Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY

FINANCIAL STATEMENTS AND SUPPLEMENTARY

DATA

CONOCOPHILLIPS

INDEX TO FINANCIAL STATEMENTS

Page

Reports of Management

...........................................................................................................................

Reports of Independent Registered Public Accounting

Firm .................................................................

Consolidated Income Statement for the years ended

December 31, 2020,

2019 and 2018

....................

Consolidated Statement of Comprehensive Income

for the years ended

December 31, 2020, 2019 and 2018

..................................................................................................

Consolidated Balance Sheet at December 31, 2020

and 2019

................................................................

Consolidated Statement of Cash Flows for the years

ended December 31, 2020,

2019 and 2018

.........

Consolidated Statement of Changes in Equity for

the years ended

December 31, 2020, 2019 and 2018

..................................................................................................

Notes to Consolidated Financial Statements

............................................................................................

Supplementary Information

Oil and Gas Operations

..............................................................................................................

Reports

of Management

Management prepared, and is responsible for, the consolidated financial

statements and the other information

appearing in this annual report.

The consolidated financial statements present

fairly the company’s financial

position, results of operations and cash flows in

conformity with accounting principles

generally accepted in

the United States.

In preparing its consolidated financial statements,

the company includes amounts that are

based on estimates and judgments management believes

are reasonable under the circumstances.

The

company’s financial statements have been audited by Ernst & Young LLP,

an independent registered public

accounting firm appointed by the Audit and Finance

Committee of the Board of Directors and ratified

by

stockholders.

Management has made available to Ernst

& Young LLP all of the company’s financial records

and related data, as well as the minutes of stockholders’

and directors’ meetings.

Assessment of Internal Control Over Financial Reporting

Management is also responsible for establishing

and maintaining adequate internal control

over financial

reporting.

ConocoPhillips’ internal control system

was designed to provide reasonable assurance to

the

company’s management and directors regarding the preparation and fair

presentation of published financial

statements.

All internal control systems, no matter how

well designed, have inherent limitations.

Therefore, even those

systems determined to be effective can provide only reasonable

assurance with respect to financial statement

preparation and presentation.

Management assessed the effectiveness of the company’s internal control over financial

reporting as of

December 31, 2020.

In making this assessment, it used the criteria

set forth by the Committee of Sponsoring

Organizations of the Treadway Commission in

Internal Control—Integrated Framework (2013)

.

Based on our

assessment, we believe the company’s internal control over financial

reporting was effective as of

December 31, 2020.

Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of

December 31, 2020, and their report is included

herein.

/s/ Ryan M. Lance

/s/ William L. Bullock, Jr.

Ryan M. Lance

William L. Bullock,

Jr.

Chairman and

Chief Executive Officer

Executive Vice President and

Chief Financial Officer

Report of Independent Registered Public Accounting

Firm

To the Stockholders and the Board of Directors of ConocoPhillips

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of ConocoPhillips

(the Company) as of

December 31, 2020 and 2019, the related consolidated

income statement, consolidated statements

of

comprehensive income, changes in equity and

cash flows for each of the three years in

the period ended

December 31, 2020, and the related notes (collectively

referred to as the “consolidated financial statements”).

In our opinion, the consolidated financial statements

present fairly, in all material respects, the financial

position of the Company at December 31, 2020

and 2019, and the results of its operations

and its cash flows

for each of the three years in the period ended

December 31, 2020, in conformity with

U.S. generally accepted

accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting

Oversight Board

(United States) (PCAOB), the Company’s internal control over financial

reporting as of December 31, 2020,

based on criteria established in Internal Control–Integrated

Framework issued by the Committee of Sponsoring

Organizations of the Treadway Commission (2013 framework) and our report

dated February 16, 2021,

expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility

of the Company’s management. Our responsibility is to

express an opinion on the Company’s financial statements based on our audits.

We are a public accounting

firm registered with the PCAOB and are required

to be independent with respect to the Company

in

accordance with the U.S. federal securities

laws and the applicable rules and regulations

of the Securities and

Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards

require that we

plan and perform the audit to obtain reasonable

assurance about whether the financial statements

are free of

material misstatement, whether due to error

or fraud. Our audits included performing procedures

to assess the

risks of material misstatement of the financial

statements, whether due to error or fraud,

and performing

procedures that respond to those risks. Such procedures

included examining, on a test basis, evidence

regarding the amounts and disclosures in the financial

statements. Our audits also included evaluating

the

accounting principles used and significant estimates

made by management, as well as evaluating the overall

presentation of the financial statements. We believe that our audits provide a reasonable

basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are

matters arising from the current period

audit of the

consolidated financial statements that were communicated

or required to be communicated to the Audit

and

Finance Committee and that: (1) relate to

accounts or disclosures that are material to the

consolidated financial

statements and (2) involved our especially challenging,

subjective or complex judgments. The communication

of critical audit matters does not alter in any

way our opinion on the consolidated financial

statements, taken as

a whole, and we are not, by communicating the

critical audit matters below, providing separate opinions on the

critical audit matters or on the accounts or disclosures

to which they relate.

Accounting for asset retirement obligations for

certain offshore properties

Description of

the Matter

At December 31, 2020, the asset retirement

obligation (ARO) balance totaled $5.6

billion. As further described in Note 9, the Company

records AROs in the period in

which they are incurred, typically when the asset

is installed at the production location.

The estimation of certain obligations related

to deepwater offshore assets requires

significant judgment given the magnitude

of these removal costs and higher estimation

uncertainty related to the removal plan and costs.

Furthermore, given certain of these

assets are nearing the end of their operations, the

impact of changes in these AROs may

result in a material impact to earnings given the

relatively short remaining useful lives of

the assets.

Auditing the Company’s AROs for the obligations identified above is complex

and

highly judgmental due to the significant estimation

required by management in

determining the obligations. In particular, the estimates were

sensitive to significant

subjective assumptions such as removal cost estimates

and end of field life, which are

affected by expectations about future market or economic

conditions.

How We

Addressed the

Matter in Our

Audit

We obtained an understanding, evaluated the design and tested the operating

effectiveness of the Company’s internal controls over its ARO estimation process,

including management’s review of the significant assumptions that

have a material effect

on the determination of the obligations. We also tested management’s controls over the

completeness and accuracy of the financial

data used in the valuation.

To test the AROs for the obligations identified above, our audit procedures included,

among others, assessing the significant assumptions

and inputs used in the valuation,

including removal cost estimates and end of

field life assumptions. For example, we

evaluated removal cost estimates by comparing

to settlements and recent removal

activities and costs. We also compared end of field life assumptions to production

forecasts.

We involved our internal specialists in testing the Company’s methodology to

estimate removal costs.

Depreciation, depletion and amortization and impairment

of properties, plants and

equipment

Description of

the Matter

At December 31, 2020, the net book value of the

Company’s properties, plants and

equipment (PP&E) was $39.9 billion, and depreciation,

depletion and amortization

(DD&A) expense and impairment expense were

$5.5 billion and $0.8 billion,

respectively, for the year then ended. As described in Note 1, under the successful

efforts

method of accounting, DD&A of PP&E on producing

hydrocarbon properties and certain

pipeline and liquified natural gas assets (those

which are expected to have a declining

utilization pattern) are determined by the unit-of-production

method. The unit-of-

production method uses proved oil and gas

reserves, as estimated by the Company’s

internal reservoir engineers. PP&E used in operations

is assessed by management for

impairment when changes in facts and circumstances

indicate a possible significant

deterioration in the future cash flows expected to

be generated by an asset group. If there

is an indication the carrying value of an asset

may not be recovered, the Company

compares undiscounted cash flows before income

taxes to the carrying value of the asset

group. If the expected undiscounted cash flows

before income taxes are lower than the

carrying value of the asset group, the carrying

value is written down to estimated fair

value.

Proved oil and gas reserve estimates are

based on geological and engineering

assessments of in-place hydrocarbon volumes, the production

plan, historical extraction

recovery and processing yield factors, installed

plant operating capacity and approved

operating limits. Additionally, the expected future cash flows used for impairment

reviews and related fair value calculations are

based on future production volumes of

estimated oil and gas reserves. Significant judgment

is required by the Company’s

internal reservoir engineers in evaluating geological

and engineering data when

estimating oil and gas reserves. Estimating

reserves also requires the selection of inputs,

including oil and gas price assumptions, future

operating and capital costs assumptions

and tax rates by jurisdiction, among others. Because

of the complexity involved in

estimating oil and gas reserves, management

also used an independent petroleum

engineering consulting firm to perform a review

of the processes and controls used by

the

Company’s internal reservoir engineers to determine estimates of

proved oil and gas

reserves.

Auditing the Company’s DD&A and impairment calculations is complex because

of the

use of the work of the internal reservoir engineers

and the independent petroleum

engineering consulting firm and the evaluation

of management’s determination of the

inputs described above used by the internal reservoir

engineers in estimating oil and gas

reserves.

How We

Addressed the

Matter in Our

Audit

We obtained an understanding, evaluated the design and tested the operating

effectiveness of the Company’s internal controls over its processes to calculate

DD&A

and impairments, including management’s controls over the completeness

and accuracy

of the financial data provided to the internal reservoir

engineers for use in estimating oil

and gas reserves.

Our audit procedures included, among others,

evaluating the professional qualifications

and objectivity of the Company’s internal reservoir engineers primarily

responsible for

overseeing the preparation of the reserve estimates

and the independent petroleum

engineering consulting firm used to review the

Company’s processes and controls. In

addition, in assessing whether we can use the

work of the internal reservoir engineers,

we

evaluated the completeness and accuracy of the financial

data and inputs described above

used by the internal reservoir engineers in estimating

oil and gas reserves by agreeing

them to source documentation and we identified

and evaluated corroborative and

contrary evidence. We also tested the accuracy of the DD&A and impairment

calculations, including comparing the oil and gas

reserve amounts used in the

calculations to the Company’s reserve report.

/s/ Ernst & Young LLP

We have served as ConocoPhillips’ auditor since 1949.

Houston, Texas

February 16, 2021

Report of Independent Registered Public Accounting Firm

To the Stockholders

and the Board of Directors of ConocoPhillips

Opinion on Internal Control over Financial Reporting

We have audited

ConocoPhillips’ internal control over financial reporting as of December 31, 2020, based

on

criteria established in Internal Control–Integrated Framework issued

by the Committee of Sponsoring Organizations

of the Treadway Commission (2013 framework)

(the COSO criteria). In our opinion, ConocoPhillips (the Company)

maintained, in all material respects, effective internal

control over financial reporting as of December 31, 2020,

based on the COSO criteria.

We also have audited,

in accordance with the standards of the Public Company Accounting Oversight Board (United

States) (PCAOB), the consolidated balance sheets of the Company as of December

31, 2020 and 2019, the related

consolidated income statement, consolidated statements of comprehensive

income, changes in equity and cash flows

for each of the three years in the period ended December 31, 2020, and the related notes and

our report dated

February 16, 2021, expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible

for maintaining effective internal control over financial reporting

and

for its assessment of the effectiveness of internal control over financial

reporting included under the heading

“Assessment of Internal Control Over Financial Reporting” in the accompanying

“Reports of Management.” Our

responsibility is to express an opinion on the Company’s

internal control over financial reporting based on our audit.

We are a public

accounting firm registered with the PCAOB and are required to be independent

with respect to the

Company in accordance with the U.S. federal securities laws and the applicable

rules and regulations of the

Securities and Exchange Commission and the PCAOB.

We conducted

our audit in accordance with the standards of the PCAOB. Those standards require

that we plan and

perform the audit to obtain reasonable assurance about whether effective

internal control over financial reporting

was maintained in all material respects.

Our audit included obtaining an understanding of internal control over

financial reporting, assessing the risk that a

material weakness exists, testing and evaluating the design and operating effectiveness

of internal control based on

the assessed risk, and performing such other procedures as we considered

necessary in the circumstances. We

believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over

financial reporting is a process designed to provide reasonable assurance

regarding the reliability of financial reporting and the preparation of financial

statements for external purposes in

accordance with generally accepted accounting principles. A company’s

internal control over financial reporting

includes those policies and procedures that (1) pertain to the maintenance

of records that, in reasonable detail,

accurately and fairly reflect the transactions and dispositions of the assets of the

company; (2) provide reasonable

assurance that transactions are recorded as necessary to permit preparation of

financial statements in accordance

with generally accepted accounting principles, and that receipts and expenditures

of the company are being made

only in accordance with authorizations of management and directors of

the company; and (3) provide reasonable

assurance regarding prevention or timely detection of unauthorized

acquisition, use, or disposition of the company’s

assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting

may not prevent or detect misstatements.

Also, projections of any evaluation of effectiveness to future periods

are subject to the risk that controls may become

inadequate because of changes in conditions, or that the degree of

compliance with the policies or procedures may

deteriorate.

/s/ Ernst & Young

LLP

Houston, Texas

February 16, 2021

Consolidated Income Statement

ConocoPhillips

Years

Ended December 31

Millions of Dollars

2020

2019

2018

Revenues and Other Income

Sales and other operating revenues

$

18,784

32,567

36,417

Equity in earnings of affiliates

1,074

Gain on dispositions

1,966

1,063

Other income (loss)

(509)

1,358

Total Revenues and

Other Income

19,256

36,670

38,727

Costs and Expenses

Purchased commodities

8,078

11,842

14,294

Production and operating expenses

4,344

5,322

5,213

Selling, general and administrative expenses

Exploration expenses

1,457

Depreciation, depletion and amortization

5,521

6,090

5,956

Impairments

Taxes other than income

taxes

1,048

Accretion on discounted liabilities

Interest and debt expense

Foreign currency transaction (gains) losses

(72)

(17)

Other expenses

Total Costs and Expenses

22,396

27,146

28,754

Income (loss) before income taxes

(3,140)

9,524

9,973

Income tax provision (benefit)

(485)

2,267

3,668

Net income (loss)

(2,655)

7,257

6,305

Less: net income attributable to noncontrolling interests

(46)

(68)

(48)

Net Income (Loss) Attributable to ConocoPhillips

$

(2,701)

7,189

6,257

Net Income (Loss) Attributable to ConocoPhillips Per Share

of Common Stock

(dollars)

Basic

$

(2.51)

6.43

5.36

Diluted

(2.51)

6.40

5.32

Average Common

Shares Outstanding

(in thousands)

Basic

1,078,030

1,117,260

1,166,499

Diluted

1,078,030

1,123,536

1,175,538

See Notes to Consolidated Financial Statements.

Consolidated Statement of Comprehensive Income

ConocoPhillips

Years

Ended December 31

Millions of Dollars

2020

2019

2018

Net Income (Loss)

$

(2,655)

7,257

6,305

Other comprehensive income (loss)

Defined benefit plans

Prior service credit (cost) arising during the period

-

(7)

Reclassification adjustment for amortization of prior

service credit included in net income (loss)

(32)

(35)

(40)

Net change

(3)

(35)

(47)

Net actuarial loss arising during the period

(210)

(55)

(150)

Reclassification adjustment for amortization of net

actuarial losses included in net income (loss)

Net change

(93)

Nonsponsored plans*

(3)

(1)

Income taxes on defined benefit plans

(2)

(42)

Defined benefit plans, net of tax

(75)

Unrealized holding gain on securities

-

-

Unrealized gain on securities, net of tax

-

-

Foreign currency translation adjustments

(645)

Income taxes on foreign currency translation adjustments

(4)

Foreign currency translation adjustments, net of tax

(642)

Other Comprehensive Income (Loss), Net of

Tax

(603)

Comprehensive Income (Loss)

(2,516)

8,003

5,702

Less: comprehensive income attributable to noncontrolling interests

(46)

(68)

(48)

Comprehensive Income (Loss) Attributable to ConocoPhillips

$

(2,562)

7,935

5,654

*Plans for which ConocoPhillips is not the primary obligor

—

primarily those administered by equity affiliates.

See Notes to Consolidated Financial Statements.

Consolidated Balance Sheet

ConocoPhillips

At December 31

Millions of Dollars

2020

2019

Assets

Cash and cash equivalents

$

2,991

5,088

Short-term investments

3,609

3,028

Accounts and notes receivable (net of allowance of $

and $

, respectively)

2,634

3,267

Accounts and notes receivable—related parties

Investment in Cenovus Energy

1,256

2,111

Inventories

1,002

1,026

Prepaid expenses and other current assets

2,259

Total Current Assets

12,066

16,913

Investments and long-term receivables

8,017

8,687

Loans and advances—related parties

Net properties, plants and equipment

(net of accumulated DD&A of $

62,213

and $

55,477

, respectively)

39,893

42,269

Other assets

2,528

2,426

Total Assets

$

62,618

70,514

Liabilities

Accounts payable

$

2,669

3,176

Accounts payable—related parties

Short-term debt

Accrued income and other taxes

1,030

Employee benefit obligations

Other accruals

1,121

2,045

Total Current Liabilities

5,366

7,043

Long-term debt

14,750

14,790

Asset retirement obligations and accrued environmental costs

5,430

5,352

Deferred income taxes

3,747

4,634

Employee benefit obligations

1,697

1,781

Other liabilities and deferred credits

1,779

1,864

Total Liabilities

32,769

35,464

Equity

Common stock (

2,500,000,000

shares authorized at $

0.01

par value)

Issued (2020—

1,798,844,267

shares; 2019—

1,795,652,203

shares)

Par value

Capital in excess of par

47,133

46,983

Treasury stock (at cost: 2020—

730,802,089

shares; 2019—

710,783,814

shares)

(47,297)

(46,405)

Accumulated other comprehensive loss

(5,218)

(5,357)

Retained earnings

35,213

39,742

Total Common

Stockholders’ Equity

29,849

34,981

Noncontrolling interests

-

Total Equity

29,849

35,050

Total Liabilities and Equity

$

62,618

70,514

See Notes to Consolidated Financial Statements.

Consolidated Statement of Cash Flows

ConocoPhillips

Years

Ended December 31

Millions of Dollars

2020

2019

2018

Cash Flows From Operating Activities

Net income (loss)

$

(2,655)

7,257

6,305

Adjustments to reconcile net income (loss) to net cash provided by

operating activities

Depreciation, depletion and amortization

5,521

6,090

5,956

Impairments

Dry hole costs and leasehold impairments

1,083

Accretion on discounted liabilities

Deferred taxes

(834)

(444)

Undistributed equity earnings

Gain on dispositions

(549)

(1,966)

(1,063)

Unrealized (gain) loss on investment in Cenovus Energy

(649)

Other

(351)

(246)

Working

capital adjustments

Decrease in accounts and notes receivable

Decrease (increase) in inventories

(25)

(67)

Decrease (increase) in prepaid expenses and other current assets

(55)

Decrease in accounts payable

(249)

(378)

(52)

Increase (decrease) in taxes and other accruals

(695)

(676)

Net Cash Provided by Operating Activities

4,802

11,104

12,934

Cash Flows From Investing Activities

Capital expenditures and investments

(4,715)

(6,636)

(6,750)

Working

capital changes associated with investing activities

(155)

(103)

(68)

Proceeds from asset dispositions

1,317

3,012

1,082

Net sales (purchases) of investments

(658)

(2,910)

1,620

Collection of advances/loans—related parties

Other

(26)

(108)

Net Cash Used in Investing Activities

(4,121)

(6,618)

(3,843)

Cash Flows From Financing Activities

Issuance of debt

-

-

Repayment of debt

(254)

(80)

(4,995)

Issuance of company common stock

(5)

(30)

Repurchase of company common stock

(892)

(3,500)

(2,999)

Dividends paid

(1,831)

(1,500)

(1,363)

Other

(26)

(119)

(123)

Net Cash Used in Financing Activities

(2,708)

(5,229)

(9,359)

Effect of Exchange Rate Changes on Cash, Cash Equivalents and

Restricted Cash

(20)

(46)

(117)

Net Change in Cash, Cash Equivalents and Restricted Cash

(2,047)

(789)

(385)

Cash, cash equivalents and restricted cash at beginning of period

5,362

6,151

6,536

Cash, Cash Equivalents and Restricted Cash at End of Period

$

3,315

5,362

6,151

Restricted cash of $

million and $

million is included in the “Prepaid expenses and other current assets” and “Other assets”

lines,

respectively, of our Consolidated Balance Sheet as of December 31, 2020.

Restricted cash of $

million and $

million is 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.

Consolidated Statement of Changes in Equity

ConocoPhillips

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

Balances at December 31, 2017

$

46,622

(39,906)

(5,518)

29,391

30,801

Net income

6,257

6,305

Other comprehensive loss

(603)

(603)

Dividends paid ($

1.16

per share of common stock)

(1,363)

(1,363)

Repurchase of company common stock

(2,999)

(2,999)

Distributions to noncontrolling interests and other

(121)

(121)

Distributed under benefit plans

Changes in Accounting Principles*

(278)

(220)

Other

Balances at December 31, 2018

$

46,879

(42,905)

(6,063)

34,010

32,064

Net income

7,189

7,257

Other comprehensive income

Dividends paid ($

1.34

per share of common stock)

(1,500)

(1,500)

Repurchase of company common stock

(3,500)

(3,500)

Distributions to noncontrolling interests and other

(128)

(128)

Distributed under benefit plans

Changes in Accounting Principles**

(40)

-

Other

Balances at December 31, 2019

$

46,983

(46,405)

(5,357)

39,742

35,050

Net income (loss)

(2,701)

(2,655)

Other comprehensive income

Dividends paid ($

1.69

per share of common stock)

(1,831)

(1,831)

Repurchase of company common stock

(892)

(892)

Distributions to noncontrolling interests and other

(32)

(32)

Disposition

(84)

(84)

Distributed under benefit plans

Other

Balances at December 31, 2020

$

47,133

(47,297)

(5,218)

35,213

-

29,849

*Cumulative effect of the adoption of ASC Topic 606, "Revenue from Contracts with Customers," and ASU No. 2016-01, "Recognition

and Measurement of

Financial Assets and Liabilities," at January 1, 2018.

**Cumulative effect of the adoption of ASU No. 2018-02, "Reclassification

of Certain Tax Effects from Accumulated Other Comprehensive Income."

See Notes to Consolidated Financial Statements.

Notes to Consolidated Financial Statements

ConocoPhillips

Note 1—Accounting Policies

■

Consolidation Principles and Investments

—Our consolidated financial statements

include the accounts

of majority-owned, controlled subsidiaries

and variable interest entities where we are the primary

beneficiary.

The equity method is used to account for

investments in affiliates in which we have the

ability to exert significant influence over the affiliates’

operating and financial policies.

When we do not

have the ability to exert significant influence,

the investment is measured at fair value

except when the

investment does not have a readily determinable

fair value.

For those exceptions, it will be measured

at

cost minus impairment, plus or minus observable

price changes in orderly transactions for an identical

or

similar investment of the same issuer.

Undivided interests in oil and gas joint ventures,

pipelines, natural

gas plants and terminals are consolidated on a proportionate

basis.

Other securities and investments are

generally carried at cost.

We manage our operations through six operating segments, defined by geographic

region: Alaska; Lower

48; Canada;

Europe,

Middle East and North Africa; Asia Pacific;

and Other International.

For additional

information, see Note 24—Segment Disclosures

and Related Information.

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 periods

to conform with the current period’s presentation.

■

Foreign Currency Translation

—Adjustments resulting from the process of translating

foreign

functional currency financial statements into

U.S. dollars are included in accumulated other

comprehensive loss in common stockholders’ equity.

Foreign currency transaction gains and losses

are

included in current earnings.

Some of our foreign operations use their local currency

as the functional

currency.

■

Use of Estimates

—The preparation of financial statements

in conformity with accounting principles

generally accepted in the U.S. requires management

to make estimates and assumptions that

affect the

reported amounts of assets, liabilities,

revenues and expenses, and the disclosures of contingent

assets and

liabilities.

Actual results could differ from these estimates.

■

Revenue Recognition

—Revenues associated with the sales of crude

oil, bitumen, natural gas, LNG,

NGLs and other items are recognized at the point

in time when the customer obtains control

of the asset.

In evaluating when a customer has control of the

asset, we primarily consider whether

the transfer of legal

title and physical delivery has occurred, whether

the customer has significant risks and rewards

of

ownership, and whether the customer has accepted

delivery and a right to payment exists.

These products

are typically sold at prevailing market prices.

We allocate variable market-based consideration to

deliveries (performance obligations) in the

current period as that consideration relates

specifically to our

efforts to transfer control of current period deliveries to the

customer and represents the amount we

expect to be entitled to in exchange for the related

products.

Payment is typically due within 30 days or

less.

Revenues associated with transactions commonly

called buy/sell contracts, in which the

purchase and sale

of inventory with the same counterparty are entered

into “in contemplation” of one another, are combined

and reported net (i.e., on the same income statement

line).

