8-K - COP - Equibles

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.

20549

FORM

8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (date of earliest event reported):

November 16, 2020

ConocoPhillips

(Exact name of registrant as specified in its charter)

Delaware

001-32395

01-0562944

(State or other jurisdiction of

(Commission

(I.R.S. Employer

incorporation)

File Number)

Identification No.)

925 N. Eldridge Parkway

Houston

Texas

77079

(Address of principal executive offices and zip code)

Registrant’s telephone number,

including area code:

(

281

)

293-1000

Check the appropriate box below if the Form 8-K filing is intended

to simultaneously satisfy the filing obligation of

the registrant under any of the following

provisions:

☐

Written communications pursuant to Rule 425

under the Securities Act (17

CFR 230.425)

☐

Soliciting material pursuant to

Rule 14a-12 under the Exchange Act

(17 CFR 240.14a-12)

☐

Pre-commencement communications

pursuant to Rule 14d-2(b) under the

Exchange Act (17 CFR 240.14d-2(b))

☐

Pre-commencement communications

pursuant to Rule 13e-4(c) under the Exchange

Act (17 CFR 240.13e-4(c))

Securities registered pursuant to Section 12(b) of the

Act:

Title of each class

Trading symbols

Name of each exchange on which registered

Common Stock, $.01 Par Value

COP

New York Stock Exchange

7% Debentures due 2029

CUSIP – 718507BK1

New York Stock Exchange

Indicate by check

mark whether the

registrant is an

emerging growth company

as defined in

Rule 405 of

the Securities

Act of 1933

(§230.405 of this

chapter) or Rule

12b-2 of the

Securities Exchange Act of

1934 (§240.12b-2 of this

chapter).

Emerging growth company

☐

If an emerging growth company,

indicate by check

mark if the registrant

has elected not

to use the extended

transition

period for complying with any

new or revised financial accounting standards

provided pursuant to Section 13(a) of

the Exchange Act.

☐

Item 8.01 Other Events.

ConocoPhillips (the

“Company”) is

recasting certain financial

information included

in its 2019

Annual Report on Form 10-K

(the “Form 10-K”) which was initially filed with the Securities and

Exchange Commission (“SEC”) on February 18, 2020, to reflect a realignment of the Company’s

segments. The Company managed

operations through six operating

segments, which are primarily

defined by

geographic region,

and were

previously named

the following:

Alaska; Lower

48;

Canada; Europe and North Africa;

Asia Pacific and Middle East; and Other International.

Effective with

the third

quarter of

2020, the

Company has

restructured segments

to align

with

changes within its

internal organization.

The Middle East

business was realigned

from the

Asia

Pacific and

Middle East segment

to the

Europe and

North Africa segment.

The segments have

been renamed the Asia Pacific segment and the Europe, Middle East and North Africa segment.

Attached as Exhibit

99.1 of

this Current

Report on Form

8-K are the

following portions

of the

Form 10-K which

were revised to

reflect this realignment

in segments: Business

and Properties

(Items 1

and 2), Management’s

Discussion and Analysis

of Financial

Condition and

Results of

Operations (Item 7),

Financial Statements and

Supplementary Data (Item

8), and Exhibit,

Financial

Statement Schedules

(Item 15).

The change

in segments

did not

impact previously

reported

consolidated net

income (loss),

net income

(loss) attributable to

ConocoPhillips, or net

income

(loss) attributable to

ConocoPhillips per share

of common stock.

The segment-specific information

presented in

exhibit 99.1

is consistent

with the

presentation of

segments in

the Company’s

Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2020, filed with the

SEC on November 3, 2020.

This Current Report on Form 8-K is being filed only for the purposes described above and all

other information in the Form 10-K

remains unchanged. In order to preserve the nature and

character of the disclosures set forth in the Form 10-K, the items included in Exhibit 99.1 of this

Current Report on Form 8-K have been updated solely for matters relating specifically to the

segment realignment and related classifications as described above. No attempt has been made in

this Current Report on Form 8-K to reflect events or occurrences after the date of the filing of the

Form 10-K, on February 18, 2020, and it should not be read to modify or update other

disclosures as presented in the Form 10-K. Therefore, this Current Report on Form 8-K should

be read in conjunction with the Form 10-K and the Company’s filings made with the SEC

subsequent to the filing of the Form 10-K, including the Company’s Quarterly Reports on Form

10-Q

for the quarters ended March 31, 2020, June 30, 2020, and September 30, 2020.

These

subsequent SEC filings contain important information regarding events, risks, developments and

updates affecting the Company and its expectations that have occurred since the filing of the

Form 10-K.

The revised portions of the Form 10-K described above are attached as Exhibit 99.1

hereto and incorporated herein by reference.

References in the attached exhibits to the Form 10-

K or parts thereof refer to the Form 10-K for the year ended December 31, 2019, filed on

February 18, 2020, except to the extent portions of such Form 10-K have been revised in this

Current Report on Form 8-K, in which case, they refer to the applicable revised portion in this

Current Report on Form 8-K. The information contained herein is not an amendment to, or a

restatement of, the Form 10-K.

Item 9.01 Financial Statements and Exhibits.

(d)

Exhibits

Exhibit No.

Description

23.1*

Consent of Ernst & Young LLP.

23.2*

Consent of DeGolyer and MacNaughton.

99.1*

Items from ConocoPhillips Annual Report on Form 10-K for the year

ended December 31, 2019, revised to reflect recast segment information:

Business and Properties (Items 1 and 2), Management’s Discussion and

Analysis of Financial Condition and Results of Operations (Item 7),

Financial Statements and Supplementary Data (Item 8), and Exhibits,

Financial Statement Schedules (Item 15).

99.2*

Report of DeGolyer and MacNaughton.

101.INS**

Inline XBRL Instance Document.

101.SCH**

Inline

XBRL Schema Document.

101.CAL**

Inline XBRL Calculation Linkbase Document.

101.DEF**

Inline XBRL Definition Linkbase Document.

101.LAB**

Inline XBRL Labels Linkbase Document.

101.PRE**

Inline XBRL Presentation Linkbase Document.

104*

Cover Page

Interactive Data

File (formatted

as Inline

XBRL and

filed

herewith).

* Filed herewith

** These interactive data files are furnished and deemed not filed or part of a registration

statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as

amended, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of

1934, as amended, and otherwise are not subject to liability under those sections.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly

caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

CONOCOPHILLIPS

/s/

Catherine A. Brooks

(Chief Accounting and Duly Authorized Officer)

November 16, 2020

d123119dex231

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the following Registration Statements:

●

ConocoPhillips

Form S-3

File No. 333-240978

●

ConocoPhillips

Form S-4

File No. 333-130967

●

ConocoPhillips

Form S-8

File No. 333-98681

●

ConocoPhillips

Form S-8

File No. 333-116216

●

ConocoPhillips

Form S-8

File No. 333-133101

●

ConocoPhillips

Form S-8

File No. 333-159318

●

ConocoPhillips

Form S-8

File No. 333-171047

●

ConocoPhillips

Form S-8

File No. 333-174479

●

ConocoPhillips

Form S-8

File No. 333-196349

●

ConocoPhillips

Form S-8

File No. 333-130967

of our report dated February 18, 2020, except as it relates to the effects

of the change in segments

described in Note 25, as to which the date is November 16, 2020, with respect

to the consolidated

financial statements (including condensed consolidating

financial information and financial statement

schedule) of ConocoPhillips and our report dated February

18, 2020, with respect to the effectiveness of

internal control over financial reporting of ConocoPhillips, included in this

Current Report on Form 8-K.

/s/ Ernst & Young LLP

Houston, Texas

November 16, 2020

d123119dex232

Exhibit 23.2

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

November 16, 2020

ConocoPhillips

925 N. Eldridge Parkway

Houston, Texas 77079

Ladies and Gentlemen:

We hereby consent to the use of the name DeGolyer and MacNaughton, to references to

DeGolyer and

MacNaughton as an independent petroleum engineering

consulting firm in ConocoPhillips’

Current Report on

Form 8-K Exhibit 99.1, with respect to the sections

under “Item 8. Financial Statements and Supplementary

Data” and subheading “Reserves Governance” and

under “Item 15. Exhibits, Financial

Statement Schedules”

and to the inclusion of our process review letter

report dated February 18, 2020 (our Report),

as exhibit 99.2

to ConocoPhillips’ Current Report on Form 8-K. We also consent to the incorporation

by reference of our

Report in the Registration Statements filed

by ConocoPhillips on Form S-3 (File No. 333-240978),

Form S-4

(File No. 333-130967), and Form S-8 (File Nos. 333-98681,

333-116216, 333-133101, 333-159318, 333-

171047, 333-174479, 333-196349, and 333-130967).

Very

truly yours,

/s/ DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

d123119dex991

PART

Unless otherwise indicated, “the company,” “we,” “our,” “us” and “ConocoPhillips” are used in

this report to

refer to the businesses of ConocoPhillips and its consolidated

subsidiaries.

Items 1 and 2—Business and

Properties, contain forward-looking statements including,

without limitation, statements relating to our plans,

strategies, objectives, expectations and intentions

that are made pursuant to the “safe harbor”

provisions of the

Private Securities Litigation Reform Act of 1995.

The words “anticipate,” “estimate,” “believe,”

“budget,”

“continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,”

“will,” “would,”

“expect,” “objective,” “projection,” “forecast,” “goal,”

“guidance,” “outlook,” “effort,” “target” and similar

expressions identify forward-looking statements.

The company does not undertake to update,

revise or correct

any forward-looking information unless required to do so under

the federal securities laws.

Readers are

cautioned that such forward-looking statements should

be read in conjunction with the company’s disclosures

under the headings “Risk Factors” beginning on page

21 in our 2019 Annual Report on Form 10-K

and

“CAUTIONARY STATEMENT

FOR THE PURPOSES OF THE ‘SAFE HARBOR’

PROVISIONS OF THE

PRIVATE

SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on page 60.

Items 1 and 2.

BUSINESS AND PROPERTIES

CORPORATE STRUCTURE

ConocoPhillips is an independent E&P company with

operations and activities in 17 countries.

Our diverse,

low cost of supply portfolio includes resource-rich unconventional

plays in North America; conventional

assets in North America, Europe, Asia and Australia;

LNG developments; oil sands assets in Canada;

and an

inventory of global conventional and unconventional exploration

prospects.

Headquartered in Houston, Texas,

at December 31, 2019, we employed approximately

10,400 people worldwide and had total assets

of $71

billion.

ConocoPhillips was incorporated in the state of

Delaware on November 16, 2001, in connection with, and

anticipation of, the merger between Conoco Inc. and Phillips

Petroleum Company.

The merger between

Conoco and Phillips was consummated on August

30, 2002.

SEGMENT AND GEOGRAPHIC INFORMATION

manage our operations through six operating

segments, defined by geographic region: Alaska;

Lower 48;

Canada; Europe, Middle East and North Africa; Asia Pacific

and Other International.

Effective with the third

quarter of 2020, we have restructured our segments to align

with changes to our internal organization.

The

Middle East business was realigned from the Asia Pacific

and Middle East segment to the Europe and North

Africa segment.

The segments have been renamed the Asia

Pacific segment and the Europe, Middle East and

North Africa segment.

We have revised segment information disclosures and segment performance metrics

presented within our results of operations for the current

and prior years.

For operating segment and

geographic information, see Note 25—Segment Disclosures

and Related Information, in the Notes to

Consolidated Financial Statements, which is incorporated

herein by reference.

explore for, produce, transport and market crude oil, bitumen,

natural gas, LNG and NGLs on a worldwide

basis.

At December 31, 2019, our operations were producing

in the U.S., Norway, Canada, Australia, Timor-

Leste, Indonesia, Malaysia, Libya, China and Qatar.

The information listed below appears in the “Oil and

Gas Operations” disclosures following the

Notes to

Consolidated Financial Statements and is incorporated

herein by reference:

●

Proved worldwide crude oil, NGLs,

natural gas and bitumen reserves.

●

Net production of crude oil, NGLs,

natural gas and bitumen.

●

Average sales prices of crude oil, NGLs,

natural gas and bitumen.

●

Average production costs per BOE.

●

Net wells completed, wells in progress and productive

wells.

●

Developed and undeveloped acreage.

The following table is a summary of the proved

reserves information included in the “Oil and Gas Operations”

disclosures following the Notes to Consolidated

Financial Statements.

Approximately 80 percent of our

proved reserves are located in politically stable

countries that belong to the Organization for Economic

Cooperation and Development.

Natural gas reserves are converted to BOE based on a

6:1 ratio: six MCF of

natural gas converts to one BOE.

See Management’s Discussion and Analysis of Financial Condition and

Results of Operations for a discussion of factors that

will enhance the understanding of the following

summary

reserves table.

Millions of Barrels of Oil Equivalent

Net Proved Reserves at December 31

2019

2018

2017

Crude oil

Consolidated operations

2,562

2,533

2,322

Equity affiliates

Total Crude Oil

2,635

2,611

2,405

Natural gas liquids

Consolidated operations

361

349

354

Equity affiliates

Total Natural Gas Liquids

400

391

399

Natural gas

Consolidated operations

1,209

1,265

1,267

Equity affiliates

736

760

717

Total Natural Gas

1,945

2,025

1,984

Bitumen

Consolidated operations

282

236

250

Total Bitumen

282

236

250

Total consolidated operations

4,414

4,383

4,193

Total equity affiliates

848

880

845

Total company

5,262

5,263

5,038

Total production of 1,348 MBOED increased 5 percent in 2019 compared with 2018.

The increase in total

average production primarily resulted from new wells

online in the Lower 48;

an increased interest in the

Western North Slope (WNS) and Greater Kuparuk Area (GKA) of Alaska following acquisitions

closed in

2018; and higher production in Norway due to drilling

activity and the startup of Aasta Hansteen

in December

2018.

The increase in production was partly offset by normal

field decline and disposition impacts,

primarily

from the U.K. asset sale in 2019 and non-core asset sales

in the Lower 48 during 2018.

Production excluding Libya was 1,305 MBOED in

2019 compared with 1,242 MBOED in 2018,

an increase of

63 MBOED or 5 percent.

Underlying production, which excludes Libya and

the net volume impact from

closed dispositions and acquisitions of 51 MBOED in 2019

and 47 MBOED in 2018, is used to measure our

ability to grow production organically.

Our underlying production grew 5 percent to 1,254

MBOED in 2019

from 1,195 MBOED in 2018.

Our worldwide annual average realized price was

$48.78 per BOE in 2019, a decrease of 9 percent

compared

with $53.88 per BOE in 2018, reflecting weaker marker

prices as a result of macroeconomic demand

concerns.

Our worldwide annual average crude oil price decreased

10 percent, from $68.13 per barrel in 2018 to $60.99

per barrel in 2019.

Additionally, our worldwide annual average NGL prices decreased

34 percent, from

$30.48 per barrel in 2018 to $20.09 per barrel in

2019.

Our worldwide annual average natural gas

price

decreased 11 percent, from $5.65 per MCF in 2018 to $5.03 per

MCF in 2019.

Average annual bitumen prices

increased 42 percent, from $22.29 per barrel in 2018 to

$31.72 per barrel in 2019.

ALASKA

The Alaska segment primarily explores for, produces, transports and markets

crude oil, natural gas and NGLs.

are the largest crude oil producer in Alaska and have

major ownership interests in two of North America’s

largest oil fields located on Alaska’s North Slope: Prudhoe Bay and Kuparuk.

We also have a 100 percent

interest in the Alpine Field, located on the Western North Slope.

Additionally, we are one of Alaska’s largest

owners of state, federal and fee exploration leases, with

approximately 1.32 million net undeveloped acres at

year-end 2019.

Alaska operations contributed 25 percent of

our consolidated liquids production and less than

1 percent of our natural gas production.

2019

Interest

Operator

Liquids

MBD

Natural Gas

MMCFD

Total

MBOED

Average Daily Net Production

Greater Prudhoe Area

36.1

Greater Kuparuk Area

91.4-94.7

ConocoPhillips

Western North Slope

100.0

ConocoPhillips

Total Alaska

217

218

Greater Prudhoe Area

The Greater Prudhoe Area includes the Prudhoe

Bay Field and five satellite fields, as well

as the Greater Point

McIntyre Area fields.

Prudhoe Bay, the largest oil field on Alaska’s North Slope, is the site of a large

waterflood and enhanced oil recovery operation, as well

as a gas plant which processes natural gas to recover

NGLs before reinjection into the reservoir.

Prudhoe Bay’s satellites are Aurora, Borealis, Polaris, Midnight

Sun and Orion, while the Point McIntyre, Niakuk,

Raven, Lisburne and North Prudhoe Bay State fields

are

part of the Greater Point McIntyre Area.

Greater Kuparuk Area

operate the Greater Kuparuk Area, which

consists of the Kuparuk Field and four satellite

fields: Tarn,

Tabasco, Meltwater and West

Sak.

Kuparuk is located 40 miles west of Prudhoe Bay.

Field installations

include three central production facilities which separate

oil, natural gas and water, as well as a separate

seawater treatment plant.

Development drilling at Kuparuk

consists of rotary-drilled wells and horizontal

multi-laterals from existing well bores utilizing

coiled-tubing drilling.

Western North Slope

On the Western North Slope, we operate the Colville River Unit, which includes the

Alpine Field and three

satellite fields: Nanuq, Fiord and Qannik.

Alpine is located 34 miles west of Kuparuk.

In 2015, first oil was

achieved at Alpine West CD5,

a drill site which extends the Alpine reservoir west into

the National Petroleum

Reserve-Alaska (NPR-A).

In 2019, we continued drilling additional wells

using the

available well slots on this

pad.

The Greater Mooses Tooth Unit, the first unit established entirely within the NPR-A, was

formed in 2008.

2017, we began construction in the unit with two

drill sites; Greater Mooses Tooth #1 (GMT-1) and Greater

Mooses Tooth #2 (GMT-2).

GMT-1 achieved first oil in the fourth

quarter of 2018 and completed drilling

2019.

We expect first oil from GMT-2 in 2021.

Alaska North Slope Gas

In 2016, we, along with affiliates of Exxon Mobil Corporation,

BP p.l.c. and Alaska Gasline Development

Corporation (AGDC), a state-owned corporation, completed

preliminary FEED technical work for a potential

LNG project which would liquefy and export natural

gas from Alaska’s North Slope and deliver it to

market.

In 2016, we, along with the affiliates of ExxonMobil

and BP,

indicated our intention not to progress

into the next phase of the project due to changes in the

economic environment.

AGDC decided to continue on

its own.

In 2019, affiliates of ExxonMobil and BP agreed

to each contribute up to $5 million or approximately

one third of

AGDC’s anticipated costs for full-year 2020.

In 2020, AGDC will be focused on permitting

efforts, the most important of which is the National Environmental

Protection Act process before the FERC.

FERC’s final milestones are the Publication of Notice of Availability of Final Environmental Impact

Statement, which is scheduled for March 6, 2020, and the

Issuance of Final Order, which is scheduled for June

4, 2020.

AGDC has recently contracted with Fluor

Corporation to evaluate cost reduction opportunities

preparation for soliciting partners for the project.

continue to be willing to sell our North Slope gas to

the

project but do not plan to take an equity position.

Exploration

Appraisal of the Willow Discovery, located in the northeast portion of the NPR-A, continued throughout

2019

with five appraisal wells.

In 2020, we will continue appraisal of the Willow Discovery and

explore the

Harpoon Prospect, located southwest of Willow.

In 2019, we drilled the West Willow-2 well to appraise the 2018 West Willow oil discovery.

In late 2018, we commenced appraisal of the Putu Discovery

with a long reach well from existing Alpine CD4

infrastructure.

The CD4 appraisal well finished drilling and

flow tested in 2019.

A supporting injector well

was drilled in late 2019 for a 2020 injectivity test.

The Cairn 2S-315 Well was drilled in late 2018 from the 2S drill site on state leases in the

Kuparuk River Unit.

A long-term flow test was commenced in 2019 and

evaluations are ongoing.

A 3-D

seismic survey was completed in 2018 over a 250-mile

area on state lands.

We are currently evaluating

this seismic data for future exploration opportunities.

were successful in the federal lease sale on the

North Slope in the fourth quarter of 2019,

where we were

the high bidder on three tracts for a total of approximately

33,000 net acres.

Acquisitions

In the third quarter of 2019, we completed the Nuna

discovery acreage acquisition, expanding the

Kuparuk

River Unit by 21,000 acres and leveraging legacy

infrastructure.

Transportation

transport the petroleum liquids produced

on the North Slope to south central Alaska through an

800-mile

pipeline that is part of Trans-Alaska Pipeline System (TAPS).

have a 29.1 percent ownership interest

TAPS, and we also have ownership interests in the Alpine, Kuparuk and Oliktok pipelines

on the North Slope.

Our wholly owned subsidiary, Polar Tankers, Inc., manages the marine transportation of our North Slope

production, using five company-owned, double-hulled

tankers, and charters third-party vessels as necessary.

The tankers deliver oil from Valdez, Alaska, primarily to refineries on the west coast of the U.S.

LOWER 48

The Lower 48 segment consists of operations located

in the contiguous U.S.

and the Gulf of Mexico.

Organized into the Gulf Coast and Great Plains business units,

we hold 10.4

million net onshore and offshore

acres,

with a portfolio of conventional production

from legacy assets as well as newer production

from our low

cost of supply, shorter cycle time, resource-rich unconventional plays.

Based on 2019 production volumes,

the

Lower 48 is the company’s largest segment and contributed 41 percent of our consolidated liquids

production

and 35 percent of our natural gas production.

2019

Interest

Operator

Liquids

MBD

Natural Gas

MMCFD

Total

MBOED

Average Daily Net Production

Eagle Ford

Various

174

251

216

Gulf of Mexico

Various

Gulf Coast—Other

Various

Total Gulf Coast

192

271

237

Bakken

Various

Permian Unconventional

Various

Permian Conventional

Various

Anadarko Basin

Various

Wyoming/Uinta

Various

Niobrara*

Various

Total Great Plains

155

351

214

Total Lower 48

347

622

451

*Classified as held-for-sale

as of December 31, 2019.

See 'Dispositions' below for additional

information.

Onshore

hold 10.3 million net acres of onshore

conventional and unconventional acreage

in the Lower 48, the

majority of which is either held by production or owned

by the company.

Our unconventional holdings total

approximately 1.7 million net acres in the following

areas:

●

610,000 net acres in the Bakken, located in North

Dakota and eastern Montana.

●

234,000 net acres in Central Louisiana, where we recently

announced our intention to discontinue

exploration activities.

●

201,000 net acres in the Eagle Ford, located in South Texas.

●

167,000 net acres in the Permian, located in West Texas and southeastern New Mexico.

●

98,000 net acres in the Niobrara, located in northeastern

Colorado.

●

363,000 net acres in other areas with unconventional

potential.

The majority of our 2019

onshore production originated from

the Big 3—Eagle Ford, Bakken and Permian

Unconventional.

Onshore activities in 2019 were centered

mostly on continued development of assets, with an

emphasis on areas with low cost of supply, particularly in growing unconventional

plays.

Our major focus

areas in 2019

included the following:

●

Eagle Ford—The Eagle Ford continued full-field development

in 2019.

We operated seven rigs on

average in 2019, resulting in 155 operated wells

drilled and 166 operated wells brought online.

Production increased 16 percent in 2019 compared with

2018, averaging 216 MBOED and 186

MBOED, respectively.

●

Bakken—We operated an average of three rigs during the year in the Bakken and participated

additional development activities operated by co-venturers.

We continued our pad drilling with 62

operated wells drilled during the year and 44 operated

wells brought online.

Production increased 15

percent in 2019 compared with 2018, averaging 97 MBOED

and 84 MBOED, respectively.

●

Permian Basin—The Permian Basin is a combination

of legacy conventional and unconventional

assets.

We operated an average of three rigs during the year in the Permian Basin, resulting

in 29

operated wells drilled and 35 operated wells brought

online.

The Permian Basin produced 86

MBOED in 2019, increasing 30 percent compared with

2018, including 56 MBOED of

unconventional production.

Gulf of Mexico

At year-end 2019, our portfolio of producing properties

in the Gulf of Mexico totaled approximately 60,000

net acres.

A majority of the production consists of three

fields operated by co-venturers:

●

15.9 percent nonoperated working interest in the unitized

Ursa Field located in the Mississippi Canyon

Area.

●

15.9 percent nonoperated working interest in the Princess

Field, a northern subsalt extension of the

Ursa Field.

●

12.4 percent nonoperated working interest in the unitized

K2 Field, comprised of seven blocks in the

Green Canyon Area.

Dispositions

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 Qatar

Liquefied Gas Company Limited (3) (QG3).

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.

In the fourth quarter of 2019, we

completed the sale of our interests in the Magnolia Field in

the Gulf of

Mexico.

Production from this disposed asset was less than

one MBOED in 2019.

In the fourth quarter of 2019, we entered into an agreement

to sell our interests in the Niobrara, with an

anticipated closing date in the first quarter of 2020.

Production from the interests to be disposed was

approximately 11 MBOED in 2019.

In January 2020, we entered into an agreement

to sell our interests in certain non-core properties

for $186

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.

This disposition will not have a significant

impact on Lower 48 production.

For additional information on these transactions,

see Note 5—Asset Acquisitions and Dispositions,

in the

Notes to Consolidated Financial Statements.

Exploration

Our exploration focus is on onshore unconventional plays,

which in 2019 included the Delaware in the

Permian Basin, and the Eagle Ford in south Texas.

In the third quarter of 2019, we announced

our decision to

discontinue exploration activities in the Central Louisiana

Austin Chalk.

Facilities

●

Lost Cabin Gas Plant—We operate and own a 46 percent interest in the Lost Cabin

Gas Plant, a 246

MMCFD capacity natural gas processing facility in

Lysite, Wyoming.

The plant is currently operating at

less than capacity due to a fire in December 2018.

Restoration efforts are ongoing and anticipated to be

completed in the second half of 2020.

The expected production loss in 2020 is immaterial

to the segment.

●

Helena Condensate Processing Facility—We operate and own the Helena Condensate

Processing Facility,

a 110 MBD condensate processing plant located in Kenedy, Texas.

●

Sugarloaf Condensate Processing Facility—We operate and own an 87.5 percent interest in the

Sugarloaf

Condensate Processing Facility, a 30 MBD condensate processing plant located

near Pawnee, Texas.

●

Bordovsky Condensate Processing Facility—We operate and own the Bordovsky Condensate

Processing

Facility, a 15 MBD condensate processing plant located in Kenedy, Texas.

CANADA

Our Canadian operations mainly consist of the Surmont

oil sands development in Alberta and the liquids-rich

Montney unconventional play in British Columbia.

In 2019, operations in Canada contributed

7 percent of our

consolidated liquids production and less than 1 percent

of our natural gas production.

2019

Liquids

Natural Gas

Bitumen

Total

Interest

Operator

MBD

MMCFD

MBD

MBOED

Average Daily Net Production

Surmont

50.0

ConocoPhillips

Montney

100.0

ConocoPhillips

Total Canada

Surmont

Our bitumen resources in Canada are produced via an

enhanced thermal oil recovery method called SAGD,

whereby steam is injected into the reservoir, effectively liquefying the heavy bitumen,

which is recovered and

pumped to the surface for further processing.

hold approximately 0.6 million net acres

of land in the

Athabasca Region of northeastern Alberta.

The Surmont oil sands leases are located approximately

35 miles south of Fort McMurray, Alberta.

Surmont

is a 50/50 joint venture with Total S.A.

The second phase of the Surmont Project achieved first

production in

2015 and reached peak production in 2018.

We are focused on structurally lowering costs, reducing GHG

intensity and optimizing asset performance.

The Alberta government imposed a production curtailment

impacting the industry beginning in January 2019.

The curtailment measure, which impacted our annualized

average production by 3 MBOED in 2019, is

intended to strengthen the WCS differential to WTI at Hardisty.

The curtailment program is established and

administered by the Alberta Energy Regulator under the

Curtailment Rules

regulation, which is currently set to

expire on December 31, 2020.

Montney

hold approximately 151,000 net acres

in the emerging unconventional Montney play in northeast

British

Columbia.

Our Montney activity in 2019 included drilling

16 horizontal wells, completing 14 horizontal wells

and acquiring approximately 6,000 additional net

acres.

Production from our 2019 drilling program

commenced in February 2020 following the completion

of third-party offtake facilities.

Appraisal drilling and completions activity will

continue in 2020 to further explore the area’s resource

potential.

Exploration

Our primary exploration focus is assessing our

Montney onshore unconventional acreage in Western Canada.

Additionally, we have exploration acreage in the Mackenzie Delta/Beaufort Sea Region

and the Arctic Islands.

EUROPE, MIDDLE EAST AND NORTH AFRICA

The Europe,

Middle East and North Africa segment consisted

of operations in Norway, Qatar, Libya and the

U.K. and exploration activities in Norway and Libya.

In 2019, operations in Europe, Middle East

and North

Africa contributed 17 percent of our consolidated liquids

production and 27 percent of natural gas production.

Norway

2019

Liquids

Natural Gas

Total

Interest

Operator

MBD

MMCFD

MBOED

Average Daily Net Production

Greater Ekofisk Area

35.1

ConocoPhillips

Heidrun

24.0

Equinor

Alvheim

20.0

Aker BP

Visund

9.1

Equinor

Aasta Hansteen

10.0

Equinor

Troll

1.6

Equinor

Other

Various

Equinor

Total Norway

254

131

The Greater Ekofisk Area is located approximately 200

miles offshore Stavanger, Norway,

in the North Sea,

and comprises three producing fields: Ekofisk, Eldfisk and

Embla.

Crude oil is exported to Teesside, England,

and the natural gas is exported to Emden, Germany.

The Ekofisk and Eldfisk fields consist of

several

production platforms and facilities, including the

Ekofisk South and Eldfisk II

developments.

Continued

development drilling in the Greater Ekofisk Area is

expected to contribute additional production over the

coming years, as additional wells come online.

The Heidrun Field is located in the Norwegian Sea.

