2021
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form
OR
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company
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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.
2
2
2
4
5
7
8
10
13
15
15
19
1A.
20
1B.
30
3.
30
4.
30
30
Part II
5.
32
6.
[Reserved]
7.
34
7A.
71
8.
74
9.
178
9A.
178
9B.
178
9C.
178
Part III
10.
179
11.
179
12.
179
13.
179
14.
179
Part IV
15.
180
186
Commonly Used Abbreviations
1
ConocoPhillips 2021 10-K
Commonly Used Abbreviations
The following industry-specific, accounting and other terms, and abbreviations may be commonly used in this
report.
Currencies
Accounting
$ or USD
U.S. dollar
ARO
asset retirement obligation
CAD
Canadian dollar
ASC
accounting standards codification
EUR
Euro
ASU
accounting standards update
GBP
British pound
DD&A
depreciation, depletion and
amortization
Units of Measurement
FASB
Financial Accounting Standards
BBL
barrel
Board
BCF
billion cubic feet
FIFO
first-in, first-out
BOE
barrels of oil equivalent
G&A
general and administrative
MBD
thousands of barrels per day
GAAP
generally accepted accounting
MCF
thousand cubic feet
principles
MBOD
thousand barrels of oil per day
LIFO
last-in, first-out
MM
million
NPNS
normal purchase normal sale
MMBOE
million barrels of oil equivalent
PP&E
properties, plants and equipment
MMBOD
million barrels of oil per day
VIE
variable interest entity
MBOED
thousands of barrels of oil
equivalent per day
MMBOED
millions of barrels of oil
Miscellaneous
equivalent per day
DE&I
diversity, equity and inclusion
MMBTU
million British thermal units
EPA
Environmental Protection Agency
MMCFD
million cubic feet per day
ESG
Environmental, Social and
Governance
EU
European Union
Industry
FERC
Federal Energy Regulatory
BLM
Bureau of Land Management
Commission
CBM
coalbed methane
GHG
greenhouse gas
E&P
exploration and production
HSE
health, safety and environment
CCUS
carbon capture utilization and
storage
ICC
International Chamber of
Commerce
FEED
front-end engineering and design
ICSID
World Bank’s International
FPS
floating production system
Centre for Settlement of
FPSO
floating production, storage and
Investment Disputes
offloading
IRS
Internal Revenue Service
G&G
geological and geophysical
OTC
over-the-counter
JOA
joint operating agreement
NYSE
New York Stock Exchange
LNG
liquefied natural gas
SEC
U.S. Securities and Exchange
NGLs
natural gas liquids
Commission
OPEC
Organization of Petroleum
TSR
total shareholder return
Exporting Countries
U.K.
United Kingdom
PSC
production sharing contract
U.S.
United States of America
PUDs
proved undeveloped reserves
VROC
variable return of cash
SAGD
steam-assisted gravity drainage
WCS
Western Canada Select
WTI
West Texas Intermediate
Business and Properties
ConocoPhillips 2021 10-K
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,”
statements. The company does not undertake to update, revise or correct any forward-looking information unless
required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements
should be read in conjunction with the company’s disclosures under the headings “Risk Factors” beginning on page
20 and “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on pa
ge
Items 1 and 2. Business and Properties
Corporate Structure
ConocoPhillips is an independent E&P company headquartered in Houston, Texas with operations and activities in
14 countries. Our diverse, low cost of supply portfolio includes resource-rich unconventional plays in North
America; conventional assets in North America, Europe, and Asia; LNG developments; oil sands assets in Canada;
and an inventory of global conventional and unconventional exploration prospects. On December 31, 2021, we
employed approximately 9,900 people worldwide and had total assets of about $91 billion. Total company
production for the year was 1,567 MBOED.
ConocoPhillips was incorporated in the state of Delaware on November 16, 2001, in connection with, and in
anticipation of, the merger between Conoco Inc. and Phillips Petroleum Company. The merger between Conoco
and Phillips was consummated on August 30, 2002. In April 2012, ConocoPhillips completed the separation of the
downstream business into an independent, publicly traded energy company, Phillips 66.
On January 15, 2021, we completed the acquisition of Concho Resources Inc. (Concho), an independent oil and gas
exploration and production company with operations in New Mexico and West Texas focused on the Permian
Basin. For additional information related to this transaction,
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,
Segment and Geographic Information
We manage our operations through six operating segments, defined by geographic region: Alaska; Lower 48;
Canada; Europe, Middle East and North Africa; Asia Pacific; and Other International. For operating segment and
geographic information,
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on a worldwide
basis. At December 31, 2021, our operations were producing in the U.S., Norway, Canada, Australia, Indonesia,
Malaysia, Libya, China and Qatar.
Business and Properties
3
ConocoPhillips 2021 10-K
The information listed below appears in the “Supplementary Data - Oil and Gas Operations” disclosures following
the Notes to Consolidated Financial Statements and is incorporated herein by reference:
●
Proved worldwide crude oil, NGLs, natural gas and bitumen reserves.
●
Net production of crude oil, NGLs, natural gas and bitumen.
●
Average sales prices of crude oil, NGLs, natural gas and bitumen.
●
Average production costs per BOE.
●
Net wells completed, wells in progress and productive wells.
●
Developed and undeveloped acreage.
The following table is a summary of the proved reserves information included in the “Supplementary Data - Oil and
Gas Operations” disclosures following the Notes to Consolidated Financial Statements. Approximately 86 percent
of our proved reserves are in countries that belong to the Organization for Economic Cooperation and
Development. Natural gas reserves are converted to BOE based on a 6:1 ratio: six MCF of natural gas converts to
one BOE. See Management’s Discussion and Analysis of Financial Condition and Results of Operations for a
discussion of factors that will enhance the understanding of the following summary reserves table.
Millions of Barrels of Oil Equivalent
Net Proved Reserves at December 31
2021
2020
2019
Crude oil
Consolidated operations
2,964
2,051
2,562
Equity affiliates
63
68
73
Total Crude Oil
3,027
2,119
2,635
Natural gas liquids
Consolidated operations
644
340
361
Equity affiliates
33
36
39
Total Natural Gas Liquids
677
376
400
Natural gas
Consolidated operations
1,523
1,011
1,209
Equity affiliates
617
621
736
Total Natural Gas
2,140
1,632
1,945
Bitumen
Consolidated operations
257
332
282
Total Bitumen
257
332
282
Total consolidated operations
5,388
3,734
4,414
Total equity affiliates
713
725
848
Total company
6,101
4,459
5,262
Business and Properties
ConocoPhillips 2021 10-K
Alaska
The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas and NGLs. We
are the largest crude oil producer in Alaska and have major ownership interests in two of North America’s largest
oil fields located on Alaska’s North Slope: Prudhoe Bay and Kuparuk. We also have a 100 percent interest in the
Alpine Field, located on the Western North Slope. Additionally, we are one of Alaska’s largest owners of state,
federal and fee exploration leases, with approximately 1.3 million net undeveloped acres at year -end 2021. Alaska
operations contributed 19 percent of our consolidated liquids production and 1 percent of our consolidated
natural gas production.
2021
Crude Oil
NGL
Natural Gas
Total
Interest
Operator
MBD
MBD
MMCFD
MBOED
Average Daily Net Production
Greater Prudhoe Area
36.1
%
Hilcorp
67
16
12
85
Greater Kuparuk Area
89.2-94.7
ConocoPhillips
73
-
2
73
Western North Slope
100.0
ConocoPhillips
38
-
2
39
Total Alaska
178
16
16
197
Greater Prudhoe Area
The Greater Prudhoe Area includes the Prudhoe Bay Field and five satellite fields, as well as the Greater Point
McIntyre Area fields. Prudhoe Bay, the largest conventional oil field in North America, is the site of a large
waterflood and enhanced oil recovery operation, supported by a large gas and water processing operation.
Prudhoe Bay’s western satellite fields are Aurora, Borealis, Polaris, Midnight Sun and Orion, while the Point
McIntyre, Niakuk, Raven, Lisburne and North Prudhoe Bay State fields are part of the Greater Point McIntyre Area.
Field installations include seven production facilities, two gas plants, two seawater plants and a central power
station.
In September 2021, rotary drilling commenced after 18 months of no drilling, resulting in four wells drilled and
brought online. To help offset decline, efforts were focused on increasing rate through well work, capacity
enhancements, less downtime, and NGL production.
Greater Kuparuk Area
We operate the Greater Kuparuk Area, which consists of the Kuparuk Field and four satellite fields: Tarn, Tabasco,
Meltwater and West Sak. Kuparuk is located 40 miles west of the Prudhoe Bay Field. Field installations include
three central production facilities which separate oil, natural gas and water, as well as a seawater treatment plant.
Development drilling at Kuparuk consists of rotary-drilled wells and horizontal multi-laterals from existing well
bores utilizing coiled-tubing drilling.
We operated a coiled-tubi ng drilling rig in the fourth quarter of 2021, resulting in five operated wells drilled and
brought online.
Western North Slope
On the Western North Slope, we operate the Colville River Unit, which includes the Alpine Field and three satellite
fields: Nanuq, Fiord and Qannik. The Alpine Field is located 34 miles west of the Kuparuk Field. Field installations
include one central production facility which separates oil, natural gas and water.
The Greater Mooses Tooth Unit is the first unit established entirely within the National Petroleum Reserve Alaska
(NPR-A). In 2017, we began construction in the unit with two drill sites: Greater Mooses Tooth #1 (GMT-1) and
Greater Mooses Tooth #2 (GMT-2). GMT-1 achieved first oil in 2018 and completed drilling in 2019. In 2021, the
third and final construction season for GMT-2 was successfully completed, and drilling operations commenced
during the second quarter. First oil for GMT-2 was achieved in the fourth quarter of 2021, as planned.
During 2021, we operated a conventional rotary rig and an extended reach drilling rig in the Western North Slope,
resulting in seven operated wells drilled and brought online.
Business and Properties
5
ConocoPhillips 2021 10-K
Exploration
Appraisal of the Willow Discovery, located 36 miles from Nuiqsut in the Bear Tooth Unit in the NPR-A, was
conducted in 2020. There was no appraisal activity in 2021. In August 2021, an Alaska federal judge vacated the
U.S. government’s approval granted to our planned Willow project previously approved by the BLM in October
2020. The Department of Justice did not appeal the decision and neither did we. We are actively supporting the
BLM and Department of Interior as they conduct the Supplemental Environmental Impact Statement process to
address issues highlighted by the federal district court. In the interim, we are continuing with FEED work in service
of a final investment decision.
The Stony Hill 1 well located to the east of the Greater Mooses Tooth Unit within the NPR-A was plugged and
abandoned in 2021 and expensed as a dry hole.
A 3D seismic survey covering 234 square miles was completed in 2020 on state and federal lands. We are currently
evaluating this seismic data for future exploration opportunities.
In late 2021, the Coyote Brookian topset exploration prospect in the Kuparuk River Unit was tested with a near
vertical sidetrack from an existing wellbore. The well was fracture stimulated and will undergo well testing early in
2022 to confirm longer term deliverability.
Transportation
We transport the petroleum liquids produced on the North Slope to Valdez, Alaska through an 800-mile pipeline
that is part of Trans -Alaska Pipeline System (TAPS). We have a 29.5 percent ownership interest in TAPS, and we
also have ownership interests in and operate the Alpine, Kuparuk and Oliktok pipelines on the North Slope.
Our wholly owned subsidiary, Polar Tankers, Inc., manages the marine transportation of our North Slope
production, using five company-owned, double -hulled tankers, and charters third-party vessels, as necessary. The
tankers deliver oil from Valdez, Alaska, primarily to refineries on the west coast of the U.S.
Lower 48
The Lower 48 segment consists of operations located in the 48 contiguous U.S. states and the Gulf of Mexico. The
segment is organized into the Permian and Gulf Coast and Rockies business units with a portfolio of low cost of
supply, short cycle time, resource-rich unconventional plays, and conventional production from legacy assets.
Based on 2021 production volumes, the Lower 48 is the company’s largest segment and contributed 55 percent of
our consolidated liquids production and 64 percent of our consolidated natural gas production.
In 2021, we completed two acquisitions significantly increasing our Permian position in the Lower 48. On January
15, 2021, we completed the acquisition of Concho adding complementary acreage across the Delaware and
Midland basins. On December 1, 2021, we completed the acquisition of Shell’s Delaware Basin position adding
significant Texas acreage in the Delaware Basin. The accounting close date used for reporting purposes of the Shell
transaction was December 31, 2021. For additional information related to these acquisitions,
Business and Properties
ConocoPhillips 2021 10-K
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
262
38
853
442
Eagle Ford
116
53
251
211
Bakken
59
16
117
94
Gulf Coast and Rockies—Other
10
3
119
33
185
72
487
338
Total Lower 48
447
110
1,340
780
At December 31, 2021, we held 10.8 million net acres of onshore conventional and unconventional acreage in the
Lower 48, the majority of which is either held by production or owned by the company. Our unconventional
holdings total approximately 2 million net acres in the following areas:
●
560,000 net acres in the Bakken, located in North Dakota and eastern Montana.
●
200,000 net acres in the Eagle Ford, located in South Texas.
●
654,000 net acres in the Permian—Delaware Basin, located in West Texas and southeastern New Mexico.
●
266,000 net acres in the Permian—Midland Basin, located in West Texas.
●
293,000 net acres in other areas with unconventional potential.
The majority of our 2021 onshore production activities were centered on continued development of assets, with
an emphasis on areas with low cost of supply, particularly in growing unconventional plays. Our major focus in
2021 included the following areas:
●
Delaware Basin—We operated six rigs and two frac crews on average during 2021, resulting in 92
operated wells drilled and 95 operated wells brought online. Primarily as a result of our Concho
acquisition, production increased in 2021 compared with 2020, averaging 286 MBOED and 79 MBOED,
respectively.
●
Midland Basin—We operated five rigs and two frac crews on average during 2021, resulting in 118
operated wells drilled and 102 operated wells brought online. Primarily as a result of our Concho
acquisition, production increased in 2021 compared with 2020, averaging 136 MBOED and 6 MBOED,
respectively.
●
Eagle Ford—We operated four rigs and two frac crews on average in the Eagle Ford during 2021, resulting
in 93 operated wells drilled and 160 operated wells brought online. Production increased in 2021
compared with 2020, averaging 211 MBOED and 186 MBOED, respectively.
●
Bakken—We operated one rig and one frac crew for parts of the year in the Bakken, resulting in 6
operated wells drilled and 21 operated wells brought online. Production increased in 2021 compared
with 2020, averaging 94 MBOED and 78 MBOED, respectively.
Dispositions
In the second half of 2021, we completed the sale of certain noncore assets in the Lower 48. In January 2022, we
entered into an agreement to sell our interests in additional noncore assets in the Lower 48. This transaction is
expected to close in the second quarter of 2022.
Facilities
We operate and own, with varying interests, centralized condensate processing facilities in Texas and New Mexico
in support of our Eagle Ford, Delaware and Midland assets.
Business and Properties
7
ConocoPhillips 2021 10-K
Canada
Our Canadian operations consist of the Surmont oil sands development in Alberta and the liquids-rich Montney
unconventional play in British Columbia. In 2021, operations in Canada contributed 8 percent of our consolidated
liquids production and 4 percent of our consolidated natural gas production.
2021
Crude Oil
NGL
Natural Gas
Bitumen
Total
Interest
Operator
MBD
MBD
MMCFD
MBD
MBOED
Average Daily Net
Production
Surmont
50.0
%
ConocoPhillips
-
-
-
69
69
Montney
100.0
ConocoPhillips
8
4
80
-
25
Total Canada
8
4
80
69
94
Surmont
Our bitumen resources in Canada are produced via an enhanced thermal oil recovery method called SAGD,
whereby steam is injected into the reservoir, effectively liquefying the heavy bitumen, which is recovered and
pumped to the surface for further processing. Operations include two central processing facilities for treatment
and blending of bitumen. At December 31, 2021, we held approximately 600,000 net acres of land in the
Athabasca Region of northeastern Alberta.
The Surmont oil sands leases are located approximately 35 miles south of Fort McMurray, Alberta. Surmont is a
50/50 joint venture with Total Energies SE that offers long-lived, sustained production. We are focused on
structurally lowering costs, reducing GHG intensity and optimizing asset performance.
In 2021, we began processing a portion of Surmont’s blended bitumen at the Diluent Recovery Unit constructed in
Alberta, unlocking additional value for the asset by providing market access to our heavy crude oil.
In 2019, Surmont implemented the use of condensate for bitumen blending through the central processing facility
2; enabling the asset to lower blend ratio and diluent supply costs, gain protection from synthetic crude oil supply
disruptions and gain optionality on sales products. The alternative blend project was complete in October at
central processing facility 1. Full Surmont Heavy Dilbit (condensate bitumen blend) was produced across both
facilities in the fourth quarter of 2021.
Montney
The Montney is an unconventional resource play located in northeastern British Columbia. At December 31, 2021,
we held approximately 300,000 acres of land with 100 percent working interest in the liquids-rich section of the
Montney.
In 2021, development activity consisted of drilling three horizontal wells and bringing 12 wells online. In addition,
construction on the second phase of our processing facility started.
Exploration
Our primary exploration focus is assessing our Montney acreage. In 2022, appraisal drilling and completions
activity within the Montney will continue to explore the area’s resource potential. Additionally, we have
exploration acreage in the Mackenzie Delta/Beaufort Sea Region and the Arctic Islands.
Business and Properties
ConocoPhillips 2021 10-K
Europe, Middle East and North Africa
The Europe, Middle East and North Africa segment consists of operations principally located in the Norwegian
sector of the North Sea; the Norwegian Sea; Qatar; Libya; and terminalling operations in the U.K. In 2021,
operations in Europe, Middle East and North Africa contributed 12 percent of our consolidated liquids production
and 14 percent of our consolidated natural gas production.
Norway
2021
Crude Oil
NGL
Natural Gas
Total
Interest
Operator
MBD
MBD
MMCFD
MBOED
Average Daily Net Production
Greater Ekofisk Area
30.7-35.1
%
ConocoPhillips
49
2
41
58
Heidrun
24.0
Equinor
13
1
35
20
Aasta Hansteen
10.0
Equinor
-
-
84
14
Alvheim
20.0
Aker BP
9
-
13
11
Troll
1.6
Equinor
2
-
58
11
Visund
9.1
Equinor
2
1
46
11
Other
Various
Equinor
6
-
21
10
Total Norway
81
4
298
135
The Greater Ekofisk Area is located approximately 200 miles offshore Stavanger, Norway, in the North Sea, and
comprises four producing fields: Ekofisk, Eldfisk, Embla and Tor. The Tor II redevelopment achieved first
production in December 2020. This project consisted of 8 wells that have all been completed and brought online
as of May 2021. Crude oil is exported to Teesside, England, and the natural gas is exported to Emden, Germany.
The Ekofisk and Eldfisk fields consist of several production platforms and facilities, with development drilling
continuing over the coming years.
