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https://cdn.kscope.io/a53cc0fe28023468692579122b15c7b9-cop10k2021p1i0.jpg
 
 
 
 
 
 
 
 
 
 
 
 
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
01-0562944
 
(State or other jurisdiction of incorporation
 
or organization)
(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
Trading symbols
Name of each exchange on which registered
 
Common Stock, $.01 Par Value
COP
New York Stock Exchange
 
7% Debentures due 2029
CUSIP—718507BK1
 
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer,
 
as defined in Rule 405 of the Securities Act.
 
[x]
Yes
 
[ ] No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
 
[ ] Yes
 
[x]
 
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.
Documents incorporated by reference:
Portions of the Proxy Statement for
 
the Annual Meeting of Stockholders to be held on May 10, 2022 (Part III)
Commonly Used Abbreviations
 
1
 
ConocoPhillips
 
2021 10-K
Commonly Used Abbreviations
The following industry-specific, accounting
 
and other terms, and abbreviations may
 
be commonly used in this
report.
Currencies
Accounting
$ or USD
U.S. dollar
ARO
asset retirement obligation
CAD
Canadian dollar
ASC
accounting standards codification
EUR
Euro
ASU
accounting standards update
GBP
British pound
DD&A
depreciation, depletion and
amortization
Units of Measurement
FASB
Financial Accounting Standards
BBL
barrel
Board
BCF
billion cubic feet
FIFO
first-in, first-out
BOE
barrels of oil equivalent
G&A
general and administrative
MBD
thousands of barrels per day
GAAP
generally accepted accounting
 
MCF
thousand cubic feet
principles
MBOD
thousand barrels of oil per day
LIFO
last-in, first-out
MM
million
NPNS
normal purchase normal sale
MMBOE
million barrels of oil equivalent
PP&E
properties, plants and equipment
MMBOD
million barrels of oil per day
VIE
variable interest entity
MBOED
thousands of barrels of oil
 
equivalent per day
MMBOED
millions of barrels of oil
Miscellaneous
equivalent per day
DE&I
diversity,
 
equity and inclusion
MMBTU
million British thermal units
EPA
Environmental Protection
 
Agency
MMCFD
million cubic feet per day
ESG
Environmental, Social and
Governance
EU
European Union
Industry
FERC
Federal Energy Regulatory
 
BLM
Bureau of Land Management
Commission
CBM
coalbed methane
GHG
greenhouse gas
E&P
exploration and production
HSE
health, safety and environment
CCUS
carbon capture utilization
 
and
storage
ICC
International Chamber of
Commerce
 
FEED
front-end engineering and design
ICSID
World Bank’s
 
International
 
FPS
floating production system
Centre for Settlement of
FPSO
floating production, storage
 
and
Investment Disputes
offloading
IRS
Internal Revenue Service
G&G
geological and geophysical
OTC
over-the-counter
JOA
joint operating agreement
NYSE
New York Stock Exchange
LNG
liquefied natural gas
SEC
U.S. Securities and Exchange
 
NGLs
natural gas liquids
Commission
OPEC
Organization of Petroleum
 
TSR
total shareholder return
Exporting Countries
U.K.
United Kingdom
PSC
production sharing contract
U.S.
United States of America
PUDs
proved undeveloped reserves
VROC
variable return of cash
SAGD
steam-assisted gravity
 
drainage
WCS
Western Canada Select
WTI
West Texas
 
Intermediate
Business and Properties
 
ConocoPhillips
 
2021 10-K
 
2
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 pa
ge
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
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
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,
 
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.
 
 
 
 
 
 
 
 
 
Business and Properties
 
3
 
ConocoPhillips
 
2021 10-K
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
 
Net Proved Reserves at December
 
31
2021
2020
2019
Crude oil
 
Consolidated operations
2,964
2,051
2,562
Equity affiliates
63
68
73
Total
 
Crude Oil
 
3,027
2,119
2,635
Natural gas liquids
Consolidated operations
644
340
361
Equity affiliates
33
36
39
Total
 
Natural Gas Liquids
677
376
400
Natural gas
Consolidated operations
1,523
1,011
1,209
Equity affiliates
617
621
736
Total
 
Natural Gas
2,140
1,632
1,945
Bitumen
Consolidated operations
257
332
282
Total
 
Bitumen
257
332
282
Total
 
consolidated operations
5,388
3,734
4,414
Total
 
equity affiliates
713
725
848
Total
 
company
6,101
4,459
5,262
 
 
 
 
 
 
Business and Properties
 
ConocoPhillips
 
2021 10-K
 
4
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.
2021
Crude Oil
NGL
Natural Gas
Total
Interest
Operator
MBD
MBD
MMCFD
MBOED
Average Daily Net Production
Greater Prudhoe Area
36.1
%
Hilcorp
67
16
12
85
Greater Kuparuk Area
89.2-94.7
ConocoPhillips
73
-
2
73
Western North Slope
100.0
ConocoPhillips
38
-
2
39
Total
 
Alaska
178
16
16
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-tubi
 
ng 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.
 
Business and Properties
 
5
 
ConocoPhillips
 
2021 10-K
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,
 
 
 
 
 
 
 
Business and Properties
 
ConocoPhillips
 
2021 10-K
 
6
2021
Crude Oil
NGL
Natural Gas
Total
MBD
MBD
MMCFD
MBOED
Average Daily Net Production
Delaware Basin
162
27
584
286
Midland Basin
89
9
229
136
Permian—Other
11
2
40
20
 
Total
 
Permian
262
38
853
442
Eagle Ford
116
53
251
211
Bakken
59
16
117
94
Gulf Coast and Rockies—Other
10
3
119
33
 
Total
 
Gulf Coast and Rockies
185
72
487
338
Total
 
Lower 48
447
110
1,340
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.
 
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.
 
 
 
 
 
 
 
Business and Properties
 
7
 
ConocoPhillips
 
2021 10-K
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.
2021
Crude Oil
NGL
Natural Gas
Bitumen
Total
Interest
Operator
MBD
MBD
MMCFD
MBD
MBOED
Average Daily Net
Production
Surmont
50.0
%
ConocoPhillips
-
-
-
69
69
Montney
100.0
ConocoPhillips
8
4
80
-
25
Total
 
Canada
8
4
80
69
94
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 Total
 
Energies 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.
 
 
 
 
 
 
Business and Properties
 
ConocoPhillips
 
2021 10-K
 
8
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
2021
Crude Oil
NGL
Natural Gas
Total
Interest
Operator
MBD
MBD
MMCFD
MBOED
Average Daily Net Production
Greater Ekofisk Area
30.7-35.1
%
ConocoPhillips
49
2
41
58
Heidrun
24.0
Equinor
13
1
35
20
Aasta Hansteen
10.0
Equinor
-
-
84
14
Alvheim
20.0
Aker BP
9
-
13
11
Troll
1.6
Equinor
2
-
58
11
Visund
9.1
Equinor
2
1
46
11
Other
Various
Equinor
6
-
21
10
Total
 
Norway
81
4
298
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.
 
 
 
 
 
 
 
 
 
 
Business and Properties
 
9
 
ConocoPhillips
 
2021 10-K
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
2021
Crude Oil
NGL
Natural
Gas
Total
Interest
Operator
MBD
MBD
MMCFD
MBOED
Average Daily Net Production
Qatargas Operating
QG3
30.0
%
Company Limited
13
8
373
83
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
 
2021
Crude Oil
NGL
Natural Gas
Total
Interest
Operator
MBD
MBD
MMCFD
MBOED
Average Daily Net Production
Waha Concession
16.3
%
Waha Oil Co.
37
-
15
40
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.
 
 
 
 
 
 
 
 
 
 
 
Business and Properties
 
ConocoPhillips
 
2021 10-K
 
10
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
2021
Crude Oil
NGL
Natural Gas
Total
Interest
Operator
MBD
MBD
MMCFD
MBOED
Average Daily Net Production
ConocoPhillips/
Australia Pacific LNG
37.5
%
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,
 
and
 
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 interes
 
t
 
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
2021
Crude Oil
NGL
Natural Gas
Total
Interest
Operator
MBD
MBD
MMCFD
MBOED
Average Daily Net Production
South Sumatra
54
%
ConocoPhillips
2
-
294
51
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.
 
 
 
 
 
Business and Properties
 
11
 
ConocoPhillips
 
2021 10-K
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
2021
Crude Oil
NGL
Natural Gas
Total
Interest
Operator
MBD
MBD
MMCFD
MBOED
Average Daily Net Production
Penglai
49.0
%
CNOOC
28
-
-
28
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.
 
 
 
 
 
 
Business and Properties
 
ConocoPhillips
 
2021 10-K
 
12
Malaysia
2021
Crude Oil
NGL
Natural Gas
Total
Interest
Operator
MBD
MBD
MMCFD
MBOED
Average Daily Net Production
Gumusut
29.5
%
Shell
19
-
-
19
Malikai
35.0
Shell
13
-
-
13
Kebabangan (KBB)
30.0
KPOC
2
-
66
13
Siakap North-Petai
21.0
PTTEP
1
-
-
1
Total
 
Malaysia
35
-
66
46
We have varying stages
 
of exploration, development and
 
production activities across approx
 
imately 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 Janu
 
ary 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.
Business and Properties
 
13
 
ConocoPhillips
 
2021 10-K
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.
 
Venezuela
For discussion of our contingencies in Venezuela,
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.
 
Business and Properties
 
ConocoPhillips
 
2021 10-K
 
14
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 Technologi
 
es 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.
Business and Properties
 
15
 
ConocoPhillips
 
2021 10-K
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.
 
Business and Properties
 
ConocoPhillips
 
2021 10-K
 
16
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.
 
 
 
 
 
 
 
Business and Properties
 
17
 
ConocoPhillips
 
2021 10-K
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
U.S.
Male
Female
White
POC
*
All Employees
74
%
26
%
72
%
28
%
All Leadership
75
25
79
21
Top Leadership
78
22
85
15
Junior Leadership
75
25
77
23
*"POC" refers to People of Color or racial and ethnic minorities self-reported in the U.S.
2021 Employees by Country
Percent of Total
U.S.
61
%
Norway
18
Canada
8
Indonesia
5
Great Britain
3
Australia
3
China
1
Other Global Locations
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.
 
 
Business and Properties
 
ConocoPhillips
 
2021 10-K
 
18
2021 Hiring & Attrition Metrics
Percent of Total
U.S. University hire acceptance
81
%
U.S. Interns acceptance
76
Diversity hiring - Women
23
Diversity hiring - U.S. POC
35
Total
 
voluntary attrition
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 promot
 
ing
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.
Business and Properties
 
19
 
ConocoPhillips
 
2021 10-K
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
.
Risk Factors
 
ConocoPhillips
 
2021 10-K
 
20
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
.
 
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
Risk Factors
 
21
 
ConocoPhillips
 
2021 10-K
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.
 
, 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 comp
 
etitive 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-
Risk Factors
 
ConocoPhillips
 
2021 10-K
 
22
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.
Risk Factors
 
23
 
ConocoPhillips
 
2021 10-K
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
Risk Factors
 
ConocoPhillips
 
2021 10-K
 
24
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 reduc
 
ing 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
Risk Factors
 
25
 
ConocoPhillips
 
2021 10-K
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,
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.
Risk Factors
 
ConocoPhillips
 
2021 10-K
 
26
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.
Risk Factors
 
27
 
ConocoPhillips
 
2021 10-K
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.
Risk Factors
 
ConocoPhillips
 
2021 10-K
 
28
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.
Risk Factors
 
29
 
ConocoPhillips
 
2021 10-K
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 adversel
 
y
 
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.
 
 
 
ConocoPhillips
 
2021 10-K
 
30
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.
 
 
for a description of such
legal and administrative
 
proceedings.
Item 4.
 
Mine Safety Disclosures
 
Not applicable.
Information about our Executive
 
Officers
Name
Position Held
Age*
William L. Bullock, Jr.
Executive Vice President and Chief
 
Financial Officer
57
Kontessa S. Haynes-Welsh
Chief Accounting Officer
47
Ryan M. Lance
Chairman of the Board of Directors
 
and Chief Executive Officer
59
Timothy A. Leach
Executive Vice President, Lower
 
48
62
Andrew D. Lundquist
Senior Vice President, Government Affairs
61
Dominic E. Macklon
Executive Vice President, Strategy,
 
Sustainability and Technology
52
Nicholas G. Olds
Executive Vice President, Global
 
Operations
52
Kelly B. Rose
Senior Vice President, Legal, General
 
Counsel
55
Heather G. Sirdashney
Vice President, Human Resources
 
and Real Estate and Facilities
 
Services
49
 
*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.
 
 
31
 
ConocoPhillips
 
2021 10-K
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 Tec
 
hnology 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.
 
 
 
 
 
 
 
 
 
 
 
ConocoPhillips
 
2021 10-K
 
32
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
Dividends
2021
2020
First
$
0.430
0.420
Second
0.430
0.420
Third
0.430
0.420
Fourth
0.460
0.430
Number of Stockholders of Record
 
at January 31, 2022*
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
Issuer Purchases of Equity Securities
Millions of Dollars
Approximate Dollar
Shares Purchased
Value of Shares
Average
as Part of Publicly
 
that May Yet
 
Be
Total
 
Number of
Price Paid
 
Announced Plans
Purchased Under the
Period
 
Shares Purchased
*
Per Share
 
or Programs
Plans or Programs
October 1-31, 2021
6,100,833
$
73.36
6,100,833
$
11,811
November 1-30, 2021
6,367,204
73.42
6,367,204
11,344
December 1-31, 2021
6,751,987
71.65
6,751,987
10,860
19,220,024
$
19,220,024
* 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
https://cdn.kscope.io/a53cc0fe28023468692579122b15c7b9-cop10k2021p35i0.gif
 
33
 
ConocoPhillips
 
2021 10-K
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.
Management’s Discussion and Analysis
 
ConocoPhillips
 
2021 10-K
 
34
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
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.
 
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.
 
.
 
 
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.
 
Management’s Discussion and Analysis
 
35
 
ConocoPhillips
 
2021 10-K
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.
 
 
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,
 
and for
more information on pending dispositions,
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.
 
Management’s Discussion and Analysis
 
ConocoPhillips
 
2021 10-K
 
36
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.
Management’s Discussion and Analysis
 
37
 
ConocoPhillips
 
2021 10-K
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.
 
 
Management’s Discussion and Analysis
 
ConocoPhillips
 
2021 10-K
 
38
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
 
.
o
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.
 
o
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.
 
 
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.
 
Management’s Discussion and Analysis
 
39
 
ConocoPhillips
 
2021 10-K
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 operati
 
onal 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:
https://cdn.kscope.io/a53cc0fe28023468692579122b15c7b9-cop10k2021p42i0.gif
Management’s Discussion and Analysis
 
ConocoPhillips
 
2021 10-K
 
40
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.
 
Management’s Discussion and Analysis
 
41
 
ConocoPhillips
 
2021 10-K
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
 
and
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 investme
 
nts 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.
 
 
 
 
Results of Operations
 
ConocoPhillips
 
2021 10-K
 
42
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:
Millions of Dollars
Years Ended
 
December 31
2021
2020
2019
Alaska
$
1,386
(719)
1,520
Lower 48
4,932
(1,122)
436
Canada
458
(326)
279
Europe, Middle East and North Africa
1,167
448
3,170
Asia Pacific
453
962
1,483
Other International
(107)
(64)
263
Corporate and Other
(210)
(1,880)
38
Net income (loss) attributable to
 
ConocoPhillips
$
8,079
(2,701)
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.
 
.
 
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
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.
o
Lower dry hole expenses.
o
Absence of early cancellation of our 2020 winter exploration
 
program in Alaska.
o
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.
 
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.
 
 
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.
 
 
 
 
 
 
 
 
 
 
 
 
 
Results of Operations
 
43
 
ConocoPhillips
 
2021 10-K
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.
 
.
 
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.
 
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,
 
and
 
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
 
for information regardin
 
g
 
our income tax provision
 
and effective tax rate.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Results of Operations
 
ConocoPhillips
 
2021 10-K
 
44
Summary Operating Statistics
2021
2020
2019
Average Net Production
Crude oil (MBD)
Consolidated Operations
816
555
692
Equity affiliates
13
13
13
Total
 
crude oil
829
568
705
Natural gas liquids (MBD)
Consolidated Operations
134
97
107
Equity affiliates
8
8
8
Total
 
natural gas liquids
142
105
115
Bitumen (MBD)
69
55
60
Natural gas (MMCFD)
Consolidated Operations
2,109
1,339
1,753
Equity affiliates
1,053
1,055
1,052
Total
 
natural gas
3,162
2,394
2,805
Total Production
 
(MBOED)
1,567
1,127
1,348
Dollars Per Unit
Average Sales Prices
 
Crude oil (per bbl)
Consolidated Operations
$
67.61
39.56
60.98
Equity affiliates
69.45
39.02
61.32
Total
 
crude oil
67.64
39.54
60.99
Natural gas liquids (per bbl)
Consolidated Operations
31.04
12.90
18.73
Equity affiliates
54.16
32.69
36.70
Total
 
natural gas liquids
32.45
14.61
20.09
Bitumen (per bbl)
37.52
8.02
31.72
Natural gas (per mcf)
Consolidated Operations
6.00
3.17
4.25
Equity affiliates
5.31
3.71
6.29
Total
 
natural gas
5.77
3.41
5.03
Millions of Dollars
Worldwide Exploration
 
Expenses
General and administrative;
 
geological and geophysical,
lease rental, and other
$
300
374
322
Leasehold impairment
10
868
221
Dry holes
34
215
200
Total
 
Exploration Expenses
$
344
1,457
743
Results of Operations
 
45
 
ConocoPhillips
 
2021 10-K
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,
China, Malaysia, Qatar and Libya.
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.
 
 
 
 
 
 
Results of Operations
 
ConocoPhillips
 
2021 10-K
 
46
Alaska
2021
2020
2019
Net Income (Loss) Attributable
 
to ConocoPhillips
($MM)
$
1,386
(719)
1,520
Average Net Production
Crude oil (MBD)
178
181
202
Natural gas liquids (MBD)
16
16
15
Natural gas (MMCFD)
16
10
7
Total Production
 
(MBOED)
197
198
218
Average Sales Prices
 
Crude oil ($ per bbl)
$
69.87
42.12
64.12
Natural gas ($ per mcf)
2.81
2.91
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.
 
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.
 
 
 
 
 
 
Results of Operations
 
47
 
ConocoPhillips
 
2021 10-K
Lower 48
2021
2020
2019
Net Income (Loss) Attributable
 
to ConocoPhillips
($MM)
$
4,932
(1,122)
436
Average Net Production
Crude oil (MBD)
447
213
266
Natural gas liquids (MBD)*
110
74
81
Natural gas (MMCFD)*
1,340
585
622
Total Production
 
(MBOED)
780
385
451
Average Sales Prices
 
Crude oil ($ per bbl)**
$
66.12
35.17
55.30
Natural gas liquids ($ per bbl)
30.63
12.13
16.83
Natural gas ($ per mcf)**
4.38
1.65
2.12
*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.
 
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
 
and
Higher gains on dispositions related to
 
selling our interests in certain noncore
 
assets.
 
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
 
and
.
 
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.
 
 
 
 
 
 
Results of Operations
 
ConocoPhillips
 
2021 10-K
 
48
Canada
2021*
2020*
2019**
Net Income (Loss) Attributable
 
to ConocoPhillips
($MM)
$
458
(326)
279
Average Net Production
Crude oil (MBD)
8
6
1
Natural gas liquids (MBD)
4
2
-
Bitumen (MBD)
69
55
60
Natural gas (MMCFD)
80
40
9
Total Production
 
(MBOED)
94
70
63
Average Sales Prices
 
Crude oil ($ per bbl)
$
56.38
23.57
40.87
Natural gas liquids ($ per bbl)
31.18
5.41
19.87
Bitumen ($ per bbl)
37.52
8.02
31.72
Natural gas ($ per mcf)
2.54
1.21
0.49
 
*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.
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.
 
 
 
 
 
 
Results of Operations
 
49
 
ConocoPhillips
 
2021 10-K
Europe, Middle East and North Africa
2021
2020
2019
Net Income (Loss) Attributable
 
to ConocoPhillips
($MM)
$
1,167
448
3,170
Consolidated Operations
Average Net Production
Crude oil (MBD)
118
86
138
Natural gas liquids (MBD)
4
4
7
Natural gas (MMCFD)
313
275
478
Total Production
 
(MBOED)
175
136
224
Average Sales Prices
 
Crude oil ($ per bbl)
$
68.97
43.30
64.94
Natural gas liquids ($ per bbl)
43.97
23.27
29.37
Natural gas ($ per mcf)
13.27
3.23
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.
 
 
 
 
 
 
Results of Operations
 
ConocoPhillips
 
2021 10-K
 
50
Asia Pacific
2021
2020
2019
Net Income (Loss) Attributable
 
to ConocoPhillips
($MM)
$
453
962
1,483
Consolidated Operations
Average Net Production
Crude oil (MBD)
65
69
85
Natural gas liquids (MBD)
-
1
4
Natural gas (MMCFD)
360
429
637
Total Production
 
(MBOED)
125
141
196
Average Sales Prices
 
Crude oil ($ per bbl)
$
70.36
42.84
65.02
Natural gas liquids ($ per bbl)
-
33.21
37.85
Natural gas ($ per mcf)
6.56
5.39
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
 
and
Absence of a $597 million after-tax gain
 
related to our Australia
 
-West divestiture.
 
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
 
and
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.
 
 
 
 
 
 
 
 
Results of Operations
 
51
 
ConocoPhillips
 
2021 10-K
Other International
2021
2020
2019
Net Income (Loss) Attributable
 
to ConocoPhillips
($MM)
$
(107)
(64)
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.
 
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
Millions of Dollars
2021
2020
2019
Net Income (Loss) Attributable
 
to ConocoPhillips
Net interest
$
(801)
(662)
(604)
Corporate general and administrative
 
expenses
(317)
(200)
(252)
Technology
25
(26)
123
Other
883
(992)
771
$
(210)
(1,880)
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.
 
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
 
.
 
 
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.
 
 
 
 
Capital Resources and Liquidity
 
ConocoPhillips
 
2021 10-K
 
52
Capital Resources and Liquidity
Financial Indicators
Millions of Dollars
Except as Indicated
2021
2020
2019
Net cash provided by operating
 
activities
$
16,996
4,802
11,104
Cash and cash equivalents
5,028
2,991
5,088
Short-term investments
446
3,609
3,028
Short-term debt
1,200
619
105
Total
 
debt
19,934
15,369
14,895
Total
 
equity
45,406
29,849
35,050
Percent of total debt to
 
capital*
31
%
34
30
Percent of floating-rate
 
debt to total debt
4
%
7
5
*Capital includes total debt and total equity.
To meet our
 
short-
 
and long-term liquidity requirements,
 
we look to a variety of funding sources,
 
including cash
generated from operating
 
activities, proceeds from asset sales,
 
our commercial paper and credit facility programs
and our ability to sell securities using our shelf registration
 
statement.
 
In 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;
Capital Resources and Liquidity
 
53
 
ConocoPhillips
 
2021 10-K
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,
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 sta
 
tement of cash flows.
 
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.
 
 
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.
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.
 
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
Capital Resources and Liquidity
 
ConocoPhillips
 
2021 10-K
 
54
price downturns and to capture opportunities
 
outside a given operating plan may
 
be invested in instruments
 
with
maturities greater than one year.
 
 
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
 
and
 
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.
Capital Resources and Liquidity
 
55
 
ConocoPhillips
 
2021 10-K
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.
 
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
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.
 
 
 
 
 
Capital Resources and Liquidity
 
ConocoPhillips
 
2021 10-K
 
56
Capital Expenditures and Investments
Millions of Dollars
2021
2020
2019
Alaska
$
982
1,038
1,513
Lower 48
3,129
1,881
3,394
Canada
203
651
368
Europe, Middle East and North Africa
534
600
708
Asia Pacific
390
384
584
Other International
33
121
8
Corporate and Other
53
40
61
Capital Program*
$
5,324
4,715
6,636
* Excludes capital related to acquisitions of businesses, net of capital acquired.
 
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.
 
 
 
 
 
 
 
Capital Resources and Liquidity
 
57
 
ConocoPhillips
 
2021 10-K
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 exclud
 
ed 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.
 
and
.
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
$
30,457
Income (loss) before income taxes*
8,017
Net income (loss)
8,079
Net Income (Loss) Attributable
 
to ConocoPhillips
8,079
*Includes approximately $5.4 billion of purchased commodities expense for transactions with Non-Obligated Subsidiaries.
Summarized Balance Sheet Data
Millions of Dollars
December 31, 2021
Current assets
$
7,689
Amounts due from Non-Obligated Subsidiaries, current
1,927
Noncurrent assets
69,841
Amounts due from Non-Obligated Subsidiaries, noncurrent
7,281
Current liabilities
8,005
Amounts due to Non-Obligated Subsidiaries,
 
current
3,477
Noncurrent liabilities
30,677
Amounts due to Non-Obligated Subsidiaries,
 
noncurrent
13,007
 
 
Capital Resources and Liquidity
 
ConocoPhillips
 
2021 10-K
 
58
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
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.
 
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.
Capital Resources and Liquidity
 
59
 
ConocoPhillips
 
2021 10-K
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.
Capital Resources and Liquidity
 
ConocoPhillips
 
2021 10-K
 
60
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.
 
and
 
for information
on environmental litigatio
 
n.
 
 
Capital Resources and Liquidity
 
61
 
ConocoPhillips
 
2021 10-K
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 21
st
 
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.
 
Capital Resources and Liquidity
 
ConocoPhillips
 
2021 10-K
 
62
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.
 
 
and
 
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.
 
 
 
 
Capital Resources and Liquidity
 
63
 
ConocoPhillips
 
2021 10-K
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.
 
 
 
ConocoPhillips
 
2021 10-K
 
64
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.
 
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.
 
 
 
65
 
ConocoPhillips
 
2021 10-K
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,
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 estimat
 
ed 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.
 
 
ConocoPhillips
 
2021 10-K
 
66
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.
 
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.
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.
 
Differing assumptions could
 
affect the timing and the amount of an
impairment in any period.
 
See
 
and
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
 
67
 
ConocoPhillips
 
2021 10-K
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.
 
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.
 
 
ConocoPhillips
 
2021 10-K
 
68
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
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 prevai
 
ling oil and gas prices).
 
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.
 
 
regarding discussion of critical accounting
 
estimates on deferred
 
tax valuation allowances.
 
 
69
 
ConocoPhillips
 
2021 10-K
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 operatio
 
ns 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
 
70
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
 
in this 2021 Annual Report on Form 10-K and any
additional risks described in our other filings with the SEC.
 
71
 
ConocoPhillips
 
2021 10-K
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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
ConocoPhillips
 
2021 10-K
 
72
Millions of Dollars Except as Indicated
 
Debt
Fixed
Average
Floating
Average
Rate
Interest
Rate
Interest
Expected Maturity Date
Maturity
Rate
Maturity
 
Rate
Year-End 2021
2022
$
346
2.53
%
$
500
1.03
%
2023
116
6.64
-
-
2024
459
3.51
-
-
2025
369
5.32
-
-
2026
1,355
5.06
-
-
Remaining years
14,338
5.80
283
0.11
Total
$
16,983
$
783
Fair value
$
21,668
$
783
Year-End 2020
2021
$
133
8.47
%
$
300
0.22
%
2022
346
2.53
500
1.12
2023
110
7.03
-
-
2024
459
3.51
-
-
2025
368
5.33
-
-
Remaining years
11,793
6.28
283
0.11
Total
$
13,209
$
1,083
Fair value
$
18,023
$
1,083
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.
 
 
 
 
 
 
 
 
73
 
ConocoPhillips
 
2021 10-K
The gross notional and fair value of these positions
 
at December 31, 2021 and 2020, were as follows
 
:
Foreign Currency Exchange
 
Derivatives
In Millions
 
Notional
Fair Value*
2021
2020
2021
2020
Sell Canadian dollar,
 
buy U.S. dollar
CAD
-
450
-
(16)
Buy Canadian dollar,
 
sell U.S. dollar
CAD
77
80
(1)
2
Buy Australian dollar,
 
sell U.S. dollar
AUD
1,850
-
21
-
Sell British pound, buy euro
GBP
239
8
(8)
-
Buy British pound, sell euro
GBP
394
3
7
-
*Denominated in USD.
For additional information about
 
our use of derivative instruments,
see Note 12
.
 
 
 
75
 
ConocoPhillips
 
2021 10-K
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 presentatio
 
n
 
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
/s/ William L. Bullock, Jr.
Ryan M. Lance
 
William L. Bullock, Jr.
Chairman and
Chief Executive Officer
 
Executive Vice President and
 
Chief Financial Officer
 
 
 
 
ConocoPhillips
 
2021 10-K
 
76
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.
 
 
77
 
ConocoPhillips
 
2021 10-K
Accounting for asset retirement
 
obligations for certain offshore properties
Description of
the Matter
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 remainin
 
g
 
useful lives of the assets.
Auditing the Company’s AROs for
 
the obligations identified above is
 
complex and highly
judgmental due to the significant
 
estimation required by management
 
in determining the
obligations. In particular,
 
the estimates were sensitive to
 
significant subjective assumptions
such as removal cost estimates
 
and end of field life, which are affected
 
by expectations
about future market or economic conditions.
How We
Addressed the
Matter in Our
Audit
We obtained an understanding,
 
evaluated the design and tested
 
the operating effectiveness
of the Company’s internal
 
controls over its ARO estimation
 
process, including management’s
review of the significant assumptions that
 
have a material effect on the
 
determination of the
obligations. We also
 
tested management’s controls
 
over the completeness and accuracy of
the financial data used in the valuation.
To test
 
the AROs for the obligations
 
identified above, our audit procedures included,
 
among
others, assessing the significant assumptions
 
and inputs used in the valuation, including
removal cost estimates
 
and end of field life assumptions. For example,
 
we evaluated
removal cost estimates
 
by comparing to settlements and
 
recent removal activities and costs.
We also compared end of field life
 
assumptions to production forecasts.
 
Depreciation, depletion and amortization of proved oil and
 
gas properties, plants and
equipment
Description of
the Matter
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.
 
ConocoPhillips
 
2021 10-K
 
78
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.
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
Description of
the Matter
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.
 
 
79
 
ConocoPhillips
 
2021 10-K
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
 
 
ConocoPhillips
 
2021 10-K
 
80
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.
 
81
 
ConocoPhillips
 
2021 10-K
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
 
 
 
 
 
 
 
 
 
 
 
Financial Statements
 
ConocoPhillips
 
2021 10-K
 
82
Consolidated Income Statement
 
ConocoPhillips
Years Ended
 
December 31
Millions of Dollars
2021
2020
2019
Revenues and Other Income
Sales and other operating revenues
$
45,828
18,784
32,567
Equity in earnings of affiliates
832
432
779
Gain on dispositions
486
549
1,966
Other income (loss)
 
1,203
(509)
1,358
Total
 
Revenues and Other Income
48,349
19,256
36,670
Costs and Expenses
Purchased commodities
18,158
8,078
11,842
Production and operating expenses
5,694
4,344
5,322
Selling, general and administrative
 
expenses
719
430
556
Exploration expenses
344
1,457
743
Depreciation, depletion and amortization
7,208
5,521
6,090
Impairments
674
813
405
Taxes
 
other than income taxes
1,634
754
953
Accretion on discounted liabilities
242
252
326
Interest and debt expense
884
806
778
Foreign currency transaction
 
(gains) losses
(22)
(72)
66
Other expenses
102
13
65
Total
 
Costs and Expenses
35,637
22,396
27,146
Income (loss) before income taxes
12,712
(3,140)
9,524
Income tax provision (benefit)
4,633
(485)
2,267
Net income (loss)
8,079
(2,655)
7,257
Less: net income attributable to noncontrolling
 
interests
-
(46)
(68)
Net Income (Loss) Attributable
 
to ConocoPhillips
$
8,079
(2,701)
7,189
Net Income (Loss) Attributable
 
to ConocoPhillips Per Share
of Common Stock
(dollars)
Basic
$
6.09
(2.51)
6.43
Diluted
6.07
(2.51)
6.40
Average Common Shares
 
Outstanding
(in thousands)
Basic
1,324,194
1,078,030
1,117,260
Diluted
1,328,151
1,078,030
1,123,536
See Notes to Consolidated Financial Statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Financial Statements
 
83
 
ConocoPhillips
 
2021 10-K
Consolidated Statement
 
of Comprehensive Income
 
ConocoPhillips
Years Ended
 
December 31
Millions of Dollars
2021
2020
2019
Net Income (Loss)
$
8,079
(2,655)
7,257
Other comprehensive income (loss)
Defined benefit plans
Prior service credit arising during the period
-
29
-
Reclassification adjustment for
 
amortization of prior
service credit included in net income (loss)
(38)
(32)
(35)
Net change
(38)
(3)
(35)
Net actuarial gain (loss) arising during the period
357
(210)
(55)
Reclassification adjustment for
 
amortization of net
actuarial losses included in net income (loss)
178
117
146
Net change
535
(93)
91
Nonsponsored plans*
5
1
(3)
Income taxes on defined benefit
 
plans
(108)
20
(2)
Defined benefit plans, net of tax
394
(75)
51
Unrealized holding gain (loss) on
 
securities
(2)
2
-
Reclassification adjustment for
 
loss included in net income
(1)
-
-
Income taxes on unrealized
 
holding loss on securities
1
-
-
Unrealized holding gain (loss) on securities,
 
net of tax
(2)
2
-
Foreign currency translation
 
adjustments
(124)
209
699
Income taxes on foreign
 
currency translation adjustments
-
3
(4)
Foreign currency translation
 
adjustments, net of tax
(124)
212
695
Other Comprehensive Income, Net of Tax
268
139
746
Comprehensive Income (Loss)
8,347
(2,516)
8,003
Less: comprehensive income attributable
 
to noncontrolling interests
-
(46)
(68)
Comprehensive Income (Loss) Attributable
 
to ConocoPhillips
$
8,347
(2,562)
7,935
*Plans for which ConocoPhillips is not the primary obligor—primarily those administered by equity
 
affiliates.
See Notes to Consolidated Financial Statements.
 