■

Shipping and Handling Costs

—We typically incur shipping and handling costs prior to control

transferring to the customer and account for these

activities as fulfillment costs.

Accordingly, we include

shipping and handling costs in production and operating

expenses for production activities.

Transportation costs related to marketing activities are recorded

in purchased commodities.

Freight costs

billed to customers are treated as a component of the

transaction price and recorded as a component

of

revenue when the customer obtains control.

■

Cash Equivalents

—Cash equivalents are highly liquid,

short-term investments that are readily

convertible to known amounts of cash and have

original maturities of 90 days or less from

their date of

purchase.

They are carried at cost plus accrued interest,

which approximates fair value.

■

Short-Term Investments

—Short-term investments include investments

in bank time deposits and

marketable securities (commercial paper and government

obligations) which are carried at cost plus

accrued interest and have original maturities

of greater than 90 days but within one year or

when the

remaining maturities are within one year.

We also invest in financial instruments classified as available

for sale debt securities which are carried at fair

value. Those instruments are included in short-term

investments when they have remaining maturities

within one year as of the balance sheet date.

■

Long-Term Investments in Debt Securities

—Long-term investments in debt securities

includes

financial instruments classified as available for sale

debt securities with remaining maturities

greater than

one year as of the balance sheet date.

They are carried at fair value and presented

within the “Investments

and long-term receivables” line of our consolidated

balance sheet.

■

Inventories

—We have several valuation methods for our various types of inventories

and consistently

use the following methods for each type of inventory.

The majority of our commodity-related inventories

are recorded at cost using the LIFO basis.

We measure these inventories at the lower-of-cost-or-market in

the aggregate.

Any necessary lower-of-cost-or-market write-downs at year

end are recorded as

permanent adjustments to the LIFO cost basis.

LIFO is used to better match current inventory

costs with

current revenues.

Costs include both direct and indirect expenditures

incurred in bringing an item or

product to its existing condition and location,

but not unusual/nonrecurring costs or research

and

development costs.

Materials, supplies and other miscellaneous inventories,

such as tubular goods and

well equipment, are valued using various methods,

including the weighted-average-cost

method, and the

FIFO method, consistent with industry practice.

■

Fair Value Measurements

—Assets and liabilities measured at fair value

and required to be categorized

within the fair value hierarchy are categorized into

one of three different levels depending on the

observability of the inputs employed in the measurement.

Level 1 inputs are quoted prices in active

markets for identical assets or liabilities.

Level 2 inputs are observable inputs other than

quoted prices

included within Level 1 for the asset or liability, either directly or indirectly

through market-corroborated

inputs.

Level 3 inputs are unobservable inputs for

the asset or liability reflecting significant

modifications

to observable related market data or our assumptions

about pricing by market participants.

■

Derivative Instruments

—Derivative instruments are recorded on the balance

sheet at fair value.

If the

right of offset exists and certain other criteria are met,

derivative assets and liabilities with the same

counterparty are netted on the balance sheet and the

collateral payable or receivable is netted

against

derivative assets and derivative liabilities,

respectively.

Recognition and classification of the gain or loss

that results from recording and adjusting

a derivative to

fair value depends on the purpose for issuing or

holding the derivative.

Gains and losses from derivatives

not accounted for as hedges are recognized immediately

in earnings.

We do not apply hedge accounting

on our derivative instruments.

■

Oil and Gas Exploration and Development

—Oil and gas exploration and development

costs are

accounted for using the successful efforts method of

accounting.

Property Acquisition Costs

—Oil and gas leasehold acquisition costs are

capitalized and included in

the balance sheet caption PP&E.

Leasehold impairment is recognized based

on exploratory

experience and management’s judgment.

Upon achievement of all conditions necessary for reserves

to be classified as proved, the associated leasehold

costs are reclassified to proved properties.

Exploratory Costs

—Geological and geophysical costs and the

costs of carrying and retaining

undeveloped properties are expensed as incurred.

Exploratory well costs are capitalized, or

“suspended,” on the balance sheet pending further

evaluation of whether economically recoverable

reserves have been found.

If economically recoverable reserves are not found,

exploratory well costs

are expensed as dry holes.

If exploratory wells encounter potentially

economic quantities of oil and

gas, the well costs remain capitalized on the balance

sheet as long as sufficient progress assessing the

reserves and the economic and operating viability

of the project is being made.

For complex

exploratory discoveries, it is not unusual to

have exploratory wells remain suspended

on the balance

sheet for several years while we perform additional

appraisal drilling and seismic work on the

potential oil and gas field or while we seek government

or co-venturer approval of development plans

or seek environmental permitting.

Once all required approvals and permits have been

obtained, the

projects are moved into the development phase,

and the oil and gas resources are designated

as proved

reserves.

Management reviews suspended well balances quarterly, continuously monitors

the results of the

additional appraisal drilling and seismic work,

and expenses the suspended well costs

as dry holes

when it judges the potential field does not

warrant further investment in the near term.

See Note 7—

Suspended Wells and Exploration Expenses, for additional information on suspended

wells.

Development Costs

—Costs incurred to drill and equip development

wells, including unsuccessful

development wells, are capitalized.

Depletion and Amortization

—Leasehold costs of producing properties

are depleted using the unit-

of-production method based on estimated proved

oil and gas reserves.

Amortization of intangible

development costs is based on the unit-of-production

method using estimated proved developed

oil

and gas reserves.

■

Capitalized Interest

—Interest from external borrowings is

capitalized on major projects with an

expected construction period of one year or longer.

Capitalized interest is added to the cost of the

underlying asset and is amortized over the useful

lives of the assets in the same manner

as the underlying

assets.

■

Depreciation and Amortization

—Depreciation and amortization of PP&E

on producing hydrocarbon

properties and SAGD facilities and certain pipeline

and LNG assets (those which are expected

to have a

declining utilization pattern), are determined by

the unit-of-production method.

Depreciation and

amortization of all other PP&E are determined

by either the individual-unit-straight-line method

or the

group-straight-line method (for those individual

units that are highly integrated with other

units).

■

Impairment of Properties, Plants and Equipment

—PP&E used in operations are assessed for

impairment whenever changes in facts and circumstances

indicate a possible significant deterioration

in

the future cash flows expected to be generated

by an asset group.

If there is an indication the carrying

amount of an asset may not be recovered, a recoverability

test is performed using management’s

assumptions such as for prices, volumes and future

development plans.

If, upon review, the sum of the

undiscounted cash flows before income-taxes is

less than the carrying value of the asset

group, the

carrying value is written down to estimated fair

value and reported as an impairment in the

period in

which the determination of the impairment

is made.

Individual assets are grouped for impairment

purposes at the lowest level for which there are

identifiable cash flows that are largely independent

of the

cash flows of other groups of assets—generally

on a field-by-field basis for E&P assets.

Because there

usually is a lack of quoted market prices for

long-lived assets, the fair value of impaired assets

is typically

determined based on the present values of expected

future cash flows using discount rates

and prices

believed to be consistent with those used by principal

market participants, or based on a multiple

of

operating cash flow validated with historical

market transactions of similar assets

where possible.

Long-

lived assets committed by management for disposal

within one year are accounted for at

the lower of

amortized cost or fair value, less cost to sell,

with fair value determined using a binding negotiated

price,

if available, or present value of expected future

cash flows as previously described.

The expected future cash flows used for impairment

reviews and related fair value calculations are

based

on estimated future production volumes, prices

and costs, considering all available evidence at the

date of

review.

The impairment review includes cash flows from

proved developed and undeveloped reserves,

including any development expenditures necessary

to achieve that production.

Additionally, when

probable and possible reserves exist, an appropriate

risk-adjusted amount of these reserves may be

included in the impairment calculation.

■

Impairment of Investments in Nonconsolidated

Entities

—Investments in nonconsolidated entities

are

assessed for impairment whenever changes in the

facts and circumstances indicate a loss

in value has

occurred.

When such a condition is judgmentally determined

to be other than temporary, the carrying

value of the investment is written down to fair

value.

The fair value of the impaired investment

is based

on quoted market prices, if available, or upon

the present value of expected future cash flows using

discount rates and prices believed to be consistent

with those used by principal market participants,

plus

market analysis of comparable assets owned by the

investee, if appropriate.

■

Maintenance and Repairs

—Costs of maintenance and repairs, which are

not significant improvements,

are expensed when incurred.

■

Property Dispositions

—When complete units of depreciable property

are sold, the asset cost and related

accumulated depreciation are eliminated,

with any gain or loss reflected in the “Gain on dispositions”

line

of our consolidated income statement.

When less than complete units of depreciable property

are

disposed of or retired which do not significantly

alter the DD&A rate, the difference between asset

cost

and salvage value is charged or credited to accumulated

depreciation.

■

Asset Retirement Obligations and Environmental Costs

—The

fair value of legal obligations to retire

and remove long-lived assets are recorded in

the period in which the obligation is incurred

(typically

when the asset is installed at the production location).

Fair value is estimated using a present value

approach, incorporating assumptions about estimated

amounts and timing of settlements and

impacts of

the use of technologies.

When the liability is initially recorded,

we capitalize this cost by increasing the

carrying amount of the related PP&E.

If, in subsequent periods, our estimate of this

liability changes, we

will record an adjustment to both the liability

and PP&E.

Over time the liability is increased for the

change in its present value, and the capitalized cost

in PP&E is depreciated over the useful

life of the

related asset.

Reductions to estimated liabilities for

assets that are no longer producing are recorded as a

credit to impairment, if the asset had been previously

impaired, or as a credit to DD&A, if the

asset had

not been previously impaired.

For additional information, see Note 9—Asset

Retirement Obligations and

Accrued Environmental Costs.

Environmental expenditures are expensed or capitalized,

depending upon their future economic benefit.

Expenditures relating to an existing condition

caused by past operations, and those having no future

economic benefit, are expensed.

Liabilities for environmental expenditures are

recorded on an

undiscounted basis (unless acquired through a business

combination, which we record on a discounted

basis) when environmental assessments or cleanups

are probable and the costs can be reasonably

estimated.

Recoveries of environmental remediation costs

from other parties are recorded as assets when

their receipt is probable and estimable.

■

Guarantees

—The fair value of a guarantee is determined

and recorded as a liability at the time the

guarantee is given.

The initial liability is subsequently reduced

as we are released from exposure under

the guarantee.

We amortize the guarantee liability over the relevant time period, if one exists, based on

the facts and circumstances surrounding each type

of guarantee.

In cases where the guarantee term is

indefinite, we reverse the liability when we have

information indicating the liability

is essentially relieved

or amortize it over an appropriate time

period as the fair value of our guarantee exposure

declines over

time.

We amortize the guarantee liability to the related income statement line item based

on the nature of

the guarantee.

When it becomes probable that we will have

to perform on a guarantee, we accrue a

separate liability if it is reasonably estimable,

based on the facts and circumstances at that

time.

We

reverse the fair value liability only when there

is no further exposure under the guarantee.

■

Share-Based Compensation

—We recognize share-based compensation expense over the shorter of the

service period (i.e., the stated period of time required

to earn the award) or the period beginning at

the

start of the service period and ending when an

employee first becomes eligible for retirement.

We have

elected to recognize expense on a straight-line

basis over the service period for the entire

award, whether

the award was granted with ratable or cliff vesting.

■

Income Taxes

—Deferred income taxes are computed using

the liability method and are provided on all

temporary differences between the financial reporting basis

and the tax basis of our assets and liabilities,

except for deferred taxes on income and temporary

differences related to the cumulative translation

adjustment considered to be permanently reinvested

in certain foreign subsidiaries and

foreign corporate

joint ventures.

Allowable tax credits are applied currently

as reductions of the provision for income

taxes.

Interest related to unrecognized tax benefits

is reflected in interest and debt expense, and

penalties

related to unrecognized tax benefits are reflected

in production and operating expenses.

■

Taxes Collected from Customers and Remitted to Governmental Authorities

—Sales and value-

added taxes are recorded net.

■

Net Income (Loss) Per Share of Common Stock

—Basic net income (loss) per share of common stock

is calculated based upon the daily weighted-average

number of common shares outstanding during

the

year.

Also, this

calculation includes fully vested stock and unit

awards that have not yet been issued as

common stock, along with an adjustment to

net income (loss) for dividend equivalents

paid on unvested

unit awards that are considered participating

securities.

Diluted net income per share of common stock

includes unvested stock, unit or option awards granted

under our compensation plans and vested but

unexercised stock options, but only to the extent these

instruments dilute net income per share, primarily

under the treasury-stock method.

Diluted net loss per share, which is calculated

the same as basic net loss

per share, does not assume conversion or exercise

of securities that would have an antidilutive

effect.

Treasury stock is excluded from the daily weighted-average number

of common shares outstanding in

both calculations.

The earnings per share impact of the participating

securities is immaterial.

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 at December 31 were:

Millions of Dollars

2020

2019

Crude oil and natural gas

$

Materials and supplies

$

1,002

1,026

Inventories valued on the LIFO basis totaled

$

million and $

million at December 31, 2020 and 2019,

respectively.

In the first quarter of 2020, we recorded a lower

of cost or market adjustment of $

million to

our crude oil and natural gas inventories, which is

included in the “Purchased commodities”

line on our

consolidated income statement.

Commodity prices have since improved.

The estimated excess of current

replacement cost over LIFO cost of inventories

was approximately $

million and $

million at

December 31, 2020 and 2019, respectively.

Note 4—Asset Acquisitions and Dispositions

All gains or losses on asset dispositions

are reported before-tax and are included net in the

“Gain on

dispositions” line on our consolidated income

statement.

All cash proceeds and payments are included in the

“Cash Flows From Investing Activities” section

of our consolidated statement of cash flows.

On January 15, 2021, we completed our acquisition

of Concho Resources Inc. (Concho), an independent

oil

and gas exploration and production company

with operations across New Mexico and West

Texas focused in

the Permian Basin.

Total consideration for the all-stock transaction was valued at $

13.1

billion, in which

1.46

shares of ConocoPhillips common stock

was exchanged for each outstanding share of

Concho common stock,

resulting in the issuance of approximately

million shares of ConocoPhillips common

stock.

We also

assumed $

3.9

billion in aggregate principal amount of outstanding

debt for Concho, which was recorded at fair

value of $

4.7

billion as of the closing date.

For additional information related to this

transaction, see Note

25—Acquisition of Concho Resources Inc.

2020

Asset Acquisition

In August 2020, we completed the acquisition

of additional Montney acreage in Canada from Kelt

Exploration

Ltd. for $

million after customary adjustments, plus the

assumption of $

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 increased

our Montney acreage position to

approximately

295,000

net acres with a

percent working interest.

This agreement was accounted for as an

asset acquisition resulting in the recognition of $

million of PP&E; $

million of ARO and accrued

environmental costs; and $

million of financing obligations recorded primarily

to long-term debt.

Results of

operations for the Montney asset are reported in our

Canada segment.

Assets Sold

In February 2020, we sold our Waddell Ranch interests in the Permian Basin for $

million after customary

adjustments.

No

gain or loss was recognized on the sale.

Results of operations for the Waddell Ranch

interests sold were reported in our Lower 48 segment.

In March 2020, we completed the sale of our

Niobrara interests for approximately $

million after

customary adjustments and recognized a before-tax

loss on disposition of $

million.

At the time of

disposition, our interest in Niobrara had a net carrying

value of $

million, consisting primarily of

$

million of PP&E and $

million of ARO. The before-tax losses associated

with our interests in

Niobrara, including the loss on disposition noted above

and an impairment of $

million recorded when we

signed an agreement to sell our interests in

the fourth quarter of 2019, were $

million and $

million for

the years ended December 31, 2020 and 2019,

respectively. The before-tax earnings associated with our

interests in Niobrara for the year ended December

31, 2018 was $

million.

Results of operations for the

Niobrara interests sold were reported in our

Lower 48 segment.

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 $

million with an

additional $

million due upon final investment decision

of the proposed Barossa development project.

We

recognized a before-tax gain of $

million related to this transaction in 2020.

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 $

million, $

million and $

million for the years ended December 31,

2020, 2019 and 2018, respectively.

Production from the beginning of the year through

the disposition date in May 2020 averaged

MBOED.

Results of operations for the subsidiaries

sold were reported in our Asia Pacific segment.

2019

Assets Sold

In January 2019, we entered into agreements to sell

our

12.4

percent ownership interests in the Golden

Pass

LNG Terminal and Golden Pass Pipeline.

We also entered into agreements to amend our contractual

obligations for retaining use of the facilities.

As a result of entering into these agreements, we recorded

a

before-tax impairment of $

million in the first quarter of 2019 which is included

in the “Equity in earnings

of affiliates” line on our consolidated income statement.

We completed the sale in the second quarter of 2019.

Results of operations for these assets were reported

in our Lower 48 segment.

See Note 14—Fair Value

Measurement for additional information.

In April 2019, we entered into an agreement to sell

two ConocoPhillips U.K. subsidiaries to

Chrysaor E&P

Limited for $

2.675

billion plus interest and customary adjustments,

with an effective date of January 1, 2018.

On September 30, 2019, we completed the sale for

proceeds of $

2.2

billion and recognized a $

1.7

billion

before-tax and $

2.1

billion after-tax gain associated with this transaction

in 2019.

Together the subsidiaries

sold indirectly held our exploration and production

assets in the U.K.

At the time of disposition, the net

carrying value was approximately $

0.5

billion, consisting primarily of $

1.6

billion of PP&E, $

0.5

billion of

cumulative foreign currency translation adjustments,

and $

0.3

billion of deferred tax assets, offset by $

1.8

billion of ARO and negative $

0.1

billion of working capital.

The before-tax earnings associated with the

subsidiaries sold, including the gain on dispositions

noted above, were $

2.1

billion and $

0.9

billion for the

years ended December 31, 2019 and 2018, respectively.

Results of operations for the U.K. were reported

within our Europe, Middle East and North Africa segment.

In the second quarter of 2019, we recognized an

after-tax gain of $

million upon the closing of the sale of

our

percent interest in the Greater Sunrise Fields

to the government of Timor-Leste for $

million.

The

Greater Sunrise Fields were included in our Asia

Pacific segment.

In the fourth quarter of 2019, we sold our interests

in the Magnolia field and platform for net proceeds

of $

million and recognized a before-tax gain of $

million.

At the time of sale, the net carrying value consisted

of $

million of PP&E offset by $

million of ARO.

The Magnolia results of operations were reported

within

our Lower 48 segment.

2018

Assets Sold

In the first quarter of 2018, we completed the sale of

certain properties in the Lower 48 segment

for net

proceeds of $

million.

No

gain or loss was recognized on the sale.

In the second quarter of 2018, we

completed the sale of a package of largely undeveloped acreage

in the Lower 48 segment for net proceeds

of

$

million and

no

gain or loss was recognized on the sale.

In the third quarter of 2018, we completed a

noncash exchange of undeveloped acreage in

the Lower 48 segment.

The transaction was recorded at fair

value resulting in the recognition of a $

million gain.

In the fourth quarter of 2018, we sold several

packages of undeveloped acreage in the Lower

48 segment for total net proceeds of $

million and

recognized gains of approximately $

million.

On October 31, 2018, we completed the sale of

our interests in the Barnett to Lime Rock Resources

for $

million after customary adjustments and recognized

a loss of $

million. We recorded an impairment of $87

million in 2018 to reduce the net carrying value

of the Barnett to fair value.

At the time of the disposition, our

interest in Barnett had a net carrying value of $

million, consisting of $

million of PP&E and $

million of AROs.

The before-tax loss associated with our

interests in the Barnett, including both the

impairment and loss on disposition noted above,

was $

million for the year ended December 31, 2018.

The

Barnett results of operations were included in our

Lower 48 segment.

On December 18, 2018, we completed the sale of

a ConocoPhillips subsidiary to BP.

The subsidiary held

16.5

percent of our

percent interest in the BP-operated Clair Field

in the U.K.

We retained a

7.5

percent

interest in the field.

At the same time, we acquired BP’s

39.2

percent nonoperated interest in the Greater

Kuparuk Area in Alaska, including their

percent interest in the Kuparuk Transportation Company (Kuparuk

Assets).

The transaction was recorded at a fair value

of $

1,743

million and was cash neutral except for

customary adjustments which resulted in net

proceeds of $

million.

At closing, our interest in the Clair

Field had a net carrying value of approximately

$

1,028

million consisting primarily of $

1,553

million of

PP&E, $

million of deferred tax liabilities, and $

million of AROs.

We recognized a before-tax gain of

$

million on the transaction.

The 2018 before-tax earnings associated

with our

16.5

percent interest in the

Clair Field, including the recognized gain, were $

million. Results of operations for our interest

in the Clair

Field are reported within our Europe, Middle

East and North Africa segment and the Kuparuk

Assets were

included in our Alaska segment.

Acquisitions

In May 2018, we completed the acquisition of

Anadarko’s

percent nonoperated interest in the Western

North Slope of Alaska, as well as its interest

in the Alpine Transportation Pipeline for $

million, after

customary adjustments.

This transaction was accounted for as a business

combination resulting in the

recognition of approximately $

million of proved property and $

million of unproved property within

PP&E, $

million of inventory, $

million of investments, and $

million of AROs. These assets are

included in our Alaska segment.

As discussed in the Clair Field transaction with BP

above, we acquired BP’s Kuparuk Assets on December 18,

The transaction was accounted for as an asset acquisition

with a net acquisition cost of $

1,490

million,

comprised of the fair value of $

1,743

million associated with the disposed

16.5

percent of our

percent

interest in the Clair Field, reduced by the net proceeds

of $

million.

Accordingly, we recorded

approximately $

1.9

billion to proved property within PP&E, $

million to inventory, $

million to

investments, $

million of AROs, and a $

million decrease to net working capital.

The Kuparuk Assets

are included in our Alaska segment.

Note 5—Investments, Loans and Long-Term Receivables

Components of investments, loans and long-term

receivables at December 31 were:

Millions of Dollars

2020

2019

Equity investments

$

7,596

8,234

Loans and advances—related parties

Long-term receivables

Long-term investments in debt securities

Other investments

$

8,131

8,906

Equity Investments

Affiliated companies in which we had a significant

equity investment at December 31, 2020, included:

●

APLNG—

37.5

percent owned joint venture with Origin Energy (

37.5

percent) and Sinopec (

percent)—

to produce CBM from the Bowen and Surat basins in Queensland, Australia, as well as process

and export

LNG.

●

Qatar Liquefied Gas Company Limited (3) (QG3)—30 percent owned

joint venture with affiliates of Qatar

Petroleum (

68.5

percent) and Mitsui & Co., Ltd. (

1.5

percent)—produces and liquefies natural gas from

Qatar’s North Field, as well as exports LNG.

Summarized 100 percent earnings information

for equity method investments in affiliated companies,

combined, was as follows:

Millions of Dollars

2020

2019

2018

Revenues

$

7,931

11,310

11,654

Income before income taxes

1,843

3,726

3,660

Net income

1,426

3,085

3,244

Summarized 100 percent balance sheet information

for equity method investments in affiliated

companies,

combined, was as follows:

Millions of Dollars

2020

2019

Current assets

$

2,579

3,289

Noncurrent assets

35,257

38,905

Current liabilities

2,110

2,603

Noncurrent liabilities

18,099

22,168

Our share of income taxes incurred directly

by an equity method investee is reported in equity

in earnings of

affiliates, and as such is not included in income taxes

on our consolidated financial statements.

At December 31, 2020, retained earnings included

$

million related to the undistributed earnings

of

affiliated companies.

Dividends received from affiliates were $

1,076

million, $

1,378

million and

$

1,226

million in 2020, 2019 and 2018, respectively.

APLNG

APLNG is a joint venture focused on producing

CBM from the Bowen and Surat basins in

Queensland,

Australia.

Natural gas is sold to domestic customers and

LNG is processed and exported to Asia Pacific

markets.

Our investment in APLNG gives us access

to CBM resources in Australia and enhances our

LNG

position.

The majority of APLNG LNG is sold under two

long-term sales and purchase agreements,

supplemented with sales of additional LNG spot

cargoes targeting the Asia Pacific markets.

Origin Energy, an

integrated Australian energy company, is the operator of APLNG’s production and pipeline system, while we

operate the LNG facility.

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

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 December 31, 2020, a balance of $

6.2

billion was outstanding on the facilities.

See Note 11—Guarantees,

for additional information.

During the fourth quarter of 2020, the estimated

fair value of our investment in APLNG declined

to an amount

below carrying value, primarily due to the weakening

of the U.S. dollar relative to the Australian

dollar.