Produced crude oil is stored in a floating storage

unit and

exported via shuttle tankers.

Part of the natural gas is currently injected

into the reservoir for optimization

crude oil production,

some gas is transported for use as

feedstock in a methanol plant in Norway, in which we

own an 18 percent interest,

and the remainder is transported to Europe

via gas processing terminals in Norway.

The Alvheim Field is located in the northern part

of the North Sea near the border with the U.K. sector, and

consists of a FPSO vessel and subsea installations.

Produced crude oil is exported via shuttle tankers,

and

natural gas is transported to the Scottish Area Gas Evacuation

(SAGE) Terminal at St. Fergus, Scotland,

through the SAGE Pipeline.

Visund is an oil and gas field located in the North Sea and consists of a floating

drilling, production and

processing unit, and subsea installations.

Crude

oil is transported by pipeline to a nearby third-party

field for

storage and export via tankers.

The natural gas is transported to a gas processing plant

at Kollsnes, Norway,

through the Gassled transportation system.

Aasta Hansteen is located in the Norwegian Sea and

achieved first production in December 2018.

Produced

condensate is loaded onto shuttle tankers and transported

to market.

Gas is transported through the Polarled

gas pipeline to the onshore Nyhamna processing plant

for final processing prior to export to market.

The Troll Field lies in the northern part of the North Sea and consists of the

Troll A, B and C platforms.

The

natural gas from Troll A is transported to Kollsnes, Norway.

Crude oil from floating platforms Troll B and

Troll C is transported to Mongstad, Norway, for storage and export.

also have varying ownership interests in two

other producing fields in the Norway sector of the

North Sea.

Exploration

In 2019, we operated the Busta and Enniberg exploration wells

in Block 25/7 in the North Sea.

The Busta well

encountered hydrocarbons and will be evaluated for

future appraisal consideration.

The Enniberg well

encountered insufficient hydrocarbons and was expensed as

a dry hole in 2019.

We also participated in the

Canela exploration well in the Heidrun area of the Norwegian

Sea.

The well encountered hydrocarbons and

will be further evaluated to determine commerciality.

In 2019, we were awarded two new exploration

licenses; PL1001 and PL1009; and one acreage

addition, PL782SD.

Transportation

own a 35.1 percent interest in the Norpipe

Oil Pipeline System, a 220-mile pipeline which

carries crude oil

from Ekofisk to a crude oil stabilization and NGLs processing

facility in Teesside, England.

United Kingdom

2019

Natural

Liquids

Gas

Total

Interest

Operator

MBD

MMCFD

MBOED

Average Daily Net Production

Britannia Satellites*

26.3–93.8

ConocoPhillips

J-Area

32.5–36.5

ConocoPhillips

Britannia

58.7

ConocoPhillips

East Irish Sea

100.0

Spirit Energy

Clair

7.5

Other

Various

Total United Kingdom

193

*Includes the Chevron

-operated Alder Field, ConocoPhillips equity

interest was 26.3

percent.

On September 30, 2019, we completed the sale of

two ConocoPhillips U.K. subsidiaries to Chrysaor

E&P

Limited, including all of our producing assets in the

U.K.

Annualized average production from the assets sold

was 50 MBOED in 2019.

For additional information on this transaction, see

Note 5—Asset Acquisitions and

Dispositions, in the Notes to Consolidated Financial

Statements.

retained our Teesside, England oil terminal, where we are the operator and

have a 40.25 percent ownership

interest, to support

our Norway operations.

Qatar

2019

Natural

Liquids

Gas

Total

Interest

Operator

MBD

MMCFD

MBOED

Average Daily Net Production

Qatargas Operating

QG3

30.0

Company Limited

373

Total Qatar

373

QG3 is an integrated development jointly owned by

Qatar Petroleum (68.5 percent), ConocoPhillips

(30 percent) and Mitsui & Co., Ltd. (1.5 percent).

QG3 consists of upstream natural gas production

facilities,

which produce approximately 1.4 billion gross cubic feet

per day of natural gas from Qatar’s North Field over

a 25-year life, in addition to a 7.8 million gross tonnes-per-year

LNG facility.

LNG is shipped in leased LNG

carriers destined for sale globally.

QG3 executed the development of the onshore and offshore assets

as a single integrated development with

Qatargas 4 (QG4), a joint venture between Qatar Petroleum

and Royal Dutch Shell plc.

This included the joint

development of offshore facilities situated in a common offshore block in

the North Field, as well as the

construction of two identical LNG process trains and

associated gas treating facilities for both the QG3

and

QG4 joint ventures.

Production from the LNG trains and associated

facilities is combined and shared.

Libya

2019

Natural

Liquids

Gas

Total

Interest

Operator

MBD

MMCFD

MBOED

Average Daily Net Production

Waha Concession

16.3

Waha Oil Co.

Total Libya

The Waha Concession consists of multiple concessions and encompasses nearly 13 million

gross acres in the

Sirte Basin.

Our production operations in Libya

and related oil exports have periodically been interrupted

over

the last several years due to the shutdown of the

Es Sider crude oil export terminal.

In 2019, we had 19 crude

liftings from Es Sider.

The number of crude liftings from the Es Sider

crude oil export terminal in 2020 is

uncertain due to civil unrest.

In January 2020, we declared Force Majeure

to our crude shippers following the

blockade of the Es Sider crude oil export terminal

and the declaration of Force Majeure by the National

Oil

Corporation of Libya.

ASIA PACIFIC

The Asia Pacific segment has exploration and production

operations in China, Indonesia, Malaysia and

Australia and producing operations in Timor-Leste.

In 2019, operations in the Asia Pacific segment

contributed 10 percent of our consolidated liquids production

and 36 percent of natural gas production.

Australia and Timor-Leste

2019

Natural

Liquids

Gas

Total

Interest

Operator

MBD

MMCFD

MBOED

Average Daily Net Production

ConocoPhillips/

Australia Pacific LNG

37.5

Origin Energy

679

113

Bayu-Undan*

56.9

ConocoPhillips

194

Athena/Perseus*

50.0

ExxonMobil

Total Australia and Timor-Leste

904

161

*This asset is held-for-sale as of December

31, 2019.

See Note 5—Asset Acquisitions

and Dispositions, in the Notes to Consolidated

Financial

Statements, for additional

information.

Australia Pacific LNG

Australia Pacific LNG Pty Ltd (APLNG), our joint venture

with Origin Energy Limited and China

Petrochemical Corporation (Sinopec), is focused

on producing CBM from the Bowen and Surat basins

Queensland, Australia, to supply the domestic gas market

and convert the CBM into LNG for export.

Origin

operates APLNG’s upstream production and pipeline system, and we operate the

downstream LNG facility,

located on Curtis Island near Gladstone, Queensland,

as well as the LNG export sales business.

operate two fully subscribed 4.5-million-metric-tonnes-per-year

LNG trains.

Approximately 3,900 net

wells are ultimately expected to supply both the LNG

sales contracts and domestic gas market.

The wells are

supported by gathering systems, central gas processing

and compression stations, water treatment

facilities,

and an export pipeline connecting the gas fields

to the LNG facilities.

The LNG is being sold to Sinopec under

20-year sales agreements for 7.6 million metric tonnes

of LNG per year, and Japan-based Kansai Electric

Power Co., Inc. under a 20-year sales agreement for approximately

1 million metric tonnes of LNG per year.

As of December 31, 2019, APLNG has an outstanding

balance of $6.7 billion on a $8.5 billion

project finance

facility.

In late 2018 and early 2019, APLNG successfully

refinanced $4.6 billion of the project finance

facility through three separate transactions, which

added lower cost United States Private Placement (USPP)

bond and commercial bank facilities.

In conjunction with these transactions, APLNG

made voluntary

repayments of $2.2 billion to a syndicate of Australian

and international commercial banks and fully

extinguished $2.4 billion

of financing from the Export-Import Bank of

China.

Project finance interest

payments are bi-annual, concluding September 2030.

For additional information, see Note 3—Variable Interest Entities, Note 6—Investments, Loans and Long-

Term Receivables and Note 12—Guarantees, in the Notes to Consolidated Financial

Statements.

Bayu-Undan

The Bayu-Undan gas condensate field is located

in the Timor Sea Joint Petroleum Development Area between

Timor-Leste and Australia.

We also operate and own a 56.9 percent interest in the associated Darwin LNG

Facility, located at Wickham Point, Darwin.

The Bayu-Undan natural gas recycle facility processes wet

gas; separates, stores and offloads condensate,

propane and butane; and re-injects dry gas back into

the reservoir.

In addition, a 310-mile natural gas pipeline

connects the facility to the 3.5-million-metric-tonnes-per-year

capacity Darwin LNG Facility.

Produced

natural gas is piped to the

Darwin LNG Plant, where it is converted

into LNG before being transported to

international markets.

In 2019, we sold 133 billion gross cubic feet

of LNG primarily to utility customers in

Japan.

Athena/Perseus

The Athena production license (WA-17-L) in which we had a 50 percent working interest is located offshore

Western Australia and our entitlement to production ended in the fourth quarter of 2019.

Annualized average

production from this license was five MBOED in 2019.

Exploration

operate three exploration permits in the

Browse Basin, offshore northwest Australia, in

which we own a 40

percent interest in permits WA-315-P,

WA-398-P and TP 28, of the Greater

Poseidon Area.

Phase I of the

Browse Basin drilling campaign resulted in three discoveries

in the Greater Poseidon Area and Phase II

resulted in five additional discoveries.

All wells have been plugged and abandoned.

operate two retention leases in the Bonaparte

Basin, offshore northern Australia, where we

own a 37.5

percent interest in the Barossa and Caldita discoveries.

In April 2018, Barossa entered the FEED

phase of

development which continued through 2019.

During the FEED phase, costs and the technical

definition for the

project will be finalized, gas and condensate sales

agreements progressed, and access arrangements negotiated

with the owners of the Darwin LNG Facility

and Bayu-Darwin Pipeline.

In December 2019, we entered into an agreement

with 3D Oil to acquire a 75 percent interest

and operatorship

of an offshore Tasmanian Permit located in the Otway Basin.

The farm-in agreement is conditional upon the

agreement and signing of a JOA by both parties and required

government approvals.

We plan to conduct a 3D

seismic survey in the second half of 2020.

This activity is excluded from the dispositions

discussed below.

Dispositions

In the second quarter of 2019, we completed the sale

of our 30 percent interest in the Greater Sunrise

Fields to

the government of Timor-Leste.

In October 2019, we entered into an agreement

to sell the subsidiaries that hold our Australia-West assets and

operations to Santos with an expected completion date

in the first quarter of 2020, subject to regulatory

approvals and other specific conditions precedent.

These subsidiaries hold our 37.5 percent

interest in the

Barossa Project and Caldita Field, our 56.9 percent interest

in the Darwin LNG Facility and Bayu-Undan

Field, our 40 percent interest in the Greater Poseidon

Fields, and our 50 percent interest in the

Athena Field.

Production associated with the Australia-West assets to be sold was 48 MBOED in 2019.

For additional information on these transactions,

see

Note 5—Asset Acquisitions and Dispositions,

in the

Notes to Consolidated Financial Statements.

Indonesia

2019

Natural

Liquids

Gas

Total

Interest

Operator

MBD

MMCFD

MBOED

Average Daily Net Production

South Sumatra

ConocoPhillips

321

Total Indonesia

321

During 2019, we

operated three PSCs in Indonesia:

the Corridor Block and South Jambi

“B,”

both located in

South Sumatra, and Kualakurun in Central Kalimantan.

Currently, we have production from the Corridor

Block.

South Sumatra

The Corridor PSC consists

of two oil fields and seven producing natural gas fields.

Natural gas is supplied

from the Grissik and Suban gas processing plants to the

Duri steamflood in central Sumatra and to

markets in

Singapore, Batam and West Java.

In 2019, we were awarded a 20-year

extension, with new terms, of the

Corridor PSC.

Under these terms, we retain a majority

interest and continue as operator for at least three

years

after 2023 and retain a participating interest until

2043.

Production from the South Jambi “B” PSC has reached depletion

and field development has been suspended.

This PSC expired on January 26, 2020 and has been

returned to the Government of Indonesia.

Exploration

hold a 60 percent working interest in

the Kualakurun PSC.

After completion of prospect evaluation, we

and the other joint venture partners decided to relinquish

all of the remaining acreage to the Government of

Indonesia.

Transportation

are a 35 percent owner of a consortium company that

has a 40 percent ownership in PT Transportasi Gas

Indonesia, which owns and operates the Grissik

to Duri and Grissik to Singapore natural gas pipelines.

China

2019

Natural

Liquids

Gas

Total

Interest

Operator

MBD

MMCFD

MBOED

Average Daily Net Production

Penglai

49.0

CNOOC

Panyu

24.5

CNOOC

Total China

Penglai

The Pengl

ai 19-

3, 19-9

and 25

-6

fields are

located in

Bohai Bay

Block 11/05

and are

in various

stages of

development.

As part

of further

development of

the Penglai

19-9 Field,

the wellhead

platform J

Project achieved

first

production in 2016.

This project will

include 62 wells,

57 of which have

been completed and brought

online

through December 2019.

The Penglai

19-3/19-9 Phase

3 Project

consists of

three new

wellhead platforms

and a

central processing

platform.

First oil from Phase 3 was achieved in

2018 for two of the platforms, with the third platform

planned

to come online

in the second

quarter of 2020.

This project could

include up to

186 wells, 42

of which have

been completed and brought online through December 2019.

In December 2018, we sanctioned the Penglai 25-6 Phase

4A Project.

This project consists of one new

wellhead platform and anticipates 62 new wells.

First production is expected in 2021.

Panyu

Our production license for Panyu

4-2, 5-1 and 11-6 located in Block 15/34 in the South China Sea

expired in

September 2019.

Annualized average production from these licenses

were six MBOED in 2019.

still have a license for Panyu 4-1 in Block

15/34 and are evaluating this area for potential

development.

Exploration

Exploration activities in the Bohai Penglai Field during

2019 consisted of two successful appraisal wells,

full-field 3-D seismic program covering existing and

future development opportunities, and an

infill

compressive seismic imaging (CSI) survey to improve

imaging beneath the gas cloud in support of future

development projects.

In Block 15/34, one exploration well

was drilled in the Panyu 4-1E prospect and was

expensed as a dry hole.

Malaysia

2019

Natural

Liquids

Gas

Total

Interest

Operator

MBD

MMCFD

MBOED

Average Daily Net Production

Gumusut

29.0

Shell

Kebabangan (KBB)

30.0

KPOC

Malikai

35.0

Shell

Siakap North-Petai

21.0

PTTEP

Total Malaysia

have varying stages of exploration, development

and production activities across 2.2 million net acres

Malaysia, with working interests in six PSCs.

Three of these PSCs

are located off the eastern Malaysian state

of Sabah: Block G, Block J and the Kebabangan Cluster

(KBBC).

We operated three exploration blocks,

Block SK304, Block SK313 and Block WL4-00,

off the eastern Malaysian state of Sarawak.

Block J

Gumusut

First production from the Gumusut Field occurred from

an early production system in 2012.

Production from

a permanent, semi-submersible Floating Production System

was achieved in 2014.

We currently have a 29

percent working interest in the Gumusut Field

following the redetermination of the Block J and Block K

Malaysia Unit in 2017.

Gumusut Phase 2 first oil was achieved in 2019.

KBBC

The KBBC PSC grants us a 30 percent working interest

in the KBB, Kamunsu East and Kamunsu East

Upthrown Canyon gas and condensate fields.

KBB

First production from the KBB gas field was achieved in

2014.

During 2019, KBB tied-in to a nearby third-

party floating LNG vessel which provided increased

gas offtake capacity.

Production in 2020 is anticipated to

be impacted between 15 to 20 MBOED due to

the rupture of a third-party pipeline, in January

2020, which

carries gas production from the KBB gas field to market.

The extent of the required pipeline repairs, and the

amount of time required to return this pipeline to

full service is still being evaluated.

Kamunsu East

Development options for the Kamunsu East gas field are

being evaluated.

Block G

Malikai

hold a 35 percent working interest

in Malikai.

This field achieved first production in December

2016 via

the Malikai Tension Leg Platform, ramping to peak production in 2018.

The KMU-1 exploration well was

completed and started producing through the Malikai

platform in 2018.

Malikai Phase 2 development,

a 6-

well drilling campaign that will commence in 2020, reached

a final investment decision in late 2019.

Siakap North-Petai

hold a 21 percent working interest

in the unitized Siakap North-Petai oil field.

Exploration

In 2016, we entered into a farm-in agreement to acquire

a 50 percent working interest in Block SK 313,

a 1.4

million gross-acre exploration block offshore Sarawak, with

an effective date of January 2017.

Following

completion of the Sadok-1 exploration well in

January 2017, we assumed operatorship of

the block from

PETRONAS and completed a 3-D

seismic survey.

have no plans for further exploration

activity in this

block.

In 2017, we were awarded operatorship and a 50 percent

working interest in Block WL4-00, which included

the existing Salam-1 oil discovery and encompassed 0.6 million

gross acres.

In 2018 and 2019, two

exploration and two appraisal wells were drilled, resulting

in oil discoveries under evaluation at Salam and

Benum, while two Patawali wells were expensed

as dry holes in 2019.

In 2018, we were awarded a 50 percent working interest

and operatorship of Block SK304 encompassing

2.1

million gross acres offshore Sarawak.

We acquired 3-D seismic over the acreage and completed processing of

this data in 2019.

The Gemilang-1 exploration well in Block J was completed

in late 2018.

Development options are being

evaluated.

OTHER INTERNATIONAL

The Other International segment includes exploration

activities in Colombia, Chile and Argentina and

contingencies associated with prior operations.

Colombia

have an 80 percent operated interest in the

Middle Magdalena Basin Block VMM-3.

The block extends

over approximately 67,000 net acres and contains

the Picoplata-1

Well,

which completed drilling in 2015 and

testing in 2017.

Plug and abandonment activity started

during 2018 and completed in 2019.

In addition, we

have an 80 percent working interest in the VMM-2 Block

which extends over approximately 58,000 net acres

and is contiguous to the VMM-3 Block.

As part of a case brought forward by environmental groups,

the

Highest Administrative Court granted a preliminary

injunction temporarily suspending hydraulic

fracturing

activities until the substance of the case is decided.

As a result, ConocoPhillips filed two separate Force

Majeure requests before the competent authority for both blocks,

which were granted.

Chile

have a 49 percent interest in the Coiron

Block located in the Magallanes Basin in southern

Chile.

Argentina

In January 2019, we secured a 50 percent nonoperated

interest in the El Turbio Este Block, within the Austral

Basin in southern Argentina.

In 2019, we acquired and processed 3-D seismic

covering approximately 500

square miles, with evaluation of the data ongoing.

In November 2019, we acquired interests in two nonoperated

blocks in the Neuquén Basin targeting the Vaca

Muerta play.

We have a 50 percent interest in the Bandurria Norte Block and a 45 percent interest

in the

Aguada Federal Block.

In Bandurria Norte, one vertical and four horizontal wells

were tested and shut-in

during 2019.

In Aguada Federal, two horizontal wells were being

tested at the end of the year.

Venezuela and Ecuador

For discussion of our contingencies in Venezuela and Ecuador, see Note 13—Contingencies and

Commitments, in the Notes to Consolidated Financial

Statements.

OTHER

Marketing Activities

Our Commercial organization manages our worldwide commodity

portfolio, which mainly includes natural

gas, crude oil, bitumen, NGLs and LNG.

Marketing activities are performed through

offices in the U.S.,

Canada, Europe and Asia.

In marketing our production, we attempt to minimize

flow disruptions, maximize

realized prices and manage credit-risk exposure.

Commodity sales are generally made at

prevailing market

prices at the time of sale.

also purchase and sell third-party volumes to better position

the company to

satisfy customer demand while fully utilizing

transportation and storage capacity.

Natural Gas

Our natural gas production, along with third-party purchased

gas, is primarily marketed in the U.S., Canada,

Europe and Asia.

Our natural gas is sold to a diverse client

portfolio which includes local distribution

companies; gas and power utilities; large industrials;

independent, integrated or state-owned oil and gas

companies; as well as marketing companies.

To reduce our market exposure and credit risk, we also transport

natural gas via firm and interruptible transportation

agreements to major market hubs.

Crude Oil, Bitumen and Natural Gas Liquids

Our crude oil, bitumen and NGL revenues are derived

from production in the U.S., Canada, Australia,

Asia,

Africa and Europe.

These commodities are primarily sold

under contracts with prices based on market indices,

adjusted for location, quality and transportation.

LNG

LNG marketing efforts are focused on equity LNG production

facilities located in Australia and Qatar.

LNG

is primarily sold under long-term contracts with prices based

on market indices.

Energy Partnerships

Marine Well Containment Company (MWCC)

are a founding member of the MWCC, a non-profit

organization formed in 2010, which provides well

containment equipment and technology in the

deepwater U.S. Gulf of Mexico.

MWCC’s containment system

meets the U.S. Bureau of Safety and Environmental

Enforcement requirements for a subsea well

containment

system that can respond to a deepwater well control

incident in the U.S. Gulf of Mexico.

For additional

information, see Note 3—Variable Interest Entities, in the Notes to Consolidated Financial Statements.

Subsea Well Response Project (SWRP)

In 2011, we, along with several leading oil and gas companies,

launched the SWRP, a non-profit organization

based in Stavanger, Norway, which was created to enhance the industry’s capability to respond to international

subsea well control incidents.

Through collaboration with Oil Spill

Response Limited, a non-profit

organization in the U.K., subsea well intervention equipment

is available for the industry to use in the

event of

a subsea well incident.

This complements the work being

undertaken in the U.S.

by MWCC and provides well

capping and containment capability outside the U.S.

Oil Spill Response Removal Organizations (OSROs)

maintain memberships in several

OSROs across the globe as a key element of our preparedness

program in

addition to internal response resources.

Many of the OSROs are not-for-profit cooperatives owned

by the

member companies wherein we may actively participate

as a member of the board of directors, steering

committee, work group or other supporting role.

Globally, our primary OSRO is Oil Spill Response Ltd.

based in the U.K., with facilities in several other countries

and the ability to respond anywhere in the world.

North America, our primary OSROs include the Marine

Spill Response Corporation for the continental United

States and Alaska Clean Seas and Ship Escort/Response

Vessel

System for the Alaska North Slope and Prince

William Sound, respectively.

Internationally, we maintain memberships in various regional OSROs including

the Norwegian Clean Seas Association for Operating Companies,

Australian Marine Oil Spill Center and

Petroleum Industry of Malaysia Mutual Aid Group.

Technology

have several technology programs that improve

our ability to develop unconventional

reservoirs, produce

heavy oil economically with less emissions, improve

the efficiency of our exploration program, increase

recoveries from our legacy fields, and implement sustainability

measures.

Our Optimized Cascade

LNG liquefaction technology business

continues to be successful with the demand

for new LNG plants.

The technology has been licensed for use in 26

LNG trains around the world, with

feasibility studies ongoing for additional trains.

RESERVES

have not filed any information with

any other federal authority or agency with respect

to our estimated

total proved reserves at December 31, 2019.

No difference exists between our estimated total proved

reserves

for year-end 2018 and year-end 2017, which are shown

in this filing, and estimates of these reserves

shown in

a filing with another federal agency in 2019.

DELIVERY COMMITMENTS

sell crude oil and natural gas from our

producing operations under a variety of

contractual arrangements,

some of which specify the delivery of a fixed and determinable

quantity.

Our commercial organization also

enters into natural gas sales contracts where the source

of the natural gas used to fulfill

the contract can be the

spot market or a combination of our reserves and the spot

market.

Worldwide, we are contractually committed

to deliver approximately 1.1 trillion cubic feet of natural

gas, including approximately 75 billion cubic feet

related to the noncontrolling interests of consolidated

subsidiaries, and 172 million barrels of crude oil

in the

future.

These contracts have various expiration dates

through the year 2030.

We expect to fulfill the majority

of these delivery commitments with proved developed

reserves.

In addition, we anticipate using PUDs and

spot market purchases to fulfill any remaining commitments.

See the disclosure on “Proved Undeveloped

Reserves” in the “Oil and Gas Operations” section

following the Notes to Consolidated Financial

Statements,

for information on the development of PUDs.

COMPETITION

compete with private, public and state-owned

companies in all facets of the E&P business.

Some of our

competitors are larger and have greater resources.

Each of our segments is highly competitive, with no single

competitor, or small group of competitors, dominating.

compete with numerous other companies in the

industry, including state-owned companies, to locate and

obtain new sources of supply and to produce oil, bitumen,

NGLs and natural gas in an efficient, cost-effective

manner.

Based on statistics published in the September

2, 2019, issue of the

Oil and Gas Journal

, we were the

third-largest U.S.-based oil and gas company in worldwide

natural gas and liquids production and worldwide

liquids reserves in 2018.

We deliver our production into the worldwide commodity markets.

Principal

methods of competing include geological, geophysical

and engineering research and technology; experience

and expertise; economic analysis in connection with

portfolio management; and safely operating

oil and gas

producing properties.

GENERAL

At the end of 2019, we held a total of 942 active patents

in 50 countries worldwide, including 371

active U.S.

patents.

During 2019, we received 64 patents in the U.S.

and 90 foreign patents.

Our products and processes

generated licensing revenues of $69 million related

to activity in 2019.

The overall profitability of any

business segment is not dependent on any single patent,

trademark, license, franchise or concession.

Health, Safety and Environment

Our HSE organization provides tools and support to our

business units and staff groups to help them ensure

world class HSE performance.

The framework through which we safely manage our

operations, the HSE

Management System Standard, emphasizes process

safety, risk management, emergency preparedness and

environmental performance, with an intense focus on process

and occupational safety.

In support of the goal

of zero incidents, HSE milestones and criteria are established

annually to drive strong safety and

environmental performance.

Progress toward these milestones and criteria

are measured and reported.

HSE

audits are conducted on business functions periodically, and improvement actions

are established and tracked

to completion.

We have designed processes relating to sustainable development in our economic,

environmental and social performance.

Our processes, related tools and requirements

focus on water,

biodiversity and climate change, as well as social

and stakeholder issues.

The environmental information contained in Management’s Discussion

and Analysis of Financial Condition

and Results of Operations on pages 50 through 55 under

the captions “Environmental” and “Climate

Change”

is incorporated herein by reference.

It includes information on expensed and

capitalized environmental costs

for 2019 and those expected for 2020 and 2021.

Website Access to SEC Reports

Our internet website address is

www.conocophillips.com

Information contained on our internet website is not

part of this report on Form 8-K.

Our Annual Reports on Form 10-K, Quarterly Reports

on Form 10-Q, Current Reports on Form 8-K

and any

amendments to these reports filed or furnished pursuant

to Section

13(a) or 15(d) of the Securities Exchange

Act of 1934 are available on our website, free of charge,

as soon as reasonably practicable after such

reports

are filed with, or furnished to, the SEC.

Alternatively, you may access these reports at the SEC’s website at

www.sec.gov

Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

Management’s

Discussion and Analysis is the company’s analysis of its financial performance and of

significant trends that may affect future performance.

It should be read in conjunction with the financial

statements and notes, and supplemental oil and gas

disclosures included elsewhere in this report.

It contains

forward-looking statements including, without limitation, statements

relating

to the company’s plans,

strategies, objectives, expectations and intentions

that are made pursuant to the “safe harbor” provisions of

the Private Securities Litigation Reform Act of 1995.

The words “anticipate,” “estimate,” “believe,”

“budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,”

“will,”

“would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,”

“effort,” “target”

and similar expressions identify forward-looking statements.

The company does not undertake to update,

revise or correct any of the forward-looking information unless required to do so under the federal securities

laws.

Readers are cautioned that such forward-looking statements should be read in conjunction with the

company’s

disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE

‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,”

beginning on page 60.

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

attributable to ConocoPhillips.

BUSINESS ENVIRONMENT AND EXECUTIVE

OVERVIEW

ConocoPhillips is an independent E&P company with

operations and activities in 17 countries.

Our diverse,

low cost of supply portfolio includes resource-rich unconventional

plays in North America; conventional

assets in North America, Europe, Asia and Australia;

LNG developments; oil sands in Canada; and

inventory of global conventional and unconventional exploration

prospects.

Headquartered in Houston, Texas,

at December 31, 2019, we employed approximately

10,400 people worldwide and had total assets

of $71

billion.

Overview

Global oil prices continued to be volatile in 2019.

Optimism about worldwide economic growth

during the

first quarter turned to pessimism in the second quarter

as trade disputes dampened growth forecasts.

At the

end of the second quarter, geopolitical tensions in the Middle East, threatening

the safe passage of supertankers

carrying crude oil through the Persian Gulf, revived

oil prices.

Worldwide economic growth concerns returned

in the third quarter to depress prices, only to be reversed

again by geopolitical tensions in the Middle East,

oilfield infrastructure in Saudi Arabia was attacked,

temporarily disrupting approximately

five percent of the

world’s oil supply.

Production was restored relatively quickly, and prices settled in the fourth

quarter.

Brent

crude averaged $64

per barrel in 2019, down nine percent from

the prior year.

Our business strategy

anticipates prices will remain volatile and is designed

to be resilient in lower price environments,

while

retaining upside during periods of higher prices.

Portfolio diversification and optimization,

a strong balance

sheet and disciplined capital investment have positioned

our company to navigate through volatile energy

cycles.

Our value proposition principles, namely, to focus on financial returns, maintain

a strong balance sheet, deliver

compelling returns of capital, and expand cash flow

through disciplined capital investments, are

being

executed in accordance with our priorities for allocating

cash flows from the business.

These priorities are:

invest capital to sustain

production and pay our existing dividend; grow

our existing dividend; maintain debt at

a level we believe is sufficient to maintain a strong investment

grade credit rating through price cycles; allocate

greater than 30 percent of our net cash provided by operating

activities to share repurchases and dividends;

and,

invest capital in a disciplined fashion to grow our

cash from operations.

We believe our commitment to

our value proposition, as evidenced by the results discussed

below, positions us for success in an environment

of price uncertainty and ongoing volatility.

