10-K
CONOCOPHILLIPS (COP)
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)
Table of Contents
Page
Commonly Used Abbreviations
1
Item
Part I
1 and 2.
Business and Properties
2
Corporate Structure
2
Segment and Geographic Information
2
Alaska
4
Lower 48
5
Canada
7
Europe, Middle East and North Africa
8
Asia Pacific
10
Other International
13
Competition
15
Human Capital Management
15
General
19
1A.
Risk Factors
20
1B.
Unresolved Staff Comments
30
3.
Legal Proceedings
30
4.
Mine Safety Disclosures
30
Information About our Executive Officers
30
Part II
5.
Market for Registrant’s Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities
32
6.
[Reserved]
7.
Management’s Discussion and Analysis of Financial Condition and
Results of Operations
34
7A.
Quantitative and Qualitative Disclosures About Market Risk
71
8.
Financial Statements and Supplementary Data
74
9.
Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
178
9A.
Controls and Procedures
178
9B.
Other Information
178
9C.
Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
178
Part III
10.
Directors, Executive Officers and Corporate Governance
179
11.
Executive Compensation
179
12.
Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
179
13.
Certain Relationships and Related Transactions, and Director Independence
179
14.
Principal Accounting Fees and Services
179
Part IV
15.
Exhibits, Financial Statement Schedules
180
Signatures
186
Commonly Used Abbreviations
Table of Contents
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
Table of Contents
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
69.
Items 1 and 2.
Business and Properties
Corporate Structure
ConocoPhillips is an independent E&P company
headquartered in Houston, Texas
with operations and activities in
14 countries.
Our diverse, low cost of supply
portfolio includes resource-rich unconventional
plays in North
America; conventional assets in
North America, Europe, and Asia; LNG developments;
oil sands assets in Canada;
and an inventory of global conventional
and unconventional exploration
prospects.
On December 31, 2021, we
employed approximately 9,900
people worldwide and had total assets of
about $91 billion.
Total
company
production for the year was 1,567 MBOED.
ConocoPhillips was incorporated
in the state of Delaware on
November 16, 2001, in connection with, and in
anticipation of,
the merger between Conoco Inc. and Phillips
Petroleum Company.
The merger between Conoco
and Phillips was consummated on
August 30, 2002.
In April 2012, ConocoPhillips completed the separation
of the
downstream business into an independent,
publicly traded energy company,
Phillips 66.
On January 15, 2021, we completed the acquisition
of Concho Resources Inc. (Concho), an independent
oil and gas
exploration and production
company with operations in New Mexico
and West Texas
focused on the Permian
Basin.
For additional information related
to this transaction,
see
Note 3
.
On December 1, 2021, we completed our acquisition
of Shell Enterprises LLC’s (Shell) assets
in the Delaware Basin.
Assets acquired include approximately
225,000 net acres of producing properties
located entirely in Texas.
For
additional information related to
this transaction,
see
Note 3
.
Segment and Geographic Information
We manage our operations
through six operating segments,
defined by geographic region: Alaska;
Lower 48;
Canada; Europe, Middle East and
North Africa; Asia Pacific; and Other International.
For operating segment and
geographic information,
see Note 23
.
We explore for,
produce, transport and market
crude oil, bitumen, natural gas,
LNG and NGLs on a worldwide
basis.
At December 31, 2021, our operations
were producing in the U.S., Norway,
Canada, Australia, Indonesia,
Malaysia, Libya, China and Qatar.
Business and Properties
Table of Contents
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
Table of Contents
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
Table of Contents
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,
see Note 3
.
Business and Properties
Table of Contents
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.
See Note 3
.
Facilities
We operate and own,
with varying interests, centralized
condensate processing facilities
in Texas
and New Mexico
in support of our Eagle Ford, Delaware
and Midland assets.
Business and Properties
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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,
see Note 4
and
Note 10
.
Exploration
In 2019, we entered into an agreement
with 3D Oil to acquire a 75 percent interest
in and operatorship
of an
offshore Exploration Permit
(T/49P) located
in the Otway Basin, Australia.
We obtained an additional five percent
interest, increasing our 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
Table of Contents
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
Table of Contents
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
Table of Contents
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.
See Note 3
.
Venezuela
For discussion of our contingencies in Venezuela,
see Note 11
.
Other
Marketing Activities
Our Commercial organization
manages our worldwide commodity portfolio,
which mainly includes natural gas,
crude oil, bitumen, NGLs and LNG.
Marketing activities are performed
through offices in the U.S., Canada, Europe
and Asia.
In marketing our production, we attempt
to minimize flow disruptions, maximize
realized prices and
manage credit-risk exposure.
Commodity sales are generally made at
prevailing market prices at
the time of sale.
We also purchase and sell third
-party volumes to better position the company
to satisfy customer demand while
fully utilizing transportation and storage
capacity.
Natural Gas
Our natural gas production,
along with third-party purchased gas, is primarily marketed
in the U.S., Canada and
Europe.
Our natural gas is sold to a diverse
client portfolio which includes local distribution
companies; gas and
power utilities; large industrials; independent,
integrated or state
-owned oil and gas companies; as well as
marketing companies.
To reduce
our market exposure and
credit risk, we also transport natural
gas via firm and
interruptible transportation
agreements to major market hubs.
Crude Oil, Bitumen and Natural Gas Liquids
Our crude oil, bitumen and NGL revenues are derived from
production in the U.S., Canada, Asia, Africa and
Europe.
These commodities are primarily sold under contracts
with prices based on market indices, adjusted
for location,
quality and transportation.
LNG
LNG marketing efforts are
focused on equity LNG production
facilities located in Australia
and Qatar.
LNG is
primarily sold under long-term contracts with
prices based on market indices.
Business and Properties
Table of Contents
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
Table of Contents
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
Table of Contents
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.
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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
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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.
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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
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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
Note 7
.
If commodity
prices decrease relative to their current
levels, and as we continue to optimize
our investments and exercise
capital flexibility,
it is reasonably likely we could
incur future impairments to long-lived assets
used in operations,
investment in nonconsolidated
entities accounted for under the equity
method and unproved properties.
Although it is not reasonably practicable to
quantify the impact of any future impairments
or estimated change to
our unit-of-production
rates at this time, our results
of operations could be adversely affected
as a result.
Our business has been, and will continue to be, adversely affected
by the coronavirus (COVID-19) pandemic.
The COVID-19 pandemic and the measures put in place to
address it have negatively
impacted the global economy,
disrupted global supply chains, reduced global demand for
oil and gas and created significant
volatility and
disruption of financial and commodity markets.
Over the course of the pandemic, public health
officials have
recommended or mandated certain
precautions to mitigate
the spread of COVID-19, including limiting non-
essential gatherings of people, ceasing all non-essential
travel and issuing “social or
physical distancing” guidelines,
“shelter-in-place” orders and
mandatory closures or reductions in capacity
for non-essential businesses.
Although
some of these limitations and mandates have
been relaxed in certain jurisdictions,
others have been reinstated
in
areas that have experienced a resurgence
of COVID-19 cases and there is no guarantee
restrictions will not be
reimposed in the future.
Despite the increased availability
of vaccines in certain jurisdictions, the COVID
-19
pandemic may continue or worsen
during the upcoming months, including as a result of the emergence
of more
infectious variants of the virus,
vaccine hesitancy or increased business and
social activities, which may cause
governmental authorities to reinstate
restrictions.
As a result, the ongoing impact of the COVID-19 pandemic
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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.
See our Human Capital Management section within Item 1 and 2—Business and Properties
, for additional
information on how we have
been impacted and the steps we have
taken in response.
Our business is likely to continue to
be further negatively impacted by the COVID
-19 pandemic.
These impacts
could include but are not limited to:
●
Reduced demand for our products
as a result of reductions in travel
and commerce, whether related to
mandated restrictions or otherwise;
●
Disruptions in our supply chain due in part to scrutiny
or embargoing of shipments from infected
areas or
invocation of force majeure
clauses in commercial contracts
due to restrictions imposed as a result
of the
global response to the pandemic;
●
Failure of third-parties on which we rely,
including our suppliers, contract
manufacturers, contractors,
joint venture partners
and external business partners, to
meet their obligations to the company,
or
significant disruptions in their ability to do so,
which may be caused by their own financial or operational
difficulties or restrictions imposed in response
to the disease outbreak;
●
Reduced workforce productivity
caused by, but
not limited to, illness, travel
restrictions, quarantine, or
government mandates;
●
Increased challenges in retention
of personnel caused by vaccine hesitancy
and the resistance of some in
our workforce to comply with
workplace protocols necessary to ensure
the health and safety of our
workforce and minimize disruptions
to the business, such as vaccine and testing requirements,
or the use
of personal protective equipment; and
●
Voluntary or involuntary
curtailments to support oil prices or alleviate storage
shortages for our products.
Any of these factors, or other cascading
effects of the COVID-19 pandemic that
are not currently foreseeable,
could materially increase our costs,
negatively impact our revenues and
damage our financial condition, results of
operations, cash flows and liquidity position.
Despite the rollout of vaccines, the pandemic continues
to progress
and evolve, and the full extent and
duration of any such impacts cannot
be predicted at this time because of the
sweeping impact of the COVID-19 pandemic on daily life
around the world and a lack of certainty
as to if or when
conditions will return to pre-COVID
levels.
Unless we successfully develop resources, the scope
of our business will decline, resulting in an adverse impact to
our business.
As we produce crude oil and natural
gas from our existing portfolio,
the amount of our remaining reserves
declines.
If we are not successful in replacing the crude oil and
natural gas we produce with
good prospects for
future organic opportunities or through
acquisitions, our business will decline.
In addition, our ability to
successfully develop our reserves is dependent
on a number of factors, including our ability to
obtain and renew
rights to develop and produce hydrocarbons;
our success at reservoir optimization; our ability
to bring long-lead
time, capital intensive projects
to completion on budget and on schedule; and our ability
to efficiently and
profitably operate mature
properties.
If we are not successful in developing the resources
in our portfolio, our
financial condition and results of operations
may be adversely affected.
The exploration and production of oil and gas is a highly 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
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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
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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
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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
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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,
see the “Contingencies—Climate
Change” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations
.
Domestic and worldwide political and economic developments
could damage our operations and materially
reduce our profitability and cash flows.
Actions of the U.S., state, local
and foreign governments, through
sanctions, tax and other legislation, executive
order and commercial restrictions,
could reduce our operating profitability
both in the U.S. and abroad.
In certain
locations, restrictions on our operations;
leasing restrictions; special taxes
or tax assessments; and payment
transparency regulations
that could require us to disclose competitively
sensitive information or might
cause us to
violate non-disclosure laws of other countries
have been imposed or proposed by governments
or certain interest
groups.
For example, in 2020 a ballot initiative
known as the Fair Share Act was proposed
in the state of Alaska,
which, if enacted would have increased
the state’s
share of production revenues and
required producers to
publicly disclose additional financial information.
Although ultimately defeated,
similar initiatives may be
proposed and may be successful in the future.
In addition, we may face regulatory
changes in the U.S. including,
but not limited to, the enactment of tax
law changes that adversely affect
the fossil fuel industry,
new methane
emissions standards, restrictive
flaring requirements, and more stringent
environmental impact studies
and
reviews.
We also cannot rule out the possibility
of similar regulatory shifts and attendant
cost and market access
implications in other international jurisdictions.
One area subject to significant political and
regulatory activity is the use of hydraulic
fracturing, an essential
completion technique that facilitates
production of oil and natural gas
otherwise trapped in lower permeability
rock formations.
A range of local, state,
federal and national laws and
regulations currently govern or,
in some
hydraulic fracturing
operations, prohibit hydraulic
fracturing in some jurisdictions.
Although hydraulic fracturing
has been conducted safely for
many decades, a number of new laws, regulations
and permitting requirements are
under consideration which could result
in increased costs, operating restrictions,
operational delays or could
limit
the ability to develop oil and natural
gas resources.
Certain jurisdictions in which we operate have
adopted or are
considering regulations that could impose
new or more stringent permitting, disclosure
or other regulatory
requirements on hydraulic
fracturing or other oil and natural gas
operations, including subsurface water
disposal.
In addition, certain interest
groups have also proposed ballot initiatives
and constitutional amendments designed
to restrict oil and natural
gas development generally and hydraulic
fracturing in particular.
In the event that ballot
initiatives, local, state,
or national restrictions or prohibitions are
adopted and result in more stringent
limitations
on the production and development of oil and
natural gas in areas where we
conduct operations, we may
incur
significant costs to comply with
such requirements or may experience delays
or curtailment in the permitting or
pursuit of exploration,
development or production activities.