Based

on a review of the facts and circumstances surrounding

this decline in fair value, we concluded the impairment

was not other than temporary under the guidance

of FASB ASC Topic

323, “Investments – Equity Method and

Joint Ventures.”

In reaching this conclusion, we primarily

considered: (1) the volatility and uncertainty

in

commodity and exchange rate markets; (2)

the intent and ability of ConocoPhillips to retain

our investment in

APLNG; and (3) the short length of time and extent

to which fair value has been less than carrying value

(fair

value exceeded carrying value as of September

30, 2020).

Fair value has been estimated based on an internal

discounted cash flow model using the following

estimated assumptions: estimated future production,

an

outlook of future prices from a combination of exchanges

(short-term) coupled with pricing service companies

and our internal outlook (long-term), operating

and capital expenditures, a market outlook of foreign

exchange

rates provided by a third party, and a discount rate believed to be consistent

with those used by principal

market participants.

At December 31, 2020, the fair value of our investment

in APLNG was estimated to be $

6,560

million,

resulting in a not other than temporary impairment

of $

million.

We will continue to monitor the

relationship between the carrying value and fair

value of APLNG.

Should we determine in the future there has

been a loss in the value of our investment

that is other than temporary, we would record an impairment of our

equity investment, calculated as the total difference between

carrying value and fair value as of the end

of the

reporting period.

At December 31, 2020, the carrying value of

our equity method investment in APLNG was $

6,672

million.

The historical cost basis of our

37.5

percent share of net assets on the books

of APLNG was $

6,242

million,

resulting in a basis difference of $

million on our books.

The basis difference, which is substantially all

associated with PP&E and subject to amortization,

has been allocated on a relative fair value

basis to

individual exploration and production license areas

owned by APLNG, some of which are not currently

in

production.

Any future additional payments are expected

to be allocated in a similar manner.

Each

exploration license area will periodically be reviewed

for any indicators of potential impairment,

which, if

required, would result in acceleration of basis

difference amortization.

As the joint venture produces natural

gas from each license, we amortize the basis

difference allocated to that license using the unit-of-production

method.

Included in net income (loss) attributable

to ConocoPhillips for 2020,

2019 and 2018 was after-tax

expense of $

million, $

million and $

million, respectively, representing the amortization of this basis

difference on currently producing licenses.

QG3

QG3 is a joint venture that owns an integrated

large-scale LNG project located in Qatar.

We provided project

financing, with a current outstanding balance

of $

million as described below under “Loans and

Long-

Term Receivables.”

At December 31, 2020, the book value of our equity

method investment in QG3,

excluding the project financing, was $

million.

We have terminal and pipeline use agreements with Golden

Pass LNG Terminal and affiliated Golden Pass Pipeline near Sabine Pass, Texas, intended to provide us with

terminal and pipeline capacity for the receipt,

storage and regasification of LNG purchased

from QG3.

We

previously held a

12.4

percent interest in Golden Pass LNG Terminal and Golden Pass Pipeline, but

we sold

those interests in the second quarter of 2019 while

retaining the basic use agreements.

Currently,

the LNG

from QG3 is being sold to markets outside of

the U.S.

For additional information, see Note 4—Asset

Acquisitions and Dispositions.

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

and long-term receivables to certain affiliated

and non-affiliated companies.

Loans are recorded when cash is

transferred or seller financing is provided to the

affiliated or non-affiliated company pursuant to a loan

agreement.

The loan balance will increase as interest is earned

on the outstanding loan balance and will

decrease as interest and principal payments are

received.

Interest is earned at the loan agreement’s stated

interest rate.

Loans and long-term receivables are assessed for

impairment when events indicate the loan

balance may not be fully recovered.

At December 31, 2020, significant loans to affiliated

companies include $

million in project financing to

QG3.

We own a

percent interest in QG3, for which we

use the equity method of accounting.

The other

participants in the project are affiliates of Qatar Petroleum

and Mitsui.

QG3 secured project financing of

$

4.0

billion in December 2005, consisting of $

1.3

billion of loans from export credit agencies

(ECA), $

1.5

billion from commercial banks, and $

1.2

billion from ConocoPhillips.

The ConocoPhillips loan facilities have

substantially the same terms as the ECA and commercial

bank facilities.

On December 15, 2011, QG3

achieved financial completion and all project loan facilities

became nonrecourse to the project participants.

Semi-annual

repayments began in January 2011 and will extend through July

The long-term portion of these loans is included

in the “Loans and advances—related parties”

line on our

consolidated balance sheet, while the short-term

portion is in “Accounts and notes receivable—related

parties.”

Note 6—Investment in Cenovus Energy

On May 17, 2017, we completed the sale of our

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

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 December 31, 2020, the investment included on

our consolidated balance sheet was $

1.26

billion and is

carried at fair value.

The fair value of the

million Cenovus Energy common shares reflects

the closing

price of $

6.04

per share on the NYSE on the last trading

day of the quarter, a decrease of $

million from its

fair value of $

2.11

billion at December 31, 2019.

The decrease in fair value resulted in a net

unrealized loss

recorded within the “Other income (loss)” line of

our consolidated income statement for the

year ended

December 31, 2020 relating to the shares held

at the reporting date.

For the years ended 2019 and 2018, we

recorded an unrealized gain of $

million and an unrealized loss of $

million, respectively.

See Note

14—Fair Value Measurement and Note 21—Other Financial Information, for additional information.

Subject

to market conditions, we intend to decrease our

investment over time through market transactions,

private

agreements or otherwise.

On January 4, 2021, Cenovus Energy completed its

all-stock acquisition of Husky Energy Inc.

As a result of

this transaction, our investment now approximates

percent of the issued and outstanding Cenovus

Energy

common stock.

Note 7—Suspended Wells and Exploration Expenses

The following table reflects the net changes in suspended

exploratory well costs during 2020, 2019 and 2018:

Millions of Dollars

2020

2019

2018

Beginning balance at January 1

$

1,020

Additions pending the determination of proved reserves

Reclassifications to proved properties

(42)

(11)

(37)

Sales of suspended wells

(313)

(54)

(93)

Charged to dry hole expense

(147)

(10)

(7)

Ending balance at December 31

$

1,020

*Includes $

million of assets held for sale in Australia at December

31, 2019.

For additional details on suspended wells charged to dry hole expense, see the

Exploration Expenses section of this Note.

The following table provides an aging of suspended

well balances at December 31:

Millions of Dollars

2020

2019

2018

Exploratory well costs capitalized for a period

of one year or less

$

Exploratory well costs capitalized for a period

greater than one year

Ending balance

$

1,020

Number of projects with exploratory well costs

capitalized for a

period greater than one year

*Includes $

million of assets held for sale in Australia at December

31, 2019.

The following table provides a further aging of

those exploratory well costs that have

been capitalized for more

than one year since the completion of drilling

as of December 31, 2020:

Millions of Dollars

Suspended Since

Total

2017–2019

2014–2016

2004–2013

NPRA—Alaska

(1)

-

Surmont—Canada

(1)

Narwhal Trend—Alaska

(1)

-

-

PL782S—Norway

(1)

-

-

WL4-00—Malaysia

(1)

-

-

NC 98—Libya

(2)

-

Other of $10 million or less each

(1)(2)

Total

$

(1)Additional appraisal wells planned.

(2)Appraisal drilling complete; costs being incurred to assess development.

Exploration Expenses

The charges discussed below are included in the “Exploration

expenses” line on our consolidated income

statement.

2020

In our Alaska segment, we recorded a before-tax impairment

of $

million for the entire associated carrying

value of capitalized undeveloped leasehold costs

related to our Alaska North Slope Gas asset.

In 2016, we,

along with affiliates of Exxon Mobil Corporation,

BP p.l.c. and Alaska Gasline Development Corporation

(AGDC), a state-owned corporation, completed

preliminary FEED technical work for

a potential LNG project

which would liquefy and export natural gas from

Alaska’s North Slope and deliver it to market.

In 2016, we,

along with the affiliates of ExxonMobil and BP, indicated our intention not to progress into the next phase

of

the project due to changes in the economic environment;

however, AGDC decided to continue on its own,

focusing primarily on permitting efforts.

Currently, AGDC is in the process of seeking new sponsors for the

project.

Given current market conditions, we no longer

believe the project will advance and, there

is no

current market for the asset.

In our Other International segment, our interests

in the Middle Magdalena Basin of Colombia

are in force

majeure.

We have no immediate plans to perform under existing contracts; therefore,

in 2020, we recorded a

before-tax expense totaling $

million for dry hole costs of a previously suspended

well and an impairment of

the associated capitalized undeveloped leasehold carrying

value.

In our Asia Pacific segment, we recorded before-tax

expense of $

million related to dry hole costs of a

previously suspended well and an impairment

of the associated capitalized undeveloped

leasehold carrying

value associated with the Kamunsu East Field

in Malaysia that is no longer in our development

plans.

2019

In our Lower 48 segment, we recorded a before-tax impairment

of $

million for the associated carrying

value of capitalized undeveloped leasehold costs

and dry hole expenses of $

million before-tax due to our

decision to discontinue exploration activities

related to our Central Louisiana Austin Chalk acreage.

Note 8—Impairments

During 2020, 2019 and 2018, we recognized the

following before-tax impairment charges:

Millions of Dollars

2020

2019

2018

Alaska

$

-

-

Lower 48

Canada

Europe, Middle East and North Africa

(79)

Asia Pacific

-

-

$

2020

During 2020, we recorded impairments of $

million, primarily related to certain

non-core assets in the

Lower 48.

Due to a significant decrease in the outlook for

current and long-term natural gas prices in early

2020, we recorded impairments of $

million, primarily for the Wind River Basin operations area,

consisting of developed properties in the

Madden Field and the Lost Cabin Gas Plant, in

the first quarter of

Additionally, due primarily to changes in development plans solidified in

the last quarter of 2020, we

recognized additional impairments of $

million in the Lower 48 during the fourth

quarter.

See Note 14—

Fair Value Measurement, for additional information.

2019

In the Lower 48, we recorded impairments

of $

million, primarily related to developed properties

in our

Niobrara asset which were written down to fair value

less costs to sell.

See Note 4—Asset Acquisitions and

Dispositions,

for additional information on this disposition.

2018

In Alaska, we recorded impairments of $

million primarily due to cancelled projects.

In the Lower 48, we recorded impairments

of $

million, primarily related to developed properties

in our

Barnett asset which were written down to fair value

less costs to sell, partly offset by a revision to reflect

finalized proceeds on a separate transaction.

In our Europe, Middle East and North Africa segment,

we recorded a credit to impairment of $

million,

primarily due to decreased ARO estimates on fields

in the U.K. which ceased production and

were impaired in

prior years, partly offset by an increased ARO estimate

on a field in Norway which ceased production.

Note 9—Asset Retirement Obligations and Accrued

Environmental Costs

Asset retirement obligations and accrued environmental

costs at December 31 were:

Millions of Dollars

2020

2019

Asset retirement obligations

$

5,573

6,206

Accrued environmental costs

Total asset retirement obligations and accrued environmental costs

5,753

6,377

Asset retirement obligations and accrued environmental

costs due within one year*

(323)

(1,025)

Long-term asset retirement obligations and accrued

environmental costs

$

5,430

5,352

*Classified as a current liability on the balance sheet under “Other accruals.” For

2019, $

million relates to assets which were held for sale

as of December 31, 2019, and subsequently sold in 2020. For

additional information see Note 4—Asset Acquisitions and Dispositions.

Asset Retirement Obligations

We record the fair value of a liability for an ARO when it is incurred (typically when

the asset is installed at

the production location).

When the liability is initially recorded,

we capitalize the associated asset retirement

cost by increasing the carrying amount of the related

PP&E.

If, in subsequent periods, our estimate

of this

liability changes, we will record an adjustment

to both the liability and PP&E.

Over time, the liability

increases for the change in its present value,

while the capitalized cost depreciates over the

useful life of the

related asset.

We have numerous AROs we are required to perform under law or contract once

an asset is permanently taken

out of service.

Most of these obligations are not expected

to be paid until several years, or decades, in

the

future and will be funded from general company

resources at the time of removal.

Our largest individual

obligations involve plugging and abandonment

of wells and removal and disposal of offshore oil

and gas

platforms around the world, as well as oil and

gas production facilities and pipelines in Alaska.

During 2020 and 2019, our overall ARO changed

as follows:

Millions of Dollars

2020

2019

Balance at January 1

$

6,206

7,908

Accretion of discount

New obligations

Changes in estimates of existing obligations

(307)

Spending on existing obligations

(116)

(229)

Property dispositions

(771)

(1,920)

Foreign currency translation

(80)

Balance at December 31

$

5,573

6,206

Accrued Environmental Costs

Total accrued environmental costs at December 31, 2020 and 2019, were $

million and $

million,

respectively.

We had accrued environmental costs of $

million and $

million at December 31, 2020 and 2019,

respectively, related to remediation activities in the U.S. and Canada.

We had also accrued in Corporate and

Other $

million and $

million of environmental costs associated

with sites no longer in operation at

December 31, 2020 and 2019, respectively.

In addition, $

million and $

million were included at both

December 31, 2020 and 2019, respectively, where the company has been named

a potentially responsible party

under the Federal Comprehensive Environmental

Response, Compensation and Liability

Act, or similar state

laws.

Accrued environmental liabilities are expected to

be paid over periods extending up to

years.

Expected expenditures for environmental obligations

acquired in various business combinations

are discounted

using a weighted-average

percent discount factor, resulting in an accrued balance for acquired

environmental

liabilities of $

million at December 31, 2020.

The expected future undiscounted payments

related to the

portion of the accrued environmental costs that

have been discounted are: $

million in 2021, $

million in

2022, $

million in 2023, $

million in 2024, $

million in 2025, and $

million for all future years

after 2025.

Note 10—Debt

Long-term debt at December 31 was:

Millions of Dollars

2020

2019

9.125

% Debentures due 2021

$

2.4

% Notes due 2022

7.65

% Debentures due 2023

3.35

% Notes due 2024

8.2

% Debentures due 2025

3.35

% Notes due 2025

6.875

% Debentures due 2026

4.95

% Notes due 2026

1,250

1,250

7.8

% Debentures due 2027

7.375

% Debentures due 2029

% Debentures due 2029

6.95

% Notes due 2029

1,549

1,549

8.125

% Notes due 2030

7.2

% Notes due 2031

7.25

% Notes due 2031

7.4

% Notes due 2031

5.9

% Notes due 2032

4.15

% Notes due 2034

5.95

% Notes due 2036

5.951

% Notes due 2037

5.9

% Notes due 2038

6.5

% Notes due 2039

2,750

2,750

4.3

% Notes due 2044

5.95

% Notes due 2046

7.9

% Debentures due 2047

Floating rate notes due 2022 at

1.12

% –

2.81

% during 2020 and

2.81

% –

3.58

% during 2019

Marine Terminal Revenue Refunding Bonds due 2031 at

0.1

% –

7.5

% during

2020 and

1.08

% –

2.45

% during 2019

Industrial Development Bonds due 2035 at

0.11

% –

7.5

% during 2020 and

1.08

% –

2.45

% during 2019

Commercial Paper at

0.08

% –

0.23

% during 2020

Other

Debt at face value

14,292

13,971

Finance leases

Net unamortized premiums, discounts and

debt issuance costs

Total debt

15,369

14,895

Short-term debt

(619)

(105)

Long-term debt

$

14,750

14,790

Maturities of long-term borrowings, inclusive

of net unamortized premiums and discounts,

in 2021 through

2025 are: $

million, $

1,001

million, $

million, $

million and $

million, respectively.

We have a revolving credit facility totaling $

6.0

billion with an expiration date of May 2023.

Our revolving

credit facility may be used for direct bank borrowings,

the issuance of letters of credit totaling

up to $

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 $

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 our ability

to issue up to $

6.0

billion of commercial paper, which is

primarily a funding source for short-term working capital

needs.

Commercial paper maturities are generally

limited to

90 days

.

We issued $

million of commercial paper in the third

quarter of 2020, which is

included in the short-term debt on our consolidated

balance sheet.

With $

million of commercial paper

outstanding and

no

direct borrowings or letters of credit,

we had access to $

5.7

billion in available borrowing

capacity under our revolving credit facility

at December 31, 2020.

We had

no

direct borrowings, letters of

credit, nor outstanding commercial paper as

of December 31, 2019.

At both December 31, 2020 and 2019, we had

$

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.

For information on Finance Leases, see Note 16—Non-Mineral

Leases.

On January 15, 2021, we completed the acquisition

of Concho in an all-stock transaction.

In the acquisition,

we assumed Concho’s publicly traded debt, which was recorded at fair value

of $

4.7

billion on the acquisition

date. On December 7, 2020, we launched a debt

exchange offer which settled on February 8, 2021.

Of the

approximately $

3.9

billion in aggregate principal amount of Concho’s notes subject to

the exchange offer,

percent, or approximately $

3.8

billion, was tendered and exchanged for new

debt issued by ConocoPhillips.

The new debt received in the exchange is fully

and unconditionally guaranteed by ConocoPhillips

Company.

In conjunction with the exchange offer, Concho successfully solicited

consents to amend each of the

indentures governing the Concho notes to eliminate

certain covenants, restrictive provisions, events

of default

and the requirements for certain Concho subsidiaries

to make future guarantees.

For additional information on

the acquisition see Note 25—Acquisition of Concho

Resources Inc.

Note 11—Guarantees

At December 31, 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 December 31, 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 December

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 to be

10 years

.

Our maximum exposure under this guarantee is

approximately $

million

and may become payable if an enforcement action

is commenced by the project finance lenders

against APLNG.

At December 31, 2020, the carrying value

of this guarantee is approximately $

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 21 years

.

Our maximum potential liability for future

payments, or cost of volume delivery, under these guarantees is estimated to

be $

million ($

1.4

billion in the event of intentional or reckless breach)

and would become payable if APLNG fails

to

meet its obligations under these agreements and

the obligations cannot otherwise be mitigated.

Future

payments are considered unlikely, as the payments, or cost of volume delivery, would only be

triggered if APLNG does not have enough natural

gas to meet these sales commitments and if

the co-

venturers do not make necessary equity contributions

into APLNG.

●

We have guaranteed the performance of APLNG with regard to certain other contracts

executed in

connection with the project’s continued development.

The guarantees have remaining terms

of

16 to

25 years or the life of the venture

.

Our maximum potential amount of future payments

related to these

guarantees is approximately $

million and would become payable if APLNG

does not perform.

At

December 31, 2020, the carrying value of these

guarantees was approximately $

million.

Other Guarantees

We have other guarantees with maximum future potential payment amounts totaling

approximately

$

million, which consist primarily of

guarantees of the residual value of leased office buildings,

guarantees

of the residual value of corporate aircraft,

and a guarantee for our portion of a joint venture’s project finance

reserve accounts.

These guarantees have remaining terms

of one to

six 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 December 31, 2020, the carrying value of these

guarantees was approximately $

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.

Most 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 indemnifications at December 31, 2020, was

approximately $

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.

See Note 18—Income Taxes, for additional information about income tax-

related contingencies.

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.

In the future, we may be involved in additional

environmental assessments, cleanups and proceedings.

See Note 9—Asset Retirement Obligations and

Accrued Environmental Costs, for a summary of our

accrued environmental liabilities.

Litigation and Other Contingencies

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.

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 December 31, 2020,

we had performance obligations secured by

letters of credit of

$

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 $

million.

The award now stands

at $

8.5

billion plus interest.

The government of Venezuela sought annulment of the award before ICSID, and

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 $

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 $

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 $

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, governmental 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

$

million, and 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 is challenging this order.

Long-Term Throughput Agreements and Take

-or-Pay Agreements

We have certain throughput agreements and take-or-pay agreements in support of financing arrangements.

The agreements typically provide for natural gas

or crude oil transportation to be used in

the ordinary course of

the company’s business.

The aggregate amounts of estimated payments

under these various agreements are:

2021—$

million; 2022—$

million; 2023—$

million; 2024—$

million; 2025—$

million; and 2026 and

after—$

million.

Total payments under the agreements were $

million in 2020, $

million in 2019 and

$

million in 2018.

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 apply 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

2020

2019

Assets

Prepaid expenses and other current assets

$

Other assets

Liabilities

Other accruals

Other liabilities and deferred credits

The gains (losses) from commodity derivatives

incurred, and the line items where they appear

on our

consolidated income statement were:

Millions of Dollars

2020

2019

2018

Sales and other operating revenues

$

Other income (loss)

Purchased commodities

(118)

(41)

The table below summarizes our material net exposures

resulting from outstanding commodity

derivative

contracts:

Open Position

Long/(Short)

2020

2019

Commodity

Natural gas and power (billions of cubic feet equivalent)

Fixed price

(20)

(5)

Basis

(10)

(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

apply hedge accounting to 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

2020

2019

Assets

Prepaid expenses and other current assets

$

Liabilities

Other accruals

Other liabilities and deferred credits

-

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

2020

2019

2018

Foreign currency transaction (gains) losses

$

(40)

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

derivatives:

In Millions

Notional Currency

2020

2019

Foreign Currency Exchange Derivatives

Buy British pound, sell euro

GBP

-

Sell British pound, buy euro

GBP

-

Sell Canadian dollar, buy U.S. dollar

CAD

1,337

At December 31, 2020, we had outstanding foreign currency exchange forward contracts to sell $0.45 billion

CAD at $0.748 CAD against the U.S. dollar. At December 31, 2019, we had outstanding foreign currency

exchange forward contracts to sell $1.35 billion CAD at $0.748 CAD against the U.S. dollar

.

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 and the

table reflects remaining maturities at December

31, 2020 and 2019:

Millions of Dollars

Carrying Amount

Cash and Cash

Equivalents

Short-Term

Investments

Investments and Long-

Term Receivables

2020

2019

2020

2019

2020

2019

Cash

$

Demand Deposits

1,133

1,483

Time Deposits

1 to 90 days

1,225

2,030

2,859

1,395

91 to 180 days

Within one year

-

One year through five years

-

Commercial Paper

1 to 90 days

-

-

1,069

U.S. Government Obligations

1 to 90 days

-

-

$

2,978

5,079

3,320

2,929

-

The following investments in debt securities

classified as available for sale are carried on our

consolidated

balance sheet at fair value as of December 31,

2020 and 2019:

Millions of Dollars

Carrying Amount

Cash and Cash

Equivalents

Short-Term

Investments

Investments and Long-

Term Receivables

2020

2019

2020

2019

2020

2019

Major Security Type

Corporate Bonds

$

-

Commercial Paper

U.S. Government Obligations

-

-

U.S. Government Agency

Obligations

-

Foreign Government Obligations

-

Asset-backed Securities

-

-

$

Cash and Cash Equivalents and Short-Term Investments have remaining maturities

within one year.

Investments and Long-Term Receivables have remaining maturities

greater than one year through five years.

The following table summarizes the amortized

cost basis and fair value of investments in

debt securities

classified as available for sale:

Millions of Dollars

Amortized Cost Basis

Fair Value

2020

2019

2020

2019

Major Security Type

Corporate bonds

$

Commercial paper

U.S. government obligations

U.S. government agency obligations

-

-

Foreign government obligations

-

-

Asset-backed securities

$

As of December 31, 2020 and December 31, 2019,

total unrealized losses for debt securities

classified as

available for sale with net losses were negligible.

Additionally, as of December 31, 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 year ended December 31, 2020, proceeds

from sales and redemptions of investments

in debt securities

classified as available for sale were $

million.

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 primarily 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.

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 December 31, 2020 and

December 31, 2019, was $

million and $

million,

respectively.

For these instruments,

no collateral

was posted as of December 31, 2020 or December

31, 2019.

If our credit rating had been downgraded below

investment grade on December 31, 2020,

we would have been

required to post $

million of additional collateral, either with

cash or letters of credit.

Note 14—Fair Value Measurement

We carry a portion of our assets and liabilities at fair value that are measured at 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 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

December 31, 2020

December 31, 2019

Level 1

Level 2

Level 3

Total

Level 1

Level 2

Level 3

Total

Assets

Investment in Cenovus Energy

$

1,256

-

-

1,256

2,111

-

-

2,111

Investments in debt securities

-

-

Commodity derivatives

Total assets

$

1,415

2,029

2,308

2,674

Liabilities

Commodity derivatives

$

Total liabilities

$

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

December 31, 2020

Assets

$

Liabilities

December 31, 2019

Assets

$

Liabilities

At December 31, 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 Measurements Using

Fair Value

Level 1

Inputs

Level 2

Inputs

Level 3

Inputs

Before-Tax

Loss

Year

ended December 31, 2020

Net PP&E (held for use)

March 31, 2020

$

-

-

December 31, 2020

-

-

Year

ended December 31, 2019

Net PP&E (held for sale)

November 30, 2019

$

-

-

December 31, 2019

-

-

Equity Method Investments

March 31, 2019

-

-

May 31, 2019

-

-

Net PP&E (held for use)

During 2020, the estimated fair value of certain

non-core assets included in our Lower

48 segment declined to

amounts below the carrying values.

