 78 ) 26 ( 880 ) 425 Canada ( 75 ) 51 ( 270 ) 273 Europe, Middle East and North Africa 92 2,171 318 3,050 Asia Pacific 25 443 945 1,220 Other International ( 8 ) 73 14 285 Corporate and Other ( 390 ) ( 14 ) ( 1,980 ) 64 Consolidated net income (loss) attributable to ConocoPhillips $ ( 450 ) 3,056 ( 1,929 ) 6,469

Millions of Dollars September 30 December 31 2020 2019 Total Assets Alaska $ 15,910 15,453 Lower 48 12,196 14,425 Canada 6,581 6,350 Europe, Middle East and North Africa 8,420 9,269 Asia Pacific 11,359 13,568 Other International 300 285 Corporate and Other 8,391 11,164 Consolidated total assets $ 63,157 70,514

Note 21—Income Taxes Our effective tax rate was 12 percent in the three-month periods ended September 30, 2020 and 2019. Both periods were primarily impacted by shifts in our before-tax income between higher and lower tax jurisdictions as well as the change in our U.S. valuation allowance driven by the fair value measurement of our Cenovus Energy common shares. The three-month period ended September 30, 2019 was also impacted by the recognition of certain tax incentives in Malaysia. Our effective tax rates for the nine-month periods ended September 30, 2020 and 2019 were 8 percent and 21 percent, respectively. The nine-month period ended September 30, 2020 was impacted by the same items noted above. Additionally, the nine-months ended September 30, 2020 was impacted by the gain on disposition recognized for our Australia-West assets of $ 587 million with an associated tax benefit of $ 10 million, the de-recognition of $ 92 million of deferred tax assets recorded as income tax expense as a result of this divestiture, and a $ 48 million refund from the Alberta Tax and Revenue Administration. The nine-month period ended September 30, 2019 was impacted by the same items noted above in addition to a benefit of $ 262 million related to the recognition of a U.S. capital loss benefit from our U.K. entity disposition. As a result of the COVID-19 pandemic and the resulting economic uncertainty, many countries in which we operate, including Australia, Canada, Norway and the U.S., have enacted responsive tax legislation. During the second quarter, Norway enacted legislation to accelerate the recovery of capital expenditures and allow immediate monetization of tax losses. As a result, in the second quarter of 2020, we recorded an increase to our net deferred tax liability of $ 120 million and a decrease to our accrued income and other taxes liability of $ 124 million. Legislation in other jurisdictions did not have a material impact to ConocoPhillips.

During the three- and nine-month periods ended September 30, 2020, our valuation allowance increased by $ 33 million and $ 264 million, respectively. The change to our U.S. valuation allowance for both periods relates primarily to the fair value measurement of our Cenovus Energy common shares and our expectation of the tax impact related to incremental capital gains and losses.

Note 22—Announced Acquisition of Concho Resources Inc. On October 19, 2020 , we announced a definitive agreement (the Merger Agreement) to acquire Concho Resources Inc. (Concho) in an all-stock transaction valued at $ 9.7 billion based upon closing share prices on October 16, 2020. Under the terms of the transaction, which has been unanimously approved by the board of directors of each company, each share of Concho common stock will be exchanged for a fixed ratio of 1.46 shares of ConocoPhillips common stock. We will also assume the debt balances of Concho, which were approximately $ 3.9 billion at September 30, 2020. The transaction is anticipated to close in the first quarter of 2021, subject to the approval of both ConocoPhillips and Concho shareholders, regulatory clearance, and other customary closing conditions. If the Merger Agreement is terminated under certain circumstances, we may be required to pay a termination fee of $ 450 million, including if the proposed Merger is terminated because our board of directors has changed its recommendation in respect of the stockholder proposal relating to the Merger. In addition, we may be required to reimburse Concho for its expenses in an amount equal to $ 142.5 million if the Merger Agreement is terminated because of a failure of our stockholders to approve the stockholder proposal. See Item 1A. “Risk Factors” for further discussion of risks related to the Concho acquisition.

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 57.

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

BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW

ConocoPhillips is an independent E&P company with operations and activities in 15 countries. Our diverse, low cost of supply portfolio includes resource-rich unconventional plays in North America; conventional assets in North America, Europe and Asia; LNG developments; oil sands assets in Canada; and an inventory of global conventional and unconventional exploration prospects. At September 30, 2020, we employed approximately 9,800 people worldwide and had total assets of $63 billion.

Announced Acquisition of Concho Resources Inc. and Paris-Aligned Climate Risk Strategy

On October 19, 2020, we announced entry into a definitive agreement to acquire Concho Resources Inc. (Concho) in an all-stock transaction valued at $9.7 billion based upon closing share prices on October 16, 2020. Under the terms of the transaction, each outstanding share of common stock of Concho will be converted into the right to receive 1.46 shares of ConocoPhillips common stock. We will also assume the debt balances of Concho, which were approximately $3.9 billion at September 30, 2020. The combined companies are expected to capture $500 million of annual cost and capital savings by 2022, which would be sourced from lower general and administrative costs and a reduction in our future global new ventures exploration program. The transaction is anticipated to close in the first quarter of 2021, subject to the approval of both ConocoPhillips and Concho shareholders, regulatory clearance, and the satisfaction or waiver of other customary closing conditions. See Item 1A. “Risk Factors” for further discussion of risks related to the Concho acquisition.

We also announced the adoption of a Paris-aligned climate risk framework as part of our continued commitment to ESG excellence. This comprehensive climate risk strategy should enable us to sustainably meet global energy demand while delivering competitive returns through the energy transition. We have set a target to reduce our gross operated (scope 1 and 2) emissions intensity by 35 to 45 percent from 2016 levels by 2030, with an ambition to achieve net zero by 2050 for operated emissions. We are advocating for reduction of scope 3 end-use emissions intensity through our support for a U.S. carbon price and reaffirmed our commitment to the Climate Leadership Council. We have joined the World Bank Flaring Initiative to work towards zero routine flaring of gas by 2030. We are committed to take ESG leadership to the next level as the first U.S.-based oil and gas company to adopt a Paris-aligned climate risk strategy.

Overview

The energy landscape changed dramatically in 2020 with simultaneous demand and supply shocks that drove the industry into a severe downturn. The demand shock was triggered by COVID-19, which was declared a global pandemic and caused unprecedented social and economic consequences. Mitigation efforts to stop the spread of this contagious disease included stay-at-home orders and business closures that caused sharp contractions in economic activity worldwide. The supply shock was triggered by disagreements between OPEC and Russia, beginning in early March, which resulted in significant supply coming onto the market and an oil price war. These dual demand and supply shocks caused oil prices to collapse as we exited the first quarter.

As we entered the second quarter, predictions of COVID-19 driven global oil demand losses intensified, with forecasts of unprecedented demand declines. Based on these forecasts, OPEC plus nations held an emergency meeting, and in April they announced a coordinated production cut that was unprecedented in both its magnitude and duration. The OPEC plus agreement spans from May 2020 until April 2022, with the volume of production cuts easing over time. Additionally, non-OPEC plus countries, including the U.S., Canada, Brazil and other G-20 countries, announced organic reductions to production through the release of drilling rigs, frac crews, normal field decline and curtailments. Despite these planned production decreases, the supply cuts were not timely enough to overcome significant demand decline. Futures prices for April WTI closed under $20 a barrel for the first time since 2001, followed by May WTI settling below zero on the day before futures contracts expiry, as holders of May futures contracts struggled to exit positions and avoid taking physical delivery. As storage constraints approached, spot prices in April for certain North American landlocked grades of crude oil were in the single digits or even negative for particularly remote or low-grade crudes, while waterborne priced crudes such as Brent sold at a relative advantage. The extreme volatility experienced in the first half of the year settled down in the third quarter, with crude oil prices stabilizing around $40 per barrel.

Since the start of the severe downturn, we have closely monitored the market and taken prudent actions in response to this situation. We entered the year in a position of relative strength, with cash and cash equivalents of more than $5 billion, short-term investments of $3 billion, and an undrawn credit facility of $6 billion, totaling approximately $14 billion in available liquidity. Additionally, we had several entity and asset sales agreements in place, which generated $1.3 billion in proceeds from dispositions during the first nine-months of 2020. For more information about the sales of our Australia-West and non-core Lower 48 assets, see Note 4— Asset Acquisitions and Dispositions in the Notes to Consolidated Financial Statements. This relative advantage allowed us to be measured in our response to the sudden change in business environment.

In March, we announced an initial set of actions to address the downturn and followed up with additional actions in April. The combined announcements reflected a reduction in our 2020 operating plan capital of $2.3 billion, a reduction to our operating costs of $600 million and suspension of our share repurchase program. These actions will decrease uses of cash by approximately $5 billion in 2020. We also established a framework for evaluating and implementing economic production curtailments considering the weakness in oil prices during the second quarter of 2020, which resulted in taking an additional significant step of voluntarily curtailing production, predominantly from operated North American assets. Due to our strong balance sheet, we were in an advantaged position to forgo some production and cash flow in anticipation of receiving higher cash flows for those volumes in the future.

In the second quarter, we curtailed production by an estimated 225 MBOED, with 145 MBOED of the curtailments from the Lower 48, 40 MBOED from Alaska and 30 MBOED from our Surmont operation in Canada. The remainder of the second-quarter curtailments were primarily in Malaysia. Other industry operators also cut production and development plans and as we progressed through the second quarter, stay-athome restrictions eased, which partially restored lost demand, and WTI and Brent prices exited the second quarter around $40 per barrel. Based on our economic criteria, we began restoring production from voluntary curtailments in July, and with oil stabilizing around $40 per barrel, we ended our curtailment program during the third quarter. Curtailments in the third quarter averaged approximately 90 MBOED, with 65 MBOED attributable to the Lower 48 and 15 MBOED to Surmont.

In August 2020, we completed the agreement to acquire additional Montney acreage for cash consideration of approximately $382 million, subject to customary post-closing adjustments. As part of the agreement, we assumed approximately $31 million in financing obligations for associated partially owned infrastructure. This acquisition consisted primarily of undeveloped properties and included 140,000 net acres in the liquids-rich Inga Fireweed asset Montney zone, which is directly adjacent to our existing Montney position. We now have a Montney acreage position of 295,000 net acres with a 100 percent working interest.

On September 30, 2020, we announced our intent to resume share repurchases; however, we recently announced the pending acquisition of Concho and our suspension of share repurchases until after the transaction closes. We ended the third quarter with over $12 billion of liquidity, comprised of $2.5 billion in cash and cash equivalents, $4.0 billion in short-term investments, and available borrowings under our credit facility of $5.7 billion. On October 9, 2020, we announced an increase to our quarterly dividend from 42 cents per share to 43 cents per share. The dividend is payable on December 1, 2020 to shareholders of record as of October 19, 2020.