In 2019, we successfully delivered on our priorities.

We achieved production growth of five percent on a total

BOE basis compared with the prior year, with higher value oil

volumes growing eight percent.

Cash provided

by operating activities of $11.1 billion exceeded capital expenditures

and investments of $6.6 billion.

After

repurchasing $3.5 billion of our common stock

and paying $1.5 billion of dividends to shareholders,

we ended

the year with cash, cash equivalents and restricted

cash totaling $5.4 billion and $3.0 billion of short-term

investments.

In October, we announced an increase to our quarterly

dividend of 38 percent to $0.42 per share

and announced planned 2020 share buybacks of $3 billion.

In February 2020, we announced 2020 operating

plan capital of $6.5 billion to $6.7 billion.

The plan includes

funding for ongoing development drilling programs, major

projects, exploration and appraisal activities, as

well as base maintenance.

Capital spend is expected to be

higher in the first quarter largely from winter

construction and exploration and appraisal drilling in

Alaska.

This guidance does not include capital for

acquisitions.

Key Operating and Financial Summary

Significant items during 2019 included the following:

●

Net cash provided by operating activities was $11.1

billion and exceeded capital expenditures and

investments of $6.6 billion.

●

Repurchased $3.5 billion of shares and paid $1.5 billion

in dividends, representing 45 percent of net

cash provided by operating activities.

●

Increased the quarterly dividend by 38 percent to $0.42

per share.

●

Achieved 100 percent total reserve replacement

and 117 percent organic replacement.

●

Underlying production, which excludes Libya and

the net volume impact from closed dispositions and

acquisitions of 51 MBOED in 2019 and 47 MBOED

in 2018, grew 5 percent.

●

Increased production from the Lower 48 Big 3 unconventionals—Eagle

Ford, Bakken and Permian

Unconventional—by 22 percent year-over-year.

●

Executed successful Alaska appraisal program; conducted

appraisal drilling and commissioned

infrastructure at Montney in Canada.

●

Completed Lower 48, Alaska and Argentina acquisitions;

awarded a 20-year extension of the

Indonesia Corridor Block PSC, with new terms.

●

Generated $3 billion in disposition proceeds; entered into

agreements to sell Australia-West assets for

$1.4 billion and Niobrara for $0.4 billion, both

subject to customary closing adjustments,

as well as

regulatory and other approvals.

●

Reduced asset retirement obligations and accrued environmental

costs by $2.3 billion, primarily due to

closed and pending dispositions.

●

Ended the year with cash, cash equivalents and

restricted cash totaling $5.4 billion and short-term

investments of $3.0 billion.

●

Recognized a $296 million after-tax impairment related

to the sale of our Niobrara interests in the

Lower 48 segment.

●

Discontinued exploration activities in the Central

Louisiana Austin Chalk trend and recognized

$197

million after-tax in leasehold impairment and dry

hole expenses.

Operationally, we remain focused on safely executing our operating plan and maintaining

capital and cost

discipline.

Production of 1,348 MBOED increased 5

percent or 65 MBOED in 2019 compared with 2018.

Production, excluding Libya, of 1,305 MBOED increased

5 percent or 63 MBOED.

Underlying production,

which excludes Libya and the net volume impact from closed

dispositions and acquisitions of 51 MBOED

2019 and 47 MBOED in 2018, is used to measure our ability

to grow production organically.

Our underlying

production grew 5 percent in 2019 to 1,254 MBOED from

1,195 MBOED in 2018.

On September 30, 2019, we completed the sale of two ConocoPhillips

U.K. subsidiaries to Chrysaor E&P

Limited for proceeds of $2.2 billion after interest

and customary adjustments.

In 2019, we recorded a $1.7

billion before-tax and $2.1 billion after-tax gain associated

with this transaction.

Together the subsidiaries

sold our indirectly held exploration and production assets

in the U.K.,

including $1.8 billion of ARO.

Annualized average production associated with the U.K. assets

sold was 50 MBOED in 2019.

Reserves

associated with the U.K. assets sold were 84 MMBOE

at the time of disposition.

Results of operations for the

U.K. are reported within our Europe,

Middle East and North Africa segment.

In the second quarter of 2019, we completed the sale of

our 30 percent interest in the Greater Sunrise

Fields to

the government of Timor-Leste for $350 million and recognized

an after-tax gain of $52 million.

production or reserve impacts were associated with

the sale.

The Greater Sunrise Fields were included in our

Asia Pacific segment.

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 $75 million upon

final investment

decision of the Barossa

development project.

These subsidiaries hold our 37.5 percent interest

in the Barossa Project and Caldita

Field, our 56.9 percent interest in the Darwin LNG Facility

and Bayu-Undan Field, our 40 percent interest in

the Greater Poseidon Fields, and our 50 percent interest

in the Athena Field.

This transaction is expected to be

completed in the first quarter of 2020, subject to regulatory

approvals and the satisfaction of other specific

conditions precedent.

In 2019, production associated with the Australia-West assets to be sold was 48

MBOED.

Year-end 2019 reserves associated with these assets were 17 MMBOE.

We will retain our 37.5

percent interest in the Australia Pacific LNG project

and operatorship of that project’s LNG facility.

Results

of operations for the subsidiaries to be sold are reported

within our Asia Pacific segment.

In the fourth quarter of 2019, we signed an agreement

to sell our interests in the Niobrara shale play

for $380

million, plus customary adjustments,

and overriding royalty interests in certain future

wells.

recorded an

after-tax impairment of $296 million in the fourth quarter

of 2019 to reduce the carrying value to fair value.

2019, production from Niobrara was 11 MBOED.

Year-end 2019 reserves associated with the Niobrara assets

to be sold were 14 MMBOE.

This transaction is subject to regulatory approval

and other 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.

For more information regarding the accounting impacts of

these transactions, see Note 5—Asset Acquisitions

and Dispositions,

in the Notes to Consolidated Financial

Statements.

Business Environment

Brent crude oil prices averaged $64 per barrel in 2019,

ranging from a low of $53 per barrel in January

to a

high of almost $75 per barrel in April.

The energy industry has periodically experienced

this type of volatility

due to fluctuating supply-and-demand conditions and such

volatility may persist for the foreseeable future.

Commodity prices are the most significant factor impacting

our profitability and related reinvestment of

operating cash flows into our business.

Our strategy is to create value through price cycles by

delivering on

the foundational principles that underpin our value proposition;

focus on financial returns through cash flow

expansion, maintain balance sheet strength and deliver peer-leading

distributions.

Operational and Financial Factors Affecting Profitability

The focus areas we believe will drive our success through

the price cycles include:

●

Maintain a relentless focus on safety and environmental

stewardship.

Safety and environmental

stewardship, including the operating integrity of our

assets, remain our highest priorities, and we

are

committed to protecting the health and safety of

everyone who has a role in our operations and

the

communities in which we operate.

strive to conduct our business with

respect and care for both

the local and global environment and systematically

manage risk to drive sustainable business growth.

Demonstrating our commitment to sustainability

and environmental stewardship, on November

2017,

we announced our intention to target a 5 to 15 percent reduction

in our GHG emission

intensity by 2030.

In December 2018, we became a founding

member of the Climate Leadership

Council (CLC), an international policy institute founded

in collaboration with business and

environmental interests to develop a carbon dividend

plan.

Participation in the CLC provides another

opportunity for ongoing dialogue about carbon pricing

and framing the issues in alignment with our

public policy principles.

We also belong to and fund Americans For Carbon Dividends, the education

and advocacy branch of the CLC.

In early 2019, we issued our first

stand-alone Climate-related Risk

Report and incorporated this into our website during

our annual Sustainability Report update.

Our

sustainability efforts continued through 2019 with a focus on

advancing our action plans for climate

change, biodiversity, water and human rights.

are committed to building a learning organization

using human performance principles as we relentlessly

pursue improved HSE and operational

performance.

●

Focus on financial returns.

This is a core principle of our value proposition.

Our goal is to achieve

strong financial returns by exercising capital discipline,

controlling our costs, and continually

optimizing our portfolio.

Maintain capital allocation discipline.

We participate in a commodity price-driven and

capital-intensive industry, with varying lead times from when an investment decision

is made

to the time an asset is operational and generates cash

flow.

As a result, we must invest

significant capital dollars to explore for new oil and

gas fields, develop newly discovered

fields, maintain existing fields, and construct pipelines

and LNG facilities.

allocate

capital across a geographically diverse, low cost of

supply resource base, which combined

with legacy assets results in low production decline.

Cost of supply is the WTI equivalent

price that generates a 10 percent after-tax return on a point-forward

and fully burdened basis.

Fully burdened includes capital infrastructure, foreign

exchange, price related inflation and

G&A.

In setting our capital plans, we exercise a rigorous

approach that evaluates projects

using this cost of supply criteria, which should

lead to value maximization and cash flow

expansion using an optimized investment pace, not production

growth for growth’s sake.

Additional capital may be allocated toward growth,

but discipline will be maintained.

Our

cash allocation priorities call for the investment

of sufficient capital to sustain production and

pay the existing dividend.

In February 2020, we announced 2020 operating

plan capital of $6.5 billion to $6.7 billion.

The plan includes funding for ongoing development

drilling programs, major projects,

exploration and appraisal activities, as well as base maintenance.

Capital spend is expected to

be higher in the first quarter largely from winter construction

and exploration and appraisal

drilling in Alaska.

This guidance does not include capital for acquisitions.

Control costs and expenses.

Controlling operating and overhead

costs, without compromising

safety and environmental stewardship, is a high priority.

monitor these costs using

various methodologies that are reported to senior management

monthly, on both an absolute-

dollar basis and a per-unit basis.

Managing operating and overhead costs

is critical to

maintaining a competitive position in our industry, particularly in a low commodity

price

environment.

The ability to control our operating and overhead

costs impacts our ability to

deliver strong cash from operations.

In 2019, our production and operating expenses

were

two percent higher than 2018, primarily due to costs associated

with higher production

volumes, which grew five percent during the same

period.

Optimize our portfolio.

We continue to optimize our asset portfolio to focus on low cost of

supply assets that support our strategy.

In 2019, we continued to dispose of

or market certain

non-core assets, including the U.K.,

Australia-West and our Niobrara assets

in the Lower 48.

Additions to the portfolio were made in the Lower 48 with

bolt-on interests and acreage

acquisitions, in Alaska with the Nuna discovery acreage

acquisition, and internationally with

entrance into Argentina’s Neuquén and Austral Basins.

will continue to evaluate our

assets to determine whether they compete for capital

within our portfolio and will optimize

the portfolio as necessary, directing capital towards the most competitive

investments.

●

Maintain balance sheet strength.

believe balance sheet strength is critical in a cyclical

business

such as ours.

Our strong operating performance buffered by a solid balance sheet

enables us to deliver

on our priorities through the price cycles.

Our priorities include execution of our development plans,

maintaining a growing dividend,

and repurchasing shares on a dollar cost average basis.

●

Return value to shareholders.

We believe in delivering value to our shareholders via a growing,

sustainable dividend supplemented by share repurchases.

In 2019, we paid dividends on our common

stock of approximately $1.5 billion and repurchased

$3.5 billion of our common stock.

Combined,

our dividend and repurchases represented 45 percent of

our net cash provided by operating activities.

Since we initiated our current share repurchase program

in late 2016, we have repurchased $9.6

billion

of shares.

Additionally, as of December 31, 2019, $5.4 billion of repurchase authority remained

of the

$15 billion share repurchase program our Board of Directors

had authorized.

In February 2020, we

announced that the Board of Directors approved an increase

to our repurchase authorization from $15

billion to $25 billion, to support our plan for future share

repurchases.

Whether we undertake these

additional repurchases is ultimately subject to numerous

considerations, including market conditions

and other factors.

See Risk Factors beginning on page 21 in

our 2019 Annual Report on Form 10-K

“Our ability to declare and pay dividends and repurchase

shares is subject to certain considerations.”

In October 2019, we announced that our Board of Directors

approved an increase to our quarterly

dividend of 38 percent to $0.42 per share.

●

Add to our proved reserve base.

We primarily add to our proved reserve base in three ways:

Successful exploration, exploitation and development

of new and existing fields.

Application of new technologies and processes

to improve recovery from existing fields.

Purchases of increased interests in existing fields and bolt-on

acquisitions.

Proved reserve estimates require economic production

based on historical 12-month, first-of-month,

average prices and current costs.

Therefore, our proved reserves generally increase

as prices rise and

decrease as prices decline.

Reserve replacement represents the net change in

proved reserves, net of

production, divided by our current year production,

as shown in our supplemental reserve table

disclosures.

In 2019, our reserve replacement, which included

a net decrease of 0.1 billion BOE from

sales and purchases, was 100 percent.

Increased crude oil reserves accounted

for approximately 55

percent of the total change in reserves. Our organic reserve

replacement, which excludes the impact of

sales and purchases, was 117 percent in 2019.

Approximately 50 percent of organic reserve additions

were from Lower 48 unconventional assets.

The remaining additions were evenly distributed across

the other operating segments.

In the five years ended December 31, 2019, our reserve

replacement was negative 34 percent,

reflecting the impact of asset dispositions and lower

prices during that period.

Our organic reserve

replacement during the five years ended December

31, 2019, which excludes a decrease of 2.0 billion

BOE related to sales and purchases, was 40 percent,

reflecting development activities as

well as lower

prices during that period.

Historically, our reserve replacement has varied considerably year to year contingent

upon the timing

of major projects which may have long lead times between

capital investment and production.

In the

last several years, more of our capital has been

allocated to short cycle time, onshore, unconventional

plays.

Accordingly, we believe our recent success in replacing reserves can be viewed

on a trailing

three-year basis.

In the three years ended December 31, 2019, our reserve

replacement was 23 percent, reflecting the

impact of asset dispositions during that period.

Our organic reserve replacement during the three

years ended December 31, 2019, which excludes a

decrease of 1.8 billion BOE related to sales and

purchases, was 143 percent, reflecting reserve additions

from development activities.

Access to additional resources may become increasingly

difficult as commodity prices can make

projects uneconomic or unattractive.

In addition, prohibition of direct investment

in some nations,

national fiscal terms, political instability, competition from national oil companies, and

lack of access

to high-potential areas due to environmental or other

regulation may negatively impact our ability

increase our reserve base.

As such, the timing and level at which we add

to our reserve base may, or

may not, allow us to replace our production over

subsequent years.

●

Apply technical capability.

We leverage our knowledge and technology to create value and safely

deliver on our plans.

Technical strength is part of our heritage and allows us to economically

convert

additional resources to reserves, achieve greater operating

efficiencies and reduce our environmental

impact.

Companywide, we continue to evaluate

potential solutions to leverage knowledge of

technological successes across our operations.

have embraced the digital transformation

and are using digital innovations to work and

operate

more efficiently.

Predictive analytics have been adopted

in our operations and planning process.

Artificial intelligence, machine learning and deep

learning are being used for seismic advancements.

●

Attract, develop and retain a talented work force.

We strive to attract, develop and retain individuals

with the knowledge and skills to implement our business

strategy and who support our values and

ethics.

offer university internships across multiple disciplines

to attract the best early career

talent.

also recruit experienced hires to fill critical skills

and maintain a broad range of expertise

and experience.

We promote continued learning, development and technical training through

structured development programs designed to enhance

the technical and functional skills of our

employees.

Other Factors Affecting Profitability

Other significant factors that can affect our profitability

include:

●

Energy commodity prices.

Our earnings and operating cash flows generally correlate

with industry

price levels for crude oil and natural gas.

Industry price levels are subject to factors

external to the

company and over which we have no control, including

but not limited to global economic health,

supply disruptions or fears thereof caused by civil

unrest or military conflicts, actions taken by

OPEC,

environmental laws, tax regulations, governmental policies

and weather-related disruptions.

The

following graph depicts the average benchmark prices

for WTI crude oil, Brent crude oil and U.S.

Henry Hub natural gas:

Brent crude oil prices averaged $64.30 per barrel

in 2019, a decrease of 9 percent compared with

$71.04 per barrel in 2018.

Similarly, WTI crude oil prices decreased 12 percent from $64.92 per

barrel in 2018 to $57.02 per barrel in 2019.

Crude oil prices weakened year over year

primarily due to

ample global supplies and a decelerating global economy.

Henry Hub natural gas price averages decreased 15

percent from $3.09 per MMBTU in 2018 to $2.63

per MMBTU in 2019.

Natural gas prices weakened in 2019

versus the prior year due to strong

production, while demand growth was dampened

by mild weather.

Our realized NGL prices decreased 34 percent from

$30.48 per barrel in 2018 to $20.09 per barrel in

2019.

NGL prices weakened year over year due

to strong supply growth with only moderate demand

growth.

Our realized bitumen price increased 42 percent

from $22.29 per barrel in 2018 to $31.72 per barrel in

2019.

Curtailment orders imposed by the Alberta Government,

which limited production from the

province starting January 2019, provided strength to the

WCS differential to WTI at Hardisty.

continue to optimize bitumen price realizations through

the utilization of downstream transportation

solutions and implementation of alternate blend

capability which results in lower diluent costs.

Our worldwide annual average realized price decreased

9 percent from $53.88

per BOE in 2018 to

$48.78

per BOE in 2019 due to lower realized

oil, natural gas and NGL prices.

North America’s energy supply landscape has been transformed from one of resource

scarcity to one

of abundance.

In recent years, the use of hydraulic fracturing

and horizontal drilling in

unconventional formations has led to increased industry

actual and forecasted crude oil and natural

gas production in the U.S.

Although providing significant short- and long-term

growth opportunities

for our company, the increased abundance of crude oil and natural gas due to development

unconventional plays could also have adverse financial

implications to us, including: an extended

period of low commodity prices; production curtailments;

and delay of plans to develop areas such as

unconventional fields.

Should one or more of these events occur, our revenues would be reduced,

and

additional asset impairments might be possible.

●

Impairments.

participate in a capital-intensive industry.

At times, our PP&E and investments

become impaired when, for example, commodity

prices decline significantly for long periods

of time,

our reserve estimates are revised downward, or a decision

to dispose of an asset leads to a write-down

to its fair value.

We may also invest large amounts of money in exploration which, if exploratory

drilling proves unsuccessful, could lead to a material

impairment of leasehold values.

As we optimize

our assets in the future, it is reasonably possible we

may incur future losses upon sale or

impairment

charges to long-lived assets used in operations, investments

in nonconsolidated entities accounted for

under the equity method, and unproved properties.

A sustained decline in the current and long-term

outlook on gas price could affect the carrying value of certain

Lower 48 non-core gas assets and it is

reasonably possible this could result in a future non-cash impairment.

For additional information on

our impairments in 2019, 2018 and 2017, see Note 9—Impairments,

in the Notes to Consolidated

Financial Statements.

●

Effective tax rate.

Our operations are in countries with different

tax rates and fiscal structures.

Accordingly, even in a stable commodity price and fiscal/regulatory environment, our

overall

effective tax rate can vary significantly between periods based

on the “mix” of before-tax earnings

within our global operations.

●

Fiscal and regulatory environment.

Our operations can be affected by changing economic,

regulatory

and political environments in the various countries in

which we operate, including the U.S.

Civil

unrest or strained relationships with governments may

impact our operations or investments.

These

changing environments could negatively impact

our results of operations, and further changes

increase government fiscal take could have a negative

impact on future operations.

Our management

carefully considers the fiscal and regulatory environment

when evaluating projects or determining the

levels and locations of our activity.

Outlook

Full-year 2020 production is expected to be 1,230 MBOED

to 1,270 MBOED, including the impact of a recent

third-party pipeline outage on the Kebabangan Field in Malaysia.

First-quarter 2020 production is expected to

be 1,240 MBOED to 1,280 MBOED.

Production guidance for 2020 excludes Libya.

Operating Segments

manage our operations through six operating

segments, which are primarily defined by geographic

region:

Alaska; Lower 48; Canada; Europe, Middle East and North

Africa; Asia Pacific and Other International.

Corporate and Other represents costs not directly

associated with an operating segment, such as

most interest

expense, premiums incurred on the early retirement

of debt, corporate overhead, certain technology

activities,

as well as licensing revenues.

Our key performance indicators, shown in the statistical

tables provided at the beginning of the operating

segment sections that follow, reflect results from our operations, including commodity prices

and production.

RESULTS OF OPERATIONS

Effective with the third quarter of 2020, we have restructured our segments to align with changes to our

internal organization.

The Middle East business was realigned from the Asia Pacific and Middle East segment

to the Europe and North Africa segment.

The segments have been renamed the Asia Pacific segment and the

Europe, Middle East and North Africa segment.

We have revised segment information disclosures and

segment performance metrics presented within our results of operations for the

current and prior years.

Consolidated Results

A summary of the company’s net income (loss) attributable to ConocoPhillips

by business segment follows:

Millions of Dollars

Years

Ended December 31

2019

2018

2017

Alaska

1,520

1,814

1,466

Lower 48

436

1,747

(2,371)

Canada

279

2,564

Europe, Middle East and North Africa

3,170

2,594

1,116

Asia Pacific

1,483

1,342

(1,661)

Other International

263

364

167

Corporate and Other

(1,667)

(2,136)

Net income (loss) attributable to ConocoPhillips

7,189

6,257

(855)

2019 vs. 2018

Net income attributable to ConocoPhillips increased $932

million in 2019.

The increase was mainly due to:

●

A $2.1 billion after-tax gain associated with the completion

of the sale of two ConocoPhillips U.K.

subsidiaries to Chrysaor E&P Limited.

●

An unrealized gain of $649 million after-tax on our Cenovus

Energy (CVE) common shares in 2019,

as compared to a $436 million after-tax unrealized loss

on those shares in 2018.

●

Higher crude oil sales volumes due to growth in the

Lower 48 unconventionals and from the

acquisition of incremental interests in operated assets

in Alaska during the second and fourth

quarters

of 2018.

●

The absence of premiums on early debt retirements

totaling $195 million after-tax.

●

A $164 million income tax benefit related to deepwater

incentive tax credits recognized for Malaysia

Block G.

●

A $151 million income tax benefit related to the revaluation

of deferred tax assets following

finalization of rules relating to the 2017 Tax Cuts and Jobs Act.

These increases in net income were partly offset by:

●

Lower realized crude oil, natural gas and NGL prices.

●

The absence of a $774 million after-tax gain on the

Clair disposition in the U.K.

●

A $296 million after-tax impairment related to the

sale of our Lower 48 Niobrara interests.

●

Lower equity in earnings of affiliates due to $120 million

of impairments to equity method

investments in our Lower 48 segment and a $118 million reduction in

equity earnings at QG3 in our

Europe, Middle East and North Africa segment due

to a deferred tax adjustment.

●

Higher exploration expenses, primarily in our Lower

48 segment due to $197

million after-tax of

leasehold impairment and dry hole costs associated

with our decision to discontinue exploration

activities in the Central Louisiana Austin Chalk

trend.

2018 vs. 2017

Net income attributable to ConocoPhillips increased $7,112

million

in 2018.

The increase was mainly due to:

●

Higher realized commodity prices on a more liquids-weighted

portfolio.

●

The absence of a combined $2.5 billion after-tax impairment

related to the sale of our interests in the

San Juan Basin and the marketing of our Barnett asset,

recognized in the second quarter of 2017.

●

The absence of a $2.4 billion before- and after-tax impairment

of our equity investment in Australia

Pacific LNG Pty Ltd (APLNG), recognized in the

second quarter of 2017.

●

Recognition of $774 million after-tax gain on the Clair disposition

in the United Kingdom, in the

fourth quarter of 2018.

●

Lower depreciation, depletion and amortization (DD&A)

expense, mainly due to lower unit-of-

production rates from reserve revisions and disposition

impacts.

●

Recognition of $417 million after-tax in other income

from a settlement agreement with PDVSA

2018.

●

Lower exploration expenses, primarily due to the

absence of first quarter 2017 charges in our Lower

48 and Other International segments.

●

Lower interest and debt expense because of a lower debt

balance.

●

Higher equity earnings in QG3 and APLNG, primarily

due to higher realized LNG prices, partly

offset

by the absence of volumes in 2018 related to the disposition

of our interest in the FCCL Partnership in

Canada in 2017.

These increases in net income were partly offset by:

●

The absence of $1.6 billion in after-tax gains related to the sale

of certain Canadian assets in 2017.

●

The absence of a $996 million deferred tax benefit

related to the disposition of certain Canadian

assets, recognized in the first quarter of 2017.

●

The absence of deferred tax benefits totaling $852

million related to the Tax Legislation enacted on

December 22, 2017.

●

An unrealized loss of $437 million on our Cenovus Energy

common shares in 2018.

●

The absence of a $337 million after-tax award, including interest,

from an arbitration settlement with

The Republic of Ecuador in 2017.

Income Statement Analysis

2019 vs. 2018

Sales and other operating revenues decreased 11 percent in 2019, mainly due to

lower realized crude oil,

natural gas and NGL prices, partly offset by higher sales volumes

of crude oil in the Lower 48 and Alaska.

Equity in earnings of affiliates decreased $295 million in 2019,

primarily due to impairments of equity method

investments in our Lower 48 segment totaling $155 million.

Additionally, equity earnings decreased $118

million resultant from a deferred tax adjustment at

QG3,

reported in our Europe, Middle East and North

Africa

segment.

For more information related to these

items, see Note 3—Variable Interest Entities and Note 5—

Asset Acquisitions and Dispositions, in the Notes

to Consolidated Financial Statements.

Gain on dispositions increased $903 million in 2019, primarily

due to a $1.7 billion

before-tax gain associated

with the completion of the sale of two ConocoPhillips

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

Partly

offsetting this increase, was the absence of a $715 million

before-tax gain on the sale of a ConocoPhillips

subsidiary to BP in 2018, which held 16.5 percent of

our 24 percent interest in the BP-operated Clair

Field in

the U.K.

For additional information related to these dispositions,

see Note 5—Asset Acquisitions and

Dispositions, in the Notes to Consolidated Financial

Statements.

Other income increased $1,185 million in 2019, primarily

due to an unrealized gain of $649 million before-tax

on our CVE common shares in 2019, and the absence

of a $437 million before-tax unrealized loss on those

shares in 2018.

For discussion of our CVE shares, see

Note 7—Investment in Cenovus Energy, in the Notes to

Consolidated Financial Statements.

Purchased commodities decreased 17 percent in 2019, primarily

due to lower natural gas and crude oil prices.

Selling, general and administrative expenses increased $155

million in 2019, primarily due to higher costs

associated with compensation and benefits, including mark

to market impacts of certain key employee

compensation programs, and increased facility costs.

Exploration expenses increased $374 million in 2019,

primarily due to higher leasehold impairment

and dry

hole costs, mainly in our Lower 48 segment,

and higher exploration G&A expenses.

In 2019, we recorded a

$141 million before-tax leasehold impairment expense

due to our decision to discontinue exploration

activities

in the Central Louisiana Austin Chalk trend and expensed

$111 million of dry hole costs related to this play.

Impairments increased $378 million in 2019, mainly due

to a $379 million before-tax impairment related

to the

sale of our Niobrara interests in the Lower 48 segment.

For additional information, see Note 5—Asset

Acquisitions and Dispositions and Note 9—Impairments,

in the Notes to Consolidated Financial Statements.

Other expenses decreased $310 million in 2019, primarily

due to the absence of a $206 million before-tax

expense for premiums on early debt retirements and lower

pension settlement expense.

See Note 19—Income Taxes, in the Notes to Consolidated Financial Statements,

for information regarding our

income tax provision (benefit) and effective tax rate.

2018 vs. 2017

Sales and other operating revenues increased 25 percent

in 2018, due to higher realized commodity

prices,

mainly crude oil, on a portfolio with a higher mix

of crude oil and less of bitumen and natural gas.

Partly

offsetting this increase, were lower natural gas volumes sold

due to 2017 dispositions in the Lower 48 and

Canada.

Equity in earnings of affiliates increased $302 million

in 2018.

The increase in equity earnings was primarily

due to higher earnings from QG3 and APLNG

as a result of higher LNG prices for both affiliates and higher

oil prices in QG3.

Partly offsetting this increase, was the absence of equity

in earnings resulting from the

disposition of our investment in the FCCL Partnership

in 2017.

Gain on dispositions decreased $1,114 million in 2018.

The decrease was primarily due to the absence

of a

$2.1 billion before-tax gain on the sale of certain Canadian

assets recognized in 2017, partly offset by a $715

million before-tax gain recognized in the fourth quarter

of 2018 on the sale of a ConocoPhillips

subsidiary to

BP, which

held 16.5 percent of our 24 percent interest

in the BP-operated Clair Field in the United

Kingdom.

For additional information concerning gain on dispositions,

see Note 5—Asset Acquisitions and Dispositions,

in the Notes to Consolidated Financial Statements.

Other income decreased $356 million in 2018, mainly

due to a $437 million unrealized loss on our

Cenovus

Energy common shares in 2018 and the absence of a $337

million arbitration settlement, including interest,

with The Republic of Ecuador in 2017.

Partly offsetting the decrease, was $430 million

before-tax from a

settlement agreement with PDVSA in 2018.

For discussion of our Cenovus Energy shares, see Note 7—Investment

in Cenovus Energy, in the Notes to

Consolidated Financial Statements.

For discussion of our Ecuador and PDVSA settlements,

see Note 13—

Contingencies and Commitments, in the Notes

to Consolidated Financial Statements.

Purchased commodities increased 15 percent in 2018,

mainly due to higher crude oil volumes purchased

and

higher crude oil prices.

Production and operating expenses increased 1 percent

in 2018, primarily due to costs associated

with higher

underlying production volumes as well as higher maintenance

and wellwork, largely offset by the absence of

costs resulting from 2017 dispositions in our Canada

and Lower 48 segments.

Exploration expenses decreased $565 million in 2018, primarily

as a result of lower dry hole costs, leasehold

impairment expense and other exploration expenses.

Dry hole costs were reduced primarily due to the absence

of before-tax charges of $288 million for multiple

Shenandoah wells in the deepwater Gulf of Mexico,

including wells previously suspended.