Such compliance costs and delays,
curtailments,
limitations or prohibitions could have
a material adverse effect
on our business, prospects, results of operations,
financial condition and liquidity.
Risk Factors
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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
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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
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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
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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.
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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.
See
Note 11
for a description of such
legal and administrative
proceedings.
Item 4.
Mine Safety Disclosures
Not applicable.
Information about our Executive
Officers
Name
Position Held
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.
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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.
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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
see “Item 1A—Risk
Factors – Our ability to execute our capital return program is subject to certain considerations.”
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
see “Item 1A—Risk Factors – Our ability to execute our capital return program is
subject to certain considerations.”
Table of Contents
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
Table of Contents
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
69.
The terms “earnings” and “loss” as used in Management’s
Discussion and Analysis refer to net income (loss)
attributable to ConocoPhillips.
Business Environment and Executive Overview
ConocoPhillips is one of the world’s
leading E&P companies based on both production and reserves
with
operations and activities in 14 countries.
Our diverse, low cost of supply portfolio
includes resource-rich
unconventional plays
in North America; conventional assets in North
America, Europe and Asia; LNG
developments; oil sands assets in Canada; and an
inventory of global conventional
and unconventional exploration
prospects.
Headquartered in Houston, Texas,
at December 31, 2021, we employed approximately
9,900 people
worldwide and had total
assets of $91 billion.
Completed Acquisitions
On January 15, 2021, we completed our acquisition
of Concho Resources Inc. (Concho), an independent
oil and gas
exploration and production
company with operations across
New Mexico and West Texas
in an all-stock
transaction for $13.1 billion.
See Note 3
.
In December 2021, we completed our acquisition
of Shell Enterprises LLC’s (Shell) assets in the
Delaware Basin in
an all-cash transaction for $8.7 billion after
customary adjustments.
Assets acquired include approximately
225,000 net acres of producing properties
located entirely in Texas.
See Note 3
.
See Item 1A “Risk Factors” for
further discussion of the risks related to integration of the assets acquired.
Overview
After an unprecedented 2020, the energy
landscape improved throughout
2021 with prices reaching pre-pandemic
levels in the second half of the year;
however,
we expect prices will continue to be cyclical
and volatile.
Our view is
that a successful business strategy
in the E&P industry must be resilient in lower price
environments while also
retaining upside during periods of higher prices.
As such,
we are unhedged, remain highly disciplined
in our
investment decisions and continually
monitor market fundamentals,
including OPEC Plus updates regarding
supply
guidance and inventory levels.
Although global oil demand improved through
2021, the global economic recovery
remains uncertain and subject to various
risk factors, including actions taken
to stem the proliferation
of COVID-
19.
Management’s Discussion and Analysis
Table of Contents
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.
See Note 5
.
We also demonstrated
our commitment to preserving our top-tier balance
sheet with an announcement to reduce the company’s
gross debt by $5 billion over five years
through a
combination of natural and accelerated
maturities.
As part of our ongoing portfolio high-grading
and optimization efforts,
in December 2021, we announced two
transactions in our Asia Pacific segment enhancing
our diverse portfolio.
This included notifying Origin Energy of
our intent to exercise
our preemption right to purchase
an additional 10 percent shareholding interest
in APLNG
for $1.645 billion, before customary
adjustments,
and the sale of our interests in Indonesia for
approximately $1.4
billion before customary adjustments.
In addition to those transactions, in January 2022, we entered
into a
divestiture agreement to sell our
interest in noncore assets within
our Lower 48 segment for $440 million.
These
transactions are expected to
close in the first half of 2022.
For more information on APLNG,
see Note 4
and for
more information on pending dispositions,
see Note 3
.
We announced an increase in our
disposition target to $4 to $5 billion in proceeds
by year-end 2023, with
approximately $2 billion sourced
from the Permian Basin.
As of year-end 2021, we have generated
$0.3 billion in
disposition proceeds.
The proceeds from these transactions will be used
in accordance with the company’s
priorities, including returns of capital to
shareholders and reduction of gross
debt.
In December 2021, we announced the initiation of a three-tier
return of capital framework.
This framework is
structured to continue delivering
a compelling, growing ordinary dividend and through
-cycle share repurchases.
It
includes the addition of a VROC tier.
The VROC tier will provide a flexible tool for
meeting our commitment of
returning greater than 30 percent
of cash from operating activities
during periods where commodity prices are
meaningfully higher than our planning price range.
We have set our expected
2022 total return of capital
from all
three tiers at approximately
$8 billion.
For more information on our three-tier return of capital framework, see
Capital Resources and Liquidity
.
Management’s Discussion and Analysis
Table of Contents
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
Table of Contents
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.
See
Note 5
.
See “Item 1A—Risk Factors Our ability to execute our capital return program is subject to certain
considerations.”
Management’s Discussion and Analysis
Table of Contents
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.
See Note 3
.
We continue to evaluate
our assets to determine whether they
compete for capital within
our
portfolio and optimize as necessary,
directing capital towards
the most competitive investments
and disposing of assets that don’t compete.
As such, in conjunction with our Shell Permian
acquisition announcement, we communicated
an increase in our planned disposition target
to $4
to $5 billion in proceeds by year-end
2023 as part of our ongoing portfolio high-grading
and
optimization efforts.
o
Add to our proved reserve base.
We primarily add to our proved
reserve base in three ways:
◾
Acquire interest in existing
or new fields.
◾
Apply new technologies and processes to
improve recovery from existing
fields.
◾
Successfully explore, develop and exploit
new and existing fields.
As required by current authoritative
guidelines, the estimated future date
when an asset will
reach the end of its economic life is based on
historical 12-month first-of-month
average prices
and current costs.
This date estimates when production
will end and affects the amount of
estimated reserves.
Therefore, as prices and
cost levels change from year to year,
the estimate
of proved reserves also changes.
Generally, our
proved reserves decrease as prices
decline and
increase as prices rise.
Management’s Discussion and Analysis
Table of Contents
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:
Management’s Discussion and Analysis
Table of Contents
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
Table of Contents
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
Note 6
and
Note 7
.
●
Effective tax rate
.
Our operations are in countries
with different tax rates
and fiscal structures.
Accordingly,
even in a stable commodity price and fiscal/regulatory
environment, our overall
effective tax
rate can vary significantly
between periods based on the “mix” of before-tax
earnings within our global
operations.
●
Fiscal and regulatory environment
.
Our operations can be affected
by changing economic, regulatory
and political
environments in the various countries
in which we operate, including civil unrest
or strained
relationships with governments
that may impact our operations or
investments.
These changing
environments could negatively
impact our results of operations, and further changes
to increase
government fiscal take
could have a negative
impact on future operations.
Our management carefully
considers the fiscal and regulatory
environment when evaluating
projects or determining the levels and
locations of our activity.
Outlook
Production and Capital
2022 operating plan capital budget
is $7.2 billion.
The plan includes funding for ongoing development
drilling
programs, major projects, exploration
and appraisal activities, base maintenance and
$0.2 billion for projects to
reduce the company’s
scope 1 and 2 emissions intensity and 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
Table of Contents
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.
See Note 3
.
●
A gain of $1,040 million after-tax on our
Cenovus Energy (CVE) common shares in 2021, as
compared to a
$855 million after-tax loss on those shares
in 2020.
●
Lower exploration expenses
due to:
o
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.
See Note 3
.
●
Lower impairments, primarily due to the absence
of impairments recognized in 2020 for
noncore assets in
our Lower 48 segment partially offset
by an impairment in our APLNG investment
included within our Asia
Pacific segment.
See Note 7
.
These increases in net income (loss) were partly
offset by:
●
Higher production and operating expenses
and taxes other than income taxes,
primarily due to higher
sales volumes.
●
Higher DD&A expenses caused by higher production
volumes, partially offset by lower rates
driven from
positive reserve revisions due to higher
commodity prices in 2021.
●
Absence of a $597 million after-tax gain
on our Australia-West
divestiture completed in May
2020.
●
Restructuring and transaction expenses
of $341 million after-tax associated
with the Concho and Shell
acquisitions in addition to mark-to-market
impacts on certain key employee
compensation programs.
Results of Operations
Table of Contents
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.
See
Note 12
.
Income Statement Analysis
Unless otherwise indicated, all results in Income Statement
Analysis are before-tax.
Sales and other operating revenues
increased 144 percent in 2021, mainly due to higher
realized commodity prices
and higher sales volumes.
Equity in earnings of affiliates increased
$400 million in 2021, primarily due to higher earnings driven
by higher
LNG and crude prices, partially offset by a higher
effective tax rate
related to equity method investments
in our
Europe, Middle East and North Africa segment
.
Gain on dispositions decreased $63 million in 2021, primarily due
to the absence of a $587 million gain related
to
our 2020 Australia-West
divestiture and a $179 million loss associated
with the sale of noncore assets in our Other
International segment.
The decreases were partially offset
by $200 million related to a FID bonus
associated with
our Australia-West
divestiture,
gains recognized for contingent
payments associated with previous
dispositions in
our Canada and Lower 48 segments and gains
on sales of certain noncore assets in our Lower 48 segment.
Other income (loss) increased $1.7 billion in 2021, primarily due
to a gain of $1,040 million on our CVE common
shares in 2021, as compared to a $855 million loss on
those shares in 2020.
See Note 5
.
Purchased commodities increased 125 percent
in 2021, primarily in line with higher gas and crude prices
and
volumes.
Production and operating expenses
increased $1,350 million in 2021, primarily in line with higher production
volumes.
Selling, general and administrative
expenses increased $289 million in 2021, primarily due to
transaction and
restructuring expenses associated
with our Concho acquisition and higher compensation and benefits
costs,
including mark-to-market impacts of certain
key employee compensation
programs.
Exploration expenses decreased
$1,113 million in 2021, primarily due to the absence of 2020 expenses
including
an $828 million impairment for the entire
carrying value of capitalized
undeveloped leasehold costs related
to our
Alaska North Slope Gas asset, the early cancellation of our
2020 winter exploration
program in Alaska, and
absence
of unproved property impairment and
dry hole expenses from 2020 for the Kamunsu
East Field in Malaysia.
2021
also saw lower dry hole expenses in Alaska.
Impairments decreased $139 million in 2021, primarily due
to the absence of impairments recognized
in 2020 for
noncore assets in our Lower 48 segment partially
offset by an impairment in our APLNG investment
included
within our Asia Pacific segment in 2021.
For additional information,
see Note 7
and
Note 13
.
Taxes
other than income taxes increased
$880 million in 2021, caused primarily by higher commodity prices and
higher Lower 48 sales volumes.
Foreign currency transaction
(gains) losses decreased $50 million in 2021 due to the
absence of derivative gains
and other remeasurements.
See
Note 17—Income Taxes
for information regardin
g
our income tax provision
and effective tax rate.
Results of Operations
Table of Contents
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
Table of Contents
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
Table of Contents
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 $648 million after-tax impairment
associated with the
carrying value of our Alaska North Slope Gas assets
and the early cancellation of our winter exploration
program.
See Note 6
.
●
Lower dry hole expenses.
Earnings were negatively
impacted by:
●
Higher taxes other than income taxes
primarily due to higher realized crude oil prices.
Production
Average production
decreased 1 MBOED in 2021 compared with 2020, primarily
due to:
●
Normal field decline.
The production decrease was partly
offset by:
●
Absence of curtailments.
●
Improved production at
our Western North Slope assets
as a result of net royalty interest
changes
associated with periodic redetermination.
●
Improved performance in the Greater
Prudhoe Area and Western
North Slope assets.
●
New wells online across the segment.
Results of Operations
Table of Contents
47
ConocoPhillips
2021 10-K
Lower 48
2021
2020
2019
Net Income (Loss) Attributable
to ConocoPhillips
($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.
See Note 12
.
The Lower 48 segment consists of operations
located in the contiguous U.S. and
the Gulf of Mexico.
During 2021,
the Lower 48 contributed 55 percent
of our consolidated liquids production
and 64 percent of our consolidated
natural gas production.
Net Income (Loss) Attributable to ConocoPhillips
Lower 48 reported earnings of $4,932 million in 2021, compared
with a loss of $1,122 million in 2020.
Earnings
were positively impacted by:
●
Higher realized crude oil, NGL and natural
gas prices.
●
Higher sales volumes due to our Concho acquisition and the absence
of production curtailments.
●
Lower impairments, primarily related
to developed properties in our noncore
assets which were written
down to fair value due to lower commodity
prices and development plan changes.
See
Note 7
and
Note
13
.
●
Higher gains on dispositions related to
selling our interests in certain noncore
assets.