The carrying values were written down to fair

value.

The fair values were

estimated based on internal discounted cash flow models

using the following estimated assumptions: estimated

future production, an outlook of future prices from

a combination of exchanges (short-term)

coupled with

pricing service companies and our internal outlook

(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 measurements

for

significant assets were as follows:

Fair Value

(Millions of

Dollars)

Valuation

Technique

Unobservable Inputs

Range

(Arithmetic Average)

March 31, 2020

Wind River Basin

$

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 a combination of 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.

Fair Value

(Millions of

Dollars)

Valuation

Technique

Unobservable Inputs

Range

(Arithmetic Average)

December 31, 2020

Central Basin Platform

$

Discounted cash

flow

Commodity production

(MBOED)

0.5

-

12.7

(

3.4

)

Commodity price outlook*

($/BOE)

$

37.35

- $

115.29

($

73.80

)

Discount rate**

6.8

%

-

7.7

% (

7.4

%)

*Commodity price outlook based on a combination of external pricing

service companies' and our internal outlook for years

2023-2050; future prices escalated at

2.0% annually after year 2050.

**Determined as the weighted average cost of capital of a group

of peer companies, adjusted for risks where

appropriate.

Net PP&E (held for sale)

Net PP&E held for sale was written down to fair

value, less costs to sell.

The fair value of the assets were

determined by their negotiated selling prices

(Level 1).

For additional information see Note 4—Asset

Acquisitions and Dispositions.

Equity Method Investments

During 2019, certain equity method investments

were determined to have fair values below their

carrying

amounts, and the impairments were considered to

be other than temporary under the guidance

of FASB ASC

Topic 323.

Investments using Level 1 inputs were

written down to fair value, less costs to

sell, determined by

negotiated selling prices.

For additional information, see Note 4—Asset

Acquisitions and Dispositions and

Note 5—Investments, Loans and Long-Term Receivables.

An investment using Level 2 inputs was

determined to have a fair value below its

carrying value, and was written down to fair

value.

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 10—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

2020

2019

2020

2019

Financial assets

Investment in Cenovus Energy

$

1,256

2,111

1,256

2,111

Commodity derivatives

Investments in debt securities

Loans and advances—related parties

Financial liabilities

Total debt, excluding finance leases

14,478

14,175

19,106

18,108

Commodity derivatives

Commodity Derivatives

At December 31, 2020, commodity derivative

assets and liabilities are presented net with $

million in

obligations to return cash collateral and $

million of rights to reclaim cash collateral,

respectively.

At

December 31, 2019, commodity derivative assets

and liabilities are presented net with $

million in

obligations to return cash collateral and $

million of rights to reclaim cash collateral,

respectively.

Note 15—Equity

Common Stock

The changes in our shares of common stock, as categorized

in the equity section of the balance sheet, were:

Shares

2020

2019

2018

Issued

Beginning of year

1,795,652,203

1,791,637,434

1,785,419,175

Distributed under benefit plans

3,192,064

4,014,769

6,218,259

End of year

1,798,844,267

1,795,652,203

1,791,637,434

Held in Treasury

Beginning of year

710,783,814

653,288,213

608,312,034

Repurchase of common stock

20,018,275

57,495,601

44,976,179

End of year

730,802,089

710,783,814

653,288,213

Preferred Stock

We have authorized

million shares of preferred stock, par value

$

0.01

per share,

none

of which was issued

or outstanding at December 31, 2020 or 2019.

Noncontrolling Interests

In the second quarter of 2020, we completed the

divestiture of our subsidiaries that held our Australia-West

assets and operations.

These assets included the Darwin LNG and

Bayu-Darwin Pipeline operating joint

ventures in which there was a noncontrolling

interest. As a result, as of December 31,

2020, we had no

noncontrolling interests.

At December 31, 2019, we had $

million of equity outstanding in the same joint

ventures.

Repurchase of Common Stock

In late 2016, we initiated our current share repurchase

program, which has a current total program

authorization of $

billion of our common stock.

Cost of share repurchases were $

million, $

3,500

million, $

2,999

million in 2020, 2019 and 2018, respectively.

Share repurchases were suspended in the second

and third quarters of 2020 in response to the economic

downturn.

In the fourth quarter of 2020, we resumed

share repurchases, repurchasing $

0.2

billion of shares in October, until suspending further repurchases

upon

entry into a definitive agreement to acquire Concho.

In February 2021, we resumed share repurchases

following our Concho acquisition.

Share repurchases since inception of our current

program totaled

million shares at a cost of $

10,517

million, as of December 31, 2020.

Note 16—Non-Mineral Leases

The company primarily leases office buildings and drilling

equipment, as well as ocean transport vessels,

tugboats, corporate aircraft, and other facilities

and equipment.

Certain leases include escalation clauses for

adjusting rental payments to reflect changes in price

indices and other leases include payment provisions

that

vary based on the nature of usage of the leased

asset.

Additionally, the company has executed certain leases

that provide it with the option to extend or renew

the term of the lease, terminate the lease

prior to the end of

the lease term, or purchase the leased asset as

of the end of the lease term.

In other cases, the company has

executed lease agreements that require it to

guarantee the residual value of certain leased office buildings.

For

additional information about guarantees, see

Note 11—Guarantees.

There are no significant restrictions

imposed on us by the lease agreements with regard

to dividends, asset dispositions or borrowing

ability.

Certain arrangements may contain both lease and

non-lease components and we determine

if an arrangement is

or contains a lease at contract inception.

We adopted the provisions of FASB ASU No. 2016-02, “Leases”

(ASC Topic 842) and its amendments, beginning January 1, 2019.

This ASU superseded the requirements in

FASB ASC Topic

840 “Leases” (ASC Topic 840).

Only the lease components of these contractual

arrangements are subject to the provisions of

ASC Topic 842, and any non-lease components are subject to

other applicable accounting guidance; however,

we have elected to adopt the optional practical expedient not

to separate lease components apart from non-lease components for accounting purposes.

This policy election

has been adopted for each of the company’s leased asset classes existing

as of the effective date and subject to

the transition provisions of ASC Topic 842 and will be applied to all new or

modified leases executed on or

after January 1, 2019.

For contractual arrangements executed in subsequent

periods involving a new leased

asset class, the company will determine at

contract inception whether it will apply the

optional practical

expedient to the new leased asset class.

Leases are evaluated for classification as operating

or finance leases at the commencement date of the

lease

and right-of-use assets and corresponding liabilities

are recognized on our consolidated balance sheet

based on

the present value of future lease payments relating

to the use of the underlying asset during the

lease term.

Future lease payments include variable lease payments

that depend upon an index or rate using

the index or

rate at the commencement date and probable

amounts owed under residual value guarantees.

The amount of

future lease payments may be increased to include

additional payments related to lease extension, termination,

and/or purchase options when the company has

determined, at or subsequent to lease commencement,

generally due to limited asset availability

or operating commitments, it is reasonably

certain of exercising such

options.

We use our incremental borrowing rate as the discount rate in determining the

present value of future

lease payments, unless the interest rate

implicit in the lease arrangement is readily determinable.

Lease

payments that vary subsequent to the commencement

date based on future usage levels, the nature

of leased

asset activities, or certain other contingencies are

not included in the measurement of lease

right-of-use assets

and corresponding liabilities.

We have elected not to record assets and liabilities on our consolidated balance

sheet for lease arrangements with terms of 12 months

or less.

We often enter into leasing arrangements acting in the capacity as operator for and/or

on behalf of certain oil

and gas joint ventures of undivided interests.

If the lease arrangement can be legally enforced only

against us

as operator and there is no separate arrangement to

sublease the underlying leased asset

to our coventurers, we

recognize at lease commencement a right-of-use

asset and corresponding lease liability on our

consolidated

balance sheet on a gross basis.

While we record lease costs on a gross basis in

our consolidated income

statement and statement of cash flows, such costs

are offset by the reimbursement we receive from our

coventurers for their share of the lease cost as the underlying

leased asset is utilized in joint venture activities.

As a result, lease cost is presented in our consolidated

income statement and statement of cash flows

on a

proportional basis.

If we are a nonoperating coventurer, we recognize a right-of-use

asset and corresponding

lease liability only if we were a specified contractual

party to the lease arrangement and the arrangement

could

be legally enforced against us.

In this circumstance, we would recognize both

the right-of-use asset and

corresponding lease liability on our consolidated

balance sheet on a proportional basis

consistent with our

undivided interest ownership in the related joint

venture.

The company has historically recorded certain

finance leases executed by investee companies

accounted for

under the proportionate consolidation method of

accounting on its consolidated balance sheet

on a proportional

basis consistent with its ownership interest

in the investee company.

In addition, the company has historically

recorded finance lease assets and liabilities

associated with certain oil and gas joint ventures

on a proportional

basis pursuant to accounting guidance applicable

prior to January 1, 2019.

In accordance with the transition

provisions of ASC Topic 842, and since we have elected to adopt the package

of optional transition-related

practical expedients, the historical accounting treatment

for these leases has been carried forward

and is subject

to reconsideration upon the modification or

other required reassessment of the arrangements

prior to lease term

expiration.

The following table summarizes

the right-of-use assets and lease liabilities

for both the operating and finance

leases on our consolidated balance sheet as of December

31:

Millions of Dollars

2020

2019

Operating

Leases

Finance

Leases

Operating

Leases

Finance

Leases

Right-of-Use Assets

Properties, plants and equipment

Gross

$

1,375

1,039

Accumulated DD&A

(721)

(649)

Net PP&E

Prepaid expenses and other current assets

$

-

Other assets

Lease Liabilities

Short-term debt

**

$

Other accruals

Long-term debt

---

Other liabilities and deferred credits

Total lease liabilities

$

Includes proportionately consolidated finance lease assets of $

million at December 31, 2020 and $

million at December 31, 2019.

** Includes proportionately consolidated finance lease liabilities of

$

million at December 31, 2020 and $

million at December 31, 2019.

*** Includes proportionately consolidated finance lease liabilities of $

million at December 31, 2020 and $

million at December 31,

The following table summarizes our lease costs

for 2020 and 2019:

Millions of Dollars

2020

2019

Lease Cost

Operating lease cost

$

Finance lease cost

Amortization of right-of-use assets

Interest on lease liabilities

Short-term lease cost

**

Total lease cost

---

$

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

** Short-term leases are not recorded on our consolidated balance sheet.

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

.

The following table summarizes the lease terms

and discount rates as of December 31:

2020

2019

Lease Term and Discount Rate

Weighted-average term (years)

Operating leases

6.11

5.19

Finance leases

7.12

8.70

Weighted-average discount rate (percent)

Operating leases

2.78

3.10

Finance leases

4.27

5.53

The following table summarizes other lease information

for 2020 and 2019:

Millions of Dollars

2020

2019

Other Information

Cash paid for amounts included in the measurement

of lease liabilities

Operating cash flows from operating leases

$

Operating cash flows from finance leases

Financing cash flows from finance leases

Right-of-use assets obtained in exchange for

operating lease liabilities

$

Right-of-use assets obtained in exchange for

finance lease liabilities

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

In

addition, pursuant to other applicable accounting guidance, lease

payments made in connection with preparing another asset for its intended use

are reported in the "Cash Flows From Investing Activities" section of our consolidated statement of cash flows.

The following table summarizes future lease

payments for operating and finance leases

at December 31, 2020:

Millions of Dollars

Operating

Leases

Finance

Leases

Maturity of Lease Liabilities

2021

$

2022

2023

2024

2025

Remaining years

Total

1,043

Less: portion representing imputed interest

(80)

(152)

Total lease liabilities

$

*Future lease payments for operating and finance leases commencing on or

after January 1, 2019, also include payments related to non-lease

components in accordance with our election to adopt the optional practical

expedient not to separate lease components apart from non-lease

components for accounting purposes.

In addition, future payments related to operating and finance leases proportionately consolidated by the

company have been included in the table on a proportionate basis consistent

with our respective ownership interest in the underlying investee

company or oil and gas venture.

For the year ended December 31, 2018 operating

lease rental expense pursuant to ASC Topic 840 was:

Millions of Dollars

Total rentals

$

Less: sublease rentals

(16)

$

Note 17—Employee Benefit Plans

Pension and Postretirement Plans

An analysis of the projected benefit obligations

for our pension plans and accumulated benefit

obligations for

our postretirement health and life insurance plans

follows:

Millions of Dollars

Pension Benefits

Other Benefits

2020

2019

2020

2019

U.S.

Int’l.

U.S.

Int’l.

Change in Benefit Obligation

Benefit obligation at January 1

$

2,319

3,880

2,136

3,438

Service cost

Interest cost

Plan participant contributions

-

-

Plan amendments

-

-

-

(30)

-

Actuarial loss

Benefits paid

(241)

(151)

(253)

(147)

(49)

(59)

Curtailment

-

-

(69)

-

-

Recognition of termination benefits

-

-

-

-

Foreign currency exchange rate change

-

-

-

Benefit obligation at December 31

$

2,548

4,403

2,319

3,880

*Accumulated benefit obligation portion of above at

December 31:

$

2,359

4,095

2,161

3,594

Change in Fair Value of Plan Assets

Fair value of plan assets at January 1

$

1,591

4,306

1,336

3,358

-

-

Actual return on plan assets

-

-

Company contributions

Plan participant contributions

-

-

Benefits paid

(241)

(151)

(253)

(147)

(49)

(59)

Foreign currency exchange rate change

-

-

-

-

Fair value of plan assets at December 31

$

1,770

4,793

1,591

4,306

-

-

Funded Status

$

(778)

(728)

(170)

(216)

Millions of Dollars

Pension Benefits

Other Benefits

2020

2019

2020

2019

U.S.

Int’l.

U.S.

Int’l.

Amounts Recognized in the

Consolidated Balance Sheet at

December 31

Noncurrent assets

$

-

-

-

-

Current liabilities

(56)

(11)

(21)

(6)

(39)

(42)

Noncurrent liabilities

(722)

(345)

(707)

(333)

(131)

(174)

Total recognized

$

(778)

(728)

(170)

(216)

Weighted-Average Assumptions Used to

Determine Benefit Obligations at

December 31

Discount rate

2.30

%

1.80

3.25

2.35

2.15

3.10

Rate of compensation increase

4.00

3.10

4.00

3.35

Interest crediting rate for applicable benefits

2.10

-

4.10

-

Weighted-Average Assumptions Used to

Determine Net Periodic Benefit Cost for

Years

Ended December 31

Discount rate

3.05

%

2.35

3.95

2.90

3.10

4.05

Expected return on plan assets

5.80

3.60

5.80

4.10

Rate of compensation increase

4.00

3.35

4.00

3.65

Interest crediting rate for applicable benefits

4.10

-

4.35

-

For both U.S. and international pensions, the

overall expected long-term rate of return is

developed from the

expected future return of each asset class, weighted

by the expected allocation of pension assets

to that asset

class.

We rely on a variety of independent market forecasts in developing the expected

rate of return for each

class of assets.

The following tables set forth information related

to the Company’s pension plans with projected and

accumulated benefit obligations in excess of

the fair value of the plans’ assets as of December

31, 2020 and

2019:

Millions of Dollars

Pension Benefits

2020

2019

U.S.

Int’l.

U.S.

Int’l.

Pension Plans with Projected Benefit Obligation in

Excess of Plan Assets

Projected benefit obligation

$

2,548

2,319

Fair value of plan assets

1,770

1,591

Pension Plans with Accumulated Benefit

Obligation in

Excess of Plan Assets

Accumulated benefit obligation

$

2,359

2,161

Fair value of plan assets

1,770

1,591

Included in accumulated other comprehensive

income (loss) at December 31 were the following

before-tax

amounts that had not been recognized in net

periodic benefit cost:

Millions of Dollars

Pension Benefits

Other Benefits

2020

2019

2020

2019

U.S.

Int’l.

U.S.

Int’l.

Unrecognized net actuarial loss

$

Unrecognized prior service credit

-

-

-

(2)

(182)

(183)

Millions of Dollars

Pension Benefits

Other Benefits

2020

2019

2020

2019

U.S.

Int’l.

U.S.

Int’l.

Sources of Change in Other

Comprehensive Income (Loss)

Net gain (loss) arising during the period

$

(83)

(120)

(79)

(7)

(27)

Amortization of actuarial (gain) loss included

in income (loss)*

(2)

Net change during the period

$

(99)

(6)

(29)

Prior service credit (cost) arising during the

period

$

-

(1)

-

-

-

Amortization of prior service cost (credit)

included in income (loss)

-

(1)

-

(2)

(31)

(33)

Net change during the period

$

-

(2)

-

(2)

(1)

(33)

*Includes settlement (gains) losses recognized in 2020 and 2019.

The components of net periodic benefit cost of

all defined benefit plans are presented in

the following table:

Millions of Dollars

Pension Benefits

Other Benefits

2020

2019

2018

2020

2019

2018

U.S.

Int’l.

U.S.

Int’l.

U.S.

Int’l.

Components of Net

Periodic Benefit Cost

Service cost

$

Interest cost

Expected return on plan

assets

(85)

(145)

(74)

(138)

(114)

(155)

-

-

-

Amortization of prior

service credit

-

(1)

-

(2)

-

(5)

(31)

(33)

(35)

Recognized net actuarial

loss (gain)

(2)

(1)

Settlements loss (gain)

(1)

-

-

-

-

-

Net periodic benefit cost

$

(22)

(26)

(27)

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.

We recognized pension settlement losses of $

million in 2020, $

million in 2019, and $

million in

2018 as lump-sum benefit payments from certain

U.S. and international pension plans exceeded the sum

of

service and interest costs for those plans and led

to recognition of settlement losses.

During 2020 and 2019, the actuarial losses

related to the benefit obligation for U.S. and international

plans

were primarily related to a decrease in the discount

rates.

The sale of two ConocoPhillips U.K. subsidiaries

completed during the third quarter of 2019 led

to a

significant reduction of future services of active

employees in certain international pension

plans, resulting in a

curtailment.

In conjunction with the recognition of the curtailment,

the fair market values of pension plan

assets were updated, the pension benefit obligation

was remeasured, and the net pension asset

decreased by

$

million, resulting in a corresponding decrease

to other comprehensive income.

This is primarily a result of

a decrease in the discount rate from

2.90

percent at December 31, 2018 to

1.80

percent at September 30, 2019

offset by a decrease in the pension benefit obligation from

curtailment.

In determining net pension and other postretirement

benefit costs, we amortize prior service costs

on a straight-

line basis over the average remaining service period

of employees expected to receive benefits

under the plan.

For net actuarial gains and losses, we amortize

percent of the unamortized balance each year.

We have multiple nonpension postretirement benefit plans for health and life insurance.

The health care plans

are contributory and subject to various cost sharing

features, with participant and company contributions

adjusted annually; the life insurance plans are

noncontributory.

The measurement of the U.S. pre-65 retiree

medical accumulated postretirement benefit

obligation assumes a health care cost trend rate

of

percent in

2021 that declines to

percent by 2028.

The measurement of the U.S. post-65 retiree

medical accumulated

postretirement benefit obligation assumes an ultimate

health care cost trend rate of

percent achieved in 2021

that increases to

percent by 2028.

Plan Assets

—We follow a policy of broadly diversifying pension plan assets across asset

classes and

individual holdings.

As a result, our plan assets have no significant

concentrations of credit risk.

Asset classes

that are considered appropriate include U.S. equities,

non-U.S. equities, U.S. fixed income, non-U.S. fixed

income, real estate and private equity investments.

Plan fiduciaries may consider and add other

asset classes to

the investment program from time to time.

The target allocations for plan assets are

percent equity

securities,

percent debt securities,

percent real estate and

percent other.

Generally, the plan investments

are publicly traded, therefore minimizing liquidity

risk in the portfolio.

The following is a description of the valuation methodologies

used for the pension plan assets.

There have

been no changes in the methodologies used at

December 31, 2020 and 2019.

●

Fair values of equity securities and government

debt securities categorized in Level 1 are primarily

based on quoted market prices in active markets

for identical assets and liabilities.

●

Fair values of corporate debt securities, agency and

mortgage-backed securities and government

debt

securities categorized in Level 2 are estimated

using recently executed transactions and quoted market

prices for similar assets and liabilities in

active markets and for identical assets and liabilities

in

markets that are not active.

If there have been no market transactions

in a particular fixed income

security, its fair value is calculated by pricing models that benchmark the security

against other

securities with actual market prices.

When observable quoted market prices are not

available, fair

value is based on pricing models that use something

other than actual market prices (e.g., observable

inputs such as benchmark yields, reported trades and

issuer spreads for similar securities), and these

securities are categorized in Level 3 of the fair

value hierarchy.

●

Fair values of investments in common/collective

trusts are determined by the issuer of each fund

based on the fair value of the underlying assets.

●

Fair values of mutual funds are based on quoted

market prices, which represent the net asset

value of

shares held.

●

Time deposits are valued at cost, which approximates fair

value.

●

Cash is valued at cost, which approximates fair

value.

Fair values of international cash equivalents

categorized in Level 2 are valued using observable

yield curves, discounting and interest

rates.

U.S.

cash balances held in the form of short-term

fund units that are redeemable at the measurement

date

are categorized as Level 2.

●

Fair values of exchange-traded derivatives classified

in Level 1 are based on quoted market prices.

For other derivatives classified in Level 2, the values

are generally calculated from pricing models

with market input parameters from third-party

sources.

●

Fair values of insurance contracts are valued at the

present value of the future benefit payments owed

by the insurance company to the plans’ participants.

●

Fair values of real estate investments are valued

using real estate valuation techniques

and other

methods that include reference to third-party sources

and sales comparables where available.

●

A portion of U.S. pension plan assets is held as

a participating interest in an insurance annuity

contract, which is calculated as the market value

of investments held under this contract, less

the

accumulated benefit obligation covered by the

contract.

The participating interest is classified as

Level 3 in the fair value hierarchy as the fair value

is determined via a combination of quoted

market

prices, recently executed transactions, and

an actuarial present value computation for

contract

obligations.

At December 31, 2020,

the participating interest in the annuity contract

was valued at

$

million and consisted of $

million in debt securities, less $

million for the accumulated

benefit obligation covered by the contract.

At December 31, 2019, the participating interest

in the

annuity contract was valued at $

million and consisted of $

million in debt securities, less

$

million for the accumulated benefit obligation

covered by the contract.

The participating interest is

not available for meeting general pension benefit

obligations in the near term.

No future company

contributions are required and no new benefits

are being accrued under this insurance annuity

contract.

The fair values of our pension plan assets at

December 31, by asset class were as follows:

Millions of Dollars

U.S.

International

Level 1

Level 2

Level 3

Total

Level 1

Level 2

Level 3

Total

2020

Equity securities

U.S.

$

-

-

-

-

-

International

-

-

-

-

-

-

Mutual funds

-

-

-

Debt securities

Corporate

-

-

-

-

-

-

Mutual funds

-

-

-

-

-

-

Cash and cash equivalents

-

-

-

-

-

-

Derivatives

-

-

-

-

-

-

Real estate

-

-

-

-

-

-

Total in fair value hierarchy

$

1,646

Investments measured at net asset value*

Equity securities

Common/collective trusts

$

2,962

Debt securities

Common/collective trusts

Cash and cash equivalents

-

Real estate

Total**

$

1,675

4,787

*In accordance with FASB ASC Topic

715, “Compensation—Retirement Benefits,” certain investments that are to be measured at fair value

using the net asset value per share (or its equivalent) practical expedient

have not been classified in the fair value hierarchy.

The fair value

amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the Change in

Fair Value of Plan Assets.

**Excludes the participating interest in the insurance annuity contract with a net

asset of $

million and net receivables related to security

transactions of $

million.

The fair values of our pension plan assets at

December 31, by asset class were as follows:

Millions of Dollars

U.S.

International

Level 1

Level 2

Level 3

Total

Level 1

Level 2

Level 3

Total

2019

Equity securities

U.S.

$

-

-

-

International

-

-

-

-

Mutual funds

-

-

-

Debt securities

Government

-

-

-

-

1,412

-

-

1,412

Corporate

-

-

-

-

-

-

Mutual funds

-

-

-

-

-

-

Cash and cash equivalents

-

-

-

-

-

-

Derivatives

-

-

-

-

-

-

Real estate

-

-

-

-

-

-

Total in fair value hierarchy

$

2,859

3,258

Investments measured at net asset value*

Equity securities

Common/collective trusts

$

Debt securities

Common/collective trusts

Cash and cash equivalents

-

Real estate

Total**

$

1,496

2,859

4,297

*In accordance with FASB ASC Topic

715, “Compensation—Retirement Benefits,” certain investments that are to be measured at fair value

using the net asset value per share (or its equivalent) practical expedient

have not been classified in the fair value hierarchy.