 
 
 
 
 
 
 
 
 
 
 
Financial Statements
 
ConocoPhillips
 
2021 10-K
 
84
Consolidated Balance Sheet
 
ConocoPhillips
At December 31
Millions of Dollars
2021
2020
Assets
Cash and cash equivalents
$
5,028
2,991
Short-term investments
446
3,609
Accounts and notes receivable (net of allowance
 
of $
2
 
and $
4
, respectively)
6,543
2,634
Accounts and notes receivable—related
 
parties
127
120
Investment in Cenovus Energy
1,117
1,256
Inventories
1,208
1,002
Prepaid expenses and other current
 
assets
1,581
454
Total
 
Current Assets
16,050
12,066
Investments and long-term receivables
7,113
8,017
Loans and advances—related parties
-
114
Net properties, plants and equipment
(net of accumulated DD&A of $
64,735
 
and $
62,213
, respectively)
64,911
39,893
Other assets
2,587
2,528
Total
 
Assets
$
90,661
62,618
Liabilities
Accounts payable
$
5,002
2,669
Accounts payable—related
 
parties
23
29
Short-term debt
1,200
619
Accrued income and other taxes
2,862
320
Employee benefit obligations
755
608
Other accruals
2,179
1,121
Total
 
Current Liabilities
12,021
5,366
Long-term debt
18,734
14,750
Asset retirement obligations
 
and accrued environmental costs
5,754
5,430
Deferred income taxes
6,179
3,747
Employee benefit obligations
1,153
1,697
Other liabilities and deferred credits
1,414
1,779
Total
 
Liabilities
45,255
32,769
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
21
18
Capital in excess of par
60,581
47,133
Treasury stock
 
(at cost: 2021—
789,319,875
 
shares; 2020—
730,802,089
 
shares)
(50,920)
(47,297)
Accumulated other comprehensive
 
loss
(4,950)
(5,218)
Retained earnings
40,674
35,213
Total
 
Equity
45,406
29,849
Total
 
Liabilities and Equity
$
90,661
62,618
See Notes to Consolidated Financial Statements.
 
 
 
 
 
 
 
 
 
 
 
 
Financial Statements
 
85
 
ConocoPhillips
 
2021 10-K
Consolidated Statement
 
of Cash Flows
 
ConocoPhillips
Years Ended
 
December 31
Millions of Dollars
2021
2020
2019
Cash Flows From Operating Activities
Net income (loss)
$
8,079
(2,655)
7,257
Adjustments to reconcile net income
 
(loss) to net cash provided by
 
operating activities
Depreciation, depletion and amortization
7,208
5,521
6,090
Impairments
674
813
405
Dry hole costs and leasehold impairments
44
1,083
421
Accretion on discounted liabilities
242
252
326
Deferred taxes
1,346
(834)
(444)
Undistributed equity earnings
446
645
594
Gain on dispositions
(486)
(549)
(1,966)
(Gain) loss on CVE common shares
(1,040)
855
(649)
Other
(788)
43
(351)
Working capital adjustments
Decrease (increase) in accounts and notes
 
receivable
(2,500)
521
505
Increase in inventories
(160)
(25)
(67)
Decrease (increase) in prepaid expenses
 
and other current
assets
(649)
76
37
Increase (decrease) in accounts payable
1,399
(249)
(378)
Increase (decrease) in taxes
 
and other accruals
3,181
(695)
(676)
Net Cash Provided by Operating
 
Activities
16,996
4,802
11,104
Cash Flows From Investing Activities
Capital expenditures and investments
(5,324)
(4,715)
(6,636)
Working capital changes
 
associated with investing activities
134
(155)
(103)
Acquisition of businesses, net of cash acquired
(8,290)
-
-
Proceeds from asset dispositions
1,653
1,317
3,012
Net sales (purchases) of investments
3,091
(658)
(2,910)
Collection of advances/loans—related parties
105
116
127
Other
87
(26)
(108)
Net Cash Used in Investing Activities
(8,544)
(4,121)
(6,618)
Cash Flows From Financing Activities
Issuance of debt
-
300
-
Repayment of debt
(505)
(254)
(80)
Issuance of company common stock
145
(5)
(30)
Repurchase of company common
 
stock
(3,623)
(892)
(3,500)
Dividends paid
(2,359)
(1,831)
(1,500)
Other
7
(26)
(119)
Net Cash Used in Financing Activities
(6,335)
(2,708)
(5,229)
Effect of Exchange
 
Rate Changes on Cash, Cash Equivalents
 
and
Restricted Cash
(34)
(20)
(46)
Net Change in Cash, Cash Equivalents and
 
Restricted Cash
2,083
(2,047)
(789)
Cash, cash equivalents and restricted
 
cash at beginning of period
3,315
5,362
6,151
Cash, Cash Equivalents and Restricted
 
Cash at End of Period
$
5,398
3,315
5,362
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.
 
 
 
 
 
 
 
 
 
Financial Statements
 
ConocoPhillips
 
2021 10-K
 
86
Consolidated Statement
 
of Changes in Equity
 
ConocoPhillips
Millions of Dollars
Attributable to ConocoPhillips
Common Stock
Par
Value
Capital in
Excess of
Par
Treasury
Stock
Accum. Other
Comprehensive
Income (Loss)
Retained
Earnings
Non-
Controlling
Interests
Total
Balances at December 31, 2018
$
18
46,879
(42,905)
(6,063)
34,010
125
32,064
Net income
7,189
68
7,257
Other comprehensive loss
746
746
Dividends declared—ordinary ($
1.34
 
per share of common stock)
(1,500)
(1,500)
Repurchase of company common stock
(3,500)
(3,500)
Distributions to noncontrolling interests and other
(128)
(128)
Distributed under benefit plans
104
104
Changes in Accounting Principles*
(40)
40
-
Other
3
4
7
Balances at December 31, 2019
$
18
46,983
(46,405)
(5,357)
39,742
69
35,050
Net income (loss)
(2,701)
46
(2,655)
Other comprehensive income
139
139
Dividends declared—ordinary ($
1.69
 
per share of common stock)
(1,831)
(1,831)
Repurchase of company common stock
(892)
(892)
Distributions to noncontrolling interests and other
(32)
(32)
Disposition
(84)
(84)
Distributed under benefit plans
150
150
Other
3
1
4
Balances at December 31, 2020
$
18
47,133
(47,297)
(5,218)
35,213
-
29,849
Net income
8,079
-
8,079
Other comprehensive income
268
268
Dividends declared
Ordinary ($
1.75
 
per share of common stock)
(2,359)
(2,359)
Variable return of cash ($
0.20
 
per share of common stock)
(260)
(260)
Acquisition of Concho
3
13,122
13,125
Repurchase of company common stock
(3,623)
(3,623)
Distributed under benefit plans
326
326
Other
1
-
1
Balances at December 31, 2021
$
21
60,581
(50,920)
(4,950)
40,674
-
45,406
*Cumulative effect of the adoption of ASU No. 2018-02, "Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income."
See Notes to Consolidated Financial Statements.
Notes to Consolidated Financial Statements
 
87
 
ConocoPhillips
 
2021 10-K
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.
 
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.
 
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
88
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
Notes to Consolidated Financial Statements
 
89
 
ConocoPhillips
 
2021 10-K
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.
 
Development Costs
—Costs incurred to drill and equip development
 
wells, including unsuccessful
development wells, are capital
 
ized.
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.
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
90
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.
 
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.
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
91
 
ConocoPhillips
 
2021 10-K
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:
Millions of Dollars
2021
2020
Crude oil and natural gas
$
647
461
Materials and supplies
561
541
Total
 
inventories
$
1,208
1,002
Inventories valued on
 
the LIFO basis
$
395
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 stat
 
ement.
 
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.
 
 
 
 
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
92
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)*
194,243
 
Number of shares of Concho stock awards
 
outstanding (in thousands)*
1,599
Number of shares exchanged
195,842
 
Exchange ratio
1.46
 
Additional shares of ConocoPhillips common stock
 
issued as consideration (in thousands)
285,929
 
Average price per share of ConocoPhillips
 
common stock**
$
45.9025
 
Total Consideration
 
(Millions)
$
13,125
 
*Outstanding as of January 15, 2021.
**Based on the ConocoPhillips average stock price on January 15, 2021.
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
Millions of Dollars
Cash and cash equivalents
$
382
Accounts receivable, net
745
Inventories
45
Prepaid expenses and other current
 
assets
37
Investments and long-term receivables
333
Net properties, plants and equipment
18,923
Other assets
62
Total assets
 
acquired
$
20,527
Liabilities Assumed
Accounts payable
$
638
Accrued income and other taxes
56
Employee benefit obligations
4
Other accruals
510
Long-term debt
4,696
Asset retirement obligations
 
and accrued environmental costs
310
Deferred income taxes
1,071
Other liabilities and deferred credits
117
Total liabilities
 
assumed
$
7,402
Net assets acquired
$
13,125
 
 
 
 
Notes to Consolidated Financial Statements
 
93
 
ConocoPhillips
 
2021 10-K
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:
Millions of Dollars
Transaction
 
Cost
Restructuring Cost
Total
 
Cost
Production and operating expenses
$
128
128
Selling, general and administration
 
expenses
135
67
202
Exploration expenses
18
8
26
Taxes
 
other than income taxes
4
2
6
Other expenses
-
29
29
$
157
234
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.
 
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.
 
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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
94
Assets Acquired
Millions of Dollars
Accounts receivable, net
$
337
Inventories
20
Net properties, plants and equipment
8,624
Other assets
50
Total assets
 
acquired
$
9,031
Liabilities Assumed
Accounts payable
$
211
Accrued income and other taxes
6
Other accruals
20
Asset retirement obligations
 
and accrued environmental costs
86
Other liabilities and deferred credits
36
Total liabilities
 
assumed
$
359
Net assets acquired
$
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 fo
 
r
 
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.
Millions of Dollars
Year Ended December 31, 2021
Pro forma
Pro forma
As reported
Shell
Combined
Total
 
Revenues and Other Income
$
48,349
3,220
51,569
Income (loss) before income taxes
12,712
1,201
13,913
Net Income (Loss) attributable to
 
ConocoPhillips
8,079
920
8,999
Earnings per share:
Basic net loss
$
6.09
6.78
Diluted net loss
6.07
6.76
Millions of Dollars
Year Ended December 31, 2020
Pro forma
Pro forma
Pro forma
As reported
Concho
Shell
Combined
Total
 
Revenues and Other Income
$
19,256
3,762
1,685
24,703
Income (loss) before income taxes
(3,140)
787
(247)
(2,600)
Net Income (Loss) attributable to
 
ConocoPhillips
(2,701)
498
(189)
(2,392)
Earnings per share:
Basic net loss
$
(2.51)
(1.75)
Diluted net loss
(2.51)
(1.75)
Notes to Consolidated Financial Statements
 
95
 
ConocoPhillips
 
2021 10-K
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
 
and
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.
 
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.
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
96
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.
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
97
 
ConocoPhillips
 
2021 10-K
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:
Millions of Dollars
2021
2020
Equity investments
$
6,701
7,596
Loans and advances—related parties
-
114
Long-term receivables
98
137
Long-term investments in debt
 
securities
248
217
Other investments
66
67
$
7,113
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
2020
2019
Revenues
$
11,824
7,931
11,310
Income before income taxes
3,946
1,843
3,726
Net income
2,557
1,426
3,085
 
 
 
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
98
Summarized 100 percent balance sheet information
 
for equity method investments
 
in affiliated companies,
 
combined, was as follows:
Millions of Dollars
2021
2020
Current assets
$
4,493
2,579
Noncurrent assets
36,602
35,257
Current liabilities
3,498
2,110
Noncurrent liabilities
17,465
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.
 
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.
 
 
 
 
Notes to Consolidated Financial Statements
 
99
 
ConocoPhillips
 
2021 10-K
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.
 
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.
December 31
2021
2020
Number of shares of CVE common stock (millions)
91
208
Ownership of issued and outstanding common
 
stock
4.5
%
16.9
Closing price on NYSE on last trading day
 
($/share)
$
12.28
6.04
Fair Value (millions
 
of dollars)
$
1,117
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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
100
Millions of Dollars
2021
2020
2019
Total
 
Net gain (loss) on equity securities
$
1,040
(855)
649
Less: Net gain (loss) on equity securities sold during
 
the period
473
Unrealized gain (loss) on equity securities
 
still held at
 
the reporting date
$
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
$
682
1,020
856
Additions pending the determination of proved
 
reserves
10
164
239
Reclassifications to proved
 
properties
-
(42)
(11)
Sales of suspended wells
-
(313)
(54)
Charged to dry hole expense
 
(32)
(147)
(10)
Ending balance at December 31
 
$
660
682
1,020
*
*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.
 
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
$
4
156
206
Exploratory well costs capitalized
 
for a period greater than one year
656
526
814
Ending balance
$
660
682
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
22
22
23
 
 
 
 
 
Notes to Consolidated Financial Statements
 
101
 
ConocoPhillips
 
2021 10-K
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:
Millions of Dollars
Suspended Since
Total
2018-2020
2015-2017
2004-2014
Willow—Alaska
(1)
313
262
51
-
Surmont—Canada
(1)
121
2
19
100
PL 1009—Norway
(1)
43
43
-
-
PL 891—Norway
(1)
34
34
-
-
Narwhal Trend—Alaska
(1)
25
25
-
-
WL4-00—Malaysia
(1)
24
24
-
-
PL782S—Norway
(1)
22
22
-
-
NC 98—Libya
(2)
13
-
-
13
Other of $10 million or less each
(1)(2)
61
21
11
29
Total
$
656
433
81
142
(1)Additional appraisal wells planned.
(2)Appraisal drilling complete; costs being incurred to assess development.
Exploration Expenses
The charges discussed below are included in the “Exploration
 
expenses” line on our consolidated income
statement.
 
2020
In our Alaska segment, we recorded
 
a before-tax impairment
 
of $
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.
 
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
102
Note 7—Impairments
During 2021, 2020 and 2019, we recognized the following
 
before-tax impairment
 
charges:
Millions of Dollars
2021
2020
2019
Alaska
$
5
-
-
Lower 48
 
(8)
804
402
Canada
6
3
2
Europe, Middle East and North Africa
 
(24)
6
1
Asia Pacific
 
695
-
-
$
674
813
405
2021
We recorded an impairment
 
of $
688
 
million on our APLNG investment included within
 
the Asia Pacific segment.
 
See
 
and
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.
 
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.
 
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.
 
Note 8—Asset Retirement
 
Obligations and Accrued Environmental
 
Costs
Asset retirement obligations
 
and accrued environmental costs
 
at December 31 were:
Millions of Dollars
2021
2020
Asset retirement obligations
$
5,926
5,573
Accrued environmental costs
187
180
Total
 
asset retirement obligations
 
and accrued environmental costs
6,113
5,753
Asset retirement obligations
 
and accrued environmental costs
 
due within one year*
(359)
(323)
Long-term asset retirement obligations
 
and accrued environmental costs
$
5,754
5,430
*Classified as a current liability on the balance sheet under “Other accruals.”
 
 
 
 
Notes to Consolidated Financial Statements
 
103
 
ConocoPhillips
 
2021 10-K
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:
Millions of Dollars
2021
2020
Balance at January 1
$
5,573
6,206
Accretion of discount
238
248
New obligations
555
262
Changes in estimates of existing
 
obligations
(113)
(307)
Spending on existing obligations
(164)
(116)
Property dispositions
(108)
(771)
Foreign currency translation
(55)
51
Balance at December 31
$
5,926
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.
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
104
Note 9—Debt
Long-term debt at December 31 was:
Millions of Dollars
2021
2020
9.125
% Debentures due 2021
$
-
123
2.4
% Notes due 2022
329
329
7.65
% Debentures due 2023
78
78
3.35
% Notes due 2024
426
426
8.2
% Debentures due 2025
134
134
3.35
% Notes due 2025
199
199
6.875
% Debentures due 2026
67
67
4.95
% Notes due 2026
1,250
1,250
7.8
% Debentures due 2027
203
203
3.75
% Notes due 2027
981
-
3.75
% Notes due 2027
19
-
4.3
% Notes due 2028
973
-
4.3
% Notes due 2028
27
-
7.375
% Debentures due 2029
92
92
7
% Debentures due 2029
200
200
6.95
% Notes due 2029
1,549
1,549
8.125
% Notes due 2030
390
390
2.4
% Notes due 2031
489
-
2.4
% Notes due 2031
11
-
7.2
% Notes due 2031
575
575
7.25
% Notes due 2031
500
500
7.4
% Notes due 2031
500
500
5.9
% Notes due 2032
505
505
4.15
% Notes due 2034
246
246
5.95
% Notes due 2036
500
500
5.951
% Notes due 2037
645
645
5.9
% Notes due 2038
600
600
6.5
% Notes due 2039
2,750
2,750
4.3
% Notes due 2044
750
750
5.95
% Notes due 2046
500
500
7.9
% Debentures due 2047
60
60
4.875
% Notes due 2047
800
-
4.85
% Notes due 2048
590
-
4.85
% Notes due 2048
10
-
Floating rate notes due 2022 at
1.02
% –
1.12
% during 2021 and
 
1.12
% –
2.81
% during 2020
500
500
Marine Terminal
 
Revenue Refunding Bonds due 2031 at
0.04
% –
0.15
% during
 
2021 and
0.1
% –
7.5
% during 2020
265
265
Industrial Development Bonds due 2035 at
0.04
% –
0.12
% during 2021 and
 
0.11
% –
7.5
% during 2020
18
18
Commercial Paper at
0.05
% –
0.22
% during 2021
-
300
Other
35
38
Debt at face value
17,766
14,292
Finance leases
1,261
891
Net unamortized premiums, discounts and debt
 
issuance costs
907
186
Total
 
debt
19,934
15,369
Short-term debt
(1,200)
(619)
Long-term debt
$
18,734
14,750
Notes to Consolidated Financial Statements
 
105
 
ConocoPhillips
 
2021 10-K
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.
 
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,
 
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
.
 
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.
 
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.
 
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
106
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.
 
for additional
information about environmental
 
liabilities.
 
Notes to Consolidated Financial Statements
 
107
 
ConocoPhillips
 
2021 10-K
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.
 
,
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
,
for a summary of our accrued environmental
 
liabilities.
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
108
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.
Notes to Consolidated Financial Statements
 
109
 
ConocoPhillips
 
2021 10-K
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.
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
110
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:
Millions of Dollars
2021
2020
Assets
Prepaid expenses and other current
 
assets
$
1,168
229
Other assets
75
26
Liabilities
Other accruals
1,160
202
Other liabilities and deferred credits
63
18
The gains (losses) from commodity derivatives
 
incurred, and the line items where they appear on our
 
consolidated
income statement were:
Millions of Dollars
2021
2020
2019
Sales and other operating revenues
$
(228)
19
141
Other income (loss)
25
4
4
Purchased commodities
75
11
(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.
 
 
 
 
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
111
 
ConocoPhillips
 
2021 10-K
The table below summarizes our material
 
net exposures resulting from
 
outstanding commodity derivative
contracts:
Open Position
Long/(Short)
2021
2020
Commodity
Natural gas and power (billions
 
of cubic feet equivalent)
Fixed price
4
(20)
Basis
(22)
(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
$
28
2
Liabilities
Other accruals
9
16
The (gains) losses from foreign
 
currency exchange derivatives
 
incurred and the line item where they appear
 
on our consolidated income statement
 
were:
Millions of Dollars
2021
2020
2019
Foreign currency transaction
 
(gains) losses
 
$
(5)
(40)
16
We had the following net notional
 
position of outstanding foreign currency
 
exchange derivatives:
In Millions
Notional Currency
 
2021
2020
Foreign Currency Exchange
 
Derivatives
Buy British pound, sell euro
GBP
155
-
Sell British pound, buy euro
GBP
-
5
Sell Canadian dollar,
 
buy U.S. dollar
CAD
-
370
Buy Canadian dollar,
 
sell U.S. dollar
CAD
77
-
Buy Australian dollar,
 
sell U.S. dollar
AUD
1,850
-
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
112
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
Short-Term
Investments
Investments and Long-
Term Receivables
2021
2020
2021
2020
2021
2020
Cash
$
670
597
Demand Deposits
1,554
1,133
Time Deposits
1 to 90 days
2,363
1,225
217
2,859
91 to 180 days
4
448
Within one year
4
13
One year through five years
-
1
U.S. Government Obligations
1 to 90 days
431
23
-
-
$
5,018
2,978
225
3,320
-
1
 
 
 
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
113
 
ConocoPhillips
 
2021 10-K
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:
Millions of Dollars
Carrying Amount
Cash and Cash
Equivalents
Short-Term
Investments
Investments and Long-
Term Receivables
2021
2020
2021
2020
2021
2020
Major Security Type
Corporate Bonds
$
3
-
128
130
173
143
Commercial Paper
7
13
82
155
U.S. Government Obligations
-
-
-
4
2
13
U.S. Government Agency
 
 
Obligations
2
-
8
17
Foreign Government Obligations
7
-
2
2
Asset-backed Securities
2
-
63
41
$
10
13
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:
Millions of Dollars
Amortized Cost Basis
Fair Value
2021
2020
2021
2020
Major Security Type
Corporate Bonds
$
305
271
304
273
Commercial Paper
88
168
89
168
U.S. Government Obligations
2
17
2
17
U.S. Government Agency Obligations
10
17
10
17
Foreign Government Obligations
9
2
9
2
Asset-Backed Securities
65
41
65
41
$
479
516
479
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.
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
114
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.
 
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
115
 
ConocoPhillips
 
2021 10-K
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 investment
 
s
 
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
December 31, 2020
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
Assets
Investment in Cenovus Energy
$
1,117
-
-
1,117
1,256
-
-
1,256
Investments in debt securities
2
477
-
479
17
501
-
518
Commodity derivatives
562
619
62
1,243
142
101
12
255
Total
 
assets
$
1,681
1,096
62
2,839
1,415
602
12
2,029
Liabilities
Commodity derivatives
$
593
543
87
1,223
120
91
9
220
Total
 
liabilities
$
593
543
87
1,223
120
91
9
220
 
 
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
116
The following table summarizes those
 
commodity derivative balances subject to
 
the right of setoff as
 
presented on our consolidated
 
balance sheet.
 
We have elected to
 
offset the recognized fair
 
value amounts for
 
multiple derivative instruments
 
executed with the same counterparty
 
in our financial statements when a legal
right of setoff exists.
Millions of Dollars
Amounts Subject to Right of Setoff
Gross
Amounts Not
Gross
Net
Amounts
Subject to
Gross
Amounts
Amounts
Cash
Net
Recognized
Right of Setoff
Amounts
Offset
Presented
Collateral
Amounts
December 31, 2021
Assets
$
1,243
85
1,158
650
508
-
508
Liabilities
1,223
82
1,141
650
491
36
455
December 31, 2020
Assets
$
255
2
253
157
96
10
86
Liabilities
220
1
219
157
62
4
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:
Millions of Dollars
 
Fair Value Measurements
 
Using
Fair Value
Level 1
Inputs
Level 2
Inputs
Level 3
Inputs
Before-Tax
Loss
Year ended
 
December 31, 2021
Net PP&E (held for use)
 
December 31, 2021
$
472
-
-
472
80
Equity Method Investments
 
December 31, 2021
5,574
-
5,574
-
688
Year ended December 31,
 
2020
Net PP&E (held for use)
 
March 31, 2020
$
65
-
-
65
522
 
December 31, 2020
268
-
-
268
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:
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
117
 
ConocoPhillips
 
2021 10-K
Fair Value
(Millions of
Dollars)
Valuation
Technique
Unobservable Inputs
Range
(Arithmetic Average)
December 31, 2021
Lower 48 Gulf Coast and
Rockies noncore field
$
472
Discounted
cash flow
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
$
65
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.
 
 
and
.
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
118
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:
 
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 corroborate
 
d
 
with market data.
 
.
 
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.
 
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):
Millions of Dollars
Carrying Amount
Fair Value
2021
2020
2021
2020
Financial assets
Investment in CVE common shares
$
1,117
1,256
1,117
1,256
Commodity derivatives
593
88
593
88
Investments in debt securities
479
518
479
518
Loans and advances—related parties
114
220
114
220
Financial liabilities
Total
 
debt, excluding finance leases
18,673
14,478
22,451
19,106
Commodity derivatives
537
59
537
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.
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
119
 
ConocoPhillips
 
2021 10-K
Note 14—Equity
Common Stock
The changes in our shares of common stock,
 
as categorized in the equity section
 
of the balance sheet, were:
Shares
2021
2020
2019
Issued
Beginning of year
1,798,844,267
1,795,652,203
1,791,637,434
Acquisition of Concho
285,928,872
-
-
Distributed under benefit plans
6,789,608
3,192,064
4,014,769
End of year
2,091,562,747
1,798,844,267
1,795,652,203
Held in Treasury
Beginning of year
730,802,089
710,783,814
653,288,213
Repurchase of common stock
58,517,786
20,018,275
57,495,601
End of year
789,319,875
730,802,089
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,
.
 
There are no significant restrictions
 
imposed on us by the lease
agreements with regard to
 
dividends, asset dispositions or borrowing ability.
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
120
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 recogni
 
ze 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.
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
121
 
ConocoPhillips
 
2021 10-K
The following table summarizes the
 
right-of-use assets and lease liabilities for both
 
the operating and finance
leases on our consolidated balance sheet as of December 31:
Millions of Dollars
2021
2020
Operating
Leases
Finance
Leases
Operating
Leases
Finance
Leases
Right-of-Use Assets
Properties, plants and equipment
Gross
$
1,812
1,375
Accumulated DD&A
(857)
(721)
Net PP&E
*
955
654
Prepaid expenses and other current
 
assets
$
16
2
Other assets
649
783
Lease Liabilities
Short-term debt
**
$
280
168
Other accruals
188
226
Long-term debt
***
981
723
Other liabilities and deferred credits
479
559
Total
 
lease liabilities
$
667
1,261
785
891
 
*
 
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.
 
The following table summarizes our
 
lease costs:
Millions of Dollars
2021
2020
2019
Lease Cost
*
Operating lease cost
$
278
321
341
Finance lease cost
Amortization of right-of-use assets
148
163
99
Interest on lease liabilities
27
34
37
Short-term lease cost
**
21
42
77
Total
 
lease cost
***
$
474
560
554
*
 
The amounts presented in the table above have not been adjusted to reflect amounts recovered or reimbursed from oil and gas
coventurers.
**
 
Short-term leases are not recorded on our consolidated balance sheet.
*** Variable lease cost and sublease income are immaterial for the periods presented and therefore are not included in the table above
.
 
 
 
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
122
The following table summarizes the
 
lease terms and discount rates
 
as of December 31:
2021
2020
Lease Term
 
and Discount Rate
Weighted-average
 
term (years)
Operating leases
5.97
6.11
Finance leases
7.49
7.12
Weighted-average
 
discount rate (percent)
Operating leases
2.66
2.78
Finance leases
3.24
4.27
The following table summarizes other
 
lease information:
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
$
204
232
203
Operating cash flows from finance
 
leases
6
11
27
Financing cash flows from finance leases
73
255
81
Right-of-use assets obtained
 
in exchange for operating
 
lease liabilities
$
174
250
499
Right-of-use assets obtained
 
in exchange for finance lease liabilities
447
426
26
*The amounts presented in the table above have not been adjusted to reflect amounts recovered or reimbursed from oil and gas coventurers.
 
In addition, pursuant to other applicable accounting guidance, lease payments made in connection with preparing another asset for its
intended use are reported in the "Cash Flows From Investing Activities" section of our consolidated statement of cash flows.
 
The following table summarizes future
 
lease payments for operating
 
and finance leases at December 31, 2021:
Millions of Dollars
Operating
Leases
Finance
 
Leases
Maturity of Lease Liabilities
2022
$
195
341
2023
143
199
2024
114
166
2025
68
143
2026
50
139
Remaining years
159
462
Total
*
729
1,450
Less: portion representing imputed
 
interest
(62)
(189)
Total
 
lease liabilities
$
667
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.
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
123
 
ConocoPhillips
 
2021 10-K
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:
Millions of Dollars
Pension Benefits
Other Benefits
2021
2020
2021
2020
U.S.
Int’l.
U.S.
Int’l.
Change in Benefit Obligation
Benefit obligation at January 1
$
2,548
4,403
2,319
3,880
170
216
Service cost
73
61
85
54
2
2
Interest cost
53
79
66
85
4
6
Plan participant contributions
-
-
-
1
16
18
Plan amendments
-
-
-
2
-
(30)
Actuarial (gain) loss
(117)
(176)
319
398
(16)
7
Benefits paid
(654)
(162)
(241)
(151)
(40)
(49)
Curtailment
12
-
-
2
1
-
Recognition of termination benefits
9
-
-
3
-
-
Foreign currency exchange
 
rate change
-
(81)
-
129
-
-
Benefit obligation at December 31
*
$
1,924
4,124
2,548
4,403
137
170
*Accumulated benefit obligation portion of above at
 
December 31:
$
1,793
3,658
2,359
4,095
Change in Fair Value
 
of Plan Assets
Fair value of plan assets at January
 
1
$
1,770
4,793
1,591
4,306
-
-
Actual return on plan assets
97
147
321
416
-
-
Company contributions
451
119
99
60
24
31
Plan participant contributions
-
1
-
1
16
18
Benefits paid
(654)
(162)
(241)
(151)
(40)
(49)
Foreign currency exchange
 
rate change
-
(86)
-
161
-
-
Fair value of plan assets at December 31
$
1,664
4,812
1,770
4,793
-
-
Funded Status
$
(260)
688
(778)
390
(137)
(170)
 
 
 
 
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
124
Millions of Dollars
Pension Benefits
Other Benefits
2021
2020
2021
2020
U.S.
Int’l.
U.S.
Int’l.
Amounts Recognized in the
 
Consolidated Balance Sheet at
 
December 31
Noncurrent assets
$
1
991
-
746
-
-
Current liabilities
(29)
(15)
(56)
(11)
(34)
(39)
Noncurrent liabilities
(232)
(288)
(722)
(345)
(103)
(131)
Total
 
recognized
$
(260)
688
(778)
390
(137)
(170)
Weighted-Average
 
Assumptions Used to
 
Determine Benefit Obligations at
 
December 31
Discount rate
2.80
%
2.15
2.30
1.80
2.65
2.15
Rate of compensation increase
4.00
3.40
4.00
3.10
Interest crediting rate
 
for applicable benefits
2.50
2.10
Weighted-Average
 
Assumptions Used to
 
Determine Net Periodic Benefit Cost
 
for
 
Years Ended
 
December 31
Discount rate
2.60
%
1.80
3.05
2.35
2.35
3.10
Expected return on plan assets
5.20
2.50
5.80
3.60
Rate of compensation increase
4.00
3.40
4.00
3.35
Interest crediting rate
 
for applicable benefits
2.10
4.10
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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
125
 
ConocoPhillips
 
2021 10-K
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:
Millions of Dollars
Pension Benefits
2021
2020
U.S.
Int’l.
U.S.
Int’l.
Pension Plans with Projected Benefit Obligation
 
in
Excess of Plan Assets
Projected benefit obligation
$
261
362
2,548
391
Fair value of plan assets
-
58
1,770
35
Pension Plans with Accumulated Benefit
 
Obligation in
Excess of Plan Assets
Accumulated benefit obligation
$
234
271
2,359
338
Fair value of plan assets
-
9
1,770
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
Other Benefits
2021
2020
2021
2020
U.S.
Int’l.
U.S.
Int’l.
Unrecognized net actuarial loss
 
(gain)
$
188
86
467
326
(1)
14
Unrecognized prior service cost
 
(credit)
-
1
-
-
(145)
(182)
Millions of Dollars
Pension Benefits
Other Benefits
2021
2020
2021
2020
U.S.
Int’l.
U.S.
Int’l.
Sources of Change in Other
 
Comprehensive Income (Loss)
Net gain (loss) arising during the period
$
134
207
(83)
(120)
16
(7)
Amortization of actuarial loss included
in income (loss)*
145
33
95
21
-
1
Net change during the period
$
279
240
12
(99)
16
(6)
Prior service credit (cost) arising during the
period
$
-
-
-
(1)
-
30
Amortization of prior service (credit)
included in income (loss)
-
(1)
-
(1)
(37)
(31)
Net change during the period
$
-
(1)
-
(2)
(37)
(1)
*Includes settlement (gains) losses recognized in 2021 and 2020.
 