See Note 3
.
Earnings were negatively
impacted by:
●
Higher DD&A expenses, production and operating
expenses and taxes other than
income taxes primarily
due to higher production volumes.
Partially offsetting the increase
in DD&A expenses were lower rates
from price-related reserve revisions.
●
Impacts resulting from our Concho acquisition,
including higher selling, general and administrative
expenses for transaction and restructuring
charges, as well as realized losses
on derivative settlements.
See
Note 3
and
Note 12
.
Production
Total
average production
increased 395 MBOED in 2021 compared with 2020, primarily
due to:
●
Higher volumes due to our Concho acquisition.
●
New wells online from our development programs
in Permian, Eagle Ford
and Bakken.
●
Absence of curtailments.
These production increases were partly
offset by:
●
Normal field decline.
Results of Operations
Table of Contents
ConocoPhillips
2021 10-K
48
Canada
2021*
2020*
2019**
Net Income (Loss) Attributable
to ConocoPhillips
($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 $246 million in 2021 associated
with the
sale of certain assets to CVE in 2017.
●
Higher sales volumes in our Surmont and Montney
assets.
Earnings were negatively impacted
by:
●
Higher production and operating expenses
primarily due to increased Surmont and Montney
production.
Production
Total
average production
increased 24 MBOED in 2021 compared with 2020.
The production increase was
primarily due to:
●
Improved well performance in
Surmont.
●
New wells online in Montney.
●
Production from our Kelt acquisition
completed in the third quarter of 2020.
●
Absence of curtailments.
Results of Operations
Table of Contents
49
ConocoPhillips
2021 10-K
Europe, Middle East and North Africa
2021
2020
2019
Net Income (Loss) Attributable
to ConocoPhillips
($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 $448 million in 2020.
Earnings were positively impacted
by:
●
Higher realized natural
gas, crude oil and NGL prices.
●
Higher LNG sales prices, reflected in equity in earnings
of affiliates.
●
Higher sales volumes of crude oil and LNG.
Earnings were negatively
impacted by:
●
Higher taxes.
●
Higher DD&A expenses and production and
operating expenses.
Partly offsetting the increase
in DD&A
expenses were lower rates
from positive reserve revisions.
Consolidated Production
Average consolidated
production increased 39 MBOED in 2021, compared
with 2020.
The consolidated production
increase was primarily due to:
●
Higher production in Libya due to the absence
of a forced shutdown of the Es Sider export
terminal and
other eastern export terminals.
●
Improved well performance in
Norway.
●
New production from Norway
drilling activities, including our Tor
II redevelopment project which
achieved full production in 2021.
These production increases were partly
offset by:
●
Normal field decline.
Results of Operations
Table of Contents
ConocoPhillips
2021 10-K
50
Asia Pacific
2021
2020
2019
Net Income (Loss) Attributable
to ConocoPhillips
($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
Note 4
and
Note 13
.
●
Absence of a $597 million after-tax gain
related to our Australia
-West divestiture.
See Note 3
.
●
Absence of sales volumes associated with Australia
-West.
Earnings were positively impacted
by:
●
Higher crude oil and natural gas
prices.
●
Higher LNG sales prices, reflected in equity in earnings
of affiliates.
●
An after-tax gain of $194 million
recognized for a FID bonus associated
with our Australia-West
divestiture.
For additional information related
to this FID bonus, see
Note 3
and
Note 11
.
Consolidated Production
Average consolidated
production decreased 16 MBOED in 2021, compared
with 2020.
The decrease was primarily
due to:
●
The divestiture of our Australia
-West assets that contributed
18 MBOED in 2020.
●
Normal field decline.
These production decreases were partly
offset by:
●
Development activity at Bohai Bay
in China.
●
First production in Malikai
Phase 2 and SNP Phase 2.
●
The absence of curtailments across the segment
and increased demand in Indonesia from coal supply
restrictions.
Results of Operations
Table of Contents
51
ConocoPhillips
2021 10-K
Other International
2021
2020
2019
Net Income (Loss) Attributable
to ConocoPhillips
($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.
See Note 3
.
●
Absence of a $29 million after-tax benefit to earnings
from the dismissal of arbitration
related to prior
operations in Senegal recognized
in the first quarter of 2020.
Changes to earnings were positively impacted
by:
●
Absence of exploration expenses
associated with dry hole costs and a full impairment of
capitalized
undeveloped leasehold costs in Colombia in the fourth
quarter of 2020.
Corporate and Other
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.
See Note 9
.
Corporate G&A expenses include
compensation programs and
staff costs.
These expenses increased by $117
million in 2021 compared with 2020, primarily due to restructuring
expenses associated with our Concho
acquisition and mark to market adjustments
associated with certain compensation programs
.
See Note 16
.
Technology includes
our investment in new technologies
or businesses, as well as licensing revenues.
Activities are
focused on both conventional
and tight oil reservoirs, shale gas,
heavy oil, oil sands, enhanced oil recovery as well
as LNG.
Earnings from Technology
increased by $51 million in 2021 compared with 2020,
primarily due to higher
licensing revenues.
The category “Other” includes certain foreign currency
transaction gains and losses,
environmental costs
associated with sites no longer in operation,
other costs not directly associated with an
operating segment,
premiums incurred on the early retirement
of debt,
holding gains or losses on equity securities, and
pension
settlement expense.
Earnings in “Other” increased by $1,875 million in 2021 compared
with 2020, primarily due
to a gain of $1,040 million on our CVE common shares
in 2021, compared with a $855 million loss in 2020.
Capital Resources and Liquidity
Table of Contents
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;
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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,
see the reserve table
disclosures contained in “Supplementary Data – Oil and Gas Operations.”
See “Item 1A—Risk Factors – Unless we
successfully develop our resources, the scope of our business will decline, resulting in an adverse impact to our
business.”
As discussed in the “Critical Accounting Estimates”
section, engineering estimates of proved
reserves are
imprecise; therefore, reserves
may be revised upward or
downward each year due to the impact of changes
in
commodity prices or as more technical data
becomes available on reservoirs.
It is not possible to reliably predict
how revisions will impact future reserve quantities.
Investing Activities
In 2021, we invested $5.3 billion
in capital expenditures.
Capital expenditures invested
in 2020 and 2019 were
$4.7 billion and $6.6 billion, respectively.
For information about our
capital expenditures and investments,
see the
“Capital Expenditures and Investments”
section.
In December 2021, we completed our acquisition
of Shell’s assets in
the Delaware Basin for cash consideration
of
approximately $8.7 billion after
customary adjustments.
We funded this transaction with cash
on hand.
We
completed our acquisition of Concho on January 15, 2021.
The assets acquired in the transaction included
$382
million of cash.
The net impact of these items is recognized
within “Acquisition
of businesses, net of cash
acquired” on our consolidated sta
tement of cash flows.
See Note 3.
In 2021, we announced a disposition target
of $4 to $5 billion in disposition proceeds by year-end
2023.
Only
proceeds from transactions announced
or initiated in the third quarter of 2021 or later
will be counted toward this
target.
The proceeds from these transactions
will be used in accordance with the company’s
priorities, including
returns of capital to shareholders
and reduction of gross debt.
To date,
we have achieved $0.3 billion from
the
sale of noncore assets in our Lower 48 segment.
Total
proceeds from asset dispositions
in 2021 were $1.7 billion.
Including the $250 million mentioned above, we
also received cash proceeds of $1.14 billion from
sales of our investment in CVE
common shares and $244 million
of contingent payments related
to dispositions completed before
2021.
See Note 3.
In May 2021, we announced
and began a paced monetization of our
investment in CVE with the plan to
direct proceeds toward
our existing
share repurchase program.
We expect to fully dispose
of our CVE common shares by early 2022, however,
the
sales pace will be guided by market conditions,
and we retain discretion to
adjust accordingly.
See Note 5.
Proceeds from asset sales in 2020 were $1.3
billion.
We received cash
proceeds of $765 million for the divestiture
of our Australia-West
assets and operations.
We also received proceeds of $359
million and $184 million from the
sale of our Niobrara interests
and Waddell Ranch interests
in the Lower 48, respectively.
Proceeds from asset sales in 2019 were $3.0
billion, including $2.2 billion for the sale of two ConocoPhillips
U.K.
subsidiaries and $350 million for the sale of our 30 percent
interest in the Greater
Sunrise Fields.
See Note 3.
We invest in short
-term investments as part of our
cash investment strategy,
the primary objective of which is to
protect principal, maintain liquidity
and provide yield and total returns;
these investments include time deposits,
commercial paper,
as well as debt securities classified as available
for sale.
Funds for short-term needs
to support
our operating plan and provide resiliency
to react to short-term price volatility
are invested in highly liquid
instruments with maturities within the year.
Funds we consider available to maintain
resiliency in longer term
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ConocoPhillips
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54
price downturns and to capture opportunities
outside a given operating plan may
be invested in instruments
with
maturities greater than one year.
See Note 12
.
Financing Activities
We have a revolving
credit facility totaling $6.0 billion, expiring
in May 2023.
Our revolving credit facility
may be
used for direct bank borrowings,
the issuance of letters of credit totaling
up to $500 million, or as support for our
commercial paper program.
The revolving credit facility is broadly
syndicated among financial institutions
and
does not contain any material
adverse change provisions or any
covenants requiring maintenance of specified
financial ratios or credit ratings.
The facility agreement contains
a cross-default provision relating
to the failure to
pay principal or interest
on other debt obligations of $200 million or more by
ConocoPhillips, or any of its
consolidated subsidiaries.
The amount of the facility is not subject to the redetermination
prior to its expiration
date.
Credit facility borrowings may
bear interest at a margin above
rates offered
by certain designated banks in the
London interbank market or
at a margin above the overnight federal
funds rate or prime rates
offered by certain
designated banks in the U.S.
The agreement calls for commitment
fees on available, but unused,
amounts.
The
agreement also contains early termination
rights if our current directors
or their approved successors
cease to be a
majority of the Board of Directors.
The revolving credit facility supports
ConocoPhillips Company’s ability to
issue up to $6.0 billion of commercial
paper, which
is primarily a funding source for short-term working
capital needs.
Commercial paper maturities are
generally limited to 90 days.
With no commercial paper outstanding
and no direct borrowings or letters
of credit,
we had access to $6.0 billion in available borrowing
capacity under the revolving credit facility
at December 31,
2021.
On January 15, 2021, we completed the acquisition of Concho
in an all-stock transaction. In the acquisition,
we
assumed Concho’s publicly
traded debt and in December 2020, we launched an offer
to exchange Concho’s
publicly traded debt for debt issued
by ConocoPhillips.
There were no impacts to ConocoPhillips’
credit ratings as a
result of the debt exchange.
In June 2021, we reaffirmed our
commitment to preserving our ‘A’
-rated balance
sheet by restating our intent
to reduce gross debt by $5 billion over
the next five years, driving a more resilient
and
efficient capital structure.
See
Note 9
and
Note 3
.
On January 25, 2021, S&P revised the industry risk assessment
for the E&P industry to ‘Moderately
High’ from
‘Intermediate’ based on a view of increasing
risks from the energy transition,
price volatility,
and weaker
profitability.
On February 11, 2021, S&P downgraded its rating
of our long-term debt from “A”
to “A
-” with a
“stable” outlook and affirmed
this rating in November 2021.
In October 2021, Moody’s affirmed its “A3”
rating of
our long-term debt and revised its outlook
from “stable” to “positive”.
In December 2021, Fitch affirmed its rating
of our long-term debt as “A”
with a “stable” outlook.
We do not have any
ratings triggers on any of our corporate
debt that would cause an automatic default,
and
thereby impact our access to liquidity,
upon downgrade of our credit ratings.
If our credit ratings are downgraded
from their current levels, it could
increase the cost of corporate
debt available to us and restrict
our access to the
commercial paper markets.
If our credit rating were to deteriorate
to a level prohibiting us from accessing
the
commercial paper market, we
would still be able to access funds under our revolving
credit facility.
Certain of our project-related
contracts, commercial contracts
and derivative instruments contain
provisions
requiring us to post collateral.
Many of these contracts and instruments
permit us to post either cash or letters
of
credit as collateral.
At December 31, 2021 and 2020, we had direct
bank letters of credit of $337 million and
$249
million, respectively,
which secured performance obligations
related to various purchase
commitments incident to
the ordinary conduct of business.
In the event of credit ratings downgrades,
we may be required to post
additional
letters of credit.
We have a universal
shelf registration statement
on file with the SEC under which we have the
ability to issue and
sell an indeterminate amount of various
types of debt and equity securities.
