CompuGroup Medical Annual Report 2021

FY2021 Annual Report · CompuGroup Medical

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Annual Report 2021

Letter to Shareholders

Dear Fellow Shareholders,

For ConocoPhillips, 2021 saw remarkable
achievements during a constructive time for our
company and industry. Coming out of one of the
most challenging years for our sector, we entered
2021 in an advantaged position, which we attribute
to our disciplined business model — generating
free cash flow, maintaining a strong balance sheet,
delivering compelling returns on and of capital, and

“ConocoPhillips enters 2022 a stronger,
more resilient company with momentum
from a transformative year. We are
prepared to reliably generate competitive
returns while thoughtfully moving forward
as a responsible and valuable player
throughout the energy transition.”

demonstrating ESG leadership. These principles
enabled us to deliver strong financial, operational
and organizational performance, and complete two
highly accretive and transformative transactions in
the Permian Basin.

Underpinning our value proposition is our Triple
Mandate, which ensures that everything we do
aligns with the underlying realities of our business
as society focuses on transitioning toward a lower-
carbon energy future. Our actions throughout 2021
supported and enhanced three objectives:

• Meeting energy transition pathway demand.

• Delivering competitive returns on and of capital

through the price cycles.

• Achieving our net-zero ambition on operational

emissions.

A Year of Operational Progress
We began 2021 by completing the acquisition of
Concho Resources and successfully integrating its
talented workforce and assets into our company,
ultimately exceeding our target and delivering
$1 billion in synergies. Then late in the year we
further expanded our Permian Basin holdings
through acquisition of Shell’s Permian assets, adding
complementary properties that feature low cost of
supply and low greenhouse gas emissions intensity.
These two additions to our existing holdings made

ConocoPhillips a major producer in the Permian,
which is now the world’s most productive oil field
and a leading contributor to recent and projected
future U.S. production growth.

Globally, we produced nearly 1.6 million barrels
of oil equivalent per day and achieved significant
milestones that included startups from GMT2 in
Alaska, a third Montney multi-well pad in Canada,
Phase 2 projects at Malikai and SNP in Malaysia,
and completion of the Tor II development in
Norway.

We further high-graded our portfolio with several
noncore Lower 48 asset sales. In the Asia Pacific
region we announced the sale of our Indonesia
assets for about $1.4 billion and exercised our
preemption rights to increase our stake in Australia
Pacific LNG. Collectively our 2021 transactions
helped reduce both the average supply cost and
greenhouse gas emissions intensity of our more
than 20-billion-barrel resource base.

Meeting Commitments
Fulfilling longstanding commitments, during 2021
we generated a 14% return on capital employed
and returned 38% of cash from operations through
$2.4 billion in dividends and $3.6 billion of share
repurchases. We introduced a third return tier,
a variable return of cash (VROC), with the initial
two payments scheduled for the first and second
quarters of 2022.

2021 saw continued momentum toward our
net-zero emissions ambition. We improved our
Scope 1 and 2 greenhouse gas emissions-intensity
reduction targets to 40-50% from a 2016 baseline
on a net equity and gross operated basis by 2030,
from the previous 35-45% target on only a gross
operated basis. We thus committed to working
with partners that operate net-equity assets to
ensure that their climate strategies align with our
own. We established a Low-Carbon Technologies
organization to evaluate potential investments
in emissions-reduction and low-carbon business
development opportunities.

CONOCOPHILLIPS AT A GL ANCE

2021 Highlights
❯ Generated earnings of $8.1 billion

❯ Produced 1.567 million barrels of oil
equivalent per day (including Libya)

❯ Made two transformative and

accretive acquisitions that added
production and long-term potential

❯ Introduced Human Capital
Management Report

❯ Started up projects in Alaska,

Canada and Malaysia; completed Tor II
in Norway

❯ Returned $6 billion to shareholders

Who We Are

ONE OF THE
WORLD’S
LARGEST
INDEPENDENT
E&P
COMPANIES

COUNTRIES WITH
OPERATIONS AND
ACTIVITIES

AMONG LEADING
PRODUCERS
FROM NORTH
AMERICAN SHALE

BALANCED,
DIVERSIFIED
GLOBAL
PORTFOLIO

$91B

IN TOTAL ASSETS

~9,900

EMPLOYEES

As of Dec. 31, 2021

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Focusing on Our People
Our strategy, performance, culture and reputation
are fueled by our world-class workforce. They made
possible all our 2021 achievements. We highlighted
their stories in our inaugural Human Capital
Management Report, which details our ongoing
actions to inspire a compelling culture that attracts,
retains and develops our people.

We took multiple steps to strengthen our SPIRIT
Values-based culture, particularly as we integrated
employees from Concho and Shell. We rolled out
multi-year global diversity, equity and inclusion (DEI)
priorities and tactics that will guide our actions over
the next few years. At several office locations we
implemented a Hybrid Office Work (HOW) program
offering increased flexibility to work from home two
days a week, while retaining the benefits of in-person
office-based interaction and collaboration on the
other three days.

guided by three companywide priorities set during
the pandemic’s early stages: protect employees and
contractors, mitigate COVID-19’s spread and safely run
the business. Our Crisis Management Support Team
provided overall guidance, frequent communications
and flexible programs to help manage the challenging
environment.

Looking Forward
ConocoPhillips enters 2022 a stronger, more resilient
company with momentum from a transformative year.
We are prepared to reliably generate competitive
returns while thoughtfully moving forward as a
responsible and valuable player throughout the
energy transition. We sincerely thank our employees
for their efforts during a highly productive year, and
our shareholders for their continuing support.

Ensuring our employees’ health and well-being
remained an ongoing focus as the world continued
adapting to the realities of COVID-19. Our actions were

Ryan M. Lance
Chairman and Chief Executive Officer
Feb. 17, 2022

S P O T L I G H T

Playing a Valued
Role in the Energy
Transition

ConocoPhillips has long acknowledged that we
play an essential role in a vital industry, while also
recognizing that we are part of an energy transition
already underway. We believe that the transition
cannot be achieved quickly, easily or inexpensively,
given the scale of the challenge of replacing the
global energy system. Time will be needed to
develop the alternative and renewable technologies
and infrastructure required to match the availability,
flexibility, affordability and energy intensity of oil

and natural gas. Experts therefore recognize that
the future energy mix must retain varying amounts
of oil and natural gas even in low-carbon transition
scenarios, though in gradually declining quantities
and produced in cleaner forms.

Considering these realities, the transition will likely be
a complex evolution with many possible pathways
and uncertainties — more likely to be an evolution
than a near-term step change. ConocoPhillips intends
to apply our strategic capabilities and resources
to meet this challenge in an economically viable,
accountable and actionable way that balances the
interests of all stakeholders. Our goal is to support
an orderly transition that matches supply to demand
and focuses on returns on and of capital while safely
and responsibly delivering affordable energy.

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2021

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K

(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2021
OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to

Commission file number: 001-32395

ConocoPhillips

(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of incorporation or organization)

01-0562944
(I.R.S. Employer identification No.)

925 N. Eldridge Parkway, Houston, TX 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

Common Stock, $.01 Par Value
7% Debentures due 2029

Trading symbols
COP
CUSIP—718507BK1

Name of each exchange on which registered
New York Stock Exchange
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] No

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. [ x ]

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

The aggregate market value of common stock held by non-affiliates of the registrant on June 30, 2021, the last business day of the
registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $60.90, was $81.5 billion.

The registrant had 1,299,526,916 shares of common stock outstanding at January 31, 2022.

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 10, 2022 (Part III)

Documents incorporated by reference:

Table of Contents

Commonly Used Abbreviations

Item

1 and 2.

Part I

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
3.
4. Mine Safety Disclosures

Information About our Executive Officers

Part II

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

Issuer Purchases of Equity Securities

[Reserved]

6.
7. Management’s Discussion and Analysis of Financial Condition and

Results of Operations

7A. Quantitative and Qualitative Disclosures About Market Risk

8.
9.

Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and

Financial Disclosure
Controls and Procedures

9A.
9B. Other Information
9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Part III

10. Directors, Executive Officers and Corporate Governance
11.
12.

Executive Compensation
Security Ownership of Certain Beneficial Owners and Management and

Related Stockholder Matters

13.
14.

Certain Relationships and Related Transactions, and Director Independence
Principal Accounting Fees and Services

15.

Exhibits, Financial Statement Schedules
Signatures

Part IV

Page
1

2
2
2
4
5
7
8
10
13
15
15
19
20
30
30
30
30

34
71
74

178
178
178
178

179
179

179
179
179

180
186

Commonly Used Abbreviations

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

Currencies
$ or USD
CAD
EUR
GBP

Units of Measurement
BBL
BCF
BOE
MBD
MCF
MBOD
MM
MMBOE
MMBOD
MBOED

MMBOED

MMBTU
MMCFD

Industry
BLM
CBM
E&P
CCUS

FEED
FPS
FPSO

G&G
JOA
LNG
NGLs
OPEC

PSC
PUDs
SAGD
WCS
WTI

U.S. dollar
Canadian dollar
Euro
British pound

barrel
billion cubic feet
barrels of oil equivalent
thousands of barrels per day
thousand cubic feet
thousand barrels of oil per day
million
million barrels of oil equivalent
million barrels of oil per day
thousands of barrels of oil
equivalent per day
millions of barrels of oil
equivalent per day
million British thermal units
million cubic feet per day

Bureau of Land Management
coalbed methane
exploration and production
carbon capture utilization and
storage
front-end engineering and design
floating production system
floating production, storage and
offloading
geological and geophysical
joint operating agreement
liquefied natural gas
natural gas liquids
Organization of Petroleum
Exporting Countries
production sharing contract
proved undeveloped reserves
steam-assisted gravity drainage
Western Canada Select
West Texas Intermediate

Accounting
ARO
ASC
ASU
DD&A

FASB

FIFO
G&A
GAAP

LIFO
NPNS
PP&E
VIE

Miscellaneous
DE&I
EPA
ESG

EU
FERC

GHG
HSE
ICC

ICSID

IRS
OTC
NYSE
SEC

TSR
U.K.
U.S.
VROC

asset retirement obligation
accounting standards codification
accounting standards update
depreciation, depletion and
amortization
Financial Accounting Standards
Board
first-in, first-out
general and administrative
generally accepted accounting
principles
last-in, first-out
normal purchase normal sale
properties, plants and equipment
variable interest entity

diversity, equity and inclusion
Environmental Protection Agency
Environmental, Social and
Governance
European Union
Federal Energy Regulatory
Commission
greenhouse gas
health, safety and environment
International Chamber of
Commerce
World Bank’s International
Centre for Settlement of
Investment Disputes
Internal Revenue Service
over-the-counter
New York Stock Exchange
U.S. Securities and Exchange
Commission
total shareholder return
United Kingdom
United States of America
variable return of cash

1 ConocoPhillips 2021 10-K

Business and Properties

Part I

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,” “believe,” “budget,” “continue,” “could,” “effort,”
“estimate,” “expect,” “forecast,” “goal,” “guidance,” “intend,” “may,” “objective,” “outlook,” “plan,” “potential,”
“predict,” “projection,” “seek,” “should,” “target,” “will,” “would,” 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
20 and “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on page 69.

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
14 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. On December 31, 2021, we
employed approximately 9,900 people worldwide and had total assets of about $91 billion. Total company
production for the year was 1,567 MBOED.

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. In April 2012, ConocoPhillips completed the separation of the
downstream business into an independent, publicly traded energy company, Phillips 66.

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 3.

On December 1, 2021, we completed our acquisition of Shell Enterprises LLC’s (Shell) assets in the Delaware Basin.
Assets acquired include approximately 225,000 net acres of producing properties located entirely in Texas. For
additional information related to this transaction, see Note 3.

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. For operating segment and
geographic information, see Note 23.

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on a worldwide
basis. At December 31, 2021, our operations were producing in the U.S., Norway, Canada, Australia, Indonesia,
Malaysia, Libya, China and Qatar.

ConocoPhillips 2021 10-K 2

Business and Properties

The information listed below appears in the “Supplementary Data - 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 “Supplementary Data - Oil and
Gas Operations” disclosures following the Notes to Consolidated Financial Statements. Approximately 86 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

2021

2,964
63
3,027

644
33
677

1,523
617
2,140

257
257

5,388
713
6,101

2020

2,051
68
2,119

340
36
376

1,011
621
1,632

332
332

3,734
725
4,459

2019

2,562
73
2,635

361
39
400

1,209
736
1,945

282
282

4,414
848
5,262

Net Proved Reserves at December 31
Crude oil

Consolidated operations
Equity affiliates

Total Crude Oil

Natural gas liquids

Consolidated operations
Equity affiliates

Total Natural Gas Liquids

Natural gas

Consolidated operations
Equity affiliates

Total Natural Gas

Bitumen

Consolidated operations

Total Bitumen

Total consolidated operations
Total equity affiliates
Total company

3 ConocoPhillips 2021 10-K

Business and Properties

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 2021. Alaska
operations contributed 19 percent of our consolidated liquids production and 1 percent of our consolidated
natural gas production.

Average Daily Net Production
Greater Prudhoe Area
Greater Kuparuk Area
Western North Slope
Total Alaska

Interest

Operator

Crude Oil

NGL
MBD MBD

Natural Gas
MMCFD

Total
MBOED

2021

36.1 %

89.2-94.7
100.0

Hilcorp
ConocoPhillips
ConocoPhillips

67
73
38
178

16
-
-
16

12
2
2
16

85
73
39
197

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 conventional oil field in North America, is the site of a large
waterflood and enhanced oil recovery operation, supported by a large gas and water processing operation.
Prudhoe Bay’s western satellite fields 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.
Field installations include seven production facilities, two gas plants, two seawater plants and a central power
station.

In September 2021, rotary drilling commenced after 18 months of no drilling, resulting in four wells drilled and
brought online. To help offset decline, efforts were focused on increasing rate through well work, capacity
enhancements, less downtime, and NGL production.

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 a coiled-tubing drilling rig in the fourth quarter of 2021, resulting in five operated wells drilled and
brought online.

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. Field installations
include one central production facility which separates oil, natural gas and water.

The Greater Mooses Tooth Unit is the first unit established entirely within the National Petroleum Reserve Alaska
(NPR-A). In 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 2018 and completed drilling in 2019. In 2021, the
third and final construction season for GMT-2 was successfully completed, and drilling operations commenced
during the second quarter. First oil for GMT-2 was achieved in the fourth quarter of 2021, as planned.

During 2021, we operated a conventional rotary rig and an extended reach drilling rig in the Western North Slope,
resulting in seven operated wells drilled and brought online.

ConocoPhillips 2021 10-K 4

Business and Properties

Exploration
Appraisal of the Willow Discovery, located 36 miles from Nuiqsut in the Bear Tooth Unit in the NPR-A, was
conducted in 2020. There was no appraisal activity in 2021. In August 2021, an Alaska federal judge vacated the
U.S. government’s approval granted to our planned Willow project previously approved by the BLM in October
2020. The Department of Justice did not appeal the decision and neither did we. We are actively supporting the
BLM and Department of Interior as they conduct the Supplemental Environmental Impact Statement process to
address issues highlighted by the federal district court. In the interim, we are continuing with FEED work in service
of a final investment decision.

The Stony Hill 1 well located to the east of the Greater Mooses Tooth Unit within the NPR-A was plugged and
abandoned in 2021 and expensed as a dry hole.

A 3D seismic survey covering 234 square miles was completed in 2020 on state and federal lands. We are currently
evaluating this seismic data for future exploration opportunities.

In late 2021, the Coyote Brookian topset exploration prospect in the Kuparuk River Unit was tested with a near
vertical sidetrack from an existing wellbore. The well was fracture stimulated and will undergo well testing early in
2022 to confirm longer term deliverability.

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
The Lower 48 segment consists of operations located in the 48 contiguous U.S. states and the Gulf of Mexico. The
segment is organized into the Permian and Gulf Coast and Rockies business units with a portfolio of low cost of
supply, short cycle time, resource-rich unconventional plays, and conventional production from legacy assets.
Based on 2021 production volumes, the Lower 48 is the company’s largest segment and contributed 55 percent of
our consolidated liquids production and 64 percent of our consolidated natural gas production.

In 2021, we completed two acquisitions significantly increasing our Permian position in the Lower 48. On January
15, 2021, we completed the acquisition of Concho adding complementary acreage across the Delaware and
Midland basins. On December 1, 2021, we completed the acquisition of Shell’s Delaware Basin position adding
significant Texas acreage in the Delaware Basin. The accounting close date used for reporting purposes of the Shell
transaction was December 31, 2021. For additional information related to these acquisitions, see Note 3.

5 ConocoPhillips 2021 10-K

Business and Properties

Average Daily Net Production
Delaware Basin
Midland Basin
Permian—Other
Total Permian
Eagle Ford
Bakken
Gulf Coast and Rockies—Other
Total Gulf Coast and Rockies
Total Lower 48

2021

Crude Oil

NGL
MBD MBD

Natural Gas
MMCFD

Total
MBOED

162
89
11
262
116
59
10
185
447

27
9
2
38
53
16
3
72
110

584
229
40
853
251
117
119
487
1,340

286
136
20
442
211
94
33
338
780

At December 31, 2021, we held 10.8 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 2 million net acres in the following areas:

•
•
•
•
•

560,000 net acres in the Bakken, located in North Dakota and eastern Montana.
200,000 net acres in the Eagle Ford, located in South Texas.
654,000 net acres in the Permian—Delaware Basin, located in West Texas and southeastern New Mexico.
266,000 net acres in the Permian—Midland Basin, located in West Texas.
293,000 net acres in other areas with unconventional potential.

The majority of our 2021 onshore production activities were centered on continued development of assets, with
an emphasis on areas with low cost of supply, particularly in growing unconventional plays. Our major focus in
2021 included the following areas:

•

Delaware Basin—We operated six rigs and two frac crews on average during 2021, resulting in 92
operated wells drilled and 95 operated wells brought online. Primarily as a result of our Concho
acquisition, production increased in 2021 compared with 2020, averaging 286 MBOED and 79 MBOED,
respectively.

•

• Midland Basin—We operated five rigs and two frac crews on average during 2021, resulting in 118
operated wells drilled and 102 operated wells brought online. Primarily as a result of our Concho
acquisition, production increased in 2021 compared with 2020, averaging 136 MBOED and 6 MBOED,
respectively.
Eagle Ford—We operated four rigs and two frac crews on average in the Eagle Ford during 2021, resulting
in 93 operated wells drilled and 160 operated wells brought online. Production increased in 2021
compared with 2020, averaging 211 MBOED and 186 MBOED, respectively.
Bakken—We operated one rig and one frac crew for parts of the year in the Bakken, resulting in 6
operated wells drilled and 21 operated wells brought online. Production increased in 2021 compared
with 2020, averaging 94 MBOED and 78 MBOED, respectively.

•

Dispositions
In the second half of 2021, we completed the sale of certain noncore assets in the Lower 48. In January 2022, we
entered into an agreement to sell our interests in additional noncore assets in the Lower 48. This transaction is
expected to close in the second quarter of 2022. See Note 3.

Facilities
We operate and own, with varying interests, centralized condensate processing facilities in Texas and New Mexico
in support of our Eagle Ford, Delaware and Midland assets.

ConocoPhillips 2021 10-K

Business and Properties

Canada
Our Canadian operations consist of the Surmont oil sands development in Alberta and the liquids-rich Montney
unconventional play in British Columbia. In 2021, operations in Canada contributed 8 percent of our consolidated
liquids production and 4 percent of our consolidated natural gas production.

Interest

Operator

Crude Oil

NGL
MBD MBD

2021
Natural Gas
MMCFD

Bitumen

Total
MBD MBOED

50.0 % ConocoPhillips
ConocoPhillips

100.0

-
8
8

-
4
4

-
80
80

69
-
69

69
25
94

Average Daily Net
Production
Surmont
Montney
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. Operations include two central processing facilities for treatment
and blending of bitumen. At December 31, 2021, we held 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 TotalEnergies SE that offers long-lived, sustained production. We are focused on
structurally lowering costs, reducing GHG intensity and optimizing asset performance.

In 2021, we began processing a portion of Surmont’s blended bitumen at the Diluent Recovery Unit constructed in
Alberta, unlocking additional value for the asset by providing market access to our heavy crude oil.

In 2019, Surmont implemented the use of condensate for bitumen blending through the central processing facility
2; enabling the asset to lower blend ratio and diluent supply costs, gain protection from synthetic crude oil supply
disruptions and gain optionality on sales products. The alternative blend project was complete in October at
central processing facility 1. Full Surmont Heavy Dilbit (condensate bitumen blend) was produced across both
facilities in the fourth quarter of 2021.

Montney
The Montney is an unconventional resource play located in northeastern British Columbia. At December 31, 2021,
we held approximately 300,000 acres of land with 100 percent working interest in the liquids-rich section of the
Montney.

In 2021, development activity consisted of drilling three horizontal wells and bringing 12 wells online. In addition,
construction on the second phase of our processing facility started.

Exploration
Our primary exploration focus is assessing our Montney acreage. In 2022, appraisal drilling and completions
activity within the Montney will continue to explore the area’s resource potential. Additionally, we have
exploration acreage in the Mackenzie Delta/Beaufort Sea Region and the Arctic Islands.

ConocoPhillips 2021 10-K

Business and Properties

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 terminalling operations in the U.K. In 2021,
operations in Europe, Middle East and North Africa contributed 12 percent of our consolidated liquids production
and 14 percent of our consolidated natural gas production.

Norway

Average Daily Net Production
Greater Ekofisk Area
Heidrun
Aasta Hansteen
Alvheim
Troll
Visund
Other
Total Norway

Interest

Operator

MBD MBD

Crude Oil

NGL Natural Gas

Total
MMCFD MBOED

2021

30.7-35.1 %

24.0
10.0
20.0
1.6
9.1
Various

ConocoPhillips
Equinor
Equinor
Aker BP
Equinor
Equinor
Equinor

49
13
-
9
2
2
6
81

2
1
-
-
-
1
-
4

41
35
84
13
58
46
21
298

58
20
14
11
11
11
10
135

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. This project consisted of 8 wells that have all been completed and brought online
as of May 2021. 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.

ConocoPhillips 2021 10-K 8

Business and Properties

Exploration
In 2021, we prepared for a four well exploration and appraisal campaign to take place in 2022. Planned wells
include Slagugle appraisal and exploration of the Peder, Bounty and Lamba prospects.

We were awarded two new exploration licenses; PL1122 and PL1123; and two acreage additions, PL891B and
PL1045B.

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 a crude oil stabilization and NGLs processing facility at
Teesside, England to support our Norway operations.

Qatar

Average Daily Net Production

QG3

Interest

Operator

30.0 %

Qatargas Operating
Company Limited

2021

Crude Oil

NGL
MBD MBD

Natural
Gas

Total
MMCFD MBOED

373

QG3 is an integrated development jointly owned by QatarEnergy (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 QatarEnergy and 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

Interest

Operator

Crude Oil
MBD

NGL
MBD

Natural Gas
MMCFD

Total
MBOED

2021

Average Daily Net Production
Waha Concession

16.3 %

Waha Oil Co.

The Waha Concession consists of multiple concessions and encompasses nearly 13 million gross acres in the Sirte
Basin. In 2021, we had 22 crude liftings from Es Sider, compared with five crude liftings from Es Sider in 2020,
primarily due to the absence of a forced shutdown after a period of civil unrest that ceased production in 2020.

9 ConocoPhillips 2021 10-K

Business and Properties

Asia Pacific
The Asia Pacific segment has exploration and production operations in China, Indonesia, Malaysia and Australia. In
2021, operations in the Asia Pacific segment contributed 6 percent of our consolidated liquids production and 17
percent of our consolidated natural gas production.

Australia

Interest

Operator

Crude Oil

NGL
MBD MBD

Natural Gas
MMCFD

Total
MBOED

2021

Average Daily Net Production

Australia Pacific LNG

37.5%

ConocoPhillips/
Origin Energy

680

113

Australia Pacific LNG Pty Ltd (APLNG), our joint venture with Origin Energy Limited (37.5 percent) and China
Petrochemical Corporation (Sinopec) (25 percent), is focused on producing CBM from the Bowen and Surat basins
in 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.

We operate two fully subscribed 4.5-million-metric-tonnes-per-year LNG trains. Approximately 2,800 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.

In December 2021, the company announced it has notified Origin Energy that it is exercising its preemption right to
purchase an additional 10 percent shareholding interest in APLNG from Origin Energy for $1.645 billion, which will
be funded from cash on the balance sheet and subject to customary adjustments. The effective date of the
transaction is July 1, 2020 with closing anticipated to occur in the first quarter of 2022 subject to Australian
government approval. There will be no change to the operational structure of the APLNG joint venture, whereby
Origin Energy will remain the upstream operator of the natural gas production and pipeline system, and
ConocoPhillips Australia will remain the downstream operator of the LNG facility.

For additional information, see Note 4 and Note 10.

Exploration
In 2019, we entered into an agreement with 3D Oil to acquire a 75 percent interest in and operatorship of an
offshore Exploration Permit (T/49P) located in the Otway Basin, Australia. We obtained an additional five percent
interest, increasing our interest to 80 percent, in June 2020. A 3D seismic survey acquisition was completed in
October 2021, and this data will be evaluated for future exploration opportunities.

Indonesia

Interest

Operator

Crude Oil
MBD

NGL
MBD

Natural Gas
MMCFD

Total
MBOED

2021

Average Daily Net Production
South Sumatra

54 %

ConocoPhillips

294

During 2021, we operated two PSCs in Indonesia: the Corridor Block located in South Sumatra, and Kualakurun in
Central Kalimantan. Currently, we have production from the Corridor Block.

ConocoPhillips 2021 10-K

Business and Properties

Asset Sales
In December 2021, we announced an agreement to sell our subsidiary that indirectly owns the company’s 54
percent interest in the Indonesia Corridor Block PSC and a 35 percent shareholding interest in the Transasia
Pipeline Company. The effective date for the transaction is January 1, 2021, with closing planned for the first
quarter of 2022.

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.

Exploration
We entered into the Central Kalimantan Kualakurun Block PSC in 2015 with an exploration period of six years. We
completed the firm working commitment program in 2017, which included satellite mapping and a 740-kilometer
2D seismic acquisition program. After completion of prospect evaluation, both PSC contractors decided to
relinquish rights and return this block to the government. The relinquishment was approved by the government in
August 2021.

Transportation
We 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

Interest

Operator

Crude Oil
MBD

NGL
MBD

Natural Gas
MMCFD

Total
MBOED

2021

Average Daily Net Production
Penglai

49.0 %

CNOOC

Penglai
The Penglai 19-3, 19-9 and 25-6 fields are located in the Bohai Bay Block 11/05 and are in various stages of
development. Phase 1 and 2 include production from all three Penglai oil fields.

The Phase 3 Project in the Penglai 19-3 and 19-9 fields consists of three new wellhead platforms and a central
processing platform. First production from Phase 3 was achieved in 2018. This project could include up to 186
wells, 126 of which have been completed and brought online as of December 2021.

The Phase 4A Project in the Penglai 25-6 field consists of one new wellhead platform and achieved first production
in 2020. This project could include up to 62 new wells, 14 of which have been completed and brought online as of
December 2021.

On April 5, 2021, a fire occurred on the non-operated V platform in the Bohai Bay. On April 6, 2021, the fire was
extinguished. We worked with the operator and implemented a recovery plan resulting in production resumption
in December 2021.

Exploration
During 2021, exploration activities in the Penglai fields consisted of two successful appraisal wells supporting
future developments in the Bohai Bay Block 11/05.

11 ConocoPhillips 2021 10-K

Business and Properties

Malaysia

Average Daily Net Production
Gumusut
Malikai
Kebabangan (KBB)
Siakap North-Petai
Total Malaysia

Interest

Operator

Crude Oil
MBD

NGL
MBD

Natural Gas
MMCFD

Total
MBOED

2021

29.5 %
35.0
30.0
21.0

Shell
Shell
KPOC
PTTEP

19
13
2
1
35

-
-
-
-
-

-
-
66
-
66

19
13
13
1
46

We have varying stages of exploration, development and production activities across approximately 2.7 million net
acres in Malaysia, with working interests in six PSCs. Four of these PSCs are located in waters off the eastern
Malaysian state of Sabah: Block G, Block J, the Kebabangan Cluster (KBBC), which we do not operate, and Block
SB405, an operated exploration block acquired in 2021. We also operate another two exploration blocks, Block
WL4-00 and Block SK304, in waters off the eastern Malaysian state of Sarawak.

Block J
Gumusut
We currently have a 29.5 percent working interest in the unitized Gumusut Field. Gumusut Phase 2 first oil was
achieved in 2019. Development drilling associated with Gumusut Phase 3, a four-well program, is planned to
commence in the first quarter of 2022. First oil is anticipated in 2022.

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. In 2020, we recognized dry hole expense and impaired the associated carrying
value of unproved properties in the Kamunsu East Field that is no longer in our development plans.

KBB
During 2019, KBB tied-in to a nearby third-party floating LNG vessel which provided increased gas offtake capacity.
Production from the field has been reduced since January 2020, due to the rupture of a third-party pipeline which
carries gas production from KBB to one of its markets. The pipeline operator has initiated repairs and is working
toward pipeline testing during 2022.

Block G
Malikai
We 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 first oil was achieved in
February 2021.

Siakap North-Petai
We hold a 21 percent working interest in the unitized Siakap North-Petai (SNP) oil field. First oil from SNP Phase 2
was achieved in November 2021.

Exploration
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. Further exploration and appraisal drilling is planned for 2022.

In 2018, we were awarded a 50 percent working interest and operatorship of Block SK304 encompassing 2.1
million gross acres off the coast of Sarawak, offshore Malaysia. We acquired 3D seismic over the acreage and
completed processing of this data in 2019. Exploration drilling is planned for 2022.

ConocoPhillips 2021 10-K 12

Business and Properties

In February 2021, we were awarded operatorship and an 85 percent working interest in Block SB405 encompassing
1.4 million gross acres off the coast of Sabah, offshore Malaysia. Acquisition of a 3D seismic survey over the
acreage is planned for 2022.

Other International
The Other International segment includes activities in Colombia as well as contingencies associated with prior
operations in other countries. As a result of our completed Concho acquisition on January 15, 2021, we refocused
our exploration program and announced our intent to pursue a managed exit from certain areas.

Colombia
We have an 80 percent operated interest in the Middle Magdalena Basin Block VMM-3 extending over
approximately 67,000 net acres. 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. The blocks are currently in
Force Majeure following a preliminary injunction temporarily suspending hydraulic fracturing activities.

Argentina
On September 16, 2021, ConocoPhillips Petroleum Holdings BV signed and closed the sale of shares in
ConocoPhillips Argentina Holdings Sarl and ConocoPhillips Argentina Ventures SRL. With this transaction, we
completed the exit from our Argentina holdings. See Note 3.

Venezuela
For discussion of our contingencies in Venezuela, see Note 11.

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.
We 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 and
Europe. 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, 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.

13 ConocoPhillips 2021 10-K

Business and Properties

Energy Partnerships
Marine Well Containment Company (MWCC)
We 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.

Oil Spill Response Limited (OSRL) - Subsea Well Intervention Service (SWIS)
OSRL-SWIS is a non-profit organization in the U.K. that is an industry funded joint initiative providing the capability
to respond to subsea well-control incidents. Through our SWIS subscription, ConocoPhillips has access to
equipment that is maintained and stored in a response ready state. This provides well capping and containment
capability outside the U.S.

Oil Spill Response Removal Organizations (OSROs)
We 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. In North America, our primary OSROs include the Marine Spill Response
Corporation for the continental U.S. 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 OSROs
including Oil Spill Response Limited, the Norwegian Clean Seas Association for Operating Companies, Australian
Marine Oil Spill Center and Petroleum Industry of Malaysia Mutual Aid Group.

Technology
We have several technology programs that improve our ability to develop unconventional reservoirs, increase
recoveries from our legacy fields, improve the efficiency of our exploration program, produce heavy oil
economically with less emissions and implement sustainability measures.

In early 2021, we established a multi-disciplinary Low Carbon Technologies organization to support the company’s
net-zero road map for scope 1 and 2 emissions, understand the new energies landscape, and prioritize
opportunities for future competitive investment. Throughout 2021, we executed emissions reduction projects
across our global portfolio including production efficiency measures and methane and flaring reductions. We also
completed pre-development work to evaluate large scale wind energy opportunities to power our operations in
the Permian, North Sea and Bohai Bay. Within the new energies landscape, the company has prioritized
opportunities in CCUS and hydrogen. In 2021, CO2 storage sites were evaluated along the Texas and Louisiana
Gulf Coast and we initiated activities to provide carbon capture and storage to industrial emitters. 2021 also saw
early investments in enabling hydrogen technologies and we began evaluating hydrogen opportunities in both
domestic and international markets.

We are the second-largest LNG liquefaction technology provider globally. Our Optimized Cascade® LNG
liquefaction technology has been licensed for use in 27 LNG trains around the world, with feasibility studies
ongoing for additional trains.

ConocoPhillips 2021 10-K 14

Business and Properties

Delivery Commitments
We 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 1.3 trillion cubic feet of natural gas and 159 million barrels of crude oil in the future. These
contracts have various expiration dates through the year 2030. We expect to fulfill these delivery commitments
with third-party purchases, as supported by our gas management agreements; proved developed reserves; and
PUDs. See the disclosure on “Proved Undeveloped Reserves” in the “Supplementary Data - Oil and Gas
Operations” section following the Notes to Consolidated Financial Statements, for information on the
development of PUDs.

Competition
ConocoPhillips is one of the world’s leading E&P companies based on both production and reserves, with a globally
diversified asset portfolio. We 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.

We 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. 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.

Human Capital Management

Values, Principles and Governance
At ConocoPhillips, our human capital management (HCM) approach is anchored to our core SPIRIT Values. Our
SPIRIT Values – Safety, People, Integrity, Responsibility, Innovation, and Teamwork – set the tone for how we
interact with all of our internal and external stakeholders. In particular, we believe a safe organization is a
successful organization, so we prioritize personal and process safety across the company. Our SPIRIT Values are a
source of pride. Our day-to-day work is guided by the principles of accountability and performance, which means
the way we do our work is as important as the results we deliver. We believe these core values and principles set
us apart, align our workforce and provide a foundation for our culture.

Our Executive Leadership Team (ELT) and our Board of Directors play a key role in setting our HCM strategy and
driving accountability for meaningful progress. The ELT and Board of Directors engage often on workforce-related
topics. Our HCM programs are overseen and administered by our human resources function with support from
business leaders across the company.

We depend on our workforce to successfully execute our company’s strategy and we recognize the importance of
creating a workplace in which our people feel valued. Our HCM programs are built around three pillars that we
believe are necessary for success: a compelling culture, a world-class workforce and strong external engagement.
Each of these pillars is described in more detail below.

A Compelling Culture
How we do our work is what sets us apart and drives our performance. We’re experts in what we do and
continuously find ways to do our jobs better. Together, we deliver strong performance, but not at all costs. We
embrace our core cultural attributes that are shared by everyone, everywhere. With two significant acquisitions
completed in 2021, we prioritized cultural integration. We seized the opportunity to learn from and value each
other’s cultures. This involved employee engagement, active listening and leveraging data analytics to monitor key
workforce and engagement metrics.

15 ConocoPhillips 2021 10-K

Business and Properties

Health, Safety and Environment
Our HSE organization sets expectations and provides tools and assurance to our workforce to promote and achieve
HSE excellence. We manage and assure ConocoPhillips HSE policies, standards and practices, to help ensure
business activities are consistently safe, healthy and conducted in an environmentally and socially responsible
manner across the globe. Each business unit manages its local operational risks with particular attention to
process safety, occupational safety and environmental and emergency preparedness risk. Objectives, targets and
deadlines are set and tracked annually to drive strong HSE performance. Progress is tracked and reported to our
ELT and the Board of Directors. HSE audits are conducted on business units and staff groups to ensure
conformance with ConocoPhillips HSE policies, standards and practices where improvement actions are identified
and tracked to completion.

We continuously look for ways to operate more safely, efficiently and responsibly. We focus on reducing human
error by emphasizing interaction among people, equipment and work processes. By being curious about how work
is done, recognizing error-likely situations and applying safeguards, we can reduce the likelihood and severity of
unexpected incidents. We conduct thorough investigations of all serious incidents to understand the root cause
and share lessons learned globally to improve our procedures, training, maintenance programs and designs.
Through this culture of continuous learning and improvement, we continue to refine our existing HSE processes
and tools and enhance our commitment to safe, efficient and responsible operations.

COVID-19 Response
In 2021, our COVID-19 activities were guided by our three company-wide priorities, set at the early pandemic
stages: protect our employees and contractors, mitigate the spread of COVID-19 and safely run the business. We
have pursued these priorities via a coordinated crisis management support team, frequent workforce
communications and flexible programs to suit the challenging environment. Our office and field staffs adhered to
rigorous mitigation protocols implemented across our operations utilizing the most current guidance from health
authorities. Mitigation measures, including requirements for remote work, vaccines and testing were driven by the
specific situations applicable to a region or business function. These measures proved effective at lessening the
impact to our employees and contractors, mitigating the spread of COVID-19 and minimizing the potential for
business disruption.

Diversity, Equity and Inclusion (DEI)
At ConocoPhillips, we value all forms of diversity, provide equitable employee programs and promote a culture of
inclusion. Our DEI vision is for our workforce to have a strong sense of belonging and feel supported in meeting
their full potential. Our commitment to DEI is foundational to our SPIRIT Values. We hold our leaders accountable
for having personal DEI goals each year and encourage all global employees to play a part in creating and
sustaining an inclusive work environment.

The ELT has ultimate accountability for advancing our DEI commitment through a governance structure that
includes an ELT-level DEI Champion, a global DEI Council consisting of senior leaders from across the company and
organization-wide DEI goals. The company sets goals and measures progress based on three pillars that guide our
DEI activities: leadership accountability, employee awareness and processes and programs. In addition, our DEI
plans and progress are reviewed regularly with the Board of Directors.

In 2021, HR and the DEI Council reviewed the results of the 2020 Perspectives Pulse DEI employee survey and
prioritized action plans tied to employee sentiment. 2021 accomplishments included:

•

•
•

•

Refreshing and diversifying the global DEI Council to reflect the diversity we seek across our global
organization;
Using survey insights to produce six multi-year corporate DEI priorities that will guide us through 2024;
Developing a detailed plan for our corporate DEI priorities, made up of 18 specific targets that position us
to deliver meaningful progress through 2024; and
Championing the addition of the ‘E’ (equity) to D&I; emphasizing the importance of providing equitable
programs that lead to fair outcomes for all employees.

ConocoPhillips 2021 10-K 16

Business and Properties

We actively monitor diversity metrics on a global basis. In 2021, we expanded our internal and external workforce
metrics and HCM disclosures, including publishing our 2018-2020 Consolidated EEO-1 Reports and our inaugural
HCM report. Tables of 2021 employee demographics by gender and ethnicity, and by country, are shown below:

2021 Employees by Gender and Race/Ethnicity

Global

Male

Female

U.S.

White

All Employees
All Leadership
Top Leadership
Junior Leadership
*"POC" refers to People of Color or racial and ethnic minorities self-reported in the U.S.

74 %
75
78
75

26%
25
22
25

72 %
79
85
77

POC*
28 %
21
15
23

2021 Employees by Country
U.S.
Norway
Canada
Indonesia
Great Britain
Australia
China
Other Global Locations

Percent of Total

61 %
18
8
5
3
3
1
1
100

The Hybrid Office Work Program
In 2021, we introduced the Hybrid Office Work (HOW) program in the U.S., offering a combination of work from
both office and home. The HOW program blends the advantages of in-person engagement with individual
flexibility for eligible employees where a hybrid schedule is feasible. The design of the U.S. program was adopted
in many of our global locations.

A World-Class Workforce
Our HCM approach addresses programs and processes necessary for ensuring we have an engaged workforce with
the skills to meet our business needs. We take a holistic view of HCM that addresses each of the critical
components of workforce planning. These are described in more detail below.

Recruitment
Our continued success requires a strong global workforce that can contribute the right skills, in the right places, to
achieve our strategic objectives. We offer university internships across multiple disciplines to attract the best
early-career talent. We partner with top diversity organizations and universities, including Hispanic-serving
organizations and historically black colleges and universities. We also recruit experienced hires to fill critical skills
and maintain a broad range of expertise and experience. We conduct routine talent assessments with leaders to
ensure we have the organizational capacity and capabilities to execute our business plans. We have taken
significant steps to embed inclusion into each step of our recruiting practices, including adapting the way we
construct job descriptions to using intentionally diverse interview panels.

As necessary, we closely monitor recruitment metrics through our internal university and experienced hire
dashboards and track voluntary turnover metrics to guide our retention activities.

17 ConocoPhillips 2021 10-K

Business and Properties

2021 Hiring & Attrition Metrics
U.S. University hire acceptance
U.S. Interns acceptance
Diversity hiring - Women
Diversity hiring - U.S. POC
Total voluntary attrition

Percent of Total

81 %
76
23
35
5

Employee Engagement and Development
We focus on the engagement and development of our workforce and encourage our employees to build diverse
and fulfilling careers with ConocoPhillips. Our workforce is trained through a combination of on-the-job learning,
formal training, regular feedback and mentoring. Skill-based Talent Management Teams (TMTs) guide employee
development and career progression by skills and location. The TMTs help identify our future business needs and
assess the availability of critical skill-sets within the company. We use a performance management program
focused on objectivity, credibility and transparency. The program includes broad stakeholder feedback, real-time
recognition and a formal “how” rating to assess behaviors to ensure they align with our SPIRIT Values.

We empower our employees to grow their careers through personal and professional development opportunities,
including individual development plans, a voluntary 360-feedback tool and training on a broad range of technical
and professional skills. Succession planning is a top priority for management and the board. This work ensures we
have the talent available for future leadership roles to inspire employees to reach their ultimate potential and limit
business interruption.

Taking steps to measure and assess employee satisfaction and engagement is at the heart of long-term business
success and creating a great place to work for our global workforce. Since 2019, the ConocoPhillips Perspectives
Survey has become our primary listening platform for gathering feedback on employee sentiment and promoting
our “Who We Are” culture. Our leadership reviews feedback gathered to guide priorities and goals. Our employee
feedback strategy is comprised of an annual engagement survey and an annual shorter DEI pulse survey.

Compensation, Benefits and Well-Being
We offer competitive, performance-based compensation packages and have global equitable pay practices. Our
compensation programs are generally comprised of a base pay rate, the annual Variable Cash Incentive Program
(VCIP) and, for eligible employees, the Restricted Stock Unit (RSU) program. From the CEO to the frontline worker,
every employee participates in VCIP, our annual incentive program, which aligns employee compensation with
ConocoPhillips’ success on critical performance metrics and also recognizes individual performance. Our RSU
program is designed to attract and retain employees, reward performance and align employee interest with
stockholders by encouraging stock ownership. Our retirement and savings plans are intended to support
employee’s financial futures and are competitive within local markets.

We routinely benchmark our global compensation and benefits programs to ensure they are competitive,
inclusive, aligned with company culture and allow our employees to meet their individual needs and the needs of
their families. We provide flexible work schedules and competitive time off, including parental leave policies in
many locations. In 2021, we enhanced our programs to provide expanded coverage for families requiring disability
support, elder care and childcare. We also provide access to quality childcare, including onsite child care, where
access locally is a challenge.

Our global wellness programs include biometric screenings and fitness challenges designed to educate and
promote a healthy lifestyle. All employees have access to our employee assistance program, and many of our
locations offer custom programs to support mental well-being.

ConocoPhillips 2021 10-K 18

Business and Properties

Compensation Risk Mitigation
We have considered the risks associated with each of its executive and broad-based compensation programs and
policies. As part of the analysis, we considered the performance measures we use as well as the different types of
compensation, varied performance measurement periods and extended vesting schedules that we utilize under
each incentive compensation program. As a result of this review, management concluded that the risks arising
from our compensation policies and practices are not reasonably likely to have a material adverse effect on the
company. As part of the Board of Directors’ oversight of our risk management programs, the Human Resources
Compensation Committee (HRCC) conducts a similar review with the assistance of its independent compensation
consultant. The HRCC agrees with management’s conclusion that the risks arising from our compensation policies
and practices are not reasonably likely to have a material adverse effect on the company.

External Engagement
Our employees make our communities stronger. We are proud to support their generous involvement in local
charitable activities through employee giving programs that include United Way campaigns, matching gift
contributions and volunteer grants.

While we have been recognized for our ESG and DEI efforts, we know that it takes ongoing commitment to make
sustainable progress; therefore, we continue to provide training, build awareness and reinforce accountability at
all levels of the organization and focus on behaviors and processes that build an environment in which everyone
has the opportunity to succeed.

General
At the end of 2021, we held a total of 1,118 active patents in 50 countries worldwide, including 438 active U.S.
patents. During 2021, we received 40 patents in the U.S. and 45 foreign patents. Our products and processes
generated licensing revenues of $65 million related to activity in 2021. The overall profitability of any business
segment is not dependent on any single patent, trademark, license, franchise or concession.

The environmental information contained in Management’s Discussion and Analysis of Financial Condition and
Results of Operations on pages 58 through 63 under the captions “Environmental” and “Climate Change” is
incorporated herein by reference. It includes information on expensed and capitalized environmental costs for
2021 and those expected for 2022 and 2023.

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 10-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.

19 ConocoPhillips 2021 10-K

Risk Factors

Item 1A. Risk Factors

You should carefully consider the following risk factors in addition to the other information included in this Annual
Report on Form 10-K. These risk factors are not the only risks we face. Our business could also be affected by
additional risks and uncertainties not currently known to us or that we currently consider to be immaterial. If any
of these risks or other risks that are yet unknown were to occur, our business, operating results and financial
condition, as well as the value of an investment in our common stock could be adversely affected.

Risks Related to Our Industry

Our operating results, our ability to execute on our strategy and the carrying value of our assets are exposed to
the effects of changing commodity prices.

The oil and gas business is a commodity business. Our revenues, operating results and future rate of growth are
highly dependent on the prices we receive for crude oil, bitumen, natural gas and NGLs. Such prices can fluctuate
widely depending upon global events or conditions that affect supply and demand, most of which are out of our
control. In early 2020 global oil demand decreased precipitously alongside global COVID-19 economic shutdowns.
Although global oil demand and global oil prices improved through 2021, the global economic recovery remains
uncertain. Our industry will continue to be exposed to the effects of changing commodity prices given the
volatility in commodity price drivers and the worldwide political and economic environment generally, as well as
continued uncertainty caused by armed hostilities in various oil-producing regions around the globe.

Lower crude oil, bitumen, natural gas and NGL prices may have a material adverse effect on our revenues,
operating income, cash flows and liquidity, and may also affect the amount of dividends we elect to declare and
pay on our common stock and the amount of shares we elect to acquire as part of the share repurchase program
and the timing of such acquisitions. Lower prices may also limit the amount of reserves we can produce
economically, thus adversely affecting our proved reserves and reserve replacement ratio and accelerating the
reduction in our existing reserve levels as we continue production from upstream fields. Prolonged depressed
crude oil prices may affect certain decisions related to our operations, including decisions to reduce capital
investments or curtail operated production.

Significant reductions in crude oil, bitumen, natural gas and NGL prices could also require us to reduce our capital
expenditures, impair the carrying value of our assets or discontinue the classification of certain assets as proved
reserves. In the past three years, we recognized several impairments, which are described in Note 7. If commodity
prices decrease relative to their current levels, and as we continue to optimize our investments and exercise
capital flexibility, it is reasonably likely we could incur future impairments to long-lived assets used in operations,
investment in nonconsolidated entities accounted for under the equity method and unproved properties.
Although it is not reasonably practicable to quantify the impact of any future impairments or estimated change to
our unit-of-production rates at this time, our results of operations could be adversely affected as a result.