The Heidrun Field is located in the Norwegian Sea. Produced crude oil is stored in a floating storage unit and
exported via shuttle tankers. Part of the natural gas is currently injected into the reservoir for optimization of
crude oil production, some gas is transported for use as feedstock in a methanol plant in Norway, in which we own
an 18 percent interest, and the remainder is transported to Europe via gas processing terminals in Norway.
Aasta Hansteen is a gas and condensate field located in the Norwegian Sea. Produced condensate is loaded onto
shuttle tankers and transported to market. Gas is transported through the Polarled gas pipeline to the onshore
Nyhamna processing plant for final processing prior to export to market.
The Troll Field lies in the northern part of the North Sea and consists of the Troll A, B and C platforms. The natural
gas from Troll A is transported to Kollsnes, Norway. Crude oil from floating platforms Troll B and Troll C is
transported to Mongstad, Norway, for storage and export.
The Alvheim Field is located in the northern part of the North Sea near the border with the U.K. sector, and
consists of a FPSO vessel and subsea installations. Produced crude oil is exported via shuttle tankers, and natural
gas is transported to the Scottish Area Gas Evacuation (SAGE) Terminal at St. Fergus, Scotland, through the SAGE
Pipeline.
Visund is an oil and gas field located in the North Sea and consists of a floating drilling, production and processing
unit, and subsea installations. Crude
oil is transported by pipeline to a nearby third-party field for storage and
export via tankers. The natural gas is transported to a gas processing plant at Kollsnes, Norway, through the
Gassled transportation system.
We also have varying ownership interests in two other producing fields in the Norway sector of the North Sea.
Business and Properties
9
ConocoPhillips 2021 10-K
Exploration
In 2021, we prepared for a four well exploration and appraisal campaign to take place in 2022. Planned wells
include Slagugle appraisal and exploration of the Peder, Bounty and Lamba prospects.
We were awarded two new exploration licenses; PL1122 and PL1123; and two acreage additions, PL891B and
PL1045B.
Transportation
We own a 35.1 percent interest in the Norpipe Oil Pipeline System, a 220-mile pipeline which carries crude oil from
Ekofisk to a crude oil stabilization and NGLs processing facility in Teesside, England.
Facilities
We operate and have a 40.25 percent ownership interest in a crude oil stabilization and NGLs processing facility at
Teesside, England to support our Norway operations.
Qatar
2021
Crude Oil
NGL
Natural
Gas
Total
Interest
Operator
MBD
MBD
MMCFD
MBOED
Average Daily Net Production
Qatargas Operating
QG3
30.0
%
Company Limited
13
8
373
83
QG3 is an integrated development jointly owned by QatarEnergy (68.5 percent), ConocoPhillips (30 percent) and
Mitsui & Co., Ltd. (1.5 percent). QG3 consists of upstream natural gas production facilities, which produce
approximately 1.4 billion gross cubic feet per day of natural gas from Qatar’s North Field over a 25-year life, in
addition to a 7.8 million gross tonnes-per-year LNG facility. LNG is shipped in leased LNG carriers destined for sale
globally.
QG3 executed the development of the onshore and offshore assets as a single integrated development with
Qatargas 4 (QG4), a joint venture between QatarEnergy and Shell plc. This included the joint development of
offshore facilities situated in a common offshore block in the North Field, as well as the construction of two
identical LNG process trains and associated gas treating facilities for both the QG3 and QG4 joint ventures.
Production from the LNG trains and associated facilities is combined and shared.
Libya
2021
Crude Oil
NGL
Natural Gas
Total
Interest
Operator
MBD
MBD
MMCFD
MBOED
Average Daily Net Production
Waha Concession
16.3
%
Waha Oil Co.
37
-
15
40
The Waha Concession consists of multiple concessions and encompasses nearly 13 million gross acres in the Sirte
Basin. In 2021, we had 22 crude liftings from Es Sider, compared with five crude liftings from Es Sider in 2020,
primarily due to the absence of a forced shutdown after a period of civil unrest that ceased production in 2020.
Business and Properties
ConocoPhillips 2021 10-K
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,
Exploration
In 2019, we entered into an agreement with 3D Oil to acquire a 75 percent interest in and operatorship of an
offshore Exploration Permit (T/49P) located in the Otway Basin, Australia. We obtained an additional five percent
interest, increasing our interes t to 80 percent, in June 2020. A 3D seismic survey acquisition was completed in
October 2021, and this data will be evaluated for future exploration opportunities.
Indonesia
2021
Crude Oil
NGL
Natural Gas
Total
Interest
Operator
MBD
MBD
MMCFD
MBOED
Average Daily Net Production
South Sumatra
54
%
ConocoPhillips
2
-
294
51
During 2021, we operated two PSCs in Indonesia: the Corridor Block located in South Sumatra, and Kualakurun in
Central Kalimantan. Currently, we have production from the Corridor Block.
Business and Properties
11
ConocoPhillips 2021 10-K
Asset Sales
In December 2021, we announced an agreement to sell our subsidiary that indirectly owns the company’s 54
percent interest in the Indonesia Corridor Block PSC and a 35 percent shareholding interest in the Transasia
Pipeline Company. The effective date for the transaction is January 1, 2021, with closing planned for the first
quarter of 2022.
South Sumatra
The Corridor PSC consists of two oil fields and seven producing natural gas fields. Natural gas is supplied from the
Grissik and Suban gas processing plants to the Duri steamflood in central Sumatra and to markets in Singapore,
Batam and West Java. In 2019, we were awarded a 20-year extension, with new terms, of the Corridor PSC. Under
these terms, we retain a majority interest and continue as operator for at least three years after 2023 and retain a
participating interest until 2043.
Exploration
We entered into the Central Kalimantan Kualakurun Block PSC in 2015 with an exploration period of six years. We
completed the firm working commitment program in 2017, which included satellite mapping and a 740-kilometer
2D seismic acquisition program. After completion of prospect evaluation, both PSC contractors decided to
relinquish rights and return this block to the government. The relinquishment was approved by the government in
August 2021.
Transportation
We are a 35 percent owner of a consortium company that has a 40 percent ownership in PT Transportasi Gas
Indonesia, which owns and operates the Grissik to Duri and Grissik to Singapore natural gas pipelines.
China
2021
Crude Oil
NGL
Natural Gas
Total
Interest
Operator
MBD
MBD
MMCFD
MBOED
Average Daily Net Production
Penglai
49.0
%
CNOOC
28
-
-
28
Penglai
The Penglai 19-3, 19-9 and 25-6 fields are located in the Bohai Bay Block 11/05 and are in various stages of
development. Phase 1 and 2 include production from all three Penglai oil fields.
The Phase 3 Project in the Penglai 19-3 and 19-9 fields consists of three new wellhead platforms and a central
processing platform. First production from Phase 3 was achieved in 2018. This project could include up to 186
wells, 126 of which have been completed and brought online as of December 2021.
The Phase 4A Project in the Penglai 25-6 field consists of one new wellhead platform and achieved first production
in 2020. This project could include up to 62 new wells, 14 of which have been completed and brought online as of
December 2021.
On April 5, 2021, a fire occurred on the non-operated V platform in the Bohai Bay. On April 6, 2021, the fire was
extinguished. We worked with the operator and implemented a recovery plan resulting in production resumption
in December 2021.
Exploration
During 2021, exploration activities in the Penglai fields consisted of two successful appraisal wells supporting
future developments in the Bohai Bay Block 11/05.
Business and Properties
ConocoPhillips 2021 10-K
Malaysia
2021
Crude Oil
NGL
Natural Gas
Total
Interest
Operator
MBD
MBD
MMCFD
MBOED
Average Daily Net Production
Gumusut
29.5
%
Shell
19
-
-
19
Malikai
35.0
Shell
13
-
-
13
Kebabangan (KBB)
30.0
KPOC
2
-
66
13
Siakap North-Petai
21.0
PTTEP
1
-
-
1
Total Malaysia
35
-
66
46
We have varying stages of exploration, development and production activities across approx imately 2.7 million net
acres in Malaysia, with working interests in six PSCs. Four of these PSCs are located in waters off the eastern
Malaysian state of Sabah: Block G, Block J, the Kebabangan Cluster (KBBC), which we do not operate, and Block
SB405, an operated exploration block acquired in 2021. We also operate another two exploration blocks, Block
WL4-00 and Block SK304, in waters off the eastern Malaysian state of Sarawak.
Block J
Gumusut
We currently have a 29.5 percent working interest in the unitized Gumusut Field. Gumusut Phase 2 first oil was
achieved in 2019. Development drilling associated with Gumusut Phase 3, a four-well program, is planned to
commence in the first quarter of 2022. First oil is anticipated in 2022.
KBBC
The KBBC PSC grants us a 30 percent working interest in the KBB, Kamunsu East and Kamunsu East Upthrown
Canyon gas and condensate fields. In 2020, we recognized dry hole expense and impaired the associated carrying
value of unproved properties in the Kamunsu East Field that is no longer in our development plans.
KBB
During 2019, KBB tied-in to a nearby third-party floating LNG vessel which provided increased gas offtake capacity.
Production from the field has been reduced since Janu ary 2020, due to the rupture of a third-party pipeline which
carries gas production from KBB to one of its markets. The pipeline operator has initiated repairs and is working
toward pipeline testing during 2022.
Block G
Malikai
We hold a 35 percent working interest in Malikai. This field achieved first production in December 2016 via the
Malikai Tension Leg Platform, ramping to peak production in 2018. The KMU-1 exploration well was completed
and started producing through the Malikai platform in 2018. Malikai Phase 2 development first oil was achieved in
February 2021.
Siakap North-Petai
We hold a 21 percent working interest in the unitized Siakap North-Petai (SNP) oil field. First oil from SNP Phase 2
was achieved in November 2021.
Exploration
In 2017, we were awarded operatorship and a 50 percent working interest in Block WL4-00, which included the
existing Salam-1 oil discovery and encompassed 0.6 million gross acres. In 2018 and 2019, two exploration and
two appraisal wells were drilled, resulting in oil discoveries under evaluation at Salam and Benum, while two
Patawali wells were expensed as dry holes in 2019. Further exploration and appraisal drilling is planned for 2022.
In 2018, we were awarded a 50 percent working interest and operatorship of Block SK304 encompassing 2.1
million gross acres off the coast of Sarawak, offshore Malaysia. We acquired 3D seismic over the acreage and
completed processing of this data in 2019. Exploration drilling is planned for 2022.
Business and Properties
13
ConocoPhillips 2021 10-K
In February 2021, we were awarded operatorship and an 85 percent working interest in Block SB405 encompassing
1.4 million gross acres off the coast of Sabah, offshore Malaysia. Acquisition of a 3D seismic survey over the
acreage is planned for 2022.
Other International
The Other International segment includes activities in Colombia as well as contingencies associated with prior
operations in other countries. As a result of our completed Concho acquisition on January 15, 2021, we refocused
our exploration program and announced our intent to pursue a managed exit from certain areas.
Colombia
We have an 80 percent operated interest in the Middle Magdalena Basin Block VMM-3 extending over
approximately 67,000 net acres. In addition, we have an 80 percent working interest in the VMM-2 Block which
extends over approximately 58,000 net acres and is contiguous to the VMM-3 Block. The blocks are currently in
Force Majeure following a preliminary injunction temporarily suspending hydraulic fracturing activities.
Argentina
On September 16, 2021, ConocoPhillips Petroleum Holdings BV signed and closed the sale of shares in
ConocoPhillips Argentina Holdings Sarl and ConocoPhillips Argentina Ventures SRL. With this transaction, we
completed the exit from our Argentina holdings.
Venezuela
For discussion of our contingencies in Venezuela,
Other
Marketing Activities
Our Commercial organization manages our worldwide commodity portfolio, which mainly includes natural gas,
crude oil, bitumen, NGLs and LNG. Marketing activities are performed through offices in the U.S., Canada, Europe
and Asia. In marketing our production, we attempt to minimize flow disruptions, maximize realized prices and
manage credit-risk exposure. Commodity sales are generally made at prevailing market prices at the time of sale.
We also purchase and sell third -party volumes to better position the company to satisfy customer demand while
fully utilizing transportation and storage capacity.
Natural Gas
Our natural gas production, along with third-party purchased gas, is primarily marketed in the U.S., Canada and
Europe. Our natural gas is sold to a diverse client portfolio which includes local distribution companies; gas and
power utilities; large industrials; independent, integrated or state -owned oil and gas companies; as well as
marketing companies. To reduce our market exposure and credit risk, we also transport natural gas via firm and
interruptible transportation agreements to major market hubs.
Crude Oil, Bitumen and Natural Gas Liquids
Our crude oil, bitumen and NGL revenues are derived from production in the U.S., Canada, Asia, Africa and Europe.
These commodities are primarily sold under contracts with prices based on market indices, adjusted for location,
quality and transportation.
LNG
LNG marketing efforts are focused on equity LNG production facilities located in Australia and Qatar. LNG is
primarily sold under long-term contracts with prices based on market indices.
Business and Properties
ConocoPhillips 2021 10-K
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
®
liquefaction technology has been licensed for use in 27 LNG trains around the world, with feasibility studies
ongoing for additional trains.
Business and Properties
15
ConocoPhillips 2021 10-K
Delivery Commitments
We sell crude oil and natural gas from our producing operations under a variety of contractual arrangements,
some of which specify the delivery of a fixed and determinable quantity. Our commercial organization also enters
into natural gas sales contracts where the source of the natural gas used to fulfill the contract can be the spot
market or a combination of our reserves and the spot market. Worldwide, we are contractually committed to
deliver approximately 1.3 trillion cubic feet of natural gas and 159 million barrels of crude oil in the future. These
contracts have various expiration dates through the year 2030. We expect to fulfill these delivery commitments
with third-party purchases, as supported by our gas management agreements; proved developed reserves; and
PUDs. See the disclosure on “Proved Undeveloped Reserves” in the “Supplementary Data - Oil and Gas
Operations” section following the Notes to Consolidated Financial Statements, for information on the
development of PUDs.
Competition
ConocoPhillips is one of the world’s leading E&P companies based on both production and reserves, with a globally
diversified asset portfolio. We compete with private, public and state-owned companies in all facets of the E&P
business. Some of our competitors are larger and have greater resources. Each of our segments is highly
competitive, with no single competitor, or small group of competitors, dominating.
We compete with numerous other companies in the industry, including state-owned companies, to locate and
obtain new sources of supply and to produce oil, bitumen, NGLs and natural gas in an efficient, cost-effective
manner. We deliver our production into the worldwide commodity markets. Principal methods of competing
include geological, geophysical and engineering research and technology; experience and expertise; economic
analysis in connection with portfolio management; and safely operating oil and gas producing properties.
Human Capital Management
Values, Principles and Governance
At ConocoPhillips, our human capital management (HCM) approach is anchored to our core SPIRIT Values. Our
SPIRIT Values – Safety, People, Integrity, Responsibility, Innovation, and Teamwork – set the tone for how we
interact with all of our internal and external stakeholders. In particular, we believe a safe organization is a
successful organization, so we prioritize personal and process safety across the company. Our SPIRIT Values are a
source of pride. Our day-to-day work is guided by the principles of accountability and performance, which means
the way we do our work is as important as the results we deliver. We believe these core values and principles set
us apart, align our workforce and provide a foundation for our culture.
Our Executive Leadership Team (ELT) and our Board of Directors play a key role in setting our HCM strategy and
driving accountability for meaningful progress. The ELT and Board of Directors engage often on workforce-related
topics. Our HCM programs are overseen and administered by our human resources function with support from
business leaders across the company.
We depend on our workforce to successfully execute our company’s strategy and we recognize the importance of
creating a workplace in which our people feel valued. Our HCM programs are built around three pillars that we
believe are necessary for success: a compelling culture, a world-class workforce and strong external engagement.
Each of these pillars is described in more detail below.
A Compelling Culture
How we do our work is what sets us apart and drives our performance. We’re experts in what we do and
continuously find ways to do our jobs better. Together, we deliver strong performance, but not at all costs. We
embrace our core cultural attributes that are shared by everyone, everywhere. With two significant acquisitions
completed in 2021, we prioritized cultural integration. We seized the opportunity to learn from and value each
other’s cultures. This involved employee engagement, active listening and leveraging data analytics to monitor key
workforce and engagement metrics.
Business and Properties
ConocoPhillips 2021 10-K
Health, Safety and Environment
Our HSE organization sets expectations and provides tools and assurance to our workforce to promote and achieve
HSE excellence. We manage and assure ConocoPhillips HSE policies, standards and practices, to help ensure
business activities are consistently safe, healthy and conducted in an environmentally and socially responsible
manner across the globe. Each business unit manages its local operational risks with particular attention to
process safety, occupational safety and environmental and emergency preparedness risk. Objectives, targets and
deadlines are set and tracked annually to drive strong HSE performance. Progress is tracked and reported to our
ELT and the Board of Directors. HSE audits are conducted on business units and staff groups to ensure
conformance with ConocoPhillips HSE policies, standards and practices where improvement actions are identified
and tracked to completion.
We continuously look for ways to operate more safely, efficiently and responsibly. We focus on reducing human
error by emphasizing interaction among people, equipment and work processes . By being curious about how work
is done, recognizing error-likely situations and applying safeguards , we can reduce the likelihood and severity of
unexpected incidents. We conduct thorough investigations of all serious incidents to understand the root cause
and share lessons learned globally to improve our procedures, training, maintenance programs and designs.
Through this culture of continuous learning and improvement, we continue to refine our existing HSE processes
and tools and enhance our commitment to safe, efficient and responsible operations.
COVID-19 Response
In 2021, our COVID-19 activities were guided by our three company-wide priorities, set at the early pandemic
stages: protect our employees and contractors, mitigate the spread of COVID-19 and safely run the business. We
have pursued these priorities via a coordinated crisis management support team, frequent workforce
communications and flexible programs to suit the challenging environment. Our office and field staffs adhered to
rigorous mitigation protocols implemented across our operations utilizing the most current guidance from health
authorities. Mitigation measures, including requirements for remote work, vaccines and testing were driven by the
specific situations applicable to a region or business function. These measures proved effective at lessening the
impact to our employees and contractors , mitigating the spread of COVID-19 and minimizing the potential for
business disruption.
Diversity, Equity and Inclusion (DEI)
At ConocoPhillips, we value all forms of diversity, provide equitable employee programs and promote a culture of
inclusion. Our DEI vision is for our workforce to have a strong sense of belonging and feel supported in meeting
their full potential. Our commitment to DEI is foundational to our SPIRIT Values. We hold our leaders accountable
for having personal DEI goals each year and encourage all global employees to play a part in creating and
sustaining an inclusive work environment.
The ELT has ultimate accountability for advancing our DEI commitment through a governance structure that
includes an ELT -level DEI Champion, a global DEI Council consisting of senior leaders from across the company and
organization-wide DEI goals. The company sets goals and measures progress based on three pillars that guide our
DEI activities: leadership accountability, employee awareness and processes and programs. In addition, our DEI
plans and progress are reviewed regularly with the Board of Directors.