Our expectation is that commodity prices will remain cyclical and volatile, and a successful business strategy in the E&P industry must be resilient in lower price environments, at the same time retaining upside during periods of higher prices. While we are not impervious to current market conditions, our decisive actions over the last several years of focusing on free cash flow generation, high-grading our asset base, lowering the cost of supply of our investment resource portfolio, and strengthening our balance sheet have put us in a strong relative position compared to our independent E&P peers. Although recent prices have been volatile, we remain committed to our core value proposition principles, namely, to focus on financial returns, maintain a strong balance sheet, deliver compelling returns of capital, and maintain disciplined capital investments.

Our workforce and operations have adjusted to mitigate the impacts of the COVID-19 global pandemic. We have operations in remote areas with confined spaces, such as offshore platforms, the North Slope of Alaska, Curtis Island in Australia, western Canada and Indonesia, where viruses could rapidly spread. Personnel are asked to perform a self-assessment for symptoms of illness each day and, when appropriate, are subject to more restrictive measures traveling to and working on location. Staffing levels in certain operating locations have been reduced to minimize health risk exposure and increase social distancing. A portion of our office staff have continued to work successfully remotely, with offices around the world carefully designing and executing a flexible, phased reentry, following national, state and local guidelines. These mitigation measures have thus far been effective at reducing business operation disruptions. Workforce health and safety remains the overriding driver for our actions and we have demonstrated our ability to adapt to local conditions as warranted.

The marketing and supply chain side of our business has also adapted in response to COVID-19. Our commercial organization managed transportation commitments during our voluntary curtailment program. Our supply chain function is proactively working with vendors to ensure the continuity of our business operations, monitor distressed service and materials providers, capture deflation opportunities, and pursue cost reduction efforts.

Operationally, we remain focused on safely executing the business. In the third quarter of 2020, production of 1,067 MBOED generated cash provided by operating activities of $0.9 billion. We invested $1.1 billion into the business in the form of capital expenditures, including $0.4 billion of acquisition capital, and paid dividends to shareholders of $0.5 billion. Production decreased 299 MBOED or 22 percent in the third quarter of 2020, compared to the third quarter of 2019. Adjusting for estimated curtailments of approximately 90 MBOED, closed acquisitions and dispositions and Libya, third quarter 2020 production would have been 1,155 MBOED, a decrease of 46 MBOED or 4 percent compared with the third quarter of 2019. This decrease was primarily due to normal field decline, partly offset by new wells online in the Lower 48, Canada and China. Production from Libya averaged 1 MBOED as it remained in force majeure during the third quarter. Force majeure was lifted in October and plans to resume production and exports are ongoing.

Business Environment

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 or demand disruptions or fears thereof caused by civil unrest, global pandemics, military conflicts, actions taken by OPEC plus and other major oil producing countries, environmental laws, tax regulations, governmental policies and weather-related disruptions. Our strategy is to create value through price cycles by delivering on the financial and operational priorities that underpin our value proposition.

Our earnings and operating cash flows generally correlate with price levels for crude oil and natural gas, which are subject to factors external to the company and over which we have no control. The following graph depicts the trend in average benchmark prices for WTI crude oil, Brent crude oil and Henry Hub natural gas:

WTI Crude Oil, Brent Crude Oil and Henry Hub Natural Gas Prices

Quarterly Averages WTI/BrentHH $/Bbl 804

3 60

40 1

20- Q3'18Q4'18Q1'19Q2'19Q3'19Q4'19Q1'20Q2'20Q3'20

WTI - $/BblBrent - $/BblHH - $/MMBTU

Brent crude oil prices averaged $43.00 per barrel in the third quarter of 2020, a decrease of 31 percent compared with $61.94 per barrel in the third quarter of 2019. WTI at Cushing crude oil prices averaged $40.93 per barrel in the third quarter of 2020, a decrease of 27 percent compared with $56.44 per barrel in the third quarter of 2019. Oil prices are lower due to high inventory levels and contractions in economic activity due to COVID-19 restrictions.

Henry Hub natural gas prices averaged $1.98 per MMBTU in the third quarter of 2020, a decrease of 11 percent compared with $2.23 per MMBTU in the third quarter of 2019. Current period Henry Hub prices are depressed due to high storage levels and seasonally weak demand.

Our realized bitumen price averaged $15.87 per barrel in the third quarter of 2020, a decrease of 51 percent compared with $32.54 per barrel in the third quarter of 2019. The decrease in the third quarter of 2020 was driven by a lower blend price for Surmont sales, largely attributed to a weaker WTI price and a narrower spread between the local market and U.S. sales points, which challenged both pipeline and rail economics. In addition, we incurred unutilized transportation costs which negatively impacted our realized bitumen price.

Our total average realized price was $30.94 per BOE in the third quarter of 2020, compared with $47.07 per BOE in the third quarter of 2019.

Key Operating and Financial Summary

Significant items during the third quarter of 2020 and recent announcements included the following:

●Produced 1,066 MBOED excluding Libya in the third quarter; curtailed approximately 90 MBOED. ●Distributed $0.5 billion in dividends and announced an increase to the quarterly dividend. ●Ended the quarter with cash, cash equivalents and restricted cash totaling $2.8 billion and short-term

investments of $4.0 billion. ●As part of a commitment to ESG excellence, announced adoption of a Paris-aligned climate risk framework to achieve net zero operated emissions by 2050. ●Completed bolt-on acquisition of adjacent acreage in the liquids-rich Montney in Canada for $0.4 billion. ●Announced agreement to acquire Concho in an all-stock transaction for 1.46 shares of ConocoPhillips common stock per share of Concho.

Outlook

Capital and Production In February 2020, we announced 2020 operating plan capital of $6.5 billion to $6.7 billion. In response to the oil market downturn earlier this year, we announced capital expenditure reductions totaling $2.3 billion. Full year 2020 operating plan capital is now expected to be $4.3 billion. This does not include approximately $0.5 billion of capital for acquisitions completed during the year, of which $0.4 billion was for bolt-on acreage in the liquids rich area of the Montney.

Fourth quarter 2020 production is expected to be 1,125 to 1,165 MBOED, resulting in anticipated full-year 2020 production of 1,115 to 1,125 MBOED. This outlook excludes Libya.

Depreciation, Depletion and Amortization DD&A expense was $4.0 billion in the nine-month period of 2020. Proved reserves estimates were updated in the interim periods of 2020 utilizing trailing twelve-month oil and gas prices, which increased DD&A expense in the nine-month period of 2020 by approximately $195 million before-tax. If oil and gas prices persist at depressed levels, our reserve estimates may decrease further, which could incrementally increase the rate used to determine DD&A expense on our unit-of-production method properties.

Impairments In October 2020, we announced an agreement to acquire Concho, thereby significantly expanding our unconventional acreage position in the Permian Basin. The planned addition of unproved properties in the Delaware and Midland Basins would reduce our need for resource additions through organic exploration, and we expect to decrease capital allocated to our global new ventures exploration program going forward. An evaluation of our exploration program is ongoing and may result in future impairments. This transaction is anticipated to close in the first quarter of 2021, subject to the approval of both ConocoPhillips and Concho shareholders, regulatory clearance, and other customary closing conditions.

RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three- and nine-month periods ended September 30, 2020, is based on a comparison with the corresponding periods of 2019.

Consolidated Results

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

Millions of Dollars Three Months EndedNine Months Ended September 30September 30 2020201920202019| Alaska | $****(16) | | 306 | (76) | 1,152 | | --- | --- | --- | --- | --- | --- | | Lower 48 | (78) | | 26 | (880) | 425 | | Canada | (75) | | 51 | (270) | 273 | | Europe, Middle East and North Africa | | 922,171 | | 318 | 3,050 | | Asia Pacific | | 25 | 443 | 945 | 1,220 | | Other International | | (8) | 73 | 14 | 285 | | Corporate and Other | (390) | | (14) | (1,980) | 64 | | Net income (loss) attributable to ConocoPhillips | $****(450) | 3,056 | | (1,929) | 6,469 |

Net income (loss) attributable to ConocoPhillips in the third quarter of 2020 decreased $3,506 million. Earnings were negatively impacted by:

●The absence of a $1.8 billion after-tax gain associated with the completion of the sale of two ConocoPhillips U.K. subsidiaries. ●Lower realized commodity prices. ●Lower sales volumes, primarily due to normal field decline, production curtailments across our North

American operated assets and the divestiture of our U.K. assets in the third quarter of 2019 and Australia-West assets in the second quarter of 2020. ●A $162 million after-tax unrealized loss on our Cenovus Energy (CVE) common shares in the third quarter of 2020, as compared to a $116 million after-tax gain on those shares in the third quarter of 2019. ●Lower equity in earnings of affiliates, primarily due to lower LNG sales prices. ●The absence of a $164 million income tax benefit related to deepwater incentive tax credits recognized for Malaysia Block G.

Third quarter 2020 net income decreases were partly offset by:

●Lower production and operating expenses, primarily due to the absence of costs related to our U.K.

and Australia-West divestitures and decreased wellwork and transportation costs resulting from production curtailments across our North American operated assets. ●Lower exploration expenses, primarily due to the absence of $186 million after-tax of leasehold impairment and dry hole costs associated with our decision to discontinue exploration activities in the Central Louisiana Austin Chalk trend. ●Lower DD&A, primarily due to lower volumes resulting from production curtailments and our Australia-West divestiture, partly offset by higher DD&A rates due to price-related downward reserve revisions.

Net income (loss) attributable to ConocoPhillips in the nine-month period ended September 30, 2020, decreased $8,398 million. Earnings were negatively impacted by:

●Lower realized commodity prices. ●Lower sales volumes, primarily due to normal field decline, production curtailments across our North

American operated assets and the divestiture of our U.K. assets in the third quarter of 2019 and our Australia-West assets in the second quarter of 2020. ●The absence of a $2.1 billion after-tax gain associated with the completion of the sale of two ConocoPhillips U.K. subsidiaries. ●A $1.3 billion after-tax unrealized loss on our CVE common shares in the nine-month period of 2020, as compared to a $0.5 billion after-tax gain on those shares in the nine-month period of 2019. ●Higher impairments of approximately $400 million after-tax, primarily related to non-core gas assets in our Lower 48 segment. ●The absence of other income of $317 million after-tax related to our settlement agreement with PDVSA. ●Lower equity in earnings of affiliates, primarily due to lower LNG sales prices, partly offset by the absence of $120 million after-tax of impairments to equity method investments.

The decreases in earnings in the nine-month period ended September 30, 2020, were partly offset by:

●A $597 million after-tax gain on dispositions related to our Australia-West divestiture. ●Lower production and operating expenses, primarily due to decreased wellwork and transportation

costs resulting from production curtailments across our North American operated assets as well as the absence of costs related to our U.K. and Australia-West divestitures. ●Lower DD&A expenses, primarily due to lower volumes related to production curtailments and our Australia-West and U.K. divestitures, partly offset by higher DD&A rates due to price-related downward reserve revisions. ●Lower exploration expenses, primarily due to the absence of $194 million after-tax of leasehold impairment and dry hole costs associated with our decision to discontinue exploration activities in the Central Louisiana Austin Chalk trend.