These charges

were reflected in our Lower 48 segment during 2017.

Leasehold impairment expense was reduced mainly due

to the absence of before-tax charges of $51 million

for

Shenandoah and $38 million for certain Lower 48

mineral assets, both recognized in 2017.

Other exploration expenses were reduced mainly

due to the absence of a $43 million before-tax charge

for the

cancellation of our Athena drilling rig contract and

other rig stacking costs in our Other International

segment

in 2017.

For additional information on leasehold impairments

and other exploration expenses, see Note 8—Suspended

Wells and Other Exploration Expenses, and Note 9—Impairments, in the Notes to Consolidated

Financial

Statements.

DD&A decreased $889 million in 2018, mainly due to lower

unit-of-production rates from positive reserve

revisions and impacts from the 2017 dispositions in our

Canada and Lower 48 segments, partly

offset by

increased underlying production volumes.

Impairments decreased $6.6 billion in 2018, mainly due

to the absence of 2017 impairments of

$3.9 billion

before-tax related to our former interests in the San

Juan Basin and the Barnett, both in our Lower

48 segment,

as well as a $2.4 billion before-

and after-tax impairment of our equity investment

in APLNG.

For additional

information, see Note 6—Investments, Loans and Long-Term Receivables and Note 9—Impairments,

in the

Notes to Consolidated Financial Statements.

Taxes other than income taxes increased $239 million in 2018, primarily due to higher

production taxes in

Alaska and the Lower 48 corresponding with

higher realized commodity prices.

Interest and debt expense decreased $363 million

in 2018, primarily due to lower debt balances.

See Note 19—Income Taxes, in the Notes to Consolidated Financial Statements,

for information regarding our

income tax provision (benefit) and effective tax rate.

Summary Operating Statistics

2019

2018

2017

Average Net Production

Crude oil (MBD)

Consolidated Operations

692

639

585

Equity affiliates

Total crude oil

705

653

599

Natural gas liquids (MBD)

Consolidated Operations

107

104

Equity affiliates

Total natural gas liquids

115

102

111

Bitumen (MBD)

Consolidated Operations

Equity affiliates

Total bitumen

122

Natural gas (MMCFD)

Consolidated Operations

1,753

1,743

2,263

Equity affiliates

1,052

1,031

1,007

Total natural gas

2,805

2,774

3,270

Total Production

(MBOED)

1,348

1,283

1,377

Dollars Per Unit

Average Sales Prices

Crude oil (per bbl)

Consolidated Operations

60.98

68.03

51.89

Equity affiliates

61.32

72.49

54.76

Total crude oil

60.99

68.13

51.96

Natural gas liquids (per bbl)

Consolidated Operations

18.73

29.03

24.21

Equity affiliates

36.70

45.69

38.74

Total natural gas liquids

20.09

30.48

25.22

Bitumen (per bbl)

Consolidated Operations

31.72

22.29

21.43

Equity affiliates

23.83

Total bitumen

31.72

22.29

22.66

Natural gas (per mcf)

Consolidated Operations

4.25

5.40

3.97

Equity affiliates

6.29

6.06

4.27

Total natural gas

5.03

5.65

4.07

Millions of Dollars

Worldwide Exploration Expenses

General and administrative; geological and geophysical,

lease rental, and other

322

274

368

Leasehold impairment

221

136

Dry holes

200

430

743

369

934

explore for, produce, transport and market crude oil, bitumen,

natural gas, LNG and NGLs on a worldwide

basis.

At December 31, 2019, our operations were producing

in the U.S., Norway, Canada, Australia, Timor-

Leste, Indonesia, China, Malaysia, Qatar and Libya.

2019 vs. 2018

Total production, including Libya, of 1,348 MBOED increased 65 MBOED or 5 percent

in 2019 compared

with 2018, primarily due to:

●

New wells online in the Lower 48.

●

An increased interest in the Western North Slope (WNS) and Greater Kuparuk Area (GKA)

of Alaska

following acquisitions closed in 2018.

●

Higher production in Norway due to drilling activity

and the startup of Aasta Hansteen in December

2018.

The increase in production during 2019 was partly offset by:

●

Normal field decline.

●

Disposition impacts from the U.K. and non-core

asset sales in the Lower 48.

Production excluding Libya was 1,305 MBOED in

2019 compared with 1,242 MBOED in 2018,

an increase of

63 MBOED or 5 percent.

Underlying production, which excludes Libya and

the net volume impact from

closed dispositions and acquisitions of 51 MBOED in

2019 and 47 MBOED in 2018, is used to measure

our

ability to grow production organically.

Our underlying production grew 5 percent to 1,254

MBOED in 2019

from 1,195 MBOED in 2018.

2018 vs. 2017

Total production, including Libya, of 1,283 MBOED decreased 7 percent in 2018 compared

with 2017,

primarily due to:

• Disposition impacts from asset sales in Canada and the Lower 48 in 2017.

• Normal field decline.

• Higher unplanned downtime, including a third-party pipeline outage in Malaysia

in 2018.

The decrease in production during 2018 was partly

offset by:

• New wells online, primarily from tight oil plays in the Lower 48 and Malikai

in Malaysia.

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

• The continued rampup in Libya.

Production excluding Libya was 1,242 MBOED in

2018 compared with 1,356 MBOED in 2017.

The volume

from closed dispositions was approximately 200 MBOED

in 2017 and 15 MBOED in 2018.

The volume from

acquisitions was less than 10 MBOED in 2018.

Our underlying production, which excludes the full-year

impact of

acquisitions, dispositions, and Libya, increased

over 5 percent in 2018 compared with 2017.

Alaska

2019

2018

2017

Net Income Attributable to ConocoPhillips

(millions of dollars)

1,520

1,814

1,466

Average Net Production

Crude oil (MBD)

202

171

167

Natural gas liquids (MBD)

Natural gas (MMCFD)

Total Production

(MBOED)

218

186

182

Average Sales Prices

Crude oil (per bbl)

64.12

70.86

53.33

Natural gas (per mcf)

3.19

2.48

2.72

The Alaska segment primarily explores for, produces, transports and markets crude

oil, NGLs and natural gas.

In 2019, Alaska contributed 25 percent of our consolidated

liquids production and less than 1 percent of our

natural gas production.

2019 vs. 2018

Alaska reported earnings of $1,520 million in 2019,

compared with earnings of $1,814 million in 2018.

The

decrease in earnings was mainly due to lower realized

crude oil prices and higher production and operating and

DD&A expenses associated with incremental volumes from

acquisitions completed during 2018.

Additionally, earnings were lower due to the absence of a $98 million tax valuation

allowance reduction,

the

absence of a $79 million after-tax benefit resulting

from an accrual reduction due to a transportation

cost ruling

by the FERC,

and $62 million less in enhanced oil recovery

credits.

Partly offsetting these decreases in

earnings, were higher crude oil sales volumes due to

the GKA and WNS acquisitions completed

in 2018.

Average production increased 32 MBOED in 2019 compared with 2018, primarily

due to acquisitions at GKA

and WNS in 2018, which provided an incremental

38 MBOED of production in 2019, as well

as volumes from

new wells online.

These production increases were partly

offset by normal field decline.

Acquisition Update

In the third quarter of 2019, we completed the Nuna discovery

acreage acquisition for approximately $100

million, expanding the Kuparuk River Unit by 21,000 acres

and leveraging legacy infrastructure.

2018 vs. 2017

Alaska reported earnings of $1,814 million in 2018,

compared with earnings of $1,466 million in 2017.

The

increase in earnings was mainly due to higher realized crude

oil prices.

Additionally, earnings were improved

due to the absence of a $110 million after-tax impairment related to our

small interest in the Point Thomson

Unit, recognized in the first quarter of 2017; a $98 million

reduction in tax valuation allowance, recognized in

the fourth quarter of 2018; lower DD&A expense from

reserve additions; and a $79 million after-tax benefit

resulting from an accrual reduction due to a transportation

cost ruling by the Federal Energy Regulatory

Commission (FERC), recorded in the first quarter of

2018.

Partly offsetting these increases in earnings, was

the absence of an $892 million tax benefit from the revaluation

of allocated U.S. deferred taxes at a lower

federal statutory rate, in accordance with the Tax Legislation enacted in 2017.

Consolidated production increased 2 percent in 2018

compared with 2017, primarily due to improved

drilling

and well performance, 8 MBOED from acquisitions

in the Western North Slope and the Greater Kuparuk

Area, and the startup of GMT-1 in the fourth quarter

of 2018, partly offset by normal field decline.

Acquisitions

During the second quarter of 2018, we obtained regulatory

approvals and completed a transaction with

Anadarko Petroleum Corporation to acquire its 22 percent

nonoperated interest in the Western North Slope of

Alaska, as well as its interest in the Alpine Transportation Pipeline,

for $386 million, after customary

adjustments.

In 2018, our Alaska segment net production

included 7 MBOED associated with the additional

interest acquired.

In addition, we now have 100 percent interest

in approximately 1.2 million

acres of

exploration and development lands, including the Willow Discovery.

In December of 2018, we completed a transaction with BP

to acquire their nonoperated interest in the Kuparuk

Assets in Alaska, and to sell a ConocoPhillips subsidiary

to BP, which held 16.5 percent of our 24 percent

interest in the BP-operated Clair Field in the United

Kingdom.

In 2018, our Alaska segment net production

included 1 MBOED related to the additional interest acquired

in the Greater Kuparuk Area.

See Note 5—

Asset Acquisitions and Dispositions in the Notes to

Consolidated Financial Statements, for additional

information.

Lower 48

2019

2018

2017

Net Income (Loss) Attributable to ConocoPhillips

(millions of dollars)

436

1,747

(2,371)

Average Net Production

Crude oil (MBD)

266

229

180

Natural gas liquids (MBD)

Natural gas (MMCFD)

622

596

898

Total Production

(MBOED)

451

397

399

Average Sales Prices

Crude oil (per bbl)

55.30

62.99

47.36

Natural gas liquids (per bbl)

16.83

27.30

22.20

Natural gas (per mcf)

2.12

2.82

2.73

The Lower 48 segment consists of operations located in the

contiguous U.S.

and the Gulf of Mexico.

During

2019, the Lower 48 contributed 41 percent of our consolidated

liquids production and 35 percent of our

natural

gas production.

2019 vs. 2018

Lower 48 reported earnings of $436 million

in 2019, compared with $1,747 million in 2018.

Earnings

decreased primarily due to lower realized crude oil,

NGL and natural gas prices; higher DD&A due

increased production volumes; a $301 million after-tax impairment

of our Niobrara assets; higher exploration

expenses, primarily due to a combined $197 million

after-tax of leasehold impairment and dry hole costs

associated with our decision to discontinue exploration

activities in the Central Louisiana Austin Chalk; and

lower earnings in equity affiliates due to a combined $120

million after-tax of impairments associated with a

fair value reduction of our investment in MWCC

and the disposition of our interests in the Golden

Pass LNG

Terminal and Golden Pass Pipeline.

Partly offsetting the decrease in earnings were

increased crude oil and

NGL sales volumes in the Eagle Ford, Bakken and Permian

Unconventional.

For additional information related to our impairment

of MWCC, see Note 3—Variable Interest Entities in the

Notes to Consolidated Financial Statements.

For more information related to the sale of

our interests in

Golden Pass LNG Terminal and Golden Pass Pipeline, see Note 5—Asset Acquisitions

and Dispositions in the

Notes to Consolidated Financial Statements.

Total average production increased 54 MBOED in 2019 compared with 2018.

The increase was primarily due

to new production from unconventional assets in Eagle

Ford, Bakken and the Permian Basin, partly

offset by

normal field decline.

Additionally, production decreased by 10

MBOED due to non-core dispositions

in 2018.

Asset Dispositions

Update

In January 2019, we entered into agreements to

sell our 12.4 percent ownership interests in

the Golden Pass

LNG Terminal and Golden Pass Pipeline.

We have also entered into agreements to amend our contractual

obligations for retaining use of the facilities.

As a result of entering into these agreements,

we recognized a

before-tax impairment of $60 million in the first quarter

of 2019 which is included in the “Equity in earnings

of affiliates” line on our consolidated income statement.

completed the sale in the second quarter of 2019.

See Note 15—Fair Value Measurement in the Notes to Consolidated Financial Statements, for additional

information.

In the fourth quarter of 2019, we sold our interests in

the Magnolia field and platform and

recognized an

after-

tax gain of $63 million.

Production from Magnolia in 2019

was less than one MBOED.

In the fourth quarter of 2019, we signed an agreement

to sell our interests in the Niobrara shale

play for $380

million, plus customary adjustments,

and overriding royalty interests in certain future

wells.

recorded an

after-tax impairment of $301 million in the fourth quarter

to reduce the carrying value to fair value.

Production from Niobrara was approximately 11 MBOED

in 2019.

This transaction is subject to regulatory

approval and other conditions precedent and is expected

to close in the first quarter of 2020.

In January 2020, we entered into an agreement

to sell our interests in certain non-core properties

in the Lower

48 segment for $186 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.

For additional information on these transactions,

see Note 5—Asset Acquisitions and Dispositions,

in the

Notes to Consolidated Financial Statements.

2018 vs. 2017

Lower 48 reported earnings of $1,747 million

in 2018, compared with a net loss of $2,371

million in 2017.

Earnings increased primarily due to the absence of

a combined $2.5 billion after-tax impairment related to

the

sale of our interests in the San Juan Basin and the marketing

of our Barnett asset, recognized in the second

quarter of 2017; higher realized crude oil and NGL

prices; higher crude oil sales volumes;

lower DD&A

expense, primarily due to reserve additions and asset

disposition impacts, partly offset by higher underlying

volumes; lower exploration expenses and higher gain

on dispositions related to noncore asset

sales.

The

increase in earnings was partly offset by lower natural

gas sales volumes, primarily due to the disposition

our interests in the San Juan Basin in 2017.

In 2018, our average realized crude oil price of $62.99

per barrel was 3 percent less than WTI

of $64.92 per

barrel.

The differential was driven primarily by local market

dynamics in the Gulf Coast, Bakken and Permian

Basin.

Consolidated production decreased 1 percent in 2018

compared with 2017.

The decrease was mainly

attributable to normal field decline and disposition

impacts related to interests sold in the San

Juan Basin and

other noncore assets.

Adjusted for the impact of dispositions

of 82 MBOED in 2017, underlying production

increased approximately 25 percent in 2018 compared

with 2017, primarily due to new production from

unconventional assets in the Eagle Ford, Bakken and Permian

Basin.

Asset Dispositions

In the first quarter of 2018, we completed the sale

of certain properties in the Lower 48 segment

for net

proceeds of $112 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

for net proceeds of $105 million.

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.

This transaction was recorded at fair value resulting

in the

recognition of a $44 million after-tax gain.

In the fourth quarter of 2018, we sold

several packages of

undeveloped acreage in the Lower 48 segment for total

net proceeds of $162 million and recognized

gains of

approximately $140 million.

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

our interests in the Barnett to Lime Rock Resources

for

$196 million after customary adjustments.

Production associated with the Barnett

averaged 8 MBOED in

2018, of which approximately 55 percent was natural gas

and 45 percent was natural gas liquids.

After-tax

impairment charges of $69 million were recognized during

2018.

On July 31, 2017, we completed the sale of our interests

in the San Juan Basin for total proceeds

comprised of

$2.5 billion in cash after customary adjustments

and 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 million

British thermal units.

During 2018, we recorded gains

on dispositions for these contingent payments

of $28 million.

On September 29, 2017, we completed the sale of

our interest in the Panhandle assets for $178

million in cash

after customary adjustments.

See Note 5—Asset Acquisitions and Dispositions in the

Notes to Consolidated Financial Statements, for

additional information.

Canada

2019

2018

2017

Net Income Attributable to ConocoPhillips

(millions of dollars)

279

2,564

Average Net Production

Crude oil (MBD)

Natural gas liquids (MBD)

Bitumen (MBD)

Consolidated operations

Equity affiliates

Total bitumen

122

Natural gas (MMCFD)

187

Total Production

(MBOED)

165

Average Sales Prices

Crude oil (per bbl)

40.87

48.73

43.69

Natural gas liquids (per bbl)

19.87

43.70

21.51

Bitumen (dollars per bbl)*

Consolidated operations

31.72

22.29

21.43

Equity affiliates

23.83

Total bitumen

31.72

22.29

22.66

Natural gas (per mcf)

0.49

1.00

1.93

*Average

prices for sales of bitumen produced

during 2018 and 2019 excludes additional

value realized from

the purchase and sale

of third-

party volumes for optimization

of our pipeline capacity between

Canada and the U.S. Gulf Coast.

Our Canadian operations consist of the Surmont oil

sands development in Alberta and the

liquids-rich

Montney unconventional play in British Columbia.

In 2019, Canada contributed 7 percent

of our consolidated

liquids production and less than one percent of our consolidated

natural gas production.

2019 vs. 2018

Canada operations reported earnings of $279 million

in 2019 compared with $63 million in 2018.

Earnings

increased mainly due to higher realized bitumen prices,

a $68 million tax benefit primarily comprised

of a

previously unrecognizable tax basis related to

a tax settlement, lower DD&A expense due to

lower rates from

reserve additions,

lower production and operating expenses,

and a $25 million tax benefit due to a four year

phased four percent reduction in Alberta’s corporate income tax rate.

Partly offsetting the increase in earnings

were lower sales volumes due to a planned turnaround

at Surmont,

lower production due to a mandated

production curtailment imposed by the Alberta government

in January 2019, and the absence of an $80 million

tax restructuring benefit.

Total average production decreased 7 MBOED in 2019 compared with 2018.

The production decrease was

primarily due to a turnaround at Surmont, which had an

annualized average impact of 3 MBOED, and a

mandated production curtailment imposed by the Alberta

government, which also impacted production by 3

MBOED.

The curtailment program is established and administered by

the Alberta Energy Regulator under the

Curtailment Rules regulation, which is currently set to

expire on December 31, 2020.

This program is

intended to strengthen the WCS differential to WTI at Hardisty.

Asset Disposition

On May 17, 2017, we completed the sale of our 50 percent

nonoperated interest in the FCCL Partnership, as

well as the majority of our western Canada gas assets

to Cenovus Energy.

Consideration for the transaction

was $11.0 billion in cash after customary adjustments, 208 million

Cenovus Energy common shares and a five

year uncapped contingent payment.

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.

During 2019 and 2018, we recorded after-tax gains on dispositions

for these contingent payments of $84

million and $68 million,

respectively.

See Note 5—Asset Acquisitions and Dispositions

in the Notes to

Consolidated Financial Statements, for additional information.

2018 vs. 2017

Canada operations reported earnings of $63 million

in 2018 compared with $2,564 million in 2017.

The

decrease was mainly due to the absence of a $1.6 billion

after-tax gain on the sale of our interest in the FCCL

Partnership and western Canada gas assets and an associated

$1.0 billion deferred tax benefit, and equity

earnings in the FCCL Partnership.

For additional information on the Canada

disposition, see Note 5—Asset

Acquisitions and Dispositions and Note 7—Investment

in Cenovus Energy, in the Notes to Consolidated

Financial Statements.

Total average production decreased 95 MBOED in 2018 compared with 2017.

The production decrease was

primarily due to our 2017 Canada disposition, partly

offset by strong well performance at Surmont.

Acquisition

In February 2018, we acquired approximately 34,500 net

acres of undeveloped land in the Montney for a net

purchase price of approximately $120 million.

The additional acreage is adjacent to our existing

position in

the liquids-rich portion of the Montney.

Europe, Middle East and North Africa

2019

2018

2017

Net Income Attributable to ConocoPhillips

(millions of dollars)

3,170

2,594

1,116

Consolidated Operations

Average Net Production

Crude oil (MBD)

138

149

142

Natural gas liquids (MBD)

Natural gas (MMCFD)

478

503

484

Total Production

(MBOED)

224

241

230

Average Sales Prices

Crude oil (dollars per bbl)

64.94

70.71

54.21

Natural gas liquids (per bbl)

29.37

36.87

34.07

Natural gas (per mcf)

4.92

7.65

5.70

*Prior periods have been

updated to reflect the Middle East

Business Unit moving

from Asia Pacific to the Europe,

Middle East and North

Africa segment.

See Note 25—Segment

Disclosures and

Related Information in the Notes to Consolidated

Financial Statements for additional

information.

The Europe,

Middle East and North Africa segment consisted

of operations principally located in the

Norwegian and U.K. sectors of the North Sea, the Norwegian

Sea, Qatar and Libya.

In 2019, our Europe,

Middle East and North Africa operations contributed 17

percent of our consolidated liquids production and

percent of our natural gas production.

2019 vs. 2018

Earnings for Europe, Middle East and North Africa operations

of $3,170 million increased $576 million in

2019 compared with 2018.

The increase

in earnings was primarily due to a $2.1 billion

after-tax gain

associated with the completion of the sale of two

ConocoPhillips U.K. subsidiaries to Chrysaor

E&P Limited.

Earnings also increased due to the cessation of DD&A in

the second quarter of 2019 for our disposed

U.K.

subsidiaries when these assets became held-for-sale.

Partly offsetting the increase in earnings were

the

absence of a $774 million after-tax gain related to the

sale of a ConocoPhillips subsidiary to BP, which held

16.5 percent of our 24 percent interest in the BP-operated

Clair Field in the U.K.; lower sales volumes

primarily due to the U.K. disposition to Chrysaor completed

September 30, 2019; lower earnings in equity

affiliates, primarily due to a deferred tax adjustment at QG3

that resulted in a $118 million reduction to equity

earnings; and lower realized natural gas and crude oil

prices.

Consolidated production decreased 7 percent in 2019,

compared with 2018.

The decrease was mainly due to

normal field decline and a 20 MBOED disposition impact

from the sale of our U.K. assets to Chrysaor

completed September 30, 2019.

Partly offsetting these production decreases were

volumes from new wells

online in Norway,

including the Aasta Hansteen Field which

achieved first production in December of

2018.

Asset Disposition Update

On September 30, 2019, we completed the sale of two ConocoPhillips

U.K. subsidiaries to Chrysaor E&P

Limited for proceeds of $2.2 billion after interest

and customary adjustments.

In 2019, we recorded a $1.7

billion before-tax and $2.1 billion after-tax gain associated

with this transaction.

Together the subsidiaries

sold indirectly held our exploration and production assets

in the U.K.,

including $1.8 billion of ARO.

Annualized average production associated with the U.K. assets

sold was 50 MBOED in 2019.

Reserves

associated with the U.K. assets sold were 84 MMBOE

at the time of disposition.

For additional information,

see Note 5—Asset Acquisitions and Dispositions in

the Notes to Consolidated Financial Statements.

2018 vs. 2017

Earnings for Europe, Middle East and North Africa operations

of $2,594 million increased $1,478 million in

2018 compared to 2017.

Earnings in 2018 included a $774

million after-tax gain related to the sale of a

ConocoPhillips subsidiary to BP, which held 16.5 percent of our 24 percent interest in the BP-operated Clair

Field in the United Kingdom.

Earnings were also improved due to higher

realized crude oil and natural gas

prices; increased equity earnings due to higher LNG

prices at QG3; and lower DD&A expense, primarily

due

to reserve additions.

Consolidated production increased 5 percent in 2018,

compared with 2017.

The increase was mainly due to

higher production in Libya and new wells online in

Norway and the United Kingdom.

These increases in

production were partly offset by normal field decline and the

final cessation of production in several producing

gas fields in the Southern North Sea in the third quarter

of 2018.

Production associated with the Southern

North Sea was 22 million cubic feet a day or 4 MBOED in

2018.

Disposition

In the fourth quarter of 2018, we completed a transaction

to sell a ConocoPhillips subsidiary to BP, which held

16.5 percent of our 24 percent interest in the BP-operated

Clair Field in the United Kingdom and acquire their

nonoperated interest in the Kuparuk Assets in Alaska.

In 2018, our Europe, Middle East and

North Africa

segment net production associated with the disposed

16.5 percent interest in the Clair Field was approximately

5 MBOED.

We recognized a $774 million after-tax gain in the fourth quarter related to this transaction, as

discussed above.

See Note 5—Asset Acquisitions and Dispositions

in the Notes to Consolidated Financial

Statements, for additional information.

Asia Pacific

2019

2018

2017

Net Income (Loss) Attributable to ConocoPhillips

(millions of dollars)

1,483

1,342

(1,661)

Consolidated Operations

Average Net Production

Crude oil (MBD)

Natural gas liquids (MBD)

Natural gas (MMCFD)

637

626

687

Total Production

(MBOED)

196

212

Average Sales Prices

Crude oil (dollars per bbl)

65.02

70.93

54.38

Natural gas liquids (dollars per bbl)

37.85

47.20

41.37

Natural gas (dollars per mcf)

5.91

6.15

4.98

*Prior periods have been

updated to reflect the Middle East

Business Unit moving

from Asia Pacific to the Europe,

Middle East and North

Africa

segment.

See Note 25—Segment

Disclosures and Related

Information in the Notes to Consolidated

Financial Statements for additional

information.

The Asia Pacific segment has operations in China, Indonesia,

Malaysia, Australia and Timor-Leste.

During

2019, Asia Pacific contributed 10 percent of our consolidated

liquids production and 36 percent of our natural

gas production.

2019 vs. 2018

Asia Pacific reported earnings of $1,483 million

in 2019, compared with $1,342 million in

2018.

The increase in

earnings was mainly due to a $164 million income

tax benefit related to deepwater incentive tax

credits from the

Malaysia Block G and a $52 million after-tax gain on disposition

of our interest in the Greater Sunrise Fields.

Partly offsetting this increase in earnings was lower realized

crude oil, NGL and natural gas prices and

lower

LNG and crude oil sales volumes.

Consolidated production was flat in 2019 compared

with 2018.

There were increases due to new production

from Malaysia, including first gas supply from KBB

to PFLNG1 in the second quarter of 2019 and

first oil from

Gumusut Phase 2 in the third quarter of 2019; and new wells

online in China, including Bohai Phase 3.

Offsetting these production increases

was normal field decline.

Asset Dispositions Update

In the second quarter of 2019, we recognized an after-tax

gain of $52 million upon completion of the sale of our

30 percent interest in the Greater Sunrise Fields to

the government of Timor-Leste for $350 million.

production or reserve impacts were associated with

the 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.

addition, we will receive a payment of $75 million

upon final investment decision of the Barossa development

project.

These subsidiaries hold our 37.5 percent interest

in the Barossa Project and Caldita Field, our 56.9

percent interest in the Darwin LNG Facility and Bayu-Undan

Field, our 40 percent interest in the Greater

Poseidon Fields, and our 50 percent interest in the Athena

Field.

This transaction is expected to be completed in

the first quarter of 2020, subject to regulatory approvals

and the satisfaction of other specific conditions

precedent.

In 2019, production associated with the Australia-West assets to be sold was

48 MBOED.

Year-end

2019 reserves associated with these assets were 17

MMBOE.

will retain our 37.5 percent interest in the

Australia Pacific LNG project and operatorship of that

project’s LNG facility.

See Note 5—Asset Acquisitions and Dispositions in the

Notes to Consolidated Financial Statements, for

additional information related to these dispositions.

2018 vs. 2017

Asia Pacific reported earnings of $1,342 million in 2018, compared

with a loss of $1,661 million in 2017.

The

increase in earnings was mainly due to the absence

of a $2,384 million before- and after-tax charge for

the

impairment of our APLNG investment in 2017, higher realized

commodity prices, and increased equity in

earnings of affiliates, mainly due to higher LNG prices at APLNG.

See the “APLNG” section of Note 6—

Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial

Statements, for

information on the 2017 impairment of our APLNG

investment.

Consolidated production decreased 8 percent in 2018,

compared with 2017.

The decrease was primarily due to

unplanned downtime in Malaysia related to the rupture of

a third-party pipeline which carries gas production

from the Kebabangan gas field in Malaysia and normal

field decline.

This decrease was partly offset by new

wells online at Malakai in Malaysia and an infill

drilling program in China.

Other International

2019

2018

2017

Net Income Attributable to ConocoPhillips

(millions of dollars)

263

364

167

The Other International segment includes exploration

activities in Colombia, Chile and Argentina and

contingencies associated with prior operations.

2019 vs. 2018

Other International operations reported earnings of $263 million

in 2019, compared with earnings of $364

million in 2018.

The decrease in earnings was primarily due to the recognition

of $417 million after-tax in

other income related to a settlement agreement with

PDVSA in 2018, compared with $317 million after-tax

associated with this settlement agreement in 2019.

In 2018 and 2019, we

collected approximately $0.8 billion

of the $2.0 billion settlement with PDVSA.

PDVSA has defaulted on its remaining payment obligations

under this agreement, we are therefore now forced

to incur additional costs as we seek to recover any unpaid

amounts under the agreement.

For additional

information, see Note 13—Contingencies and Commitments

in the Notes to Consolidated Financial

Statements.

Argentina

January 2019, we secured a 50 percent nonoperated interest

in the El Turbio Este Block,

within the Austral

Basin in southern Argentina.

In 2019, we acquired and processed 3-D seismic

covering 500 square miles,

with

evaluation of the data ongoing.

In November 2019, we acquired interests in two nonoperated

blocks in the Neuquén Basin targeting the Vaca

Muerta play.

We have a 50 percent interest in the Bandurria Norte Block and a 45 percent interest

in the

Aguada Federal Block.

In Bandurria Norte, 1 vertical and 4 horizontal

wells

were tested and shut-in during

2019.

In Aguada Federal, 2 horizontal wells were being

tested at the end of the year.

2018 vs. 2017

Other International operations reported earnings of $364 million

in 2018, compared with earnings of $167

million in 2017.

The increase in earnings was primarily due

to recognizing $417 million after-tax in other

income under a settlement agreement with PDVSA

associated with an arbitration award issued by the

ICC.

Partly offsetting the increase in earnings, was the absence of

a $320 million after-tax award from an arbitration

settlement with The Republic of Ecuador in 2017.

See Note 13—Contingencies and Commitments

in the

Notes to Consolidated Financial Statements, for additional

information.