In 2021, HR and the DEI Council reviewed the results of the 2020 Perspectives Pulse DEI employee survey and
prioritized action plans tied to employee sentiment. 2021 accomplishments included:
●
Refreshing and diversifying the global DEI Council to reflect the diversity we seek across our global
organization;
●
Using survey insights to produce six multi-year corporate DEI priorities that will guide us through 2024;
●
Developing a detailed plan for our corporate DEI priorities, made up of 18 specific targets that position us
to deliver meaningful progress through 2024; and
●
Championing the addition of the ‘E’ (equity) to D&I; emphasizing the importance of providing equitable
programs that lead to fair outcomes for all employees.
Business and Properties
17
ConocoPhillips 2021 10-K
We actively monitor diversity metrics on a global basis. In 2021, we expanded our internal and external workforce
metrics and HCM disclosures, including publishing our 2018-2020 Consolidated EEO-1 Reports and our inaugural
HCM report. Tables of 2021 employee demographics by gender and ethnicity, and by country, are shown below:
2021 Employees by Gender and Race/Ethnicity
Global
U.S.
Male
Female
White
POC
*
All Employees
74
%
26
%
72
%
28
%
All Leadership
75
25
79
21
Top Leadership
78
22
85
15
Junior Leadership
75
25
77
23
*"POC" refers to People of Color or racial and ethnic minorities self-reported in the U.S.
2021 Employees by Country
Percent of Total
U.S.
61
%
Norway
18
Canada
8
Indonesia
5
Great Britain
3
Australia
3
China
1
Other Global Locations
1
100
The Hybrid Office Work Program
In 2021, we introduced the Hybrid Office Work (HOW) program in the U.S., offering a combination of work from
both office and home. The HOW program blends the advantages of in-person engagement with individual
flexibility for eligible employees where a hybrid schedule is feasible. The design of the U.S. program was adopted
in many of our global locations.
A World-Class Workforce
Our HCM approach addresses programs and processes necessary for ensuring we have an engaged workforce with
the skills to meet our business needs. We take a holistic view of HCM that addresses each of the critical
components of workforce planning. These are described in more detail below.
Recruitment
Our continued success requires a strong global workforce that can contribute the right skills, in the right places, to
achieve our strategic objectives. We offer university internships across multiple disciplines to attract the best
early-career talent. We partner with top diversity organizations and universities, including Hispanic-serving
organizations and historically black colleges and universities. We also recruit experienced hires to fill critical skills
and maintain a broad range of expertise and experience. We conduct routine talent assessments with leaders to
ensure we have the organizational capacity and capabilities to execute our business plans. We have taken
significant steps to embed inclusion into each step of our recruiting practices, including adapting the way we
construct job descriptions to using intentionally diverse interview panels.
As necessary, we closely monitor recruitment metrics through our internal university and experienced hire
dashboards and track voluntary turnover metrics to guide our retention activities.
Business and Properties
ConocoPhillips 2021 10-K
2021 Hiring & Attrition Metrics
Percent of Total
U.S. University hire acceptance
81
%
U.S. Interns acceptance
76
Diversity hiring - Women
23
Diversity hiring - U.S. POC
35
Total voluntary attrition
5
Employee Engagement and Development
We focus on the engagement and development of our workforce and encourage our employees to build diverse
and fulfilling careers with ConocoPhillips. Our workforce is trained through a combination of on-the-job learning,
formal training, regular feedback and mentoring. Skill-based Talent Management Teams (TMTs) guide employee
development and career progression by skills and location. The TMTs help identify our future business needs and
assess the availability of critical skill-sets within the company. We use a performance management program
focused on objectivity, credibility and transparency. The program includes broad stakeholder feedback, real-time
recognition and a formal “how” rating to assess behaviors to ensure they align with our SPIRIT Values.
We empower our employees to grow their careers through personal and professional development opportunities,
including individual development plans, a voluntary 360-feedback tool and training on a broad range of technical
and professional skills. Succession planning is a top priority for management and the board. This work ensures we
have the talent available for future leadership roles to inspire employees to reach their ultimate potential and limit
business interruption.
Taking steps to measure and assess employee satisfaction and engagement is at the heart of long-term business
success and creating a great place to work for our global workforce. Since 2019, the ConocoPhillips Perspectives
Survey has become our primary listening platform for gathering feedback on employee sentiment and promot ing
our “Who We Are” culture. Our leadership reviews feedback gathered to guide priorities and goals. Our employee
feedback strategy is comprised of an annual engagement survey and an annual shorter DEI pulse survey.
Compensation, Benefits and Well-Being
We offer competitive, performance-based compensation packages and have global equitable pay practices. Our
compensation programs are generally comprised of a base pay rate, the annual Variable Cash Incentive Program
(VCIP) and, for eligible employees, the Restricted Stock Unit (RSU) program. From the CEO to the frontline worker,
every employee participates in VCIP, our annual incentive program, which aligns employee compensation with
ConocoPhillips’ success on critical performance metrics and also recognizes individual performance. Our RSU
program is designed to attract and retain employees, reward performance and align employee interest with
stockholders by encouraging stock ownership. Our retirement and savings plans are intended to support
employee’s financial futures and are competitive within local markets.
We routinely benchmark our global compensation and benefits programs to ensure they are competitive,
inclusive, aligned with company culture and allow our employees to meet their individual needs and the needs of
their families. We provide flexible work schedules and competitive time off, including parental leave policies in
many locations. In 2021, we enhanced our programs to provide expanded coverage for families requiring disability
support, elder care and childcare. We also provide access to quality childcare, including onsite child care, where
access locally is a challenge.
Our global wellness programs include biometric screenings and fitness challenges designed to educate and
promote a healthy lifestyle. All employees have access to our employee assistance program, and many of our
locations offer custom programs to support mental well-being.
Business and Properties
19
ConocoPhillips 2021 10-K
Compensation Risk Mitigation
We have considered the risks associated with each of its executive and broad-based compensation programs and
policies. As part of the analysis, we considered the performance measures we use as well as the different types of
compensation, varied performance measurement periods and extended vesting schedules that we utilize under
each incentive compensation program. As a result of this review, management concluded that the risks arising
from our compensation policies and practices are not reasonably likely to have a material adverse effect on the
company. As part of the Board of Directors’ oversight of our risk management programs, the Human Resources
Compensation Committee (HRCC) conducts a similar review with the assistance of its independent compensation
consultant. The HRCC agrees with management’s conclusion that the risks arising from our compensation policies
and practices are not reasonably likely to have a material adverse effect on the company.
External Engagement
Our employees make our communities stronger. We are proud to support their generous involvement in local
charitable activities through employee giving programs that include United Way campaigns, matching gift
contributions and volunteer grants.
While we have been recognized for our ESG and DEI efforts, we know that it takes ongoing commitment to make
sustainable progress; therefore, we continue to provide training, build awareness and reinforce accountability at
all levels of the organization and focus on behaviors and processes that build an environment in which everyone
has the opportunity to succeed.
General
At the end of 2021, we held a total of 1,118 active patents in 50 countries worldwide, including 438 active U.S.
patents. During 2021, we received 40 patents in the U.S. and 45 foreign patents. Our products and processes
generated licensing revenues of $65 million related to activity in 2021. The overall profitability of any business
segment is not dependent on any single patent, trademark, license, franchise or concession.
The environmental information contained in Management’s Discussion and Analysis of Financial Condition and
Results of Operations on pages 58 through 63 under the captions “Environmental” and “Climate Change” is
incorporated herein by reference. It includes information on expensed and capitalized environmental costs for
2021 and those expected for 2022 and 2023.
Website Access to SEC Reports
Our internet website address is
www.conocophillips.com
. Information contained on our internet website is not
part of this report on Form 10-K.
Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any
amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act
of 1934 are available on our website, free of charge, as soon as reasonably practicable after such reports are filed
with, or furnished to, the SEC. Alternatively, you may access these reports at the SEC’s website at
www.sec.gov
.
Risk Factors
ConocoPhillips 2021 10-K
Item 1A. Risk Factors
You should carefully consider the following risk factors in addition to the other information included in this Annual
Report on Form 10-K. These risk factors are not the only risks we face. Our business could also be affected by
additional risks and uncertainties not currently known to us or that we currently consider to be immaterial. If any
of these risks or other risks that are yet unknown were to occur, our business, operating results and financial
condition, as well as the value of an investment in our common stock could be adversely affected.
Risks Related to Our Industry
Our operating results, our ability to execute on our strategy and the carrying value of our assets are exposed to
the effects of changing commodity prices.
The oil and gas business is a commodity business. Our revenues, operating results and future rate of growth are
highly dependent on the prices we receive for crude oil, bitumen, natural gas and NGLs. Such prices can fluctuate
widely depending upon global events or conditions that affect supply and demand, most of which are out of our
control. In early 2020 global oil demand decreased precipitously alongside global COVID-19 economic shutdowns.
Although global oil demand and global oil prices improved through 2021, the global economic recovery remains
uncertain. Our industry will continue to be exposed to the effects of changing commodity prices given the
volatility in commodity price drivers and the worldwide political and economic environment generally, as well as
continued uncertainty caused by armed hostilities in various oil-producing regions around the globe.
Lower crude oil, bitumen, natural gas and NGL prices may have a material adverse effect on our revenues,
operating income, cash flows and liquidity, and may also affect the amount of dividends we elect to declare and
pay on our common stock and the amount of shares we elect to acquire as part of the share repurchase program
and the timing of such acquisitions. Lower prices may also limit the amount of reserves we can produce
economically, thus adversely affecting our proved reserves and reserve replacement ratio and accelerating the
reduction in our existing reserve levels as we continue production from upstream fields. Prolonged depressed
crude oil prices may affect certain decisions related to our operations, including decisions to reduce capital
investments or curtail operated production.
Significant reductions in crude oil, bitumen, natural gas and NGL prices could also require us to reduce our capital
expenditures, impair the carrying value of our assets or discontinue the classification of certain assets as proved
reserves. In the past three years, we recognized several impairments, which are described in
. If commodity
prices decrease relative to their current levels, and as we continue to optimize our investments and exercise
capital flexibility, it is reasonably likely we could incur future impairments to long-lived assets used in operations,
investment in nonconsolidated entities accounted for under the equity method and unproved properties.
Although it is not reasonably practicable to quantify the impact of any future impairments or estimated change to
our unit-of-production rates at this time, our results of operations could be adversely affected as a result.
Our business has been, and will continue to be, adversely affected by the coronavirus (COVID-19) pandemic.
The COVID-19 pandemic and the measures put in place to address it have negatively impacted the global economy,
disrupted global supply chains, reduced global demand for oil and gas and created significant volatility and
disruption of financial and commodity markets. Over the course of the pandemic, public health officials have
recommended or mandated certain precautions to mitigate the spread of COVID-19, including limiting non-
essential gatherings of people, ceasing all non-essential travel and issuing “social or physical distancing” guidelines,
“shelter-in-place” orders and mandatory closures or reductions in capacity for non-essential businesses. Although
some of these limitations and mandates have been relaxed in certain jurisdictions, others have been reinstated in
areas that have experienced a resurgence of COVID-19 cases and there is no guarantee restrictions will not be
reimposed in the future. Despite the increased availability of vaccines in certain jurisdictions, the COVID -19
pandemic may continue or worsen during the upcoming months, including as a result of the emergence of more
infectious variants of the virus, vaccine hesitancy or increased business and social activities, which may cause
governmental authorities to reinstate restrictions. As a result, the ongoing impact of the COVID-19 pandemic
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remains uncertain and will depend on the severity, location and duration of the effects and spread of the disease,
the effectiveness and duration of actions taken by authorities to contain the virus or treat its effect, the availability
and effectiveness of vaccines or other treatments, and how quickly and to what extent economic conditions
improve.
, for additional
information on how we have been impacted and the steps we have taken in response.
Our business is likely to continue to be further negatively impacted by the COVID -19 pandemic. These impacts
could include but are not limited to:
●
Reduced demand for our products as a result of reductions in travel and commerce, whether related to
mandated restrictions or otherwise;
●
Disruptions in our supply chain due in part to scrutiny or embargoing of shipments from infected areas or
invocation of force majeure clauses in commercial contracts due to restrictions imposed as a result of the
global response to the pandemic;
●
Failure of third-parties on which we rely, including our suppliers, contract manufacturers, contractors,
joint venture partners and external business partners, to meet their obligations to the company, or
significant disruptions in their ability to do so, which may be caused by their own financial or operational
difficulties or restrictions imposed in response to the disease outbreak;
●
Reduced workforce productivity caused by, but not limited to, illness, travel restrictions, quarantine, or
government mandates;
●
Increased challenges in retention of personnel caused by vaccine hesitancy and the resistance of some in
our workforce to comply with workplace protocols necessary to ensure the health and safety of our
workforce and minimize disruptions to the business, such as vaccine and testing requirements, or the use
of personal protective equipment; and
●
Voluntary or involuntary curtailments to support oil prices or alleviate storage shortages for our products.
Any of these factors, or other cascading effects of the COVID-19 pandemic that are not currently foreseeable,
could materially increase our costs, negatively impact our revenues and damage our financial condition, results of
operations, cash flows and liquidity position. Despite the rollout of vaccines, the pandemic continues to progress
and evolve, and the full extent and duration of any such impacts cannot be predicted at this time because of the
sweeping impact of the COVID-19 pandemic on daily life around the world and a lack of certainty as to if or when
conditions will return to pre-COVID levels.
Unless we successfully develop resources, the scope of our business will decline, resulting in an adverse impact to
our business.
As we produce crude oil and natural gas from our existing portfolio, the amount of our remaining reserves
declines. If we are not successful in replacing the crude oil and natural gas we produce with good prospects for
future organic opportunities or through acquisitions, our business will decline. In addition, our ability to
successfully develop our reserves is dependent on a number of factors, including our ability to obtain and renew
rights to develop and produce hydrocarbons; our success at reservoir optimization; our ability to bring long-lead
time, capital intensive projects to completion on budget and on schedule; and our ability to efficiently and
profitably operate mature properties. If we are not successful in developing the resources in our portfolio, our
financial condition and results of operations may be adversely affected.
The exploration and production of oil and gas is a highly comp etitive industry.
The exploration and production of crude oil, bitumen, natural gas and NGLs is a highly competitive business. We
compete with private, public and state-owned companies in all facets of the exploration and production business,
including to locate and obtain new sources of supply and to produce crude oil, bitumen, natural gas and NGLs in an
efficient, cost-effective manner. We must compete for the materials, equipment, services, employees and other
personnel (including geologists, geophysicists, engineers and other specialists) necessary to conduct our business.
Some of our competitors are larger and have greater resources than we do, or may have established strategic long-
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ConocoPhillips 2021 10-K
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.
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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
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ConocoPhillips 2021 10-K
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
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ConocoPhillips 2021 10-K
abate alleged climate change impacts. Additional lawsuits with similar allegations are expected to be filed. The
amounts claimed by plaintiffs are unspecified and the legal and factual issues involved in these cases are
unprecedented. ConocoPhillips believes these lawsuits are factually and legally meritless and are an inappropriate
vehicle to address the challenges associated with climate change and will vigorously defend against such lawsuits.
The ultimate outcome and impact to us cannot be predicted with certainty, and we could incur substantial legal
costs associated with defending these and similar lawsuits in the future. We could also receive lawsuits alleging a
failure or lack of diligence to meet our publicly stated ESG goals, so called “greenwashing” cases.
In addition, although we design and operate our business operations to accommodate expected climatic
conditions, to the extent there are significant changes in the earth’s climate, such as more severe or frequent
weather conditions in the markets where we operate or the areas where our assets reside, we could incur
increased expenses, our operations and supply chain could be adversely impacted, and demand for our products
could fall.
For more information on legislation or precursors for possible regulation relating to global climate change that
affect or could affect our operations and a description of the company’s response,
Domestic and worldwide political and economic developments could damage our operations and materially
reduce our profitability and cash flows.
Actions of the U.S., state, local and foreign governments, through sanctions, tax and other legislation, executive
order and commercial restrictions, could reduce our operating profitability both in the U.S. and abroad. In certain
locations, restrictions on our operations; leasing restrictions; special taxes or tax assessments; and payment
transparency regulations that could require us to disclose competitively sensitive information or might cause us to
violate non-disclosure laws of other countries have been imposed or proposed by governments or certain interest
groups. For example, in 2020 a ballot initiative known as the Fair Share Act was proposed in the state of Alaska,
which, if enacted would have increased the state’s share of production revenues and required producers to
publicly disclose additional financial information. Although ultimately defeated, similar initiatives may be
proposed and may be successful in the future. In addition, we may face regulatory changes in the U.S. including,
but not limited to, the enactment of tax law changes that adversely affect the fossil fuel industry, new methane
emissions standards, restrictive flaring requirements, and more stringent environmental impact studies and
reviews. We also cannot rule out the possibility of similar regulatory shifts and attendant cost and market access
implications in other international jurisdictions.
One area subject to significant political and regulatory activity is the use of hydraulic fracturing, an essential
completion technique that facilitates production of oil and natural gas otherwise trapped in lower permeability
rock formations. A range of local, state, federal and national laws and regulations currently govern or, in some
hydraulic fracturing operations, prohibit hydraulic fracturing in some jurisdictions. Although hydraulic fracturing
has been conducted safely for many decades, a number of new laws, regulations and permitting requirements are
under consideration which could result in increased costs, operating restrictions, operational delays or could limit
the ability to develop oil and natural gas resources. Certain jurisdictions in which we operate have adopted or are
considering regulations that could impose new or more stringent permitting, disclosure or other regulatory
requirements on hydraulic fracturing or other oil and natural gas operations, including subsurface water disposal.
In addition, certain interest groups have also proposed ballot initiatives and constitutional amendments designed
to restrict oil and natural gas development generally and hydraulic fracturing in particular. In the event that ballot
initiatives, local, state, or national restrictions or prohibitions are adopted and result in more stringent limitations
on the production and development of oil and natural gas in areas where we conduct operations, we may incur
significant costs to comply with such requirements or may experience delays or curtailment in the permitting or
pursuit of exploration, development or production activities. Such compliance costs and delays, curtailments,
limitations or prohibitions could have a material adverse effect on our business, prospects, results of operations,
financial condition and liquidity.
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ConocoPhillips 2021 10-K
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.
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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.
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ConocoPhillips 2021 10-K
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.
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ConocoPhillips 2021 10-K
Our technologies, systems and networks may be subject to cyberattacks.