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ConocoPhillips
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Capital Requirements
For information about our capital
expenditures and investments,
see the “Capital Expenditures and Investments”
section.
Our debt balance at December 31, 2021, was $19.9 billion,
an increase of $4.6 billion from the balance at
December 31, 2020, driven by debt acquired as part
of the Concho acquisition.
Maturities of debt (including
payments for finance leases) due in
2022 of $1.1 billion will be paid from current cash
balances and cash generated
by operations.
See Note 9
.
In December 2021, we announced our expected 2022 return
of capital program and the initiation
of a three-tier
return of capital framework.
The framework is structured
to deliver a compelling, growing ordinary dividend
and
through-cycle share repurchases.
It includes the addition of a discretionary VROC tier.
The VROC will provide a
flexible tool for meeting our commitment
of returning greater than
30 percent of cash from operating
activities
during periods where commodity prices are meaningfully
higher than our planning price range.
We have set our
expected 2022 total capital returns
at approximately $8 billion,
consisting of distributions from each of the three
tiers.
Consistent with our commitment to
deliver value to shareholders,
in 2021, we paid $2.4 billion, $1.75 per share of
common stock, in ordinary dividends. This
was an increase over 2020 and 2019, when we paid $1.69 and
$1.34 per
share of common stock, respectively.
On February 3, 2022, we announced a quarterly dividend of $0.46 per share,
payable March 1, 2022, to stockholders
of record at the close of business on February
14, 2022.
On January 14,
2022, we paid the first VROC payment
of $0.20 per share to shareholders
of record as of January 3, 2022.
On
February 3, 2022, we announced a VROC of $0.30 per share,
payable on April 14, 2022, to stockholders
of record at
the close of business on March 31, 2022.
The ordinary dividend and VROC are subject to
numerous considerations
and will be determined and approved
each quarter by the Board of Directors.
We expect to announce the VROC
when we announce our ordinary
dividend, but the quarterly payouts
will be staggered from the ordinary dividend,
resulting in up to eight cash
distributions throughout the year.
In late 2016, we initiated our current
share repurchase program
with Board of Director’s authorization
of $25
billion of our common stock.
Share repurchases were $3.6
billion, $0.9 billion, and $3.5 billion in 2021, 2020, and
2019, respectively.
As of December 31, 2021, share repurchases
since the inception of our current program
totaled 247 million shares and $14 billion.
Repurchases are made at management’s
discretion, at prevailing prices,
subject to market conditions and
other factors.
For more information on factors
considered when determining the levels of returns
of capital
see “Item 1A—Risk
Factors – Our ability to execute our capital return program is subject to certain considerations.”
In addition to the priorities described above, we have
contractual obligations
to purchase goods and services of
approximately $11.8 billion.
We expect to fulfill $6 billion of these
obligations in 2022. These figures exclude
purchase commitments for jointly
owned fields and facilities where we are not
the operator.
Purchase obligations
of $5.3 billion are related to agreements
to access and utilize the capacity of third
-party equipment and facilities,
including pipelines and LNG product terminals, to
transport, process, treat and store
commodities.
Purchase
obligations of $5.3 billion are related
to market-based contracts
for commodity product purchases
with third
parties.
The remainder is primarily our net share of purchase
commitments for materials
and services for jointly
owned fields and facilities where we are the operator.
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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.
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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.
See Note 3
and
Note 9
.
Transactions
and balances reflecting activity between the Obligors
and Non-Obligated Subsidiaries
are presented
separately below:
Summarized Income Statement
Data
Millions of Dollars
2021
Revenues and Other Income
$
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
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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
Note 11
for information on contingencies.
Legal and Tax
Matters
We are subject to various
lawsuits and claims, including but not limited to matters
involving oil and gas royalty
and
severance tax payments,
gas measurement and valuation
methods, contract disputes,
environmental damages,
climate change, personal injury,
and property damage.
Our primary exposures for such matters
relate to alleged
royalty and tax underpayments
on certain federal, state
and privately owned properties,
claims of alleged
environmental contamination
and damages from historic operations,
and climate change.
We will continue to
defend ourselves vigorously
in these matters.
Our legal organization
applies its knowledge, experience, and professional
judgment to the specific characteristics
of our cases, employing a litigation management
process to manage and monitor the legal
proceedings against us.
Our process facilitates the
early evaluation and quantification
of potential exposures in individual cases.
This
process also enables us to track those cases
that have been scheduled for trial and/or
mediation.
Based on
professional judgment and experience
in using these litigation management
tools and available information
about
current developments in all our cases,
our legal organization regularly
assesses the adequacy of current accruals
and determines if an adjustment of existing
accruals, or establishment of new accruals, is
required.
See Note 17
.
Environmental
We are subject to the same numerous
international, federal,
state, and local environmental
laws and regulations
as other companies in our industry.
The most significant of these environmental
laws and regulations include,
among others, the:
●
U.S. Federal Clean Air Act, which governs
air emissions.
●
U.S. Federal Clean Water
Act, which governs discharges
to water bodies.
●
European Union Regulation for
Registration, Evaluation,
Authorization and Restriction of Chemicals
(REACH).
●
U.S. Federal Comprehensive
Environmental Response,
Compensation and Liability Act (CERCLA or
Superfund), which imposes liability on generators,
transporters and arrangers
of hazardous substances at
sites where hazardous substance
releases have occurred or are
threatening to occur.
●
U.S. Federal Resource
Conservation and Recovery
Act (RCRA), which governs the treatment,
storage, and
disposal of solid waste.
●
U.S. Federal Oil Pollution Act
of 1990 (OPA90), under which
owners and operators
of onshore facilities
and pipelines, lessees or permittees of an area in which an
offshore facility is located,
and owners and
operators of vessels
are liable for removal costs
and damages that result from a discharge
of oil into
navigable waters
of the U.S.
●
U.S. Federal Emergency Planning
and Community Right-to-Know Act (EPCRA),
which requires facilities to
report toxic chemical inventories
with local emergency planning committees
and response departments.
●
U.S. Federal Safe Drinking
Water Act, which governs
the disposal of wastewater
in underground injection
wells.
●
U.S. Department of the Interior regulations,
which relate to offshore oil and
gas operations in U.S. waters
and impose liability for the cost of pollution
cleanup resulting from operations, as
well as potential liability
for pollution damages.
●
European Union Trading
Directive resulting in European
Emissions Trading Scheme.
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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.
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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.
See Item 1A—Risk Factors – We expect to continue to incur substantial capital expenditures and operating costs as
a result of our compliance with existing and future environmental laws and regulations
and
Note 11
for information
on environmental litigatio
n.
Capital Resources and Liquidity
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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
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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.
See Item 1A—Risk Factors – Existing and future laws, regulations and internal initiatives relating to global climate
changes, such as limitations on GHG emissions may impact or limit our business plans, result in significant
expenditures, promote alternative uses of energy or reduce demand for our products
and
Note 11
for information
on climate change litigation.
Company Response to Climate
-Related Risks
The company has responded by putting
in place a Sustainable Development Risk Management
Standard covering
the assessment and registration
of significant and high sustainable development
risks based on their consequence
and likelihood of occurrence.
We have developed a
company-wide Climate Change Action
Plan with the goal of
tracking mitigation activities for
each climate-related risk included in the corporate
Sustainable Development Risk
Register.
The risks addressed in our Climate Change Action
Plan fall into four broad
categories:
●
GHG-related legislation and regulation.
●
GHG emissions management.
●
Physical climate-related
impacts.
●
Climate-related disclosure
and reporting.
Emissions are categorized
into three different
scopes.
Gross operated and net
equity Scope 1 and Scope 2 GHG
emissions help us understand our climate
transition risk.
●
Scope 1 emissions are direct GHG emissions from
sources that we control
or in which we have
ownership interest.
●
Scope 2 emissions are indirect GHG emissions
from the generation of purchased
electricity or steam that
we consume.
●
Scope 3 emissions are indirect emissions from
sources that we neither own nor control.
Capital Resources and Liquidity
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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.
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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.
See Note 1
for descriptions of our major accounting policies.
Certain of these accounting
policies involve judgments and uncertainties
to such an extent there is a reasonable
likelihood materially different
amounts would have been reported
under different conditions,
or if different assumptions had been
used.
These
critical accounting estimates are
discussed with the Audit and Finance Committee of the Board
of Directors at least
annually.
We believe the following discussions
of critical accounting estimates address
all important accounting
areas where the nature of accounting
estimates or assumptions is material
due to the levels of subjectivity and
judgment necessary to account for
highly uncertain matters or
the susceptibility of such matters to
change.
Oil and Gas Accounting
Accounting for oil and gas activity
is subject to special accounting rules unique to the oil
and gas industry.
The
acquisition of G&G seismic information, prior to
the discovery of proved reserves,
is expensed as incurred, similar
to accounting for research
and development costs.
However,
leasehold acquisition costs and exploratory
well
costs are capitalized
on the balance sheet pending determination of whether
proved oil and gas reserves
have
been recognized.
Property Acquisition Costs
At year-end 2021, we held $9.3 billion
of net capitalized unproved
property costs which consisted
primarily of
individually significant and pooled leaseholds, mineral
rights held in perpetuity by title ownership,
exploratory
wells currently being drilled, and to a lesser
extent, suspended exploratory
wells and capitalized interest.
This
amount increased by $6.9 billion at December 31, 2021 as compared
to December 31, 2020, primarily due to the
Concho and Shell Permian acquisitions
in the Permian Basin where we have an ongoing
significant and active
development program.
Outside of the Permian Basin, the remaining
$2.0 billion is concentrated
in 9 major
development areas.
Management periodically assesses our unproved
property for impairment based on the
results of exploration and
drilling efforts and the outlook for commercialization.
For individually significant leaseholds, management
periodically assesses for impairment based
on exploration and
drilling efforts to date.
For insignificant individual leasehold acquisition
costs, management exercises
judgment
and determines a percentage probability
that the prospect ultimately will fail to
find proved oil and gas reserves,
including estimates of future expirations,
and pools that leasehold information with others
in similar geographic
areas.
For prospects in areas with limited, or
no, previous exploratory
drilling, the percentage probability of
ultimate failure is normally judged
to be quite high.
This judgmental percentage is multiplied
by the leasehold
acquisition cost, and that product is
divided by the contractual period of the leasehold to
determine a periodic
leasehold impairment charge that is
reported in exploration expense.
This judgmental probability percentage
is
reassessed and adjusted throughout
the contractual period of the leasehold based on favorable
or unfavorable
exploratory activity on the leasehold or
on adjacent leaseholds, and leasehold impairment amortization
expense is
adjusted prospectively.
Exploratory Costs
For exploratory wells, drilling
costs are temporarily capitalized,
or “suspended,”
on the balance sheet, pending a
determination of whether potentially economic
oil and gas reserves have
been discovered by the drilling effort
to
justify development.
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If exploratory wells encounter
potentially economic quantities of oil and gas,
the well costs remain capitalized
on
the balance sheet as long as sufficient progress
assessing the reserves and the economic and operating
viability of
the project is being made.
The accounting notion of “sufficient
progress” is a judgmental area,
but the accounting
rules do prohibit continued capitalization
of suspended well costs on the expectation
future market conditions will
improve or new technologies will be found
that would make the development
economically profitable.
Often, the
ability to move into the development
phase and record proved
reserves is dependent on obtaining permits and
government or co-venturer
approvals, the timing of which is ultimately
beyond our control.
Exploratory well costs
remain suspended as long as we are actively pursuing
such approvals and permits, and believe they will be
obtained.
Once all required approvals
and permits have been obtained, the projects
are moved into the
development phase, and the oil and gas
reserves are designated as proved
reserves.
At year-end 2021, total suspended
well costs were $660 million, compared
with $682 million at year-end 2020.
For additional information on suspended
wells, including an aging analysis,
see Note 6
.
Proved Reserves
Engineering estimates of the quantities of proved
reserves are inherently imprecise and
represent only
approximate amounts because
of the judgments involved in developing
such information.
Reserve estimates are
based on geological and engineering assessments of in-place
hydrocarbon volumes,
the production plan, historical
extraction recovery and processing
yield factors, installed plant
operating capacity and approved
operating limits.
The reliability of these estimates at
any point in time depends on both the quality and quantity
of the technical and
economic data and the efficiency of extracting
and processing the hydrocarbons.
Despite the inherent imprecision in
these engineering estimates, accounting
rules require disclosure of “proved”
reserve estimates due to the importance
of these estimates to better
understand the perceived value
and future
cash flows of a company’s
operations.
There are several authoritative
guidelines regarding the engineering criteria
that must be met before estimated
reserves can be designated as “proved.”