 
 
 
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
126
The components of net periodic benefit cost of all defined
 
benefit plans are presented in the following
 
table:
Millions of Dollars
Pension Benefits
Other Benefits
2021
2020
2019
2021
2020
2019
U.S.
Int’l.
U.S.
Int’l.
U.S.
Int’l.
Components of Net
 
Periodic Benefit Cost
Service cost
$
73
61
85
54
79
69
2
2
1
Interest cost
53
79
66
85
79
97
4
6
8
Expected return on plan
assets
(80)
(120)
(85)
(145)
(74)
(138)
-
-
-
Amortization of prior
 
service credit
-
(1)
-
(1)
-
(2)
(37)
(31)
(33)
Recognized net actuarial
 
loss (gain)
43
33
51
22
54
32
-
1
(2)
Settlements loss (gain)
102
-
44
(1)
62
-
-
-
-
Curtailment loss
12
-
-
-
-
-
-
-
-
Net periodic benefit cost
$
203
52
161
14
200
58
(31)
(22)
(26)
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.
Notes to Consolidated Financial Statements
 
127
 
ConocoPhillips
 
2021 10-K
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.
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
128
The fair values of our pension plan assets at
 
December 31, by asset class were as follows:
 
Millions of Dollars
U.S.
International
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
2021
Equity securities
U.S.
$
3
-
5
8
-
-
-
-
International
42
-
-
42
-
-
-
-
Mutual funds
17
-
-
17
236
403
-
639
Debt securities
Corporate
-
1
-
1
-
-
-
-
Mutual funds
-
-
-
-
511
-
-
511
Cash and cash equivalents
-
-
-
-
68
-
-
68
Real estate
-
-
-
-
-
-
157
157
Total in fair
 
value hierarchy
$
62
1
5
68
815
403
157
1,375
Investments measured at net asset value*
Equity securities
Common/collective trusts
$
394
417
Debt securities
Common/collective trusts
1,073
3,015
Cash and cash equivalents
9
-
Real estate
36
1
Total**
$
62
1
5
1,580
815
403
157
4,808
 
*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.
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
129
 
ConocoPhillips
 
2021 10-K
The fair values of our pension plan assets at
 
December 31, by asset class were as follows:
 
Millions of Dollars
U.S.
International
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
2020
Equity securities
U.S.
$
-
3
5
8
-
-
-
-
International
99
-
-
99
-
-
-
-
Mutual funds
72
-
-
72
235
384
-
619
Debt securities
Corporate
-
1
-
1
-
-
-
-
Mutual funds
-
-
-
-
455
-
-
455
Cash and cash equivalents
-
-
-
-
74
-
-
74
Derivatives
-
-
-
-
6
-
-
6
Real estate
-
-
-
-
-
-
142
142
Total in fair
 
value hierarchy
$
171
4
5
180
770
384
142
1,296
Investments measured at net asset value*
Equity securities
Common/collective trusts
$
678
372
Debt securities
Common/collective trusts
730
3,007
Cash and cash equivalents
8
-
Real estate
79
112
Total**
$
171
4
5
1,675
770
384
142
4,787
 
*In accordance with FASB ASC Topic 715, “Compensation—Retirement Benefits,”
 
certain investments that are to be measured at fair value
 
 
using the net asset value per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy.
 
The fair value
 
 
amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the Change in
 
 
Fair Value of Plan Assets.
**Excludes the participating interest in the insurance annuity contract with a net asset of $
94
 
million and net receivables related to security
 
 
transactions of $
7
 
million.
Level 3 activity was not material for all periods.
Our funding policy for U.S. plans is to contribute
 
at least the minimum required by the Employee
 
Retirement
Income Security Act of 1974 and the Internal Revenue
 
Code of 1986, as amended.
 
Contributions to foreign plans
are dependent upon local laws and tax
 
regulations.
 
In 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.
 
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
130
The following benefit payments,
 
which are exclusive of amounts
 
to be paid from the insurance annuity contract
and which reflect expected future
 
service, as appropriate, are expected
 
to be paid:
Millions of Dollars
Pension
Other
Benefits
Benefits
U.S.
Int’l.
2022
$
369
152
21
2023
185
152
18
2024
176
158
15
2025
154
162
14
2026
144
164
12
2027–2031
557
893
44
The following table summarizes our
 
severance accrual activity:
Millions of Dollars
2021
2020
2019
Balance at January 1
$
24
23
48
Accruals
170
14
(1)
Benefit payments
(116)
(13)
(24)
Balance at December 31
$
78
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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
131
 
ConocoPhillips
 
2021 10-K
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:
Millions of Dollars
2021
2020
2019
Compensation cost
$
304
159
274
Tax benefit
 
76
40
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:
Millions of Dollars
Weighted-Average
Aggregate
Options
Exercise Price
Intrinsic Value
Outstanding at December 31, 2020
16,922,525
$
55.12
$
22
Exercised
(3,846,361)
51.40
68
Expired or cancelled
(1,102,381)
53.47
Outstanding at December 31, 2021
11,973,783
$
56.46
$
188
Vested at December
 
31, 2021
11,973,783
$
56.46
$
188
Exercisable at December 31, 2021
11,973,783
$
56.46
$
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.
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
132
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:
Weighted-Average
Millions of Dollars
Stock Units
Grant Date Fair Value
Total
 
Fair Value
Outstanding at December 31, 2020
6,431,985
$
58.94
Granted
4,590,103
46.56
Forfeited
(566,047)
48.59
Issued
(2,810,730)
54.74
$
144
Outstanding at December 31, 2021
7,645,311
$
53.81
Not Vested at
 
December 31, 2021
5,509,133
53.81
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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
133
 
ConocoPhillips
 
2021 10-K
The following summarizes our cash
 
-settled stock unit activity for the year
 
ended December 31, 2021:
Weighted-Average
Millions of Dollars
Stock Units
Grant Date Fair Value
Total
 
Fair Value
Outstanding at December 31, 2020
614,615
$
39.95
Granted
11,186
57.19
Forfeited
(2,927)
51.43
Issued
(396,398)
50.75
$
20
Outstanding at December 31, 2021
226,476
$
72.18
Not Vested at
 
December 31, 2021
59,443
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:
Weighted-Average
Millions of Dollars
Stock Units
Grant Date Fair Value
Total
 
Fair Value
Outstanding at December 31, 2020
1,736,728
$
50.56
Issued
(287,881)
49.91
$
18
Outstanding at December 31, 2021
1,448,847
$
50.69
Not Vested at
 
December 31, 2021
3,191
$
48.61
 
 
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
134
At December 31, 2021, there was
no
 
remaining unrecognized compensation
 
cost to be recorded on the unvested
stock-settled performance share
 
s.
 
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:
Weighted-Average
Millions of Dollars
Stock Units
Grant Date Fair Value
Total
 
Fair Value
Outstanding at December 31, 2020
124,529
$
39.95
Granted
1,073,228
46.65
Settled
(1,080,078)
48.13
$
52
Outstanding at December 31, 2021
117,679
$
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.
 
 
 
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
135
 
ConocoPhillips
 
2021 10-K
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:
Weighted-Average
Millions of Dollars
Stock Units
Grant Date Fair Value
Total
 
Fair Value
Outstanding at December 31, 2020
970,099
$
47.78
Granted
797,704
46.43
Cancelled
(1,948)
27.80
Issued
(149,488)
46.80
$
8
Outstanding at December 31, 2021
1,616,367
$
47.24
Not Vested at
 
December 31, 2021
695,958
$
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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
136
Note 17—Income Taxes
Components of income tax provision
 
(benefit) were:
Millions of Dollars
2021
2020
2019
Income Taxes
Federal
Current
$
32
3
18
Deferred
1,161
(625)
(113)
Foreign
Current
3,128
350
2,545
Deferred
66
(70)
(323)
State and local
Current
127
(4)
148
Deferred
119
(139)
(8)
Total
 
tax provision (benefit)
$
4,633
(485)
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
2021
2020
Deferred Tax
 
Liabilities
PP&E and intangibles
$
10,170
7,744
Inventory
44
64
Other
213
242
Total
 
deferred tax liabilities
10,427
8,050
Deferred Tax
 
Assets
Benefit plan accruals
321
540
Asset retirement obligations
 
and accrued environmental costs
2,297
2,262
Investments in joint ventures
1,684
1,653
Other financial accruals and deferrals
827
907
Loss and credit carryforwards
7,402
8,904
Other
399
365
Total
 
deferred tax assets
12,930
14,631
Less: valuation allowance
(8,342)
(9,965)
Total
 
deferred tax assets
 
net of valuation allowance
4,588
4,666
Net deferred tax liabilities
$
5,839
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.
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
137
 
ConocoPhillips
 
2021 10-K
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
Balance at January 1
$
9,965
10,214
3,040
Charged to expense (benefit)
(45)
460
(225)
Other*
(1,578)
(709)
7,399
Balance at December 31
$
8,342
9,965
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.
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
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.
 
 
 
 
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
138
The following table shows a reconciliation
 
of the beginning and ending unrecognized
 
tax benefits for 2021,
 
2020 and 2019:
Millions of Dollars
2021
2020
2019
Balance at January 1
$
1,206
1,177
1,081
Additions based on tax positions related
 
to the current year
15
6
9
Additions for tax positions of prior years
177
67
120
Reductions for tax positions
 
of prior years
(5)
(34)
(22)
Settlements
-
(9)
(9)
Lapse of statute
(48)
(1)
(2)
Balance at December 31
$
1,345
1,206
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.
 
 
and
 
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.
 
 
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
139
 
ConocoPhillips
 
2021 10-K
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
$
8,024
(3,587)
4,704
63.1
%
114.2
49.4
Foreign
4,688
447
4,820
36.9
(14.2)
50.6
$
12,712
(3,140)
9,524
100.0
%
100.0
100.0
Federal statutory
 
income tax
$
2,670
(659)
2,000
21.0
%
21.0
21.0
Non-U.S. effective tax
 
rates
1,915
194
1,399
15.1
(6.2)
14.7
Tax impact of debt
 
restructuring
75
-
-
0.6
-
-
Australia disposition
-
(349)
-
-
11.1
-
U.K. disposition
-
-
(732)
-
-
(7.7)
Recovery of outside basis
(55)
(22)
(77)
(0.4)
0.7
(0.8)
Adjustment to tax reserves
(11)
18
9
(0.1)
(0.6)
0.1
Adjustment to valuation allowance
(45)
460
(225)
(0.4)
(14.6)
(2.4)
State income tax
194
(112)
123
1.5
3.6
1.3
Malaysia Deepwater Incentive
-
-
(164)
-
-
(1.7)
Enhanced oil recovery credit
(99)
(6)
(27)
(0.8)
0.2
(0.3)
Other
(11)
(9)
(39)
(0.1)
0.3
(0.4)
Tota
 
l
$
4,633
(485)
2,267
36.4
%
15.5
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.
 
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.
 
 
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
140
Note 18—Accumulated Other Comprehensive
 
Loss
Accumulated other comprehensive
 
loss in the equity section of the balance sheet included:
Millions of Dollars
Defined
Benefit Plans
Net
Unrealized
Gain/(Loss)
on Securities
Foreign
Currency
Translation
Accumulated
Other
Comprehensive
Loss
December 31, 2018
$
(361)
-
(5,702)
(6,063)
Other comprehensive income (loss)
51
-
695
746
Cumulative effect of adopting
 
ASU No. 2018-02*
(40)
-
-
(40)
December 31, 2019
(350)
-
(5,007)
(5,357)
Other comprehensive income
(75)
2
212
139
December 31, 2020
(425)
2
(4,795)
(5,218)
Other comprehensive income (loss)
394
(2)
(124)
268
December 31, 2021
$
(31)
-
(4,919)
(4,950)
 
*We adopted ASU No. 2018-02, "Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income," beginning January 1,
2019.
During 2019, we recognized $
483
 
million of foreign currency translation
 
adjustments related to the completion
 
of
our sale of two ConocoPhillips U.K. subsidiaries.
 
The following table summarizes reclassifications
 
out of accumulated other comprehensive
 
loss during the years
ended December 31:
Millions of Dollars
2021
2020
Defined Benefit Plans
$
109
72
Above amounts are included in the computation of net periodic benefit cost and
 
are presented net of tax expense of:
$
31
13
See Note 16.
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
141
 
ConocoPhillips
 
2021 10-K
Note 19—Cash Flow Information
Millions of Dollars
2021
2020
2019
Noncash Investing Activities
 
Increase (decrease) in PP&E related to
 
an increase (decrease) in asset
retirement obligations
$
442
(116)
205
Cash Payments
Interest
$
924
785
810
Income taxes
856
905
2,905
Net Sales (Purchases) of Investments
Short-term investments
 
purchased
$
(5,554)
(12,435)
(4,902)
Short-term investments
 
sold
8,810
12,015
2,138
Investments and long-term receivables
 
purchased
(279)
(325)
(146)
Investments and long-term receivables
 
sold
114
87
-
$
3,091
(658)
(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
 
and
 
for additional information on cash
 
and non-cash changes to our consolidated
 
balance
sheet associated with our Concho acquisition.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
142
Note 20—Other Financial Information
Millions of Dollars
2021
2020
2019
Interest and Debt Expense
Incurred
Debt
$
887
788
799
Other
59
73
36
946
861
835
Capitalized
(62)
(55)
(57)
Expensed
$
884
806
778
Other Income (Loss)
Interest income
$
33
100
166
Gain (loss) on investment in Cenovus
 
Energy*
1,040
(855)
649
Other, net
130
246
543
$
1,203
(509)
1,358
*See Note 5.
Research and Development Expenditures
—expensed
$
62
75
82
Shipping and Handling Costs
$
1,047
857
1,008
Foreign Currency Transaction
 
(Gains) Losses
—after-tax
Alaska
$
-
-
-
Lower 48
-
-
-
Canada
(1)
(7)
5
Europe, Middle East and North Africa
(11)
(15)
-
Asia Pacific
2
(11)
31
Other International
1
2
1
Corporate and Other
(7)
(31)
21
$
(16)
(62)
58
Millions of Dollars
2021
2020
Properties, Plants and Equipment
Proved properties*
$
114,274
**
94,312
Unproved properties*
10,993
4,141
Other
4,379
3,653
Gross properties, plants and equipment
129,646
102,106
Less: Accumulated depreciation,
 
depletion and amortization
(64,735)
**
(62,213)
Net properties, plants and equipment
$
64,911
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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
143
 
ConocoPhillips
 
2021 10-K
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,
Significant transactions with our equity
 
affiliates were:
 
Millions of Dollars
2021
2020
2019
Operating revenues and other income
$
88
79
89
Purchases
5
-
38
Operating expenses and selling, general
 
and administrative expenses
196
63
65
Net interest income*
(2)
(5)
(13)
*We paid interest to, or received interest from, various affiliates.
 
See Note 4, for additional information on loans to
 
affiliated companies.
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:
Millions of Dollars
2021
2020
2019
Revenue from contracts
 
with customers
$
34,590
13,662
26,106
Revenue from contracts
 
outside the scope of ASC Topic
 
606
Physical contracts
 
meeting the definition of a derivative
11,500
5,177
6,558
Financial derivative contracts
(262)
(55)
(97)
Consolidated sales and other operating
 
revenues
$
45,828
18,784
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
Millions of Dollars
2021
2020
2019
Revenue from Outside the Scope of ASC Topic
 
606
by Segment
Lower 48
$
9,050
3,966
4,989
Canada
1,457
727
691
Europe, Middle East and North Africa
993
484
878
Physical contracts
 
meeting the definition of a derivative
$
11,500
5,177
6,558
Millions of Dollars
2021
2020
2019
Revenue from Outside the Scope of ASC Topic
 
606
by Product
Crude oil
$
757
395
804
Natural gas
10,034
4,339
5,313
Other
709
443
441
Physical contracts
 
meeting the definition of a derivative
$
11,500
5,177
6,558
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
144
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.
Millions of Dollars
Contract Liabilities
At December 31, 2020
$
97
Contractual payments received
15
Revenue recognized
(62)
At December 31, 2021
$
50
Amounts Recognized in the Consolidated
 
Balance Sheet at December 31, 2021
Current liabilities
$
50
We expect to recognize the contract liabilities as of December 31, 2021, as revenue during 2022.
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
145
 
ConocoPhillips
 
2021 10-K
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
.
 
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.
 
Analysis of Results by Operating Segment
Millions of Dollars
2021
2020
2019
Sales and Other Operating Revenues
Alaska
$
5,480
3,408
5,483
Intersegment eliminations
-
(11)
-
Alaska
5,480
3,397
5,483
Lower 48
29,306
9,872
15,514
Intersegment eliminations
(12)
(51)
(46)
Lower 48
29,294
9,821
15,468
Canada
4,077
1,666
2,910
Intersegment eliminations
(1,583)
(405)
(1,141)
Canada
2,494
1,261
1,769
Europe, Middle East and North Africa
5,902
1,919
5,101
Intersegment eliminations
-
(2)
-
Europe, Middle East and North Africa
5,902
1,917
5,101
Asia Pacific
2,579
2,363
4,525
Other International
4
7
-
Corporate and Other
75
18
221
Consolidated sales and other operating
 
revenues
$
45,828
18,784
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.
 
 
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
146
Millions of Dollars
2021
2020
2019
Depreciation, Depletion, Amortization
 
and Impairments
Alaska
$
1,002
996
805
Lower 48
4,067
3,358
3,224
Canada
392
342
232
Europe, Middle East and North Africa
862
775
887
Asia Pacific
1,483
809
1,285
Other International
-
-
-
Corporate and Other
76
54
62
Consolidated depreciation, depletion,
 
amortization and impairments
$
7,882
6,334
6,495
Equity in Earnings of Affiliates
Alaska
$
5
(7)
7
Lower 48
(18)
(11)
(159)
Canada
-
-
-
Europe, Middle East and North Africa
502
311
470
Asia Pacific
343
137
461
Other International
-
2
-
Corporate and Other
-
-
-
Consolidated equity in earnings of affiliates
$
832
432
779
Income Tax
 
Provision (Benefit)
Alaska
$
402
(256)
472
Lower 48
1,390
(378)
137
Canada
150
(185)
(43)
Europe, Middle East and North Africa
2,543
136
1,425
Asia Pacific
483
294
501
Other International
(53)
(20)
8
Corporate and Other
(282)
(76)
(233)
Consolidated income tax provision
 
(benefit)
$
4,633
(485)
2,267
Net Income (Loss) Attributable
 
to ConocoPhillips
Alaska
$
1,386
(719)
1,520
Lower 48
4,932
(1,122)
436
Canada
458
(326)
279
Europe, Middle East and North Africa
1,167
448
3,170
Asia Pacific
453
962
1,483
Other International
(107)
(64)
263
Corporate and Other
(210)
(1,880)
38
Consolidated net income (loss) attributable
 
to ConocoPhillips
$
8,079
(2,701)
7,189
 
 
 
 
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
147
 
ConocoPhillips
 
2021 10-K
Millions of Dollars
2021
2020
2019
Investments in and Advances to
 
Affiliates
Alaska
$
58
62
83
Lower 48
242
25
35
Canada
-
-
-
Europe, Middle East and North Africa
797
918
1,070
Asia Pacific
5,603
6,705
7,265
Other International
1
-
-
Corporate and Other
-
-
-
Consolidated investments
 
in and advances to affiliates
$
6,701
7,710
8,453
Total Assets
Alaska
$
14,812
14,623
15,453
Lower 48
41,699
11,932
14,425
Canada
7,439
6,863
6,350
Europe, Middle East and North Africa
9,125
8,756
9,269
Asia Pacific
9,840
11,231
13,568
Other International
1
226
285
Corporate and Other
7,745
8,987
11,164
Consolidated total assets
$
90,661
62,618
70,514
Capital Expenditures and Investments
Alaska
$
982
1,038
1,513
Lower 48
3,129
1,881
3,394
Canada
203
651
368
Europe, Middle East and North Africa
534
600
708
Asia Pacific
390
384
584
Other International
33
121
8
Corporate and Other
53
40
61
Consolidated capital expenditures
 
and investments
$
5,324
4,715
6,636
Interest Income and Expense
Interest income
Alaska
$
-
-
-
Lower 48
 
-
-
-
Canada
-
-
-
Europe, Middle East and North Africa
2
5
11
Asia Pacific
9
7
6
Other International
-
-
-
Corporate and Other
22
88
149
Interest and debt expense
Corporate and Other
$
884
806
778
Sales and Other Operating Revenues
 
by Product
Crude oil
 
$
23,648
9,736
18,482
Natural gas
16,904
6,427
8,715
Natural gas liquids
1,668
528
814
Other*
3,608
2,093
4,556
Consolidated sales and other operating
 
revenues by product
$
45,828
18,784
32,567
*Includes LNG and bitumen.
 
 
 
 
 
 
 
Notes to Consolidated Financial Statements
 
ConocoPhillips
 
2021 10-K
 
148
Geographic Information
Millions of Dollars
Sales and Other Operating Revenues
(1)
Long-Lived Assets
(2)
2021
2020
2019
2021
2020
2019
United States
$
34,847
13,230
21,159
50,580
24,034
26,566
Australia and Timor-Leste
 
-
605
1,647
5,579
6,676
7,228
Canada
2,494
1,261
1,769
6,608
6,385
5,769
China
724
460
772
1,476
1,491
1,447
Indonesia
(3)
879
689
875
28
464
605
Libya
1,102
155
1,103
659
670
668
Malaysia
975
610
1,230
1,252
1,501
1,871
Norway
2,563
1,426
2,349
4,681
5,294
5,258
United Kingdom
2,236
336
1,649
1
1
2
Other foreign countries
8
12
14
748
1,087
1,308
Worldwide consolidated
$
45,828
18,784
32,567
71,612
47,603
50,722
(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.
 
Supplementary Data
 
149
 
ConocoPhillips
 
2021 10-K
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.
Supplementary Data
 
ConocoPhillips
 
2021 10-K
 
150
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.
 
 
 
 
 
 
 
 
 
 
 
 
 
Supplementary Data
 
151
 
ConocoPhillips
 
2021 10-K
Proved Reserves
Years Ended
Crude Oil
 
December 31
Millions of Barrels
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Total
Developed and Undeveloped
Consolidated operations
End of 2018
1,233
703
1,936
4
246
159
188
2,533
Revisions
40
(36)
4
(1)
18
(5)
23
39
Improved recovery
7
-
7
-
-
-
-
7
Purchases
-
1
1
-
-
-
-
1
Extensions and discoveries
25
226
251
2
-
11
-
264
Production
(74)
(95)
(169)
-
(36)
(31)
(14)
(250)
Sales
-
(2)
(2)
-
(30)
-
-
(32)
End of 2019
1,231
797
2,028
5
198
134
197
2,562
Revisions
(297)
(126)
(423)
(2)
4
(4)
(3)
(428)
Improved recovery
-
-
-
-
-
3
-
3
Purchases
-
5
5
3
-
-
-
8
Extensions and discoveries
10
108
118
3
-
-
-
121
Production
(65)
(77)
(142)
(2)
(28)
(25)
(3)
(200)
Sales
-
(14)
(14)
(1)
-
-
-
(15)
End of 2020
879
693
1,572
6
174
108
191
2,051
Revisions
209
(52)
157
2
14
37
6
216
Improved recovery
1
-
1
-
-
-
-
1
Purchases
-
691
691
-
-
-
-
691
Extensions and discoveries
10
289
299
5
2
1
-
307
Production
(64)
(160)
(224)
(3)
(29)
(24)
(13)
(293)
Sales
-
(9)
(9)
-
-
-
-
(9)
End of 2021
1,035
1,452
2,487
10
161
122
184
2,964
Equity affiliates
End of 2018
-
-
-
-
-
78
-
78
Revisions
-
-
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
-
Production
-
-
-
-
-
(5)
-
(5)
Sales
-
-
-
-
-
-
-
-
End of 2019
-
-
-
-
-
73
-
73
Revisions
-
-
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
-
Production
-
-
-
-
-
(5)
-
(5)
Sales
-
-
-
-
-
-
-
-
End of 2020
-
-
-
-
-
68
-
68
Revisions
-
-
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
-
Production
-
-
-
-
-
(5)
-
(5)
Sales
-
-
-
-
-
-
-
-
End of 2021
-
-
-
-
-
63
-
63
Total
 
company
End of 2018
1,233
703
1,936
4
246
237
188
2,611
End of 2019
1,231
797
2,028
5
198
207
197
2,635
End of 2020
879
693
1,572
6
174
176
191
2,119
End of 2021
1,035
1,452
2,487
10
161
185
184
3,027
 
 
 
 
 
 
 
 
Supplementary Data
 
ConocoPhillips
 
2021 10-K
 
152
Years Ended
Crude Oil
 
December 31
Millions of Barrels
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Total
Developed
Consolidated operations
End of 2018
1,058
346
1,404
2
192
113
185
1,896
End of 2019
1,048
334
1,382
3
149
94
181
1,809
End of 2020
765
263
1,028
6
129
77
175
1,415
End of 2021
912
916
1,828
4
122
98
171
2,223
Equity affiliates
End of 2018
-
-
-
-
-
78
-
78
End of 2019
-
-
-
-
-
73
-
73
End of 2020
-
-
-
-
-
68
-
68
End of 2021
-
-
-
-
-
63
-
63
Undeveloped
Consolidated operations
End of 2018
175
357
532
2
54
46
3
637
End of 2019
183
463
646
2
49
40
16
753
End of 2020
114
430
544
-
45
31
16
636
End of 2021
123
536
659
6
39
24
13
741
Equity affiliates
End of 2018
-
-
-
-
-
-
-
-
End of 2019
-
-
-
-
-
-
-
-
End of 2020
-
-
-
-
-
-
-
-
End of 2021
-
-
-
-
-
-
-
-
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.
 
 
 
 
Supplementary Data
 
153
 
ConocoPhillips
 
2021 10-K
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.
 
 
 
 
 
 
 
 
 
 
 
 
Supplementary Data
 
ConocoPhillips
 
2021 10-K
 
154
Years Ended
Natural Gas Liquids
December 31
Millions of Barrels
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Total
Developed and Undeveloped
Consolidated operations
End of 2018
106
222
328
1
17
3
349
Revisions
(1)
(11)
(12)
-
3
(1)
(10)
Improved recovery
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
Extensions and discoveries
-
62
62
1
-
-
63
Production
(5)
(28)
(33)
-
(3)
(1)
(37)
Sales
-
-
-
-
(4)
-
(4)
End of 2019
100
245
345
2
13
1
361
Revisions
-
(26)
(26)
-
1
(1)
(26)
Improved recovery
-
-
-
-
-
-
-
Purchases
-
2
2
2
-
-
4
Extensions and discoveries
-
41
41
1
-
-
42
Production
(6)
(27)
(33)
(1)
(2)
-
(36)
Sales
-
(5)
(5)
-
-
-
(5)
End of 2020
94
230
324
4
12
-
340
Revisions
(6)
213
207
-
1
-
208
Improved recovery
-
-
-
-
-
-
-
Purchases
-
72
72
-
-
-
72
Extensions and discoveries
-
82
82
2
-
-
84
Production
(6)
(50)
(56)
(1)
(2)
-
(59)
Sales
-
(1)
(1)
-
-
-
(1)
End of 2021
82
546
628
5
11
-
644
Equity affiliates
End of 2018
-
-
-
-
-
42
42
Revisions
-
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
Production
-
-
-
-
-
(3)
(3)
Sales
-
-
-
-
-
-
-
End of 2019
-
-
-
-
-
39
39
Revisions
-
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
Production
-
-
-
-
-
(3)
(3)
Sales
-
-
-
-
-
-
-
End of 2020
-
-
-
-
-
36
36
Revisions
-
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
Production
-
-
-
-
-
(3)
(3)
Sales
-
-
-
-
-
-
-
End of 2021
-
-
-
-
-
33
33
Total
 
company
End of 2018
106
222
328
1
17
45
391
End of 2019
100
245
345
2
13
40
400
End of 2020
94
230
324
4
12
36
376
End of 2021
82
546
628
5
11
33
677
 
 
 
 
 
 
 
 
 
 
 
Supplementary Data
 
155
 
ConocoPhillips
 
2021 10-K
Years Ended
Natural Gas Liquids
December 31
Millions of Barrels
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Total
Developed
Consolidated operations
End of 2018
106
97
203
-
15
3
221
End of 2019
100
99
199
1
10
1
211
End of 2020
94
83
177
4
9
-
190
End of 2021
82
334
416
3
9
-
428
Equity affiliates
End of 2018
-
-
-
-
-
42
42
End of 2019
-
-
-
-
-
39
39
End of 2020
-
-
-
-
-
36
36
End of 2021
-
-
-
-
-
33
33
Undeveloped
Consolidated operations
End of 2018
-
125
125
1
2
-
128
End of 2019
-
146
146
1
3
-
150
End of 2020
-
147
147
-
3
-
150
End of 2021
-
212
212
2
2
-
216
Equity affiliates
End of 2018
-
-
-
-
-
-
-
End of 2019
-
-
-
-
-
-
-
End of 2020
-
-
-
-
-
-
-
End of 2021
-
-
-
-
-
-
-
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.
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
 
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 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.
 
 
 
 
 
 
 
 
 
 
 
 
Supplementary Data
 
ConocoPhillips
 
2021 10-K
 
156
Years Ended
Natural Gas
December 31
Billions of Cubic Feet
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Total
Developed and Undeveloped
Consolidated operations
End of 2018
2,736
2,318
5,054
26
1,212
1,079
214
7,585
Revisions
30
(113)
(83)
(2)
160
147
21
243
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
2
2
-
-
-
-
2
Extensions and discoveries
7
483
490
23
-
1
-
514
Production
(85)
(252)
(337)
(4)
(178)
(250)
(11)
(780)
Sales
-
(7)
(7)
-
(298)
-
-
(305)
End of 2019
2,688
2,431
5,119
43
896
977
224
7,259
Revisions
(607)
(439)
(1,046)
(15)
39
103
2
(917)
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
74
74
29
-
-
-
103
Extensions and discoveries
-
304
304
33
2
-
-
339
Production
(85)
(231)
(316)
(16)
(112)
(171)
(2)
(617)
Sales
-
(39)
(39)
-
-
(58)
-
(97)
End of 2020
1,996
2,100
4,096
74
825
851
224
6,070
Revisions
715
41
756
15
54
60
-
885
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
2,438
2,438
-
-
-
-
2,438
Extensions and discoveries
-
822
822
46
2
-
-
870
Production
(86)
(473)
(559)
(30)
(113)
(147)
(7)
(856)
Sales
-
(270)
(270)
-
-
-
-
(270)
End of 2021
2,625
4,658
7,283
105
768
764
217
9,137
Equity affiliates
End of 2018
-
-
-
-
-
4,564
-
4,564
Revisions
-
-
-
-
-
(7)
-
(7)
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
252
-
252
Production
-
-
-
-
-
(388)
-
(388)
Sales
-
-
-
-
-
-
-
-
End of 2019
-
-
-
-
-
4,421
-
4,421
Revisions
-
-
-
-
-
(382)
-
(382)
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
2
-
2
Extensions and discoveries
-
-
-
-
-
78
-
78
Production
-
-
-
-
-
(395)
-
(395)
Sales
-
-
-
-
-
-
-
-
End of 2020
-
-
-
-
-
3,724
-
3,724
Revisions
-
-
-
-
-
247
-
247
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
116
-
116
Production
-
-
-
-
-
(390)
-
(390)
Sales
-
-
-
-
-
-
-
-
End of 2021
-
-
-
-
-
3,697
-
3,697
Total
 
company
End of 2018
2,736
2,318
5,054
26
1,212
5,643
214
12,149
End of 2019
2,688
2,431
5,119
43
896
5,398
224
11,680
End of 2020
1,996
2,100
4,096
74
825
4,575
224
9,794
End of 2021
2,625
4,658
7,283
105
768
4,461
217
12,834
 
 
 
 
 
 
 
 
Supplementary Data
 
157
 
ConocoPhillips
 
2021 10-K
Years Ended
Natural Gas
December 31
Billions of Cubic Feet
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Total
Developed
Consolidated operations
End of 2018
2,720
1,427
4,147
17
1,052
758
214
6,188
End of 2019
2,601
1,398
3,999
30
697
843
224
5,793
End of 2020
1,961
1,051
3,012
74
598
806
224
4,714
End of 2021
2,579
3,100
5,679
52
679
688
217
7,315
Equity affiliates
End of 2018
-
-
-
-
-
4,059
-
4,059
End of 2019
-
-
-
-
-
3,898
-
3,898
End of 2020
-
-
-
-
-
3,293
-
3,293
End of 2021
-
-
-
-
-
3,204
-
3,204
Undeveloped
Consolidated operations
End of 2018
16
891
907
9
160
321
-
1,397
End of 2019
87
1,033
1,120
13
199
134
-
1,466
End of 2020
35
1,049
1,084
-
227
45
-
1,356
End of 2021
46
1,558
1,604
53
89
76
-
1,822
Equity affiliates
End of 2018
-
-
-
-
-
505
-
505
End of 2019
-
-
-
-
-
523
-
523
End of 2020
-
-
-
-
-
431
-
431
End of 2021
-
-
-
-
-
493
-
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
 
 
 
Supplementary Data
 
ConocoPhillips
 
2021 10-K
 
158
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.
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.
 
Extensions and discoveries in Canada were primarily
 
driven by ongoing drilling
successes in Montney.
In 2020,
extensions and discoveries in Lower
 
48 were due to planned development
 
to add specific well locations from
 
the
unconventional plays
 
which more than offset the decreases resulting
 
from development plan timing in the revisions
category.
 
Extensions and discoveries in Canada were primarily
 
driven by ongoing drilling successes in Montney.
In 2019, extensions and discoveries in Lower
 
48 were due to planned development
 
to add specific well locations from
 
the
unconventional plays
 
which more than offset the decreases in the revisions
 
category.
 
Extensions and discoveries in our
equity affiliates were due to ongoing
 
development in APLNG.
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.
 
 
 
 
 
 
 
 
 
 
 
 
 
Supplementary Data
 
159
 
ConocoPhillips
 
2021 10-K
Years Ended
Bitumen
December 31
Millions of Barrels
Canada
Developed and Undeveloped
Consolidated operations
End of 2018
236
Revisions
37
Improved recovery
-
Purchases
-
Extensions and discoveries
31
Production
(22)
Sales
-
End of 2019
282
Revisions
(15)
Improved recovery
-
Purchases
-
Extensions and discoveries
85
Production
(20)
Sales
-
End of 2020
332
Revisions
(50)
Improved recovery
-
Purchases
-
Extensions and discoveries
-
Production
(25)
Sales
-
End of 2021
257
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
236
End of 2019
282
End of 2020
332
End of 2021
257
 
 
 
 
 
 
 
 
 
Supplementary Data
 
ConocoPhillips
 
2021 10-K
 
160
Years Ended
Bitumen
December 31
Millions of Barrels
Canada
Developed
Consolidated operations
End of 2018
155
End of 2019
187
End of 2020
117
End of 2021
150
Equity affiliates
End of 2018
-
End of 2019
-
End of 2020
-
End of 2021
-
Undeveloped
Consolidated operations
End of 2018
81
End of 2019
95
End of 2020
215
End of 2021
107
Equity affiliates
End of 2018
-
End of 2019
-
End of 2020
-
End of 2021
-
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.
 
