cop10k2020

2020

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington,

D.C. 20549

Form

10-K

(Mark One)

[

]

ANNUAL REPORT PURSUANT

TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended

December 31, 2020

[

]

TRANSITION REPORT PURSUANT

TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from

Commission file number:

001-32395

ConocoPhillips

(Exact name of registrant as specified in its

charter)

Delaware

01-0562944

(State or other jurisdiction of

(I.R.S. Employer

incorporation or organization)

Identification No.)

925 N. Eldridge Parkway

Houston

77079

(Address of principal executive offices)

(Zip Code)

Registrant's telephone number, including

area code:

281

293-1000

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

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

[x]

Yes

[ ] No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

[ ] Yes

[x]

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities

Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such

reports), and (2) has been subject to such filing requirements for the past 90 days. [x]

Yes

[ ] No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted

pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that

the registrant was required to submit such files).

[x]

Yes

[ ] No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller

reporting company, or an emerging growth company.

See the definitions of “large accelerated filer,” “accelerated filer,” “smaller

reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer

[x]

Accelerated filer [

]

Non-accelerated filer [

]

Smaller reporting company

[

]

Emerging

growth company

[

]

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for

complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [

]

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the

effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b))

by the registered public accounting firm that prepared or issued its audit report. [

]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). [

] Yes

[x]

The aggregate market value of common stock held by non-affiliates of the registrant on June 30, 2020, the last business day of the

registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $42.02, was $

45.1

billion.

The registrant had

1,354,734,727

shares of common stock outstanding at January 31, 2021.

Documents incorporated by reference:

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 11, 2021 (Part III)

TABLE OF CONTENTS

Page

Commonly Used Abbreviations……………………………………………………………………….

Item

PART

1 and 2.

Business and Properties

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

Corporate Structure

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

Segment and Geographic Information

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

Alaska

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

Lower 48

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

Canada ......................................................................................................................

Europe, Middle East and North Africa

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

Asia Pacific

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

Other International

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

Competition ...................................................................................................................

Human Capital Management .........................................................................................

General

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

1A.

Risk Factors

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

1B.

Unresolved Staff Comments

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

Legal Proceedings

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

Mine Safety Disclosures

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

Information About our Executive Officers

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

PART

Market for Registrant’s Common Equity, Related Stockholder Matters and

Issuer Purchases of Equity Securities

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

Management’s Discussion and Analysis of Financial Condition and

Results of Operations

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

7A.

Quantitative and Qualitative Disclosures

About Market Risk

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

Financial Statements and Supplementary

Data

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

Changes in and Disagreements with Accountants

on Accounting and

Financial Disclosure

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

179

9A.

Controls and Procedures

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

179

9B.

Other Information

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

179

PART

III

10.

Directors, Executive Officers and Corporate Governance

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

180

11.

Executive Compensation

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

180

12.

Security Ownership of Certain Beneficial Owners

and Management and

Related Stockholder Matters

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

180

13.

Certain Relationships and Related Transactions, and Director

Independence....................

180

14.

Principal Accounting Fees and Services

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

180

PART

15.

Exhibits, Financial Statement Schedules

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

181

Signatures ...........................................................................................................................

191

Commonly Used Abbreviations

The following industry-specific, accounting and other

terms, and abbreviations may be commonly

used in this

report.