Our business, like others within the oil and gas industry, has become increasingly dependent on digital
technologies, some of which are managed by third -party service providers on whom we rely to help us collect, host
or process information. Among other activities, we rely on digital technology to estimate oil and gas reserves,
process and record financial and operating data, analyze seismic and drilling information and communicate with
employees and third-parties. As a result, we face various cybersecurity threats such as attempts to gain
unauthorized access to, or control of, sensitive information about our operations and our employees, attempts to
render our data or systems (or those of third-parties with whom we do business, including third-party cloud and IT
service providers) corrupted or unusable, threats to the security of our facilities and infrastructure as well as those
of third-parties with whom we do business, including third-party cloud and IT service providers, and attempted
cyber terrorism.
In addition, computers control oil and gas production, processing equipment and distribution systems globally and
are necessary to deliver our production to market. A disruption, failure, or a cyberattack of these operating
systems, or of the networks , software and infrastructure on which they rely, many of which are not owned or
operated by us, could damage critical production, distribution or storage assets, delay or prevent delivery to
markets, make it difficult or impossible to accurately account for production and settle transactions, or negatively
impact public health or safety, economic security, or national security.
Although we have experienced occasional cybersecurity incidents, none have had a material effect on our
business, operations or reputation. As cyberattacks have continued to evolve, we have become subject to new
government-imposed security requirements to implement specific mitigation measures to protect against
ransomware attacks and other known threats to information and operations technology. In response, we must
continually expend additional resources to continue to modify or enhance our protective measures or to
investigate and remediate any vulnerabilities detected. Our implementation of reasonable security procedures
and controls to monitor and mitigate security threats and to increase security for our information, facilities and
infrastructure may result in increased costs. Despite our ongoing investments in security resources, talent and
business practices, we are unable to assure that any security measures will be completely effective.
If our systems and infrastructure were to be breached, damaged or disrupted, we could be subject to serious
negative consequences, including disruption of our operations, damage to our reputation, a loss of counterparty
trust, reimbursement or other costs, increased compliance costs, litigation exposure and legal liability or regulatory
fines, penalties or intervention. In addition, we have exposure to cybersecurity incidents and the negative impacts
of such incidents related to our data and proprietary information housed on third-party IT systems, including the
cloud. Any of these could materially and adversel y affect our business, results of operations or financial condition,
and any of the foregoing can be exacerbated by a delay or failure to detect a cybersecurity incident or the full
extent of such incident notwithstanding reasonable security procedures and controls. The prevalence of remote
working during the pandemic has introduced additional cybersecurity risk. Although we have business continuity
plans in place, our operations may be adversely affected by significant and widespread disruption to our systems
and infrastructure that support our business. While we continue to evolve and modify our business continuity
plans, there can be no assurance that they will be completely effective in avoiding disruption and business impacts.
Further, our insurance may not be adequate to compensate us for all resulting losses, and the cost to obtain
adequate coverage may increase for us in the future.
ConocoPhillips 2021 10-K
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.
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.
having previously served as President, Asia Pacific & Middle East since April 2015. Prior to that, he was Vice
President, Corporate Planning & Development since May 2012.
31
ConocoPhillips 2021 10-K
Kontessa S. Haynes-Welsh
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
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
having previously served as Senior Vice President, Global Operations since August 2020. Prior to that, he served as
Vice President, Corporate Planning & Development from June 2018 to August 2020, Vice President, Mid-Continent
Business Unit, Lower 48 from September 2016 to June 2018, and Vice President, North Slope Operations and
Development in Alaska from August 2012 to September 2016.
Kelly B. Rose
was appointed Senior Vice President, Legal, General Counsel in September 2018. Prior to that, she
was a senior partner in the Houston office of an international law firm, Baker Botts L.L.P., where she counseled
clients on corporate and securities matters. She began her career at the firm in 1991.
Heather G. Sirdashney
was appointed Vice President, Human Resources and Real Estate and Facilities Services in
March 2021, having previously served as Vice President, Human Resources from January 2019. Prior to that, she
served in other leadership roles including Human Resources General Manager, Human Resources Business Partner
Manager, Lower 48, and Director of Human Resources Shared Services.
ConocoPhillips 2021 10-K
Part II
Item 5. Market for Registrant's Common Equity, Related Stockholder
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
In December 2021, we announced the addition of a VROC tier to our return of capital program. The declaration of
ordinary and VROC dividends are subject to the discretion and approval of our Board of Directors. The Board has
adopted a dividend declaration policy providing that the declaration of any dividends will be determined quarterly.
For more information on factors considered when determining the level of these distributions
Issuer Purchases of Equity Securities
Millions of Dollars
Approximate Dollar
Shares Purchased
Value of Shares
Average
as Part of Publicly
Total Number of
Price Paid
Purchased Under the
Period
*
Per Share
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
33
ConocoPhillips 2021 10-K
Stock Performance Graph
The following graph shows the cumulative TSR for ConocoPhillips’ common stock in each of the five years from
December 31, 2016 to December 31, 2021. The graph also compares the cumulative total returns for the same
five-year period with the S&P 500 Index and our performance peer group consisting of Chevron, ExxonMobil,
Apache, Marathon Oil Corporation, Devon, Occidental, Hess, and EOG weighted according to the respective peer’s
stock market capitalization at the beginning of each annual period.
The comparison assumes $100 was invested on December 31, 2016, in ConocoPhillips stock, the S&P 500 Index
and ConocoPhillips’ peer group and assumes that all dividends were reinvested. The cumulative total returns of
the peer group companies' common stock do not include the cumulative total return of ConocoPhillips’ common
stock. The stock price performance included in this graph is not necessarily indicative of future stock price
performance.
Management’s Discussion and Analysis
ConocoPhillips 2021 10-K
Item 7. Management’s Discussion and Analysis of Financial Condition and
Results of Operations
Management’s Discussion and Analysis is the company’s analysis of its financial performance and of significant
trends that may affect future performance. It should be read in conjunction with the financial statements and
notes, and supplemental oil and gas disclosures included elsewhere in this report. It contains forward-looking
statements including, without limitation, statements relating to the company’s plans, strategies, objectives,
expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities
Litigation Reform Act of 1995. The words “anticipate,” “believe,” “budget,” “continue,” “could,” “effort,”
“estimate,” “expect,” “forecast,” “goal,” “guidance,” “intend,” “may,” “objective,” “outlook,” “plan,” “potential,”
“predict,” “projection,” “seek,” “should,” “target,” “will,” “would,” and similar expressions identify forward-looking
statements. The company does not undertake to update, revise or correct any of the forward-looking information
unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking
statements should be read in conjunction with the company’s disclosures under the heading: “CAUTIONARY
STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION
REFORM ACT OF 1995,” beginning on page
The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to net income (loss)
attributable to ConocoPhillips.
Business Environment and Executive Overview
ConocoPhillips is one of the world’s leading E&P companies based on both production and reserves with
operations and activities in 14 countries. Our diverse, low cost of supply portfolio includes resource-rich
unconventional plays in North America; conventional assets in North America, Europe and Asia; LNG
developments; oil sands assets in Canada; and an inventory of global conventional and unconventional exploration
prospects. Headquartered in Houston, Texas, at December 31, 2021, we employed approximately 9,900 people
worldwide and had total assets of $91 billion.
Completed Acquisitions
On January 15, 2021, we completed our acquisition of Concho Resources Inc. (Concho), an independent oil and gas
exploration and production company with operations across New Mexico and West Texas in an all-stock
transaction for $13.1 billion.
In December 2021, we completed our acquisition of Shell Enterprises LLC’s (Shell) assets in the Delaware Basin in
an all-cash transaction for $8.7 billion after customary adjustments. Assets acquired include approximately
225,000 net acres of producing properties located entirely in Texas.
.
Overview
After an unprecedented 2020, the energy landscape improved throughout 2021 with prices reaching pre-pandemic
levels in the second half of the year; however, we expect prices will continue to be cyclical and volatile. Our view is
that a successful business strategy in the E&P industry must be resilient in lower price environments while also
retaining upside during periods of higher prices. As such, we are unhedged, remain highly disciplined in our
investment decisions and continually monitor market fundamentals, including OPEC Plus updates regarding supply
guidance and inventory levels. Although global oil demand improved through 2021, the global economic recovery
remains uncertain and subject to various risk factors, including actions taken to stem the proliferation of COVID-
19.
Management’s Discussion and Analysis
35
ConocoPhillips 2021 10-K
As the macro energy environment continues to evolve, we are embracing what we believe sector leadership
requires through what we call our triple mandate. We believe that ConocoPhillips will play an essential role in
meeting energy transition pathway demand delivering superior and consistent returns on and of capital through
the price cycles, and achieving our net zero ambition on operational emissions, while retaining the flexibility to
successfully adapt as the future unfolds.
Our triple mandate is supported by financial principles and capital allocation priorities that should allow us to
deliver superior returns through the cycles. Our financial principles consist of maintaining balance sheet strength,
providing peer-leading distributions, making disciplined investments, and delivering ESG excellence, all of which
are in service to delivering competitive financial returns. Our 2021 acquisitions of Concho and the Shell Permian
assets further reinforce our differential value proposition.
In 2021, we successfully delivered on our priorities. Total company production was 1,567 MBOED yielding cash
provided by operating activities of $17 billion. We invested $5.3 billion into the business in the form of capital
expenditures and provided returns of capital to shareholders of approximately $6 billion through our ordinary
dividend and share repurchases. For 2021, our ordinary dividend returned $2.4 billion which included an increase
from 43 cents per share to 46 cents per share, effective in December. Share repurchases resumed in February and
amounted to $3.6 billion inclusive of our paced monetization program related to the Cenovus Energy (CVE)
common shares owned.
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,
more information on pending dispositions,
We announced an increase in our disposition target to $4 to $5 billion in proceeds by year-end 2023, with
approximately $2 billion sourced from the Permian Basin. As of year-end 2021, we have generated $0.3 billion in
disposition proceeds. The proceeds from these transactions will be used in accordance with the company’s
priorities, including returns of capital to shareholders and reduction of gross debt.
In December 2021, we announced the initiation of a three-tier return of capital framework. This framework is
structured to continue delivering a compelling, growing ordinary dividend and through -cycle share repurchases. It
includes the addition of a VROC tier. The VROC tier will provide a flexible tool for meeting our commitment of
returning greater than 30 percent of cash from operating activities during periods where commodity prices are
meaningfully higher than our planning price range. We have set our expected 2022 total return of capital from all
three tiers at approximately $8 billion.
Management’s Discussion and Analysis
ConocoPhillips 2021 10-K
In 2021, we reaffirmed and improved upon our commitment to ESG leadership and excellence and the specific
targets we set in October 2020 when we became the first U.S.-based oil and gas company to adopt a Paris-aligned
climate-risk strategy. Our commitment includes:
●
Net-zero ambition for operational (scope 1 and 2) emissions by 2050 with active advocacy for a price on
carbon to address end-use (scope 3) emissions;
●
Targeting a reduction in gross operated and net equity operational GHG emissions intensity by 40 to 50
percent from 2016 levels by 2030;
●
Zero routine flaring by 2030, with an ambition to get there by 2025;
●
10 percent reduction target for methane emissions intensity by 2025 from a 2019 baseline, in addition to
the 65 percent reduction we have made since 2015;
●
Adding continuous methane detection devices to our operations, with an initial focus on the larger Lower
48 facilities;
●
Dedicated low carbon technology organization responsible for identifying and prioritizing global emissions
reduction initiatives and opportunities associated with the energy transition, CCUS and hydrogen; and
●
ESG performance factoring into executive and employee compensation programs.
To support this commitment, in December 2021, we announced that approximately $0.2 billion of our 2022
company-wide capital expenditures would be dedicated to energy transition efforts across the company’s global
operations aimed at accelerating the reduction of the company’s scope 1 and 2 emissions and to pursue business
opportunities that address end-use emissions and early-stage low-carbon technology opportunities that leverage
the company’s adjacencies.
Operationally, we remain focused on safely executing the business. Production increased 440 MBOED or 39
percent in 2021, compared to 2020. Production excluding Libya for 2021 was 1,527 MBOED. After adjusting for
closed acquisitions and dispositions, impacts from 2020 curtailments, 2021 Winter Storm Uri and the conversion of
Concho two-stream contracted volumes to a three-stream basis, production increased by 28 MBOED or 2 percent.
This increase was primarily due to new production from the Lower 48 and other development programs across the
portfolio, partially offset by normal field decline. Production from Libya averaged 40 MBOED in 2021.
Management’s Discussion and Analysis
37
ConocoPhillips 2021 10-K
Key Operating and Financial Summary
Significant items during 2021 and recent announcements included the following:
●
Announced an increase to expected 2022 return of capital to shareholders to a total of $8 billion, with the
incremental $1 billion to be distributed through share repurchases and VROC tiers;
●
Acquired and integrated Concho, capturing over $1 billion of synergies and savings ahead of schedule;
acquired Shell’s Permian assets on December 1, 2021;
●
Exercised preemption right to purchase an additional 10 percent shareholding interest in APLNG,
expected to close in the first quarter of 2022;
●
Generated $0.3 billion in disposition proceeds from noncore sales and entered into agreements to sell an
additional $1.8 billion in assets, subject to customary closing adjustments;
●
Delivered strong operational performance across the company’s asset base, resulting in full-year
production of 1,527 MBOED, excluding Libya;
●
Achieved first production from GMT2, Malikai Phase 2, SNP Phase 2; completed Tor II project and started
production from a third Montney multi-well pad;
●
Net cash provided by operating activities was $17 billion, exceeding capital expenditures and investments
of $5.3 billion;
●
Distributed $6.0 billion to shareholders through $2.4 billion in dividends and $3.6 billion of share
repurchases, representing over 30 percent return of cash provided by operating activities to shareholders;
●
Ended the year with cash and cash equivalents of $5.0 billion and short-term investments of $0.4 billion,
totaling over $5.4 billion in ending cash and cash equivalents and short-term investments ;
●
Initiated a paced monetization of the company’s CVE investment, generating $1.1 billion in proceeds
through the sale of 117 million shares, with the funds applied to share repurchases; 91 million CVE shares
remained outstanding at year -end 2021; and
●
Advanced the company’s net-zero ambition by announcing an increase in scope 1 and 2 GHG emissions-
intensity reduction targets to 40 to 50 percent from a 2016 baseline on a net equity and gross operated
basis by 2030, from the previous target of 35 to 45 percent on only a gross operated basis.
Business Environment
Brent crude oil prices averaged $71 per barrel in 2021, compared with $42 per barrel in 2020. The energy industry
has periodically experienced this type of volatility due to fluctuating supply-and-demand conditions and such
volatility may persist in the future. Commodity prices are the most significant factor impacting our profitability
and related reinvestment of operating cash flows into our business. Our strategy is to create value through price
cycles by delivering on the financial principles that underpin our value proposition; balance sheet strength, peer
leading distributions, disciplined investments and ESG excellence, all of which support strong financial returns.
●
Balance sheet strength.
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.
of capital framework, which consists of a growing, sustainable dividend, share repurchases, and beginning
in 2022, the addition of VROC. In 2021, we paid dividends on our common stock of approximately $2.4
billion and repurchased $3.6 billion of our common stock partially sourced from our paced monetization
program related to the CVE common shares owned. Our combined dividends and repurchases
represented over 30 percent of our net cash provided by operating activities. Our first VROC of $0.20
cents per share was paid on January 14, 2022, to shareholders of record as of January 3, 2022. Our VROC
will be made at the Board of Director’s discretion, subject to market conditions and other factors.
Management’s Discussion and Analysis
ConocoPhillips 2021 10-K
●
Disciplined investments.
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.
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.
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.
assets, significantly increasing our unconventional portfolio with many additional years of low
cost of supply inventory. The addition of this highly complementary acreage in the Midland and
Delaware basins created a sizeable Permian presence to augment our leading unconventional
positions in the Eagle Ford and Bakken in the Lower 48. In our Asia Pacific segment, we notified
Origin Energy of our intent to exercise our preemption right to purchase an additional 10 percent
shareholding interest in APLNG and announced the sale of our interests in Indonesia.
We continue to evaluate our assets to determine whether they compete for capital within our
portfolio and optimize as necessary, directing capital towards the most competitive investments
and disposing of assets that don’t compete. As such, in conjunction with our Shell Permian
acquisition announcement, we communicated an increase in our planned disposition target to $4
to $5 billion in proceeds by year-end 2023 as part of our ongoing portfolio high-grading and
optimization efforts.
o
Add to our proved reserve base.
◾
Acquire interest in existing or new fields.
◾
Apply new technologies and processes to improve recovery from existing fields.
◾
Successfully explore, develop and exploit new and existing fields.
As required by current authoritative guidelines, the estimated future date when an asset will
reach the end of its economic life is based on historical 12-month first-of-month average prices
and current costs. This date estimates when production will end and affects the amount of
estimated reserves. Therefore, as prices and cost levels change from year to year, the estimate
of proved reserves also changes. Generally, our proved reserves decrease as prices decline and
increase as prices rise.
Management’s Discussion and Analysis
39
ConocoPhillips 2021 10-K
Reserve replacement represents the net change in proved reserves, net of production, divided by
our current year production, as shown in our supplemental reserve table disclosures. Our
reserve replacement was 377 percent in 2021, reflecting a net increase from purchases and sales
as well as higher prices. Our organic reserve replacement, which excluded a net increase of
1,115 MMBOE from sales and purchases, was 189 percent in 2021.
In the three years ended December 31, 2021, our reserve replacement was 155 percent. Our
organic reserve replacement during the three years ended December 31, 2021, which excluded a
net increase of 1,022 MMBOE related to sales and purchases, was 88 percent.
Access to additional resources may become increasingly difficult as commodity prices can make
projects uneconomic or unattractive. In addition, prohibition of direct investment in some
nations, national fiscal terms, political instability, competition from national oil companies, and
lack of access to high-potential areas due to environmental or other regulation may negatively
impact our ability to increase our reserve base. As such, the timing and level at which we add to
our reserve base may, or may not, allow us to fully replace our production over subsequent
years.
●
ESG Leadership.
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
ConocoPhillips 2021 10-K
Brent crude oil prices averaged $70.73 per barrel in 2021, an increase of 70 percent compared with
$41.68 per barrel in 2020. Similarly, WTI crude oil prices increased 72 percent from $39.37 per barrel in
2020 to $67.92 per barrel in 2021. Following COVID-19 economic shutdowns in early 2020, global oil
demand increased steadily through the year alongside the global economic recovery. OPEC Plus supply
restraint, capital discipline by U.S. E&P’s and various unplanned supply disruptions in producing countries
moderated supply growth, reducing excess global inventories and putting upward pressure on global oil
prices.
Henry Hub natural gas prices increased 85 percent from an average of $2.08 per MMBTU in 2020 to $3.85
per MMBTU in 2021. Extreme weather events in many parts of the world and several global LNG
liquefaction outages depleted global natural gas inventories in early 2021, generating strong demand for
U.S. LNG exports and supporting robust domestic demand.