 
 
 
 
 
 
 
 
 
 
 
Supplementary Data
 
161
 
ConocoPhillips
 
2021 10-K
Years Ended
Total Proved
 
Reserves
December 31
Millions of Barrels of Oil Equivalent
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Total
Developed and Undeveloped
Consolidated operations
End of 2018
1,795
1,312
3,107
245
465
342
224
4,383
Revisions
44
(67)
(23)
36
48
19
26
106
Improved recovery
7
-
7
-
-
-
-
7
Purchases
-
2
2
-
-
-
-
2
Extensions and discoveries
26
368
394
38
-
11
-
443
Production
(93)
(165)
(258)
(23)
(68)
(74)
(16)
(439)
Sales
-
(3)
(3)
-
(85)
-
-
(88)
End of 2019
1,779
1,447
3,226
296
360
298
234
4,414
Revisions
(398)
(226)
(624)
(20)
12
13
(3)
(622)
Improved recovery
-
-
-
-
-
3
-
3
Purchases
-
19
19
10
-
-
-
29
Extensions and discoveries
10
200
210
95
-
-
-
305
Production
(85)
(142)
(227)
(25)
(49)
(55)
(3)
(359)
Sales
-
(25)
(25)
(1)
-
(10)
-
(36)
End of 2020
1,306
1,273
2,579
355
323
249
228
3,734
Revisions
322
168
490
(45)
23
47
6
521
Improved recovery
1
-
1
-
-
-
-
1
Purchases
-
1,169
1,169
-
-
-
-
1,169
Extensions and discoveries
10
508
518
15
3
1
-
537
Production
(84)
(289)
(373)
(35)
(50)
(48)
(14)
(520)
Sales
-
(54)
(54)
-
-
-
-
(54)
End of 2021
1,555
2,775
4,330
290
299
249
220
5,388
Equity affiliates
End of 2018
-
-
-
-
-
880
-
880
Revisions
-
-
-
-
-
(1)
-
(1)
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
42
-
42
Production
-
-
-
-
-
(73)
-
(73)
Sales
-
-
-
-
-
-
-
-
End of 2019
-
-
-
-
-
848
-
848
Revisions
-
-
-
-
-
(63)
-
(63)
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
13
-
13
Production
-
-
-
-
-
(73)
-
(73)
Sales
-
-
-
-
-
-
-
-
End of 2020
-
-
-
-
-
725
-
725
Revisions
-
-
-
-
-
42
-
42
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
19
-
19
Production
-
-
-
-
-
(73)
-
(73)
Sales
-
-
-
-
-
-
-
-
End of 2021
-
-
-
-
-
713
-
713
Total
 
company
End of 2018
1,795
1,312
3,107
245
465
1,222
224
5,263
End of 2019
1,779
1,447
3,226
296
360
1,146
234
5,262
End of 2020
1,306
1,273
2,579
355
323
974
228
4,459
End of 2021
1,555
2,775
4,330
290
299
962
220
6,101
 
 
 
 
 
 
 
 
 
 
 
 
Supplementary Data
 
ConocoPhillips
 
2021 10-K
 
162
Years Ended
Total Proved
 
Reserves
December 31
Millions of Barrels of Oil Equivalent
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Total
Developed
Consolidated operations
End of 2018
1,617
681
2,298
160
382
244
221
3,305
End of 2019
1,582
666
2,248
197
275
236
218
3,174
End of 2020
1,186
521
1,707
140
238
211
212
2,508
End of 2021
1,424
1,767
3,191
166
244
212
207
4,020
Equity affiliates
End of 2018
-
-
-
-
-
796
-
796
End of 2019
-
-
-
-
-
761
-
761
End of 2020
-
-
-
-
-
653
-
653
End of 2021
-
-
-
-
-
631
-
631
Undeveloped
Consolidated operations
End of 2018
178
631
809
85
83
98
3
1,078
End of 2019
197
781
978
99
85
62
16
1,240
End of 2020
120
752
872
215
85
38
16
1,226
End of 2021
131
1,008
1,139
124
55
37
13
1,368
Equity affiliates
End of 2018
-
-
-
-
-
84
-
84
End of 2019
-
-
-
-
-
87
-
87
End of 2020
-
-
-
-
-
72
-
72
End of 2021
-
-
-
-
-
82
-
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:
Proved Undeveloped Reserves
Millions of Barrels of
Oil Equivalent
End of 2020
1,298
Revisions
(167)
Improved recovery
1
Purchases
158
Extensions and discoveries
448
Sales
-
Transfers
 
to proved developed
(288)
End of 2021
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.
 
Supplementary Data
 
163
 
ConocoPhillips
 
2021 10-K
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 transportatio
 
n
 
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.
 
 
 
 
 
 
 
 
 
 
 
Supplementary Data
 
ConocoPhillips
 
2021 10-K
 
164
Results of Operations
Year Ended
Millions of Dollars
December 31, 2021
Lower
Total
Asia Pacific/
Other
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Areas
Total
Consolidated operations
Sales
$
4,832
14,093
18,925
1,219
3,568
2,525
917
-
27,154
Transfers
4
-
4
-
-
-
-
-
4
Transportation costs
(626)
-
(626)
-
-
-
-
-
(626)
Other revenues
14
135
149
323
(5)
237
141
(161)
684
Total revenues
4,224
14,228
18,452
1,542
3,563
2,762
1,058
(161)
27,216
Production costs excluding taxes
1,073
2,414
3,487
518
487
466
43
-
5,001
Taxes
 
other than income taxes
442
937
1,379
23
36
91
1
1
1,531
Exploration expenses
80
98
178
39
21
51
2
15
306
Depreciation, depletion and
 
amortization
864
4,053
4,917
383
844
787
35
-
6,966
Impairments
5
(8)
(3)
6
(24)
7
-
-
(14)
Other related expenses
(31)
12
(19)
(22)
(42)
4
4
12
(63)
Accretion
71
47
118
10
70
26
-
-
224
1,720
6,675
8,395
585
2,171
1,330
973
(189)
13,265
Income tax provision (benefit)
378
1,467
1,845
145
1,673
494
870
(53)
4,974
Results of operations
$
1,342
5,208
6,550
440
498
836
103
(136)
8,291
Equity affiliates
Sales
$
-
-
-
-
-
745
-
-
745
Transfers
-
-
-
-
-
1,797
-
-
1,797
Transportation costs
-
-
-
-
-
-
-
-
-
Other revenues
-
-
-
-
-
5
-
-
5
Total revenues
-
-
-
-
-
2,547
-
-
2,547
Production costs excluding taxes
-
-
-
-
-
329
-
-
329
Taxes
 
other than income taxes
-
-
-
-
-
824
-
-
824
Exploration expenses
-
-
-
-
-
268
-
-
268
Depreciation, depletion and
 
amortization
-
-
-
-
-
593
593
Impairments
-
-
-
-
-
718
-
-
718
Other related expenses
-
-
-
-
-
3
-
-
3
Accretion
-
-
-
-
-
17
-
-
17
-
-
-
-
-
(205)
-
-
(205)
Income tax provision (benefit)
-
-
-
-
-
(42)
-
-
(42)
Results of operations
$
-
-
-
-
-
(163)
-
-
(163)
 
 
 
 
 
 
 
 
 
 
Supplementary Data
 
165
 
ConocoPhillips
 
2021 10-K
Year Ended
Millions of Dollars
December 31, 2020
Lower
Total
Asia Pacific/
Other
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Areas
Total
Consolidated operations
Sales
$
2,944
3,421
6,365
230
1,560
1,717
129
-
10,001
Transfers
4
-
4
-
-
191
-
-
195
Transportation costs
(587)
-
(587)
-
-
(19)
-
-
(606)
Other revenues
(1)
(20)
(21)
40
(21)
576
11
10
595
Total revenues
2,360
3,401
5,761
270
1,539
2,465
140
10
10,185
Production costs excluding taxes
1,058
1,399
2,457
366
417
478
21
2
3,741
Taxes
 
other than income taxes
296
263
559
16
30
42
3
1
651
Exploration expenses
1,099
73
1,172
40
52
71
13
108
1,456
Depreciation, depletion and
 
amortization
840
2,544
3,384
335
755
808
8
-
5,290
Impairments
-
804
804
3
5
-
-
-
812
Other related expenses
46
5
51
5
(58)
(25)
(29)
2
(54)
Accretion
72
46
118
8
73
33
-
-
232
(1,051)
(1,733)
(2,784)
(503)
265
1,058
124
(103)
(1,943)
Income tax provision (benefit)
(271)
(430)
(701)
(191)
116
277
88
(20)
(431)
Results of operations
$
(780)
(1,303)
(2,083)
(312)
149
781
36
(83)
(1,512)
Equity affiliates
Sales
$
-
-
-
-
-
483
-
-
483
Transfers
-
-
-
-
-
1,205
-
-
1,205
Transportation costs
-
-
-
-
-
-
-
-
-
Other revenues
-
-
-
-
-
8
-
-
8
Total revenues
-
-
-
-
-
1,696
-
-
1,696
Production costs excluding taxes
-
-
-
-
-
289
-
-
289
Taxes
 
other than income taxes
-
-
-
-
-
502
-
-
502
Exploration expenses
-
-
-
-
-
20
-
-
20
Depreciation, depletion and
 
amortization
-
-
-
-
-
569
-
-
569
Impairments
-
-
-
-
-
-
-
-
-
Other related expenses
-
-
-
-
-
(2)
-
-
(2)
Accretion
-
-
-
-
-
15
-
-
15
-
-
-
-
-
303
-
-
303
Income tax provision (benefit)
-
-
-
-
-
39
-
-
39
Results of operations
$
-
-
-
-
-
264
-
-
264
 
 
 
 
 
 
 
 
 
 
Supplementary Data
 
ConocoPhillips
 
2021 10-K
 
166
Year Ended
Millions of Dollars
December 31, 2019
Lower
Total
Asia Pacific/
Other
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Areas
Total
Consolidated operations
Sales
$
4,883
6,356
11,239
709
3,207
3,032
919
-
19,106
Transfers
4
-
4
-
-
449
-
-
453
Transportation costs
(629)
-
(629)
-
-
(41)
-
-
(670)
Other revenues
61
78
139
86
1,785
12
101
326
2,449
Total revenues
4,319
6,434
10,753
795
4,992
3,452
1,020
326
21,338
Production costs excluding taxes
1,235
1,578
2,813
380
741
619
70
(8)
4,615
Taxes
 
other than income taxes
308
437
745
18
32
54
3
(2)
850
Exploration expenses
97
430
527
32
69
80
5
33
746
Depreciation, depletion and
 
amortization
700
2,804
3,504
230
842
1,172
37
-
5,785
Impairments
-
402
402
2
1
-
-
-
405
Other related expenses
(12)
116
104
(38)
(42)
58
22
10
114
Accretion
62
49
111
7
142
43
-
-
303
1,929
618
2,547
164
3,207
1,426
883
293
8,520
Income tax provision (benefit)
444
147
591
(74)
591
458
833
7
2,406
Results of operations
$
1,485
471
1,956
238
2,616
968
50
286
6,114
Equity affiliates
Sales
$
-
-
-
-
-
599
-
-
599
Transfers
-
-
-
-
-
2,229
-
-
2,229
Transportation costs
-
-
-
-
-
-
-
-
-
Other revenues
-
-
-
-
-
31
-
-
31
Total revenues
-
-
-
-
-
2,859
-
-
2,859
Production costs excluding taxes
-
-
-
-
-
335
-
-
335
Taxes
 
other than income taxes
-
-
-
-
-
820
-
-
820
Exploration expenses
-
-
-
-
-
-
-
-
-
Depreciation, depletion and
 
amortization
-
-
-
-
-
579
-
-
579
Impairments
-
-
-
-
-
-
-
-
-
Other related expenses
-
-
-
-
-
11
-
-
11
Accretion
-
-
-
-
-
16
-
-
16
-
-
-
-
-
1,098
-
-
1,098
Income tax provision (benefit)
-
-
-
-
-
170
-
-
170
Results of operations
$
-
-
-
-
-
928
-
-
928
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Supplementary Data
 
167
 
ConocoPhillips
 
2021 10-K
Statistics
 
Net Production
2021
2020
2019
Thousands of Barrels Daily
Crude Oil
 
Consolidated operations
Alaska
 
178
181
202
Lower 48
447
213
266
United States
625
394
468
Canada
8
6
1
Europe
81
78
100
Asia Pacific
65
69
85
Africa
37
8
38
Total
 
consolidated operations
816
555
692
Equity affiliates—
Asia Pacific/Middle East
13
13
13
Total
 
company
829
568
705
Delaware Basin Area (Lower 48)*
162
28
24
Greater Prudhoe Area (Alaska)*
67
68
66
Natural Gas Liquids
Consolidated operations
Alaska
 
16
16
15
Lower 48
110
74
81
United States
126
90
96
Canada
4
2
-
Europe
4
4
7
Asia Pacific
-
1
4
Total
 
consolidated operations
134
97
107
Equity affiliates—
Asia Pacific/Middle East
8
8
8
Total
 
company
142
105
115
Delaware Basin Area (Lower 48)*
27
11
11
Greater Prudhoe Area (Alaska)*
16
15
15
Bitumen
Consolidated operations—
Canada
69
55
60
Total
 
company
69
55
60
Natural Gas
Millions of Cubic Feet Daily
Consolidated operations
Alaska
16
10
7
Lower 48
1,340
585
622
United States
1,356
595
629
Canada
80
40
9
Europe
298
270
447
Asia Pacific
360
429
637
Africa
15
5
31
Total
 
consolidated operations
2,109
1,339
1,753
Equity affiliates—
Asia Pacific/Middle East
1,053
1,055
1,052
Total
 
company
3,162
2,394
2,805
Delaware Basin Area (Lower 48)*
584
99
86
Greater Prudhoe Area (Alaska)*
12
4
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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Supplementary Data
 
ConocoPhillips
 
2021 10-K
 
168
Average Sales Prices
2021
2020
2019
Crude Oil Per Barrel
 
Consolidated operations
Alaska*
$
60.81
33.72
55.85
Lower 48
66.12
35.17
55.30
United States
64.53
34.48
55.54
Canada
56.38
23.57
40.87
Europe
68.94
42.80
65.12
Asia Pacific
70.36
42.84
65.02
Africa
69.06
48.64
64.47
Total
 
international
68.85
42.39
64.85
Total
 
consolidated operations
65.53
36.69
58.51
Equity affiliates
—Asia Pacific/Middle East
69.45
39.02
61.32
Total
 
operations
65.59
36.75
58.57
Natural Gas Liquids Per Barrel
 
Consolidated operations
Lower 48
$
30.63
12.13
16.83
United States
30.63
12.13
16.85
Canada
31.18
5.41
19.87
Europe
43.97
23.27
29.37
Asia Pacific
-
33.21
37.85
Total
 
international
37.50
20.25
32.29
Total
 
consolidated operations
31.04
12.90
18.73
Equity affiliates
—Asia Pacific/Middle East
54.16
32.69
36.70
Total
 
operations
32.45
14.61
20.09
Bitumen Per Barrel
Consolidated operations—
Canada
$
37.52
8.02
**
31.72
Natural Gas Per Thousand Cubic Feet
Consolidated operations
Alaska
$
2.81
2.91
3.19
Lower 48
4.38
1.65
2.12
United States
4.38
1.66
2.12
Canada
2.54
1.21
0.49
Europe
13.75
3.23
4.92
Asia Pacific*
6.56
5.27
5.73
Africa
3.73
3.71
4.87
Total
 
international
8.91
4.31
5.35
Total
 
consolidated operations
6.00
3.13
4.19
Equity affiliates
—Asia Pacific/Middle East
5.31
3.71
6.29
Total
 
operations
5.77
3.38
4.99
*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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Supplementary Data
 
169
 
ConocoPhillips
 
2021 10-K
2021
2020
2019
Average Production Costs
 
Per Barrel of Oil Equivalent*
Consolidated operations
Alaska
$
14.92
14.60
15.52
Lower 48
8.48
9.93
9.59
United States
9.78
11.51
11.52
Canada
15.10
14.29
16.53
Europe
9.88
8.97
11.22
Asia Pacific
10.21
9.26
8.74
Africa
2.95
6.38
4.46
Total
 
international
10.53
10.11
10.26
Total
 
consolidated operations
9.99
10.99
10.99
Equity affiliates—
Asia Pacific/Middle East
4.60
4.01
4.68
Average Production Costs
 
Per Barrel—Bitumen
Consolidated operations—
Canada
$
13.41
12.45
13.74
Taxes
 
Other Than Income Taxes
 
Per Barrel of Oil Equivalent
Consolidated operations
Alaska
$
6.15
4.08
3.87
Lower 48
3.29
1.87
2.65
United States
3.87
2.62
3.05
Canada
0.67
0.62
0.78
Europe
0.73
0.65
0.48
Asia Pacific
1.99
0.81
0.76
Africa
0.07
0.91
0.19
Total
 
international
1.06
0.72
0.60
Total
 
consolidated operations
3.06
1.91
2.03
Equity affiliates—
Asia Pacific/Middle East
11.52
6.96
11.46
Depreciation, Depletion and Amortization Per Barrel of Oil Equivalent
Consolidated operations
Alaska
$
12.02
11.59
8.80
Lower 48
14.24
18.05
17.03
United States
13.79
15.86
14.35
Canada
11.16
13.08
10.00
Europe
17.13
16.24
12.75
Asia Pacific
17.25
15.66
16.55
Africa
2.40
2.43
2.36
Total
 
international
14.25
15.01
12.99
Total
 
consolidated operations
13.92
15.54
13.78
Equity affiliates—
Asia Pacific/Middle East
8.29
7.89
8.09
*Includes bitumen.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Supplementary Data
 
ConocoPhillips
 
2021 10-K
 
170
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
Productive
Dry
2021
2020
2019
2021
2020
2019
Exploratory
Consolidated operations
Alaska
-
-
7
1
3
-
Lower 48
87
3
35
-
-
6
United States
87
3
42
1
3
6
Canada
12
23
-
-
-
-
Europe
-
-
1
-
 
*
1
Asia Pacific/Middle East
*
 
*
1
*
 
*
1
Africa
-
-
-
-
 
*
-
Other areas
-
-
-
-
 
*
-
Total
 
consolidated operations
99
26
44
1
3
8
Equity affiliates
Asia Pacific/Middle East
3
8
8
-
-
-
Total
 
equity affiliates
3
8
8
-
-
-
Development
Consolidated operations
 
Alaska
1
7
12
-
-
-
Lower 48
339
127
255
-
-
-
United States
340
134
267
-
-
-
Canada
2
-
2
-
-
-
Europe
7
7
6
-
-
-
Asia Pacific/Middle East
21
16
21
-
-
-
Africa
1
2
2
-
-
-
Other areas
-
-
-
-
-
-
Total
 
consolidated operations
371
159
298
-
-
-
Equity affiliates
Asia Pacific/Middle East
30
109
106
-
-
-
Total
 
equity affiliates
30
109
106
-
-
-
*Our total proportionate interest was less than one.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Supplementary Data
 
171
 
ConocoPhillips
 
2021 10-K
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.
Wells at December 31, 2021
Productive
In Progress
Oil
Gas
Gross
Net
Gross
Net
Gross
Net
Consolidated operations
Alaska
2
1
1,602
940
-
-
Lower 48
665
337
16,306
8,015
5,091
2,211
United States
667
338
17,908
8,955
5,091
2,211
Canada
18
15
186
94
149
149
Europe
11
1
494
84
59
2
Asia Pacific/Middle East
15
7
351
166
38
18
Africa
7
1
858
140
10
2
Other areas
-
-
-
-
-
-
Total
 
consolidated operations
718
362
19,797
9,439
5,347
2,382
Equity affiliates
Asia Pacific/Middle East
130
25
-
-
4,908
1,171
Total
 
equity affiliates
130
25
-
-
4,908
1,171
Acreage at December 31, 2021
Thousands of Acres
Developed
Undeveloped
Gross
Net
Gross
Net
Consolidated operations
Alaska
663
479
1,341
1,329
Lower 48
4,096
2,538
10,514
8,233
United States
4,759
3,017
11,855
9,562
Canada
297
219
3,433
1,948
Europe
430
50
938
371
Asia Pacific/Middle East
921
421
10,451
6,930
Africa
358
58
12,545
2,049
Other areas
-
-
156
125
Total
 
consolidated operations
6,765
3,765
39,378
20,985
Equity affiliates
Asia Pacific/Middle East
1,039
248
3,807
856
Total equity
 
affiliates
1,039
248
3,807
856
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Supplementary Data
 
ConocoPhillips
 
2021 10-K
 
172
Costs Incurred
Year Ended
Millions of Dollars
December 31
Lower
Total
Asia Pacific/
Other
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Areas
Total
2021
Consolidated operations
Unproved property acquisition
$
1
11,261
11,262
4
-
-
-
-
11,266
Proved property acquisition
-
16,101
16,101
1
-
-
-
-
16,102
1
27,362
27,363
5
-
-
-
-
27,368
Exploration
84
765
849
80
31
51
2
40
1,053
Development
949
2,461
3,410
175
398
433
24
-
4,440
$
1,034
30,588
31,622
260
429
484
26
40
32,861
Equity affiliates
Unproved property acquisition
$
-
-
-
-
-
-
-
-
-
Proved property acquisition
-
-
-
-
-
-
-
-
-
-
-
Exploration
-
-
-
-
-
5
-
-
5
Development
-
-
-
-
-
21
-
-
21
$
-
-
-
-
-
26
-
-
26
2020
Consolidated operations
Unproved property acquisition
$
4
10
14
378
-
3
-
9
404
Proved property acquisition
-
62
62
129
-
-
-
-
191
4
72
76
507
-
3
-
9
595
Exploration
287
116
403
218
110
32
4
38
805
Development
745
1,758
2,503
102
451
427
18
-
3,501
$
1,036
1,946
2,982
827
561
462
22
47
4,901
Equity affiliates
Unproved property acquisition
$
-
-
-
-
-
-
-
-
-
Proved property acquisition
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Exploration
-
-
-
-
-
12
-
-
12
Development
-
-
-
-
-
282
-
-
282
$
-
-
-
-
-
294
-
-
294
2019
Consolidated operations
Unproved property acquisition
$
101
45
146
14
-
-
-
197
357
Proved property acquisition
1
116
117
-
-
115
-
-
232
102
161
263
14
-
115
-
197
589
Exploration
281
390
671
200
119
66
8
39
1,103
Development
1,125
3,028
4,153
215
625
486
22
-
5,501
$
1,508
3,579
5,087
429
744
667
30
236
7,193
Equity affiliates
Unproved property acquisition
$
-
-
-
-
-
62
-
-
62
Proved property acquisition
-
-
-
-
-
-
-
-
-
-
-
-
-
-
62
-
-
62
Exploration
-
-
-
-
-
23
-
-
23
Development
-
-
-
-
-
171
-
-
171
$
-
-
-
-
-
256
-
-
256
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Supplementary Data
 
173
 
ConocoPhillips
 
2021 10-K
Capitalized Costs
At December 31
Millions of Dollars
Lower
Total
Asia Pacific/
Other
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Areas
Total
2021
Consolidated operations
Proved property
 
$
22,750
58,561
81,311
7,380
14,514
12,226
966
-
116,397
Unproved property
 
1,402
7,704
9,106
1,517
155
92
114
9
10,993
24,152
66,265
90,417
8,897
14,669
12,318
1,080
9
127,390
Accumulated depreciation,
depletion and amortization
11,945
29,975
41,920
2,749
10,166
9,240
422
9
64,506
$
12,207
36,290
48,497
6,148
4,503
3,078
658
-
62,884
Equity affiliates
Proved property
 
$
-
-
-
-
-
10,357
-
-
10,357
Unproved property
 
-
-
-
-
-
2,162
-
-
2,162
-
-
-
-
-
12,519
-
-
12,519
Accumulated depreciation,
depletion and amortization
-
-
-
-
-
8,539
-
-
8,539
$
-
-
-
-
-
3,980
-
-
3,980
2020
Consolidated operations
Proved property
$
21,819
37,452
59,271
7,255
14,931
11,913
942
 
-
 
94,312
Unproved property
 
1,398
631
2,029
1,529
151
89
114
229
4,141
23,217
38,083
61,300
8,784
15,082
12,002
1,056
229
98,453
Accumulated depreciation,
depletion and amortization
11,098
27,948
39,046
2,431
10,015
8,567
387
9
60,455
$
12,119
10,135
22,254
6,353
5,067
3,435
669
220
37,998
Equity affiliates
Proved property
$
-
-
-
-
-
10,310
-
-
10,310
Unproved property
-
-
-
-
-
2,187
-
-
2,187
-
-
-
-
-
12,497
-
-
12,497
Accumulated depreciation,
depletion and amortization
-
-
-
-
-
6,959
-
-
6,959
$
-
-
-
-
-
5,538
-
-
5,538
 
 
 
 
 
 
 
 
 
 
Supplementary Data
 
ConocoPhillips
 
2021 10-K
 
174
Standardized Measure of
 
Discounted Future Net Cash Flows Relatin
 
g
 
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 prescri
 
bed 10 percent discount factor.
 
Twelve-
month average prices are calculated
 
as the unweighted arithmetic average
 
of the first-day-of-the-month
 
price for each month within
the 12-month period prior to the end of the reporting period.
 
For all years, continuation of year
 
-end economic conditions was
assumed.
 
The calculations were based on estimates
 
of proved reserves, which are revised
 
over time as new data becomes available.
 
Probable or possible reserves, which may become
 
proved in the future, were not considered.
 
The calculations also require
assumptions as to the timing of future production
 
of proved reserves and the timing and amount
 
of future development costs,
including dismantlement, and future production
 
costs, including taxes other than
 
income taxes.
While due care was taken in
 
its preparation, we do not represent
 
that this data is the fair value of our
 
oil and gas properties, or a fair
estimate of the present value
 
of cash flows to be obtained from their development
 
and production.
Discounted Future Net Cash Flows
Millions of Dollars
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Total
2021
Consolidated operations
Future cash inflows
$
65,910
125,197
191,107
10,847
21,670
11,583
15,778
250,985
Less:
Future production costs
 
34,444
43,034
77,478
4,960
6,090
4,987
801
94,316
Future development costs
8,033
13,386
21,419
923
3,960
1,314
413
28,029
Future income tax provisions
5,310
13,167
18,477
117
8,345
1,542
13,506
41,987
Future net cash flows
18,123
55,610
73,733
4,847
3,275
3,740
1,058
86,653
10 percent annual discount
7,963
22,290
30,253
1,639
696
930
440
33,958
Discounted future net cash flows
$
10,160
33,320
43,480
3,208
2,579
2,810
618
52,695
Equity affiliates
Future cash inflows
$
-
-
-
-
-
27,851
-
27,851
Less:
Future production costs
 
-
-
-
-
-
15,491
-
15,491
Future development costs
-
-
-
-
-
1,649
-
1,649
Future income tax provisions
-
-
-
-
-
3,071
-
3,071
Future net cash flows
-
-
-
-
-
7,640
-
7,640
10 percent annual discount
-
-
-
-
-
2,640
-
2,640
Discounted future net cash flows
$
-
-
-
-
-
5,000
-
5,000
Total
 
company
Discounted future net cash flows
$
10,160
33,320
43,480
3,208
2,579
7,810
618
57,695
 
 
 
 
 
 
 
 
 
Supplementary Data
 
175
 
ConocoPhillips
 
2021 10-K
Millions of Dollars
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada*
Europe
Middle East
Africa
Total
2020
Consolidated operations
Future cash inflows
$
30,145
31,533
61,678
4,198
9,857
7,940
9,997
93,670
Less:
Future production costs
 
22,905
17,582
40,487
4,316
4,770
3,838
1,277
54,688
Future development costs
7,932
12,799
20,731
750
3,688
1,289
461
26,919
Future income tax provisions
-
376
376
-
267
1,075
7,571
9,289
Future net cash flows
(692)
776
84
(868)
1,132
1,738
688
2,774
10 percent annual discount
(1,501)
(820)
(2,321)
(396)
117
406
294
(1,900)
Discounted future net cash flows
$
809
1,596
2,405
(472)
1,015
1,332
394
4,674
Equity affiliates
Future cash inflows
$
-
-
-
-
-
17,284
-
17,284
Less:
Future production costs
-
-
-
-
-
10,239
-
10,239
Future development costs
-
-
-
-
-
1,186
-
1,186
Future income tax provisions
-
-
-
-
-
1,728
-
1,728
Future net cash flows
-
-
-
-
-
4,131
-
4,131
10 percent annual discount
-
-
-
-
-
1,269
-
1,269
Discounted future net cash flows
$
-
-
-
-
-
2,862
-
2,862
Total
 
company
Discounted future net cash flows
$
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.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Supplementary Data
 
ConocoPhillips
 
2021 10-K
 
176
Millions of Dollars
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Total
2019
Consolidated operations
Future cash inflows
$
70,341
53,400
123,741
8,244
16,919
13,084
15,582
177,570
Less:
Future production costs
40,464
22,194
62,658
4,525
5,843
5,162
1,314
79,502
Future development costs
9,721
14,083
23,804
577
4,143
2,179
484
31,187
Future income tax provisions
3,904
2,793
6,697
-
4,201
1,931
12,747
25,576
Future net cash flows
16,252
14,330
30,582
3,142
2,732
3,812
1,037
41,305
10 percent annual discount
6,571
4,311
10,882
1,198
558
835
460
13,933
Discounted future net cash flows
$
9,681
10,019
19,700
1,944
2,174
2,977
577
27,372
Equity affiliates
Future cash inflows
$
-
-
-
-
-
31,671
-
31,671
Less:
Future production costs
-
-
-
-
-
16,157
-
16,157
Future development costs
-
-
-
-
-
1,218
-
1,218
Future income tax provisions
-
-
-
-
-
3,086
-
3,086
Future net cash flows
-
-
-
-
-
11,210
-
11,210
10 percent annual discount
-
-
-
-
-
4,040
-
4,040
Discounted future net cash flows
$
-
-
-
-
-
7,170
-
7,170
Total
 
company
Discounted future net cash flows
$
9,681
10,019
19,700
1,944
2,174
10,147
577
34,542
 
 
 
 
 
 
 
 
 
 
 
Supplementary Data
 
177
 
ConocoPhillips
 
2021 10-K
Sources of Change in Discounted
 
Future Net Cash Flows
Millions of Dollars
Consolidated Operations
Equity Affiliates
Total Company
2021
2020
2019
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
(20,000)
(5,198)
(13,424)
(1,389)
(897)
(1,673)
(21,389)
(6,095)
(15,097)
Net change in prices and
production costs
50,956
(34,307)
(13,538)
3,822
(4,769)
(422)
54,778
(39,076)
(13,960)
Extensions, discoveries and
improved recovery,
 
less
estimated future costs
10,420
887
2,985
(44)
22
260
10,376
909
3,245
Development costs for the year
4,396
3,593
5,333
91
192
239
4,487
3,785
5,572
Changes in estimated future
development costs
(33)
754
559
(104)
(205)
(21)
(137)
549
538
Purchases of reserves in place,
 
less estimated future costs
17,833
1
10
-
(3)
-
17,833
(2)
10
Sales of reserves in place,
 
less estimated future costs
(468)
(302)
(1,997)
-
-
-
(468)
(302)
(1,997)
Revisions of previous quantity
estimates
2,985
(2,299)
2,099
178
(42)
69
3,163
(2,341)
2,168
Accretion of discount
964
3,984
5,144
344
804
869
1,308
4,788
6,013
Net change in income taxes
(19,032)
10,189
4,767
(760)
590
(80)
(19,792)
10,779
4,687
Total changes
48,021
(22,698)
(8,062)
2,138
(4,308)
(759)
50,159
(27,006)
(8,821)
Discounted future net cash flows
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.
 
ConocoPhillips
 
2021 10-K
 
178
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
 
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.
 
179
 
ConocoPhillips
 
2021 10-K
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.
 
 
 
 
ConocoPhillips
 
2021 10-K
 
180
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
, are filed as part of this annual report.
 
2.
 
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.
 
3.
 
Exhibits
The exhibits listed in the Index to
 
Exhibits, which appears on pages
 
through 185, are filed as part of
this annual report.
 