See the “Segment Results” section for additional information.

Income Statement Analysis

Sales and other operating revenues for the three- and nine-month periods of 2020 decreased $3,370 million and $11,566 million, respectively, mainly due to lower realized commodity prices and lower sales volumes. Sales volumes decreased due to normal field decline, production curtailments from our North American operated assets and the divestiture of our U.K. assets in the third quarter of 2019 and our Australia-West assets in the second quarter of 2020.

Equity in earnings of affiliates for the three- and nine-month periods of 2020 decreased $255 million and $305 million, respectively, primarily due to lower earnings from QG3 and APLNG as a result of lower LNG sales prices. Partly offsetting this decrease was the absence of impairments related to equity method investments in our Lower 48 segment of $155 million in the nine-month period of 2019.

Gain on dispositions for the three- and nine-month periods of 2020 decreased $1,788 million and $1,333 million, respectively, primarily due to the absence of a $1.8 billion before-tax gain associated with the completion of the sale of two ConocoPhillips U.K. subsidiaries. Partly offsetting the decrease in the ninemonth period of 2020, was a $587 million before-tax gain associated with our Australia-West divestiture. For more information related to our Australia-West divestiture, see Note 4—Asset Acquisitions and Dispositions in the Notes to Consolidated Financial Statements.

Other income (loss) for the third quarter of 2020 decreased $300 million, primarily due to an unrealized loss of $162 million before-tax on our CVE common shares in the third quarter of 2020, and the absence of a $116 million before-tax gain on those shares in the third quarter of 2019. Other income (loss) for the nine-month period of 2020 decreased $2,119 million, primarily due to an unrealized loss of $1,302 million before-tax on our CVE common shares in the nine-month period of 2020, and the absence of a $489 million before-tax gain on those shares in the nine-month period of 2019. Additionally, other income (loss) in the nine-month period of 2020 decreased due to the absence of $325 million before-tax related to our settlement agreement with PDVSA.

For discussion of our Cenovus Energy shares, see Note 6—Investment in Cenovus Energy, in the Notes to Consolidated Financial Statements. For discussion of our PDVSA settlement, see Note 12—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

Purchased commodities for the three- and nine-month periods of 2020 decreased $871 million and $3,429 million, respectively, primarily due to lower natural gas and crude oil prices and lower crude oil and natural gas volumes purchased.

Production and operating expenses for the three- and nine-month periods of 2020 decreased $368 million and $837 million, respectively, primarily due to decreased wellwork and transportation costs associated with production curtailments across our North American operated assets as well as the absence of costs related to our U.K. and Australia-West divestitures. Additionally, in the nine-month period of 2020, production and operating expenses decreased due to lower legal accruals in our Lower 48 and Other International segments.

Selling, general and administrative expenses decreased $120 million in the nine-month period of 2020, primarily due to lower costs associated with compensation and benefits, including mark to market impacts of certain key employee compensation programs.

Exploration expenses for the three- and nine-month periods of 2020 decreased $235 million and $182 million, respectively, primarily due to the absence of a $141 million before-tax leasehold impairment expense due to our decision to discontinue exploration activities in the Central Louisiana Austin Chalk trend and lower dry hole costs in the Lower 48, primarily related to this play; partly offset by higher dry hole expenses in Alaska. In addition to the items detailed above, in the nine-month period of 2020, the decrease in exploration expenses were partly offset by an unproved property impairment and dry hole expenses related to the Kamunsu East Field in Malaysia that is no longer in our development plans and charges related to the early termination of the Alaska winter exploration program.

DD&A for the three- and nine-month periods of 2020 decreased $155 million and $622 million, respectively, mainly due to lower production volumes because of production curtailments and the divestiture of our Australia-West asset, partly offset by higher DD&A rates due to price-related downward reserve revisions. In addition to the items detailed above, DD&A in the nine-month period of 2020 decreased due to our U.K. divestiture, which met held-for-sale status in the second quarter of 2019. For more information regarding the Australia-West divestiture, see Note 4—Asset Acquisitions and Dispositions in the Notes to Consolidated Financial Statements.

Impairments increased $495 million in the nine-month period of 2020, primarily due to a $511 million beforetax impairment of certain non-core gas assets in our Lower 48 segment because of a significant decrease in the outlook for natural gas prices. See Note 8—Impairments in the Notes to Consolidated Financial Statements, for additional information.

Taxes other than income taxes for the three- and nine-month periods of 2020 decreased $58 million and $136 million, respectively, primarily due to lower commodity prices and sales volumes.

Foreign currency transaction (gain) loss decreased $107 million in the nine-month period of 2020, resulting from gains recognized from foreign currency derivatives and other foreign currency remeasurements. See Note 13—Derivative and Financial Instruments in the Notes to Consolidated Financial Statements, for additional information.

See Note 21—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our income tax provision (benefit) and effective tax rate.

Summary Operating Statistics

Three Months EndedNine Months Ended September 30September 30 2020201920202019| Crude oil (MBD) | | | | | | --- | --- | --- | --- | --- | | Consolidated operations | 535 | 696 | 546 | 696 | | Equity affiliates | 13 | 14 | 13 | 13 | | Total crude oil | 548 | 710 | 559 | 709 |

Natural gas liquids (MBD)
Consolidated operations	89	106	97	106
Equity affiliates	8	8	7	8
Total natural gas liquids	97	114	104	114

Bitumen (MBD)49635059| Natural gas (MMCFD) | | | | | | --- | --- | --- | --- | --- | | Consolidated operations | 1,201 | 1,795 | 1,353 | 1,783 | | Equity affiliates | 1,034 | 1,076 | 1,042 | 1,043 | | Total natural gas* | 2,235 | 2,871 | 2,395 | 2,826 |

Total Production(MBOED)1,0671,3661,1121,353| Crude oil (per bbl) | | | | | | --- | --- | --- | --- | --- | | Consolidated operations | **$**39.49 | 59.56 | 39.04 | 61.26 | | Equity affiliates | 37.56 | 59.91 | 38.22 | 61.23 | | Total crude oil | 39.45 | 59.57 | 39.02 | 61.26 |

Natural gas liquids (per bbl)
Consolidated operations	13.73	14.33	11.72	18.90
Equity affiliates	30.21	30.18	31.65	36.49
Total natural gas liquids	15.29	15.59	13.45	20.24

Bitumen (per bbl)15.8732.542.9034.11| Natural gas (per MCF) | | | | | | --- | --- | --- | --- | --- | | Consolidated operations | 2.77 | 3.73 | 3.07 | 4.37 | | Equity affiliates | 2.61 | 6.40 | 3.98 | 6.48 | | Total natural gas | 2.70 | 4.74 | 3.47 | 5.17 |

General administrative, geological and geophysical,
lease rental, and other	$	81	67	296	231
Leasehold impairment		-	154	31	196
Dry holes		44	139	83	165
	$125		360	410	592

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on a worldwide basis. At September 30, 2020, our operations were producing in the U.S., Norway, Canada, Australia, Indonesia, China, Malaysia, Qatar and Libya.

Total production decreased 299 MBOED or 22 percent in the third quarter of 2020, primarily due to:

●Normal field decline. ●The divestiture of our U.K. assets in the third quarter of 2019, our Australia-West assets in the second quarter of 2020, and non-core Lower 48 assets in the first quarter of 2020. ●Production curtailments, primarily from our North American operated assets. ●Less production in Libya due to the forced shutdown of the Es Sider export terminal and other eastern export terminals after a period of civil unrest.

The decrease in third quarter 2020 production was partly offset by:

●New wells online in the Lower 48, Canada and China.

Total production decreased 241 MBOED or 18 percent in the nine-month period of 2020, primarily due to:

●Normal field decline. ●Production curtailments, primarily from our North American operated assets and Malaysia. ●The divestiture of our U.K. assets in the third quarter of 2019, our Australia-West assets in the second

quarter of 2020, and non-core Lower 48 assets in the first quarter of 2020. ●Lower production in Libya due to the forced shutdown of the Es Sider export terminal and other eastern export terminals after a period of civil unrest in the first quarter of 2020.

The decrease in production during the nine-month period of 2020 was partly offset by:

●New wells online in the Lower 48, Canada, Norway, Alaska and China.

Production excluding Libya was 1,066 MBOED in the third quarter of 2020, a decrease of 256 MBOED compared with the same period of 2019. Adjusting for estimated curtailments of approximately 90 MBOED, closed acquisitions and dispositions and Libya, third quarter 2020 production would have been 1,155 MBOED, a decrease of 46 MBOED or 4 percent compared with the third quarter of 2019. This decrease was primarily due to normal field decline, partly offset by new wells online in the Lower 48, Canada and China. Production from Libya averaged 1 MBOED as it remained in force majeure during the third quarter.

Production excluding Libya was 1,108 MBOED in the nine-month period of 2020, a decrease of 202 MBOED compared with the same period of 2019. Adjusting for estimated curtailments of approximately 105 MBOED, closed acquisitions and dispositions and Libya, nine-month period 2020 production would have been 1,186 MBOED, an increase of 6 MBOED compared with the same period a year ago. This increase was primarily due to new wells online in the Lower 48, Canada, Norway, Alaska, and China, partly offset by normal field decline. Production from Libya averaged 4 MBOED as it has been in force majeure for most of the year.

Segment Results

Alaska

Three Months EndedNine Months Ended September 30September 30 2020201920202019

Net income (loss) attributable to ConocoPhillips($MM)**$****(16)306(76)**1,152| Average Net Production | | | | | | --- | --- | --- | --- | --- | | Crude oil (MBD) | 184 | 190 | 179 | 200 | | Natural gas liquids (MBD) | 14 | 11 | 15 | 15 | | Natural gas (MMCFD) | 14 | 6 | 10 | 7 |

Total Production(MBOED)201202195216| Average Sales Prices | | | | | | --- | --- | --- | --- | --- | | Crude oil ($ per bbl) | **$**40.88 | 62.78 | 41.92 | 64.34 | | Natural gas ($ per MCF) | 2.48 | 3.01 | 2.71 | 3.23 |

The Alaska segment primarily explores for, produces, transports and markets crude oil, NGLs and natural gas. As of September 30, 2020, Alaska contributed 28 percent of our consolidated liquids production and less than 1 percent of our consolidated natural gas production.

Earnings from Alaska decreased $322 million in the third quarter of 2020, primarily driven by lower realized crude oil prices and higher DD&A expense due to increased DD&A rates from price-related downward reserve revisions. Partly offsetting the decrease in earnings were lower production and operating expenses, primarily at the Greater Prudhoe Area.