Corporate and Other

Millions of Dollars

2019

2018

2017

Net Income (Loss) Attributable to ConocoPhillips

Net interest

(604)

(680)

(739)

Corporate general and administrative expenses

(252)

(91)

(193)

Technology

123

109

Other

771

(1,005)

(1,224)

(1,667)

(2,136)

2019 vs. 2018

Net interest consists of interest and financing expense,

net of interest income and capitalized interest.

Net

interest decreased $76 million in 2019 compared with

2018,

primarily due to lower capitalized interest on

projects; increased interest income from holding higher

cash balances; and lower interest on debt expense

resultant from the retirement of $4.7

billion of debt in 2018; partly offset by the absence of an

accrual

reduction due to a transportation cost ruling by the FERC.

Corporate G&A expenses include compensation programs

and staff costs.

These costs increased by $161

million in 2019 compared with 2018, primarily due to

higher costs associated with compensation and

benefits,

including certain key employee compensation programs

and higher facility costs.

Technology includes our investment in new technologies or businesses, as well as licensing revenues.

Activities are focused on both conventional and tight oil

reservoirs, shale gas, heavy oil, oil sands,

enhanced

oil recovery and LNG.

Earnings from Technology increased by $14 million in 2019 compared with 2018,

primarily due to higher licensing revenues.

The category “Other” includes certain foreign currency transaction

gains and losses, environmental costs

associated with sites no longer in operation, other costs not

directly associated with an operating segment,

premiums incurred on the early retirement of debt,

unrealized holding gains or losses on equity securities,

and

pension settlement expense.

Earnings in “Other” increased by $1,776 million

in 2019 compared with 2018,

primarily due to an unrealized gain of $649 million

after-tax on our CVE common shares in 2019, and the

absence of a $436 million after-tax unrealized loss on those shares in

2018.

Additionally, earnings increased

due to the absence of $195 million in premiums on

the early retirement of debt, lower pension settlement

expense, and a $151 million tax benefit related to the

revaluation of deferred tax assets following

finalization

of rules related to the 2017 Tax Cuts and Jobs Act.

See Note 19—Income Taxes, in the Notes to Consolidated

Financial Statements, for additional information related

to the 2017 Tax Cuts and Jobs Act.

2018 vs. 2017

Net interest consists of interest and financing expense,

net of interest income and capitalized interest.

Net

interest decreased $59 million in 2018 compared with

2017, primarily due to less interest from lower

debt

balances, higher capitalized interest on projects, and

an accrual reduction due to a transportation

cost ruling by

the FERC in the first quarter of 2018.

Partly offsetting these impacts, were reduced tax

benefits on interest

expense following the Tax Legislation, which lowered the U.S. corporate income

tax rate from 35 percent to

21 percent effective January 1, 2018, and a lower tax benefit

due to higher interest from the fair market value

method of apportioning interest expense in the United

States.

Corporate general and administrative expenses include

compensation programs and staff costs.

These costs

decreased by $102 million in 2018 compared with

2017, primarily due to lower staff expenses and

costs

associated with certain key employee compensation

programs.

Technology includes our investment in new technologies or businesses, as well as licensing

revenues.

Activities are focused on tight oil reservoirs, LNG,

oil sands and other production operations.

Earnings from

Technology increased by $89 million in 2018 compared with 2017, primarily due to

higher licensing revenues.

The category “Other” includes certain foreign currency

transaction gains and losses, environmental

costs

associated with sites no longer in operation, other

costs not directly associated with an

operating segment,

premiums incurred on the early retirement of debt,

unrealized holding gains or losses on equity

securities, and

pension settlement expense.

Losses in “Other” decreased by $219 million

in 2018 compared with 2017,

primarily due to the absence of an $813 million tax

charge from the revaluation of deferred taxes at a lower

federal statutory rate, in accordance with the Tax Legislation enacted in 2017; lower

premiums on the early

retirement of debt; partly offset by a $437 million unrealized

loss on our Cenovus Energy common shares.

CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators

Millions of Dollars

Except as Indicated

2019

2018

2017

Net cash provided by operating activities

11,104

12,934

7,077

Cash and cash equivalents

5,088

5,915

6,325

Short-term debt

105

112

2,575

Total debt

14,895

14,968

19,703

Total equity

35,050

32,064

30,801

Percent of total debt to capital*

Percent of floating-rate debt to total debt

*Capital includes total debt

and total equity.

To meet our short-

and long-term liquidity requirements, we look to a variety

of funding sources, including

cash generated from operating activities, proceeds from

asset sales, our commercial paper and credit facility

programs and our ability to sell securities using our

shelf registration statement.

In 2019, the primary uses of

our available cash were $6,636 million to support

our ongoing capital expenditures and investments

program;

$3,500 million to repurchase our common stock;

$2,910 million net purchases of investments, and

$1,500

million to pay dividends on our common stock.

During 2019, cash and cash equivalents decreased

by $827

million to $5,088 million.

believe current cash balances and cash generated

by operations, together with access to external

sources of

funds as described below in the “Significant Changes

in Capital” section, will be sufficient to meet

our funding

requirements in the near and long term, including our

capital spending program, share repurchases, dividend

payments and required debt payments.

Our commitment to disciplined execution of these

funding requirements includes cash

investment strategies

that position us for success in an environment of short-term

price volatility as well as extended downturns in

commodity prices.

The primary objectives of these cash investment

strategies in priority order are to protect

principal, maintain liquidity, and provide yield and total returns.

Funds for short-term needs to support

our

operating plan and provide resiliency to react to short-term

price volatility are invested in highly liquid

instruments with maturities within the year.

Funds we consider available to maintain resiliency

in longer term

price downturns and to capture opportunities outside

a given operating plan may be invested in instruments

with maturities greater than one year.

For additional information, see Note 1–Accounting

Policies and Note

14–Derivative and Financial Instruments.

Significant Changes in Capital

Operating Activities

During 2019, cash provided by operating activities was

$11,104 million, a 14 percent decrease from 2018.

The

decrease was primarily due to lower prices, lower collections

related to settlements reached with Ecuador and

PDVSA, and a pension contribution made in conjunction

with the sale of two U.K. subsidiaries, partially offset

by higher volumes.

While the stability of our cash flows from operating activities

benefits from geographic diversity, our short-

and long-term operating cash flows are highly dependent

upon prices for crude oil, bitumen, natural gas, LNG

and NGLs.

Prices and margins in our industry have historically

been volatile and are driven by market

conditions over which we have no control.

Absent other mitigating factors, as these prices

and margins

fluctuate, we would expect a corresponding change in

our operating cash flows.

The level of absolute production

volumes, as well as product and location mix, impacts

our cash flows.

Full-

year production averaged 1,348 MBOED in 2019.

Full-year production excluding Libya averaged

1,305

MBOED in 2019

and is expected to be 1,230 to 1,270 MBOED in 2020.

Future production is subject to

numerous uncertainties, including, among others, the volatile

crude oil and natural gas price environment,

which may impact investment decisions; the effects of price changes on

production sharing and variable-

royalty contracts; acquisition and disposition of fields;

field production decline rates; new technologies;

operating efficiencies; timing of startups and major turnarounds;

political instability; weather-related

disruptions; and the addition of proved reserves through

exploratory success and their timely and cost-effective

development.

While we actively manage these factors, production

levels can cause variability in cash flows,

although generally this variability has not been as

significant as that caused by commodity prices.

To maintain or grow our production volumes on an ongoing basis, we must continue to add

to our proved

reserve base.

Our proved reserves generally increase as prices rise

and decrease as prices decline.

In 2019,

our reserve replacement, which included a net decrease of

0.1 billion BOE from sales and purchases, was 100

percent.

Increased crude oil reserves accounted for

approximately 55 percent of the total change in reserves.

Our organic reserve replacement, which excludes the impact of

sales and purchases, was 117 percent in 2019.

Approximately 51 percent of organic reserve additions are

from Lower 48, 13 percent from Alaska, 12 percent

from Canada, 12 percent from Europe, Middle East and

North Africa and 12 percent from Asia Pacific.

In the five years ended December 31, 2019, our reserve

replacement, which included a decrease of

2.0 billion

BOE from sales and purchases, was negative 34 percent,

reflecting the impact of asset dispositions

and lower

prices during that period.

Our organic reserve replacement during the five years ended

December 31, 2019,

was 40 percent, reflecting development activities as well

as lower prices during that period.

Historically our reserve replacement has varied considerably

year to year contingent upon the timing of major

projects which may have long lead times between capital

investment and production.

In the last several years,

more of our capital has been allocated to short cycle time,

onshore, unconventional plays.

Accordingly, we

believe our recent success in replacing reserves can be

viewed on a trailing three-year basis.

In the three years ended December 31, 2019, our reserve

replacement was 23 percent, reflecting the impact

asset dispositions during that period.

Our organic reserve replacement during the three years

ended December

31, 2019, which excludes a decrease of 1.8 billion

BOE related to sales and purchases, was 143 percent,

reflecting reserve additions from development activities.

Reserve replacement represents the net change in proved reserves,

net of production, divided by our current

year production, as shown in our supplemental reserve table

disclosures. For additional information about our

2020 capital budget, see the “2020 Capital Budget” section

within “Capital Resources and Liquidity” and for

additional information on proved reserves, including both

developed and undeveloped reserves, see the “Oil

and Gas Operations” section of this report.

As discussed in the “Critical Accounting Estimates”

section, engineering estimates of proved reserves are

imprecise; therefore, each year reserves may be revised

upward or downward due

to the impact of changes in

commodity prices or as more technical data becomes available

on reservoirs.

We have reported revisions as

increases to reserves in the current period, however in prior

periods,

reported revisions as decreases to

reserves. It is not possible to reliably predict how revisions

will impact reserve quantities in the future.

Investing Activities

Proceeds from asset sales in 2019 were $3.0 billion.

completed the sale of two ConocoPhillips U.K.

subsidiaries to Chrysaor E&P Limited for $2.2 billion.

also completed the sale of several assets including

our 30 percent interest in the Greater Sunrise Fields for $350

million and received $106 million of contingent

payments from Cenovus Energy.

In the fourth quarter of 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.

In addition, we will receive a

payment of $75 million upon final investment decision

of the Barossa development project.

Also in the fourth

quarter of 2019, we signed an agreement to sell our interests

in the Niobrara shale play for $380 million, plus

customary adjustments,

and overriding royalty interests in certain future wells.

Both transactions are subject to

regulatory approval and other conditions precedent and expected

to close in the first quarter of 2020.

Investing activities in 2019 also included net purchases of

$2.9 billion of investments in short-term and long-

term

financial instruments. These investments

include time deposits, commercial paper as

well as debt

securities classified as available for sale.

The investment in short-term instruments was

$2.8 billion, the

remaining $0.1 billion was invested in long-term debt

securities.

For additional information, see Note 14–

Derivative and Financial Instruments.

Proceeds from asset sales in 2018 were $1.1 billion.

We completed several undeveloped acreage transactions

in our Lower 48 segment for a total of $267 million

after customary adjustments and another transaction in

our

Lower 48 segment for $112 million after customary adjustments.

completed the sale of our interests in the

Barnett to Lime Rock Resources for $196 million

after customary adjustments.

We also completed the sale of

a ConocoPhillips subsidiary to BP and received $253 million

net proceeds.

The subsidiary held 16.5 percent

of our 24 percent interest in the BP-operated Clair Field

in the U.K.

During 2018, we

received $95 million of

contingent payments from Cenovus Energy.

For additional information on our dispositions,

see Note 5—Asset Acquisitions and

Dispositions in the Notes

to Consolidated Financial Statements.

Commercial Paper and Credit Facilities

have a revolving credit facility totaling

$6.0 billion, expiring in May 2023.

Our revolving credit facility

may be used for direct bank borrowings, the issuance

of letters of credit totaling up to $500 million, or

support for our commercial paper program.

The revolving credit facility is broadly syndicated

among financial

institutions and does not contain any material

adverse change provisions or any covenants requiring

maintenance of specified financial ratios or credit

ratings.

The facility agreement contains a cross-default

provision relating to the failure to pay principal or

interest on other debt obligations of $200 million

or more

by ConocoPhillips, or any of its consolidated subsidiaries.

Credit facility borrowings may bear interest at a

margin above rates offered by certain designated banks in the

London interbank market or at a margin above the overnight

federal funds rate or prime rates offered by

certain designated banks in the U.S.

The agreement calls for commitment fees

on available, but unused,

amounts.

The agreement also contains early termination

rights if our current directors or their approved

successors cease to be a majority of the Board

of Directors.

The revolving credit facility supports the ConocoPhillips

Company $6.0 billion commercial paper program,

which is primarily a funding source for short-term working

capital needs.

Commercial paper maturities are

generally limited to 90 days.

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 and 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

Our current long-term debt ratings remained unchanged

in 2019 and are as follows:

Fitch - “A” with a “stable”

outlook; Moody’s Investors Services - “A3” with a “stable” outlook; and Standard

& Poor’s - “A” with a

stable outlook.

We do not have any ratings triggers on any of our corporate debt that would cause an

automatic default, and thereby impact our access to liquidity, in the event of

a downgrade of our credit rating.

If our credit rating were downgraded, it could increase

the cost of corporate debt available to us and restrict

our

access to the commercial paper markets.

If our credit rating were to deteriorate

to a level prohibiting us from

accessing the commercial paper market, we would still

be able to access funds under our revolving credit

facility.

Certain of our project-related contracts, commercial

contracts

and derivative instruments contain provisions

requiring us to post collateral.

Many of these contracts and instruments permit us to post

either cash or letters

of credit as collateral.

At December 31, 2019 and 2018, we had direct bank letters

of credit of $277 million

and $323 million, respectively, which secured performance obligations related to various

purchase

commitments incident to the ordinary conduct of business.

In the event of credit ratings downgrades, we may

be required to post additional letters of credit.

Shelf Registration

have a universal shelf registration statement

on file with the SEC under which we, as a

well-known

seasoned issuer, have the ability to issue and sell an indeterminate amount of

various types of debt and equity

securities.

Off-Balance Sheet Arrangements

As part of our normal ongoing business operations and

consistent with normal industry practice, we enter

into

numerous agreements with other parties to pursue

business opportunities, which share costs

and apportion

risks among the parties as governed by the agreements.

For information about guarantees, see Note 12—Guarantees,

in the Notes to Consolidated Financial

Statements, which is incorporated herein by reference.

Capital Requirements

For information about our capital expenditures

and investments, see the “Capital Expenditures”

section.

Our debt balance at December 31, 2019, was $14,895 million,

a decrease of $73 million from the balance at

December 31, 2018.

For more information on Debt, see Note

11—Debt, in the Notes to Consolidated

Financial Statements.

On January 30, 2019, we announced a quarterly dividend

of $0.305 per share.

The dividend was paid on

March 1, 2019, to stockholders of record at the close of

business on February 11, 2019.

On May 1, 2019, we

announced a quarterly dividend of $0.305 per share.

The dividend was paid on June 3, 2019, to stockholders

of record at the close of business on May 13, 2019.

July 11, 2019, we announced a quarterly dividend of

$0.305 per share.

The dividend was paid on September 3,

2019, to stockholders of record at the close of

business on July 22, 2019.

On October 7, 2019, we announced a 38 percent increase

in the quarterly dividend

to $0.42 per share.

The dividend was paid on December 2, 2019, to

stockholders of record at the close of

business on October 17, 2019.

In February 2020, we announced a quarterly

dividend of $0.42 per share,

payable March 2, 2020, to stockholders of record at the

close of business on February 14, 2020.

In late 2016, we initiated our current share repurchase program.

As of December 31, 2019, we had

announced

a total authorization to repurchase $15 billion of our

common stock.

We repurchased $3 billion in 2017, $3

billion in 2018 and $3.5 billion in 2019.

Of the remaining authorization, we expect to repurchase

$3 billion in

2020.

In February 2020, we announced that the Board

of Directors approved an increase to our

authorization

from $15 billion to $25 billion, to support our plan for future

share repurchases.

Whether we undertake these

additional repurchases is ultimately subject to numerous

considerations, market conditions and other factors.

See Risk Factors beginning on page 21 in our 2019

Annual Report on Form 10-K, “Our ability to

declare and

pay dividends and repurchase shares is subject to certain considerations.”

Since our share repurchase program

began in November 2016, we have repurchased 169 million

shares at a cost of $9.6 billion through December

31, 2019.

Contractual Obligations

The table below summarizes our aggregate contractual

fixed and variable obligations as of December

31, 2019:

Millions of Dollars

Payments Due by Period

Up to 1

Years

After

Total

Year

2–3

4–5

5 Years

Debt obligations (a)

14,175

1,018

605

12,534

Finance lease obligations (b)

720

157

141

335

Total debt

14,895

105

1,175

746

12,869

Interest on debt

11,339

856

1,671

1,603

7,209

Operating lease obligations (c)

1,050

379

377

145

149

Purchase obligations (d)

8,671

3,237

1,745

1,327

2,362

Other long-term liabilities

Pension and postretirement benefit

contributions (e)

1,375

440

540

395

Asset retirement obligations (f)

6,206

997

282

309

4,618

Accrued environmental costs (g)

171

Unrecognized tax benefits (h)

(h)

Total

43,789

6,124

5,823

4,546

27,296

(a)

Includes $204 million of net unamortized premiums,

discounts and debt issuance costs.

See Note 11—

Debt, in the Notes to Consolidated Financial Statements,

for additional information.

(b)

See Note 17—Non-Mineral Leases, in the Notes to

Consolidated Financial Statements, for

additional

information.

(c)

Includes $31 million of short-term leases that are not recorded

on our consolidated balance sheet.

See

Note 17—Non-Mineral Leases, in the Notes to Consolidated

Financial Statements, for additional

information.

(d)

Represents any agreement to purchase goods or

services that is enforceable and legally

binding and that

specifies all significant terms, presented on an undiscounted

basis.

Does not include purchase

commitments for jointly owned fields and facilities

where we are not the operator.

The majority of the purchase obligations are market-based

contracts related to our commodity business.

Product purchase commitments with third parties

totaled $2,426 million.

Purchase obligations of $5,111 million are related to agreements to access and utilize

the capacity of

third-party equipment and facilities, including pipelines

and LNG and product terminals, to transport,

process, treat and store commodities.

The remainder is primarily our net share of

purchase

commitments for materials and services for jointly

owned fields and facilities where we are the

operator.

(e)

Represents contributions to qualified and nonqualified

pension and postretirement benefit plans for

the

years 2020 through 2024.

For additional information related to expected benefit

payments subsequent to

2024, see Note 18—Employee Benefit Plans, in

the Notes to Consolidated Financial Statements.

(f)

Represents estimated discounted costs to retire and remove

long-lived assets at the end of their

operations.

(g)

Represents estimated costs for accrued environmental

expenditures presented on a discounted

basis for

costs acquired in various business combinations

and an undiscounted basis for all other accrued

environmental costs.

(h)

Excludes unrecognized tax benefits of $1,095 million

because the ultimate disposition and timing

of any

payments to be made with regard to such amounts

are not reasonably estimable.

Although unrecognized

tax benefits are not a contractual obligation, they are

presented in this table because they represent

potential demands on our liquidity.

Capital Expenditures and Investments

Millions of Dollars

2019

2018

2017

Alaska

1,513

1,298

815

Lower 48

3,394

3,184

2,136

Canada

368

477

202

Europe, Middle East and North Africa

708

877

872

Asia Pacific

584

718

482

Other International

Corporate and Other

190

Capital Program

6,636

6,750

4,591

Our capital expenditures and investments for the

three-year period ended December 31, 2019, totaled $18.0

billion.

The 2019 expenditures supported key exploration

and developments, primarily:

●

Development, appraisal and exploration activities

in the Lower 48, including Eagle Ford,

Permian

Unconventional, and Bakken.

●

Appraisal and development activities in Alaska related

to the Western North Slope; development

activities in the Greater Kuparuk Area and the Greater Prudhoe

Area; leasehold acquisition in the

Greater Kuparuk Area.

●

Development activities across assets in Norway, as well as for assets in the

U.K. that recently have

been sold.

●

Optimization of oil sands development and appraisal

activities in liquids-rich plays in Canada.

●

Signature bonus for Indonesia Corridor Block production

sharing contract, as well as continued

development in China, Malaysia, Australia, and Indonesia.

2020 CAPITAL BUDGET

In February 2020, we announced 2020 operating

plan capital of $6.5 billion to $6.7 billion.

The plan includes

funding for ongoing development drilling programs, major

projects, exploration and appraisal activities, as

well as base maintenance.

Capital spend is expected to be higher in the

first quarter largely from winter

construction and exploration and appraisal drilling

in Alaska.

This guidance does not include capital for

acquisitions.

For information on PUDs and the associated costs to develop

these reserves, see the “Oil and Gas Operations”

section in this report.

Contingencies

A number of lawsuits involving a variety of claims

arising in the ordinary course of business have been

filed

against ConocoPhillips.

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

the

placement, storage, disposal or release of certain

chemical, mineral and petroleum substances

at various active

and inactive sites.

regularly assess the need for accounting

recognition or disclosure of these

contingencies.

In the case of all known contingencies (other

than those related to income taxes), we

accrue a

liability when the loss is probable and the amount is

reasonably estimable.

If a range of amounts can be

reasonably estimated and no amount within the range

is a better estimate than any other amount,

then the

minimum of the range is accrued.

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

recoveries.

If applicable, we accrue receivables for

probable insurance or other third-party

recoveries.

With

respect to income tax-related contingencies, we use a

cumulative probability-weighted loss accrual in cases

where sustaining a tax position is less than certain.

Based on currently available information, we

believe it is remote that future costs related to known

contingent

liability exposures will exceed current accruals by an

amount that would have a material adverse

impact on our

consolidated financial statements.

For information on other contingencies,

see “Critical Accounting

Estimates” and Note 13—Contingencies and Commitments,

in the Notes to Consolidated Financial Statements.

Legal and Tax Matters

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.

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.

See Note 19—Income Taxes, in the Notes to Consolidated Financial Statements,

for

additional information about income tax-related contingencies.

Environmental

are subject to the same numerous international,

federal, state and local environmental laws and regulations

as other companies in our industry.

The most significant of these environmental laws

and regulations include,

among others, the:

●

U.S. Federal Clean Air Act, which governs air

emissions.

●

U.S. Federal Clean Water Act, which governs discharges to water bodies.

●

European Union Regulation for Registration, Evaluation,

Authorization and Restriction of Chemicals

(REACH).

●

U.S. Federal Comprehensive Environmental Response,

Compensation and Liability Act (CERCLA

Superfund), which imposes liability on generators, transporters

and arrangers of hazardous substances

at sites where hazardous substance releases have

occurred or are threatening to occur.

●

U.S. Federal Resource Conservation and Recovery

Act (RCRA), which governs the treatment,

storage

and disposal of solid waste.

●

U.S. Federal Oil Pollution Act of 1990 (OPA90), under which owners and operators

of onshore

facilities and pipelines, lessees or permittees of an area

in which an offshore facility is located, and

owners and operators of vessels are liable for removal

costs and damages that result from a discharge

of oil into navigable waters of the U.S.

●

U.S. Federal Emergency Planning and Community Right-to-Know

Act (EPCRA), which requires

facilities to report toxic chemical inventories with

local emergency planning committees and response

departments.

●

U.S. Federal Safe Drinking Water Act, which governs the disposal of wastewater in

underground

injection wells.

●

U.S. Department of the Interior regulations, which relate

to offshore oil and gas operations in U.S.

waters and impose liability for the cost of pollution

cleanup resulting from operations, as well as

potential liability for pollution damages.

●

European Union Trading Directive resulting in European Emissions

Trading Scheme.

These laws and their implementing regulations set

limits on emissions and, in the case of discharges to water,

establish water quality limits and establish standards

and impose obligations for the remediation of releases

hazardous substances and hazardous wastes.

They also, in most cases, require permits

in association with new

or modified operations.

These permits can require an applicant to collect

substantial information in connection

with the application process, which can be expensive

and time consuming.

In addition, there can be delays

associated with notice and comment periods and the

agency’s processing of the application.

Many of the

delays associated with the permitting process are

beyond the control of the applicant.

Many states and foreign countries where we operate

also have, or are developing, similar environmental

laws

and regulations governing these same types of activities.

While similar, in some cases these regulations may

impose additional, or more stringent, requirements

that can add to the cost and difficulty of marketing or

transporting products across state and international

borders.

The ultimate financial impact arising from environmental

laws and regulations is neither clearly known nor

easily determinable as new standards, such as air emission

standards and water quality standards, continue

evolve.

However, environmental laws and regulations, including those

that may arise to address concerns

about global climate change, are expected to continue

to have an increasing impact on our operations

in the

U.S.

and in other countries in which we operate.

Notable areas of potential impacts include air emission

compliance and remediation obligations in the U.S.

and Canada.

An example is the use of hydraulic fracturing, an

essential completion technique that facilitates

production of

oil and natural gas otherwise trapped in lower

permeability rock formations.

A range of local, state, federal or

national laws and regulations currently govern hydraulic

fracturing operations, with hydraulic fracturing

currently prohibited in some jurisdictions.

Although hydraulic fracturing has been conducted

for many

decades, a number of new laws, regulations and permitting

requirements are under consideration by various

state environmental agencies, and others which could

result in increased costs, operating restrictions,

operational delays and/or limit the ability to

develop oil and natural gas resources.

Governmental restrictions

on hydraulic fracturing could impact the overall profitability

or viability of certain of our oil and natural gas

investments.

We have adopted operating principles that incorporate established industry standards designed

meet or exceed government requirements.

Our practices continually evolve as technology

improves and

regulations change.

also are subject to certain laws and regulations relating

to environmental remediation obligations

associated with current and past operations.

Such laws and regulations include CERCLA and RCRA

and their

state equivalents.

Longer-term expenditures are subject to

considerable uncertainty and may fluctuate

significantly.

occasionally receive requests for information

or notices of potential liability from the EPA and state

environmental agencies alleging we are a potentially

responsible party under CERCLA or an equivalent

state

statute.

On occasion, we also have been made

a party to cost recovery litigation by those agencies

or by

private parties.

These requests, notices and lawsuits

assert potential liability for remediation costs

at various

sites that typically are not owned by us, but allegedly

contain wastes attributable to our past operations.

As of

December 31, 2019, there were 15 sites around the

U.S.

in which we were identified as a potentially

responsible party under CERCLA and comparable

state laws.

For most Superfund sites, our potential liability

will be significantly less than the total site remediation

costs

because the percentage of waste attributable to us, versus

that attributable to all other potentially responsible

parties, is relatively low.

Although liability of those potentially

responsible is generally joint and several for

federal sites and frequently so for state sites, other

potentially responsible parties at sites where we are a

party

typically have had the financial strength to meet their

obligations, and where they have not, or

where

potentially responsible parties could not be located,

our share of liability has not increased materially.

Many of

the sites at which we are potentially responsible are

still under investigation by the EPA or the state agencies

concerned.

Prior to actual cleanup, those potentially

responsible normally assess site conditions,

apportion

responsibility and determine the appropriate remediation.

In some instances, we may have no liability or attain

a settlement of liability.

Actual cleanup costs generally occur after the parties

obtain EPA or equivalent state

agency approval.

There are relatively few sites where we are a major participant,

and given the timing and

amounts of anticipated expenditures, neither the

cost of remediation at those sites nor such costs

at all

CERCLA sites, in the aggregate, is expected to have

a material adverse effect on our competitive or financial

condition.

Expensed environmental costs were $511 million in 2019 and are

expected to be about $545 million per year

in 2020 and 2021.

Capitalized environmental costs were $194

million in 2019 and are expected to be about

$225 million per year in 2020 and 2021.

Accrued liabilities for remediation activities are not reduced

for potential recoveries from insurers or other

third parties and are not discounted (except those assumed

in a purchase business combination, which we do

record on a discounted basis).

Many of these liabilities result from CERCLA,

RCRA and similar state or international laws that

require us to

undertake certain investigative and remedial activities

at sites where we conduct, or once conducted,

operations or at sites where ConocoPhillips-generated waste

was disposed.

The accrual also includes a number

of sites we identified that may require environmental

remediation, but which are not currently the subject of

CERCLA, RCRA or other agency enforcement activities.

The laws that require or address environmental

remediation may apply retroactively and regardless of

fault, the legality of the original activities or the current

ownership or control of sites.

If applicable, we accrue receivables for probable

insurance or other third-party

recoveries.

In the future, we may incur significant

costs under both CERCLA and RCRA.

Remediation activities vary substantially in duration and

cost from site to site, depending on the mix of unique

site characteristics, evolving remediation technologies,

diverse regulatory agencies and enforcement policies,

and the presence or absence of potentially liable third

parties.

Therefore, it is difficult to develop reasonable

estimates of future site remediation costs.

At December 31, 2019, our balance sheet included

total accrued environmental costs of $171 million,

compared with $178 million at December 31, 2018, for

remediation activities in the U.S. and Canada.

expect to incur a substantial amount of these expenditures

within the next 30 years.

Notwithstanding any of the foregoing, and as with

other companies engaged in similar businesses,

environmental costs and liabilities are inherent

concerns in our operations and products, and there

can be no

assurance that material costs and liabilities will not be

incurred.

However, we currently do not expect any

material adverse effect upon our results of operations or financial

position as a result of compliance with

current environmental laws

and regulations.

Climate Change

Continuing political and social attention to the

issue of global climate change has resulted

in a broad range of

proposed or promulgated state, national and international

laws focusing on GHG reduction.

These proposed or

promulgated laws apply or could apply in countries

where we have interests or may have interests

in the future.

Laws in this field continue to evolve, and while it

is not possible to accurately estimate either

a timetable for

implementation or our future compliance costs relating

to implementation, such laws, if enacted, could

have a

material impact on our results of operations and financial

condition.

Examples of legislation or precursors for

possible regulation that do or could affect our operations

include:

●

European Emissions Trading Scheme (ETS), the program through

which many of the EU member

states are implementing the Kyoto Protocol.