Our realized bitumen price increased 368 percent from an average of $8.02 per barrel in 2020 to $37.52
per barrel in 2021. The increase was largely driven by strength in WTI, reflective of increasing global
demand and OPEC discipline. The WCS differential to WTI at Hardisty remained fairly flat as record high
production offsets incremental pipeline capacity. We continue to optimize bitumen price realizations
through improvements in alternate blend capability which results in lower diluent costs and access to the
U.S. Gulf Coast market through rail and pipeline contracts.
Our worldwide annual average realized price increased 70 percent from $32.15
per BOE in 2020 to $54.63
per BOE in 2021 primarily due to higher realized oil, natural gas and bitumen prices.
North America’s energy supply landscape has been transformed from one of resource scarcity to one of
abundance. In recent years, the use of hydraulic fracturing and horizontal drilling in unconventional
formations has led to increased industry actual and forecasted crude oil and natural gas production in the
U.S. Although providing significant short - and long-term growth opportunities for our company, the
increased abundance of crude oil and natural gas due to development of unconventional plays could also
have adverse financial implications to us, including: an extended period of low commodity prices;
production curtailments; and delay of plans to develop areas such as unconventional fields. Should one
or more of these events occur, our revenues would be reduced, and additional asset impairments might
be possible.
Management’s Discussion and Analysis
41
ConocoPhillips 2021 10-K
●
Impairments
. We participate in a capital -intensive industry. At times, our PP&E and investments become
impaired when, for example, commodity prices decline significantly for long periods of time, our reserve
estimates are revised downward, a decision to dispose of an asset leads to a write-down to its fair value,
or the current fair value of an investment is less than its carrying amount and the loss in value is deemed
other than temporary. As we optimize our assets in the future, it is reasonably possible we may incur
future losses upon sale or impairment charges to long-lived assets used in operations, investments in
nonconsolidated entities accounted for under the equity method, and unproved properties. For more
information on our impairments, see
●
Effective tax rate
. Our operations are in countries with different tax rates and fiscal structures.
Accordingly, even in a stable commodity price and fiscal/regulatory environment, our overall effective tax
rate can vary significantly between periods based on the “mix” of before-tax earnings within our global
operations.
●
Fiscal and regulatory environment
. Our operations can be affected by changing economic, regulatory
and political environments in the various countries in which we operate, including civil unrest or strained
relationships with governments that may impact our operations or investments. These changing
environments could negatively impact our results of operations, and further changes to increase
government fiscal take could have a negative impact on future operations. Our management carefully
considers the fiscal and regulatory environment when evaluating projects or determining the levels and
locations of our activity.
Outlook
Production and Capital
2022 operating plan capital budget is $7.2 billion. The plan includes funding for ongoing development drilling
programs, major projects, exploration and appraisal activities, base maintenance and $0.2 billion for projects to
reduce the company’s scope 1 and 2 emissions intensity and investme nts in several early-stage low-carbon
opportunities that address end-use emissions.
Production guidance is 1.8 MMBOED in 2022 including Libya but excluding the impacts from the pending Indonesia
disposition and acquisition of additional APLNG shareholding interest. First quarter 2022 production is expected to
be 1.75 MMBOED to 1.79 MMBOED.
Operating Segments
We manage our operations through six operating segments, which are primarily defined by geographic region:
Alaska; Lower 48; Canada; Europe, Middle East and North Africa; Asia Pacific; and Other International.
Corporate and Other represents income and costs not directly associated with an operating segment, such as most
interest expense, premiums incurred on the early retirement of debt, corporate overhead, certain technology
activities, as well as licensing revenues.
Our key performance indicators, shown in the statistical tables provided at the beginning of the operating segment
sections that follow, reflect results from our operations, including commodity prices and production.
Results of Operations
ConocoPhillips 2021 10-K
Results of Operations
This section of the Form 10-K discusses year-to-year comparisons between 2021 and 2020. For discussion of year-
to-year comparisons between 2020 and 2019, see "Management's Discussion and Analysis of Financial Condition
and Results of Operations" in Part II, Item 7 of our 2020 10-K.
Consolidated Results
A summary of the company’s net income (loss) attributable to ConocoPhillips by business segment follows:
Millions of Dollars
Years Ended December 31
2021
2020
2019
Alaska
$
1,386
(719)
1,520
Lower 48
4,932
(1,122)
436
Canada
458
(326)
279
Europe, Middle East and North Africa
1,167
448
3,170
Asia Pacific
453
962
1,483
Other International
(107)
(64)
263
Corporate and Other
(210)
(1,880)
38
Net income (loss) attributable to ConocoPhillips
$
8,079
(2,701)
7,189
Net Income (loss) attributable to ConocoPhillips increased $10.8 billion in 2021. 2021 earnings were positively
impacted by:
●
Higher realized commodity prices.
●
Higher sales volumes primarily due to our Concho acquisition and absence of production curtailments.
.
●
A gain of $1,040 million after-tax on our Cenovus Energy (CVE) common shares in 2021, as compared to a
$855 million after-tax loss on those shares in 2020.
●
Lower exploration expenses due to:
o
Absence of a 2020 impairment for $648 million after -tax for the entire carrying value of
capitalized undeveloped leasehold costs related to our Alaska North Slope Gas asset.
o
Lower dry hole expenses.
o
Absence of early cancellation of our 2020 winter exploration program in Alaska.
o
Absence of unproved property impairment and dry hole expenses in 2020 for the Kamunsu East
Field in Malaysia, which is no longer in our development plans.
●
Higher equity in earnings of affiliates, primarily due to higher LNG sales prices.
●
Contingent payments related to prior dispositions in our Canada and Lower 48 segments.
●
An after-tax gain of $194 million recognized for a FID bonus associated with our Australia -West divestiture
in 2020.
●
Lower impairments, primarily due to the absence of impairments recognized in 2020 for noncore assets in
our Lower 48 segment partially offset by an impairment in our APLNG investment included within our Asia
Pacific segment.
These increases in net income (loss) were partly offset by:
●
Higher production and operating expenses and taxes other than income taxes, primarily due to higher
sales volumes.
●
Higher DD&A expenses caused by higher production volumes, partially offset by lower rates driven from
positive reserve revisions due to higher commodity prices in 2021.
●
Absence of a $597 million after-tax gain on our Australia-West divestiture completed in May 2020.
●
Restructuring and transaction expenses of $341 million after-tax associated with the Concho and Shell
acquisitions in addition to mark-to-market impacts on certain key employee compensation programs.
Results of Operations
43
ConocoPhillips 2021 10-K
●
Realized losses on hedges of $233 million after -tax related to derivative positions assumed through our
Concho acquisition. These derivative positions were settled entirely within the first quarter of 2021.
.
Income Statement Analysis
Unless otherwise indicated, all results in Income Statement Analysis are before-tax.
Sales and other operating revenues increased 144 percent in 2021, mainly due to higher realized commodity prices
and higher sales volumes.
Equity in earnings of affiliates increased $400 million in 2021, primarily due to higher earnings driven by higher
LNG and crude prices, partially offset by a higher effective tax rate related to equity method investments in our
Europe, Middle East and North Africa segment .
Gain on dispositions decreased $63 million in 2021, primarily due to the absence of a $587 million gain related to
our 2020 Australia-West divestiture and a $179 million loss associated with the sale of noncore assets in our Other
International segment. The decreases were partially offset by $200 million related to a FID bonus associated with
our Australia-West divestiture, gains recognized for contingent payments associated with previous dispositions in
our Canada and Lower 48 segments and gains on sales of certain noncore assets in our Lower 48 segment.
Other income (loss) increased $1.7 billion in 2021, primarily due to a gain of $1,040 million on our CVE common
shares in 2021, as compared to a $855 million loss on those shares in 2020.
Purchased commodities increased 125 percent in 2021, primarily in line with higher gas and crude prices and
volumes.
Production and operating expenses increased $1,350 million in 2021, primarily in line with higher production
volumes.
Selling, general and administrative expenses increased $289 million in 2021, primarily due to transaction and
restructuring expenses associated with our Concho acquisition and higher compensation and benefits costs,
including mark-to-market impacts of certain key employee compensation programs.
Exploration expenses decreased $1,113 million in 2021, primarily due to the absence of 2020 expenses including
an $828 million impairment for the entire carrying value of capitalized undeveloped leasehold costs related to our
Alaska North Slope Gas asset, the early cancellation of our 2020 winter exploration program in Alaska, and absence
of unproved property impairment and dry hole expenses from 2020 for the Kamunsu East Field in Malaysia. 2021
also saw lower dry hole expenses in Alaska.
Impairments decreased $139 million in 2021, primarily due to the absence of impairments recognized in 2020 for
noncore assets in our Lower 48 segment partially offset by an impairment in our APLNG investment included
within our Asia Pacific segment in 2021. For additional information,
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
Results of Operations
ConocoPhillips 2021 10-K
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
1,567
1,127
1,348
Dollars Per Unit
Average Sales Prices
Crude oil (per bbl)
Consolidated Operations
$
67.61
39.56
60.98
Equity affiliates
69.45
39.02
61.32
Total crude oil
67.64
39.54
60.99
Natural gas liquids (per bbl)
Consolidated Operations
31.04
12.90
18.73
Equity affiliates
54.16
32.69
36.70
Total natural gas liquids
32.45
14.61
20.09
Bitumen (per bbl)
37.52
8.02
31.72
Natural gas (per mcf)
Consolidated Operations
6.00
3.17
4.25
Equity affiliates
5.31
3.71
6.29
Total natural gas
5.77
3.41
5.03
Millions of Dollars
Worldwide Exploration Expenses
General and administrative; geological and geophysical,
lease rental, and other
$
300
374
322
Leasehold impairment
10
868
221
Dry holes
34
215
200
Total Exploration Expenses
$
344
1,457
743
Results of Operations
45
ConocoPhillips 2021 10-K
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on a worldwide
basis. At December 31, 2021, our operations were producing in the U.S., Norway, Canada, Australia, Indonesia,
China, Malaysia, Qatar and Libya.
Total production, including Libya, of 1,567 MBOED increased 440 MBOED or 39 percent in 2021 compared with
2020, primarily due to:
●
Higher volumes in Lower 48 due to our Concho acquisition .
●
New wells online in Lower 48, Canada, Norway, Malaysia and Alaska.
●
Absence of production curtailments, primarily in our North American assets.
●
Higher production in Libya due to the absence of a forced shutdown of the Es Sider export terminal and
other eastern export terminals.
●
Improved well performance in Norway, Canada, Alaska and China.
The increase in production during 2021 was partly offset by:
●
Normal field decline.
●
Absence of production from Australia -West due to our second quarter 2020 disposition.
Production excluding Libya for 2021 was 1,527 MBOED. After adjusting for closed acquisitions and dispositions,
impacts from 2020 curtailments, 2021 Winter Storm Uri and the conversion of Concho two-stream contracted
volumes to a three-stream basis, production increased by 28 MBOED or 2 percent. This increase was primarily due
to new production from the Lower 48 and other development programs across the portfolio, partially offset by
normal field decline. Production from Libya averaged 40 MBOED in 2021.
Results of Operations
ConocoPhillips 2021 10-K
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
197
198
218
Average Sales Prices
Crude oil ($ per bbl)
$
69.87
42.12
64.12
Natural gas ($ per mcf)
2.81
2.91
3.19
The Alaska segment primarily explores for, produces, transports and markets crude oil, NGLs and natural gas. In
2021, Alaska contributed 19 percent of our consolidated liquids production and less than 1 percent of our
consolidated natural gas production.
Net Income (Loss) Attributable to ConocoPhillips
Alaska reported earnings of $1,386 million in 2021, compared with a loss of $719 million in 2020. Earnings were
positively impacted by:
●
Higher realized crude oil prices.
●
Absence of 2020 exploration expenses , including a $648 million after-tax impairment associated with the
carrying value of our Alaska North Slope Gas assets and the early cancellation of our winter exploration
program.
●
Lower dry hole expenses.
Earnings were negatively impacted by:
●
Higher taxes other than income taxes primarily due to higher realized crude oil prices.
Production
Average production decreased 1 MBOED in 2021 compared with 2020, primarily due to:
●
Normal field decline.
The production decrease was partly offset by:
●
Absence of curtailments.
●
Improved production at our Western North Slope assets as a result of net royalty interest changes
associated with periodic redetermination.
●
Improved performance in the Greater Prudhoe Area and Western North Slope assets.
●
New wells online across the segment.
Results of Operations
47
ConocoPhillips 2021 10-K
Lower 48
2021
2020
2019
Net Income (Loss) Attributable to ConocoPhillips
($MM)
$
4,932
(1,122)
436
Average Net Production
Crude oil (MBD)
447
213
266
Natural gas liquids (MBD)*
110
74
81
Natural gas (MMCFD)*
1,340
585
622
Total Production
780
385
451
Average Sales Prices
Crude oil ($ per bbl)**
$
66.12
35.17
55.30
Natural gas liquids ($ per bbl)
30.63
12.13
16.83
Natural gas ($ per mcf)**
4.38
1.65
2.12
*Includes conversion of previously acquired Concho two-stream contracts to three-stream initiated in the fourth quarter of 2021.
**Average sales prices, including the impact of hedges settling per initial contract terms in the first quarter of 2021 assumed in our Concho
acquisition were $65.19 per barrel for crude oil and $4.33 per mcf for natural gas for the year ended December 31, 2021. As of March 31, 2021,
we had settled all oil and gas hedging positions acquired from Concho.
The Lower 48 segment consists of operations located in the contiguous U.S. and the Gulf of Mexico. During 2021,
the Lower 48 contributed 55 percent of our consolidated liquids production and 64 percent of our consolidated
natural gas production.
Net Income (Loss) Attributable to ConocoPhillips
Lower 48 reported earnings of $4,932 million in 2021, compared with a loss of $1,122 million in 2020. Earnings
were positively impacted by:
●
Higher realized crude oil, NGL and natural gas prices.
●
Higher sales volumes due to our Concho acquisition and the absence of production curtailments.
●
Lower impairments, primarily related to developed properties in our noncore assets which were written
down to fair value due to lower commodity prices and development plan changes. See
●
Higher gains on dispositions related to selling our interests in certain noncore assets.
Earnings were negatively impacted by:
●
Higher DD&A expenses, production and operating expenses and taxes other than income taxes primarily
due to higher production volumes. Partially offsetting the increase in DD&A expenses were lower rates
from price-related reserve revisions.
●
Impacts resulting from our Concho acquisition, including higher selling, general and administrative
expenses for transaction and restructuring charges, as well as realized losses on derivative settlements.
See
.
Production
Total average production increased 395 MBOED in 2021 compared with 2020, primarily due to:
●
Higher volumes due to our Concho acquisition.
●
New wells online from our development programs in Permian, Eagle Ford and Bakken.
●
Absence of curtailments.
These production increases were partly offset by:
●
Normal field decline.
Results of Operations
ConocoPhillips 2021 10-K
Canada
2021*
2020*
2019**
Net Income (Loss) Attributable to ConocoPhillips
($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
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 prices for sales of bitumen produced excludes additional value realized from the purchase and sale of third-party volumes for
optimization of our pipeline capacity between Canada and the U.S. Gulf Coast.
Our Canadian operations consist of the Surmont oil sands development in Alberta and the liquids-rich Montney
unconventional play in British Columbia. In 2021, Canada contributed 8 percent of our consolidated liquids
production and 4 percent of our consolidated natural gas production.
Net Income (Loss) Attributable to ConocoPhillips
Canada operations reported earnings of $458 million in 2021 compared with a loss of $326 million in 2020.
Earnings were positively impacted by:
●
Higher realized bitumen prices and crude oil prices.
●
After-tax gains on disposition related to contingent payments of $246 million in 2021 associated with the
sale of certain assets to CVE in 2017.
●
Higher sales volumes in our Surmont and Montney assets.
Earnings were negatively impacted by:
●
Higher production and operating expenses primarily due to increased Surmont and Montney production.
Production
Total average production increased 24 MBOED in 2021 compared with 2020. The production increase was
primarily due to:
●
Improved well performance in Surmont.
●
New wells online in Montney.
●
Production from our Kelt acquisition completed in the third quarter of 2020.
●
Absence of curtailments.
Results of Operations
49
ConocoPhillips 2021 10-K
Europe, Middle East and North Africa
2021
2020
2019
Net Income (Loss) Attributable to ConocoPhillips
($MM)
$
1,167
448
3,170
Consolidated Operations
Average Net Production
Crude oil (MBD)
118
86
138
Natural gas liquids (MBD)
4
4
7
Natural gas (MMCFD)
313
275
478
Total Production
175
136
224
Average Sales Prices
Crude oil ($ per bbl)
$
68.97
43.30
64.94
Natural gas liquids ($ per bbl)
43.97
23.27
29.37
Natural gas ($ per mcf)
13.27
3.23
4.92
The Europe, Middle East and North Africa segment consists of operations principally located in the Norwegian
sector of the North Sea; the Norwegian Sea; Qatar; Libya; and terminalling operations in the U.K. In 2021, our
Europe, Middle East and North Africa operations contributed 12 percent of our consolidated liquids production
and 14 percent of our consolidated natural gas production.
Net Income Attributable to ConocoPhillips
The Europe, Middle East and North Africa segment reported earnings of $1,167 million in 2021 compared with
earnings of $448 million in 2020. Earnings were positively impacted by:
●
Higher realized natural gas, crude oil and NGL prices.
●
Higher LNG sales prices, reflected in equity in earnings of affiliates.
●
Higher sales volumes of crude oil and LNG.
Earnings were negatively impacted by:
●
Higher taxes.
●
Higher DD&A expenses and production and operating expenses. Partly offsetting the increase in DD&A
expenses were lower rates from positive reserve revisions.
Consolidated Production
Average consolidated production increased 39 MBOED in 2021, compared with 2020. The consolidated production
increase was primarily due to:
●
Higher production in Libya due to the absence of a forced shutdown of the Es Sider export terminal and
other eastern export terminals.
●
Improved well performance in Norway.
●
New production from Norway drilling activities, including our Tor II redevelopment project which
achieved full production in 2021.
These production increases were partly offset by:
●
Normal field decline.
Results of Operations
ConocoPhillips 2021 10-K
Asia Pacific
2021
2020
2019
Net Income (Loss) Attributable to ConocoPhillips
($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
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
●
Absence of a $597 million after-tax gain related to our Australia -West divestiture.
●
Absence of sales volumes associated with Australia -West.
Earnings were positively impacted by:
●
Higher crude oil and natural gas prices.
●
Higher LNG sales prices, reflected in equity in earnings of affiliates.
●
An after-tax gain of $194 million recognized for a FID bonus associated with our Australia-West divestiture.
For additional information related to this FID bonus, see
Consolidated Production
Average consolidated production decreased 16 MBOED in 2021, compared with 2020. The decrease was primarily
due to:
●
The divestiture of our Australia -West assets that contributed 18 MBOED in 2020.
●
Normal field decline.
These production decreases were partly offset by:
●
Development activity at Bohai Bay in China.
●
First production in Malikai Phase 2 and SNP Phase 2.