Earnings from Alaska decreased $1,228 million in the nine-month period of 2020, primarily driven by lower realized crude oil prices and lower sales volumes due to production curtailments at our operated assets on the North Slope—the Greater Kuparuk Area (GKA) and Western North Slope (WNS). Partly offsetting the earnings decrease was lower production and operating expenses primarily associated with lower transportation and terminaling costs as well as lower wellwork across our assets.

Average production decreased 1 MBOED in the third quarter of 2020, primarily due to normal field decline, partly offset by lower planned downtime and new wells online. Average production decreased 21 MBOED in the nine-month period of 2020, primarily due to normal field decline and curtailments at our operated assets on the North Slope—GKA and WNS, partly offset by new wells online.

Curtailment Update Based on our economic criteria, we restored curtailed production in Alaska during July.

Lower 48

Three Months EndedNine Months Ended September 30September 30 2020201920202019

Net Income (Loss) Attributable to ConocoPhillips($MM)**$****(78)26(880)**425| Average Net Production | | | | | | --- | --- | --- | --- | --- | | Crude oil (MBD) | 197 | 277 | 211 | 264 | | Natural gas liquids (MBD) | 68 | 84 | 74 | 80 | | Natural gas (MMCFD) | 566 | 649 | 577 | 604 |

Total Production(MBOED)359469381444| Average Sales Prices | | | | | | --- | --- | --- | --- | --- | | Crude oil ($ per bbl) | **$**36.43 | 54.38 | 34.02 | 55.63 | | Natural gas liquids ($ per bbl) | 13.51 | 13.04 | 10.96 | 17.03 | | Natural gas ($ per MCF) | 1.63 | 1.80 | 1.45 | 2.19 |

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, 2020, the Lower 48 contributed 41 percent of our consolidated liquids production and 43 percent of our consolidated natural gas production.

Earnings from the Lower 48 decreased $104 million in the third quarter of 2020, primarily due to lower sales volumes due to normal field decline and production curtailments and lower realized crude oil prices. Partly offsetting this decrease in earnings were lower exploration expenses due to the absence of $186 million aftertax of leasehold impairment and dry hole costs associated with our decision to discontinue exploration activities in the Central Louisiana Austin Chalk trend; lower DD&A expense due to lower volumes, partly offset by higher DD&A rates due to price-related reserve revisions; and higher other income due to a favorable $70 million after-tax settlement.

Earnings from the Lower 48 decreased $1,305 million in the nine-month period of 2020, primarily due to lower realized crude oil, NGL and natural gas prices; lower crude oil sales volumes due to normal field decline and production curtailments; and a $399 million after-tax impairment related to certain non-core gas assets in the Wind River Basin operations area. Partly offsetting this decrease in earnings was the absence of $194 million after-tax of leasehold impairment and dry hole costs associated with our decision to discontinue exploration activities in the Central Louisiana Austin Chalk trend; lower DD&A expense due to lower volumes, partly offset by higher DD&A rates due to price-related reserve revisions; and the absence of $120 million of impairments in equity method investments. See Note 8—Impairments and Note 14—Fair Value Measurement in the Notes to Consolidated Financial Statements, for additional information related to the Wind River Basin operations area impairment.

Total average production decreased 110 MBOED and 63 MBOED in the three- and nine-month periods of 2020, respectively, primarily due to normal field decline and production curtailments. Partly offsetting the production decrease was new production from unconventional assets in the Eagle Ford, Permian and Bakken.

Curtailment Update The third quarter 2020 production impact from curtailments in the Lower 48 was estimated to be 65 MBOED. Based on our economic criteria, we began restoring curtailed volumes in July and ended our curtailment program by the end of the third quarter.

Canada

Three Months EndedNine Months Ended September 30September 30 2020201920202019**

Net Income (Loss) Attributable to ConocoPhillips($MM)**$****(75)51(270)**273| Average Net Production | | | | | | --- | --- | --- | --- | --- | | Crude oil (MBD) | 6 | 1 | 4 | 1 | | Natural gas liquids (MBD) | 2 | - | 2 | - | | Bitumen (MBD) | 49 | 63 | 50 | 59 | | Natural gas (MMCFD) | 43 | 9 | 35 | 8 |

Total Production(MBOED)64666262| Average Sales Prices | | | | | | --- | --- | --- | --- | --- | | Crude oil ($ per bbl) | **$**25.16 | - | 19.84 | - | | Natural gas liquids ($ per bbl) | 5.99 | - | 3.60 | - | | Bitumen ($ per bbl) | 15.87 | 32.54 | 2.90 | 34.11 | | Natural gas ($ per MCF) | 0.71 | - | 0.91 | - | | *Average sales prices include unutilized transportation costs. | | | | | | 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, 2020, Canada contributed 8 percent of our consolidated liquids production and 3 percent of our consolidated natural gas production.

Earnings from Canada decreased $126 million and $543 million, respectively, in the three- and nine-month periods of 2020, primarily due to lower bitumen and crude oil price realizations, lower sales volumes related to production curtailments, higher DD&A expense associated with increased production from the Montney and price-related reserve revisions, and lower gain on dispositions related to the absence of contingent payments. Partly offsetting the decreases in earnings in both periods were higher sales volumes from new wells online at Montney.

Total average production decreased 2 MBOED in the third quarter of 2020, primarily due to production curtailments and a planned turnaround at Surmont, partly offset by new wells online at Montney. Total average production was flat in the nine-month period of 2020, with production decreases from curtailments at Surmont offset by new wells online at Montney and lower planned downtime at Surmont.

Curtailment Update The third quarter 2020 production impact from curtailments in Canada was estimated to be 15 MBOED net. Based on our economic criteria, we began to restore curtailed production at Surmont in July and ended our voluntary curtailment program by the end of the third quarter.

Completed Acquisition In August 2020, we completed the agreement to acquire additional Montney acreage for cash consideration of approximately $382 million, subject to customary post-closing adjustments. As part of the agreement, we assumed approximately $31 million in financing obligations for associated partially owned infrastructure. This acquisition consisted primarily of undeveloped properties and included 140,000 net acres in the liquids-rich Inga Fireweed asset Montney zone, which is directly adjacent to our existing Montney position. We now have a Montney acreage position of 295,000 net acres with a 100 percent working interest.

Europe, Middle East and North Africa

Three Months EndedNine Months Ended September 30September 30 2020201920202019

Net Income Attributable to ConocoPhillips($MM)$****922,1713183,050| Average Net Production | | | | | | --- | --- | --- | --- | --- | | Crude oil (MBD) | 77 | 149 | 82 | 143 | | Natural gas liquids (MBD) | 5 | 7 | 5 | 7 | | Natural gas (MMCFD) | 256 | 473 | 276 | 531 |

Total Production(MBOED)125235133238| Average Sales Prices | | | | | | | --- | --- | --- | --- | --- | --- | | Crude oil ($ per bbl) | | **$**41.79 | 63.47 | 43.72 | 65.17 | | Natural gas liquids ($ per bbl) | | 23.50 | 23.20 | 20.01 | 28.65 | | Natural gas ($ per MCF) | | 2.40 | 3.60 | 2.85 | 4.98 | | Africa segment. See Note 20 | —Segment Disclosures and Related Information in the Notes to Consolidated Financial Statements for additional | | | | | | information. | | | | | |

The Europe, Middle East and North Africa segment consists of operations principally located in the Norwegian sector of the North Sea and the Norwegian Sea, Qatar, Libya and commercial operations in the U.K. As of September 30, 2020, our Europe, Middle East and North Africa operations contributed 13 percent of our consolidated liquids production and 20 percent of our consolidated natural gas production.

Earnings for Europe, Middle East and North Africa decreased by $2,079 million and $2,732 million in the three- and nine-month periods of 2020, respectively, primarily due to impacts associated with our U.K. divestiture in 2019. We recorded a $1.8 billion and $2.1 billion after-tax gain in the three-and nine-month periods of 2019, respectively, associated with the completion of the sale of two ConocoPhillips U.K. subsidiaries. In addition to the items detailed above, earnings in both periods decreased due to lower equity in earnings of affiliates, primarily due to lower LNG sales prices; and lower realized crude oil prices in Norway.

Consolidated production decreased 110 MBOED and 105 MBOED in the three- and nine-month periods of 2020, respectively, primarily due to our U.K. disposition in the third quarter of 2019, lower production in Libya due to a cessation of production following a period of civil unrest and normal field decline. In addition to the items detailed above, in the nine-month period of 2020, the production decrease was partly offset by new wells online in Norway.

Force Majeure in Libya Production ceased February 12, 2020, due to a forced shutdown of the Es Sider export terminal and other eastern export terminals after a period of civil unrest. Force majeure was lifted on October 23, 2020. Plans to resume production and exports are ongoing.

Asia Pacific

Three Months EndedNine Months Ended September 30September 30 2020201920202019

Net Income Attributable to ConocoPhillips($MM)$****254439451,220| Average Net Production | | | | | | --- | --- | --- | --- | --- | | Crude oil (MBD) | 71 | 79 | 70 | 88 | | Natural gas liquids (MBD) | - | 4 | 1 | 4 | | Natural gas (MMCFD) | 322 | 658 | 455 | 633 |

Total Production(MBOED)125193147198| Average Sales Prices | | | | | | | --- | --- | --- | --- | --- | --- | | Crude oil ($ per bbl) | **$**42.79 | 62.01 | | 42.94 | 64.75 | | Natural gas liquids ($ per bbl) | | **-**30.13 | | 33.21 | 38.13 | | Natural gas ($ per MCF) | 5.33 | | 5.78 | 5.42 | 6.01 |

The Asia Pacific segment has operations in China, Indonesia, Malaysia and Australia. As of September 30, 2020, Asia Pacific contributed 10 percent of our consolidated liquids production and 33 percent of our consolidated natural gas production.

Earnings decreased $418 million in the third quarter of 2020, mainly due to the sale of our disposed Australia- West assets; the absence of a $164 million income tax benefit related to deepwater incentive tax credits from the Malaysia Block G; and lower equity in earnings of affiliates, primarily due to lower LNG sales prices.

Earnings decreased $275 million in the nine-month period of 2020, primarily due to lower realized crude oil and natural gas prices; lower oil sales volumes, primarily related to curtailments in Malaysia; lower equity in earnings of affiliates, mainly due to lower LNG sales prices; and the absence of a $164 million income tax benefit related to deepwater incentive tax credits from the Malaysia Block G. The decrease was partly offset by a $597 million after-tax gain on disposition related to our Australia-West divestiture.

Consolidated production decreased 68 MBOED and 51 MBOED in the three- and nine-month periods of 2020, primarily due to the divestiture of our Australia-West assets, normal field decline, the expiration of the Panyu production license in China and higher unplanned downtime due to the rupture of a third-party pipeline impacting gas production from the Kebabangan Field in Malaysia. Partly offsetting these production decreases, was new production from development activity at Bohai Bay in China and Malaysia.