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

The COVID-19 pandemic and the measures put in place to address it have negatively impacted the global economy,
disrupted global supply chains, reduced global demand for oil and gas and created significant volatility and
disruption of financial and commodity markets. Over the course of the pandemic, public health officials have
recommended or mandated certain precautions to mitigate the spread of COVID-19, including limiting non-
essential gatherings of people, ceasing all non-essential travel and issuing “social or physical distancing” guidelines,
“shelter-in-place” orders and mandatory closures or reductions in capacity for non-essential businesses. Although
some of these limitations and mandates have been relaxed in certain jurisdictions, others have been reinstated in
areas that have experienced a resurgence of COVID-19 cases and there is no guarantee restrictions will not be
reimposed in the future. Despite the increased availability of vaccines in certain jurisdictions, the COVID-19
pandemic may continue or worsen during the upcoming months, including as a result of the emergence of more
infectious variants of the virus, vaccine hesitancy or increased business and social activities, which may cause
governmental authorities to reinstate restrictions. As a result, the ongoing impact of the COVID-19 pandemic

ConocoPhillips 2021 10-K 20

Risk Factors

remains uncertain and will depend on the severity, location and duration of the effects and spread of the disease,
the effectiveness and duration of actions taken by authorities to contain the virus or treat its effect, the availability
and effectiveness of vaccines or other treatments, and how quickly and to what extent economic conditions
improve.

See our Human Capital Management section within Item 1 and 2—Business and Properties, for additional
information on how we have been impacted and the steps we have taken in response.

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

•

Reduced demand for our products as a result of reductions in travel and commerce, whether related to
mandated restrictions or otherwise;
Disruptions in our supply chain due in part to scrutiny or embargoing of shipments from infected areas or
invocation of force majeure clauses in commercial contracts due to restrictions imposed as a result of the
global response to the pandemic;
Failure of third-parties on which we rely, including our suppliers, contract manufacturers, contractors,
joint venture partners and external business partners, to meet their obligations to the company, or
significant disruptions in their ability to do so, which may be caused by their own financial or operational
difficulties or restrictions imposed in response to the disease outbreak;
Reduced workforce productivity caused by, but not limited to, illness, travel restrictions, quarantine, or
government mandates;
Increased challenges in retention of personnel caused by vaccine hesitancy and the resistance of some in
our workforce to comply with workplace protocols necessary to ensure the health and safety of our
workforce and minimize disruptions to the business, such as vaccine and testing requirements, or the use
of personal protective equipment; and
Voluntary or involuntary curtailments to support oil prices or alleviate storage shortages for our products.

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

Unless we successfully develop resources, the scope of our business will decline, resulting in an adverse impact to
our business.

As we produce crude oil and natural gas from our existing portfolio, the amount of our remaining reserves
declines. If we are not successful in replacing the crude oil and natural gas we produce with good prospects for
future organic opportunities or through acquisitions, our business will decline. In addition, our ability to
successfully develop our reserves is dependent on a number of factors, including our ability to obtain and renew
rights to develop and produce hydrocarbons; our success at reservoir optimization; our ability to bring long-lead
time, capital intensive projects to completion on budget and on schedule; and our ability to efficiently and
profitably operate mature properties. If we are not successful in developing the resources in our portfolio, our
financial condition and results of operations may be adversely affected.

The exploration and production of oil and gas is a highly competitive industry.

The exploration and production of crude oil, bitumen, natural gas and NGLs is a highly competitive business. We
compete with private, public and state-owned companies in all facets of the exploration and production business,
including to locate and obtain new sources of supply and to produce crude oil, bitumen, natural gas and NGLs in an
efficient, cost-effective manner. We must compete for the materials, equipment, services, employees and other
personnel (including geologists, geophysicists, engineers and other specialists) necessary to conduct our business.
Some of our competitors are larger and have greater resources than we do, or may have established strategic long-

21 ConocoPhillips 2021 10-K

Risk Factors

term positions or strong governmental or other relationships in countries or areas in which we operate, or may be
willing to incur a higher level of risk than we are willing to incur to obtain potential sources of supply. As a
consequence, we may be at a competitive disadvantage in certain respects, such as in accessing the necessary
materials, equipment, services, resources and personnel. In addition, we may be at a competitive disadvantage
when competing with state-owned companies if they are motivated by political or other factors in making their
business decisions, with less emphasis on financial returns. If we are not successful in our competition for new
reserves, our financial condition and results of operations may be adversely affected.

Any material change in the factors and assumptions underlying our estimates of crude oil, bitumen, natural gas
and NGL reserves could impair the quantity and value of those reserves.

Our proved reserve information included in this annual report represents management’s best estimates based on
assumptions, as of a specified date, of the volumes to be recovered from underground accumulations of crude oil,
bitumen, natural gas and NGLs. Such volumes cannot be directly measured and the estimates and underlying
assumptions used by management are subject to substantial risk and uncertainty. Any material changes in the
factors and assumptions underlying our estimates of these items could result in a material negative impact to the
volume of reserves reported or could cause us to incur impairment expenses on property associated with the
production of those reserves. Future reserve revisions could also result from changes in, among other things,
governmental regulation.

Our business may be adversely affected by price controls, government-imposed limitations on production or
exports of crude oil, bitumen, natural gas and NGLs, or the unavailability of adequate gathering, processing,
compression, transportation, and pipeline facilities and equipment for our production of crude oil, bitumen,
natural gas and NGLs.

As discussed herein, our operations are subject to extensive governmental regulations. From time to time,
regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of
crude oil, bitumen, natural gas and NGL wells below actual production capacity. Similarly, in response to increased
domestic energy costs, circumstances determined to be in the economic interest of the country, or a declared
national emergency, the U.S. government could restrict the export of our products which would adversely impact
our domestic business. Because legal requirements are frequently changed and subject to interpretation, we
cannot predict whether future restrictions on our business may be enacted or become applicable to us.

Our ability to sell and deliver the crude oil, bitumen, natural gas, NGLs and LNG that we produce also depends on
the availability, proximity, and capacity of gathering, processing, compression, transportation and pipeline facilities
and equipment, as well as any necessary diluents to prepare our crude oil, bitumen, natural gas, NGLs and LNG for
transport. Furthermore, we rely on there being sufficient facilities and takeaway capacity to support our ambitions
to reduce routine flaring. The facilities, equipment and diluents we rely on may be temporarily unavailable to us
due to market conditions, extreme weather events, regulatory reasons, mechanical reasons or other factors or
conditions, many of which are beyond our control. In addition, in certain newer plays, the capacity of necessary
facilities, equipment and diluents may not be sufficient to accommodate production from existing and new wells,
and construction and permitting delays, permitting costs and regulatory or other constraints could limit or delay
the construction, manufacture or other acquisition of new facilities and equipment. If any facilities, equipment or
diluents, or any of the transportation methods and channels that we rely on become unavailable for any period of
time, we may incur increased costs to transport our crude oil, bitumen, natural gas, NGLs and LNG for sale or we
may be forced to curtail our production of crude oil, bitumen, natural gas or NGLs.

ConocoPhillips 2021 10-K 22

Risk Factors

Our investments in joint ventures decrease our ability to manage risk.

We conduct many of our operations through joint ventures in which we may share control with our joint venture
partners. There is a risk our joint venture participants may at any time have economic, business or legal interests
or goals that are inconsistent with those of the joint venture or us, or our joint venture partners may be unable to
meet their economic or other obligations and we may be required to fulfill those obligations alone. Failure by us,
or an entity in which we have a joint venture interest, to adequately manage the risks associated with any
operations, acquisitions or dispositions could have a material adverse effect on the financial condition or results of
operations of our joint ventures and, in turn, our business and operations.

Our operations present hazards and risks that require significant and continuous oversight.

The scope and nature of our operations present a variety of significant hazards and risks, including operational
hazards and risks such as explosions, fires, product spills, severe weather, geological events, labor disputes,
geopolitical tensions, armed hostilities, terrorist or piracy attacks, sabotage, civil unrest or cyberattacks. Our
operations are subject to the additional hazards of pollution, toxic substances and other environmental hazards
and risks. Offshore activities may pose incrementally greater risks because of complex subsurface conditions such
as higher reservoir pressures, water depths and metocean conditions. All such hazards could result in loss of
human life, significant property and equipment damage, environmental pollution, impairment of operations,
substantial losses to us and damage to our reputation. Our business and operations may be disrupted if we do not
respond, or are perceived not to respond, in an appropriate manner to any of these hazards and risks or any other
major crisis or if we are unable to efficiently restore or replace affected operational components and capacity.
Further, our insurance may not be adequate to compensate us for all resulting losses, and the cost to obtain
adequate coverage may increase for us in the future.

Legal and Regulatory Risks

We expect to continue to incur substantial capital expenditures and operating costs as a result of our compliance
with existing and future environmental laws and regulations.

Our business is subject to numerous laws and regulations relating to the protection of the environment, which are
expected to continue to have an increasing impact on our operations. For a description of the most significant of
these environmental laws and regulations, see the “Contingencies—Environmental” and “Contingencies—Climate
Change” sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations.
These laws and regulations continue to increase in both number and complexity and affect our operations with
respect to, among other things:

•

•
•

•

Permits required in connection with exploration, drilling, production and other activities, including those
issued by national, subnational, and local authorities;
The discharge of pollutants into the environment;
Emissions into the atmosphere, such as nitrogen oxides, sulfur dioxide, mercury and GHG emissions,
including methane;
Carbon taxes;
The handling, use, storage, transportation, disposal and cleanup of hazardous materials and hazardous
and nonhazardous wastes;
The dismantlement, abandonment and restoration of historic properties and facilities at the end of their
useful lives; and
Exploration and production activities in certain areas, such as offshore environments, arctic fields, oil
sands reservoirs and unconventional plays.

We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation
expenditures as a result of these laws and regulations. In addition, to the extent these expenditures are assumed
by a buyer as a result of a disposition, it may result in our incurring substantial costs if the buyer is unable to satisfy
these obligations. Any failure by us to comply with existing or future laws, regulations and other requirements
could result in administrative or civil penalties, criminal fines, other enforcement actions or third-party litigation

23 ConocoPhillips 2021 10-K

Risk Factors

against us. To the extent these expenditures, as with all costs, are not ultimately reflected in the prices of our
products and services, our business, financial condition, results of operations and cash flows in future periods
could be materially adversely affected.

Existing and future laws, regulations and internal initiatives relating to global climate change, such as
limitations on GHG emissions may impact or limit our business plans, result in significant expenditures, promote
alternative uses of energy or reduce demand for our products.

Continuing political and social attention to the issue of global climate change has resulted in both existing and
pending international agreements and national, regional or local legislation and regulatory measures to limit GHG
emissions, such as cap and trade regimes, specific emission standards, carbon taxes, restrictive permitting,
increased fuel efficiency standards and incentives or mandates for renewable energy. Although we may support
many of these legislative and regulatory measures, how and when they are enacted could result in a material
adverse effect to our business, financial condition, results of operations and cash flows in future periods.

For example, in November 2021, the U.S. Environmental Protection Agency published a Proposed Rule that would
revise the regulations governing the emission of GHG and volatile organic compounds from new oil and gas
production facilities, and emission guidelines for states to use when revising Clean Air Act implementation plans to
limit GHG emissions from existing oil and gas facilities. Although the company supports the direct federal
regulation of methane from new and existing sources, the final form and substance of any regulations are not
currently known and could result in additional capital expenditures and compliance, operating and maintenance
costs, any of which may have an adverse effect on our business and results of operations.

Additionally, in 2021, the U.S. joined the international community at the 26th Conference of the Parties (COP26).
At the conclusion of COP26, the U.S. and nearly 200 other counties agreed to the Glasgow Climate Pact,
committing to revisiting and strengthening their current emissions targets to 2030 in 2022 and finalizing the
outstanding elements of the Paris Agreement. In addition, our operations continue in countries around the world
which are party to the Paris Agreement. The implementation of current agreements and regulatory measures, as
well as any future agreements or measures addressing climate change and GHG emissions, may adversely impact
the demand for our products, impose taxes on our products or operations or require us to purchase emission
credits or reduce emission of GHGs from our operations. As a result, we may experience declines in commodity
prices or incur substantial capital expenditures and compliance, operating, maintenance and remediation costs,
any of which may have an adverse effect on our business and results of operations.

In September 2021, we announced an improvement to our Paris-aligned climate risk framework, whereby we
committed to an improvement to our targets for reducing our scope 1 and 2 emissions intensity on both a gross
operated and net equity basis and reaffirmed our commitment to advocate for the reduction of scope 3 emissions
through our support for a U.S. carbon price. Compliance with, and achievement of, climate change-related
internal initiatives such as the foregoing may increase costs, require us to purchase emission credits, or limit or
impact our business plans. If we are not successful in select internal initiatives, we may be adversely affected and
potentially need to reduce economic end-of-field life of certain assets and impair associated net book value.

Increasing attention to global climate change has also resulted in pressure from and upon stockholders, financial
institutions and/or financial markets to modify their relationships with oil and gas companies and to limit
investments and/or funding to such companies. For example, Harvard University announced in September 2021
that it will stop investing its $42 billion endowment in fossil fuels and will let its current investments expire without
renewal. As public pressure continues to mount, our access to capital on terms we find favorable (if it is available
at all) may be limited and our costs may increase, our reputation could be damaged or our business and results of
operations may be otherwise adversely affected.

Furthermore, increasing attention to global climate change has resulted in an increased likelihood of governmental
investigations and private litigation, which could increase our costs or otherwise adversely affect our business.
Beginning in 2017, cities, counties, governments and other entities in several states in the U.S. have filed lawsuits
against oil and gas companies, including ConocoPhillips, seeking compensatory damages and equitable relief to

ConocoPhillips 2021 10-K 24

Risk Factors

abate alleged climate change impacts. Additional lawsuits with similar allegations are expected to be filed. The
amounts claimed by plaintiffs are unspecified and the legal and factual issues involved in these cases are
unprecedented. ConocoPhillips believes these lawsuits are factually and legally meritless and are an inappropriate
vehicle to address the challenges associated with climate change and will vigorously defend against such lawsuits.
The ultimate outcome and impact to us cannot be predicted with certainty, and we could incur substantial legal
costs associated with defending these and similar lawsuits in the future. We could also receive lawsuits alleging a
failure or lack of diligence to meet our publicly stated ESG goals, so called “greenwashing” cases.

In addition, although we design and operate our business operations to accommodate expected climatic
conditions, to the extent there are significant changes in the earth’s climate, such as more severe or frequent
weather conditions in the markets where we operate or the areas where our assets reside, we could incur
increased expenses, our operations and supply chain could be adversely impacted, and demand for our products
could fall.

For more information on legislation or precursors for possible regulation relating to global climate change that
affect or could affect our operations and a description of the company’s response, see the “Contingencies—Climate
Change” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Domestic and worldwide political and economic developments could damage our operations and materially
reduce our profitability and cash flows.

Actions of the U.S., state, local and foreign governments, through sanctions, tax and other legislation, executive
order and commercial restrictions, could reduce our operating profitability both in the U.S. and abroad. In certain
locations, restrictions on our operations; leasing restrictions; special taxes or tax assessments; and payment
transparency regulations that could require us to disclose competitively sensitive information or might cause us to
violate non-disclosure laws of other countries have been imposed or proposed by governments or certain interest
groups. For example, in 2020 a ballot initiative known as the Fair Share Act was proposed in the state of Alaska,
which, if enacted would have increased the state’s share of production revenues and required producers to
publicly disclose additional financial information. Although ultimately defeated, similar initiatives may be
proposed and may be successful in the future. In addition, we may face regulatory changes in the U.S. including,
but not limited to, the enactment of tax law changes that adversely affect the fossil fuel industry, new methane
emissions standards, restrictive flaring requirements, and more stringent environmental impact studies and
reviews. We also cannot rule out the possibility of similar regulatory shifts and attendant cost and market access
implications in other international jurisdictions.

One area subject to significant political and regulatory activity 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 and national laws and regulations currently govern or, in some
hydraulic fracturing operations, prohibit hydraulic fracturing in some jurisdictions. Although hydraulic fracturing
has been conducted safely for many decades, a number of new laws, regulations and permitting requirements are
under consideration which could result in increased costs, operating restrictions, operational delays or could limit
the ability to develop oil and natural gas resources. Certain jurisdictions in which we operate have adopted or are
considering regulations that could impose new or more stringent permitting, disclosure or other regulatory
requirements on hydraulic fracturing or other oil and natural gas operations, including subsurface water disposal.

In addition, certain interest groups have also proposed ballot initiatives and constitutional amendments designed
to restrict oil and natural gas development generally and hydraulic fracturing in particular. In the event that ballot
initiatives, local, state, or national restrictions or prohibitions are adopted and result in more stringent limitations
on the production and development of oil and natural gas in areas where we conduct operations, we may incur
significant costs to comply with such requirements or may experience delays or curtailment in the permitting or
pursuit of exploration, development or production activities. Such compliance costs and delays, curtailments,
limitations or prohibitions could have a material adverse effect on our business, prospects, results of operations,
financial condition and liquidity.

25 ConocoPhillips 2021 10-K

Risk Factors

The U.S. government can also prevent or restrict us from doing business in foreign countries. These restrictions
and those of foreign governments have in the past limited our ability to operate in, or gain access to, opportunities
in various countries. Actions by host governments, such as the expropriation of our oil assets by the Venezuelan
government, have affected operations significantly in the past and may continue to do so in the future. Changes in
domestic and international policies and regulations may affect our ability to collect payments such as those
pertaining to the settlement with Petróleos de Venezuela, S.A. (PDVSA) or the ICSID Award against the
Government of Venezuela; or to obtain or maintain licenses or permits, including those necessary for drilling and
development of wells in various locations. Similarly, the declaration of a “climate emergency” could result in
actions to limit exports of our products and other restrictions.

Local political and economic factors in international markets could have a material adverse effect on us.
Approximately 38 percent of our hydrocarbon production was derived from production outside the U.S. in 2021,
and 29 percent of our proved reserves, as of December 31, 2021, were located outside the U.S. We are subject to
risks associated with operations in both domestic and international markets, including changes in foreign
governmental policies relating to crude oil, natural gas, bitumen, NGLs or LNG pricing and taxation, other political,
economic or diplomatic developments (including the macro effects of international trade policies and disputes),
potentially disruptive geopolitical conditions, and international monetary and currency rate fluctuations.
Restrictions on production of oil and gas could increase to the extent governments view such measures as a viable
approach for pursuing national and global energy and climate policies. In addition, some countries where we
operate lack a fully independent judiciary system. This, coupled with changes in foreign law or policy, results in a
lack of legal certainty that exposes our operations to increased risks, including increased difficulty in enforcing our
agreements in those jurisdictions and increased risks of adverse actions by local government authorities, such as
expropriations.

Other Risk Factors Facing our Business or Operations

We may need additional capital in the future, and it may not be available on acceptable terms or at all.

We have historically relied primarily upon cash generated by our operations to fund our operations and strategy;
however, we have also relied from time to time on access to the debt and equity capital markets for funding.
There can be no assurance that additional debt or equity financing will be available in the future on acceptable
terms or at all. In addition, although we anticipate we will be able to repay our existing indebtedness when it
matures or in accordance with our stated plans, there can be no assurance we will be able to do so. Our ability to
obtain additional financing or refinance our existing indebtedness when it matures or in accordance with our
plans, will be subject to a number of factors, including market conditions, our operating performance, investor
sentiment and our ability to incur additional debt in compliance with agreements governing our then-outstanding
debt. If we are unable to generate sufficient funds from operations or raise additional capital for any reason, our
business could be adversely affected.

In addition, we are regularly evaluated by the major rating agencies based on a number of factors, including our
financial strength and conditions affecting the oil and gas industry generally. We and other industry companies
have had their ratings reduced in the past due to negative commodity price outlooks. Any downgrade in our credit
rating or announcement that our credit rating is under review for possible downgrade could increase the cost
associated with any additional indebtedness we incur.

ConocoPhillips 2021 10-K 26

Risk Factors

Our business may be adversely affected by deterioration in the credit quality of, or defaults under our contracts
with, third-parties with whom we do business.

The operation of our business requires us to engage in transactions with numerous counterparties operating in a
variety of industries, including other companies operating in the oil and gas industry. These counterparties may
default on their obligations to us as a result of operational failures or a lack of liquidity, or for other reasons,
including bankruptcy. Market speculation about the credit quality of these counterparties, or their ability to
continue performing on their existing obligations, may also exacerbate any operational difficulties or liquidity
issues they are experiencing, particularly as it relates to other companies in the oil and gas industry as a result of
the volatility in commodity prices. Any default by any of our counterparties may result in our inability to perform
our obligations under agreements we have made with third-parties or may otherwise adversely affect our business
or results of operations. In addition, our rights against any of our counterparties as a result of a default may not be
adequate to compensate us for the resulting harm caused or may not be enforceable at all in some circumstances.
We may also be forced to incur additional costs as we attempt to enforce any rights we have against a defaulting
counterparty, which could further adversely impact our results of operations.

Our ability to execute our capital return program is subject to certain considerations.

In December 2021, we initiated a three-tier capital return program that consists of our ordinary dividend, share
repurchases and a quarterly variable return of cash (VROC).

Ordinary dividends are authorized and determined by our Board of Directors in its sole discretion and depend
upon a number of factors, including:

•
•
•
•
•
•

Cash available for distribution;
Our results of operations and anticipated future results of operations;
Our financial condition, especially in relation to the anticipated future capital needs of our properties;
The level of distributions paid by comparable companies;
Our operating expenses; and
Other factors our Board of Directors deems relevant.

VROC distributions are also authorized and determined by our Board of Directors in its sole discretion and depend
upon a number of factors, including:

•
•
•
•
•

The anticipated level of distributions required to meet our capital returns commitment;
Forward prices;
Balance sheet cash;
Total yield; and
Other factors our Board of Directors deems relevant.

We expect to continue to pay a quarterly ordinary dividend to our stockholders. In addition, based on the current
environment, we anticipate also paying a quarterly VROC to our shareholders staggered from the ordinary
dividend payment, resulting in up to eight cash distributions to shareholders throughout the year; however, the
amount of the VROC is variable and will depend upon the above factors, and our Board of Directors may determine
not to pay a VROC in a quarter or may cease declaring a VROC at any time. In addition, our Board of Directors may
reduce our ordinary dividend or cease declaring dividends at any time, including if it determines that our net cash
provided by operating activities, after deducting capital expenditures and investments, are not sufficient to pay
our desired levels of dividends to our stockholders or to pay dividends to our stockholders at all.

27 ConocoPhillips 2021 10-K

Risk Factors

Additionally, as of December 31, 2021, $10.9 billion of repurchase authority remained of the $25 billion share
repurchase program our Board of Directors had authorized. Our share repurchase program does not obligate us to
acquire a specific number of shares during any period, and our decision to commence, discontinue or resume
repurchases in any period will depend on the same factors that our Board of Directors may consider when
declaring dividends, among others. In the past we have suspended our share repurchase program in response to
market downturns, including as a result of the oil market downturn that began in early 2020, and we may do so
again in the future.

Any downward revision in the amount of our ordinary dividend or VROC or the volume of shares we purchase
under our share repurchase program could have an adverse effect on the market price of our common stock.

There are substantial risks with any acquisitions or divestitures we have completed or that we may choose to
undertake.

We regularly review our portfolio and pursue growth through acquisitions and seek to divest noncore assets or
businesses. We may not be able to complete these transactions on favorable terms, on a timely basis, or at all.
Even if we do complete such transactions, our cash flow from operations may be adversely impacted or otherwise
the transactions may not result in the benefits anticipated due to various risks, including, but not limited to (i) the
failure of the acquired assets or businesses to meet or exceed expected returns, including risk of impairment; (ii)
the inability to dispose of noncore assets and businesses on satisfactory terms and conditions; and (iii) the
discovery of unknown and unforeseen liabilities or other issues related to any acquisition for which contractual
protections are inadequate or we lack insurance or indemnities, including environmental liabilities, or with regard
to divested assets or businesses, claims by purchasers to whom we have provided contractual indemnification.

In addition, we may face difficulties in integrating the operations, technologies, products and personnel of any
acquired assets or businesses. For example, we completed two major acquisitions in 2021, including the
acquisition of Concho in January and the acquisition of the Shell Permian assets in December. Combined, these
transactions added approximately 800,000 net acres, thereby significantly increasing our unconventional position
and operations in the Permian. We may still encounter difficulties integrating the acquired assets into our
business. There are a large number of processes, policies, procedures, operations and technologies and systems
that must be integrated in connection with the transactions and the integration of the acquired assets. It is
possible that the integration process could result in the disruption of our ongoing business; inconsistencies in
standards, controls, procedures and policies; unexpected integration issues; higher than expected integration costs
and an overall post-completion integration process that takes longer than originally anticipated. We have been
and will be required to devote management attention and resources to integrating the business practices and
operations. Any delays encountered in the integration process could have an adverse effect on our revenues or on
our level of expenses or capital investment and operating results, which may adversely affect the value of our
common stock. In addition, the actual integration may result in additional and unforeseen expenses. Although we
expect that the strategic benefits, and additional income, as well as the realization of other efficiencies related to
the integration of the acquired assets, may offset incremental transaction-related costs over time, if we are not
able to adequately address integration challenges.

ConocoPhillips 2021 10-K 28

Risk Factors

Our technologies, systems and networks may be subject to cyberattacks.

Our business, like others within the oil and gas industry, has become increasingly dependent on digital
technologies, some of which are managed by third-party service providers on whom we rely to help us collect, host
or process information. Among other activities, we rely on digital technology to estimate oil and gas reserves,
process and record financial and operating data, analyze seismic and drilling information and communicate with
employees and third-parties. As a result, we face various cybersecurity threats such as attempts to gain
unauthorized access to, or control of, sensitive information about our operations and our employees, attempts to
render our data or systems (or those of third-parties with whom we do business, including third-party cloud and IT
service providers) corrupted or unusable, threats to the security of our facilities and infrastructure as well as those
of third-parties with whom we do business, including third-party cloud and IT service providers, and attempted
cyber terrorism.

In addition, computers control oil and gas production, processing equipment and distribution systems globally and
are necessary to deliver our production to market. A disruption, failure, or a cyberattack of these operating
systems, or of the networks, software and infrastructure on which they rely, many of which are not owned or
operated by us, could damage critical production, distribution or storage assets, delay or prevent delivery to
markets, make it difficult or impossible to accurately account for production and settle transactions, or negatively
impact public health or safety, economic security, or national security.

Although we have experienced occasional cybersecurity incidents, none have had a material effect on our
business, operations or reputation. As cyberattacks have continued to evolve, we have become subject to new
government-imposed security requirements to implement specific mitigation measures to protect against
ransomware attacks and other known threats to information and operations technology. In response, we must
continually expend additional resources to continue to modify or enhance our protective measures or to
investigate and remediate any vulnerabilities detected. Our implementation of reasonable security procedures
and controls to monitor and mitigate security threats and to increase security for our information, facilities and
infrastructure may result in increased costs. Despite our ongoing investments in security resources, talent and
business practices, we are unable to assure that any security measures will be completely effective.

If our systems and infrastructure were to be breached, damaged or disrupted, we could be subject to serious
negative consequences, including disruption of our operations, damage to our reputation, a loss of counterparty
trust, reimbursement or other costs, increased compliance costs, litigation exposure and legal liability or regulatory
fines, penalties or intervention. In addition, we have exposure to cybersecurity incidents and the negative impacts
of such incidents related to our data and proprietary information housed on third-party IT systems, including the
cloud. Any of these could materially and adversely affect our business, results of operations or financial condition,
and any of the foregoing can be exacerbated by a delay or failure to detect a cybersecurity incident or the full
extent of such incident notwithstanding reasonable security procedures and controls. The prevalence of remote
working during the pandemic has introduced additional cybersecurity risk. Although we have business continuity
plans in place, our operations may be adversely affected by significant and widespread disruption to our systems
and infrastructure that support our business. While we continue to evolve and modify our business continuity
plans, there can be no assurance that they will be completely effective in avoiding disruption and business impacts.
Further, our insurance may not be adequate to compensate us for all resulting losses, and the cost to obtain
adequate coverage may increase for us in the future.

29 ConocoPhillips 2021 10-K

Item 1B. Unresolved Staff Comments

None.

Item 3. Legal Proceedings

We are a defendant in a number of legal and administrative proceedings arising in the ordinary course of business,
including those involving governmental authorities under federal, state and local laws regulating the discharge of
materials into the environment. While it is not possible to accurately predict the final outcome of these pending
proceedings, if any one or more of such proceedings were to be decided adversely to ConocoPhillips, we expect
there would be no material effect on our consolidated financial position. See Note 11 for a description of such
legal and administrative proceedings.

Item 4. Mine Safety Disclosures

Not applicable.

Information about our Executive Officers

Name

Position Held

William L. Bullock, Jr.

Executive Vice President and Chief Financial Officer

Kontessa S. Haynes-Welsh

Chief Accounting Officer

Ryan M. Lance

Chairman of the Board of Directors and Chief Executive Officer

Timothy A. Leach

Executive Vice President, Lower 48

Andrew D. Lundquist

Senior Vice President, Government Affairs

Dominic E. Macklon

Executive Vice President, Strategy, Sustainability and Technology

Nicholas G. Olds

Kelly B. Rose

Executive Vice President, Global Operations

Senior Vice President, Legal, General Counsel

Heather G. Sirdashney

Vice President, Human Resources and Real Estate and Facilities Services

*On February 17, 2022.

There are no family relationships among any of the officers named above. Each officer of the company is elected
by the Board of Directors at its first meeting after the Annual Meeting of Stockholders and thereafter as
appropriate. Each officer of the company holds office from the date of election until the first meeting of the
directors held after the next Annual Meeting of Stockholders or until a successor is elected. The date of the next
annual meeting is May 10, 2022. Set forth below is information about the executive officers.

William L. Bullock, Jr. was appointed Executive Vice President and Chief Financial Officer as of September 2020,
having previously served as President, Asia Pacific & Middle East since April 2015. Prior to that, he was Vice
President, Corporate Planning & Development since May 2012.

Age*

ConocoPhillips 2021 10-K 30

Kontessa S. Haynes-Welsh was appointed Chief Accounting Officer in March 2021, having previously served as
Assistant Controller since January 2020. Prior to that, she was Manager, Strategy, Planning and Portfolio
Management from June 2018 to December 2019. She became Manager, Finance & Performance Analysis in
September 2016 and served in that role until May 2018. Ms. Haynes-Welsh previously held the position of
Director, Lower 48 Strategy & Portfolio Management from February 2016 to September 2016.

Ryan M. Lance was appointed Chairman of the Board of Directors and Chief Executive Officer in May 2012, having
previously served as Senior Vice President, Exploration and Production—International since May 2009.

Timothy A. Leach was appointed Executive Vice President, Lower 48 in January 2021. Prior to joining
ConocoPhillips, Mr. Leach served as Chairman and Chief Executive Officer of Concho Resources Inc., from its
formation in February 2006, until its acquisition by ConocoPhillips in January 2021.

Andrew D. Lundquist was appointed Senior Vice President, Government Affairs in February 2013. Prior to that, he
served as managing partner of BlueWater Strategies LLC, since 2002.

Dominic E. Macklon was appointed Executive Vice President, Strategy, Sustainability and Technology in September
2021, having previously served as Senior Vice President, Strategy, Exploration and Technology since August 2020.
Prior to that, he served as President, Lower 48 from June 2018 to August 2020, Vice President, Corporate Planning
& Development from January 2017 to June 2018, and President, U.K. from September 2015 to January 2017. Mr.
Macklon previously served as Senior Vice President, Oil Sands in Canada from July 2012 to September 2015.

Nicholas G. Olds was appointed Executive Vice President, Global Operations as of August 2021,
having previously served as Senior Vice President, Global Operations since August 2020. Prior to that, he served as
Vice President, Corporate Planning & Development from June 2018 to August 2020, Vice President, Mid-Continent
Business Unit, Lower 48 from September 2016 to June 2018, and Vice President, North Slope Operations and
Development in Alaska from August 2012 to September 2016.

Kelly B. Rose was appointed Senior Vice President, Legal, General Counsel in September 2018. Prior to that, she
was a senior partner in the Houston office of an international law firm, Baker Botts L.L.P., where she counseled
clients on corporate and securities matters. She began her career at the firm in 1991.

Heather G. Sirdashney was appointed Vice President, Human Resources and Real Estate and Facilities Services in
March 2021, having previously served as Vice President, Human Resources from January 2019. Prior to that, she
served in other leadership roles including Human Resources General Manager, Human Resources Business Partner
Manager, Lower 48, and Director of Human Resources Shared Services.

31 ConocoPhillips 2021 10-K

Part II

Item 5. Market for Registrant's Common Equity, Related Stockholder

Matters and Issuer Purchases of Equity Securities

ConocoPhillips’ common stock is traded on the New York Stock Exchange, under the symbol “COP.”

Cash Dividends Per Share

First
Second
Third
Fourth

Number of Stockholders of Record at January 31, 2022*

Dividends

2021
0.430
0.430
0.430
0.460

2020
0.420
0.420
0.420
0.430

38,099

*In determining the number of stockholders, we consider clearing agencies and security position listings as one stockholder for each agency
listing.

In December 2021, we announced the addition of a VROC tier to our return of capital program. The declaration of
ordinary and VROC dividends are subject to the discretion and approval of our Board of Directors. The Board has
adopted a dividend declaration policy providing that the declaration of any dividends will be determined quarterly.
For more information on factors considered when determining the level of these distributions see “Item 1A—Risk
Factors – Our ability to execute our capital return program is subject to certain considerations.”

Issuer Purchases of Equity Securities

Total Number of
Shares Purchased*

Average
Price Paid
Per Share

Shares Purchased
as Part of Publicly
Announced Plans
or Programs

Millions of Dollars
Approximate Dollar
Value of Shares
that May Yet Be
Purchased Under the
Plans or Programs

6,100,833
6,367,204
6,751,987
19,220,024

73.36
73.42
71.65

6,100,833
6,367,204
6,751,987
19,220,024

11,811
11,344
10,860

Period

October 1-31, 2021
November 1-30, 2021
December 1-31, 2021

* There were no repurchases of common stock from company employees in connection with the company's broad-based employee incentive
plans.

In late 2016, we initiated our current share repurchase program, which has a current total program authorization
of $25 billion of our common stock. As of December 31, 2021, we had repurchased $14.1 billion of shares.
Repurchases are made at management’s discretion, at prevailing prices, subject to market conditions and other
factors. Except as limited by applicable legal requirements, repurchases may be increased, decreased or
discontinued at any time without prior notice. Shares of stock repurchased under the plan are held as treasury
shares. For more information see “Item 1A—Risk Factors – Our ability to execute our capital return program is
subject to certain considerations.”

ConocoPhillips 2021 10-K 32

Stock Performance Graph
The following graph shows the cumulative TSR for ConocoPhillips’ common stock in each of the five years from
December 31, 2016 to December 31, 2021. The graph also compares the cumulative total returns for the same
five-year period with the S&P 500 Index and our performance peer group consisting of Chevron, ExxonMobil,
Apache, Marathon Oil Corporation, Devon, Occidental, Hess, and EOG weighted according to the respective peer’s
stock market capitalization at the beginning of each annual period.

The comparison assumes $100 was invested on December 31, 2016, in ConocoPhillips stock, the S&P 500 Index
and ConocoPhillips’ peer group and assumes that all dividends were reinvested. The cumulative total returns of
the peer group companies' common stock do not include the cumulative total return of ConocoPhillips’ common
stock. The stock price performance included in this graph is not necessarily indicative of future stock price
performance.

ConocoPhillips 2021 10-K

Management’s Discussion and Analysis

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,” “believe,” “budget,” “continue,” “could,” “effort,”
“estimate,” “expect,” “forecast,” “goal,” “guidance,” “intend,” “may,” “objective,” “outlook,” “plan,” “potential,”
“predict,” “projection,” “seek,” “should,” “target,” “will,” “would,” 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 69.

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 one of the world’s leading E&P companies based on both production and reserves with
operations and activities in 14 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. Headquartered in Houston, Texas, at December 31, 2021, we employed approximately 9,900 people
worldwide and had total assets of $91 billion.

Completed Acquisitions
On January 15, 2021, we completed our acquisition of Concho Resources Inc. (Concho), an independent oil and gas
exploration and production company with operations across New Mexico and West Texas in an all-stock
transaction for $13.1 billion. See Note 3.

In December 2021, we completed our acquisition of Shell Enterprises LLC’s (Shell) assets in the Delaware Basin in
an all-cash transaction for $8.7 billion after customary adjustments. Assets acquired include approximately
225,000 net acres of producing properties located entirely in Texas. See Note 3. See Item 1A “Risk Factors” for
further discussion of the risks related to integration of the assets acquired.

Overview
After an unprecedented 2020, the energy landscape improved throughout 2021 with prices reaching pre-pandemic
levels in the second half of the year; however, we expect prices will continue to be cyclical and volatile. Our view is
that a successful business strategy in the E&P industry must be resilient in lower price environments while also
retaining upside during periods of higher prices. As such, we are unhedged, remain highly disciplined in our
investment decisions and continually monitor market fundamentals, including OPEC Plus updates regarding supply
guidance and inventory levels. Although global oil demand improved through 2021, the global economic recovery
remains uncertain and subject to various risk factors, including actions taken to stem the proliferation of COVID-
19.

ConocoPhillips 2021 10-K 34

Management’s Discussion and Analysis

As the macro energy environment continues to evolve, we are embracing what we believe sector leadership
requires through what we call our triple mandate. We believe that ConocoPhillips will play an essential role in
meeting energy transition pathway demand delivering superior and consistent returns on and of capital through
the price cycles, and achieving our net zero ambition on operational emissions, while retaining the flexibility to
successfully adapt as the future unfolds.

Our triple mandate is supported by financial principles and capital allocation priorities that should allow us to
deliver superior returns through the cycles. Our financial principles consist of maintaining balance sheet strength,
providing peer-leading distributions, making disciplined investments, and delivering ESG excellence, all of which
are in service to delivering competitive financial returns. Our 2021 acquisitions of Concho and the Shell Permian
assets further reinforce our differential value proposition.

In 2021, we successfully delivered on our priorities. Total company production was 1,567 MBOED yielding cash
provided by operating activities of $17 billion. We invested $5.3 billion into the business in the form of capital
expenditures and provided returns of capital to shareholders of approximately $6 billion through our ordinary
dividend and share repurchases. For 2021, our ordinary dividend returned $2.4 billion which included an increase
from 43 cents per share to 46 cents per share, effective in December. Share repurchases resumed in February and
amounted to $3.6 billion inclusive of our paced monetization program related to the Cenovus Energy (CVE)
common shares owned. See Note 5. We also demonstrated our commitment to preserving our top-tier balance
sheet with an announcement to reduce the company’s gross debt by $5 billion over five years through a
combination of natural and accelerated maturities.

As part of our ongoing portfolio high-grading and optimization efforts, in December 2021, we announced two
transactions in our Asia Pacific segment enhancing our diverse portfolio. This included notifying Origin Energy of
our intent to exercise our preemption right to purchase an additional 10 percent shareholding interest in APLNG
for $1.645 billion, before customary adjustments, and the sale of our interests in Indonesia for approximately $1.4
billion before customary adjustments. In addition to those transactions, in January 2022, we entered into a
divestiture agreement to sell our interest in noncore assets within our Lower 48 segment for $440 million. These
transactions are expected to close in the first half of 2022. For more information on APLNG, see Note 4 and for
more information on pending dispositions, see Note 3.

We announced an increase in our disposition target to $4 to $5 billion in proceeds by year-end 2023, with
approximately $2 billion sourced from the Permian Basin. As of year-end 2021, we have generated $0.3 billion in
disposition proceeds. The proceeds from these transactions will be used in accordance with the company’s
priorities, including returns of capital to shareholders and reduction of gross debt.

In December 2021, we announced the initiation of a three-tier return of capital framework. This framework is
structured to continue delivering a compelling, growing ordinary dividend and through-cycle share repurchases. It
includes the addition of a VROC tier. The VROC tier will provide a flexible tool for meeting our commitment of
returning greater than 30 percent of cash from operating activities during periods where commodity prices are
meaningfully higher than our planning price range. We have set our expected 2022 total return of capital from all
three tiers at approximately $8 billion. For more information on our three-tier return of capital framework, see
Capital Resources and Liquidity.

35 ConocoPhillips 2021 10-K

Management’s Discussion and Analysis

In 2021, we reaffirmed and improved upon our commitment to ESG leadership and excellence and the specific
targets we set in October 2020 when we became the first U.S.-based oil and gas company to adopt a Paris-aligned
climate-risk strategy. Our commitment includes:

•

•
•

•

Net-zero ambition for operational (scope 1 and 2) emissions by 2050 with active advocacy for a price on
carbon to address end-use (scope 3) emissions;
Targeting a reduction in gross operated and net equity operational GHG emissions intensity by 40 to 50
percent from 2016 levels by 2030;
Zero routine flaring by 2030, with an ambition to get there by 2025;
10 percent reduction target for methane emissions intensity by 2025 from a 2019 baseline, in addition to
the 65 percent reduction we have made since 2015;
Adding continuous methane detection devices to our operations, with an initial focus on the larger Lower
48 facilities;
Dedicated low carbon technology organization responsible for identifying and prioritizing global emissions
reduction initiatives and opportunities associated with the energy transition, CCUS and hydrogen; and
ESG performance factoring into executive and employee compensation programs.

To support this commitment, in December 2021, we announced that approximately $0.2 billion of our 2022
company-wide capital expenditures would be dedicated to energy transition efforts across the company’s global
operations aimed at accelerating the reduction of the company’s scope 1 and 2 emissions and to pursue business
opportunities that address end-use emissions and early-stage low-carbon technology opportunities that leverage
the company’s adjacencies.

Operationally, we remain focused on safely executing the business. Production increased 440 MBOED or 39
percent in 2021, compared to 2020. Production excluding Libya for 2021 was 1,527 MBOED. After adjusting for
closed acquisitions and dispositions, impacts from 2020 curtailments, 2021 Winter Storm Uri and the conversion of
Concho two-stream contracted volumes to a three-stream basis, production increased by 28 MBOED or 2 percent.
This increase was primarily due to new production from the Lower 48 and other development programs across the
portfolio, partially offset by normal field decline. Production from Libya averaged 40 MBOED in 2021.

ConocoPhillips 2021 10-K 36

Management’s Discussion and Analysis

Key Operating and Financial Summary
Significant items during 2021 and recent announcements included the following:

•

Announced an increase to expected 2022 return of capital to shareholders to a total of $8 billion, with the
incremental $1 billion to be distributed through share repurchases and VROC tiers;
Acquired and integrated Concho, capturing over $1 billion of synergies and savings ahead of schedule;
acquired Shell’s Permian assets on December 1, 2021;
Exercised preemption right to purchase an additional 10 percent shareholding interest in APLNG,
expected to close in the first quarter of 2022;
Generated $0.3 billion in disposition proceeds from noncore sales and entered into agreements to sell an
additional $1.8 billion in assets, subject to customary closing adjustments;
Delivered strong operational performance across the company’s asset base, resulting in full-year
production of 1,527 MBOED, excluding Libya;
Achieved first production from GMT2, Malikai Phase 2, SNP Phase 2; completed Tor II project and started
production from a third Montney multi-well pad;
Net cash provided by operating activities was $17 billion, exceeding capital expenditures and investments
of $5.3 billion;
Distributed $6.0 billion to shareholders through $2.4 billion in dividends and $3.6 billion of share
repurchases, representing over 30 percent return of cash provided by operating activities to shareholders;
Ended the year with cash and cash equivalents of $5.0 billion and short-term investments of $0.4 billion,
totaling over $5.4 billion in ending cash and cash equivalents and short-term investments;
Initiated a paced monetization of the company’s CVE investment, generating $1.1 billion in proceeds
through the sale of 117 million shares, with the funds applied to share repurchases; 91 million CVE shares
remained outstanding at year-end 2021; and
Advanced the company’s net-zero ambition by announcing an increase in scope 1 and 2 GHG emissions-
intensity reduction targets to 40 to 50 percent from a 2016 baseline on a net equity and gross operated
basis by 2030, from the previous target of 35 to 45 percent on only a gross operated basis.

Business Environment
Brent crude oil prices averaged $71 per barrel in 2021, compared with $42 per barrel in 2020. The energy industry
has periodically experienced this type of volatility due to fluctuating supply-and-demand conditions and such
volatility may persist in the 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 financial principles that underpin our value proposition; balance sheet strength, peer
leading distributions, disciplined investments and ESG excellence, all of which support strong financial returns.

•

Balance sheet strength. A strong balance sheet is a strategic asset that provides flexibility through price
cycles. We strive to maintain our ‘A’-rating, and we have committed to reducing gross debt by $5 billion
over the next five years. This will reduce interest expense and provide resilience in periods of volatility.
We ended the year with over $5 billion in cash, maintaining balance sheet strength even after completing
the all-cash acquisition of Shell’s Permian assets.

Peer leading distributions. We believe in delivering value to our shareholders via our three-tiered return
of capital framework, which consists of a growing, sustainable dividend, share repurchases, and beginning
in 2022, the addition of VROC. In 2021, we paid dividends on our common stock of approximately $2.4
billion and repurchased $3.6 billion of our common stock partially sourced from our paced monetization
program related to the CVE common shares owned. Our combined dividends and repurchases
represented over 30 percent of our net cash provided by operating activities. Our first VROC of $0.20
cents per share was paid on January 14, 2022, to shareholders of record as of January 3, 2022. Our VROC
will be made at the Board of Director’s discretion, subject to market conditions and other factors. See
Note 5. See “Item 1A—Risk Factors Our ability to execute our capital return program is subject to certain
considerations.”

37 ConocoPhillips 2021 10-K

Management’s Discussion and Analysis

•

Disciplined investments. Our goal is to achieve strong free cash flow by exercising capital discipline,
controlling our costs, and safely and reliably delivering production. We expect to make capital
investments sufficient to sustain production throughout the price cycles. Free cash flow provides funds
that are available to return to shareholders, strengthen the balance sheet or reinvest back into the
business for future cash flow expansion.

Exercise capital discipline. We participate in a commodity price-driven and capital-intensive
industry, with varying lead times from when an investment decision is made to when an asset is
operational and generates cash flow. As a result, we must invest significant capital dollars to
develop newly discovered fields, maintain existing fields, and construct pipelines and LNG
facilities. We allocate capital across a geographically diverse, low cost of supply resource base,
which combined with legacy assets results in low overall 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, cost of carbon,
price-related inflation and G&A. In setting our capital plans, we exercise a rigorous approach
that evaluates projects using these cost of supply criteria, which we believe will lead to value
maximization and cash flow expansion using an optimized investment pace, not production
growth for growth’s sake. Our cash allocation priorities call for the investment of sufficient
capital to sustain production and provide returns of capital to shareholders.

Control our costs. Controlling operating and overhead costs, without compromising safety or
environmental stewardship, is a high priority. Using various methodologies, we monitor these
costs monthly, on an absolute-dollar basis and a per-unit basis and report to management.
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 positively impacts our ability to deliver strong cash from operations.

o Optimize our portfolio. In 2021, we completed the acquisition of Concho and Shell’s Permian
assets, significantly increasing our unconventional portfolio with many additional years of low
cost of supply inventory. The addition of this highly complementary acreage in the Midland and
Delaware basins created a sizeable Permian presence to augment our leading unconventional
positions in the Eagle Ford and Bakken in the Lower 48. In our Asia Pacific segment, we notified
Origin Energy of our intent to exercise our preemption right to purchase an additional 10 percent
shareholding interest in APLNG and announced the sale of our interests in Indonesia. See Note 3.

We continue to evaluate our assets to determine whether they compete for capital within our
portfolio and optimize as necessary, directing capital towards the most competitive investments
and disposing of assets that don’t compete. As such, in conjunction with our Shell Permian
acquisition announcement, we communicated an increase in our planned disposition target to $4
to $5 billion in proceeds by year-end 2023 as part of our ongoing portfolio high-grading and
optimization efforts.

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

▪
▪
▪

Acquire interest in existing or new fields.
Apply new technologies and processes to improve recovery from existing fields.
Successfully explore, develop and exploit new and existing fields.

As required by current authoritative guidelines, the estimated future date when an asset will
reach the end of its economic life is based on historical 12-month first-of-month average prices
and current costs. This date estimates when production will end and 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.

ConocoPhillips 2021 10-K 38

Management’s Discussion and Analysis

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. Our
reserve replacement was 377 percent in 2021, reflecting a net increase from purchases and sales
as well as higher prices. Our organic reserve replacement, which excluded a net increase of
1,115 MMBOE from sales and purchases, was 189 percent in 2021.

In the three years ended December 31, 2021, our reserve replacement was 155 percent. Our
organic reserve replacement during the three years ended December 31, 2021, which excluded a
net increase of 1,022 MMBOE related to sales and purchases, was 88 percent.

