Item 8. , and financial statement schedule listed

in Item 15(a) (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, 2019 and 2018, and the

results of its

operations and its cash flows for each of the three

years in the period ended December 31, 2019,

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, 2019,

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 18, 2020,

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, 2019, the asset retirement

obligation (“ARO”) balance totaled $6.2

billion. As further described in Note 10, 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 obligations related to certain

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 underlying removal cost

estimates.

Depreciation, depletion and amortization of

proved oil and gas properties

Description of

the Matter

At December 31, 2019, the net book value of

the Company’s properties, plants and

equipment was $42.3 billion, and depreciation,

depletion and amortization (DD&A)

expense was $6.1 billion for the year then ended.

As described in Note 1, DD&A of

properties, plants and equipment on producing

hydrocarbon properties and certain

pipeline and LNG assets (those which are expected

to have a declining utilization

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

based on proved oil and gas

reserves, as estimated by the Company’s internal reservoir engineers. 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. Significant

judgment is required by the Company’s internal reservoir engineers

in evaluating

geological and engineering data when estimating

proved 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 a third-party petroleum

engineering 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 calculation is complex because of the

use of the work of

the internal reservoir engineers and third-party petroleum

engineering firm and the

evaluation of management’s determination of the inputs described above

used by the

internal reservoir engineers in estimating

proved 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 process to calculate DD&A,

including management’s controls over the completeness and accuracy of the

financial

data provided to the internal reservoir engineers

for use in estimating proved 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 third-party petroleum

engineering 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

proved oil and gas reserves by agreeing

them to source documentation and we identified

and evaluated corroborative and

contrary evidence. For proved undeveloped reserves,

we evaluated management’s

development plan for compliance with the SEC

rule that undrilled locations are

scheduled to be drilled within five years, unless

specific circumstances justify a longer

time, by assessing consistency of the development

projections with the Company’s drill

plan. We also tested the accuracy of the DD&A calculations, including comparing the

proved oil and gas reserve amounts used in the

calculation to the Company’s reserve

report.

/s/ Ernst & Young LLP

We have served as ConocoPhillips’ auditor since 1949.

Houston, Texas

February 18, 2020

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,

2019, 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, 2019,

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, 2019 and 2018, 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, 2019, and the related notes,

condensed consolidating

financial information listed in the Index at Item 8, and financial statement schedule

listed in Item 15(a) and our

report dated February 18, 2020, 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

“Report 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 18, 2020

Consolidated Income Statement

ConocoPhillips

Years

Ended December 31

Millions of Dollars

2019

2018

2017

Revenues and Other Income

Sales and other operating revenues

$

32,567

36,417

29,106

Equity in earnings of affiliates

1,074

Gain on dispositions

1,966

1,063

2,177

Other income

1,358

Total Revenues and

Other Income

36,670

38,727

32,584

Costs and Expenses

Purchased commodities

11,842

14,294

12,475

Production and operating expenses

5,322

5,213

5,162

Selling, general and administrative expenses

Exploration expenses

Depreciation, depletion and amortization

6,090

5,956

6,845

Impairments

6,601

Taxes other than income

taxes

1,048

Accretion on discounted liabilities

Interest and debt expense

1,098

Foreign currency transaction (gains) losses

(17)

Other expenses

Total Costs and Expenses

27,146

28,754

35,199

Income (loss) before income taxes

9,524

9,973

(2,615)

Income tax provision (benefit)

2,267

3,668

(1,822)

Net income (loss)

7,257

6,305

(793)

Less: net income attributable to noncontrolling interests

(68)

(48)

(62)

Net Income (Loss) Attributable to ConocoPhillips

$

7,189

6,257

(855)

Net Income (Loss) Attributable to ConocoPhillips Per Share

of Common Stock

(dollars)

Basic

$

6.43

5.36

(0.70)

Diluted

6.40

5.32

(0.70)

Average Common

Shares Outstanding

(in thousands)

Basic

1,117,260

1,166,499

1,221,038

Diluted

1,123,536

1,175,538

1,221,038

See Notes to Consolidated Financial Statements.

Consolidated Statement of Comprehensive Income

ConocoPhillips

Years

Ended December 31

Millions of Dollars

2019

2018

2017

Net Income (Loss)

$

7,257

6,305

(793)

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)

(35)

(40)

(38)

Net change

(35)

(47)

(36)

Net actuarial gain (loss) arising during the period

(55)

(150)

Reclassification adjustment for amortization of net

actuarial losses included in net income (loss)

Net change

Nonsponsored plans*

(3)

(1)

(2)

Income taxes on defined benefit plans

(2)

(42)

(81)

Defined benefit plans, net of tax

Unrealized holding loss on securities

-

-

(58)

Unrealized loss on securities, net of tax

-

-

(58)

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)

8,003

5,702

(118)

Less: comprehensive income attributable to noncontrolling interests

(68)

(48)

(62)

Comprehensive Income (Loss) Attributable to ConocoPhillips

$

7,935

5,654

(180)

*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

2019

2018

Assets

Cash and cash equivalents

$

5,088

5,915

Short-term investments

3,028

Accounts and notes receivable (net of allowance of $

million in 2019

and $

million in 2018)

3,267

3,920

Accounts and notes receivable—related parties

Investment in Cenovus Energy

2,111

1,462

Inventories

1,026

1,007

Prepaid expenses and other current assets

2,259

Total Current Assets

16,913

13,274

Investments and long-term receivables

8,687

9,329

Loans and advances—related parties

Net properties, plants and equipment (net of accumulated depreciation,

depletion

and amortization of $

55,477

million in 2019 and $

64,899

million in 2018)

42,269

45,698

Other assets

2,426

1,344

Total Assets

$

70,514

69,980

Liabilities

Accounts payable

$

3,176

3,863

Accounts payable—related parties

Short-term debt

Accrued income and other taxes

1,030

1,320

Employee benefit obligations

Other accruals

2,045

1,259

Total Current Liabilities

7,043

7,395

Long-term debt

14,790

14,856

Asset retirement obligations and accrued environmental costs

5,352

7,688

Deferred income taxes

4,634

5,021

Employee benefit obligations

1,781

1,764

Other liabilities and deferred credits

1,864

1,192

Total Liabilities

35,464

37,916

Equity

Common stock (

2,500,000,000

shares authorized at $

0.01

par value)

Issued (2019—

1,795,652,203

shares; 2018—

1,791,637,434

shares)

Par value

Capital in excess of par

46,983

46,879

Treasury stock (at cost: 2019—

710,783,814

shares; 2018—

653,288,213

shares)

(46,405)

(42,905)

Accumulated other comprehensive loss

(5,357)

(6,063)

Retained earnings

39,742

34,010

Total Common

Stockholders’ Equity

34,981

31,939

Noncontrolling interests

Total Equity

35,050

32,064

Total Liabilities and Equity

$

70,514

69,980

See Notes to Consolidated Financial Statements.

Consolidated Statement of Cash Flows

ConocoPhillips

Years

Ended December 31

Millions of Dollars

2019

2018

2017

Cash Flows From Operating Activities

Net income (loss)

$

7,257

6,305

(793)

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

operating activities

Depreciation, depletion and amortization

6,090

5,956

6,845

Impairments

6,601

Dry hole costs and leasehold impairments

Accretion on discounted liabilities

Deferred taxes

(444)

(3,681)

Undistributed equity earnings

(232)

Gain on dispositions

(1,966)

(1,063)

(2,177)

Other

(1,000)

(429)

Working

capital adjustments

Decrease (increase) in accounts and notes receivable

(886)

Decrease (increase) in inventories

(67)

(55)

Decrease (increase) in prepaid expenses and other current assets

(55)

Increase (decrease) in accounts payable

(378)

(52)

Increase (decrease) in taxes and other accruals

(676)

Net Cash Provided by Operating Activities

11,104

12,934

7,077

Cash Flows From Investing Activities

Capital expenditures and investments

(6,636)

(6,750)

(4,591)

Working

capital changes associated with investing activities

(103)

(68)

Proceeds from asset dispositions

3,012

1,082

13,860

Net sales (purchases) of investments

(2,910)

1,620

(1,790)

Collection of advances/loans—related parties

Other

(108)

Net Cash Provided by (Used in) Investing Activities

(6,618)

(3,843)

7,762

Cash Flows From Financing Activities

Repayment of debt

(80)

(4,995)

(7,876)

Issuance of company common stock

(30)

(63)

Repurchase of company common stock

(3,500)

(2,999)

(3,000)

Dividends paid

(1,500)

(1,363)

(1,305)

Other

(119)

(123)

(112)

Net Cash Used in Financing Activities

(5,229)

(9,359)

(12,356)

Effect of Exchange Rate Changes on Cash, Cash Equivalents

and Restricted Cash

(46)

(117)

Net Change in Cash, Cash Equivalents and Restricted Cash

(789)

(385)

2,715

Cash, cash equivalents and restricted cash at beginning of period

6,151

6,536

3,610

Cash, Cash Equivalents and Restricted Cash at End of Period

$

5,362

6,151

6,325

Restricted cash of $

million and $

million are included in the “Prepaid expenses and other current assets” and “Other assets” lines,

respectively, of our Consolidated Balance Sheet as of December 31, 2019.

Restricted cash totaling $

million is included in the “Other assets” line of our Consolidated

Balance Sheet as of December 31, 2018.

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

December 31, 2016

$

46,507

(36,906)

(6,193)

31,548

35,226

Net income (loss)

(855)

(793)

Other comprehensive income

Dividends paid ($

1.06

per share of common stock)

(1,305)

(1,305)

Repurchase of company common stock

(3,000)

(3,000)

Distributions to noncontrolling interests and other

(120)

(120)

Distributed under benefit plans

Other

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

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

December 31, 2019

$

46,983

(46,405)

(5,357)

39,742

35,050

*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.

**See Note 2—Changes in Accounting Principles for additional

information.

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 and North Africa, Asia Pacific

and Middle East, and Other International.

For

additional information, see Note 25—Segment

Disclosures and Related Information.

■

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.

■

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 8—

Suspended Wells and Other 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 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 and annually in the fourth

quarter

following updates to corporate planning assumptions.

If there is an indication the carrying amount of

an

asset may not be recovered, the asset is monitored

by management through an established

process where

changes to significant assumptions such as prices,

volumes and future development plans are reviewed.

If, upon review, the sum of the undiscounted before-tax cash flows is less

than the carrying value of the

asset group, the carrying value is written down to

estimated fair value through additional

amortization or

depreciation provisions and reported as impairments

in the periods 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

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 and annually following updates to corporate

planning assumptions.

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 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).

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 10—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 in a purchase

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. 2016-02, “Leases,” (ASC Topic 842) and its amendments,

beginning January 1, 2019.

ASC Topic 842 establishes comprehensive accounting and financial reporting

requirements for leasing arrangements, supersedes

the existing requirements in FASB ASC Topic 840,

“Leases” (ASC Topic 840), and requires lessees to recognize substantially

all lease assets and lease liabilities

on the balance sheet.

The provisions of ASC Topic 842 also modify the definition of a lease

and outline

requirements for recognition, measurement, presentation

and disclosure of leasing arrangements by

both

lessees and lessors.

We adopted ASC Topic

842 using the modified retrospective

approach and elected to utilize the Optional

Transition Method, which permits us to apply the provisions

of ASC Topic 842 to leasing arrangements

existing at or entered into after January 1, 2019,

and present in our financial statements comparative

periods

prior to January 1, 2019 under the historical

requirements of ASC Topic 840.

In addition, we elected to adopt

the package of optional transition-related practical

expedients, which among other things, allows us to

carry

forward certain historical conclusions reached

under ASC Topic 840 regarding lease identification,

classification, and the accounting treatment

of initial direct costs.

Furthermore, we elected not to record assets

and liabilities on our consolidated balance sheet

for new or existing lease arrangements

with terms of 12

months or less.

The primary impact of applying ASC Topic 842 is the initial recognition

of $

million of lease liabilities and

corresponding right-of-use assets on our consolidated

balance sheet as of January 1, 2019, for leases

classified

as operating leases under ASC Topic 840, as well as enhanced disclosure of our leasing

arrangements.

Our

accounting treatment for finance leases remains

unchanged.

In addition, there is no cumulative effect to

retained earnings or other components of equity

recognized as of January 1, 2019, and the adoption

of ASC

Topic 842 did not impact the presentation of our consolidated income statement

or statement of cash flows.

See Note 17—Non-Mineral Leases for additional

information related to the adoption of ASC Topic 842.

We adopted the provisions of FASB ASU No. 2018-02, “Reclassification of Certain Tax Effects from

Accumulated Other Comprehensive Income,”

beginning January 1, 2019.

The ASU allows a reclassification

from accumulated other comprehensive income

to retained earnings for stranded tax effects resulting

from the

Tax Cuts and Jobs Act, eliminating the stranded tax effects.

The cumulative effect to our consolidated balance

sheet at January 1, 2019 for the adoption of

ASU No. 2018-02 was as follows:

Millions of Dollars

December 31

ASU No. 2018-02

January 1

2018

Adjustments

2019

Equity

Accumulated other comprehensive loss

$

(6,063)

(40)

(6,103)

Retained earnings

34,010

34,050

For additional information regarding the impact of the adoption of ASU No. 2018-02, see

Note 20—Accumulated Other Comprehensive Loss.

Note 3—Variable Interest Entities

We hold variable interests in VIEs for which there are existing arrangements that provide

those entities with

additional forms of subordinated financial support.

However, as we are not considered the primary

beneficiary, these entities have not been consolidated in our financial statements.

Marine Well Containment Company, LLC (MWCC)

We have a

percent ownership interest in MWCC, and

it is accounted for as an equity method investment

because MWCC is a limited liability company

in which we are a founding member.

MWCC is considered a

VIE, as it has entered into arrangements that provide

it with additional forms of subordinated

financial support.

We are not the primary beneficiary and do not consolidate MWCC because we share

the power to govern the

business and operation of the company and to

undertake certain obligations that most

significantly impact its

economic performance with nine other unaffiliated

owners of MWCC.

Based on inputs related to the fair value of MWCC

observed in the second quarter of 2019, we reduced

the

carrying value of our equity method investment

in MWCC to $

million and recorded a before-tax

impairment of $

million which is included in the “Equity

in earnings of affiliates” line on our consolidated

income statement. For additional information

see Note 15—Fair Value Measurement.

At December 31, 2019,

the book value of our equity method investment

in MWCC was $

million. We have not provided any

financial support to MWCC other than amounts

previously contractually required. Unless we elect

otherwise,

we have no requirement to provide liquidity

or purchase the assets of MWCC.

Australia Pacific LNG Pty Ltd (APLNG)

We hold a

37.5

percent interest in APLNG, our joint venture

with Origin Energy and Sinopec. We are not the

primary beneficiary because we share, with

our joint venture partners, the power to direct

the key activities of

APLNG that most significantly impacts its

economic performance. Therefore, we do not consolidate

APLNG

and account for this entity as an equity method

investment.

As of December 31, 2019, we no longer have

certain guarantees that provide APLNG with additional

subordinated financial support. For additional

information see Note 12—Guarantees.

Note 4—Inventories

Inventories at December 31 were:

Millions of Dollars

2019

2018

Crude oil and natural gas

$

Materials and supplies

$

1,026

1,007

Inventories valued on the LIFO basis totaled

$

million and $

million at December 31, 2019 and 2018,

respectively.

The estimated excess of current replacement

cost over LIFO cost of inventories was

approximately $

million and $

million at December 31, 2019 and December

31, 2018, respectively.

Note 5—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 are included in the “Cash Flows

From Investing Activities” section of our consolidated

statement of cash flows.

2019

Assets Held for Sale

In October 2019, we entered into an agreement to sell

the subsidiaries that hold our Australia-West assets and

operations to Santos for $

1.39

billion, plus customary adjustments, with an effective

date of January 1, 2019.

In addition, we will receive a payment of $

million upon final investment decision of

the Barossa

development project.

These subsidiaries hold our

37.5

percent interest in the Barossa Project and

Caldita

Field, our

56.9

percent interest in the Darwin LNG Facility and

Bayu-Undan Field, our

percent interest in

the Greater Poseidon Fields, and our

percent interest in the Athena Field.

The net carrying value is

approximately $

0.6

billion, which consisted primarily of $

1.2

billion of PP&E and $

0.3

billion of cash and

working capital, offset by $

0.7

billion of ARO and $

0.2

billion of deferred tax liabilities.

The assets met held

for sale criteria in the fourth quarter, and as of December 31, 2019

we had reclassified $

1.2

billion of PP&E to

“Prepaid expenses and other current assets” and $

0.7

billion of noncurrent ARO to “Other accruals”

on our

consolidated balance sheet.

The before-tax earnings associated with our

Australia-West subsidiaries were

$

million, $

million and $

million for the years ended December 31,

2019, 2018 and 2017,

respectively.

This transaction is expected to be completed

in the first quarter of 2020, subject to regulatory

approvals and other specific conditions precedent.

Results of operations for the subsidiaries

to be sold are

reported within our Asia Pacific and Middle East

segment.

In the fourth quarter of 2019, we signed an agreement

to sell our interests in the Niobrara shale play

for $

million, plus customary adjustments,

and overriding royalty interests in certain

future wells.

To reduce the

carrying value to fair value, in the fourth quarter

of 2019, we recorded an impairment of $

million before-

tax for developed properties and exploration expenses

of $

million related to leasehold impairment of

undeveloped properties.