Asset Disposition In the second quarter of 2020, we completed the divestiture of our Australia-West assets and operations, and based on an effective date of January 1, 2019, we received proceeds of $765 million in May with an additional $200 million due upon final investment decision of the proposed Barossa development project. Production from the beginning of the year through the disposition date in May 2020 averaged 43 MBOED and proved reserves associated with the disposed assets was approximately 17 MMBOE at year-end 2019. For additional information related to this transaction, see Note 4—Asset Acquisitions and Dispositions.

Other International

Three Months EndedNine Months Ended September 30September 30 2020201920202019

Net Income (Loss) Attributable to ConocoPhillips($MM)$****(8)7314285

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

Earnings from our Other International operations decreased $81 million and $271 million in the three- and nine-month periods of 2020, respectively. The decrease in earnings was primarily due to the absence of recognizing $86 million and $317 million after-tax in other income from a settlement award with PDVSA associated with prior operations in Venezuela, in the three- and nine-month periods of 2019, respectively. See Note 12—Contingencies and Commitments in the Notes to Consolidated Financial Statements, for additional information.

Corporate and Other| | September 30 | | | September 30 | | | --- | --- | --- | --- | --- | --- | | | 2020 | | 2019 | 2020 | 2019 | | Net Income (Loss) Attributable to ConocoPhillips | | | | | | | Net interest expense | $****(179) | | (123) | (508) | (450) | | Corporate general and administrative expenses | (50) | | (34) | (90) | (148) | | Technology | | (8) | 43 | (16) | 129 | | Other income (expense) | (153) | | 100 | (1,366) | 533 | | | $****(390) | | (14) | (1,980) | 64 |

Net interest expense consists of interest and financing expense, net of interest income and capitalized interest. Net interest expense increased by $56 million and $58 million in the three-and nine-month periods of 2020, respectively, primarily due to lower interest income related to lower cash and cash equivalent balances and higher interest expense.

Corporate G&A expenses include compensation programs and staff costs. These expenses increased by $16 million and decreased by $58 million in the three- and nine-month periods of 2020, respectively, primarily due to mark to market adjustments associated with certain compensation programs.

Technology includes our investment in new technologies or businesses, as well as licensing revenues. Activities are focused on both conventional and tight oil reservoirs, shale gas, heavy oil, oil sands, enhanced oil recovery, as well as LNG. Earnings from Technology decreased by $51 million and $145 million in the three-and nine-month periods of 2020, respectively, primarily due to lower licensing revenues.

Other income (expense) or “Other” includes certain corporate tax-related items, foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation, other costs not directly associated with an operating segment, premiums incurred on the early retirement of debt, unrealized holding gains or losses on equity securities, and pension settlement expense. “Other” decreased by $253 million in the third quarter of 2020, primarily due to an unrealized loss of $162 million after-tax on our CVE common shares in the third quarter of 2020, and the absence of a $116 million after-tax gain on those shares in the third quarter of 2019. In the nine-month period of 2020, “Other” decreased by $1,899 million, primarily due to an unrealized loss of $1,302 million after-tax on our CVE common shares in the nine-month period of 2020, and the absence of a $489 million after-tax gain on those shares in the nine-month period of 2019.

CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators Millions of Dollars September 30December 31 20202019| Short-term debt | $ | 482 | 105 | | --- | --- | --- | --- | | Total debt | | 15,387 | 14,895 | | Total equity | | 30,783 | 35,050 | | Percent of total debt to capital* | | 33**%** | 30 | | Percent of floating-rate debt to total debt | | 7**%** | 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 2020, the primary uses of our available cash were $3,657 million to support our ongoing capital expenditures and investments program, including the $382 million of cash used to acquire additional Montney acreage, $1,089 million for net purchases of investments, $726 million to repurchase common stock, and $1,367 million to pay dividends. During the first nine months of 2020, our cash, cash equivalents and restricted cash decreased by $2,566 million to $2,796 million.

We entered the year with a strong balance sheet including cash and cash equivalents of over $5 billion, shortterm investments of $3 billion, and an undrawn credit facility of $6 billion, totaling approximately $14 billion in available liquidity. This strong foundation allowed us to be measured in our response to the sudden change in business environment as we exited the first quarter of 2020. In response to the oil market downturn earlier this year, we announced the following capital, operating cost and share repurchase reductions. We reduced our 2020 operating plan capital expenditures by a total of $2.3 billion, or approximately thirty-five percent of the original guidance. We suspended our share repurchase program, further reducing cash outlays by approximately $2 billion. We also reduced our operating costs by approximately $0.6 billion, or roughly ten percent of the original 2020 guidance. Collectively, these actions represent a reduction in 2020 cash uses of approximately $5 billion versus the original operating plan.

Considering the weakness in oil prices during the second quarter of 2020, we established a framework for evaluating and implementing economic curtailments, which resulted in taking an additional significant step of curtailing production, predominantly from operated North American assets. Due to our strong balance sheet, we were in an advantaged position to forgo some production and cash flow in anticipation of receiving higher cash flows for those volumes in the future. Based on our economic criteria, we began restoring production from voluntary curtailments in July, and with oil stabilizing around $40 per barrel, we ended our curtailment program by the end of the third quarter.

At the end of the third quarter, we had cash and cash equivalents of $2.5 billion, short-term investments of $4.0 billion, and available borrowing capacity under our credit facility of $5.7 billion, totaling over $12 billion of liquidity. We believe current cash balances and cash generated by operations, the recent adjustments to our operating plan, 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 $3.1 billion for the first nine months of 2020, compared with $8.1 billion for the corresponding period of 2019. The decrease in cash provided by operating activities is primarily due to lower realized commodity prices, normal field decline, production curtailments, the divestiture of our U.K. and Australia-West assets, and the absence in 2020 of payments under our settlement agreement with PDVSA.

Our short- and long-term operating cash flows are highly dependent upon prices for crude oil, bitumen, natural gas, LNG and NGLs. Prices and margins in our industry have historically been volatile and are driven by market conditions over which we have no control. Absent other mitigating factors, as these prices and margins fluctuate, we would expect a corresponding change in our operating cash flows.

The level of absolute production volumes, as well as product and location mix, impacts our cash flows. Production levels are impacted by such factors as the volatile crude oil and natural gas price environment, which may impact investment decisions; the effects of price changes on production sharing and variableroyalty contracts; acquisition and disposition of fields; field production decline rates; new technologies; operating efficiencies; timing of startups and major turnarounds; political instability; global pandemics and associated demand decreases; 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. Due to recent capital reductions, our reserve replacement could be delayed thus limiting our ability to replace depleted reserves.

Investing Activities Proceeds from asset sales in the first nine months of 2020 were $1.3 billion compared with $2.9 billion in the corresponding period of 2019. In the second quarter of 2020, we completed the divestiture of our Australia- West assets and operations. Based on an effective date of January 1, 2019 and customary closing adjustments, we received cash proceeds of $765 million in the second quarter with another $200 million payment due upon final investment decision of the proposed Barossa development project. In the first quarter of 2020, proceeds from asset sales were $549 million, which included the sale of our Niobrara interests and Waddell Ranch interests in the Lower 48 for proceeds of $359 million and $184 million, respectively. See Note 4—Asset Acquisitions and Dispositions in the Notes to Consolidated Financial Statements, for additional information on these transactions.

Proceeds from asset sales in the first nine months of 2019 were $2.9 billion, which consisted primarily of $2.2 billion related to the sale of two ConocoPhillips U.K. subsidiaries, $350 million from the sale of our 30 percent interest in the Greater Sunrise Fields and $77 million of contingent payments from Cenovus Energy.

Commercial Paper and Credit Facilities We have a revolving credit facility totaling $6.0 billion, expiring in May 2023. Our revolving credit facility may be used for direct bank borrowings, the issuance of letters of credit totaling up to $500 million, or as support for our commercial paper program. The revolving credit facility is broadly syndicated among financial institutions and does not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or credit ratings. The facility agreement contains a cross-default provision relating to the failure to pay principal or interest on other debt obligations of $200 million or more by ConocoPhillips, or any of its consolidated subsidiaries. The amount of the facility is not subject to redetermination prior to its expiration date.

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 U.S. The agreement calls for commitment fees on available, but unused, amounts. The agreement also contains early termination rights if our current directors or their approved successors cease to be a majority of the Board of Directors.

The revolving credit facility supports the ConocoPhillips Company $6.0 billion commercial paper program, which is primarily a funding source for short-term working capital needs. Commercial paper maturities are generally limited to 90 days. With $300 million of commercial paper outstanding and no direct borrowings or letters of credit, we had $5.7 billion in available borrowing capacity under the revolving credit facility at September 30, 2020. We may consider issuing additional commercial paper in the future to supplement our cash position.

Despite recent volatility and price weakness for energy issuers in the debt capital markets, we believe the company continues to have access to the markets based on the composition of our balance sheet and asset portfolio.

In October 2020, S&P affirmed its “A” rating on our senior long-term debt and revised its outlook to “stable” from “negative,” Fitch affirmed its rating of “A” with a “stable” outlook and Moody’s affirmed its rating of “A3” 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 potentially restrict our access to the commercial paper and debt capital markets. If our credit rating were to deteriorate to a level prohibiting us from accessing the commercial paper and debt capital markets, 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, 2020 and December 31, 2019, we had direct bank letters of credit of $240 million and $277 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 SEC under which we have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.

Off-Balance Sheet Arrangements

As part of our normal ongoing business operations and consistent with normal industry practice, we enter into numerous agreements with other parties to pursue business opportunities, which share costs and apportion risks among the parties as governed by the agreements.

For information about guarantees, see Note 11—Guarantees, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

Guarantor Summarized Financial Information

We have various cross guarantees among ConocoPhillips, ConocoPhillips Company and Burlington Resources LLC, with respect to publicly held debt securities. ConocoPhillips Company is 100 percent owned by ConocoPhillips. Burlington Resources LLC is 100 percent owned by ConocoPhillips Company. ConocoPhillips and/or ConocoPhillips Company have fully and unconditionally guaranteed the payment obligations of Burlington Resources LLC, with respect to its publicly held debt securities. Similarly, ConocoPhillips has fully and unconditionally guaranteed the payment obligations of ConocoPhillips Company with respect to its publicly held debt securities. In addition, ConocoPhillips Company has fully and unconditionally guaranteed the payment obligations of ConocoPhillips with respect to its publicly held debt securities. All guarantees are joint and several.