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 to 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 fully replace our production over subsequent
years.

•

ESG Leadership. Safety and environmental stewardship, including the operational integrity of our assets,
remain our highest priorities. 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. We strive to conduct our business
with respect and care for the local and global environment and systematically manage risk to drive
sustainable business operations. In September 2021, we reaffirmed and improved upon our commitment
to ESG leadership and excellence and the specific targets that we set in October 2020 when we became
the first U.S. based oil and gas company to adopt a Paris-aligned climate-risk strategy. Our
comprehensive energy transition strategy is designed to sustainably meet global energy demand while
delivering competitive returns on and of capital through the energy transition. Our strategy also
recognizes the importance of reducing society’s end-use emissions to meet global climate goals. As an
E&P company, active only in the upstream side of the business, we do not produce end-use products
directly for consumers. We believe that if everyone addressed their scope 1 and 2 emissions, scope 3
would also be addressed. This is why we have consistently taken a prominent role in advocating that
scope 3 emissions be addressed through a well-designed economywide price on carbon. In addition, we
are making early-stage investments in transition opportunities with the potential to generate competitive
returns that will help address end-use emissions, including CCUS and Hydrogen. We are also engaging
with our supply chain on their emissions targets.

Other significant factors that can affect our profitability include:

•

Energy commodity prices. Our earnings and operating cash flows generally correlate with crude oil and
natural gas commodity prices. Commodity 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 Plus and other producing
countries, environmental laws, tax regulations, governmental policies, global pandemics 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 over the past three years:

39 ConocoPhillips 2021 10-K

Management’s Discussion and Analysis

Brent crude oil prices averaged $70.73 per barrel in 2021, an increase of 70 percent compared with
$41.68 per barrel in 2020. Similarly, WTI crude oil prices increased 72 percent from $39.37 per barrel in
2020 to $67.92 per barrel in 2021. Following COVID-19 economic shutdowns in early 2020, global oil
demand increased steadily through the year alongside the global economic recovery. OPEC Plus supply
restraint, capital discipline by U.S. E&P’s and various unplanned supply disruptions in producing countries
moderated supply growth, reducing excess global inventories and putting upward pressure on global oil
prices.

Henry Hub natural gas prices increased 85 percent from an average of $2.08 per MMBTU in 2020 to $3.85
per MMBTU in 2021. Extreme weather events in many parts of the world and several global LNG
liquefaction outages depleted global natural gas inventories in early 2021, generating strong demand for
U.S. LNG exports and supporting robust domestic demand.

Our realized bitumen price increased 368 percent from an average of $8.02 per barrel in 2020 to $37.52
per barrel in 2021. The increase was largely driven by strength in WTI, reflective of increasing global
demand and OPEC discipline. The WCS differential to WTI at Hardisty remained fairly flat as record high
production offsets incremental pipeline capacity. We continue to optimize bitumen price realizations
through improvements in alternate blend capability which results in lower diluent costs and access to the
U.S. Gulf Coast market through rail and pipeline contracts.

Our worldwide annual average realized price increased 70 percent from $32.15 per BOE in 2020 to $54.63
per BOE in 2021 primarily due to higher realized oil, natural gas and bitumen 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 of 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.

ConocoPhillips 2021 10-K

Management’s Discussion and Analysis

•

Impairments. We 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, a decision to dispose of an asset leads to a write-down to its fair value,
or the current fair value of an investment is less than its carrying amount and the loss in value is deemed
other than temporary. 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. For more
information on our impairments, see Note 6 and Note 7.

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 civil unrest or strained
relationships with governments that may impact our operations or investments. These changing
environments could negatively impact our results of operations, and further changes to 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
Production and Capital
2022 operating plan capital budget is $7.2 billion. The plan includes funding for ongoing development drilling
programs, major projects, exploration and appraisal activities, base maintenance and $0.2 billion for projects to
reduce the company’s scope 1 and 2 emissions intensity and investments in several early-stage low-carbon
opportunities that address end-use emissions.

Production guidance is 1.8 MMBOED in 2022 including Libya but excluding the impacts from the pending Indonesia
disposition and acquisition of additional APLNG shareholding interest. First quarter 2022 production is expected to
be 1.75 MMBOED to 1.79 MMBOED.

Operating Segments
We manage our operations through six operating segments, which are primarily defined by geographic region:
Alaska; Lower 48; Canada; Europe, Middle East and North Africa; Asia Pacific; and Other International.

Corporate and Other represents income and costs not directly associated with an operating segment, such as most
interest expense, premiums 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.

41 ConocoPhillips 2021 10-K

Results of Operations

This section of the Form 10-K discusses year-to-year comparisons between 2021 and 2020. For discussion of year-
to-year comparisons between 2020 and 2019, see "Management's Discussion and Analysis of Financial Condition
and Results of Operations" in Part II, Item 7 of our 2020 10-K.

Consolidated Results

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

Years Ended December 31

Alaska
Lower 48
Canada
Europe, Middle East and North Africa
Asia Pacific
Other International
Corporate and Other
Net income (loss) attributable to ConocoPhillips

Millions of Dollars

2021

2020

2019

1,386
4,932
458
1,167
453
(107)
(210)
8,079

(719)
(1,122)
(326)
448
962
(64)
(1,880)
(2,701)

1,520
436
279
3,170
1,483
263
38
7,189

Net Income (loss) attributable to ConocoPhillips increased $10.8 billion in 2021. 2021 earnings were positively
impacted by:

•
•

•

•
•
•

•

Higher realized commodity prices.
Higher sales volumes primarily due to our Concho acquisition and absence of production curtailments.
See Note 3.
A gain of $1,040 million after-tax on our Cenovus Energy (CVE) common shares in 2021, as compared to a
$855 million after-tax loss on those shares in 2020.
Lower exploration expenses due to:

o
o
o

Absence of a 2020 impairment for $648 million after-tax for the entire carrying value of
capitalized undeveloped leasehold costs related to our Alaska North Slope Gas asset.
Lower dry hole expenses.
Absence of early cancellation of our 2020 winter exploration program in Alaska.
Absence of unproved property impairment and dry hole expenses in 2020 for the Kamunsu East
Field in Malaysia, which is no longer in our development plans.
Higher equity in earnings of affiliates, primarily due to higher LNG sales prices.
Contingent payments related to prior dispositions in our Canada and Lower 48 segments.
An after-tax gain of $194 million recognized for a FID bonus associated with our Australia-West divestiture
in 2020. See Note 3.
Lower impairments, primarily due to the absence of impairments recognized in 2020 for noncore assets in
our Lower 48 segment partially offset by an impairment in our APLNG investment included within our Asia
Pacific segment. See Note 7.

These increases in net income (loss) were partly offset by:

•

•
•

Higher production and operating expenses and taxes other than income taxes, primarily due to higher
sales volumes.
Higher DD&A expenses caused by higher production volumes, partially offset by lower rates driven from
positive reserve revisions due to higher commodity prices in 2021.
Absence of a $597 million after-tax gain on our Australia-West divestiture completed in May 2020.
Restructuring and transaction expenses of $341 million after-tax associated with the Concho and Shell
acquisitions in addition to mark-to-market impacts on certain key employee compensation programs.

ConocoPhillips 2021 10-K 42

Results of Operations

•

Realized losses on hedges of $233 million after-tax related to derivative positions assumed through our
Concho acquisition. These derivative positions were settled entirely within the first quarter of 2021. See
Note 12.

Income Statement Analysis

Unless otherwise indicated, all results in Income Statement Analysis are before-tax.

Sales and other operating revenues increased 144 percent in 2021, mainly due to higher realized commodity prices
and higher sales volumes.

Equity in earnings of affiliates increased $400 million in 2021, primarily due to higher earnings driven by higher
LNG and crude prices, partially offset by a higher effective tax rate related to equity method investments in our
Europe, Middle East and North Africa segment.

Gain on dispositions decreased $63 million in 2021, primarily due to the absence of a $587 million gain related to
our 2020 Australia-West divestiture and a $179 million loss associated with the sale of noncore assets in our Other
International segment. The decreases were partially offset by $200 million related to a FID bonus associated with
our Australia-West divestiture, gains recognized for contingent payments associated with previous dispositions in
our Canada and Lower 48 segments and gains on sales of certain noncore assets in our Lower 48 segment.

Other income (loss) increased $1.7 billion in 2021, primarily due to a gain of $1,040 million on our CVE common
shares in 2021, as compared to a $855 million loss on those shares in 2020. See Note 5.

Purchased commodities increased 125 percent in 2021, primarily in line with higher gas and crude prices and
volumes.

Production and operating expenses increased $1,350 million in 2021, primarily in line with higher production
volumes.

Selling, general and administrative expenses increased $289 million in 2021, primarily due to transaction and
restructuring expenses associated with our Concho acquisition and higher compensation and benefits costs,
including mark-to-market impacts of certain key employee compensation programs.

Exploration expenses decreased $1,113 million in 2021, primarily due to the absence of 2020 expenses including
an $828 million impairment for the entire carrying value of capitalized undeveloped leasehold costs related to our
Alaska North Slope Gas asset, the early cancellation of our 2020 winter exploration program in Alaska, and absence
of unproved property impairment and dry hole expenses from 2020 for the Kamunsu East Field in Malaysia. 2021
also saw lower dry hole expenses in Alaska.

Impairments decreased $139 million in 2021, primarily due to the absence of impairments recognized in 2020 for
noncore assets in our Lower 48 segment partially offset by an impairment in our APLNG investment included
within our Asia Pacific segment in 2021. For additional information, see Note 7 and Note 13.

Taxes other than income taxes increased $880 million in 2021, caused primarily by higher commodity prices and
higher Lower 48 sales volumes.

Foreign currency transaction (gains) losses decreased $50 million in 2021 due to the absence of derivative gains
and other remeasurements.

See Note 17—Income Taxes for information regarding our income tax provision and effective tax rate.

43 ConocoPhillips 2021 10-K

Results of Operations

Summary Operating Statistics

Average Net Production
Crude oil (MBD)

Consolidated Operations
Equity affiliates
Total crude oil

Natural gas liquids (MBD)
Consolidated Operations
Equity affiliates
Total natural gas liquids

Bitumen (MBD)

Natural gas (MMCFD)

Consolidated Operations
Equity affiliates
Total natural gas

Total Production (MBOED)

Average Sales Prices
Crude oil (per bbl)

Consolidated Operations
Equity affiliates
Total crude oil

Natural gas liquids (per bbl)
Consolidated Operations
Equity affiliates
Total natural gas liquids

Bitumen (per bbl)

Natural gas (per mcf)

Consolidated Operations
Equity affiliates
Total natural gas

Worldwide Exploration Expenses
General and administrative; geological and geophysical,

lease rental, and other

Leasehold impairment
Dry holes
Total Exploration Expenses

2021

2020

2019

816
13
829

134
8
142

555
13
568

97
8
105

692
13
705

107
8
115

2,109
1,053
3,162

1,339
1,055
2,394

1,753
1,052
2,805

1,567

1,127

1,348

Dollars Per Unit

67.61
69.45
67.64

31.04
54.16
32.45

37.52

6.00
5.31
5.77

39.56
39.02
39.54

12.90
32.69
14.61

60.98
61.32
60.99

18.73
36.70
20.09

8.02

31.72

3.17
3.71
3.41

Millions of Dollars

300
10
34
344

374
868
215
1,457

4.25
6.29
5.03

322
221
200
743

ConocoPhillips 2021 10-K 44

Results of Operations

Total production, including Libya, of 1,567 MBOED increased 440 MBOED or 39 percent in 2021 compared with
2020, primarily due to:

•
•
•
•

•

Higher volumes in Lower 48 due to our Concho acquisition.
New wells online in Lower 48, Canada, Norway, Malaysia and Alaska.
Absence of production curtailments, primarily in our North American assets.
Higher production in Libya due to the absence of a forced shutdown of the Es Sider export terminal and
other eastern export terminals.
Improved well performance in Norway, Canada, Alaska and China.

The increase in production during 2021 was partly offset by:

•
•

Normal field decline.
Absence of production from Australia-West due to our second quarter 2020 disposition.

Production excluding Libya for 2021 was 1,527 MBOED. After adjusting for closed acquisitions and dispositions,
impacts from 2020 curtailments, 2021 Winter Storm Uri and the conversion of Concho two-stream contracted
volumes to a three-stream basis, production increased by 28 MBOED or 2 percent. This increase was primarily due
to new production from the Lower 48 and other development programs across the portfolio, partially offset by
normal field decline. Production from Libya averaged 40 MBOED in 2021.

45 ConocoPhillips 2021 10-K

Results of Operations

Alaska

Net Income (Loss) Attributable to ConocoPhillips ($MM)

Average Net Production
Crude oil (MBD)
Natural gas liquids (MBD)
Natural gas (MMCFD)
Total Production (MBOED)

Average Sales Prices
Crude oil ($ per bbl)
Natural gas ($ per mcf)

2021
1,386

2020
(719)

2019
1,520

178
16
16
197

181
16
10
198

202
15
7
218

69.87
2.81

42.12
2.91

64.12
3.19

The Alaska segment primarily explores for, produces, transports and markets crude oil, NGLs and natural gas. In
2021, Alaska contributed 19 percent of our consolidated liquids production and less than 1 percent of our
consolidated natural gas production.

Net Income (Loss) Attributable to ConocoPhillips
Alaska reported earnings of $1,386 million in 2021, compared with a loss of $719 million in 2020. Earnings were
positively impacted by:

•
•

•

Higher realized crude oil prices.
Absence of 2020 exploration expenses, including a $648 million after-tax impairment associated with the
carrying value of our Alaska North Slope Gas assets and the early cancellation of our winter exploration
program. See Note 6.
Lower dry hole expenses.

Earnings were negatively impacted by:

•

Higher taxes other than income taxes primarily due to higher realized crude oil prices.

Production
Average production decreased 1 MBOED in 2021 compared with 2020, primarily due to:

•

Normal field decline.

•
•

The production decrease was partly offset by:
Absence of curtailments.
Improved production at our Western North Slope assets as a result of net royalty interest changes
associated with periodic redetermination.
Improved performance in the Greater Prudhoe Area and Western North Slope assets.
New wells online across the segment.

•
•

ConocoPhillips 2021 10-K 46

Results of Operations

Lower 48

Net Income (Loss) Attributable to ConocoPhillips ($MM)

Average Net Production
Crude oil (MBD)
Natural gas liquids (MBD)*
Natural gas (MMCFD)*
Total Production (MBOED)

2021
4,932

2020
(1,122)

447
110
1,340
780

213
74
585
385

2019
436

266
81
622
451

Average Sales Prices
Crude oil ($ per bbl)**
Natural gas liquids ($ per bbl)
Natural gas ($ per mcf)**
*Includes conversion of previously acquired Concho two-stream contracts to three-stream initiated in the fourth quarter of 2021.
**Average sales prices, including the impact of hedges settling per initial contract terms in the first quarter of 2021 assumed in our Concho
acquisition were $65.19 per barrel for crude oil and $4.33 per mcf for natural gas for the year ended December 31, 2021. As of March 31, 2021,
we had settled all oil and gas hedging positions acquired from Concho. See Note 12.

66.12
30.63
4.38

55.30
16.83
2.12

35.17
12.13
1.65

The Lower 48 segment consists of operations located in the contiguous U.S. and the Gulf of Mexico. During 2021,
the Lower 48 contributed 55 percent of our consolidated liquids production and 64 percent of our consolidated
natural gas production.

Net Income (Loss) Attributable to ConocoPhillips
Lower 48 reported earnings of $4,932 million in 2021, compared with a loss of $1,122 million in 2020. Earnings
were positively impacted by:

•
•
•

•

Higher realized crude oil, NGL and natural gas prices.
Higher sales volumes due to our Concho acquisition and the absence of production curtailments.
Lower impairments, primarily related to developed properties in our noncore assets which were written
down to fair value due to lower commodity prices and development plan changes. See Note 7 and Note
13.
Higher gains on dispositions related to selling our interests in certain noncore assets. See Note 3.

Earnings were negatively impacted by:

•

Higher DD&A expenses, production and operating expenses and taxes other than income taxes primarily
due to higher production volumes. Partially offsetting the increase in DD&A expenses were lower rates
from price-related reserve revisions.
Impacts resulting from our Concho acquisition, including higher selling, general and administrative
expenses for transaction and restructuring charges, as well as realized losses on derivative settlements.
See Note 3 and Note 12.

Production
Total average production increased 395 MBOED in 2021 compared with 2020, primarily due to:

•
•
•

Higher volumes due to our Concho acquisition.
New wells online from our development programs in Permian, Eagle Ford and Bakken.
Absence of curtailments.

These production increases were partly offset by:

•

Normal field decline.

47 ConocoPhillips 2021 10-K

Results of Operations

Canada

Net Income (Loss) Attributable to ConocoPhillips ($MM)

2021*
458

2020*
(326)

2019**
279

Average Net Production
Crude oil (MBD)
Natural gas liquids (MBD)
Bitumen (MBD)
Natural gas (MMCFD)
Total Production (MBOED)

8
4
69
80
94

6
2
55
40
70

Average Sales Prices
Crude oil ($ per bbl)
Natural gas liquids ($ per bbl)
Bitumen ($ per bbl)
Natural gas ($ per mcf)
*Average sales prices include unutilized transportation costs.
**Average prices for sales of bitumen produced 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.

56.38
31.18
37.52
2.54

23.57
5.41
8.02
1.21

1
-
60
9
63

40.87
19.87
31.72
0.49

Our Canadian operations consist of the Surmont oil sands development in Alberta and the liquids-rich Montney
unconventional play in British Columbia. In 2021, Canada contributed 8 percent of our consolidated liquids
production and 4 percent of our consolidated natural gas production.

Net Income (Loss) Attributable to ConocoPhillips
Canada operations reported earnings of $458 million in 2021 compared with a loss of $326 million in 2020.
Earnings were positively impacted by:

•
•

•

Higher realized bitumen prices and crude oil prices.
After-tax gains on disposition related to contingent payments of $246 million in 2021 associated with the
sale of certain assets to CVE in 2017.
Higher sales volumes in our Surmont and Montney assets.

Earnings were negatively impacted by:

•

Higher production and operating expenses primarily due to increased Surmont and Montney production.

Production
Total average production increased 24 MBOED in 2021 compared with 2020. The production increase was
primarily due to:

•
•
•
•

Improved well performance in Surmont.
New wells online in Montney.
Production from our Kelt acquisition completed in the third quarter of 2020.
Absence of curtailments.

ConocoPhillips 2021 10-K 48

Results of Operations

Europe, Middle East and North Africa

Net Income (Loss) Attributable to ConocoPhillips ($MM)

Consolidated Operations
Average Net Production
Crude oil (MBD)
Natural gas liquids (MBD)
Natural gas (MMCFD)
Total Production (MBOED)

Average Sales Prices
Crude oil ($ per bbl)
Natural gas liquids ($ per bbl)
Natural gas ($ per mcf)

2021
1,167

2020
448

2019
3,170

118
4
313
175

68.97
43.97
13.27

86
4
275
136

43.30
23.27
3.23

138
7
478
224

64.94
29.37
4.92

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 terminalling operations in the U.K. In 2021, our
Europe, Middle East and North Africa operations contributed 12 percent of our consolidated liquids production
and 14 percent of our consolidated natural gas production.

Net Income Attributable to ConocoPhillips
The Europe, Middle East and North Africa segment reported earnings of $1,167 million in 2021 compared with
earnings of $448 million in 2020. Earnings were positively impacted by:
Higher realized natural gas, crude oil and NGL prices.
Higher LNG sales prices, reflected in equity in earnings of affiliates.
Higher sales volumes of crude oil and LNG.

•
•
•

Earnings were negatively impacted by:

•
•

Higher taxes.
Higher DD&A expenses and production and operating expenses. Partly offsetting the increase in DD&A
expenses were lower rates from positive reserve revisions.

Consolidated Production
Average consolidated production increased 39 MBOED in 2021, compared with 2020. The consolidated production
increase was primarily due to:

•

•
•

Higher production in Libya due to the absence of a forced shutdown of the Es Sider export terminal and
other eastern export terminals.
Improved well performance in Norway.
New production from Norway drilling activities, including our Tor II redevelopment project which
achieved full production in 2021.

These production increases were partly offset by:

•

Normal field decline.

49 ConocoPhillips 2021 10-K

Results of Operations

Asia Pacific

Net Income (Loss) Attributable to ConocoPhillips ($MM)

Consolidated Operations
Average Net Production
Crude oil (MBD)
Natural gas liquids (MBD)
Natural gas (MMCFD)
Total Production (MBOED)

Average Sales Prices
Crude oil ($ per bbl)
Natural gas liquids ($ per bbl)
Natural gas ($ per mcf)

2021
453

2020
962

2019
1,483

65
-
360
125

70.36
-
6.56

69
1
429
141

42.84
33.21
5.39

85
4
637
196

65.02
37.85
5.91

The Asia Pacific segment has operations in China, Indonesia, Malaysia and Australia. During 2021, Asia Pacific
contributed 6 percent of our consolidated liquids production and 17 percent of our consolidated natural gas
production.

Net Income Attributable to ConocoPhillips
Asia Pacific reported earnings of $453 million in 2021, compared with $962 million in 2020. The decrease in earnings
was mainly due to:

•
•
•

An impairment of $688 million after-tax on our APLNG investment. See Note 4 and Note 13.
Absence of a $597 million after-tax gain related to our Australia-West divestiture. See Note 3.
Absence of sales volumes associated with Australia-West.

Earnings were positively impacted by:

•
•
•

Higher crude oil and natural gas prices.
Higher LNG sales prices, reflected in equity in earnings of affiliates.
An after-tax gain of $194 million recognized for a FID bonus associated with our Australia-West divestiture.
For additional information related to this FID bonus, see Note 3 and Note 11.

Consolidated Production
Average consolidated production decreased 16 MBOED in 2021, compared with 2020. The decrease was primarily
due to:

•
•

The divestiture of our Australia-West assets that contributed 18 MBOED in 2020.
Normal field decline.

These production decreases were partly offset by:

•
•
•

Development activity at Bohai Bay in China.
First production in Malikai Phase 2 and SNP Phase 2.
The absence of curtailments across the segment and increased demand in Indonesia from coal supply
restrictions.

ConocoPhillips 2021 10-K 50

Results of Operations

Other International

Net Income (Loss) Attributable to ConocoPhillips ($MM)

2021
(107)

2020
(64)

2019
263

The Other International segment includes exploration and appraisal activities in Colombia as well as contingencies
associated with prior operations in other countries. As a result of our Concho acquisition, we refocused our
exploration program and announced our intent to pursue managed exits from certain areas.

Other International operations reported a loss of $107 million in 2021, compared with a loss of $64 million in 2020.
Earnings were negatively impacted by:

•
•

A $137 million after-tax loss on divestiture related to our Argentina exploration interests. See Note 3.
Absence of a $29 million after-tax benefit to earnings from the dismissal of arbitration related to prior
operations in Senegal recognized in the first quarter of 2020.

Changes to earnings were positively impacted by:

•

Absence of exploration expenses associated with dry hole costs and a full impairment of capitalized
undeveloped leasehold costs in Colombia in the fourth quarter of 2020.

Corporate and Other

Net Income (Loss) Attributable to ConocoPhillips
Net interest
Corporate general and administrative expenses
Technology
Other

Millions of Dollars

2021

(801)
(317)
25
883
(210)

2020

(662)
(200)
(26)
(992)
(1,880)

2019

(604)
(252)
123
771
38

Net interest consists of interest and financing expense, net of interest income and capitalized interest. Net
interest expense increased $139 million in 2021 compared with 2020, primarily due to higher debt balances
assumed due to our Concho acquisition. See Note 9.

Corporate G&A expenses include compensation programs and staff costs. These expenses increased by $117
million in 2021 compared with 2020, primarily due to restructuring expenses associated with our Concho
acquisition and mark to market adjustments associated with certain compensation programs. See Note 16.

Technology includes our investment in new technologies or businesses, as well as licensing revenues. Activities are
focused on both conventional and tight oil reservoirs, shale gas, heavy oil, oil sands, enhanced oil recovery as well
as LNG. Earnings from Technology increased by $51 million in 2021 compared with 2020, 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, holding gains or losses on equity securities, and pension
settlement expense. Earnings in “Other” increased by $1,875 million in 2021 compared with 2020, primarily due
to a gain of $1,040 million on our CVE common shares in 2021, compared with a $855 million loss in 2020.

51 ConocoPhillips 2021 10-K

Capital Resources and Liquidity

Capital Resources and Liquidity
Financial Indicators

Net cash provided by operating activities
Cash and cash equivalents
Short-term investments
Short-term debt
Total debt
Total equity
Percent of total debt to capital*
Percent of floating-rate debt to total debt
*Capital includes total debt and total equity.

Millions of Dollars
Except as Indicated
2020

2021

16,996
5,028
446
1,200
19,934
45,406

31 %
4 %

4,802
2,991
3,609
619
15,369
29,849
34
7

2019

11,104
5,088
3,028
105
14,895
35,050
30
5

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 2021, the primary uses of our available
cash were $8.7 billion for the acquisition of Shell Permian; $5.3 billion to support our ongoing capital expenditures
and investments program; $3.6 billion to repurchase our common stock; $2.4 billion to pay dividends; and $1.2
billion for hedging, transaction and restructuring costs. In 2021, cash and cash equivalents increased by $2.0
billion to $5.0 billion.

At December 31, 2021, we had cash and cash equivalents of $5.0 billion, short-term investments of $0.4 billion,
and available borrowing capacity under our credit facility of $6.0 billion, totaling approximately $11.5 billion of
liquidity. We 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, dividend payments and
required debt payments.

Significant Changes in Capital
Operating Activities
In 2021, cash provided by operating activities was $17 billion, compared with $4.8 billion for 2020. The increase is
primarily due to higher realized commodity prices and higher sales volumes, mostly resulting from our acquisition
of Concho. The increase was partly offset by the $0.8 billion in settlement of oil and gas hedging positions
acquired from Concho, and approximately $0.4 billion of transaction and restructuring costs.

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 1,567 MBOED in 2021. Full-year production excluding Libya averaged 1,527 MBOED.
Adjusting for closed acquisitions and dispositions, impacts from 2020 curtailments, 2021 Winter Storm Uri and the
conversion of Concho two-stream contracted volumes to a three-stream basis, production increased 28 MBOED or
2 percent. First quarter 2022 production is expected to be 1.75 MMBOED to 1.79 MMBOED. 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;

ConocoPhillips 2021 10-K 52

Capital Resources and Liquidity

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. Reserve replacement
represents the net change in proved reserves, net of production, divided by our current year production. For
information on proved reserves, including both developed and undeveloped reserves, see the reserve table
disclosures contained in “Supplementary Data – Oil and Gas Operations.” See “Item 1A—Risk Factors – Unless we
successfully develop our resources, the scope of our business will decline, resulting in an adverse impact to our
business.”

As discussed in the “Critical Accounting Estimates” section, engineering estimates of proved reserves are
imprecise; therefore, reserves may be revised upward or downward each year due to the impact of changes in
commodity prices or as more technical data becomes available on reservoirs. It is not possible to reliably predict
how revisions will impact future reserve quantities.

Investing Activities
In 2021, we invested $5.3 billion in capital expenditures. Capital expenditures invested in 2020 and 2019 were
$4.7 billion and $6.6 billion, respectively. For information about our capital expenditures and investments, see the
“Capital Expenditures and Investments” section.

In December 2021, we completed our acquisition of Shell’s assets in the Delaware Basin for cash consideration of
approximately $8.7 billion after customary adjustments. We funded this transaction with cash on hand. We
completed our acquisition of Concho on January 15, 2021. The assets acquired in the transaction included $382
million of cash. The net impact of these items is recognized within “Acquisition of businesses, net of cash
acquired” on our consolidated statement of cash flows. See Note 3.

In 2021, we announced a disposition target of $4 to $5 billion in disposition proceeds by year-end 2023. Only
proceeds from transactions announced or initiated in the third quarter of 2021 or later will be counted toward this
target. The proceeds from these transactions will be used in accordance with the company’s priorities, including
returns of capital to shareholders and reduction of gross debt. To date, we have achieved $0.3 billion from the
sale of noncore assets in our Lower 48 segment.

Total proceeds from asset dispositions in 2021 were $1.7 billion. Including the $250 million mentioned above, we
also received cash proceeds of $1.14 billion from sales of our investment in CVE common shares and $244 million
of contingent payments related to dispositions completed before 2021. See Note 3. In May 2021, we announced
and began a paced monetization of our investment in CVE with the plan to direct proceeds toward our existing
share repurchase program. We expect to fully dispose of our CVE common shares by early 2022, however, the
sales pace will be guided by market conditions, and we retain discretion to adjust accordingly. See Note 5.

Proceeds from asset sales in 2020 were $1.3 billion. We received cash proceeds of $765 million for the divestiture
of our Australia-West assets and operations. We also received proceeds of $359 million and $184 million from the
sale of our Niobrara interests and Waddell Ranch interests in the Lower 48, respectively.

Proceeds from asset sales in 2019 were $3.0 billion, including $2.2 billion for the sale of two ConocoPhillips U.K.
subsidiaries and $350 million for the sale of our 30 percent interest in the Greater Sunrise Fields. See Note 3.

We invest in short-term investments as part of our cash investment strategy, the primary objective of which is to
protect principal, maintain liquidity and provide yield and total returns; these investments include time deposits,
commercial paper, as well as debt securities classified as available for sale. 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

ConocoPhillips 2021 10-K

Capital Resources and Liquidity

price downturns and to capture opportunities outside a given operating plan may be invested in instruments with
maturities greater than one year. See Note 12.

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

Credit facility borrowings may bear interest at a margin above rates offered by certain designated banks in the
London interbank market or at a margin above the overnight federal funds rate or prime rates offered by certain
designated banks in the U.S. The agreement calls for commitment fees on available, but unused, amounts. The
agreement also contains early termination rights if our current directors or their approved successors cease to be a
majority of the Board of Directors.

The revolving credit facility supports ConocoPhillips Company’s ability to issue up to $6.0 billion of commercial
paper, which is primarily a funding source for short-term working capital needs. Commercial paper maturities are
generally limited to 90 days. With no commercial paper outstanding and no direct borrowings or letters of credit,
we had access to $6.0 billion in available borrowing capacity under the revolving credit facility at December 31,
2021.

On January 15, 2021, we completed the acquisition of Concho in an all-stock transaction. In the acquisition, we
assumed Concho’s publicly traded debt and in December 2020, we launched an offer to exchange Concho’s
publicly traded debt for debt issued by ConocoPhillips. There were no impacts to ConocoPhillips’ credit ratings as a
result of the debt exchange. In June 2021, we reaffirmed our commitment to preserving our ‘A’-rated balance
sheet by restating our intent to reduce gross debt by $5 billion over the next five years, driving a more resilient and
efficient capital structure. See Note 9 and Note 3.

On January 25, 2021, S&P revised the industry risk assessment for the E&P industry to ‘Moderately High’ from
‘Intermediate’ based on a view of increasing risks from the energy transition, price volatility, and weaker
profitability. On February 11, 2021, S&P downgraded its rating of our long-term debt from “A” to “A-” with a
“stable” outlook and affirmed this rating in November 2021. In October 2021, Moody’s affirmed its “A3” rating of
our long-term debt and revised its outlook from “stable” to “positive”. In December 2021, Fitch affirmed its rating
of our long-term debt as “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, upon downgrade of our credit ratings. If our credit ratings are downgraded
from their current levels, 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, 2021 and 2020, we had direct bank letters of credit of $337 million and $249
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.

We have a universal shelf registration statement on file with the SEC under which we have the ability to issue and
sell an indeterminate amount of various types of debt and equity securities.

ConocoPhillips 2021 10-K 54

Capital Resources and Liquidity

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

Our debt balance at December 31, 2021, was $19.9 billion, an increase of $4.6 billion from the balance at
December 31, 2020, driven by debt acquired as part of the Concho acquisition. Maturities of debt (including
payments for finance leases) due in 2022 of $1.1 billion will be paid from current cash balances and cash generated
by operations. See Note 9.

In December 2021, we announced our expected 2022 return of capital program and the initiation of a three-tier
return of capital framework. The framework is structured to deliver a compelling, growing ordinary dividend and
through-cycle share repurchases. It includes the addition of a discretionary VROC tier. The VROC will provide a
flexible tool for meeting our commitment of returning greater than 30 percent of cash from operating activities
during periods where commodity prices are meaningfully higher than our planning price range. We have set our
expected 2022 total capital returns at approximately $8 billion, consisting of distributions from each of the three
tiers.

Consistent with our commitment to deliver value to shareholders, in 2021, we paid $2.4 billion, $1.75 per share of
common stock, in ordinary dividends. This was an increase over 2020 and 2019, when we paid $1.69 and $1.34 per
share of common stock, respectively. On February 3, 2022, we announced a quarterly dividend of $0.46 per share,
payable March 1, 2022, to stockholders of record at the close of business on February 14, 2022. On January 14,
2022, we paid the first VROC payment of $0.20 per share to shareholders of record as of January 3, 2022. On
February 3, 2022, we announced a VROC of $0.30 per share, payable on April 14, 2022, to stockholders of record at
the close of business on March 31, 2022.

The ordinary dividend and VROC are subject to numerous considerations and will be determined and approved
each quarter by the Board of Directors. We expect to announce the VROC when we announce our ordinary
dividend, but the quarterly payouts will be staggered from the ordinary dividend, resulting in up to eight cash
distributions throughout the year.

In late 2016, we initiated our current share repurchase program with Board of Director’s authorization of $25
billion of our common stock. Share repurchases were $3.6 billion, $0.9 billion, and $3.5 billion in 2021, 2020, and
2019, respectively. As of December 31, 2021, share repurchases since the inception of our current program
totaled 247 million shares and $14 billion. Repurchases are made at management’s discretion, at prevailing prices,
subject to market conditions and other factors.

For more information on factors considered when determining the levels of returns of capital see “Item 1A—Risk
Factors – Our ability to execute our capital return program is subject to certain considerations.”

In addition to the priorities described above, we have contractual obligations to purchase goods and services of
approximately $11.8 billion. We expect to fulfill $6 billion of these obligations in 2022. These figures exclude
purchase commitments for jointly owned fields and facilities where we are not the operator. Purchase obligations
of $5.3 billion are related to agreements to access and utilize the capacity of third-party equipment and facilities,
including pipelines and LNG product terminals, to transport, process, treat and store commodities. Purchase
obligations of $5.3 billion are related to market-based contracts for commodity product purchases with third
parties. 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.

55 ConocoPhillips 2021 10-K

Capital Resources and Liquidity

Capital Expenditures and Investments

Alaska
Lower 48
Canada
Europe, Middle East and North Africa
Asia Pacific
Other International
Corporate and Other
Capital Program*
* Excludes capital related to acquisitions of businesses, net of capital acquired.

Millions of Dollars

2021
982
3,129
203
534
390
33
53
5,324

2020
1,038
1,881
651
600
384
121
40
4,715

2019
1,513
3,394
368
708
584
8
61
6,636

Our capital expenditures and investments for the three-year period ended December 31, 2021, totaled
$16.7 billion. The 2021 expenditures supported key exploration and developments, primarily:

•
•

•

•
•

Development activities in the Lower 48, primarily Permian, Eagle Ford, and Bakken.
Appraisal and development activities in Alaska related to the Western North Slope and development
activities in the Greater Kuparuk Area.
Appraisal and development activities in the Montney and optimization of oil sands development in
Canada.
Continued development activities across assets in Norway.
Continued development activities in China, Malaysia, and Indonesia.

2022 Capital Budget
In December 2021, we announced our 2022 operating plan capital of $7.2 billion. The plan includes funding for
ongoing development drilling programs, major projects, exploration and appraisal activities, base maintenance and
$0.2 billion for projects to reduce the company’s scope 1 and 2 emissions intensity and investments in several
early-stage low-carbon opportunities that address end-use emissions.

ConocoPhillips 2021 10-K 56

Capital Resources and Liquidity

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

The following tables present summarized financial information for the Obligor Group, as defined below:

•

The Obligor Group will reflect guarantors and issuers of guaranteed securities consisting of
ConocoPhillips, ConocoPhillips Company and Burlington Resources LLC.
Consolidating adjustments for elimination of investments in and transactions between the collective
guarantors and issuers of guaranteed securities are reflected in the balances of the summarized financial
information.
Non-Obligated Subsidiaries are excluded from this presentation.

Upon completing the Concho acquisition on January 15, 2021, we assumed Concho’s publicly traded debt of
approximately $3.9 billion in aggregate principal amount, which was recorded at the fair value of $4.7 billion on
the acquisition date. We completed a debt exchange offer that settled on February 8, 2021, of which 98 percent,
or approximately $3.8 billion in aggregate principal amount of Concho’s notes, were tendered and accepted for
new debt issued by ConocoPhillips. The new debt issued in the exchange is fully and unconditionally guaranteed
by ConocoPhillips Company. Both the guarantor and issuer of the exchange debt is reflected within the Obligor
Group presented here. See Note 3 and Note 9.

Transactions and balances reflecting activity between the Obligors and Non-Obligated Subsidiaries are presented
separately below:

Summarized Income Statement Data

Millions of Dollars
2021

Revenues and Other Income
Income (loss) before income taxes*
Net income (loss)
Net Income (Loss) Attributable to ConocoPhillips
*Includes approximately $5.4 billion of purchased commodities expense for transactions with Non-Obligated Subsidiaries.

30,457
8,017
8,079
8,079

Summarized Balance Sheet Data

Current assets
Amounts due from Non-Obligated Subsidiaries, current
Noncurrent assets
Amounts due from Non-Obligated Subsidiaries, noncurrent
Current liabilities
Amounts due to Non-Obligated Subsidiaries, current
Noncurrent liabilities
Amounts due to Non-Obligated Subsidiaries, noncurrent

57 ConocoPhillips 2021 10-K

Millions of Dollars
December 31, 2021
7,689
1,927
69,841
7,281
8,005
3,477
30,677
13,007

Capital Resources and Liquidity

Contingencies
We are subject to legal proceedings, claims, and liabilities that arise in the ordinary course of business. We accrue
for losses associated with legal claims when such losses are considered probable and the amounts can be
reasonably estimated. See “Critical Accounting Estimates” and Note 11 for information on contingencies.

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

Our legal organization applies its knowledge, experience, and professional judgment to the specific characteristics
of our cases, employing a litigation management process to manage and monitor the legal proceedings against us.
Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This
process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on
professional judgment and experience in using these litigation management tools and available information about
current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals
and determines if an adjustment of existing accruals, or establishment of new accruals, is required. See Note 17.

Environmental
We 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 or
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.

ConocoPhillips 2021 10-K 58

Capital Resources and Liquidity

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 of
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 to 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 to meet or exceed government requirements.
Our practices continually evolve as technology improves and regulations change.

We 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.

We occasionally receive requests for information or notices of potential liability from the EPA and state
environmental agencies alleging that we are a potentially responsible party under 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, 2021, there were 15 sites around the U.S. in which we were identified as a potentially responsible
party under CERCLA and comparable state laws.

59 ConocoPhillips 2021 10-K

Capital Resources and Liquidity

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 $632 million in 2021 and are expected to be about $642 million and
$700 million in 2022 and 2023, respectively. Capitalized environmental costs were $184 million in 2021 and are
expected to be about $218 million and $316 million in 2022 and 2023, respectively.

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, 2021, our balance sheet included total accrued environmental costs of $187 million, compared
with $180 million at December 31, 2020, for remediation activities in the U.S. and Canada. We expect to incur a
substantial amount of these expenditures within the next 30 years.

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

See Item 1A—Risk Factors – We expect to continue to incur substantial capital expenditures and operating costs as
a result of our compliance with existing and future environmental laws and regulations and Note 11 for information
on environmental litigation.

ConocoPhillips 2021 10-K 60

Capital Resources and Liquidity

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

•

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 2021 was approximately $19
million (net share before-tax).
U.K. Emissions Trading Scheme, the program with which the U.K. has replaced the ETS. Our cost of
compliance with the U.K. ETS in 2021 was approximately $2.8 million (net share before-tax).
The Alberta Technology Innovation and Emissions Reduction (TIER) regulation requires any existing facility
with emissions equal to or greater than 100,000 metric tonnes of carbon dioxide, or equivalent, per year
to meet a facility benchmark intensity. The total cost of these regulations in 2021 was approximately $1
million (net share before-tax).
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 2, 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 U.S. government has announced on September 17, 2021 the Global Methane Pledge, a global
initiative to reduce global methane emissions by at least 30 percent from 2020 levels by 2030.
Carbon taxes in certain jurisdictions. Our cost of compliance with Norwegian carbon legislation in 2021
were fees of approximately $35 million (net share before-tax). We also incur a carbon tax for emissions
from fossil fuel combustion in our British Columbia and Alberta operations in Canada, totaling
approximately $5.7 million (net share before-tax).
The agreement reached in Paris in December 2015 at the 21st Conference of the Parties to the United
Nations Framework Convention on Climate Change, setting out a process for achieving global emission
reductions. The new administration has recommitted the United States to the Paris Agreement, and a
significant number of U.S. state and local governments and major corporations headquartered in the U.S.
have also announced related commitments. Accordingly, the U.S. administration set a new target on
April 22, 2021 of a 50 to 52 percent reduction in GHG emissions from 2005 levels in 2030.

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.

61 ConocoPhillips 2021 10-K

Capital Resources and Liquidity

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.

See Item 1A—Risk Factors – Existing and future laws, regulations and internal initiatives relating to global climate
changes, such as limitations on GHG emissions may impact or limit our business plans, result in significant
expenditures, promote alternative uses of energy or reduce demand for our products and Note 11 for information
on climate change litigation.

Company Response to Climate-Related Risks
The company has responded by putting in place a Sustainable Development Risk Management Standard covering
the assessment and registration 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 three different scopes. Gross operated and net equity Scope 1 and Scope 2 GHG
emissions help us understand our climate transition risk.

•

Scope 1 emissions are direct GHG emissions from sources that we control or in which we have
ownership interest.
Scope 2 emissions are indirect GHG emissions from the generation of purchased electricity or steam that
we consume.
Scope 3 emissions are indirect emissions from sources that we neither own nor control.

ConocoPhillips 2021 10-K 62

Capital Resources and Liquidity

We announced in October 2020 the adoption of a Paris-aligned climate risk framework with the objective of
implementing a coherent set of choices designed to facilitate the success of our existing exploration and
production business through the energy transition. Given the uncertainties remaining about how the energy
transition will evolve, the strategy aims to be robust across a range of potential future outcomes.

The strategy is comprised of four pillars:

•

Targets: Our target framework consists of a hierarchy of targets, from a long-term ambition that sets the
direction and aim of the strategy, to a medium-term performance target for GHG emissions intensity, to
shorter-term targets for flaring and methane intensity reductions. These performance targets are
supported by lower-level internal business unit goals to enable the company to achieve the company-
wide targets. In September 2021, we increased our interim operational target and have set it to reduce
our gross operated and net equity (scope 1 and 2) emissions intensity by 40 to 50 percent from 2016
levels by 2030, an improvement from the previously announced target of 35 to 45 percent on only a gross
operated basis, with an ambition to achieve net-zero operated emissions by 2050. We have joined the
World Bank Flaring Initiative to work towards zero routine flaring of associated gas by 2030, with an
ambition to meet that goal by 2025.
Technology choices: We expanded our Marginal Abatement Cost Curve process to provide a broader
range of opportunities for emission reduction technology.
Portfolio choices: Our corporate authorization process requires all qualifying projects to include a GHG
price in their project approval economics. Different GHG prices are used depending on the region or
jurisdiction. Projects in jurisdictions with existing GHG pricing regimes incorporate the existing GHG price
and forecast into their economics. Projects where no existing GHG pricing regime exists utilize a scenario
forecast from our internally consistent World Energy Model. In this way, 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.
This is in contrast to changes to the cost of existing GHG emission regulations which can impact our
reserves calculations.
External engagement: Our external engagement aims to differentiate ConocoPhillips within the oil and
gas sector with our approach to managing climate-related risk. We are 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.

63 ConocoPhillips 2021 10-K

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 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 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 activity is subject to special accounting rules unique to the oil and gas industry. The
acquisition of G&G 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
At year-end 2021, we held $9.3 billion of net capitalized unproved property costs which consisted primarily of
individually significant and pooled leaseholds, mineral rights held in perpetuity by title ownership, exploratory
wells currently being drilled, and to a lesser extent, suspended exploratory wells and capitalized interest. This
amount increased by $6.9 billion at December 31, 2021 as compared to December 31, 2020, primarily due to the
Concho and Shell Permian acquisitions in the Permian Basin where we have an ongoing significant and active
development program. Outside of the Permian Basin, the remaining $2.0 billion is concentrated in 9 major
development areas. Management periodically assesses our unproved property for impairment based on the
results of exploration and drilling efforts and the outlook for commercialization.

For individually significant leaseholds, management periodically assesses for impairment based on exploration and
drilling efforts to date. For insignificant 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,
including estimates of future expirations, and pools that leasehold information with others in similar geographic
areas. 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.

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.

ConocoPhillips 2021 10-K 64

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 as proved reserves.

At year-end 2021, total suspended well costs were $660 million, compared with $682 million at year-end 2020.
For additional information on suspended wells, including an aging analysis, see Note 6.

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. See Oil and Gas supplemental disclosures for
additional information.

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 reach the end of its economic life is
based on 12-month average prices and current costs. This date estimates when production will end and 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 reserves is also important to the income statement because the proved 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 2021, the net book value of productive PP&E subject to a unit-of-production calculation
was approximately $52 billion and the DD&A recorded on these assets in 2021 was approximately $7.0 billion. The
estimated proved reserves for our consolidated operations were 2.5 billion BOE at the end of 2020 and 4.0 billion
BOE at the end of 2021. 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 2021 would have increased by an estimated
$774 million.

65 ConocoPhillips 2021 10-K

Business Combination—Valuation of Oil and Gas Properties
For recent transactions, management applied the principles of acquisition accounting under FASB ASC Topic 805 –
“Business Combinations” and allocated the purchase price to assets acquired and liabilities assumed, based on
their estimated fair values as of the acquisition date. Estimating the fair values involved making various
assumptions, of which the most significant assumptions relate to the fair values assigned to proved and unproved
oil and gas properties. Management utilized a discounted cash flow approach, based on market participant
assumptions, and engaged third party valuation experts in preparing fair value estimates.

Significant inputs incorporated within the valuation include future commodity price assumptions and production
profiles of reserve estimates, the pace of drilling plans, future operating and development costs, inflation rates,
and discount rates using a market-based weighted average cost of capital determined at the time of the
acquisition. When estimating the fair value of unproved properties, additional risk-weighting adjustments are
applied to probable and possible reserves.

The assumptions and inputs incorporated within the fair value estimates are subject to considerable management
judgement and are based on industry, market, and economic conditions prevalent at the time of the acquisition.
Although we based these estimates on assumptions believed to be reasonable, these estimates are inherently
unpredictable and uncertain and actual results could differ. See Note 3.

Impairments
Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances
indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. If
there is an indication the carrying amount of an asset may not be recovered, a recoverability test is performed
using management’s assumptions for prices, volumes and future development plans. If the sum of the
undiscounted cash flows before income-taxes is less than the carrying value of the asset group, the carrying value
is written down to estimated fair value and reported as an impairment in the periods in which the determination is
made. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable
cash flows that are largely independent of the cash flows of other groups of assets—generally on a field-by-field
basis for E&P assets. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of
impaired assets is typically determined based on the present values of expected future cash flows using discount
rates and prices believed to be consistent with those used by principal market participants, or based on a multiple
of operating cash flow validated with historical market transactions of similar assets where possible.

Investments in nonconsolidated entities accounted for under the equity method are assessed for impairment
whenever changes in the facts and circumstances indicate a loss in value has occurred. 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 such a condition is judgmentally determined to be 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 and prices believed to be consistent
with those used by principal market participants, plus market analysis of comparable assets owned by the
investee, if appropriate. Differing assumptions could affect the timing and the amount of an impairment of an
investment in any period. See the “APLNG” section of Note 4.

ConocoPhillips 2021 10-K 66

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. Fair value is estimated using a
present value approach, incorporating assumptions about estimated amounts and timing of settlements and
impacts of the use of technologies. Estimating future asset removal costs requires significant judgement. 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.
The carrying value of our asset retirement obligation estimate is sensitive to inputs such as 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, which are all subject to change between the time
of initial recognition of the liability and future settlement of our obligation.