Our cost of compliance with the EU

ETS in 2019 was

approximately $8 million before-tax.

●

The Alberta Carbon Competitiveness Incentive Regulation

(CCIR) requires any existing facility with

emissions equal to or greater than 100,000 metric tonnes

of carbon dioxide, or equivalent, per year to

meet an industry benchmark intensity.

The total cost of these regulations in 2019 was approximately

$4 million.

●

The U.S. Supreme Court decision in Massachusetts v. EPA, 549 U.S. 497, 127 S.Ct. 1438 (2007),

confirmed that the EPA has the authority to regulate carbon dioxide as an “air pollutant” under

the

Federal Clean Air Act.

●

The U.S. EPA’s

announcement on March 29, 2010 (published as

“Interpretation of Regulations that

Determine Pollutants Covered by Clean Air Act

Permitting Programs,” 75 Fed. Reg. 17004 (April

2010)), and the EPA’s

and U.S. Department of Transportation’s joint promulgation of a Final Rule on

April 1, 2010, that triggers regulation of GHGs

under the Clean Air Act, may trigger more climate-

based claims for damages, and may result in longer agency

review time for development projects.

●

The U.S. EPA’s

announcement on January 14, 2015, outlining a series of

steps it plans to take to

address methane and smog-forming volatile organic compound

emissions from the oil and gas

industry.

The former U.S. administration established a

goal of reducing the 2012 levels in methane

emissions from the oil and gas industry by 40 to 45 percent

by 2025.

●

Carbon taxes in certain jurisdictions.

Our cost of compliance with Norwegian carbon

tax legislation

in 2019 was approximately $30 million (net share before-tax).

We also incur a carbon tax for

emissions from fossil fuel combustion in our British

Columbia and Alberta Operations totaling just

over $0.8

million (net share before-tax).

●

The agreement reached in Paris in December 2015

at the 21

Conference of the Parties to the United

Nations Framework on Climate Change, setting out a

new process for achieving global emission

reductions.

While the U.S.

announced its intention to withdraw from the Paris

Agreement, there is no

guarantee that the commitments made by the U.S.

will not be implemented, in whole or in part,

U.S. state and local governments or by major corporations

headquartered in the U.S.

In the U.S., some additional form of regulation

may be forthcoming in the future at the federal

and state levels

with respect to GHG emissions.

Such regulation could take any of several

forms that may result in the creation

of additional costs in the form of taxes, the restriction of

output, investments of capital to maintain compliance

with laws and regulations, or required acquisition

or trading of emission allowances.

We are working to

continuously improve operational and energy efficiency through

resource and energy conservation throughout

our operations.

Compliance with changes in laws and regulations

that create a GHG tax, emission trading scheme

or GHG

reduction policies could significantly increase our

costs, reduce demand for fossil energy derived products,

impact the cost and availability of capital and increase

our exposure to litigation.

Such laws and regulations

could also increase demand for less carbon intensive

energy sources, including natural gas.

The ultimate

impact on our financial performance, either positive or

negative, will depend on a number of factors,

including

but not limited to:

●

Whether and to what extent legislation or regulation

is enacted.

●

The timing of the introduction of such legislation

or regulation.

●

The nature of the legislation (such as a cap and trade system

or a tax on emissions) or regulation.

●

The price placed on GHG emissions (either by the

market or through a tax).

●

The GHG reductions required.

●

The price and availability of offsets.

●

The amount and allocation of allowances.

●

Technological and scientific developments leading to new products or services.

●

Any potential significant physical effects of climate change

(such as increased severe weather events,

changes in sea levels and changes in temperature).

●

Whether, and the extent to which, increased compliance costs are ultimately

reflected in the prices of

our products and services.

The company has responded by putting in place a

Sustainable Development Risk Management

Standard

covering the assessment and registering of significant

and high sustainable development risks based on their

consequence and likelihood of occurrence.

We have developed a company-wide Climate Change Action Plan

with the goal of tracking mitigation activities for

each climate-related risk included in the corporate

Sustainable Development Risk Register.

The risks addressed in our Climate Change Action

Plan fall into four broad categories:

●

GHG-related legislation and regulation.

●

GHG emissions management.

●

Physical climate-related impacts.

●

Climate-related disclosure and reporting.

Emissions are categorized into different scopes.

Scope 1 and Scope 2 GHG emissions help

us understand

climate transition risk.

Scope 1 emissions are direct GHG

emissions from sources that we own or control.

Scope 2 emissions are GHG emissions from the generation

of purchased electricity or steam that we consume.

Our corporate authorization process requires all

qualifying projects to run a GHG pricing

sensitivity using a

corporate price of $40 per tonne of carbon dioxide equivalent,

plus annual inflation, for all Scope 1 and Scope

2 GHG emissions produced in 2024 and later.

Projects in jurisdictions with existing GHG

pricing regimes

must incorporate that existing GHG price and its

forecast into their base case economics.

Where the existing

GHG price is below the corporate price, the $40 per

tonne of carbon dioxide equivalent sensitivity must

also be

run from 2024 onward.

Thus, both existing and emerging regulatory requirements

are considered in our

decision-making.

The company does not use an estimated

market cost of GHG emissions when assessing

reserves in jurisdictions without existing GHG

regulations.

In December 2018, we became a founding member

of the CLC, an international policy institute

founded in

collaboration with business and environmental interests

to develop a carbon dividend plan.

Participation in the

CLC provides another opportunity for ongoing dialogue

about carbon pricing and framing the issues in

alignment with our public policy principles.

We also belong to and fund Americans For Carbon Dividends,

the education and advocacy branch of the CLC.

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

in California, New York, Washington,

Rhode Island

and Maryland, as well as the Pacific Coast Federation

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

against oil and gas companies, including ConocoPhillips,

seeking compensatory damages and equitable relief

to abate alleged climate change impacts.

ConocoPhillips is vigorously defending against

these lawsuits.

The

lawsuits brought by the Cities of San Francisco,

Oakland and New York have been dismissed by the district

courts and appeals are pending.

Lawsuits filed by other cities and counties

in California and Washington are

currently stayed pending resolution of the appeals

brought by the Cities of San Francisco and

Oakland to the

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

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.

Other

have deferred tax assets related to certain

accrued liabilities, loss carryforwards and

credit carryforwards.

Valuation

allowances have been established to reduce

these deferred tax assets to an amount that will,

likely than not, be realized.

Based on our historical taxable income,

our expectations for the future, and

available tax-planning strategies, management expects

the net deferred tax assets will be realized as

offsets to

reversing deferred tax liabilities.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in conformity

with GAAP requires management to select

appropriate

accounting policies and to make estimates and

assumptions that affect the reported amounts of assets,

liabilities, revenues and expenses.

See Note 1—Accounting Policies, in the Notes to Consolidated

Financial

Statements, for descriptions of our major accounting policies.

Certain of these accounting policies involve

judgments and uncertainties to such an extent there

is a reasonable likelihood materially different amounts

would have been reported under different conditions, or if

different assumptions had been used.

These critical

accounting estimates are discussed with the Audit

and Finance Committee of the Board of Directors

at least

annually.

We believe the following discussions of critical accounting estimates, along with

the discussion of

deferred tax asset valuation allowances in this report,

address all important accounting areas where

the nature

of accounting estimates or assumptions is material due

to the levels of subjectivity and judgment

necessary to

account for highly uncertain matters or the susceptibility

of such matters to change.

Oil and Gas Accounting

Accounting for oil and gas exploratory activity is

subject to special accounting rules unique to the

oil and gas

industry.

The acquisition of geological and geophysical

seismic information, prior to the discovery of proved

reserves, is expensed as incurred, similar to accounting

for research and development costs.

However,

leasehold acquisition costs and exploratory well

costs are capitalized on the balance sheet pending

determination of whether proved oil and gas reserves

have been recognized.

Property Acquisition Costs

For individually significant leaseholds, management

periodically assesses for impairment based

on exploration

and drilling efforts to date.

For relatively small individual

leasehold acquisition costs, management exercises

judgment and determines a percentage probability

that the prospect ultimately will fail to find proved oil

and

gas reserves and pools that leasehold information

with others in the geographic area.

For prospects in areas

with limited, or no, previous exploratory drilling,

the percentage probability of ultimate failure is

normally

judged to be quite high.

This judgmental percentage is multiplied

by the leasehold acquisition cost, and that

product is divided by the contractual period of the leasehold

to determine a periodic leasehold impairment

charge that is reported in exploration expense.

This judgmental probability percentage is reassessed

and

adjusted throughout the contractual period of the leasehold

based on favorable or unfavorable exploratory

activity on the leasehold or on adjacent leaseholds,

and leasehold impairment amortization expense is

adjusted

prospectively.

At year-end 2019, the remaining $3.5 billion of net

capitalized unproved property costs consisted primarily

individually significant leaseholds, mineral rights

held in perpetuity by title ownership, exploratory

wells

currently being drilled, suspended exploratory wells,

and capitalized interest.

Of this amount, approximately

$2.1 billion is concentrated in 10 major development areas,

the majority of which are not expected to move

proved properties in 2020, and $0.6 billion is held for sale.

Management periodically assesses individually

significant leaseholds for impairment based on

the results of exploration and drilling efforts and the outlook

for

commercialization.

Exploratory Costs

For exploratory wells, drilling costs are temporarily capitalized,

or “suspended,” on the balance sheet, pending

a determination of whether potentially economic

oil and gas reserves have been discovered

by the drilling

effort to justify development.

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.

The accounting notion of “sufficient progress” is a judgmental

area, but

the accounting rules do prohibit continued capitalization

of suspended well costs on the expectation

future

market conditions will improve or new technologies

will be found that would make the development

economically profitable.

Often, the ability to move into the development

phase and record proved reserves is

dependent on obtaining permits and government or

co-venturer approvals, the timing of which is ultimately

beyond our control.

Exploratory well costs remain suspended as long as we

are actively pursuing such

approvals and permits, and believe they will

be obtained.

Once all required approvals and permits have been

obtained, the projects are moved into the development

phase, and the oil and gas reserves are designated

proved reserves.

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 a determination is made the well did not

encounter potentially

economic oil and gas quantities, the well costs

are expensed as a dry hole and reported in exploration

expense.

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 a dry hole when it determines

the potential field does not warrant further investment

in the near term.

Criteria utilized in making this

determination include evaluation of the reservoir characteristics

and hydrocarbon properties, expected

development costs, ability to apply existing technology

to produce the reserves, fiscal terms, regulations

contract negotiations, and our expected return on

investment.

At year-end 2019, total suspended well costs

were $1,020 million, compared with $856 million at

year-end

2018.

For additional information on suspended wells,

including an aging analysis, see Note 8—Suspended

Wells and Other Exploration Expenses, in the Notes to Consolidated Financial

Statements.

Proved Reserves

Engineering estimates of the quantities of proved reserves

are inherently imprecise and represent only

approximate amounts because of the judgments involved

in developing such information.

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.

The reliability of these estimates at any point

in time depends on both the quality and

quantity of the technical and economic data and the

efficiency of extracting and processing the hydrocarbons.

Despite the inherent imprecision in these engineering

estimates, accounting rules require disclosure of

“proved” reserve estimates due to the importance

of these estimates to better understand

the perceived value

and future cash flows of a company’s operations.

There are several authoritative guidelines

regarding the

engineering criteria that must be met before estimated

reserves can be designated as “proved.”

Our

geosciences and reservoir engineering organization has policies

and procedures in place consistent with these

authoritative guidelines.

We have trained and experienced internal engineering personnel who estimate our

proved reserves held by consolidated companies, as

well as our share of equity affiliates.

Proved reserve estimates are adjusted annually in the fourth

quarter and during the year if significant changes

occur, and take into account recent production and subsurface information

about each field.

Also, as required

by current authoritative guidelines, the estimated

future date when an asset will be permanently shut

down for

economic reasons is based on 12-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, 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.

We would expect reserves from these contracts to

decrease when product prices rise and increase

when prices decline.

The estimation of proved developed reserves also

is important to the income statement because

the proved

developed reserve estimate for a field serves as the denominator

in the unit-of-production calculation of the

DD&A of the capitalized costs for that asset.

At year-end 2019, the net book value of productive

PP&E

subject to a unit-of-production calculation was approximately

$35 billion and the DD&A recorded on these

assets in 2019 was approximately $5.8

billion.

The estimated proved developed reserves for

our consolidated

operations were 3.3 billion BOE at the end of 2018 and

3.2

billion BOE at the end of 2019.

If the estimates of

proved reserves used in the unit-of-production calculations

had been lower by 10 percent across all

calculations, before-tax DD&A in 2019 would have

increased by an estimated $642 million.

Impairments

Long-lived assets used in operations are assessed for

impairment whenever changes in facts

and circumstances

indicate a possible significant deterioration in 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.

Individual assets

are grouped for impairment purposes based on a judgmental

assessment of 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,

based on a multiple of operating cash flow validated

with historical market transactions of similar assets where

possible.

The expected future cash flows used for impairment

reviews and related fair value calculations are

based on judgmental assessments of future production volumes,

commodity prices, operating costs and

capital

decisions, considering all available information at

the date of review.

Differing assumptions could affect the

timing and the amount of an impairment in any period.

See Note 9—Impairments, in the Notes to

Consolidated Financial Statements, for additional

information.

Investments in nonconsolidated entities accounted

for under the equity method are reviewed for

impairment

when there is evidence of a loss in value and annually

following updates to corporate planning assumptions.

Such evidence of a loss in value might include our

inability to recover the carrying amount, the

lack of

sustained earnings capacity which would justify

the current investment amount, or a current fair value less

than

the investment’s carrying amount.

When it is determined such a loss in value is

other than temporary, an

impairment charge is recognized for the difference between

the investment’s carrying value and its estimated

fair value.

When determining whether a decline in value is

other than temporary, management considers

factors such as the length of time and extent of

the decline, the investee’s financial condition and near-term

prospects, and our ability and intention to retain our

investment for a period that will be sufficient to allow

for

any anticipated recovery in the market value of the

investment.

Since quoted market prices are usually not

available, the fair value is typically based on 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

comparable assets owned by the investee, if appropriate.

Differing assumptions could affect the timing and the

amount of an impairment of an investment in any period.

See the “APLNG” section of Note 6—Investments,

Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements,

for additional

information.

Asset Retirement Obligations and Environmental Costs

Under various contracts, permits and regulations,

we have material legal obligations to remove tangible

equipment and restore the land or seabed at the

end of operations at operational sites.

Our largest asset

removal obligations involve plugging and abandonment

of wells, removal and disposal of offshore oil

and gas

platforms around the world,

as well as oil and gas production

facilities and pipelines in Alaska.

The fair values

of obligations for dismantling and removing these facilities

are recorded as a liability and an increase to PP&E

at the time of installation of the asset based on estimated

discounted costs.

Estimating future asset removal

costs is difficult.

Most of these removal obligations are many

years, or decades, in the future and the contracts

and regulations often have vague descriptions

of what removal practices and criteria must

be met when the

removal event actually occurs.

Asset removal technologies and costs, regulatory

and other compliance

considerations, expenditure timing, and other inputs into

valuation of the obligation, including discount

and

inflation rates, are also subject to change.

Normally, changes in asset removal obligations are reflected in the income statement

as increases or decreases

to DD&A over the remaining life of the assets.

However, for assets at or nearing the end of their operations, as

well as previously sold assets for which we retained the

asset removal obligation, an increase in the asset

removal obligation can result in an immediate charge to earnings, because

any increase in PP&E due to the

increased obligation would immediately be subject

to impairment, due to the low fair value of

these properties.

In addition to asset removal obligations, under the

above or similar contracts, permits and regulations, we

have

certain environmental-related projects.

These are primarily related to remediation activities

required by

Canada and various states

within the U.S. at exploration and production

sites.

Future environmental

remediation costs are difficult to estimate because they 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.

See Note

10—Asset Retirement Obligations and Accrued Environmental

Costs, in the Notes to Consolidated Financial

Statements, for additional information.

Projected Benefit Obligations

Determination of the projected benefit obligations for our

defined benefit pension and postretirement plans

are

important to the recorded amounts for such obligations

on the balance sheet and to the amount of benefit

expense in the income statement.

The actuarial determination of projected benefit obligations

and company

contribution requirements involves judgment about

uncertain future events, including estimated retirement

dates, salary levels at retirement, mortality rates, lump-sum

election rates, rates of return on plan assets, future

health care cost-trend rates, and rates of utilization

of health care services by retirees.

Due to the specialized

nature of these calculations, we engage outside actuarial

firms to assist in the determination of these projected

benefit obligations and company contribution requirements.

For Employee Retirement Income Security Act-

governed pension plans, the actuary exercises fiduciary

care on behalf of plan participants in the determination

of the judgmental assumptions used in determining

required company contributions into the plans.

Due to

differing objectives and requirements between financial

accounting rules and the pension plan funding

regulations promulgated by governmental agencies,

the actuarial methods and assumptions

for the two

purposes differ in certain important respects.

Ultimately, we will be required to fund all vested benefits under

pension and postretirement benefit plans not funded by

plan assets or investment returns, but the

judgmental

assumptions used in the actuarial calculations significantly

affect periodic financial statements and funding

patterns over time.

Projected benefit obligations are particularly

sensitive to the discount rate assumption.

100 basis-point decrease in the discount rate assumption

would increase projected benefit obligations by

$1,000 million.

Benefit expense is sensitive to the discount

rate and return on plan assets assumptions.

100 basis-point decrease in the discount rate assumption

would increase annual benefit expense by

$100 million, while a 100 basis-point decrease in the

return on plan assets assumption would increase

annual

benefit expense by $60

million.

In determining the discount rate, we use yields on high-quality

fixed income

investments matched to the estimated benefit cash

flows of our plans.

are also exposed to the possibility

that lump sum retirement benefits taken from pension

plans during the year could exceed the

total of service

and interest components of annual pension expense and

trigger accelerated recognition of a portion

unrecognized net actuarial losses and gains.

These benefit payments are based on decisions

by plan

participants and are therefore difficult to predict.

In the event there is a significant reduction

in the expected

years of future service of present employees or the elimination

of the accrual of defined benefits for some

or all

of their future services for a significant number of

employees, we could recognize a curtailment gain

or loss.

See Note 18—Employee Benefit Plans, in the Notes to

Consolidated Financial Statements, for additional

information.

Contingencies

A number of claims and lawsuits are made against the

company arising in the ordinary course of

business.

Management exercises judgment related to accounting

and disclosure of these claims which includes losses,

damages, and underpayments associated with

environmental remediation, tax, contracts, and other

legal

disputes.

As we learn new facts concerning contingencies,

we reassess our position both with respect to

amounts recognized and disclosed considering changes

to the probability of additional losses and

potential

exposure.

However, actual losses can and do vary from estimates for a variety

of reasons including legal,

arbitration, or other third-party decisions; settlement discussions;

evaluation of scope of damages;

interpretation of regulatory or contractual terms;

expected timing of future actions; and proportion of

liability

shared with other responsible parties.

Estimated future costs related to contingencies

are subject to change as

events evolve and as additional information becomes

available during the administrative and litigation

processes.

For additional information on contingent liabilities,

see the “Contingencies” section within “Capital

Resources and Liquidity” and Note 13—Contingencies and

Commitments.

CAUTIONARY STATEMENT

FOR THE PURPOSES OF THE “SAFE HARBOR”

PROVISIONS OF

THE PRIVATE

SECURITIES LITIGATION REFORM ACT OF 1995

This report includes forward-looking statements within

the meaning of Section 27A of the Securities

Act of

1933 and Section 21E of the Securities Exchange Act

of 1934.

All statements other than statements of

historical fact included or incorporated by reference

in this report, including, without limitation, statements

regarding our future financial position, business strategy, budgets, projected revenues,

projected costs and

plans, and objectives of management for future operations,

are forward-looking statements.

Examples of

forward-looking statements contained in this report include

our expected production growth and outlook

on the

business environment generally, our expected capital budget and capital expenditures,

and discussions

concerning future dividends.

You

can often identify our forward-looking statements by

the words “anticipate,”

“estimate,” “believe,” “budget,” “continue,” “could,”

“intend,” “may,” “plan,” “potential,” “predict,” “seek,”

“should,” “will,” “would,” “expect,” “objective,” “projection,”

“forecast,” “goal,” “guidance,” “outlook,”

“effort,” “target” and similar expressions.

based the forward-looking statements on

our current expectations, estimates and projections

about

ourselves and the industries in which we operate in

general.

caution you these statements are not

guarantees of future performance as they involve

assumptions that, while made in good faith, may prove

to be

incorrect, and involve risks and uncertainties we cannot

predict.

In addition, we based many of these forward-

looking statements on assumptions about future events

that may prove to be inaccurate.

Accordingly, our

actual outcomes and results may differ materially from what

we have expressed or forecast in the forward-

looking statements.

Any differences could result from a variety of factors,

including, but not limited to, the

following:

●

Fluctuations in crude oil, bitumen, natural gas, LNG

and NGLs prices, including a prolonged decline

in these prices relative to historical or future expected

levels.

●

The impact of significant declines in prices for

crude oil, bitumen, natural gas, LNG and NGLs,

which

may result in recognition of impairment costs on our

long-lived assets, leaseholds and

nonconsolidated equity investments.

●

Potential failures or delays in achieving expected reserve

or production levels from existing and future

oil and gas developments, including due to operating hazards,

drilling risks and the inherent

uncertainties in predicting reserves and reservoir

performance.

●

Reductions in reserves replacement rates, whether as

a result of the significant declines in commodity

prices or otherwise.

●

Unsuccessful exploratory drilling activities or the

inability to obtain access to exploratory

acreage.

●

Unexpected changes in costs or technical requirements

for constructing, modifying or operating E&P

facilities.

●

Legislative and regulatory initiatives addressing environmental

concerns, including initiatives

addressing the impact of global climate change

or further regulating hydraulic fracturing, methane

emissions, flaring or water disposal.

●

Lack of, or disruptions in, adequate and reliable transportation

for our crude oil, bitumen, natural gas,

LNG and NGLs.

●

Inability to timely obtain or maintain permits,

including those necessary for construction, drilling

and/or development, or inability to make capital expenditures

required to maintain compliance with

any necessary permits or applicable laws or regulations.

●

Failure to complete definitive agreements and feasibility

studies for, and to complete construction of,

announced and future exploration and production and

LNG development in a timely manner (if at all)

or on budget.

●

Potential disruption or interruption of our operations

due to accidents, extraordinary weather events,

civil unrest, political events, war, global health epidemics,

terrorism, cyber attacks, and information

technology failures, constraints or disruptions.

●

Changes in international monetary conditions and foreign

currency exchange rate fluctuations.

●

Changes in international trade relationships, including

the imposition of trade restrictions or tariffs

relating to crude oil, bitumen, natural gas, LNG, NGLs

and any materials or products (such as

aluminum and steel) used in the operation of our

business.

●

Substantial investment in and development use

of, competing or alternative energy sources, including

as a result of existing or future environmental rules and

regulations.

●

Liability for remedial actions, including removal and

reclamation obligations, under existing or future

environmental regulations and litigation.

●

Significant operational or investment changes imposed

by existing or future environmental statutes

and regulations, including international agreements

and national or regional legislation and regulatory

measures to limit or reduce GHG emissions.

●

Liability resulting from litigation or our failure to

comply with applicable laws and regulations.

●

General domestic and international economic and

political developments, including armed hostilities;

expropriation of assets; changes in governmental

policies relating to crude oil, bitumen, natural

gas,

LNG and NGLs pricing, regulation or taxation; the impact

of and uncertainty surrounding the U.K.’s

decision to withdraw from the EU; and other political,

economic or diplomatic developments.

●

Volatility

in the commodity futures markets.

●

Changes in tax and other laws, regulations (including

alternative energy mandates), or royalty rules

applicable to our business, including changes resulting

from the implementation and interpretation

the Tax Cuts and Jobs Act.

●

Competition and consolidation in the oil and gas

E&P industry.

●

Any limitations on our access to capital or increase

in our cost of capital, including as a result

illiquidity or uncertainty in domestic or international

financial markets.

●

Our inability to execute, or delays in the completion,

of any asset dispositions or acquisitions we elect

to pursue.

●

Potential failure to obtain, or delays in obtaining, any

necessary regulatory approvals for asset

dispositions or acquisitions, or that such approvals

may require modification to the terms of

the

transactions or the operation of our remaining business.

●

Potential disruption of our operations as a result

of asset dispositions or acquisitions, including

the

diversion of management time and attention.

●

Our inability to deploy the net proceeds from any asset

dispositions we undertake in the manner and

timeframe we currently anticipate, if at all.

●

Our inability to liquidate the common stock issued to us

by Cenovus Energy as part of our sale of

certain assets in western Canada at prices we deem

acceptable, or at all.

●

The operation and financing of our joint ventures.

●

The ability of our customers and other contractual counterparties

to satisfy their obligations to us,

including our ability to collect payments when due

from the government of Venezuela or PDVSA.

●

Our inability to realize anticipated cost savings and expenditure

reductions.

●

The risk factors generally described in Item 1A—Risk

Factors in our 2019 Annual Report on Form

10-K filed with the SEC on February 18, 2020, and any

additional risks described in our other filings

with the SEC.

Item 8.

FINANCIAL STATEMENTS

AND SUPPLEMENTARY DATA

CONOCOPHILLIPS

INDEX TO FINANCIAL STATEMENTS

Page

Report of Management ............................................................................................................................

Reports of Independent Registered Public Accounting

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

Consolidated Income Statement for the years ended December

31, 2019, 2018 and 2017 ....................

Consolidated Statement of Comprehensive Income for

the years ended

December 31, 2019, 2018 and 2017 ..................................................................................................

Consolidated Balance Sheet at December 31,

2019 and 2018 ................................................................

Consolidated Statement of Cash Flows for the years

ended December 31, 2019,

2018 and 2017 .........

Consolidated Statement of Changes in Equity for

the years ended

December 31, 2019, 2018 and 2017 ..................................................................................................

Notes to Consolidated Financial Statements

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

Supplementary Information

Oil and Gas Operations ..............................................................................................................

137

Selected Quarterly Financial Data ..............................................................................................

165

Condensed Consolidating Financial Information

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

166

Report of Management

Management prepared, and is responsible for, the consolidated financial

statements and the other information

appearing in this annual report.

The consolidated financial statements present

fairly the company’s financial

position, results of operations and cash flows in conformity

with accounting principles generally accepted

the United States.

In preparing its consolidated financial statements,

the company includes amounts that are

based on estimates and judgments management believes

are reasonable under the circumstances.

The

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

an independent registered public

accounting firm appointed by the Audit and Finance Committee

of the Board of Directors and ratified by

stockholders.

Management has made available to Ernst

& Young LLP all of the company’s financial records

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

and directors’ meetings.

Assessment of Internal Control Over Financial Reporting

Management is also responsible for establishing and maintaining

adequate internal control over financial

reporting.

ConocoPhillips’ internal control system

was designed to provide reasonable assurance to the

company’s management and directors regarding the preparation and fair presentation

of published financial

statements.

All internal control systems, no matter how well

designed, have inherent limitations.

Therefore, even those

systems determined to be effective can provide only reasonable

assurance with respect to financial statement

preparation and presentation.

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

reporting as of

December 31, 2019.

In making this assessment, it

used the criteria set forth by the Committee of

Sponsoring

Organizations of the Treadway Commission in

Internal Control—Integrated Framework (2013)

Based on our

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

was effective as of

December 31, 2019.

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

December 31, 2019, and their report is included herein.

/s/ Ryan M. Lance

/s/ Don E. Wallette, Jr.

Ryan M. Lance

Don E. Wallette, Jr.

Chairman and

Chief Executive Officer

Executive Vice President and

Chief Financial Officer

February 18, 2020

Report of Independent Registered Public Accounting

Firm

To the Stockholders and the Board of Directors of ConocoPhillips

Opinion on the Financial Statements

have audited the accompanying consolidated

balance sheets of ConocoPhillips (the Company)

as of

December 31, 2019 and 2018, the related consolidated

income statement, consolidated statements

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

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.

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.

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

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

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

have served as ConocoPhillips’ auditor

since 1949.

Houston, Texas

February 18, 2020, except as it relates to the effects of the

change in segments described in Note 25, as to

which the date is November 16, 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.

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

779

1,074

772

Gain on dispositions

1,966

1,063

2,177

Other income

1,358

173

529

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

556

401

427

Exploration expenses

743

369

934

Depreciation, depletion and amortization

6,090

5,956

6,845

Impairments

405

6,601

Taxes other than income taxes

953

1,048

809

Accretion on discounted liabilities

326

353

362

Interest and debt expense

778

735

1,098

Foreign currency transaction (gains)

losses

(17)

Other expenses

375

451

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)

146

279

247

Net change

129

266

Nonsponsored plans*

(3)

(1)

(2)

Income taxes on defined benefit plans

(2)

(42)

(81)

Defined benefit plans, net of tax

147

Unrealized holding loss on securities

(58)

Unrealized loss on securities, net of

tax

(58)

Foreign currency translation adjustments

699

(645)

586

Income taxes on foreign currency

translation adjustments

(4)

Foreign currency translation adjustments,

net of tax

695

(642)

586

Other Comprehensive Income (Loss), Net

of Tax

746

(603)

675

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

248

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

134

147

Investment in Cenovus Energy

2,111

1,462

Inventories

1,026

1,007

Prepaid expenses and other current

assets

2,259

575

Total Current Assets

16,913

13,274

Investments and long-term receivables

8,687

9,329

Loans and advances—related parties

219

335

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

105

112

Accrued income and other taxes

1,030

1,320

Employee benefit obligations

663

809

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

125

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

405

6,601

Dry hole costs and leasehold impairments

421

566

Accretion on discounted liabilities

326

353

362

Deferred taxes

(444)

283

(3,681)

Undistributed equity earnings

594

152

(232)

Gain on dispositions

(1,966)

(1,063)

(2,177)

Other

(1,000)

191

(429)

Working capital adjustments

Decrease (increase) in accounts and

notes receivable

505

235

(886)

Decrease (increase) in inventories

(67)

(55)

Decrease (increase) in prepaid expenses

and other current assets

(55)

Increase (decrease) in accounts payable

(378)

(52)

265

Increase (decrease) in taxes and other

accruals

(676)

421

622

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)

132

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

127

119

115

Other

(108)

154

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)

121

(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)

232

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 $

184

million are included

in the “Prepaid expenses

and other current

assets” and “Other assets” lines,

respectively,

of our Consolidated Balance

Sheet as of December 31, 2019.