In March of 2020, the SEC adopted amendments to simplify the financial disclosure requirements for guarantors and issuers of guaranteed securities registered under Rule 3-10 of Regulation S-X. Based on our evaluation of our existing guarantee relationships, we qualify for the transition to alternative disclosures. We have elected early voluntary compliance with the final amendments beginning in the third quarter of 2020. Accordingly, condensed consolidating information by guarantor and issuer of guaranteed securities will no longer be reported, and alternative disclosures of summarized financial information for the consolidated Obligor Group is presented. The following tables present summarized financial information for the Obligor Group, as defined below:

●The Obligor Group will reflect guarantors and issuers of guaranteed securities consisting of

ConocoPhillips, ConocoPhillips Company and Burlington Resources LLC. ●Consolidating adjustments for elimination of investments in and transactions between the collective guarantors and issuers of guaranteed securities are reflected in the balances of the summarized financial information. ●Non-Obligated Subsidiaries are excluded from this presentation. Transactions and balances reflecting activity between the Obligors and Non-Obligated Subsidiaries are presented below:

Summarized Income Statement Data Millions of Dollars Nine Months Ended September 30, 2020| Revenues and Other Income | $ | 5,690 | | --- | --- | --- | | Income (loss) before income taxes | | (2,018) | | Net income (loss) | | (1,929) | | Net Income (Loss) Attributable to ConocoPhillips | | (1,929) |

Summarized Balance Sheet Data Millions of Dollars| | | 2020 | 2019 | | --- | --- | --- | --- | | Current assets | $ | 7,890 | 10,829 | | Amounts due from Non-Obligated Subsidiaries, current | | 473 | 732 | | Noncurrent assets | | 40,026 | 43,194 | | Amounts due from Non-Obligated Subsidiaries, noncurrent | | 7,622 | 7,977 | | Current liabilities | | 3,247 | 3,813 | | Amounts due to Non-Obligated Subsidiaries, current | | 1,361 | 1,836 | | Noncurrent liabilities | | 20,444 | 21,787 | | Amounts due to Non-Obligated Subsidiaries, noncurrent | | 5,725 | 6,974 |

Capital Requirements

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

Our debt balance at September 30, 2020, was $15,387 million, compared with $14,895 million at December 31, 2019. Maturities of debt for the remainder of 2020, and for each of the years 2021 through 2024, are: $367 million, $281 million, $998 million, $256 million and $577 million, respectively.

On February 4, 2020, we announced a quarterly dividend of 42 cents per share. The dividend was paid on March 2, 2020, to stockholders of record at the close of business on February 14, 2020. On April 30, 2020, we announced a quarterly dividend of 42 cents per share. The dividend was paid on June 1, 2020, to stockholders of record at the close of business on May 11, 2020. On July 8, 2020, we announced a quarterly dividend of 42 cents per share, payable September 1, 2020, to stockholders of record at the close of business on July 20, 2020. On October 9, 2020, we announced an increase to our quarterly dividend from 42 cents per share to 43 cents per share. The dividend is payable on December 1, 2020 to shareholders of record as of October 19, 2020.

Capital Expenditures

Millions of Dollars Nine Months Ended September 30 20202019| Alaska | $ | 882 | 1,207 | | --- | --- | --- | --- | | Lower 48 | | 1,398 | 2,613 | | Canada | | 593 | 315 | | Europe, Middle East and North Africa | | 410 | 537 | | Asia Pacific | | 280 | 322 | | Other International | | 66 | 1 | | Corporate and Other | | 28 | 46 | | Capital expenditures and investments | $ | 3,657 | 5,041 |

During the first nine months of 2020, capital expenditures and investments supported key exploration and development programs, primarily:

●Development, appraisal and exploration activities in the Lower 48, including Eagle Ford, Permian

Unconventional and Bakken. ●Appraisal, exploration and development activities in Alaska related to the Western North Slope; development activities in the Greater Kuparuk Area and the Greater Prudhoe Area. ●Development and exploration activities across assets in Norway. ●Appraisal activities in the liquids-rich portion of the Montney in Canada and optimization of oil sands development. ●Continued development in China, Malaysia, Australia and Indonesia. ●Lease acquisition and appraisal activities in Argentina.

In February 2020, we announced 2020 operating plan capital of $6.5 billion to $6.7 billion. In response to the oil market downturn earlier this year, we announced capital expenditure reductions totaling $2.3 billion. Full year 2020 operating plan capital is now expected to be $4.3 billion. This does not include approximately $0.5 billion of capital for acquisitions completed during the year, of which $0.4 billion was for bolt-on acreage in the liquids rich area of the Montney.

In August 2020, we completed the acquisition of additional Montney acreage in Canada for $382 million after customary adjustments, plus the assumption of $31 million in financing obligations associated with partially owned infrastructure. See Note 4—Asset Acquisitions and Dispositions, in the Notes to Consolidated Financial Statements, for additional information.

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. We accrue receivables for insurance or other third-party recoveries when applicable. With respect to income-tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain.

Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, legal and tax matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties. Estimated future costs related to legal and tax matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes. For information on other contingencies, see Note 12—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

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

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

Environmental We are subject to the same numerous international, federal, state and local environmental laws and regulations as other companies in our industry. For a discussion of the most significant of these environmental laws and regulations, including those with associated remediation obligations, see the “Environmental” section in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 60–62 of our 2019 Annual Report on Form 10-K.

We occasionally receive requests for information or notices of potential liability from the EPA and state environmental agencies alleging that we are a potentially responsible party under the Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain waste attributable to our past operations. As of September 30, 2020, there were 15 sites around the U.S. in which we were identified as a potentially responsible party under CERCLA and comparable state laws.

At September 30, 2020, our balance sheet included a total environmental accrual of $177 million, compared with $171 million at December 31, 2019, for remediation activities in the U.S. and Canada. We expect to incur a substantial amount of these expenditures within the next 30 years.

Notwithstanding any of the foregoing, and as with other companies engaged in similar businesses, environmental costs and liabilities are inherent concerns in our operations and products, and there can be no assurance that material costs and liabilities will not be incurred. However, we currently do not expect any material adverse effect upon our results of operations or financial position as a result of compliance with current environmental laws and regulations.

Climate Change Continuing political and social attention to the issue of global climate change has resulted in a broad range of proposed or promulgated state, national and international laws focusing on GHG reduction. These proposed or promulgated laws apply or could apply in countries where we have interests or may have interests in the future. Laws in this field continue to evolve, and while it is not possible to accurately estimate either a timetable for implementation or our future compliance costs relating to implementation, such laws, if enacted, could have a material impact on our results of operations and financial condition. Examples of legislation and precursors for possible regulation that do or could affect our operations include:

●The EPA’s and U.S. Department of Transportation’s joint promulgation of a Final Rule on April 1,

2010, that triggered regulation of GHGs under the Clean Air Act, may trigger more climate-based claims for damages, and may result in longer agency review time for development projects. ●New Mexico’s Energy, Minerals and Natural Resources Department has proposed natural gas waste rules as part of New Mexico’s statewide, enforceable regulatory framework to secure reductions in oil and gas sector emissions and to prevent natural gas waste from new and existing sources.

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 63–65 of our 2019 Annual Report on Form 10-K.

We announced in October 2020 the adoption of a Paris-aligned climate risk framework as part of our continued commitment to ESG excellence. This comprehensive climate risk strategy should enable us to sustainably meet global energy demand while delivering competitive returns through the energy transition. We have set a target to reduce our gross operated (scope 1 and 2) emissions intensity by 35 to 45 percent from 2016 levels by 2030, with an ambition to achieve net zero by 2050 for operated emissions. We are advocating for reduction of scope 3 end-use emissions intensity through our support for a U.S. carbon price. We have joined the World Bank Flaring Initiative to work towards zero routine flaring of gas by 2030. We are committed to take ESG

leadership to the next level as the first U.S.-based oil and gas company to adopt a Paris-aligned climate risk strategy.

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 our October 2020 Paris aligned-climate risk framework announcement, we reaffirmed our commitment to the Climate Leadership Council.

Beginning in 2017, cities, counties, governments and other entities in several states in the U.S. have filed lawsuits against oil and gas companies, including ConocoPhillips, seeking compensatory damages and equitable relief to abate alleged climate change impacts. Additional lawsuits with similar allegations are expected to be filed. The amounts claimed by plaintiffs are unspecified and the legal and factual issues involved in these cases are unprecedented. ConocoPhillips believes these lawsuits are factually and legally meritless and are an inappropriate vehicle to address the challenges associated with climate change and will vigorously defend against such lawsuits.

Several Louisiana parishes and the State of Louisiana have filed 43 lawsuits under Louisiana’s State and Local Coastal Resources Management Act (SLCRMA) against oil and gas companies, including ConocoPhillips, seeking compensatory damages for contamination and erosion of the Louisiana coastline allegedly caused by historical oil and gas operations. ConocoPhillips entities are defendants in 22 of the lawsuits and will vigorously defend against them. Because Plaintiffs’ SLCRMA theories are unprecedented, there is uncertainty about these claims (both as to scope and damages) and any potential financial impact on the company.

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, objectives of management for future operations, the anticipated benefits of the proposed transaction between us and Concho, the anticipated impact of the proposed transaction on the combined company’s business and future financial and operating results, the expected amount and the timing of synergies from the proposed transaction, and the anticipated closing date for the proposed transaction 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 forwardlooking 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 forwardlooking statements. Any differences could result from a variety of factors and uncertainties, including, but not limited to, the following:

●The impact of public health crises, including pandemics (such as COVID-19) and epidemics and any

related company or government policies or actions. ●Global and regional changes in the demand, supply, prices, differentials or other market conditions affecting oil and gas, including changes resulting from a public health crisis or from the imposition or lifting of crude oil production quotas or other actions that might be imposed by OPEC and other producing countries and the resulting company or third-party actions in response to such changes. ●Fluctuations in crude oil, bitumen, natural gas, LNG and NGLs prices, including a prolonged decline in these prices relative to historical or future expected levels. ●The impact of significant declines in prices for crude oil, bitumen, natural gas, LNG and NGLs, which may result in recognition of impairment charges on our long-lived assets, leaseholds and nonconsolidated equity investments. ●Potential failures or delays in achieving expected reserve or production levels from existing and future oil and gas developments, including due to operating hazards, drilling risks and the inherent uncertainties in predicting reserves and reservoir performance. ●Reductions in reserves replacement rates, whether as a result of the significant declines in commodity prices or otherwise. ●Unsuccessful exploratory drilling activities or the inability to obtain access to exploratory acreage. ●Unexpected changes in costs or technical requirements for constructing, modifying or operating E&P facilities. ●Legislative and regulatory initiatives addressing environmental concerns, including initiatives addressing the impact of global climate change or further regulating hydraulic fracturing, methane emissions, flaring or water disposal. ●Lack of, or disruptions in, adequate and reliable transportation for our crude oil, bitumen, natural gas, LNG and NGLs. ●Inability to timely obtain or maintain permits, including those necessary for construction, drilling and/or development, or inability to make capital expenditures required to maintain compliance with any necessary permits or applicable laws or regulations. ●Failure to complete definitive agreements and feasibility studies for, and to complete construction of, announced and future E&P 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. ●Changes in international trade relationships, including the imposition of trade restrictions or tariffs relating to crude oil, bitumen, natural gas, LNG, NGLs and any materials or products (such as aluminum and steel) used in the operation of our business. ●Substantial investment in and development use of, competing or alternative energy sources, including as a result of existing or future environmental rules and regulations. ●Liability for remedial actions, including removal and reclamation obligations, under existing and future environmental regulations and litigation. ●Significant operational or investment changes imposed by existing or future environmental statutes and regulations, including international agreements and national or regional legislation and regulatory measures to limit or reduce GHG emissions.