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 8.

Projected Benefit Obligations
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. 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. A 100 basis-point decrease
in the discount rate assumption would increase projected benefit obligations by $1.0 billion. Benefit expense is
sensitive to the discount rate and return on plan assets assumptions. A 100 basis-point decrease in the discount
rate assumption would increase annual benefit expense by $70 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. We 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 of 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 16.

67 ConocoPhillips 2021 10-K

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 11.

Income Taxes
We are subject to income taxation in numerous jurisdictions worldwide. We record deferred tax assets and
liabilities to account for the expected future tax consequences of events that have been recognized in our financial
statements and our tax returns. We routinely assess our deferred tax assets and reduce such assets by a valuation
allowance if we deem it is more likely than not that some portion, or all, of the deferred tax assets will not be
realized. In assessing the need for adjustments to existing valuation allowances, we consider all available positive
and negative evidence. Positive evidence includes reversals of temporary differences, forecasts of future taxable
income, assessment of future business assumptions and applicable tax planning strategies that are prudent and
feasible. Negative evidence includes losses in recent years as well as the forecasts of future net income (loss) in
the realizable period. In making our assessment regarding valuation allowances, we weight the evidence based on
objectivity. Numerous judgments and assumptions are inherent in the determination of future taxable income,
including factors such as future operating conditions and the assessment of the effects of foreign taxes on our U.S.
federal income taxes (particularly as related to prevailing oil and gas prices). See Note 17.

We regularly assess and, if required, establish accruals for uncertain tax positions that could result from
assessments of additional tax by taxing jurisdictions in countries where we operate. We recognize a tax benefit
from an uncertain tax position when it is more likely than not that the position will be sustained upon examination,
based on the technical merits of the position. These accruals for uncertain tax positions are subject to a significant
amount of judgment and are reviewed and adjusted on a periodic basis in light of changing facts and
circumstances considering the progress of ongoing tax audits, court proceedings, changes in applicable tax laws,
including tax case rulings and legislative guidance, or expiration of the applicable statute of limitations. See Note
17 regarding discussion of critical accounting estimates on deferred tax valuation allowances.

ConocoPhillips 2021 10-K 68

Cautionary Statement for the Purposes of the “Safe Harbor” Provisions of the
Private Securities Litigation Reform Act of 1995

This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933
and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact
included or incorporated by reference in this report, including, without limitation, statements regarding our future
financial position, business strategy, budgets, projected revenues, projected costs and plans, objectives of
management for future operations and the anticipated impact of the Shell Enterprise LLC (Shell) transaction on the
company’s business and future financial and operating results 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,” “believe,”
“budget,” “continue,” “could,” “effort,” “estimate,” “expect,” “forecast,” “intend,” “goal,” “guidance,” “may,”
“objective,” “outlook,” “plan,” “potential,” “predict,” “projection,” “seek,” “should,” “target,” “will,” “would” and
similar expressions.

We based the forward-looking statements on our current expectations, estimates and projections about ourselves
and the industries in which we operate in general. We caution you these statements are not guarantees of future
performance as they involve assumptions that, while made in good faith, may prove to be incorrect, and involve
risks and uncertainties we cannot predict. In addition, we based many of these 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 and uncertainties, including, but not limited to, the following:

•

•
•

•

The impact of public health crises, including pandemics (such as COVID-19) and epidemics and any related
company or government policies or actions.
Global and regional changes in the demand, supply, prices, differentials or other market conditions
affecting oil and gas, including changes resulting from a public health crisis or from the imposition or
lifting of crude oil production quotas or other actions that might be imposed by OPEC and other producing
countries and the resulting company or third-party actions in response to such changes.
Fluctuations in crude oil, bitumen, natural gas, LNG and NGLs prices, including a prolonged decline in
these prices relative to historical or future expected levels.
The impact of significant declines in prices for crude oil, bitumen, natural gas, LNG and NGLs, which may
result in recognition of impairment charges on our long-lived assets, leaseholds and nonconsolidated
equity investments.
The potential for insufficient liquidity or other factors, such as those described herein, that could impact
our ability to repurchase shares and declare and pay dividends, whether fixed or variable.
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.

ConocoPhillips 2021 10-K

•

•
•

•

•
•

Failure to complete definitive agreements and feasibility studies for, and to complete construction of,
announced and future E&P and LNG development in a timely manner (if at all) or on budget.
Potential disruption or interruption of our operations due to accidents, extraordinary weather events,
supply chain disruptions, civil unrest, political events, war, terrorism, cyber attacks, and information
technology failures, constraints or disruptions.
Changes in international monetary conditions and foreign currency exchange rate fluctuations.
Changes in international trade relationships, including the imposition of trade restrictions or tariffs
relating to crude oil, bitumen, natural gas, LNG, NGLs and any materials or products (such as aluminum
and steel) used in the operation of our business.
Substantial investment in and development use of, competing or alternative energy sources, including as
a result of existing or future environmental rules and regulations.
Liability for remedial actions, including removal and reclamation obligations, under existing and future
environmental regulations and litigation.
Significant operational or investment changes imposed by existing or future environmental statutes and
regulations, including international agreements and national or regional legislation and regulatory
measures to limit or reduce GHG emissions.
Liability resulting from litigation, including litigation directly or indirectly related to the transaction with
Concho Resources Inc., or our failure to comply with applicable laws and regulations.
General domestic and international economic and political developments, including armed hostilities;
expropriation of assets; changes in governmental policies relating to crude oil, bitumen, natural gas, LNG
and NGLs pricing; regulation or taxation; and other political, economic or diplomatic developments.
Volatility in the commodity futures markets.
Changes in tax and other laws, regulations (including alternative energy mandates), or royalty rules
applicable to our business.
Competition and consolidation in the oil and gas E&P industry.
Any limitations on our access to capital or increase in our cost of capital, including as a result of illiquidity
or uncertainty in domestic or international financial markets or investment sentiment.

• Our inability to execute, or delays in the completion, of any asset dispositions or acquisitions we elect to

•

pursue.
Potential failure to obtain, or delays in obtaining, any necessary regulatory approvals for pending or
future asset dispositions or acquisitions, or that such approvals may require modification to the terms of
the transactions or the operation of our remaining business.
Potential disruption of our operations as a result of pending or future asset dispositions or acquisitions,
including the diversion of management time and attention.

• Our inability to deploy the net proceeds from any asset dispositions that are pending or that we elect to

•
•

undertake in the future in the manner and timeframe we currently anticipate, if at all.
The operation and financing of our joint ventures.
The ability of our customers and other contractual counterparties to satisfy their obligations to us,
including our ability to collect payments when due from the government of Venezuela or PDVSA.

• Our inability to realize anticipated cost savings and capital expenditure reductions.
•

The inadequacy of storage capacity for our products, and ensuing curtailments, whether voluntary or
involuntary, required to mitigate this physical constraint.
The risk that we will be unable to retain and hire key personnel.
Unanticipated integration issues relating to the acquisition of assets from Shell, such as potential
disruptions of our ongoing business and higher than anticipated integration costs.
Uncertainty as to the long-term value of our common stock.
The diversion of management time on integration-related matters.
The factors generally described in Item 1A—Risk Factors in this 2021 Annual Report on Form 10-K and any
additional risks described in our other filings with the SEC.

•
•

•
•
•

ConocoPhillips 2021 10-K 70

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

Financial Instrument Market Risk
We and certain of our subsidiaries hold and issue derivative contracts and financial instruments that expose our
cash flows or earnings to changes in commodity prices, foreign currency exchange rates or interest rates. We may
use financial and commodity-based derivative contracts to manage the risks produced by changes in the prices of
natural gas, crude oil and related products; fluctuations in interest rates and foreign currency exchange rates; or to
capture market opportunities.

Our use of derivative instruments is governed by an “Authority Limitations” document approved by our Board of
Directors that prohibits the use of highly leveraged derivatives or derivative instruments without sufficient
liquidity. The Authority Limitations document also establishes the Value at Risk (VaR) limits for the company, and
compliance with these limits is monitored daily. The Executive Vice President and Chief Financial Officer, who
reports to the Chief Executive Officer, monitors commodity price risk and risks resulting from foreign currency
exchange rates and interest rates. The Commercial organization manages our commercial marketing, optimizes
our commodity flows and positions, and monitors risks.

Commodity Price Risk
Our Commercial organization uses futures, forwards, swaps and options in various markets to accomplish the
following objectives:

• Meet customer needs. Consistent with our policy to generally remain exposed to market prices, we use

•

swap contracts to convert fixed-price sales contracts, which are often requested by natural gas
consumers, to floating market prices.
Enable us to use market knowledge to capture opportunities such as moving physical commodities to
more profitable locations and storing commodities to capture seasonal or time premiums. We may use
derivatives to optimize these activities.

We use a VaR model to estimate the loss in fair value that could potentially result on a single day from the effect of
adverse changes in market conditions on the derivative financial instruments and derivative commodity
instruments we hold or issue, including commodity purchases and sales contracts recorded on the balance sheet at
December 31, 2021, as derivative instruments. Using Monte Carlo simulation, a 95 percent confidence level and a
one-day holding period, the VaR for those instruments issued or held for trading purposes or held for purposes
other than trading at December 31, 2021 and 2020, was immaterial to our consolidated cash flows and net income
attributable to ConocoPhillips.

Interest Rate Risk
The following table provides information about our debt instruments that are sensitive to changes in U.S. interest
rates. The table presents principal cash flows and related weighted-average interest rates by expected maturity
dates. Weighted-average variable rates are based on effective rates at the reporting date. The carrying amount of
our floating-rate debt approximates its fair value. A hypothetical 10 percent change in prevailing interest rates
would not have a material impact on interest expense associated with our floating-rate debt. The fair value of the
fixed-rate debt is measured using prices available from a pricing service that is corroborated by market data.
Changes to prevailing interest rates would not impact our cash flows associated with fixed rate debt, unless we
elect to repurchase or retire such debt prior to maturity.

71 ConocoPhillips 2021 10-K

Expected Maturity Date
Year-End 2021
2022
2023
2024
2025
2026
Remaining years
Total
Fair value

Year-End 2020
2021
2022
2023
2024
2025
Remaining years
Total
Fair value

Millions of Dollars Except as Indicated
Debt

Fixed
Rate
Maturity

Average
Interest
Rate

Floating
Rate
Maturity

Average
Interest
Rate

$
$

346
116
459
369
1,355
14,338
16,983
21,668

133
346
110
459
368
11,793
13,209
18,023

2.53 % $
6.64
3.51
5.32
5.06
5.80

$
$

8.47 % $
2.53
7.03
3.51
5.33
6.28

$
$

500
-
-
-
-
283
783
783

300
500
-
-
-
283
1,083
1,083

1.03 %
-
-
-
-
0.11

0.22 %
1.12
-
-
-
0.11

Foreign Currency Exchange Risk
We have foreign currency exchange rate risk resulting from international operations. We do not comprehensively
hedge the exposure to currency exchange rate changes although we may choose to selectively hedge certain
foreign currency exchange rate exposures, such as firm commitments for capital projects or local currency tax
payments, dividends and cash returns from net investments in foreign affiliates to be remitted within the coming
year, and investments in equity securities.

At December 31, 2021 and 2020, we held foreign currency exchange forwards hedging cross-border commercial
activity and foreign currency exchange swaps for purposes of mitigating our cash-related exposures. Although
these forwards and swaps hedge exposures to fluctuations in exchange rates, we elected not to utilize hedge
accounting. As a result, the change in the fair value of these foreign currency exchange derivatives is recorded
directly in earnings.

At December 31, 2021, we had outstanding foreign currency exchange forward contracts to buy $1.9 billion AUD at
$0.715 AUD against the U.S. dollar. At December 31, 2020, we had outstanding foreign currency exchange forward
contracts to sell $0.45 billion CAD at $0.748 CAD against the U.S. dollar. Based on the assumed volatility in the fair
value calculation, the net fair value of these foreign currency contracts at December 31, 2021 and December 31,
2020, were a before-tax gain of $21 million and before-tax loss of $16 million, respectively. Based on an adverse
hypothetical 10 percent change in the December 2021 and December 2020 exchange rate, this would result in an
additional before-tax loss of $134 million and $39 million, respectively. The sensitivity analysis is based on
changing one assumption while holding all other assumptions constant, which in practice may be unlikely to occur,
as changes in some of the assumptions may be correlated.

ConocoPhillips 2021 10-K 72

The gross notional and fair value of these positions at December 31, 2021 and 2020, were as follows:

Foreign Currency Exchange Derivatives

In Millions

Sell Canadian dollar, buy U.S. dollar
Buy Canadian dollar, sell U.S. dollar
Buy Australian dollar, sell U.S. dollar
Sell British pound, buy euro
Buy British pound, sell euro
*Denominated in USD.

Notional
2021

-
77
1,850
239
394

2020

450
80
-
8
3

CAD
CAD
AUD
GBP
GBP

Fair Value*
2021

-
(1)
21
(8)
7

2020

(16)
2
-
-
-

For additional information about our use of derivative instruments, see Note 12.

73 ConocoPhillips 2021 10-K

Item 8. Financial Statements and Supplementary Data

ConocoPhillips

Index to Financial Statements

Reports of Management

Reports of Independent Registered Public Accounting Firm (PCAOB ID #42)

Consolidated Income Statement for the years ended December 31, 2021, 2020 and 2019

Consolidated Statement of Comprehensive Income for the years ended

December 31, 2021, 2020 and 2019

Consolidated Balance Sheet at December 31, 2021 and 2020

Consolidated Statement of Cash Flows for the years ended December 31, 2021, 2020 and 2019

Consolidated Statement of Changes in Equity for the years ended

December 31, 2021, 2020 and 2019

Notes to Consolidated Financial Statements

Supplementary Information

Oil and Gas Operations

Page
75

149

ConocoPhillips 2021 10-K 74

Reports of Management

Management prepared, and is responsible for, the consolidated financial statements and the other information
appearing in this annual report. The consolidated financial statements present fairly the company’s financial
position, results of operations and cash flows in conformity with accounting principles generally accepted in the
United States. In preparing its consolidated financial statements, the company includes amounts that are based on
estimates and judgments management believes are reasonable under the circumstances. The company’s financial
statements have been audited by Ernst & Young LLP, an independent registered public accounting firm appointed
by the Audit and Finance Committee of the Board of Directors and ratified by stockholders. Management has
made available to Ernst & Young LLP all of the company’s financial records and related data, as well as the minutes
of stockholders’ and directors’ meetings.

Assessment of Internal Control Over Financial Reporting
Management is also responsible for establishing and maintaining adequate internal control over financial
reporting. ConocoPhillips’ internal control system was designed to provide reasonable assurance to the company’s
management and directors regarding the preparation and fair presentation of published financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those
systems determined to be effective can provide only reasonable assurance with respect to financial statement
preparation and presentation.

Management assessed the effectiveness of the company’s internal control over financial reporting as of
December 31, 2021. 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, 2021. Management’s assessment of, and conclusion on, the effectiveness of internal control over
financial reporting did not include the internal controls of the assets acquired from Shell Enterprise LLC in
December 2021. The total assets acquired represented approximately 10 percent of the company’s consolidated
total assets at December 31, 2021.

Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of
December 31, 2021, and their report is included herein.

/s/ Ryan M. Lance

Ryan M. Lance
Chairman and
Chief Executive Officer

/s/ William L. Bullock, Jr.

William L. Bullock, Jr.
Executive Vice President and
Chief Financial Officer

75 ConocoPhillips 2021 10-K

Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of ConocoPhillips

Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of ConocoPhillips (the Company) as of December
31, 2021 and 2020, 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, 2021, and
the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the
consolidated financial statements present fairly, in all material respects, the financial position of the Company as
of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in
the period ended December 31, 2021, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2021, 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 17, 2022, expressed
an unqualified opinion thereon.

Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an
opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered
with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S.
federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the
PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial statements are free of material
misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of
material misstatement of the financial statements, whether due to error or fraud, and performing procedures that
respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and
disclosures in the financial statements. Our audits also included evaluating the accounting principles used and
significant estimates made by management, as well as evaluating the overall presentation of the financial
statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the
consolidated financial statements that were communicated or required to be communicated to the Audit and
Finance Committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial
statements and (2) involved our especially challenging, subjective or complex judgments. The communication of
critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a
whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the
critical audit matters or on the accounts or disclosures to which they relate.

ConocoPhillips 2021 10-K 76

Description of
the Matter

Accounting for asset retirement obligations for certain offshore properties

At December 31, 2021, the asset retirement obligation (ARO) balance totaled $5.9 billion. As
further described in Note 8, 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 and higher estimation uncertainty related to plugging and abandonment of wells
and removal and disposal of offshore oil and gas platforms, facilities and pipelines costs
(collectively, removal costs). Furthermore, given certain of these assets are nearing the end
of their operations, the impact of changes in these AROs may result in a material impact to
earnings given the relatively short remaining useful lives of the assets.

Auditing the Company’s AROs for the obligations identified above is complex and highly
judgmental due to the significant estimation required by management in determining the
obligations. In particular, the estimates were sensitive to significant subjective assumptions
such as removal cost estimates and end of field life, which are affected by expectations
about future market or economic conditions.

How We
Addressed the
Matter in Our
Audit

We obtained an understanding, evaluated the design and tested the operating effectiveness
of the Company’s internal controls over its ARO estimation process, including management’s
review of the significant assumptions that have a material effect on the determination of the
obligations. We also tested management’s controls over the completeness and accuracy of
the financial data used in the valuation.

Description of
the Matter

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.

Depreciation, depletion and amortization of proved oil and gas properties, plants and
equipment

At December 31, 2021, the net book value of the Company’s proved oil and gas properties,
plants and equipment (PP&E) was $52 billion, and depreciation, depletion and amortization
(DD&A) expense was $7.0 billion for the year then ended. As described in Note 1, under the
successful efforts method of accounting, DD&A of PP&E on producing hydrocarbon
properties and steam-assisted gravity drainage facilities and certain pipeline and liquified
natural gas assets (those which are expected to have a declining utilization pattern) are
determined by the unit-of-production method. The unit-of-production method uses proved
oil and gas reserves, as estimated by the Company’s internal reservoir engineers.

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
proved oil and gas 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 proved oil and gas reserves,
management also used an independent petroleum engineering consulting firm to perform a
review of the processes and controls used by the Company’s internal reservoir engineers to
determine estimates of proved oil and gas reserves.

77 ConocoPhillips 2021 10-K

Auditing the Company’s DD&A calculation is complex because of the use of the work of the
internal reservoir engineers and the independent petroleum engineering consulting firm and
the evaluation of management’s determination of the inputs described above used by the
internal reservoir engineers in estimating proved oil and gas reserves.

How We
Addressed the
Matter in Our
Audit

We obtained an understanding, evaluated the design and tested the operating effectiveness
of the Company’s internal controls over its processes 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.

Description of
the Matter

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 proved oil and gas reserve estimates and the independent
petroleum engineering consulting firm used to review the Company’s processes and
controls. In addition, in assessing whether we can use the work of the internal reservoir
engineers, we evaluated the completeness and accuracy of the financial data and inputs
described above used by the internal reservoir engineers in estimating proved oil and gas
reserves by agreeing them to source documentation and we identified and evaluated
corroborative and contrary evidence. We also tested the accuracy of the DD&A calculation,
including comparing the proved oil and gas reserve amounts used in the calculation to the
Company’s reserve report.

Valuation and recognition of proved and unproved oil & gas properties acquired in
business combinations

During 2021, the Company closed its acquisition of Concho Resources Inc. and its acquisition
of Permian assets from Shell Enterprises LLC resulting in the recognition of proved and
unproved oil and gas properties within net properties, plants and equipment of $18.9 billion
and $8.6 billion, respectively. As described in Note 3, the transactions were accounted for as
business combinations under FASB ASC 805 using the acquisition method, which requires
assets acquired and liabilities assumed to be measured at their acquisition date fair values.
Oil and gas properties were valued using a discounted cash flow approach based on market
participant assumptions and third party valuation experts were engaged by the Company to
prepare fair value estimates. Significant inputs to the valuation of proved and unproved oil
and gas properties include estimates of future commodity price assumptions and production
profiles of reserve estimates, the pace of drilling plans, future operating costs and discount
rates using a market-based weighted average cost of capital.

Auditing the Company's accounting for its valuation of proved and unproved oil and gas
properties is complex and considerably judgmental due to the significant estimation
required by management of reserves and resources associated with the acquired assets and
the sensitivity of significant assumptions used in determining the fair value. In evaluating
the reasonableness of management’s estimates and assumptions used, the audit testing
procedures performed required a high degree of auditor judgment and additional effort,
including involving internal specialists.

How We
Addressed the
Matter in Our
Audit

We obtained an understanding, evaluated the design and tested the operating effectiveness
of the Company’s internal controls over its process to estimate the fair value of the acquired
proved and unproved oil and gas properties, including management’s review of the
significant assumptions used as inputs to the fair value calculations and final recording of
the analysis.

ConocoPhillips 2021 10-K 78

To test the estimated fair value of the acquired proved and unproved oil and gas properties,
our audit procedures included, among others, evaluating the significant assumptions used
and testing the completeness and accuracy of the underlying data supporting the significant
assumptions. For example, we compared certain significant assumptions to current industry,
third-party data and historical results for reasonableness. We also performed sensitivity
analyses of significant assumptions, to evaluate the extent of their impact to the fair value
calculation. In addition, we involved our valuation specialists to assist with certain significant
assumptions included in the fair value estimate. Furthermore, we evaluated the professional
qualifications and objectivity of the third party valuation specialist engaged by the Company
to prepare the fair value of the acquired proved and unproved oil and gas properties.

/s/ Ernst & Young LLP

We have served as ConocoPhillips’ auditor since 1949.

Houston, Texas
February 17, 2022

79 ConocoPhillips 2021 10-K

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, 2021, 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, 2021, based on the COSO criteria. As indicated under the heading “Assessment of Internal Control
Over Financial Reporting” in the accompanying Reports of Management, management’s assessment of and
conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of
the assets acquired from Shell Enterprise LLC, which is included in the 2021 consolidated financial statements of
ConocoPhillips and constituted approximately 10 percent of consolidated total assets as of December 31, 2021.
Our audit of internal control over financial reporting of ConocoPhillips also did not include an evaluation of the
internal control over financial reporting of the assets acquired from Shell Enterprise LLC.

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, 2021 and 2020, 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, 2021, and the related notes and our
report dated February 17, 2022, expressed an unqualified opinion thereon.

Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and
for its assessment of the effectiveness of internal control over financial reporting included under the heading
“Assessment of Internal Control Over Financial Reporting” in the accompanying “Reports of Management.” Our
responsibility is to express an opinion on the Company’s internal control over financial reporting based on our
audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect
to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the
Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting
was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a
material weakness exists, testing and evaluating the design and operating effectiveness of internal control based
on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We
believe that our audit provides a reasonable basis for our opinion.

ConocoPhillips 2021 10-K 80

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 17, 2022

81 ConocoPhillips 2021 10-K

Financial Statements

Consolidated Income Statement

Years Ended December 31

Revenues and Other Income
Sales and other operating revenues
Equity in earnings of affiliates
Gain on dispositions
Other income (loss)

Total Revenues and Other Income

Costs and Expenses
Purchased commodities
Production and operating expenses
Selling, general and administrative expenses
Exploration expenses
Depreciation, depletion and amortization
Impairments
Taxes other than income taxes
Accretion on discounted liabilities
Interest and debt expense
Foreign currency transaction (gains) losses
Other expenses

Total Costs and Expenses
Income (loss) before income taxes
Income tax provision (benefit)
Net income (loss)
Less: net income attributable to noncontrolling interests
Net Income (Loss) Attributable to ConocoPhillips

Net Income (Loss) Attributable to ConocoPhillips Per Share

of Common Stock (dollars)

Basic
Diluted

Average Common Shares Outstanding (in thousands)
Basic
Diluted
See Notes to Consolidated Financial Statements.

ConocoPhillips

Millions of Dollars

2021

2020

2019

45,828
832
486
1,203
48,349

18,158
5,694
719
344
7,208
674
1,634
242
884
(22)
102
35,637
12,712
4,633
8,079
-
8,079

18,784
432
549
(509)
19,256

8,078
4,344
430
1,457
5,521
813
754
252
806
(72)
13
22,396
(3,140)
(485)
(2,655)
(46)
(2,701)

32,567
779
1,966
1,358
36,670

11,842
5,322
556
743
6,090
405
953
326
778
66
65
27,146
9,524
2,267
7,257
(68)
7,189

6.09
6.07

(2.51)
(2.51)

6.43
6.40

1,324,194
1,328,151

1,078,030
1,078,030

1,117,260
1,123,536

ConocoPhillips 2021 10-K 82

Financial Statements

Consolidated Statement of Comprehensive Income

ConocoPhillips

Years Ended December 31

Net Income (Loss)
Other comprehensive income (loss)

Defined benefit plans

Prior service credit arising during the period
Reclassification adjustment for amortization of prior

service credit included in net income (loss)

Net change

Net actuarial gain (loss) arising during the period
Reclassification adjustment for amortization of net

actuarial losses included in net income (loss)

Net change
Nonsponsored plans*
Income taxes on defined benefit plans

Defined benefit plans, net of tax

Unrealized holding gain (loss) on securities
Reclassification adjustment for loss included in net income
Income taxes on unrealized holding loss on securities

Unrealized holding gain (loss) on securities, net of tax

Foreign currency translation adjustments
Income taxes on foreign currency translation adjustments
Foreign currency translation adjustments, net of tax

Millions of Dollars

2021
8,079

2020
(2,655)

2019
7,257

(38)
(38)
357

178
535
5
(108)
394
(2)
(1)
1
(2)
(124)
-
(124)
268
8,347
-
8,347

(32)
(3)
(210)

117
(93)
1
20
(75)
2
-
-
2
209
3
212
139
(2,516)
(46)
(2,562)

(35)
(35)
(55)

146
91
(3)
(2)
51
-
-
-
-
699
(4)
695
746
8,003
(68)
7,935

Other Comprehensive Income, Net of Tax
Comprehensive Income (Loss)
Less: comprehensive income attributable to noncontrolling interests
Comprehensive Income (Loss) Attributable to ConocoPhillips
*Plans for which ConocoPhillips is not the primary obligor—primarily those administered by equity affiliates.
See Notes to Consolidated Financial Statements.

83 ConocoPhillips 2021 10-K

Financial Statements

Consolidated Balance Sheet

At December 31

Assets
Cash and cash equivalents
Short-term investments
Accounts and notes receivable (net of allowance of $2 and $4, respectively)
Accounts and notes receivable—related parties
Investment in Cenovus Energy
Inventories
Prepaid expenses and other current assets

Total Current Assets

Investments and long-term receivables
Loans and advances—related parties
Net properties, plants and equipment

(net of accumulated DD&A of $64,735 and $62,213, respectively)

Other assets
Total Assets

Liabilities
Accounts payable
Accounts payable—related parties
Short-term debt
Accrued income and other taxes
Employee benefit obligations
Other accruals

Total Current Liabilities

Long-term debt
Asset retirement obligations and accrued environmental costs
Deferred income taxes
Employee benefit obligations
Other liabilities and deferred credits
Total Liabilities

Equity
Common stock (2,500,000,000 shares authorized at $0.01 par value)

Issued (2021—2,091,562,747 shares; 2020—1,798,844,267 shares)

Par value
Capital in excess of par

Treasury stock (at cost: 2021—789,319,875 shares; 2020—730,802,089 shares)

Accumulated other comprehensive loss
Retained earnings
Total Equity
Total Liabilities and Equity
See Notes to Consolidated Financial Statements.

ConocoPhillips

Millions of Dollars

2021

2020

5,028
446
6,543
127
1,117
1,208
1,581
16,050
7,113
-

64,911
2,587
90,661

5,002
23
1,200
2,862
755
2,179
12,021
18,734
5,754
6,179
1,153
1,414
45,255

2,991
3,609
2,634
120
1,256
1,002
454
12,066
8,017
114

39,893
2,528
62,618

2,669
29
619
320
608
1,121
5,366
14,750
5,430
3,747
1,697
1,779
32,769

21
60,581
(50,920)
(4,950)
40,674
45,406
90,661

18
47,133
(47,297)
(5,218)
35,213
29,849
62,618

ConocoPhillips 2021 10-K 84

Financial Statements

Consolidated Statement of Cash Flows

ConocoPhillips

Years Ended December 31

Cash Flows From Operating Activities
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by

Millions of Dollars

2021

2020

2019

8,079

(2,655)

7,257

operating activities

Depreciation, depletion and amortization
Impairments
Dry hole costs and leasehold impairments
Accretion on discounted liabilities
Deferred taxes
Undistributed equity earnings
Gain on dispositions
(Gain) loss on CVE common shares
Other
Working capital adjustments

Decrease (increase) in accounts and notes receivable
Increase in inventories
Decrease (increase) in prepaid expenses and other current
assets
Increase (decrease) in accounts payable
Increase (decrease) in taxes and other accruals

Net Cash Provided by Operating Activities

Cash Flows From Investing Activities
Capital expenditures and investments
Working capital changes associated with investing activities
Acquisition of businesses, net of cash acquired
Proceeds from asset dispositions
Net sales (purchases) of investments
Collection of advances/loans—related parties
Other
Net Cash Used in Investing Activities

Cash Flows From Financing Activities
Issuance of debt
Repayment of debt
Issuance of company common stock
Repurchase of company common stock
Dividends paid
Other
Net Cash Used in Financing Activities

7,208
674
44
242
1,346
446
(486)
(1,040)
(788)

(2,500)
(160)

(649)
1,399
3,181
16,996

(5,324)
134
(8,290)
1,653
3,091
105
87
(8,544)

-
(505)
145
(3,623)
(2,359)
7
(6,335)

5,521
813
1,083
252
(834)
645
(549)
855
43

521
(25)

76
(249)
(695)
4,802

(4,715)
(155)
-
1,317
(658)
116
(26)
(4,121)

300
(254)
(5)
(892)
(1,831)
(26)
(2,708)

6,090
405
421
326
(444)
594
(1,966)
(649)
(351)

505
(67)

37
(378)
(676)
11,104

(6,636)
(103)
-
3,012
(2,910)
127
(108)
(6,618)

-
(80)
(30)
(3,500)
(1,500)
(119)
(5,229)

Effect of Exchange Rate Changes on Cash, Cash Equivalents and

Restricted Cash

(34)

(20)

Net Change in Cash, Cash Equivalents and Restricted Cash
Cash, cash equivalents and restricted cash at beginning of period
Cash, Cash Equivalents and Restricted Cash at End of Period
Restricted cash of $152 million and $218 million is included in the “Prepaid expenses and other current assets” and “Other assets” lines,
respectively, of our Consolidated Balance Sheet as of December 31, 2021.
Restricted cash of $94 million and $230 million is included in the “Prepaid expenses and other current assets” and “Other assets” lines,
respectively, of our Consolidated Balance Sheet as of December 31, 2020.
See Notes to Consolidated Financial Statements.

(2,047)
5,362
3,315

2,083
3,315
5,398

(46)

(789)
6,151
5,362

85 ConocoPhillips 2021 10-K

Financial Statements

Consolidated Statement of Changes in Equity

ConocoPhillips

Millions of Dollars

Attributable to ConocoPhillips

Common Stock

Capital in
Excess of
Par

Par
Value

Treasury
Stock

Accum. Other
Comprehensive
Income (Loss)

Retained
Earnings

Non-
Controlling
Interests

Balances at December 31, 2018
Net income
Other comprehensive loss
Dividends declared—ordinary ($1.34 per share of common stock)
Repurchase of company common stock
Distributions to noncontrolling interests and other
Distributed under benefit plans
Changes in Accounting Principles*
Other
Balances at December 31, 2019
Net income (loss)
Other comprehensive income
Dividends declared—ordinary ($1.69 per share of common stock)
Repurchase of company common stock
Distributions to noncontrolling interests and other
Disposition
Distributed under benefit plans
Other
Balances at December 31, 2020
Net income
Other comprehensive income
Dividends declared

Ordinary ($1.75 per share of common stock)
Variable return of cash ($0.20 per share of common stock)

46,879

(42,905)

(6,063)

(3,500)

104

746

(40)

46,983

(46,405)

(5,357)

139

(892)

150

47,133

(47,297)

(5,218)

268

34,010
7,189

(1,500)

40
3
39,742
(2,701)

(1,831)

3
35,213
8,079

(2,359)
(260)

Acquisition of Concho
Repurchase of company common stock
Distributed under benefit plans
Other
Balances at December 31, 2021
*Cumulative effect of the adoption of ASU No. 2018-02, "Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income."
See Notes to Consolidated Financial Statements.

1
40,674

(50,920)

(3,623)

(4,950)

60,581

13,122

326

125
68

(128)

4
69
46

(32)
(84)

1
-
-

-
-

Total

32,064
7,257
746
(1,500)
(3,500)
(128)
104
-
7
35,050
(2,655)
139
(1,831)
(892)
(32)
(84)
150
4
29,849
8,079
268

(2,359)
(260)
13,125
(3,623)
326
1
45,406

ConocoPhillips 2021 10-K 86

Notes to Consolidated Financial Statements

Note 1—Accounting Policies

•

Consolidation Principles and Investments—Our consolidated financial statements include the accounts of
majority-owned, controlled subsidiaries and, if applicable, variable interest entities where we are the
primary beneficiary. The equity method is used to account for investments in affiliates in which we have
the ability to exert significant influence over the affiliates’ operating and financial policies. When we do
not have the ability to exert significant influence, the investment is measured at fair value except when
the investment does not have a readily determinable fair value. For those exceptions, it will be measured
at cost minus impairment, plus or minus observable price changes in orderly transactions for an identical
or similar investment of the same issuer. Undivided interests in oil and gas joint ventures, pipelines,
natural gas plants and terminals are consolidated on a proportionate basis. Other securities and
investments are generally carried at cost. We manage our operations through six operating segments,
defined by geographic region: Alaska; Lower 48; Canada; Europe, Middle East and North Africa; Asia
Pacific; and Other International. See Note 23.

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 U.S. GAAP requires
management to make estimates and assumptions that affect the reported amounts of assets, liabilities,
revenues and expenses and the disclosures of contingent assets and liabilities. Actual results could differ
from these estimates.

Revenue Recognition—Revenues associated with the sales of crude oil, bitumen, natural gas, LNG, NGLs
and other items are recognized at the point in time when the customer obtains control of the asset. In
evaluating when a customer has control of the asset, we primarily consider whether the transfer of legal
title and physical delivery has occurred, whether the customer has significant risks and rewards of
ownership and whether the customer has accepted delivery and a right to payment exists. These
products are typically sold at prevailing market prices. We allocate variable market-based consideration
to deliveries (performance obligations) in the current period as that consideration relates specifically to
our efforts to transfer control of current period deliveries to the customer and represents the amount we
expect to be entitled to in exchange for the related products. Payment is typically due within 30 days or
less.

Revenues associated with transactions commonly called buy/sell contracts, in which the purchase and
sale of inventory with the same counterparty are entered into “in contemplation” of one another, are
combined and reported net (i.e., on the same income statement line).

Shipping and Handling Costs—We typically incur shipping and handling costs prior to control transferring
to the customer and account for these activities as fulfillment costs. Accordingly, we include shipping and
handling costs in production and operating expenses for production activities. Transportation costs
related to marketing activities are recorded in purchased commodities. Freight costs billed to customers
are treated as a component of the transaction price and recorded as a component of revenue when the
customer obtains control.

Cash Equivalents—Cash equivalents are highly liquid, short-term investments that are readily convertible
to known amounts of cash and have original maturities of 90 days or less from their date of purchase.
They are carried at cost plus accrued interest, which approximates fair value.

87 ConocoPhillips 2021 10-K

Notes to Consolidated Financial Statements

•

Short-Term Investments—Short-term investments include investments in bank time deposits and
marketable securities (commercial paper and government obligations) which are carried at cost plus
accrued interest and have original maturities of greater than 90 days but within one year or when the
remaining maturities are within one year. We also invest in financial instruments classified as available
for sale debt securities which are carried at fair value. Those instruments are included in short-term
investments when they have remaining maturities within one year as of the balance sheet date.

Long-Term Investments in Debt Securities—Long-term investments in debt securities includes financial
instruments classified as available for sale debt securities with remaining maturities greater than one year
as of the balance sheet date. They are carried at fair value and presented within the “Investments and
long-term receivables” line of our consolidated balance sheet.

Inventories—We have several valuation methods for our various types of inventories and consistently use
the following methods for each type of inventory. The majority of our commodity-related inventories are
recorded at cost using the LIFO basis. We measure these inventories at the lower-of-cost-or-market in
the aggregate. Any necessary lower-of-cost-or-market write-downs at year end are recorded as
permanent adjustments to the LIFO cost basis. LIFO is used to better match current inventory costs with
current revenues. Costs include both direct and indirect expenditures incurred in bringing an item or
product to its existing condition and location, but not unusual/nonrecurring costs or research and
development costs. Materials, supplies and other miscellaneous inventories, such as tubular goods and
well equipment, are valued using various methods, including the weighted-average-cost method and the
FIFO method, consistent with industry practice.

Fair Value Measurements—Assets and liabilities measured at fair value and required to be categorized
within the fair value hierarchy are categorized into one of three different levels depending on the
observability of the inputs employed in the measurement. Level 1 inputs are quoted prices in active
markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices
included within Level 1 for the asset or liability, either directly or indirectly through market-corroborated
inputs. Level 3 inputs are unobservable inputs for the asset or liability reflecting significant modifications
to observable related market data or our assumptions about pricing by market participants.

Derivative Instruments—Derivative instruments are recorded on the balance sheet at fair value. If the
right of offset exists and certain other criteria are met, derivative assets and liabilities with the same
counterparty are netted on the balance sheet and the collateral payable or receivable is netted against
derivative assets and derivative liabilities, respectively.

Recognition and classification of the gain or loss that results from recording and adjusting a derivative to
fair value depends on the purpose for issuing or holding the derivative. Gains and losses from derivatives
not accounted for as hedges are recognized immediately in earnings. We do not apply hedge accounting
to our derivative instruments.

• Oil and Gas Exploration and Development—Oil and gas exploration and development costs are

accounted for using the successful efforts method of accounting.

Property Acquisition Costs—Oil and gas leasehold acquisition costs are capitalized and included in
the balance sheet caption PP&E. Leasehold impairment is recognized based on exploratory
experience and management’s judgment. Upon achievement of all conditions necessary for reserves
to be classified as proved, the associated leasehold costs are reclassified to proved properties.

Exploratory Costs—Geological and geophysical costs and the costs of carrying and retaining
undeveloped properties are expensed as incurred. Exploratory well costs are capitalized, or
“suspended,” on the balance sheet pending further evaluation of whether economically recoverable
reserves have been found. If economically recoverable reserves are not found, exploratory well costs
are expensed as dry holes. If exploratory wells encounter potentially economic quantities of oil and

ConocoPhillips 2021 10-K 88

Notes to Consolidated Financial Statements

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 6.

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 development
costs is based on the unit-of-production method using estimated proved developed oil and gas
reserves.

•

Capitalized Interest—Interest from external borrowings is capitalized on major projects with an expected
construction period of one year or longer. Capitalized interest is added to the cost of the underlying asset
and is amortized over the useful lives of the assets in the same manner as the underlying assets.

Depreciation and Amortization—Depreciation and amortization of PP&E on producing hydrocarbon
properties and SAGD facilities and certain pipeline and LNG assets (those which are expected to have a
declining utilization pattern), are determined by the unit-of-production method. Depreciation and
amortization of all other PP&E are determined by either the individual-unit-straight-line method or the
group-straight-line method (for those individual units that are highly integrated with other units).

Impairment of Properties, Plants and Equipment—Long-lived assets used in operations are assessed for
impairment whenever changes in facts and circumstances indicate a possible significant deterioration in
the future cash flows expected to be generated by an asset group. If there is an indication the carrying
amount of an asset may not be recovered, a recoverability test is performed using management’s
assumptions for prices, volumes and future development plans. If the sum of the undiscounted cash
flows before income-taxes is less than the carrying value of the asset group, the carrying value is written
down to estimated fair value and reported as an impairment in the period in which the determination is
made. Individual assets are grouped for impairment purposes at the lowest level for which there are
identifiable cash flows that are largely independent of the cash flows of other groups of assets—generally
on a field-by-field basis for E&P assets. Because there usually is a lack of quoted market prices for long-
lived assets, the fair value of impaired assets is typically determined based on the present values of
expected future cash flows using discount rates and prices believed to be consistent with those used by
principal market participants, or based on a multiple of operating cash flow validated with historical
market transactions of similar assets where possible.

The expected future cash flows used for impairment reviews and related fair value calculations are based
on estimated future production volumes, commodity prices, operating costs and capital decisions,
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.

89 ConocoPhillips 2021 10-K

Notes to Consolidated Financial Statements

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.

• 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 partial units of depreciable property are disposed of or
retired which do not significantly alter the DD&A rate, the difference between asset cost and salvage
value is charged or credited to accumulated depreciation.

Asset Retirement Obligations and Environmental Costs—The fair value of legal obligations to retire and
remove long-lived assets are recorded in the period in which the obligation is incurred (typically when the
asset is installed at the production location). Fair value is estimated using a present value approach,
incorporating assumptions about estimated amounts and timing of settlements and impacts of the use of
technologies. See Note 8.

Environmental expenditures are expensed or capitalized, depending upon their future economic benefit.
Expenditures relating to an existing condition caused by past operations, and those having no future
economic benefit, are expensed. Liabilities for environmental expenditures are recorded on an
undiscounted basis (unless acquired through a business combination, which we record on a discounted
basis) when environmental assessments or cleanups are probable and the costs can be reasonably
estimated. Recoveries of environmental remediation costs from other parties are recorded as assets
when their receipt is probable and estimable.

Impairment of Investments in Nonconsolidated Entities—Investments in nonconsolidated entities are
assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has
occurred. When such a condition is judgmentally determined to be other than temporary, the carrying
value of the investment is written down to fair value. The fair value of the impaired investment is based
on quoted market prices, if available, or upon the present value of expected future cash flows using
discount rates and prices believed to be consistent with those used by principal market participants, plus
market analysis of comparable assets owned by the investee, if appropriate.

Guarantees—The fair value of a guarantee is determined and recorded as a liability at the time the
guarantee is given. The initial liability is subsequently reduced as we are released from exposure under
the guarantee. We amortize the guarantee liability over the relevant time period, if one exists, based on
the facts and circumstances surrounding each type of guarantee. In cases where the guarantee term is
indefinite, we reverse the liability when we have information indicating the liability is essentially relieved
or amortize it over an appropriate time period as the fair value of our guarantee exposure declines over
time. We amortize the guarantee liability to the related income statement line item based on the nature
of the guarantee. When it becomes probable that we will have to perform on a guarantee, we accrue a
separate liability if it is reasonably estimable, based on the facts and circumstances at that time. We
reverse the fair value liability only when there is no further exposure under the guarantee.

Share-Based Compensation—We recognize share-based compensation expense over the shorter of the
service period (i.e., the stated period of time required to earn the award) or the period beginning at the
start of the service period and ending when an employee first becomes eligible for retirement. We have
elected to recognize expense on a straight-line basis over the service period for the entire award, whether
the award was granted with ratable or cliff vesting.

ConocoPhillips 2021 10-K 90

Notes to Consolidated Financial Statements

•

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—Inventories
Inventories at December 31 were:

Crude oil and natural gas
Materials and supplies
Total inventories

Inventories valued on the LIFO basis

Millions of Dollars

2021

2020

647
561
1,208

395

461
541
1,002

282

The estimated excess of current replacement cost over LIFO cost of inventories was approximately $251 million
and $87 million at December 31, 2021 and 2020, respectively.

Note 3—Asset Acquisitions and Dispositions
All gains or losses on asset dispositions are reported before-tax and are included net in the “Gain on dispositions”
line on our consolidated income statement. All cash proceeds and payments are included in the “Cash Flows From
Investing Activities” section of our consolidated statement of cash flows.

During the year, we completed the acquisitions of Concho Resources Inc. (Concho) and of Shell Enterprises LLC’s
(Shell) Permian assets. The acquisitions were accounted for as business combinations under FASB Topic ASC 805
using the acquisition method, which requires assets acquired and liabilities assumed to be measured at their
acquisition date fair values. Fair value measurements were made for acquired assets and liabilities, and
adjustments to those measurements may be made in subsequent periods, up to one year from the acquisition date
as we identify new information about facts and circumstances that existed as of the acquisition date to consider.

91 ConocoPhillips 2021 10-K

Notes to Consolidated Financial Statements

2021
Acquisition of Concho Resources Inc.
In January 2021, we completed our acquisition of Concho, an independent oil and gas exploration and production
company with operations across New Mexico and West Texas focused in the Permian Basin. Total consideration
for the all-stock transaction was valued at $13.1 billion, in which 1.46 shares of ConocoPhillips common stock were
exchanged for each outstanding share of Concho common stock.

Total Consideration
Number of shares of Concho common stock issued and outstanding (in thousands)*
Number of shares of Concho stock awards outstanding (in thousands)*

Number of shares exchanged

Exchange ratio
Additional shares of ConocoPhillips common stock issued as consideration (in thousands)
Average price per share of ConocoPhillips common stock**
Total Consideration (Millions)
*Outstanding as of January 15, 2021.
**Based on the ConocoPhillips average stock price on January 15, 2021.

$
$

194,243
1,599
195,842
1.46
285,929
45.9025
13,125

Oil and gas properties were valued using a discounted cash flow approach incorporating market participant and
internally generated price assumptions; production profiles; and operating and development cost assumptions.
Debt assumed in the acquisition was valued based on observable market prices. The fair values determined for
accounts receivable, accounts payable, and most other current assets and current liabilities were equivalent to the
carrying value due to their short-term nature. The total consideration of $13.1 billion was allocated to the
identifiable assets and liabilities based on their fair values as of January 15, 2021.

Assets Acquired

Cash and cash equivalents
Accounts receivable, net
Inventories
Prepaid expenses and other current assets
Investments and long-term receivables
Net properties, plants and equipment
Other assets

Total assets acquired

Liabilities Assumed
Accounts payable
Accrued income and other taxes
Employee benefit obligations
Other accruals
Long-term debt
Asset retirement obligations and accrued environmental costs
Deferred income taxes
Other liabilities and deferred credits

Total liabilities assumed
Net assets acquired

Millions of Dollars

382
745
45
37
333
18,923
62
20,527

638
56
4
510
4,696
310
1,071
117
7,402
13,125

$
$

ConocoPhillips 2021 10-K 92

Notes to Consolidated Financial Statements

With the completion of the Concho transaction, we acquired proved and unproved properties of approximately
$11.8 billion and $6.9 billion, respectively.

We recognized approximately $157 million of transaction-related costs, all of which were expensed in the first
quarter of 2021. These non-recurring costs related primarily to fees paid to advisors and the settlement of share-
based awards for certain Concho employees based on the terms of the Merger Agreement.

In the first quarter of 2021, we commenced a company-wide restructuring program, the scope of which included
combining the operations of the two companies as well as other global restructuring activities. We recognized
non-recurring restructuring costs mainly for employee severance and related incremental pension benefit costs.

The impact from these transaction and restructuring costs to the lines of our consolidated income statement for
the year ended December 31, 2021, are below:

Production and operating expenses
Selling, general and administration expenses
Exploration expenses
Taxes other than income taxes
Other expenses

Transaction Cost

135
18
4
-
157

Millions of Dollars

Restructuring Cost
128
67
8
2
29
234

Total Cost
128
202
26
6
29
391

On February 8, 2021, we completed a debt exchange offer related to the debt assumed from Concho. As a result
of the debt exchange, we recognized an additional income tax related restructuring charge of $75 million. See
Note 17.

From the acquisition date through December 31, 2021, “Total Revenues and Other Income” and “Net Income
(Loss) Attributable to ConocoPhillips” associated with the acquired Concho business were approximately $6,571
million and $2,330 million, respectively. The results associated with the Concho business for the same period
include a before- and after-tax loss of $305 million and $233 million, respectively, on the acquired derivative
contracts. The before-tax loss is recorded within “Total Revenues and Other Income” on our consolidated income
statement. See Note 12.