Our Niobrara interests to be sold have a net carrying

value of approximately $

million, which consisted primarily of $

million of PP&E, offset by $

million of noncurrent ARO.

The

assets met held for sale criteria in the fourth quarter, and as of December

31, 2019, we had reclassified $

million of PP&E to “Prepaid expenses and other

current assets” and $

million of noncurrent AROs to “Other

accruals” on our consolidated balance sheet.

The before-tax losses associated with our interests

in Niobrara,

including the $386 million of impairments noted

above, were $

million and $

million for the years ended

December 31, 2019 and 2017,

respectively.

The before-tax earnings associated with our interests

in Niobrara

for the year ended December 31, 2018 was $

million.

This transaction is subject to regulatory approval

and

other specific conditions precedent and is expected

to close in the first quarter of 2020.

The Niobrara results of

operations are reported within our Lower 48 segment.

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 are reported in

our Lower 48 segment.

See Note 15—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 were $

0.4

billion, $

0.9

billion and $

0.3

billion for the years ended December 31, 2019,

2018

and 2017,

respectively.

Results of operations for the U.K. are reported

within our Europe and North Africa

segment.

In the second quarter of 2019, we recognized an

after-tax gain of $

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 and Middle East 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 are reported

within

our Lower 48 segment.

Planned Dispositions

In January 2020, we entered into an agreement to sell

our interests in certain non-core properties

in the Lower

48 segment for $

million, plus customary adjustments.

The assets met the held for sale criteria in

January

2020 and the transaction is expected to be completed

in the first quarter of 2020.

No gain or loss is anticipated

on the sale.

This disposition will not have a significant

impact on Lower 48 production.

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 impairments of $

million in 2018 and $

million in 2017 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 losses associated with our

interests in the Barnett,

including both the impairments and loss on disposition

noted above, were $

million and $

million for the

years 2018 and 2017, respectively.

The Barnett results of operations are 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 24 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 38 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 interest in the Clair

Field, including the recognized gain, were $

million.

The before-tax loss associated with our interest

in the

Clair Field was $

0.4

million for 2017. Results of operations

for our interest in the Clair Field are reported

within our Europe and North Africa segment and

the Kuparuk Assets are 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 24 percent

interest in the Clair Field, reduced by the net proceeds

of $253 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.

2017

Assets Sold

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

50 percent nonoperated interest in the Foster

Creek Christina

Lake (FCCL) Partnership, as well as the majority

of our western Canada gas assets to Cenovus

Energy.

Consideration for the transaction was $

11.0

billion in cash after customary adjustments,

million Cenovus

Energy common shares and a five-year uncapped contingent

payment.

The value of the shares at closing was

$

1.96

billion based on a price of $

9.41

per share on the NYSE.

The contingent payment, calculated and paid

on a quarterly basis, is $6 million CAD for every $1 CAD by which the WCS quarterly average crude price

exceeds $52 CAD per barrel.

Contingent payments received during the five-year

period are reflected as “Gain

on dispositions” on our consolidated income statement.

We reported before-tax equity earnings associated

with FCCL of $

million for 2017.

We reported a before-tax loss of $

million for the western Canada gas

producing properties for 2017.

We recorded gains on dispositions for these contingent payments of $

million and $

million for the years 2019 and 2018, respectively.

At closing, the carrying value of our equity investment

in FCCL was $

8.9

billion.

The carrying value of our

interest in the western Canada gas assets was $

1.9

billion consisting primarily of $

2.6

billion of PP&E, partly

offset by AROs of $

million and approximately $

million of environmental and other accruals.

A gain

of $

2.1

billion was included in the “Gain on dispositions”

line on our consolidated income statement in 2017.

Both FCCL and the western Canada gas assets

were reported in our Canada segment.

For more information on the Canada disposition

and our investment in Cenovus Energy see Note 7—

Investment in Cenovus Energy, Note 15—Fair Value Measurement, and Note 20—Accumulated Other

Comprehensive Loss.

In July 2017, we completed the sale of our interests

in the San Juan Basin to an affiliate of Hilcorp Energy

Company for $

2.5

billion in cash after customary adjustments

and recognized a loss on disposition of

$

million.

The transaction includes a contingent payment of up to $300 million. The six-year contingent

payment, effective beginning January 1, 2018, is due annually for the periods in which the monthly U.S. Henry

Hub price is at or above $3.20 per MMBTU.

In 2018, we recorded a gain on dispositions

for these contingent

payments of $

million.

No

contingent payments were recorded in 2019.

In the second quarter of 2017, we

recorded an impairment of $

3.3

billion to reduce the carrying value of our

interests in the San Juan Basin to

fair value.

At the time of disposition, the San Juan Basin

interests had a net carrying value of approximately

$

2.5

billion, consisting of $

2.9

billion of PP&E and $

million of liabilities, primarily AROs.

The before-

tax loss associated with our interests in the San Juan

Basin, including both the $3.3 billion impairment

and $22

million loss on disposition noted above, was $

3.2

billion for 2017.

The San Juan Basin results were reported

in our Lower 48 segment.

In September 2017, we completed the sale of our

interest in the Panhandle assets for $

million in cash after

customary adjustments and recognized a loss on

disposition of $

million.

At the time of the disposition, the

carrying value of our interest was $

million, consisting primarily of $

million of PP&E and $

million

of AROs.

Including the $28 million loss on disposition

noted above, we reported a before-tax loss for the

Panhandle properties of $

million for 2017.

The Panhandle results were reported in

our Lower 48 segment.

Note 6—Investments, Loans and Long-Term Receivables

Components of investments, loans and long-term

receivables at December 31 were:

Millions of Dollars

2019

2018

Equity investments

$

8,234

9,005

Loans and advances—related parties

Long-term receivables

Long-term investments in debt securities

-

Other investments

$

8,906

9,664

Equity Investments

Affiliated companies in which we had a significant

equity investment at December 31, 2019, 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

2019

2018

2017

Revenues

$

11,310

11,654

11,554

Income (loss) before income taxes

3,726

3,660

(2,875)

Net income (loss)

3,085

3,244

(1,431)

Summarized 100 percent balance sheet information

for equity method investments in affiliated

companies,

combined, was as follows:

Millions of Dollars

2019

2018

Current assets

$

3,289

3,285

Noncurrent assets

38,905

41,563

Current liabilities

2,603

2,625

Noncurrent liabilities

22,168

23,874

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, 2019, retained earnings included

$

million related to the undistributed earnings

of

affiliated companies.

Dividends received from affiliates were $

1,378

million, $

1,226

million and $

million

in 2019, 2018 and 2017,

respectively.

APLNG

APLNG is focused on CBM production from the

Bowen and Surat basins in Queensland, Australia,

to supply

the domestic gas market and on LNG processing

and export sales.

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.

At December 31, 2019, all amounts have been

drawn from the facility.

APLNG

made its first principal and interest repayment

in March 2017 and is scheduled to make

bi-annual

payments

until March 2029.

APLNG made a voluntary repayment of $

1.4

billion to the Export-Import Bank of China

in September 2018.

At the same time, APLNG obtained a United

States Private Placement (USPP) bond facility

of $

1.4

billion.

APLNG made its first interest payment related to

this facility in March 2019, and principal

payments are

scheduled to commence in September 2023,

with

bi-annual

payments due on the facility until September

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, 2019, a balance of $

6.7

billion was outstanding on the facilities.

See Note 12—Guarantees,

for additional information.

During the first half of 2017, the outlook for crude

oil prices deteriorated, and as a result of significantly

reduced price outlooks, the estimated fair

value of our investment in APLNG declined to

an amount below

carrying value.

Based on a review of the facts and circumstances

surrounding this decline in fair value, we

concluded in the second quarter of 2017 the impairment

was other than temporary under the guidance of

FASB

ASC Topic 323, “Investments—Equity Method and Joint Ventures,” and the recognition of an impairment of

our investment to fair value was necessary.

Accordingly, we recorded a noncash $

2,384

million, before- and

after-tax impairment in our second quarter 2017

results.

Fair value was estimated based on an internal

discounted cash flow model using estimated

future production, an outlook of future prices

from a combination

of exchanges (short-term) and pricing service

companies (long-term), costs, 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.

The impairment was included in the “Impairments”

line on our consolidated

income statement.

At December 31, 2019, the carrying value of

our equity method investment in APLNG was $

7,228

million.

The historical cost basis of our

37.5

percent share of net assets on the books

of APLNG was $

6,751

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 2019,

2018 and 2017 was after-tax

expense of $

million, $

million and $

million, respectively, representing the amortization of this basis

difference on currently producing licenses.

Distributions from APLNG commenced in

April 2018.

FCCL

FCCL Partnership, a Canadian upstream 50/50 general

partnership with Cenovus Energy Inc., produces

bitumen in the Athabasca oil sands in northeastern

Alberta and sells the bitumen blend.

Cenovus is the

operator and managing partner of FCCL.

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

50 percent nonoperated interest in the FCCL

Partnership, as

well as the majority of our western Canada gas

assets to Cenovus Energy.

Financial information presented

within this footnote includes our historical

interest up to the date of sale.

For additional information on the

Canada disposition and our investment in Cenovus

Energy, see Note 5—Asset Acquisitions and Dispositions

and Note 7—Investment in Cenovus Energy.

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, 2019, 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 5—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, 2019, significant loans to affiliated

companies include $335 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 7—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

million Cenovus Energy common shares, which,

at closing, approximated

16.9

percent of issued

and outstanding Cenovus Energy common stock.

See Note 5—Asset Acquisitions and Dispositions,

for

additional information on the Canada disposition.

The fair value and cost basis of our investment

in 208

million Cenovus Energy common shares was $

1.96

billion based on a price of $

9.41

per share on the NYSE on

the closing date.

Our investment on our consolidated balance sheet

as of December 31, 2019, is carried

at fair value of $

2.11

billion, reflecting the closing price of Cenovus

Energy shares on the NYSE of $

10.15

per share, an increase of

$

million from $

1.46

billion at December 31, 2018.

The increase in fair value represents the

net unrealized

gain recorded within the “Other income” line of

our consolidated income statement for

the year ended

December 31, 2019 relating to the shares held

at the reporting date.

See Note 15—Fair Value Measurement

and Note 22—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.

Note 8—Suspended Wells and Other Exploration Expenses

The following table reflects the net changes in suspended

exploratory well costs during 2019, 2018 and 2017:

Millions of Dollars

2019

2018

2017

Beginning balance at January 1

$

1,063

Additions pending the determination of proved reserves

Reclassifications to proved properties

(11)

(37)

(66)

Sales of suspended wells

(54)

(93)

-

Charged to dry hole expense

(10)

(7)

(262)

Ending balance at December 31

$

1,020

*Includes $

million of assets held for sale in Australia.

The following table provides an aging of suspended

well balances at December 31:

Millions of Dollars

2019

2018

2017

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 $313 million of assets held for sale in Australia.

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, 2019:

Millions of Dollars

Suspended Since

Total

2016–2018

2013–2015

2004–2012

Greater Poseidon—Australia

(2)(3)

-

NPRA—Alaska

(1)

-

Barossa/Caldita—Australia

(2)(3)

-

Surmont—Canada

(1)

Middle Magdalena Basin—Colombia

(1)

-

-

Narwhal Trend—Alaska

(1)

-

-

Kamunsu East—Malaysia

(2)

-

-

NC 98—Libya

(2)

-

WL4-00—Malaysia

(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.

(3)Assets held for sale as of December 31, 2019.

Other Exploration Expenses

In February 2017, we reached a settlement

agreement on our contract for the Athena drilling

rig, initially

secured for our four-well commitment program

in Angola.

As a result of the cancellation, we recognized

a

before-tax charge of $

million net in the first quarter of 2017.

These charges are included in the

“Exploration expenses” line on our consolidated income

statement and in our Other International segment

in

In 2019, we recorded before-tax dry hole expenses

of $

million due to our decision to discontinue

exploration activities in the Central Louisiana Austin

Chalk trend.

These charges are included in our Lower 48

segment and in the “Exploration expenses” line

on our consolidated income statement.

See Note 9—

Impairments for additional information on our

decision to discontinue these exploration activities.

Note 9—Impairments

During 2019, 2018 and 2017, we recognized the

following before-tax impairment charges:

Millions of Dollars

2019

2018

2017

Alaska

$

-

Lower 48

3,969

Canada

Europe and North Africa

(79)

Asia Pacific and Middle East

-

2,384

$

6,601

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 5—Asset Acquisitions and

Dispositions,

for additional information on this disposition.

The charges discussed below, within this section, are included in the “Exploration

expenses” line on our

consolidated income statement and are not reflected

in the table above.

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

of $

million for the associated carrying

value of capitalized undeveloped leasehold costs

due to our decision to discontinue exploration

activities

related to our Central Louisiana Austin Chalk

acreage.

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 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 have ceased production and

were impaired in prior years,

partly offset by an increased ARO estimate on a field

in Norway which has ceased production.

2017

In Alaska, we recorded impairments of $

million primarily for the associated PP&E

carrying value of our

small interest in the Point Thomson unit.

In the Lower 48, we recorded impairments

of $

3,969

million primarily due to certain developed

properties

which were written down to fair value less costs

to sell.

See Note 5—Asset Acquisitions and Dispositions, for

additional information on our dispositions.

In Canada, we recorded impairments of $

million primarily due to cancelled projects.

In Europe and North Africa, we recorded impairments

of $

million primarily due to reduced volume

forecasts for a field in the U.K. and restructured ownership

and a change in commercial premises for a gas

processing plant in Norway, partly offset by decreased ARO estimates on fields at or

nearing the end of life

which were impaired in prior years.

In Asia Pacific and Middle East, we recorded impairments

of $

2,384

million, including the impairment of our

APLNG investment.

For more information, see the “APLNG”

section of Note 6—Investments, Loans and

Long-Term Receivables.

The charges discussed below, within this section, are included in the “Exploration

expenses” line on our

consolidated income statement and are not reflected

in the table above.

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

of $

million for the associated carrying

value of capitalized undeveloped leasehold costs

of Shenandoah in deepwater Gulf of Mexico

following the

suspension of appraisal activity by the operator.

Additionally, we recorded a $

million before-tax

impairment for mineral assets primarily

due to plan of development changes.

Note 10—Asset Retirement Obligations and Accrued

Environmental Costs

Asset retirement obligations and accrued environmental

costs at December 31 were:

Millions of Dollars

2019

2018

Asset retirement obligations

$

6,206

7,908

Accrued environmental costs

Total asset retirement obligations and accrued environmental costs

6,377

8,086

Asset retirement obligations and accrued environmental

costs due within one year*

(1,025)

(398)

Long-term asset retirement obligations and accrued

environmental costs

$

5,352

7,688

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

million relates to assets which are held for sale as of

December 31, 2019. For additional information see Note 5—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 2019 and 2018, our overall ARO changed

as follows:

Millions of Dollars

2019

2018

Balance at January 1

$

7,908

7,798

Accretion of discount

New obligations

Changes in estimates of existing obligations

(266)

Spending on existing obligations

(229)

(228)

Property dispositions

(1,920)

(161)

Foreign currency translation

(80)

(240)

Balance at December 31

$

6,206

7,908

Accrued Environmental Costs

Total accrued environmental costs at December 31, 2019 and 2018, were $

million and $

million,

respectively.

We had accrued environmental costs of $

million and $

million at December 31, 2019 and 2018,

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, 2019 and 2018, respectively.

In addition, $

million and $

million were included at both

December 31, 2019 and 2018, 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, 2019.

The expected future undiscounted payments

related to the

portion of the accrued environmental costs that

have been discounted are: $

million in 2020, $

million in

2021, $

million in 2022, $

million in 2023, $

million in 2024, and $

million for all future years

after 2024.

Note 11—Debt

Long-term debt at December 31 was:

Millions of Dollars

2019

2018

9.125% Debentures due 2021

$

8.20% Debentures due 2025

8.125% Notes due 2030

7.9% Debentures due 2047

7.8% Debentures due 2027

7.65% Debentures due 2023

7.40% Notes due 2031

7.375% Debentures due 2029

7.25% Notes due 2031

7.20% Notes due 2031

7% Debentures due 2029

6.95% Notes due 2029

1,549

1,549

6.875% Debentures due 2026

6.50% Notes due 2039

2,750

2,750

5.951% Notes due 2037

5.95% Notes due 2036

5.95% Notes due 2046

5.90% Notes due 2032

5.90% Notes due 2038

4.95% Notes due 2026

1,250

1,250

4.30% Notes due 2044

4.15% Notes due 2034

3.35% Notes due 2024

3.35% Notes due 2025

2.4% Notes due 2022

Floating rate notes due 2022 at

2.81

% –

3.58

% during 2019 and

2.32

% –

3.52

% during 2018

Industrial Development Bonds due 2035 at

1.08

% –

2.45

% during 2019 and

0.95

% –

1.86

% during 2018

Marine Terminal Revenue Refunding Bonds due 2031 at

1.08

% –

2.45

% during

2019 and

0.88

% –

1.95

% during 2018

Other

Debt at face value

13,971

13,971

Finance leases

Net unamortized premiums, discounts and

debt issuance costs

Total debt

14,895

14,968

Short-term debt

(105)

(112)

Long-term debt

$

14,790

14,856

Maturities of long-term borrowings, inclusive

of net unamortized premiums and discounts,

in 2020 through

2024 are: $

million, $

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.