Our geosciences and reservoir
engineering organization has
policies and procedures in place consistent
with these authoritative guidelines.
We
have trained and experienced
internal engineering personnel who estimate
our proved reserves held by
consolidated companies, as well as our share
of equity affiliates.
See Oil and Gas supplemental disclosures for
additional information.
Proved reserve estimates are
adjusted annually in the fourth quarter
and during the year if significant changes
occur, and
take into account
recent production and subsurface information
about each field.
Also, as required by
current authoritative guidelines,
the estimated future date
when an asset will reach the end of its economic life is
based on 12-month average prices
and current costs.
This date estimates when production
will end and affects
the amount of estimated reserves.
Therefore, as prices and cost
levels change from year to year,
the estimate of
proved reserves also changes.
Generally, our
proved reserves decrease as prices
decline and increase as prices
rise.
Our proved reserves include 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.
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Business Combination—Valuation
of Oil and Gas Properties
For recent transactions, management
applied the principles of acquisition accounting under FASB
ASC Topic 805
–
“Business Combinations” and allocated the purchase
price to assets acquired and liabilities assumed, based
on
their estimated fair values as
of the acquisition date.
Estimating the fair values involved
making various
assumptions, of which the most significant assumptions
relate to the fair values assigned
to proved and unproved
oil and gas properties.
Management utilized a discounted
cash flow approach, based on market participant
assumptions, and engaged third party
valuation experts in preparing fair value
estimates.
Significant inputs incorporated
within the valuation include future commodity price assumptions
and production
profiles of reserve estimates, the
pace of drilling plans, future operating and development
costs, inflation rates,
and discount rates using a market
-based weighted average
cost of capital determined at the
time of the
acquisition.
When estimating the fair value of unproved
properties, additional risk-weighting
adjustments are
applied to probable and possible reserves.
The assumptions and inputs incorporated
within the fair value estimates are
subject to considerable management
judgement and are based on industry,
market, and economic conditions prevalent
at the time of the acquisition.
Although we based these estimates on assumptions
believed to be reasonable, these estimates
are inherently
unpredictable and uncertain and actual results
could differ.
See Note 3
.
Impairments
Long-lived assets used in operations
are assessed for impairment whenever changes
in facts and circumstances
indicate a possible significant deterioration
in the future cash flows expected
to be generated by an
asset group.
If
there is an indication the carrying amount
of an asset may not be recovered,
a recoverability test
is performed
using management’s assumptions
for prices, volumes and future development
plans.
If the sum of the
undiscounted cash flows before
income-taxes is less than
the carrying value of the asset group, the carrying
value
is written down to estimated fair
value and reported as an impairment
in the periods in which the determination is
made.
Individual assets are grouped for
impairment purposes at the lowest level for
which there are identifiable
cash flows that are largely independent
of the cash flows of other groups of assets—generally
on a field-by-field
basis for E&P assets.
Because there usually is a lack of quoted market
prices for long-lived assets, the fair
value of
impaired assets is typically determined based
on the present values of expected
future cash flows using discount
rates and prices believed to
be consistent with those used by principal
market participants, or based on a multiple
of operating cash flow validated
with historical market transactions
of similar assets where possible.
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
Note 6
and
Note 7
.
Investments in nonconsolidated
entities accounted for under the equity
method are assessed for impairment
whenever changes in the facts and circumstances
indicate a loss in value has occurred.
Such evidence of a loss in
value might include our inability to recover
the carrying amount, the lack of sustained earnings
capacity which
would justify the current investment
amount, or a current fair value
less than the investment’s
carrying amount.
When such a condition is judgmentally determined
to be other than temporary,
an impairment charge is
recognized for the difference
between the investment’s
carrying value and its estimated fair
value.
When
determining whether a decline in value is other than
temporary,
management considers factors
such as the length
of time and extent of the decline, the investee’s
financial condition and near-term prospects,
and our ability and
intention to retain our
investment for a period that
will be sufficient to allow for any
anticipated recovery in the
market value of the investment.
Since quoted market prices are usually
not available, the fair value is typically
based on the present value of expected future
cash flows using discount
rates and prices believed to be consistent
with those used by principal market participants,
plus market analysis of comparable
assets owned by the
investee, if appropriate.
Differing assumptions could affect
the timing and the amount of an impairment of an
investment in any period.
See the “APLNG” section
of
Note 4
.
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Asset Retirement Obligations
and Environmental Costs
Under various contracts, permits
and regulations, we have material
legal obligations to remove
tangible
equipment and restore the land or
seabed at the end of operations at operational
sites.
Our largest asset removal
obligations involve
plugging and abandonment of wells, removal and disposal
of offshore oil and gas platforms
around the world, as well as oil and gas
production facilities and pipelines in Alaska.
Fair value is estimated using
a
present value approach,
incorporating assumptions about estimated
amounts and timing of settlements and
impacts of the use of technologies.
Estimating future asset removal
costs requires significant
judgement.
Most of
these removal obligations are
many years, or decades,
in the future and the contracts and regulations
often have
vague descriptions of what removal
practices and criteria must be met when the removal
event actually occurs.
The carrying value of our asset retirement
obligation estimate is sensitive
to inputs such as asset removal
technologies and costs, regulatory
and other compliance considerations,
expenditure timing, and other inputs into
valuation of the obligation,
including discount and inflation rates,
which are all subject to change between the time
of initial recognition of the liability and future settlement
of our obligation.
Normally, changes
in asset removal obligations
are reflected in the income statement
as increases or decreases to
DD&A over the remaining life of the assets.
However,
for assets at or nearing the end of their operations,
as well
as previously sold assets for which we retained
the asset removal obligation,
an increase in the asset removal
obligation can result in an immediate charge
to earnings, because any increase
in PP&E due to the increased
obligation would immediately
be subject to impairment, due to the low fair value
of these properties.
In addition to asset removal obligations,
under the above or similar contracts, permits
and regulations, we have
certain environmental-related
projects.
These are primarily related to remediation
activities required by Canada
and various states within the U.S.
at exploration and production
sites.
Future environmental remediation
costs are
difficult to estimate because they
are subject to change due to such factors
as the uncertain magnitude of cleanup
costs, the unknown time and extent of such
remedial actions that may be required,
and the determination of our
liability in proportion to that of other responsible
parties.
See Note 8
.
Projected Benefit Obligations
The actuarial determination of projected benefit
obligations and company
contribution requirements involves
judgment about uncertain future events,
including estimated retirement
dates, salary levels at retirement,
mortality rates, lump-sum election rates,
rates of return on plan assets,
future health care cost-trend rates,
and
rates of utilization of health
care services by retirees.
Due to the specialized nature of these
calculations, we
engage outside actuarial firms to assist
in the determination of these projected benefit
obligations and company
contribution requirements.
Ultimately,
we will be required to fund all vested
benefits under pension and
postretirement benefit plans
not funded by plan assets or investment
returns, but the judgmental assumptions
used in the actuarial calculations significantly affect
periodic financial statements and
funding patterns over time.
Projected benefit obligations
are particularly sensitive to the discount
rate assumption.
A 100 basis-point decrease
in the discount rate assumption
would increase projected benefit obligations
by $1.0 billion.
Benefit expense is
sensitive to the discount rate
and return on plan assets assumptions.
A 100 basis-point decrease in the discount
rate assumption would increase
annual benefit expense by $70 million, while a 100 basis-point
decrease in the
return on plan assets assumption would increase
annual benefit expense by $60 million.
In determining the
discount rate, we use yields
on high-quality fixed income investments
matched to the estimated benefit
cash flows
of our plans.
We are also exposed to the possibility
that lump sum retirement benefits taken
from pension plans
during the year could exceed the
total of service and interest components
of annual pension expense and
trigger accelerated recognition
of a portion of unrecognized net actuarial
losses and gains.
These benefit
payments are based on decisions by plan
participants and are therefore difficult
to predict.
In the event there is a
significant reduction in the expected years
of future service of present employees or the elimination
of the accrual
of defined benefits for some or all of their future
services for a significant number of employees,
we could
recognize a curtailment gain
or loss.
See Note 16
.
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Contingencies
A number of claims and lawsuits are made against
the company arising in the ordinary course
of business.
Management exercises
judgment related to accounting
and disclosure of these claims which includes losses,
damages, and underpayments associated
with environmental remediation,
tax, contracts, and
other legal disputes.
As we learn new facts concerning contingencies,
we reassess our position both with respect to amounts
recognized and disclosed considering changes
to the probability of additional losses and potential
exposure.
However,
actual losses can and do vary from estimates
for a variety of reasons
including legal, arbitration, or other
third-party decisions; settlement discussions;
evaluation of scope of damages; interpretation
of regulatory or
contractual terms; expected
timing of future actions; and proportion of liability
shared with other responsible
parties.
Estimated future costs related
to contingencies are subject to
change as events evolve and as additional
information becomes available
during the administrative and litigation
processes.
For additional information on
contingent liabilities, see the “Contingencies”
section within “Capital Resources and
Liquidity” and
Note 11
.
Income Taxes
We are subject to income taxation
in numerous jurisdictions worldwide.
We record deferred
tax assets and
liabilities to account for the expected
future tax consequences of events
that have been recognized
in our financial
statements and our tax
returns.
We routinely assess our deferred
tax assets and reduce such assets
by a valuation
allowance if we deem it is more likely than
not that some portion,
or all, of the deferred tax assets
will not be
realized.
In assessing the need for adjustments
to existing valuation allowances,
we consider all available positive
and negative evidence.
Positive evidence includes reversals
of temporary differences,
forecasts of future taxable
income, assessment of future business assumptions
and applicable tax planning strategies
that are prudent and
feasible.
Negative evidence includes losses
in recent years as well as the forecasts
of future net income (loss) in
the realizable period.
In making our assessment regarding
valuation allowances, we weight
the evidence based on
objectivity.
Numerous judgments and assumptions are
inherent in the determination of future taxable
income,
including factors such as future operating
conditions and the assessment of the effects
of foreign taxes
on our U.S.
federal income taxes
(particularly as related to prevai
ling oil and gas prices).
See Note 17
.
We regularly assess and, if required,
establish accruals for uncertain tax
positions that could result from
assessments of additional tax by taxing
jurisdictions in countries where we operate.
We recognize a tax
benefit
from an uncertain tax position when it
is more likely than not that the
position will be sustained upon examination,
based on the technical merits of the position.
These accruals for uncertain tax positions
are subject to a significant
amount of judgment and are reviewed
and adjusted on a periodic basis in light of changing facts
and
circumstances considering the progress
of ongoing tax audits, court proceedings,
changes in applicable tax laws,
including tax case rulings and legislative guidance,
or expiration of the applicable statute
of limitations.
See Note
17
regarding discussion of critical accounting
estimates on deferred
tax valuation allowances.
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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.
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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
Item 1A—Risk Factors
in this 2021 Annual Report on Form 10-K and any
additional risks described in our other filings with the SEC.
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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.
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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.
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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
.
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ConocoPhillips
2021 10-K
74
Item 8.
Financial Statements and Supplementary Data
ConocoPhillips
Index to Financial Statements
Page
Reports of Management
75
Reports of Independent Registered Public Accounting Firm
(PCAOB ID #
42
)
76
Consolidated Income Statement for the years ended December 31, 2021, 2020 and 2019
82
Consolidated Statement of Comprehensive Income for the years ended
December 31, 2021, 2020 and 2019
83
Consolidated Balance Sheet at December 31, 2021 and 2020
84
Consolidated Statement of Cash Flows for the years ended December 31, 2021, 2020 and 2019
85
Consolidated Statement of Changes in Equity for the years ended
December 31, 2021, 2020 and 2019
86
Notes to Consolidated Financial Statements
87
Supplementary Information
Oil and Gas Operations
149
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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
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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.
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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.
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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.
Table of Contents
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
Table of Contents
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.
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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.
See Note 23
.
●
Foreign Currency Translation
—Adjustments resulting from the
process of translating foreign
functional
currency financial statements
into U.S. dollars are included
in accumulated other comprehensive
loss in
common stockholders’ equity.
Foreign currency transaction
gains and losses are included in current
earnings.
Some of our foreign operations
use their local currency as the functional currency.
●
Use of Estimates
—The preparation of financial statements
in conformity with U.S. GAAP requires
management to make estimates
and assumptions that affect the
reported amounts of assets, liabilities,
revenues and expenses and the disclosures
of contingent assets and liabilities.
Actual results could differ
from these estimates.
●
Revenue Recognition
—Revenues associated with
the sales of crude oil, bitumen, natural gas,
LNG, NGLs
and other items are recognized
at the point in time when the customer obtains
control of the asset.