Acquisition of Shell Permian Assets
In December 2021, we completed our acquisition of Shell assets in the Permian based Delaware Basin. The
accounting close date used for reporting purposes was December 31, 2021. Assets acquired include approximately
225,000 net acres and producing properties located entirely in Texas. Total consideration for the transaction was
$8.7 billion.

Oil and gas properties were valued using a discounted cash flow approach incorporating market participant and
internally generated price assumptions, production profiles, and operating and development cost assumptions.
The fair values determined for accounts receivable, accounts payable, and most other current assets and current
liabilities were equivalent to the carrying value due to their short-term nature. The total consideration of $8.7
billion was allocated to the identifiable assets and liabilities based on their fair values at the acquisition date.

ConocoPhillips 2021 10-K

Notes to Consolidated Financial Statements

Assets Acquired

Accounts receivable, net
Inventories
Net properties, plants and equipment
Other assets

Total assets acquired

Liabilities Assumed
Accounts payable
Accrued income and other taxes
Other accruals
Asset retirement obligations and accrued environmental costs
Other liabilities and deferred credits

Total liabilities assumed
Net assets acquired

Millions of Dollars

337
20
8,624
50
9,031

211
6
20
86
36
359
8,672

$
$

With the completion of the Shell Permian transaction, we acquired proved and unproved properties of
approximately $4.2 billion and $4.4 billion, respectively. We recognized approximately $44 million of transaction-
related costs which were expensed during 2021.

Supplemental Pro Forma (unaudited)
The following tables summarize the unaudited supplemental pro forma financial information for the year ended
December 31, 2021, and 2020, as if we had completed the acquisitions of Concho and the Shell Permian assets on
January 1, 2020.

Total Revenues and Other Income
Income (loss) before income taxes
Net Income (Loss) attributable to ConocoPhillips

Earnings per share:
Basic net loss
Diluted net loss

Total Revenues and Other Income
Income (loss) before income taxes
Net Income (Loss) attributable to ConocoPhillips

Earnings per share:
Basic net loss
Diluted net loss

Millions of Dollars
Year Ended December 31, 2021
Pro forma
Shell
3,220
1,201
920

As reported
48,349
12,712
8,079

6.09
6.07

Millions of Dollars
Year Ended December 31, 2020
Pro forma
Shell
1,685
(247)
(189)

Pro forma
Concho
3,762
787
498

As reported
19,256
(3,140)
(2,701)

(2.51)
(2.51)

Pro forma
Combined
51,569
13,913
8,999

6.78
6.76

Pro forma
Combined
24,703
(2,600)
(2,392)

(1.75)
(1.75)

ConocoPhillips 2021 10-K 94

Notes to Consolidated Financial Statements

The unaudited supplemental pro forma financial information is presented for illustration purposes only and is not
necessarily indicative of the operating results that would have occurred had the transactions been completed on
January 1, 2020, nor is it necessarily indicative of future operating results of the combined entity. The unaudited
pro forma financial information for the twelve-month period ending December 31, 2020 is a result of combining
the consolidated income statement of ConocoPhillips with the results of Concho and the assets acquired from
Shell. The pro forma results do not include transaction-related costs, nor any cost savings anticipated as a result of
the transactions. The pro forma results include adjustments from Concho’s historical results to reverse
impairment expense of $10.5 billion and $1.9 billion related to oil and gas properties and goodwill, respectively.
Other adjustments made relate primarily to DD&A, which is based on the unit-of-production method, resulting
from the purchase price allocated to properties, plants and equipment. We believe the estimates and assumptions
are reasonable, and the relative effects of the transaction are properly reflected.

Announced Acquisitions
In December 2021, we announced that we have notified Origin Energy that we are exercising our preemption right
to purchase an additional 10 percent shareholding interest in APLNG from Origin Energy for $1.645 billion, which
will be funded from cash on the balance sheet, before customary adjustments. The effective date of the
transaction will be July 1, 2020 with closing anticipated to occur in the first quarter of 2022 subject to Australian
government approval. See Note 4 and Note 7.

Assets Sold
In 2020, we completed the sale of our Australia-West asset and operations. The sales agreement entitled us to a
$200 million payment upon a final investment decision (FID) of the Barossa development project. On March 30,
2021, FID was announced and as such, we recognized a $200 million gain on disposition in the first quarter of 2021.
The purchaser failed to pay the FID bonus when due. We have commenced an arbitration proceeding against the
purchaser to enforce our contractual right to the $200 million, plus interest accruing from the due date. Results of
operations related to this transaction are reflected in our Asia Pacific segment. See Note 11.

In the second half of 2021, we sold our interests in certain noncore assets in our Lower 48 segment for
approximately $250 million after customary adjustments, recognizing a before-tax gain on sale of approximately
$58 million. We also completed the sale of our noncore exploration interests in Argentina, recognizing a before-
tax loss on disposition of $179 million. Results of operations for Argentina were reported in our Other
International segment.

In 2021, we recorded contingent payments of $369 million relating to previous dispositions. The contingent
payments are recorded as gain on disposition on our consolidated income statement and are reflected within our
Canada and Lower 48 segments. In our Canada segment, 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. The term for contingent payments in our Canada segment ends on May 16, 2022. In our Lower 48
segment, the contingent payment, paid on an annual basis, is calculated monthly at $7 million per month in which
the U.S. Henry Hub price is at or above $3.20 per MMBTU. The term for contingent payments in our Lower 48
segment goes through 2023. No contingent payments were recorded in 2020.

Planned Dispositions
In December 2021, we entered into an agreement to sell two subsidiaries holding our Indonesia assets and
operations to MedcoEnergi for $1.355 billion, before customary adjustments, with an effective date of January 1,
2021. The subsidiaries hold our 54 percent interest in the Indonesia Corridor Block Production Sharing Contract
(PSC) and a 35 percent shareholding interest in the Transasia Pipeline Company. The net carrying value is
approximately $0.4 billion, which consists primarily of PP&E. The assets met the held for sale criteria in the fourth
quarter, and as of December 31, 2021, we have reclassified $0.3 billion of PP&E to “Prepaid expenses and other
current assets” and $0.1 billion of noncurrent ARO to “Other accruals” on our consolidated balance sheet. The
before-tax earnings associated with our Indonesia subsidiaries were $604 million, $394 million and $512 million for
the years ended December 31, 2021, 2020 and 2019, respectively. This transaction is expected to close in early
2022, 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.

95 ConocoPhillips 2021 10-K

Notes to Consolidated Financial Statements

In January 2022, we entered into an agreement to sell our interests in certain noncore assets in the Lower 48
segment for $440 million, before customary adjustments. This transaction is expected to close in the second
quarter of 2022.

2020
Asset Acquisition
In August 2020, we completed the acquisition of additional Montney acreage in Canada from Kelt Exploration Ltd.
for $382 million after customary adjustments, plus the assumption of $31 million in financing obligations
associated with partially owned infrastructure. This acquisition consisted primarily of undeveloped properties and
included 140,000 net acres in the liquids-rich Inga Fireweed asset Montney zone, which is directly adjacent to our
existing Montney position. The transaction increased our Montney acreage position to approximately 295,000 net
acres with a 100 percent working interest. This agreement was accounted for as an asset acquisition resulting in
the recognition of $490 million of PP&E; $77 million of ARO and accrued environmental costs; and $31 million of
financing obligations recorded primarily to long-term debt. Results of operations for the Montney asset are
reported in our Canada segment.

Assets Sold
In February 2020, we sold our Waddell Ranch interests in the Permian Basin for $184 million after customary
adjustments. No gain or loss was recognized on the sale. Results of operations for the Waddell Ranch interests
sold were reported in our Lower 48 segment.

In March 2020, we completed the sale of our Niobrara interests for approximately $359 million after customary
adjustments and recognized a before-tax loss on disposition of $38 million. At the time of disposition, our interest
in Niobrara had a net carrying value of $397 million, consisting primarily of $433 million of PP&E and $34 million of
ARO. The before-tax losses associated with our interests in Niobrara, including the loss on disposition noted above
and an impairment of $386 million recorded when we signed an agreement to sell our interests in the fourth
quarter of 2019, were $25 million and $372 million for the years ended December 31, 2020 and 2019, respectively.
Results of operations for the Niobrara interests sold were reported in our Lower 48 segment.

In May 2020, we completed the divestiture of our subsidiaries that held our Australia-West assets and operations,
and based on an effective date of January 1, 2019, we received proceeds of $765 million. We recognized a before-
tax gain of $587 million related to this transaction in 2020. At the time of disposition, the net carrying value of the
subsidiaries sold was approximately $0.2 billion, excluding $0.5 billion of cash. The net carrying value consisted
primarily of $1.3 billion of PP&E and $0.1 billion of other current assets offset by $0.7 billion of ARO, $0.3 billion of
deferred tax liabilities, and $0.2 billion of other liabilities. The before-tax earnings associated with the subsidiaries
sold, including the gain on disposition noted above, were $851 million and $372 million for the years ended
December 31, 2020 and 2019, respectively. Production from the beginning of the year through the disposition
date in May 2020 averaged 43 MBOED. The sales agreement entitled us to an additional $200 million upon FID of
the Barossa development project. Results of operations for the subsidiaries sold were reported in our Asia Pacific
segment.

2019
Assets Sold
In January 2019, we entered into agreements to sell our 12.4 percent ownership interests in the Golden Pass LNG
Terminal and Golden Pass Pipeline. We also entered into agreements to amend our contractual obligations for
retaining use of the facilities. As a result of entering into these agreements, we recorded a before-tax impairment
of $60 million in the first quarter of 2019 which is included in the “Equity in earnings of affiliates” line on our
consolidated income statement. We completed the sale in the second quarter of 2019. Results of operations for
these assets were reported in our Lower 48 segment.

ConocoPhillips 2021 10-K 96

Notes to Consolidated Financial Statements

In April 2019, we entered into an agreement to sell two ConocoPhillips U.K. subsidiaries to Chrysaor E&P Limited
for $2.675 billion plus interest and customary adjustments, with an effective date of January 1, 2018. On
September 30, 2019, we completed the sale for proceeds of $2.2 billion and recognized a $1.7 billion before-tax
and $2.1 billion after-tax gain associated with this transaction in 2019. Together the subsidiaries sold indirectly
held our exploration and production assets in the U.K. At the time of disposition, the net carrying value was
approximately $0.5 billion, consisting primarily of $1.6 billion of PP&E, $0.5 billion of cumulative foreign currency
translation adjustments, and $0.3 billion of deferred tax assets, offset by $1.8 billion of ARO and negative $0.1
billion of working capital. The before-tax earnings associated with the subsidiaries sold, including the gain on
dispositions noted above, was $2.1 billion for the year ended December 31, 2019. Results of operations for the
U.K. were reported within our Europe, Middle East and North Africa segment.

In the second quarter of 2019, we recognized an after-tax gain of $52 million upon the closing of the sale of our 30
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 $16
million and recognized a before-tax gain of $82 million. At the time of sale, the net carrying value consisted of $4
million of PP&E offset by $70 million of ARO. The Magnolia results of operations were reported within our Lower
48 segment.

Note 4—Investments, Loans and Long-Term Receivables
Components of investments, loans and long-term receivables at December 31 were:

Equity investments
Loans and advances—related parties
Long-term receivables
Long-term investments in debt securities
Other investments

Millions of Dollars

2021
6,701
-
98
248
66
7,113

2020
7,596
114
137
217
67
8,131

Equity Investments
Affiliated companies in which we had a significant equity investment at December 31, 2021, included:

•

APLNG—37.5 percent owned joint venture with Origin Energy (37.5 percent) and Sinopec (25 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
QatarEnergy (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

2021
11,824
3,946
2,557

2020
7,931
1,843
1,426

2019
11,310
3,726
3,085

Revenues
Income before income taxes
Net income

97 ConocoPhillips 2021 10-K

Notes to Consolidated Financial Statements

Summarized 100 percent balance sheet information for equity method investments in affiliated companies,
combined, was as follows:

Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities

Millions of Dollars

2021
4,493
36,602
3,498
17,465

2020
2,579
35,257
2,110
18,099

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, 2021, retained earnings included $42 million related to the undistributed earnings of affiliated
companies. Dividends received from affiliates were $1,279 million, $1,076 million and $1,378 million in 2021, 2020
and 2019, respectively.

APLNG
APLNG is a joint venture focused on producing CBM from the Bowen and Surat basins in Queensland, Australia.
Natural gas is sold to domestic customers and LNG is processed and exported to Asia Pacific markets. Our
investment in APLNG gives us access to CBM resources in Australia and enhances our LNG position. The majority
of APLNG LNG is sold under two long-term sales and purchase agreements, supplemented with sales of additional
LNG spot cargoes targeting the Asia Pacific markets. Origin Energy, an integrated Australian energy company, is
the operator of APLNG’s production and pipeline system, while we operate the LNG facility.

APLNG executed project financing agreements for an $8.5 billion project finance facility in 2012. All amounts were
drawn from the facility. APLNG achieved financial completion on its original $8.5 billion project finance facility
during the third quarter of 2017, resulting in the facility being nonrecourse. The project financing facility has been
refinanced over time and at December 31, 2021, this facility was composed of a financing agreement with the
Export-Import Bank of the United States, a commercial bank facility and two United States Private Placement note
facilities. APLNG made its first principal and interest repayment in March 2017 and is scheduled to make bi-annual
payments until September 2030. At December 31, 2021, a balance of $5.7 billion was outstanding on the facilities.
See Note 10.

During the fourth quarter of 2021, Origin Energy Limited agreed to the sale of 10 percent of their interest in APLNG
for $1.645 billion, before customary adjustments. ConocoPhillips announced in December 2021 that we were
exercising our preemption right under the APLNG Shareholders Agreement to purchase an additional 10 percent
shareholding interest in APLNG, subject to government approvals. The sales price associated with this preemption
right was determined to reflect a relevant observable market participant view of APLNG’s fair value which was
below the carrying value of our existing investment in APLNG. Based on a review of the facts and circumstances
surrounding this decline in fair value, we concluded in the fourth quarter of 2021 the impairment was other than
temporary under the guidance of FASB ASC Topic 323, and the recognition of an impairment of our existing
investment was necessary. Accordingly, we recorded a noncash $688 million, before-tax and after-tax impairment
in the fourth quarter of 2021. The impairment, which is included in the “Impairments” line on our consolidated
income statement, had the effect of reducing the carrying value of our existing investment to $5,574 million as of
December 31, 2021. This carrying value is included in the “Investments and long-term receivables” line on our
consolidated balance sheet. See Note 7.

ConocoPhillips 2021 10-K

Notes to Consolidated Financial Statements

The historical cost basis of our 37.5 percent share of net assets on the books of APLNG was $5,523 million,
resulting in a basis difference of $51 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
production license areas owned by APLNG. Any future additional payments are expected to be allocated in a
similar manner. 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 2021, 2020 and 2019 was after-tax expense of $39 million, $41 million and $36 million,
respectively, representing the amortization of this basis difference on currently producing licenses.

QG3
QG3 is a joint venture that owns an integrated large-scale LNG project located in Qatar. We provided project
financing, with a current outstanding balance of $114 million as described below under “Loans.” At December 31,
2021, the book value of our equity method investment in QG3, excluding the project financing, was $736 million.
We have terminal and pipeline use agreements with Golden Pass LNG Terminal and affiliated Golden Pass Pipeline
near Sabine Pass, Texas, intended to provide us with terminal and pipeline capacity for the receipt, storage and
regasification of LNG purchased from QG3. We previously held a 12.4 percent interest in Golden Pass LNG
Terminal and Golden Pass Pipeline, but we sold those interests in the second quarter of 2019 while retaining the
basic use agreements. Currently, the LNG from QG3 is being sold to markets outside of the U.S. See Note 3.

Loans
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 to certain
affiliated and non-affiliated companies.

At December 31, 2021, significant loans to affiliated companies include $114 million in project financing to QG3
which is recorded within the “Accounts and notes receivable—related parties” line on our consolidated balance
sheet. 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.

Note 5—Investment in Cenovus Energy
Our investment in Cenovus Energy (CVE) common shares is carried on our balance sheet at fair value.

Number of shares of CVE common stock (millions)
Ownership of issued and outstanding common stock
Closing price on NYSE on last trading day ($/share)
Fair Value (millions of dollars)

December 31

2021
91
4.5 %

$
$

12.28
1,117

2020
208
16.9
6.04
1,256

During 2021, we began to dispose of CVE shares, selling 117 million shares during the year, recognizing proceeds of
$1.18 billion, $1.14 billion of which was received during the year. Proceeds related to the sale of our CVE shares
are presented within “Cash Flows from Investing Activities” on our consolidated statement of cash flows. Subject
to market conditions, we intend to continue to decrease our investment.

All gains and losses are recognized within “Other income (loss)” on our consolidated income statement. See Note
13.

99 ConocoPhillips 2021 10-K

Notes to Consolidated Financial Statements

Total Net gain (loss) on equity securities
Less: Net gain (loss) on equity securities sold during the period
Unrealized gain (loss) on equity securities still held at
the reporting date

Millions of Dollars

2021
1,040
473

2020
(855)

2019
649

567

(855)

649

Note 6—Suspended Wells and Exploration Expenses
The following table reflects the net changes in suspended exploratory well costs during 2021, 2020 and 2019:

Millions of Dollars

2021

2020

2019

Beginning balance at January 1
Additions pending the determination of proved reserves
Reclassifications to proved properties
Sales of suspended wells
Charged to dry hole expense
Ending balance at December 31
*Includes $313 million of assets held for sale in Australia-West at December 31, 2019.
For additional details on suspended wells charged to dry hole expense, see the Exploration Expenses section of this Note.

682
10
-
-
(32)
660

1,020
164
(42)
(313)
(147)
682

856
239
(11)
(54)
(10)
1,020 *

The following table provides an aging of suspended well balances at December 31:

Millions of Dollars

2021

2020

2019

Exploratory well costs capitalized for a period of one year or less
Exploratory well costs capitalized for a period greater than one year
Ending balance

4
656
660

156
526
682

206
814
1,020 *

*Includes $313 million of assets held for sale in Australia-West at December 31, 2019.

Number of projects with exploratory well costs capitalized for a period
greater than one year

ConocoPhillips 2021 10-K 100

Notes to Consolidated Financial Statements

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, 2021:

Willow—Alaska(1)
Surmont—Canada(1)
PL 1009—Norway(1)
PL 891—Norway(1)
Narwhal Trend—Alaska(1)
WL4-00—Malaysia(1)
PL782S—Norway(1)
NC 98—Libya(2)
Other of $10 million or less each(1)(2)
Total
(1)Additional appraisal wells planned.
(2)Appraisal drilling complete; costs being incurred to assess development.

Millions of Dollars

2018-2020
262
2
43
34
25
24
22
-
21
433

Suspended Since
2015-2017
51
19
-
-
-
-
-
-
11
81

2004-2014
-
100
-
-
-
-
-
13
29
142

Total
313
121
43
34
25
24
22
13
61
656

Exploration Expenses
The charges discussed below are included in the “Exploration expenses” line on our consolidated income
statement.

2020
In our Alaska segment, we recorded a before-tax impairment of $828 million for the entire associated carrying
value of capitalized undeveloped leasehold costs related to our Alaska North Slope Gas asset. We no longer
believe the project will advance, and there is no current market for the asset.

In our Other International segment, our interests in the Middle Magdalena Basin of Colombia are in force majeure.
As we had no immediate plans to perform under existing contracts; therefore, in 2020, we recorded a before-tax
expense totaling $84 million for dry hole costs of a previously suspended well and an impairment of the associated
capitalized undeveloped leasehold carrying value.

In our Asia Pacific segment, we recorded before-tax expense of $50 million related to dry hole costs of a previously
suspended well and an impairment of the associated capitalized undeveloped leasehold carrying value associated
with the Kamunsu East Field in Malaysia that is no longer in our development plans.

2019
In our Lower 48 segment, we recorded a before-tax impairment of $141 million for the associated carrying value of
capitalized undeveloped leasehold costs and dry hole expenses of $111 million before-tax due to our decision to
discontinue exploration activities related to our Central Louisiana Austin Chalk acreage.

101 ConocoPhillips 2021 10-K

Notes to Consolidated Financial Statements

Note 7—Impairments
During 2021, 2020 and 2019, we recognized the following before-tax impairment charges:

Alaska

Lower 48

Canada

Europe, Middle East and North Africa

Asia Pacific

Millions of Dollars
2020

2021

(8)

(24)

695
674

804

-
813

2019

402

-
405

2021
We recorded an impairment of $688 million on our APLNG investment included within the Asia Pacific segment.
See Note 4 and Note 13.

In our Lower 48 segment, we recorded a credit to impairment of $89 million due to a decreased ARO estimate for a
previously sold asset, in which we retained the ARO liability. This was offset by recorded impairments of $84
million during the fourth quarter of 2021, related to certain noncore assets due to changes in development plans.
See Note 13.

In our Europe, Middle East and North Africa segment, we recorded a credit to impairment of $24 million due to
decreased ARO estimates on fields in Norway which ceased production and were fully depreciated in prior years.

2020
We recorded impairments of $813 million, primarily related to certain noncore assets in the Lower 48. Due to a
significant decrease in the outlook for current and long-term natural gas prices in early 2020, we recorded
impairments of $523 million, primarily for the Wind River Basin operations area, consisting of developed
properties in the Madden Field and the Lost Cabin Gas Plant, in the first quarter of 2020. Additionally, due
primarily to changes in development plans solidified in the last quarter of 2020, we recognized additional
impairments of $287 million in the Lower 48 during the fourth quarter. See Note 13.

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 3.

Note 8—Asset Retirement Obligations and Accrued Environmental Costs
Asset retirement obligations and accrued environmental costs at December 31 were:

Asset retirement obligations
Accrued environmental costs
Total asset retirement obligations and accrued environmental costs
Asset retirement obligations and accrued environmental costs due within one year*
Long-term asset retirement obligations and accrued environmental costs
*Classified as a current liability on the balance sheet under “Other accruals.”

Millions of Dollars

2021

2020

5,926
187
6,113
(359)
5,754

5,573
180
5,753
(323)
5,430

ConocoPhillips 2021 10-K 102

Notes to Consolidated Financial Statements

Asset Retirement Obligations
We record the fair value of a liability for an ARO when it is incurred (typically when the asset is installed at the
production location). When the liability is initially recorded, we capitalize the associated asset retirement cost by
increasing the carrying amount of the related PP&E. If, in subsequent periods, our estimate of this liability
changes, we will record an adjustment to both the liability and PP&E. Over time, the liability increases for the
change in its present value, while the capitalized cost depreciates over the useful life of the related asset.
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.

We have numerous AROs we are required to perform under law or contract once an asset is permanently taken
out of service. Most of these obligations are not expected to be paid until several years, or decades, in the future
and will be funded from general company resources at the time of removal. Our largest individual obligations
involve plugging and abandonment of wells and removal and disposal of offshore oil and gas platforms around the
world, as well as oil and gas production facilities and pipelines in Alaska.

During 2021 and 2020, our overall ARO changed as follows:

Balance at January 1
Accretion of discount
New obligations
Changes in estimates of existing obligations
Spending on existing obligations
Property dispositions
Foreign currency translation
Balance at December 31

Millions of Dollars

2021

2020

5,573
238
555
(113)
(164)
(108)
(55)
5,926

6,206
248
262
(307)
(116)
(771)
51
5,573

Accrued Environmental Costs
Total accrued environmental costs at December 31, 2021 and 2020, were $187 million and $180 million,
respectively.

We had accrued environmental costs of $135 million and $116 million at December 31, 2021 and 2020,
respectively, related to remediation activities in the U.S. and Canada. We had also accrued in Corporate and Other
$36 million and $48 million of environmental costs associated with sites no longer in operation at December 31,
2021 and 2020, respectively. In addition, both December 31, 2021 and 2020, included a $16 million accrual, 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 30 years.

Expected expenditures for environmental obligations acquired in various business combinations are discounted
using a weighted-average 5 percent discount factor, resulting in an accrued balance for acquired environmental
liabilities of $109 million at December 31, 2021. The total expected future undiscounted payments related to the
portion of the accrued environmental costs that have been discounted are $153 million.

103 ConocoPhillips 2021 10-K

Notes to Consolidated Financial Statements

Note 9—Debt
Long-term debt at December 31 was:

9.125% Debentures due 2021
2.4% Notes due 2022
7.65% Debentures due 2023
3.35% Notes due 2024
8.2% Debentures due 2025
3.35% Notes due 2025
6.875% Debentures due 2026
4.95% Notes due 2026
7.8% Debentures due 2027
3.75% Notes due 2027
3.75% Notes due 2027
4.3% Notes due 2028
4.3% Notes due 2028
7.375% Debentures due 2029
7% Debentures due 2029
6.95% Notes due 2029
8.125% Notes due 2030
2.4% Notes due 2031
2.4% Notes due 2031
7.2% Notes due 2031
7.25% Notes due 2031
7.4% Notes due 2031
5.9% Notes due 2032
4.15% Notes due 2034
5.95% Notes due 2036
5.951% Notes due 2037
5.9% Notes due 2038
6.5% Notes due 2039
4.3% Notes due 2044
5.95% Notes due 2046
7.9% Debentures due 2047
4.875% Notes due 2047
4.85% Notes due 2048
4.85% Notes due 2048
Floating rate notes due 2022 at 1.02% – 1.12% during 2021 and

1.12% – 2.81% during 2020

Marine Terminal Revenue Refunding Bonds due 2031 at 0.04% – 0.15% during

2021 and 0.1% – 7.5% during 2020

Industrial Development Bonds due 2035 at 0.04% – 0.12% during 2021 and

0.11% – 7.5% during 2020

Commercial Paper at 0.05% – 0.22% during 2021
Other
Debt at face value
Finance leases
Net unamortized premiums, discounts and debt issuance costs
Total debt
Short-term debt
Long-term debt

Millions of Dollars

2021
-
329
78
426
134
199
67
1,250
203
981
19
973
27
92
200
1,549
390
489
11
575
500
500
505
246
500
645
600
2,750
750
500
60
800
590
10

500

265

18
-
35
17,766
1,261
907
19,934
(1,200)
18,734

2020
123
329
78
426
134
199
67
1,250
203
-
-
-
-
92
200
1,549
390
-
-
575
500
500
505
246
500
645
600
2,750
750
500
60
-
-
-

500

265

18
300
38
14,292
891
186
15,369
(619)
14,750

ConocoPhillips 2021 10-K 104

Notes to Consolidated Financial Statements

On January 15, 2021, we completed the acquisition of Concho in an all-stock transaction. In the acquisition, we
assumed Concho’s publicly traded debt, with an outstanding principal balance of $3.9 billion, which was recorded
at fair value of $4.7 billion on the acquisition date. The adjustment to fair value of the senior notes of
approximately $0.8 billion on the acquisition date will be amortized as an adjustment to interest expense over the
remaining contractual terms of the senior notes.

In the first quarter of 2021, we completed a debt exchange offer related to the debt assumed from Concho. Of the
approximately $3.9 billion in aggregate principal amount of Concho’s senior notes offered in the exchange, 98
percent, or approximately $3.8 billion, was tendered and accepted. The new debt issued by ConocoPhillips had
the same interest rates and maturity dates as the Concho senior notes. The portion not exchanged, approximately
$67 million, remained outstanding across five series of senior notes issued by Concho. The debt exchange was
treated as a debt modification for accounting purposes resulting in a portion of the unamortized fair value
adjustment of the Concho senior notes allocated to the new debt issued by ConocoPhillips on the settlement date
of the exchange. The new debt issued in the exchange is fully and unconditionally guaranteed by ConocoPhillips
Company. See Note 3.

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

Credit facility borrowings may bear interest at a margin above rates offered by certain designated banks in the
London interbank market or at a margin above the overnight federal funds rate or prime rates offered by certain
designated banks in the U.S. The facility agreement calls for commitment fees on available, but unused, amounts.
The agreement also contains early termination rights if our current directors or their approved successors cease to
be a majority of the Board of Directors.

The revolving credit facility supports our ability to issue up to $6.0 billion of commercial paper, which is primarily a
funding source for short-term working capital needs. Commercial paper maturities are generally limited to 90
days. With no commercial paper outstanding and no direct borrowings or letters of credit, we had access to
$6.0 billion in available borrowing capacity under our revolving credit facility at December 31, 2021. We had no
direct borrowings, letters of credit, and $300 million of commercial paper outstanding as of December 31, 2020.

For information on Finance Leases, see Note 15.

The current credit ratings on our long-term debt are:
•
Fitch: “A” with a “stable” outlook.
•
S&P: “A-” with a “stable” outlook.
• Moody’s: “A3” with a “positive” outlook.

At both December 31, 2021 and 2020, we had $283 million of certain variable rate demand bonds (VRDBs)
outstanding with maturities ranging through 2035. The VRDBs are redeemable at the option of the bondholders
on any business day. If they are ever redeemed, we have the ability and intent to refinance on a long-term basis,
therefore, the VRDBs are included in the “Long-term debt” line on our consolidated balance sheet.

105 ConocoPhillips 2021 10-K

Notes to Consolidated Financial Statements

Note 10—Guarantees
At December 31, 2021, we were liable for certain contingent obligations under various contractual arrangements
as described below. We recognize a liability, at inception, for the fair value of our obligation as a guarantor for
newly issued or modified guarantees. Unless the carrying amount of the liability is noted below, we have not
recognized a liability because the fair value of the obligation is immaterial. In addition, unless otherwise stated, we
are not currently performing with any significance under the guarantee and expect future performance to be
either immaterial or have only a remote chance of occurrence.

APLNG Guarantees
At December 31, 2021, 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 2021
exchange rates:

•

During the third quarter of 2016, we issued a guarantee to facilitate the withdrawal of our pro-rata
portion of the funds in a project finance reserve account. We estimate the remaining term of this
guarantee to be 9 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, 2021, the carrying value of this guarantee is approximately $14 million.

In conjunction with our original purchase of an ownership interest in APLNG from Origin Energy in
October 2008, we agreed to reimburse Origin Energy for our share of the existing contingent liability
arising under guarantees of an existing obligation of APLNG to deliver natural gas under several sales
agreements. The final guarantee expires in the fourth quarter of 2041. Our maximum potential liability
for future payments, or cost of volume delivery, under these guarantees is estimated to be $660 million
($1.2 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-ventures do not
make necessary equity contributions into APLNG.

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

connection with the project’s continued development. The guarantees have remaining terms of 15 to 24
years or the life of the venture. Our maximum potential amount of future payments related to these
guarantees is approximately $180 million and would become payable if APLNG does not perform. At
December 31, 2021, the carrying value of these guarantees was approximately $11 million.

Other Guarantees
We have other guarantees with maximum future potential payment amounts totaling approximately $720 million,
which consist primarily of guarantees of the residual value of leased office buildings, guarantees of the residual
value of corporate aircraft, and a guarantee for our portion of a joint venture’s project finance reserve accounts.
These guarantees have remaining terms of one to five years and would become payable if certain asset values are
lower than guaranteed amounts at the end of the lease or contract term, business conditions decline at
guaranteed entities, or as a result of nonperformance of contractual terms by guaranteed parties. At
December 31, 2021, the carrying value of these guarantees was approximately $8 million.

Indemnifications
Over the years, we have entered into agreements to sell ownership interests in certain legal entities, joint ventures
and assets that gave rise to qualifying indemnifications. These agreements include indemnifications for taxes and
environmental liabilities. The carrying amount recorded for these indemnifications at December 31, 2021, was
approximately $20 million. Those related to environmental issues have terms that are generally indefinite and the
maximum amounts of future payments are generally unlimited. 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. See Note 11 for additional
information about environmental liabilities.

ConocoPhillips 2021 10-K 106

Notes to Consolidated Financial Statements

Note 11—Contingencies and Commitments
A number of lawsuits involving a variety of claims arising in the ordinary course of business have been filed against
ConocoPhillips. We also may be required to remove or mitigate the effects on the environment of the placement,
storage, disposal or release of certain chemical, mineral and petroleum substances at various active and inactive
sites. We regularly assess the need for accounting recognition or disclosure of these contingencies. In the case of
all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable
and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within
the range is a better estimate than any other amount, then the low end of the range is accrued. We do not reduce
these liabilities for potential insurance or third-party recoveries. We accrue receivables for insurance or other
third-party recoveries when applicable. With respect to income tax-related contingencies, we use a cumulative
probability-weighted loss accrual in cases where sustaining a tax position is less than certain. See Note 17, for
additional information about income tax-related contingencies.

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

Environmental
We are subject to international, federal, state and local environmental laws and regulations and record accruals for
environmental liabilities based on management’s best estimates. These estimates are based on currently available
facts, existing technology, and presently enacted laws and regulations, taking into account stakeholder and
business considerations. When measuring environmental liabilities, we also consider our prior experience in
remediation of contaminated sites, other companies’ cleanup experience, and data released by the U.S. EPA or
other organizations. We consider unasserted claims in our determination of environmental liabilities, and we
accrue them in the period they are both probable and reasonably estimable.

Although liability of those potentially responsible for environmental remediation costs is generally joint and
several for federal sites and frequently so for other sites, we are usually only one of many companies cited at a
particular site. Due to the joint and several liabilities, we could be responsible for all cleanup costs related to any
site at which we have been designated as a potentially responsible party. We have been successful to date in
sharing cleanup costs with other financially sound companies. Many of the sites at which we are potentially
responsible are still under investigation by the EPA or the agency concerned. Prior to actual cleanup, those
potentially responsible normally assess the site conditions, apportion responsibility and determine the appropriate
remediation. In some instances, we may have no liability or may attain a settlement of liability. Where it appears
that other potentially responsible parties may be financially unable to bear their proportional share, we consider
this inability in estimating our potential liability, and we adjust our accruals accordingly. As a result of various
acquisitions in the past, we assumed certain environmental obligations. Some of these environmental obligations
are mitigated by indemnifications made by others for our benefit, and some of the indemnifications are subject to
dollar limits and time limits.

We are currently participating in environmental assessments and cleanups at numerous federal Superfund and
comparable state and international sites. After an assessment of environmental exposures for cleanup and other
costs, we make accruals on an undiscounted basis (except those acquired in a purchase business combination,
which we record on a discounted basis) for planned investigation and remediation activities for sites where it is
probable future costs will be incurred and these costs can be reasonably estimated. We have not reduced these
accruals for possible insurance recoveries. In the future, we may be involved in additional environmental
assessments, cleanups and proceedings. See Note 8, for a summary of our accrued environmental liabilities.

107 ConocoPhillips 2021 10-K

Notes to Consolidated Financial Statements

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

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

We have contingent liabilities resulting from throughput agreements with pipeline and processing companies not
associated with financing arrangements. Under these agreements, we may be required to provide any such
company with additional funds through advances and penalties for fees related to throughput capacity not utilized.
In addition, at December 31, 2021, we had performance obligations secured by letters of credit of $337
million (issued as direct bank letters of credit) related to various purchase commitments for materials, supplies,
commercial activities and services incident to the ordinary conduct of business.

In 2007, ConocoPhillips was unable to reach agreement with respect to the empresa mixta structure mandated by
the Venezuelan government’s Nationalization Decree. As a result, Venezuela’s national oil company, Petróleos de
Venezuela, S.A. (PDVSA), or its affiliates, directly assumed control over ConocoPhillips’ interests in the Petrozuata
and Hamaca heavy oil ventures and the offshore Corocoro development project. In response to this expropriation,
ConocoPhillips initiated international arbitration on November 2, 2007, with the ICSID. On September 3, 2013, an
ICSID arbitration tribunal held that Venezuela unlawfully expropriated ConocoPhillips’ significant oil investments in
June 2007. On January 17, 2017, the Tribunal reconfirmed the decision that the expropriation was unlawful. In
March 2019, the Tribunal unanimously ordered the government of Venezuela to pay ConocoPhillips approximately
$8.7 billion in compensation for the government’s unlawful expropriation of the company’s investments in
Venezuela in 2007. On August 29, 2019, the ICSID Tribunal issued a decision rectifying the award and reducing it
by approximately $227 million. The award now stands at $8.5 billion plus interest. The government of Venezuela
sought annulment of the award, which automatically stayed enforcement of the award. On September 29, 2021,
the ICSID annulment committee lifted the stay of enforcement of the award. The annulment proceedings have
been suspended as a result of Venezuela’s non-payment of advances to cover the costs of these proceedings.

In 2014, ConocoPhillips filed a separate and independent arbitration under the rules of the ICC against PDVSA
under the contracts that had established the Petrozuata and Hamaca projects. The ICC Tribunal issued an award in
April 2018, finding that PDVSA owed ConocoPhillips approximately $2 billion under their agreements in connection
with the expropriation of the projects and other pre-expropriation fiscal measures. In August 2018, ConocoPhillips
entered into a settlement with PDVSA to recover the full amount of this ICC award, plus interest through the
payment period, including initial payments totaling approximately $500 million within a period of 90 days from the
time of signing of the settlement agreement. The balance of the settlement is to be paid quarterly over a period of
four and a half years. Per the settlement, PDVSA recognized the ICC award as a judgment in various jurisdictions,
and ConocoPhillips agreed to suspend its legal enforcement actions. ConocoPhillips sent notices of default to
PDVSA on October 14 and November 12, 2019, and to date PDVSA has failed to cure its breach. As a result,
ConocoPhillips has resumed legal enforcement actions. To date, ConocoPhillips has received approximately $768
million in connection with the ICC award. ConocoPhillips has ensured that the settlement and any actions taken in
enforcement thereof meet all appropriate U.S. regulatory requirements, including those related to any applicable
sanctions imposed by the U.S. against Venezuela.

ConocoPhillips 2021 10-K 108

Notes to Consolidated Financial Statements

In 2016, ConocoPhillips filed a separate and independent arbitration under the rules of the ICC against PDVSA
under the contracts that had established the Corocoro Project. On August 2, 2019, the ICC Tribunal awarded
ConocoPhillips approximately $33 million plus interest under the Corocoro contracts. ConocoPhillips is seeking
recognition and enforcement of the award in various jurisdictions. ConocoPhillips has ensured that all the actions
related to the award meet all appropriate U.S. regulatory requirements, including those related to any applicable
sanctions imposed by the U.S. against Venezuela.

The Office of Natural Resources Revenue (ONRR) has conducted audits of ConocoPhillips’ payment of royalties on
federal lands and has issued multiple orders to pay additional royalties to the federal government. ConocoPhillips
and the ONRR entered into a settlement agreement on March 23, 2021, to resolve the dispute. All orders and
associated appeals have been withdrawn with prejudice.

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

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

In October 2020, the Bureau of Safety and Environmental Enforcement (BSEE) ordered the prior owners of Outer
Continental Shelf (OCS) Lease P-0166, including ConocoPhillips, to decommission the lease facilities, including two
offshore platforms located near Carpinteria, California. This order was sent after the current owner of OCS Lease
P-0166 relinquished the lease and abandoned the lease platforms and facilities. BSEE’s order to ConocoPhillips is
premised on its connection to Phillips Petroleum Company, a legacy company of ConocoPhillips, which held a
historical 25 percent interest in this lease and operated these facilities, but sold its interest approximately 30 years
ago. ConocoPhillips continues to evaluate our exposure in these lawsuits.

On May 10, 2021, ConocoPhillips filed arbitration under the rules of the Singapore International Arbitration Centre
(SIAC) against Santos KOTN Pty Ltd. and Santos Limited for their failure to timely pay the $200 million bonus due
upon FID of the Barossa development project under the sale and purchase agreement. Santos KOTN Pty Ltd. and
Santos Limited have filed a response and counterclaim, and the arbitration is underway.

In July 2021, a federal securities class action was filed against Concho, certain of Concho’s officers, and
ConocoPhillips as Concho’s successor in the United States District Court for the Southern District of Texas. On
October 21, 2021, the court issued an order appointing Utah Retirement Systems and the Construction Laborers
Pension Trust for Southern California as lead plaintiffs (Lead Plaintiffs). On January 7, 2022, the Lead Plaintiffs filed
their consolidated complaint alleging that Concho made materially false and misleading statements regarding its
business and operations in violation of the federal securities laws and seeking unspecified damages, attorneys’
fees, costs, equitable/injunctive relief, and such other relief that may be deemed appropriate. We believe the
allegations in the action are without merit, and we intend to vigorously defend this litigation.

Long-Term Throughput Agreements and Take-or-Pay Agreements
We have certain throughput agreements and take-or-pay agreements in support of financing arrangements. The
agreements typically provide for natural gas or crude oil transportation to be used in the ordinary course of
business. The aggregate amounts of estimated payments under these various agreements are: 2022—$7 million;
2023—$7 million; 2024—$7 million; 2025—$7 million; 2026—$7 million; and 2027 and after—$43 million.
Total payments under the agreements were $27 million in 2021, $25 million in 2020 and $25 million in 2019.

109 ConocoPhillips 2021 10-K

Notes to Consolidated Financial Statements

Note 12—Derivative and Financial Instruments
We use futures, forwards, swaps and options in various markets to meet our customer needs, capture market
opportunities, and manage foreign exchange currency risk.

Commodity Derivative Instruments
Our commodity business primarily consists of natural gas, crude oil, bitumen, LNG and NGLs.

Commodity derivative instruments are held at fair value on our consolidated balance sheet. Where these balances
have the right of setoff, they are presented on a net basis. Related cash flows are recorded as operating activities
on our consolidated statement of cash flows. On our consolidated income statement, 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 and certain gas contracts. We do not
apply hedge accounting for our commodity derivatives.

The following table presents the gross fair values of our commodity derivatives, excluding collateral, and the line
items where they appear on our consolidated balance sheet:

Assets
Prepaid expenses and other current assets
Other assets
Liabilities
Other accruals
Other liabilities and deferred credits

Millions of Dollars

2021

2020

1,168
75

1,160
63

229
26

202
18

The gains (losses) from commodity derivatives incurred, and the line items where they appear on our consolidated
income statement were:

Sales and other operating revenues
Other income (loss)
Purchased commodities

Millions of Dollars

2021

(228)
25
75

2020

19
4
11

2019

141
4
(118)

On January 15, 2021, we assumed financial derivative instruments consisting of oil and natural gas swaps in
connection with the acquisition of Concho. At the acquisition date, the financial derivative instruments acquired
were recognized at fair value as a net liability of $456 million with settlement dates under the contracts through
December 31, 2022. During 2021, we recognized a loss on settlement of the contracts for $305 million. This loss
associated with the acquired financial instruments is recorded within the “Sales and other operating revenues” line
on our consolidated income statement. In connection with the settlement, we issued a cash payment of $761
million during 2021. Cash settlements related to the derivative contracts are presented within “Cash Flows From
Operating Activities” on our consolidated statement of cash flows.

ConocoPhillips 2021 10-K 110

Notes to Consolidated Financial Statements

The table below summarizes our material net exposures resulting from outstanding commodity derivative
contracts:

Commodity
Natural gas and power (billions of cubic feet equivalent)

Fixed price
Basis

Open Position
Long/(Short)

2021

4
(22)

2020

(20)
(10)

Foreign Currency Exchange Derivatives
We have foreign currency exchange rate risk resulting from international operations. Our foreign currency
exchange derivative activity primarily relates to managing our cash-related foreign currency exchange rate
exposures, such as firm commitments for capital programs or local currency tax payments, dividends and cash
returns from net investments in foreign affiliates, and investments in equity securities.

Our foreign currency exchange derivative instruments are held at fair value on our consolidated balance sheet.
Related cash flows are included within operating activities on our consolidated statement of cash flows. We do
not elect hedge accounting on our foreign currency exchange derivatives.

The following table presents the gross fair values of our foreign currency exchange derivatives, excluding
collateral, and the line items where they appear on our consolidated balance sheet:

Millions of Dollars

2021

2020

Assets
Prepaid expenses and other current assets
Liabilities
Other accruals

The (gains) losses from foreign currency exchange derivatives incurred and the line item where they appear
on our consolidated income statement were:

Foreign currency transaction (gains) losses

Millions of Dollars

2021

(5)

2020

(40)

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

Foreign Currency Exchange Derivatives
Buy British pound, sell euro
Sell British pound, buy euro
Sell Canadian dollar, buy U.S. dollar
Buy Canadian dollar, sell U.S. dollar
Buy Australian dollar, sell U.S. dollar

111 ConocoPhillips 2021 10-K

In Millions
Notional Currency
2021

GBP
GBP
CAD
CAD
AUD

155
-
-
77
1,850

2019

2020

-
5
370
-
-

Notes to Consolidated Financial Statements

At December 31, 2021, we had outstanding foreign currency exchange forward contracts to buy $1.9 billion AUD at
$0.715 AUD against the U.S. dollar in anticipation of our future acquisition of an additional interest in APLNG. At
December 31, 2020, we had outstanding foreign currency exchange forward contracts to sell $0.45 billion CAD at
$0.748 CAD against the U.S. dollar.

Financial Instruments
We invest in financial instruments with maturities based on our cash forecasts for the various accounts and
currency pools we manage. The types of financial instruments in which we currently invest include:

•

•
•
•

Time deposits: Interest bearing deposits placed with financial institutions for a predetermined amount of
time.
Demand deposits: Interest bearing deposits placed with financial institutions. Deposited funds can be
withdrawn without notice.
Commercial paper: Unsecured promissory notes issued by a corporation, commercial bank or government
agency purchased at a discount to mature at par.
U.S. government or government agency obligations: Securities issued by the U.S. government or U.S.
government agencies.
Foreign government obligations: Securities issued by foreign governments.
Corporate bonds: Unsecured debt securities issued by corporations.
Asset-backed securities: Collateralized debt securities.

The following investments are carried on our consolidated balance sheet at cost, plus accrued interest and the
table reflects remaining maturities at December 31, 2021 and 2020:

Millions of Dollars
Carrying Amount

Cash and Cash
Equivalents
2021

2020

Short-Term
Investments
2021

Investments and Long-
Term Receivables

2020

2021

2020

Cash
Demand Deposits
Time Deposits
1 to 90 days
91 to 180 days
Within one year
One year through five years
U.S. Government Obligations
1 to 90 days

670
1,554

597
1,133

2,363

1,225

431
5,018

23
2,978

217
4
4

-
225

2,859
448
13

-
3,320

ConocoPhillips 2021 10-K 112

Notes to Consolidated Financial Statements

The following investments in debt securities classified as available for sale are carried at fair value on our
consolidated balance sheet at December 31, 2021 and 2020:

Major Security Type
Corporate Bonds
Commercial Paper
U.S. Government Obligations
U.S. Government Agency
Obligations
Foreign Government Obligations
Asset-backed Securities

Cash and Cash
Equivalents
2021

2020

3
7
-

-
13
-

Millions of Dollars
Carrying Amount
Short-Term
Investments
2021

2020

128
82
-

2
7
2

130
155
4

-
-
-

Investments and Long-
Term Receivables

2021

2020

173

143

8
2
63

17
2
41

221

289

248

216

Cash and Cash Equivalents and Short-Term Investments have remaining maturities within one year.
Investments and Long-Term Receivables have remaining maturities that vary from greater than one year through
eight years.

The following table summarizes the amortized cost basis and fair value of investments in debt securities classified
as available for sale at December 31:

Major Security Type
Corporate Bonds
Commercial Paper
U.S. Government Obligations
U.S. Government Agency Obligations
Foreign Government Obligations
Asset-Backed Securities

Millions of Dollars

Amortized Cost Basis

2021

2020

Fair Value
2021

2020

305
88
2
10
9
65
479

271
168
17
17
2
41
516

304
89
2
10
9
65
479

273
168
17
17
2
41
518

As of December 31, 2021 and 2020, total unrealized losses for debt securities classified as available for sale with
net losses were negligible. Additionally, as of December 31, 2021 and 2020, investments in these debt securities in
an unrealized loss position for which an allowance for credit losses has not been recorded were negligible.

For the years ended December 31, 2021 and 2020, proceeds from sales and redemptions of investments in debt
securities classified as available for sale were $594 million and $422 million, respectively. Gross realized gains and
losses included in earnings from those sales and redemptions were negligible. The cost of securities sold and
redeemed is determined using the specific identification method.

113 ConocoPhillips 2021 10-K

Notes to Consolidated Financial Statements

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, U.S. government and government agency obligations, time deposits with major international banks
and financial institutions, high-quality corporate bonds, foreign government obligations and asset-backed
securities. Our long-term investments in debt securities are placed in high-quality corporate bonds, asset-backed
securities, U.S. government and government agency obligations, foreign government obligations, and time
deposits with major international banks and financial institutions.