Currencies

Accounting

$ or USD

U.S. dollar

ARO

asset retirement obligation

CAD

Canadian dollar

ASC

accounting standards codification

EUR

Euro

ASU

accounting standards update

GBP

British pound

DD&A

depreciation, depletion and

amortization

Units of Measurement

FASB

Financial Accounting Standards

BBL

barrel

Board

BCF

billion cubic feet

FIFO

first-in, first-out

BOE

barrels of oil equivalent

G&A

general and administrative

MBD

thousands of barrels per day

GAAP

generally accepted accounting

MCF

thousand cubic feet

principles

MBOD

thousand barrels of oil per day

LIFO

last-in, first-out

million

NPNS

normal purchase normal sale

MMBOE

million barrels of oil equivalent

PP&E

properties, plants and equipment

MMBOD

million barrels of oil per day

SAB

staff accounting bulletin

MBOED

thousands of barrels of oil

VIE

variable interest entity

equivalent per day

MMBOED

millions of barrels of oil

equivalent per day

Miscellaneous

MMBTU

million British thermal units

EPA

Environmental Protection Agency

MMCFD

million cubic feet per day

ESG

Environmental, Social and

Corporate Governance

European Union

Industry

FERC

Federal Energy Regulatory

CBM

coalbed methane

Commission

E&P

exploration and production

GHG

greenhouse gas

FEED

front-end engineering and design

HSE

health, safety and environment

FPS

floating production system

ICC

International Chamber of

FPSO

floating production, storage and

Commerce

offloading

ICSID

World Bank’s

International

G&G

geological and geophysical

Centre for Settlement of

JOA

joint operating agreement

Investment Disputes

LNG

liquefied natural gas

IRS

Internal Revenue Service

NGLs

natural gas liquids

OTC

over-the-counter

OPEC

Organization of Petroleum

NYSE

New York Stock Exchange

Exporting Countries

SEC

U.S. Securities and Exchange

PSC

production sharing contract

Commission

PUDs

proved undeveloped reserves

TSR

total shareholder return

SAGD

steam-assisted gravity drainage

U.K.

United Kingdom

WCS

Western Canada Select

U.S.

United States of America

WTI

West Texas

Intermediate

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

23 and “CAUTIONARY STATEMENT

FOR THE

PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS

OF THE PRIVATE

SECURITIES LITIGATION

REFORM ACT OF 1995,” beginning on page

75.

Items 1 and 2.

BUSINESS AND PROPERTIES

CORPORATE STRUCTURE

ConocoPhillips is an independent E&P company

headquartered in Houston, Texas with operations and

activities in 15 countries.

Our diverse, low cost of supply portfolio includes

resource-rich unconventional

plays in North America; conventional assets

in North America, Europe, and Asia; LNG developments;

oil

sands assets in Canada; and an inventory of

global conventional and unconventional exploration

prospects.

December 31, 2020, we employed approximately

9,700 people worldwide and had total

assets of $63 billion.

ConocoPhillips was incorporated in the state

of Delaware on November 16, 2001, in connection

with, and in

anticipation of, the merger between Conoco Inc. and Phillips

Petroleum Company.

The merger between

Conoco and Phillips was consummated on

August 30, 2002.

On January 15, 2021, we completed the acquisition

of Concho Resources Inc. (Concho), an independent

oil

and gas exploration and production company

with operations in New Mexico and West Texas focused on the

Permian Basin.

For additional information related to this

transaction, see Note 25—Acquisition of Concho

Resources Inc.,

in the Notes to Consolidated Financial Statements.

SEGMENT AND GEOGRAPHIC INFORMATION

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

region: Alaska; Lower 48;

Canada; Europe, Middle East and North Africa;

Asia Pacific;

and Other International.

Effective with the third

quarter of 2020, we restructured our segments

to align with changes to our internal organization.

The Middle

East business was realigned from the Asia Pacific

and Middle East segment to the Europe and North

Africa segment.

The segments have been renamed the Asia

Pacific segment and the Europe, Middle East

and

North Africa segment.

We have revised segment information disclosures and segment performance metrics

presented within our results of operations for the current

and prior years.

For operating segment and

geographic information, see Note 24—Segment

Disclosures and Related Information, in the Notes

Consolidated Financial Statements.

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

a worldwide

basis.