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.

We have a $

6.0

billion commercial paper program, which

is primarily a funding source for short-term

working

capital needs.

Commercial paper maturities are generally

limited to

90 days

.

We had no commercial paper

outstanding in programs in place at December

31, 2019 or December 31, 2018.

We had

no

direct outstanding

borrowings or letters of credit under the revolving

credit facility at December 31, 2019 or December

31, 2018.

Since we had

no

commercial paper outstanding and had issued

no letters of credit, we had access to

$

6.0

billion in borrowing capacity under our revolving

credit facility at December 31, 2019.

At both December 31, 2019 and 2018, we had

$

million of certain variable rate demand

bonds (VRDBs)

outstanding which mature

in 2035.

The VRDBs are redeemable at the option of the

bondholders on any

business day.

If they are ever redeemed, we intend to refinance

on a long-term basis, therefore, the VRDBs are

included in the “Long-term debt” line on our consolidated

balance sheet.

For additional information on Finance Leases,

see Note 17

—

Non-Mineral Leases.

Note 12—Guarantees

At December 31, 2019, we were liable for certain

contingent obligations under various contractual

arrangements as described below.

We recognize a liability, at inception, for the fair value of our obligation as

a guarantor for newly issued or modified guarantees.

Unless the carrying amount of the liability

is noted

below, we have not recognized a liability because the fair value of the obligation

is immaterial.

In addition,

unless otherwise stated, we are not currently

performing with any significance under the

guarantee and expect

future performance to be either immaterial

or have only a remote chance of occurrence.

APLNG Guarantees

At December 31, 2019, we had outstanding multiple

guarantees in connection with our

37.5

percent ownership

interest in APLNG.

The following is a description of the guarantees

with values calculated utilizing December

2019 exchange rates:

●

During the third

quarter of 2016, we issued a guarantee to facilitate

the withdrawal of our pro-rata

portion of the funds in a project finance reserve

account.

We estimate the remaining term of this

guarantee is

11 years

.

Our maximum exposure under this guarantee is

approximately $

million

and may become payable if an enforcement action

is commenced by the project finance lenders

against APLNG.

At December 31, 2019, 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 up to

22 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 up to

26 years or the life of the venture

.

As of December 31, 2019, we were released from

certain of these

guarantees considered subordinated financial

support to APLNG.

Our remaining maximum potential

amount of future payments related to the remaining

guarantees is approximately $

million and

would become payable if APLNG does not perform.

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 leased corporate aircraft,

and a guarantee for our portion of a joint

venture’s project

finance reserve accounts.

These guarantees have remaining terms of up to

three years

and would become

payable if, upon sale, certain asset values are lower

than guaranteed amounts, business conditions

decline at

guaranteed entities, or as a result of nonperformance

of contractual terms by guaranteed parties.

In conjunction with the disposition of our two

U.K. subsidiaries to Chrysaor E&P Limited,

we will temporarily

continue to support various guarantees and letters

of credit which were provided for the benefit of entities

that

are now affiliates of Chrysaor E&P Limited.

Our maximum potential payment exposure under

these

obligations is approximately $

million.

Chrysaor E&P Limited has agreed to fully

indemnify

ConocoPhillips for any losses suffered by us related to

these obligations.

Indemnifications

Over the years, we have entered into agreements to

sell ownership interests in certain corporations,

joint

ventures and assets that gave rise to qualifying

indemnifications.

These agreements include indemnifications

for taxes, environmental liabilities, employee claims

and litigation.

The terms of these indemnifications vary

greatly.

The majority of these indemnifications are related

to environmental issues, the term is generally

indefinite and the maximum amount of future payments

is generally unlimited.

The carrying amount recorded

for these indemnifications at December 31, 2019,

was approximately $

million.

We amortize the

indemnification liability over the relevant time

period, if one exists, based on the facts and circumstances

surrounding each type of indemnity.

In cases where the indemnification term is

indefinite, we will reverse the

liability when we have information the liability

is essentially relieved or amortize the liability

over an

appropriate time period as the fair value of our indemnification

exposure declines.

Although it is reasonably

possible future payments may exceed amounts recorded,

due to the nature of the indemnifications, it

is not

possible to make a reasonable estimate of the

maximum potential amount of future payments.

Included in the

recorded carrying amount at December 31, 2019,

were approximately $

million of environmental accruals

for known contamination that are included in

the “Asset retirement obligations and accrued

environmental

costs” line on our consolidated balance sheet.

For additional information about environmental

liabilities, see

Note 13—Contingencies and Commitments.

Note 13—Contingencies and Commitments

A number of lawsuits involving a variety of claims

arising in the ordinary course of business

have been filed

against ConocoPhillips.

We also may be required to remove or mitigate the effects on the environment of the

placement, storage, disposal or release of certain

chemical, mineral and petroleum substances

at various active

and inactive sites.

We regularly assess the need for accounting recognition or disclosure of these

contingencies.

In the case of all known contingencies (other

than those related to income taxes), we accrue

a

liability when the loss is probable and the amount

is reasonably estimable.

If a range of amounts can be

reasonably estimated and no amount within the range

is a better estimate than any other amount,

then the

minimum of the range is accrued.

We do not reduce these liabilities for potential insurance or third-party

recoveries.

If applicable, we accrue receivables for probable

insurance or other third-party recoveries.

With

respect to income tax-related contingencies,

we use a cumulative probability-weighted loss

accrual in cases

where sustaining a tax position is less than certain.

See Note 19—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 10—Asset Retirement Obligations and

Accrued Environmental Costs, for a summary of our

accrued environmental liabilities.

Legal Proceedings

We are subject to various lawsuits and claims including but not limited to matters

involving oil and gas royalty

and severance tax payments, gas measurement and

valuation methods, contract disputes,

environmental

damages, climate change, personal injury, and property damage.

Our primary exposures for such matters

relate to alleged royalty and tax underpayments

on certain federal, state and privately owned

properties and

claims of alleged environmental contamination

from historic operations.

We will continue to defend ourselves

vigorously in these matters.

Our legal organization applies its knowledge, experience

and professional judgment to the specific

characteristics of our cases, employing a litigation

management process to manage and monitor the

legal

proceedings against us.

Our process facilitates the early evaluation and

quantification of potential exposures in

individual cases.

This process also enables us to track those cases that

have been scheduled for trial and/or

mediation.

Based on professional judgment and experience

in using these litigation management tools and

available information about current developments

in all our cases, our legal organization regularly assesses

the

adequacy of current accruals and determines if

adjustment of existing accruals, or establishment

of new

accruals, is required.

Other Contingencies

We have contingent liabilities resulting from throughput agreements with pipeline and

processing companies

not associated with financing arrangements.

Under these agreements, we may be required

to provide any such

company with additional funds through advances

and penalties for fees related to throughput capacity

not

utilized.

In addition, at December 31, 2019, 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.

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 failed to

cure its breach.

As

a result, ConocoPhillips has resumed legal enforcement

actions.

ConocoPhillips has ensured that the

settlement and any actions thereof meet all appropriate

U.S. regulatory requirements, including those related

to

any applicable sanctions imposed by the U.S. against

Venezuela.

In 2016, ConocoPhillips filed a separate and independent

arbitration under the rules of the ICC against

PDVSA under the contracts that had established the

Corocoro project.

On August 2, 2019, the ICC Tribunal

awarded ConocoPhillips approximately $

million 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

Ve

nezuela.

In February 2017, the ICSID Tribunal unanimously awarded Burlington

Resources, Inc., a wholly owned

subsidiary of ConocoPhillips, $

million for Ecuador’s unlawful expropriation of

Burlington’s investment in

Blocks 7 and 21, in breach of the U.S.-Ecuador

Bilateral Investment Treaty.

The tribunal also issued a

separate decision finding Ecuador to be entitled

to $

million for environmental and infrastructure

counterclaims.

In December 2017, Burlington and Ecuador

entered into a settlement agreement by which

Ecuador paid Burlington $

million in two installments.

The first installment of $

million was paid in

December 2017, and the second installment

of $

million was paid in April 2018.

The settlement included

an offset for the counterclaims decision, of which Burlington

is entitled to a contribution from Perenco

Ecuador Limited, its co-venturer and consortium

operator, pursuant to a joint and several liability provision in

the JOA.

In September 2019, a separate ICSID Tribunal issued an award

in the Perenco arbitration, ordering

Perenco to pay an additional $

million to Ecuador for its environmental counterclaim.

Burlington and

Perenco will reconcile their shares of the environmental

and infrastructure counterclaims according

to their

JOA participating interests, and we expect Burlington’s share will be immaterial.

In June 2017, FAR Ltd. initiated arbitration before the ICC against ConocoPhillips

Senegal B.V.

in connection

with the sale of ConocoPhillips Senegal B.V. to Woodside Energy Holdings (Senegal) Limited in 2016.

In

February 2020, the ICC Tribunal issued an award dismissing

FAR Ltd.’s

claims in the arbitration.

In late 2017, ConocoPhillips (U.K.) Limited

(CPUKL) initiated United Nations Commission

on International

Trade and Law (UNCITRAL) arbitration against Vietnam in accordance with the U.K.-Vietnam Bilateral

Investment Treaty relating to a tax dispute arising from the

2012 sale of ConocoPhillips (U.K.) Cuu Long

Limited and ConocoPhillips (U.K.) Gama Limited.

The parties entered into a settlement agreement

in October

2019, and the arbitration was dismissed in

December 2019 as a result of this agreement.

In 2017 and 2018, cities, counties, and a state

government in California, New York, Washington, Rhode Island

and Maryland, as well as the Pacific Coast Federation

of Fishermen’s Association, Inc., have filed lawsuits

against oil and gas companies, including ConocoPhillips,

seeking compensatory damages and equitable

relief

to abate alleged climate change impacts.

ConocoPhillips is vigorously defending against

these lawsuits.

The

lawsuits brought by the Cities of San Francisco,

Oakland and New York have been dismissed by the district

courts and appeals are pending.

Lawsuits filed by other cities and counties

in California and Washington are

currently stayed pending resolution of the appeals

brought by the Cities of San Francisco and

Oakland to the

U.S. Court of Appeals for the Ninth Circuit.

Lawsuits filed in Maryland and Rhode Island

are proceeding in

state court while rulings in those matters, on the

issue of whether the matters should proceed

in state or federal

court, are on appeal to the U.S. Court of Appeals

for the Fourth Circuit and First Circuit,

respectively.

Several Louisiana parishes and individual landowners

have filed lawsuits against oil and gas companies,

including ConocoPhillips, seeking compensatory

damages in connection with historical oil

and gas operations

in Louisiana.

All parish lawsuits are stayed pending an appeal

to the Fifth Circuit Court of Appeals on the

issue of whether they will proceed in federal or

state court.

ConocoPhillips will vigorously defend against

these lawsuits.

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:

2020—$

million; 2021—$

million; 2022—$

million; 2023—$

million; 2024—$

million; and 2025 and

after—$

million.

Total payments under the agreements were $

million in 2019, $

million in 2018 and

$

million in 2017.

Note 14—Derivative and Financial Instruments

We use futures, forwards, swaps and options in various markets to meet our customer

needs and capture

market opportunities.

Our commodity business primarily consists of

natural gas, crude oil, bitumen, LNG and

NGLs.

Our derivative instruments are held at fair value

on our consolidated balance sheet.

Where these balances have

the right of setoff, they are presented on a net basis.

Related cash flows are recorded as operating

activities on

our consolidated statement of cash flows.

On our consolidated income statement, realized

and unrealized gains

and losses are recognized either on a gross basis

if directly related to our physical business

or a net basis if held

for trading.

Gains and losses related to contracts that meet

and are designated with the NPNS exception are

recognized upon settlement.

We generally apply this exception to eligible crude contracts.

We do not use

hedge accounting for our commodity derivatives.

The following table presents the gross fair values

of our commodity derivatives, excluding

collateral, and the

line items where they appear on our consolidated

balance sheet:

Millions of Dollars

2019

2018

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

2019

2018

2017

Sales and other operating revenues

$

Other income

-

Purchased commodities

(118)

(41)

(61)

The table below summarizes our material net exposures

resulting from outstanding commodity

derivative

contracts:

Open Position

Long/(Short)

2019

2018

Commodity

Natural gas and power (billions of cubic feet equivalent)

Fixed price

(5)

(17)

Basis

(23)

(1)

Foreign Currency Exchange Derivatives

We have foreign currency exchange rate risk resulting from international operations.

Our foreign currency

exchange derivative activity primarily

relates to managing our cash-related foreign currency

exchange rate

exposures, such as firm commitments for

capital programs or local currency tax payments,

dividends and cash

returns from net investments in foreign affiliates,

and investments in equity securities.

We do not elect hedge

accounting on our foreign currency exchange

derivatives.

The following table presents the gross fair values

of our foreign currency exchange derivatives,

excluding

collateral, and the line items where they appear

on our consolidated balance sheet:

Millions of Dollars

2019

2018

Assets

Prepaid expenses and other current assets

$

Liabilities

Other accruals

Other liabilities and deferred credits

-

The losses from foreign currency exchange derivatives

incurred and the line item where they appear

on our

consolidated income statement were:

Millions of Dollars

2019

2018

2017

Foreign currency transaction losses

$

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

derivatives:

In Millions

Notional Currency

2019

2018

Foreign Currency Exchange Derivatives

Sell U.S. dollar, buy British pound

USD

-

Sell British pound, buy other currencies*

GBP

-

Buy British pound, sell euro

GBP

-

Sell Canadian dollar, buy U.S. dollar

CAD

1,337

1,242

*Primarily euro and Norwegian krone.

In December 2017, we entered into foreign exchange zero cost collars buying the right to sell $1.25 billion

CAD at $0.707 CAD and selling the right to buy $1.25 billion CAD at $0.842 CAD against the U.S. dollar.

The collar expired during the second quarter of 2019 and we entered into new foreign currency exchange

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

Financial Instruments

We invest 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.

●

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.

●

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:

Carrying Amount

Cash and Cash Equivalents

Short-Term Investments

2019

2018

2019

2018

Cash

$

Demand Deposits

1,483

-

-

-

Time Deposits

Remaining maturities from 1 to 90 days

2,030

3,509

1,395

-

Remaining maturities from 91 to 180 days

-

-

-

Commercial Paper

Remaining maturities from 1 to 90 days

1,069

U.S. Government Obligations

Remaining maturities from 1 to 90 days

1,301

-

-

$

5,079

5,915

2,929

The following table reflects our investments

in debt securities classified as available

for sale at December 31,

2019 which are carried at fair value:

Millions of Dollars

Carrying Amount

Cash and

Cash

Equivalents

Short-Term

Investments

Investments

and Long-

Term

Receivables

Corporate Bonds

Remaining maturities within one year

$

-

Remaining maturities greater than one year through

five years

-

-

Commercial Paper

Remaining maturities within one year

-

U.S. Government Obligations

Remaining maturities within one year

-

-

Remaining maturities greater than one year through

five years

-

-

Asset-backed Securities

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 at December 31,

2019:

Millions of Dollars

Amortized Cost

Basis

Fair Value

Major Security Type

Corporate bonds

$

Commercial paper

U.S. government obligations

Asset-backed securities

$

Gross unrealized gains and gross unrealized losses

included in other comprehensive income related

to

investments in debt securities classified as available

for sale as of December 31, 2019, were negligible.

There were no other-than-temporary impairments

recognized in earnings or in other comprehensive

income

during the year ended December 31, 2019.

Gross realized gains and gross realized losses

included in earnings from sales and redemptions

of investments

in debt securities classified as available for sale

during the year ended December 31, 2019,

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

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.

We do not generally require collateral to limit the exposure to loss;

however, we will sometimes use letters of credit, prepayments

and master netting arrangements to mitigate

credit risk with counterparties that both buy from

and sell to us, as these agreements permit

the amounts owed

by us or owed to others

to be offset against amounts due to us.

Certain of our derivative instruments contain provisions that require us to post collateral if the derivative

exposure exceeds a threshold amount. We have contracts with fixed threshold amounts and other contracts

with variable threshold amounts that are contingent on our credit rating. The variable threshold amounts

typically decline for lower credit ratings, while both the variable and fixed threshold amounts typically revert

to zero if we fall below investment grade. Cash is the primary collateral in all contracts; however, many also

permit us to post letters of credit as collateral, such as transactions administered through the New York

Mercantile Exchange.

The aggregate fair value of all derivative

instruments with such credit risk-related contingent

features that were

in a liability position on December 31, 2019 and

December 31, 2018, was $

million and $

million,

respectively.

For these instruments,

no collateral

was posted as of December 31, 2019 or December 31,

If our credit rating had been downgraded below

investment grade on December 31, 2019,

we would be

required to post $

million of additional collateral, either with

cash or letters of credit.

Note 15—Fair Value Measurement

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

date using an exit

price (i.e., the price that would be received to sell

an asset or paid to transfer a liability) and disclosed

according to the quality of valuation inputs under

the following hierarchy:

●

Level 1: Quoted prices (unadjusted) in an active

market for identical assets or liabilities.

●

Level 2: Inputs other than quoted prices that

are directly or indirectly observable.

●

Level 3: Unobservable inputs that are significant

to the fair value of assets or liabilities.