Restricted cash totaling $

236

million is included in the “Other assets” line of

our Consolidated

Balance Sheet as of December 31,

2018.

See Notes to Consolidated

Financial Statements.

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

252

35,226

Net income (loss)

(855)

(793)

Other comprehensive income

675

Dividends paid ($

1.06

per share of common stock)

(1,305)

Repurchase of company common

stock

(3,000)

Distributions to noncontrolling

interests and other

(120)

Distributed under benefit plans

115

Other

December 31, 2017

46,622

(39,906)

(5,518)

29,391

194

30,801

Net income

6,257

6,305

Other comprehensive loss

(603)

Dividends paid ($

1.16

per share of common stock)

(1,363)

Repurchase of company common

stock

(2,999)

Distributions to noncontrolling

interests and other

(121)

Distributed under benefit plans

257

Changes in Accounting

Principles*

(278)

(220)

Other

December 31, 2018

46,879

(42,905)

(6,063)

34,010

125

32,064

Net income

7,189

7,257

Other comprehensive income

746

Dividends paid ($

1.34

per share of common stock)

(1,500)

Repurchase of company common

stock

(3,500)

Distributions to noncontrolling

interests and other

(128)

Distributed under benefit plans

104

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 Accou

nting 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

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.

manage our operations through six operating

segments, defined by geographic region: Alaska;

Lower

48; Canada; Europe,

Middle East and North Africa;

Asia Pacific and Other International.

For additional

information, see Note 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

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

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

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

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.

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.

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

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.

adopted ASC Topic 842 using the modified retrospective approach and elected

to utilize the Optional

Transition Method, which permits us to apply the provisions

of ASC Topic 842 to leasing arrangements

existing at or entered into after January 1, 2019, and

present in our financial statements comparative

periods

prior to January 1, 2019 under the historical requirements

of ASC Topic 840.

In addition, we elected to adopt

the package of optional transition-related practical

expedients, which among other things, allows

us to carry

forward certain historical conclusions reached

under ASC Topic 840 regarding lease identification,

classification, and the accounting treatment of

initial direct costs.

Furthermore, we elected not to record assets

and liabilities on our consolidated balance sheet for

new or existing lease arrangements with

terms of 12

months or less.

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

998

million of lease liabilities and

corresponding right-of-use assets

on our consolidated balance sheet as of January

1, 2019, for leases classified

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

our leasing arrangements.

Our

accounting treatment for finance leases remains

unchanged.

In addition, there is no cumulative effect to

retained earnings or other components of equity recognized

as of January 1, 2019, and the adoption of ASC

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

statement of cash flows.

See Note 17—Non-Mineral Leases for additional information

related to the adoption of ASC Topic 842.

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

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)

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.

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)

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

472

432

Materials and supplies

554

575

1,026

1,007

Inventories valued on the LIFO basis totaled $

286

million and $

292

million at December 31, 2019 and 2018,

respectively.

The estimated excess of current replacement

cost over LIFO cost of inventories was

approximately $

155

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

372

million, $

364

million and $

317

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 segment.

In the fourth quarter of 2019, we signed an agreement

to sell our interests in the Niobrara shale play

for $

380

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 $

379

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 $

390

million, which consisted primarily of $

426

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 $

426

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

372

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

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.

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,

Middle East and

North Africa segment.

In the second quarter of 2019, we recognized an after-tax gain of $

million upon the closing of the sale of

our

percent interest in the Greater Sunrise Fields to

the government of Timor-Leste for $

350

million.

The

Greater Sunrise Fields were

included in our Asia Pacific segment.

In the fourth quarter of 2019, we sold our interests in the

Magnolia field and platform for net proceeds of $

million and recognized a before-tax gain of $

million.

At the time of sale, the net carrying value consisted

of $

million of PP&E offset by $

million of ARO.

The Magnolia results of operations 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 $

186

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 $

112

million.

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

105

million and

gain or loss was recognized on the sale.

In the third quarter of 2018, we completed

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 $

162

million and

recognized gains of approximately $

140

million.

On October 31, 2018, we completed the sale of our interests

in the Barnett to Lime Rock Resources for $

196

million after customary adjustments and recognized

a loss of $

million. We recorded impairments of $

million in 2018 and $

572

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 $

201

million, consisting of $

250

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 $

566

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 $

253

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, $

485

million of deferred tax liabilities, and $

million of AROs.

We recognized a before-tax gain of

715

million on the transaction.

The 2018 before-tax earnings associated with our

16.5 interest in the Clair

Field, including the recognized gain, were $

748

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,

Middle East 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 $

386

million, after

customary adjustments.

This transaction was accounted for as a

business combination resulting in the

recognition of approximately $

297

million of proved property and $

114

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,

2018.

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, $

374

million of AROs, and a $

100

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,

208

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.

reported before-tax equity earnings associated

with FCCL of $

197

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 $

114

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 $

585

million and approximately $

100

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.

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 $

406

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 $

178

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 $

206

million, consisting primarily of $

279

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

219

335

Long-term receivables

243

238

Long-term investments in debt securities

133

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 $

605

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

2030.

During the first quarter of 2019, APLNG

refinanced $

3.2

billion of existing project finance debt through two

transactions.

As a result of the first transaction, APLNG obtained

a commercial bank facility of $

2.6

billion.

APLNG made its first principal and interest repayment

in September 2019 with

bi-annual

payments due on the

facility until March 2028.

Through the second transaction, APLNG

obtained a USPP bond facility of $

0.6

billion.

APLNG made its first interest payment in September 2019,

and principal payments are scheduled

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 $

477

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

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,

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 $

100

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 $

335

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 $

797

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.

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 2022.

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

208

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

649

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

856

853

1,063

Additions pending the determination of proved reserves

239

140

118

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

856

853

*Includes $

313

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

206

145

Exploratory well costs capitalized for a period greater

than one year

814

711

786

Ending balance

1,020

856

853

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)

177

157

NPRA—Alaska

(1)

149

111

Barossa/Caldita—Australia

(2)(3)

136

Surmont—Canada

(1)

118

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

814

265

374

175

(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

2017.

In 2019, we recorded before-tax dry hole expenses of

111

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

180

Lower 48

402

3,969

Canada

Europe, Middle East and North Africa

(79)

Asia Pacific

2,384

405

6,601

2019

In the Lower 48, we recorded impairments of $

402

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 $

141

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, Middle East and North Africa segment, we

recorded a credit to impairment of $

million,

primarily due to decreased ARO estimates on fields in the

U.K. which 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 $

180

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, Middle East 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, 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

171

178

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.” $

741

million relates to assets which

are held for sale as

December 31, 2019. For additional

information see Note 5—Asset Acquisitions

and Dispositions.

Asset Retirement Obligations

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.

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

322

348

New obligations

155

657

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 $

171

million and $

178

million,

respectively.

had accrued environmental costs of $

112

million and $

100

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 $

108

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

123

8.20% Debentures due 2025

134

8.125% Notes due 2030

390

7.9% Debentures due 2047

7.8% Debentures due 2027

203

7.65% Debentures due 2023

7.40% Notes due 2031

500

7.375% Debentures due 2029

7.25% Notes due 2031

500

7.20% Notes due 2031

575

7% Debentures due 2029

200

6.95% Notes due 2029

1,549

6.875% Debentures due 2026

6.50% Notes due 2039

2,750

5.951% Notes due 2037

645

5.95% Notes due 2036

500

5.95% Notes due 2046

500

5.90% Notes due 2032

505

5.90% Notes due 2038

600

4.95% Notes due 2026

1,250

4.30% Notes due 2044

750

4.15% Notes due 2034

246

3.35% Notes due 2024

426

3.35% Notes due 2025

199

2.4% Notes due 2022

329

Floating rate notes due 2022 at

2.81

% –

3.58

% during 2019 and

2.32

% –

3.52

% during 2018

500

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

265

Other

Debt at face value

13,971

Finance leases

720

777

Net unamortized premiums, discounts and debt issuance

costs

204

220

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: $

105

million, $

235

million, $

940

million, $

198

million and $

548

million, respectively.

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 $

500

million, or as support for our commercial paper program.

The revolving credit facility is broadly syndicated

among financial institutions and does not contain

any material adverse change provisions or any covenants

requiring maintenance of specified financial ratios

or credit ratings.

The facility agreement contains a cross-

default provision relating to the failure to pay principal

or interest on other debt obligations of

200

million or

more by ConocoPhillips, or any of its consolidated

subsidiaries.

Credit facility borrowings may bear interest at a

margin above rates offered by certain designated banks in the

London interbank market or at a margin above the overnight

federal funds rate or prime rates offered by

certain designated banks in the 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.

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

direct outstanding

borrowings or letters of credit under the revolving credit

facility at December 31, 2019 or

December 31, 2018

Since we had

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 $

283

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.

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.

estimate the remaining term of this

guarantee is

11 years

Our maximum exposure under this guarantee is approximately

170

million

and may become payable if an enforcement action

is commenced by the project finance lenders

against APLNG.

At 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 $

780

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.

●

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

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

have other guarantees with maximum

future potential payment amounts totaling

approximately

820

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 $

100

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.

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.

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

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

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.

measure estimates and base liabilities

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

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.

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.

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

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.

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

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

277

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.

response to this expropriation, ConocoPhillips initiated international

arbitration on November 2, 2007, with the

ICSID.

On September 3, 2013, an ICSID arbitration tribunal held that

Venezuela

unlawfully expropriated

ConocoPhillips’ significant oil investments in June 2007.

On January 17, 2017, the Tribunal reconfirmed the

decision that the expropriation was unlawful.

In March 2019, the Tribunal unanimously ordered the

government of Venezuela to pay ConocoPhillips approximately $

8.7

billion in compensation for the

government’s unlawful expropriation of the company’s investments in Venezuela in 2007.

ConocoPhillips has

filed a request for recognition of the award in several

jurisdictions.

On August 29, 2019, the ICSID Tribunal

issued a decision rectifying the award and reducing it by

approximately $

227

million.

The award now stands

at $

8.5

billion plus interest.

The government of Venezuela sought annulment of the award.

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 $

754

million.

Per the settlement, PDVSA recognized the ICC

award as a judgment in various

jurisdictions, and ConocoPhillips agreed to suspend

its legal enforcement actions.

ConocoPhillips sent notices

of default to PDVSA on October 14 and November 12, 2019,

and to date PDVSA failed to cure its breach.

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

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 Venezuela.

In February 2017, the ICSID Tribunal unanimously awarded

Burlington Resources, Inc., a wholly owned

subsidiary of ConocoPhillips, $

380

million for Ecuador’s unlawful expropriation of Burlington’s investment

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 $

337

million in two installments.

The first installment of $

million was paid in

December 2017, and the second installment of $

262

million was paid in April 2018.

The settlement included

an offset for the counterclaims decision, of which Burlington

is entitled to a contribution from Perenco

Ecuador Limited, its co-venturer and consortium operator,

pursuant to a joint and several liability provision

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.

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

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

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

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

288

410

Other assets

Liabilities

Other accruals

283

370

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

141

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

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

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

805

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

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

759

876

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

465

Commercial Paper

Remaining maturities from 1 to 90 days

413

229

1,069

248

U.S. Government Obligations

Remaining maturities from 1 to 90 days

394

1,301

5,079

5,915

2,929

248

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

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

133

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

159

Commercial paper

U.S. government obligations

Asset-backed securities

241

Gross unrealized gains and gross unrealized losses

included in other comprehensive income related

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.

100

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,

collateral was posted as of December 31, 2019 or

December 31, 2018

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

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

101

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

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

1,462

Investments in debt securities

216

241

Commodity derivatives

172

114

322

236

181

450

Total assets

2,308

330

2,674

1,698

181

1,912

Liabilities

Commodity derivatives

174

115

311

225

145

400

Total liabilities

174

115

311

225

145

400

102

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

Cash

Net

Recognized

Right of Setoff

Amounts

Offset

Presented

Collateral

Amounts

December 31, 2019

Assets

322

319

193

126

122

Liabilities

311

307

193

114

102

December 31, 2018

Assets

450

441

280

161

Liabilities

400

396

280

116

106

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

194

351

December 31, 2019

166

Equity Method Investments

March 31, 2019

171

May 31, 2019

Year

ended December 31, 2018

Net PP&E (held for sale)

March 31, 2018

250

September 30, 2018

201

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

103

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

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

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

125

170

125

170

Investments in debt securities

241

Total loans and advances—related parties

339

468

339

468

Financial liabilities

Total debt, excluding finance leases

14,175

14,191

18,108

16,147

Commodity derivatives

106

110

106

110

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.

December 31, 2018, commodity derivative assets and

liabilities are presented net with

obligations to return

cash collateral and $

million of rights to reclaim cash collateral,

respectively.

104

Note 16—Equity

Common Stock

The changes in our shares of common stock, as categorized

in the equity section of the balance sheet, were:

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

have authorized

500

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 $

125

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.

105

Certain arrangements may contain both lease and

non-lease components and we determine if an arrangement

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,

2019.

For contractual arrangements executed in subsequent

periods involving a new leased asset class, the

company will determine at contract inception whether

it will apply the optional practical expedient to

the new

leased asset class.

Leases are evaluated for classification as operating

or finance leases at the commencement date of

the lease

and right-of-use assets and corresponding liabilities

are recognized on our consolidated balance sheet

based on

the present value of future lease payments relating to

the use of the underlying asset during the lease term.

Future lease payments include variable lease payments

that depend upon an index or rate using the index or

rate at the commencement date and probable amounts

owed under residual value guarantees.

The amount of

future lease payments may be increased to include additional

payments related to lease extension, termination,

and/or purchase options when the company has

determined, at or subsequent to lease commencement,

generally due to limited asset availability or operating

commitments, it is reasonably certain of exercising

such

options.

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

value of future

lease payments, unless the interest rate implicit

in the lease arrangement is readily determinable.

Lease

payments that vary subsequent to the commencement

date based on future usage levels, the nature of

leased

asset activities, or certain other contingencies are not

included in the measurement of lease right-of-use assets

and corresponding liabilities.

have elected not to record assets and liabilities

on our consolidated balance

sheet for lease arrangements with terms of 12 months

or less.

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

proportional basis.

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

and corresponding

lease liability only if we were a specified contractual

party to the lease arrangement and the arrangement

could

be legally enforced against us.

In this circumstance, we would

recognize both the right-of-use asset and

corresponding lease liability on our consolidated

balance sheet on a proportional basis consistent with

our

undivided interest ownership in the related joint venture.

The company has historically recorded certain finance

leases executed by investee companies accounted

for

under the proportionate consolidation method of accounting

on its consolidated balance sheet on a proportional

basis consistent with its ownership interest in the

investee company.

In addition, the company has historically

recorded finance lease assets and liabilities associated

with certain oil and gas joint ventures

on a proportional

basis pursuant to accounting guidance applicable

prior to January 1, 2019.

As of December 31, 2018, $

420

million of finance lease assets (net of accumulated

DD&A) and $

688

million of finance lease liabilities were

recorded on our consolidated balance sheet associated

with these leases.

In accordance with the transition

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

optional transition-related

practical expedients, the historical accounting treatment

for these leases has been carried forward and is

subject

to reconsideration upon the modification or other required

reassessment of the arrangements prior to lease term

expiration.

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

consolidated balance sheet $

million of operating leases executed by investee

companies accounted for under the proportionate

106

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

494

Adoption of ASC Topic 842 as of January 1, 2019

998

Lease Liabilities

Short-term debt

Long-term debt

698

Total finance leases debt as of December 31, 2018

777

Adoption of ASC Topic 842 as of January 1, 2019

998

Amounts recognized in line items in our Consolidated

Balance Sheet at 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

390

Prepaid expenses and other current assets

Other assets

896

* Includes proportionately

consolidated finance lease assets

(net of accumulated depreciation,

depletion and amortization)

of $

335

million.

107

Millions of Dollars

Carrying Amount

Operating

Leases

Finance

Leases

Lease Liabilities

Short-term debt

Other accruals

347

Long-term debt

633

Other liabilities and deferred credits

585

Total lease liabilities

932

720

Short-term debt

and

long-term debt

include proportionately

consolidated finance lease liabilities of $

million and $

579

million, respectively.

The following table summarizes our lease costs for 2019:

Millions of Dollars

2019

Lease Cost

Operating lease cost

341

Finance lease cost

Amortization of right-of-use assets

Interest on lease liabilities

Short-term lease cost

Total lease cost

***

554

*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

108

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

203

Operating cash flows from finance leases

Financing cash flows from finance leases

Right-of-use assets obtained in exchange for operating

lease liabilities

499

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.

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

348

120

2021

247

104

2022

130

102

2023

2024

Remaining years

149

382

Total

1,019

880

Less: portion representing imputed interest

(87)

(160)

Total lease liabilities

932

720

*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.

109

At December 31, 2018, future minimum payments

due under finance (capital) leases pursuant

ASC Topic 840 were:

Millions

of Dollars

2019

118

2020

116

2021

100

2022

2023

Remaining years

453

Total

972

Less: portion representing imputed interest

(195)

Capital lease obligations

777

At December 31, 2018, future undiscounted minimum

rental payments due under noncancelable operating

leases pursuant to ASC Topic 840 were:

Millions

of Dollars

2019

248

2020

425

2021

136

2022

319

2023

Remaining years

212

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

253

264

Less: sublease rentals

(16)

(20)

237

244

110

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

218

265

Service cost

Interest cost

107

Plan participant contributions

Plan amendments

Actuarial (gain) loss

278

387

(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

102

(199)

(1)

Benefit obligation at December 31*

2,319

3,880

2,136

3,438

216

218

*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

273

529

(112)

(106)

Company contributions

235

464

144

156

Plan participant contributions

Benefits paid

(253)

(147)

(507)

(143)

(59)

(67)

Settlement

(730)

Foreign currency exchange rate change

100

(198)

Fair value of plan assets at December 31

1,591

4,306

1,336

3,358

Funded Status

(728)

426

(800)

(80)

(216)

(218)

111

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

765

232

Current liabilities

(21)

(6)

(59)

(4)

(42)

(44)

Noncurrent liabilities

(707)

(333)

(741)

(308)

(174)

Total recognized

(728)

426

(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

479

227

516

310

(21)

Unrecognized prior service cost (credit)

(2)

(4)

(183)

(216)

112

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)*

116

249

(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

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 $

601

million and $

542

million, respectively, at December 31, 2019,

and were $

586

million and $

504

million, respectively, at December 31, 2018.

113

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

107

118

103

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

196

131

Net periodic benefit cost

200

317

279

(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 $

730

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.

recognized pension settlement losses of $

million in 2019, $

196

million in 2018, and $

131

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.

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

114

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

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.

115

●

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 $

235

million in debt securities, less $

140

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 $

228

million in debt securities, less $

144

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.

101

435

International

266

Mutual funds

245

267

512

Debt securities

Government

1,412

Corporate

Mutual funds

392

Cash and cash equivalents

Derivatives

Real estate

132

Total in fair value hierarchy

285

294

2,859

267

132

3,258

Investments measured at

net asset value*

Equity securities

Common/collective trusts

457

167

Debt securities

Common/collective trusts

637

760

Cash and cash equivalents

Real estate

112

Total**

285

1,496

2,859

267

132

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.

116

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.

371

International

241

Mutual funds

213

181

394

Debt securities

Government

889

Corporate

Mutual funds

363

Cash and cash equivalents

Time deposits

Derivatives

(17)

Real estate

124

Total in fair value hierarchy

230

252

2,137

181

124

2,442

Investments measured at

net asset value*

Equity securities

Common/collective trusts

364

153

Debt securities

Common/collective trusts

548

641

Cash and cash equivalents

Real estate

109

Total**

230

1,249

2,137

181

124

3,345

*In accordance

with FASB

ASC Topic 715,

“Compensation

—Retirement Benefits,” certain

investments that are

to be measured

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 $

350

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.

117

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

U.S.

Int’l.

2020

447

150

2021

270

156

2022

250

158

2023

217

163

2024

220

170

2025–2029

822

927

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

100

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.

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

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

118

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).

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

274

265

227

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

2017.

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

119

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

214

Exercised

(1,339,480)

36.28

Forfeited

Expired or cancelled

Outstanding at December 31, 2019

18,040,197

54.11

206

Vested at

December 31, 2019

17,922,026

54.14

205

Exercisable at December 31, 2019

17,172,815

54.33

194

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

120

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

225

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

154

million and $

159

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.

121

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

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

122

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

171

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

dividend equivalent.

123

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

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)

545

(3,046)

Foreign

Current

2,545

3,273

1,729

Deferred

(323)

(166)

(510)

State and local

Current

148

108

Deferred

(8)

(96)

(125)

2,267

3,668

(1,822)

124

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

234

156

Total deferred tax liabilities

8,929

8,281

Deferred Tax Assets

Benefit plan accruals

542

641

Asset retirement obligations and accrued environmental

costs

2,339

2,891

Investments in joint ventures

1,722

104

Other financial accruals and deferrals

777

330

Loss and credit carryforwards

8,968

2,378

Other

345

398

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 $

184

million and

4,634

million, respectively.

At December 31, 2018, noncurrent assets and liabilities

included deferred taxes

of $

442

million and $

5,021

million, respectively.

At December 31, 2019, the components of our loss and

credit carryforwards before and after consideration

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

250

2036-2038

U.S. capital loss

202

2024

State net operating losses and tax credits

370

Various

Foreign net operating losses and tax credits

450

413

Post 2025

8,968

759

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.

125

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 $

151

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

210

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

882

381

Additions based on tax positions related to the current

year

268

612

Additions for tax positions of prior years

120

109

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

882

Included in the balance of unrecognized tax benefits

for 2019, 2018 and 2017 were $

1,100

million,

1,081

million and $

882

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

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

impact to earnings

in 2017.

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

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

change is not estimable.

126

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

Federal statutory income tax

2,000

2,095

(915)

21.0

35.0

Non-U.S. effective tax rates

1,399

1,766

625

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)

881

0.1

(33.7)

Adjustment to valuation allowance

(225)

(26)

(2.4)

(0.3)

APLNG impairment

834

(31.9)

State income tax

123

135

(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 $

335

million. The disposition generated a U.S. capital loss

of approximately $

2.1

billion which has generated a U.S.

tax benefit of approximately $

285

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 $

164

million.

The decrease in the effective tax rate for 2018 was primarily

due to the impact of the Clair Field disposition

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 $

715

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.

127

SAB 118 measurement period

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.

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 $

908

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)

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 $

822

million.

However, since we

believe it is not likely we will receive a corresponding

cash tax savings, this $

822

million benefit has been

offset by a full tax reserve.

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 $

962

million, respectively.

128

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)

147

(58)

586

675

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

695

746

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

(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 $

483

million of foreign currency translation adjustments

related to the completion

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

For additional information related

to this disposition, see

Note 5—Asset 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

189

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.

129

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

205

395

(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

810

772

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.

collected $

330

million and $

430

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 $

262

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 $

324

million contribution to our U.K.

pension plan.

made discretionary payments to

our domestic qualified pension plan of $

120

million and $

600

million in 2018 and 2017, respectively.

In 2017, we recognized a $

180

million adverse cash impact from the settlement

of cross-currency swap

transactions.

130

Note 22—Other Financial Information

Millions of Dollars

2019

2018

2017

Interest and Debt Expense

Incurred

Debt

799

838

1,114

Other

103

835

905

1,217

Capitalized

(57)

(170)

(119)

Expensed

778

735

1,098

Other Income

Interest income

166

112

Unrealized gains (losses) on Cenovus Energy common shares*

649

(437)

Other, net

543

513

417

1,358

173

529

*See Note 7—Investment

in Cenovus Energy,

for additional information.

Research and Development Expenditures

—expensed

100

Shipping and Handling Costs

1,008

1,075

1,050

Foreign Currency Transaction (Gains) Losses

—after-tax

Alaska

Lower 48

Canada

(11)

Europe, Middle East and North Africa

(26)

Asia Pacific

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, 2019.

See Note 5

—

Asset Acquisitions and Dispositions,

for additional information.

131

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

107

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)

101

(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

691

629

864

Europe, Middle East and North Africa

878

1,231

1,503

Physical contracts meeting the definition of a derivative

6,558

8,218

8,669

132

Millions of Dollars

2019

2018

2017

Revenue from Outside the Scope of ASC Topic 606

by Product

Crude oil

804

1,112

588

Natural gas

5,313

6,734

7,811

Other

441

372

270

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

206

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.

133

Note 25—Segment Disclosures and Related Information

explore for, produce, transport and market crude oil, bitumen,

natural gas, LNG and NGLs on a worldwide

basis.

We manage our operations through

six

operating segments, which are primarily defined

by geographic

region: Alaska; Lower 48; Canada;

Europe, Middle East and North Africa; Asia Pacific

and Other

International.

Corporate and Other represents 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.

evaluate performance and allocate resources

based on net income (loss) attributable to ConocoPhillips.

Segment accounting policies are the same as those

in Note 1—Accounting Policies.

Intersegment sales are at

prices that approximate market.

Effective with the third quarter of 2020, we have restructured

our segments to align with the changes to our

internal organization.

The Middle East business was realigned

from the Asia Pacific and Middle East

segment

to the Europe and North Africa segment.

The segments have been renamed the

Asia Pacific segment and the

Europe, Middle East and North Africa segment.

have revised segment information

disclosures and

segment performance metrics presented within

our results of operations for the current and prior

years.

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, Middle East and North Africa

5,101

6,635

5,181

Asia Pacific

4,525

4,861

4,014

Other International

Corporate and Other

221

168

104

Consolidated sales and other operating revenues

32,567

36,417

29,106

Depreciation, Depletion, Amortization and Impairments

Alaska

805

760

1,026

Lower 48

3,224

2,370

6,693

Canada

232

324

461

Europe, Middle East and North Africa

887

1,041

1,313

Asia Pacific

1,285

1,382

3,819

Other International

Corporate and Other

106

134

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.

134

Millions of Dollars

2019

2018

2017

Equity in Earnings of Affiliates

Alaska

Lower 48

(159)

Canada

197

Europe, Middle East and North Africa

470

744

534

Asia Pacific

461

323

Other International

Corporate and Other

Consolidated equity in earnings of affiliates

779

1,074

772

Income Taxes

Alaska

472

376

(689)

Lower 48

137

474

(2,453)

Canada

(43)

(96)

(616)

Europe, Middle East and North Africa

1,425

2,259

1,120

Asia Pacific

501

728

396

Other International

Corporate and Other

(233)

(103)

399

Consolidated income taxes

2,267

3,668

(1,822)

Net Income (Loss) Attributable to ConocoPhillips

Alaska

1,520

1,814

1,466

Lower 48

436

1,747

(2,371)

Canada

279

2,564

Europe, Middle East and North Africa

3,170

2,594

1,116

Asia Pacific

1,483

1,342

(1,661)

Other International

263

364

167

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

378

402

Canada

Europe, Middle East and North Africa

1,070

1,311

1,402

Asia Pacific

7,265

7,565

7,730

Other International

Corporate and Other

Consolidated investments in and advances to affiliates

8,453

9,340

9,590

135

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, Middle East and North Africa

9,269

11,276

13,346

Asia Pacific

13,568

14,758

15,509

Other International

285

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

815

Lower 48

3,394

3,184

2,136

Canada

368

477

202

Europe, Middle East and North Africa

708

877

872

Asia Pacific

584

718

482

Other International

Corporate and Other

190

Consolidated capital expenditures and investments

6,636

6,750

4,591

Interest Income and Expense

Interest income

Alaska

Lower 48

Canada

Europe, Middle East and North Africa

Asia Pacific

Other International

Corporate and Other

149

101

Interest and debt expense

Corporate and Other

778

735

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

814

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.

**Prior periods have been updated

to reflect the Middle East Business

Unit moving from

Asia Pacific to the Europe,

Middle East

and North

Africa segment.

136

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

772

836

712

1,447

1,380

1,275

Indonesia

875

886

757

605

669

758

Libya

1,103

1,142

586

668

679

699

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

153

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 $

426

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.

(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.

137

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

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

138

methods, volumetric-based methods, geologic maps, seismic

interpretation, well logs, well test data, core data,

analogy and statistical analysis.

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 99.2 of this Current

Report on Form 8-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.

139

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

837

506

1,343

303

185

203

2,047

Revisions

113

178

249

Improved recovery

Purchases

Extensions and discoveries

210

251

253

Production

(60)

(64)

(124)

(1)

(45)

(34)

(7)

(211)

Sales

(10)

(12)

(22)

End of 2017

937

707

1,644

296

185

196

2,322

Revisions

(90)

(18)

Improved recovery

Purchases

233

234

Extensions and discoveries

179

227

232

Production

(59)

(82)

(141)

(1)

(40)

(33)

(13)

(228)

Sales

(12)

(36)

(48)

End of 2018

1,233

703

1,936

246

159

188

2,533

Revisions

(36)

(1)

(5)

Improved recovery

Purchases

Extensions and discoveries

226

251

264

Production

(74)

(95)

(169)

(36)

(31)

(14)

(250)

Sales

(2)

(30)

(32)

End of 2019

1,231

797

2,028

198

134

197

2,562

Equity affiliates

End of 2016

Revisions

Improved recovery

Purchases

Extensions and discoveries

Production

(5)

Sales

End of 2017

Revisions

Improved recovery

Purchases

Extensions and discoveries

Production

(5)

Sales

End of 2018

Revisions

Improved recovery

Purchases

Extensions and discoveries

Production

(5)

Sales

End of 2019

Total company

End of 2016

837

506

1,343

303

273

203

2,135

End of 2017

937

707

1,644

296

268

196

2,405

End of 2018

1,233

703

1,936

246

237

188

2,611

End of 2019

1,231

797

2,028

198

207

197

2,635

140

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

747

256

1,003

184

106

203

1,509

End of 2017

828

315

1,143

190

121

196

1,651

End of 2018

1,058

346

1,404

192

113

185

1,896

End of 2019

1,048

334

1,382

149

181

1,809

Equity affiliates

End of 2016

End of 2017

End of 2018

End of 2019

Undeveloped

Consolidated operations

End of 2016

250

340

119

538

End of 2017

109

392

501

106

671

End of 2018

175

357

532

637

End of 2019

183

463

646

753

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.