●Liability resulting from litigation, including the potential for litigation related to the proposed

transaction, or our failure to comply with applicable laws and regulations. ●General domestic and international economic and political developments, including armed hostilities; expropriation of assets; changes in governmental policies relating to crude oil, bitumen, natural gas, LNG and NGLs pricing, regulation or taxation; and other political, economic or diplomatic developments. ●Volatility in the commodity futures markets. ●Changes in tax and other laws, regulations (including alternative energy mandates), or royalty rules applicable to our business. ●Competition and consolidation in the oil and gas E&P industry. ●Any limitations on our access to capital or increase in our cost of capital, including as a result of illiquidity or uncertainty in domestic or international financial markets. ●Our inability to execute, or delays in the completion, of any asset dispositions or acquisitions we elect to pursue. ●Potential failure to obtain, or delays in obtaining, any necessary regulatory approvals for pending or future 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 pending or future asset dispositions or acquisitions, including the diversion of management time and attention. ●Our inability to deploy the net proceeds from any asset dispositions that are pending or that we elect to undertake in the future in the manner and timeframe we currently anticipate, if at all. ●Our inability to liquidate the common stock issued to us by Cenovus Energy as part of our sale of certain assets in western Canada at prices we deem acceptable, or at all. ●The operation and financing of our joint ventures. ●The ability of our customers and other contractual counterparties to satisfy their obligations to us, including our ability to collect payments when due from the government of Venezuela or PDVSA. ●Our inability to realize anticipated cost savings and capital expenditure reductions. ●The inadequacy of storage capacity for our products, and ensuing curtailments, whether voluntary or involuntary, required to mitigate this physical constraint. ●Our ability to successfully integrate Concho’s business. ●The risk that the expected benefits and cost reductions associated with the proposed transaction may not be fully achieved in a timely manner, or at all. ●The risk that we or Concho will be unable to retain and hire key personnel. ●The risk associated with our and Concho’s ability to obtain the approvals of our respective stockholders required to consummate the proposed transaction and the timing of the closing of the proposed transaction, including the risk that the conditions to the transaction are not satisfied on a timely basis or at all or the failure of the transaction to close for any other reason or to close on the anticipated terms, including the anticipated tax treatment. ●The risk that any regulatory approval, consent or authorization that may be required for the proposed transaction is not obtained or is obtained subject to conditions that are not anticipated. ●Unanticipated difficulties or expenditures relating to the transaction, the response of business partners and retention as a result of the announcement and pendency of the transaction. ●Uncertainty as to the long-term value of our common stock. ●The diversion of management time on transaction-related matters. ●The risk factors generally described in Part II—Item 1A in this report, in Part I—Item 1A in our 2019 Annual Report on Form 10-K, in our Forms 8-K filed with the SEC on May 20, 2020 and September 8, 2020, respectively, and any additional risks described in our other filings with the SEC.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information about market risks for the nine months ended September 30, 2020, does not differ materially from that discussed under Item 7A in our 2019 Annual Report on Form 10-K.

Item 4. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures designed to ensure information required to be disclosed in reports we file or submit under the Securities Exchange Act of 1934, as amended (the Act), is recorded, processed, summarized and reported within the time periods specified in SEC 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, 2020, with the participation of our management, our Chairman and Chief Executive Officer (principal executive officer) and our Executive Vice President and Chief Financial Officer (principal financial officer) carried out an evaluation, pursuant to Rule 13a-15(b) of the Act, of ConocoPhillips’ disclosure controls and procedures (as defined in Rule 13a-15(e) of the Act). Based upon that evaluation, our Chairman and Chief Executive Officer and our Executive Vice President and Chief Financial Officer concluded our disclosure controls and procedures were operating effectively as of September 30, 2020.

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

PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

There are no new material legal proceedings or material developments with respect to matters previously disclosed in Item 3 of our 2019 Annual Report on Form 10-K.

Item 1A. RISK FACTORS

Other than the risk factors set forth below, there have been no material changes to the risk factors disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019.

Risks Related to the Business

Existing and future laws, regulations and internal initiatives relating to global climate change, such as limitations on GHG emissions, may impact or limit our business plans, result in significant expenditures,

promote alternative uses of energy or reduce demand for our products.

Continuing political and social attention to the issue of global climate change has resulted in both existing and pending international agreements and national, regional or local legislation and regulatory measures to limit GHG emissions, such as cap and trade regimes, carbon taxes, restrictive permitting, increased fuel efficiency standards and incentives or mandates for renewable energy. For example, in December 2015, the U.S. joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris that prepared an agreement requiring member countries to review and represent a progression in their intended GHG emission reduction goals every five years beginning in 2020. While the U.S. announced its intention to withdraw from the Paris Agreement, there is no guarantee that the commitments made by the U.S. will not be implemented, in whole or in part, by U.S. state and local governments or by major corporations headquartered in the U.S. In addition, our operations continue in countries around the world which are party to, and have not announced an intent to withdraw from, the Paris Agreement. The implementation of current agreements and regulatory measures, as well as any future agreements or measures addressing climate change and GHG emissions, may adversely impact the demand for our products, impose taxes on our products or operations or require us to purchase emission credits or reduce emission of GHGs from our operations. As a result, we may experience declines in commodity prices or incur substantial capital expenditures and compliance, operating, maintenance and remediation costs, any of which may have an adverse effect on our business and results of operations.

Compliance with the various climate change related internal initiatives described in the “Business Environment and Executive Overview” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations may increase costs, require us to purchase emission credits, or limit or impact our business plans, potentially resulting in the reduction to the economic end-of-field life of certain assets and an impairment of the associated net book value.

Additionally, increasing attention to global climate change has resulted in pressure upon shareholders, financial institutions and/or financial markets to modify their relationships with oil and gas companies and to limit investments and/or funding to such companies, which could increase our costs or otherwise adversely affect our business and results of operations.

Furthermore, increasing attention to global climate change has resulted in an increased likelihood of governmental investigations and private litigation, which could increase our costs or otherwise adversely affect our business. Beginning in 2017, cities, counties, governments and other entities in several states in the U.S. have filed lawsuits against oil and gas companies, including ConocoPhillips, seeking compensatory damages and equitable relief to abate alleged climate change impacts. Additional lawsuits with similar allegations are expected to be filed. The amounts claimed by plaintiffs are unspecified and the legal and factual issues involved in these cases are unprecedented. ConocoPhillips believes these lawsuits are factually and legally meritless and are an inappropriate vehicle to address the challenges associated with climate change and will vigorously defend against such lawsuits. The ultimate outcome and impact to us cannot be predicted with certainty, and we could incur substantial legal costs associated with defending these and similar lawsuits in the future.

In addition, although we design and operate our business operations to accommodate expected climatic conditions, to the extent there are significant changes in the earth’s climate, such as more severe or frequent weather conditions in the markets where we operate or the areas where our assets reside, we could incur increased expenses, our operations could be adversely impacted, and demand for our products could fall. For more information on legislation or precursors for possible regulation relating to global climate change that affect or could affect our operations and a description of the company’s response, see the “Contingencies— Climate Change” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Our business has been, and will continue to be, affected by the coronavirus (COVID-19) pandemic.

The COVID-19 outbreak and the measures put in place to address it have negatively impacted the global economy, disrupted global supply chains, reduced global demand for oil and gas, and created significant volatility and disruption of financial and commodity markets. Public health officials have recommended or mandated certain precautions to mitigate the spread of COVID-19, including limiting non-essential gatherings of people, ceasing all non-essential travel and issuing “social or physical distancing” guidelines, “shelter-inplace” orders and mandatory closures or reductions in capacity for non-essential businesses. The full impact of the COVID-19 pandemic remains uncertain and will depend on the severity, location and duration of the effects and spread of the disease, the effectiveness and duration of actions taken by authorities to contain the virus or treat its effect, and how quickly and to what extent economic conditions improve. According to the National Bureau of Economic Research, as a result of the pandemic and its broad reach across the entire economy, the U.S. entered a recession in early 2020.

We have already been impacted by the COVID-19 pandemic. See Management’s Discussion and Analysis of Financial Condition and Results of Operations, for additional information on how we have been impacted and the steps we have taken in response.

Our business is likely to be further negatively impacted by the COVID-19 pandemic. These impacts could include but are not limited to:

●Continued reduced demand for our products as a result of reductions in travel and commerce;

●Disruptions in our supply chain due in part to scrutiny or embargoing of shipments from infected areas

or invocation of force majeure clauses in commercial contracts due to restrictions imposed as a result of the global response to the pandemic; ●Failure of third parties on which we rely, including our suppliers, contract manufacturers, contractors, joint venture partners and external business partners, to meet their obligations to the company, or significant disruptions in their ability to do so, which may be caused by their own financial or operational difficulties or restrictions imposed in response to the disease outbreak; ●Reduced workforce productivity caused by, but not limited to, illness, travel restrictions, quarantine, or government mandates; ●Business interruptions resulting from a portion of our workforce continuing to telecommute, as well as the implementation and maintenance of protections for employees commuting for work, such as personnel screenings and self-quarantines before or after travel; and ●Voluntary or involuntary curtailments to support oil prices or alleviate storage shortages for our products.

Any of these factors, or other cascading effects of the COVID-19 pandemic that are not currently foreseeable, could materially increase our costs, negatively impact our revenues and damage our financial condition, results of operations, cash flows and liquidity position. The pandemic continues to progress and evolve, and the full extent and duration of any such impacts cannot be predicted at this time because of the sweeping impact of the COVID-19 pandemic on daily life around the world.

We have been negatively affected and are likely to continue to be negatively affected by the recent swift and

sharp drop in commodity prices.

The oil and gas business is fundamentally a commodity business and prices for crude oil, bitumen, natural gas, NGLs and LNG can fluctuate widely depending upon global events or conditions that affect supply and demand. Recently, there has been a precipitous decrease in demand for oil globally, largely caused by the dramatic decrease in travel and commerce resulting from the COVID-19 pandemic. See Management’s Discussion and Analysis of Financial Condition and Results of Operations, for additional information on commodity prices and how we have been impacted. There is no assurance of when or if commodity prices will return to pre-COVID-19 levels. The speed and extent of any recovery remains uncertain and is subject to various risks, including the duration, impact and actions taken to stem the proliferation of the COVID-19 pandemic, the extent to which those nations party to the OPEC plus production agreement decide to increase production of crude oil, bitumen, natural gas and NGLs and other risks described in this Quarterly Report on Form 10-Q or in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019.