The classification of an asset or liability

is based on the lowest level of input significant

to its fair value.

Those

that are initially classified as Level 3 are subsequently

reported as Level 2 when the fair value derived

from

unobservable inputs is inconsequential to the overall

fair value, or if corroborated market data becomes

available.

Assets and liabilities initially reported as Level

2 are subsequently reported as Level 3 if

corroborated market data is no longer available.

Transfers occur at the end of the reporting period.

There were

no material transfers in or out of Level 1 during

2019 or 2018.

Recurring Fair Value Measurement

Financial assets and liabilities reported at fair

value on a recurring basis primarily include

our investment in

Cenovus Energy shares,

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, and

asset-backed securities 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, 2019

December 31, 2018

Level 1

Level 2

Level 3

Total

Level 1

Level 2

Level 3

Total

Assets

Investment in Cenovus Energy

$

2,111

-

-

2,111

1,462

-

-

1,462

Investments in debt securities

-

Commodity derivatives

Total assets

$

2,308

2,674

1,698

1,912

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, 2019

Assets

$

Liabilities

December 31, 2018

Assets

$

-

Liabilities

At December 31, 2019 and December 31, 2018,

we did not present any amounts gross on our consolidated

balance sheet where we had the right of setoff.

Non-Recurring Fair Value Measurement

The following table summarizes the fair value

hierarchy by major category and date of

remeasurement for

assets accounted for at fair value on a non-recurring

basis:

Millions of Dollars

Fair Value Measurements Using

Fair Value

Level 1

Inputs

Level 2

Inputs

Level 3

Inputs

Before-Tax

Loss

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

-

-

Year

ended December 31, 2018

Net PP&E (held for sale)

March 31, 2018

$

-

-

September 30, 2018

-

-

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 each asset was

determined by its negotiated selling price (Level

1. or information gathered during marketing

efforts (Level 3).

For additional information see Note 5—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.

During 2019, 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 5—Asset

Acquisitions and

Dispositions.

During 2019, an investment using Level 2 inputs

was determined to have a fair value below its

carrying value, and was written down to fair value.

For additional information, see Note 3—Variable Interest

Entities.

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 shares: See Note 7—Investment

in Cenovus Energy for a discussion of

the carrying value and fair value of our investment

in Cenovus Energy shares.

●

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 14—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 6—Investments, Loans and Long-Term

Receivables, for additional information.

●

Accounts payable (including related parties)

and floating-rate debt: The carrying amount of accounts

payable and floating-rate debt reported on the balance

sheet approximates fair value.

●

Fixed-rate debt: The estimated fair value of fixed-rate

debt is measured using prices available

from a

pricing service that is corroborated by market

data; therefore, these liabilities are categorized

as Level

2 in the fair value hierarchy.

The following table summarizes the net fair

value of financial instruments (i.e., adjusted

where the right of

setoff exists for commodity derivatives):

Millions of Dollars

Carrying Amount

Fair Value

2019

2018

2019

2018

Financial assets

Investment in Cenovus Energy

$

2,111

1,462

2,111

1,462

Commodity derivatives

Investments in debt securities

-

-

Total loans and advances—related parties

Financial liabilities

Total debt, excluding finance leases

14,175

14,191

18,108

16,147

Commodity derivatives

Commodity Derivatives

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.

At

December 31, 2018, commodity derivative assets

and liabilities are presented net with

no

obligations to return

cash collateral and $

million of rights to reclaim cash collateral,

respectively.

Note 16—Equity

Common Stock

The changes in our shares of common stock, as categorized

in the equity section of the balance sheet,

were:

Shares

2019

2018

2017

Issued

Beginning of year

1,791,637,434

1,785,419,175

1,782,079,107

Distributed under benefit plans

4,014,769

6,218,259

3,340,068

End of year

1,795,652,203

1,791,637,434

1,785,419,175

Held in Treasury

Beginning of year

653,288,213

608,312,034

544,809,771

Repurchase of common stock

57,495,601

44,976,179

63,502,263

End of year

710,783,814

653,288,213

608,312,034

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, 2019 or 2018.

Noncontrolling Interests

At December 31, 2019 and 2018, we had $

million and $

million outstanding, respectively, of equity in

less-than-wholly owned consolidated subsidiaries

held by noncontrolling interest owners.

For both periods,

the amounts were related to the Darwin LNG

and Bayu-Darwin Pipeline operating joint

ventures we control.

Repurchase of Common Stock

As of December 31, 2019, we had announced a total

authorization to repurchase $

billion of our common

stock.

Repurchase of shares began in November 2016,

and totaled

168,553,141

shares at a cost of $

9,625

million, through December 31, 2019.

In February 2020, we announced that the

Board of Directors approved

an increase to our repurchase authorization

from $15 billion to $

billion, to support our plan for future share

repurchases.

Note 17—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 12—Guarantees.

There are no significant restrictions

imposed on us by the lease agreements with regard

to dividends, asset dispositions or borrowing

ability.

Certain arrangements may contain both lease and

non-lease components and we determine

if an arrangement is

or contains a lease at contract inception.

Only the lease components of these contractual

arrangements are

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

to other applicable

accounting guidance; however,

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,

For contractual arrangements executed in subsequent

periods involving a new leased asset class, the

company will determine at contract inception

whether it will apply the optional practical

expedient to the new

leased asset class.

Leases are evaluated for classification as operating

or finance leases at the commencement date of the

lease

and right-of-use assets and corresponding liabilities

are recognized on our consolidated balance sheet

based on

the present value of future lease payments relating

to the use of the underlying asset during the

lease term.

Future lease payments include variable lease payments

that depend upon an index or rate using

the index or

rate at the commencement date and probable

amounts owed under residual value guarantees.

The amount of

future lease payments may be increased to include

additional payments related to lease extension, termination,

and/or purchase options when the company has

determined, at or subsequent to lease commencement,

generally due to limited asset availability

or operating commitments, it is reasonably

certain of exercising such

options.

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

present value of future

lease payments, unless the interest rate

implicit in the lease arrangement is readily determinable.

Lease

payments that vary subsequent to the commencement

date based on future usage levels, the nature

of leased

asset activities, or certain other contingencies are

not included in the measurement of lease

right-of-use assets

and corresponding liabilities.

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

sheet for lease arrangements with terms of 12 months

or less.

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

on behalf of certain oil

and gas joint ventures of undivided interests.

If the lease arrangement can be legally enforced only

against us

as operator and there is no separate arrangement to

sublease the underlying leased asset

to our coventurers, we

recognize at lease commencement a right-of-use

asset and corresponding lease liability on our

consolidated

balance sheet on a gross basis.

While we record lease costs on a gross basis in

our consolidated income

statement and statement of cash flows, such costs

are offset by the reimbursement we receive from our

coventurers for their share of the lease cost as the underlying

leased asset is utilized in joint venture activities.

As a result, lease cost is presented in our consolidated

income statement and statement of cash flows

on a

proportional basis.

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

asset and corresponding

lease liability only if we were a specified contractual

party to the lease arrangement and the arrangement

could

be legally enforced against us.

In this circumstance, we would recognize both

the right-of-use asset and

corresponding lease liability on our consolidated

balance sheet on a proportional basis

consistent with our

undivided interest ownership in the related joint

venture.

The company has historically recorded certain

finance leases executed by investee companies

accounted for

under the proportionate consolidation method of

accounting on its consolidated balance sheet

on a proportional

basis consistent with its ownership interest

in the investee company.

In addition, the company has historically

recorded finance lease assets and liabilities

associated with certain oil and gas joint ventures

on a proportional

basis pursuant to accounting guidance applicable

prior to January 1, 2019.

As of December 31, 2018, $

million of finance lease assets (net of accumulated

DD&A) and $

million of finance lease liabilities were

recorded on our consolidated balance sheet

associated with these leases.

In accordance with the transition

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

of optional transition-related

practical expedients, the historical accounting treatment

for these leases has been carried forward

and is subject

to reconsideration upon the modification or

other required reassessment of the arrangements

prior to lease term

expiration.

In connection with our adoption of ASC Topic 842, we have recorded on our

consolidated balance sheet $

million of operating leases executed by investee

companies accounted for under the proportionate

consolidation method of accounting on a proportional

basis consistent with our ownership interest

in the

investee company.

The following tables summarize the finance leases

amounts that were reflected on our consolidated

balance

sheet as of December 31, 2018, the operating

leases impact of adopting ASC Topic 842, and the right-of-use

asset and lease liability balances reflected for both

operating and finance leases on our consolidated

balance

sheet as of December 31, 2019:

Millions of Dollars

Carrying Amount

Operating

Leases

Finance

Leases

Amounts recognized in line items in our Consolidated

Balance Sheet upon adoption of ASC Topic 842

Right-of-Use Assets

Properties, plants and equipment

Gross

$

1,044

Accumulated depreciation, depletion and amortization

(550)

Net properties, plants and equipment as of December

31, 2018

$

Adoption of ASC Topic 842 as of January 1, 2019

$

Lease Liabilities

Short-term debt

$

Long-term debt

Total finance leases debt as of December 31, 2018

$

Adoption of ASC Topic 842 as of January 1, 2019

$

Amounts recognized in line items in our Consolidated

Balance Sheet at December 31, 2019

Right-of-Use Assets

Properties, plants and equipment

Gross

$

1,039

Accumulated depreciation, depletion and amortization

(649)

Net properties, plants and equipment

$

Prepaid expenses and other current assets

$

Other assets

• Includes proportionately consolidated finance lease assets (net of

accumulated depreciation, depletion and amortization) of $

million.

Millions of Dollars

Carrying Amount

Operating

Leases

Finance

Leases

Lease Liabilities

Short-term debt

$

Other accruals

$

Long-term debt

Other liabilities and deferred credits

Total lease liabilities

$

$

Short-term debt and long-term debt include proportionately consolidated finance

lease liabilities of $

million and $

million, respectively.

The following table summarizes our lease costs

for 2019:

Millions of Dollars

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.

Our future short-term lease commitments amount to $

million, of

which $

million is related to leases whose terms have not yet commenced

as of December 31, 2019.

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

The following table summarizes the lease terms

and discount rates:

December 31, 2019

Lease Term and Discount Rate

Weighted-average term (years)

Operating leases

5.19

Finance leases

8.70

Weighted-average discount rate (percent)

Operating leases

3.10

Finance leases

5.53

The following table summarizes other lease information

for 2019:

Millions of Dollars

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, 2019:

Millions of Dollars

Operating

Leases

Finance

Leases

Maturity of Lease Liabilities

2020

$

2021

2022

2023

2024

Remaining years

Total

1,019

Less: portion representing imputed interest

(87)

(160)

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.

At December 31, 2018, future minimum payments

due under finance (capital) leases pursuant

to

ASC Topic 840 were:

Millions

of Dollars

2019

$

2020

2021

2022

2023

Remaining years

Total

Less: portion representing imputed interest

(195)

Capital lease obligations

$

At December 31, 2018, future undiscounted minimum

rental payments due under noncancelable operating

leases pursuant to ASC Topic 840 were:

Millions

of Dollars

2019

$

2020

2021

2022

2023

Remaining years

Total

1,394

Less: income from subleases

(7)

Net minimum operating lease payments

$

1,387

For the years ended December 31, operating

lease rental expense pursuant to ASC Topic 840 was:

Millions of Dollars

2018

2017

Total rentals

$

Less: sublease rentals

(16)

(20)

$

Note 18—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

2019

2018

2019

2018

U.S.

Int’l.

U.S.

Int’l.

Change in Benefit Obligation

Benefit obligation at January 1

$

2,136

3,438

3,236

3,845

Service cost

Interest cost

Plan participant contributions

-

-

Plan amendments

-

-

-

-

-

Actuarial (gain) loss

(44)

(259)

(10)

Benefits paid

(253)

(147)

(507)

(143)

(59)

(67)

Curtailment

-

(69)

(4)

(3)

-

-

Settlement

-

-

(730)

-

-

-

Recognition of termination benefits

-

-

-

-

Foreign currency exchange rate change

-

-

(199)

(1)

Benefit obligation at December 31*

$

2,319

3,880

2,136

3,438

*Accumulated benefit obligation portion of above at

December 31:

$

2,161

3,594

1,969

3,066

Change in Fair Value of Plan Assets

Fair value of plan assets at January 1

$

1,336

3,358

2,541

3,647

-

-

Actual return on plan assets

(112)

(106)

-

-

Company contributions

Plan participant contributions

-

-

Benefits paid

(253)

(147)

(507)

(143)

(59)

(67)

Settlement

-

-

(730)

-

-

-

Foreign currency exchange rate change

-

-

(198)

-

-

Fair value of plan assets at December 31

$

1,591

4,306

1,336

3,358

-

-

Funded Status

$

(728)

(800)

(80)

(216)

(218)

Millions of Dollars

Pension Benefits

Other Benefits

2019

2018

2019

2018

U.S.

Int’l.

U.S.

Int’l.

Amounts Recognized in the

Consolidated Balance Sheet at

December 31

Noncurrent assets

$

-

-

-

-

Current liabilities

(21)

(6)

(59)

(4)

(42)

(44)

Noncurrent liabilities

(707)

(333)

(741)

(308)

(174)

(174)

Total recognized

$

(728)

(800)

(80)

(216)

(218)

Weighted-Average Assumptions Used to

Determine Benefit Obligations at

December 31

Discount rate

3.25

%

2.35

4.25

3.05

3.10

4.05

Rate of compensation increase

4.00

3.35

4.00

3.65

-

Weighted-Average Assumptions Used to

Determine Net Periodic Benefit Cost for

Years

Ended December 31

Discount rate

3.95

%

2.90

3.80

2.90

4.05

3.30

Expected return on plan assets

5.80

4.10

5.80

4.30

-

Rate of compensation increase

4.00

3.65

4.00

3.75

-

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.

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

2019

2018

2019

2018

U.S.

Int’l.

U.S.

Int’l.

Unrecognized net actuarial (gain) loss

$

(21)

Unrecognized prior service cost (credit)

-

(2)

-

(4)

(183)

(216)

Millions of Dollars

Pension Benefits

Other Benefits

2019

2018

2019

2018

U.S.

Int’l.

U.S.

Int’l.

Sources of Change in Other

Comprehensive Income (Loss)

Net gain (loss) arising during the period

$

(79)

(177)

(27)

Amortization of actuarial (gain) loss included

in income (loss)*

(2)

(1)

Net change during the period

$

(29)

Prior service credit (cost) arising during the

period

$

-

-

-

(7)

-

-

Amortization of prior service cost (credit)

included in income (loss)

-

(2)

-

(5)

(33)

(35)

Net change during the period

$

-

(2)

-

(12)

(33)

(35)

*Includes settlement losses recognized in 2019 and 2018.

Included in accumulated other comprehensive

loss at December 31, 2019, were the following

before-tax

amounts that are expected to be amortized into

net periodic benefit cost during 2020:

Millions of Dollars

Pension

Other

Benefits

Benefits

U.S.

Int’l.

Unrecognized net actuarial (gain) loss

$

Unrecognized prior service credit

-

(2)

(31)

For our tax-qualified pension plans with projected

benefit obligations in excess of plan

assets, the projected

benefit obligation, the accumulated benefit obligation,

and the fair value of plan assets were $

2,073

million,

$

1,919

million, and $

1,635

million, respectively, at December 31, 2019, and $

1,871

million, $

1,737

million,

and $

1,373

million, respectively, at December 31, 2018.

For our unfunded nonqualified key employee supplemental

pension plans, the projected benefit obligation and

the accumulated benefit obligation were $

million and $

million, respectively, at December 31, 2019,

and were $

million and $

million, respectively, at December 31, 2018.

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

2019

2018

2017

2019

2018

2017

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

(74)

(138)

(114)

(155)

(132)

(158)

-

-

-

Amortization of prior

service cost (credit)

-

(2)

-

(5)

(6)

(33)

(35)

(36)

Recognized net actuarial

loss (gain)

(2)

(1)

(3)

Settlements

-

-

-

-

-

-

Net periodic benefit cost

$

(26)

(27)

(28)

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.

In 2018, we purchased a group annuity contract

from Prudential and transferred $

million of future benefit

obligations from the U.S. qualified pension plan to

Prudential.

The purchase of the group annuity contract

was

funded directly by plan assets of the U.S. qualified

pension plan.

Effective January 1, 2019, the Cash Balance

Account (Title II) of the ConocoPhillips Retirement Plan,

a U.S. qualified pension plan, was closed to new

entrants.

New employees and rehires on or after January

1, 2019, and employees that elected to opt out of

Title II will no longer receive pay credits to their Cash Balance

Account and instead will be eligible for a

Company Retirement Contribution (CRC) as

described in the Defined Contribution Plans section.

We recognized pension settlement losses of $

million in 2019, $

million in 2018, and $

million in

2017 as lump-sum benefit payments from certain

U.S. pension plans exceeded the sum of service

and interest

costs for those plans and led to recognition of settlement

losses.

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

2020 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 2020

that increases to

percent by

2028

.

A one-percentage-point change in the assumed

health care cost trend rate

would be immaterial to ConocoPhillips.

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, 2019 and 2018.

●

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, 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.

At December 31, 2018, 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 net change from 2018 to

2019 is due to an increase in the fair value of the

underlying investments of $

million offset by a

decrease in the present value of the contract obligation

of $

million.

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

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.

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

2018

Equity securities

U.S.