In
evaluating when a customer has control
of the asset, we primarily consider whether the transfer
of legal
title and physical delivery has occurred,
whether the customer has significant risks
and rewards of
ownership and whether the customer has
accepted delivery and a right to payment
exists.
These
products are typically sold at prevailing
market prices.
We allocate variable
market-based consideration
to deliveries (performance obligations)
in the current period as that consideration
relates specifically to
our efforts to transfer
control of current period deliveries
to the customer and represents
the amount we
expect to be entitled to in exchange
for the related products.
Payment is typically due within 30 days or
less.
Revenues associated with transactions
commonly called buy/sell contracts,
in which the purchase and
sale of inventory with the same counterparty
are entered into “in contemplation”
of one another, are
combined and reported net (i.e., on the same income
statement line).
●
Shipping and Handling Costs
—We typically incur shipping and handling
costs prior to control transferring
to the customer and account for
these activities as fulfillment costs.
Accordingly,
we include shipping and
handling costs in production and operating
expenses for production activities.
Transportation
costs
related to marketing activities
are recorded in purchased commodities.
Freight costs billed to customers
are treated as a component of the transaction
price and recorded as a component of revenue
when the
customer obtains control.
●
Cash Equivalents
—Cash equivalents are highly liquid, short-term
investments that are
readily convertible
to known amounts of cash and have
original maturities of 90 days or less from their date
of purchase.
They are carried at cost plus accrued interest,
which approximates fair value.
Notes to Consolidated Financial Statements
Table of Contents
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
Table of Contents
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.
See Note 6
.
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
Table of Contents
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.
See Note 8
.
Environmental expenditures
are expensed or capitalized,
depending upon their future economic benefit.
Expenditures relating to an existing
condition caused by past operations,
and those having no future
economic benefit, are expensed.
Liabilities for environmental
expenditures are recorded
on an
undiscounted basis (unless acquired through
a business combination, which we record
on a discounted
basis) when environmental assessments
or cleanups are probable and the costs
can be reasonably
estimated.
Recoveries of environmental
remediation costs from other parties
are recorded as assets
when their receipt is probable and estimable.
●
Impairment of Investments
in Nonconsolidated Entities
—Investments in nonconsolidated
entities are
assessed for impairment whenever changes
in the facts and circumstances
indicate a loss in value has
occurred.
When such a condition is judgmentally determined
to be other than temporary,
the carrying
value of the investment is written
down to fair value.
The fair value of the impaired investment
is based
on quoted market prices, if available,
or upon the present value of expected
future cash flows using
discount rates and prices believed
to be consistent with those used by
principal market participants, plus
market analysis of comparable
assets owned by the investee,
if appropriate.
●
Guarantees
—The fair value of a guarantee
is determined and recorded as a
liability at the time the
guarantee is given.
The initial liability is subsequently reduced as we are
released from exposure
under
the guarantee.
We amortize the guarantee
liability over the relevant time period, if one
exists, based on
the facts and circumstances surrounding
each type of guarantee.
In cases where the guarantee term
is
indefinite, we reverse the liability
when we have information
indicating the liability is essentially relieved
or amortize it over an appropriate
time period as the fair value of our guarantee
exposure declines over
time.
We amortize the guarantee
liability to the related income statement
line item based on the nature
of the guarantee.
When it becomes probable that we will have
to perform on a guarantee, we accrue
a
separate liability if it is reasonably estimable,
based on the facts and circumstances
at that time.
We
reverse the fair value liability
only when there is no further exposure under the
guarantee.
●
Share-Based Compensation
—We recognize share
-based compensation expense over
the shorter of the
service period (i.e., the stated period of time required
to earn the award) or the period beginning at
the
start of the service period and ending when an employee first
becomes eligible for retirement.
We have
elected to recognize expense
on a straight-line basis over the service period for
the entire award, whether
the award was granted
with ratable or cliff vesting.
Notes to Consolidated Financial Statements
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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
Table of Contents
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
Table of Contents
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.
See
Note 17.
From the acquisition date through
December 31, 2021, “Total Revenues
and Other Income” and “Net Income
(Loss) Attributable to ConocoPhillips”
associated with the acquired Concho business
were approximately $
6,571
million and $
2,330
million, respectively.
The results associated with the Concho business
for the same period
include a before- and after-tax
loss of $
305
million and $
233
million, respectively,
on the acquired derivative
contracts.
The before-tax loss is recorded
within “Total Revenues
and Other Income” on our consolidated
income
statement.
See Note 12.
Acquisition of Shell Permian Assets
In December 2021, we completed our acquisition
of Shell assets in the Permian based Delaware Basin.
The
accounting close date used for reporting
purposes was December 31, 2021.
Assets acquired include approximately
225,000
net acres and producing properties
located entirely in Texas.
Total
consideration for the transaction
was
$
8.7
billion.
Oil and gas properties were valued
using a discounted cash flow approach
incorporating market
participant and
internally generated price assumptions
,
production profiles,
and operating and development cost
assumptions.
The fair values determined for
accounts receivable, accounts
payable, and most other current
assets and current
liabilities were equivalent to the carrying
value due to their short-term
nature.
The total consideration
of $
8.7
billion was allocated to the identifiable
assets and liabilities based on their fair values
at the acquisition date.
Notes to Consolidated Financial Statements
Table of Contents
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
Table of Contents
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
Note 4
and
Note 7
.
Assets Sold
In 2020, we completed the sale of our Australia
-West asset and operations.
The sales agreement entitled us to a
$
200
million payment upon a final investment
decision (FID) of the Barossa development project.
On March 30,
2021, FID was announced and as such, we recognized
a $
200
million gain on disposition in the first quarter
of 2021.
The purchaser failed to pay the FID bonus
when due.
We have commenced an arbitration
proceeding against the
purchaser to enforce our contractual
right to the $
200
million, plus interest accruing from the due
date.
Results of
operations related to
this transaction are reflected in
our Asia Pacific segment.
See Note 11
.
In the second half of 2021, we sold our interests
in certain noncore assets in our Lower 48 segment for
approximately $
250
million after customary adjustments,
recognizing a before-tax gain
on sale of approximately
$
58
million.
We also completed the sale of our
noncore exploration
interests in Argentina,
recognizing a before-
tax loss on disposition of $
179
million.
Results of operations for
Argentina were reported
in our Other
International segment.
In 2021, we recorded contingent
payments of $
369
million relating to previous dispositions.
The contingent
payments are recorded
as gain on disposition on our consolidated
income statement and are
reflected within our
Canada and Lower 48 segments.
In our Canada segment, the
contingent payment, calculated and paid on a
quarterly basis, is $6 million CAD for every $1 CAD by which the WCS quarterly average crude price exceeds $52
CAD per barrel
.
The term for contingent
payments in our Canada segment ends on
May 16, 2022.
In our Lower 48
segment, the
contingent payment, paid on an annual basis, is calculated monthly at $7 million per month in which
the U.S. Henry Hub price is at or above $3.20 per MMBTU
.
The term for contingent payments
in our Lower 48
segment goes through 2023.
No
contingent payments were
recorded in 2020.
Planned Dispositions
In December 2021, we entered into
an agreement to sell two subsidiaries holding
our Indonesia assets and
operations to MedcoEnergi for
$
1.355
billion, before customary
adjustments, with an effective
date of January 1,
2021.
The subsidiaries hold our
54
percent interest in the Indonesia
Corridor Block Production Sharing Contract
(PSC) and a
35
percent shareholding interest
in the Transasia Pipeline
Company.
The net carrying value is
approximately $
0.4
billion, which consists primarily of PP&E.
The assets met the held for sale criteria in the fourth
quarter,
and as of December 31, 2021, we have reclassified
$
0.3
billion of PP&E to “Prepaid expenses and
other
current assets” and $
0.1
billion of noncurrent ARO to “Other accruals”
on our consolidated balance sheet.
The
before-tax earnings associated
with our Indonesia subsidiaries were $
604
million, $
394
million and $
512
million for
the years ended December 31, 2021, 2020 and 2019, respectively
.
This transaction is expected to close in
early
2022, subject to regulatory approvals
and other specific conditions precedent.
Results of operations for
the
subsidiaries to be sold are reported within our
Asia Pacific segment.
Notes to Consolidated Financial Statements
Table of Contents
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
Table of Contents
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
Table of Contents
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.
See Note 10
.
During the fourth quarter of 2021, Origin Energy Limited
agreed to the sale of
10
percent of their interest in
APLNG
for $
1.645
billion, before customary
adjustments.
ConocoPhillips announced in December 2021 that we were
exercising our preemption
right under the APLNG Shareholders Agreement
to purchase an additional
10
percent
shareholding interest in APLNG, subject
to government approvals.
The sales price associated with this preemption
right was determined to reflect
a relevant observable market
participant view of APLNG’s
fair value which was
below the carrying value of our existing
investment in APLNG.
Based on a review of the facts and circumstances
surrounding this decline in fair value,
we concluded in the fourth quarter of 2021 the impairment
was other than
temporary under the guidance of FASB
ASC Topic 323,
and the recognition of an impairment of our existing
investment was necessary.
Accordingly,
we recorded a noncash $
688
million, before-tax and
after-tax impairment
in the fourth quarter of 2021.
The impairment, which is included in the “Impairments” line on
our consolidated
income statement, had the
effect of reducing the carrying value
of our existing investment
to $
5,574
million as of
December 31, 2021.
This carrying value is included in the “Investments
and long-term receivables” line on our
consolidated balance sheet.
See Note 7
.
Notes to Consolidated Financial Statements
Table of Contents
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.
See Note 3
.
Loans
As part of our normal ongoing business operations
and consistent with industry practice,
we enter into numerous
agreements with other parties to pursue
business opportunities.
Included in such activity are loans to certain
affiliated and non-affiliated
companies.
At December 31, 2021, significant loans
to affiliated companies include $
114
million in project financing to QG3
which is recorded within the “Accounts
and notes receivable—related
parties” line on our consolidated balance
sheet.
QG3 secured project financing of $
4.0
billion in December 2005, consisting of $
1.3
billion of loans from
export credit agencies (ECA), $
1.5
billion from commercial banks
and $
1.2
billion from ConocoPhillips.
The
ConocoPhillips loan facilities have
substantially the same terms as the ECA
and commercial bank facilities.
On
December 15, 2011, QG3 achieved financial completion
and all project loan facilities became nonrecourse
to the
project participants.
Semi-annual
repayments began in January 2011 and
will extend through July 2022.
Note 5—Investment in Cenovus
Energy
Our investment in Cenovus Energy
(CVE) common shares is carried on our balance sheet
at fair value.
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.
See Note
13
.
Notes to Consolidated Financial Statements
Table of Contents
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
Table of Contents
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
Table of Contents
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
Note 4
and
Note 13
.
In our Lower 48 segment, we recorded
a credit to impairment of $
89
million due to a decreased ARO estimate
for a
previously sold asset, in which we retained
the ARO liability.
This was offset by recorded
impairments of $
84
million during the fourth quarter of 2021, related
to certain noncore assets
due to changes in development plans.
See Note 13
.
In our Europe, Middle East and North
Africa segment, we recorded a credit
to impairment of $
24
million due to
decreased ARO estimates on fields
in Norway which ceased production and
were fully depreciated in prior years.
2020
We recorded impairments
of $
813
million, primarily related to certain
noncore assets in the Lower 48.
Due to a
significant
decrease in the outlook for current and
long-term natural gas prices
in early 2020, we recorded
impairments of $
523
million, primarily for the Wind River Basin operations
area, consisting of developed
properties in the Madden Field and the Lost Cabin
Gas Plant, in the first quarter of 2020.
Additionally,
due
primarily to changes in development plans
solidified in the last quarter of 2020, we recognized
additional
impairments of $
287
million in the Lower 48 during the fourth
quarter.
See Note 13
.
2019
In the Lower 48, we recorded impairments
of $
402
million, primarily related to developed
properties in our
Niobrara asset which were written
down to fair value less costs
to sell.
See Note 3
.
Note 8—Asset Retirement
Obligations and Accrued Environmental
Costs
Asset retirement obligations
and accrued environmental costs
at December 31 were:
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
Table of Contents
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
Table of Contents
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
Table of Contents
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.
See Note 3.
We have a revolving
credit facility totaling $
6.0
billion with an expiration date
of May 2023.
Our revolving credit
facility may be used for direct
bank borrowings, the issuance of letters
of credit totaling up to $
500
million, or as
support for our commercial paper program.
The revolving credit facility is broadly
syndicated among financial
institutions and does not contain any
material adverse change provisions
or any covenants requiring maintenance
of specified financial ratios or credit ratings.