At December 31, 2020, our operations were

producing in the U.S., Norway, Canada, Australia,

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 in 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

2020

2019

2018

Crude oil

Consolidated operations

2,051

2,562

2,533

Equity affiliates

Total Crude Oil

2,119

2,635

2,611

Natural gas liquids

Consolidated operations

340

361

349

Equity affiliates

Total Natural Gas Liquids

376

400

391

Natural gas

Consolidated operations

1,011

1,209

1,265

Equity affiliates

621

736

760

Total Natural Gas

1,632

1,945

2,025

Bitumen

Consolidated operations

332

282

236

Total Bitumen

332

282

236

Total consolidated operations

3,734

4,414

4,383

Total equity affiliates

725

848

880

Total company

4,459

5,262

5,263

Total production, including Libya, of 1,127 MBOED decreased 221 MBOED or 16

percent in 2020 compared

with 2019, primarily due to:

●

Normal field decline.

●

The divestiture of our U.K. assets in the third

quarter of 2019 and our Australia-West assets in the

second quarter of 2020.

●

Production curtailments of approximately 80 MBOED,

primarily from North American operated

assets and Malaysia.

●

Lower production in Libya due to the forced shutdown

of the Es Sider export terminal and other

eastern export terminals after a period of civil unrest.

The decrease in production during 2020 was partly

offset by:

●

New wells online in the Lower 48, Canada,

Norway, Alaska and China.

Production excluding Libya for 2020 was 1,118 MBOED.

Adjusting for estimated curtailments

approximately 80 MBOED; closed acquisitions

and dispositions;

and excluding Libya, production for 2020

would have been 1,176 MBOED, a decrease of 15

MBOED compared with 2019 production.

This decrease

was primarily due to normal field decline, partly

offset by new wells online in the Lower 48, Canada,

Norway,

Alaska and China.

Production from Libya averaged

9 MBOED as it was in force majeure during

a significant

portion of the year.

Our worldwide annual average realized price decreased

34 percent from $48.78 per BOE in 2019

to $32.15 per

BOE in 2020 primarily due to lower realized crude

oil, natural gas and bitumen prices.

Our worldwide annual

average crude oil price decreased 35 percent, from

$60.99 per barrel in 2019

to $39.54 per barrel in 2020.

Our

worldwide annual average natural gas price decreased

32 percent, from $5.03 per MCF in 2019 to $3.41

per

MCF in 2020.

Average annual bitumen prices decreased 75 percent, from $31.72 per barrel in 2019 to

$8.02

per barrel in 2020.

ALASKA

The Alaska segment primarily explores for, produces, transports

and markets crude oil, natural gas and NGLs.

We 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 1.3 million net undeveloped

acres at

year-end 2020.

Alaska operations contributed 28 percent

of our consolidated liquids production and 1 percent

of our consolidated natural gas production.

2020

Crude Oil

NGL

Natural Gas

Total

Interest

Operator

MBD

MMCFD

MBOED

Average Daily Net Production

Greater Prudhoe Area

36.1

Hilcorp

Greater Kuparuk Area

89.2-94.7

ConocoPhillips

Western North Slope

100.0

ConocoPhillips

Total Alaska

181

198

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.

In 2020, development activity included both rotary

and coiled-tubing drilling through April,

resulting in ten

wells drilled and brought online.

In response to the oil price collapse, the second

half of 2020 saw a reduction

in rig activity.

Average net production increased from 81

MBOED in 2019 to 84 MBOED in 2020.

Greater Kuparuk Area

We 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 the Prudhoe

Bay Field.

Field

installations include three central production facilities

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

seawater treatment plant.

Development drilling at Kuparuk consists of

rotary-drilled wells and horizontal

multi-laterals from existing well bores utilizing

coiled-tubing drilling.

We operated both a rotary and a coiled-tubing drilling rig in the first half of

2020, resulting in seven operated

wells drilled and brought online in 2020.

In response to the oil price collapse, the second

half of 2020 saw a

reduction in rig activity.

Average net production decreased from 86 MBOED in 2019 to 74 MBOED in

2020.

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.

The Alpine Field is located 34 miles west of

the Kuparuk Field.

2020, an extended-reach drilling rig was delivered

to the Alpine CD2 drillsite.

This rig is North America’s

largest mobile land rig and is expected to commence

drilling operations in 2021.