$

-

-

-

International

-

-

-

-

Mutual funds

-

-

-

Debt securities

Government

-

-

-

-

-

-

Corporate

-

-

-

-

-

-

Mutual funds

-

-

-

-

-

-

Cash and cash equivalents

-

-

-

-

-

-

Time deposits

-

-

-

-

-

-

Derivatives

-

-

-

-

(17)

-

-

(17)

Real estate

-

-

-

-

-

-

Total in fair value hierarchy

$

2,137

2,442

Investments measured at net asset value*

Equity securities

Common/collective trusts

$

-

-

-

-

-

-

Debt securities

Common/collective trusts

-

-

-

-

-

-

Cash and cash equivalents

-

-

-

-

-

-

-

Real estate

-

-

-

-

-

-

Total**

$

1,249

2,137

3,345

*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 2020, 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.

2020

$

2021

2022

2023

2024

2025–2029

Severance Accrual

The following table summarizes our severance accrual

activity for the year ended December 31, 2019:

Millions of Dollars

Balance at December 31, 2018

$

Accruals

(1)

Benefit payments

(24)

Balance at December 31, 2019

$

Of the remaining balance at December 31, 2019,

$

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 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 2019, $

million in 2018, and

$

million in 2017.

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 2019, $

million in 2018, and $

million in 2017.

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 79 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 income (loss) and the

associated tax benefit for the years ended

December 31 were as follows:

Millions of Dollars

2019

2018

2017

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.

The fair market values of the options granted in

2017 were measured on the date of grant

using the

Black-Scholes-Merton option-pricing model.

The weighted-average assumptions used were as follows:

2017

Assumptions used

Risk-free interest rate

2.24

%

Dividend yield

4.00

%

Volatility

factor

28.12

%

Expected life (years)

6.39

There were no ranges in the assumptions used to

determine the fair market values of our options

granted in

We believe our historical volatility for periods prior to the 2012 separation of our

Downstream businesses is no

longer relevant in estimating expected volatility.

For 2017,

expected volatility was based on the weighted-

average blend of the company’s historical stock price volatility from

May 1, 2012 (the date of separation of our

Downstream businesses) through the stock option

grant date and the average historical

stock price volatility of

a group of peer companies for the expected term

of the options.

The following summarizes our stock option activity

for the year ended December 31, 2019:

Millions of Dollars

Weighted-Average

Aggregate

Options

Exercise Price

Intrinsic Value

Outstanding at December 31, 2018

19,379,677

$

52.88

$

Exercised

(1,339,480)

36.28

Forfeited

-

Expired or cancelled

-

Outstanding at December 31, 2019

18,040,197

$

54.11

$

Vested at December 31, 2019

17,922,026

$

54.14

$

Exercisable at December 31, 2019

17,172,815

$

54.33

$

The weighted-average remaining contractual term

of outstanding options, vested options and exercisable

options at December 31, 2019, was

4.43

years,

4.41

years and

4.29

years, respectively.

The weighted-average

grant date fair value of stock option awards granted

during 2017 was $

9.18

.

The aggregate intrinsic value of

options exercised was $

million in 2018 and $

million in 2017.

During 2019, we received $

million in cash and realized a tax benefit

of $

million from the exercise of

options.

At December 31, 2019, the remaining unrecognized

compensation expense from unvested options

was

zero

.

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 quarterly

cash payment of a dividend equivalent 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, 2019:

Weighted-Average

Millions of Dollars

Stock Units

Grant Date Fair Value

Total Fair Value

Outstanding at December 31, 2018

7,546,973

$

43.41

Granted

2,045,503

67.77

Forfeited

(99,748)

62.93

Issued

(3,269,682)

34.32

$

Outstanding at December 31, 2019

6,223,046

$

55.99

Not Vested at December 31, 2019

4,185,141

56.17

At December 31, 2019,

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

2.73

years.

The weighted-average grant date fair value

of stock unit awards granted during 2018 and

2017 was $

52.45

and $

48.77

, respectively.

The total fair value of stock units issued during

2018 and 2017 was

$

million and $

million, respectively.

Cash-Settled

Beginning in 2018, cash-settled executive restricted stock units 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.

The following summarizes our cash-settled stock

unit activity for the year ended December 31, 2019:

Weighted-Average

Millions of Dollars

Stock Units

Grant Date Fair Value

Total Fair Value

Outstanding at December 31, 2018

376,608

$

62.21

Granted

319,552

68.20

Forfeited

(6,914)

61.35

Issued

(92,255)

61.61

$

Outstanding at December 31, 2019

596,991

$

64.54

Not Vested at December 31, 2019

153,457

64.54

At December 31, 2019,

the remaining unrecognized compensation

cost from the unvested cash-settled units

was $

million, which will be recognized over a

weighted-average period of

1.70

years, the longest period

being

2.12

years.

The weighted-average grant date fair value

of stock unit awards granted during 2018

was

$

53.68

.

The total fair value of stock units issued during

2018 was $

million.

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, 2019:

Weighted-Average

Millions of Dollars

Stock Units

Grant Date Fair Value

Total Fair Value

Outstanding at December 31, 2018

2,335,542

$

50.45

Granted

77,841

68.90

Forfeited

-

Issued

(388,559)

53.66

$

Outstanding at December 31, 2019

2,024,824

$

50.55

Not Vested at December 31, 2019

15,616

$

47.80

At December 31, 2019,

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 2018 and 2017 was $

53.28

and $

49.76

, respectively.

The total fair value of stock-settled PSUs issued

during 2018 and 2017 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, 2019:

Weighted-Average

Millions of Dollars

Stock Units

Grant Date Fair Value

Total Fair Value

Outstanding at December 31, 2018

1,131,007

$

62.21

Granted

1,958,043

68.90

Forfeited

-

Settled

(2,479,776)

69.10

$

Outstanding at December 31, 2019

609,274

$

64.54

Not Vested at December 31, 2019

38,487

$

64.54

At December 31, 2019,

the remaining unrecognized compensation

cost from unvested cash-settled

performance share awards was

zero

.

The weighted-average grant date fair value of

cash-settled PSUs granted

during 2018 and 2017 was $

53.28

and $

49.76

, respectively.

The total fair value of cash-settled performance

share awards settled during 2018 and 2017

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 quarterly dividend

or

dividend equivalent.

The following summarizes the aggregate activity

of these restricted shares and units for the

year ended

December 31, 2019:

Weighted-Average

Millions of Dollars

Stock Units

Grant Date Fair Value

Total Fair Value

Outstanding at December 31, 2018

1,107,315

$

46.57

Granted

64,063

63.58

Cancelled

(2,307)

23.73

Issued

(177,163)

49.23

$

Outstanding at December 31, 2019

991,908

$

47.24

At December 31, 2019, 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 2018 and 2017 was $

62.01

and $

48.87

, respectively.

The total fair value of awards issued

during 2018 and 2017 was $

million and $

million, respectively.

Note 19—Income Taxes

Income taxes charged to net income (loss) were:

Millions of Dollars

2019

2018

2017

Income Taxes

Federal

Current

$

Deferred

(113)

(3,046)

Foreign

Current

2,545

3,273

1,729

Deferred

(323)

(166)

(510)

State and local

Current

Deferred

(8)

(96)

(125)

$

2,267

3,668

(1,822)

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

2019

2018

Deferred Tax Liabilities

PP&E and intangibles

$

8,660

8,004

Inventory

Deferred state income tax

-

Other

Total deferred tax liabilities

8,929

8,281

Deferred Tax Assets

Benefit plan accruals

Asset retirement obligations and accrued environmental

costs

2,339

2,891

Investments in joint ventures

1,722

Other financial accruals and deferrals

Loss and credit carryforwards

8,968

2,378

Other

Total deferred tax assets

14,693

6,742

Less: valuation allowance

(10,214)

(3,040)

Net deferred tax assets

4,479

3,702

Net deferred tax liabilities

$

4,450

4,579

At December 31, 2019, noncurrent assets and liabilities

included deferred taxes of $

million and

$

4,634

million, respectively.

At December 31, 2018, noncurrent assets and liabilities

included deferred taxes

of $

million and $

5,021

million, respectively.

At December 31, 2019, the components of

our loss and credit carryforwards before and

after consideration of

the applicable valuation allowances were:

Millions of Dollars

Net Deferred

Expiration of

Gross Deferred

Tax Asset After

Net Deferred

Tax Asset

Valuation Allowance

Tax Asset

U.S. foreign tax credits

$

7,696

2028

U.S. general business credits

2036-2038

U.S. capital loss

2024

State net operating losses and tax credits

Various

Foreign net operating losses and tax credits

Post 2025

$

8,968

Valuation

allowances have been established to reduce

deferred tax assets to an amount that will,

more likely

than not, be realized.

During 2019, valuation allowances increased a total

of $

7,174

million.

The increase

primarily relates to deferred tax assets recognized

during 2019 as a result of the finalization of rules

related to

the U.S. Tax Cuts and Jobs Act (Tax Legislation including ongoing issuance of tax regulations related to such

legislation), as further discussed below.

Based on our historical taxable income, expectations

for the future,

and available tax-planning strategies, management

expects deferred tax assets, net of valuation

allowance, 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, 2019, unremitted income

considered to be permanently reinvested in

certain foreign

subsidiaries and foreign corporate joint ventures

totaled approximately $

4,196

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 2019,

2018 and 2017:

Millions of Dollars

2019

2018

2017

Balance at January 1

$

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

(22)

(73)

(129)

Settlements

(9)

(35)

(5)

Lapse of statute

(2)

(4)

(86)

Balance at December 31

$

1,177

1,081

Included in the balance of unrecognized tax benefits

for 2019, 2018 and 2017 were $

1,100

million,

$

1,081

million and $

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.

The balance of unrecognized tax benefits

increased in 2017

mainly due to the recognition of a U.S. worthless securities

deduction that we do not believe will generate a

cash tax benefit.

See Note 13—Contingencies and Commitments,

for more information on the PDVSA

settlement.

At December 31, 2019, 2018 and 2017, accrued liabilities

for interest and penalties totaled $

million,

$

million and $

million, respectively, net of accrued income taxes.

Interest and penalties resulted in a

benefit to earnings of $

million in 2019, a benefit to earnings

of $

million in 2018, and

no

impact to earnings

in 2017.

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 (2018).

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 with the provision for income taxes,

were:

Millions of Dollars

Percent of Pre-Tax Income (Loss)

2019

2018

2017

2019

2018

2017

Income (loss) before income taxes

United States

$

4,704

2,867

(5,250)

49.4

%

28.7

200.8

Foreign

4,820

7,106

2,635

50.6

71.3

(100.8)

$

9,524

9,973

(2,615)

100.0

%

100.0

100.0

Federal statutory income tax

$

2,000

2,095

(915)

21.0

%

21.0

35.0

Non-U.S. effective tax rates

1,399

1,766

14.7

17.7

(23.9)

Tax Legislation

-

(10)

(852)

-

(0.1)

32.6

Canada disposition

-

-

(1,277)

-

-

48.8

U.K. disposition

(732)

(150)

-

(7.7)

(1.5)

-

Recovery of outside basis

(77)

(21)

(962)

(0.8)

(0.2)

36.8

Adjustment to tax reserves

(4)

0.1

-

(33.7)

Adjustment to valuation allowance

(225)

(26)

-

(2.4)

(0.3)

-

APLNG impairment

-

-

-

-

(31.9)

State income tax

(84)

1.3

1.4

3.2

Malaysia Deepwater Incentive

(164)

-

-

(1.7)

-

-

Enhanced oil recovery credit

(27)

(99)

(68)

(0.3)

(1.0)

2.6

Other

(39)

(18)

(4)

(0.4)

(0.2)

0.2

$

2,267

3,668

(1,822)

23.8

%

36.8

69.7

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 5—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 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 24 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 5—Asset Acquisitions and

Dispositions,

for additional information on the disposition.

Tax Legislation was enacted in the U.S. on December 22, 2017, reducing the

U.S. federal corporate income tax

rate to 21 percent from 35 percent, requiring companies

to pay a one-time transition tax on earnings of certain

foreign subsidiaries that were previously tax deferred

and creating new taxes on certain foreign-sourced

earnings.

SAB 118 measurement period

We applied the guidance in Staff Accounting Bulletin No. 118 when accounting for the enactment-date effects

of Tax Legislation in 2017 and throughout 2018.

At December 31, 2017, we had not completed

our

accounting for all the enactment-date income

tax effects of Tax Legislation under ASC 740, Income Taxes, for

the remeasurement of deferred tax assets and liabilities

and the one-time transition tax.

As of December 31,

2018, we had completed our accounting for all the

enactment-date income tax effects of Tax Legislation.

As

further discussed below, during 2018, we recognized adjustments of $

million to the provisional amounts

recorded at December 31, 2017, and included these

adjustments as a component

of income tax provision.

Provisional Amounts—Foreign tax effects

The one-time transition tax is based on our total

post-1986 earnings, the tax on which we previously

deferred

from U.S. income taxes under U.S. law.

We estimated at December 31, 2017, that we would not incur a one-

time transition tax.

Upon further analyses of Tax Legislation and Notices and regulations issued and proposed

by the U.S. Department of the Treasury and the Internal Revenue

Service, we finalized our calculations of the

transition tax liability during 2018.

Based upon this analysis, we did not incur a

one-time transition tax.

As a result of the Tax Legislation, we removed the indefinite reinvestment

assertion on one of our foreign

subsidiaries and recorded a tax expense of $

million in the fourth quarter of 2017.

Deferred tax assets and liabilities

As of December 31, 2017, we remeasured certain deferred

tax assets and liabilities based on the rates at

which

they were expected to reverse in the future (which

was generally 21 percent), by recording a provisional

amount of $

million.

Upon further analysis of certain aspects of

Tax Legislation and refinement of our

calculations during the 12 months ended December

31, 2018, we adjusted our provisional amount by

$

million, which is included as a component of income

tax expense.

Global intangible low-taxed income (GILTI)

We have elected to account for GILTI

in the year the tax is incurred.

For 2019 and 2018,

the current-year U.S.

income tax impact related to GILTI activities is immaterial.

Our effective tax rate in 2017 was favorably impacted

by a tax benefit of $

1,277

million related to the Canada

disposition.

This tax benefit was primarily associated with

a deferred tax recovery related to the Canadian

capital gains exclusion component of the 2017

Canada disposition and the recognition

of previously

unrealizable Canadian capital asset tax basis.

The Canada disposition, along with the

associated restructuring

of our Canadian operations, may generate an additional

tax benefit of $

million.

However, since we

believe it is not likely we will receive a corresponding

cash tax savings, this $

million benefit has been

offset by a full tax reserve.

See Note 5—Asset Acquisitions and Dispositions

for additional information on our

Canada disposition.

The impairment of our APLNG investment in the

second quarter of 2017 did not generate

a tax benefit.

See

the “APLNG” section of Note 6—Investments,

Loans and Long-Term Receivables, for information on the

impairment of our APLNG investment.

Certain operating losses in jurisdictions outside

of the U.S.

only yield a tax benefit in the U.S. as a worthless

security deduction.

For 2019, 2018 and 2017, before consideration

of unrecorded tax benefits discussed above,

the amount of the tax benefit was $

million, $

million and $

million, respectively.

Note 20—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, 2016

$

(547)

-

(5,646)

(6,193)

Other comprehensive income (loss)

(58)

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)

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

January 1, 2018.

**See Note 2

—

Changes in Accounting Principles for additional information.

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 5—Asset Acquisitions and Dispositions.

There were no items within accumulated other comprehensive

loss related to noncontrolling interests.

The following table summarizes reclassifications

out of accumulated other comprehensive loss during

the years

ended December 31:

Millions of Dollars

2019

2018

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 18—Employee Benefit Plans, for additional information.

Note 21—Cash Flow Information

Millions of Dollars

2019

2018

2017

Noncash Investing Activities

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

(decrease) in asset

retirement obligations

$

(37)

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

$

1,163

Income taxes

2,905

2,976

1,168

Net Sales (Purchases) of Investments

Short-term investments purchased

$

(4,902)

(1,953)

(6,617)

Short-term investments sold

2,138

3,573

4,827

Investments and long-term receivables purchased

(146)

-

-

$

(2,910)

1,620

(1,790)

*See Note 5—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.

We collected $

million and $

million

from Ecuador in 2018 and 2017, respectively, as installment payments related

to an agreement reached with

Ecuador in 2017.

For more information on these settlements,

see Note 13—Contingencies and Commitments.

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 and $

million in 2018 and 2017, respectively.

In 2017, we recognized a $

million adverse cash impact from the settlement

of cross-currency swap

transactions.

Note 22—Other Financial Information

Millions of Dollars

2019

2018

2017

Interest and Debt Expense

Incurred

Debt

$

1,114

Other

1,217

Capitalized

(57)

(170)

(119)

Expensed

$

1,098

Other Income

Interest income

$

Unrealized gains (losses) on Cenovus Energy common shares*

(437)

-

Other, net

$

1,358

*See Note 7—Investment in Cenovus Energy, for additional information.