 
 
181
 
ConocoPhillips
 
2021 10-K
ConocoPhillips
Index to Exhibits
Incorporated by Reference
Exhibit
No.
Description
Exhibit
Form
File No.
2.1
2.1
8-K
001-32395
2.2†‡
2.1
10-Q
001-32395
2.3†‡
2.2
8-K
001-32395
2.4
2.1
8-K
001-32395
3.1
3.1
10-Q
001-32395
3.2
3.2
8-K
000-49987
3.3
3.1
8-K
001-32395
3.4*
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
4.1
10-K
001-32395
10.1
10.11
10-K
004-49987
10.2
10.12
10-K
004-49987
10.5
 
10.14
10-Q
001-32395
10.7
10.19
10-K
004-49987
10.10.1
10.10.1
10-K
001-32395
10.10.2
10.1
10-Q
001-32395
 
ConocoPhillips
 
2021 10-K
 
182
10.11.1
10.11.1
10-K
001-32395
10.11.2
10.11.2
10-K
001-32395
10.12
10.26
10-K
000-49987
10.15
10.17
10-K
001-32395
10.16.1
10.11
10-K
001-14521
10.16.2
10.39.1
10-K
000-49987
10.16.3
10.17.3
10-K
001-32395
10.16.4
10.17.4
10-K
001-32395
10.16.5
10.17.5
10-K
001-32395
10.16.6
10.17.6
10-K
001-32395
10.16.7
10.17.7
10-K
001-32395
10.16.8
10.17.8
10-K
001-32395
10.17.1
10.40
10-K
000-49987
10.17.2
10
10-Q
001-32395
10.19.1
10.19.1
10-K
001-32395
10.19.2
10.19.2
10-K
001-32395
10.20
10.21
10-K
001-32395
10.20.1*
10.22.1
Schedule
14A
Proxy
000-49987
10.22.2
10.26
10-K
001-32395
10.22.3
10.27
10-K
001-32395
10.23
10.30
10-K
001-32395
 
183
 
ConocoPhillips
 
2021 10-K
10.24
Schedule
14A
Proxy
001-32395
10.25.1
Schedule
14A
Proxy
001-32395
10.25.2
10
10-Q
001-32395
10.25.4
10.26.6
10-K
001-32395
10.25.7
10.26.9
10-K
001-32395
10.25.8
10.2
10-Q
001-32395
10.25.9
10.1
10-Q
001-32395
10.25.10
10.26.12
10-K
001-32395
10.25.12
 
10.3
10-Q
001-32395
10.25.14
 
10.5
10-Q
001-32395
10.25.17
 
10.11
10-Q
001-32395
10.25.18
10.26.24
10-K
001-32395
10.26.1
10.1
8-K
001-32395
10.26.4
10.3
10-Q
001-32395
10.26.7
10.1
10-Q
001-32395
 
ConocoPhillips
 
2021 10-K
 
184
10.26.11
10.27.12
10-K
001-32395
10.26.13
10.27.14
10-K
001-32395
10.26.14
10.27.15
10-K
001-32395
10.26.15
 
10.27.16
10-K
001-32395
10.27
10.27
10-K
001-32395
10.29
10.9
10-Q
001-32395
10.30.1
10.1
10-Q
001-32395
10.30.2
10.2
10-Q
001-32395
10.31
10.1
8-K
001-32395
10.32
10.2
8-K
001-32395
10.33
10.3
8-K
001-32395
10.34
10.4
8-K
001-32395
10.36
10.3
10-Q
001-32395
10.37
10.1
8-K
001-32395
10.38
10.39
10-K
001-32395
10.40
10.1
10-Q
001-32395
10.41
10.1
10-Q
001-32395
 
185
 
ConocoPhillips
 
2021 10-K
10.42
10.1
10-Q
001-32395
10.43
10.3
10-Q
001-32395
10.44
10.1
10-Q
001-32395
10.45
10.2
10-Q
001-32395
10.46
10.1
10-Q
001-32395
10.47*
 
21*
22*
23.1*
23.2*
31.1*
31.2*
32*
99*
 
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.
 
 
 
 
ConocoPhillips
 
2021 10-K
 
186
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.
CONOCOPHILLIPS
February 17, 2022
/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
Chairman of the Board of Directors
Ryan M. Lance
and Chief Executive Officer
(Principal executive officer)
/s/ William L. Bullock, Jr.
Executive Vice President and
William L. Bullock, Jr.
Chief Financial Officer
(Principal financial officer)
/s/ Kontessa S. Haynes-Welsh
Chief Accounting Officer
Kontessa S. Haynes-Welsh
(Principal accounting officer)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
187
 
ConocoPhillips
 
2021 10-K
/s/ Charles E. Bunch
Director
Charles E. Bunch
 
/s/ Caroline M. Devine
Director
Caroline M. Devine
/s/ Gay Huey Evans
Director
Gay Huey Evans
/s/ John V.
 
Faraci
Director
John V.
 
Faraci
/s/ Jody Freeman
Director
Jody Freeman
/s/ Jeffrey A. Joerres
Director
Jeffrey A. Joerres
/s/ Timothy A. Leach
Director
Timothy A. Leach
/s/ William H. McRaven
Director
William H. McRaven
/s/ Sharmila Mulligan
Director
Sharmila Mulligan
/s/ Eric D. Mullins
Director
Eric D. Mullins
/s/ Arjun N. Murti
Director
Arjun N. Murti
/s/ Robert A. Niblock
Director
Robert A. Niblock
/s/ David T.
 
Seaton
Director
David T.
 
Seaton
/s/ R.A. Walker
Director
R.A. Walker
d123121dex34
 
Exhibit 3.4
RESTATED
 
CERTIFICATE
 
OF INCORPORATION
OF
CONOCOPHILLIPS COMPANY
a Delaware corporation
ConocoPhillips Company (the “Corporation”),
 
a corporation existing under
 
the laws of the State of Delaware,
 
does
hereby certify that:
A.
The name of the Corporation is ConocoPhillips
 
Company.
B.
The Corporation was originally incorporated
 
as Phillips Petroleum Company.
C.
The Certificate of Incorporation
 
of the Corporation was filed with the Secretary
 
of State of the State of
Delaware on July 13, 1917.
D.
This Restated Certificate
 
of Incorporation was duly
 
adopted in accordance with Section 245 of the General
Corporation Law of the State
 
of Delaware and restates
 
and integrates and does not
 
further amend the
provisions of the Corporation’s
 
Certificate of Incorporation as theretofore
 
amended or supplemented, and
there is no discrepancy between those provisions
 
and the provisions of the restated
 
certificate.
E.
The text of the Certificate of Incorporation
 
of the Corporation is hereby restated
 
in its entirety to read as
follows:
ARTICLE I
The name of the corporation is ConocoPhillips
 
Company
ARTICLE II
The address of the Corporation’s
 
registered office in the State
 
of Delaware is 251 Little Falls
 
Drive, in the City
of Wilmington, County of New Castle,
 
Delaware 19808. The name of its registered
 
agent is Corporation Service
Company.
ARTICLE III
The purpose of the Corporation shall be to engage
 
in any lawful act or activity for which corporations
 
may be
organized and incorporated
 
under the General Corporation Law of the State
 
of Delaware.
ARTICLE IV
Section 1.
 
The Corporation shall be authorized
 
to issue 2,100 shares of capital stock,
 
of which 2,100 shares
shall be shares of Common Stock, $.01 par value (“Common
 
Stock”).
Section 2.
 
Except as otherwise provided by law,
 
the Common Stock shall have the exclusive
 
right to vote for
the election of directors and for
 
all other purposes. Each share of Common Stock shall
 
have one vote, and the
Common Stock shall vote together as
 
a single class.
 
 
ARTICLE
 
V
Unless and except to the extent
 
that the By-Laws of the Corporation
 
shall so require, the election of directors
of the Corporation need not be by written
 
ballot.
ARTICLE VI
In furtherance and not in limitation of the powers
 
conferred by law,
 
the Board of Directors is expressly
authorized and empowered to
 
make, alter and repeal the By
 
-Laws of the Corporation by a majority
 
vote at any
regular or special meeting of the
 
Board of Directors or by written
 
consent, subject to the power of the
stockholders of the Corporation
 
to alter or repeal any By-Laws
 
made by the Board of Directors.
ARTICLE VII
The Corporation reserves the right
 
at any time from time to time to amend, alter,
 
change or repeal any
provision contained in this Certificate
 
of Incorporation, and any
 
other provisions authorized by the laws
 
of the
State of Delaware at the time
 
in force may be added or inserted,
 
in the manner now or hereafter prescribed by
law; and all rights, preferences
 
and privileges of whatsoever nature
 
conferred upon stockholders,
 
directors or any
other persons whomsoever by and pursuant
 
to this Certificate of Incorporation
 
in its present form or as hereafter
amended are granted subject to
 
the right reserved in this Article.
ARTICLE VIII
A director of the Corporation shall not
 
be personally liable to the Corporation
 
or its stockholders for monetary
damages for breach of fiduciary duty as a director,
 
except to the extent such
 
exemption from liability or limitation
thereof is not permitted under the General
 
Corporation Law of the State of Delaware
 
as the same exists or may
hereafter be amended.
Any repeal or modification of the foregoing
 
paragraph shall not adversely
 
affect any right or protection
 
of a
director of the Corporation existing
 
hereunder with respect to any
 
act or omission occurring prior to such repeal or
modification.
IN WITNESS WHEREOF,
 
the Corporation has caused this Restated
 
Certificate of Incorporation
 
to be signed by
the undersigned, a duly authorized officer of the Corporation
 
on February 6, 2019.
By:
 
/s/ Kelly B. Rose
 
 
Kelly B. Rose
 
 
Senior Vice President, Legal, General
 
Counsel and Corporate Secretary
d123121dex10201
 
 
Exhibit
 
10.20.1
1
CONOCOPHILLIPS
KEY EMPLOYEE CHANGE IN CONTROL SEVERANCE PLAN
(Amended and Restated Effective
 
as of December 2, 2021)
The ConocoPhillips Key Employee Change in Control Severance
 
Plan (the "Plan") is hereby
amended and restated effective
 
as of December 2, 2021.
 
All capitalized terms used herein are
defined in Section 1 hereof.
 
Effective October 1, 2004, the Company adopted
 
this Plan for the
 
benefit of certain employees
 
of
the Company
 
and its Subsidiaries.
 
This Plan
 
was subsequently
 
amended and
 
restated
 
effective
December 31,
 
2008, then subsequently
 
amended and restated
 
as of the
 
Effective
 
Time (as that
term is
 
used in
 
the Employee
 
Matters Agreement between ConocoPhillips
 
and Phillips
 
66 dated
 
as
of
 
April
 
26,
 
2012),
 
then
 
further
 
amended
 
and
 
restated
 
effective
 
January 1,
 
2014.
 
This
 
Plan
 
is
hereby subsequently
 
amended
 
and
 
restated
 
effective
 
December
 
2,
 
2021,
 
which
 
restatement
 
wholly
replaces the prior restatement
 
(except as set forth below), by approval
 
of the Human Resources
and
 
Compensation
 
Committee
 
of
 
the
 
Board
 
of
 
Directors
 
of
 
ConocoPhillips
 
at
 
its
 
meeting
 
on
December 2, 2021.
This
 
Plan
 
is
 
intended
 
to
 
be
 
a
 
plan
 
maintained
 
primarily
 
for
 
the
 
purpose
 
of
 
providing
 
deferred
compensation for
 
a select group
 
of management
 
or highly compensated
 
employees, within
 
the
meaning of
 
Title I of
 
the Employee
 
Retirement Income Security
 
Act of
 
1974, as
 
amended, and
 
shall
be interpreted in a manner consistent with such intention.
SECTION 1.
 
DEFINITIONS.
 
As hereinafter used:
1.1
 
"Accounting Firm" has the meaning ascribed to such term in Section 2.4(b) of this Plan.
1.2
 
"Affiliate" has the meaning
 
ascribed to such term in
 
Rule 12b-2 of the General Rules
 
and
Regulations under the Exchange Act, as in effect on the Effective
 
Date.
1.3
 
"Associate" means, with
 
reference
 
to any
 
Person, (a) any
 
corporation, firm,
 
partnership,
association, unincorporated organization, or
 
other entity
 
(other than
 
the Company
 
or a
 
Subsidiary
of the
 
Company) of
 
which such
 
Person is an
 
officer or
 
general partner (or
 
officer or
 
general
 
partner
of a
 
general partner)
 
or is,
 
directly or
 
indirectly, the Beneficial
 
Owner
 
of 10%
 
or more
 
of any
 
class
 
of
equity securities,
 
(b) any trust
 
or other
 
estate
 
in which
 
such Person
 
has a
 
substantial
 
beneficial
interest or as to which such Person serves as trustee or in a similar
 
fiduciary capacity, and (c) any
relative or spouse of
 
such Person, or any relative of
 
such spouse, who
 
has the same
 
home as such
Person.
1.4
 
"Beneficial Owner" means, with reference to any
 
securities, any Person if:
 
Exhibit
 
10.20.1
2
(a)
 
such Person
 
or any
 
of such
 
Person’s
 
Affiliates
 
and Associates,
 
directly
 
or
indirectly, is the "beneficial
 
owner"
 
of
 
(as
 
determined
 
pursuant
 
to Rule
 
13d-3
 
of
 
the
 
General
Rules
 
and
 
Regulations
 
under the
 
Exchange
 
Act, as
 
in
 
effect
 
on the
 
Effective
 
Date)
 
such
securities
 
or
 
otherwise
 
has
 
the
 
right
 
to
 
vote
 
or
 
dispose
 
of
 
such
 
securities,
 
including
pursuant to
 
any agreement,
 
arrangement, or
 
understanding (whether
 
or not in writing);
provided,
 
however,
 
that a
 
Person
 
shall not
 
be deemed
 
the "Beneficial
 
Owner" of,
 
or to
"beneficially
 
own,"
 
any
 
security
 
under
 
this
 
subsection
 
(a)
 
as
 
a
 
result
 
of
 
an
 
agreement,
arrangement, or understanding to vote such security if such agreement, arrangement,
 
or
understanding:
 
(i) arises solely from a revocable
 
proxy or consent
 
given in response to a
public (
i.e.
, not including a solicitation exempted
 
by Rule 14a-2(b)(2) of the General Rules
and Regulations under the Exchange Act) proxy or consent solicitation made pursuant to,
and in
 
accordance with,
 
the applicable
 
provisions
 
of the
 
General
 
Rules and
 
Regulations
under the
 
Exchange Act,
 
and (ii) is
 
not then
 
reportable by
 
such Person
 
on Schedule 13D
under the Exchange Act (or any comparable or successor report);
 
(b)
 
such Person
 
or any
 
of such
 
Person’s
 
Affiliates
 
and Associates,
 
directly
 
or
indirectly,
 
has
 
the
 
right
 
or
 
obligation
 
to
 
acquire
 
such
 
securities
 
(whether
 
such
 
right
 
or
obligation is exercisable or effective
 
immediately or only after the passage of time or the
occurrence
 
of
 
an
 
event)
 
pursuant
 
to
 
any
 
agreement,
 
arrangement,
 
or
 
understanding
(whether or
 
not in
 
writing) or
 
upon the
 
exercise of
 
conversion
 
rights,
 
exchange
 
rights,
 
other
rights, warrants,
 
or options, or
 
otherwise; provided, however,
 
that a Person
 
shall not be
deemed the Beneficial
 
Owner of, or to
 
"beneficially own," (i)
 
securities tendered pursuant
to a
 
tender or
 
exchange offer
 
made by
 
such Person
 
or any
 
of such
 
Person’s
 
Affiliates
 
or
Associates
 
until
 
such
 
tendered
 
securities
 
are
 
accepted
 
for
 
purchase
 
or
 
exchange
 
or
(ii) securities issuable upon exercise of Exempt Rights; or
 
(c)
 
such
 
Person
 
or
 
any
 
of
 
such
 
Person’s
 
Affiliates
 
or
 
Associates
 
(i) has
 
any
agreement,
 
arrangement,
 
or
 
understanding
 
(whether
 
or
 
not
 
in
 
writing)
 
with
 
any
 
other
Person (or any Affiliate or Associate thereof)
 
that beneficially owns such
 
securities for the
purpose of
 
acquiring, holding,
 
voting (except as
 
set forth in
 
the proviso
 
to subsection (a)
 
of
this definition),
 
or disposing
 
of such
 
securities or
 
(ii) is a
 
member of
 
a group
 
(as that
 
term is
used in Rule 13d-5(b) of the General Rules and Regulations under the Exchange
 
Act) that
includes any other Person that beneficially owns such securities;
provided, however,
 
that nothing in this definition shall cause a Person engaged in business as an
underwriter of
 
securities to
 
be the
 
Beneficial Owner
 
of,
 
or to
 
"beneficially own,"
 
any securities
acquired through such
 
Person’s participation in good
 
faith
 
in
 
a
 
firm
 
commitment
 
underwriting
 
until
the
 
expiration
 
of
 
40
 
days
 
after
 
the
 
date
 
of
 
such
 
acquisition.
 
For
 
purposes
 
hereof,
 
"voting"
 
a
security shall include
 
voting, granting a
 
proxy, consenting or making a
 
request or demand
 
relating
to
 
corporate
 
action
 
(including,
 
without
 
limitation,
 
a
 
demand
 
for
 
a
 
stockholder
 
list,
 
to
 
call
 
a
stockholder
 
meeting
 
or
 
to
 
inspect
 
corporate
 
books
 
and
 
records),
 
or
 
otherwise
 
giving
 
an
authorization (within the
 
meaning of
 
section 14(a) of
 
the Exchange
 
Act) in
 
respect
 
of
 
such
 
security.
 
Exhibit
 
10.20.1
3
The terms
 
"beneficially own"
 
and "beneficially
 
owning" have meanings
 
that are
 
correlative
to this definition of the term "Beneficial Owner."
1.5
 
"Board" means the Board of Directors of the Company.
1.6
 
"Cause" means
 
(i) the willful
 
and continued
 
failure by the
 
Eligible
 
Employee
 
to substantially
perform the
 
Eligible Employee's duties
 
with the Employer
 
(other than any
 
such failure
 
resulting
from the
 
Eligible Employee's
 
incapacity
 
due
 
to physical
 
or mental
 
illness),
 
or
 
(ii) the
 
willful
 
engaging,
not
 
in
 
good
 
faith,
 
by
 
the
 
Eligible
 
Employee
 
in
 
conduct
 
which
 
is
 
demonstrably
 
injurious
 
to
 
the
Company or any of its Subsidiaries, monetarily or otherwise.
1.7
 
"Change in Control" means any of the following occurring on or after the Effective
 
Date:
 
 
(a)
 
any
 
Person
 
(other
 
than
 
an
 
Exempt
 
Person)
 
shall
 
become
 
the
 
Beneficial
Owner of
 
20% or
 
more of
 
the shares
 
of Common
 
Stock then
 
outstanding or
 
20% or
 
more
 
of
the
 
combined
 
voting
 
power
 
of
 
the
 
Voting
 
Stock
 
of
 
the
 
Company
 
then
 
outstanding;
provided, however, that no Change
 
of Control
 
shall
 
be deemed
 
to occur
 
for
 
purposes
 
of
 
this
subsection (a) if
 
such Person
 
shall become
 
a Beneficial
 
Owner of
 
20% or
 
more
 
of
 
the
 
shares
of Common Stock then outstanding or 20% or more of the combined voting power of the
Voting
 
Stock
 
of
 
the
 
Company
 
then
 
outstanding
 
solely
 
as
 
a
 
result
 
of
 
(i) any
 
acquisition
directly from the
 
Company or
 
(ii) any acquisition
 
by a
 
Person pursuant to
 
a transaction
 
that
complies with clauses (i), (ii), and (iii) of subsection (c) of this definition are satisfied;
(b)
 
individuals
 
who,
 
as
 
of
 
the
 
Effective
 
Date,
 
constitute
 
the
 
Board
 
(the
“Incumbent Board”)
 
cease for
 
any reason
 
to constitute
 
at least
 
a majority
 
of the
 
Board;
provided, however,
 
that any
 
individual becoming
 
a director
 
subsequent to
 
the Effective
Date,
 
whose
 
election,
 
or
 
nomination
 
for
 
election
 
by
 
the
 
Company’s
 
shareholders,
 
was
approved by a vote of at least a majority of the directors
 
then comprising the Incumbent
Board
 
shall be
 
considered
 
as
 
though
 
such individual
 
were
 
a
 
member of
 
the
 
Incumbent
Board; provided, further, that
 
there shall
 
be excluded, for
 
this purpose,
 
any such
 
individual
whose initial assumption of
 
office occurs as
 
a result of any
 
actual or threatened
 
election
contest with respect to the election or removal of directors or other actual or threatened
solicitation of proxies or consents by or on behalf of a Person
 
other than the Board;
(c)
 
the Company shall consummate a
 
reorganization, merger,
 
statutory share,
consolidation, or
 
similar transaction
 
involving the
 
Company or
 
any
 
of
 
its
 
subsidiaries
 
or sale
or
 
other
 
disposition
 
of
 
all
 
or
 
substantially
 
all
 
of
 
the
 
assets
 
of
 
the
 
Company,
 
or
 
the
acquisition of
 
assets or
 
securities of
 
another
 
entity
 
by the
 
Company
 
or any
 
of
 
its
 
subsidiaries
(a “Business Combination”), in
 
each case, unless,
 
following such Business Combination, (i)
50%
 
or
 
more
 
of
 
the
 
then
 
outstanding
 
shares
 
of
 
common
 
stock
 
of
 
the
 
corporation,
 
or
common
 
equity
 
securities
 
of
 
an
 
entity
 
other
 
than
 
a
 
corporation,
 
resulting
 
from
 
such
Business Combination
 
and
 
the
 
combined
 
voting
 
power
 
of
 
the
 
then
 
outstanding
 
Voting Stock
of such corporation or other entity
 
are beneficially owned, directly or
 
indirectly,
 
by all or
substantially
 
all
 
of
 
the
 
Persons
 
who
 
were
 
the
 
Beneficial
 
Owners
 
of
 
the
 
outstanding
 
Exhibit
 
10.20.1
4
Common Stock immediately prior to
 
such Business Combination in
 
substantially the same
proportions as
 
their ownership,
 
immediately prior
 
to such
 
Business Combination, of
 
the
outstanding
 
Common Stock,
 
(ii) no Person
 
(excluding
 
any Exempt
 
Person
 
or any
 
Person
beneficially owning,
 
immediately prior
 
to such
 
Business Combination,
 
directly
 
or indirectly,
20% or
 
more
 
of the
 
Common Stock
 
then outstanding
 
or 20%
 
or more
 
of the
 
combined
voting
 
power
 
of the
 
Voting
 
Stock
 
of the
 
Company
 
then
 
outstanding)
 
beneficially
 
owns,
directly or indirectly, 20% or more of
 
the then outstanding shares of
 
common stock of the
corporation,
 
or common equity securities of an entity other than a corporation, resulting
from such Business
 
Combination or the
 
combined voting power
 
of the then outstanding
Voting Stock of
 
such corporation or
 
other entity, and (iii)
 
at least
 
a majority
 
of the
 
members
of the
 
board of
 
directors of the
 
corporation, or common
 
equity securities
 
of
 
an entity
 
other
than
 
a
 
corporation,
 
resulting
 
from
 
such
 
Business
 
Combination
 
were
 
members
 
of
 
the
Incumbent Board at
 
the time
 
of the
 
initial
 
agreement
 
or initial
 
action
 
by
 
the
 
Board
 
providing
for such Business Combination; or
 
(d)
 
the shareholders
 
of the Company
 
shall approve a
 
complete liquidation
 
or
dissolution of the Company unless such liquidation or dissolution is approved as part of a
transaction that complies with clauses (i), (ii), and (iii) of subsection (c) of this definition.
1.8
 
"Code" means
 
the Internal
 
Revenue Code of
 
1986,
 
as
 
it may
 
be amended
 
from
 
time
 
to time.
1.9
 
"Common Stock" means the common stock, par value $.01 per share, of the Company.
1.10
 
"Company" means ConocoPhillips or any successors thereto.
1.11
 
" Company
 
Retirement Contribution Percentage"
 
means the
 
percentage, determined with
regard to a
 
Severed Employee as
 
of their
 
Severance Date, set
 
forth in
 
(a) the
 
Company Retirement
Contribution
 
feature under
 
the ConocoPhillips
 
Savings Plan
 
and (b) the
 
Supplemental Company
Retirement Contribution
 
feature under
 
the Company Retirement
 
Contribution Make-Up Plan
 
of
ConocoPhillips.
 
1.12
 
"Controlled Group" shall mean ConocoPhillips and its Subsidiaries.
1.13
 
"Credited
 
Compensation"
 
of
 
a
 
Severed
 
Employee
 
means
 
the
 
aggregate
 
of
 
the
 
Severed
Employee's
 
annual
 
base salary
 
plus his
 
or her
 
annual
 
incentive
 
compensation,
 
each
 
as
 
further
described
 
below.
 
For
 
purposes
 
of
 
this
 
definition,
 
(a) annual
 
base
 
salary
 
shall
 
be
 
determined
immediately
 
prior
 
to
 
the
 
Severance
 
Date
 
(without
 
regard
 
to
 
any
 
reductions
 
therein
 
which
constitute
 
Good Reason)
 
and (b) annual
 
incentive
 
compensation
 
shall be
 
deemed to
 
equal the
higher of
 
(i) the
 
Severed Employee’s most recently
 
established target (determined
 
at one
 
hundred
percent of target) for
 
annual incentive compensation
 
for such employee
 
prior to such
 
employee’s
Severance Date or
 
(ii) the
 
average of
 
the
 
most
 
recent
 
two annual
 
incentive
 
compensation
 
payments
to by
 
such Severed
 
Employee pursuant
 
to the
 
Variable
 
Cash Incentive
 
Program
 
or its
 
successor
program maintained by
 
the Employer
 
made before his
 
or her
 
Severance Date; provided,
 
however,
that for purposes of this clause (ii), (I) if such Severed Employee has been eligible to receive only
 
Exhibit
 
10.20.1
5
one such
 
annual incentive
 
compensation payment for
 
a period
 
ending before his
 
or her
 
Severance
Date,
 
the
 
amount
 
of
 
annual
 
incentive
 
compensation
 
for
 
purposes
 
of
 
determining
 
Credited
Compensation shall
 
be equal
 
to the
 
amount
 
of such
 
single
 
annual
 
incentive
 
compensation
 
payment
(if
 
any),
 
and
 
(II)
 
if
 
such
 
Severed
 
Employee
 
has
 
not
 
been
 
eligible
 
for
 
any
 
such
 
annual
 
incentive
compensation
 
payment,
 
the
 
amount
 
of annual
 
incentive
 
compensation
 
for
 
purposes
 
of
 
determining
Credited Compensation shall
 
be equal
 
to his
 
or her
 
most
 
recently
 
established
 
target (determined
 
at
one hundred
 
percent of
 
target) for annual
 
incentive compensation
 
for such
 
employee
 
prior
 
to such
employee’s
 
Severance Date.
1.14
 
"Effective Date" means the
 
effective date of
 
this Plan
 
as amended
 
and restated as
 
set
 
forth
in the preamble to this Plan.
1.15
 
"Eligible Employee" means any employee that is a Tier 1 Employee or a Tier 2 Employee.
1.16
 
"Employer" means the Company or any of its Subsidiaries.
1.17
 
"Exchange Act" means the Securities Exchange Act of 1934, as amended.
1.18
 
"Excise Tax" shall mean the excise tax
 
imposed by section
 
4999 of the
 
Code, together with
any interest or penalties imposed with respect to such excise
 
tax.
1.19
 
"Exempt Person" means any
 
of the Company,
 
any entity controlled by the Company,
 
any
employee benefit plan (or related
 
trust) sponsored or maintained
 
by the Company or any
 
entity
controlled by the
 
Company,
 
and any
 
Person organized, appointed, or
 
established by the
 
Company
or any
 
entity controlled by
 
the Company for
 
or pursuant
 
to the
 
terms
 
of any
 
such
 
employee
 
benefit
plan.
1.20
 
"Exempt
 
Rights" means any
 
rights to
 
purchase shares
 
of Common Stock
 
or other
 
Voting
Stock of
 
the Company
 
if at
 
the time
 
of the
 
issuance thereof
 
such rights
 
are not
 
separable
 
from
 
such
Common Stock
 
or other
 
Voting Stock (
i.e.
, are
 
not transferable otherwise
 
than
 
in connection
 
with
 
a
transfer of the underlying
 
Common Stock or
 
other Voting Stock), except upon
 
the occurrence of
 
a
contingency,
 
whether such
 
rights exist
 
as of
 
the Effective
 
Date,
 
or are
 
thereafter
 
issued by
 
the
Company as a dividend on shares of Common Stock or other Voting Securities or otherwise.
1.21
 
"Good Reason"
 
means the
 
occurrence, on
 
or after
 
the date
 
of a
 
Change in
 
Control,
 
and
without the Eligible Employee's
 
written consent, of (i) the assignment to
 
the Eligible Employee of
duties in
 
the aggregate
 
that are
 
inconsistent with
 
the Eligible
 
Employee's level
 
of responsibility
immediately
 
prior to
 
the date
 
of the
 
Change in
 
Control
 
or any
 
diminution in
 
the nature
 
of the
Eligible Employee's
 
responsibilities
 
from
 
those
 
in
 
effect immediately
 
prior
 
to the
 
date of
 
the
 
Change
in Control;
 
(ii) a reduction
 
by the
 
Employer in
 
the Eligible
 
Employee's annual
 
base salary or
 
any
adverse change in
 
the Eligible
 
Employee's aggregate annual
 
and
 
long
 
term
 
incentive
 
compensation
opportunity from
 
that in effect
 
immediately prior
 
to the
 
Change in Control
 
which change
 
is not
pursuant to a
 
program applicable to
 
all comparably
 
situated executives of
 
the
 
Employer;
 
or
 
(iii) the
relocation of
 
the Eligible
 
Employee's principal
 
place of
 
employment to
 
a location
 
more than
 
50
 
Exhibit
 
10.20.1
6
miles from
 
the Eligible
 
Employee's principal
 
place of
 
employment immediately prior
 
to the
 
date of
the Change in
 
Control; provided, however, that this clause (iii)
 
shall not be
 
considered to be Good
Reason
 
if
 
the
 
Employer
 
undertakes
 
to
 
pay
 
all
 
reasonable
 
relocation
 
expenses
 
of
 
the
 
Eligible
Employee
 
in connection
 
with
 
such
 
relocation,
 
whether
 
through
 
a
 
relocation
 
plan,
 
program,
 
or
policy of the Employer or otherwise.
1.22
 
"Net Benefit" shall mean the present value of the Payments
 
net of all Federal, state,
local, and foreign income, employment, and excise
 
taxes.
1.23
 
"Parachute Value"
 
of a Payment shall mean the present value as of the date of the
change of control for purposes of section 280G of the Code of the portion of such Payment that
constitutes a "parachute payment"
 
under section 280G(b)(2), as determined by the Accounting
Firm for purposes of determining whether and to what extent the Excise
 
Tax will
 
apply to such
Payment.
1.24
 
"Payment" shall mean any payment
 
or distribution in the nature of compensation
(within the meaning of section 280G(b)(2) of the Code) to or for the benefit of an Eligible
Employee, whether paid or payable pursuant to
 
this Plan or otherwise, by any Employer or by a
Person that is a party to the Change in Control.
1.25
 
"Person"
 
means
 
any
 
individual,
 
firm,
 
corporation,
 
partnership,
 
association,
 
trust,
unincorporated organization,
 
or other entity.
1.26
 
"Plan" means the ConocoPhillips Key
 
Employee Change in Control
 
Severance Plan, as
 
set
forth herein, as it may be amended from time to time.
1.27
 
"Plan Administrator"
 
means the
 
person
 
or persons
 
appointed
 
from time
 
to time
 
by the
Board, which appointment may
 
be revoked
 
at any time by
 
the Board.
 
At the Effective
 
Date, the
Plan Administrator
 
shall be
 
the Vice
 
President, Human
 
Resources and
 
Real Estate
 
and Facilities
Services of
 
the Company.
 
Any successor
 
to the
 
office of
 
Vice President,
 
Human
 
Resources
 
and
 
Real
Estate and Facilities Services (or to
 
a lesser or
 
greater position encompassing the role
 
of the most
senior officer
 
of the
 
Company
 
with
 
responsibility
 
over
 
the
 
Human
 
Resources
 
function)
 
shall
 
become
the
 
Plan
 
Administrator,
 
unless
 
and
 
until
 
the
 
Board
 
appoints
 
another
 
person
 
or
 
persons.
 
Notwithstanding the forgoing,
 
any person appointed
 
as
 
Plan
 
Administrator
 
shall
 
recuse
 
themselves
from any action with regard to
 
a claim relating to such person as an Eligible Employee.
1.28
 
"Public
 
Offering"
 
means
 
the
 
initial
 
sale
 
of
 
common
 
equity
 
securities
 
of
 
the
 
Company
pursuant to an
 
effective registration statement (other than
 
a registration
 
on
 
Form S-4
 
or S-8
 
or any
successor or similar forms) filed under the Securities Act of 1933.
1.29
 
"Retirement Plans" means
 
the ConocoPhillips Retirement Plan
 
and the
 
ConocoPhillips Key
Employee Supplemental Retirement
 
Plan.
 
1.30
 
"Safe Harbor Amount"
 
means, with
 
respect to
 
an Eligible
 
Employee, 2.99
 
times the
 
Eligible
Employee's "base amount," within the meaning of section 280G(b)(3) of the Code.
 
Exhibit
 
10.20.1
7
1.31
 
"Separation from Service"
 
means the
 
date on
 
which the
 
Participant separates from service
with the Controlled
 
Group within the
 
meaning of
 
Code section
 
409A, whether
 
by reason of
 
death,
disability, retirement, or otherwise.
 
In determining
 
Separation from Service,
 
with
 
regard to
 
a bona
fide leave of
 
absence that
 
is due
 
to any medically
 
determinable
 
physical
 
or
 
mental
 
impairment
 
that
can be expected to
 
result in death or can
 
be expected to
 
last for a continuous
 
period of not less
than six
 
months, where such
 
impairment causes the
 
Employee to be
 
unable to
 
perform the duties
of his or
 
her position of
 
employment or
 
any substantially
 
similar position of
 
employment, a
 
29-
month period
 
of absence
 
shall be
 
substituted for the
 
six-month period set
 
forth in section
 
1.409A-
1(h)(1)(i) of the regulations issued under section 409A of the Code, as allowed thereunder.
1.32
 
"Severance"
 
means
 
the
 
termination
 
of
 
an
 
Eligible
 
Employee's
 
employment
 
with
 
the
Employer on
 
or within two
 
years following
 
the date
 
of a
 
Change in
 
Control, (i) by
 
the Employer
other than for Cause, or (ii) by the Eligible Employee for Good Reason.
 
An Eligible Employee will
not be
 
considered to
 
have incurred a
 
Severance if his
 
employment is
 
discontinued
 
by reason
 
of
 
the
Eligible
 
Employee's
 
death
 
or
 
a
 
physical
 
or
 
mental
 
condition
 
causing
 
such
 
Eligible
 
Employee's
inability to substantially perform his
 
duties with the
 
Employer and entitling
 
him or her
 
to benefits
under any long-term
sick pay
 
or disability
 
income policy
 
or program
 
of
 
the
 
Employer.
 
Furthermore,
an Eligible Employee will
 
not be considered to have incurred a
 
Severance if employment with the
Employer is discontinued after the
 
Eligible Employee has been
 
offered employment with another
employer that has purchased a Subsidiary or division of the Company or all or substantially all of
the assets of
 
a Subsidiary
 
or division of
 
the Company and
 
the offer of employment
 
from the other
employer
 
is at
 
the same
 
or greater
 
salary and
 
the same
 
or greater
 
target
 
bonus as
 
the Eligible
Employee
 
has
 
at
 
that
 
time
 
from
 
the
 
Employer.
 