●
The absence of curtailments across the segment and increased demand in Indonesia from coal supply
restrictions.
Results of Operations
51
ConocoPhillips 2021 10-K
Other International
2021
2020
2019
Net Income (Loss) Attributable to ConocoPhillips
($MM)
$
(107)
(64)
263
The Other International segment includes exploration and appraisal activities in Colombia as well as contingencies
associated with prior operations in other countries. As a result of our Concho acquisition, we refocused our
exploration program and announced our intent to pursue managed exits from certain areas.
Other International operations reported a loss of $107 million in 2021, compared with a loss of $64 million in 2020.
Earnings were negatively impacted by:
●
A $137 million after-tax loss on divestiture related to our Argentina exploration interests.
●
Absence of a $29 million after-tax benefit to earnings from the dismissal of arbitration related to prior
operations in Senegal recognized in the first quarter of 2020.
Changes to earnings were positively impacted by:
●
Absence of exploration expenses associated with dry hole costs and a full impairment of capitalized
undeveloped leasehold costs in Colombia in the fourth quarter of 2020.
Corporate and Other
Millions of Dollars
2021
2020
2019
Net Income (Loss) Attributable to ConocoPhillips
Net interest
$
(801)
(662)
(604)
Corporate general and administrative expenses
(317)
(200)
(252)
Technology
25
(26)
123
Other
883
(992)
771
$
(210)
(1,880)
38
Net interest consists of interest and financing expense, net of interest income and capitalized interest. Net
interest expense increased $139 million in 2021 compared with 2020, primarily due to higher debt balances
assumed due to our Concho acquisition.
Corporate G&A expenses include compensation programs and staff costs. These expenses increased by $117
million in 2021 compared with 2020, primarily due to restructuring expenses associated with our Concho
acquisition and mark to market adjustments associated with certain compensation programs .
Technology includes our investment in new technologies or businesses, as well as licensing revenues. Activities are
focused on both conventional and tight oil reservoirs, shale gas, heavy oil, oil sands, enhanced oil recovery as well
as LNG. Earnings from Technology increased by $51 million in 2021 compared with 2020, primarily due to higher
licensing revenues.
The category “Other” includes certain foreign currency transaction gains and losses, environmental costs
associated with sites no longer in operation, other costs not directly associated with an operating segment,
premiums incurred on the early retirement of debt, holding gains or losses on equity securities, and pension
settlement expense. Earnings in “Other” increased by $1,875 million in 2021 compared with 2020, primarily due
to a gain of $1,040 million on our CVE common shares in 2021, compared with a $855 million loss in 2020.
Capital Resources and Liquidity
ConocoPhillips 2021 10-K
Capital Resources and Liquidity
Financial Indicators
Millions of Dollars
Except as Indicated
2021
2020
2019
Net cash provided by operating activities
$
16,996
4,802
11,104
Cash and cash equivalents
5,028
2,991
5,088
Short-term investments
446
3,609
3,028
Short-term debt
1,200
619
105
Total debt
19,934
15,369
14,895
Total equity
45,406
29,849
35,050
Percent of total debt to capital*
31
%
34
30
Percent of floating-rate debt to total debt
4
%
7
5
*Capital includes total debt and total equity.
To meet our short- and long-term liquidity requirements, we look to a variety of funding sources, including cash
generated from operating activities, proceeds from asset sales, our commercial paper and credit facility programs
and our ability to sell securities using our shelf registration statement. In 2021, the primary uses of our available
cash were $8.7 billion for the acquisition of Shell Permian; $5.3 billion to support our ongoing capital expenditures
and investments program; $3.6 billion to repurchase our common stock; $2.4 billion to pay dividends; and $1.2
billion for hedging, transaction and restructuring costs. In 2021, cash and cash equivalents increased by $2.0
billion to $5.0 billion.
At December 31, 2021, we had cash and cash equivalents of $5.0 billion, short-term investments of $0.4 billion,
and available borrowing capacity under our credit facility of $6.0 billion, totaling approximately $11.5 billion of
liquidity. We believe current cash balances and cash generated by operations, together with access to external
sources of funds as described below in the “Significant Changes in Capital” section, will be sufficient to meet our
funding requirements in the near- and long-term, including our capital spending program, dividend payments and
required debt payments.
Significant Changes in Capital
Operating Activities
In 2021, cash provided by operating activities was $17 billion, compared with $4.8 billion for 2020. The increase is
primarily due to higher realized commodity prices and higher sales volumes, mostly resulting from our acquisition
of Concho. The increase was partly offset by the $0.8 billion in settlement of oil and gas hedging positions
acquired from Concho, and approximately $0.4 billion of transaction and restructuring costs.
Our short- and long-term operating cash flows are highly dependent upon prices for crude oil, bitumen, natural
gas, LNG and NGLs. Prices and margins in our industry have historically been volatile and are driven by market
conditions over which we have no control. Absent other mitigating factors, as these prices and margins fluctuate,
we would expect a corresponding change in our operating cash flows.
The level of absolute production volumes, as well as product and location mix, impacts our cash flows. Full-year
production averaged 1,567 MBOED in 2021. Full-year production excluding Libya averaged 1,527 MBOED.
Adjusting for closed acquisitions and dispositions, impacts from 2020 curtailments, 2021 Winter Storm Uri and the
conversion of Concho two-stream contracted volumes to a three-stream basis, production increased 28 MBOED or
2 percent. First quarter 2022 production is expected to be 1.75 MMBOED to 1.79 MMBOED. Future production is
subject to numerous uncertainties, including, among others, the volatile crude oil and natural gas price
environment, which may impact investment decisions; the effects of price changes on production sharing and
variable-royalty contracts; acquisition and disposition of fields; field production decline rates; new technologies;
operating efficiencies; timing of startups and major turnarounds; political instability; weather-related disruptions;
Capital Resources and Liquidity
53
ConocoPhillips 2021 10-K
and the addition of proved reserves through exploratory success and their timely and cost -effective
development. While we actively manage these factors, production levels can cause variability in cash flows,
although generally this variability has not been as significant as that caused by commodity prices.
To maintain or grow our production volumes on an ongoing basis, we must continue to add to our proved reserve
base. Our proved reserves generally increase as prices rise and decrease as prices decline. Reserve replacement
represents the net change in proved reserves, net of production, divided by our current year production. For
information on proved reserves, including both developed and undeveloped reserves,
As discussed in the “Critical Accounting Estimates” section, engineering estimates of proved reserves are
imprecise; therefore, reserves may be revised upward or downward each year due to the impact of changes in
commodity prices or as more technical data becomes available on reservoirs. It is not possible to reliably predict
how revisions will impact future reserve quantities.
Investing Activities
In 2021, we invested $5.3 billion in capital expenditures. Capital expenditures invested in 2020 and 2019 were
$4.7 billion and $6.6 billion, respectively. For information about our capital expenditures and investments, see the
“Capital Expenditures and Investments” section.
In December 2021, we completed our acquisition of Shell’s assets in the Delaware Basin for cash consideration of
approximately $8.7 billion after customary adjustments. We funded this transaction with cash on hand. We
completed our acquisition of Concho on January 15, 2021. The assets acquired in the transaction included $382
million of cash. The net impact of these items is recognized within “Acquisition of businesses, net of cash
acquired” on our consolidated sta tement of cash flows.
In 2021, we announced a disposition target of $4 to $5 billion in disposition proceeds by year-end 2023. Only
proceeds from transactions announced or initiated in the third quarter of 2021 or later will be counted toward this
target. The proceeds from these transactions will be used in accordance with the company’s priorities, including
returns of capital to shareholders and reduction of gross debt. To date, we have achieved $0.3 billion from the
sale of noncore assets in our Lower 48 segment.
Total proceeds from asset dispositions in 2021 were $1.7 billion. Including the $250 million mentioned above, we
also received cash proceeds of $1.14 billion from sales of our investment in CVE common shares and $244 million
of contingent payments related to dispositions completed before 2021.
In May 2021, we announced
and began a paced monetization of our investment in CVE with the plan to direct proceeds toward our existing
share repurchase program. We expect to fully dispose of our CVE common shares by early 2022, however, the
sales pace will be guided by market conditions, and we retain discretion to adjust accordingly.
Proceeds from asset sales in 2020 were $1.3 billion. We received cash proceeds of $765 million for the divestiture
of our Australia-West assets and operations. We also received proceeds of $359 million and $184 million from the
sale of our Niobrara interests and Waddell Ranch interests in the Lower 48, respectively.
Proceeds from asset sales in 2019 were $3.0 billion, including $2.2 billion for the sale of two ConocoPhillips U.K.
subsidiaries and $350 million for the sale of our 30 percent interest in the Greater Sunrise Fields.
We invest in short -term investments as part of our cash investment strategy, the primary objective of which is to
protect principal, maintain liquidity and provide yield and total returns; these investments include time deposits,
commercial paper, as well as debt securities classified as available for sale. Funds for short-term needs to support
our operating plan and provide resiliency to react to short-term price volatility are invested in highly liquid
instruments with maturities within the year. Funds we consider available to maintain resiliency in longer term
Capital Resources and Liquidity
ConocoPhillips 2021 10-K
price downturns and to capture opportunities outside a given operating plan may be invested in instruments with
maturities greater than one year.
Financing Activities
We have a revolving credit facility totaling $6.0 billion, expiring in May 2023. Our revolving credit facility may be
used for direct bank borrowings, the issuance of letters of credit totaling up to $500 million, or as support for our
commercial paper program. The revolving credit facility is broadly syndicated among financial institutions and
does not contain any material adverse change provisions or any covenants requiring maintenance of specified
financial ratios or credit ratings. The facility agreement contains a cross-default provision relating to the failure to
pay principal or interest on other debt obligations of $200 million or more by ConocoPhillips, or any of its
consolidated subsidiaries. The amount of the facility is not subject to the redetermination prior to its expiration
date.
Credit facility borrowings may bear interest at a margin above rates offered by certain designated banks in the
London interbank market or at a margin above the overnight federal funds rate or prime rates offered by certain
designated banks in the U.S. The agreement calls for commitment fees on available, but unused, amounts. The
agreement also contains early termination rights if our current directors or their approved successors cease to be a
majority of the Board of Directors.
The revolving credit facility supports ConocoPhillips Company’s ability to issue up to $6.0 billion of commercial
paper, which is primarily a funding source for short-term working capital needs. Commercial paper maturities are
generally limited to 90 days. With no commercial paper outstanding and no direct borrowings or letters of credit,
we had access to $6.0 billion in available borrowing capacity under the revolving credit facility at December 31,
2021.
On January 15, 2021, we completed the acquisition of Concho in an all-stock transaction. In the acquisition, we
assumed Concho’s publicly traded debt and in December 2020, we launched an offer to exchange Concho’s
publicly traded debt for debt issued by ConocoPhillips. There were no impacts to ConocoPhillips’ credit ratings as a
result of the debt exchange. In June 2021, we reaffirmed our commitment to preserving our ‘A’ -rated balance
sheet by restating our intent to reduce gross debt by $5 billion over the next five years, driving a more resilient and
efficient capital structure. See
On January 25, 2021, S&P revised the industry risk assessment for the E&P industry to ‘Moderately High’ from
‘Intermediate’ based on a view of increasing risks from the energy transition, price volatility, and weaker
profitability. On February 11, 2021, S&P downgraded its rating of our long-term debt from “A” to “A -” with a
“stable” outlook and affirmed this rating in November 2021. In October 2021, Moody’s affirmed its “A3” rating of
our long-term debt and revised its outlook from “stable” to “positive”. In December 2021, Fitch affirmed its rating
of our long-term debt as “A” with a “stable” outlook.
We do not have any ratings triggers on any of our corporate debt that would cause an automatic default, and
thereby impact our access to liquidity, upon downgrade of our credit ratings. If our credit ratings are downgraded
from their current levels, it could increase the cost of corporate debt available to us and restrict our access to the
commercial paper markets. If our credit rating were to deteriorate to a level prohibiting us from accessing the
commercial paper market, we would still be able to access funds under our revolving credit facility.
Certain of our project-related contracts, commercial contracts and derivative instruments contain provisions
requiring us to post collateral. Many of these contracts and instruments permit us to post either cash or letters of
credit as collateral. At December 31, 2021 and 2020, we had direct bank letters of credit of $337 million and $249
million, respectively, which secured performance obligations related to various purchase commitments incident to
the ordinary conduct of business. In the event of credit ratings downgrades, we may be required to post additional
letters of credit.
We have a universal shelf registration statement on file with the SEC under which we have the ability to issue and
sell an indeterminate amount of various types of debt and equity securities.
Capital Resources and Liquidity
55
ConocoPhillips 2021 10-K
Capital Requirements
For information about our capital expenditures and investments, see the “Capital Expenditures and Investments”
section.
Our debt balance at December 31, 2021, was $19.9 billion, an increase of $4.6 billion from the balance at
December 31, 2020, driven by debt acquired as part of the Concho acquisition. Maturities of debt (including
payments for finance leases) due in 2022 of $1.1 billion will be paid from current cash balances and cash generated
by operations.
In December 2021, we announced our expected 2022 return of capital program and the initiation of a three-tier
return of capital framework. The framework is structured to deliver a compelling, growing ordinary dividend and
through-cycle share repurchases. It includes the addition of a discretionary VROC tier. The VROC will provide a
flexible tool for meeting our commitment of returning greater than 30 percent of cash from operating activities
during periods where commodity prices are meaningfully higher than our planning price range. We have set our
expected 2022 total capital returns at approximately $8 billion, consisting of distributions from each of the three
tiers.
Consistent with our commitment to deliver value to shareholders, in 2021, we paid $2.4 billion, $1.75 per share of
common stock, in ordinary dividends. This was an increase over 2020 and 2019, when we paid $1.69 and $1.34 per
share of common stock, respectively. On February 3, 2022, we announced a quarterly dividend of $0.46 per share,
payable March 1, 2022, to stockholders of record at the close of business on February 14, 2022. On January 14,
2022, we paid the first VROC payment of $0.20 per share to shareholders of record as of January 3, 2022. On
February 3, 2022, we announced a VROC of $0.30 per share, payable on April 14, 2022, to stockholders of record at
the close of business on March 31, 2022.
The ordinary dividend and VROC are subject to numerous considerations and will be determined and approved
each quarter by the Board of Directors. We expect to announce the VROC when we announce our ordinary
dividend, but the quarterly payouts will be staggered from the ordinary dividend, resulting in up to eight cash
distributions throughout the year.
In late 2016, we initiated our current share repurchase program with Board of Director’s authorization of $25
billion of our common stock. Share repurchases were $3.6 billion, $0.9 billion, and $3.5 billion in 2021, 2020, and
2019, respectively. As of December 31, 2021, share repurchases since the inception of our current program
totaled 247 million shares and $14 billion. Repurchases are made at management’s discretion, at prevailing prices,
subject to market conditions and other factors.
For more information on factors considered when determining the levels of returns of capital
In addition to the priorities described above, we have contractual obligations to purchase goods and services of
approximately $11.8 billion. We expect to fulfill $6 billion of these obligations in 2022. These figures exclude
purchase commitments for jointly owned fields and facilities where we are not the operator. Purchase obligations
of $5.3 billion are related to agreements to access and utilize the capacity of third -party equipment and facilities,
including pipelines and LNG product terminals, to transport, process, treat and store commodities. Purchase
obligations of $5.3 billion are related to market-based contracts for commodity product purchases with third
parties. The remainder is primarily our net share of purchase commitments for materials and services for jointly
owned fields and facilities where we are the operator.
Capital Resources and Liquidity
ConocoPhillips 2021 10-K
Capital Expenditures and Investments
Millions of Dollars
2021
2020
2019
Alaska
$
982
1,038
1,513
Lower 48
3,129
1,881
3,394
Canada
203
651
368
Europe, Middle East and North Africa
534
600
708
Asia Pacific
390
384
584
Other International
33
121
8
Corporate and Other
53
40
61
Capital Program*
$
5,324
4,715
6,636
* Excludes capital related to acquisitions of businesses, net of capital acquired.
Our capital expenditures and investments for the three-year period ended December 31, 2021, totaled
$16.7 billion. The 2021 expenditures supported key exploration and developments, primarily:
●
Development activities in the Lower 48, primarily Permian, Eagle Ford, and Bakken.
●
Appraisal and development activities in Alaska related to the Western North Slope and development
activities in the Greater Kuparuk Area.
●
Appraisal and development activities in the Montney and optimization of oil sands development in
Canada.
●
Continued development activities across assets in Norway.
●
Continued development activities in China, Malaysia, and Indonesia.
2022 Capital Budget
In December 2021, we announced our 2022 operating plan capital of $7.2 billion. The plan includes funding for
ongoing development drilling programs, major projects, exploration and appraisal activities, base maintenance and
$0.2 billion for projects to reduce the company’s scope 1 and 2 emissions intensity and investments in several
early-stage low-carbon opportunities that address end-use emissions.
Capital Resources and Liquidity
57
ConocoPhillips 2021 10-K
Guarantor Summarized Financial Information
We have various cross guarantees among ConocoPhillips, ConocoPhillips Company, and Burlington Resources LLC
with respect to publicly held debt securities. ConocoPhillips Company is 100 percent owned by ConocoPhillips.
Burlington Resources LLC is 100 percent owned by ConocoPhillips Company. ConocoPhillips and/or ConocoPhillips
Company have fully and unconditionally guaranteed the payment obligations of Burlington Resources LLC with
respect to its publicly held debt securities. Similarly, ConocoPhillips has fully and unconditionally guaranteed the
payment obligations of ConocoPhillips Company with respect to its publicly held debt securities. In addition,
ConocoPhillips Company has fully and unconditionally guaranteed the payment obligations of ConocoPhillips with
respect to its publicly held debt securities. All guarantees are joint and several.
The following tables present summarized financial information for the Obligor Group, as defined below:
●
The Obligor Group will reflect guarantors and issuers of guaranteed securities consisting of
ConocoPhillips, ConocoPhillips Company and Burlington Resources LLC.
●
Consolidating adjustments for elimination of investments in and transactions between the collective
guarantors and issuers of guaranteed securities are reflected in the balances of the summarized financial
information.
●
Non-Obligated Subsidiaries are exclud ed from this presentation.
Upon completing the Concho acquisition on January 15, 2021, we assumed Concho’s publicly traded debt of
approximately $3.9 billion in aggregate principal amount, which was recorded at the fair value of $4.7 billion on
the acquisition date. We completed a debt exchange offer that settled on February 8, 2021, of which 98 percent,
or approximately $3.8 billion in aggregate principal amount of Concho’s notes, were tendered and accepted for
new debt issued by ConocoPhillips. The new debt issued in the exchange is fully and unconditionally guaranteed
by ConocoPhillips Company. Both the guarantor and issuer of the exchange debt is reflected within the Obligor
Group presented here.
and
.