Research and Development Expenditures

—expensed

$

Shipping and Handling Costs

$

1,008

1,075

1,050

Foreign Currency Transaction (Gains) Losses

—after-tax

Alaska

$

-

-

-

Lower 48

-

-

-

Canada

(11)

Europe and North Africa

-

(26)

Asia Pacific and Middle East

Other International

-

Corporate and Other

(3)

$

(13)

Millions of Dollars

2019

2018

Properties, Plants and Equipment

Proved properties

$

88,284

100,657

Unproved properties

3,980

4,662

Other

5,482

5,278

Gross properties, plants and equipment

97,746

110,597

Less: Accumulated depreciation, depletion and amortization

(55,477)

(64,899)

Net properties, plants and equipment

$

42,269

45,698

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

See Note 5

—

Asset Acquisitions and Dispositions, for additional information.

Note 23—Related Party Transactions

Our related parties primarily include equity method

investments and certain trusts for the benefit

of employees.

Significant transactions with our equity affiliates

were:

Millions of Dollars

2019

2018

2017

Operating revenues and other income

$

Purchases

Operating expenses and selling, general and administrative

expenses

Net interest (income) expense*

(13)

(14)

(13)

*We paid interest to, or received interest from,

various affiliates.

See Note 6—Investments, Loans and Long-Term Receivables, for additional

information on loans to affiliated companies.

The table above includes transactions with the

FCCL Partnership through the date of the

sale.

See Note 6—

Investments, Loans and Long-Term Receivables, for additional information.

Note 24—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

2019

2018

2017

Revenue from contracts with customers

$

26,106

28,098

20,525

Revenue from contracts outside the scope of ASC

Topic 606

Physical contracts meeting the definition of a derivative

6,558

8,218

8,669

Financial derivative contracts

(97)

(88)

Consolidated sales and other operating revenues

$

32,567

36,417

29,106

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 25—Segment Disclosures and Related

Information:

Millions of Dollars

2019

2018

2017

Revenue from Outside the Scope of ASC Topic 606

by Segment

Lower 48

$

4,989

6,358

6,302

Canada

Europe and North Africa

1,231

1,503

Physical contracts meeting the definition of a derivative

$

6,558

8,218

8,669

Millions of Dollars

2019

2018

2017

Revenue from Outside the Scope of ASC Topic 606

by Product

Crude oil

$

1,112

Natural gas

5,313

6,734

7,811

Other

Physical contracts meeting the definition of a derivative

$

6,558

8,218

8,669

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, 2019, the “Accounts and

notes receivable” line on our consolidated

balance sheet included

trade receivables of $

2,372

million compared with $

2,889

million at December 31, 2018, 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, 2018

$

Contractual payments received

Revenue recognized

(199)

At December 31, 2019

$

We expect to recognize the contract liabilities as of December 31, 2019, as revenue during 2021 and 2022.

Note 25—Segment Disclosures and Related Information

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

a worldwide

basis.

We manage our operations through

six

operating segments, which are primarily defined

by geographic

region: Alaska, Lower 48, Canada, Europe and

North Africa, Asia Pacific and Middle East,

and Other

International.

Corporate and Other represents 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.

Analysis of Results by Operating Segment

Millions of Dollars

2019

2018

2017

Sales and Other Operating Revenues

Alaska

$

5,483

5,740

4,224

Lower 48

15,514

17,029

12,968

Intersegment eliminations

(46)

(40)

(4)

Lower 48

15,468

16,989

12,964

Canada

2,910

3,184

3,178

Intersegment eliminations

(1,141)

(1,160)

(559)

Canada

1,769

2,024

2,619

Europe and North Africa

5,101

6,635

5,181

Asia Pacific and Middle East

4,525

4,861

4,014

Other International

-

-

-

Corporate and Other

Consolidated sales and other operating revenues

$

32,567

36,417

29,106

Depreciation, Depletion, Amortization and Impairments

Alaska

$

1,026

Lower 48

3,224

2,370

6,693

Canada

Europe and North Africa

1,041

1,313

Asia Pacific and Middle East

1,285

1,382

3,819

Other International

-

-

-

Corporate and Other

Consolidated depreciation, depletion, amortization

and impairments

$

6,495

5,983

13,446

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

2019

2018

2017

Equity in Earnings of Affiliates

Alaska

$

Lower 48

(159)

Canada

-

-

Europe and North Africa

Asia Pacific and Middle East

1,051

Other International

-

-

-

Corporate and Other

-

-

-

Consolidated equity in earnings of affiliates

$

1,074

Income Taxes

Alaska

$

(689)

Lower 48

(2,453)

Canada

(43)

(96)

(616)

Europe and North Africa

1,435

2,265

1,165

Asia Pacific and Middle East

Other International

Corporate and Other

(233)

(103)

Consolidated income taxes

$

2,267

3,668

(1,822)

Net Income (Loss) Attributable to ConocoPhillips

Alaska

$

1,520

1,814

1,466

Lower 48

1,747

(2,371)

Canada

2,564

Europe and North Africa

2,724

1,866

Asia Pacific and Middle East

1,929

2,070

(1,098)

Other International

Corporate and Other

(1,667)

(2,136)

Consolidated net income (loss) attributable

to ConocoPhillips

$

7,189

6,257

(855)

Investments in and Advances to Affiliates

Alaska

$

Lower 48

Canada

-

-

-

Europe and North Africa

Asia Pacific and Middle East

8,281

8,821

9,077

Other International

-

-

-

Corporate and Other

-

-

-

Consolidated investments in and advances to affiliates

$

8,453

9,340

9,590

Millions of Dollars

2019

2018

2017

Total Assets

Alaska

$

15,453

14,648

12,108

Lower 48

14,425

14,888

14,632

Canada

6,350

5,748

6,214

Europe and North Africa

8,121

9,883

11,870

Asia Pacific and Middle East

14,716

16,151

16,985

Other International

Corporate and Other

11,164

8,573

11,456

Consolidated total assets

$

70,514

69,980

73,362

Capital Expenditures and Investments

Alaska

$

1,513

1,298

Lower 48

3,394

3,184

2,136

Canada

Europe and North Africa

Asia Pacific and Middle East

Other International

Corporate and Other

Consolidated capital expenditures and investments

$

6,636

6,750

4,591

Interest Income and Expense

Interest income

Alaska

$

-

-

-

Lower 48

-

-

-

Canada

-

-

-

Europe and North Africa

Asia Pacific and Middle East

Other International

-

-

-

Corporate and Other

Interest and debt expense

Corporate and Other

$

1,098

Sales and Other Operating Revenues by

Product

Crude oil

$

18,482

19,571

13,260

Natural gas

8,715

10,720

10,773

Natural gas liquids

1,114

1,102

Other*

4,556

5,012

3,971

Consolidated sales and other operating revenues

by product

$

32,567

36,417

29,106

*Includes LNG and bitumen.

Geographic Information

Millions of Dollars

Sales and Other Operating Revenues

(1)

Long-Lived Assets

(2)

2019

2018

2017

2019

2018

2017

United States

(3)

$

21,159

22,740

17,204

26,566

26,838

23,623

Australia and Timor-Leste

(4)

1,647

1,798

1,448

7,228

9,301

9,657

Canada

1,769

2,024

2,619

5,769

5,333

5,613

China

1,447

1,380

1,275

Indonesia

Libya

1,103

1,142

Malaysia

1,230

1,346

1,103

1,871

2,327

2,736

Norway

2,349

2,886

2,348

5,258

5,582

6,154

United Kingdom

1,649

2,606

2,248

1,583

3,335

Other foreign countries

1,308

1,346

1,423

Worldwide consolidated

$

32,567

36,417

29,106

50,722

55,038

55,273

(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.

(3) Long-lived assets do not include $

million of net PP&E associated with assets held

for sale as of December 31,

See Note 5—Acquisitions and Dispositions, for additional

information.

(4) Long-lived assets do not include $

1,236

million of net PP&E associated with assets

held for sale as of December

31, 2019.

See Note 5—Acquisitions and Dispositions, for additional

information.

Note 26—New Accounting Standards

In June 2016, the FASB issued ASU No. 2016-13, “Measurement of Credit Losses on

Financial Instruments”

(ASU No. 2016-13), which sets forth the current

expected credit loss model, a new forward-looking

impairment model for certain financial instruments

based on expected losses rather than incurred losses.

The

ASU is effective for interim and annual periods beginning

after December 15, 2019.

Entities are required to

adopt ASU No. 2016-13 using a modified retrospective

approach, subject to certain limited exceptions.

The

impact

of adopting this ASU is not expected to be material

to our financial statements.

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, and Africa. Period end proved

reserves, capitalized costs, wells and acreage

include held-

for-sale assets at December 31, 2019. See Note 5—Asset

Acquisitions and Dispositions, in the Notes to

Consolidated Financial Statements, for additional

information on held-for-sale assets.

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, 2019, approximately

6 percent of our total

proved reserves were under PSCs, located in

our Asia Pacific/Middle East geographic

reporting area, and 6

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 2019, our processes and controls used

to assess over 90 percent of proved reserves

as of December 31,

2019, 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, 2019, 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 2016

1,343

2,047

Revisions

-

Improved recovery

-

-

-

-

-

Purchases

-

-

-

-

-

-

-

-

Extensions and discoveries

-

-

-

Production

(60)

(64)

(124)

(1)

(45)

(34)

(7)

(211)

Sales

-

(10)

(10)

(12)

-

-

-

(22)

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

Equity affiliates

End of 2016

-

-

-

-

-

-

Revisions

-

-

-

-

-

-

-

-

Improved recovery

-

-

-

-

-

-

-

-

Purchases

-

-

-

-

-

-

-

-

Extensions and discoveries

-

-

-

-

-

-

-

-

Production

-

-

-

-

-

(5)

-

(5)

Sales

-

-

-

-

-

-

-

-

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

-

-

-

-

-

-

Total

company

End of 2016

1,343

2,135

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

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 2016

1,003

1,509

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

Equity affiliates

End of 2016

-

-

-

-

-

-

End of 2017

-

-

-

-

-

-

End of 2018

-

-

-

-

-

-

End of 2019

-

-

-

-

-

-

Undeveloped

Consolidated operations

End of 2016

-

-

End of 2017

-

-

End of 2018

End of 2019

Equity affiliates

End of 2016

-

-

-

-

-

-

-

-

End of 2017

-

-

-

-

-

-

-

-

End of 2018

-

-

-

-

-

-

-

-

End of 2019

-

-

-

-

-

-

-

-

Notable changes in proved crude oil reserves

in the three years ended December 31, 2019,

included:

●

Revisions

: 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.

In 2017, revisions in Alaska, Lower 48, 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 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.

In 2017, extensions and discoveries in Lower 48

were primarily due to continued drilling success

in the Permian

Unconventional, Eagle Ford and Bakken.

●

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.

In 2017,

Canada sales were due to the disposition of

a majority of our western Canada assets.

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 2016

Revisions

-

Improved recovery

-

-

-

-

-

-

-

Purchases

-

-

-

-

-

-

-

Extensions and discoveries

-

-

-

Production

(5)

(24)

(29)

(3)

(3)

(2)

(37)

Sales

-

(130)

(130)

(44)

-

-

(174)

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

Equity affiliates

End of 2016

-

-

-

-

-

Revisions

-

-

-

-

-

-

-

Improved recovery

-

-

-

-

-

-

-

Purchases

-

-

-

-

-

-

-

Extensions and discoveries

-

-

-

-

-

-

-

Production

-

-

-

-

-

(2)

(2)

Sales

-

-

-

-

-

-

-

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

-

-

-

-

-

Total

company

End of 2016

End of 2017

End of 2018

End of 2019

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 2016

End of 2017

End of 2018

-

End of 2019

Equity affiliates

End of 2016

-

-

-

-

-

End of 2017

-

-

-

-

-

End of 2018

-

-

-

-

-

End of 2019

-

-

-

-

-

Undeveloped

Consolidated operations

End of 2016

-

-

End of 2017

-

-

End of 2018

-

-

End of 2019

-

-

Equity affiliates

End of 2016

-

-

-

-

-

-

-

End of 2017

-

-

-

-

-

-

-

End of 2018

-

-

-

-

-

-

-

End of 2019

-

-

-

-

-

-

-

Notable changes in proved NGL reserves in the three

years ended December 31, 2019,

included:

●

Revisions

: 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.

In 2017, revisions in Lower 48 were primarily

due to higher prices.

●

Extensions and discoveries

: 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.

In 2017, extensions and discoveries in Lower 48

were primarily due to continued drilling success

in the Permian

Unconventional, Eagle Ford and Bakken.

●

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.

In 2017, Lower 48 sales were due to the

disposition of our interests in the

San Juan Basin and Panhandle assets, while Canada

sales were due to the disposition of a majority

of our western

Canada assets.

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 2016

2,102

4,714

6,816

1,037

1,238

1,526

10,844

Revisions

-

Improved recovery

-

-

-

-

-

-

-

-

Purchases

-

-

-

-

-

-

-

-

Extensions and discoveries

-

-

Production

(71)

(338)

(409)

(71)

(188)

(267)

(3)

(938)

Sales

-

(2,885)

(2,885)

(966)

-

-

-

(3,851)

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

Equity affiliates

End of 2016

-

-

-

-

-

4,381

-

4,381

Revisions

-

-

-

-

-

-

Improved recovery

-

-

-

-

-

-

-

-

Purchases

-

-

-

-

-

-

-

-

Extensions and discoveries

-

-

-

-

-

-

Production

-

-

-

-

-

(374)

-

(374)

Sales

-

-

-

-

-

-

-

-

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

Total

company

End of 2016

2,102

4,714

6,816

1,037

1,238

5,907

15,225

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

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 2016

2,094

4,199

6,293

1,031

1,188

9,737

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

Equity affiliates

End of 2016

-

-

-

-

-

4,110

-

4,110

End of 2017

-

-

-

-

-

4,044

-

4,044

End of 2018

-

-

-

-

-

4,059

-

4,059

End of 2019

-

-

-

-

-

3,898

-

3,898

Undeveloped

Consolidated operations

End of 2016

-

1,107

End of 2017

-

-

1,519

End of 2018

-

1,397

End of 2019

1,033

1,120

-

1,466

Equity affiliates

End of 2016

-

-

-

-

-

-

End of 2017

-

-

-

-

-

-

End of 2018

-

-

-

-

-

-

End of 2019

-

-

-

-

-

-

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 3,141 Bcf,

3,131 Bcf, and 3,825 Bcf as of December 31,

2019, 2018 and 2017, 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, 2019, included:

●

Revisions

: 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.

In 2017, revisions in Alaska, Lower 48 and

Europe 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 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.

In 2017, extensions and discoveries in Lower 48

were primarily due to continued drilling success

in the Permian

Unconventional, Eagle Ford and Bakken.

●

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 interest in Barnett.

In 2017, Lower 48 sales were due to the disposition

of our interests in the San

Juan Basin and Panhandle assets, while Canada sales

were due to the disposition of a majority

of our western Canada

assets.

Years Ended

Bitumen

December 31

Millions of Barrels

Canada

Developed and Undeveloped

Consolidated operations

End of 2016

Revisions

Improved recovery

-

Purchases

-

Extensions and discoveries

Production

(21)

Sales

-

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

Equity affiliates

End of 2016

1,089

Revisions

-

Improved recovery

-

Purchases

-

Extensions and discoveries

-

Production

(23)

Sales

(1,066)

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

Total

company

End of 2016

1,248

End of 2017

End of 2018

End of 2019

Years Ended

Bitumen

December 31

Millions of Barrels

Canada

Developed

Consolidated operations

End of 2016

End of 2017

End of 2018

End of 2019

Equity affiliates

End of 2016

End of 2017

-

End of 2018

-

End of 2019

-

Undeveloped

Consolidated operations

End of 2016

-

End of 2017

End of 2018

End of 2019

Equity affiliates

End of 2016

End of 2017

-

End of 2018

-

End of 2019

-

Notable changes in proved bitumen reserves

in the three years ended December 31, 2019,

included:

●

Revisions

: 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 and 2017,

revisions were primarily due to higher

prices at Surmont.

●

Extensions and discoveries

: 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.

In 2017, extensions and discoveries were primarily

due to higher prices at Surmont, which allowed

undeveloped reserves previously de-booked due

to low prices to be recognized.

●

Sales

: In 2017, sales were due to the disposition of

our 50 percent interest in the FCCL Partnership

in

Canada.

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 2016

1,294

1,570

2,864

4,470

Revisions

-

Improved recovery

-

-

-

-

-

Purchases

-

-

-

-

-

-

-

-

Extensions and discoveries

-

-

Production

(77)

(144)

(221)

(37)

(79)

(81)

(8)

(426)

Sales

-

(621)

(621)

(217)

-

-

-

(838)

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

Equity affiliates

End of 2016

-

-

-

1,089

-

-

1,954

Revisions

-

-

-

-

-

-

Improved recovery

-

-

-

-

-

-

-

-

Purchases

-

-

-

-

-

-

-

-

Extensions and discoveries

-

-

-

-

-

-

Production

-

-

-

(23)

-

(69)

-

(92)

Sales

-

-

-

(1,066)

-

-

-

(1,066)

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

-

-

-

-

-

-

Total

company

End of 2016

1,294

1,570

2,864

1,482

1,309

6,424

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

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 2016

1,203

1,165

2,368

3,674

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

Equity affiliates

End of 2016

-

-

-

-

-

1,142

End of 2017

-

-

-

-

-

-

End of 2018

-

-

-

-

-

-

End of 2019

-

-

-

-

-

-

Undeveloped

Consolidated operations

End of 2016

-

End of 2017

-

1,148

End of 2018

1,078

End of 2019

1,240

Equity affiliates

End of 2016

-

-

-

-

-

End of 2017

-

-

-

-

-

-

End of 2018

-

-

-

-

-

-

End of 2019

-

-

-

-

-

-

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

We had 1,327 MMBOE of PUDs at year-end 2019,

compared with 1,162 MMBOE at year-end 2018.