The Greater Mooses Tooth Unit is the first unit established entirely within the

NPR-A.

In 2017, we began

construction in the unit with two drill sites;

Greater Mooses Tooth #1 (GMT-1) and Greater Mooses Tooth

(GMT-2).

GMT-1 achieved first oil in 2018 and completed drilling in 2019.

In 2020, the second of three

construction seasons for GMT-2 was completed and drilling operations are expected to commence

in 2021

with first oil later in the year.

We operated both a rotary and a coiled-tubing drilling rig in the Western North Slope during 2020, resulting in

five operated wells drilled and brought online.

In response to the oil price collapse, the

second half of 2020

saw a reduction in rig activity.

Average net production decreased from 51 MBOED in 2019 to 40 MBOED in

2020.

Production Curtailments

In response to the oil price collapse that began in

early 2020,

we curtailed operated production—in the Greater

Kuparuk Area and Western North Slope—by 8 MBOED in 2020.

For more information related to the 2020

industry downturn and our response, please see Item

7. Management’s Discussion and Analysis of Financial

Condition and Results of Operations.

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, however, AGDC decided to continue

its own, focusing primarily on permitting efforts.

Currently, AGDC is in the process of seeking new sponsors

for the project.

Given current market conditions, we no longer believe

the project will advance and since there

is no current market,

we recorded a before-tax impairment of $841 million

for the entire associated carrying

value of capitalized undeveloped leasehold costs

and an equity method investment related

to our Alaska North

Slope Gas asset.

We remain willing to sell our Alaska North Slope Gas to interested parties on a competitive

basis if a market materializes in the future.

For additional information related to this

impairment, See Note

7—Suspended Wells and Exploration Expenses, in the Notes to Consolidated Financial

Statements.

Exploration

Appraisal of the Willow Discovery in the Bear Tooth Unit in the National Petroleum Reserve-Alaska (NPR-A)

continued with the drilling of two of four planned

appraisal wells before the early cancellation

of the 2020

program as part of our COVID-19 response.

The reduced 2020 appraisal program consisted

of drilling a

horizontal well in the eastern portion of the field,

informing the reservoir’s connectivity,

and a vertical well in

the field’s southern extent, reducing the original oil in place uncertainty.

The initial development plan for the

Willow Discovery, approved in the fourth quarter, does not include the Cassin Discovery from 2013; therefore,

we recognized dry hole expense for two previously

suspended Cassin wells in 2020.

In 2020, exploration of the Harpoon Complex—Harpoon,

Lower Harpoon and West Harpoon—commenced.

One exploration well of a planned three-well program

was drilled before the early cancellation

of our 2020

winter drilling season in response to COVID-19.

The well was expensed as a dry hole after

evaluations

confirmed the well intersected sub-commercial

volumes of hydrocarbons

in the upper Harpoon interval which

will not be developed.

Future exploration plans include returning

to the Harpoon Complex to explore the

remaining potential.

In late 2018, we commenced appraisal of the

Putu Discovery with a long-reach well from

existing Alpine CD4

infrastructure.

In 2019 and 2020 the long reach CD4 appraisal

and supporting injector well finished drilling

and testing. Production and injectivity tests

confirmed development and waterflood feasibility

of the reservoir.

The project transitioned from appraisal to development

in early 2020.

Development planning is ongoing.

A 3-D

seismic survey was completed in 2020 over

a 234-mile area on state and federal

lands.

We are currently

evaluating this seismic data for future exploration

opportunities.

Transportation

We transport the petroleum liquids produced on the North Slope to Valdez, Alaska through an 800-mile

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

We have a 29.5

percent ownership interest in

TAPS, and we also have ownership interests in and operate 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

On January 15,

2021, we completed the acquisition of Concho.

This transaction significantly increases our

Permian position by adding complementary acreage

across the Delaware and Midland basins.

The production

and acreage figures and the property descriptions

below do not reflect this recently closed acquisition.