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 may require collateral to limit the exposure to loss including, letters of
credit, prepayments and surety bonds, as well as master netting arrangements to mitigate credit risk with
counterparties that both buy from and sell to us, as these agreements permit the amounts owed by us or owed to
others to be offset against amounts due to us.

Certain of our derivative instruments contain provisions that require us to post collateral if the derivative exposure
exceeds a threshold amount. We have contracts with fixed threshold amounts and other contracts with variable
threshold amounts that are contingent on our credit rating. The variable threshold amounts typically decline for
lower credit ratings, while both the variable and fixed threshold amounts typically revert to zero if we fall below
investment grade. Cash is the primary collateral in all contracts; however, many also permit us to post letters of
credit as collateral, such as transactions administered through the New York Mercantile Exchange.

The aggregate fair value of all derivative instruments with such credit risk-related contingent features that were in
a liability position on December 31, 2021 and December 31, 2020, was $281 million and $25 million, respectively.
For these instruments, no collateral was posted as of December 31, 2021 or December 31, 2020. If our credit
rating had been downgraded below investment grade on December 31, 2021, we would have been required to
post $252 million of additional collateral, either with cash or letters of credit.

Note 13—Fair Value Measurement
We carry a portion of our assets and liabilities at fair value that are measured at the reporting date using an exit
price (i.e., the price that would be received to sell an asset or paid to transfer a liability) and disclosed according to
the quality of valuation inputs under the fair value hierarchy.

The classification of an asset or liability is based on the lowest level of input significant to its fair value. Those that
are initially classified as Level 3 are subsequently reported as Level 2 when the fair value derived from unobservable
inputs is inconsequential to the overall fair value, or if corroborated market data becomes available. Assets and
liabilities initially reported as Level 2 are subsequently reported as Level 3 if corroborated market data is no longer
available. There were no material transfers into or out of Level 3 during 2021 or 2020.

ConocoPhillips 2021 10-K 114

Notes to Consolidated Financial Statements

Recurring Fair Value Measurement
Financial assets and liabilities reported at fair value on a recurring basis primarily include our investment in CVE
common shares, our investments in debt securities classified as available for sale, and commodity derivatives.

•

Level 1 derivative assets and liabilities primarily represent exchange-traded futures and options that are
valued using unadjusted prices available from the underlying exchange. Level 1 also includes our investment
in common shares of CVE, which is valued using quotes for shares on the NYSE, and our investments in U.S.
government obligations classified as available for sale debt securities, which are valued using exchange prices.
Level 2 derivative assets and liabilities primarily represent OTC swaps, options and forward purchase and sale
contracts that are valued using adjusted exchange prices, prices provided by brokers or pricing service
companies that are all corroborated by market data. Level 2 also includes our investments in debt securities
classified as available for sale including investments in corporate bonds, commercial paper, asset-backed
securities, U.S. government agency obligations and foreign government obligations that are valued using
pricing provided by brokers or pricing service companies that are corroborated with market data.
Level 3 derivative assets and liabilities consist of OTC swaps, options and forward purchase and sale contracts
where a significant portion of fair value is calculated from underlying market data that is not readily available.
The derived value uses industry standard methodologies that may consider the historical relationships among
various commodities, modeled market prices, time value, volatility factors and other relevant economic
measures. The use of these inputs results in management’s best estimate of fair value. Level 3 activity was
not material for all periods presented.

The following table summarizes the fair value hierarchy for gross financial assets and liabilities (i.e., unadjusted
where the right of setoff exists for commodity derivatives accounted for at fair value on a recurring basis):

Millions of Dollars

December 31, 2021
Level 3

Level 2

Level 1

Total

Level 1

December 31, 2020
Level 3

Level 2

Assets
Investment in Cenovus Energy
Investments in debt securities
Commodity derivatives
Total assets

Liabilities
Commodity derivatives
Total liabilities

$
$

1,117
2
562
1,681

-
477
619
1,096

593
593

543
543

-
-
62
62

87
87

1,117
479
1,243
2,839

1,223
1,223

1,256
17
142
1,415

120
120

-
501
101
602

91
91

-
-
12
12

9
9

Total

1,256
518
255
2,029

220
220

115 ConocoPhillips 2021 10-K

Notes to Consolidated Financial Statements

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
Recognized

Amounts Not
Subject to
Right of Setoff

December 31, 2021
Assets
Liabilities

December 31, 2020
Assets
Liabilities

1,243
1,223

255
220

85
82

2
1

Amounts

1,158
1,141

253
219

Gross
Gross Amounts

Net
Amounts

Net
Offset Presented Collateral Amounts

Cash

650
650

157
157

508
491

96
62

-
36

10
4

508
455

86
58

At December 31, 2021 and December 31, 2020, 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:

Year ended December 31, 2021
Net PP&E (held for use)
December 31, 2021
Equity Method Investments
December 31, 2021

Year ended December 31, 2020
Net PP&E (held for use)
March 31, 2020
December 31, 2020

Fair Value

472

5,574

65
268

Millions of Dollars
Fair Value Measurements Using
Level 1
Inputs

Level 2
Inputs

Level 3
Inputs

Before-Tax
Loss

-
-

5,574

-
-

472

65
268

688

522
287

Net PP&E (held for use)
During 2021 and 2020, the estimated fair value of certain noncore assets included in our Lower 48 segment
declined to amounts below the carrying values. The carrying values were written down to fair value. The fair
values were estimated based on internal discounted cash flow models using the following estimated assumptions:
estimated future production, an outlook of future prices from a combination of exchanges (short-term) coupled
with pricing service companies and our internal outlook (long-term), future operating costs and capital
expenditures, and a discount rate believed to be consistent with those used by principal market participants. The
range and arithmetic average of significant unobservable inputs used in the Level 3 fair value measurements for
significant assets were as follows:

ConocoPhillips 2021 10-K 116

Notes to Consolidated Financial Statements

Fair Value
(Millions of
Dollars)

Valuation
Technique

Unobservable Inputs

Range
(Arithmetic Average)

December 31, 2021

Lower 48 Gulf Coast and
Rockies noncore field

Discounted
cash flow

472

Commodity production
(MBOED)

0.2 - 17 (5.4)

Commodity price outlook*

($/BOE) $41.45 - $93.68 ($64.39)

Discount rate**

7.3% - 9.7% (8.7%)

*Commodity price outlook based on a combination of external pricing service companies' and our internal outlook for years 2024-2050; future prices escalated at
2.0% annually after year 2050.
**Determined as the weighted average cost of capital of a group of peer companies, adjusted for risks where appropriate.

Fair Value
(Millions of
Dollars)

Valuation
Technique

Unobservable Inputs

Range
(Arithmetic Average)

March 31, 2020

Wind River Basin

Discounted
cash flow

Natural gas production
(MMCFD)

8.4 - 55.2 (22.9)

Natural gas price outlook*
($/MMBTU)

$2.67 - $9.17 ($5.68)

Discount rate**

7.9% - 9.1% (8.3%)

*Henry Hub natural gas price outlook based on a combination of external pricing service companies' outlooks for years 2022-2034; future prices escalated at 2.2%
annually after year 2034.
**Determined as the weighted average cost of capital of a group of peer companies, adjusted for risks where appropriate.

Fair Value
(Millions of
Dollars)

Valuation
Technique

Unobservable Inputs

Range
(Arithmetic Average)

December 31, 2020

Central Basin Platform

244

Discounted
cash flow

Commodity production
(MBOED)

0.5 - 12.7 (3.4)

Commodity price outlook*
($/BOE)

$37.35 - $115.29
($73.80)

Discount rate**

6.8% - 7.7% (7.4%)

*Commodity price outlook based on a combination of external pricing service companies' and our internal outlook for years 2023-2050; future prices escalated at
2.0% annually after year 2050.
**Determined as the weighted average cost of capital of a group of peer companies, adjusted for risks where appropriate.

Equity Method Investments
During the fourth quarter of 2021, Origin Energy Limited agreed to the sale of 10 percent of their interest in APLNG
for $1.645 billion, before customary adjustments. ConocoPhillips announced in December 2021 that we were
exercising our preemption right under the APLNG Shareholders Agreement to purchase an additional 10 percent
shareholding interest in APLNG, subject to government approvals. The sales price associated with this preemption
right was determined to reflect a relevant observable market participant view of APLNG’s fair value which was
below the carrying value of our existing investment in APLNG. As such, our investment in APLNG was written
down to its fair value of $5,574 million, resulting in a before-tax charge of $688 million. See Note 4 and Note 7.

117 ConocoPhillips 2021 10-K

Notes to Consolidated Financial Statements

Reported Fair Values of Financial Instruments
We used the following methods and assumptions to estimate the fair value of financial instruments:

•

Cash and cash equivalents and short-term investments: The carrying amount reported on the balance
sheet approximates fair value. For those investments classified as available for sale debt securities, the
carrying amount reported on the balance sheet is fair value.
Accounts and notes receivable (including long-term and related parties): The carrying amount reported on
the balance sheet approximates fair value. The valuation technique and methods used to estimate the
fair value of the current portion of fixed-rate related party loans is consistent with Loans and advances—
related parties.
Investment in Cenovus Energy: See Note 5 for a discussion of the carrying value and fair value of our
investment in CVE common shares.
Investments in debt securities classified as available for sale: The fair value of investments in debt
securities categorized as Level 1 in the fair value hierarchy is measured using exchange prices. The fair
value of investments in debt securities categorized as Level 2 in the fair value hierarchy is measured using
pricing provided by brokers or pricing service companies that are corroborated with market data. See
Note 12.
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 4.
Accounts payable (including related parties) and floating-rate debt: The carrying amount of accounts
payable and floating-rate debt reported on the balance sheet approximates fair value.
Fixed-rate debt: The estimated fair value of fixed-rate debt is measured using prices available from a
pricing service that is corroborated by market data; therefore, these liabilities are categorized as Level 2 in
the fair value hierarchy.
Commercial paper: The carrying amount of our commercial paper instruments approximates fair value
and is reported on the balance sheet as short-term debt.

The following table summarizes the net fair value of financial instruments (i.e., adjusted where the right of setoff
exists for commodity derivatives):

Financial assets
Investment in CVE common shares
Commodity derivatives
Investments in debt securities
Loans and advances—related parties
Financial liabilities
Total debt, excluding finance leases
Commodity derivatives

Millions of Dollars

Carrying Amount

Fair Value

2021

2020

2021

2020

1,117
593
479
114

18,673
537

1,256
88
518
220

1,117
593
479
114

14,478
59

22,451
537

1,256
88
518
220

19,106
59

Commodity Derivatives
At December 31, 2021, commodity derivative assets and liabilities are presented net with no obligation to return
cash collateral and $36 million of rights to reclaim cash collateral, respectively. At December 31, 2020, commodity
derivative assets and liabilities are presented net with $10 million in obligations to return cash collateral and
$4 million of rights to reclaim cash collateral, respectively.

ConocoPhillips 2021 10-K 118

Notes to Consolidated Financial Statements

Note 14—Equity
Common Stock
The changes in our shares of common stock, as categorized in the equity section of the balance sheet, were:

Issued
Beginning of year
Acquisition of Concho
Distributed under benefit plans
End of year

Held in Treasury
Beginning of year
Repurchase of common stock
End of year

2021

2020

2019

1,798,844,267
285,928,872
6,789,608
2,091,562,747

1,795,652,203
-
3,192,064
1,798,844,267

1,791,637,434
-
4,014,769
1,795,652,203

730,802,089
58,517,786
789,319,875

710,783,814
20,018,275
730,802,089

653,288,213
57,495,601
710,783,814

Preferred Stock
We have authorized 500 million shares of preferred stock, par value $0.01 per share, none of which was issued or
outstanding at December 31, 2021 or 2020.

Noncontrolling Interests
In the second quarter of 2020, we completed the divestiture of our subsidiaries that held our Australia-West assets
and operations. These assets included the Darwin LNG and Bayu-Darwin Pipeline operating joint ventures in which
there was a noncontrolling interest. As a result, as of December 31, 2021 and 2020, we had no noncontrolling
interests.

Repurchase of Common Stock
In late 2016, we initiated our current share repurchase program, which has a current total program authorization
of $25 billion of our common stock. In May 2021, we began a paced monetization of our CVE common shares, the
proceeds of which have been applied to share repurchases. Share repurchases since inception of our current
program totaled 247 million shares at a cost of $14 billion through the end of December 2021.

Note 15—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 10. There are no significant restrictions imposed on us by the lease
agreements with regard to dividends, asset dispositions or borrowing ability.

119 ConocoPhillips 2021 10-K

Notes to Consolidated Financial Statements

Certain arrangements may contain both lease and non-lease components and we determine if an arrangement is
or contains a lease at contract inception. We adopted the provisions of FASB ASU No. 2016-02, “Leases” (ASC
Topic 842) and its amendments, beginning January 1, 2019. This ASU superseded the requirements in FASB ASC
Topic 840 “Leases” (ASC Topic 840). Only the lease components of these contractual arrangements are subject to
the provisions of ASC Topic 842, and any non-lease components are subject to other applicable accounting
guidance; however, we have elected to adopt the optional practical expedient not to separate lease components
apart from non-lease components for accounting purposes. This policy election has been adopted for each of the
company’s leased asset classes existing as of the effective date and subject to the transition provisions of ASC
Topic 842 and will be applied to all new or modified leases executed on or after January 1, 2019. For contractual
arrangements executed in subsequent periods involving a new leased asset class, the company will determine at
contract inception whether it will apply the optional practical expedient to the new leased asset class.

Leases are evaluated for classification as operating or finance leases at the commencement date of the lease and
right-of-use assets and corresponding liabilities are recognized on our consolidated balance sheet based on the
present value of future lease payments relating to the use of the underlying asset during the lease term. Future
lease payments include variable lease payments that depend upon an index or rate using the index or rate at the
commencement date and probable amounts owed under residual value guarantees. The amount of future lease
payments may be increased to include additional payments related to lease extension, termination, and/or
purchase options when the company has determined, at or subsequent to lease commencement, generally due to
limited asset availability or operating commitments, it is reasonably certain of exercising such options. We use our
incremental borrowing rate as the discount rate in determining the present value of future lease payments, unless
the interest rate implicit in the lease arrangement is readily determinable. Lease payments that vary subsequent
to the commencement date based on future usage levels, the nature of leased asset activities, or certain other
contingencies are not included in the measurement of lease right-of-use assets and corresponding liabilities. We
have elected not to record assets and liabilities on our consolidated balance sheet for lease arrangements with
terms of 12 months or less.

We often enter into leasing arrangements acting in the capacity as operator for and/or on behalf of certain oil and
gas joint ventures of undivided interests. If the lease arrangement can be legally enforced only against us as
operator and there is no separate arrangement to sublease the underlying leased asset to our coventurers, we
recognize at lease commencement a right-of-use asset and corresponding lease liability on our consolidated
balance sheet on a gross basis. While we record lease costs on a gross basis in our consolidated income statement
and statement of cash flows, such costs are offset by the reimbursement we receive from our coventurers for their
share of the lease cost as the underlying leased asset is utilized in joint venture activities. As a result, lease cost is
presented in our consolidated income statement and statement of cash flows on a proportional basis. If we are a
nonoperating coventurer, we recognize a right-of-use asset and corresponding lease liability only if we were a
specified contractual party to the lease arrangement and the arrangement could be legally enforced against us. In
this circumstance, we would recognize both the right-of-use asset and corresponding lease liability on our
consolidated balance sheet on a proportional basis consistent with our undivided interest ownership in the related
joint venture.

The company has historically recorded certain finance leases executed by investee companies accounted for under
the proportionate consolidation method of accounting on its consolidated balance sheet on a proportional basis
consistent with its ownership interest in the investee company. In addition, the company has historically recorded
finance lease assets and liabilities associated with certain oil and gas joint ventures on a proportional basis
pursuant to accounting guidance applicable prior to January 1, 2019. In accordance with the transition provisions
of ASC Topic 842, and since we have elected to adopt the package of optional transition-related practical
expedients, the historical accounting treatment for these leases has been carried forward and is subject to
reconsideration upon the modification or other required reassessment of the arrangements prior to lease term
expiration.

ConocoPhillips 2021 10-K 120

Notes to Consolidated Financial Statements

The following table summarizes the right-of-use assets and lease liabilities for both the operating and finance
leases on our consolidated balance sheet as of December 31:

Right-of-Use Assets
Properties, plants and equipment

Gross
Accumulated DD&A

Net PP&E*
Prepaid expenses and other current assets
Other assets

Lease Liabilities

Short-term debt**
Other accruals
Long-term debt***
Other liabilities and deferred credits

The following table summarizes our lease costs:

Lease Cost*
Operating lease cost
Finance lease cost

Amortization of right-of-use assets
Interest on lease liabilities

Millions of Dollars

2021

2020

Operating
Leases

Finance
Leases

Operating
Leases

Finance
Leases

16
649

188

1,812
(857)

955
2

280

981

1,375
(721)

654

168

723

783

226

479
667

559
785

Millions of Dollars

2021

2020

2019

278

321

148
27
21
474

163
34
42
560

341

99
37
77
554

Total lease liabilities
$
* Includes proportionately consolidated finance lease assets of $208 million at December 31, 2021 and $258 million at December 31, 2020.
** Includes proportionately consolidated finance lease liabilities of $154 million at December 31, 2021 and $97 million at December 31, 2020.
*** Includes proportionately consolidated finance lease liabilities of $462 million at December 31, 2021 and $522 million at December 31,
2020.

1,261

891

Short-term lease cost**
Total lease cost***
* The amounts presented in the table above have not been adjusted to reflect amounts recovered or reimbursed from oil and gas
coventurers.
** Short-term leases are not recorded on our consolidated balance sheet.
*** Variable lease cost and sublease income are immaterial for the periods presented and therefore are not included in the table above.

121 ConocoPhillips 2021 10-K

Notes to Consolidated Financial Statements

The following table summarizes the lease terms and discount rates as of December 31:

Lease Term and Discount Rate
Weighted-average term (years)

Operating leases
Finance leases

Weighted-average discount rate (percent)

Operating leases
Finance leases

The following table summarizes other lease information:

2021

2020

5.97
7.49

2.66
3.24

6.11
7.12

2.78
4.27

Millions of Dollars

2021

2020

2019

Other Information*
Cash paid for amounts included in the measurement of lease liabilities

Operating cash flows from operating leases
Operating cash flows from finance leases
Financing cash flows from finance leases

204
6
73

232
11
255

203
27
81

499
Right-of-use assets obtained in exchange for operating lease liabilities
26
Right-of-use assets obtained in exchange for finance lease liabilities
*The amounts presented in the table above have not been adjusted to reflect amounts recovered or reimbursed from oil and gas coventurers.
In addition, pursuant to other applicable accounting guidance, lease payments made in connection with preparing another asset for its
intended use are reported in the "Cash Flows From Investing Activities" section of our consolidated statement of cash flows.

250
426

174
447

The following table summarizes future lease payments for operating and finance leases at December 31, 2021:

Millions of Dollars

Operating
Leases

Finance
Leases

Maturity of Lease Liabilities
341
2022
199
2023
166
2024
143
2025
139
2026
462
Remaining years
Total*
1,450
(189)
Less: portion representing imputed interest
Total lease liabilities
1,261
*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.

195
143
114
68
50
159
729
(62)
667

ConocoPhillips 2021 10-K 122

Notes to Consolidated Financial Statements

Note 16—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:

Change in Benefit Obligation
Benefit obligation at January 1
Service cost
Interest cost
Plan participant contributions
Plan amendments
Actuarial (gain) loss
Benefits paid
Curtailment
Recognition of termination benefits
Foreign currency exchange rate change
Benefit obligation at December 31*
*Accumulated benefit obligation portion of above at

December 31:

Change in Fair Value of Plan Assets
Fair value of plan assets at January 1
Actual return on plan assets
Company contributions
Plan participant contributions
Benefits paid
Foreign currency exchange rate change
Fair value of plan assets at December 31

Funded Status

Millions of Dollars

Pension Benefits

2021

U.S.

2,548
73
53
-
-
(117)
(654)
12
9
-
1,924

Int’l.

4,403
61
79
-
-
(176)
(162)
-
-
(81)
4,124

2020
U.S.

2,319
85
66
-
-
319
(241)
-
-
-
2,548

Int’l.

3,880
54
85
1
2
398
(151)
2
3
129
4,403

1,793

3,658

2,359

4,095

1,770
97
451
-
(654)
-
1,664

(260)

4,793
147
119
1
(162)
(86)
4,812

688

1,591
321
99
-
(241)
-
1,770

(778)

4,306
416
60
1
(151)
161
4,793

390

Other Benefits

2021

2020

170
2
4
16
-
(16)
(40)
1
-
-
137

-
-
24
16
(40)
-
-

216
2
6
18
(30)
7
(49)
-
-
-
170

-
-
31
18
(49)
-
-

(137)

(170)

123 ConocoPhillips 2021 10-K

Notes to Consolidated Financial Statements

Amounts Recognized in the

Consolidated Balance Sheet at
December 31
Noncurrent assets
Current liabilities
Noncurrent liabilities
Total recognized

Weighted-Average Assumptions Used to

Determine Benefit Obligations at
December 31

Discount rate
Rate of compensation increase
Interest crediting rate for applicable benefits

Weighted-Average Assumptions Used to
Determine Net Periodic Benefit Cost for
Years Ended December 31

Discount rate
Expected return on plan assets
Rate of compensation increase
Interest crediting rate for applicable benefits

Millions of Dollars

Pension Benefits

2021

U.S.

Int’l.

2020
U.S.

Int’l.

Other Benefits

2021

2020

1
(29)
(232)
(260)

991
(15)
(288)
688

-
(56)
(722)
(778)

746
(11)
(345)
390

-
(34)
(103)
(137)

-
(39)
(131)
(170)

2.80 %
4.00
2.50

2.15
3.40

2.30
4.00
2.10

1.80
3.10

2.65

2.15

2.60 %
5.20
4.00
2.10

1.80
2.50
3.40

3.05
5.80
4.00
4.10

2.35
3.60
3.35

2.35

3.10

For both U.S. and international pension plans, 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.

During 2021, the actuarial gains related to the benefit obligations for U.S. and international plans were primarily
related to an increase in the discount rates. During 2020 and 2019, the actuarial losses related to the benefit
obligations for U.S. and international plans were primarily related to a decrease in the discount rates.

ConocoPhillips 2021 10-K 124

Notes to Consolidated Financial Statements

The following tables summarize information related to the Company's pension plans with projected and
accumulated benefit obligations in excess of the fair value of the plans' assets:

Pension Plans with Projected Benefit Obligation in

Excess of Plan Assets

Projected benefit obligation
Fair value of plan assets

Pension Plans with Accumulated Benefit Obligation in

Excess of Plan Assets

Accumulated benefit obligation
Fair value of plan assets

Millions of Dollars
Pension Benefits

Int’l.

362
58

2020

U.S.

2,548
1,770

271
9

2,359
1,770

2021

U.S.

261
-

234
-

Int’l.

391
35

338
35

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

2021

2020

Other Benefits

2021

2020

U.S.

Int’l.

U.S.

Int’l.

Unrecognized net actuarial loss (gain)

Unrecognized prior service cost (credit)

188

467

326

(1)

(145)

(182)

Millions of Dollars

Pension Benefits

2021

2020

Other Benefits

2021

2020

U.S.

Int’l.

U.S.

Int’l.

134

145

279

-
-

207

240

(1)
(1)

(83)

(120)

-
-

(99)

(1)

(1)
(2)

(7)

(6)

(37)
(37)

(31)
(1)

Sources of Change in Other

Comprehensive Income (Loss)

Net gain (loss) arising during the period
Amortization of actuarial loss included

in income (loss)*

Net change during the period

Prior service credit (cost) arising during the

period

Amortization of prior service (credit)

included in income (loss)
$
Net change during the period
*Includes settlement (gains) losses recognized in 2021 and 2020.

125 ConocoPhillips 2021 10-K

Notes to Consolidated Financial Statements

The components of net periodic benefit cost of all defined benefit plans are presented in the following table:

Millions of Dollars

2021

Pension Benefits
2020

Other Benefits

2019

2021

2020

2019

U.S.

Int’l.

U.S.

Int’l.

U.S.

Int’l.

73
53

61
79

85
66

54
85

79
79

69
97

(80)

(120)

(85)

(145)

(74)

(138)

2
4

2
6

1
8

(1)

43
102
12
203

33
-
-
52

51
44
-
161

(1)

22
(1)
-
14

(2)

(37)

(31)

(33)

54
62
-
200

32
-
-
58

-
-
-
(31)

1
-
-
(22)

(2)
-
-
(26)

Components of Net

Periodic Benefit Cost

Service cost
Interest cost
Expected return on plan

assets

Amortization of prior

service credit

Recognized net actuarial

loss (gain)

Settlements loss (gain)
Curtailment loss
Net periodic benefit cost

The components of net periodic benefit cost, other than the service cost component, are included in the “Other
expenses” line item on our consolidated income statement.

We recognized pension settlement losses of $102 million in 2021, $43 million in 2020, and $62 million in 2019 as
lump-sum benefit payments from certain U.S. and international pension plans exceeded the sum of service and
interest costs for those plans and led to recognition of settlement losses.

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 10 percent of the unamortized balance each year.

We have multiple non-pension 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 6.5 percent in 2022 that
declines to 5 percent by 2028. The measurement of the U.S. post-65 retiree medical accumulated postretirement
benefit obligation assumes a health care cost trend rate of 4.25 percent in 2022 that increases to 5 percent by
2028.

ConocoPhillips 2021 10-K 126

Notes to Consolidated Financial Statements

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 22 percent equity securities, 74 percent debt
securities, 3 percent real estate and 1 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, 2021 and 2020.

•

•
•

•

Fair values of equity securities and government debt securities categorized in Level 1 are primarily based
on quoted market prices in active markets for identical assets and liabilities.
Fair values of corporate debt securities, agency and mortgage-backed securities and government debt
securities categorized in Level 2 are estimated using recently executed transactions and quoted market
prices for similar assets and liabilities in active markets and for identical assets and liabilities in markets
that are not active. If there have been no market transactions in a particular fixed income security, its fair
value is calculated by pricing models that benchmark the security against other securities with actual
market prices. When observable quoted market prices are not available, fair value is based on pricing
models that use something other than actual market prices (e.g., observable inputs such as benchmark
yields, reported trades and issuer spreads for similar securities), and these securities are categorized in
Level 3 of the fair value hierarchy.
Fair values of investments in common/collective trusts are determined by the issuer of each fund based
on the fair value of the underlying assets.
Fair values of mutual funds are based on quoted market prices, which represent the net asset value of
shares held.
Time deposits are valued at cost, which approximates fair value.
Cash is valued at cost, which approximates fair value. Fair values of international cash equivalents
categorized in Level 2 are valued using observable yield curves, discounting and interest rates. U.S. cash
balances held in the form of short-term fund units that are redeemable at the measurement date are
categorized as Level 2.
Fair values of exchange-traded derivatives classified in Level 1 are based on quoted market prices. For
other derivatives classified in Level 2, the values are generally calculated from pricing models with market
input parameters from third-party sources.
Fair values of insurance contracts are valued at the present value of the future benefit payments owed by
the insurance company to the plans’ participants.
Fair values of real estate investments are valued using real estate valuation techniques and other
methods that include reference to third-party sources and sales comparables where available.
A portion of U.S. pension plan assets is held as a participating interest in an insurance annuity contract,
which is calculated as the market value of investments held under this contract, less the accumulated
benefit obligation covered by the contract. The participating interest is classified as Level 3 in the fair
value hierarchy as the fair value is determined via a combination of quoted market prices, recently
executed transactions, and an actuarial present value computation for contract obligations. At
December 31, 2021, the participating interest in the annuity contract was valued at $83 million and
consisted of $206 million in debt securities, less $123 million for the accumulated benefit obligation
covered by the contract. At December 31, 2020, the participating interest in the annuity contract was
valued at $94 million and consisted of $233 million in debt securities, less $139 million for the
accumulated benefit obligation covered by the contract. The participating interest is not available for
meeting general pension benefit obligations in the near term. No future company contributions are
required and no new benefits are being accrued under this insurance annuity contract.

127 ConocoPhillips 2021 10-K

Notes to Consolidated Financial Statements

The fair values of our pension plan assets at December 31, by asset class were as follows:

Millions of Dollars

U.S.

Level 1

Level 2

Level 3

Total

Level 1

International
Level 2

Level 3

Total

3
42
17

-
-
-
-
62

-
-
-

1
-
-
-
1

5
-
-

-
-
-
-
5

8
42
17

1
-
-
-
68

394

-
-
236

-
511
68
-
815

-
-
403

-
-
-
-
403

-
-
-

-
-
-
157
157

-
-
639

-
511
68
157
1,375

417

2021
Equity securities

U.S.
International
Mutual funds
Debt securities
Corporate
Mutual funds

Cash and cash equivalents
Real estate

Total in fair value hierarchy

Investments measured at net asset value*
Equity securities

Common/collective trusts

Debt securities

Common/collective trusts

Cash and cash equivalents
Real estate
Total**
*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 $83 million and net receivables related to security
transactions of $5 million.

157

815

403

3,015
-
1
4,808

1,073
9
36
1,580

ConocoPhillips 2021 10-K 128

Notes to Consolidated Financial Statements

The fair values of our pension plan assets at December 31, by asset class were as follows:

Millions of Dollars

U.S.

Level 1

Level 2

Level 3

Total

Level 1

International
Level 2

Level 3

Total

-
99
72

-
-
-
-
-
171

3
-
-

1
-
-
-
-
4

5
-
-

-
-
-
-
-
5

8
99
72

1
-
-
-
-
180

678

-
-
235

-
455
74
6
-
770

-
-
384

-
-
-
-
-
384

-
-
-

-
-
-
-
142
142

-
-
619

-
455
74
6
142
1,296

372

2020
Equity securities

U.S.
International
Mutual funds
Debt securities
Corporate
Mutual funds

Cash and cash equivalents
Derivatives
Real estate

Total in fair value hierarchy

Investments measured at net asset value*
Equity securities

Common/collective trusts

Debt securities

Common/collective trusts

Cash and cash equivalents
Real estate
Total**
*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 $94 million and net receivables related to security
transactions of $7 million.

142

384

770

171

3,007
-
112
4,787

730
8
79
1,675

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 2022, we expect to contribute approximately $115 million
to our domestic qualified and nonqualified pension and postretirement benefit plans and $80 million to our
international qualified and nonqualified pension and postretirement benefit plans.

129 ConocoPhillips 2021 10-K

Notes to Consolidated Financial Statements

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
Benefits

U.S.

Int’l.

Other
Benefits

2022
2023
2024
2025
2026
2027–2031

The following table summarizes our severance accrual activity:

369
185
176
154
144
557

152
152
158
162
164
893

Millions of Dollars

Balance at January 1
Accruals
Benefit payments
Balance at December 31

2021

24
170
(116)
78

2020

23
14
(13)
24

21
18
15
14
12
44

2019

48
(1)
(24)
23

Accruals include severance costs associated with our company-wide restructuring program. Of the remaining
balance at December 31, 2021, $43 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 75 percent of their eligible pay, subject to statutory limits, in the CPSP to a choice of 17 investment options.
Employees who participate in the CPSP and contribute 1 percent of their eligible pay receive a 6 percent company
cash match with a potential company discretionary cash contribution of up to 6 percent. Effective January 1, 2019,
new employees, rehires, and employees that elected to opt out of Title II of the ConocoPhillips Retirement Plan are
eligible to receive a Company Retirement Contribution (CRC) of 6 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 $93 million in 2021, $62 million in 2020, and $82
million in 2019.

We have several defined contribution plans for our international employees, each with its own terms and eligibility
depending on location. Total compensation expense recognized for these international plans was approximately
$26 million in 2021, $25 million in 2020, and $30 million in 2019.

Share-Based Compensation Plans
The 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (the Plan) was approved by
shareholders in May 2014, replacing similar prior plans and providing that no new awards shall be granted under
the prior plans. Over its 10-year life, the Plan allows the issuance of up to 79 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 Plan or 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. Of the 79 million shares available for issuance under the Plan, no more than
40 million shares of common stock are available for incentive stock options. The Human Resources and
Compensation Committee of our Board of Directors is authorized to determine the types, terms, conditions and
limitations of awards granted. Awards may be granted in the form of, but not limited to, stock options, restricted

ConocoPhillips 2021 10-K 130

Notes to Consolidated Financial Statements

stock units and performance share units to employees and non-employee directors who contribute to the
company’s continued success and profitability.

Total share-based compensation expense is measured using the grant date fair value for our equity-classified
awards and the settlement date fair value for our liability-classified awards. We recognize share-based
compensation expense over the shorter of the service period (i.e., the stated period of time required to earn the
award); or the period beginning at the start of the service period and ending when an employee first becomes
eligible for retirement, but not less than six months, as this is the minimum period of time required for an award to
not be subject to forfeiture. Our share-based compensation programs generally provide accelerated vesting (i.e., a
waiver of the remaining period of service required to earn an award) for awards held by employees at the time of
their retirement. Some of our share-based awards vest ratably (i.e., portions of the award vest at different times)
while some of our awards cliff vest (i.e., all of the award vests at the same time). We recognize expense on a
straight-line basis over the service period for the entire award, whether the award was granted with ratable or cliff
vesting.

Compensation Expense—Total share-based compensation expense recognized in net income (loss) and the
associated tax benefit were:

Compensation cost
Tax benefit

Millions of Dollars

2021

304
76

2020

2019

159
40

274
71

Stock Options—Stock options granted under the provisions of the Plan and prior plans permit purchase of our
common stock at exercise prices equivalent to the average fair market value of ConocoPhillips common stock on
the date the options were granted. The options have terms of 10 years and generally vest ratably, with one-third
of the options awarded vesting and becoming exercisable on each anniversary date following the date of grant.
Options awarded to certain employees already eligible for retirement vest within six months of the grant date, but
those options do not become exercisable until the end of the normal vesting period. Beginning in 2018, stock
option grants were discontinued and replaced with three-year, time-vested restricted stock units which generally
will be cash-settled for 2018 and 2019 awards and stock-settled beginning with 2020 awards.

The following summarizes our stock option activity for the year ended December 31, 2021:

Outstanding at December 31, 2020
Exercised
Expired or cancelled
Outstanding at December 31, 2021
Vested at December 31, 2021
Exercisable at December 31, 2021

Options

16,922,525
(3,846,361)
(1,102,381)
11,973,783
11,973,783
11,973,783

Weighted-Average
Exercise Price

Millions of Dollars
Aggregate
Intrinsic Value

$
$
$

55.12
51.40
53.47
56.46
56.46
56.46

$
$
$

22
68

188
188
188

The weighted-average remaining contractual term of outstanding options, vested options and exercisable options
at December 31, 2021, were all 3.06 years. The aggregate intrinsic value of options exercised was $23 million in
2020 and $39 million in 2019.

During 2021, we received $198 million in cash and realized a tax benefit of $15 million from the exercise of
options. At December 31, 2021, all outstanding stock options were fully vested and there was no remaining
compensation cost to be recorded.

131 ConocoPhillips 2021 10-K

Notes to Consolidated Financial Statements

Stock Unit Program—Generally, restricted stock units are granted annually under the provisions of the Plan and
vest in an aggregate installment on the third anniversary of the grant date. In addition, restricted stock units
granted under the Plan for a variable long-term incentive program vest ratably in three equal annual installments
beginning on the first anniversary of the grant date. Restricted stock units are also granted ad hoc to attract or
retain key personnel, and the terms and conditions under which these restricted stock units vest vary by award.

Stock-Settled
Upon vesting, these restricted stock units are settled by issuing one share of ConocoPhillips common stock per
unit. Units awarded to retirement eligible employees vest six months from the grant date; however, those units
are not issued as common stock until the earlier of separation from the company or the end of the regularly
scheduled vesting period. Until issued as stock, most recipients of the restricted stock units receive a cash
payment of a dividend equivalent or an accrued reinvested dividend equivalent that is charged to retained
earnings. The grant date fair market value of these restricted stock units is deemed equal to the average
ConocoPhillips stock price on the grant date. The grant date fair market value of units that do not receive a
dividend equivalent while unvested is deemed equal to the average ConocoPhillips stock price on the grant date,
less the net present value of the dividends that will not be received.

The following summarizes our stock-settled stock unit activity for the year ended December 31, 2021:

Outstanding at December 31, 2020
Granted
Forfeited
Issued
Outstanding at December 31, 2021
Not Vested at December 31, 2021

Stock Units

6,431,985
4,590,103
(566,047)
(2,810,730)
7,645,311
5,509,133

Weighted-Average
Grant Date Fair Value

Millions of Dollars
Total Fair Value

58.94
46.56
48.59
54.74
53.81
53.81

144

At December 31, 2021, the remaining unrecognized compensation cost from the unvested stock-settled units was
$126 million, which will be recognized over a weighted-average period of 1.67 years, the longest period being 2.59
years. The weighted-average grant date fair value of stock unit awards granted during 2020 and 2019 was $57.40
and $67.77, respectively. The total fair value of stock units issued during 2020 and 2019 was $143 million and
$225 million, respectively.

Cash-Settled
Cash settled executive restricted stock units granted in 2018 and 2019 replaced the stock option program. These
restricted stock units, subject to elections to defer, will be settled in cash equal to the fair market value of a share
of ConocoPhillips common stock per unit on the settlement date and are classified as liabilities on the balance
sheet. Units awarded to retirement eligible employees vest six months from the grant date; however, those units
are not settled until the earlier of separation from the company or the end of the regularly scheduled vesting
period. Compensation expense is initially measured using the average fair market value of ConocoPhillips common
stock and is subsequently adjusted, based on changes in the ConocoPhillips stock price through the end of each
subsequent reporting period, through the settlement date. Recipients receive an accrued reinvested dividend
equivalent that is charged to compensation expense. The accrued reinvested dividend is paid at the time of
settlement, subject to the terms and conditions of the award. Beginning with executive restricted stock units
granted in 2020 awards will be settled in stock.

ConocoPhillips 2021 10-K 132

Notes to Consolidated Financial Statements

The following summarizes our cash-settled stock unit activity for the year ended December 31, 2021:

Outstanding at December 31, 2020
Granted
Forfeited
Issued
Outstanding at December 31, 2021
Not Vested at December 31, 2021

Stock Units

614,615
11,186
(2,927)
(396,398)
226,476
59,443

Weighted-Average
Grant Date Fair Value

Millions of Dollars
Total Fair Value

39.95
57.19
51.43
50.75
72.18
72.18

At December 31, 2021, there was no remaining unrecognized compensation cost to be recorded for the unvested
cash-settled units. The weighted-average grant date fair value of stock unit awards granted during 2020 and 2019
were $41.59 and $68.20, respectively. The total fair value of stock units issued during 2020 and 2019 were
negligible and $6 million, respectively.

Performance Share Program—Under the Plan, we also annually grant restricted performance share units (PSUs) to
senior management. These PSUs are authorized three years prior to their effective grant date (the performance
period). Compensation expense is initially measured using the average fair market value of ConocoPhillips
common stock and is subsequently adjusted, based on changes in the ConocoPhillips stock price through the end
of each subsequent reporting period, through the grant date for stock-settled awards and the settlement date for
cash-settled awards.

Stock-Settled
For performance periods beginning before 2009, PSUs do not vest until the employee becomes eligible for
retirement by reaching age 55 with five years of service, and restrictions do not lapse until the employee separates
from the company. With respect to awards for performance periods beginning in 2009 through 2012, PSUs do not
vest until the earlier of the date the employee becomes eligible for retirement by reaching age 55 with five years
of service or five years after the grant date of the award, and restrictions do not lapse until the earlier of the
employee’s separation from the company or five years after the grant date (although recipients can elect to defer
the lapsing of restrictions until separation). We recognize compensation expense for these awards beginning on
the grant date and ending on the date the PSUs are scheduled to vest. Since these awards are authorized three
years prior to the effective 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, 2021:

Stock Units

1,736,728
(287,881)
1,448,847
3,191

Weighted-Average
Grant Date Fair Value

Millions of Dollars
Total Fair Value

$
$

50.56
49.91
50.69
48.61

Outstanding at December 31, 2020
Issued
Outstanding at December 31, 2021
Not Vested at December 31, 2021

133 ConocoPhillips 2021 10-K

Notes to Consolidated Financial Statements

At December 31, 2021, there was no remaining unrecognized compensation cost to be recorded on the unvested
stock-settled performance shares. The weighted-average grant date fair value of stock-settled PSUs granted
during 2020 and 2019 was $58.61 and $68.90, respectively. The total fair value of stock-settled PSUs issued during
2020 and 2019 was $13 million and $25 million, respectively.

Cash-Settled
In connection with and immediately following the separation of our Downstream businesses in 2012, grants of new
PSUs, subject to a shortened performance period, were authorized. Once granted, these PSUs vest, absent
employee election to defer, on the earlier of five years after the grant date of the award or the date the employee
becomes eligible for retirement. For employees eligible for retirement by or shortly after the grant date, we
recognize compensation expense over the period beginning on the date of authorization and ending on the date of
grant. Otherwise, we recognize compensation expense beginning on the grant date and ending on the date the
PSUs are scheduled to vest. These PSUs are settled in cash equal to the fair market value of a share of
ConocoPhillips common stock per unit on the settlement date and thus are classified as liabilities on the balance
sheet. Until settlement occurs, recipients of the PSUs receive a quarterly cash payment of a dividend equivalent
that is charged to compensation expense.

Beginning in 2013, PSUs authorized for future grants will vest upon settlement following the conclusion of the
three-year performance period. We recognize compensation expense over the period beginning on the date of
authorization and ending at the conclusion of the performance period. These PSUs will be settled in cash equal to
the fair market value of a share of ConocoPhillips common stock per unit on the settlement date and are classified
as liabilities on the balance sheet. For performance periods beginning before 2018, during the performance
period, recipients of the PSUs do not receive a quarterly cash payment of a dividend equivalent, but after the
performance period ends, until settlement in cash occurs, recipients of the PSUs receive a quarterly cash payment
of a dividend equivalent that is charged to compensation expense. For the performance period beginning in 2018,
recipients of the PSUs receive an accrued reinvested dividend equivalent that is charged to compensation expense.
The accrued reinvested dividend is paid at the time of settlement, subject to the terms and conditions of the
award.

The following summarizes our cash-settled Performance Share Program activity for the year ended
December 31, 2021:

Outstanding at December 31, 2020
Granted
Settled
Outstanding at December 31, 2021

Stock Units

124,529
1,073,228
(1,080,078)
117,679

Weighted-Average
Grant Date Fair Value

Millions of Dollars
Total Fair Value

39.95
46.65
48.13
72.18

At December 31, 2021, all outstanding cash-settled performance awards were fully vested and there was no
remaining compensation cost to be recorded. The weighted-average grant date fair value of cash-settled PSUs
granted during 2020 and 2019 was $58.61 and $68.90, respectively. The total fair value of cash-settled
performance share awards settled during 2020 and 2019 was $116 million and $171 million, respectively.

ConocoPhillips 2021 10-K 134

Notes to Consolidated Financial Statements

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, as part of an executive compensation program that has
been discontinued or acquired as a result of an acquisition. Generally, the recipients of the restricted shares or
units receive a dividend or dividend equivalent.

The following summarizes the aggregate activity of these restricted shares and units for the year ended
December 31, 2021:

Outstanding at December 31, 2020
Granted
Cancelled
Issued
Outstanding at December 31, 2021
Not Vested at December 31, 2021

Stock Units

970,099
797,704
(1,948)
(149,488)
1,616,367
695,958

Weighted-Average
Grant Date Fair Value

Millions of Dollars
Total Fair Value

$
$

47.78
46.43
27.80
46.80
47.24
45.87

At December 31, 2021, the remaining compensation cost from the unvested restricted stock was $20 million,
which will be recognized over a weighted-average period of 1.46 years, the longest period being 2 years. The
weighted-average grant date fair value of awards granted during 2020 and 2019 was $51.46 and $63.58,
respectively. The total fair value of awards issued during 2020 and 2019 was $6 million and $11 million,
respectively.

135 ConocoPhillips 2021 10-K

Notes to Consolidated Financial Statements

Note 17—Income Taxes
Components of income tax provision (benefit) were:

Income Taxes
Federal

Current
Deferred

Foreign

Current
Deferred
State and local

Current
Deferred

Total tax provision (benefit)

Millions of Dollars

2021

2020

32
1,161

3,128
66

127
119
4,633

3
(625)

350
(70)

(4)
(139)
(485)

2019

18
(113)

2,545
(323)

148
(8)
2,267

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

Deferred Tax Liabilities
PP&E and intangibles
Inventory
Other
Total deferred tax liabilities

Deferred Tax Assets
Benefit plan accruals
Asset retirement obligations and accrued environmental costs
Investments in joint ventures
Other financial accruals and deferrals
Loss and credit carryforwards
Other
Total deferred tax assets
Less: valuation allowance
Total deferred tax assets net of valuation allowance
Net deferred tax liabilities

2021

10,170
44
213
10,427

321
2,297
1,684
827
7,402
399
12,930
(8,342)
4,588
5,839

2020

7,744
64
242
8,050

540
2,262
1,653
907
8,904
365
14,631
(9,965)
4,666
3,384

At December 31, 2021, noncurrent assets and liabilities included deferred taxes of $340 million and $6,179 million,
respectively. At December 31, 2020, noncurrent assets and liabilities included deferred taxes of $363 million and
$3,747 million, respectively.

At December 31, 2021, the loss and credit carryforward deferred tax assets were primarily related to U.S. foreign
tax credit carryforwards of $5.5 billion and various jurisdictions net operating loss and credit carryforwards of $1.9
billion. If not utilized, U.S. foreign tax credits and net operating losses will begin to expire in 2022.

Our overall deferred tax liability increased during 2021 by $1.1 billion due to our Concho acquisition. See Note 3.

ConocoPhillips 2021 10-K 136

Notes to Consolidated Financial Statements

The following table shows a reconciliation of the beginning and ending deferred tax asset valuation allowance for
for 2021, 2020 and 2019:

Millions of Dollars

2021

2020

2019

3,040
Balance at January 1
(225)
Charged to expense (benefit)
7,399
Other*
Balance at December 31
10,214
*Represents changes due to originating deferred tax asset that have no impact to our effective tax rate, acquisitions/dispositions/revisions and
the effect of translating foreign financial statements.

10,214
460
(709)
9,965

9,965
(45)
(1,578)
8,342

Valuation allowances have been established to reduce deferred tax assets to an amount that will, more likely than
not, be realized. At December 31, 2021, we have maintained a valuation allowance with respect to substantially all
U.S. foreign tax credit carryforwards as well as certain net operating loss carryforwards for various jurisdictions.
During 2021, the valuation allowance movement charged to earnings primarily relates to the fair value
measurement of our CVE common shares that are not expected to be realized, and the expected realization of
certain U.S. tax attributes associated with our planned disposition of our Indonesia assets. This is partially offset
by Australian tax benefits associated with our impairment of APLNG that we do not expect to be realized. Other
movements are primarily related to valuation allowances on expiring tax attributes. Based on our historical
taxable income, expectations for the future, and available tax-planning strategies, management expects deferred
tax assets, net of valuation allowances, will primarily be realized as offsets to reversing deferred tax liabilities. For
more information on our pending Indonesia disposition see Note 3.

During 2020, the valuation allowance movement charged to earnings primarily related to capital losses in Australia
and to the fair value measurement of our CVE common shares that are not expected to be realized. Other
movements are primarily related to valuation allowances on expiring tax attributes.

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, 2021, unremitted income considered to be permanently reinvested in certain foreign subsidiaries
and foreign corporate joint ventures totaled approximately $4,384 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 $219 million.

137 ConocoPhillips 2021 10-K

Notes to Consolidated Financial Statements

The following table shows a reconciliation of the beginning and ending unrecognized tax benefits for 2021,
2020 and 2019:

Balance at January 1
Additions based on tax positions related to the current year
Additions for tax positions of prior years
Reductions for tax positions of prior years
Settlements
Lapse of statute
Balance at December 31

Millions of Dollars

2021

2020

2019

1,206
15
177
(5)
-
(48)
1,345

1,177
6
67
(34)
(9)
(1)
1,206

1,081
9
120
(22)
(9)
(2)
1,177

Included in the balance of unrecognized tax benefits for 2021, 2020 and 2019 were $1,261 million, $1,128 million
and $1,100 million, respectively, which, if recognized, would impact our effective tax rate. The balance of the
unrecognized tax benefits increased in 2021 mainly due to U.S. tax credits acquired through our Concho
acquisition. The balance of the unrecognized tax benefits increased in 2019 mainly due to the treatment of our
PDVSA settlement. See Note 3 and Note 11.