The following table

shows changes in total proved undeveloped reserves

for 2019:

Proved Undeveloped Reserves

Millions of Barrels of

Oil Equivalent

End of 2018

1,162

Transfers to proved developed

(286)

Revisions

(5)

Improved recovery

Purchases

Extensions and discoveries

Sales

(20)

End of 2019

1,327

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 Asia Pacific/Middle East, Alaska, Europe

and Canada regions.

Downward revisions were driven by changes in

development timing of 166 MMBOE primarily

in Lower 48 and Canada,

largely offset by upward revisions for infill drilling of 147 MMBOE

primarily in Lower 48, Europe, Alaska and

Africa.

Extensions and discoveries were largely driven by an addition

of 358 MMBOE in Lower 48 for the continued development

of

unconventional plays. The remaining extensions

and discoveries were driven by the continued

development planned in Alaska,

Canada and Asia Pacific/Middle East.

Sales were due to the disposition of the U.K.

assets.

At December 31, 2019, our PUDs represented

25 percent of total proved reserves, compared

with 22 percent at December 31,

Costs incurred for the year ended December

31, 2019, relating to the development of PUDs

were $4.6 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 2019, more than 90 percent of total

PUDs were under development or scheduled for

development within five

years of initial disclosure. The remainder are to

be developed as parts of major projects ongoing

in our Canada, Asia

Pacific/Middle East and Europe regions.

All major development areas are currently producing

and are expected to have PUDs

convert to proved developed over time.

Of our total PUDs at year-end 2019, 81 percent are

in North America, and 95 percent of

these reserve volumes are planned for development

within five years of initial disclosure.

Results of Operations

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

for the years 2019, 2018 and 2017 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, 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

$

-

-

-

-

-

-

-

Year Ended

Millions of Dollars

December 31, 2017

Lower

Total

Asia Pacific/

Other

Alaska

U.S.

Canada

Europe

Middle East

Africa

Areas

Total

Consolidated operations

Sales

$

3,542

4,557

8,099

3,527

2,752

-

15,570

Transfers

-

-

-

-

-

Transportation costs

(706)

-

(706)

-

-

(80)

-

-

(786)

Other revenues

2,158

2,649

Total revenues

2,854

4,585

7,439

2,863

3,595

3,094

17,848

Production costs excluding taxes

1,607

2,554

(1)

4,537

Taxes other than income taxes

-

Exploration expenses

Depreciation, depletion and

amortization

2,685

3,415

1,234

1,283

-

6,386

Impairments

3,969

4,148

-

-

-

4,216

Other related expenses

(7)

-

Accretion

-

-

(4,703)

(4,108)

1,721

1,239

1,012

Income tax provision (benefit)

(669)

(2,401)

(3,070)

(651)

(2,217)

Results of operations

$

1,264

(2,302)

(1,038)

2,372

(22)

2,765

Equity affiliates

Sales

$

-

-

-

-

-

-

1,091

Transfers

-

-

-

-

-

1,398

-

-

1,398

Transportation costs

-

-

-

-

-

-

-

-

-

Other revenues

-

-

-

-

-

-

-

Total revenues

-

-

-

-

1,961

-

-

2,494

Production costs excluding taxes

-

-

-

-

-

-

Taxes other than income taxes

-

-

-

-

-

-

Exploration expenses

-

-

-

-

1,699

-

-

1,700

Depreciation, depletion and

-

-

-

-

-

-

-

-

amortization

-

-

-

-

-

-

Impairments

-

-

-

-

-

1,717

-

-

1,717

Other related expenses

-

-

-

-

-

Accretion

-

-

-

-

-

-

-

-

-

-

(3,072)

-

(19)

(2,896)

Income tax provision (benefit)

-

-

-

-

(998)

-

(959)

Results of operations

$

-

-

-

-

(2,074)

-

(32)

(1,937)

Statistics

Net Production

2019

2018

2017

Thousands of Barrels Daily

Crude Oil

Consolidated operations

Alaska

Lower 48

United States

Canada

Europe

Asia Pacific/Middle East

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/Middle East

Total consolidated

operations

Equity affiliates—

Asia Pacific/Middle East

Total company

Greater Prudhoe Area

(Alaska)*

Bitumen

Consolidated operations—

Canada

Equity affiliates—

Canada

Total company

Natural Gas

Millions of Cubic Feet Daily

Consolidated operations

Alaska

Lower 48

United States

Canada

Europe

Asia Pacific/Middle East

Africa

Total consolidated

operations

1,753

1,743

2,263

Equity affiliates—

Asia Pacific/Middle East

1,052

1,031

1,007

Total company

2,805

2,774

3,270

Greater Prudhoe Area

(Alaska)*

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

Average Sales

Prices

2019

2018

2017

Crude Oil Per Barrel

Consolidated operations

Alaska

$

55.85

60.23

42.69

Lower 48

55.30

62.99

47.36

United States

55.54

61.75

45.01

Canada

40.87

48.73

43.69

Europe

65.12

70.98

54.04

Asia Pacific/Middle East

65.02

70.93

54.38

Africa

64.47

69.83

55.11

Total international

64.85

70.67

54.16

Total consolidated

operations

58.51

65.01

48.70

Equity affiliates

—Asia Pacific/Middle East

61.32

72.49

54.76

Total operations

58.57

65.17

48.84

Natural Gas Liquids Per Barrel

Consolidated operations

Lower 48

$

16.83

27.30

22.20

United States

16.85

27.30

22.20

Canada

19.87

43.70

21.51

Europe

29.37

36.87

34.07

Asia Pacific/Middle East

37.85

47.20

41.37

Total international

32.29

40.00

30.34

Total consolidated

operations

18.73

29.03

24.21

Equity affiliates

—Asia Pacific/Middle East

36.70

45.69

38.74

Total operations

20.09

30.48

25.22

Bitumen Per Barrel

Consolidated operations—

Canada

$

31.72

22.29

21.43

Equity affiliates—

Canada

23.83

Natural Gas Per Thousand Cubic Feet

Consolidated operations

Alaska

$

3.19

2.48

2.72

Lower 48

2.12

2.82

2.73

United States

2.12

2.82

2.73

Canada

0.49

1.00

1.93

Europe

4.92

7.79

5.72

Asia Pacific/Middle East

5.73

5.95

4.66

Africa

4.87

4.84

3.53

Total international

5.35

6.64

4.64

Total consolidated

operations

4.19

5.33

3.87

Equity affiliates

—Asia Pacific/Middle East

6.29

6.06

4.27

Total operations

4.99

5.60

4.00

Average sales prices for Alaska crude oil and Asia Pacific/Middle East 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.

2019

2018

2017

Average Production

Costs Per Barrel of Oil Equivalent*

Consolidated operations

Alaska

$

15.52

14.20

14.26

Lower 48

9.59

10.58

11.03

United States

11.52

11.73

12.04

Canada

16.53

16.32

16.22

Europe

11.22

11.73

10.09

Asia Pacific/Middle East

8.74

9.03

7.31

Africa

4.46

4.14

5.74

Total international

10.26

10.72

9.99

Total consolidated operations

10.99

11.26

11.05

Equity affiliates

Canada

7.57

Asia Pacific/Middle East

4.68

4.56

5.26

Total equity affiliates

4.68

4.56

5.84

Average Production

Costs Per Barrel—Bitumen

Consolidated operations—

Canada

$

13.74

13.59

14.63

Equity affiliates—

Canada

18.74

Taxes

Other Than Income Taxes Per Barrel

of Oil Equivalent

Consolidated operations

Alaska

$

3.87

5.26

4.14

Lower 48

2.65

2.98

2.18

United States

3.05

3.71

2.80

Canada

0.78

0.82

0.89

Europe

0.48

0.45

0.42

Asia Pacific/Middle East

0.76

1.33

0.50

Africa

0.19

0.20

0.26

Total international

0.60

0.82

0.53

Total consolidated operations

2.03

2.37

1.70

Equity affiliates

Canada

0.30

Asia Pacific/Middle East

11.46

11.41

8.76

Total equity affiliates

11.46

11.41

6.64

Depreciation, Depletion and Amortization Per Barrel of Oil Equivalent

Consolidated operations

Alaska

$

8.80

9.07

10.99

Lower 48

17.03

15.73

18.44

United States

14.35

13.60

16.10

Canada

10.00

12.25

11.76

Europe

12.75

14.66

16.18

Asia Pacific/Middle East

16.55

16.58

16.58

Africa

2.36

2.21

2.09

Total international

12.99

14.06

14.96

Total consolidated operations

13.78

13.82

15.55

Equity affiliates

Canada

6.52

Asia Pacific/Middle East

8.09

9.09

8.94

Total equity affiliates

8.09

9.09

8.34

*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, 2019,

2018 and 2017.

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

2019

2018

2017

2019

2018

2017

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

Canada

-

-

-

-

-

Asia Pacific/Middle East

-

-

-

Other areas

-

-

-

-

-

-

Total equity affiliates

-

-

-

*Our total proportionate interest was less than one.

The table below represents the status of our wells

drilling at December 31, 2019, 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, 2019.

Wells at December 31, 2019

Productive

In Progress

Oil

Gas

Gross

Net

Gross

Net

Gross

Net

Consolidated operations

Alaska

1,656

-

-

Lower 48

10,070

4,547

4,329

1,704

United States

11,726

5,544

4,329

1,704

Canada

Europe

Asia Pacific/Middle East

Africa

Other areas

-

-

-

-

Total consolidated

operations

13,523

5,996

4,478

1,762

Equity affiliates

Asia Pacific/Middle East

-

-

4,307

1,051

Total equity affiliates

-

-

4,307

1,051

Acreage at December 31, 2019

Thousands of Acres

Developed

Undeveloped

Gross

Net

Gross

Net

Consolidated operations

Alaska

1,331

1,320

Lower 48

2,569

2,012

10,337

8,396

United States

3,220

2,479

11,668

9,716

Canada

3,270

1,798

Europe

2,102

Asia Pacific/Middle East

1,538

9,910

5,735

Africa

12,545

2,049

Other areas

-

-

1,400

Total consolidated

operations

5,752

3,434

40,895

20,650

Equity affiliates

Asia Pacific/Middle East

3,723

Total equity affiliates

3,723

Costs Incurred

Year Ended

Millions of Dollars

December 31

Lower

Total

Asia Pacific/

Other

Alaska

U.S.

Canada

Europe

Middle East

Africa

Areas

Total

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

-

-

-

-

-

-

-

$

-

-

-

-

-

-

-

2017

Consolidated operations

Unproved property acquisition

$

-

-

-

Proved property acquisition

-

-

-

-

-

-

-

-

-

Exploration

Development

1,559

2,295

-

3,579

$

2,260

3,088

4,813

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

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

2018

Consolidated operations

Proved property

$

20,154

35,269

55,423

5,946

23,520

14,866

-

100,657

Unproved property

1,184

1,125

2,309

1,083

4,662

21,338

36,394

57,732

7,029

23,708

15,740

1,021

105,319

Accumulated depreciation,

depletion and amortization

9,055

23,999

33,054

1,692

16,591

9,974

61,662

$

12,283

12,395

24,678

5,337

7,117

5,766

43,657

Equity affiliates

Proved property

$

-

-

-

-

-

9,990

-

-

9,990

Unproved property

-

-

-

-

-

2,162

-

-

2,162

-

-

-

-

-

12,152

-

-

12,152

Accumulated depreciation,

depletion and amortization

-

-

-

-

-

5,960

-

-

5,960

$

-

-

-

-

-

6,192

-

-

6,192

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

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

Millions of Dollars

Lower

Total

Asia Pacific/

Alaska

U.S.

Canada

Europe

Middle East

Africa

Total

2017

Consolidated operations

Future cash inflows

$

44,969

44,556

89,525

5,479

23,137

15,207

13,181

146,529

Less:

Future production costs

29,524

18,947

48,471

4,417

8,128

5,398

1,401

67,815

Future development costs

7,255

10,881

18,136

8,758

2,511

30,638

Future income tax provisions

2,375

2,428

-

3,333

2,459

10,356

18,576

Future net cash flows

8,137

12,353

20,490

2,918

4,839

29,500

10 percent annual discount

2,712

4,358

7,070

1,032

8,891

Discounted future net cash flows

$

5,425

7,995

13,420

2,629

3,807

20,609

Equity affiliates

Future cash inflows

$

-

-

-

-

-

23,222

-

23,222

Less:

Future production costs

-

-

-

-

-

12,984

-

12,984

Future development costs

-

-

-

-

-

1,444

-

1,444

Future income tax provisions

-

-

-

-

-

2,083

-

2,083

Future net cash flows

-

-

-

-

-

6,711

-

6,711

10 percent annual discount

-

-

-

-

-

2,316

-

2,316

Discounted future net cash flows

$

-

-

-

-

-

4,395

-

4,395

Total

company

Discounted future net cash flows

$

5,425

7,995

13,420

2,629

8,202

25,004

Sources of Change in Discounted Future Net Cash Flows

Millions of Dollars

Consolidated Operations

Equity Affiliates

Total Company

2019

2018

2017

2019

2018

2017

2019

2018

2017

Discounted future net cash flows

at the beginning of the year

$

35,434

20,609

8,151

7,929

4,395

3,937

43,363

25,004

12,088

Changes during the year

Revenues less production

costs for the year

(13,424)

(14,909)

(9,844)

(1,673)

(1,651)

(1,341)

(15,097)

(16,560)

(11,185)

Net change in prices and

production costs

(13,538)

25,391

19,310

(422)

4,559

2,750

(13,960)

29,950

22,060

Extensions, discoveries and

improved recovery, less

estimated future costs

2,985

4,574

1,445

(4)

3,245

4,956

1,441

Development costs for the year

5,333

5,197

3,653

5,572

5,468

4,079

Changes in estimated future

development costs

(1,141)

1,225

(21)

(64)

(1,127)

1,161

Purchases of reserves in place,

less estimated future costs

3,033

-

-

-

-

3,033

-

Sales of reserves in place,

less estimated future costs

(1,997)

(1,531)

(855)

-

-

(786)

(1,997)

(1,531)

(1,641)

Revisions of previous quantity

estimates

2,099

(365)

2,300

(648)

2,168

(303)

1,652

Accretion of discount

5,144

3,055

1,313

6,013

3,540

1,726

Net change in income taxes

4,767

(8,479)

(6,089)

(80)

(588)

(288)

4,687

(9,067)

(6,377)

Total changes

(8,062)

14,825

12,458

(759)

3,534

(8,821)

18,359

12,916

Discounted future net cash flows

at year end

$

27,372

35,434

20,609

7,170

7,929

4,395

34,542

43,363

25,004

●

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.

Selected Quarterly Financial Data

(Unaudited)

Millions of Dollars

Per Share of Common Stock

Sales and

Net Income

Net Income (Loss)

Other

Income (Loss)

Net

(Loss)

Attributable

Operating

Before

Income

Attributable to

to ConocoPhillips

Revenues

Income Taxes

(Loss)

ConocoPhillips

Basic

Diluted

2019

First

$

9,150

2,687

1,846

1,833

1.61

1.60

Second

7,953

2,058

1,597

1,580

1.40

1.40

Third

7,756

3,493

3,071

3,056

2.76

2.74

Fourth

7,708

1,286

0.66

0.66

2018

First

$

8,798

1,776

0.75

0.75

Second

8,504

2,619

1,654

1,640

1.40

1.39

Third

9,449

2,906

1,873

1,861

1.60

1.59

Fourth

9,666

2,672

1,878

1,868

1.62

1.61

For additional information on the commodity price environment, see the

Business Environment and Executive Overview section of Management's Discussion

and

Analysis of Financial Condition and Results of Operations.

Supplementary Information—Condensed Consolidating

Financial Information

We have various cross guarantees among ConocoPhillips, ConocoPhillips Company

and Burlington Resources

LLC, with respect to publicly held debt securities.

ConocoPhillips Company is 100 percent owned

by

ConocoPhillips.

Burlington Resources LLC is 100 percent

owned by ConocoPhillips Company.

ConocoPhillips and/or ConocoPhillips Company

have fully and unconditionally guaranteed

the payment

obligations of Burlington Resources LLC, with respect

to its publicly held debt securities.

Similarly,

ConocoPhillips has fully and unconditionally

guaranteed the payment obligations of ConocoPhillips

Company

with respect to its publicly held debt securities.

In addition, ConocoPhillips Company

has fully and

unconditionally guaranteed the payment obligations

of ConocoPhillips with respect to its publicly

held debt

securities.

All guarantees are joint and several.

The following condensed consolidating financial

information

presents the results of operations, financial position

and cash flows for:

●

ConocoPhillips, ConocoPhillips Company and

Burlington Resources LLC (in each case, reflecting

investments in subsidiaries utilizing the equity

method of accounting).

●

All other nonguarantor subsidiaries of ConocoPhillips.

●

The consolidating adjustments necessary to present

ConocoPhillips’ results on a consolidated

basis.