The facility agreement contains
a cross-default provision
relating to
the failure to pay principal or
interest on other debt obligations
of $
200
million or more by ConocoPhillips, or any
of its consolidated subsidiaries.
The amount of the facility is not subject to redetermination
prior to its expiration
date.
Credit facility borrowings may
bear interest at a margin above
rates offered
by certain designated banks in the
London interbank market or
at a margin above the overnight federal
funds rate or prime rates
offered by certain
designated banks in the U.S.
The facility agreement calls for
commitment fees on available,
but unused, amounts.
The agreement also contains early termination
rights if our current directors
or their approved successors
cease to
be a majority of the Board of Directors.
The revolving credit facility supports
our ability to issue up to $
6.0
billion of commercial paper,
which is primarily a
funding source for short-term
working capital needs.
Commercial paper maturities are generally
limited to
90
days
.
With no commercial paper outstanding
and
no
direct borrowings or letters
of credit, we had access to
$
6.0
billion in available borrowing capacity
under our revolving credit facility
at December 31, 2021.
We had
no
direct borrowings, letters
of credit, and $
300
million of commercial paper outstanding
as of December 31, 2020.
For information on Finance Leases,
see Note 15
.
The current credit ratings on our
long-term debt are:
●
Fitch: “A” with a “stable” outlook
.
●
S&P: “A-” with a “stable” outlook
.
●
Moody’s: “A3” with a “positive” outlook
.
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
Table of Contents
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.
See Note 11
for additional
information about environmental
liabilities.
Notes to Consolidated Financial Statements
Table of Contents
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.
See Note 17
,
for
additional information about income tax
-related contingencies.
Based on currently available information,
we believe it is remote that future
costs related to known
contingent
liability exposures will exceed
current accruals by an amount that
would have a material adverse
impact on our
consolidated financial statements.
As we learn new facts concerning contingencies,
we reassess our position both
with respect to accrued liabilities and other potential
exposures.
Estimates particularly sensitive to future
changes
include contingent liabilities recorded
for environmental
remediation, tax and legal matters.
Estimated future
environmental remediation
costs are subject to change due to
such factors as the uncertain
magnitude of cleanup
costs, the unknown time and extent of such
remedial actions that may be required,
and the determination of our
liability in proportion to that of other responsible
parties.
Estimated future costs
related to tax and legal
matters
are subject to change as events
evolve and as additional information
becomes available during the administrative
and litigation processes.
Environmental
We are subject to international,
federal, state and
local environmental laws
and regulations and record
accruals for
environmental liabilities based on
management’s best estimates
.
These estimates are based on currently
available
facts, existing technology,
and presently enacted laws and regulations,
taking into account stakeholder
and
business considerations.
When measuring environmental liabilities,
we also consider our prior experience in
remediation of contaminated
sites, other companies’ cleanup experience, and data
released by the U.S. EPA
or
other organizations.
We consider unasserted claims in our determination
of environmental liabilities,
and we
accrue them in the period they are both probable and
reasonably estimable.
Although liability of those potentially responsible
for environmental remediation
costs is generally joint and
several for federal
sites and frequently so for other
sites, we are usually only one of many companies
cited at a
particular site.
Due to the joint and several liabilities, we could
be responsible for all cleanup costs related
to any
site at which we have been designated
as a potentially responsible party.
We have been successful to
date in
sharing cleanup costs with other financially sound
companies.
Many of the sites at which we are potentially
responsible are still under investigation
by the EPA or
the agency concerned.
Prior to actual cleanup, those
potentially responsible normally assess the
site conditions, apportion responsibility and determine
the appropriate
remediation.
In some instances, we may have
no liability or may attain a settlement
of liability.
Where it appears
that other potentially responsible parties may
be financially unable to bear their proportional share,
we consider
this inability in estimating our potential liability,
and we adjust our accruals accordingly.
As a result of various
acquisitions in the past, we assumed certain environmental
obligations.
Some of these environmental obligations
are mitigated by indemnifications
made by others for our benefit, and some of the indemnifications
are subject to
dollar limits and time limits.
We are currently participating
in environmental assessments
and cleanups at numerous federal
Superfund and
comparable state and
international sites.
After an assessment of environmental
exposures for cleanup and other
costs, we make accruals on an
undiscounted basis (except
those acquired in a purchase business combination,
which we record on a discounted
basis) for planned investigation
and remediation activities for sites where
it is
probable future costs will be incurred
and these costs can be reasonably estimated.
We have not reduced
these
accruals for possible insurance recoveries.
In the future, we may be involved
in additional environmental
assessments, cleanups and proceedings.
See
Note 8
,
for a summary of our accrued environmental
liabilities.
Notes to Consolidated Financial Statements
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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.
See Note 4
and
Note 7
.
Notes to Consolidated Financial Statements
Table of Contents
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:
See Note 5
for a discussion of the carrying value and fair
value of our
investment in CVE common shares.
●
Investments in debt securities classified
as available for sale: The fair value
of investments in debt
securities categorized as Level
1 in the fair value hierarchy
is measured using exchange prices.
The fair
value of investments in debt
securities categorized as Level 2 in
the fair value hierarchy
is measured using
pricing provided by brokers
or pricing service companies that are corroborate
d
with market data.
See
Note
12
.
●
Loans and advances—related parties: The carrying
amount of floating-rate loans
approximates fair value.
The fair value of fixed-rate
loan activity is measured using market
observable data and is categorized
as
Level 2 in the fair value hierarchy.
See Note
4
.
●
Accounts payable (including related
parties) and floating-rate debt:
The carrying amount of accounts
payable and floating-rate
debt reported on the balance sheet approximates
fair value.
●
Fixed-rate debt: The estimated
fair value of fixed-rate
debt is measured using prices available from
a
pricing service that is corroborated
by market data; therefore,
these liabilities are categorized
as Level 2 in
the fair value hierarchy.
●
Commercial paper: The carrying amount of our commercial
paper instruments approximates
fair value
and is reported on the balance sheet as short-term
debt
.
The following table summarizes the
net fair value of financial instruments
(i.e., adjusted where the right of setoff
exists for commodity derivatives):
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
Table of Contents
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,
see Note 10
.
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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.
See Note 3
.
Notes to Consolidated Financial Statements
Table of Contents
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
see Note 3
.
During 2020, the valuation allowance movement
charged to earnings primarily related
to capital losses in Australia
and to the fair value measurement of our
CVE common shares that are not expected
to be realized.
Other
movements are primarily related
to valuation allowances on expiring
tax attributes.
On December 2, 2019, the Internal Revenue Service finalized
foreign tax credit regulations
related to the 2017 Tax
Cuts and Jobs Act.
Due to the finalization of these regulations,
in the fourth quarter of 2019 we recognized
$
151
million of net deferred tax
assets.
Correspondingly,
we recorded $
6,642
million of existing foreign tax
credit
carryovers where recognition
was previously considered to
be remote.
Present legislation still makes
their
realization unlikely and
therefore these credits have
been offset with a full valuation allowance.
At December 31, 2021, unremitted
income considered to be permanently reinvested
in certain foreign subsidiaries
and foreign corporate
joint ventures totaled
approximately $
4,384
million.
Deferred income taxes
have not been
provided on this amount, as we do not plan to
initiate any action that would require
the payment of income taxes.
The estimated amount of additional tax,
primarily local withholding tax, that would
be payable on this income if
distributed is approximately
$
219
million.
Notes to Consolidated Financial Statements
Table of Contents
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.
See Note 3
and
Note 11
.
At December 31, 2021, 2020 and 2019, accrued liabilities for
interest and penalties totaled $
47
million, $
46
million
and $
42
million, respectively,
net of accrued income taxes.
Interest and penalties resulted
in a reduction to
earnings of $
1
million in 2021, a reduction of $
4
million in 2020, and benefit to earnings of $
3
million in 2019.
We file tax returns
in the U.S. federal jurisdiction and
in many foreign and state
jurisdictions.
Audits in major
jurisdictions are generally complete as
follows: Canada (2016), U.S. (2017)
and Norway (2020).
Issues in dispute
for audited years and audits
for subsequent years are ongoing
and in various stages of completion in
the many
jurisdictions in which we operate around
the world.
Consequently,
the balance in unrecognized tax benefits
can
be expected to fluctuate from
period to period.
Within the next twelve months, we may
have audit periods close
that could significantly impact our total
unrecognized tax benefits.
It is reasonably possible such changes could be
significant when compared with our total
unrecognized tax benefits, but
the amount of change is not estimable.
In January 2022, the IRS closed the 2017 audit of our U.S. federal
income tax return.
As a result, in the first quarter
of 2022, we will recognize a previously
unrecognized $
475
million federal tax benefit
related to the recovery
of
outside tax basis previously offset
by a full reserve.
Notes to Consolidated Financial Statements
Table of Contents
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.
See Note 3.
During 2019, we received final partner approval
in Malaysia Block G to claim certain deepwater
tax credits.
As a
result, we recorded an income tax
benefit of $
164
million.
Notes to Consolidated Financial Statements
Table of Contents
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.
See Note 3
.
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
Table of Contents
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 Note 11
.
See
Note 3
and
Note 12
for additional information on cash
and non-cash changes to our consolidated
balance
sheet associated with our Concho acquisition.
Notes to Consolidated Financial Statements
Table of Contents
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
Table of Contents
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,
see Note 16
.
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
Note 23—Segment Disclosures and Related Information
:
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
Table of Contents
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
Table of Contents
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
Note 1
.
Intersegment sales are at
prices that approximate
market.
In 2021, we completed our acquisition of Concho,
an independent oil and gas exploration
and production company
with operations across New Mexico
and West Texas
as well as our acquisition of Shell’s
Permian assets in the Texas
Delaware Basin.
The accounting close date of the Shell transaction
,
used for reporting purposes, was December
31, 2021.
Results of operations for
Concho and assets acquired from Shell are included in
our Lower 48 segment.
Certain transaction and restructuring
costs associated with these acquisitions
are included in our Corporate and
Other segment.
See Note 3
.
Analysis of Results by Operating Segment
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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
Table of Contents
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.
Table of Contents
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
75
and is incorporated herein by
reference.
Report of Independent Registered
Public Accounting Firm
This report is included in Item 8 on page 76 and is incorporated
herein by reference.
Item 9B.
Other Information
None.
Item 9C.
Disclosure Regarding Foreign Jurisdictions that Prevent
Inspections
Not applicable.
Table of Contents
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.
Table of Contents
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
74
, 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
181
through 185, are filed as part of
this annual report.
Table of Contents
181
ConocoPhillips
2021 10-K
ConocoPhillips
Index to Exhibits
Incorporated by Reference
Exhibit
No.
Description
Exhibit
Form
File No.
2.1
Separation and Distribution Agreement Between ConocoPhillips and Phillips
2.1
8-K
001-32395
2.2†‡
Purchase and Sale Agreement, dated March 29, 2017, by and among
ConocoPhillips Company, ConocoPhillips Canada Resources Corp.,
ConocoPhillips Canada Energy Partnership, ConocoPhillips Western Canada
Partnership, ConocoPhillips Canada (BRC) Partnership, ConocoPhillips Canada
E&P ULC, and Cenovus Energy Inc.
2.1
10-Q
001-32395
2.3†‡
Asset Purchase and Sale Agreement Amending Agreement, dated as of May
16, 2017, by and among ConocoPhillips Company, ConocoPhillips Canada
Resources Corp., ConocoPhillips Canada Energy Partnership, ConocoPhillips
Western Canada Partnership, ConocoPhillips Canada (BRC) Partnership,
ConocoPhillips Canada E&P ULC, and Cenovus Energy Inc.
2.2
8-K
001-32395
2.4
Agreement and Plan of Merger, dated as of October 18, 2020, among
ConocoPhillips, Falcon Merger Sub Corp. and Concho Resources Inc.
2.1
8-K
001-32395
3.1
Amended and Restated Certificate of Incorporation.
3.1
10-Q
001-32395
3.2
Certificate of Designations of Series A Junior Participating Preferred Stock of
3.2
8-K
000-49987
3.3
Amended and Restated By-Laws of ConocoPhillips, as amended and restated
3.1
8-K
001-32395
3.4*
Restated Certificate of Incorporation of ConocoPhillips Company, dated
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
Description of Securities of the Registrant.
4.1
10-K
001-32395
10.1
1986 Stock Plan of Phillips Petroleum Company.
10.11
10-K
004-49987
10.2
1990 Stock Plan of Phillips Petroleum Company.
10.12
10-K
004-49987
10.5
Amendment and Restatement of ConocoPhillips Supplemental Executive
Retirement Plan, dated April 19, 2012.