At December 31, 2021, 2020 and 2019, accrued liabilities for interest and penalties totaled $47 million, $46 million
and $42 million, respectively, net of accrued income taxes. Interest and penalties resulted in a reduction to
earnings of $1 million in 2021, a reduction of $4 million in 2020, and benefit to earnings of $3 million in 2019.

We file tax returns in the U.S. federal jurisdiction and in many foreign and state jurisdictions. Audits in major
jurisdictions are generally complete as follows: Canada (2016), U.S. (2017) and Norway (2020). Issues in dispute
for audited years and audits for subsequent years are ongoing and in various stages of completion in the many
jurisdictions in which we operate around the world. Consequently, the balance in unrecognized tax benefits can
be expected to fluctuate from period to period. Within the next twelve months, we may have audit periods close
that could significantly impact our total unrecognized tax benefits. It is reasonably possible such changes could be
significant when compared with our total unrecognized tax benefits, but the amount of change is not estimable.

In January 2022, the IRS closed the 2017 audit of our U.S. federal income tax return. As a result, in the first quarter
of 2022, we will recognize a previously unrecognized $475 million federal tax benefit related to the recovery of
outside tax basis previously offset by a full reserve.

ConocoPhillips 2021 10-K 138

Notes to Consolidated Financial Statements

The amounts of U.S. and foreign income (loss) before income taxes, with a reconciliation of tax at the federal
statutory rate to the provision for income taxes, were:

Millions of Dollars

Percent of Pre-Tax Income (Loss)

2021

2020

2019

2021

2020

2019

Income (loss) before income taxes

United States
Foreign

Federal statutory income tax
Non-U.S. effective tax rates
Tax impact of debt restructuring
Australia disposition
U.K. disposition
Recovery of outside basis
Adjustment to tax reserves
Adjustment to valuation allowance
State income tax
Malaysia Deepwater Incentive
Enhanced oil recovery credit
Other
Total

8,024
4,688
12,712

(3,587)
447
(3,140)

2,670
1,915
75
-
-
(55)
(11)
(45)
194
-
(99)
(11)
4,633

(659)
194
-
(349)
-
(22)
18
460
(112)
-
(6)
(9)
(485)

4,704
4,820
9,524

2,000
1,399
-
-
(732)
(77)
9
(225)
123
(164)
(27)
(39)
2,267

63.1 %
36.9
100.0 %

21.0 %
15.1
0.6
-
-
(0.4)
(0.1)
(0.4)
1.5
-
(0.8)
(0.1)
36.4 %

114.2
(14.2)
100.0

21.0
(6.2)
-
11.1
-
0.7
(0.6)
(14.6)
3.6
-
0.2
0.3
15.5

49.4
50.6
100.0

21.0
14.7
-
-
(7.7)
(0.8)
0.1
(2.4)
1.3
(1.7)
(0.3)
(0.4)
23.8

Our effective tax rate for 2021 was driven by our jurisdictional tax rates for this profit mix with net favorable
impacts from routine tax credits and valuation allowance adjustments. The valuation allowance adjustment is
primarily related to the fair value measurement and disposition of our CVE common shares of $218 million and the
ability to utilize the U.S. foreign tax credit and capital loss carryforward due to our anticipated disposition of our
Indonesia entities of $29 million. This was partially offset by an increase to our valuation allowance related to the
tax impact of the impairment of our APLNG investment of $206 million for which we do not expect to receive a tax
benefit.

Our effective tax rate for 2020 was impacted by the disposition of our Australia-West assets as well as the
valuation allowance related to the fair value measurement of our CVE common shares. The Australia-West
disposition generated a before-tax gain of $587 million with an associated tax benefit of $10 million and resulted in
the de-recognition of deferred tax assets resulting in $92 million of tax expense. The disposition also generated an
Australia capital loss tax benefit of $313 million which has been fully offset by a valuation allowance. Due to
changes in the fair market value of CVE common shares, the valuation allowance was increased by $178 million to
offset the expected capital loss.

Our effective tax rate for 2019 was favorably impacted by the sale of two of our U.K. subsidiaries. The disposition
generated a before-tax gain of more than $1.7 billion with an associated tax benefit of $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 3.

During 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.

139

ConocoPhillips 2021 10-K

Notes to Consolidated Financial Statements

Note 18—Accumulated Other Comprehensive Loss
Accumulated other comprehensive loss in the equity section of the balance sheet included:

Millions of Dollars

Net
Unrealized
Gain/(Loss)
on Securities

Foreign
Currency
Translation

Accumulated
Other
Comprehensive
Loss

Defined
Benefit Plans

(6,063)
December 31, 2018
746
Other comprehensive income (loss)
(40)
Cumulative effect of adopting ASU No. 2018-02*
(5,357)
December 31, 2019
139
Other comprehensive income
(5,218)
December 31, 2020
268
Other comprehensive income (loss)
December 31, 2021
(4,950)
*We adopted ASU No. 2018-02, "Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income," beginning January 1,
2019.

(5,702)
695
-
(5,007)
212
(4,795)
(124)
(4,919)

(361)
51
(40)
(350)
(75)
(425)
394
(31)

-
-
-
-
2
2
(2)
-

During 2019, we recognized $483 million of foreign currency translation adjustments related to the completion of
our sale of two ConocoPhillips U.K. subsidiaries. See Note 3.

The following table summarizes reclassifications out of accumulated other comprehensive loss during the years
ended December 31:

Defined Benefit Plans
Above amounts are included in the computation of net periodic benefit cost and
are presented net of tax expense of:
See Note 16.

Millions of Dollars

2021

109

2020

ConocoPhillips 2021 10-K 140

Notes to Consolidated Financial Statements

Note 19—Cash Flow Information

Noncash Investing Activities
Increase (decrease) in PP&E related to an increase (decrease) in asset

retirement obligations

Cash Payments
Interest
Income taxes

Net Sales (Purchases) of Investments
Short-term investments purchased
Short-term investments sold
Investments and long-term receivables purchased
Investments and long-term receivables sold

Millions of Dollars

2021

2020

2019

442

(116)

205

924
856

785
905

810
2,905

(5,554)
8,810
(279)
114
3,091

(12,435)
12,015
(325)
87
(658)

(4,902)
2,138
(146)
-
(2,910)

The following items are included in the “Cash Flows from Operating Activities” section of our consolidated cash
flows.

In 2021, we made a total of $297 million in contributions to our U.S. qualified pension plan. In 2019, we made a
$324 million contribution to our U.K. pension plan.

We collected $330 million in 2019 from PDVSA under settlement agreements related to an award issued by the ICC
Tribunal in 2018. For more information on these settlements, see Note 11.

See Note 3 and Note 12 for additional information on cash and non-cash changes to our consolidated balance
sheet associated with our Concho acquisition.

141 ConocoPhillips 2021 10-K

Notes to Consolidated Financial Statements

Note 20—Other Financial Information

Interest and Debt Expense
Incurred
Debt
Other

Capitalized
Expensed

Other Income (Loss)
Interest income
Gain (loss) on investment in Cenovus Energy*
Other, net

*See Note 5.

Research and Development Expenditures—expensed

Shipping and Handling Costs

Foreign Currency Transaction (Gains) Losses—after-tax
Alaska
Lower 48
Canada
Europe, Middle East and North Africa
Asia Pacific
Other International
Corporate and Other

Properties, Plants and Equipment
Proved properties*
Unproved properties*
Other
Gross properties, plants and equipment
Less: Accumulated depreciation, depletion and amortization
Net properties, plants and equipment

Millions of Dollars

2021

2020

2019

887
59
946
(62)
884

33
1,040
130
1,203

1,047

-
-
(1)
(11)
2
1
(7)
(16)

788
73
861
(55)
806

100
(855)
246
(509)

857

-
-
(7)
(15)
(11)
2
(31)
(62)

799
36
835
(57)
778

166
649
543
1,358

1,008

-
-
5
-
31
1
21
58

Millions of Dollars

2021

2020

114,274 **
10,993
4,379
129,646
(64,735)**
64,911

94,312
4,141
3,653
102,106
(62,213)
39,893

*Proved and Unproved properties increased by $20.0 billion and $6.9 billion, respectively, in 2021 compared with 2020, primarily due to

the Concho and Shell Permian acquisitions.

**Excludes assets classified as held for sale at December 31, 2021. See Note 3.

ConocoPhillips 2021 10-K 142

Notes to Consolidated Financial Statements

Note 21—Related Party Transactions
Our related parties primarily include equity method investments and certain trusts for the benefit of employees.
For disclosures on trusts for the benefit of employees, see Note 16.

Significant transactions with our equity affiliates were:

Millions of Dollars

2021

2020

2019

Operating revenues and other income
Purchases
Operating expenses and selling, general and administrative expenses
Net interest income*
*We paid interest to, or received interest from, various affiliates. See Note 4, for additional information on loans to
affiliated companies.

88
5
196
(2)

79
-
63
(5)

89
38
65
(13)

Note 22—Sales and Other Operating Revenues
Revenue from Contracts with Customers
The following table provides further disaggregation of our consolidated sales and other operating revenues:

Revenue from contracts with customers
Revenue from contracts outside the scope of ASC Topic 606
Physical contracts meeting the definition of a derivative
Financial derivative contracts

Consolidated sales and other operating revenues

Millions of Dollars

2021

2020

2019

34,590

13,662

26,106

11,500
(262)
45,828

5,177
(55)
18,784

6,558
(97)
32,567

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 23—Segment Disclosures and Related Information:

Revenue from Outside the Scope of ASC Topic 606
by Segment
Lower 48
Canada
Europe, Middle East and North Africa
Physical contracts meeting the definition of a derivative

Revenue from Outside the Scope of ASC Topic 606
by Product
Crude oil
Natural gas
Other
Physical contracts meeting the definition of a derivative

143

ConocoPhillips 2021 10-K

Millions of Dollars

2021

2020

2019

9,050
1,457
993
11,500

3,966
727
484
5,177

4,989
691
878
6,558

Millions of Dollars

2021

2020

2019

757
10,034
709
11,500

395
4,339
443
5,177

804
5,313
441
6,558

Notes to Consolidated Financial Statements

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, 2021, the “Accounts and notes receivable” line on our consolidated balance sheet included trade
receivables of $5,268 million compared with $1,827 million at December 31, 2020, 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.

Contract Liabilities
At December 31, 2020
Contractual payments received
Revenue recognized
At December 31, 2021

Amounts Recognized in the Consolidated Balance Sheet at December 31, 2021
Current liabilities

Millions of Dollars

97
15
(62)
50

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

ConocoPhillips 2021 10-K 144

Notes to Consolidated Financial Statements

Note 23—Segment Disclosures and Related Information
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on a worldwide
basis. We manage our operations through six operating segments, which are primarily defined by geographic
region: Alaska; Lower 48; Canada; Europe, Middle East and North Africa; Asia Pacific; and Other International.

Corporate and Other represents income and costs not directly associated with an operating segment, such as most
interest expense, premiums on early retirement of debt, corporate overhead and certain technology activities,
including licensing revenues. Corporate assets include all cash and cash equivalents and short-term investments.

We evaluate performance and allocate resources based on net income (loss) attributable to ConocoPhillips.
Segment accounting policies are the same as those in Note 1. Intersegment sales are at prices that approximate
market.

In 2021, we completed our acquisition of Concho, an independent oil and gas exploration and production company
with operations across New Mexico and West Texas as well as our acquisition of Shell’s Permian assets in the Texas
Delaware Basin. The accounting close date of the Shell transaction, used for reporting purposes, was December
31, 2021. Results of operations for Concho and assets acquired from Shell are included in our Lower 48 segment.
Certain transaction and restructuring costs associated with these acquisitions are included in our Corporate and
Other segment. See Note 3.

Analysis of Results by Operating Segment

Sales and Other Operating Revenues
Alaska
Intersegment eliminations

Alaska
Lower 48
Intersegment eliminations

Lower 48

Canada
Intersegment eliminations

Canada

Europe, Middle East and North Africa
Intersegment eliminations

Europe, Middle East and North Africa

Asia Pacific
Other International
Corporate and Other
Consolidated sales and other operating revenues

Millions of Dollars

2021

2020

2019

5,480
-
5,480
29,306
(12)
29,294
4,077
(1,583)
2,494
5,902
-
5,902
2,579
4
75
45,828

3,408
(11)
3,397
9,872
(51)
9,821
1,666
(405)
1,261
1,919
(2)
1,917
2,363
7
18
18,784

5,483
-
5,483
15,514
(46)
15,468
2,910
(1,141)
1,769
5,101
-
5,101
4,525
-
221
32,567

The market for our products is large and diverse, therefore, our sales and other operating revenues are not
dependent upon any single customer.

145 ConocoPhillips 2021 10-K

Notes to Consolidated Financial Statements

Depreciation, Depletion, Amortization and Impairments
Alaska
Lower 48
Canada
Europe, Middle East and North Africa
Asia Pacific
Other International
Corporate and Other
Consolidated depreciation, depletion, amortization and impairments $

Equity in Earnings of Affiliates
Alaska
Lower 48
Canada
Europe, Middle East and North Africa
Asia Pacific
Other International
Corporate and Other
Consolidated equity in earnings of affiliates

Income Tax Provision (Benefit)
Alaska
Lower 48
Canada
Europe, Middle East and North Africa
Asia Pacific
Other International
Corporate and Other
Consolidated income tax provision (benefit)

Net Income (Loss) Attributable to ConocoPhillips
Alaska
Lower 48
Canada
Europe, Middle East and North Africa
Asia Pacific
Other International
Corporate and Other
Consolidated net income (loss) attributable to ConocoPhillips

Millions of Dollars
2020

2021

1,002
4,067
392
862
1,483
-
76
7,882

5
(18)
-
502
343
-
-
832

402
1,390
150
2,543
483
(53)
(282)
4,633

1,386
4,932
458
1,167
453
(107)
(210)
8,079

996
3,358
342
775
809
-
54
6,334

(7)
(11)
-
311
137
2
-
432

(256)
(378)
(185)
136
294
(20)
(76)
(485)

(719)
(1,122)
(326)
448
962
(64)
(1,880)
(2,701)

2019

805
3,224
232
887
1,285
-
62
6,495

7
(159)
-
470
461
-
-
779

472
137
(43)
1,425
501
8
(233)
2,267

1,520
436
279
3,170
1,483
263
38
7,189

ConocoPhillips 2021 10-K 146

Notes to Consolidated Financial Statements

Investments in and Advances to Affiliates
Alaska
Lower 48
Canada
Europe, Middle East and North Africa
Asia Pacific
Other International
Corporate and Other
Consolidated investments in and advances to affiliates

Total Assets
Alaska
Lower 48
Canada
Europe, Middle East and North Africa
Asia Pacific
Other International
Corporate and Other
Consolidated total assets

Capital Expenditures and Investments
Alaska
Lower 48
Canada
Europe, Middle East and North Africa
Asia Pacific
Other International
Corporate and Other
Consolidated capital expenditures and investments

Interest Income and Expense
Interest income

Alaska
Lower 48
Canada
Europe, Middle East and North Africa
Asia Pacific
Other International
Corporate and Other
Interest and debt expense
Corporate and Other

Sales and Other Operating Revenues by Product
Crude oil
Natural gas
Natural gas liquids
Other*
Consolidated sales and other operating revenues by product
*Includes LNG and bitumen.

147 ConocoPhillips 2021 10-K

Millions of Dollars

2021

2020

2019

58
242
-
797
5,603
1
-
6,701

14,812
41,699
7,439
9,125
9,840
1
7,745
90,661

982
3,129
203
534
390
33
53
5,324

-
-
-
2
9
-
22

62
25
-
918
6,705
-
-
7,710

14,623
11,932
6,863
8,756
11,231
226
8,987
62,618

1,038
1,881
651
600
384
121
40
4,715

-
-
-
5
7
-
88

884

806

83
35
-
1,070
7,265
-
-
8,453

15,453
14,425
6,350
9,269
13,568
285
11,164
70,514

1,513
3,394
368
708
584
8
61
6,636

-
-
-
11
6
-
149

778

23,648
16,904
1,668
3,608
45,828

9,736
6,427
528
2,093
18,784

18,482
8,715
814
4,556
32,567

Notes to Consolidated Financial Statements

Geographic Information

Sales and Other Operating Revenues(1)

Long-Lived Assets(2)

2021

2020

2019

2021

2020

2019

Millions of Dollars

34,847

United States
Australia and Timor-Leste
Canada
China
Indonesia(3)
Libya
Malaysia
Norway
United Kingdom
Other foreign countries
Worldwide consolidated
(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) Met held for sale criteria in 2021 in conjunction with our agreement to sell our subsidiary holding our Indonesia assets.

13,230
605
1,261
460
689
155
610
1,426
336
12
18,784

21,159
1,647
1,769
772
875
1,103
1,230
2,349
1,649
14
32,567

50,580
5,579
6,608
1,476
28
659
1,252
4,681
1
748
71,612

2,494
724
879
1,102
975
2,563
2,236
8
45,828

24,034
6,676
6,385
1,491
464
670
1,501
5,294
1
1,087
47,603

26,566
7,228
5,769
1,447
605
668
1,871
5,258
2
1,308
50,722

ConocoPhillips 2021 10-K 148

Supplementary Data

Oil and Gas Operations (Unaudited)

In accordance with FASB ASC Topic 932, “Extractive Activities—Oil and Gas,” and regulations of the SEC, we are
making certain supplemental disclosures about our oil and gas exploration and production operations.

These disclosures include information about our consolidated oil and gas activities and our proportionate share of
our equity affiliates’ oil and gas activities in our operating segments. As a result, amounts reported as equity
affiliates in Oil and Gas Operations may differ from those shown in the individual segment disclosures reported
elsewhere in this report. Our disclosures by geographic area include the U.S., Canada, Europe, Asia Pacific/Middle
East (inclusive of equity affiliates), and Africa.

As required by current authoritative guidelines, the estimated future date when an asset will be permanently shut
down for economic reasons is based on historical 12-month first-of-month average prices and current costs. This
estimated date when production will end affects the amount of estimated reserves. Therefore, as prices and cost
levels change from year to year, the estimate of proved reserves also changes. Generally, our proved reserves
decrease as prices decline and increase as prices rise.

Our proved reserves include estimated quantities related to PSCs, which are reported under the “economic
interest” method, as well as variable-royalty regimes, and are subject to fluctuations in commodity prices,
recoverable operating expenses and capital costs. If costs remain stable, reserve quantities attributable to
recovery of costs will change inversely to changes in commodity prices. For example, if prices increase, then our
applicable reserve quantities would decline. At December 31, 2021, approximately 4 percent of our total proved
reserves were under PSCs, located in our Asia Pacific/Middle East geographic reporting area, and 5 percent of our
total proved reserves were under a variable-royalty regime, located in our Canada geographic reporting area.

Reserves Governance
The recording and reporting of proved reserves are governed by criteria established by regulations of the SEC and
FASB. Proved reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data,
can be estimated with reasonable certainty to be economically producible—from a given date forward, from
known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior
to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is
reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The
project to extract the hydrocarbons must have commenced or the operator must be reasonably certain it will
commence the project within a reasonable time.

Proved reserves are further classified as either developed or undeveloped. Proved developed reserves are proved
reserves that can be expected to be recovered through existing wells with existing equipment and operating
methods, or in which the cost of the required equipment is relatively minor compared with the cost of a new well,
and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if
the extraction is by means not involving a well. Proved undeveloped reserves are proved reserves expected to be
recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is
required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development
spacing areas that are reasonably certain of production when drilled, unless evidence provided by reliable
technologies exists that establishes reasonable certainty of economic producibility at greater distances. As defined
by SEC regulations, reliable technologies may be used in reserve estimation when they have been demonstrated in
the field to provide reasonably certain results with consistency and repeatability in the formation being evaluated
or in an analogous formation. The technologies and data used in the estimation of our proved reserves include, but
are not limited to, performance-based methods, volumetric-based methods, geologic maps, seismic interpretation,
well logs, well test data, core data, analogy and statistical analysis.

149 ConocoPhillips 2021 10-K

Supplementary Data

We have a company-wide, 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 2021, our processes and controls used to assess over 90 percent of proved reserves as of December 31,
2021, 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, 2021, proved reserves for the properties reviewed are in accordance with the SEC reserves
definitions. D&M’s report is included as Exhibit 99 of this Annual Report on Form 10-K.

The technical person primarily responsible for overseeing the processes and internal controls used in the
preparation of the company’s reserves estimates is the Manager of Reserves Compliance and Reporting. This
individual holds a master’s degree in petroleum engineering. He is a member of the Society of Petroleum
Engineers with over 25 years of oil and gas industry experience and has held positions of increasing responsibility
in reservoir engineering, subsurface and asset management in the U.S. and several international field locations.

Engineering estimates of the quantities of proved reserves are inherently imprecise. See the “Critical Accounting
Estimates” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for
additional discussion of the sensitivities surrounding these estimates.

ConocoPhillips 2021 10-K 150

Supplementary Data

Proved Reserves

Years Ended
December 31

Developed and Undeveloped
Consolidated operations
End of 2018
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2019
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2020
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2021

Equity affiliates
End of 2018
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2019
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2020
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2021

Total company
End of 2018
End of 2019
End of 2020
End of 2021

151 ConocoPhillips 2021 10-K

Crude Oil
Millions of Barrels

Lower
48

Total
U.S.

Canada

Europe

Asia Pacific/
Middle East

Africa

Total

703
(36)
-
1
226
(95)
(2)
797
(126)
-
5
108
(77)
(14)
693
(52)
-
691
289
(160)
(9)
1,452

1,936
4
7
1
251
(169)
(2)
2,028
(423)
-
5
118
(142)
(14)
1,572
157
1
691
299
(224)
(9)
2,487

-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-

4
(1)
-
-
2
-
-
5
(2)
-
3
3
(2)
(1)
6
2
-
-
5
(3)
-
10

-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-

246
18
-
-
-
(36)
(30)
198
4
-
-
-
(28)
-
174
14
-
-
2
(29)
-
161

-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-

159
(5)
-
-
11
(31)
-
134
(4)
3
-
-
(25)
-
108
37
-
-
1
(24)
-
122

78
-
-
-
-
(5)
-
73
-
-
-
-
(5)
-
68
-
-
-
-
(5)
-
63

188
23
-
-
-
(14)
-
197
(3)
-
-
-
(3)
-
191
6
-
-
-
(13)
-
184

-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-

2,533
39
7
1
264
(250)
(32)
2,562
(428)
3
8
121
(200)
(15)
2,051
216
1
691
307
(293)
(9)
2,964

78
-
-
-
-
(5)
-
73
-
-
-
-
(5)
-
68
-
-
-
-
(5)
-
63

Alaska

1,233
40
7
-
25
(74)
-
1,231
(297)
-
-
10
(65)
-
879
209
1
-
10
(64)
-
1,035

-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-

1,233
1,231
879
1,035

703
797
693
1,452

1,936
2,028
1,572
2,487

4
5
6
10

246
198
174
161

237
207
176
185

188
197
191
184

2,611
2,635
2,119
3,027

Supplementary Data

Years Ended
December 31

Developed
Consolidated operations
End of 2018
End of 2019
End of 2020
End of 2021

Equity affiliates
End of 2018
End of 2019
End of 2020
End of 2021

Undeveloped
Consolidated operations
End of 2018
End of 2019
End of 2020
End of 2021

Equity affiliates
End of 2018
End of 2019
End of 2020
End of 2021

Crude Oil
Millions of Barrels

Alaska

Lower
48

Total
U.S.

Canada

Europe

Asia Pacific/
Middle East

Africa

Total

1,058
1,048
765
912

-
-
-
-

175
183
114
123

-
-
-
-

346
334
263
916

-
-
-
-

357
463
430
536

-
-
-
-

1,404
1,382
1,028
1,828

-
-
-
-

532
646
544
659

-
-
-
-

2
3
6
4

-
-
-
-

2
2
-
6

-
-
-
-

192
149
129
122

-
-
-
-

54
49
45
39

-
-
-
-

113
94
77
98

78
73
68
63

46
40
31
24

-
-
-
-

185
181
175
171

1,896
1,809
1,415
2,223

-
-
-
-

3
16
16
13

-
-
-
-

78
73
68
63

637
753
636
741

-
-
-
-

Notable changes in proved crude oil reserves in the three years ended December 31, 2021, included:

•

Revisions: In 2021, Alaska upward revisions were primarily driven by higher prices. Downward revisions in Lower 48 were
due to development timing for specific well locations from unconventional plays of 203 million barrels and technical
revisions of 35 million barrels, partially offset by upward revisions due to higher prices of 115 million barrels and additional
infill drilling in the unconventional plays of 71 million barrels. Upward revisions in Europe were primarily due to higher
prices. In Asia Pacific/Middle East, increases were due to higher prices of 21 million barrels and technical revisions of 16
million barrels.

In 2020, Alaska downward revisions were primarily driven by lower prices of 243 million barrels and development plan
changes of 54 million barrels. Downward revisions in Lower 48 were due to lower prices of 89 million barrels and
development timing for specific well locations from unconventional plays of 82 million barrels, partially offset by upward
technical revisions and additional infill drilling in the unconventional plays of 45 million barrels.

In 2019, Alaska upward revisions were due to cost and technical revisions of 74 million barrels, partially offset by downward
price revisions of 34 million barrels. Upward revisions in Europe and Africa were primarily due to infill drilling and technical
revisions. Downward revisions in Lower 48 were due to changes in development timing for specific well locations from the
unconventional plays of 71 million barrels and price revisions of 22 million barrels, partially offset by upward revisions
related to infill drilling and improved well performance of 57 million barrels.

ConocoPhillips 2021 10-K 152

Supplementary Data

•

Purchases: In 2021, Lower 48 purchases were due to the Concho and Shell Permian acquisitions.

Extensions and discoveries: In 2021, extensions and discoveries in Lower 48 were due to planned development to add
specific well locations from the unconventional plays which more than offset the decreases resulting from development
plan timing in the revisions category.

In 2020, extensions and discoveries in Lower 48 were due to planned development to add specific well locations from the
unconventional plays which more than offset the decreases resulting from development plan timing in the revisions
category.

In 2019, extensions and discoveries in Lower 48 were due to planned development to add specific well locations from the
unconventional plays which more than offset the decreases in the revisions category. In Asia Pacific/Middle East, increases
were due to sanctioning of development programs in China and Malaysia.

•

Sales: In 2019, Europe sales represent the disposition of the U.K. assets.

153 ConocoPhillips 2021 10-K

Supplementary Data

Years Ended
December 31

Total company
End of 2018
End of 2019
End of 2020
End of 2021

Natural Gas Liquids
Millions of Barrels

Alaska

Lower
48

Total
U.S.

Canada

Europe

Asia Pacific/
Middle East

Total

106
(1)
-
-
-
(5)
-
100
-
-
-
-
(6)
-
94
(6)
-
-
-
(6)
-
82

-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-

222
(11)
-
-
62
(28)
-
245
(26)
-
2
41
(27)
(5)
230
213
-
72
82
(50)
(1)
546

-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-

328
(12)
-
-
62
(33)
-
345
(26)
-
2
41
(33)
(5)
324
207
-
72
82
(56)
(1)
628

-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-

106
100
94
82

222
245
230
546

328
345
324
628

1
-
-
-
1
-
-
2
-
-
2
1
(1)
-
4
-
-
-
2
(1)
-
5

-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-

1
2
4
5

17
3
-
-
-
(3)
(4)
13
1
-
-
-
(2)
-
12
1
-
-
-
(2)
-
11

-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-

17
13
12
11

3
(1)
-
-
-
(1)
-
1
(1)
-
-
-
-
-
-
-
-
-
-
-
-
-

42
-
-
-
-
(3)
-
39
-
-
-
-
(3)
-
36
-
-
-
-
(3)
-
33

45
40
36
33

349
(10)
-
-
63
(37)
(4)
361
(26)
-
4
42
(36)
(5)
340
208
-
72
84
(59)
(1)
644

42
-
-
-
-
(3)
-
39
-
-
-
-
(3)
-
36
-
-
-
-
(3)
-
33

391
400
376
677

ConocoPhillips 2021 10-K 154

Supplementary Data

Years Ended
December 31

Developed
Consolidated operations
End of 2018
End of 2019
End of 2020
End of 2021

Equity affiliates
End of 2018
End of 2019
End of 2020
End of 2021

Undeveloped
Consolidated operations
End of 2018
End of 2019
End of 2020
End of 2021

Equity affiliates
End of 2018
End of 2019
End of 2020
End of 2021

Natural Gas Liquids
Millions of Barrels

Alaska

Lower
48

Total
U.S.

Canada

Europe

Asia Pacific/
Middle East

Total

106
100
94
82

-
-
-
-

97
99
83
334

-
-
-
-

125
146
147
212

-
-
-
-

203
199
177
416

-
-
-
-

125
146
147
212

-
-
-
-

-
1
4
3

-
-
-
-

1
1
-
2

-
-
-
-

15
10
9
9

-
-
-
-

2
3
3
2

-
-
-
-

3
1
-
-

42
39
36
33

-
-
-
-

221
211
190
428

42
39
36
33

128
150
150
216

-
-
-
-

Notable changes in proved NGL reserves in the three years ended December 31, 2021, included:

•

Revisions: In 2021, upward revisions in Lower 48 were due to conversion of acquired Concho Permian two-stream contracts
to a three-stream (crude oil, natural gas and natural gas liquids) basis, adding 182 million barrels, additional infill drilling in
the unconventional plays of 44 million barrels, technical revisions of 21 million barrels and higher prices of 28 million
barrels, partially offset by downward revisions related to development timing for specific well locations from
unconventional plays of 62 million barrels.

In 2020, downward revisions in Lower 48 were due to lower prices of 33 million barrels and development timing for specific
well locations from unconventional plays of 20 million barrels, partially offset by upward technical revisions and additional
infill drilling in the unconventional plays of 27 million barrels.

In 2019, downward revisions in Lower 48 were due to changes in development timing for specific well locations from the
unconventional plays of 32 million barrels and price revisions of 11 million barrels, partially offset by upward revisions
related to infill drilling and improved well performance of 32 million barrels.

Purchases: In 2021, Lower 48 purchases were due to the Shell Permian acquisition.

In 2020, extensions and discoveries in Lower 48 were due to planned development to add specific well locations from the
unconventional plays, which more than offset the decreases in the revisions category.

In 2019, extensions and discoveries in Lower 48 were due to planned development to add specific well locations from the
unconventional plays, which more than offset the decreases in the revisions category.

•

Sales: In 2019, Europe sales represent the disposition of the U.K. assets.

155 ConocoPhillips 2021 10-K

Supplementary Data

Years Ended
December 31

Total company
End of 2018
End of 2019
End of 2020
End of 2021

Natural Gas
Billions of Cubic Feet

Lower
48

Total
U.S.

Canada

Europe

Asia Pacific/
Middle East

Africa

Total

Alaska

2,736
30
-
-
7
(85)
-
2,688
(607)
-
-
-
(85)
-
1,996
715
-
-
-
(86)
-
2,625

-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-

2,318
(113)
-
2
483
(252)
(7)
2,431
(439)
-
74
304
(231)
(39)
2,100
41
-
2,438
822
(473)
(270)
4,658

5,054
(83)
-
2
490
(337)
(7)
5,119
(1,046)
-
74
304
(316)
(39)
4,096
756
-
2,438
822
(559)
(270)
7,283

-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-

26
(2)
-
-
23
(4)
-
43
(15)
-
29
33
(16)
-
74
15
-
-
46
(30)
-
105

-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-

1,212
160
-
-
-
(178)
(298)
896
39
-
-
2
(112)
-
825
54
-
-
2
(113)
-
768

-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-

2,736
2,688
1,996
2,625

2,318
2,431
2,100
4,658

5,054
5,119
4,096
7,283

26
43
74
105

1,212
896
825
768

1,079
147
-
-
1
(250)
-
977
103
-
-
-
(171)
(58)
851
60
-
-
-
(147)
-
764

4,564
(7)
-
-
252
(388)
-
4,421
(382)
-
2
78
(395)
-
3,724
247
-
-
116
(390)
-
3,697

5,643
5,398
4,575
4,461

214
21
-
-
-
(11)
-
224
2
-
-
-
(2)
-
224
-
-
-
-
(7)
-
217

-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-

7,585
243
-
2
514
(780)
(305)
7,259
(917)
-
103
339
(617)
(97)
6,070
885
-
2,438
870
(856)
(270)
9,137

4,564
(7)
-
-
252
(388)
-
4,421
(382)
-
2
78
(395)
-
3,724
247
-
-
116
(390)
-
3,697

214
224
224
217

12,149
11,680
9,794
12,834

ConocoPhillips 2021 10-K 156

Supplementary Data

Years Ended
December 31

Developed
Consolidated operations
End of 2018
End of 2019
End of 2020
End of 2021

Equity affiliates
End of 2018
End of 2019
End of 2020
End of 2021

Undeveloped
Consolidated operations
End of 2018
End of 2019
End of 2020
End of 2021

Equity affiliates
End of 2018
End of 2019
End of 2020
End of 2021

Natural Gas
Billions of Cubic Feet

Alaska

Lower
48

Total
U.S.

Canada

Europe

Asia Pacific/
Middle East

Africa

Total

2,720
2,601
1,961
2,579

1,427
1,398
1,051
3,100

4,147
3,999
3,012
5,679

-
-
-
-

16
87
35
46

-
-
-
-

891
1,033
1,049
1,558

907
1,120
1,084
1,604

-
-
-
-

17
30
74
52

-
-
-
-

9
13
-
53

-
-
-
-

1,052
697
598
679

-
-
-
-

160
199
227
89

-
-
-
-

758
843
806
688

4,059
3,898
3,293
3,204

321
134
45
76

505
523
431
493

214
224
224
217

-
-
-
-

6,188
5,793
4,714
7,315

4,059
3,898
3,293
3,204

1,397
1,466
1,356
1,822

505
523
431
493

Natural gas production in the reserves table may differ from gas production (delivered for sale) in our statistics disclosure, primarily
because the quantities above include gas consumed in production operations. Quantities consumed in production operations are
not significant in the periods presented. The value of net production consumed in operations is not reflected in net revenues and
production expenses, nor do the volumes impact the respective per unit metrics.

Reserve volumes include natural gas to be consumed in operations of 2,748 Bcf, 2,286 Bcf and 3,141 Bcf, as of December 31, 2021,
2020 and 2019, 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, 2021, included:

•

Revisions: In 2021, upward revisions in Alaska were due to higher prices of 587 Bcf and technical revisions of 128 Bcf. In
Lower 48, upward revisions of 614 Bcf were due to higher prices, additional infill drilling in the unconventional plays of 277
Bcf and technical revisions of 60 Bcf, partially offset by downward revisions due to development timing for specific well
locations from unconventional plays of 498 Bcf and conversion of previously acquired Permian two-stream contracted
volumes to a three-stream (crude oil, natural gas and natural gas liquids) basis of 412 Bcf. Upward revisions in Canada were
due to higher prices of 29 Bcf, partially offset by downward revisions due to technical revisions of 14 Bcf. In Europe,
upward revisions were primarily due to higher prices. Upward revisions in our consolidated operations in Asia
Pacific/Middle East were due to technical revisions of 76 Bcf, partially offset by price revisions of 16 Bcf. In our equity
affiliates in Asia Pacific/Middle East, upward revisions were due to higher prices of 124 Bcf and technical and cost revisions
of 123 Bcf.

In 2020, downward revisions in Alaska were primarily due to lower prices. In Lower 48, downward revisions of 372 Bcf were
due to lower prices and 154 Bcf were due to development timing for specific well locations from unconventional plays,
partially offset by technical revisions of 87 Bcf. Downward revisions in our equity affiliates in Asia Pacific/Middle East were

157 ConocoPhillips 2021 10-K

Supplementary Data

due to lower prices of 426 Bcf, partially offset by performance revisions of 44 Bcf. Upward revisions in our consolidated
operations in Asia Pacific/Middle East were due to technical revisions of 88 Bcf and price revisions of 15 Bcf.

In 2019, upward revisions in Europe were due to technical and cost revisions. In Asia Pacific/Middle East upward revisions
were primarily due to the Indonesia Corridor PSC term extension. Downward revisions in Lower 48 were due to changes in
development timing for specific well locations from the unconventional plays of 207 Bcf and price revisions of 125 Bcf,
partially offset by upward revisions related to infill drilling and improved well performance of 219 Bcf.

•

Purchases: In 2021, Lower 48 purchases were due to the Concho and Shell Permian acquisitions.

In 2020, Canada purchases were due to the acquisition of additional Montney acreage.

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.

•

Sales: In 2021, Lower 48 sales represent the disposition of noncore assets.

In 2020, Asia Pacific/Middle East sales represent the disposition of the Australia-West assets.

In 2019, Europe sales represent the disposition of the U.K. assets.

ConocoPhillips 2021 10-K 158

Supplementary Data

Years Ended
December 31

Total company
End of 2018
End of 2019
End of 2020
End of 2021

159 ConocoPhillips 2021 10-K

Bitumen
Millions of Barrels

Canada

236
37
-
-
31
(22)
-
282
(15)
-
-
85
(20)
-
332
(50)
-
-
-
(25)
-
257

-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-

236
282
332
257

Supplementary Data

Years Ended
December 31

Developed
Consolidated operations
End of 2018
End of 2019
End of 2020
End of 2021

Equity affiliates
End of 2018
End of 2019
End of 2020
End of 2021

Undeveloped
Consolidated operations
End of 2018
End of 2019
End of 2020
End of 2021

Equity affiliates
End of 2018
End of 2019
End of 2020
End of 2021

Bitumen
Millions of Barrels

Canada

155
187
117
150

-
-
-
-

81
95
215
107

-
-
-
-

Notable changes in proved bitumen reserves in the three years ended December 31, 2021, included:

•

Revisions: In 2021, downward revisions of 64 million barrels were driven by changes in carbon tax costs
and 39 million barrels due to changes in development timing for specific pad locations from the Surmont
development program, partially offset by upward revisions from price of 53 million barrels.

In 2020, downward revisions in Canada were due to changes in development timing for specific pad
locations from the Surmont development program of 12 million barrels with the remaining revisions
primarily related to lower prices.

In 2019, upward revisions in Canada were due to technical revisions in Surmont of 70 million barrels,
partially offset by downward revisions due to changes in development timing for specific pad locations
from the Surmont development program of 31 million barrels.

Extensions and discoveries: In 2020, extensions and discoveries in Canada were primarily due to planned
development to add specific pad locations from the Surmont development program, which more than
offset the decrease in the revisions category.

In 2019, extensions and discoveries in Canada were due to planned development to add specific pad
locations from the Surmont development program, which offset the decrease in the revisions category of
31 million barrels.

ConocoPhillips 2021 10-K 160

Supplementary Data

Years Ended
December 31

Total company
End of 2018
End of 2019
End of 2020
End of 2021

161 ConocoPhillips 2021 10-K

Total Proved Reserves
Millions of Barrels of Oil Equivalent

Lower
48

Total
U.S.

Canada

Europe

Asia Pacific/
Middle East

Africa

Total

1,312
(67)
-
2
368
(165)
(3)
1,447
(226)
-
19
200
(142)
(25)
1,273
168
-
1,169
508
(289)
(54)
2,775

3,107
(23)
7
2
394
(258)
(3)
3,226
(624)
-
19
210
(227)
(25)
2,579
490
1
1,169
518
(373)
(54)
4,330

-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-

245
36
-
-
38
(23)
-
296
(20)
-
10
95
(25)
(1)
355
(45)
-
-
15
(35)
-
290

-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-

465
48
-
-
-
(68)
(85)
360
12
-
-
-
(49)
-
323
23
-
-
3
(50)
-
299

-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-

342
19
-
-
11
(74)
-
298
13
3
-
-
(55)
(10)
249
47
-
-
1
(48)
-
249

880
(1)
-
-
42
(73)
-
848
(63)
-
-
13
(73)
-
725
42
-
-
19
(73)
-
713

224
26
-
-
-
(16)
-
234
(3)
-
-
-
(3)
-
228
6
-
-
-
(14)
-
220

-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-

4,383
106
7
2
443
(439)
(88)
4,414
(622)
3
29
305
(359)
(36)
3,734
521
1
1,169
537
(520)
(54)
5,388

880
(1)
-
-
42
(73)
-
848
(63)
-
-
13
(73)
-
725
42
-
-
19
(73)
-
713

Alaska

1,795
44
7
-
26
(93)
-
1,779
(398)
-
-
10
(85)
-
1,306
322
1
-
10
(84)
-
1,555

-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-

1,795
1,779
1,306
1,555

1,312
1,447
1,273
2,775

3,107
3,226
2,579
4,330

245
296
355
290

465
360
323
299

1,222
1,146
974
962

224
234
228
220

5,263
5,262
4,459
6,101

Supplementary Data

Years Ended
December 31

Developed
Consolidated operations
End of 2018
End of 2019
End of 2020
End of 2021

Equity affiliates
End of 2018
End of 2019
End of 2020
End of 2021

Undeveloped
Consolidated operations
End of 2018
End of 2019
End of 2020
End of 2021

Equity affiliates
End of 2018
End of 2019
End of 2020
End of 2021

Total Proved Reserves
Millions of Barrels of Oil Equivalent

Alaska

Lower
48

Total
U.S.

Canada

Europe

Asia Pacific/
Middle East

Africa

Total

1,617
1,582
1,186
1,424

681
666
521
1,767

2,298
2,248
1,707
3,191

-
-
-
-

178
197
120
131

-
-
-
-

631
781
752
1,008

809
978
872
1,139

-
-
-
-

160
197
140
166

-
-
-
-

85
99
215
124

-
-
-
-

382
275
238
244

-
-
-
-

83
85
85
55

-
-
-
-

244
236
211
212

796
761
653
631

98
62
38
37

84
87
72
82

221
218
212
207

-
-
-
-

3
16
16
13

-
-
-
-

3,305
3,174
2,508
4,020

796
761
653
631

1,078
1,240
1,226
1,368

84
87
72
82

Natural gas reserves are converted to barrels of oil equivalent (BOE) based on a 6:1 ratio: six MCF of natural gas converts to one
BOE.

Proved Undeveloped Reserves

The following table shows changes in total proved undeveloped reserves for 2021:

End of 2020
Revisions
Improved recovery
Purchases
Extensions and discoveries
Sales
Transfers to proved developed
End of 2021

Proved Undeveloped Reserves
Millions of Barrels of
Oil Equivalent

1,298
(167)
1
158
448
-
(288)
1,450

Downward revisions were driven by changes in development timing of 389 MMBOE primarily in North America and negative
bitumen revisions in Canada due to changes in carbon tax costs of 65 MMBOE, partially offset by upward revisions for Lower 48 infill
drilling of 162 MMBOE and higher prices of 125 MMBOE.

Purchases were driven by Lower 48 due to the Concho acquisition.

ConocoPhillips 2021 10-K 162

Supplementary Data

Extensions and discoveries were largely driven by an addition of 399 MMBOE in Lower 48 for the continued development of
unconventional plays. The remaining extensions and discoveries were driven by the continued development planned in the other
geographic regions.

Transfers to proved developed reserves were driven by the ongoing development of our assets. Approximately 65 percent of the
transfers were from the development of our Lower 48 unconventional plays. The remainder of transfers were from development
across the other geographic regions.

At December 31, 2021, our PUDs represented 24 percent of total proved reserves, compared with 29 percent at December 31, 2020.
Costs incurred for the year ended December 31, 2021, relating to the development of PUDs were $3.8 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 2021, approximately 93 percent of total PUDs were under development or scheduled for development within five
years of initial disclosure, including all of our Lower 48 PUDs. The remaining PUDs are in major development areas which are
currently producing and within our Canada and Asia Pacific/Middle East geographic areas.

Results of Operations

The company’s results of operations from oil and gas activities for the years 2021, 2020 and 2019 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.

163 ConocoPhillips 2021 10-K

Supplementary Data

Results of Operations

Year Ended
December 31, 2021

Consolidated operations
Sales
Transfers
Transportation costs
Other revenues

Total revenues

Production costs excluding taxes
Taxes other than income taxes
Exploration expenses
Depreciation, depletion and

amortization

Impairments
Other related expenses
Accretion

Income tax provision (benefit)
Results of operations

Equity affiliates
Sales
Transfers
Transportation costs
Other revenues

Total revenues

Production costs excluding taxes
Taxes other than income taxes
Exploration expenses
Depreciation, depletion and

amortization

Impairments
Other related expenses
Accretion

Income tax provision (benefit)
Results of operations

Lower
48

Total
U.S.

Canada

Asia Pacific/
Europe Middle East

Africa

Other
Areas

Millions of Dollars

14,093
-
-
135
14,228
2,414
937
98

4,053
(8)
12
47
6,675
1,467
5,208

18,925
4
(626)
149
18,452
3,487
1,379
178

4,917
(3)
(19)
118
8,395
1,845
6,550

1,219
-
-
323
1,542
518
23
39

383
6
(22)
10
585
145
440

3,568
-
-
(5)
3,563
487
36
21

844
(24)
(42)
70
2,171
1,673
498

-
-
-
-
-
-
-
-

-
-
-
-
-
-
-

-
-
-
-
-
-
-
-

-
-
-
-
-
-
-

-
-
-
-
-
-
-
-

-
-
-
-
-
-
-

-
-
-
-
-
-
-
-

-
-
-
-
-
-
-

2,525
-
-
237
2,762
466
91
51

787
7
4
26
1,330
494
836

745
1,797
-
5
2,547
329
824
268

593
718
3
17
(205)
(42)
(163)

917
-
-
141
1,058
43
1
2

35
-
4
-
973
870
103

-
-
-
-
-
-
-
-

-
-
-
-
-
-

-
-
-
(161)
(161)
-
1
15

-
-
12
-
(189)
(53)
(136)

-
-
-
-
-
-
-
-

-
-
-
-
-
-

Alaska

4,832
4
(626)
14
4,224
1,073
442
80

864
5
(31)
71
1,720
378
1,342

-
-
-
-
-
-
-
-

-
-
-
-
-
-
-

Total

27,154
4
(626)
684
27,216
5,001
1,531
306

6,966
(14)
(63)
224
13,265
4,974
8,291

745
1,797
-
5
2,547
329
824
268

593
718
3
17
(205)
(42)
(163)

ConocoPhillips 2021 10-K 164

Millions of Dollars

Total
U.S. Canada

Asia Pacific/
Europe Middle East

Africa

Other
Areas

Alaska

2,944
4
(587)
(1)
2,360
1,058
296
1,099

840
-
46
72
(1,051)
(271)
(780)

Lower
48

3,421
-
-
(20)
3,401
1,399
263
73

2,544
804
5
46
(1,733)
(430)
(1,303)

6,365
4
(587)
(21)
5,761
2,457
559
1,172

3,384
804
51
118
(2,784)
(701)
(2,083)

230
-
-
40
270
366
16
40

335
3
5
8
(503)
(191)
(312)

1,560
-
-
(21)
1,539
417
30
52

755
5
(58)
73
265
116
149

-
-
-
-
-
-
-
-

-
-
-
-
-
-
-

-
-
-
-
-
-
-
-

-
-
-
-
-
-
-

-
-
-
-
-
-
-
-

-
-
-
-
-
-
-

-
-
-
-
-
-
-
-

-
-
-
-
-
-
-

-
-
-
-
-
-
-
-

-
-
-
-
-
-
-

1,717
191
(19)
576
2,465
478
42
71

808
-
(25)
33
1,058
277
781

483
1,205
-
8
1,696
289
502
20

569
-
(2)
15
303
39
264

129
-
-
11
140
21
3
13

8
-
(29)
-
124
88
36

-
-
-
-
-
-
-
-

-
-
-
-
-
-
-

-
-
-
10
10
2
1
108

-
-
2
-
(103)
(20)
(83)

-
-
-
-
-
-
-
-

-
-
-
-
-
-
-

Total

10,001
195
(606)
595
10,185
3,741
651
1,456

5,290
812
(54)
232
(1,943)
(431)
(1,512)

483
1,205
-
8
1,696
289
502
20

569
-
(2)
15
303
39
264

Supplementary Data

Year Ended
December 31, 2020

Consolidated operations
Sales
Transfers
Transportation costs
Other revenues

Total revenues

Production costs excluding taxes
Taxes other than income taxes
Exploration expenses
Depreciation, depletion and

amortization

Impairments
Other related expenses
Accretion

Income tax provision (benefit)
Results of operations

Equity affiliates
Sales
Transfers
Transportation costs
Other revenues

Total revenues

Production costs excluding taxes
Taxes other than income taxes
Exploration expenses
Depreciation, depletion and

amortization

Impairments
Other related expenses
Accretion

Income tax provision (benefit)
Results of operations

165 ConocoPhillips 2021 10-K

Supplementary Data

Year Ended
December 31, 2019

Consolidated operations
Sales
Transfers
Transportation costs
Other revenues

Total revenues

Production costs excluding taxes
Taxes other than income taxes
Exploration expenses
Depreciation, depletion and

amortization

Impairments
Other related expenses
Accretion

Income tax provision (benefit)
Results of operations

Equity affiliates
Sales
Transfers
Transportation costs
Other revenues

Total revenues

Production costs excluding taxes
Taxes other than income taxes
Exploration expenses
Depreciation, depletion and

amortization

Impairments
Other related expenses
Accretion

Income tax provision (benefit)
Results of operations

Lower
48

Total
U.S.