Even after a recovery, our industry will continue to be exposed to the effects of changing commodity prices given the volatility in commodity price drivers and the worldwide political and economic environment generally, as well as continued uncertainty caused by armed hostilities in various oil-producing regions around the globe. Our revenues, operating results and future rate of growth are highly dependent on the prices we receive for our crude oil, bitumen, natural gas, NGLs and LNG. Many of the factors influencing these prices are beyond our control.

Lower crude oil, bitumen, natural gas, NGL and LNG prices may have a material adverse effect on our revenues, earnings, cash flows and liquidity, and may also affect the amount of dividends we elect to declare and pay on our common stock. As a result of the oil market downturn earlier this year, we suspended our share repurchase program. Lower prices may also limit the amount of reserves we can produce economically, thus adversely affecting our proved reserves, reserve replacement ratio and accelerating the reduction in our existing reserve levels as we continue production from upstream fields. Prolonged lower crude oil prices may affect certain decisions related to our operations, including decisions to reduce capital investments or decisions to shut-in production.

Significant reductions in crude oil, bitumen, natural gas, NGLs and LNG prices could also require us to reduce our capital expenditures, impair the carrying value of our assets or discontinue the classification of certain

assets as proved reserves. In the nine-month period of 2020, we recognized several impairments, which are described in Note 8—Impairments. If the outlook for commodity prices remains low relative to historic levels, and as we continue to optimize our investments and exercise capital flexibility, it is reasonably likely we will incur future impairments to long-lived assets used in operations, investments in nonconsolidated entities accounted for under the equity method and unproved properties. If oil and gas prices persist at depressed levels, our reserve estimates may decrease further, which could incrementally increase the rate used to determine DD&A expense on our unit-of-production method properties. See Management’s Discussion and Analysis for further examination of DD&A rate impacts versus comparative periods. Although it is not reasonably practicable to quantify the impact of any future impairments or estimated change to our unit-ofproduction at this time, our results of operations could be adversely affected as a result.

Risks Related to the Proposed Acquisition of Concho Resources Inc. (Concho)

Our ability to complete the acquisition of Concho is subject to various closing conditions, including approval by our and Concho’s stockholders and regulatory clearance, which may impose conditions that

could adversely affect us or cause the acquisition not to be completed.

On October 18, 2020, we entered into a definitive agreement (the Merger Agreement) to acquire Concho, one of the largest unconventional shale producers in the Permian Basin.

The Merger is subject to a number of conditions to closing as specified in the Merger Agreement. These closing conditions include, among others, (1) the receipt of the required approvals from ConocoPhillips stockholders and Concho stockholders, (2) the expiration or termination of the waiting period under the Hart- Scott-Rodino Antitrust Improvements Act of 1976, as amended (the HSR Act) and (3) the absence of any governmental order or law that makes consummation of the Merger illegal or otherwise prohibited. No assurance can be given that the required stockholder approvals and regulatory clearance be obtained or that the required conditions to closing will be satisfied, and, if all required approvals and regulatory clearance are obtained and the required conditions are satisfied, no assurance can be given as to the terms, conditions and timing of such approvals and clearance, including whether any required conditions will materially adversely affect the combined company following the acquisition. Any delay in completing the Merger could cause the combined company not to realize, or to be delayed in realizing, some or all of the benefits that we and Concho expect to achieve if the Merger is successfully completed within its expected time frame.

We can provide no assurance that these conditions will not result in the abandonment or delay of the acquisition. The occurrence of any of these events individually or in combination could have a material adverse effect on our results of operations and the trading price of our common stock.

The termination of the Merger Agreement could negatively impact our business or result in our having to

pay a termination fee.

If the Merger is not completed for any reason, including as a result of a failure to obtain the required approvals from our stockholders or Concho’s stockholders, our ongoing business may be adversely affected and, without realizing any of the expected benefits of having completed the Merger, we would be subject to a number of risks, including the following:

●we may experience negative reactions from the financial markets, including negative impacts on our stock price; ●we may experience negative reactions from our commercial and vendor partners and employees; and ●we will be required to pay our costs relating to the Merger, such as financial advisory, legal, financing and accounting costs and associated fees and expenses, whether or not the Merger is completed.

Additionally, if the Merger Agreement is terminated under certain circumstances, we may be required to pay a termination fee of $450 million, including if the proposed Merger is terminated because our Board of Directors has changed its recommendation in respect of the stockholder proposal relating to the Merger. In

addition, we may be required to reimburse Concho for its expenses in an amount equal to $142.5 million, if the Merger Agreement is terminated because of a failure of our stockholders to approve the stockholder proposal.

Whether or not the Merger is completed, the announcement and pendency of the Merger could cause disruptions in our business, which could have an adverse effect on our business and financial results.

Whether or not the Merger is completed, the announcement and pendency of the Merger could cause disruptions in our business. Specifically:

●our and Concho’s current and prospective employees will experience uncertainty about their future

roles with the combined company, which might adversely affect the two companies’ abilities to retain key managers and other employees; ●uncertainty regarding the completion of the Merger may cause our and Concho’s commercial and vendor partners or others that deal with us or Concho to delay or defer certain business decisions or to decide to seek to terminate, change or renegotiate their relationships with us or Concho, which could negatively affect our respective revenues, earnings and cash flows; ●the Merger Agreement restricts us and our subsidiaries from taking specified actions during the pendency of the Merger without Concho’s consent, which may prevent us from making appropriate changes to our business or organizational structure or prevent us from pursuing attractive business opportunities or strategic transactions that may arise prior to the completion of the Merger; and ●the attention of our and Concho’s management may be directed toward the completion of the Merger, as well as integration planning, which could otherwise have been devoted to day-to-day operations or to other opportunities that may have been beneficial to our business.

We have and will continue to divert significant management resources in an effort to complete the Merger and are subject to restrictions contained in the Merger Agreement on the conduct of our business. If the Merger is not completed, we will have incurred significant costs, including the diversion of management resources, for which we will have received little or no benefit.

The market value of our common stock could decline if large amounts of our common stock are sold

following the Concho acquisition.

If the Merger is consummated, ConocoPhillips will issue shares of ConocoPhillips common stock to former Concho stockholders. Former Concho stockholders may decide not to hold the shares of ConocoPhillips common stock that they will receive in the Merger, and ConocoPhillips stockholders may decide to reduce their investment in ConocoPhillips as a result of the changes to ConocoPhillips’ investment profile as a result of the Merger. Other Concho stockholders, such as funds with limitations on their permitted holdings of stock in individual issuers, may be required to sell the shares of ConocoPhillips common stock that they receive in the Merger. Such sales of ConocoPhillips common stock could have the effect of depressing the market price for ConocoPhillips common stock.

Combining our business with Concho’s may be more difficult, costly or time-consuming than expected and the combined company may fail to realize the anticipated benefits of the Merger, which may adversely affect the combined company’s business results and negatively affect the value of the combined company’s

common stock.

The success of the Merger will depend on, among other things, the ability of the two companies to combine their businesses in a manner that facilitates growth opportunities and realizes expected cost savings. The combined company may encounter difficulties in integrating our and Concho’s businesses and realizing the anticipated benefits of the Merger. The combined company must achieve the anticipated improvement in free cash flow generation and returns and achieve the planned cost savings without adversely affecting current revenues or compromising the disciplined investment philosophy for future growth. If the combined company is not able to successfully achieve these objectives, the anticipated benefits of the Merger may not be realized fully, or at all, or may take longer to realize than expected.

The Merger involves the combination of two companies which currently operate, and until the completion of the Merger will continue to operate, as independent public companies. There can be no assurances that our respective businesses can be integrated successfully. It is possible that the integration process could result in the loss of key employees from both companies; the loss of commercial and vendor partners; the disruption of our, Concho’s or both companies’ ongoing businesses; inconsistencies in standards, controls, procedures and policies; unexpected integration issues; higher than expected integration costs and an overall post-completion integration process that takes longer than originally anticipated. The combined company will be required to devote management attention and resources to integrating its business practices and operations, and prior to the Merger, management attention and resources will be required to plan for such integration.

An inability to realize the full extent of the anticipated benefits of the Merger and the other transactions contemplated by the Merger Agreement, as well as any delays encountered in the integration process, could have an adverse effect upon the revenues, level of expenses and operating results of the combined company, which may adversely affect the value of the common stock of the combined company.

In addition, the actual integration may result in additional and unforeseen expenses, and the anticipated benefits of the integration plan may not be realized. There are a large number of processes, policies, procedures, operations and technologies and systems that must be integrated in connection with the Merger and the integration of Concho’s business. Although we expect that the elimination of duplicative costs, strategic benefits, and additional income, as well as the realization of other efficiencies related to the integration of the business, may offset incremental transaction and Merger-related costs over time, any net benefit may not be achieved in the near term or at all. If we and Concho are not able to adequately address integration challenges, we may be unable to successfully integrate operations or realize the anticipated benefits of the integration of the two companies.

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

Issuer Purchases of Equity Securities Millions of Dollars Total Number ofApproximate Dollar Shares Purchased asValue of Shares That Total Number ofPart of PubliclyMay Yet Be SharesAverage PriceAnnounced Plans orPurchased Under the PeriodPurchased*Paid per ShareProgramsPlans or Programs

July 1-31, 2020-$--$14,649 August 1-31, 2020---14,649 September 1-30, 2020---14,649 -$-- *There were no repurchases of common stock from company employees in connection with the company's broad-based employee incentive plans.

In late 2016, we initiated our current share repurchase program. As of September 30, 2020, we had announced a total authorization to repurchase $25 billion of our common stock. As of December 31, 2019, we had repurchased $9.6 billion of shares. In the first quarter of 2020, we repurchased an additional $726 million of shares. On April 16, 2020, as a response to the oil market downturn, we announced we were suspending our share repurchase program, and on September 30, 2020, we announced our intent to resume share repurchases of $1 billion in the fourth quarter; however, on October 19, 2020 we announced that we had entered into a definitive agreement to acquire Concho and would suspend share repurchases until after the transaction closes. The transaction is expected to close in the first quarter of 2021. Acquisitions for the share repurchase program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Except as limited by applicable legal requirements, 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 21–22 of our 2019 Annual Report on Form 10-K.

Item 6. EXHIBITS

2.1Agreement and Plan of Merger, dated as of October 18, 2020, among ConocoPhillips, Falcon Merger Sub Corp. and Concho Resources Inc. (incorporated by reference to Exhibit 2.1 to the Current Report of ConocoPhillips on Form 8-K filed on October 19, 2020; File No. 001-32395)

10.1*Successor Trustee Agreement of the Deferred Compensation Trust Agreement for Non- Employee Directors of ConocoPhillips, dated July 31, 2020.

10.2*First Amendment to the Successor Trustee Agreement of the Deferred Compensation Trust Agreement for Non-Employee Directors of ConocoPhillips, dated August 4, 2020.

22*Subsidiary Guarantors of Guaranteed Securities.

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

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

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

101.INS*Inline XBRL Instance Document.

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.

SIGNATURE

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

CONOCOPHILLIPS

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

November 3, 2020

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