For

additional information related to this acquisition,

see Note 25—Acquisition of Concho Resources

Inc., in the

Notes to Consolidated Financial Statements.

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, at year-end 2020 we held 10.1 million net

onshore and offshore acres, with a portfolio of low cost of

supply, shorter cycle time, resource-rich

unconventional plays, and conventional production

from legacy assets.

Based on 2020 production volumes,

the Lower 48 is the company’s largest segment and contributed 40 percent of our

consolidated liquids

production and 44 percent of our consolidated

natural gas production.

2020

Crude Oil

NGL

Natural Gas

Total

Interest

Operator

MBD

MMCFD

MBOED

Average Daily Net Production

Eagle Ford

Various

103

228

186

Gulf of Mexico

Various

Gulf Coast—Other

Various

Total Gulf Coast

113

241

199

Bakken

Various

Permian Unconventional

Various

113

Permian Conventional

Various

Anadarko Basin

Various

Wyoming/Uinta

Various

Niobrara*

Various

Total Great Plains

100

344

186

Total Lower 48

213

585

385

*Disposed in March 2020.

See Note 4

—

Acquisitions and Dispositions in the Notes to Consolidated

Financial Statements for additional

information.

Onshore

At December 31, 2020, we held 10.1 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

1.3 million net acres in the following areas:

●

610,000 net acres in the Bakken, located in

North Dakota and eastern Montana.

●

200,000 net acres in the Eagle Ford, located in South

Texas.

●

170,000 net acres in the Permian, located in West Texas and southeastern New Mexico.

●

300,000 net acres in other areas with unconventional

potential.

In response to the oil price collapse that began

in early 2020, we curtailed production

in the Lower 48 by

approximately 55 MBOED in 2020.

For more information related to the 2020 industry

downturn and our

response, please see Item 7. Management’s Discussion and Analysis of Financial

Condition and Results of

Operations.

These production curtailments contributed to

lower production in 2020 compared with

2019 from

our three focus areas:

●

Eagle Ford—We operated five rigs on average in the Eagle Ford during 2020,

resulting in 154

operated wells drilled and 71 operated wells brought

online.

Production decreased 14 percent in 2020

compared with 2019, averaging 186 MBOED and

216 MBOED, respectively.

●

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

additional development activities operated by co-venturers.

We continued our pad drilling with 57

operated wells drilled during the year and 29

operated wells brought online.

Production decreased 20

percent in 2020 compared with 2019, averaging

78 MBOED and 97 MBOED, respectively.

●

Permian Basin—The Permian Basin is a combination

of legacy conventional and unconventional

assets.

We operated one rig during the full year and another rig during parts of the year

in the Permian

Basin, resulting in 16 operated wells drilled and

16 operated wells brought online.

Production

decreased 1 percent in 2020 compared with 2019,

averaging 85 MBOED and 86 MBOED,

respectively.

Gulf of Mexico

At year-end 2020,

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 interest in the unitized Ursa Field

located in the Mississippi Canyon Area.

●

15.9 percent interest in the Princess Field, a northern

subsalt extension of the Ursa Field.

●

12.4 percent interest in the unitized K2 Field,

comprised of seven blocks in the Green Canyon

Area.

Dispositions

In the first quarter of 2020, we completed the sale

of our Waddell Ranch interests in the Permian Basin and our

Niobrara interests.

Production from these dispositions was immaterial

to the Lower 48 segment in 2020.

For

additional information on these transactions,

see Note 4—Asset Acquisitions and Dispositions,

in the Notes to

Consolidated Financial Statements.

Facilities

●

Lost Cabin Gas Plant—We operate and own a 60 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 first half of 2021.

The expected production loss in 2021

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.

This facility is currently being

decommissioned.

CANADA

Our Canadian operations consist of the Surmont

oil sands development in Alberta and the liquids-rich

Montney unconventional play in British Columbia.

In 2020, operations in Canada contributed

9 percent of our

consolidated liquids production and 3 percent

of our consolidated natural gas production.