Transactions and balances reflecting activity between the Obligors and Non-Obligated Subsidiaries are presented
separately below:
Summarized Income Statement Data
Millions of Dollars
2021
Revenues and Other Income
$
30,457
Income (loss) before income taxes*
8,017
Net income (loss)
8,079
Net Income (Loss) Attributable to ConocoPhillips
8,079
*Includes approximately $5.4 billion of purchased commodities expense for transactions with Non-Obligated Subsidiaries.
Summarized Balance Sheet Data
Millions of Dollars
December 31, 2021
Current assets
$
7,689
Amounts due from Non-Obligated Subsidiaries, current
1,927
Noncurrent assets
69,841
Amounts due from Non-Obligated Subsidiaries, noncurrent
7,281
Current liabilities
8,005
Amounts due to Non-Obligated Subsidiaries, current
3,477
Noncurrent liabilities
30,677
Amounts due to Non-Obligated Subsidiaries, noncurrent
13,007
Capital Resources and Liquidity
ConocoPhillips 2021 10-K
Contingencies
We are subject to legal proceedings, claims, and liabilities that arise in the ordinary course of business. We accrue
for losses associated with legal claims when such losses are considered probable and the amounts can be
reasonably estimated. See “Critical Accounting Estimates” and
for information on contingencies.
Legal and Tax Matters
We are subject to various lawsuits and claims, including but not limited to matters involving oil and gas royalty and
severance tax payments, gas measurement and valuation methods, contract disputes, environmental damages,
climate change, personal injury, and property damage. Our primary exposures for such matters relate to alleged
royalty and tax underpayments on certain federal, state and privately owned properties, claims of alleged
environmental contamination and damages from historic operations, and climate change. We will continue to
defend ourselves vigorously in these matters.
Our legal organization applies its knowledge, experience, and professional judgment to the specific characteristics
of our cases, employing a litigation management process to manage and monitor the legal proceedings against us.
Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This
process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on
professional judgment and experience in using these litigation management tools and available information about
current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals
and determines if an adjustment of existing accruals, or establishment of new accruals, is required.
Environmental
We are subject to the same numerous international, federal, state, and local environmental laws and regulations
as other companies in our industry. The most significant of these environmental laws and regulations include,
among others, the:
●
U.S. Federal Clean Air Act, which governs air emissions.
●
U.S. Federal Clean Water Act, which governs discharges to water bodies.
●
European Union Regulation for Registration, Evaluation, Authorization and Restriction of Chemicals
(REACH).
●
U.S. Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA or
Superfund), which imposes liability on generators, transporters and arrangers of hazardous substances at
sites where hazardous substance releases have occurred or are threatening to occur.
●
U.S. Federal Resource Conservation and Recovery Act (RCRA), which governs the treatment, storage, and
disposal of solid waste.
●
U.S. Federal Oil Pollution Act of 1990 (OPA90), under which owners and operators of onshore facilities
and pipelines, lessees or permittees of an area in which an offshore facility is located, and owners and
operators of vessels are liable for removal costs and damages that result from a discharge of oil into
navigable waters of the U.S.
●
U.S. Federal Emergency Planning and Community Right-to-Know Act (EPCRA), which requires facilities to
report toxic chemical inventories with local emergency planning committees and response departments.
●
U.S. Federal Safe Drinking Water Act, which governs the disposal of wastewater in underground injection
wells.
●
U.S. Department of the Interior regulations, which relate to offshore oil and gas operations in U.S. waters
and impose liability for the cost of pollution cleanup resulting from operations, as well as potential liability
for pollution damages.
●
European Union Trading Directive resulting in European Emissions Trading Scheme.
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59
ConocoPhillips 2021 10-K
These laws and their implementing regulations set limits on emissions and, in the case of discharges to water,
establish water quality limits, and establish standards and impose obligations for the remediation of releases of
hazardous substances and hazardous wastes. They also, in most cases, require permits in association with new or
modified operations. These permits can require an applicant to collect substantial information in connection with
the application process, which can be expensive and time-consuming. In addition, there can be delays associated
with notice and comment periods and the agency’s processing of the application. Many of the delays associated
with the permitting process are beyond the control of the applicant.
Many states and foreign countries where we operate also have or are developing, similar environmental laws and
regulations governing these same types of activities. While similar, in some cases these regulations may impose
additional, or more stringent, requirements that can add to the cost and difficulty of marketing or transporting
products across state and international borders.
The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor easily
determinable as new standards, such as air emission standards and water quality standards, continue to evolve.
However, environmental laws and regulations, including those that may arise to address concerns about global
climate change, are expected to continue to have an increasing impact on our operations in the U.S. and in other
countries in which we operate. Notable areas of potential impacts include air emission compliance and
remediation obligations in the U.S. and Canada.
An example is the use of hydraulic fracturing, an essential completion technique that facilitates production of oil
and natural gas otherwise trapped in lower permeability rock formations. A range of local, state, federal, or
national laws and regulations currently govern hydraulic fracturing operations, with hydraulic fracturing currently
prohibited in some jurisdictions. Although hydraulic fracturing has been conducted for many decades, a number of
new laws, regulations and permitting requirements are under consideration by various state environmental
agencies, and others which could result in increased costs, operating restrictions, operational delays and/or limit
the ability to develop oil and natural gas resources. Governmental restrictions on hydraulic fracturing could impact
the overall profitability or viability of certain of our oil and natural gas investments. We have adopted operating
principles that incorporate established industry standards designed to meet or exceed government requirements.
Our practices continually evolve as technology improves and regulations change.
We also are subject to certain laws and regulations relating to environmental remediation obligations associated
with current and past operations. Such laws and regulations include CERCLA and RCRA and their state equivalents.
Longer-term expenditures are subject to considerable uncertainty and may fluctuate significantly.
We occasionally receive requests for information or notices of potential liability from the EPA and state
environmental agencies alleging that we are a potentially responsible party under CERCLA or an equivalent state
statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private
parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that
typically are not owned by us, but allegedly contain wastes attributable to our past operations. As of
December 31, 2021, there were 15 sites around the U.S. in which we were identified as a potentially responsible
party under CERCLA and comparable state laws.
Capital Resources and Liquidity
ConocoPhillips 2021 10-K
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.
on environmental litigatio n.
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61
ConocoPhillips 2021 10-K
Climate Change
Continuing political and social attention to the issue of global climate change has resulted in a broad range of
proposed or promulgated state, national and international laws focusing on GHG reduction. These proposed or
promulgated laws apply or could apply in countries where we have interests or may have interests in the future.
Laws in this field continue to evolve, and while it is not possible to accurately estimate either a timetable for
implementation or our future compliance costs relating to implementation, such laws, if enacted, could have a
material impact on our results of operations and financial condition. Examples of legislation and precursors for
possible regulation that do or could affect our operations include:
●
European Emissions Trading Scheme (ETS), the program through which many of the EU member states are
implementing the Kyoto Protocol. Our cost of compliance with the EU ETS in 2021 was approximately $19
million (net share before-tax ).
●
U.K. Emissions Trading Scheme, the program with which the U.K. has replaced the ETS. Our cost of
compliance with the U.K. ETS in 2021 was approximately $2.8 million (net share before -tax).
●
The Alberta Technology Innovation and Emissions Reduction (TIER) regulation requires any existing facility
with emissions equal to or greater than 100,000 metric tonnes of carbon dioxide, or equivalent, per year
to meet a facility benchmark intensity. The total cost of these regulations in 2021 was approximately $1
million (net share before-tax) .
●
The U.S. Supreme Court decision in Massachusetts v. EPA, 549 U.S. 497, 127 S.Ct. 1438 (2007), confirmed
that the EPA has the authority to regulate carbon dioxide as an “air pollutant” under the Federal Clean Air
Act.
●
The U.S. EPA’s announcement on March 29, 2010 (published as “Interpretation of Regulations that
Determine Pollutants Covered by Clean Air Act Permitting Programs,” 75 Fed. Reg. 17004 (April 2, 2010)),
and the EPA’s and U.S. Department of Transportation’s joint promulgation of a Final Rule on April 1, 2010,
that triggers regulation of GHGs under the Clean Air Act, may trigger more climate-based claims for
damages, and may result in longer agency review time for development projects.
●
The U.S. EPA’s announcement on January 14, 2015, outlining a series of steps it plans to take to address
methane and smog-forming volatile organic compound emissions from the oil and gas industry.
●
The U.S. government has announced on September 17, 2021 the Global Methane Pledge, a global
initiative to reduce global methane emissions by at least 30 percent from 2020 levels by 2030.
●
Carbon taxes in certain jurisdictions. Our cost of compliance with Norwegian carbon legislation in 2021
were fees of approximately $35 million (net share before -tax). We also incur a carbon tax for emissions
from fossil fuel combustion in our British Columbia and Alberta operations in Canada, totaling
approximately $5.7 million (net share before-tax).
●
The agreement reached in Paris in December 2015 at the 21
st
Nations Framework Convention on Climate Change, setting out a process for achieving global emission
reductions. The new administration has recommitted the United States to the Paris Agreement, and a
significant number of U.S. state and local governments and major corporations headquartered in the U.S.
have also announced related commitments. Accordingly, the U.S. administration set a new target on
April 22, 2021 of a 50 to 52 percent reduction in GHG emissions from 2005 levels in 2030.
In the U.S., some additional form of regulation may be forthcoming in the future at the federal and state levels
with respect to GHG emissions. Such regulation could take any of several forms that may result in the creation of
additional costs in the form of taxes, the restriction of output, investments of capital to maintain compliance with
laws and regulations, or required acquisition or trading of emission allowances. We are working to continuously
improve operational and energy efficiency through resource and energy conservation throughout our operations.
Capital Resources and Liquidity
ConocoPhillips 2021 10-K
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.
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.
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63
ConocoPhillips 2021 10-K
We announced in October 2020 the adoption of a Paris-aligned climate risk framework with the objective of
implementing a coherent set of choices designed to facilitate the success of our existing exploration and
production business through the energy transition. Given the uncertainties remaining about how the energy
transition will evolve, the strategy aims to be robust across a range of potential future outcomes.
The strategy is comprised of four pillars:
●
Targets : Our target framework consists of a hierarchy of targets, from a long-term ambition that sets the
direction and aim of the strategy, to a medium-term performance target for GHG emissions intensity, to
shorter-term targets for flaring and methane intensity reductions. These performance targets are
supported by lower-level internal business unit goals to enable the company to achieve the company-
wide targets. In September 2021, we increased our interim operational target and have set it to reduce
our gross operated and net equity (scope 1 and 2) emissions intensity by 40 to 50 percent from 2016
levels by 2030, an improvement from the previously announced target of 35 to 45 percent on only a gross
operated basis, with an ambition to achieve net-zero operated emissions by 2050. We have joined the
World Bank Flaring Initiative to work towards zero routine flaring of associated gas by 2030, with an
ambition to meet that goal by 2025.
●
Technology choices: We expanded our Marginal Abatement Cost Curve process to provide a broader
range of opportunities for emission reduction technology.
●
Portfolio choices: Our corporate authorization process requires all qualifying projects to include a GHG
price in their project approval economics. Different GHG prices are used depending on the region or
jurisdiction. Projects in jurisdictions with existing GHG pricing regimes incorporate the existing GHG price
and forecast into their economics. Projects where no existing GHG pricing regime exists utilize a scenario
forecast from our internally consistent World Energy Model. In this way, both existing and emerging
regulatory requirements are considered in our decision-making. The company does not use an estimated
market cost of GHG emissions when assessing reserves in jurisdictions without existing GHG regulations .
This is in contrast to changes to the cost of existing GHG emission regulations which can impact our
reserves calculations.
●
External engagement: Our external engagement aims to differentiate ConocoPhillips within the oil and
gas sector with our approach to managing climate-related risk. We are a Founding Member of the
Climate Leadership Council (CLC), an international policy institute founded in collaboration with business
and environmental interests to develop a carbon dividend plan. Participation in the CLC provides another
opportunity for ongoing dialogue about carbon pricing and framing the issues in alignment with our public
policy principles. We also belong to and fund Americans For Carbon Dividends, the education and
advocacy branch of the CLC.
ConocoPhillips 2021 10-K
Critical Accounting Estimates
The preparation of financial statements in conformity with GAAP requires management to select appropriate
accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities,
revenues and expenses.
for descriptions of our major accounting policies. Certain of these accounting
policies involve judgments and uncertainties to such an extent there is a reasonable likelihood materially different
amounts would have been reported under different conditions, or if different assumptions had been used. These
critical accounting estimates are discussed with the Audit and Finance Committee of the Board of Directors at least
annually. We believe the following discussions of critical accounting estimates address all important accounting
areas where the nature of accounting estimates or assumptions is material due to the levels of subjectivity and
judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change.
Oil and Gas Accounting
Accounting for oil and gas activity is subject to special accounting rules unique to the oil and gas industry. The
acquisition of G&G seismic information, prior to the discovery of proved reserves, is expensed as incurred, similar
to accounting for research and development costs. However, leasehold acquisition costs and exploratory well
costs are capitalized on the balance sheet pending determination of whether proved oil and gas reserves have
been recognized.
Property Acquisition Costs
At year-end 2021, we held $9.3 billion of net capitalized unproved property costs which consisted primarily of
individually significant and pooled leaseholds, mineral rights held in perpetuity by title ownership, exploratory
wells currently being drilled, and to a lesser extent, suspended exploratory wells and capitalized interest. This
amount increased by $6.9 billion at December 31, 2021 as compared to December 31, 2020, primarily due to the
Concho and Shell Permian acquisitions in the Permian Basin where we have an ongoing significant and active
development program. Outside of the Permian Basin, the remaining $2.0 billion is concentrated in 9 major
development areas. Management periodically assesses our unproved property for impairment based on the
results of exploration and drilling efforts and the outlook for commercialization.
For individually significant leaseholds, management periodically assesses for impairment based on exploration and
drilling efforts to date. For insignificant individual leasehold acquisition costs, management exercises judgment
and determines a percentage probability that the prospect ultimately will fail to find proved oil and gas reserves,
including estimates of future expirations, and pools that leasehold information with others in similar geographic
areas. For prospects in areas with limited, or no, previous exploratory drilling, the percentage probability of
ultimate failure is normally judged to be quite high. This judgmental percentage is multiplied by the leasehold
acquisition cost, and that product is divided by the contractual period of the leasehold to determine a periodic
leasehold impairment charge that is reported in exploration expense. This judgmental probability percentage is
reassessed and adjusted throughout the contractual period of the leasehold based on favorable or unfavorable
exploratory activity on the leasehold or on adjacent leaseholds, and leasehold impairment amortization expense is
adjusted prospectively.
Exploratory Costs
For exploratory wells, drilling costs are temporarily capitalized, or “suspended,” on the balance sheet, pending a
determination of whether potentially economic oil and gas reserves have been discovered by the drilling effort to
justify development.
65
ConocoPhillips 2021 10-K
If exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain capitalized on
the balance sheet as long as sufficient progress assessing the reserves and the economic and operating viability of
the project is being made. The accounting notion of “sufficient progress” is a judgmental area, but the accounting
rules do prohibit continued capitalization of suspended well costs on the expectation future market conditions will
improve or new technologies will be found that would make the development economically profitable. Often, the
ability to move into the development phase and record proved reserves is dependent on obtaining permits and
government or co-venturer approvals, the timing of which is ultimately beyond our control. Exploratory well costs
remain suspended as long as we are actively pursuing such approvals and permits, and believe they will be
obtained. Once all required approvals and permits have been obtained, the projects are moved into the
development phase, and the oil and gas reserves are designated as proved reserves.
At year-end 2021, total suspended well costs were $660 million, compared with $682 million at year-end 2020.
For additional information on suspended wells, including an aging analysis,
Proved Reserves
Engineering estimates of the quantities of proved reserves are inherently imprecise and represent only
approximate amounts because of the judgments involved in developing such information. Reserve estimates are
based on geological and engineering assessments of in-place hydrocarbon volumes, the production plan, historical
extraction recovery and processing yield factors, installed plant operating capacity and approved operating limits.
The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and
economic data and the efficiency of extracting and processing the hydrocarbons.
Despite the inherent imprecision in these engineering estimates, accounting rules require disclosure of “proved”
reserve estimates due to the importance of these estimates to better understand the perceived value and future
cash flows of a company’s operations. There are several authoritative guidelines regarding the engineering criteria
that must be met before estimated reserves can be designated as “proved.” Our geosciences and reservoir
engineering organization has policies and procedures in place consistent with these authoritative guidelines. We
have trained and experienced internal engineering personnel who estimate our proved reserves held by
consolidated companies, as well as our share of equity affiliates. See Oil and Gas supplemental disclosures for
additional information.
Proved reserve estimates are adjusted annually in the fourth quarter and during the year if significant changes
occur, and take into account recent production and subsurface information about each field. Also, as required by
current authoritative guidelines, the estimated future date when an asset will reach the end of its economic life is
based on 12-month average prices and current costs. This date estimates when production will end and affects
the amount of estimated reserves. Therefore, as prices and cost levels change from year to year, the estimate of
proved reserves also changes. Generally, our proved reserves decrease as prices decline and increase as prices
rise.
Our proved reserves include estimat ed quantities related to PSCs, reported under the “economic interest”
method, as well as variable-royalty regimes, and are subject to fluctuations in commodity prices; recoverable
operating expenses; and capital costs. If costs remain stable, reserve quantities attributable to recovery of costs
will change inversely to changes in commodity prices. We would expect reserves from these contracts to decrease
when product prices rise and increase when prices decline.
The estimation of proved reserves is also important to the income statement because the proved reserve estimate
for a field serves as the denominator in the unit-of-production calculation of the DD&A of the capitalized costs
for that asset. At year-end 2021, the net book value of productive PP&E subject to a unit-of-production calculation
was approximately $52 billion and the DD&A recorded on these assets in 2021 was approximately $7.0 billion. The
estimated proved reserves for our consolidated operations were 2.5 billion BOE at the end of 2020 and 4.0 billion
BOE at the end of 2021. If the estimates of proved reserves used in the unit-of-production calculations had been
lower by 10 percent across all calculations, before-tax DD&A in 2021 would have increased by an estimated
$774 million.
ConocoPhillips 2021 10-K
Business Combination—Valuation of Oil and Gas Properties
For recent transactions, management applied the principles of acquisition accounting under FASB ASC Topic 805 –
“Business Combinations” and allocated the purchase price to assets acquired and liabilities assumed, based on
their estimated fair values as of the acquisition date. Estimating the fair values involved making various
assumptions, of which the most significant assumptions relate to the fair values assigned to proved and unproved
oil and gas properties. Management utilized a discounted cash flow approach, based on market participant
assumptions, and engaged third party valuation experts in preparing fair value estimates.
Significant inputs incorporated within the valuation include future commodity price assumptions and production
profiles of reserve estimates, the pace of drilling plans, future operating and development costs, inflation rates,
and discount rates using a market -based weighted average cost of capital determined at the time of the
acquisition. When estimating the fair value of unproved properties, additional risk-weighting adjustments are
applied to probable and possible reserves.