141

●

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.

142

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

107

278

385

457

Revisions

Improved recovery

Purchases

Extensions and discoveries

Production

(5)

(24)

(29)

(3)

(2)

(37)

Sales

(130)

(44)

(174)

End of 2017

106

224

330

354

Revisions

(25)

(20)

(1)

(20)

Improved recovery

Purchases

Extensions and discoveries

Production

(5)

(25)

(30)

(3)

(1)

(34)

Sales

(21)

End of 2018

106

222

328

349

Revisions

(1)

(11)

(12)

(1)

(10)

Improved recovery

Purchases

Extensions and discoveries

Production

(5)

(28)

(33)

(3)

(1)

(37)

Sales

(4)

End of 2019

100

245

345

361

Equity affiliates

End of 2016

Revisions

Improved recovery

Purchases

Extensions and discoveries

Production

(2)

Sales

End of 2017

Revisions

Improved recovery

Purchases

Extensions and discoveries

Production

(3)

Sales

End of 2018

Revisions

Improved recovery

Purchases

Extensions and discoveries

Production

(3)

Sales

End of 2019

Total company

End of 2016

107

278

385

504

End of 2017

106

224

330

399

End of 2018

106

222

328

391

End of 2019

100

245

345

400

143

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

107

209

316

383

End of 2017

106

101

207

226

End of 2018

106

203

221

End of 2019

100

199

211

Equity affiliates

End of 2016

End of 2017

End of 2018

End of 2019

Undeveloped

Consolidated operations

End of 2016

End of 2017

123

128

End of 2018

125

128

End of 2019

146

150

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.

144

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

227

10,844

Revisions

287

460

747

167

938

Improved recovery

Purchases

Extensions and discoveries

582

584

610

Production

(71)

(338)

(409)

(71)

(188)

(267)

(3)

(938)

Sales

(2,885)

(966)

(3,851)

End of 2017

2,320

2,533

4,853

1,217

1,298

224

7,603

Revisions

150

(283)

(133)

(34)

Improved recovery

Purchases

335

336

Extensions and discoveries

527

529

110

673

Production

(71)

(237)

(308)

(5)

(188)

(246)

(10)

(757)

Sales

(223)

(13)

(236)

End of 2018

2,736

2,318

5,054

1,212

1,079

214

7,585

Revisions

(113)

(83)

(2)

160

147

243

Improved recovery

Purchases

Extensions and discoveries

483

490

514

Production

(85)

(252)

(337)

(4)

(178)

(250)

(11)

(780)

Sales

(7)

(298)

(305)

End of 2019

2,688

2,431

5,119

896

977

224

7,259

Equity affiliates

End of 2016

4,381

Revisions

111

Improved recovery

Purchases

Extensions and discoveries

185

Production

(374)

Sales

End of 2017

4,303

Revisions

280

Improved recovery

Purchases

Extensions and discoveries

362

Production

(381)

Sales

End of 2018

4,564

Revisions

(7)

Improved recovery

Purchases

Extensions and discoveries

252

Production

(388)

Sales

End of 2019

4,421

Total company

End of 2016

2,102

4,714

6,816

1,037

1,238

5,907

227

15,225

End of 2017

2,320

2,533

4,853

1,217

5,601

224

11,906

End of 2018

2,736

2,318

5,054

1,212

5,643

214

12,149

End of 2019

2,688

2,431

5,119

896

5,398

224

11,680

145

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

998

1,188

227

9,737

End of 2017

2,310

1,597

3,907

997

945

224

6,084

End of 2018

2,720

1,427

4,147

1,052

758

214

6,188

End of 2019

2,601

1,398

3,999

697

843

224

5,793

Equity affiliates

End of 2016

4,110

End of 2017

4,044

End of 2018

4,059

End of 2019

3,898

Undeveloped

Consolidated operations

End of 2016

515

523

240

338

1,107

End of 2017

936

946

220

353

1,519

End of 2018

891

907

160

321

1,397

End of 2019

1,033

1,120

199

134

1,466

Equity affiliates

End of 2016

271

End of 2017

259

End of 2018

505

End of 2019

523

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.

146

●

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.

147

Years Ended

Bitumen

December 31

Millions of Barrels

Canada

Developed and Undeveloped

Consolidated operations

End of 2016

159

Revisions

Improved recovery

Purchases

Extensions and discoveries

Production

(21)

Sales

End of 2017

250

Revisions

Improved recovery

Purchases

Extensions and discoveries

Production

(24)

Sales

End of 2018

236

Revisions

Improved recovery

Purchases

Extensions and discoveries

Production

(22)

Sales

End of 2019

282

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

250

End of 2018

236

End of 2019

282

148

Years Ended

Bitumen

December 31

Millions of Barrels

Canada

Developed

Consolidated operations

End of 2016

159

End of 2017

154

End of 2018

155

End of 2019

187

Equity affiliates

End of 2016

322

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

767

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

Canada.

149

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

393

528

444

241

4,470

Revisions

166

170

336

458

Improved recovery

Purchases

Extensions and discoveries

378

419

523

Production

(77)

(144)

(221)

(37)

(79)

(81)

(8)

(426)

Sales

(621)

(217)

(838)

End of 2017

1,430

1,353

2,783

254

517

406

233

4,193

Revisions

102

(161)

(59)

Improved recovery

Purchases

289

290

Extensions and discoveries

335

383

414

Production

(76)

(146)

(222)

(25)

(75)

(15)

(412)

Sales

(70)

(38)

(108)

End of 2018

1,795

1,312

3,107

245

465

342

224

4,383

Revisions

(67)

(23)

106

Improved recovery

Purchases

Extensions and discoveries

368

394

443

Production

(93)

(165)

(258)

(23)

(68)

(74)

(16)

(439)

Sales

(3)

(85)

(88)

End of 2019

1,779

1,447

3,226

296

360

298

234

4,414

Equity affiliates

End of 2016

1,089

865

1,954

Revisions

Improved recovery

Purchases

Extensions and discoveries

Production

(23)

(69)

(92)

Sales

(1,066)

End of 2017

845

Revisions

Improved recovery

Purchases

Extensions and discoveries

Production

(71)

Sales

End of 2018

880

Revisions

(1)

Improved recovery

Purchases

Extensions and discoveries

Production

(73)

Sales

End of 2019

848

Total company

End of 2016

1,294

1,570

2,864

1,482

528

1,309

241

6,424

End of 2017

1,430

1,353

2,783

254

517

1,251

233

5,038

End of 2018

1,795

1,312

3,107

245

465

1,222

224

5,263

End of 2019

1,779

1,447

3,226

296

360

1,146

234

5,262

150

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

391

365

309

241

3,674

End of 2017

1,319

682

2,001

158

372

281

233

3,045

End of 2018

1,617

681

2,298

160

382

244

221

3,305

End of 2019

1,582

666

2,248

197

275

236

218

3,174

Equity affiliates

End of 2016

322

820

1,142

End of 2017

802

End of 2018

796

End of 2019

761

Undeveloped

Consolidated operations

End of 2016

405

496

163

135

796

End of 2017

111

671

782

145

125

1,148

End of 2018

178

631

809

1,078

End of 2019

197

781

978

1,240

Equity affiliates

End of 2016

767

812

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

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

468

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.

151

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

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,

2018.

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.

152

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

709

3,207

3,032

919

19,106

Transfers

449

453

Transportation costs

(629)

(41)

(670)

Other revenues

139

1,785

101

326

2,449

Total revenues

4,319

6,434

10,753

795

4,992

3,452

1,020

326

21,338

Production costs excluding

taxes

1,235

1,578

2,813

380

741

619

(8)

4,615

Taxes other than income taxes

308

437

745

(2)

850

Exploration expenses

430

527

746

Depreciation, depletion

and

amortization

700

2,804

3,504

230

842

1,172

5,785

Impairments

402

405

Other related expenses

(12)

116

104

(38)

(42)

114

Accretion

111

142

303

1,929

618

2,547

164

3,207

1,426

883

293

8,520

Income tax provision (benefit)

444

147

591

(74)

591

458

833

2,406

Results of operations

1,485

471

1,956

238

2,616

968

286

6,114

Equity affiliates

Sales

599

Transfers

2,229

Transportation costs

Other revenues

Total revenues

2,859

Production costs excluding

taxes

335

Taxes other than income taxes

820

Exploration expenses

Depreciation, depletion

and

amortization

579

Impairments

Other related expenses

Accretion

1,098

Income tax provision (benefit)

170

Results of operations

928

153

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

582

4,449

3,177

950

20,547

Transfers

545

550

Transportation costs

(722)

(45)

(767)

Other revenues

335

213

548

164

737

110

432

1,997

Total revenues

4,434

6,786

11,220

746

5,186

3,683

1,060

432

22,327

Production costs excluding

taxes

964

1,533

2,497

417

856

646

4,480

Taxes other than income taxes

357

432

789

941

Exploration expenses

176

235

(4)

372

Depreciation, depletion

and

amortization

616

2,279

2,895

313

1,070

1,186

5,497

Impairments

(78)

Other related expenses

(62)

(19)

(1)

Accretion

107

178

331

2,365

2,188

4,553

(98)

3,132

1,679

965

411

10,642

Income tax provision (benefit)

419

466

885

(114)

1,354

683

926

(8)

3,726

Results of operations

1,946

1,722

3,668

1,778

996

419

6,916

Equity affiliates

Sales

758

Transfers

2,018

Transportation costs

Other revenues

(6)

Total revenues

2,770

Production costs excluding

taxes

321

Taxes other than income taxes

804

Exploration expenses

Depreciation, depletion

and

amortization

640

Impairments

Other related expenses

(4)

Accretion

994

Income tax provision (benefit)

103

Results of operations

891

154

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

705

3,527

2,752

487

15,570

Transfers

411

415

Transportation costs

(706)

(80)

(786)

Other revenues

2,158

322

2,649

Total revenues

2,854

4,585

7,439

2,863

3,595

3,094

535

322

17,848

Production costs excluding

taxes

947

1,607

2,554

604

770

566

(1)

4,537

Taxes other than income taxes

275

318

593

699

Exploration expenses

584

667

937

Depreciation, depletion

and

amortization

730

2,685

3,415

438

1,234

1,283

6,386

Impairments

179

3,969

4,148

4,216

Other related expenses

(7)

185

Accretion

115

172

340

595

(4,703)

(4,108)

1,721

1,239

1,012

406

278

548

Income tax provision (benefit)

(669)

(2,401)

(3,070)

(651)

702

363

428

(2,217)

Results of operations

1,264

(2,302)

(1,038)

2,372

537

649

(22)

267

2,765

Equity affiliates

Sales

528

563

1,091

Transfers

1,398

Transportation costs

Other revenues

Total revenues

533

1,961

2,494

Production costs excluding

taxes

174

363

537

Taxes other than income taxes

604

611

Exploration expenses

1,699

1,700

Depreciation, depletion

and

amortization

150

617

767

Impairments

1,717

Other related expenses

Accretion

195

(3,072)

(19)

(2,896)

Income tax provision (benefit)

(998)

(959)

Results of operations

169

(2,074)

(32)

(1,937)

155

Statistics

Net Production

2019

2018

2017

Thousands of Barrels Daily

Crude Oil

Consolidated operations

Alaska

202

171

167

Lower 48

266

229

180

United States

468

400

347

Canada

Europe

100

113

122

Asia Pacific

Africa

Total consolidated operations

692

639

585

Equity affiliates—

Asia Pacific/Middle East

Total company

705

653

599

Greater Prudhoe Area (Alaska)*

Natural Gas Liquids

Consolidated operations

Alaska

Lower 48

United States

Canada

Europe

Asia Pacific

Total consolidated operations

107

104

Equity affiliates—

Asia Pacific/Middle East

Total company

115

102

111

Greater Prudhoe Area (Alaska)*

Bitumen

Consolidated operations—

Canada

Equity affiliates—

Canada

Total company

122

Natural Gas

Millions of Cubic Feet Daily

Consolidated operations

Alaska

Lower 48

622

596

898

United States

629

602

905

Canada

187

Europe

447

475

476

Asia Pacific

637

626

687

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.

156

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

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

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

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 natural gas above

reflect a reduction

for transportation costs in which

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 Operation

157

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

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

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

16.55

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.

158

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

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

Africa

Other areas

Total consolidated operations

Equity affiliates

Asia Pacific/Middle East

Total equity affiliates

Development

Consolidated operations

Alaska

Lower 48

255

254

161

United States

267

265

170

Canada

Europe

Asia Pacific

Africa

Other areas

Total consolidated operations

298

288

198

Equity affiliates

Canada

Asia Pacific/Middle East

106

Other areas

Total equity affiliates

106

103

*Our total proportionate

interest was less than one.

159

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

997

Lower 48

349

170

10,070

4,547

4,329

1,704

United States

353

174

11,726

5,544

4,329

1,704

Canada

186

Europe

469

Asia Pacific

302

143

Africa

840

137

Other areas

Total consolidated operations

443

222

13,523

5,996

4,478

1,762

Equity affiliates

Asia Pacific/Middle East

325

4,307

1,051

Total equity affiliates

325

4,307

1,051

Acreage at December 31, 2019

Thousands of Acres

Developed

Undeveloped

Gross

Net

Gross

Net

Consolidated operations

Alaska

651

467

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

206

126

3,270

1,798

Europe

430

2,102

610

Asia Pacific

1,538

721

9,910

5,735

Africa

358

12,545

2,049

Other areas

1,400

742

Total consolidated operations

5,752

3,434

40,895

20,650

Equity affiliates

Asia Pacific/Middle East

933

229

3,723

840

Total equity affiliates

933

229

3,723

840

160

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

101

146

197

357

Proved property acquisition

116

117

115

232

102

161

263

115

197

589

Exploration

281

390

671

200

119

1,103

Development

1,125

3,028

4,153

215

625

486

5,501

1,508

3,579

5,087

429

744

667

236

7,193

Equity affiliates

Unproved property acquisition

Proved property acquisition

Exploration

Development

171

256

2018

Consolidated operations

Unproved property acquisition

119

126

245

126

371

Proved property acquisition

2,227

2,243

2,249

2,346

142

2,488

132

2,620

Exploration

203

500

703

(6)

975

Development

718

2,715

3,433

301

703

773

5,226

3,267

3,357

6,624

523

768

855

8,821

Equity affiliates

Unproved property acquisition

Proved property acquisition

Exploration

Development

206

228

2017

Consolidated operations

Unproved property acquisition

267

285

376

Proved property acquisition

302

320

411

Exploration

399

473

139

823

Development

736

1,559

2,295

102

784

388

3,579

828

2,260

3,088

234

836

542

4,813

Equity affiliates

Unproved property acquisition

Proved property acquisition

Exploration

Development

150

403

553

156

441

597

161

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

924

94,724

Unproved property

1,429

1,055

2,484

1,149

501

123

290

4,634

22,386

38,546

60,932

7,822

14,200

15,067

1,047

290

99,358

Accumulated depreciation,

depletion and amortization

9,419

26,294

35,713

2,050

9,017

10,253

379

57,421

12,967

12,252

25,219

5,772

5,183

4,814

668

281

41,937

Equity affiliates

Proved property

9,996

Unproved property

2,223

12,219

Accumulated depreciation,

depletion and amortization

6,390

5,829

2018

Consolidated operations

Proved property

20,154

35,269

55,423

5,946

23,520

14,866

902

100,657

Unproved property

1,184

1,125

2,309

1,083

188

874

119

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

342

61,662

12,283

12,395

24,678

5,337

7,117

5,766

679

43,657

Equity affiliates

Proved property

9,990

Unproved property

2,162

12,152

Accumulated depreciation,

depletion and amortization

5,960

6,192

162

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

577

4,143

2,179

484

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

558

835

460

13,933

Discounted future net cash flows

9,681

10,019

19,700

1,944

2,174

2,977

577

27,372

Equity affiliates

Future cash inflows

31,671

Less:

Future production costs

16,157

Future development costs

1,218

Future income tax provisions

3,086

Future net cash flows

11,210

10 percent annual discount

4,040

Discounted future net cash flows

7,170

Total company

Discounted future net cash flows

9,681

10,019

19,700

1,944

2,174

10,147

577

34,542

163

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

606

7,608

1,995

507

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

426

371

1,132

498

19,237

Discounted future net cash flows

13,377

12,544

25,921

908

3,341

4,663

601

35,434

Equity affiliates

Future cash inflows

33,606

Less:

Future production costs

16,449

Future development costs

1,228

Future income tax provisions

3,147

Future net cash flows

12,782

10 percent annual discount

4,853

Discounted future net cash flows

7,929

Total company

Discounted future net cash flows

13,377

12,544

25,921

908

3,341

12,592

601

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

696

8,758

2,511

537

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

366

2,918

4,839

887

29,500

10 percent annual discount

2,712

4,358

7,070

289

1,032

422

8,891

Discounted future net cash flows

5,425

7,995

13,420

288

2,629

3,807

465

20,609

Equity affiliates

Future cash inflows

23,222

Less:

Future production costs

12,984

Future development costs

1,444

Future income tax provisions

2,083

Future net cash flows

6,711

10 percent annual discount

2,316

Discounted future net cash flows

4,395

Total company

Discounted future net cash flows

5,425

7,995

13,420

288

2,629

8,202

465

25,004

164

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

260

382

(4)

3,245

4,956

1,441

Development costs for the

year

5,333

5,197

3,653

239

271

426

5,572

5,468

4,079

Changes in estimated future

development costs

559

(1,141)

1,225

(21)

(64)

538

(1,127)

1,161

Purchases of reserves in place,

less estimated future costs

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

869

485

413

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

458

(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.

165

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

Third

7,756

3,493

3,071

3,056

2.76

2.74

Fourth

7,708

1,286

743

720

0.66

2018

First

8,798

1,776

900

888

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.

166

Supplementary Information—Condensed Consolidating

Financial Information

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

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.

167

Millions of Dollars

Year Ended

December 31, 2019

Income Statement

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

775

(14,306)

779

Gain (loss) on dispositions

2,786

(820)

1,966

Other income

875

477

1,358

Intercompany revenues

113

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

421

131

(5)

556

Exploration expenses

422

321

743

Depreciation, depletion and amortization

596

5,494

6,090

Impairments

157

248

405

Taxes other than income taxes

139

814

953

Accretion on discounted liabilities

310

326

Interest and debt expense

283

544

133

(251)

778

Foreign currency transaction losses

Other expenses

Total Costs and Expenses

293

16,594

134

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)

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

239

824

1,063

Other income (loss)

(384)

557

173

Intercompany revenues

162

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

289

109

(5)

401

Exploration expenses

170

199

369

Depreciation, depletion and amortization

584

5,372

5,956

Impairments

(10)

Taxes other than income taxes

143

905

1,048

Accretion on discounted liabilities

336

353

Interest and debt expense

295

613

156

(375)

735

Foreign currency transaction (gains) losses

(12)

116

(167)

(17)

Other expenses

349

375

Total Costs and Expenses

349

17,757

172

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)

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.

168

Millions of Dollars

Year Ended

December 31, 2017

Income Statement

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

886

770

(2,477)

772

Gain on dispositions

916

1,261

2,177

Other income

492

529

Intercompany revenues

291

3,369

(3,721)

Total Revenues and

Other Income

(404)

15,722

899

22,565

(6,198)

32,584

Costs and Expenses

Purchased commodities

11,145

4,580

(3,250)

12,475

Production and operating expenses

813

4,366

(17)

5,162

Selling, general and administrative expenses

342

(6)

427

Exploration expenses

542

392

934

Depreciation, depletion and amortization

855

5,990

6,845

Impairments

1,159

5,442

6,601

Taxes other than income taxes

140

668

809

Accretion on discounted liabilities

330

362

Interest and debt expense

420

664

410

(448)

1,098

Foreign currency transaction (gains) losses

(43)

(137)

204

Other expenses

267

190

(6)

451

Total Costs and Expenses

653

15,893

(84)

22,458

(3,721)

35,199

Income (Loss) before income taxes

(1,057)

(171)

983

107

(2,477)

(2,615)

Income tax provision (benefit)

(202)

283

(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)

Net Income (Loss) Attributable to ConocoPhillips

(855)

(454)

1,320

1,611

(2,477)

(855)

Comprehensive Income (Loss) Attributable

to ConocoPhillips

(180)

221

1,672

2,275

(4,168)

(180)

See Notes to Consolidated Financial Statements.

169

Millions of Dollars

At December 31, 2019

Balance Sheet

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

358

3,028

Accounts and notes receivable

2,088

3,881

(2,575)

3,401

Investment in Cenovus Energy

2,111

Inventories

168

858

1,026

Prepaid expenses and other current assets

352

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

765

253

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)

105

Accrued income and other taxes

951

1,030

Employee benefit obligations

508

155

663

Other accruals

408

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

322

5,030

5,352

Deferred income taxes

5,438

(804)

4,634

Employee benefit obligations

1,329

452

1,781

Other liabilities and deferred credits*

1,787

7,514

826

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

248

Accounts and notes receivable

5,646

6,707

(8,392)

4,067

Investment in Cenovus Energy

1,462

Inventories

184

823

1,007

Prepaid expenses and other current assets

267

307

575

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

642

227

1,269

(798)

1,344

Total Assets

29,975

61,058

15,504

72,563

(109,120)

69,980

Liabilities and Stockholders’ Equity

Accounts payable

5,098

7,113

(8,392)

3,895

Short-term debt

(3)

(9)

112

Accrued income and other taxes

1,235

1,320

Employee benefit obligations

638

171

809

Other accruals

587

552

1,259

Total Current Liabilities

6,420

124

9,170

(8,401)

7,395

Long-term debt

3,791

7,151

2,143

2,249

(478)

14,856

Asset retirement obligations and accrued environmental

costs

415

7,273

7,688

Deferred income taxes

5,819

(798)

5,021

Employee benefit obligations

1,340

424

1,764

Other liabilities and deferred credits*

725

9,277

839

8,126

(17,775)

1,192

Total Liabilities

4,598

24,603

3,106

33,061

(27,452)

37,916

Retained earnings

27,512

18,511

1,113

9,764

(22,890)

34,010

Other common stockholders’ equity

(2,135)

17,944

11,285

29,613

(58,778)

(2,071)

Noncontrolling interests

125

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.

170

Millions of Dollars

Year Ended

December 31, 2019

Statement of Cash Flows

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

769

1,055

(8,233)

3,012

Net purchases of investments

(2,803)

(107)

(2,910)

Long-term advances/loans—related parties

(812)

812

Collection of advances/loans—related parties

141

147

(161)

127

Intercompany cash management

1,060

(2,849)

1,402

387

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

(812)

Repayment of debt

(21)

(220)

161

(80)

Issuance of company common stock

105

(135)

(30)

Repurchase of company common stock

(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

860

4,019

838

14,132

(6,915)

12,934

Cash Flows From Investing Activities

Capital expenditures and investments

(980)

(603)

(5,777)

610

(6,750)

Working

capital changes associated with investing activities

(110)

(68)

Proceeds from asset dispositions

3,457

666

1,926

705

(5,672)

1,082

Net sales of short-term investments

1,620

Long-term advances/loans—related parties

(126)

(173)

(10)

309

Collection of advances/loans—related parties

589

3,432

212

129

(4,243)

119

Intercompany cash management

(803)

3,504

(2,150)

(551)

Other

151

154

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

299

(309)

Repayment of debt

(4,865)

(53)

(4,320)

4,243

(4,995)

Issuance of company common stock

254

(133)

121

Repurchase of company common stock

(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

234

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.

171

Millions of Dollars

Year Ended

December 31, 2017

Statement of Cash Flows

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

194

(62)

132

Proceeds from asset dispositions

7,765

11,146

12,178

12,796

(30,025)

13,860

Net purchases of short-term investments

(1,790)

Long-term advances/loans—related parties

(214)

(65)

(20)

299

Collection of advances/loans—related parties

658

1,527

389

2,196

(4,655)

115

Intercompany cash management

1,151

101

(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

279

(299)

Repayment of debt

(5,459)

(4,411)

(2,661)

4,655

(7,876)

Issuance of company common stock

115

(178)

(63)

Repurchase of company common stock

(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)

233

232

Net Change in Cash and Cash Equivalents

(124)

(2)

2,841

2,715

Cash and cash equivalents at beginning of period

358

3,247

3,610

Cash and Cash Equivalents at End of Period

234

6,088

6,325

See Notes to Consolidated Financial Statements.

172

PART

Item 15. EXHIBITS, FINANCIAL STATEMENT

SCHEDULES

(a) 1. Financial

Statements and Supplementary Data

The financial statements and supplementary information

listed in the Index to Financial Statements, which appears

page 62, are filed as part of this Current Report.

Financial

Statement Schedules

Schedule II—Valuation and Qualifying Accounts, appears below.

All other schedules are omitted because they are not

required, not significant, not applicable or the information

is shown in another schedule, the financial statements

or the

notes to consolidated financial statements.

SCHEDULE II—VALUATION

AND QUALIFYING ACCOUNTS (Consolidated)

ConocoPhillips

Millions of Dollars

Balance at

Charged to

Balance at

Description

January 1

Expense

Other

(a)

Deductions

December 31

2019

Deducted from asset accounts:

Allowance for doubtful

accounts and notes receivable

(17)

(b)

Deferred tax asset valuation

allowance

3,040

7,376

(26)

(176)

10,214

Included in other liabilities:

Restructuring accruals

(1)

(24)

(c)

2018

Deducted from asset accounts:

Allowance for doubtful

accounts and notes receivable

(2)

(b)

Deferred tax asset valuation

allowance

1,254

2,067

(8)

(273)

3,040

Included in other liabilities:

Restructuring accruals

(2)

(73)

(c)

2017

Deducted from asset accounts:

Allowance for doubtful

accounts and notes receivable

(3)

(b)

Deferred tax asset valuation

allowance

675

560

1,254

Included in other liabilities:

Restructuring accruals

(93)

(c)

(a)Represents acquisitions/dispositions/revisions

and the effect of translating foreign

financial statements.

(b)Amounts charged

off less recoveries of amounts

previously charged

off.

(c)Benefit payments.

See Note 19

—

Income Taxes, in the Notes to Consolidated

Financial Statements,

for additional information

related to our deferred

tax asset valuation allowance.

d123119dex992

Exhibit 99.2

DeGolyer and MacNaughton

5001 Spring Valley

Road

Suite 800 East

Dallas, Texas 75244

February 18, 2020

ConocoPhillips

925 N. Eldridge Parkway

Houston, Texas 77079

Re: SEC Process Review

Ladies and Gentlemen:

Pursuant to your

request, DeGolyer and

MacNaughton has performed a

process review of

the processes and

controls used within

ConocoPhillips in preparing

its internal estimates

of proved

reserves, as of

December 31, 2019.

This process review,

which is contemplated by Item

1202 (a)(8) of Regulation

S–K of the United States

Securities and

Exchange Commission

(SEC), has been

performed specifically

to address the

adequacy and

effectiveness of

ConocoPhillips’ internal processes

and controls relative to

its estimation

of proved reserves in compliance with

Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC.

DeGolyer and

MacNaughton has

participated as

an independent

member of

the internal

ConocoPhillips

Reserves Compliance Assessment Team

in reviews and

discussions with each

of the relevant

ConocoPhillips business

units relative

to SEC

proved reserves

estimation. DeGolyer

and MacNaughton

has participated

in the

review of

all

major fields

in all

countries in

which ConocoPhillips

has proved

reserves worldwide,

which ConocoPhillips

has

indicated represents over 90 percent of its estimated total proved reserves as of December 31, 2019.

The reviews with ConocoPhillips’ technical

staff involved presentations and

discussions of a) basic reservoir

data, including seismic

data, well-log data,

pressure and production

tests, core analysis,

pressure-volume-temperature

data, and production history, b) technical methods employed

in SEC proved reserves estimation, including performance

analysis, geology,

mapping, and volumetric

estimates, c) economic analysis,

and d) commercial assessment,

including

the legal

basis for

the interest

in the

reserves, primarily

related to

lease agreements

and other

petroleum license

agreements, such as concession and production sharing agreements.

A field examination of the properties was not considered necessary for the purposes of this review of

ConocoPhillips’ processes and controls.

It is DeGolyer and MacNaughton’s

opinion that ConocoPhillips’ estimates of proved

reserves for the

properties reviewed were

prepared by the

use of recognized

geologic and engineering

methods generally accepted

the petroleum industry.

The method or combination of

methods used in the analysis

of each reservoir was tempered

ConocoPhillips’ experience with

similar reservoirs, stage

of development, quality

and completeness of basic

data, and

production history.

It is DeGolyer

and MacNaughton’s

opinion that 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.

This process

review of

ConocoPhillips’ procedures

and methods

does not

constitute a

review, study,

independent audit

of ConocoPhillips’ estimated

proved reserves and

corresponding future net

revenues. This

process

review is not intended

to indicate that DeGolyer

and MacNaughton is offering

any opinion as to

the reasonableness of

the reserves estimates reported by ConocoPhillips.

DeGolyer and MacNaughton

is an independent

petroleum engineering consulting

firm that has

been

providing petroleum consulting services throughout the world since 1936. Neither DeGolyer and MacNaughton nor any

employee who

participated in

this project

has any

financial interest,

including stock

ownership, in

ConocoPhillips.

DeGolyer and MacNaughton’s fees were not contingent on the results of its evaluation.

Very

truly yours,

/s/ DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

/s/ Charles F.

Boyette

Charles F. Boyette, P.E.

President

DeGolyer and MacNaughton