10.14
10-Q
001-32395
10.7
Omnibus Securities Plan of Phillips Petroleum Company.
10.19
10-K
004-49987
10.10.1
Amended and Restated ConocoPhillips Key Employee Supplemental
Retirement Plan, dated January 1, 2020.
10.10.1
10-K
001-32395
10.10.2
Eighth Amendment to Retirement Plans as amended and restated effective
10.1
10-Q
001-32395
Table of Contents
ConocoPhillips
2021 10-K
182
10.11.1
Amended and Restated Defined Contribution Make-Up Plan of
ConocoPhillips—Title I, dated January 1, 2020.
10.11.1
10-K
001-32395
10.11.2
Amended and Restated Defined Contribution Make-Up Plan of
ConocoPhillips—Title II, dated January 1, 2020.
10.11.2
10-K
001-32395
10.12
2002 Omnibus Securities Plan of Phillips Petroleum Company.
10.26
10-K
000-49987
10.15
Deferred Compensation Plan for Non-Employee Directors of ConocoPhillips.
10.17
10-K
001-32395
10.16.1
Rabbi Trust Agreement dated December 17, 1999.
10.11
10-K
001-14521
10.16.2
Amendment to Rabbi Trust Agreement dated February 25, 2002.
10.39.1
10-K
000-49987
10.16.3
Phillips Petroleum Company Grantor Trust Agreement, dated June 1, 1998.
10.17.3
10-K
001-32395
10.16.4
First Amendment to the Trust Agreement under the Phillips Petroleum
Company Grantor Trust Agreement, dated May 3, 1999.
10.17.4
10-K
001-32395
10.16.5
Second Amendment to the Trust Agreement under the Phillips Petroleum
Company Grantor Trust Agreement, dated January 15, 2002.
10.17.5
10-K
001-32395
10.16.6
Third Amendment to the Trust Agreement under the Phillips Petroleum
Company Grantor Trust Agreement, dated October 5, 2006.
10.17.6
10-K
001-32395
10.16.7
Fourth Amendment to the Trust Agreement under the
ConocoPhillips Company Grantor Trust Agreement, dated May 1, 2012.
10.17.7
10-K
001-32395
10.16.8
Fifth Amendment to the Trust Agreement under the ConocoPhillips Company
Grantor Trust Agreement, dated May 20, 2015.
10.17.8
10-K
001-32395
10.17.1
ConocoPhillips Directors’ Charitable Gift Program.
10.40
10-K
000-49987
10.17.2
First and Second Amendments to the ConocoPhillips Directors’ Charitable Gift
10
10-Q
001-32395
10.19.1
Amended and Restated Key Employee Deferred Compensation Plan of
ConocoPhillips—Title I, dated January 1, 2020.
10.19.1
10-K
001-32395
10.19.2
Amended and Restated Key Employee Deferred Compensation Plan of
ConocoPhillips—Title II, dated January 1, 2020.
10.19.2
10-K
001-32395
10.20
Amendment and Restatement of ConocoPhillips Key Employee Change in
Control Severance Plan, effective January 1, 2014.
10.21
10-K
001-32395
10.20.1*
Amendment and Restatement of ConocoPhillips Key Employee Change in
Control Severance Plan, effective December 2, 2021.
10.22.1
2004 Omnibus Stock and Performance Incentive Plan of ConocoPhillips.
Schedule
14A
Proxy
000-49987
10.22.2
Form of Stock Option Award Agreement under the Stock Option and Stock
Appreciation Rights Program under the 2004 Omnibus Stock and Performance
Incentive Plan of ConocoPhillips.
10.26
10-K
001-32395
10.22.3
Form of Performance Share Unit Award Agreement under the Performance
Share Program under the 2004 Omnibus Stock and Performance Incentive
10.27
10-K
001-32395
10.23
Omnibus Amendments to certain ConocoPhillips employee benefit plans,
10.30
10-K
001-32395
Table of Contents
183
ConocoPhillips
2021 10-K
10.24
2009 Omnibus Stock and Performance Incentive Plan of ConocoPhillips.
Schedule
14A
Proxy
001-32395
10.25.1
2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips.
Schedule
14A
Proxy
001-32395
10.25.2
Form of Stock Option Award Agreement under the Stock Option and Stock
Appreciation Rights Program under the 2011 Omnibus Stock and Performance
Incentive Plan of ConocoPhillips, effective February 9, 2012.
10
10-Q
001-32395
10.25.4
Form of Performance Share Unit Agreement under the Restricted Stock
Program under the 2011 Omnibus Stock and Performance Incentive Plan of
ConocoPhillips, dated February 5, 2013.
10.26.6
10-K
001-32395
10.25.7
Form of Stock Option Award Agreement under the Stock Option and Stock
Appreciation Rights Program under the 2011 Omnibus Stock and Performance
Incentive Plan of ConocoPhillips, dated February 5, 2013.
10.26.9
10-K
001-32395
10.25.8
Form of Make-Up Grant Award Agreement under the 2011 Omnibus Stock and
Performance Incentive Plan of ConocoPhillips, dated January 1, 2012.
10.2
10-Q
001-32395
10.25.9
Form of Key Employee Award Agreement, as part of the ConocoPhillips Stock
Option Program granted under the 2011 Omnibus Stock and Performance
Incentive Plan of ConocoPhillips, dated February 18, 2014.
10.1
10-Q
001-32395
10.25.10
Form of Key Employee Award Agreement, as part of the ConocoPhillips Stock
Option Program granted under the 2014 Omnibus Stock and Performance
Incentive Plan of ConocoPhillips, dated February 16, 2016.
10.26.12
10-K
001-32395
10.25.12
Form of Performance Period IX Award Agreement, as part of the
ConocoPhillips Performance Share Program granted under the 2011 Omnibus
Stock and Performance Incentive Plan of ConocoPhillips, dated February 18,
10.3
10-Q
001-32395
10.25.14
Form of Performance Period X Award Agreement, as part of the
ConocoPhillips Performance Share Program granted under the 2011 Omnibus
Stock and Performance Incentive Plan of ConocoPhillips, dated February 18,
10.5
10-Q
001-32395
10.25.17
Form of Inducement Grant Award Agreement under the 2011 Omnibus Stock
and Performance Incentive Plan of ConocoPhillips, dated March 31, 2014.
10.11
10-Q
001-32395
10.25.18
Form of Performance Share Unit Award Terms and Conditions for
Performance Period 18, as part of the ConocoPhillips Performance Share
Program granted under the 2014 Omnibus Stock and Performance Incentive
Plan of ConocoPhillips, dated February 13, 2018.
10.26.24
10-K
001-32395
10.26.1
2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips.
10.1
8-K
001-32395
10.26.4
Form of Non-Employee Director Restricted Stock Units Terms and Conditions,
as part of the Deferred Compensation Plan for Non-Employee Directors of
ConocoPhillips, dated January 15, 2016.
10.3
10-Q
001-32395
10.26.7
Form of Key Employee Award Terms and Conditions, as part of the
ConocoPhillips Stock Option Program granted under the 2014 Omnibus Stock
and Performance Incentive Plan of ConocoPhillips, dated February 14, 2017.
10.1
10-Q
001-32395
Table of Contents
ConocoPhillips
2021 10-K
184
10.26.11
Form of Key Employee Award Terms and Conditions as part of the
ConocoPhillips Executive Restricted Stock Unit Program granted under the
2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated
10.27.12
10-K
001-32395
10.26.13
Form of Key Employee Award Terms and Conditions as part of the
ConocoPhillips Restricted Stock Program granted under the 2014 Omnibus
Stock and Performance Incentive Plan of ConocoPhillips, dated February 13,
10.27.14
10-K
001-32395
10.26.14
Form of Retention Award Terms and Conditions, 2017 revision, as part of the
Restricted Stock Unit Award, granted under the 2014 Omnibus Stock and
Performance Incentive Plan of ConocoPhillips.
10.27.15
10-K
001-32395
10.26.15
Form of Key Employee Award Terms and Conditions as part of the
ConocoPhillips Restricted Stock Unit Program granted under the 2014
Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated
10.27.16
10-K
001-32395
10.27
Amended and Restated 409A Annex to Nonqualified Deferred Compensation
Arrangements of ConocoPhillips, dated January 1, 2020.
10.27
10-K
001-32395
10.29
Amendment and Restatement of the Burlington Resources Inc. Management
Supplemental Benefits Plan, dated April 19, 2012.
10.9
10-Q
001-32395
10.30.1
Successor Trustee Agreement of the Deferred Compensation Trust Agreement
for Non-Employee Directors of ConocoPhillips dated July 31, 2020.
10.1
10-Q
001-32395
10.30.2
First Amendment to the Successor Trust Agreement of the Deferred
Compensation Trust Agreement for Non-Employee Directors of
ConocoPhillips, dated August 4, 2020.
10.2
10-Q
001-32395
10.31
Indemnification and Release Agreement between ConocoPhillips and Phillips
10.1
8-K
001-32395
10.32
Intellectual Property Assignment and License Agreement between
ConocoPhillips and Phillips 66, dated April 26, 2012.
10.2
8-K
001-32395
10.33
Tax Sharing Agreement between ConocoPhillips and Phillips 66, dated April
10.3
8-K
001-32395
10.34
Employee Matters Agreement between ConocoPhillips and Phillips 66, dated
10.4
8-K
001-32395
10.36
ConocoPhillips Clawback Policy dated October 3, 2012.
10.3
10-Q
001-32395
10.37
Term Loan Agreement, between ConocoPhillips, as borrower, ConocoPhillips
Company, as guarantor, Toronto Dominion (Texas) LLC, as administrative
agent and the banks party thereto, with TD Securities (USA) LLC, as lead
arranger and bookrunner, dated March 18, 2016.
10.1
8-K
001-32395
10.38
Company Retirement Contribution Make-Up Plan of ConocoPhillips, dated
10.39
10-K
001-32395
10.40
Form of Key Employee Award Terms and Conditions, as part of the
ConocoPhillips Targeted Variable Long Term Incentive Program, granted under
the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips,
10.1
10-Q
001-32395
10.41
ConocoPhillips Executive Restricted Stock Unit Program, dated February 11,
10.1
10-Q
001-32395
Table of Contents
185
ConocoPhillips
2021 10-K
10.42
Form of Retention Award Terms and Conditions, as part of the Restricted
Stock Unit Award, granted under the 2014 Omnibus Stock and Performance
Incentive Plan of ConocoPhillips.
10.1
10-Q
001-32395
10.43
Form of Inducement Grant Award Agreement under the 2014 Omnibus Stock
and Performance Incentive Plan of ConocoPhillips, dated January 15, 2021.
10.3
10-Q
001-32395
10.44
Compensation Resolutions regarding Matthew J. Fox, dated April 8, 2021.
10.1
10-Q
001-32395
10.45
Form of Aircraft Time Sharing Agreement by and between certain executives
and ConocoPhillips dated June 21, 2021.
10.2
10-Q
001-32395
10.46
Purchase and Sale Agreement, dated as of September 20, 2021, by and
between Shell Enterprises LLC and ConocoPhillips.
10.1
10-Q
001-32395
10.47*
Amendment and Restatement of ConocoPhillips Executive Severance Plan,
21*
List of Subsidiaries of ConocoPhillips.
22*
Subsidiary Guarantors of Guaranteed Securities.
23.1*
23.2*
Consent of DeGolyer and MacNaughton.
31.1*
Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the
Securities Exchange Act of 1934.
31.2*
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the
Securities Exchange Act of 1934.
32*
Certifications pursuant to 18 U.S.C. Section 1350.
99*
Report of DeGolyer and MacNaughton.
101.INS*
Inline XBRL Instance Document.
101.SCH*
Inline XBRL Schema Document.
101.CAL*
Inline XBRL Calculation Linkbase Document.
101.DEF*
Inline XBRL Definition Linkbase Document.
101.LAB*
Inline XBRL Labels Linkbase Document.
101.PRE*
Inline XBRL Presentation Linkbase Document.
104*
Cover Page Interactive
Data File (formatted
as Inline XBRL and contained in
Exhibit 101).
*
Filed herewith.
†
The schedules to this exhibit have been omitted pursuant to Item 601(b)(2) of Regulation S-K.
ConocoPhillips agrees to furnish
a copy of any schedule omitted from this exhibit to the SEC upon request.
‡ ConocoPhillips has previously been granted confidential treatment for certain portions
of this exhibit pursuant to Rule 24b-2
under the Securities Exchange Act of 1934, as amended.
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