Still
 
further,
 
an
 
Eligible
 
Employee
 
will
 
not
 
be
considered
 
to
 
have
 
incurred
 
a
 
Severance
 
as
 
a
 
result
 
of
 
(i)
 
the
 
Distribution,
 
(ii)
 
the
 
Eligible
Employee's transfer to the
 
controlled group of
 
Phillips
 
66 in
 
connection
 
with
 
the
 
Distribution,
 
or (iii)
the
 
Eligible
 
Employee's
 
transfer
 
to
 
the
 
Controlled
 
Group
 
in
 
connection
 
with
 
the
 
Distribution.
 
Notwithstanding
 
anything
 
herein
 
to
 
the
 
contrary,
 
Good
 
Reason
 
shall
 
not
 
be
 
deemed
 
to
 
have
occurred unless the Company shall have
 
been given (1) written notice of the Eligible
 
Employee's
assertion that
 
an event
 
constituting Good
 
Reason has
 
occurred,
 
which
 
notice
 
shall
 
be
 
given
 
not
 
less
than
 
30
 
days
 
prior
 
to
 
the
 
Severance
 
Date
 
to
 
which
 
such
 
notice
 
relates,
 
and
 
(2) a
 
reasonable
opportunity
 
to
 
cure
 
such
 
occurrence
 
during
 
such
 
30-day
 
period.
 
Furthermore,
 
in
 
order
 
to
 
be
considered a Severance, the
 
termination must also meet the requirements
 
of a Separation from
Service.
1.33
 
"Severance Date" means the date on which an Eligible Employee incurs
 
a Severance.
1.34
 
"Severance Pay" means the payment
 
determined pursuant to Section 2.1 hereof.
1.35
 
"Severed Employee" means an Eligible Employee who has incurred a Severance.
1.36
 
"Salary
 
Grade"
 
means
 
a
 
classification
 
level
 
for
 
Employees
 
under
 
the
 
practices
 
of
 
the
Company.
 
Where Salary
 
Grades are used
 
in this
 
Plan, they
 
are
 
depicted
 
under
 
the
 
U.S.
 
practices
 
for
 
 
Exhibit
 
10.20.1
8
the Company.
 
Practices may vary in other countries or particular subsidiaries, and Salary Grades
shall be transposed as necessary to reflect the practice in the relevant
 
country or subsidiary.
1.37
 
"Subsidiary" means
 
any corporation or
 
other entity
 
that is
 
treated
 
as
 
a single
 
employer
 
with
ConocoPhillips after
 
the Distribution,
 
under section
 
414(b) or
 
(c) of
 
the Code;
 
provided, that
 
in
making this determination, in
 
applying section 1563(a)(1),
 
(2), and (3)
 
of the Code
 
for purposes of
determining a
 
controlled group of
 
corporations under section
 
414(b) of
 
the Code
 
and
 
for purposes
of determining trades or businesses
 
(whether or not incorporated) under common
 
control under
regulation section
 
1.414(c)-2 for
 
purposes of
 
section 414(c)
 
of the
 
Code, the
 
language “at
 
least
80%” shall
 
be used
 
without substitution as
 
allowed under regulations
 
pursuant to section
 
409A of
the Code.
1.38
 
"Tier 1
 
Employee" means
 
any employee of
 
the Employer
 
who is
 
in
 
Salary
 
Grade
 
26
 
or above
(under
 
the
 
Salary
 
Grade
 
schedule
 
of
 
the
 
Company
 
on
 
the
 
Effective
 
Date,
 
with
 
appropriate
adjustment for
 
any subsequent
 
change in such
 
Salary Grade
 
schedule), at
 
or subsequent to
 
the
time of the Change in Control.
 
1.39
 
"Tier 2
 
Employee" means
 
any employee
 
of
 
the
 
Employer, other
 
than
 
a
 
Tier
 
1 Employee,
 
who
is in Salary Grade 23 or above (under the Salary Grade schedule of the Company on the Effective
Date, with appropriate
 
adjustment for any
 
subsequent change
 
in such
 
Salary
 
Grade
 
schedule)
 
at or
subsequent to the time of the Change in Control.
1.40
 
"Value" of a
 
Payment shall mean
 
the economic
 
present value
 
of
 
a Payment
 
as
 
of the
 
date of
the change of control
 
for purposes of section
 
280G of the
 
Code, as determined
 
by the Accounting
Firm using the discount rate required by
 
section 280G(d)(4) of the Code.
1.41
 
"Voting Stock" means,
 
(i) with
 
respect to
 
a corporation, all
 
securities of
 
such corporation
 
of
any class or series that are entitled to vote generally in the election of, or to appoint by contract,
directors of
 
such corporation
 
(excluding any
 
class or series
 
that would be
 
entitled so
 
to vote
 
by
reason of
 
the occurrence
 
of any contingency, so
 
long as
 
such contingency
 
has
 
not
 
occurred)
 
and
 
(ii)
with respect
 
to an entit
 
y
 
which is not
 
a corporation,
 
all securities of
 
any class
 
or series that
 
are
entitled to vote
 
generally in the
 
election of, or
 
to appoint by
 
contract, members of
 
the body
 
which
is most analogous to the board of directors of a corporation
 
.
SECTION 2.
 
BENEFITS.
2.1
 
Subject to Section 2.8, each Severed Employee shall be entitled to receive Severance
 
Pay
equal to the
 
sum of the
 
amounts determined under
 
Sections 2.1(a), (b),
 
(c), and (d),
 
as applicable.
 
Furthermore, for purposes of Employer compensation plans, programs, and arrangements,
 
each
Severed Employee shall be considered to have
 
been laid off by the Employer.
 
(a)
 
The amount that is the
 
Severed Employee's Credited Compensation, multiplied by
(i) 3, in the case of a Tier 1 Employee or (ii) 2 in the case of a Tier 2 Employee.
 
Exhibit
 
10.20.1
9
(b)
For Severed Employees
 
actively participating in the Retirement
 
Plans the amount
that is
 
the present
 
value, determined as
 
of the
 
Severed
 
Employee's
 
Severance
 
Date,
of
 
the
 
benefits
 
under
 
the
 
Retirement
 
Plans
 
that
 
would
 
result
 
if
 
the
 
Severed
Employee was
 
credited with the following
 
number of additional years
 
of age and
service under
 
the Retirement Plans:
 
(i) 3, in
 
the case
 
of a
 
Tier 1
 
Employee
 
or (ii)
 
2, in
the case of a Tier 2 Employee;
 
less the amount that is the
 
value determined as of
the Severed Employee’s Severance Date (including any additional credited service
due to the circumstances
 
of the Severed Employee’s
 
termination) of the benefits
under
 
the
 
Retirement
 
Plans.
 
Present
 
value
 
shall
 
be
 
determined
 
based
 
on
 
the
assumptions
 
utilized
 
under
 
the
 
ConocoPhillips
 
Retirement
 
Plan
 
for
 
purposes
 
of
determining contributions under
 
Code section
 
412
 
for the
 
most
 
recently
 
completed
plan year.
 
No amounts provided under this Section 2.1(b) shall be
 
less than zero.
 
For the
 
avoidance of
 
doubt, with
 
respect to
 
a Severed
 
Employee who
 
is actively
participating in a cash
 
balance formula under the
 
Retirement Plans, the Severance
Pay
 
amount
 
determined
 
under
 
this
 
subsection
 
shall
 
be
 
the
 
amount
 
that
 
is
 
the
present
 
value
 
of
 
benefits
 
under
 
the
 
Retirement
 
Plans
 
that
 
would
 
result
 
if
 
the
Severed Employee
 
was credited with
 
the following number of
 
additional years of
pay
 
credits
 
and interest
 
credits
 
under the
 
Retirement
 
Plans as
 
of the
 
Severance
Date: (i) 3,
 
in the
 
case of
 
a Tier
 
1 Employee
 
or (ii)
 
2, in
 
the case
 
of a
 
Tier 2
 
Employee;
less
 
the
 
amount
 
that
 
is
 
the
 
value
 
determined
 
as
 
of
 
the
 
Severed
 
Employee’s
Severance Date of the benefits under the Retirement
 
Plans.
 
(c)
For
 
Severed
 
Employees
 
actively
 
participating
 
in
 
the
 
Company
 
Retirement
Contribution
 
Account feature
 
of the
 
ConocoPhillips Savings
 
Plan, as
 
that term
 
is
therein defined, the amount that would be the result of the Company Retirement
Contribution
 
Percentage
 
multiplied
 
by
 
the
 
Severed
 
Employee's
 
Credited
Compensation and (i) 3,
 
in the case
 
of a Tier 1
 
Employee or (ii)
 
2, in the case
 
of a
Tier 2 Employee.
 
(d)
The amount that is equal to the sum of (i), (ii), and (iii):
(i)
The
 
lesser
 
of
 
the
 
difference
 
between
 
the
 
annual
 
COBRA
 
participant
contribution
 
amount
 
or
 
the
 
ConocoPhillips
 
Retiree
 
Medical
 
Pre-65
 
Plan
participant
 
contribution
 
amount,
 
as
 
applicable,
 
and
 
the
 
annual
 
active
employee contribution
 
amount, each
 
as of the
 
Severance Date,
 
based on
the active medical coverage for which the Severed Employee was enrolled
as of
 
the Severance Date
 
multiplied by
 
(a) 3,
 
in the
 
case of
 
a Tier
 
1 Employee
or (b) 2, in the case of a Tier 2 Employee.
 
For the avoidance of doubt, any
Severed
 
Employee
 
or
 
dependents
 
who
 
are
 
over
 
the
 
age
 
of
 
65
 
on
 
the
Severance
 
Date
 
will
 
not
 
be
 
eligible
 
for
 
any
 
amounts
 
under
 
this
 
section
2.1(d)(i).
(ii)
The difference between
 
the annual
 
COBRA participant
 
contribution
 
amount
and
 
the
 
annual
 
active
 
employee
 
contribution
 
amount,
 
each
 
as
 
of
 
the
 
Exhibit
 
10.20.1
10
Severance Date, based
 
on the
 
active dental coverage
 
for which
 
the Severed
Employee was enrolled as of the Severance Date multiplied by (a) 3, in the
case of a Tier 1 Employee or (b) 2, in the case of a Tier 2 Employee.
(iii)
The
 
difference
 
between
 
the
 
annual
 
cost
 
to
 
maintain
 
coverage
 
and
 
the
annual active
 
employee contribution, each
 
as of
 
the
 
Severance
 
Date,
 
for the
company-sponsored
 
life
 
insurance
 
coverage
 
(including
 
basic,
 
executive
basic, and supplemental) for which the Severed Employee was
 
enrolled on
the Severance Date multiplied by (a) 3, in the case of a Tier 1 Employee
 
or
(b) 2,
 
in the
 
case of
 
a Tier
 
2 Employee.
 
For the
 
avoidance
 
of doubt,
 
this
amount
 
will
 
be
 
calculated
 
using
 
differences
 
in
 
cost
 
ignoring
 
any
 
limits
imposed by
 
the insurance
 
carrier for portability
 
and
 
conversion
 
of coverage.
Any amounts provided under
 
this Section 2.1(d)
 
will not be
 
adjusted to reflect that
the Severed Employee’s
 
cost will no longer be pre-tax.
2.2
 
Severance Pay (as
 
well as
 
any amount payable
 
pursuant to Section
 
2.5 hereof)
 
shall
 
be
 
paid
 
to an
 
eligible Severed Employee
 
in a
 
cash lump
 
sum on
 
the
 
first
 
business
 
day
 
immediately
 
following
10 days after
 
the end
 
of the
 
period for
 
executing and delivering
 
the Severed
 
Employee's
 
release,
 
as
set forth in Section 2.8.
2.3
 
Upon Change in
 
Control, the following shall apply
 
to equity awards made
 
by the Company
to an Eligible Employee:
(a)
With
 
regard
 
to
 
all
 
equity awards
 
which
 
do
 
not
 
directly
 
provide
 
otherwise, each
Eligible Employee shall
 
become fully vested
 
in such
 
equity awards upon
 
incurring a
Severance
 
following
 
such
 
Change
 
in
 
Control,
 
and
 
such
 
equity
 
awards
 
shall
 
not
thereafter
 
be forfeitable
 
for
 
any reason
 
(except
 
that options
 
shall expire
 
and be
cancelled ten years from the date of their grant).
(b)
Any options granted to the Eligible Employee
 
shall be exercisable at the times set
forth
 
in
 
the
 
applicable
 
award
 
documents.
 
Each
 
such
 
option
 
shall
 
remain
outstanding until ten
 
years from the
 
date of
 
grant,
 
notwithstanding
 
any
 
provision
 
of
the option grant
 
or any plan
 
under which
 
the option may
 
have been granted to
 
the
contrary.
(c)
The date
 
of distribution
 
of any
 
stock or
 
other value
 
from such
 
awards shall be
 
as
 
set
forth in the applicable terms and conditions of the award.
2.4
 
With regard to any potential
 
Excise Tax
 
and the avoidance thereof:
 
(a)
 
Anything
 
in
 
this plan
 
to
 
the
 
contrary
 
notwithstanding,
 
if any
 
Parachute
 
Value
 
is
received
 
or is
 
expected
 
to be
 
received
 
under the
 
Plan, then
 
prior to
 
making any
payment of Severance
 
Pay under this
 
Plan, a
 
calculation
 
shall
 
be
 
made
 
comparing
 
(i)
 
 
Exhibit
 
10.20.1
11
the Net Benefit
 
to the Severed Employee
 
after payment of the
 
Excise Tax to (ii) the
Net
 
Benefit
 
to
 
the
 
Severed
 
Employee
 
if
 
the
 
Payments
 
are
 
limited
 
to
 
the
 
extent
necessary to avoid being
 
subject
 
to the Excise Tax.
 
If the amount
 
calculated under
clause
 
(i)
 
above
 
is
 
less
 
than
 
the
 
amount
 
under
 
clause
 
(ii)
 
above,
 
Severance
 
Pay
under this
 
Plan will
 
be reduced
 
to the
 
minimum extent necessary
 
to ensure that
 
no
portion of the Payments is subject
 
to the Excise Tax.
 
For avoidance of doubt, it is
intended that, for purposes of reducing the
 
Payments to the Safe Harbor Amount,
only amounts payable under this Plan (and no other Payments) shall be reduced.
 
 
(b)
 
All determinations required to be made under this Section 2.4
 
shall be made by a
nationally
 
recognized
 
certified
 
public
 
accounting
 
firm
 
designated
 
by
 
the
 
Plan
Administrator (the "Accounting
 
Firm").
 
The Accounting Firm
 
shall provide detailed
supporting calculations
 
both to
 
the Company
 
and each
 
Eligible Employee
 
within 15
business days
 
of the
 
receipt of
 
notice from
 
the Eligible
 
Employee that
 
there has
been a Payment, or such
 
earlier time as
 
is requested by the
 
Company.
 
All fees and
expenses
 
of
 
the
 
Accounting
 
Firm
 
shall
 
be
 
borne
 
solely
 
by
 
the
 
Company.
 
Any
determination by the Accounting Firm
 
shall be binding
 
upon the Company
 
and the
Eligible Employee.
2.5
 
Each Severed Employee shall be entitled to receive the
 
employee's full salary through the
Severance Date
 
and, subject to Section 2.8 but
 
notwithstanding any provision
 
of the Company's
Variable
 
Cash Incentive Program
 
or similar annual bonus incentive
 
plan to the contrary,
 
shall be
eligible for consideration
 
for an award
 
under such program or plan when
 
awards are made with
regard to the fiscal year under
 
such program or plan in which the Severance Date occurred.
2.6
 
The Company
 
will pay
 
to each
 
Eligible Employee
 
all reasonable
 
legal fees
 
and expenses
incurred
 
by such
 
Eligible Employee
 
in pursuing
 
any claim
 
under the
 
Plan, unless
 
the applicable
finder of
 
fact determines
 
that the
 
Eligible Employee's
 
claim
 
was frivolous
 
or
 
not
 
maintained
 
in good
faith.
2.7
 
The Company
 
shall be
 
entitled to
 
withhold and/or
 
to cause
 
to be
 
withheld
 
from
 
amounts
 
to
be paid
 
to the Severed
 
Employee hereunder any
 
federal, state, or local
 
withholding or
 
other taxes
or charges which it is from time to time required to withhold.
2.8
 
No Severed Employee
 
shall be
 
eligible to
 
receive Severance Pay or
 
other
 
benefits
 
under
 
the
Plan unless
 
he or
 
she first
 
executes a written
 
release substantially in
 
the form
 
attached
 
as
 
Exhibit A
hereto (or, if the
 
Severed Employee was
 
not a
 
United States employee,
 
a similar
 
release
 
which
 
is
 
in
accordance with the applicable
 
laws in the
 
relevant jurisdiction) and, to
 
the extent such release
 
is
revocable
 
by its
 
terms, only
 
if the
 
Severed
 
Employee does
 
not revoke
 
it.
 
Such release
 
must be
executed and delivered to
 
the Company within 30 days of the Employee’s
 
Severance Date.
SECTION 3.
 
PLAN ADMINISTRATION
 
.
 
 
Exhibit
 
10.20.1
12
3.1
 
The Plan
 
Administrator
 
shall administer
 
the Plan
 
and may
 
interpret
 
the Plan,
 
prescribe,
amend,
 
and
 
rescind
 
rules
 
and
 
regulations
 
under
 
the
 
Plan
 
and
 
make
 
all
 
other
 
determinations
necessary or
 
advisable for
 
the administration of
 
the
 
Plan,
 
subject
 
to all
 
of
 
the
 
provisions
 
of
 
the
 
Plan.
3.2
 
In the event of
 
a claim by
 
an Eligible Employee as
 
to the amount or
 
timing of any payment
or benefit,
 
such Eligible
 
Employee shall
 
present the
 
reason for his
 
or her
 
claim
 
in writing
 
to the
 
Plan
Administrator.
 
The Plan Administrator
 
shall, within
 
14 days
 
after receipt
 
of such
 
written claim,
send a written
 
notification to the
 
Eligible Employee as
 
to its disposition.
 
Except as provided in
 
the
preceding portion
 
of this
 
Section 3.2, all
 
disputes under
 
this Plan
 
shall be settled
 
exclusively
 
by
binding arbitration
 
in Houston,
 
Texas,
 
in accordance
 
with the
 
rules of the
 
American Arbitration
Association then
 
in effect.
 
Judgment may be
 
entered on the
 
arbitrator's award in
 
any
 
court
 
having
jurisdiction.
3.3
 
The Plan
 
Administrator may delegate any
 
of its
 
duties hereunder
 
to such
 
person
 
or
 
persons
from time to time as it may designate.
3.4
 
The Plan Administrator is empowered, on
 
behalf of the
 
Plan, to engage accountants, legal
counsel,
 
and
 
such
 
other
 
personnel
 
as
 
it
 
deems
 
necessary
 
or
 
advisable
 
to
 
assist
 
it
 
in
 
the
performance of its duties under
 
the Plan.
 
The functions of any such
 
persons engaged by the Plan
Administrator shall be
 
limited to
 
the specified
 
services and
 
duties for
 
which they
 
are engaged, and
such
 
persons
 
shall
 
have
 
no
 
other
 
duties,
 
obligations,
 
or
 
responsibilities
 
under
 
the
 
Plan.
 
Such
persons
 
shall
 
exercise
 
no
 
discretionary
 
authority
 
or
 
discretionary
 
control
 
respecting
 
the
management of the Plan.
 
All reasonable expenses thereof shall be borne by the Employer.
SECTION 4.
 
DURATION;
 
AMENDMENT; AND TERMINATION
 
.
4.1
 
This Plan,
 
in its
 
immediately
 
prior
 
version,
 
was
 
effective
 
on the
 
Effective
 
Date
 
and was
amended and restated effective as of the Effective Date.
 
If a Change in
 
Control has not occurred,
this Plan shall continue
 
in effect unless
 
and until it is
 
terminated as provided
 
in Section 4.2.
 
If a
Change in
 
Control occurs,
 
this Plan
 
shall continue
 
in full
 
force and effect
 
and shall
 
not terminate or
expire
 
until after
 
all Eligible
 
Employees who
 
become or
 
may become
 
entitled to
 
any payments
hereunder
 
shall have
 
received
 
such payments
 
in full
 
and all
 
adjustments
 
required
 
to
 
be
 
made
pursuant to Section 2 have been made.
4.2
 
(a)
 
If a Change
 
in Control
 
has not occurred,
 
this Plan may
 
be amended from
 
time to
time during
 
its term
 
by the
 
Company acting
 
through its
 
Board of
 
Directors or, to
 
the
extent
 
authorized
 
by the
 
Board of
 
Directors,
 
its officers,
 
provided
 
that any
 
such
amendment which
 
shall in
 
any manner
 
reduce, diminish,
 
or otherwise
 
adversely
affect
 
any
 
benefit
 
which
 
is
 
or
 
may
 
at
 
any
 
time
 
in
 
the
 
future
 
become
 
payable
hereunder,
 
or any
 
such amendment
 
which shall alter
 
the definition
 
of Change
 
in
Control,
 
shall
 
be
 
made
 
effective
 
not
 
less
 
than
 
two
 
years
 
after
 
the
 
action
 
of
 
the
Company authorizing such
 
amendment, unless, and
 
then only to the
 
extent that,
such amendment
 
is or
 
becomes necessary
 
in order
 
to assure
 
continued
 
compliance
by this Plan with any applicable state or federal
 
law or regulation.
 
 
Exhibit
 
10.20.1
13
(b)
 
The Company
 
may, by action of
 
its Board
 
of
 
Directors,
 
terminate
 
this
 
Plan,
 
provided,
however,
 
that
 
the
 
effective
 
date
 
of
 
such termination
 
shall be
 
not
 
less
 
than two
years
 
from
 
the
 
date
 
of
 
such
 
Board
 
action.
 
Provided
 
further that
 
in
 
the event
 
a
Change
 
in
 
Control
 
shall
 
occur
 
prior
 
to
 
the
 
effective
 
date
 
of
 
termination,
 
the
provisions of Section 4.2(c) shall apply.
(c)
 
If
 
a
 
Change
 
in
 
Control
 
shall
 
occur
 
while
 
this
 
Plan
 
is
 
in
 
effect,
 
no
 
then-pending
amendment or termination shall
 
take effect, this Plan shall
 
remain in full
 
force and
effect
 
as
 
at
 
the
 
Change
 
in
 
Control,
 
and
 
this
 
Plan
 
shall
 
terminate
 
automatically
without further
 
action on
 
behalf of
 
the Company
 
immediately
 
following
 
the
 
making
of all payments to Eligible Employees under this Plan.
SECTION 5.
 
GENERAL PROVISIONS.
5.1
 
Except as otherwise
 
provided herein or
 
by law, no right
 
or interest of
 
any Eligible
 
Employee
under
 
the
 
Plan
 
shall
 
be
 
assignable
 
or
 
transferable,
 
in
 
whole
 
or
 
in
 
part,
 
either
 
directly
 
or
 
by
operation
 
of
 
law
 
or
 
otherwise,
 
including
 
without
 
limitation
 
by
 
execution,
 
levy,
 
garnishment,
attachment,
 
pledge,
 
or
 
in
 
any
 
manner;
 
no
 
attempted
 
assignment
 
or
 
transfer
 
thereof
 
shall
 
be
effective;
 
and no right
 
or interest
 
of any
 
Eligible Employee
 
under the
 
Plan shall
 
be liable
 
for,
 
or
subject to, any obligation
 
or liability of
 
such Eligible
 
Employee.
 
When a
 
payment is due
 
under this
Plan to
 
a Severed
 
Employee who
 
is unable to
 
care for
 
his or her
 
affairs,
 
payment may
 
be made
directly to his or her legal guardian or personal representative.
5.2
 
If
 
any
 
Employer
 
is obligated
 
by
 
law or
 
by
 
contract
 
to pay
 
severance
 
pay,
 
a
 
termination
indemnity, notice pay, or the
 
like, to a
 
Severed Employee, or
 
if any
 
Employer is
 
obligated by law
 
to
provide advance notice
 
of separation ("Notice
 
Period")
 
to a
 
Severed
 
Employee,
 
then
 
any
 
Severance
Pay hereunder to such Severed Employee shall be reduced by the amount of any such severance
pay,
 
termination
 
indemnity,
 
notice
 
pay,
 
or
 
the
 
like,
 
as
 
applicable,
 
and
 
by
 
the
 
amount
 
of
 
any
compensation received during
 
any Notice
 
Period.
 
This
 
provision
 
specifically
 
includes
 
any
 
payments
or obligations under
 
the ConocoPhillips
 
Severance Pay Plan,
 
as effective on
 
the
 
Effective Date
 
or as
subsequently amended, or
 
under the ConocoPhillips
 
Executive Severance Plan as effective on
 
the
Effective Date or as subsequently amended.
 
Furthermore, if an Eligible Employee has willful and
bad faith
 
conduct demonstrably injurious
 
to Company
 
or its
 
Subsidiaries, monetarily
 
or otherwise,
after receiving Severance
 
Pay,
 
the Company may
 
offset an amount equal
 
to such Severance
 
Pay
against any other amounts due from other plans or programs, unless otherwise required by law.
5.3
 
Neither the
 
establishment of
 
the Plan,
 
nor any
 
modification
 
thereof, nor
 
the
 
creation
 
of
 
any
fund, trust, or account, nor the payment
 
of any benefits shall be construed
 
as giving any Eligible
Employee, or
 
any person
 
whomsoever, the right to
 
be retained in
 
the service
 
of the
 
Employer, and
all Eligible
 
Employees shall
 
remain subject
 
to discharge to
 
the same
 
extent as if
 
the Plan
 
had never
been adopted.
 
 
Exhibit
 
10.20.1
14
5.4
 
If
 
any
 
provision
 
of
 
this
 
Plan
 
shall
 
be
 
held
 
invalid
 
or
 
unenforceable,
 
such
 
invalidity
 
or
unenforceability shall not affect any other
 
provisions hereof, and this Plan shall
 
be construed and
enforced as if such provisions had not been included.
5.5
 
This Plan
 
shall be
 
binding upon
 
the heirs,
 
executors, administrators,
 
successors,
 
and
 
assigns
of
 
the
 
parties,
 
including each
 
Eligible
 
Employee,
 
present
 
and
 
future,
 
and
 
any
 
successor
 
to
 
the
Employer.
5.6
 
The headings and captions herein are provided for reference
 
and convenience only,
 
shall
not be considered part of the Plan, and shall not be employed in the construction of the Plan.
5.7
 
The Plan shall not be funded.
 
No Eligible Employee shall have any right to,
 
or interest in,
any assets
 
of any
 
Employer that
 
may be applied
 
by the Employer
 
to the payment
 
of benefits
 
or
other rights under this Plan.
5.8
 
Any notice or
 
other communication required
 
or permitted pursuant
 
to the terms
 
hereof
shall have
 
been duly
 
given when
 
delivered
 
or mailed
 
by United
 
States
 
Mail, first
 
-class, postage
prepaid, addressed to the intended recipient at his, her or its last known address.
5.9
 
This Plan shall be construed and enforced according to the laws of the State of Delaware.
The Plan is hereby
 
amended and restated
 
effective as
 
of the Effective
 
Date; provided,
 
however,
that in
 
the event that
 
a Change
 
in Control
 
occurs on
 
or before December
 
1, 2023,
 
the provisions
 
of
the immediately prior
 
version of
 
this Plan
 
shall control
 
to the
 
extent
 
that
 
those
 
provisions,
 
or any
 
of
them,
 
are
 
more
 
favorable
 
to
 
a
 
Severed
 
Employee
 
and
 
have
 
not
 
been
 
waived
 
by
 
that
 
Severed
Employee.
 
For the avoidance of doubt all Eligible Employees who previously were eligible for an
Excise
 
Tax
 
gross-up
 
under the
 
plan
 
have
 
waived
 
these
 
benefits
 
as
 
of the
 
effective
 
date
 
of this
amended and restated Plan.
 
Executed this __ day of December 2021, by a duly authorized officer of the Company.
CONOCOPHILLIPS
 
By:
 
/s/ Heather G. Sirdashney
 
Dated: 12/2/2021
Heather G. Sirdashney
Vice President, Human Resources and Real Estate
 
and Facilities Services
 
 
 
 
 
 
 
 
Exhibit
10.20.1
15
Exhibit A
Date of Delivery
 
to Employee:
_________
 
Deadline for Receipt by the Company:
____________
WAIVER AND RELEASE OF CLAIMS
 
Introduction and General Information
 
to Employee.
 
Signing
 
this
 
Waiver and
 
Release
 
of Claims
 
is
one condition
 
to receiving
 
certain benefit
 
payments (“Benefits”)
 
under the
 
ConocoPhillips Executive
Severance Plan (the “Plan”)
 
offered by ConocoPhillips (the “Company”).
 
You should thoroughly review
and understand
 
the effect
 
of this
 
Waiver and
 
Release of
 
Claims and
 
consult with
 
an attorney
 
before
signing it.
 
To the extent you have any claims covered by this Waiver and Release of Claims, you will be
giving up potentially valuable rights by signing.
 
You may take
 
time to consider whether or not to sign
this Waiver
 
and Release of Claims.
 
If you sign this
 
Waiver and
 
Release of Claims and
 
deliver it to
 
the
Company as set
 
forth below, and if the
 
Company’s designated recipient
 
receives
 
the
 
Waiver and
 
Release
of Claims on
 
or before the
 
date indicated above as
 
the “Deadline for
 
Receipt by the Company,” and you
do not
 
revoke
 
the Waiver
 
and Release
 
of Claims
 
within seven
 
(7) days
 
following receipt,
 
you will
 
be
entitled to Benefits
 
under the Plan
 
if you are
 
otherwise eligible.
 
If the signed
 
Waiver and
 
Release of
Claims is
 
not received
 
by the
 
deadline, or
 
if you
 
revoke
 
it during
 
the seven
 
(7) day
 
period following
receipt, no Benefits will be paid.
1.
General
 
Release.
 
In
 
consideration
 
of,
 
and subject
 
to,
 
the payments
 
to
 
be
 
made
 
to
 
me
 
by
 
the
Company or any
 
of its
 
subsidiaries, pursuant to the
 
Plan,
 
which
 
I acknowledge
 
that I
 
would
 
not otherwise
be entitled to receive, I hereby waive any claims I may have for employment or re-employment by the
Company or any subsidiary or parent of the Company after the date hereof, and I further agree to and
do release and forever discharge
 
the Company or any subsidiary
 
or parent of the Company,
 
and their
respective past and
 
present officers, directors, shareholders, employees, agents, and
 
assigns, as
 
well
 
as
any employee benefit
 
plans maintained by the
 
Company or
 
any subsidiary
 
or parent
 
of the
 
Company
 
and
fiduciaries, employees,
 
and agents
 
of such
 
plans, and
 
any related
 
parties (all
 
of which
 
are hereafter
referred to as the “Released
 
Parties”) from any and all
 
claims and causes
 
of action, known
 
or unknown,
arising
 
out
 
of
 
or
 
relating
 
to
 
my
 
employment
 
with
 
the
 
Company
 
or
 
any
 
subsidiary
 
or
 
parent
 
of
 
the
Company (including the termination of that employment), except
 
claims that the law does not permit
me to
 
waive by
 
signing this
 
Waiver
 
and Release
 
of Claims.
 
Such possible
 
claims or
 
causes of
 
action
include, but are
 
not limited to,
 
wrongful discharge,
 
contract, breach
 
of contract,
 
tort, fraud,
 
the Civil
Rights Acts (including, but not limited to, Title VII of the Civil Rights Act of 1964 and sections 1981 and
1983 of the Civil Rights Act of 1866), the Age Discrimination in Employment Act (“ADEA”),
 
the Worker
Adjustment and Retraining
 
Notification Act (“WARN”), the Employee
 
Retirement Income Security
 
Act
(“ERISA”), the Americans with
 
Disabilities Act (“ADA”), the Americans with
 
Disabilities
 
Act Amendments
Act
 
(“ADAAA”),
 
the
 
Family
 
and
 
Medical
 
Leave
 
Act
 
(“FMLA”),
 
the
 
Texas
 
Labor
 
Code,
 
and
 
any
 
other
federal,
 
state,
 
or
 
local
 
legislation
 
or
 
common
 
law
 
relating
 
to
 
employment
 
or
 
discrimination
 
in
employment or otherwise, except as
 
specifically excluded in paragraph
 
4 below.
PLEASE READ CAREFULLY
THIS AGREEMENT INCLUDES A RELEASE OF
ALL KNOWN AND UNKNOWN CLAIMS
 
 
 
 
 
 
Exhibit
10.20.1
16
2.
Extent of Release.
 
For the purpose of
 
implementing a full
 
and complete release and discharge of
the Released Parties,
 
I expressly acknowledge that
 
the release I
 
am giving in
 
this
 
document
 
is intended
to include in its effect, without
 
limitation, all claims I may
 
have against the Released Parties, whether
known, unknown, or
 
suspected at the
 
time I
 
delivered to
 
the designated
 
recipient
 
for the
 
Company
 
this
signed Waiver and Release of
 
Claims, and regardless of whether
 
the knowledge of such
 
claims, or the
facts upon which
 
they might be
 
based, would materially have
 
affected my decision to
 
sign this Waiver
and Release of
 
Claims, and that
 
the consideration given under
 
this Waiver
 
and Release
 
of Claims
 
is also
for the release
 
of those claims
 
and contemplates the
 
extinguishment
 
of any
 
such
 
claims.
 
In furtherance
of this Waiver and Release of
 
Claims, I waive any rights provided
 
by California Civil Code section
 
1542
or other similar local, state, provincial,
 
or federal law.
 