The fair value

amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the Change in

Fair Value of Plan Assets.

**Excludes the participating interest in the insurance annuity contract with a

net asset of $

million and net receivables related to security

transactions of $

million.

Level 3 activity was not material for all

periods.

Our funding policy for U.S. plans is to contribute

at least the minimum required by the Employee

Retirement

Income Security Act of 1974 and the Internal

Revenue Code of 1986, as amended.

Contributions to foreign

plans are dependent upon local laws and tax regulations.

In 2021, we expect to contribute approximately $

million to our domestic qualified and nonqualified

pension and postretirement benefit plans and $

million to

our international qualified and nonqualified

pension and postretirement benefit plans.

The following benefit payments, which are exclusive

of amounts to be paid from the insurance annuity

contract

and which reflect expected future service, as appropriate,

are expected to be paid:

Millions of Dollars

Pension

Other

Benefits

Benefits

U.S.

Int’l.

2021

$

2022

2023

2024

2025

2026–2030

Severance Accrual

The following table summarizes our severance accrual

activity for 2020, 2019 and 2018:

Millions of Dollars

2020

2019

2018

Balance at January 1

$

Accruals

(1)

Benefit payments

(13)

(24)

(73)

Foreign currency translation adjustments

-

-

(2)

Balance at December 31

$

Of the remaining balance at December 31, 2020,

$

million is classified as short-term.

Defined Contribution Plans

Most U.S. employees are eligible to participate

in the ConocoPhillips Savings Plan (CPSP).

Employees can

deposit up to

percent of their eligible pay, subject to statutory limits, in the CPSP to

a choice of

approximately

investment options.

Employees who participate in the CPSP and contribute

percent of

their eligible pay receive a

percent company cash match with a potential

company discretionary cash

contribution of up to

percent.

Effective January 1, 2019, new employees, rehires, and

employees that elected

to opt out of Title II are eligible to receive a Company Retirement

Contribution (CRC) of

percent of eligible

pay into their CPSP.

After

three years

of service with the company, the employee is

percent vested in any

CRC.

Company contributions charged to expense for the

CPSP and predecessor plans were $

million in

2020, $

million in 2019, and $

million in 2018.

We have several defined contribution plans for our international employees, each

with its own terms and

eligibility depending on location.

Total compensation expense recognized for these international plans was

approximately $

million in 2020, $

million in 2019, and $

million in 2018.

Share-Based Compensation Plans

The 2014 Omnibus Stock and Performance Incentive

Plan of ConocoPhillips (the Plan) was approved

by

shareholders in May 2014.

Over its

-year life, the Plan allows the issuance of

up to

million shares of our

common stock for compensation to our employees

and directors; however, as of the effective date of the Plan,

(i) any shares of common stock available for future

awards under the prior plans and (ii)

any shares of common

stock represented by awards granted under the prior

plans that are forfeited, expire or are cancelled

without

delivery of shares of common stock or which result

in the forfeiture of shares of common stock

back to the

company shall be available for awards under the

Plan, and no new awards shall be granted

under the prior

plans.

Of the

million shares available for issuance

under the Plan, no more than

million shares of

common stock are available for incentive stock

options.

The Human Resources and Compensation Committee

of our Board of Directors is authorized to determine

the types, terms, conditions and limitations

of awards

granted.

Awards may be granted in the form of, but not limited to, stock options, restricted stock units

and

performance share units to employees and non-employee

directors who contribute to the company’s continued

success and profitability.

Total share-based compensation expense is measured using the grant date fair value

for our equity-classified

awards and the settlement date fair value for our

liability-classified awards.

We recognize share-based

compensation expense over the shorter of the service

period (i.e., the stated period of time required

to earn the

award); or the period beginning at the start of the

service period and ending when an employee

first becomes

eligible for retirement, but not less than six months,

as this is the minimum period of time

required for an

award to not be subject to forfeiture.

Our share-based compensation programs generally

provide accelerated

vesting (i.e., a waiver of the remaining period of service

required to earn an award) for awards held

by

employees at the time of their retirement.

Some of our share-based awards vest ratably (i.e., portions

of the

award vest at different times) while some of our awards

cliff vest (i.e., all of the award vests at the same time).

We recognize expense on a straight-line basis over the service period for the entire

award, whether the award

was granted with ratable or cliff vesting.

Compensation Expense

—Total share-based compensation expense recognized in net income (loss) and the

associated tax benefit for the years ended

December 31 were as follows:

Millions of Dollars

2020

2019

2018

Compensation cost

$

Tax benefit

Stock Options

—

Stock options granted under the provisions of the Plan and prior plans permit purchase of our

common stock at exercise prices equivalent to the average fair market value of ConocoPhillips common stock

on the date the options were granted. The options have terms of 10 years and generally vest ratably, with one-

third of the options awarded vesting and becoming exercisable on each anniversary date following the date of

grant. Options awarded to certain employees already eligible for retirement vest within six months of the grant

date, but those options do not become exercisable until the end of the normal vesting period. Beginning in

2018, stock option grants were discontinued and replaced with three-year, time-vested restricted stock units

which generally will be cash-settled

for 2018 and 2019 awards and stock-settled for 2020

awards.

The following summarizes our stock option activity

for the year ended December 31, 2020:

Millions of Dollars

Weighted-Average

Aggregate

Options

Exercise Price

Intrinsic Value

Outstanding at December 31, 2019

18,040,197

$

54.11

$

Exercised

(1,111,805)

38.80

Forfeited

(5,867)

49.76

Expired or cancelled

-

Outstanding at December 31, 2020

16,922,525

$

55.12

$

Vested at December 31, 2020

16,922,525

$

55.12

$

Exercisable at December 31, 2020

16,922,525

$

55.12

$

The weighted-average remaining contractual term

of outstanding options, vested options and exercisable

options at December 31, 2020, were all

3.66

years.

The aggregate intrinsic value of options exercised

was $

million in 2019 and $

million in 2018.

During 2020, we received $

million in cash and realized a tax benefit

of $

million from the exercise of

options.

At December 31, 2020, all outstanding stock

options were fully vested and there was no remaining

compensation cost to be recorded.

Stock Unit Program—

Generally, restricted stock units are granted annually under the provisions of the Plan

and vest in an aggregate installment on the third anniversary of the grant date. In addition, restricted stock

units granted under the Plan for a variable long-term incentive program vest ratably in three equal annual

installments beginning on the first anniversary of the grant date. Restricted stock units are also granted ad hoc

to attract or retain key personnel, and the terms and conditions under which these restricted stock units vest

vary by award

.

Stock-Settled

Upon vesting, these restricted stock units are settled by issuing one share of ConocoPhillips common stock per

unit. Units awarded to retirement eligible employees vest six months from the grant date; however, those units

are not issued as common stock until the earlier of separation from the company or the end of the regularly

scheduled vesting period. Until issued as stock, most recipients of the restricted stock units receive a cash

payment of a dividend equivalent that is charged to retained earnings. Executive recipients receive an accrued

reinvested dividend equivalent, subject to the terms and conditions of the award, that is charged to retained

earnings. The grant date fair market value of these restricted stock units is deemed equal to the average

ConocoPhillips stock price on the grant date. The grant date fair market value of units that do not receive a

dividend equivalent while unvested is deemed equal to the average ConocoPhillips stock price on the grant

date, less the net present value of the dividends that will not be received

.

The following summarizes our stock-settled stock

unit activity for the year ended December

31, 2020:

Weighted-Average

Millions of Dollars

Stock Units

Grant Date Fair Value

Total Fair Value

Outstanding at December 31, 2019

6,223,046

$

55.99

Granted

2,890,840

57.40

Forfeited

(127,181)

55.84

Issued

(2,554,720)

50.16

$

Outstanding at December 31, 2020

6,431,985

$

58.94

Not Vested at December 31, 2020

4,230,413

59.01

At December 31, 2020,

the remaining unrecognized compensation

cost from the unvested stock-settled units

was $

million, which will be recognized over

a weighted-average period of

1.71

years, the longest period

being

2.14

years.

The weighted-average grant date fair value

of stock unit awards granted during 2019 and

2018 was $

67.77

and $

52.45

, respectively.

The total fair value of stock units issued during

2019 and 2018 was

$

million and $

million, respectively.

Cash-Settled

Cash settled executive restricted stock units granted in 2018 and 2019 replaced the stock option program.

These restricted stock units, subject to elections to defer, will be settled in cash equal to the fair market value

of a share of ConocoPhillips common stock per unit on the settlement date and are classified as liabilities on

the balance sheet. Units awarded to retirement eligible employees vest six months from the grant date;

however, those units are not settled until the earlier of separation from the company or the end of the regularly

scheduled vesting period. Compensation expense is initially measured using the average fair market value of

ConocoPhillips common stock and is subsequently adjusted, based on changes in the ConocoPhillips stock

price through the end of each subsequent reporting period, through the settlement date. Recipients receive an

accrued reinvested dividend equivalent that is charged to compensation expense. The accrued reinvested

dividend is paid at the time of settlement, subject to the terms and conditions of the award. Beginning with

executive restricted stock units granted in 2020 awards will be settled in stock.

The following summarizes our cash-settled stock

unit activity for the year ended December 31, 2020:

Weighted-Average

Millions of Dollars

Stock Units

Grant Date Fair Value

Total Fair Value

Outstanding at December 31, 2019

596,991

$

64.54

Granted

24,437

41.59

Forfeited

(5,622)

40.01

Issued

(1,191)

40.20

$

-

Outstanding at December 31, 2020

614,615

$

39.95

Not Vested at December 31, 2020

121,696

39.95

At December 31, 2020,

the remaining unrecognized compensation

cost from the unvested cash-settled units

was $

million, which will be recognized over a

weighted-average period of

year, the longest period being

1.12

years.

The weighted-average grant date fair value of

stock unit awards granted during 2019

and 2018

were $

68.20

and $

53.68

, respectively.

The total fair value of stock units issued during

2019 and 2018 were $

million and $

million, respectively.

Performance Share Program

—Under the Plan, we also annually grant restricted

performance share units

(PSUs) to senior management.

These PSUs are authorized three years prior to

their effective grant date (the

performance period).

Compensation expense is initially measured

using the average fair market value of

ConocoPhillips common stock and is subsequently

adjusted, based on changes in the ConocoPhillips

stock

price through the end of each subsequent reporting

period, through the grant date for stock-settled

awards and

the settlement date for cash-settled awards.

Stock-Settled

For performance periods beginning before 2009, PSUs do not vest until the employee becomes eligible for

retirement by reaching age 55 with five years of service, and restrictions do not lapse until the employee

separates from the company. With respect to awards for performance periods beginning in 2009 through 2012,

PSUs do not vest until the earlier of the date the employee becomes eligible for retirement by reaching age 55

with five years of service or five years after the grant date of the award, and restrictions do not lapse until the

earlier of the employee’s separation from the company or five years after the grant date (although recipients

can elect to defer the lapsing of restrictions until separation). We recognize compensation expense for these

awards beginning on the grant date and ending on the date the PSUs are scheduled to vest. Since these awards

are authorized three years prior to the grant date, for employees eligible for retirement by or shortly after the

grant date, we recognize compensation expense over the period beginning on the date of authorization and

ending on the date of grant. Until issued as stock, recipients of the PSUs receive a quarterly cash payment of a

dividend equivalent that is charged to retained earnings. Beginning in 2013, PSUs authorized for future grants

will vest, absent employee election to defer, upon settlement following the conclusion of the three-year

performance period. We recognize compensation expense over the period beginning on the date of

authorization and ending on the conclusion of the performance period. PSUs are settled by issuing one share

of ConocoPhillips common stock per unit.

The following summarizes our stock-settled Performance

Share Program activity for the year ended

December 31, 2020:

Weighted-Average

Millions of Dollars

Stock Units

Grant Date Fair Value

Total Fair Value

Outstanding at December 31, 2019

2,024,824

$

50.55

Granted

26,244

58.61

Forfeited

-

Issued

(314,340)

51.15

$

Outstanding at December 31, 2020

1,736,728

$

50.56

Not Vested at December 31, 2020

3,191

$

48.61

At December 31, 2020,

the remaining unrecognized compensation

cost from unvested stock-settled

performance share awards was

zero

.

The weighted-average grant date fair value of

stock-settled PSUs granted

during 2019 and 2018 was $

68.90

and $

53.28

, respectively.

The total fair value of stock-settled PSUs issued

during 2019 and 2018 was $

million and $

million, respectively.

Cash-Settled

In connection with and immediately following the

separation of our Downstream businesses

in 2012, grants of

new PSUs, subject to a shortened performance

period, were authorized.

Once granted, these PSUs vest, absent

employee election to defer, on the earlier of five years after

the grant date of the award or the date the

employee becomes eligible for retirement.

For employees eligible for retirement by or shortly

after the grant

date, we recognize compensation expense

over the period beginning on the date of authorization

and ending on

the date of grant.

Otherwise, we recognize compensation expense

beginning on the grant date and ending on

the date the PSUs are scheduled to vest.

These PSUs are settled in cash equal to the fair

market value of a

share of ConocoPhillips common stock per unit

on the settlement date and thus are classified

as liabilities on

the balance sheet.

Until settlement occurs, recipients of the PSUs receive

a quarterly cash payment of a

dividend equivalent that is charged to compensation expense.

Beginning in 2013, PSUs authorized for future grants

will vest upon settlement following the conclusion

of the

three-year performance period.

We recognize compensation expense over the period beginning on the date of

authorization and ending at the conclusion of

the performance period.

These PSUs will be settled in cash equal

to the fair market value of a share of ConocoPhillips

common stock per unit on the settlement date

and are

classified as liabilities on the balance sheet.

For performance periods beginning before

2018, during the

performance period, recipients of the PSUs do

not receive a quarterly cash payment of a dividend

equivalent,

but after the performance period ends, until

settlement in cash occurs, recipients of the PSUs

receive a

quarterly cash payment of a dividend equivalent

that is charged to compensation expense.

For the performance

period beginning in 2018, recipients of the PSUs

receive an accrued reinvested dividend equivalent

that is

charged to compensation expense.

The accrued reinvested dividend is paid at

the time of settlement, subject to

the terms and conditions of the award.

The following summarizes our cash-settled Performance

Share Program activity for the year ended

December 31, 2020:

Weighted-Average

Millions of Dollars

Stock Units

Grant Date Fair Value

Total Fair Value

Outstanding at December 31, 2019

609,274

$

64.54

Granted

1,491,098

58.61

Forfeited

-

Settled

(1,975,843)

58.54

$

Outstanding at December 31, 2020

124,529

$

39.95

At December 31, 2020, all outstanding cash-settled

performance awards were fully vested and there

was

no

remaining compensation cost to be recorded.

The weighted-average grant date fair value

of cash-settled PSUs

granted during 2019 and 2018 was $

68.90

and $

53.28

, respectively.

The total fair value of cash-settled

performance share awards settled during 2019

and 2018 was $

million and $

million, respectively.

From inception of the Performance Share Program

through 2013, approved PSU awards

were granted after the

conclusion of performance periods.

Beginning in February 2014, initial target PSU awards are issued near the

beginning of new performance periods. These initial target PSU awards will terminate at the end of the

performance periods and will be settled after the performance periods have ended. Also in 2014, initial target

PSU awards were issued for open performance periods that began in prior years. For the open performance

period beginning in 2012, the initial target PSU awards terminated at the end of the three-year performance

period and were replaced with approved PSU awards. For the open performance period beginning in 2013, the

initial target PSU awards terminated at the end of the three-year performance period and were settled after the

performance period ended.

There is no effect on recognition of compensation expense.

Other

—In addition to the above active programs,

we have outstanding shares of restricted stock and

restricted

stock units that were either issued as part of

our non-employee director compensation program

for current and

former members of the company’s Board of Directors or as part of an executive

compensation program that

has been discontinued.

Generally, the recipients of the restricted shares or units receive a dividend

or dividend

equivalent.

The following summarizes the aggregate activity

of these restricted shares and units for the

year ended

December 31, 2020:

Weighted-Average

Millions of Dollars

Stock Units

Grant Date Fair Value

Total Fair Value

Outstanding at December 31, 2019

991,908

$

47.24

Granted

77,824

51.46

Cancelled

(1,336)

23.09

Issued

(98,297)

45.57

$

Outstanding at December 31, 2020

970,099

$

47.78

At December 31, 2020, all outstanding restricted

stock and restricted stock units were fully vested

and there

was

no

remaining compensation cost to be recorded.

The weighted-average grant date fair value of awards

granted during 2019 and 2018 was $

63.58

and $

62.01

, respectively.

The total fair value of awards issued

during 2019 and 2018 was $

million and $

million, respectively.

Note 18—Income Taxes

Components of income tax expense (benefit)

were:

Millions of Dollars

2020

2019

2018

Income Taxes

Federal

Current

$

Deferred

(625)

(113)

Foreign

Current

2,545

3,273

Deferred

(70)

(323)

(166)

State and local

Current

(4)

Deferred

(139)

(8)

(96)

$

(485)

2,267

3,668

Deferred income taxes reflect the net tax effect of temporary

differences between the carrying amounts of

assets and liabilities for financial reporting purposes

and the amounts used for tax purposes.

Major components

of deferred tax liabilities and assets at December

31 were:

Millions of Dollars

2020

2019

Deferred Tax Liabilities

PP&E and intangibles

$

7,744

8,660

Inventory

Other

Total deferred tax liabilities

8,050

8,929

Deferred Tax Assets

Benefit plan accruals

Asset retirement obligations and accrued environmental

costs

2,262

2,339

Investments in joint ventures

1,653

1,722

Other financial accruals and deferrals

Loss and credit carryforwards

8,904

8,968

Other

Total deferred tax assets

14,631

14,693

Less: valuation allowance

(9,965)

(10,214)

Total deferred tax assets net of valuation allowance

4,666

4,479

Net deferred tax liabilities

$

3,384

4,450

At December 31, 2020, noncurrent assets and liabilities

included deferred taxes of $

million and

$

3,747

million, respectively.

At December 31, 2019, noncurrent assets and liabilities

included deferred taxes

of $

million and $

4,634

million, respectively.

At December 31, 2020,

the loss and credit carryforward deferred tax

assets were primarily related to U.S.

foreign tax credit carryforwards of $

billion and various jurisdictions net

operating loss and credit

carryforwards of $

1.9

billion.

If not utilized, U.S. foreign tax credits and net operating

losses will begin to

expire in 2021.

The following table shows a reconciliation

of the beginning and ending deferred tax asset

valuation allowance

for

for 2020, 2019 and 2018:

Millions of Dollars

2020

2019

2018

Balance at January 1

$

10,214

3,040

1,254

Charged to expense (benefit)

(225)

(26)

Other*

(709)

7,399

1,812

Balance at December 31

$

9,965

10,214

3,040

*Represents changes due to originating deferred tax asset that have no impact to our effective

tax rate, acquisitions/dispositions/revisions and the

effect of translating foreign financial statements.

Certain items in the prior year have been reclassed to conform with the current year

presentation, with no impacts to beginning and ending balances.

Valuation

allowances have been established to reduce

deferred tax assets to an amount that will,

more likely

than not, be realized.

At December 31, 2020, we have maintained a valuation

allowance with respect to

substantially all U.S. foreign tax credit carryforwards

as well as certain net operating loss carryforwards

for

various jurisdictions.

During 2020, the valuation allowance movement

charged to earnings primarily relates

to

capital losses in Australia and to the fair value

measurement of our Cenovus Energy common shares that

are

not expected to be realized. Other movements are

primarily related to valuation allowances

on expiring tax

attributes.

Based on our historical taxable income, expectations

for the future, and available tax-planning

strategies,

management expects deferred tax assets, net of

valuation allowances, will primarily be realized

as

offsets to reversing deferred tax liabilities.

On December 2, 2019, the Internal Revenue Service

finalized foreign tax credit regulations related

to the 2017

Tax Cuts and Jobs Act.

Due to the finalization of these regulations, in the

fourth quarter of 2019 we

recognized $

million of net deferred tax assets.

Correspondingly, we recorded $

6,642

million of existing

foreign tax credit carryovers where recognition

was previously considered to be remote.

Present legislation

still makes their realization unlikely and therefore

these credits have been offset with a full valuation

allowance.

At December 31, 2020, unremitted income

considered to be permanently reinvested in certain

foreign

subsidiaries and foreign corporate joint ventures

totaled approximately $

3,982

million.

Deferred income taxes

have not been provided on this amount, as

we do not plan to initiate any action that would

require the payment

of income taxes.

The estimated amount of additional tax, primarily

local withholding tax, that would be

payable on this income if distributed is approximately

$

million.

The following table shows a reconciliation

of the beginning and ending unrecognized

tax benefits for 2020,

2019 and 2018:

Millions of Dollars

2020

2019

2018

Balance at January 1

$

1,177

1,081

Additions based on tax positions related to the current

year

Additions for tax positions of prior years

Reductions for tax positions of prior years

(34)

(22)

(73)

Settlements

(9)

(9)

(35)

Lapse of statute

(1)

(2)

(4)

Balance at December 31

$

1,206

1,177

1,081

Included in the balance of unrecognized tax benefits

for 2020, 2019 and 2018 were $

1,128

million,

$

1,100

million and $

1,081

million, respectively, which, if recognized, would impact our effective tax rate.

The

balance of the unrecognized tax benefits increased

in 2019 mainly due to the treatment of our

PDVSA

settlement. The balance of the unrecognized tax

benefits increased in 2018 mainly due to the treatment

of

distributions from certain foreign subsidiaries.

See Note 12—Contingencies and Commitments,

for more

information on the PDVSA settlement.

At December 31, 2020, 2019 and 2018, accrued liabilities

for interest and penalties totaled $

million,

$

million and $

million, respectively, net of accrued income taxes.

Interest and penalties resulted in a

reduction to earnings of $

million in 2020, a benefit to earnings of $

million in 2019, and a benefit to

earnings of $

million in 2018, respectively.

We file tax returns in the U.S. federal jurisdiction and in many foreign and state jurisdictions.

Audits in major

jurisdictions are generally complete as follows:

U.K. (2015), Canada (2014), U.S. (2014) and

Norway (2019).

Issues in dispute for audited years and audits for

subsequent years are ongoing and in various stages

of

completion in the many jurisdictions in which

we operate around the world.

Consequently, the balance in

unrecognized tax benefits can be expected to fluctuate

from period to period.

It is reasonably possible such

changes could be significant when compared

with our total unrecognized tax benefits, but the amount

of

change is not estimable.

The amounts of U.S. and foreign income (loss)

before income taxes, with a reconciliation of tax

at the federal

statutory rate to the provision for income taxes,

were:

Millions of Dollars

Percent of Pre-Tax Income (Loss)

2020

2019

2018

2020

2019

2018

Income (loss) before income taxes

United States

$

(3,587)

4,704

2,867

114.2

%

49.4

28.7

Foreign

4,820

7,106

(14.2)

50.6

71.3

$

(3,140)

9,524

9,973

100.0

%

100.0

100.0

Federal statutory income tax

$

(659)

2,000

2,095

21.0

%

21.0

21.0

Non-U.S. effective tax rates

1,399

1,766

(6.2)

14.7

17.7

Tax Legislation

-

-

(10)

-

-

(0.1)

Australia disposition

(349)

-

-

11.1

-

-

U.K. disposition

-

(732)

(150)

-

(7.7)

(1.5)

Recovery of outside basis

(22)

(77)

(21)

0.7

(0.8)

(0.2)

Adjustment to tax reserves

(4)

(0.6)

0.1

-

Adjustment to valuation allowance

(225)

(26)

(14.6)

(2.4)

(0.3)

State income tax

(112)

3.6

1.3

1.4

Malaysia Deepwater Incentive

-

(164)

-

-

(1.7)

-

Enhanced oil recovery credit

(6)

(27)

(99)

0.2

(0.3)

(1.0)

Other

(9)

(39)

(18)

0.3

(0.4)

(0.2)

$

(485)

2,267

3,668

15.5

%

23.8

36.8

Our effective tax rate for 2020 was impacted by the disposition

of our Australia-West assets as well as the

valuation allowance related to the fair value measurement

of our Cenovus Energy common shares.

The

Australia-West disposition generated a before-tax gain of $

million with an associated tax benefit of

$

million and resulted in the de-recognition of deferred

tax assets resulting in $

million of tax expense.

The

disposition also generated an Australia capital

loss tax benefit of $

million which has been fully offset by a

valuation allowance.