2020

Crude Oil

NGL

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.

We hold approximately 600,000 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. that offers long-lived, sustained production.

We are focused on

structurally lowering costs, reducing GHG intensity

and optimizing asset performance.

In response to the oil price collapse that began

in early 2020, we voluntarily curtailed

production at Surmont

by approximately 12 MBOED in 2020.

For more information related to the 2020 industry

downturn and our

response, please see Item 7. Management’s Discussion and Analysis of Financial

Condition and Results of

Operations.

Montney

In August 2020, we completed the acquisition

of additional Montney acreage from Kelt Exploration.

This

acquisition consisted primarily of undeveloped

properties, including 140,000 net acres in the

liquids-rich Inga

Fireweed asset Montney zone, which is directly

adjacent to our existing Montney position.

We now hold

approximately 300,000 net acres in the Montney

play with a 100 percent working interest.

For additional

information related to the Kelt Exploration acquisition,

please see Note 4—Acquisitions and Dispositions,

the Notes to Consolidated Financial Statements.

Following the completion of third-party offtake facilities,

our newly commissioned processing facility

and

production from our 2019 drilling program

came online in February 2020.

In 2020, development activity

consisted of drilling 14 horizontal wells and completing

18 wells.

Overall, 23 wells came online in 2020.

2021, appraisal drilling and completions activity

will continue to further explore the area’s resource potential.

Exploration

Our primary exploration focus is assessing our

Montney acreage.

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

consists of operations principally located in the

Norwegian

sector of the North Sea; the Norwegian Sea;

Qatar; Libya; and commercial and terminalling

operations in the

U.K.

In 2020, operations in Europe, Middle East

and North Africa contributed 13 percent of our

consolidated

liquids production and 20 percent of our consolidated

natural gas production.

Norway

2020

Crude Oil

NGL

Natural Gas

Total

Interest

Operator

MBD

MMCFD

MBOED

Average Daily Net Production

Greater Ekofisk Area

30.7-35.1

ConocoPhillips

Heidrun

24.0

Equinor

Aasta Hansteen

10.0

Equinor

Troll

1.6

Equinor

Alvheim

20.0

Aker BP

Visund

9.1

Equinor

Other

Various

Equinor

Total Norway

270

127

The Greater Ekofisk Area is located approximately

200 miles offshore Stavanger, Norway, in the North Sea,

and comprises four producing fields: Ekofisk, Eldfisk,

Embla and Tor.

The Tor II redevelopment achieved

first production in December 2020.

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,

with development drilling continuing over the

coming years.

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 of

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.

Aasta Hansteen is a gas and condensate field located

in the Norwegian Sea.

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.

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.

We also have varying ownership interests in two other producing fields in the Norway

sector of the North Sea.

Exploration

A well we participated in during 2019, Canela,

was expensed as a dry hole in 2020 after post

drill analysis.

In 2020, we completed the third well of a three-well

operated exploration campaign in Block 25/7

in the North

Sea with the Hasselbaink Well.

The Hasselbaink Well encountered insufficient hydrocarbons and was

expensed as a dry hole in 2020.

In the second half of 2020 we completed

a two-well operated exploration

campaign in the Norwegian Sea with the Warka and Slagugle wells.

Both the Warka and Slagugle wells

encountered hydrocarbons and will be evaluated

for future appraisal programs.

We were awarded three new exploration licenses; PL1045, PL1047 and PL1064; and two

acreage additions,

PL917B and PL1009B.

Additionally, we exchanged our interest in the PL938 exploration license for

increased interest in the PL1047 exploration

license.

Transportation

We 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.

Facilities

We operate and have a 40.25 percent ownership interest in an oil terminal at Teesside, England to support our

Norway operations.

Qatar

2020

Crude Oil

NGL

Natural

Gas

Total

Interest

Operator

MBD

MMCFD

MBOED

Average Daily Net Production

Qatargas Operating

QG3

30.0

Company Limited

371

Total Qatar

371

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.