Section 1542 states:
“A general release does not
 
extend to claims
 
which the creditor
 
does not know
 
or
suspect to exist
 
in his favor
 
at the time
 
of executing the
 
release,
 
which
 
if known
 
by
him must have materially affected
 
his settlement with the debtor.”
Some of
 
the types of
 
claims that I
 
acknowledge I am
 
releasing, although there
 
may be others
 
not listed
here, are claims
 
I may have
 
under any applicable
 
labor agreement and
 
claims under any
 
federal,
 
state,
or local statute, ordinance,
 
order, or law
 
arising out of or relating to the terms and conditions
 
of my
employment with the Company and the termination
 
of my employment, including claims such as:
a.
Discrimination on the
 
basis of sex,
 
race, color,
 
national
 
origin,
 
religion,
 
sexual
orientation, disability,
 
veteran status,
 
or any other legally protected status;
b.
Harassment,
 
wrongful
 
discharge,
 
or
 
retaliation,
 
including
 
retaliatory
discharge,
 
arising
 
under
 
local,
 
state,
 
or
 
federal
 
law,
 
including
 
any
 
worker’s
compensation or whistleblower statute;
c.
Any other
 
possible restrictions
 
on the
 
Company’s
 
ability to
 
end its
 
employees’
employment at will, including but not limited to (i) violation of public policy, (ii) breach of
any
 
express
 
or
 
implied
 
covenant
 
of
 
the
 
employment
 
contract,
 
and
 
(iii)
 
breach
 
of
 
any
covenant of good faith and
 
fair dealing;
d.
Unpaid wages, including, but
 
not limited to claims
 
for unpaid overtime, break, meal,
or rest periods;
e.
Amounts determined under an incentive
 
compensation or bonus program
 
of the
Company,
 
including, but not limited to, the varying amounts
 
at its discretion;
f.
Civil
 
claims
 
of
 
negligence,
 
defamation,
 
business
 
disparagement,
 
invasion
 
of
privacy,
 
personal injury,
 
fraud, misrepresentation,
 
or infliction
 
of emotional
 
or mental
distress;
 
g.
Matters for which a civil
 
action may be
 
brought under section 502
 
or section
510 of
 
ERISA, except
 
as specifically
 
excluded
 
in paragraph
 
4 below
 
(“Exceptions
 
to
Release”); and
h.
Claims for breach of any agreement(s) ancillary to my employment with
 
the
Company.
3.
Release of Claims under the
 
Age Discrimination in Employment Act.
 
In consideration for receiving
the Benefits from
 
the Company or
 
any of its
 
subsidiaries, I specifically
 
waive all existing
 
rights
 
and claims
I may have
 
against the Released Parties under
 
the Age Discrimination
 
in Employment Act,
 
29 USC § 621
et seq., and any
 
other applicable federal,
 
state, or
 
local statute
 
or law involving
 
age discrimination.
 
I
acknowledge that the
 
Benefits constitute independent consideration for this
 
release of liability
 
and are
 
 
 
 
Exhibit
10.20.1
17
in addition to
 
any other payment
 
to which I
 
am entitled.
 
I further acknowledge
 
that I
 
have been
 
advised
to consult with an attorney of my
 
own choosing before executing
 
this Waiver and Release of Claims.
 
4.
Exceptions to Release.
 
The Waiver and Release of Claims does
 
not release any claims related
 
to:
a.
The business expense reimbursement
 
policy of the Company or any of its subsidiaries;
b.
Claims pursuant
 
to section
 
502(a)(1)(B) of ERISA
 
to recover
 
benefits under
 
the terms
 
of the
employee benefit plans
 
of the Company or
 
any of its subsidiaries
 
as applicable to me on
 
the
date of my employment termination;
c.
Claims made for work-related
 
injuries under applicable worker’s
 
compensation statutes;
d.
Any claim that
 
may arise after
 
the date this
 
signed Waiver and Release
 
of Claims is
 
delivered
 
to
the designated recipient for the
 
Company; and
e.
My rights
 
to indemnification
 
under any
 
indemnification agreement,
 
applicable law,
 
and the
certificates of incorporation and bylaws of the Company or
 
of any subsidiary of the
 
Company,
and my rights under any directors’
 
and officers’ liability insurance policy covering
 
me.
Nothing in this
 
Waiver and Release of
 
Claims, however, will limit my
 
right to report
 
possible
 
violations
 
of
law to any governmental
 
agency,
 
make other disclosures that
 
are protected under the
 
whistleblower
provisions of federal, state, or local law,
 
or testify, assist, or participate in an investigation,
 
hearing, or
proceeding conducted by the EEOC, EPA, DOL, SEC, IRS, or
 
any other governmental agency.
 
Nothing in
this
 
Waiver
 
and
 
Release
 
of
 
Claims
 
limits
 
my
 
right
 
to
 
receive
 
an
 
award
 
or
 
incentive
 
payment
 
for
information provided to
 
any governmental agency.
 
5.
Review Period and Revocation Period.
 
I acknowledge that
 
I have been
 
given
 
a period
 
of twenty-one
(21) calendar
 
days within
 
which to
 
review and
 
consider the
 
provisions of
 
this Waiver
 
and Release
 
of
Claims, whether I
 
choose to do
 
so or
 
not.
 
I understand and acknowledge
 
that the Company has
 
advised
me
 
in
 
writing
 
that
 
I
 
have
 
seven
 
(7)
 
calendar
 
days
 
following
 
the
 
timely
 
delivery
 
to
 
the
 
designated
representative of
 
the Company of
 
this properly executed
 
Waiver and
 
Release of Claims to
 
revoke my
acceptance of this
 
Waiver and Release of
 
Claims.
 
I understand the revocation
 
can be
 
made by
 
delivering
a written notice
 
of revocation to ConocoPhillips,
 
Attn: _________________________.
 
I understand
 
and
acknowledge that _________________ is the
 
designated recipient for the Company of
 
this Waiver and
Release of Claims
 
and that I
 
must deliver to
 
him at the
 
foregoing address this signed
 
Waiver and
 
Release
of Claims
 
on or
 
before
 
the deadline
 
set out
 
above
 
in order
 
to be
 
entitled to
 
receive the
 
Benefits.
 
I
understand that for the
 
revocation to be effective, the
 
Company through the designated
 
recipient
 
must
receive
 
written
 
notice
 
no
 
later
 
than
 
the close
 
of business
 
on
 
the seventh
 
day
 
after
 
I deliver
 
to
 
the
designated
 
recipient
 
for
 
the
 
Company
 
this
 
signed
 
Waiver
 
and
 
Release
 
of
 
Claims.
 
This
 
Waiver
 
and
Release of
 
Claims shall
 
not become
 
effective
 
or enforceable,
 
and the
 
Plan Benefits
 
will not
 
become
payable until after the seven
 
-day revocation period has expired,
 
but in no event prior to the effective
date of my termination of
 
employment, whether designated as a
 
layoff or other form
 
of termination of
employment.
 
I acknowledge
 
that
 
I have
 
had
 
adequate
 
time to
 
read
 
and
 
consider
 
this
 
Waiver
 
and
Release of
 
Claims before
 
executing
 
it.
 
I acknowledge
 
that I
 
have signed
 
this Waiver
 
and Release
 
of
Claims voluntarily, knowingly, of my own free will, with
 
the intent to be
 
legally bound by the
 
same, and
without reservation or duress, and that no promises or representations have been made to me by any
person to induce me to do so other than the promise of
 
Benefits set forth in the first paragraph above
and the Company’s acknowledgment
 
of my rights reserved under the fourth
 
paragraph above.
6.
Choice of
 
Laws.
 
I understand, acknowledge, and
 
agree that this
 
Waiver and Release of
 
Claims shall
be construed, interpreted,
 
governed, and enforced
 
in accordance with the laws of the State
 
of Texas,
without giving effect to
 
any conflict of law
 
principles.
 
I agree that all
 
disputes and actions arising
 
out of
 
Exhibit
10.20.1
18
or relating to this
 
Waiver and Release of Claims
 
shall be litigated solely
 
and exclusively in the
 
state or
federal courts
 
located in Harris
 
County,
 
Texas.
 
I submit to the
 
personal jurisdiction
 
of said courts for
purposes of any such disputes or actions.
Employee Signature:____________________________
 
Date:
 
________________________
Employee Name Printed:
 
______________________
 
Employee No: ________________
d123121dex1047
 
Exhibit
 
10.
47
1
CONOCOPHILLIPS
EXECUTIVE SEVERANCE PLAN
(Amended and Restated Effective
 
as of December 2, 2021)
Effective
 
October
 
1,
 
2004,
 
the
 
Company
 
adopted
 
this
 
the
 
ConocoPhillips
 
Executive
Severance
 
Plan
 
(the
 
"Plan")
 
for
 
the
 
benefit
 
of
 
certain
 
employees
 
of
 
the
 
Company
 
and
 
its
subsidiaries.
 
It was
 
amended and
 
restated
 
effective
 
January 1,
 
2005,
 
December 31,
 
2008, and
January 15, 2021.
 
This amendment and
 
restatement
 
of the Plan
 
shall be effective
 
December 2,
2021.
 
Any Eligible Employee (as
 
defined below) having a
 
Severance Date (as defined below)
 
prior
to
 
December
 
2,
 
2021,
 
shall
 
have
 
benefits
 
under
 
this
 
Plan
 
determined
 
in
 
accordance
 
with
 
the
provisions
 
of this
 
Plan
 
as they
 
existed
 
prior
 
to
 
this amendment
 
and
 
restatement.
 
Any
 
Eligible
Employee (as defined
 
below) having a
 
Severance Date (as
 
defined below) on
 
or after December
 
2,
2021, shall
 
have benefits
 
under this
 
Plan determined
 
in accordance
 
with the
 
provisions of
 
this
 
Plan
pursuant to
 
this amendment and
 
restatement.
 
All capitalized
 
terms used herein
 
are defined
 
in
Section 1 hereof.
 
This
 
Plan
 
is
 
intended
 
to
 
be
 
a
 
plan
 
maintained
 
primarily
 
for
 
the
 
purpose
 
of
 
providing
deferred
 
compensation
 
for
 
a
 
select
 
group
 
of
 
management
 
or
 
highly
 
compensated
 
employees,
within the
 
meaning of
 
Title I of
 
the Employee
 
Retirement Income
 
Security
 
Act
 
of 1974,
 
as
 
amended
and shall be interpreted in a manner consistent with such intention.
SECTION 1.
 
DEFINITIONS.
 
As hereinafter used:
1.1
 
"Board" means the Board of Directors of the Company.
1.2
 
"Cause" means
 
(i) the willful
 
and continued
 
failure by the
 
Eligible
 
Employee
 
to substantially
perform the
 
Eligible Employee's duties
 
with the Employer
 
(other than any
 
such failure
 
resulting
from the
 
Eligible Employee's
 
incapacity
 
due
 
to physical
 
or mental
 
illness),
 
or
 
(ii) the
 
willful
 
engaging,
not
 
in
 
good
 
faith,
 
by
 
the
 
Eligible
 
Employee
 
in
 
conduct
 
which
 
is
 
demonstrably
 
injurious
 
to
 
the
Company or any of its subsidiaries, monetarily or otherwise.
1.3
 
"Code" means
 
the Internal
 
Revenue Code of
 
1986,
 
as
 
it may
 
be amended
 
from
 
time
 
to time.
1.4
 
"Company" means ConocoPhillips or any successors thereto.
1.5
 
"Controlled Group" shall mean ConocoPhillips and its Subsidiaries.
1.6
 
"Credited
 
Compensation"
 
of
 
a
 
Severed
 
Employee
 
means
 
the
 
aggregate
 
of
 
the
 
Severed
Employee's
 
annual
 
base salary
 
plus his
 
or her
 
annual
 
incentive
 
compensation,
 
each
 
as
 
further
described
 
below.
 
For
 
purposes
 
of
 
this
 
definition,
 
(a) annual
 
base
 
salary
 
shall
 
be
 
determined
immediately prior to
 
the Severance Date and (b) annual
 
incentive compensation shall
 
be deemed
Exhibit
 
10.
47
2
to equal
 
the Severed
 
Employee’s
 
most recently
 
established target
 
(determined at
 
one hundred
percent of target) for
 
annual incentive compensation
 
for such employee
 
prior to such
 
employee’s
Severance
 
Date
 
pursuant
 
to
 
the
 
Variable
 
Cash
 
Incentive
 
Program
 
or
 
its
 
successor
 
program
maintained by the Employer.
1.7
 
"Effective Date"
 
means, as applicable, the date first stated above
 
as the original effective
date of this Plan or the effective date of this Plan as amended and restated.
1.8
 
"Eligible Employee" means any
 
employee that is a Tier 1
 
Employee or a Tier 2 Employee,
other than those employees who are listed on Exhibit B.
1.9
 
"Employer" means the Company or any of its subsidiaries.
1.10
 
"Person"
 
means
 
any
 
individual,
 
firm,
 
corporation,
 
partnership,
 
association,
 
trust,
unincorporated organization,
 
or other entity.
1.11
 
"Plan" means
 
the ConocoPhillips
 
Executive Severance Plan,
 
as set
 
forth herein,
 
as
 
it may
 
be
amended from time to time.
1.12
 
"Plan Administrator"
 
means the
 
person
 
or persons
 
appointed
 
from time
 
to
 
time by
 
the
Board, which appointment may
 
be revoked
 
at any time by
 
the Board.
 
At the Effective
 
Date, the
Plan Administrator
 
shall be
 
the Vice
 
President, Human
 
Resources and
 
Real Estate
 
and Facilities
Services of
 
the Company.
 
Any successor
 
to the
 
office of
 
Vice President,
 
Human
 
Resources
 
and
 
Real
Estate and Facilities Services (or to
 
a lesser or
 
greater position encompassing the role
 
of the most
senior officer
 
of the
 
Company
 
with
 
responsibility
 
over
 
the
 
Human
 
Resources
 
function)
 
shall
 
become
the
 
Plan
 
Administrator,
 
unless
 
and
 
until
 
the
 
Board
 
appoints
 
another
 
person
 
or
 
persons.
 
Notwithstanding the forgoing,
 
any person appointed
 
as
 
Plan
 
Administrator
 
shall
 
recuse
 
themselves
from any action with regard to
 
a claim relating to such person as an Eligible Employee.
1.13
 
"Retirement Plans" means
 
the ConocoPhillips Retirement Plan
 
and the
 
ConocoPhillips Key
Employee Supplemental Retirement
 
Plan.
1.14
 
“Salary
 
Grade”
means
 
a
 
classification
 
level
 
for
 
Employees
 
under
 
the
 
practices
 
of
 
the
Company.
 
Where
 
Salary
 
Grades
 
are
 
used
 
in
 
this
 
Procedure,
 
they
 
are
 
depicted
 
under
 
the
 
U.S.
practices for
 
the Company.
 
Practices may
 
vary in other countries
 
or particular subsidiaries,
 
and
Salary Grades shall
 
be transposed as
 
necessary to reflect
 
the practice
 
in the relevant
 
country or
subsidiary.
1.15
 
"Separation from Service"
 
means the
 
date on
 
which the
 
Participant separates from service
with the Controlled
 
Group within the
 
meaning of
 
Code section
 
409A, whether
 
by reason of
 
death,
disability, retirement, or otherwise.
 
In determining
 
Separation from Service,
 
with
 
regard to
 
a bona
fide leave of
 
absence that
 
is due
 
to any medically
 
determinable
 
physical
 
or
 
mental
 
impairment
 
that
can be expected to
 
result in death or can
 
be expected to
 
last for a continuous
 
period of not less
than six
 
months, where such
 
impairment causes the
 
Employee to be
 
unable to
 
perform the duties
Exhibit
 
10.
47
3
of his or
 
her position of
 
employment or
 
any substantially
 
similar position of
 
employment, a
 
29-
month period
 
of absence
 
shall be
 
substituted for the
 
six-month period set
 
forth in section
 
1.409A-
1(h)(1)(i) of the regulations issued under section 409A of the Code, as allowed thereunder.
1.16
 
"Severance"
 
means
 
the
 
termination
 
of
 
an
 
Eligible
 
Employee's
 
employment
 
with
 
the
Employer by the Employer other
 
than for Cause.
 
An Eligible Employee will not
 
be considered to
have incurred a Severance if his
 
employment is discontinued by reason
 
of the Eligible
 
Employee's
death or a physical or mental condition causing such Eligible Employee's inability to substantially
perform his
 
duties with
 
the Employer
 
and entitling
 
him or
 
her to
 
benefits under
 
any long-term
sick
pay or
 
disability income
 
policy or
 
program of the
 
Employer.
 
Furthermore,
 
an
 
Eligible
 
Employee
 
will
not be considered
 
to have incurred a
 
Severance if employment with
 
the Employer is
 
discontinued
after
 
the
 
Eligible
 
Employee
 
has
 
been
 
offered
 
employment
 
with
 
another
 
employer
 
that
 
has
purchased a subsidiary or
 
division of the Company
 
or all or substantially
 
all of the assets of
 
an a
subsidiary or division
 
of the Company and
 
the offer of employment from
 
the other employer is
 
at
the same or greater salary and
 
the same or greater target
 
bonus as the Eligible Employee has at
that time
 
from the
 
Employer.
 
Still further,
 
an Eligible
 
Employee will
 
not be
 
considered to
 
have
incurred a
 
Severance if employment
 
with the
 
Employer
 
is
 
discontinued
 
and
 
the
 
Eligible
 
Employee
 
is
also eligible for
 
payments under
 
the ConocoPhillips Key
 
Employee Change in
 
Control Severance
Plan, as
 
effective as of
 
the Effective Date,
 
or as
 
subsequently amended,
 
.
 
Furthermore, in
 
order to
be considered
 
a Severance, the
 
termination must also
 
meet the
 
requirements
 
of a
 
Separation
 
from
Service.
1.17
 
"Severance Date" means the date on which an Eligible Employee incurs
 
a Severance.
1.18
 
"Severance Pay" means the payment
 
determined pursuant to Section 2.1 hereof.
1.19
 
"Severed Employee" means an Eligible Employee who has incurred a Severance.
1.20
 
"Subsidiary" means
 
any corporation or
 
other entity
 
that is
 
treated
 
as
 
a single
 
employer
 
with
ConocoPhillips,
 
under
 
section
 
414(b)
 
or
 
(c)
 
of
 
the
 
Code;
 
provided,
 
that
 
in
 
making
 
this
determination, in applying
 
section 1563(a)(1),
 
(2), and
 
(3) of
 
the Code
 
for purposes
 
of determining
a
 
controlled
 
group
 
of
 
corporations
 
under
 
section
 
414(b)
 
of
 
the
 
Code
 
and
 
for
 
purposes
 
of
determining
 
trades
 
or businesses
 
(whether or
 
not incorporated)
 
under common
 
control
 
under
regulation section
 
1.414(c)-2 for
 
purposes of
 
section 414(c)
 
of the
 
Code, the
 
language “at
 
least
80%” shall
 
be used
 
without substitution as
 
allowed under regulations
 
pursuant to section
 
409A of
the Code.
1.21
 
"Tier 1
 
Employee" means
 
any employee of
 
the Employer
 
who is
 
in
 
Salary
 
Grade
 
26
 
or above
(under
 
the
 
Salary
 
Grade
 
schedule
 
of
 
the
 
Company
 
on
 
the
 
Effective
 
Date,
 
with
 
appropriate
adjustment for any subsequent change in such Salary Grade schedule) on the Severance
 
Date.
1.22
 
"Tier 2
 
Employee" means
 
any employee
 
of
 
the
 
Employer, other
 
than
 
a
 
Tier
 
1 Employee,
 
who
is in Salary Grade 23 or above (under the Salary Grade schedule of the Company on the Effective
 
Exhibit
 
10.
47
4
Date, with appropriate adjustment for any subsequent change in such Salary Grade schedule) on
the Severance Date.
SECTION 2.
 
BENEFITS.
2.1
 
Subject to Section 2.6, each Severed Employee shall be entitled to receive Severance
 
Pay
equal to the
 
sum of the
 
amounts determined under
 
Sections 2.1(a), (b),
 
and (c).
 
Furthermore, for
purposes of
 
Employer compensation plans,
 
programs, and arrangements,
 
each Severed
 
Employee
shall be considered to have been laid off by the Employer.
(a)
The amount that is the
 
Severed Employee's Credited Compensation, multiplied by
(i) 2, in the case of a Tier 1 Employee or (ii) 1.5 in the case of a Tier 2 Employee.
(b)
For Severed Employees actively participating in the Retirement Plans, the amount
that is
 
the present
 
value, determined as
 
of the
 
Severed
 
Employee's
 
Severance
 
Date,
of
 
the
 
benefits
 
under
 
the
 
Retirement
 
Plans
 
that
 
would
 
result
 
if
 
the
 
Severed
Employee was
 
credited with the following
 
number of additional years
 
of age and
service under
 
the Retirement Plans:
 
(i) 2, in
 
the case
 
of a
 
Tier 1 Employee
 
or (ii)
 
1.5,
in the
 
case of
 
a Tier 2
 
Employee; less the
 
amount that is
 
the value
 
determined as of
the Severed Employee’s Severance Date (including any additional credited service
due to the circumstances
 
of the Severed Employee’s
 
termination) of the benefits
under
 
the
 
Retirement
 
Plans.
 
Present
 
value
 
shall
 
be
 
determined
 
based
 
on
 
the
assumptions
 
utilized
 
under
 
the
 
ConocoPhillips
 
Retirement
 
Plan
 
for
 
purposes
 
of
determining contributions under
 
Code section
 
412
 
for the
 
most
 
recently
 
completed
plan year.
 
No amounts provided under this Section 2.1(b) shall be less
 
than zero.
 
For the
 
avoidance of
 
doubt, with
 
respect to
 
a Severed
 
Employee who
 
is actively
participating in a cash
 
balance formula under the
 
Retirement Plans, the Severance
Pay
 
amount
 
determined
 
under
 
this
 
subsection
 
shall
 
be
 
the
 
amount
 
that
 
is
 
the
present
 
value
 
of
 
benefits
 
under
 
the
 
Retirement
 
Plans
 
that
 
would
 
result
 
if
 
the
Severed Employee
 
was credited with
 
the following number of
 
additional years of
pay
 
credits
 
and interest
 
credits
 
under the
 
Retirement
 
Plans as
 
of the
 
Severance
Date:
 
(i)
 
2,
 
in
 
the
 
case
 
of
 
a
 
Tier
 
1
 
Employee
 
or
 
(ii)
 
1.5,
 
in
 
the
 
case
 
of
 
a
 
Tier
 
2
Employee;
 
less
 
the
 
amount
 
that
 
is
 
the
 
value
 
determined
 
as
 
of
 
the
 
Severed
Employee’s
 
Severance Date of the benefits under the Retirement
 
Plans.
(c)
The amount that is equal to the sum of (i), (ii), and (iii):
(i)
The
 
lesser
 
of
 
the
 
difference
 
between
 
the
 
annual
 
COBRA
 
participant
contribution
 
amount
 
or
 
the
 
ConocoPhillips
 
Retiree
 
Medical
 
Pre-65
 
Plan
participant
 
contribution
 
amount,
 
as
 
applicable,
 
and
 
the
 
annual
 
active
employee contribution
 
amount, each
 
as of the
 
Severance Date,
 
based on
the active medical coverage for which the Severed Employee was enrolled
as of
 
the Severance Date
 
multiplied by
 
(a) 2,
 
in the
 
case of
 
a Tier
 
1 Employee
or (b) 1.5,
 
in the
 
case of a
 
Tier 2 Employee.
 
For the avoidance
 
of doubt, any
Exhibit
 
10.
47
5
Severed
 
Employee
 
or
 
dependents
 
who
 
are
 
over
 
the
 
age
 
of
 
65
 
on
 
the
Severance
 
Date
 
will
 
not
 
be
 
eligible
 
for
 
any
 
amounts
 
under
 
this
 
section
2.1(c)(i).
(ii)
The difference between
 
the annual
 
COBRA participant
 
contribution
 
amount
and
 
the
 
annual
 
active
 
employee
 
contribution
 
amount,
 
each
 
as
 
of
 
the
Severance Date, based
 
on the
 
active dental coverage
 
for which
 
the Severed
Employee was enrolled as of
 
the Severance Date,
 
multiplied by (a) 2,
 
in the
case of a Tier 1 Employee or (b) 1.5, in the case of a Tier 2 Employee.
(iii)
The
 
difference
 
between
 
the
 
annual
 
cost
 
to
 
maintain
 
coverage
 
and
 
the
annual active
 
employee contribution, each
 
as of
 
the
 
Severance
 
Date,
 
for the
company-sponsored
 
life
 
insurance
 
coverage
 
(including
 
basic,
 
executive
basic, and supplemental) for which the Severed Employee was
 
enrolled on
the Severance Dd
 
ate multiplied by
 
(a) 2,
 
in the
 
case of
 
a Tier
 
1 Employee or
(b) 1.5, in the
 
case of a Tier
 
2 Employee.
 
For the avoidance
 
of doubt, this
amount
 
will
 
be
 
calculated
 
using
 
differences
 
in
 
cost
 
ignoring
 
any
 
limits
imposed by
 
the insurance
 
carrier for portability
 
and
 
conversion
 
of coverage.
Any amounts provided under this
 
Section 2.1(c) will
 
not be adjusted to
 
reflect that
the Severed Employee’s
 
cost will no longer be pre-tax.
2.2
 
Subject to Section 2.6, Severance Pay (as well as any amount payable pursuant to Section
2.3 hereof) shall be
 
paid to an eligible Severed Employee in
 
a cash lump sum on
 
the first business
day immediately
 
following 10
 
days
 
after the
 
end of
 
the period
 
for executing
 
and delivering
 
the
Severed Employee's release, as set forth
 
in Section 2.6.
2.3
 
Each Severed Employee shall be entitled to receive the
 
employee's full salary through the
Severance Date
 
and, subject to Section 2.6 but
 
notwithstanding any provision
 
of the Company's
Variable
 
Cash Incentive Program
 
or similar annual bonus incentive
 
plan to the contrary,
 
shall be
eligible for consideration
 
for an award
 
under such program or plan when
 
awards are made with
regard to the fiscal year under
 
such program or plan in which the Severance Date occurred
 
.
2.4
 
Each party
 
to any dispute
 
concerning this
 
Plan
 
shall
 
be responsible
 
for that
 
party’s
 
own
 
legal
fees and expenses;
 
provided, however, that the
 
arbitrator
 
appointed
 
pursuant
 
to Section
 
3.2
 
of
 
this
Plan
 
may
 
award
 
reasonable
 
legal
 
fees
 
and
 
expenses
 
to
 
an
 
Eligible
 
Employee
 
if
 
the
 
arbitrator
determines that the Company’s denial of the claim of the Eligible Employee was not
 
reasonable.
2.5
 
The Company
 
shall be
 
entitled to
 
withhold and/or
 
to cause
 
to be
 
withheld
 
from
 
amounts
 
to
be paid
 
to the Severed
 
Employee hereunder any
 
federal, state, or local
 
withholding or
 
other taxes
or charges which it is from time to time required to withhold.
2.6
 
No Severed Employee
 
shall be
 
eligible to
 
receive Severance Pay or
 
other
 
benefits
 
under
 
the
Plan unless
 
he or
 
she first
 
executes a written
 
release substantially in
 
the form
 
attached
 
as
 
Exhibit A
 
 
Exhibit
 
10.
47
6
hereto (or, if the
 
Severed Employee was
 
not a
 
United States employee,
 
a similar
 
release
 
which
 
is
 
in
accordance with the applicable
 
laws in the
 
relevant jurisdiction) and, to
 
the extent such release
 
is
revocable by its terms,
 
only if the
 
Severed Employee does not
 
revoke it, and unless
 
he or she
 
also,
at the request of
 
the Company, executes a written agreement not
 
to compete with
 
the Company,
with such
 
terms and
 
conditions as
 
may be
 
proposed by
 
the
 
Company
 
at the
 
time.
 
Such
 
release
 
and,
if requested,
 
such agreement
 
not to
 
compete must
 
be executed
 
and delivered
 
to the
 
Company
within 30 days of the Employee’s
 
Severance Date.
SECTION 3.
 
PLAN ADMINISTRATION
 
.
3.1
 
The Plan
 
Administrator
 
shall administer
 
the Plan
 
and may
 
interpret
 
the Plan,
 
prescribe,
amend,
 
and
 
rescind
 
rules
 
and
 
regulations
 
under
 
the
 
Plan
 
and
 
make
 
all
 
other
 
determinations
necessary or advisable for
 
the administration of the Plan,
 
subject to all the
 
provisions of the Plan.
 
The
 
Plan
 
Administrator
 
shall
 
have
 
absolute
 
discretion
 
and
 
authority
 
in
 
carrying
 
out
 
its
responsibilities, and
 
all interpretations
 
of the
 
Plan, determinations
 
of eligibility
 
under the
 
Plan,
determinations to grant
 
or deny
 
benefits under
 
the
 
Plan,
 
or
 
findings
 
of
 
fact
 
or resolutions
 
related
 
to
the Plan
 
and its
 
administration that are
 
made by
 
the Plan
 
Administrator shall be
 
binding, final,
 
and
conclusive on all parties.
3.2
 
In the event of
 
a claim by
 
an Eligible Employee as
 
to the amount or
 
timing of any payment
or benefit,
 
such Eligible
 
Employee shall
 
present the
 
reason for his
 
or her
 
claim
 
in writing
 
to the
 
Plan
Administrator.
 
The Plan Administrator
 
shall, within
 
14 days
 
after receipt
 
of such
 
written claim,
send a written
 
notification to the
 
Eligible Employee as
 
to its disposition.
 
Except as provided in
 
the
preceding portion
 
of this
 
Section 3.2, all
 
disputes under
 
this Plan
 
shall be settled
 
exclusively
 
by
binding arbitration
 
in Houston,
 
Texas,
 
in accordance
 
with the
 
rules of the
 
American Arbitration
Association then
 
in effect.
 
Judgment may be
 
entered on the
 
arbitrator's award in
 
any
 
court
 
having
jurisdiction.
3.3
 
The Plan
 
Administrator may delegate any
 
of its
 
duties hereunder
 
to such
 
person
 
or
 
persons
from time to time as it may designate.
 
3.4
 
The Plan Administrator is empowered, on
 
behalf of the
 
Plan, to engage accountants, legal
counsel,
 
and
 
such
 
other
 
personnel
 
as
 
it
 
deems
 
necessary
 
or
 
advisable
 
to
 
assist
 
it
 
in
 
the
performance of its duties under
 
the Plan.
 
The functions of any such
 
persons engaged by the Plan
Administrator shall be
 
limited to
 
the specified
 
services and
 
duties for
 
which they
 
are engaged, and
such
 
persons
 
shall
 
have
 
no
 
other
 
duties,
 
obligations,
 
or
 
responsibilities
 
under
 
the
 
Plan.
 
Such
persons
 
shall
 
exercise
 
no
 
discretionary
 
authority
 
or
 
discretionary
 
control
 
respecting
 
the
management of the Plan.
 
All reasonable expenses thereof shall be borne by the Employer.
SECTION 4.
 
DURATION;
 
AMENDMENT; AND TERMINATION
 
.
4.1
 
This Plan shall be effective on the Effective
 
Date.
 
This Plan shall continue in effect unless
and until it is terminated as provided in Section 4.2.
 
Exhibit
 
10.
47
7
4.2
 
This
 
Plan
 
may
 
be
 
amended
 
from
 
time
 
to
 
time
 
during
 
its
 
term
 
by
 
the
 
Company
 
acting
through its Board of Directors or,
 
to the extent authorized by the Board
 
of Directors, its officers.
 
The Company may,
 
by action of its Board of Directors, terminate this Plan at any
 
time.
SECTION 5.
 
GENERAL PROVISIONS.
5.1
 
Except as otherwise
 
provided herein or
 
by law, no right
 
or interest of
 
any Eligible
 
Employee
under
 
the
 
Plan
 
shall
 
be
 
assignable
 
or
 
transferable,
 
in
 
whole
 
or
 
in
 
part,
 
either
 
directly
 
or
 
by
operation
 
of
 
law
 
or
 
otherwise,
 
including
 
without
 
limitation
 
by
 
execution,
 
levy,
 
garnishment,
attachment,
 
pledge,
 
or
 
in
 
any
 
manner;
 
no
 
attempted
 
assignment
 
or
 
transfer
 
thereof
 
shall
 
be
effective;
 
and no right
 
or interest
 
of any
 
Eligible Employee
 
under the
 
Plan shall be
 
liable for,
 
or
subject to, any obligation
 
or liability of
 
such Eligible
 
Employee.
 
When a
 
payment is due
 
under this
Plan to
 
a Severed
 
Employee who
 
is unable to
 
care for
 
his or her
 
affairs,
 
payment may
 
be made
directly to his or her legal guardian or personal representative.
5.2
 
If
 
any
 
Employer
 
is obligated
 
by
 
law or
 
by
 
contract
 
to pay
 
severance
 
pay,
 
a
 
termination
indemnity, notice pay, or the
 
like, to a
 
Severed Employee, or
 
if any
 
Employer is
 
obligated by law
 
to
provide advance notice
 
of separation ("Notice
 
Period")
 
to a
 
Severed
 
Employee,
 
then
 
any
 
Severance
Pay hereunder to such Severed Employee shall be reduced by the amount of any such severance
pay,
 
termination
 
indemnity,
 
notice
 
pay,
 
or
 
the
 
like,
 
as
 
applicable,
 
and
 
by
 
the
 
amount
 
of
 
any
compensation received during
 
any Notice
 
Period.
 
This
 
provision
 
specifically
 
includes
 
any
 
payments
or obligations under
 
the ConocoPhillips
 
Severance Pay Plan,
 
as effective
 
on
 
the
 
Effective Date
 
or as
subsequently amended.
 