Due to changes in the fair market value of Cenovus

Energy common shares, the

valuation allowance was increased by $

million to offset the expected capital loss.

Our effective tax rate for 2019 was favorably impacted

by the sale of two of our U.K. subsidiaries.

The

disposition generated a before-tax gain of more than

$

1.7

billion with an associated tax benefit of $

million. The disposition generated a U.S. capital

loss of approximately $

2.1

billion which has generated a U.S.

tax benefit of approximately $

million. The remaining U.S. capital loss

has been recorded as a deferred tax

asset fully offset with a valuation

allowance.

See Note 4—Asset Acquisitions and Dispositions,

for additional

information on the disposition.

During the third quarter of 2019, we received final

partner approval in Malaysia Block G to claim

certain

deepwater tax credits. As a result, we recorded

an income tax benefit of $

million.

The decrease in the effective tax rate for 2018 was primarily

due to the impact of the Clair Field disposition

in

the U.K. and our overall income position, partially

offset by our change in mix of income among taxing

jurisdictions.

Our effective tax rate for 2018 was favorably impacted

by the sale of a U.K. subsidiary to BP.

The subsidiary held

16.5

percent of our

percent interest in the BP-operated Clair Field

in the U.K.

The

disposition generated a before-tax gain of $

million with no associated tax cost.

See Note 4—Asset

Acquisitions and Dispositions, for additional

information on the 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 $

million and a decrease to our accrued income

and other taxes liability of

$

million.

Legislation in other jurisdictions did not have

a material impact to ConocoPhillips.

Note 19—Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss in the

equity section of the balance sheet included:

Millions of Dollars

Defined

Benefit Plans

Net

Unrealized

Loss on

Securities

Foreign

Currency

Translation

Accumulated

Other

Comprehensive

Loss

December 31, 2017

$

(400)

(58)

(5,060)

(5,518)

Other comprehensive income (loss)

-

(642)

(603)

Cumulative effect of adopting ASU No. 2016-01*

-

-

December 31, 2018

(361)

-

(5,702)

(6,063)

Other comprehensive income

-

Cumulative effect of adopting ASU No. 2018-02**

(40)

-

-

(40)

December 31, 2019

(350)

-

(5,007)

(5,357)

Other comprehensive income (loss)

(75)

December 31, 2020

$

(425)

(4,795)

(5,218)

*We adopted ASU No. 2016-01, "Recognition and Measurement of Financial Assets and Liabilities," beginning

January 1, 2018.

**We adopted ASU No. 2018-02, "Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income," beginning January

1, 2019.

During 2019, we recognized $

million of foreign currency translation adjustments

related to the completion

of our sale of two ConocoPhillips U.K. subsidiaries.

For additional information related to this

disposition, see

Note 4—Asset Acquisitions and Dispositions.

The following table summarizes reclassifications

out of accumulated other comprehensive loss during

the years

ended December 31:

Millions of Dollars

2020

2019

Defined Benefit Plans

$

Above amounts are included in the computation of net periodic benefit cost

and

are presented net of tax expense of:

$

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

Note 20—Cash Flow Information

Millions of Dollars

2020

2019

2018

Noncash Investing Activities

Increase (decrease) in PP&E related to an increase

(decrease) in asset

retirement obligations

$

(116)

Increase (decrease) in assets and liabilities

acquired in a nonmonetary

exchange*

Accounts receivable

-

-

(44)

Inventories

-

-

Investments and long-term receivables

-

-

PP&E

-

-

1,907

Other long-term assets

-

-

(9)

Accounts payable

-

-

Accrued income and other taxes

-

-

Cash Payments

Interest

$

Income taxes

2,905

2,976

Net Sales (Purchases) of Investments

Short-term investments purchased

$

(12,435)

(4,902)

(1,953)

Short-term investments sold

12,015

2,138

3,573

Investments and long-term receivables purchased

(325)

(146)

-

Investments and long-term receivables sold

-

-

$

(658)

(2,910)

1,620

*See Note 4—Asset Acquisitions and Dispositions.

The following items are included in the “Cash

Flows from Operating Activities” section

of our consolidated

cash flows.

We collected $

million and $

million in 2019 and 2018, respectively, from PDVSA under a settlement

agreement related to an award issued by the ICC Tribunal in 2018.

For more information on these settlements,

see Note 12—Contingencies and Commitments.

We collected $

million from Ecuador in 2018, as

installment payments related to an agreement

reached with Ecuador in 2017.

In 2019, we made a $

million contribution to our U.K. pension plan.

We made discretionary payments to

our domestic qualified pension plan of $

million in 2018.

Note 21—Other Financial Information

Millions of Dollars

2020

2019

2018

Interest and Debt Expense

Incurred

Debt

$

Other

Capitalized

(55)

(57)

(170)

Expensed

$

Other Income (Loss)

Interest income

$

Unrealized gains (losses) on Cenovus Energy common shares*

(855)

(437)

Other, net

$

(509)

1,358

*See Note 6—Investment in Cenovus Energy, for additional information.

Research and Development Expenditures

—expensed

$

Shipping and Handling Costs

$

1,008

1,075

Foreign Currency Transaction (Gains) Losses

—after-tax

Alaska

$

-

-

-

Lower 48

-

-

-

Canada

(7)

(11)

Europe, Middle East and North Africa

(15)

-

(26)

Asia Pacific

(11)

Other International

-

Corporate and Other

(31)

$

(62)

(13)

Millions of Dollars

2020

2019

Properties, Plants and Equipment

Proved properties

$

94,312

88,284

Unproved properties

4,141

3,980

Other

3,653

5,482

Gross properties, plants and equipment

102,106

97,746

Less: Accumulated depreciation, depletion and amortization

(62,213)

(55,477)

Net properties, plants and equipment

$

39,893

42,269

*Excludes assets classified as held for sale at December 31,

See Note 4

—

Asset Acquisitions and Dispositions, for additional information.

Note 22—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

2020

2019

2018

Operating revenues and other income

$

Purchases

-

Operating expenses and selling, general and administrative

expenses

Net interest income*

(5)

(13)

(14)

*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 23—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

2020

2019

2018

Revenue from contracts with customers

$

13,662

26,106

28,098

Revenue from contracts outside the scope of ASC

Topic 606

Physical contracts meeting the definition of a derivative

5,177

6,558

8,218

Financial derivative contracts

(55)

(97)

Consolidated sales and other operating revenues

$

18,784

32,567

36,417

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 24—Segment Disclosures and Related

Information:

Millions of Dollars

2020

2019

2018

Revenue from Outside the Scope of ASC Topic 606

by Segment

Lower 48

$

3,966

4,989

6,358

Canada

Europe, Middle East and North Africa

1,231

Physical contracts meeting the definition of a derivative

$

5,177

6,558

8,218

Millions of Dollars

2020

2019

2018

Revenue from Outside the Scope of ASC Topic 606

by Product

Crude oil

$

1,112

Natural gas

4,339

5,313

6,734

Other

Physical contracts meeting the definition of a derivative

$

5,177

6,558

8,218

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 December 31, 2020, the “Accounts and

notes receivable” line on our consolidated

balance sheet included

trade receivables of $

1,827

million compared with $

2,372

million at December 31, 2019, and included both

contracts with customers within the scope of ASC

Topic 606 and those that are outside the scope of ASC

Topic 606.

We typically receive payment within 30 days or less (depending on the terms of the invoice) once

delivery is made.

Revenues that are outside the scope of ASC Topic 606 relate primarily to

physical gas sales

contracts at market prices for which we do not

elect NPNS and are therefore accounted for

as a derivative

under ASC Topic 815.

There is little distinction in the nature

of the customer or credit quality of trade

receivables associated with gas sold under contracts

for which NPNS has not been elected

compared with 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

$

Contractual payments received

At December 31, 2020

$

Amounts Recognized in the Consolidated

Balance Sheet at December 31, 2020

Current liabilities

$

Noncurrent liabilities

$

We expect to recognize the contract liabilities as of December 31, 2020, as revenue during 2021 and 2022.

There was no revenue recognized during the

year ended December 31, 2020.

Note 24—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, premiums on early retirement

of debt, 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.

Segment accounting policies are the same as those

in Note 1—Accounting Policies.

Intersegment sales are at

prices that approximate market.

Effective with the third quarter of 2020, we 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

2020

2019

2018

Sales and Other Operating Revenues

Alaska

$

3,408

5,483

5,740

Intersegment eliminations

(11)

-

-

Alaska

3,397

5,483

5,740

Lower 48

9,872

15,514

17,029

Intersegment eliminations

(51)

(46)

(40)

Lower 48

9,821

15,468

16,989

Canada

1,666

2,910

3,184

Intersegment eliminations

(405)

(1,141)

(1,160)

Canada

1,261

1,769

2,024

Europe, Middle East and North Africa

1,919

5,101

6,635

Intersegment eliminations

(2)

-

-

Europe, Middle East and North Africa

1,917

5,101

6,635

Asia Pacific

2,363

4,525

4,861

Other International

-

-

Corporate and Other

Consolidated sales and other operating revenues

$

18,784

32,567

36,417

The market for our products is large and diverse, therefore,

our sales and other operating revenues are not

dependent upon any single customer.

Millions of Dollars

2020

2019

2018

Depreciation, Depletion, Amortization and Impairments

Alaska

$

Lower 48

3,358

3,224

2,370

Canada

Europe, Middle East and North Africa

1,041

Asia Pacific

1,285

1,382

Other International

-

-

-

Corporate and Other

Consolidated depreciation, depletion, amortization

and impairments

$

6,334

6,495

5,983

Equity in Earnings of Affiliates

Alaska

$

(7)

Lower 48

(11)

(159)

Canada

-

-

-

Europe, Middle East and North Africa

Asia Pacific

Other International

-

-

Corporate and Other

-

-

-

Consolidated equity in earnings of affiliates

$

1,074

Income Tax Provision (Benefit)

Alaska

$

(256)

Lower 48

(378)

Canada

(185)

(43)

(96)

Europe, Middle East and North Africa

1,425

2,259

Asia Pacific

Other International

(20)

Corporate and Other

(76)

(233)

(103)

Consolidated income tax provision (benefit)

$

(485)

2,267

3,668

Net Income (Loss) Attributable to ConocoPhillips

Alaska

$

(719)

1,520

1,814

Lower 48

(1,122)

1,747

Canada

(326)

Europe, Middle East and North Africa

3,170

2,594

Asia Pacific

1,483

1,342

Other International

(64)

Corporate and Other

(1,880)

(1,667)

Consolidated net income (loss) attributable

to ConocoPhillips

$

(2,701)

7,189

6,257

Millions of Dollars

2020

2019

2018

Investments in and Advances to Affiliates

Alaska

$

Lower 48

Canada

-

-

-

Europe, Middle East and North Africa

1,070

1,311

Asia Pacific

6,705

7,265

7,565

Other International

-

-

-

Corporate and Other

-

-

-

Consolidated investments in and advances to affiliates

$

7,710

8,453

9,340

Total Assets

Alaska

$

14,623

15,453

14,648

Lower 48

11,932

14,425

14,888

Canada

6,863

6,350

5,748

Europe, Middle East and North Africa

8,756

9,269

11,276

Asia Pacific

11,231

13,568

14,758

Other International

Corporate and Other

8,987

11,164

8,573

Consolidated total assets

$

62,618

70,514

69,980

Capital Expenditures and Investments

Alaska

$

1,038

1,513

1,298

Lower 48

1,881

3,394

3,184

Canada

Europe, Middle East and North Africa

Asia Pacific

Other International

Corporate and Other

Consolidated capital expenditures and investments

$

4,715

6,636

6,750

Interest Income and Expense

Interest income

Alaska

$

-

-

-

Lower 48

-

-

-

Canada

-

-

-

Europe, Middle East and North Africa

Asia Pacific

Other International

-

-

-

Corporate and Other

Interest and debt expense

Corporate and Other

$

Sales and Other Operating Revenues by

Product

Crude oil

$

9,736

18,482

19,571

Natural gas

6,427

8,715

10,720

Natural gas liquids

1,114

Other*

2,093

4,556

5,012

Consolidated sales and other operating revenues

by product

$

18,784

32,567

36,417

*Includes LNG and bitumen.

Geographic Information

Millions of Dollars

Sales and Other Operating Revenues

(1)

Long-Lived Assets

(2)

2020

2019

2018

2020

2019

2018

United States

$

13,230

21,159

22,740

24,034

26,566

26,838

Australia and Timor-Leste

1,647

1,798

6,676

7,228

9,301

Canada

1,261

1,769

2,024

6,385

5,769

5,333

China

1,491

1,447

1,380

Indonesia

Libya

1,103

1,142

Malaysia

1,230

1,346

1,501

1,871

2,327

Norway

1,426

2,349

2,886

5,294

5,258

5,582

United Kingdom

1,649

2,606

1,583

Other foreign countries

1,087

1,308

1,346

Worldwide consolidated

$

18,784

32,567

36,417

47,603

50,722

55,038

(1) Sales and other operating revenues are attributable to countries based on the location of

the selling operation.

(2) Defined as net PP&E plus equity investments and advances

to affiliated companies.

Note 25—Acquisition of Concho Resources Inc.

On

October 18, 2020

, we entered into a definitive agreement

to acquire Concho in an all-stock transaction.

The transaction closed on January 15, 2021

and as defined under the terms of the transaction

agreement, each

share of Concho common stock was exchanged

at a fixed ratio of

1.46

for shares of ConocoPhillips common

stock, for total consideration of $

13.1

billion.

This resulted in issuance of

million shares, representing

approximately

percent of the outstanding shares of ConocoPhillips

common stock upon completion of the

transaction.

We also assumed Concho’s outstanding debt of $

3.9

billion in aggregate principal amount, recorded

at fair

value of $

4.7

billion on the transaction closing date.

On December 7, 2020, we launched a debt

exchange offer

which settled on February 8, 2021, for

percent of Concho’s historical notes.

The historical notes issued by

Concho were exchanged for new notes issued by

ConocoPhillips, which are fully and unconditionally

guaranteed by ConocoPhillips Company.

For further discussion about the debt exchange,

see Note 10 – Debt.

As of the acquisition date, January 15, 2021, the

fair value of consideration transferred is

summarized below:

Total Consideration

Number of shares of Concho common stock

issued and outstanding (in thousands)*

194,243

Number of shares of Concho stock awards outstanding

(in thousands)*

1,599

Number of shares exchanged

195,842

Exchange ratio

1.46

Additional shares of ConocoPhillips common stock

issued as consideration (in thousands)

285,929

Average price per share of ConocoPhillips common stock**

$

45.9025

Total Consideration (Millions)

$

13,125

*Outstanding as of January 15, 2021.

**Based on the ConocoPhillips average stock price on January

15, 2021.

The transaction will be accounted for as a

business combination under the acquisition method

of accounting.

The total purchase price will be allocated to identifiable

assets acquired and the liabilities assumed

based on

their fair values as of the closing date.

We are currently in the process of finalizing the initial accounting for

this transaction and provisional fair value measurements

will be made in the first quarter of 2021.

We may

adjust the measurements in subsequent periods,

up to one year from the acquisition date as we identify

additional information to complete the necessary

analysis.

Oil and Gas Operations

(Unaudited)

In accordance with FASB ASC Topic 932, “Extractive Activities—Oil and Gas,” and regulations of the SEC,

we are making certain supplemental disclosures

about our oil and gas exploration and production

operations.

These disclosures include information about our

consolidated oil and gas activities and our proportionate

share

of our equity affiliates’ oil and gas activities in our operating

segments.

As a result, amounts reported as

equity affiliates in Oil and Gas Operations may differ from

those shown in the individual segment disclosures

reported elsewhere in this report.

Our disclosures by geographic area include the

U.S., Canada, Europe, Asia

Pacific/Middle East (inclusive of equity affiliates),

and Africa.

As required by current authoritative guidelines,

the estimated future date when an asset will be permanently

shut down for economic reasons is based on historical

12-month first-of-month average prices and current

costs.

This estimated date when production will

end affects the amount of estimated reserves.

Therefore, as

prices and cost levels change from year to year, the estimate of proved

reserves also changes.

Generally, our

proved reserves decrease as prices decline and increase

as prices rise.

Our proved reserves include estimated quantities

related to PSCs, which are reported under the “economic

interest” method, as well as variable-royalty regimes,

and are subject to fluctuations in commodity

prices,

recoverable operating expenses and capital

costs.

If costs remain stable, reserve quantities

attributable to

recovery of costs will change inversely to changes

in commodity prices.

For example, if prices increase, then

our applicable reserve quantities would decline.

At December 31, 2020, approximately

6 percent of our total

proved reserves were under PSCs, located in our

Asia Pacific/Middle East geographic reporting

area, and 8

percent of our total proved reserves were under

a variable-royalty regime, located in our Canada

geographic

reporting area.

Reserves Governance

The recording and reporting of proved reserves

are governed by criteria established by regulations

of the SEC

and FASB.

Proved reserves are those quantities of oil

and gas, which, by analysis of geoscience and

engineering data, can be estimated with reasonable

certainty to be economically producible—from

a given date

forward, from known reservoirs, and under existing

economic conditions, operating methods, and government

regulations—prior to the time at which contracts

providing the right to operate expire, unless

evidence

indicates renewal is reasonably certain, regardless

of whether deterministic or probabilistic

methods are used

for the estimation.

The project to extract the hydrocarbons must

have commenced or the operator must be

reasonably certain it will commence the project

within a reasonable time.

Proved reserves are further classified as either

developed or undeveloped.

Proved developed reserves are

proved reserves that can be expected to be recovered

through existing wells with existing equipment

and

operating methods, or in which the cost of the required

equipment is relatively minor compared

with the cost

of a new well, and through installed extraction

equipment and infrastructure operational

at the time of the

reserves estimate if the extraction is by means not

involving a well.

Proved undeveloped reserves are proved

reserves expected to be recovered from new

wells on undrilled acreage, or from existing wells

where a

relatively major expenditure is required for recompletion.

Reserves on undrilled acreage are limited

to those

directly offsetting development spacing areas that

are reasonably certain of production when drilled,

unless

evidence provided by reliable technologies exists

that establishes reasonable certainty of economic

producibility at greater distances. As defined

by SEC regulations, reliable technologies

may be used in reserve

estimation when they have been demonstrated

in the field to provide reasonably certain results

with

consistency and repeatability in the formation

being evaluated or in an analogous formation.

The technologies

and data used in the estimation of our proved reserves

include, but are not limited to, performance-based

methods, volumetric-based methods, geologic

maps, seismic interpretation, well logs, well test

data, core data,

analogy and statistical analysis.

We have a companywide, comprehensive, SEC-compliant internal policy that

governs the determination and

reporting of proved reserves.

This policy is applied by the geoscientists and reservoir

engineers in our

business units around the world.

As part of our internal control process, each

business unit’s reserves

processes and controls are reviewed annually by

an internal team which is headed by the company’s Manager

of Reserves Compliance and Reporting.

This team, composed of internal reservoir engineers,

geoscientists,

finance personnel and a senior representative

from DeGolyer and MacNaughton (D&M),

a third-party

petroleum engineering consulting firm, reviews

the business units’ reserves for adherence to SEC

guidelines

and company policy through on-site visits,

teleconferences and review of documentation.

In addition to

providing independent reviews, this internal team

also ensures reserves are calculated using

consistent and

appropriate standards and procedures.

This team is independent of business unit line

management and is

responsible for reporting its findings to senior management.

The team is responsible for communicating

our

reserves policy and procedures and is available

for internal peer reviews and consultation

on major projects or

technical issues throughout the year.

All of our proved reserves held by consolidated

companies and our share

of equity affiliates have been estimated by ConocoPhillips.

During 2020, our processes and controls used

to assess over 90 percent of proved reserves

as of December 31,

2020, were reviewed by D&M.

The purpose of their review was to assess

whether the adequacy and

effectiveness of our internal processes and controls used to

determine estimates of proved reserves are

in

accordance with SEC regulations.

In such review, ConocoPhillips’ technical staff presented D&M with an

overview of the reserves data, as well as the

methods and assumptions used in estimating

reserves.

The data

presented included pertinent seismic information,

geologic maps, well logs, production tests, material

balance

calculations, reservoir simulation models, well

performance data, operating procedures and relevant

economic

criteria.

Management’s intent in retaining D&M to review its processes and controls

was to provide objective

third-party input on these processes and controls.

D&M’s opinion was the general processes and controls

employed by ConocoPhillips in estimating

its December 31, 2020,

proved reserves for the properties reviewed

are in accordance with the SEC reserves definitions.

D&M’s report is included as Exhibit 99 of this Annual

Report on Form 10-K.

The technical person primarily responsible for

overseeing the processes and internal controls

used in the

preparation of the company’s reserves estimates is the Manager of Reserves

Compliance and Reporting.

This

individual holds a master’s degree in petroleum engineering.

He is a member of the Society of Petroleum

Engineers with over 25 years of oil and gas industry

experience and has held positions of increasing

responsibility in reservoir engineering, subsurface

and asset management in the U.S. and

several international

field locations.

Engineering estimates of the quantities of proved reserves

are inherently imprecise.

See the “Critical

Accounting Estimates” section of Management’s Discussion and

Analysis of Financial Condition and Results

of Operations for additional discussion of the

sensitivities surrounding these estimates.

Proved Reserves

Years Ended

Crude Oil

December 31

Millions of Barrels

Lower

Total

Asia Pacific/

Alaska

U.S.

Canada

Europe

Middle East

Africa

Total

Developed and Undeveloped

Consolidated operations

End of 2017

1,644

2,322

Revisions

(90)

(18)

Improved recovery

-

-

-

-

-

Purchases

-

-

-

-

Extensions and discoveries

-

Production

(59)

(82)

(141)

(1)

(40)

(33)

(13)

(228)

Sales

-

(12)

(12)

-

(36)

-

-

(48)

End of 2018

1,233

1,936

2,533

Revisions

(36)

(1)

(5)

Improved recovery

-

-

-

-

-

Purchases

-

-

-

-

-

Extensions and discoveries

-

-

Production

(74)

(95)

(169)

-

(36)

(31)

(14)

(250)

Sales

-

(2)

(2)

-

(30)

-

-

(32)

End of 2019

1,231

2,028

2,562

Revisions

(297)

(126)

(423)

(2)

(4)

(3)

(428)

Improved recovery

-

-

-

-

-

-

Purchases

-

-

-

-

Extensions and discoveries

-

-

-

Production

(65)

(77)

(142)

(2)

(28)

(25)

(3)

(200)

Sales

-

(14)

(14)

(1)

-

-

-

(15)

End of 2020

1,572

2,051

Equity affiliates

End of 2017

-

-

-

-

-

-

Revisions

-

-

-

-

-

-

-

-

Improved recovery

-

-

-

-

-

-

-

-

Purchases

-

-

-

-

-

-

-

-

Extensions and discoveries

-

-

-

-

-

-

-

-

Production

-

-

-

-

-

(5)

-

(5)

Sales

-

-

-

-

-

-

-

-

End of 2018

-

-

-

-

-

-

Revisions

-

-

-

-

-

-

-

-

Improved recovery

-

-

-

-

-

-

-

-

Purchases

-

-

-

-

-

-

-

-

Extensions and discoveries

-

-

-

-

-

-

-

-

Production

-

-

-

-

-

(5)

-

(5)

Sales

-

-

-

-

-

-

-

-

End of 2019

-

-

-

-

-

-

Revisions

-

-

-

-

-

-

-

-

Improved recovery

-

-

-

-

-

-

-

-

Purchases

-

-

-

-

-

-

-

-

Extensions and discoveries

-

-

-

-

-

-

-

-

Production

-

-

-

-

-

(5)

-

(5)

Sales

-

-

-

-

-

-

-

-

End of 2020

-

-

-

-

-

-

Total

company

End of 2017

1,644

2,405

End of 2018

1,233

1,936

2,611

End of 2019

1,231

2,028

2,635

End of 2020

1,572

2,119

Years Ended

Crude Oil

December 31

Millions of Barrels

Lower

Total

Asia Pacific/

Alaska

U.S.

Canada

Europe

Middle East

Africa

Total

Developed

Consolidated operations

End of 2017

1,143

1,651

End of 2018

1,058

1,404

1,896

End of 2019

1,048

1,382

1,809

End of 2020

1,028

1,415

Equity affiliates

End of 2017

-

-

-

-

-

-

End of 2018

-

-

-

-

-

-

End of 2019

-

-

-

-

-

-

End of 2020

-

-

-

-

-

-

Undeveloped

Consolidated operations

End of 2017

-

-

End of 2018

End of 2019

End of 2020

-

Equity affiliates

End of 2017

-

-

-

-

-

-

-

-

End of 2018

-

-

-

-

-

-

-

-

End of 2019

-

-

-

-

-

-

-

-

End of 2020

-

-

-

-

-

-

-

-

Notable changes in proved crude oil reserves

in the three years ended December 31, 2020,

included:

●

Revisions

: In 2020, Alaska downward revisions were primarily

driven by lower prices of 243 million barrels and

development plan changes of 54 million barrels.