In 2017, ConocoPhillips Company received a $

9.8

billion return of capital and a $

1.4

billion loan repayment

from nonguarantor subsidiaries to settle certain

accumulated intercompany balances.

These transactions had

no impact on our consolidated financial statements.

In 2017, ConocoPhillips received a $

7.8

billion return of capital and a $

0.2

billion return of earnings from

ConocoPhillips Company to settle certain

accumulated intercompany balances.

These transactions had no

impact on our consolidated financial statements.

In 2018, ConocoPhillips Company received a $

4.8

billion return of earnings and a $

2.4

billion loan repayment

from nonguarantor subsidiaries to settle certain

accumulated intercompany balances.

These transactions had

no impact on our consolidated financial statements.

In 2018, ConocoPhillips received a $

3.5

billion return of capital and a $

1.0

billion return of earnings from

ConocoPhillips Company to settle certain

accumulated intercompany balances.

These transactions had no

impact on our consolidated financial statements.

In 2019, ConocoPhillips received a $

2.4

billion return of capital and a $

1.7

billion return of earnings from

ConocoPhillips Company to settle certain

accumulated intercompany balances.

This transaction had no impact

on our consolidated financial statements.

In 2019, ConocoPhillips Company received a $

4.5

billion return of earnings and a $

4.2

billion return of capital

from nonguarantor subsidiaries to settle certain

accumulated intercompany balances.

These transactions had

no impact on our consolidated financial statements.

In 2019, Burlington Resources LLC received

a $

3.2

billion return of earnings from nonguarantor

subsidiaries

to settle certain accumulated intercompany balances.

These transactions had no impact on our consolidated

financial statements.

This condensed consolidating financial information

should be read in conjunction with the accompanying

consolidated financial statements and notes.

Millions of Dollars

Year Ended December 31,

2019

Income Statement

ConocoPhillips

ConocoPhillips

Company

Burlington

Resources LLC

All Other

Subsidiaries

Consolidating

Adjustments

Total

Consolidated

Revenues and Other Income

Sales and other operating revenues

$

-

14,510

-

18,057

-

32,567

Equity in earnings of affiliates

7,419

5,281

1,610

(14,306)

Gain (loss) on dispositions

-

2,786

-

(820)

-

1,966

Other income

-

1,358

Intercompany revenues

-

5,542

(5,695)

-

Total Revenues and Other

Income

7,420

23,565

1,655

24,031

(20,001)

36,670

Costs and Expenses

Purchased commodities

-

12,838

-

4,038

(5,034)

11,842

Production and operating expenses

1,380

4,345

(405)

5,322

Selling, general and administrative expenses

-

(5)

Exploration expenses

-

-

-

Depreciation, depletion and amortization

-

-

5,494

-

6,090

Impairments

-

-

-

Taxes other than income taxes

-

-

-

Accretion on discounted liabilities

-

-

-

Interest and debt expense

(251)

Foreign currency transaction losses

-

-

-

Other expenses

-

-

-

Total Costs and Expenses

16,594

15,820

(5,695)

27,146

Income before income taxes

7,127

6,971

1,521

8,211

(14,306)

9,524

Income tax provision (benefit)

(62)

(448)

(46)

2,823

-

2,267

Net income

7,189

7,419

1,567

5,388

(14,306)

7,257

Less: net income attributable to noncontrolling interests

-

-

-

(68)

-

(68)

Net Income Attributable to ConocoPhillips

$

7,189

7,419

1,567

5,320

(14,306)

7,189

Comprehensive Income Attributable to ConocoPhillips

$

7,935

8,165

1,873

6,058

(16,096)

7,935

Income Statement

Year Ended December 31,

2018

Revenues and Other Income

Sales and other operating revenues

$

-

16,113

-

20,304

-

36,417

Equity in earnings of affiliates

6,503

8,142

1,953

1,072

(16,596)

1,074

Gain on dispositions

-

-

-

1,063

Other income (loss)

-

(384)

-

-

Intercompany revenues

5,627

(5,867)

-

Total Revenues and Other

Income

6,538

24,272

1,996

28,384

(22,463)

38,727

Costs and Expenses

Purchased commodities

-

14,591

-

5,131

(5,428)

14,294

Production and operating expenses

-

1,023

4,245

(59)

5,213

Selling, general and administrative expenses

-

(5)

Exploration expenses

-

-

-

Depreciation, depletion and amortization

-

-

5,372

-

5,956

Impairments

-

(10)

-

-

Taxes other than income taxes

-

-

-

1,048

Accretion on discounted liabilities

-

-

-

Interest and debt expense

(375)

Foreign currency transaction (gains) losses

(12)

(167)

-

(17)

Other expenses

-

-

Total Costs and Expenses

17,757

16,343

(5,867)

28,754

Income before income taxes

6,189

6,515

1,824

12,041

(16,596)

9,973

Income tax provision (benefit)

(68)

(41)

3,765

-

3,668

Net income

6,257

6,503

1,865

8,276

(16,596)

6,305

Less: net income attributable to noncontrolling interests

-

-

-

(48)

-

(48)

Net Income Attributable to ConocoPhillips

$

6,257

6,503

1,865

8,228

(16,596)

6,257

Comprehensive Income Attributable to ConocoPhillips

$

5,654

5,900

1,364

7,961

(15,225)

5,654

See Notes to Consolidated Financial Statements.

Millions of Dollars

Year Ended December 31,

2017

Income Statement

ConocoPhillips

ConocoPhillips

Company

Burlington

Resources LLC

All Other

Subsidiaries

Consolidating

Adjustments

Total

Consolidated

Revenues and Other Income

Sales and other operating revenues

$

-

12,433

-

16,673

-

29,106

Equity in earnings (losses) of affiliates

(454)

2,047

(2,477)

Gain on dispositions

-

-

1,261

-

2,177

Other income

-

-

Intercompany revenues

3,369

(3,721)

-

Total Revenues and Other

Income

(404)

15,722

22,565

(6,198)

32,584

Costs and Expenses

Purchased commodities

-

11,145

-

4,580

(3,250)

12,475

Production and operating expenses

-

-

4,366

(17)

5,162

Selling, general and administrative expenses

-

(6)

Exploration expenses

-

-

-

Depreciation, depletion and amortization

-

-

5,990

-

6,845

Impairments

-

1,159

-

5,442

-

6,601

Taxes other than income taxes

-

-

Accretion on discounted liabilities

-

-

-

Interest and debt expense

(448)

1,098

Foreign currency transaction (gains) losses

(43)

(137)

-

Other expenses

-

(6)

-

Total Costs and Expenses

15,893

(84)

22,458

(3,721)

35,199

Income (Loss) before income taxes

(1,057)

(171)

(2,477)

(2,615)

Income tax provision (benefit)

(202)

(337)

(1,566)

-

(1,822)

Net income (loss)

(855)

(454)

1,320

1,673

(2,477)

(793)

Less: net income attributable to noncontrolling interests

-

-

-

(62)

-

(62)

Net Income (Loss) Attributable to ConocoPhillips

$

(855)

(454)

1,320

1,611

(2,477)

(855)

Comprehensive Income (Loss) Attributable to ConocoPhillips

$

(180)

1,672

2,275

(4,168)

(180)

See Notes to Consolidated Financial Statements.

Millions of Dollars

At December 31, 2019

Balance Sheet

ConocoPhillips

ConocoPhillips

Company

Burlington

Resources LLC

All Other

Subsidiaries

Consolidating

Adjustments

Total

Consolidated

Assets

Cash and cash equivalents

$

-

3,439

-

1,649

-

5,088

Short-term investments

-

2,670

-

-

3,028

Accounts and notes receivable

2,088

3,881

(2,575)

3,401

Investment in Cenovus Energy

-

2,111

-

-

-

2,111

Inventories

-

-

-

1,026

Prepaid expenses and other current assets

-

1,906

-

2,259

Total Current Assets

10,828

8,652

(2,575)

16,913

Investments, loans and long-term receivables*

34,076

44,969

11,662

15,612

(97,413)

8,906

Net properties, plants and equipment

-

3,552

-

38,717

-

42,269

Other assets

2,210

(805)

2,426

Total Assets

$

34,085

60,114

11,917

65,191

(100,793)

70,514

Liabilities and Stockholders’ Equity

Accounts payable

$

-

2,670

3,084

(2,575)

3,200

Short-term debt

(3)

-

Accrued income and other taxes

-

-

-

1,030

Employee benefit obligations

-

-

-

Other accruals

1,518

-

2,045

Total Current Liabilities

3,669

5,799

(2,575)

7,043

Long-term debt

3,794

6,670

2,129

2,197

-

14,790

Asset retirement obligations and accrued environmental costs

-

-

5,030

-

5,352

Deferred income taxes

-

-

-

5,438

(804)

4,634

Employee benefit obligations

-

1,329

-

-

1,781

Other liabilities and deferred credits*

1,787

7,514

9,271

(17,534)

1,864

Total Liabilities

5,662

19,504

3,024

28,187

(20,913)

35,464

Retained earnings

33,184

21,898

2,164

10,481

(27,985)

39,742

Other common stockholders’ equity

(4,761)

18,712

6,729

26,454

(51,895)

(4,761)

Noncontrolling interests

-

-

-

-

Total Liabilities and Stockholders’

Equity

$

34,085

60,114

11,917

65,191

(100,793)

70,514

Balance Sheet

At December 31, 2018

Assets

Cash and cash equivalents

$

-

1,428

-

4,487

-

5,915

Short-term investments

-

-

-

-

Accounts and notes receivable

5,646

6,707

(8,392)

4,067

Investment in Cenovus Energy

-

1,462

-

-

-

1,462

Inventories

-

-

-

1,007

Prepaid expenses and other current assets

-

-

Total Current Assets

8,987

12,572

(8,392)

13,274

Investments, loans and long-term receivables*

29,942

47,062

15,199

16,926

(99,465)

9,664

Net properties, plants and equipment

-

4,367

-

41,796

(465)

45,698

Other assets

1,269

(798)

1,344

Total Assets

$

29,975

61,058

15,504

72,563

(109,120)

69,980

Liabilities and Stockholders’ Equity

Accounts payable

$

-

5,098

7,113

(8,392)

3,895

Short-term debt

(3)

(9)

Accrued income and other taxes

-

-

1,235

-

1,320

Employee benefit obligations

-

-

-

Other accruals

-

1,259

Total Current Liabilities

6,420

9,170

(8,401)

7,395

Long-term debt

3,791

7,151

2,143

2,249

(478)

14,856

Asset retirement obligations and accrued environmental costs

-

-

7,273

-

7,688

Deferred income taxes

-

-

-

5,819

(798)

5,021

Employee benefit obligations

-

1,340

-

-

1,764

Other liabilities and deferred credits*

9,277

8,126

(17,775)

1,192

Total Liabilities

4,598

24,603

3,106

33,061

(27,452)

37,916

Retained earnings

27,512

18,511

1,113

9,764

(22,890)

34,010

Other common stockholders’ equity

(2,135)

17,944

11,285

29,613

(58,778)

(2,071)

Noncontrolling interests

-

-

-

-

Total Liabilities and Stockholders’

Equity

$

29,975

61,058

15,504

72,563

(109,120)

69,980

*Includes intercompany loans.

See Notes to Consolidated Financial Statements.

Millions of Dollars

Year Ended December 31,

2019

Statement of Cash Flows

ConocoPhillips

ConocoPhillips

Company

Burlington

Resources LLC

All Other

Subsidiaries

Consolidating

Adjustments

Total

Consolidated

Cash Flows From Operating Activities

Net Cash Provided by Operating Activities

$

1,457

7,986

3,207

9,803

(11,349)

11,104

Cash Flows From Investing Activities

Capital expenditures and investments

-

(2,517)

-

(5,714)

1,595

(6,636)

Working capital changes associated

with investing activities

-

-

(140)

-

(103)

Proceeds from asset dispositions

2,374

7,047

1,055

(8,233)

3,012

Net purchases of investments

-

(2,803)

-

(107)

-

(2,910)

Long-term advances/loans—related parties

-

(812)

-

-

-

Collection of advances/loans—related parties

-

-

(161)

Intercompany cash management

1,060

(2,849)

1,402

-

-

Other

-

(149)

-

-

(108)

Net Cash Provided by (Used in) Investing Activities

3,434

(1,905)

2,171

(4,331)

(5,987)

(6,618)

Cash Flows From Financing Activities

Issuance of debt

-

-

-

(812)

-

Repayment of debt

-

(21)

-

(220)

(80)

Issuance of company common stock

-

-

-

(135)

(30)

Repurchase of company common stock

(3,500)

-

-

-

-

(3,500)

Dividends paid

(1,500)

(4,034)

(454)

(7,097)

11,585

(1,500)

Other

-

(4,924)

(1,736)

6,537

(119)

Net Cash Used in Financing Activities

(4,891)

(4,055)

(5,378)

(8,241)

17,336

(5,229)

Effect of Exchange Rate Changes on Cash, Cash Equivalents and

Restricted Cash

-

(11)

-

(35)

-

(46)

Net Change in Cash, Cash Equivalents and Restricted Cash

-

2,015

-

(2,804)

-

(789)

Cash, cash equivalents and restricted cash at beginning of period

-

1,428

-

4,723

-

6,151

Cash, Cash Equivalents and Restricted Cash at End of Period

$

-

3,443

-

1,919

-

5,362

Statement of Cash Flows

Year Ended December 31,

2018*

Cash Flows From Operating Activities

Net Cash

Provided by Operating Activities

$

4,019

14,132

(6,915)

12,934

Cash Flows From Investing Activities

Capital expenditures and investments

-

(980)

(603)

(5,777)

(6,750)

Working capital changes associated

with investing activities

-

(110)

-

-

(68)

Proceeds from asset dispositions

3,457

1,926

(5,672)

1,082

Net sales of short-term investments

-

-

-

1,620

-

1,620

Long-term advances/loans—related parties

-

(126)

(173)

(10)

-

Collection of advances/loans—related parties

3,432

(4,243)

Intercompany cash management

(803)

3,504

(2,150)

(551)

-

-

Other

-

-

-

Net Cash Provided by (Used in) Investing Activities

3,243

6,537

(788)

(3,839)

(8,996)

(3,843)

Cash Flows From Financing Activities

Issuance

of debt

-

-

(309)

-

Repayment of debt

-

(4,865)

(53)

(4,320)

4,243

(4,995)

Issuance of company common stock

-

-

-

(133)

Repurchase of company common stock

(2,999)

-

-

-

-

(2,999)

Dividends paid

(1,363)

(1,043)

-

(6,057)

7,100

(1,363)

Other

(3,468)

-

(1,670)

5,010

(123)

Net Cash Used in Financing Activities

(4,103)

(9,366)

(53)

(11,748)

15,911

(9,359)

Effect of Exchange Rate Changes on Cash, Cash Equivalents and

Restricted Cash

-

-

(121)

-

(117)

Net Change in Cash, Cash Equivalents and Restricted Cash

-

1,194

(3)

(1,576)

-

(385)

Cash, cash equivalents and restricted cash at beginning of period

-

6,299

-

6,536

Cash, Cash Equivalents and Restricted Cash at End of Period

$

-

1,428

-

4,723

-

6,151

*Revised to reclassify certain intercompany distributions from Operating Activities to 'Proceeds from asset dispositions' within Investing Activities based on the nature of the distributions.

There was no impact to Total Consolidated results.

Millions of Dollars

Year Ended December 31,

2017

Statement of Cash Flows

ConocoPhillips

ConocoPhillips

Company

Burlington

Resources LLC

All Other

Subsidiaries

Consolidating

Adjustments

Total

Consolidated

Cash Flows From Operating Activities

Net Cash Provided by Operating Activities

$

1,183

2,971

5,904

(3,052)

7,077

Cash Flows From Investing Activities

Capital expenditures and investments

-

(1,663)

(4,351)

(3,795)

5,218

(4,591)

Working capital changes associated

with investing activities

-

-

(62)

-

Proceeds from asset dispositions

7,765

11,146

12,178

12,796

(30,025)

13,860

Net purchases of short-term investments

-

-

-

(1,790)

-

(1,790)

Long-term advances/loans—related parties

-

(214)

(65)

(20)

-

Collection of advances/loans—related parties

1,527

2,196

(4,655)

Intercompany cash management

1,151

(1,341)

-

-

Other

-

(8)

-

-

Net Cash Provided by Investing Activities

9,574

11,083

6,810

9,458

(29,163)

7,762

Cash Flows From Financing Activities

Issuance of debt

-

-

(299)

-

Repayment of debt

(5,459)

(4,411)

-

(2,661)

4,655

(7,876)

Issuance of company common stock

-

-

-

(178)

(63)

Repurchase of company common stock

(3,000)

-

-

-

-

(3,000)

Dividends paid

(1,305)

(235)

-

(2,995)

3,230

(1,305)

Other

(7,765)

(9,781)

(7,377)

24,807

(112)

Net Cash Used in Financing Activities

(9,645)

(12,391)

(9,781)

(12,754)

32,215

(12,356)

Effect of Exchange Rate Changes on Cash and Cash Equivalents

-

(2)

-

Net Change in Cash and Cash Equivalents

-

(124)

(2)

2,841

-

2,715

Cash and cash equivalents at beginning of period

-

3,247

-

3,610

Cash and Cash Equivalents at End of Period

$

-

6,088

-

6,325

See Notes to Consolidated Financial Statements.