Furthermore, if
 
an Eligible
 
Employee has
 
willful and
 
bad faith
 
conduct
demonstrably
 
injurious to
 
Company or
 
its subsidiaries,
 
monetarily or
 
otherwise, after
 
receiving
Severance Pay, the Company may
 
offset an amount
 
equal to
 
such Severance Pay
 
against any
 
other
amounts due from other plans or programs, unless otherwise required by law.
5.3
 
Neither the
 
establishment of
 
the Plan,
 
nor any
 
modification
 
thereof, nor
 
the
 
creation
 
of
 
any
fund, trust, or account, nor the payment
 
of any benefits shall be construed
 
as giving any Eligible
Employee, or
 
any person
 
whomsoever, the right to
 
be retained in
 
the service
 
of the
 
Employer, and
all Eligible
 
Employees shall
 
remain subject
 
to discharge to
 
the same
 
extent as if
 
the Plan
 
had never
been adopted.
5.4
 
If
 
any
 
provision
 
of
 
this
 
Plan
 
shall
 
be
 
held
 
invalid
 
or
 
unenforceable,
 
such
 
invalidity
 
or
unenforceability shall not affect any other
 
provisions hereof, and this Plan shall
 
be construed and
enforced as if such provisions had not been included.
5.5
 
This Plan
 
shall be
 
binding upon
 
the heirs,
 
executors, administrators,
 
successors,
 
and
 
assigns
of
 
the
 
parties,
 
including each
 
Eligible
 
Employee,
 
present
 
and
 
future,
 
and
 
any
 
successor
 
to
 
the
Employer.
5.6
 
The headings and captions herein are provided for reference
 
and convenience only,
 
shall
not be considered part of the Plan, and shall not be employed in the construction of the Plan.
 
Exhibit
 
10.
47
8
5.7
 
The Plan shall not be funded.
 
No Eligible Employee shall have any right to,
 
or interest in,
any assets
 
of any
 
Employer that
 
may be applied
 
by the Employer
 
to the payment
 
of benefits or
other rights under this Plan.
5.8
 
Any notice or
 
other communication required
 
or permitted pursuant
 
to the terms
 
hereof
shall have
 
been duly
 
given when
 
delivered
 
or mailed
 
by United
 
States
 
Mail, first
 
-class, postage
prepaid, addressed to the intended recipient at his, her or its last known address.
5.9
 
This Plan shall be construed and enforced according to the laws of the State of Delaware.
Executed this __ day of December 2021, by a duly authorized officer of the Company.
CONOCOPHILLIPS
 
By: /s/ Heather G. Sirdashney
 
Dated: 12/2/2021
Heather G. Sirdashney
Vice President, Human Resources and Real Estate
 
and Facilities Services
 
 
 
 
 
 
 
 
 
Exhibit
 
10.
47
9
Exhibit A
Date of Delivery
 
to Employee:
_______________
Deadline for Receipt
 
by the Company:
________________
WAIVER AND RELEASE OF CLAIMS
Introduction
 
and
 
General
 
Information
 
to
 
Employee.
 
Signing
 
this
 
Waiver
 
and
 
Release
 
of
 
Claims
 
is
 
one
condition to receiving certain
 
benefit payments (“Benefits”) under the
 
ConocoPhillips Executive Severance
Plan (the “Plan”)
 
offered by ConocoPhillips (the “Company”).
 
You should
 
thoroughly
 
review and
 
understand
the effect of this
 
Waiver and Release of
 
Claims and consult
 
with an attorney before signing
 
it.
 
To the extent
you have any claims
 
covered by this Waiver and
 
Release of Claims, you
 
will be
 
giving up potentially
 
valuable
rights by signing.
 
You may take time to consider
 
whether or not
 
to sign this
 
Waiver and
 
Release
 
of Claims.
 
If
you sign
 
this Waiver
 
and Release
 
of Claims
 
and deliver
 
it to
 
the Company
 
as set
 
forth
 
below,
 
and if
 
the
Company’s designated recipient receives the Waiver and Release of Claims
 
on or before the
 
date indicated
above as
 
the “Deadline
 
for Receipt
 
by the
 
Company,”
 
and you
 
do not revoke
 
the Waiver
 
and Release
 
of
Claims within
 
seven (7)
 
days
 
following
 
receipt,
 
you will
 
be entitled
 
to Benefits
 
under the
 
Plan if
 
you are
otherwise eligible.
 
If the
 
signed Waiver
 
and Release
 
of Claims
 
is not
 
received by
 
the deadline,
 
or if
 
you
revoke it during the seven
 
(7) day period following receipt,
 
no Benefits will be paid.
1.
General Release.
 
In consideration
 
of, and
 
subject to, the
 
payments to
 
be made to me by
 
the
Company or any of
 
its subsidiaries, pursuant to the
 
Plan, which I
 
acknowledge that I
 
would
 
not otherwise
 
be
entitled
 
to
 
receive,
 
I
 
hereby
 
waive
 
any
 
claims
 
I
 
may
 
have
 
for
 
employment
 
or
 
re-employment
 
by
 
the
Company or any subsidiary or parent
 
of the Company after the date
 
hereof,
 
and I further agree to and do
release and forever discharge the
 
Company or any
 
subsidiary
 
or parent
 
of the
 
Company, and
 
their
 
respective
past and present officers, directors, shareholders, employees, agents, and
 
assigns, as well
 
as any employee
benefit
 
plans
 
maintained
 
by
 
the
 
Company
 
or
 
any
 
subsidiary
 
or
 
parent
 
of
 
the
 
Company
 
and
 
fiduciaries,
employees, and agents of such plans, and any related parties (all of which are hereafter
 
referred to as the
“Released
 
Parties”)
 
from
 
any
 
and all
 
claims
 
and
 
causes
 
of action,
 
known
 
or unknown,
 
arising
 
out of
 
or
relating to my
 
employment with the
 
Company or any
 
subsidiary or parent
 
of the Company (including
 
the
termination of that employment),
 
except claims that
 
the law does not permit me
 
to waive by signing this
Waiver
 
and Release
 
of Claims.
 
Such possible
 
claims or
 
causes
 
of action
 
include, but
 
are not
 
limited
 
to,
wrongful discharge, contract, breach of contract, tort,
 
fraud, the Civil
 
Rights Acts (including,
 
but not limited
to, Title VII
 
of the
 
Civil Rights Act
 
of 1964
 
and sections 1981
 
and 1983 of
 
the Civil
 
Rights
 
Act of
 
1866),
 
the Age
Discrimination
 
in
 
Employment
 
Act
 
(“ADEA”),
 
the
 
Worker
 
Adjustment
 
and
 
Retraining
 
Notification
 
Act
(“WARN”),
 
the Employee
 
Retirement
 
Income Security
 
Act (“ERISA”),
 
the Americans
 
with Disabilities
 
Act
(“ADA”),
 
the Americans with
 
Disabilities Act Amendments Act
 
(“ADAAA”),
 
the Family
 
and Medical
 
Leave Act
(“FMLA”), the Texas Labor Code, and any
 
other federal, state,
 
or local legislation
 
or common
 
law relating
 
to
PLEASE READ CAREFULLY
THIS AGREEMENT INCLUDES A RELEASE OF ALL KNOWN AND UNKNOWN CLAIMS
 
 
 
 
 
Exhibit
 
10.
47
10
employment or discrimination in employment or otherwise, except as specifically excluded in paragraph 4
below.
2.
Extent of Release.
 
For the purpose of
 
implementing a full and complete release and discharge
of the
 
Released Parties, I expressly acknowledge that
 
the release I
 
am giving in
 
this document
 
is intended
 
to
include in its effect, without limitation, all claims I may
 
have against the Released Parties, whether known,
unknown,
 
or suspected
 
at the
 
time I
 
delivered
 
to the
 
designated
 
recipient
 
for
 
the Company
 
this signed
Waiver and Release of Claims,
 
and regardless of whether the
 
knowledge of such claims, or the facts upon
which they might be based, would materially have affected my decision to sign this Waiver and Release of
Claims, and that the consideration given
 
under this Waiver and Release of Claims
 
is also for the release of
those claims and
 
contemplates
 
the extinguishment
 
of any such
 
claims. In furtherance
 
of this Waiver
 
and
Release of Claims,
 
I waive any
 
rights provided
 
by California
 
Civil Code section
 
1542 or other similar
 
local,
state, provincial,
 
or federal law.
 
section 1542 states:
“A
 
general release does not
 
extend to claims which
 
the creditor does not
 
know or
suspect to exist in his favor at the time of executing the release, which if known by
him must have materially affected
 
his settlement with the debtor.”
Some of
 
the types of
 
claims that I
 
acknowledge I am
 
releasing, although there
 
may be
 
others
 
not listed
 
here,
are claims I may
 
have under any
 
applicable labor agreement
 
and claims under any
 
federal, state,
 
or local
statute, ordinance,
 
order,
 
or law arising out of or relating to
 
the terms and conditions of my
 
employment
with the Company and the
 
termination of my
 
employment, including claims
 
such as:
a.
Discrimination on the basis of sex, race, color, national origin, religion, sexual
 
orientation,
disability,
 
veteran status,
 
or any other legally protected
 
status;
b.
Harassment, wrongful
 
discharge,
 
or retaliation,
 
including
 
retaliatory
 
discharge,
 
arising
 
under
local, state,
 
or federal law,
 
including any worker’s
 
compensation or whistleblower statute;
c.
Any other possible
 
restrictions on the Company’s ability
 
to end
 
its employees’
 
employment
at will, including but
 
not limited to (i)
 
violation of public policy, (ii) breach of
 
any express or implied
covenant
 
of
 
the
 
employment
 
contract,
 
and
 
(iii)
 
breach
 
of
 
any
 
covenant
 
of
 
good
 
faith
 
and
 
fair
dealing;
d.
Unpaid wages, including,
 
but not
 
limited to
 
claims for
 
unpaid overtime, break,
 
meal, or
 
rest
periods;
e.
Amounts determined under an
 
incentive compensation or
 
bonus
 
program of
 
the Company,
including, but not limited to,
 
the varying amounts at
 
its discretion;
f.
Civil
 
claims
 
of
 
negligence,
 
defamation,
 
business
 
disparagement,
 
invasion
 
of
 
privacy,
personal injury,
 
fraud, misrepresentation,
 
or infliction of emotional or mental
 
distress;
 
g.
Matters for which a civil action may be
 
brought under section 502 or section 510
 
of ERISA,
except as specifically
 
excluded in paragraph
 
4 below (“Exceptions
 
to Release”); and
h.
Claims for breach of
 
any agreement(s) ancillary
 
to my employment
 
with the Company.
3.
Release of Claims under Age Discrimination in
 
Employment Act.
 
In consideration for receiving
the Benefits from the Company or any of its subsidiaries,
 
I specifically waive all existing
 
rights and claims I
may have against
 
the Released Parties
 
under the Age Discrimination
 
in Employment Act,
 
29 USC § 621 et
seq.,
 
and
 
any
 
other
 
applicable
 
federal,
 
state,
 
or
 
local
 
statute
 
or
 
law
 
involving
 
age
 
discrimination.
 
I
acknowledge that the Benefits constitute
 
independent consideration
 
for this release of liability and are in
 
 
Exhibit
 
10.
47
11
addition to any other
 
payment to which
 
I am entitled.
 
I further acknowledge
 
that I have been
 
advised to
consult with an attorney
 
of my own choosing before
 
executing this Waiver
 
and Release of Claims.
 
4.
Exceptions to Release.
 
The Waiver and Release
 
of Claims
 
does
 
not release
 
any claims
 
related
 
to:
a.
The business expense reimbursement
 
policy of the Company or any
 
of its subsidiaries;
b.
Claims pursuant to section
 
502(a)(1)(B) of ERISA
 
to recover benefits under
 
the terms
 
of the
employee benefit plans of
 
the Company or
 
any of its
 
subsidiaries as applicable to
 
me on
 
the date of
my employment termination;
c.
Claims made for work-related
 
injuries under applicable worker’s
 
compensation statutes;
d.
Any claim that may
 
arise after the
 
date this signed
 
Waiver and
 
Release
 
of Claims
 
is delivered
to the designated recipient
 
for the Company; and
e.
My rights to
 
indemnification under any indemnification agreement,
 
applicable
 
law, and the
certificates of incorporation and bylaws of the Company or of any subsidiary of the Company, and
my rights under any
 
directors’
 
and officers’ liability insurance
 
policy covering me.
Nothing in this
 
Waiver and Release of
 
Claims, however, will limit my right
 
to report
 
possible
 
violations
 
of law
to any governmental agency, make other disclosures that are
 
protected under
 
the whistleblower
 
provisions
of federal,
 
state,
 
or local
 
law,
 
or testify,
 
assist, or
 
participate
 
in an
 
investigation,
 
hearing, or
 
proceeding
conducted by the EEOC, EPA, DOL, SEC,
 
IRS, or any other
 
governmental agency.
 
Nothing in this
 
Waiver and
Release of Claims limits
 
my right to receive an
 
award or incentive payment for information provided to any
governmental agency.
 
5.
Review Period and Revocation Period.
 
I acknowledge that
 
I have
 
been
 
given
 
a period
 
of twenty-
one (21) calendar
 
days within
 
which to review
 
and consider
 
the provisions
 
of this Waiver
 
and Release
 
of
Claims, whether I
 
choose to do
 
so or
 
not.
 
I understand and acknowledge
 
that the Company has
 
advised me
in writing that
 
I have seven
 
(7) calendar days following the
 
timely delivery to
 
the designated representative
of the Company
 
of this properly
 
executed
 
Waiver and
 
Release of Claims
 
to revoke
 
my acceptance
 
of this
Waiver and Release
 
of Claims.
 
I understand the revocation
 
can be made by delivering a written
 
notice of
revocation
 
to
 
ConocoPhillips,
 
Attn:
 
____________,
 
600
 
N.
 
Dairy
 
Ashford,
 
Houston,
 
Texas
 
77079.
 
I
understand
 
and
 
acknowledge
 
that
 
_____________
 
is
 
the
 
designated
 
recipient
 
for
 
the
 
Company
 
of
 
this
Waiver and Release of
 
Claims and that
 
I must deliver
 
to him at
 
the foregoing address this
 
signed
 
Waiver and
Release of Claims on or before the deadline set out above in order to be entitled to receive the Benefits.
 
I
understand
 
that for
 
the revocation
 
to be
 
effective,
 
the Company
 
through the
 
designated
 
recipient must
receive written notice no
 
later than the
 
close of business
 
on the
 
seventh day
 
after I
 
deliver
 
to the
 
designated
recipient for the Company this
 
signed Waiver and Release of
 
Claims.
 
This
 
Waiver and
 
Release
 
of Claims
 
shall
not become effective or enforceable,
 
and the Plan Benefits will not become payable until after the seven-
day
 
revocation
 
period
 
has
 
expired,
 
but
 
in
 
no
 
event
 
prior
 
to
 
the
 
effective
 
date
 
of
 
my
 
termination
 
of
employment, whether designated as a layoff or other form of termination of employment.
 
I acknowledge
that I have
 
had adequate time to
 
read and consider this
 
Waiver and Release of
 
Claims before executing it.
 
I
acknowledge that I have
 
signed this Waiver
 
and Release of Claims
 
voluntarily,
 
knowingly,
 
of my own free
will,
 
with
 
the
 
intent
 
to
 
be
 
legally
 
bound
 
by
 
the
 
same,
 
and
 
without
 
reservation
 
or
 
duress,
 
and
 
that
 
no
promises or representations
 
have been made
 
to me by
 
any person
 
to induce me
 
to do so
 
other than the
promise of Benefits set
 
forth in the
 
first paragraph above and the
 
Company’s acknowledgment of my rights
reserved under the fourth
 
paragraph above.
 
Exhibit
 
10.
47
12
6.
Choice of Laws.
 
I understand, acknowledge, and agree that this Waiver and Release of Claims
shall be construed, interpreted, governed, and enforced in accordance with the laws of the State of Texas,
without giving effect to any conflict of law principles.
 
I agree that all disputes and actions arising out of or
relating to this Waiver and Release of Claims shall be litigated solely and exclusively
 
in the state or federal
courts located in Harris
 
County,
 
Texas.
 
I submit to the personal jurisdiction
 
of said courts for purposes
 
of
any such disputes or actions.
Employee Signature:
 
____________________________
 
Date:
 
________________________
Employee Name Printed:
 
________________________
 
Employee No:
 
________________
Exhibit
 
10.
47
13
Exhibit B
Employees Ineligible for Executive Severance
 
Plan
Employees of Concho
 
Resources Inc. or
 
any of
 
its subsidiaries,
 
including but
 
not limited
to COG Operating LLC, who are participants in but do not waive all benefits under the
Concho Resources Inc. Executive Severance
 
Plan
d123121dex21
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1
Exhibit 21
SUBSIDIARY LISTING OF CONOCOPHILLIPS
Listed below are subsidiaries of the registrant at December 31, 2021.
 
Certain subsidiaries are
omitted since such companies considered in the aggregate do not constitute a significant subsidiary.
Company Name
Incorporation
 
Location
Ashford Energy Capital
 
Limited
Cayman Islands
BROG LP LLC
Delaware
Burlington Resources International
 
Inc.
Delaware
Burlington Resources LLC
Delaware
Burlington Resources Offshore
 
Inc.
Delaware
Burlington Resources Oil & Gas
 
Company LP
Delaware
Burlington Resources Trading
 
LLC
Delaware
COG Acreage LP
Texas
COG Operating LLC
Delaware
COG Production LLC
Texas
COG Realty LLC
Texas
Concho Resources Inc.
Delaware
Conoco Development Services Inc.
Delaware
Conoco Funding Company
Nova Scotia
Conoco Petroleum Operations
 
Inc.
Delaware
ConocoPhillips (Grissik) Ltd.
Bermuda
ConocoPhillips (U.K.) Holdings Limited
United Kingdom
ConocoPhillips (U.K.) Marketing
 
and Trading
 
Limited
United Kingdom
ConocoPhillips (U.K.) Teesside
 
Operator Limited
United Kingdom
ConocoPhillips Alaska II, Inc.
Delaware
ConocoPhillips Alaska, Inc.
Delaware
ConocoPhillips Angola 36 Ltd.
Cayman Islands
ConocoPhillips Angola 37 Ltd.
Cayman Islands
ConocoPhillips ANS Marketing Company
Delaware
ConocoPhillips Asia Ventures
 
Pte. Ltd.
Singapore
ConocoPhillips Australia Investments
 
Pty Ltd
Australia
ConocoPhillips Australia Pacific
 
LNG Pty Ltd
Western Australia
ConocoPhillips Australia SH1 Pty Ltd
Western Australia
ConocoPhillips Bohai Limited
Bahamas
ConocoPhillips Canada (BRC) Partnership
Alberta
ConocoPhillips Canada E&P ULC
Alberta
ConocoPhillips Canada Marketing &
 
Trading ULC
Alberta
ConocoPhillips Canada Resources Corp.
Alberta
ConocoPhillips China Inc.
Liberia
ConocoPhillips Company
Delaware
ConocoPhillips Funding Ltd.
Bermuda
ConocoPhillips Hamaca B.V.
Netherlands
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2
Company Name
Incorporation
 
Location
ConocoPhillips Indonesia Holding Ltd.
British Virgin Islands
ConocoPhillips Libya Waha
 
Ltd.
Cayman Islands
ConocoPhillips Marine Containment Holdings
 
LLC
Delaware
ConocoPhillips Norge
Delaware
ConocoPhillips North Caspian Ltd.
Liberia
ConocoPhillips Norway Funding Ltd.
Bermuda
ConocoPhillips Petroleum Holdings
 
B.V.
Netherlands
ConocoPhillips Qatar Funding Ltd.
Cayman Islands
ConocoPhillips Qatar Ltd.
Cayman Islands
ConocoPhillips Sabah Gas Ltd.
Cayman Islands
ConocoPhillips Sabah Ltd.
Bermuda
ConocoPhillips Skandinavia AS
Norway
ConocoPhillips Surmont Partnership
Alberta
ConocoPhillips Transportation
 
Alaska, Inc.
Delaware
Inexco Oil Company
Delaware
Mongoose Minerals LLC
Delaware
Oliktok Pipeline Company
Delaware
Permian Delaware Enterprises
 
Holdings LLC
Texas
Phillips Coal Company
Nevada
Phillips International Investments,
 
Inc.
Delaware
Phillips Investment Company
 
LLC
Nevada
Phillips Petroleum International
 
Corporation LLC
Delaware
Phillips Petroleum International
 
Investment Company LLC
Delaware
Phillips Pt. Arguello Production Company
Delaware
Polar Tankers,
 
Inc.
Delaware
RSP Permian, Inc.
Delaware
RSP Permian, L.L.C.
Delaware
Sooner Insurance Company
Vermont
The Louisiana Land and Exploration Company
 
LLC
Maryland
d123121dex22
 
 
 
 
 
 
 
 
1
 
ConocoPhillips
 
2021 10-K
Exhibit 22
SUBSIDIARY GUARANTORS
 
OF GUARANTEED SECURITIES
Listed below are subsidiaries serving as an issuer or
 
guarantor,
 
as applicable, for outstanding publicly
 
held debt
securities.
Company Name
Incorporation Location
ConocoPhillips
Delaware
ConocoPhillips Company
Delaware
Burlington Resources LLC
Delaware
d123121dex231
 
Exhibit 23.1
CONSENT OF INDEPENDENT
 
REGISTERED
 
PUBLIC ACCOUNTING
 
FIRM
We consent to the incorporation by reference
 
in the following Registration Statements:
 
ConocoPhillips
 
Form S-3
 
File No. 333-240978
 
ConocoPhillips
 
Form S-4
 
File No. 333-130967
 
ConocoPhillips
 
Form S-4
 
File No. 333-250183
 
ConocoPhillips
 
Form S-8
 
File No. 333-130967
 
ConocoPhillips
 
Form S-8
 
File No. 333-98681
 
ConocoPhillips
 
Form S-8
 
File No. 333-116216
 
ConocoPhillips
 
Form S-8
 
File No. 333-133101
 
ConocoPhillips
 
Form S-8
 
File No. 333-159318
 
ConocoPhillips
 
Form S-8
 
File No. 333-171047
 
ConocoPhillips
 
Form S-8
 
File No. 333-174479
 
ConocoPhillips
 
Form S-8
 
File No. 333-196349
 
ConocoPhillips
 
Form S-8
 
File No. 333-250183
of our reports dated February 17, 2022, with respect to the consolidated financial statements of
ConocoPhillips, and the effectiveness of internal control over financial reporting of ConocoPhillips,
included in this Annual Report (Form 10-K) of ConocoPhillips for the year ended December 31, 2021.
/s/ Ernst & Young LLP
Houston, Texas
February 17, 2022
d123121dex232
Exhibit 23.2
DeGolyer and MacNaughton
5001
 
Spring
 
Valley Road
Suite 800 East
Dallas, Texas
 
75244
February 17, 2022
ConocoPhillips
 
925 N. Eldridge Parkway
Houston, Texas
 
77079
Ladies and Gentlemen:
We hereby consent to the use of the name DeGolyer and MacNaughton, to references to DeGolyer
and MacNaughton as an independent petroleum engineering consulting firm in ConocoPhillips’ Annual
Report on Form 10-K for the year ended December 31, 2021, under the “Part II” heading “Item 8. Financial
Statements and Supplementary Data” and subheading “Reserves Governance” and under the “Part IV”
heading “Item 15. Exhibits, Financial Statement Schedules” and subheading “Index to Exhibits,” and to the
inclusion of our process review letter report dated February 17, 2022 (our Report), as an exhibit to
ConocoPhillips’ Annual Report on Form 10-K for the year ended December 31, 2021. We also consent to
the incorporation by reference of our Report in the Registration Statements
 
filed by ConocoPhillips on
Form S-3 (File No. 333-240978), Form S-4 (File Nos. 333-130967 and 333-250183),
 
and Form S-8 (File Nos.
333-98681, 333 116216, 333-133101, 333 159318, 333 171047, 333-174479,
 
333-196349, 333-130967, and
333-250183).
 
Very truly yours,
/s/ DeGolyer and MacNaughton
DeGOLYER and MacNAUGHTON
 
Texas
 
Registered Engineering Firm F-716
d123121dex311
 
 
 
Exhibit 31.1
CERTIFICATION
I, Ryan M. Lance, certify that:
1.
I have reviewed this annual report on Form
 
10-K of ConocoPhillips;
2.
Based on my knowledge, this report does not contain
 
any untrue statement of a material fact or omit
 
to
state a material fact necessary to make the statements
 
made, in light of the circumstances under
 
which
such statements were made, not misleading with
 
respect to the period covered by this
 
report;
3.
Based on my knowledge, the financial statements,
 
and other financial information included in this
 
report,
fairly present in all material respects the financial
 
condition, results of operations and cash
 
flows of the
registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing
 
and maintaining disclosure
controls and procedures (as defined in Exchange
 
Act Rules 13a-15(e) and 15d-15(e)) and internal control
over financial reporting (as defined in Exchange
 
Act Rules 13a-15(f) and 15d-15(f)) for the registrant
 
and
have:
(a)
Designed such disclosure controls and procedures,
 
or caused such disclosure controls
 
and
procedures to be designed under our supervision,
 
to ensure that material information relating
 
to the
registrant, including its consolidated subsidiaries,
 
is made known to us by others within those
entities, particularly during the period in which this
 
report is being prepared;
(b)
Designed such internal control over financial reporting,
 
or caused such internal control over
financial reporting to be designed under our supervision,
 
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;
(c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and
 
presented in
this report our conclusions about the effectiveness of the
 
disclosure controls and procedures, as of
the end of the period covered by this report based
 
on such evaluation; and
(d)
Disclosed in this report any change in the registrant’s internal control
 
over financial reporting that
occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter
 
in
the case of an annual report) that has materially
 
affected, or is reasonably likely to materially
affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most
 
recent evaluation of
internal control over financial reporting, to the
 
registrant’s auditors and the audit committee of the
registrant’s board of directors (or persons performing the equivalent functions):
(a)
All significant deficiencies and material weaknesses
 
in the design or operation of internal control
over financial reporting which are reasonably
 
likely to adversely affect the registrant’s ability to
record, process, summarize and report financial
 
information; and
(b)
Any fraud, whether or not material, that
 
involves management or other employees who
 
have a
significant role in the registrant’s internal control over financial reporting.
February 17, 2022
 
 
/s/ Ryan M. Lance
 
 
 
Ryan M. Lance
 
 
Chairman and
 
Chief Executive Officer
d123121dex312
 
Exhibit 31.2
CERTIFICATION
I, William L. Bullock, Jr.,
 
certify that:
1.
I have reviewed this annual report on Form
 
10-K of ConocoPhillips;
2.
Based on my knowledge, this report does not contain
 
any untrue statement of a material fact or omit
 
to
state a material fact necessary to make the statements
 
made, in light of the circumstances under
 
which
such statements were made, not misleading with
 
respect to the period covered by this
 
report;
3.
Based on my knowledge, the financial statements,
 
and other financial information included in this
 
report,
fairly present in all material respects the financial
 
condition, results of operations and cash
 
flows of the
registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing
 
and maintaining disclosure
controls and procedures (as defined in Exchange
 
Act Rules 13a-15(e) and 15d-15(e)) and internal control
over financial reporting (as defined in Exchange
 
Act Rules 13a-15(f) and 15d-15(f)) for the registrant
 
and
have:
(a)
Designed such disclosure controls and procedures,
 
or caused such disclosure controls
 
and
procedures to be designed under our supervision,
 
to ensure that material information relating
 
to the
registrant, including its consolidated subsidiaries,
 
is made known to us by others within those
entities, particularly during the period in which this
 
report is being prepared;
(b)
Designed such internal control over financial reporting,
 
or caused such internal control over
financial reporting to be designed under our supervision,
 
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;
(c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and
 
presented in
this report our conclusions about the effectiveness of the
 
disclosure controls and procedures, as of
the end of the period covered by this report based
 
on such evaluation; and
(d)
Disclosed in this report any change in the registrant’s internal control
 
over financial reporting that
occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter
 
in
the case of an annual report) that has materially
 
affected, or is reasonably likely to materially
affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most
 
recent evaluation of
internal control over financial reporting, to the
 
registrant’s auditors and the audit committee of the
registrant’s board of directors (or persons performing the equivalent functions):
(a)
All significant deficiencies and material weaknesses
 
in the design or operation of internal
 
control
over financial reporting which are reasonably
 
likely to adversely affect the registrant’s ability to
record, process, summarize and report financial
 
information; and
(b)
Any fraud, whether or not material, that
 
involves management or other employees who
 
have a
significant role in the registrant’s internal control over financial reporting.
February 17, 2022
/s/ William L. Bullock, Jr.
William L. Bullock, Jr.
Executive Vice President and
Chief Financial Officer
d123121dex32
 
 
Exhibit 32
CERTIFICATIONS PURSUANT TO 18 U.S.C. SECTION 1350
In connection with the Annual Report of ConocoPhillips
 
(the Company) on Form 10-K for the period ended
December 31, 2021, as filed with the U.S.
 
Securities and Exchange Commission on the
 
date hereof (the
Report), each of the undersigned hereby certifies,
 
pursuant to 18 U.S.C. Section 1350, as adopted
 
pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002,
 
that to their knowledge:
(1)
The Report fully complies with the requirements
 
of Sections 13(a) or 15(d) of the Securities
Exchange Act of 1934; and
(2)
The information contained in the Report fairly
 
presents, in all material respects, the financial
condition and results of operations of the Company.
February 17, 2022
/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
d123121dex99
 
Exhibit 99
DeGolyer and MacNaughton
5001 Spring Valley
 
Road
Suite 800 East
Dallas, Texas
 
75244
February 17, 2022
ConocoPhillips
925 N. Eldridge Parkway
Houston, Texas
 
77079
Re: SEC Process Review
 
Ladies and Gentlemen:
Pursuant to your request,
 
DeGolyer and MacNaughton has performed a process
 
review of the
processes and controls used
 
by ConocoPhillips in preparing its internal estimates
 
of proved reserves, as of
December 31, 2021. This process review,
 
which is contemplated by Item
 
1202 (a)(8) of Regulation S–K of
the United States Securities and Exchange
 
Commission (SEC), has been performed specifically
 
to address
the adequacy and effectiveness
 
of ConocoPhillips’
 
internal processes and controls
 
relative to its
estimation of proved reserves
 
in compliance with Rules 4–10(a) (1)–(32) of Regulation
 
S–X of the SEC.
 
DeGolyer
 
and
 
MacNaughton
 
has
 
participated
 
as
 
an
 
independent
 
member
 
of
 
the
 
internal
ConocoPhillips Reserves Compliance Assessment Team in reviews and discussions with each of the relevant
ConocoPhillips business
 
units relative to
 
SEC proved
 
reserves estimation.
 
DeGolyer and MacNaughton
 
has
participated in the
 
review of all
 
major fields in all
 
countries in which
 
ConocoPhillips holds proved
 
reserves
worldwide.
 
ConocoPhillips has indicated that
 
these reserves represent over
 
90 percent of its estimated
 
total
proved reserves as of December 31, 2021.
 
The reviews
 
with ConocoPhillips’ technical staff
 
involved presentations
 
and discussions of a) basic
reservoir data,
 
including seismic data,
 
well-log data,
 
pressure and production tests, core analysis, pressure-
volume-temperature data
 
,
 
and production history,
 
b) technical methods employed
 
in SEC proved
 
reserves
estimation,
 
including
 
performance
 
analysis,
 
geology,
 
mapping,
 
and
 
volumetric
 
estimates,
 
c)
 
economic
analysis, and d) commercial
 
assessment, including the
 
legal basis for
 
the interest in
 
the reserves, primarily
related to
 
lease agreements
 
and other petroleum
 
license agreements,
 
such as concession
 
and production
sharing agreements.
 
ConocoPhillips
February 17, 2022
Page 2 of 2
A
 
field
 
examination
 
was
 
not
 
considered
 
necessary
 
for
 
the
 
purposes
 
of
 
this
 
review
 
of
ConocoPhillips’ processes and controls
 
.
It is
 
DeGolyer and
 
MacNaughton’s
 
opinion that
 
ConocoPhillips’
 
estimates
 
of proved
 
reserves for
the
 
properties
 
reviewed
 
were
 
prepared
 
by
 
the
 
use
 
of
 
recognized
 
geologic
 
and
 
engineering
 
methods
generally accepted by the petroleum industry.
 
The method or combination of methods used in the analysis
of
 
each
 
reservoir
 
was
 
tempered
 
by
 
ConocoPhillips’
 
experience
 
with
 
similar
 
reservoirs,
 
stage
 
of
development,
 
quality
 
and
 
completeness
 
of
 
basic
 
data,
 
and
 
production
 
history.
 
It
 
is
 
DeGolyer
 
and
MacNaughton’s
 
opinion that the general processes
 
and controls employed by
 
ConocoPhillips in estimating
its December 31,
 
2021, proved reserves for the
 
properties reviewed are in accordance with
 
the SEC reserves
definitions.
This
 
process
 
review
 
of
 
ConocoPhillips’
 
procedures
 
and
 
methods
 
does
 
not
 
constitute
 
a
 
review,
study,
 
or
 
independent
 
audit of
 
ConocoPhillips’
 
estimated
 
proved
 
reserves
 
and
 
corresponding
 
future
 
net
revenues. This
 
process review
 
is not intended
 
to indicate
 
that DeGolyer and
 
MacNaughton is
 
offering any
opinion as to the reasonableness of the reserves estimates
 
reported by ConocoPhillips.
DeGolyer
 
and
 
MacNaughton
 
is
 
an
 
independent
 
petroleum
 
engineering
 
consulting
 
firm
 
that
 
has
been
 
providing
 
petroleum
 
consulting
 
services
 
throughout
 
the
 
world
 
since
 
1936.
 
Neither
 
DeGolyer
 
and
MacNaughton nor any employee
 
who participated in this project has any
 
financial interest, including stock
ownership, in ConocoPhillips.
 
DeGolyer and MacNaughton’s
 
fees were not
 
contingent on
 
the results of
 
its
evaluation.
 
Very truly yours,
/s/ DeGolyer and MacNaughton
DeGOLYER and MacNAUGHTON
Texas
 
Registered Engineering Firm F-716
/s/ Dilhan Ilk
Dilhan Ilk, P.E.
Senior Vice President
DeGolyer and MacNaughton