Downward revisions in Lower 48 were due to

lower prices of 89

million barrels and development timing for

specific well locations from unconventional plays

of 82 million barrels,

partially offset by upward technical revisions and additional

infill drilling in the unconventional plays of

45 million

barrels.

In 2019, Alaska upward revisions were due to cost

and technical revisions of 74 million barrels, partially

offset by

downward price revisions of 34 million barrels.

Upward revisions in Europe and Africa were

primarily due to infill

drilling and technical revisions.

Downward revisions in Lower 48 were due to

changes in development timing for

specific well locations from the unconventional plays

of 71 million barrels and price revisions

of 22 million barrels,

partially offset by upward revisions related to infill

drilling and improved well performance of 57 million

barrels.

In 2018, downward revisions in Lower 48 were

primarily due to changes in development

timing for specific well

locations from the unconventional plays and are

more than offset by increases in planned well locations

in the

unconventional plays in the extensions and discoveries

category.

Downward revisions in Lower 48 due to development

timing were partially offset by higher prices. Revisions in

Alaska, Europe and Asia Pacific/Middle East

were primarily

due to higher prices.

●

Purchases:

In 2018, Alaska purchases were due to the

Greater Kuparuk Area and Western North Slope acquisitions.

●

Extensions and discoveries

: In 2020, extensions and discoveries in

Lower 48 were due to planned development to

add

specific well locations from the unconventional plays

which more than offset the decreases resulting from development

plan timing in the revisions category.

In 2019, extensions and discoveries in Lower 48

were due to planned development to add specific

well locations from

the unconventional plays which more than offset the decreases

in the revisions category.

In Asia Pacific/Middle East,

increases were due to sanctioning

of development programs in China and Malaysia.

In 2018, extensions and discoveries in Lower 48

were primarily due to changes in the development

strategy to add

specific well locations from the unconventional plays.

Extensions and discoveries in Alaska

were driven by drilling

success in Western North Slope.

●

Sales

: In 2019, Europe sales represent the disposition

of the U.K. assets. In 2018, Europe sales

were due to the

disposition of a subsidiary that held 16.5 percent

of our 24 percent interest in the Clair Field

in the U.K.

Years Ended

Natural Gas Liquids

December 31

Millions of Barrels

Lower

Total

Asia Pacific/

Alaska

U.S.

Canada

Europe

Middle East

Total

Developed and Undeveloped

Consolidated operations

End of 2017

Revisions

(25)

(20)

-

(1)

(20)

Improved recovery

-

-

-

-

-

-

-

Purchases

-

-

-

-

-

-

-

Extensions and discoveries

-

-

-

Production

(5)

(25)

(30)

-

(3)

(1)

(34)

Sales

-

(21)

(21)

-

-

-

(21)

End of 2018

Revisions

(1)

(11)

(12)

-

(1)

(10)

Improved recovery

-

-

-

-

-

-

-

Purchases

-

-

-

-

-

-

-

Extensions and discoveries

-

-

-

Production

(5)

(28)

(33)

-

(3)

(1)

(37)

Sales

-

-

-

-

(4)

-

(4)

End of 2019

Revisions

-

(26)

(26)

-

(1)

(26)

Improved recovery

-

-

-

-

-

-

-

Purchases

-

-

-

Extensions and discoveries

-

-

-

Production

(6)

(27)

(33)

(1)

(2)

-

(36)

Sales

-

(5)

(5)

-

-

-

(5)

End of 2020

-

Equity affiliates

End of 2017

-

-

-

-

-

Revisions

-

-

-

-

-

-

-

Improved recovery

-

-

-

-

-

-

-

Purchases

-

-

-

-

-

-

-

Extensions and discoveries

-

-

-

-

-

-

-

Production

-

-

-

-

-

(3)

(3)

Sales

-

-

-

-

-

-

-

End of 2018

-

-

-

-

-

Revisions

-

-

-

-

-

-

-

Improved recovery

-

-

-

-

-

-

-

Purchases

-

-

-

-

-

-

-

Extensions and discoveries

-

-

-

-

-

-

-

Production

-

-

-

-

-

(3)

(3)

Sales

-

-

-

-

-

-

-

End of 2019

-

-

-

-

-

Revisions

-

-

-

-

-

-

-

Improved recovery

-

-

-

-

-

-

-

Purchases

-

-

-

-

-

-

-

Extensions and discoveries

-

-

-

-

-

-

-

Production

-

-

-

-

-

(3)

(3)

Sales

-

-

-

-

-

-

-

End of 2020

-

-

-

-

-

Total

company

End of 2017

End of 2018

End of 2019

End of 2020

Years Ended

Natural Gas Liquids

December 31

Millions of Barrels

Lower

Total

Asia Pacific/

Alaska

U.S.

Canada

Europe

Middle East

Total

Developed

Consolidated operations

End of 2017

End of 2018

-

End of 2019

End of 2020

-

Equity affiliates

End of 2017

-

-

-

-

-

End of 2018

-

-

-

-

-

End of 2019

-

-

-

-

-

End of 2020

-

-

-

-

-

Undeveloped

Consolidated operations

End of 2017

-

-

End of 2018

-

-

End of 2019

-

-

End of 2020

-

-

-

Equity affiliates

End of 2017

-

-

-

-

-

-

-

End of 2018

-

-

-

-

-

-

-

End of 2019

-

-

-

-

-

-

-

End of 2020

-

-

-

-

-

-

-

Notable changes in proved NGL reserves in the three

years ended December 31, 2020,

included:

●

Revisions

: In 2020, downward revisions in Lower 48

were due to lower prices of 33 million barrels

and development

timing for specific well locations from unconventional

plays of 20 million barrels, partially

offset by upward technical

revisions and additional infill drilling in

the unconventional plays of 27 million barrels.

In 2019, downward revisions in Lower 48 were

due to changes in development timing

for specific well locations from

the unconventional plays of 32 million barrels

and price revisions of 11 million barrels, partially offset by upward

revisions related to infill drilling and improved

well performance of 32 million barrels.

In 2018, downward revisions in Lower 48 were

primarily due to changes in development

timing for specific well

locations from the unconventional plays and are

more than offset by increases in planned well locations

in the

unconventional plays in the extensions and discoveries

category.

●

Extensions and discoveries

: In 2020, extensions and discoveries in

Lower 48 were due to planned development to add

specific well locations from the unconventional plays

which more than offset the decreases in the revisions

category.

In 2019, extensions and discoveries in Lower 48

were due to planned development to add specific

well locations from

the unconventional plays which more than offset the decreases

in the revisions category.

In 2018, extensions and discoveries in Lower 48

were primarily due to changes in the development

strategy to add

specific well locations from the unconventional plays.

●

Sales

: In 2019, Europe sales represent the disposition

of the U.K. assets.

In 2018, Lower 48 sales were primarily

due to

the disposition of our interests in the Barnett.

Years Ended

Natural Gas

December 31

Billions of Cubic Feet

Lower

Total

Asia Pacific/

Alaska

U.S.

Canada

Europe

Middle East

Africa

Total

Developed and Undeveloped

Consolidated operations

End of 2017

2,320

2,533

4,853

1,217

1,298

7,603

Revisions

(283)

(133)

-

(34)

Improved recovery

-

-

-

-

-

-

-

-

Purchases

-

-

-

-

Extensions and discoveries

-

Production

(71)

(237)

(308)

(5)

(188)

(246)

(10)

(757)

Sales

-

(223)

(223)

-

(13)

-

-

(236)

End of 2018

2,736

2,318

5,054

1,212

1,079

7,585

Revisions

(113)

(83)

(2)

Improved recovery

-

-

-

-

-

-

-

-

Purchases

-

-

-

-

-

Extensions and discoveries

-

-

Production

(85)

(252)

(337)

(4)

(178)

(250)

(11)

(780)

Sales

-

(7)

(7)

-

(298)

-

-

(305)

End of 2019

2,688

2,431

5,119

7,259

Revisions

(607)

(439)

(1,046)

(15)

(917)

Improved recovery

-

-

-

-

-

-

-

-

Purchases

-

-

-

-

Extensions and discoveries

-

-

-

Production

(85)

(231)

(316)

(16)

(112)

(171)

(2)

(617)

Sales

-

(39)

(39)

-

-

(58)

-

(97)

End of 2020

1,996

2,100

4,096

6,070

Equity affiliates

End of 2017

-

-

-

-

-

4,303

-

4,303

Revisions

-

-

-

-

-

-

Improved recovery

-

-

-

-

-

-

-

-

Purchases

-

-

-

-

-

-

-

-

Extensions and discoveries

-

-

-

-

-

-

Production

-

-

-

-

-

(381)

-

(381)

Sales

-

-

-

-

-

-

-

-

End of 2018

-

-

-

-

-

4,564

-

4,564

Revisions

-

-

-

-

-

(7)

-

(7)

Improved recovery

-

-

-

-

-

-

-

-

Purchases

-

-

-

-

-

-

-

-

Extensions and discoveries

-

-

-

-

-

-

Production

-

-

-

-

-

(388)

-

(388)

Sales

-

-

-

-

-

-

-

-

End of 2019

-

-

-

-

-

4,421

-

4,421

Revisions

-

-

-

-

-

(382)

-

(382)

Improved recovery

-

-

-

-

-

-

-

-

Purchases

-

-

-

-

-

-

Extensions and discoveries

-

-

-

-

-

-

Production

-

-

-

-

-

(395)

-

(395)

Sales

-

-

-

-

-

-

-

-

End of 2020

-

-

-

-

-

3,724

-

3,724

Total

company

End of 2017

2,320

2,533

4,853

1,217

5,601

11,906

End of 2018

2,736

2,318

5,054

1,212

5,643

12,149

End of 2019

2,688

2,431

5,119

5,398

11,680

End of 2020

1,996

2,100

4,096

4,575

9,794

Years Ended

Natural Gas

December 31

Billions of Cubic Feet

Lower

Total

Asia Pacific/

Alaska

U.S.

Canada

Europe

Middle East

Africa

Total

Developed

Consolidated operations

End of 2017

2,310

1,597

3,907

6,084

End of 2018

2,720

1,427

4,147

1,052

6,188

End of 2019

2,601

1,398

3,999

5,793

End of 2020

1,961

1,051

3,012

4,714

Equity affiliates

End of 2017

-

-

-

-

-

4,044

-

4,044

End of 2018

-

-

-

-

-

4,059

-

4,059

End of 2019

-

-

-

-

-

3,898

-

3,898

End of 2020

-

-

-

-

-

3,293

-

3,293

Undeveloped

Consolidated operations

End of 2017

-

-

1,519

End of 2018

-

1,397

End of 2019

1,033

1,120

-

1,466

End of 2020

1,049

1,084

-

-

1,356

Equity affiliates

End of 2017

-

-

-

-

-

-

End of 2018

-

-

-

-

-

-

End of 2019

-

-

-

-

-

-

End of 2020

-

-

-

-

-

-

Natural gas production in the reserves table may differ from

gas production (delivered for sale) in our statistics

disclosure,

primarily because the quantities above include

gas consumed in production operations.

Quantities consumed in production

operations are not significant in the periods presented.

The value of net production consumed in operations

is not reflected in

net revenues and production expenses, nor do the

volumes impact the respective per unit metrics.

Reserve volumes include natural gas to be consumed

in operations of 2,286 Bcf, 3,141 Bcf, and

3,131 Bcf as of December 31,

2020, 2019 and 2018, respectively.

These volumes are not included in the calculation

of our Standardized Measure of

Discounted Future Net Cash Flows Relating to

Proved Oil and Gas Reserve Quantities.

Natural gas reserves are computed at 14.65 pounds

per square inch absolute and 60 degrees

Fahrenheit.

Notable changes in proved natural gas reserves

in the three years ended December 31, 2020, included:

●

Revisions

: In 2020,

downward revisions in Alaska were primarily

due to lower prices. In Lower 48, downward

revisions of 372 Bcf were due to lower prices

and 154 Bcf were due to development timing

for specific well locations

from unconventional plays, partially offset by technical

revisions of 87 Bcf. Downward revisions in

our equity affiliates

in Asia Pacific/Middle East were due to lower prices

of 426 Bcf, partially offset by performance revisions

of 44 Bcf.

Upward revisions in our consolidated operations

in Asia Pacific/Middle East were due to

technical revisions of 88 Bcf

and price revisions of 15 Bcf.

In 2019, upward revisions in Europe were due to technical

and cost revisions.

In Asia Pacific/Middle East upward

revisions were primarily due to the Indonesia Corridor

PSC term extension.

Downward revisions in Lower 48 were

due to changes in development timing for specific

well locations from the unconventional plays of

207 Bcf and price

revisions of 125 Bcf, partially offset by upward revisions

related to infill drilling and improved well performance

of

219 Bcf.

In 2018, downward revisions in Lower 48 were

primarily due to changes in development

timing for specific well

locations from the unconventional plays and are

more than offset by increases in planned well locations

in the

unconventional plays in the extensions and discoveries

category.

Downward revisions in Lower 48 due to development

timing were partially offset by higher prices.

Revisions in Alaska, Canada, Europe and our equity

affiliates in Asia

Pacific/Middle East were primarily due to higher prices.

●

Purchases

: In 2020, Canada purchases were due to the

acquisition of additional Montney acreage.

In 2018, Alaska purchases were due to the Greater

Kuparuk Area and Western North Slope acquisitions.

●

Extensions and discoveries

: In 2020,

extensions and discoveries in Lower 48

were due to planned development to add

specific well locations from the unconventional plays

which more than offset the decreases resulting from

development

plan timing in the revisions category. Extensions and discoveries in Canada

were primarily driven by ongoing drilling

successes in Montney.

In 2019, extensions and discoveries in Lower 48

were due to planned development to add specific

well locations from

the unconventional plays which more than offset the decreases

in the revisions category.

Extensions and discoveries in

our equity affiliates were due to ongoing development in

APLNG.

In 2018, extensions and discoveries in Lower 48

were primarily due to changes in the development

strategy to add

specific well locations from the unconventional plays.

Extensions and discoveries in Canada,

Europe and our equity

affiliates in Asia Pacific/Middle East were primarily

driven by ongoing drilling successes in Montney, Norway and

APLNG, respectively.

●

Sales

: In 2020, Asia Pacific/Middle East sales represent

the disposition of the Australia-West assets.

In 2019, Europe sales represent

the disposition of the U.K. assets.

In 2018, Lower 48 sales were primarily

due to the disposition of our interest in Barnett.

Years Ended

Bitumen

December 31

Millions of Barrels

Canada

Developed and Undeveloped

Consolidated operations

End of 2017

Revisions

Improved recovery

-

Purchases

-

Extensions and discoveries

-

Production

(24)

Sales

-

End of 2018

Revisions

Improved recovery

-

Purchases

-

Extensions and discoveries

Production

(22)

Sales

-

End of 2019

Revisions

(15)

Improved recovery

-

Purchases

-

Extensions and discoveries

Production

(20)

Sales

-

End of 2020

Equity affiliates

End of 2017

-

Revisions

-

Improved recovery

-

Purchases

-

Extensions and discoveries

-

Production

-

Sales

-

End of 2018

-

Revisions

-

Improved recovery

-

Purchases

-

Extensions and discoveries

-

Production

-

Sales

-

End of 2019

-

Revisions

-

Improved recovery

-

Purchases

-

Extensions and discoveries

-

Production

-

Sales

-

End of 2020

-

Total

company

End of 2017

End of 2018

End of 2019

End of 2020

Years Ended

Bitumen

December 31

Millions of Barrels

Canada

Developed

Consolidated operations

End of 2017

End of 2018

End of 2019

End of 2020

Equity affiliates

End of 2017

-

End of 2018

-

End of 2019

-

End of 2020

-

Undeveloped

Consolidated operations

End of 2017

End of 2018

End of 2019

End of 2020

Equity affiliates

End of 2017

-

End of 2018

-

End of 2019

-

End of 2020

-

Notable changes in proved bitumen reserves

in the three years ended December 31, 2020,

included:

●

Revisions

: In 2020,

downward revisions in Canada were due

to changes in development timing for

specific pad locations from the Surmont development

program of 12 million barrels with the

remaining revisions primarily related to lower

prices.

In 2019, upward revisions in Canada were due to

technical revisions in Surmont of 70 million

barrels,

partially offset by downward revisions due to changes in

development timing for specific pad

locations from the Surmont development program

of 31 million barrels.

In 2018, revisions were primarily due to higher prices

at Surmont.

●

Extensions and discoveries

: In 2020,

extensions and discoveries in Canada

were primarily due to

planned development to add specific pad locations

from the Surmont development program,

which

more than offset the decrease in the revisions category.

In 2019, extensions and discoveries in Canada

were due to planned development to add specific

pad

locations from the Surmont development program,

which offset the decrease in the revisions category

of 31 million barrels.

Years Ended

Total Proved

Reserves

December 31

Millions of Barrels of Oil Equivalent

Lower

Total

Asia Pacific/

Alaska

U.S.

Canada

Europe

Middle East

Africa

Total

Developed and Undeveloped

Consolidated operations

End of 2017

1,430

1,353

2,783

4,193

Revisions

(161)

(59)

Improved recovery

-

-

-

-

-

Purchases

-

-

-

-

Extensions and discoveries

-

Production

(76)

(146)

(222)

(25)

(75)

(75)

(15)

(412)

Sales

-

(70)

(70)

-

(38)

-

-

(108)

End of 2018

1,795

1,312

3,107

4,383

Revisions

(67)

(23)

Improved recovery

-

-

-

-

-

Purchases

-

-

-

-

-

Extensions and discoveries

-

-

Production

(93)

(165)

(258)

(23)

(68)

(74)

(16)

(439)

Sales

-

(3)

(3)

-

(85)

-

-

(88)

End of 2019

1,779

1,447

3,226

4,414

Revisions

(398)

(226)

(624)

(20)

(3)

(622)

Improved recovery

-

-

-

-

-

-

Purchases

-

-

-

-

Extensions and discoveries

-

-

-

Production

(85)

(142)

(227)

(25)

(49)

(55)

(3)

(359)

Sales

-

(25)

(25)

(1)

-

(10)

-

(36)

End of 2020

1,306

1,273

2,579

3,734

Equity affiliates

End of 2017

-

-

-

-

-

-

Revisions

-

-

-

-

-

-

Improved recovery

-

-

-

-

-

-

-

-

Purchases

-

-

-

-

-

-

-

-

Extensions and discoveries

-

-

-

-

-

-

Production

-

-

-

-

-

(71)

-

(71)

Sales

-

-

-

-

-

-

-

-

End of 2018

-

-

-

-

-

-

Revisions

-

-

-

-

-

(1)

-

(1)

Improved recovery

-

-

-

-

-

-

-

-

Purchases

-

-

-

-

-

-

-

-

Extensions and discoveries

-

-

-

-

-

-

Production

-

-

-

-

-

(73)

-

(73)

Sales

-

-

-

-

-

-

-

-

End of 2019

-

-

-

-

-

-

Revisions

-

-

-

-

-

(63)

-

(63)

Improved recovery

-

-

-

-

-

-

-

-

Purchases

-

-

-

-

-

-

-

-

Extensions and discoveries

-

-

-

-

-

-

Production

-

-

-

-

-

(73)

-

(73)

Sales

-

-

-

-

-

-

-

-

End of 2020

-

-

-

-

-

-

Total

company

End of 2017

1,430

1,353

2,783

1,251

5,038

End of 2018

1,795

1,312

3,107

1,222

5,263

End of 2019

1,779

1,447

3,226

1,146

5,262

End of 2020

1,306

1,273

2,579

4,459

Years Ended

Total Proved

Reserves

December 31

Millions of Barrels of Oil Equivalent

Lower

Total

Asia Pacific/

Alaska

U.S.

Canada

Europe

Middle East

Africa

Total

Developed

Consolidated operations

End of 2017

1,319

2,001

3,045

End of 2018

1,617

2,298

3,305

End of 2019

1,582

2,248

3,174

End of 2020

1,186

1,707

2,508

Equity affiliates

End of 2017

-

-

-

-

-

-

End of 2018

-

-

-

-

-

-

End of 2019

-

-

-

-

-

-

End of 2020

-

-

-

-

-

-

Undeveloped

Consolidated operations

End of 2017

-

1,148

End of 2018

1,078

End of 2019

1,240

End of 2020

1,226

Equity affiliates

End of 2017

-

-

-

-

-

-

End of 2018

-

-

-

-

-

-

End of 2019

-

-

-

-

-

-

End of 2020

-

-

-

-

-

-

Natural gas reserves are converted to barrels

of oil equivalent (BOE) based on a 6:1 ratio:

six MCF of natural gas converts to

one BOE.

Proved Undeveloped Reserves

The following table shows changes in total proved

undeveloped reserves for 2020:

Proved Undeveloped Reserves

Millions of Barrels of

Oil Equivalent

End of 2019

1,327

Revisions

(205)

Improved recovery

Purchases

Extensions and discoveries

Sales

-

Transfers to proved developed

(138)

End of 2020

1,298

Downward revisions were driven by changes in

development timing of 137 MMBOE primarily

in North America and lower

prices of 103 MMBOE, partially offset by upward revisions

for infill drilling of 35 MMBOE primarily

in Lower 48 and Europe.

Extensions and discoveries were largely driven by an addition

of 196 MMBOE in Lower 48 for the continued development

of

unconventional plays. The remaining extensions

and discoveries were driven by the continued

development planned in Canada,

Asia Pacific/Middle East and Alaska.

Transfers to proved developed reserves were driven by the ongoing

development of our assets. Approximately half

of the

transfers were from the development of our

Lower 48 unconventional plays. The remainder

of transfers were from development

across the Alaska, Asia Pacific/Middle East

and Europe regions.

At December 31, 2020, our PUDs represented 29

percent of total proved reserves, compared

with 25 percent at December 31,

Costs incurred for the year ended December

31, 2020, relating to the development of

PUDs were $3.2 billion.

A portion

of our costs incurred each year relates to

development projects where the PUDs will be

converted to proved developed reserves

in future years.

At the end of 2020, more than 97 percent of total

PUDs were under development or scheduled for

development within five

years of initial disclosure, including our PUDs in

North America.

The remaining PUDs are in major development

areas which

are currently producing and within our Asia

Pacific/Middle

East geographic area.

Results of Operations

The company’s results of operations from oil and gas activities

for the years 2020, 2019 and 2018 are shown in the

following

tables.

Non-oil and gas activities, such as pipeline and marine

operations, LNG operations, crude oil and gas marketing

activities, and the profit element of transportation

operations in which we have an ownership

interest are excluded.

Additional

information about selected line items within the

results of operations tables is shown below:

●

Sales include sales to unaffiliated entities attributable

primarily to the company’s net working interests and royalty

interests.

Sales are net of fees to transport our produced hydrocarbons

beyond the production function to a final

delivery point using transportation operations which

are not consolidated.

●

Transportation costs reflect fees to transport our produced hydrocarbons

beyond the production function to a final

delivery point using transportation operations which

are consolidated.

●

Other revenues include gains and losses from asset

sales, certain amounts resulting from

the purchase and sale of

hydrocarbons, and other miscellaneous income.

●

Production costs include costs incurred to operate

and maintain wells, related equipment and facilities

used in the

production of petroleum liquids and natural gas.

●

Taxes other than income taxes include production, property and other non-income

taxes.

●

Depreciation of support equipment is reclassified

as applicable.

●

Other related expenses include inventory fluctuations,

foreign currency transaction gains and losses

and other

miscellaneous expenses.

Results of Operations

Year Ended

Millions of Dollars

December 31, 2020

Lower

Total

Asia Pacific/

Other

Alaska

U.S.