Canada

Asia Pacific/
Europe Middle East

Africa

Other
Areas

Millions of Dollars

6,356
-
-
78
6,434
1,578
437
430

2,804
402
116
49
618
147
471

11,239
4
(629)
139
10,753
2,813
745
527

3,504
402
104
111
2,547
591
1,956

-
-
-
-
-
-
-
-

-
-
-
-
-
-
-

-
-
-
-
-
-
-
-

-
-
-
-
-
-
-

709
-
-
86
795
380
18
32

230
2
(38)
7
164
(74)
238

-
-
-
-
-
-
-
-

-
-
-
-
-
-
-

3,207
-
-
1,785
4,992
741
32
69

842
1
(42)
142
3,207
591
2,616

-
-
-
-
-
-
-
-

-
-
-
-
-
-
-

3,032
449
(41)
12
3,452
619
54
80

1,172
-
58
43
1,426
458
968

599
2,229
-
31
2,859
335
820
-

579
-
11
16
1,098
170
928

919
-
-
101
1,020
70
3
5

37
-
22
-
883
833
50

-
-
-
-
-
-
-
-

-
-
-
-
-
-
-

-
-
-
326
326
(8)
(2)
33

-
-
10
-
293
7
286

-
-
-
-
-
-
-
-

-
-
-
-
-
-
-

Total

19,106
453
(670)
2,449
21,338
4,615
850
746

5,785
405
114
303
8,520
2,406
6,114

599
2,229
-
31
2,859
335
820
-

579
-
11
16
1,098
170
928

Alaska

4,883
4
(629)
61
4,319
1,235
308
97

700
-
(12)
62
1,929
444
1,485

-
-
-
-
-
-
-
-

-
-
-
-
-
-
-

ConocoPhillips 2021 10-K 166

Supplementary Data

Statistics

Net Production

Crude Oil
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific
Africa
Total consolidated operations
Equity affiliates—Asia Pacific/Middle East
Total company
Delaware Basin Area (Lower 48)*
Greater Prudhoe Area (Alaska)*

Natural Gas Liquids
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific
Total consolidated operations
Equity affiliates—Asia Pacific/Middle East
Total company
Delaware Basin Area (Lower 48)*
Greater Prudhoe Area (Alaska)*

Bitumen
Consolidated operations—Canada
Total company

Natural Gas
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific
Africa
Total consolidated operations
Equity affiliates—Asia Pacific/Middle East
Total company
Delaware Basin Area (Lower 48)*
Greater Prudhoe Area (Alaska)*

2021
Thousands of Barrels Daily

2020

2019

178
447
625
8
81
65
37
816
13
829
162
67

16
110
126
4
4
-
134
8
142
27
16

69
69

181
213
394
6
78
69
8
555
13
568
28
68

16
74
90
2
4
1
97
8
105
11
15

55
55

Millions of Cubic Feet Daily

16
1,340
1,356
80
298
360
15
2,109
1,053
3,162
584
12

10
585
595
40
270
429
5
1,339
1,055
2,394
99
4

202
266
468
1
100
85
38
692
13
705
24
66

15
81
96
-
7
4
107
8
115
11
15

60
60

7
622
629
9
447
637
31
1,753
1,052
2,805
86
4

*At year-end 2021, the Delaware Basin Area in Lower 48 contained more than 15 percent of our total proved reserves. At year-end 2021, 2020
and 2019, the Greater Prudhoe Area in Alaska contained more than 15 percent of our total proved reserves.

167 ConocoPhillips 2021 10-K

Supplementary Data

Average Sales Prices

Crude Oil Per Barrel
Consolidated operations
Alaska*
Lower 48
United States
Canada
Europe
Asia Pacific
Africa
Total international
Total consolidated operations
Equity affiliates—Asia Pacific/Middle East
Total operations

Natural Gas Liquids Per Barrel
Consolidated operations
Lower 48
United States
Canada
Europe
Asia Pacific
Total international
Total consolidated operations
Equity affiliates—Asia Pacific/Middle East
Total operations

Bitumen Per Barrel
Consolidated operations—Canada

2021

2020

2019

60.81
66.12
64.53
56.38
68.94
70.36
69.06
68.85
65.53
69.45
65.59

30.63
30.63
31.18
43.97
-
37.50
31.04
54.16
32.45

33.72
35.17
34.48
23.57
42.80
42.84
48.64
42.39
36.69
39.02
36.75

12.13
12.13
5.41
23.27
33.21
20.25
12.90
32.69
14.61

55.85
55.30
55.54
40.87
65.12
65.02
64.47
64.85
58.51
61.32
58.57

16.83
16.85
19.87
29.37
37.85
32.29
18.73
36.70
20.09

37.52

8.02 **

31.72

Natural Gas Per Thousand Cubic Feet
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific*
Africa
Total international
Total consolidated operations
Equity affiliates—Asia Pacific/Middle East
Total operations
*Average sales prices for Alaska crude oil and Asia Pacific natural gas above reflect a reduction for transportation costs in which we
have an ownership interest that are incurred subsequent to the terminal point of the production function. Accordingly, the average sales prices
differ from those discussed in Item 7 of Management's Discussion and Analysis of Financial Condition and Results of Operations.
**Average sales prices include unutilized transportation costs.

2.81
4.38
4.38
2.54
13.75
6.56
3.73
8.91
6.00
5.31
5.77

2.91
1.65
1.66
1.21
3.23
5.27
3.71
4.31
3.13
3.71
3.38

3.19
2.12
2.12
0.49
4.92
5.73
4.87
5.35
4.19
6.29
4.99

ConocoPhillips 2021 10-K 168

Supplementary Data

Average Production Costs Per Barrel of Oil Equivalent*
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific
Africa
Total international
Total consolidated operations
Equity affiliates—Asia Pacific/Middle East

Average Production Costs Per Barrel—Bitumen
Consolidated operations—Canada

Taxes Other Than Income Taxes Per Barrel of Oil Equivalent
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific
Africa
Total international
Total consolidated operations
Equity affiliates—Asia Pacific/Middle East

Depreciation, Depletion and Amortization Per Barrel of Oil Equivalent
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific
Africa
Total international
Total consolidated operations
Equity affiliates—Asia Pacific/Middle East
*Includes bitumen.

2021

2020

2019

14.92
8.48
9.78
15.10
9.88
10.21
2.95
10.53
9.99
4.60

14.60
9.93
11.51
14.29
8.97
9.26
6.38
10.11
10.99
4.01

15.52
9.59
11.52
16.53
11.22
8.74
4.46
10.26
10.99
4.68

13.41

12.45

13.74

6.15
3.29
3.87
0.67
0.73
1.99
0.07
1.06
3.06
11.52

12.02
14.24
13.79
11.16
17.13
17.25
2.40
14.25
13.92
8.29

4.08
1.87
2.62
0.62
0.65
0.81
0.91
0.72
1.91
6.96

11.59
18.05
15.86
13.08
16.24
15.66
2.43
15.01
15.54
7.89

3.87
2.65
3.05
0.78
0.48
0.76
0.19
0.60
2.03
11.46

8.80
17.03
14.35
10.00
12.75
16.55
2.36
12.99
13.78
8.09

169 ConocoPhillips 2021 10-K

Supplementary Data

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, 2021, 2020 and 2019. A “development well” is a well drilled within the proved area
of a reservoir to the depth of a stratigraphic horizon known to be productive. An “exploratory well” is a well drilled
to find and produce crude oil or natural gas in an unknown field or a new reservoir within a proven field.
Exploratory wells also include wells drilled in areas near or offsetting current production, or in areas where well
density or production history have not achieved statistical certainty of results. Excluded from the exploratory well
count are stratigraphic-type exploratory wells, primarily relating to oil sands delineation wells located in Canada
and CBM test wells located in Asia Pacific/Middle East.

Net Wells Completed

Exploratory
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific/Middle East
Africa
Other areas
Total consolidated operations
Equity affiliates
Asia Pacific/Middle East
Total equity affiliates

Development
Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific/Middle East
Africa
Other areas
Total consolidated operations
Equity affiliates
Asia Pacific/Middle East
Total equity affiliates
*Our total proportionate interest was less than one.

Productive
2020

2021

2019

2021

2020

2019

Dry

-
87
87
12
-
*
-
-
99

3
3

1
339
340
2
7
21
1
-
371

30
30

-
3
3
23
-
*
-
-
26

8
8

7
127
134
-
7
16
2
-
159

109
109

7
35
42
-
1
1
-
-
44

8
8

12
255
267
2
6
21
2
-
298

106
106

1
-
1
-
-
*
-
-
1

-
-

-
-
-
-
-
-
-
-
-

-
-

3
-
3
-
*
*
*
*
3

-
-

-
-
-
-
-
-
-
-
-

-
-

-
6
6
-
1
1
-
-
8

-
-

-
-
-
-
-
-
-
-
-

-
-

ConocoPhillips 2021 10-K 170

Supplementary Data

The table below represents the status of our wells drilling at December 31, 2021, 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, 2021.

In Progress
Gross

Net

Oil

Gross

Productive

Gas

Net

Gross

Net

2
665
667
18
11
15
7
-
718

130
130

1
337
338
15
1
7
1
-
362

25
25

1,602
16,306
17,908
186
494
351
858
-
19,797

-
-

940
8,015
8,955
94
84
166
140
-
9,439

-
-

-
5,091
5,091
149
59
38
10
-
5,347

4,908
4,908

-
2,211
2,211
149
2
18
2
-
2,382

1,171
1,171

Thousands of Acres

Developed
Gross

Net

Undeveloped
Gross

Net

663
4,096
4,759
297
430
921
358
-
6,765

1,039
1,039

479
2,538
3,017
219
50
421
58
-
3,765

248
248

1,341
10,514
11,855
3,433
938
10,451
12,545
156
39,378

3,807
3,807

1,329
8,233
9,562
1,948
371
6,930
2,049
125
20,985

856
856

Wells at December 31, 2021

Consolidated operations
Alaska
Lower 48
United States
Canada
Europe
Asia Pacific/Middle East
Africa
Other areas
Total consolidated operations
Equity affiliates
Asia Pacific/Middle East
Total equity affiliates

Acreage at December 31, 2021

171

ConocoPhillips 2021 10-K

Supplementary Data

Costs Incurred

Year Ended
December 31

2021
Consolidated operations
Unproved property acquisition
Proved property acquisition

Exploration
Development

Equity affiliates
Unproved property acquisition
Proved property acquisition

Exploration
Development

2020
Consolidated operations
Unproved property acquisition
Proved property acquisition

Exploration
Development

Equity affiliates
Unproved property acquisition
Proved property acquisition

Exploration
Development

2019
Consolidated operations
Unproved property acquisition
Proved property acquisition

Exploration
Development

Equity affiliates
Unproved property acquisition
Proved property acquisition

Exploration
Development

Alaska

Lower
48

Total
U.S.

Canada

Europe

Asia Pacific/
Middle East

Africa

Other
Areas

Total

Millions of Dollars

1
-
1
84
949
$ 1,034

11,261
16,101
27,362
765
2,461
30,588

11,262
16,101
27,363
849
3,410
31,622

-
-
-
-

-
-
-
-
-
-

4
-
4
287
745
$ 1,036

10
62
72
116
1,758
1,946

14
62
76
403
2,503
2,982

-
-
-
-
-
-

101
1
102
281
1,125
$ 1,508

45
116
161
390
3,028
3,579

146
117
263
671
4,153
5,087

-
-
-
-
-
-

4
1
5
80
175
260

-
-
-
-

378
129
507
218
102
827

-
-
-
-
-
-

14
-
14
200
215
429

-
-
-
-
-
-

-
-
-
31
398
429

-
-
-
-

-
-
-
110
451
561

-
-
-
-
-
-

-
-
-
119
625
744

-
-
-
-
-
-

-
-
-
51
433
484

-
5
21
26

3
-
3
32
427
462

-
-
-
12
282
294

-
115
115
66
486
667

62
-
62
23
171
256

-
-
-
2
24
26

-
-
-
-

-
-
-
4
18
22

-
-
-
-
-
-

-
-
-
8
22
30

-
-
-
-
-
-

-
-
-
40
-
40

-
-
-
-

9
-
9
38
-
47

-
-
-
-
-
-

197
-
197
39
-
236

-
-
-
-
-
-

11,266
16,102
27,368
1,053
4,440
32,861

-
-
-
5
21
26

404
191
595
805
3,501
4,901

-
-
-
12
282
294

357
232
589
1,103
5,501
7,193

62
-
62
23
171
256

ConocoPhillips 2021 10-K 172

Supplementary Data

Capitalized Costs

At December 31

2021
Consolidated operations
Proved property
Unproved property

Accumulated depreciation,

depletion and amortization

Equity affiliates
Proved property
Unproved property

Accumulated depreciation,

depletion and amortization

2020
Consolidated operations
Proved property
Unproved property

Accumulated depreciation,

depletion and amortization

Equity affiliates
Proved property
Unproved property

Accumulated depreciation,

depletion and amortization

Alaska

Lower
48

Total
U.S.

Canada

Asia Pacific/
Europe Middle East

Africa

Other
Areas

Total

Millions of Dollars

$ 22,750
1,402
24,152

58,561
7,704
66,265

81,311
9,106
90,417

11,945
$ 12,207

29,975
36,290

41,920
48,497

7,380
1,517
8,897

2,749
6,148

14,514
155
14,669

10,166
4,503

-
-
-

-
-

-
-
-

-
-

-
-
-

-
-

-
-
-

-
-

-
-
-

-
-

$ 21,819
1,398
23,217

37,452
631
38,083

59,271
2,029
61,300

11,098
$ 12,119

27,948
10,135

39,046
22,254

7,255
1,529
8,784

2,431
6,353

14,931
151
15,082

10,015
5,067

-
-
-

-
-

-
-
-

-
-

-
-
-

-
-

-
-
-

-
-

-
-
-

-
-

12,226
92
12,318

9,240
3,078

10,357
2,162
12,519

8,539
3,980

11,913
89
12,002

8,567
3,435

10,310
2,187
12,497

6,959
5,538

966
114
1,080

422
658

-
-
-

-
-

-
9
9

9
-

-
-
-

-
-

942 -
114
1,056

229
229

387
669

9
220

-
-
-

-
-

-
-
-

-
-

116,397
10,993
127,390

64,506
62,884

10,357
2,162
12,519

8,539
3,980

94,312
4,141
98,453

60,455
37,998

10,310
2,187
12,497

6,959
5,538

173 ConocoPhillips 2021 10-K

Supplementary Data

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

2021
Consolidated operations
Future cash inflows
Less:

Future production costs
Future development costs
Future income tax provisions

Future net cash flows
10 percent annual discount
Discounted future net cash flows

Equity affiliates
Future cash inflows
Less:

Future production costs
Future development costs
Future income tax provisions

Future net cash flows
10 percent annual discount
Discounted future net cash flows

Total company
Discounted future net cash flows

Alaska

Lower
48

Total
U.S.

Millions of Dollars

Canada

Europe

Asia Pacific/
Middle East

Africa

Total

$ 65,910

125,197

191,107

10,847

21,670

11,583

15,778

250,985

34,444
8,033
5,310
18,123
7,963
$ 10,160

43,034
13,386
13,167
55,610
22,290
33,320

77,478
21,419
18,477
73,733
30,253
43,480

4,960
923
117
4,847
1,639
3,208

6,090
3,960
8,345
3,275
696
2,579

-
-
-
-
-
-

4,987
1,314
1,542
3,740
930
2,810

27,851

15,491
1,649
3,071
7,640
2,640
5,000

801
413
13,506
1,058
440
618

-
-
-
-
-
-

94,316
28,029
41,987
86,653
33,958
52,695

27,851

15,491
1,649
3,071
7,640
2,640
5,000

$ 10,160

33,320

43,480

3,208

2,579

7,810

618

57,695

ConocoPhillips 2021 10-K 174

Supplementary Data

2020
Consolidated operations
Future cash inflows
Less:

Future production costs
Future development costs
Future income tax provisions

Future net cash flows
10 percent annual discount
Discounted future net cash flows

Equity affiliates
Future cash inflows
Less:

Future production costs
Future development costs
Future income tax provisions

Future net cash flows
10 percent annual discount
Discounted future net cash flows

Total company
Discounted future net cash flows

Alaska

Lower
48

Total
U.S.

Millions of Dollars

Canada*

Europe

Asia Pacific/
Middle East

Africa

Total

$ 30,145

31,533

61,678

4,198

9,857

7,940

9,997

93,670

22,905
7,932
-
(692)
(1,501)
809

17,582
12,799
376
776
(820)
1,596

40,487
20,731
376
84
(2,321)
2,405

4,316
750
-
(868)
(396)
(472)

4,770
3,688
267
1,132
117
1,015

-
-
-
-
-
-

3,838
1,289
1,075
1,738
406
1,332

17,284

10,239
1,186
1,728
4,131
1,269
2,862

1,277
461
7,571
688
294
394

-
-
-
-
-
-

54,688
26,919
9,289
2,774
(1,900)
4,674

17,284

10,239
1,186
1,728
4,131
1,269
2,862

809

1,596

2,405

(472)

1,015

4,194

394

7,536

*Undiscounted future net cash flows related to the proved oil and gas reserves disclosed for Canada for the year ending December 31, 2020, are negative due to the
inclusion of asset retirement costs and certain indirect costs in the calculation of the standardized measure of discounted future net cash flows. These costs are not
required to be included in the economic limit test for proved developed reserves as defined in Regulation S-X Rule 4-10. Future net cash flows for Canada were also
impacted by lower 12-month average pricing for bitumen and crude oil in 2020. Commodity prices have since improved in the current environment.

175 ConocoPhillips 2021 10-K

Supplementary Data

2019
Consolidated operations
Future cash inflows
Less:

Future production costs
Future development costs
Future income tax provisions

Future net cash flows
10 percent annual discount
Discounted future net cash flows

Equity affiliates
Future cash inflows
Less:

Future production costs
Future development costs
Future income tax provisions

Future net cash flows
10 percent annual discount
Discounted future net cash flows

Total company
Discounted future net cash flows

Alaska

Lower
48

Total
U.S.

Canada

Europe

Asia Pacific/
Middle East

Africa

Total

Millions of Dollars

70,341

53,400

123,741

8,244

16,919

13,084

15,582

177,570

40,464
9,721
3,904
16,252
6,571
9,681

22,194
14,083
2,793
14,330
4,311
10,019

62,658
23,804
6,697
30,582
10,882
19,700

4,525
577
-
3,142
1,198
1,944

5,843
4,143
4,201
2,732
558
2,174

5,162
2,179
1,931
3,812
835
2,977

1,314
484
12,747
1,037
460
577

-
-
-
-
-
-

31,671

16,157
1,218
3,086
11,210
4,040
7,170

-
-
-
-
-
-

79,502
31,187
25,576
41,305
13,933
27,372

31,671

16,157
1,218
3,086
11,210
4,040
7,170

9,681

10,019

19,700

1,944

2,174

10,147

577

34,542

ConocoPhillips 2021 10-K 176

Supplementary Data

Sources of Change in Discounted Future Net Cash Flows

Consolidated Operations
2021

2020

2019

Millions of Dollars
Equity Affiliates

Total Company

2021

2020

2019

2021

2020

2019

Discounted future net cash flows

at the beginning of the year

4,674

27,372

35,434

2,862

7,170

7,929

7,536

34,542

43,363

Changes during the year

Revenues less production

costs for the year

Net change in prices and

production costs

Extensions, discoveries and
improved recovery, less
estimated future costs

Development costs for the year
Changes in estimated future

development costs

Purchases of reserves in place,
less estimated future costs

Sales of reserves in place,

less estimated future costs
Revisions of previous quantity

estimates

Accretion of discount
Net change in income taxes

Total changes
Discounted future net cash flows

(20,000)

(5,198)

(13,424)

(1,389)

(897)

(1,673)

(21,389)

(6,095)

(15,097)

50,956

(34,307)

(13,538)

3,822

(4,769)

(422)

54,778

(39,076)

(13,960)

10,420
4,396

887
3,593

2,985
5,333

(44)
91

22
192

260
239

10,376
4,487

909
3,785

(104)

(205)

(21)

(137)

549

(33)

754

17,833

559

(468)

(302)

(1,997)

(3)

2,985
964
(19,032)
48,021

(2,299)
3,984
10,189
(22,698)

2,099
5,144
4,767
(8,062)

178
344
(760)
2,138

(42)
804
590
(4,308)

69
869
(80)
(759)

17,833

(2)

(468)

(302)

(1,997)

3,163
1,308
(19,792)
50,159

(2,341)
4,788
10,779
(27,006)

2,168
6,013
4,687
(8,821)

3,245
5,572

538

at year end

52,695

4,674

27,372

5,000

2,862

7,170

57,695

7,536

34,542

•

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.

177 ConocoPhillips 2021 10-K

Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure

None.

Item 9A. Controls and Procedures

We maintain disclosure controls and procedures designed to ensure information required to be disclosed in
reports we file or submit under the Securities Exchange Act of 1934, as amended (the Act), is recorded, processed,
summarized and reported within the time periods specified in Securities and Exchange Commission rules and
forms, and that such information is accumulated and communicated to management, including our principal
executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure.
As of December 31, 2021, with the participation of our management, our Chairman and Chief Executive Officer
(principal executive officer) and our Executive Vice President and Chief Financial Officer (principal financial officer)
carried out an evaluation, pursuant to Rule 13a-15(b) of the Act, of ConocoPhillips’ disclosure controls and
procedures (as defined in Rule 13a-15(e) of the Act). Based upon that evaluation, our Chairman and Chief
Executive Officer and our Executive Vice President and Chief Financial Officer concluded our disclosure controls
and procedures were operating effectively as of December 31, 2021.

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

Management’s Annual Report on Internal Control Over Financial Reporting
This report is included in Item 8 on page 75 and is incorporated herein by reference.

Report of Independent Registered Public Accounting Firm
This report is included in Item 8 on page 76 and is incorporated herein by reference.

Item 9B. Other Information

None.

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not applicable.

ConocoPhillips 2021 10-K 178

Part III

Item 10. Directors, Executive Officers and Corporate Governance

Information regarding our executive officers appears in Part I of this report on page 30.

Code of Business Ethics and Conduct for Directors and Employees
We have a Code of Business Ethics and Conduct for Directors and Employees (Code of Ethics), including our
principal executive officer, principal financial officer, principal accounting officer and persons performing similar
functions. We have posted a copy of our Code of Ethics on the “Corporate Governance” section of our internet
website at www.conocophillips.com (within the Investors>Corporate Governance section). Any waivers of the
Code of Ethics must be approved, in advance, by our full Board of Directors. Any amendments to, or waivers from,
the Code of Ethics that apply to our executive officers and directors will be posted on the “Corporate Governance”
section of our internet website.

All other information required by Item 10 of Part III will be included in our Proxy Statement relating to our 2022
Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2022, and is
incorporated herein by reference.*

Item 11. Executive Compensation

Information required by Item 11 of Part III will be included in our Proxy Statement relating to our 2022 Annual
Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2022, and is incorporated
herein by reference.*

Item 12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters

Information required by Item 12 of Part III will be included in our Proxy Statement relating to our 2022 Annual
Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2022, and is incorporated
herein by reference.*

Item 13. Certain Relationships and Related Transactions, and Director
Independence

Information required by Item 13 of Part III will be included in our Proxy Statement relating to our 2022 Annual
Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2022, and is incorporated
herein by reference.*

Item 14. Principal Accounting Fees and Services

Information required by Item 14 of Part III will be included in our Proxy Statement relating to our 2022 Annual
Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2022, and is incorporated
herein by reference.*
_________________________
*Except for information or data specifically incorporated herein by reference under Items 10 through 14, other information and data appearing
in our 2022 Proxy Statement are not deemed to be a part of this Annual Report on Form 10-K or deemed to be filed with the Commission as a
part of this report.

179 ConocoPhillips 2021 10-K

Part IV

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 on page 74, are filed as part of this annual report.

Financial Statement Schedules
All financial statement 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.

Exhibits
The exhibits listed in the Index to Exhibits, which appears on pages 181 through 185, are filed as part of
this annual report.

ConocoPhillips 2021 10-K 180

ConocoPhillips

Index to Exhibits

Incorporated by Reference

Exhibit
No.

2.1

2.2†‡

2.3†‡

2.4

3.1

3.2

3.3

Description
Separation and Distribution Agreement Between ConocoPhillips and Phillips
66, dated April 26, 2012.

Exhibit

Form

File No.

2.1

8-K

001-32395

Purchase and Sale Agreement, dated March 29, 2017, by and among
ConocoPhillips Company, ConocoPhillips Canada Resources Corp.,
ConocoPhillips Canada Energy Partnership, ConocoPhillips Western Canada
Partnership, ConocoPhillips Canada (BRC) Partnership, ConocoPhillips Canada
E&P ULC, and Cenovus Energy Inc.

Asset Purchase and Sale Agreement Amending Agreement, dated as of May
16, 2017, by and among ConocoPhillips Company, ConocoPhillips Canada
Resources Corp., ConocoPhillips Canada Energy Partnership, ConocoPhillips
Western Canada Partnership, ConocoPhillips Canada (BRC) Partnership,
ConocoPhillips Canada E&P ULC, and Cenovus Energy Inc.

Agreement and Plan of Merger, dated as of October 18, 2020, among
ConocoPhillips, Falcon Merger Sub Corp. and Concho Resources Inc.

Amended and Restated Certificate of Incorporation.

Certificate of Designations of Series A Junior Participating Preferred Stock of
ConocoPhillips.

Amended and Restated By-Laws of ConocoPhillips, as amended and restated
as of October 9, 2015.

2.1

10-Q

001-32395

2.2

8-K

001-32395

2.1

3.1

3.2

3.1

8-K

001-32395

10-Q

001-32395

8-K

000-49987

8-K

001-32395

3.4*

Restated Certificate of Incorporation of ConocoPhillips Company, dated
February 6, 2019.

ConocoPhillips and its subsidiaries are parties to several debt instruments
under which the total amount of securities authorized does not exceed
10 percent of the total assets of ConocoPhillips and its subsidiaries on a
consolidated basis. Pursuant to paragraph 4(iii)(A) of Item 601(b) of
Regulation S-K, ConocoPhillips agrees to furnish a copy of such instruments to
the SEC upon request.

4.1

10.1

10.2

10.5

Description of Securities of the Registrant.

1986 Stock Plan of Phillips Petroleum Company.

1990 Stock Plan of Phillips Petroleum Company.

Amendment and Restatement of ConocoPhillips Supplemental Executive
Retirement Plan, dated April 19, 2012.

4.1

10.11

10.12

10-K

001-32395

004-49987

10.14

10-Q

001-32395

10.7

Omnibus Securities Plan of Phillips Petroleum Company.

10.19

10-K

004-49987

10.10.1

10.10.2

Amended and Restated ConocoPhillips Key Employee Supplemental
Retirement Plan, dated January 1, 2020.

10.10.1

10-K

001-32395

Eighth Amendment to Retirement Plans as amended and restated effective
January 1, 2016.

10.1

10-Q

001-32395

181 ConocoPhillips 2021 10-K

10.11.1

10.11.2

Amended and Restated Defined Contribution Make-Up Plan of
ConocoPhillips—Title I, dated January 1, 2020.

Amended and Restated Defined Contribution Make-Up Plan of
ConocoPhillips—Title II, dated January 1, 2020.

10.12

2002 Omnibus Securities Plan of Phillips Petroleum Company.

10.15

Deferred Compensation Plan for Non-Employee Directors of ConocoPhillips.

10.16.1

Rabbi Trust Agreement dated December 17, 1999.

10.16.2

Amendment to Rabbi Trust Agreement dated February 25, 2002.

10.16.3

Phillips Petroleum Company Grantor Trust Agreement, dated June 1, 1998.

First Amendment to the Trust Agreement under the Phillips Petroleum
Company Grantor Trust Agreement, dated May 3, 1999.

10.11.1

10-K

001-32395

10.11.2

10-K

001-32395

10.26

10.17

10.11

10.39.1

10.17.3

10-K

000-49987

001-32395

001-14521

000-49987

001-32395

10.17.4

10-K

001-32395

Second Amendment to the Trust Agreement under the Phillips Petroleum
Company Grantor Trust Agreement, dated January 15, 2002.

10.17.5

10-K

001-32395

Third Amendment to the Trust Agreement under the Phillips Petroleum
Company Grantor Trust Agreement, dated October 5, 2006.

Fourth Amendment to the Trust Agreement under the
ConocoPhillips Company Grantor Trust Agreement, dated May 1, 2012.

10.17.6

10-K

001-32395

10.17.7

10-K

001-32395

Fifth Amendment to the Trust Agreement under the ConocoPhillips Company
Grantor Trust Agreement, dated May 20, 2015.

10.17.8

10-K

001-32395

10.16.4

10.16.5

10.16.6

10.16.7

10.16.8

10.17.1

ConocoPhillips Directors’ Charitable Gift Program.

10.40

10-K

000-49987

10.17.2

10.19.1

10.19.2

10.20

First and Second Amendments to the ConocoPhillips Directors’ Charitable Gift
Program.

10-Q

001-32395

Amended and Restated Key Employee Deferred Compensation Plan of
ConocoPhillips—Title I, dated January 1, 2020.

Amended and Restated Key Employee Deferred Compensation Plan of
ConocoPhillips—Title II, dated January 1, 2020.

10.19.1

10-K

001-32395

10.19.2

10-K

001-32395

Amendment and Restatement of ConocoPhillips Key Employee Change in
Control Severance Plan, effective January 1, 2014.

10.21

10-K

001-32395

10.20.1*

Amendment and Restatement of ConocoPhillips Key Employee Change in
Control Severance Plan, effective December 2, 2021.

10.22.1

2004 Omnibus Stock and Performance Incentive Plan of ConocoPhillips.

10.22.2

10.22.3

Form of Stock Option Award Agreement under the Stock Option and Stock
Appreciation Rights Program under the 2004 Omnibus Stock and Performance
Incentive Plan of ConocoPhillips.

Form of Performance Share Unit Award Agreement under the Performance
Share Program under the 2004 Omnibus Stock and Performance Incentive
Plan of ConocoPhillips.

Schedule
14A

Proxy

000-49987

10.26

10-K

001-32395

10.27

10-K

001-32395

10.23

Omnibus Amendments to certain ConocoPhillips employee benefit plans,
adopted December 7, 2007.

10.30

10-K

001-32395

ConocoPhillips 2021 10-K 182

10.24

2009 Omnibus Stock and Performance Incentive Plan of ConocoPhillips.

10.25.1

2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips.

10.25.2

10.25.4

10.25.7

Form of Stock Option Award Agreement under the Stock Option and Stock
Appreciation Rights Program under the 2011 Omnibus Stock and Performance
Incentive Plan of ConocoPhillips, effective February 9, 2012.

Form of Performance Share Unit Agreement under the Restricted Stock
Program under the 2011 Omnibus Stock and Performance Incentive Plan of
ConocoPhillips, dated February 5, 2013.

Schedule
14A

Proxy

001-32395

Proxy

001-32395

10-Q

001-32395

10.26.6

10-K

001-32395

10.26.9

10-K

001-32395

10.25.8

Form of Make-Up Grant Award Agreement under the 2011 Omnibus Stock and
Performance Incentive Plan of ConocoPhillips, dated January 1, 2012.

10.2

10-Q

001-32395

10.25.9

10.25.10

Form of Key Employee Award Agreement, as part of the ConocoPhillips Stock
Option Program granted under the 2011 Omnibus Stock and Performance
Incentive Plan of ConocoPhillips, dated February 18, 2014.

Form of Key Employee Award Agreement, as part of the ConocoPhillips Stock
Option Program granted under the 2014 Omnibus Stock and Performance
Incentive Plan of ConocoPhillips, dated February 16, 2016.

10.25.12

Form of Performance Period IX Award Agreement, as part of the
ConocoPhillips Performance Share Program granted under the 2011 Omnibus
Stock and Performance Incentive Plan of ConocoPhillips, dated February 18,
2014.

10.25.14

Form of Performance Period X Award Agreement, as part of the
ConocoPhillips Performance Share Program granted under the 2011 Omnibus
Stock and Performance Incentive Plan of ConocoPhillips, dated February 18,
2014.

10.1

10-Q

001-32395

10.26.12

10-K

001-32395

10.3

10-Q

001-32395

10.5

10-Q

001-32395

10.25.17

Form of Inducement Grant Award Agreement under the 2011 Omnibus Stock
and Performance Incentive Plan of ConocoPhillips, dated March 31, 2014.

10.11

10-Q

001-32395

10.25.18

Form of Performance Share Unit Award Terms and Conditions for
Performance Period 18, as part of the ConocoPhillips Performance Share
Program granted under the 2014 Omnibus Stock and Performance Incentive
Plan of ConocoPhillips, dated February 13, 2018.

10.26.24

10-K

001-32395

10.26.1

2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips.

10.1

8-K

001-32395

10.26.4

10.26.7

Form of Non-Employee Director Restricted Stock Units Terms and Conditions,
as part of the Deferred Compensation Plan for Non-Employee Directors of
ConocoPhillips, dated January 15, 2016.

Form of Key Employee Award Terms and Conditions, as part of the
ConocoPhillips Stock Option Program granted under the 2014 Omnibus Stock
and Performance Incentive Plan of ConocoPhillips, dated February 14, 2017.

10.3

10-Q

001-32395

10.1

10-Q

001-32395

183 ConocoPhillips 2021 10-K

10.26.15

10.27

10.29

10.26.11

10.26.13

Form of Key Employee Award Terms and Conditions as part of the
ConocoPhillips Executive Restricted Stock Unit Program granted under the
2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated
February 13, 2018.

Form of Key Employee Award Terms and Conditions as part of the
ConocoPhillips Restricted Stock Program granted under the 2014 Omnibus
Stock and Performance Incentive Plan of ConocoPhillips, dated February 13,
2018.

10.26.14

Form of Retention Award Terms and Conditions, 2017 revision, as part of the
Restricted Stock Unit Award, granted under the 2014 Omnibus Stock and
Performance Incentive Plan of ConocoPhillips.

Form of Key Employee Award Terms and Conditions as part of the
ConocoPhillips Restricted Stock Unit Program granted under the 2014
Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated
February 14, 2019.

10.27.12

10-K

001-32395

10.27.14

10-K

001-32395

10.27.15

10-K

001-32395

10.27.16

10-K

001-32395

Amended and Restated 409A Annex to Nonqualified Deferred Compensation
Arrangements of ConocoPhillips, dated January 1, 2020.

10.27

10-K

001-32395

Amendment and Restatement of the Burlington Resources Inc. Management
Supplemental Benefits Plan, dated April 19, 2012.

10.9

10-Q

001-32395

10.30.1

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

10.1

10-Q

001-32395

10.30.2

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

10.2

10-Q

001-32395

10.31

10.32

10.33

10.34

Indemnification and Release Agreement between ConocoPhillips and Phillips
66, dated April 26, 2012.

10.1

8-K

001-32395

Intellectual Property Assignment and License Agreement between
ConocoPhillips and Phillips 66, dated April 26, 2012.

10.2

8-K

001-32395

Tax Sharing Agreement between ConocoPhillips and Phillips 66, dated April
26, 2012.

10.3

8-K

001-32395

Employee Matters Agreement between ConocoPhillips and Phillips 66, dated
April 12, 2012.

10.4

8-K

001-32395

10.36

ConocoPhillips Clawback Policy dated October 3, 2012.

10.3

10-Q

001-32395

10.37

Term Loan Agreement, between ConocoPhillips, as borrower, ConocoPhillips
Company, as guarantor, Toronto Dominion (Texas) LLC, as administrative
agent and the banks party thereto, with TD Securities (USA) LLC, as lead
arranger and bookrunner, dated March 18, 2016.

10.1

8-K

001-32395

10.38

Company Retirement Contribution Make-Up Plan of ConocoPhillips, dated
December 28, 2018.

10.39

10-K

001-32395

10.40

Form of Key Employee Award Terms and Conditions, as part of the
ConocoPhillips Targeted Variable Long Term Incentive Program, granted under
the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips,
dated September 23, 2019.

10.1

10-Q

001-32395

10.41

ConocoPhillips Executive Restricted Stock Unit Program, dated February 11,
2020.

10.1

10-Q

001-32395

ConocoPhillips 2021 10-K 184

10.42

10.43

Form of Retention Award Terms and Conditions, as part of the Restricted
Stock Unit Award, granted under the 2014 Omnibus Stock and Performance
Incentive Plan of ConocoPhillips.

10.1

10-Q

001-32395

Form of Inducement Grant Award Agreement under the 2014 Omnibus Stock
and Performance Incentive Plan of ConocoPhillips, dated January 15, 2021.

10.3

10-Q

001-32395

10.44

Compensation Resolutions regarding Matthew J. Fox, dated April 8, 2021.

10.1

10-Q

001-32395

10.45

10.46

Form of Aircraft Time Sharing Agreement by and between certain executives
and ConocoPhillips dated June 21, 2021.

10.2

10-Q

001-32395

Purchase and Sale Agreement, dated as of September 20, 2021, by and
between Shell Enterprises LLC and ConocoPhillips.

10.1

10-Q

001-32395

10.47*

Amendment and Restatement of ConocoPhillips Executive Severance Plan,
dated December 2, 2021.

21*

22*

23.1*

23.2*

31.1*

31.2*

List of Subsidiaries of ConocoPhillips.

Subsidiary Guarantors of Guaranteed Securities.

Consent of Ernst & Young LLP.

Consent of DeGolyer and MacNaughton.

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

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

32*

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

99* 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 contained in
Exhibit 101).

* Filed herewith.
† The schedules to this exhibit have been omitted pursuant to Item 601(b)(2) of Regulation S-K. ConocoPhillips agrees to furnish

a copy of any schedule omitted from this exhibit to the SEC upon request.

‡ ConocoPhillips has previously been granted confidential treatment for certain portions of this exhibit pursuant to Rule 24b-2

under the Securities Exchange Act of 1934, as amended.

185 ConocoPhillips 2021 10-K

Signature

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

February 17, 2022

CONOCOPHILLIPS

/s/ Ryan M. Lance
Ryan M. Lance
Chairman of the Board of Directors
and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed, as of February
17, 2022, on behalf of the registrant by the following officers in the capacity indicated and by a majority of
directors.

Signature

Title

/s/ Ryan M. Lance
Ryan M. Lance

/s/ William L. Bullock, Jr.
William L. Bullock, Jr.

Chairman of the Board of Directors
and Chief Executive Officer
(Principal executive officer)

Executive Vice President and
Chief Financial Officer
(Principal financial officer)

/s/ Kontessa S. Haynes-Welsh
Kontessa S. Haynes-Welsh

Chief Accounting Officer
(Principal accounting officer)

ConocoPhillips 2021 10-K 186

/s/ Charles E. Bunch
Charles E. Bunch

/s/ Caroline M. Devine
Caroline M. Devine

/s/ Gay Huey Evans
Gay Huey Evans

/s/ John V. Faraci
John V. Faraci

/s/ Jody Freeman
Jody Freeman

/s/ Jeffrey A. Joerres
Jeffrey A. Joerres

/s/ Timothy A. Leach
Timothy A. Leach

/s/ William H. McRaven
William H. McRaven

/s/ Sharmila Mulligan
Sharmila Mulligan

/s/ Eric D. Mullins
Eric D. Mullins

/s/ Arjun N. Murti
Arjun N. Murti

/s/ Robert A. Niblock
Robert A. Niblock

/s/ David T. Seaton
David T. Seaton

/s/ R.A. Walker
R.A. Walker

187 ConocoPhillips 2021 10-K

Director

Non-GAAP Financial Measures

USE OF NON-GAAP FINANCIAL INFORMATION
This annual report includes non-GAAP terms to help facilitate comparisons of company operating performance
across periods and with peer companies. The company believes that the non-GAAP measures included, when
viewed in combination with the company’s results prepared in accordance with GAAP, provide a more complete
understanding of the factors and trends affecting the company’s business and performance. The board of directors
and management also use these non-GAAP measures to analyze operating performance across periods when
overseeing and managing the company’s business. Reconciliations of any non-GAAP measures presented in the
annual report to the nearest corresponding GAAP measures are included both in the annual report and on our
website at www.conocophillips.com/nongaap.

CASH FROM OPERATIONS
Cash provided by operating activities excluding the impact from operating working capital. The company believes
this measure is meaningful, as it provides insight into the cash flows generated by operating activities across periods
by excluding the timing effects associated with operating working capital changes.

FREE CASH FLOW
Cash from operations in excess of capital expenditures and investments. The company believes this measure is
meaningful, as it provides insight into the company’s ability to fund its current capital plan and future development
growth from its cash from operations. Free cash flow is not a measure of cash available for discretionary
expenditures, since the company has certain nondiscretionary obligations, such as debt service, that are not
deducted from the measure. Cash from operations is a non-GAAP term defined above.

RETURN ON CAPITAL EMPLOYED
Calculated as a ratio, the numerator of which is net income, and the denominator of which is average total equity plus
average total debt. The net income is adjusted for after‐tax interest expense, for the purposes of measuring efficiency
of debt capital used in operations; net income is also adjusted for nonoperational or special items impacts to allow for
comparability in the long-term view across periods. Return on capital employed (ROCE) is a measure of the profitability
of the company’s capital employed in its business operations compared with that of its peers. The company believes
ROCE is a good indicator of long-term company and management performance as it relates to capital efficiency, both
absolute and relative to the company’s primary peer group.

RECONCILIATION OF RETURN ON CAPITAL EMPLOYED (ROCE)
$ Millions, except as indicated

FOR THE YEAR ENDED
DEC. 31, 2021

NUMERATOR
Net Income (Loss) Attributable to ConocoPhillips

Adjustment to exclude special items
After-tax interest expense

ROCE earnings
DENOMINATOR
Average total equity¹
Average total debt²
Average capital employed
ROCE (percent)

8,079
(79)
698
8,698

42,293
19,338
61,631
14%

¹ Average total equity is the average of beginning total equity and ending total equity by quarter.

2 Average total debt is the average of beginning long-term debt and short-term debt and ending long-term debt and short-term debt by quarter.

Other Terms

RESOURCES
Based on the Petroleum Resources Management System, a system developed by industry that classifies recoverable
hydrocarbons into commercial and sub-commercial to reflect their status at the time of reporting. Proved, probable
and possible reserves are classified as commercial, while remaining resources are categorized as sub-commercial or
contingent. The company’s resource estimate includes volumes associated with both commercial and contingent
categories. The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and
possible reserves. U.S. investors are urged to consider closely the oil and gas disclosures in our Form 10-K and other
reports and filings with the SEC.

RETURNS OF CAPITAL
The total of the ordinary dividend, share repurchases and variable return of cash (VROC). Also referred to as distributions.

Board of Directors
(As of Feb. 17, 2022)

Charles E. Bunch
Former Chairman and
Chief Executive Officer,
PPG Industries, Inc.

Caroline Maury Devine
Former President and
Managing Director of a
Norwegian affiliate of
ExxonMobil

John V. Faraci
Former Chairman and
Chief Executive Officer,
International Paper
Company

Jody Freeman
Archibald Cox Professor of
Law, Harvard Law School

Timothy A. Leach
Executive Vice President,
Lower 48, ConocoPhillips

Gay Huey Evans CBE
Chairman, London
Metal Exchange

William H. McRaven
Retired U.S. Navy Four-Star
Admiral (SEAL)

Jeffrey A. Joerres
Former Executive Chairman
and Chief Executive Officer,
ManpowerGroup Inc.

Ryan M. Lance
Chairman and Chief
Executive Officer,
ConocoPhillips

Sharmila Mulligan
Former Chief Strategy
Officer, Alteryx

Eric D. Mullins
Chairman and Chief
Executive Officer,
Lime Rock Resources

Arjun N. Murti
Senior Advisor, Warburg Pincus

Robert A. Niblock
Former Chairman, President
and Chief Executive Officer,
Lowe’s Companies, Inc.

David T. Seaton
Former Chairman and
Chief Executive Officer,
Fluor Corporation

R.A. Walker
Former Chairman and Chief
Executive Officer, Anadarko
Petroleum Corporation

Executive Leadership Team
(As of Feb. 17, 2022)

Ryan M. Lance
Chairman and Chief
Executive Officer

Timothy A. Leach
Executive Vice President,
Lower 48

William L. Bullock, Jr.
Executive Vice President
and Chief Financial Officer

Andrew D. Lundquist
Senior Vice President,
Government Affairs

Dominic E. Macklon
Executive Vice President,
Strategy, Sustainability
and Technology

Nicholas G. Olds
Executive Vice President,
Global Operations

Kelly B. Rose
Senior Vice President,
Legal and General Counsel

Heather G. Sirdashney
Senior Vice President,*
Human Resources and Real
Estate and Facility Services

*As of March 1, 2022

Explore ConocoPhillips

Fact Sheets
Published annually to provide detailed
operational updates for each of the
company’s six segments.
www.conocophillips.com/factsheets

Sustainability Report
Published annually to provide details on
priority reporting issues for the company, a
letter from our CEO and key environmental,
social and governance metrics.
www.conocophillips.com/susdev

Managing Climate-Related
Risks Report
Published annually to provide details on
the company’s governance framework,
risk management approach, strategy,
key metrics and targets for climate-
related issues.
www.conocophillips.com/climatechange

Human Capital
Management Report
Published annually to provide details
of the actions the company is taking
to inspire a compelling culture, attract
and retain great people and meet our
commitments to all stakeholders.
www.conocophillips.com/hcmreport

Upcoming and Past
Investor Presentations
Provides notice of future presentations
and archived presentations dating back
one year, including webcast replays,
transcripts, slides and other information.
www.conocophillips.com/
investorpresentations

Certain disclosures in this annual report may be considered “forward-looking” statements. These are made pursuant to “safe harbor” provisions of the Private Securities Litigation Reform Act of
1995. The “Cautionary Statement” in the Management’s Discussion and Analysis in ConocoPhillips’ 2021 Form 10-K should be read in conjunction with such statements.
“ConocoPhillips,” “the company,” “we,” “us” and “our” are used interchangeably in this report to refer to the businesses of ConocoPhillips and its consolidated
subsidiaries.
Cautionary Note to U.S. Investors – The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible
reserves. We use the terms “resource” and “resources” in this annual report, which the SEC’s guidelines prohibit us from including in filings with the SEC. U.S.
investors are urged to consider closely the oil and gas disclosures in our Form 10-K and other reports and filings with the SEC. Copies are available from the
SEC and on the ConocoPhillips website.

ACHIEVE
NET-ZERO
EMISSIONS AMBITION 1

TRIPLE MANDATE
ConocoPhillips intends to play a valued role in the energy transition
by executing three objectives: meeting transition pathway demand, delivering
competitive returns on and of capital, and achieving our net-zero emissions
ambition. We call this commitment the Triple Mandate, and it represents
our commitment to create long-term value for our stakeholders.
We view each element of the Triple Mandate as equal in importance.

1Scope 1 and 2 emissions on a net equity and gross operated basis.

MEET TRANSITIONPATHWAY DEMANDDELIVER COMPETITIVE RETURNS