Canada

Europe

Middle East

Africa

Areas

Total

Consolidated operations

Sales

$

2,944

3,421

6,365

1,560

1,717

-

10,001

Transfers

-

-

-

-

-

Transportation costs

(587)

-

(587)

-

-

(19)

-

-

(606)

Other revenues

(1)

(20)

(21)

(21)

Total revenues

2,360

3,401

5,761

1,539

2,465

10,185

Production costs excluding taxes

1,058

1,399

2,457

3,741

Taxes other than income taxes

Exploration expenses

1,099

1,172

1,456

Depreciation, depletion and

amortization

2,544

3,384

-

5,290

Impairments

-

-

-

-

Other related expenses

(58)

(25)

(29)

(54)

Accretion

-

-

(1,051)

(1,733)

(2,784)

(503)

1,058

(103)

(1,943)

Income tax provision (benefit)

(271)

(430)

(701)

(191)

(20)

(431)

Results of operations

$

(780)

(1,303)

(2,083)

(312)

(83)

(1,512)

Equity affiliates

Sales

$

-

-

-

-

-

-

-

Transfers

-

-

-

-

-

1,205

-

-

1,205

Transportation costs

-

-

-

-

-

-

-

-

-

Other revenues

-

-

-

-

-

-

-

Total revenues

-

-

-

-

-

1,696

-

-

1,696

Production costs excluding taxes

-

-

-

-

-

-

-

Taxes other than income taxes

-

-

-

-

-

-

-

Exploration expenses

-

-

-

-

-

-

-

Depreciation, depletion and

amortization

-

-

-

-

-

-

-

Impairments

-

-

-

-

-

-

-

-

-

Other related expenses

-

-

-

-

-

(2)

-

-

(2)

Accretion

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Income tax provision (benefit)

-

-

-

-

-

-

-

Results of operations

$

-

-

-

-

-

-

-

Year Ended

Millions of Dollars

December 31, 2019

Lower

Total

Asia Pacific/

Other

Alaska

U.S.

Canada

Europe

Middle East

Africa

Areas

Total

Consolidated operations

Sales

$

4,883

6,356

11,239

3,207

3,032

-

19,106

Transfers

-

-

-

-

-

Transportation costs

(629)

-

(629)

-

-

(41)

-

-

(670)

Other revenues

1,785

2,449

Total revenues

4,319

6,434

10,753

4,992

3,452

1,020

21,338

Production costs excluding taxes

1,235

1,578

2,813

(8)

4,615

Taxes other than income taxes

(2)

Exploration expenses

Depreciation, depletion and

amortization

2,804

3,504

1,172

-

5,785

Impairments

-

-

-

-

Other related expenses

(12)

(38)

(42)

Accretion

-

-

1,929

2,547

3,207

1,426

8,520

Income tax provision (benefit)

(74)

2,406

Results of operations

$

1,485

1,956

2,616

6,114

Equity affiliates

Sales

$

-

-

-

-

-

-

-

Transfers

-

-

-

-

-

2,229

-

-

2,229

Transportation costs

-

-

-

-

-

-

-

-

-

Other revenues

-

-

-

-

-

-

-

Total revenues

-

-

-

-

-

2,859

-

-

2,859

Production costs excluding taxes

-

-

-

-

-

-

-

Taxes other than income taxes

-

-

-

-

-

-

-

Exploration expenses

-

-

-

-

-

-

-

-

-

Depreciation, depletion and

amortization

-

-

-

-

-

-

-

Impairments

-

-

-

-

-

-

-

-

-

Other related expenses

-

-

-

-

-

-

-

Accretion

-

-

-

-

-

-

-

-

-

-

-

-

1,098

-

-

1,098

Income tax provision (benefit)

-

-

-

-

-

-

-

Results of operations

$

-

-

-

-

-

-

-

Year Ended

Millions of Dollars

December 31, 2018

Lower

Total

Asia Pacific/

Other

Alaska

U.S.

Canada

Europe

Middle East

Africa

Areas

Total

Consolidated operations

Sales

$

4,816

6,573

11,389

4,449

3,177

-

20,547

Transfers

-

-

-

-

-

Transportation costs

(722)

-

(722)

-

-

(45)

-

-

(767)

Other revenues

1,997

Total revenues

4,434

6,786

11,220

5,186

3,683

1,060

22,327

Production costs excluding taxes

1,533

2,497

4,480

Taxes other than income taxes

-

Exploration expenses

(4)

Depreciation, depletion and

amortization

2,279

2,895

1,070

1,186

-

5,497

Impairments

(78)

-

-

Other related expenses

(62)

(19)

(1)

Accretion

-

-

2,365

2,188

4,553

(98)

3,132

1,679

10,642

Income tax provision (benefit)

(114)

1,354

(8)

3,726

Results of operations

$

1,946

1,722

3,668

1,778

6,916

Equity affiliates

Sales

$

-

-

-

-

-

-

-

Transfers

-

-

-

-

-

2,018

-

-

2,018

Transportation costs

-

-

-

-

-

-

-

-

-

Other revenues

-

-

-

-

-

(6)

-

-

(6)

Total revenues

-

-

-

-

-

2,770

-

-

2,770

Production costs excluding taxes

-

-

-

-

-

-

-

Taxes other than income taxes

-

-

-

-

-

-

-

Exploration expenses

-

-

-

-

-

-

-

-

-

Depreciation, depletion and

-

-

-

-

amortization

-

-

-

-

-

-

-

Impairments

-

-

-

-

-

-

-

-

-

Other related expenses

-

-

-

-

-

(4)

-

-

(4)

Accretion

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Income tax provision (benefit)

-

-

-

-

-

-

-

Results of operations

$

-

-

-

-

-

-

-

Statistics

Net Production

2020

2019

2018

Thousands of Barrels Daily

Crude Oil

Consolidated operations

Alaska

Lower 48

United States

Canada

Europe

Asia Pacific

Africa

Total consolidated

operations

Equity affiliates—

Asia Pacific/Middle East

Total company

Greater Prudhoe Area

(Alaska)*

Natural Gas Liquids

Consolidated operations

Alaska

Lower 48

United States

Canada

-

Europe

Asia Pacific

Total consolidated

operations

Equity affiliates—

Asia Pacific/Middle East

Total company

Greater Prudhoe Area

(Alaska)*

Bitumen

Consolidated operations—

Canada

Total company

Natural Gas

Millions of Cubic Feet Daily

Consolidated operations

Alaska

Lower 48

United States

Canada

Europe

Asia Pacific

Africa

Total consolidated

operations

1,339

1,753

1,743

Equity affiliates—

Asia Pacific/Middle East

1,055

1,052

1,031

Total company

2,394

2,805

2,774

Greater Prudhoe Area

(Alaska)*

*At year-end 2020 and 2019, the Greater Prudhoe Area in Alaska contained more than 15 percent of our total proved reserves.

Average Sales

Prices

2020

2019

2018

Crude Oil Per Barrel

Consolidated operations

Alaska*

$

33.72

55.85

60.23

Lower 48

35.17

55.30

62.99

United States

34.48

55.54

61.75

Canada

23.57

40.87

48.73

Europe

42.80

65.12

70.98

Asia Pacific

42.84

65.02

70.93

Africa

48.64

64.47

69.83

Total international

42.39

64.85

70.67

Total consolidated

operations

36.69

58.51

65.01

Equity affiliates

—Asia Pacific/Middle East

39.02

61.32

72.49

Total operations

36.75

58.57

65.17

Natural Gas Liquids Per Barrel

Consolidated operations

Lower 48

$

12.13

16.83

27.30

United States

12.13

16.85

27.30

Canada

5.41

19.87

43.70

Europe

23.27

29.37

36.87

Asia Pacific

33.21

37.85

47.20

Total international

20.25

32.29

40.00

Total consolidated

operations

12.90

18.73

29.03

Equity affiliates

—Asia Pacific/Middle East

32.69

36.70

45.69

Total operations

14.61

20.09

30.48

Bitumen Per Barrel

Consolidated operations—

Canada

$

8.02

**

31.72

22.29

Natural Gas Per Thousand Cubic Feet

Consolidated operations

Alaska

$

2.91

3.19

2.48

Lower 48

1.65

2.12

2.82

United States

1.66

2.12

2.82

Canada

1.21

0.49

1.00

Europe

3.23

4.92

7.79

Asia Pacific*

5.27

5.73

5.95

Africa

3.71

4.87

4.84

Total international

4.31

5.35

6.64

Total consolidated

operations

3.13

4.19

5.33

Equity affiliates

—Asia Pacific/Middle East

3.71

6.29

6.06

Total operations

3.38

4.99

5.60

*Average sales prices for Alaska crude oil and Asia Pacific natural gas above reflect a reduction for transportation

costs in which we

have an ownership interest that are incurred subsequent to the terminal point of the production function.

Accordingly, the average sales prices

differ from those discussed in Item 7 of Management's Discussion and Analysis

of Financial Condition and Results of Operations.

**Average sales prices include unutilized transportation costs.

2020

2019

2018

Average Production

Costs Per Barrel of Oil Equivalent*

Consolidated operations

Alaska

$

14.60

15.52

14.20

Lower 48

9.93

9.59

10.58

United States

11.51

11.52

11.73

Canada

14.29

16.53

16.32

Europe

8.97

11.22

11.73

Asia Pacific

9.26

8.74

9.03

Africa

6.38

4.46

4.14

Total international

10.11

10.26

10.72

Total consolidated operations

10.99

10.99

11.26

Equity affiliates—

Asia Pacific/Middle East

4.01

4.68

4.56

Average Production

Costs Per Barrel—Bitumen

Consolidated operations—

Canada

$

12.45

13.74

13.59

Taxes

Other Than Income Taxes Per Barrel

of Oil Equivalent

Consolidated operations

Alaska

$

4.08

3.87

5.26

Lower 48

1.87

2.65

2.98

United States

2.62

3.05

3.71

Canada

0.62

0.78

0.82

Europe

0.65

0.48

0.45

Asia Pacific

0.81

0.76

1.33

Africa

0.91

0.19

0.20

Total international

0.72

0.60

0.82

Total consolidated operations

1.91

2.03

2.37

Equity affiliates—

Asia Pacific/Middle East

6.96

11.46

11.41

Depreciation, Depletion and Amortization Per Barrel of Oil Equivalent

Consolidated operations

Alaska

$

11.59

8.80

9.07

Lower 48

18.05

17.03

15.73

United States

15.86

14.35

13.60

Canada

13.08

10.00

12.25

Europe

16.24

12.75

14.66

Asia Pacific

15.66

16.55

16.58

Africa

2.43

2.36

2.21

Total international

15.01

12.99

14.06

Total consolidated operations

15.54

13.78

13.82

Equity affiliates—

Asia Pacific/Middle East

7.89

8.09

9.09

*Includes bitumen.

Development and Exploration Activities

The following two tables summarize our net interest

in productive and dry exploratory and development

wells

in the years ended December 31, 2020,

2019 and 2018.

A “development well” is a well drilled

within the

proved area of a reservoir to the depth of a stratigraphic

horizon known to be productive.

An “exploratory

well” is a well drilled to find and produce crude

oil or natural gas in an unknown field or

a new reservoir

within a proven field.

Exploratory wells also include wells

drilled in areas near or offsetting current

production, or in areas where well density or production

history have not achieved statistical certainty

of

results.

Excluded from the exploratory well count are stratigraphic-type

exploratory wells, primarily relating

to oil sands delineation wells located in Canada

and CBM test wells located in Asia Pacific/Middle

East.

Net Wells Completed

Productive

Dry

2020

2019

2018

2020

2019

2018

Exploratory

Consolidated operations

Alaska

-

-

-

Lower 48

-

United States

Canada

-

-

-

-

Europe

-

Asia Pacific/Middle East

-

Africa

-

-

-

-

Other areas

-

-

-

-

-

Total consolidated operations

Equity affiliates

Asia Pacific/Middle East

-

-

Total equity affiliates

-

-

Development

Consolidated operations

Alaska

-

-

-

Lower 48

-

-

-

United States

-

-

-

Canada

-

-

-

-

Europe

-

-

-

Asia Pacific/Middle East

-

-

-

Africa

-

-

-

Other areas

-

-

-

-

-

-

Total consolidated operations

-

-

-

Equity affiliates

Asia Pacific/Middle East

-

-

-

Total equity affiliates

-

-

-

*Our total proportionate interest was less than one.

The table below represents the status of our wells

drilling at December 31, 2020, and includes

wells in the

process of drilling or in active completion.

It also represents gross and net productive

wells, including

producing wells and wells capable of production

at December 31, 2020.

Wells at December 31, 2020

Productive

In Progress

Oil

Gas

Gross

Net

Gross

Net

Gross

Net

Consolidated operations

Alaska

1,576

-

-

Lower 48

9,382

4,149

4,182

1,678

United States

10,958

5,095

4,182

1,678

Canada

Europe

Asia Pacific/Middle East

Africa

Other areas

-

-

-

-

Total consolidated

operations

12,817

5,576

4,458

1,864

Equity affiliates

Asia Pacific/Middle East

-

-

4,898

1,154

Total equity affiliates

-

-

4,898

1,154

Acreage at December 31, 2020

Thousands of Acres

Developed

Undeveloped

Gross

Net

Gross

Net

Consolidated operations

Alaska

1,345

1,336

Lower 48

3,228

1,974

10,215

8,165

United States

3,887

2,446

11,560

9,501

Canada

3,417

1,946

Europe

Asia Pacific/Middle East

9,015

5,704

Africa

12,545

2,049

Other areas

-

-

Total consolidated

operations

5,889

3,189

38,499

20,111

Equity affiliates

Asia Pacific/Middle East

1,026

3,820

Total equity affiliates

1,026

3,820

Costs Incurred

Year Ended

Millions of Dollars

December 31

Lower

Total

Asia Pacific/

Other

Alaska

U.S.

Canada

Europe

Middle East

Africa

Areas

Total

2020

Consolidated operations

Unproved property acquisition

$

-

-

Proved property acquisition

-

-

-

-

-

-

-

Exploration

Development

1,758

2,503

-

3,501

$

1,036

1,946

2,982

4,901

Equity affiliates

Unproved property acquisition

$

-

-

-

-

-

-

-

-

-

Proved property acquisition

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Exploration

-

-

-

-

-

-

-

Development

-

-

-

-

-

-

-

$

-

-

-

-

-

-

-

2019

Consolidated operations

Unproved property acquisition

$

-

-

-

Proved property acquisition

-

-

-

-

-

-

Exploration

1,103

Development

1,125

3,028

4,153

-

5,501

$

1,508

3,579

5,087

7,193

Equity affiliates

Unproved property acquisition

$

-

-

-

-

-

-

-

Proved property acquisition

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Exploration

-

-

-

-

-

-

-

Development

-

-

-

-

-

-

-

$

-

-

-

-

-

-

-

2018

Consolidated operations

Unproved property acquisition

$

-

-

-

-

Proved property acquisition

2,227

2,243

-

-

-

-

2,249

2,346

2,488

-

-

-

-

2,620

Exploration

(6)

Development

2,715

3,433

-

5,226

$

3,267

3,357

6,624

8,821

Equity affiliates

Unproved property acquisition

$

-

-

-

-

-

-

-

-

-

Proved property acquisition

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Exploration

-

-

-

-

-

-

-

Development

-

-

-

-

-

-

-

$

-

-

-

-

-

-

-

Capitalized Costs

At December 31

Millions of Dollars

Lower

Total

Asia Pacific/

Other

Alaska

U.S.

Canada

Europe

Middle East

Africa

Areas

Total

2020

Consolidated operations

Proved property

$

21,819

37,452

59,271

7,255

14,931

11,913

-

94,312

Unproved property

1,398

2,029

1,529

4,141

23,217

38,083

61,300

8,784

15,082

12,002

1,056

98,453

Accumulated depreciation,

depletion and amortization

11,098

27,948

39,046

2,431

10,015

8,567

60,455

$

12,119

10,135

22,254

6,353

5,067

3,435

37,998

Equity affiliates

Proved property

$

-

-

-

-

-

10,310

-

-

10,310

Unproved property

-

-

-

-

-

2,187

-

-

2,187

-

-

-

-

-

12,497

-

-

12,497

Accumulated depreciation,

depletion and amortization

-

-

-

-

-

6,959

-

-

6,959

$

-

-

-

-

-

5,538

-

-

5,538

2019

Consolidated operations

Proved property

$

20,957

37,491

58,448

6,673

14,113

14,566

-

94,724

Unproved property

1,429

1,055

2,484

1,149

4,634

22,386

38,546

60,932

7,822

14,200

15,067

1,047

99,358

Accumulated depreciation,

depletion and amortization

9,419

26,294

35,713

2,050

9,017

10,253

57,421

$

12,967

12,252

25,219

5,772

5,183

4,814

41,937

Equity affiliates

Proved property

$

-

-

-

-

-

9,996

-

-

9,996

Unproved property

-

-

-

-

-

2,223

-

-

2,223

-

-

-

-

-

12,219

-

-

12,219

Accumulated depreciation,

depletion and amortization

-

-

-

-

-

6,390

-

-

6,390

$

-

-

-

-

-

5,829

-

-

5,829

Standardized Measure of Discounted Future Net Cash Flows

Relating to Proved Oil and Gas Reserve Quantities

In accordance with SEC and FASB requirements, amounts were computed using

12-month average prices (adjusted only for

existing contractual terms)

and end-of-year costs,

appropriate statutory tax rates and a

prescribed 10 percent discount factor.

Twelve-month average prices are calculated as the unweighted arithmetic average of

the first-day-of-the-month price for each

month within the 12-month period prior to the end

of the reporting period.

For all years, continuation of year-end economic

conditions was assumed.

The calculations were based on estimates

of proved reserves, which are revised over time as

new data

becomes available.

Probable or possible reserves, which may become

proved in the future, were not considered.

The

calculations also require assumptions as to the

timing of future production of proved reserves

and the timing and amount of

future development costs,

including dismantlement, and future production costs,

including taxes other than income taxes.

While due care was taken in its preparation, we

do not represent that this data is the fair value

of our oil and gas properties, or a

fair estimate of the present value of cash flows to

be obtained from their development and production.

Discounted Future Net Cash Flows

Millions of Dollars

Lower

Total

Asia Pacific/

Alaska

U.S.

Canada

Europe

Middle East

Africa

Total

2020

Consolidated operations

Future cash inflows

$

30,145

31,533

61,678

4,198

9,857

7,940

9,997

93,670

Less:

Future production costs

22,905

17,582

40,487

4,316

4,770

3,838

1,277

54,688

Future development costs

7,932

12,799

20,731

3,688

1,289

26,919

Future income tax provisions

-

-

1,075

7,571

9,289

Future net cash flows

(692)

(868)

1,132

1,738

2,774

10 percent annual discount

(1,501)

(820)

(2,321)

(396)

(1,900)

Discounted future net cash flows

$

1,596

2,405

(472)

1,015

1,332

4,674

Equity affiliates

Future cash inflows

$

-

-

-

-

-

17,284

-

17,284

Less:

Future production costs

-

-

-

-

-

10,239

-

10,239

Future development costs

-

-

-

-

-

1,186

-

1,186

Future income tax provisions

-

-

-

-

-

1,728

-

1,728

Future net cash flows

-

-

-

-

-

4,131

-

4,131

10 percent annual discount

-

-

-

-

-

1,269

-

1,269

Discounted future net cash flows

$

-

-

-

-

-

2,862

-

2,862

Total

company

Discounted future net cash flows

$

1,596

2,405

(472)

1,015

4,194

7,536

*Undiscounted future net cash flows related to the proved oil and gas reserves disclosed for Canada for the year ending December 31, 2020,

are negative due to the inclusion of asset retirement costs and certain indirect costs in the calculation of the standardized measure of

discounted future net cash flows. These costs are not required to be included in the economic limit test for proved developed reserves as

defined in Regulation S-X Rule 4-10.

Future net cash flows for Canada were also impacted by lower 12-month average pricing for bitumen

and crude oil in 2020.

Commodity prices have since improved in the current environment.

Millions of Dollars

Lower

Total

Asia Pacific/

Alaska

U.S.

Canada

Europe

Middle East

Africa

Total

2019

Consolidated operations

Future cash inflows

$

70,341

53,400

123,741

8,244

16,919

13,084

15,582

177,570

Less:

Future production costs

40,464

22,194

62,658

4,525

5,843

5,162

1,314

79,502

Future development costs

9,721

14,083

23,804

4,143

2,179

31,187

Future income tax provisions

3,904

2,793

6,697

-

4,201

1,931

12,747

25,576

Future net cash flows

16,252

14,330

30,582

3,142

2,732

3,812

1,037

41,305

10 percent annual discount

6,571

4,311

10,882

1,198

13,933

Discounted future net cash flows

$

9,681

10,019

19,700

1,944

2,174

2,977

27,372

Equity affiliates

Future cash inflows

$

-

-

-

-

-

31,671

-

31,671

Less:

Future production costs

-

-

-

-

-

16,157

-

16,157

Future development costs

-

-

-

-

-

1,218

-

1,218

Future income tax provisions

-

-

-

-

-

3,086

-

3,086

Future net cash flows

-

-

-

-

-

11,210

-

11,210

10 percent annual discount

-

-

-

-

-

4,040

-

4,040

Discounted future net cash flows

$

-

-

-

-

-

7,170

-

7,170

Total

company

Discounted future net cash flows

$

9,681

10,019

19,700

1,944

2,174

10,147

34,542

Millions of Dollars

Lower

Total

Asia Pacific/

Alaska

U.S.

Canada

Europe

Middle East

Africa

Total

2018

Consolidated operations

Future cash inflows

$

82,072

56,922

138,994

6,039

26,989

16,368

16,434

204,824

Less:

Future production costs

42,755

21,363

64,118

4,099

8,567

5,705

1,336

83,825

Future development costs

10,053

12,136

22,189

7,608

1,995

32,905

Future income tax provisions

5,538

4,418

9,956

-

7,102

2,873

13,492

33,423

Future net cash flows

23,726

19,005

42,731

1,334

3,712

5,795

1,099

54,671

10 percent annual discount

10,349

6,461

16,810

1,132

19,237

Discounted future net cash flows

$

13,377

12,544

25,921

3,341

4,663

35,434

Equity affiliates

Future cash inflows

$

-

-

-

-

-

33,606

-

33,606

Less:

Future production costs

-

-

-

-

-

16,449

-

16,449

Future development costs

-

-

-

-

-

1,228

-

1,228

Future income tax provisions

-

-

-

-

-

3,147

-

3,147

Future net cash flows

-

-

-

-

-

12,782

-

12,782

10 percent annual discount

-

-

-

-

-

4,853

-

4,853

Discounted future net cash flows

$

-

-

-

-

-

7,929

-

7,929

Total

company

Discounted future net cash flows

$

13,377

12,544

25,921

3,341

12,592

43,363

Sources of Change in Discounted Future Net Cash Flows

Millions of Dollars

Consolidated Operations

Equity Affiliates

Total Company

2020

2019

2018

2020

2019

2018

2020

2019

2018

Discounted future net cash flows

at the beginning of the year

$

27,372

35,434

20,609

7,170

7,929

4,395

34,542

43,363

25,004

Changes during the year

Revenues less production

costs for the year

(5,198)

(13,424)

(14,909)

(897)

(1,673)

(1,651)

(6,095)

(15,097)

(16,560)

Net change in prices and

production costs

(34,307)

(13,538)

25,391

(4,769)

(422)

4,559

(39,076)

(13,960)

29,950

Extensions, discoveries and

improved recovery, less

estimated future costs

2,985

4,574

3,245

4,956

Development costs for the year

3,593

5,333

5,197

3,785

5,572

5,468

Changes in estimated future

development costs

(1,141)

(205)

(21)

(1,127)

Purchases of reserves in place,

less estimated future costs

3,033

(3)

-

-

(2)

3,033

Sales of reserves in place,

less estimated future costs

(302)

(1,997)

(1,531)

-

-

-

(302)

(1,997)

(1,531)

Revisions of previous quantity

estimates

(2,299)

2,099

(365)

(42)

(2,341)

2,168

(303)

Accretion of discount

3,984

5,144

3,055

4,788

6,013

3,540

Net change in income taxes

10,189

4,767

(8,479)

(80)

(588)

10,779

4,687

(9,067)

Total changes

(22,698)

(8,062)

14,825

(4,308)

(759)

3,534

(27,006)

(8,821)

18,359

Discounted future net cash flows

at year end

$

4,674

27,372

35,434

2,862

7,170

7,929

7,536

34,542

43,363

●

The net change in prices and production costs

is the beginning-of-year reserve-production

forecast multiplied by the net

annual change in the per-unit sales price and production cost,

discounted at 10 percent.

●

Purchases and sales of reserves in place, along with

extensions, discoveries and improved recovery, are calculated using

production forecasts of the applicable reserve

quantities for the year multiplied by the

12-month average sales prices, less

future estimated costs, discounted at 10 percent.

●

Revisions of previous quantity estimates

are calculated using production forecast changes

for the year, including changes in

the timing of production, multiplied by the 12-month

average sales prices, less future estimated

costs, discounted at

10 percent.

●

The accretion of discount is 10 percent of the prior

year’s discounted future cash inflows, less future production

and

development costs.

●

The net change in income taxes is the annual

change in the discounted future income tax provisions.