The assumptions and inputs incorporated within the fair value estimates are subject to considerable management
judgement and are based on industry, market, and economic conditions prevalent at the time of the acquisition.
Although we based these estimates on assumptions believed to be reasonable, these estimates are inherently
unpredictable and uncertain and actual results could differ.
Impairments
Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances
indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. If
there is an indication the carrying amount of an asset may not be recovered, a recoverability test is performed
using management’s assumptions for prices, volumes and future development plans. If the sum of the
undiscounted cash flows before income-taxes is less than the carrying value of the asset group, the carrying value
is written down to estimated fair value and reported as an impairment in the periods in which the determination is
made. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable
cash flows that are largely independent of the cash flows of other groups of assets—generally on a field-by-field
basis for E&P assets. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of
impaired assets is typically determined based on the present values of expected future cash flows using discount
rates and prices believed to be consistent with those used by principal market participants, or based on a multiple
of operating cash flow validated with historical market transactions of similar assets where possible.
The expected future cash flows used for impairment reviews and related fair value calculations are based on
estimated future production volumes, commodity prices, operating costs and capital decisions, considering all
available evidence at the date of review. Differing assumptions could affect the timing and the amount of an
impairment in any period.
See
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
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ConocoPhillips 2021 10-K
Asset Retirement Obligations and Environmental Costs
Under various contracts, permits and regulations, we have material legal obligations to remove tangible
equipment and restore the land or seabed at the end of operations at operational sites. Our largest asset removal
obligations involve plugging and abandonment of wells, removal and disposal of offshore oil and gas platforms
around the world, as well as oil and gas production facilities and pipelines in Alaska. Fair value is estimated using a
present value approach, incorporating assumptions about estimated amounts and timing of settlements and
impacts of the use of technologies. Estimating future asset removal costs requires significant judgement. Most of
these removal obligations are many years, or decades, in the future and the contracts and regulations often have
vague descriptions of what removal practices and criteria must be met when the removal event actually occurs.
The carrying value of our asset retirement obligation estimate is sensitive to inputs such as asset removal
technologies and costs, regulatory and other compliance considerations, expenditure timing, and other inputs into
valuation of the obligation, including discount and inflation rates, which are all subject to change between the time
of initial recognition of the liability and future settlement of our obligation.
Normally, changes in asset removal obligations are reflected in the income statement as increases or decreases to
DD&A over the remaining life of the assets. However, for assets at or nearing the end of their operations, as well
as previously sold assets for which we retained the asset removal obligation, an increase in the asset removal
obligation can result in an immediate charge to earnings, because any increase in PP&E due to the increased
obligation would immediately be subject to impairment, due to the low fair value of these properties.
In addition to asset removal obligations, under the above or similar contracts, permits and regulations, we have
certain environmental-related projects. These are primarily related to remediation activities required by Canada
and various states within the U.S. at exploration and production sites. Future environmental remediation costs are
difficult to estimate because they are subject to change due to such factors as the uncertain magnitude of cleanup
costs, the unknown time and extent of such remedial actions that may be required, and the determination of our
liability in proportion to that of other responsible parties.
Projected Benefit Obligations
The actuarial determination of projected benefit obligations and company contribution requirements involves
judgment about uncertain future events, including estimated retirement dates, salary levels at retirement,
mortality rates, lump-sum election rates, rates of return on plan assets, future health care cost-trend rates, and
rates of utilization of health care services by retirees. Due to the specialized nature of these calculations, we
engage outside actuarial firms to assist in the determination of these projected benefit obligations and company
contribution requirements. Ultimately, we will be required to fund all vested benefits under pension and
postretirement benefit plans not funded by plan assets or investment returns, but the judgmental assumptions
used in the actuarial calculations significantly affect periodic financial statements and funding patterns over time.
Projected benefit obligations are particularly sensitive to the discount rate assumption. A 100 basis-point decrease
in the discount rate assumption would increase projected benefit obligations by $1.0 billion. Benefit expense is
sensitive to the discount rate and return on plan assets assumptions. A 100 basis-point decrease in the discount
rate assumption would increase annual benefit expense by $70 million, while a 100 basis-point decrease in the
return on plan assets assumption would increase annual benefit expense by $60 million. In determining the
discount rate, we use yields on high-quality fixed income investments matched to the estimated benefit cash flows
of our plans. We are also exposed to the possibility that lump sum retirement benefits taken from pension plans
during the year could exceed the total of service and interest components of annual pension expense and
trigger accelerated recognition of a portion of unrecognized net actuarial losses and gains. These benefit
payments are based on decisions by plan participants and are therefore difficult to predict. In the event there is a
significant reduction in the expected years of future service of present employees or the elimination of the accrual
of defined benefits for some or all of their future services for a significant number of employees, we could
recognize a curtailment gain or loss.
ConocoPhillips 2021 10-K
Contingencies
A number of claims and lawsuits are made against the company arising in the ordinary course of business.
Management exercises judgment related to accounting and disclosure of these claims which includes losses,
damages, and underpayments associated with environmental remediation, tax, contracts, and other legal disputes.
As we learn new facts concerning contingencies, we reassess our position both with respect to amounts
recognized and disclosed considering changes to the probability of additional losses and potential exposure.
However, actual losses can and do vary from estimates for a variety of reasons including legal, arbitration, or other
third-party decisions; settlement discussions; evaluation of scope of damages; interpretation of regulatory or
contractual terms; expected timing of future actions; and proportion of liability shared with other responsible
parties. Estimated future costs related to contingencies are subject to change as events evolve and as additional
information becomes available during the administrative and litigation processes. For additional information on
contingent liabilities, see the “Contingencies” section within “Capital Resources and Liquidity” and
Income Taxes
We are subject to income taxation in numerous jurisdictions worldwide. We record deferred tax assets and
liabilities to account for the expected future tax consequences of events that have been recognized in our financial
statements and our tax returns. We routinely assess our deferred tax assets and reduce such assets by a valuation
allowance if we deem it is more likely than not that some portion, or all, of the deferred tax assets will not be
realized. In assessing the need for adjustments to existing valuation allowances, we consider all available positive
and negative evidence. Positive evidence includes reversals of temporary differences, forecasts of future taxable
income, assessment of future business assumptions and applicable tax planning strategies that are prudent and
feasible. Negative evidence includes losses in recent years as well as the forecasts of future net income (loss) in
the realizable period. In making our assessment regarding valuation allowances, we weight the evidence based on
objectivity. Numerous judgments and assumptions are inherent in the determination of future taxable income,
including factors such as future operating conditions and the assessment of the effects of foreign taxes on our U.S.
federal income taxes (particularly as related to prevai ling oil and gas prices).
We regularly assess and, if required, establish accruals for uncertain tax positions that could result from
assessments of additional tax by taxing jurisdictions in countries where we operate. We recognize a tax benefit
from an uncertain tax position when it is more likely than not that the position will be sustained upon examination,
based on the technical merits of the position. These accruals for uncertain tax positions are subject to a significant
amount of judgment and are reviewed and adjusted on a periodic basis in light of changing facts and
circumstances considering the progress of ongoing tax audits, court proceedings, changes in applicable tax laws,
including tax case rulings and legislative guidance, or expiration of the applicable statute of limitations.
69
ConocoPhillips 2021 10-K
Cautionary Statement for the Purposes of the “Safe Harbor” Provisions of the
Private Securities Litigation Reform Act of 1995
This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933
and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact
included or incorporated by reference in this report, including, without limitation, statements regarding our future
financial position, business strategy, budgets, projected revenues, projected costs and plans, objectives of
management for future operatio ns and the anticipated impact of the Shell Enterprise LLC (Shell) transaction on the
company’s business and future financial and operating results are forward-looking statements. Examples of
forward-looking statements contained in this report include our expected production growth and outlook on the
business environment generally, our expected capital budget and capital expenditures, and discussions concerning
future dividends. You can often identify our forward-looking statements by the words “anticipate,” “believe,”
“budget,” “continue,” “could,” “effort,” “estimate,” “expect,” “forecast,” “intend,” “goal,” “guidance,” “may,”
“objective,” “outlook,” “plan,” “potential,” “predict,” “projection,” “seek,” “should,” “target,” “will,” “would” and
similar expressions.
We based the forward-looking statements on our current expectations, estimates and projections about ourselves
and the industries in which we operate in general. We caution you these statements are not guarantees of future
performance as they involve assumptions that, while made in good faith, may prove to be incorrect, and involve
risks and uncertainties we cannot predict. In addition, we based many of these forward -looking statements on
assumptions about future events that may prove to be inaccurate. Accordingly, our actual outcomes and results
may differ materially from what we have expressed or forecast in the forward -looking statements. Any differences
could result from a variety of factors and uncertainties, including, but not limited to, the following:
●
The impact of public health crises, including pandemics (such as COVID -19) and epidemics and any related
company or government policies or actions.
●
Global and regional changes in the demand, supply, prices, differentials or other market conditions
affecting oil and gas, including changes resulting from a public health crisis or from the imposition or
lifting of crude oil production quotas or other actions that might be imposed by OPEC and other producing
countries and the resulting company or third-party actions in response to such changes.
●
Fluctuations in crude oil, bitumen, natural gas, LNG and NGLs prices, including a prolonged decline in
these prices relative to historical or future expected levels.
●
The impact of significant declines in prices for crude oil, bitumen, natural gas, LNG and NGLs, which may
result in recognition of impairment charges on our long-lived assets, leaseholds and nonconsolidated
equity investments.
●
The potential for insufficient liquidity or other factors, such as those described herein, that could impact
our ability to repurchase shares and declare and pay dividends, whether fixed or variable.
●
Potential failures or delays in achieving expected reserve or production levels from existing and future oil
and gas developments, including due to operating hazards, drilling risks and the inherent uncertainties in
predicting reserves and reservoir performance.
●
Reductions in reserves replacement rates, whether as a result of the significant declines in commodity
prices or otherwise.
●
Unsuccessful exploratory drilling activities or the inability to obtain access to exploratory acreage.
●
Unexpected changes in costs or technical requirements for constructing, modifying or operating E&P
facilities.
●
Legislative and regulatory initiatives addressing environmental concerns, including initiatives addressing
the impact of global climate change or further regulating hydraulic fracturing, methane emissions, flaring
or water disposal.
●
Lack of, or disruptions in, adequate and reliable transportation for our crude oil, bitumen, natural gas,
LNG and NGLs.
●
Inability to timely obtain or maintain permits, including those necessary for construction, drilling and/or
development, or inability to make capital expenditures required to maintain compliance with any
necessary permits or applicable laws or regulations.
ConocoPhillips 2021 10-K
●
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
additional risks described in our other filings with the SEC.
71
ConocoPhillips 2021 10-K
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Financial Instrument Market Risk
We and certain of our subsidiaries hold and issue derivative contracts and financial instruments that expose our
cash flows or earnings to changes in commodity prices, foreign currency exchange rates or interest rates. We may
use financial and commodity-based derivative contracts to manage the risks produced by changes in the prices of
natural gas, crude oil and related products; fluctuations in interest rates and foreign currency exchange rates; or to
capture market opportunities.
Our use of derivative instruments is governed by an “Authority Limitations” document approved by our Board of
Directors that prohibits the use of highly leveraged derivatives or derivative instruments without sufficient
liquidity. The Authority Limitations document also establishes the Value at Risk (VaR) limits for the company, and
compliance with these limits is monitored daily. The Executive Vice President and Chief Financial Officer, who
reports to the Chief Executive Officer, monitors commodity price risk and risks resulting from foreign currency
exchange rates and interest rates. The Commercial organization manages our commercial marketing, optimizes
our commodity flows and positions, and monitors risks.
Commodity Price Risk
Our Commercial organization uses futures, forwards, swaps and options in various markets to accomplish the
following objectives:
●
Meet customer needs. Consistent with our policy to generally remain exposed to market prices, we use
swap contracts to convert fixed-price sales contracts, which are often requested by natural gas
consumers, to floating market prices.
●
Enable us to use market knowledge to capture opportunities such as moving physical commodities to
more profitable locations and storing commodities to capture seasonal or time premiums. We may use
derivatives to optimize these activities.
We use a VaR model to estimate the loss in fair value that could potentially result on a single day from the effect of
adverse changes in market conditions on the derivative financial instruments and derivative commodity
instruments we hold or issue, including commodity purchases and sales contracts recorded on the balance sheet at
December 31, 2021, as derivative instruments. Using Monte Carlo simulation, a 95 percent confidence level and a
one-day holding period, the VaR for those instruments issued or held for trading purposes or held for purposes
other than trading at December 31, 2021 and 2020, was immaterial to our consolidated cash flows and net income
attributable to ConocoPhillips.
Interest Rate Risk
The following table provides information about our debt instruments that are sensitive to changes in U.S. interest
rates. The table presents principal cash flows and related weighted-average interest rates by expected maturity
dates. Weighted-average variable rates are based on effective rates at the reporting date. The carrying amount of
our floating-rate debt approximates its fair value. A hypothetical 10 percent change in prevailing interest rates
would not have a material impact on interest expense associated with our floating-rate debt. The fair value of the
fixed-rate debt is measured using prices available from a pricing service that is corroborated by market data.
Changes to prevailing interest rates would not impact our cash flows associated with fixed rate debt, unless we
elect to repurchase or retire such debt prior to maturity.
ConocoPhillips 2021 10-K
Millions of Dollars Except as Indicated
Debt
Fixed
Average
Floating
Average
Rate
Interest
Rate
Interest
Expected Maturity Date
Maturity
Rate
Maturity
Year-End 2021
2022
$
346
2.53
%
$
500
1.03
%
2023
116
6.64
-
-
2024
459
3.51
-
-
2025
369
5.32
-
-
2026
1,355
5.06
-
-
Remaining years
14,338
5.80
283
0.11
Total
$
16,983
$
783
Fair value
$
21,668
$
783
Year-End 2020
2021
$
133
8.47
%
$
300
0.22
%
2022
346
2.53
500
1.12
2023
110
7.03
-
-
2024
459
3.51
-
-
2025
368
5.33
-
-
Remaining years
11,793
6.28
283
0.11
Total
$
13,209
$
1,083
Fair value
$
18,023
$
1,083
Foreign Currency Exchange Risk
We have foreign currency exchange rate risk resulting from international operations. We do not comprehensively
hedge the exposure to currency exchange rate changes although we may choose to selectively hedge certain
foreign currency exchange rate exposures, such as firm commitments for capital projects or local currency tax
payments, dividends and cash returns from net investments in foreign affiliates to be remitted within the coming
year, and investments in equity securities.
At December 31, 2021 and 2020, we held foreign currency exchange forwards hedging cross-border commercial
activity and foreign currency exchange swaps for purposes of mitigating our cash-related exposures. Although
these forwards and swaps hedge exposures to fluctuations in exchange rates, we elected not to utilize hedge
accounting. As a result, the change in the fair value of these foreign currency exchange derivatives is recorded
directly in earnings.
At December 31, 2021, we had outstanding foreign currency exchange forward contracts to buy $1.9 billion AUD at
$0.715 AUD against the U.S. dollar. At December 31, 2020, we had outstanding foreign currency exchange forward
contracts to sell $0.45 billion CAD at $0.748 CAD against the U.S. dollar. Based on the assumed volatility in the fair
value calculation, the net fair value of these foreign currency contracts at December 31, 2021 and December 31,
2020, were a before-tax gain of $21 million and before -tax loss of $16 million, respectively. Based on an adverse
hypothetical 10 percent change in the December 2021 and December 2020 exchange rate, this would result in an
additional before-tax loss of $134 million and $39 million, respectively. The sensitivity analysis is based on
changing one assumption while holding all other assumptions constant, which in practice may be unlikely to occur,
as changes in some of the assumptions may be correlated.
73
ConocoPhillips 2021 10-K
The gross notional and fair value of these positions at December 31, 2021 and 2020, were as follows :
Foreign Currency Exchange Derivatives
In Millions
Notional
Fair Value*
2021
2020
2021
2020
Sell Canadian dollar, buy U.S. dollar
CAD
-
450
-
(16)
Buy Canadian dollar, sell U.S. dollar
CAD
77
80
(1)
2
Buy Australian dollar, sell U.S. dollar
AUD
1,850
-
21
-
Sell British pound, buy euro
GBP
239
8
(8)
-
Buy British pound, sell euro
GBP
394
3
7
-
*Denominated in USD.
For additional information about our use of derivative instruments,
see Note 12
.
ConocoPhillips 2021 10-K
Item 8. Financial Statements and Supplementary Data
ConocoPhillips
Index to Financial Statements
Page
75
)
76
82
83
84
85
86
87
Supplementary Information
149
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ConocoPhillips 2021 10-K
Reports of Management
Management prepared, and is responsible for, the consolidated financial statements and the other information
appearing in this annual report. The consolidated financial statements present fairly the company’s financial
position, results of operations and cash flows in conformity with accounting principles generally accepted in the
United States. In preparing its consolidated financial statements, the company includes amounts that are based on
estimates and judgments management believes are reasonable under the circumstances. The company’s financial
statements have been audited by Ernst & Young LLP, an independent registered public accounting firm appointed
by the Audit and Finance Committee of the Board of Directors and ratified by stockholders. Management has
made available to Ernst & Young LLP all of the company’s financial records and related data, as well as the minutes
of stockholders’ and directors’ meetings.
Assessment of Internal Control Over Financial Reporting
Management is also responsible for establishing and maintaining adequate internal control over financial
reporting. ConocoPhillips’ internal control system was designed to provide reasonable assurance to the company’s
management and directors regarding the preparation and fair presentatio n of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those
systems determined to be effective can provide only reasonable assurance with respect to financial statement
preparation and presentation.
Management assessed the effectiveness of the company’s internal control over financial reporting as of
December 31, 2021. In making this assessment, it used the criteria set forth by the Committee of Sponsoring
Organizations of the Treadway Commission in
Internal Control—Integrated Framework (2013)
. Based on our
assessment, we believe the company’s internal control over financial reporting was effective as of
December 31, 2021. Management’s assessment of, and conclusion on, the effectiveness of internal control over
financial reporting did not include the internal controls of the assets acquired from Shell Enterprise LLC in
December 2021. The total assets acquired represented approximately 10 percent of the company’s consolidated
total assets at December 31, 2021.
Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of
December 31, 2021, and their report is included herein.
/s/ Ryan M. Lance
/s/ William L. Bullock, Jr.
Ryan M. Lance
William L. Bullock, Jr.
Chairman and
Chief Executive Officer
Executive Vice President and
Chief Financial Officer
ConocoPhillips 2021 10-K
Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of ConocoPhillips
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of ConocoPhillips (the Company) as of December
31, 2021 and 2020, the related consolidated income statement, consolidated statements of comprehensive
income, changes in equity and cash flows for each of the three years in the period ended December 31, 2021, and
the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the
consolidated financial statements present fairly, in all material respects, the financial position of the Company as
of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in
the period ended December 31, 2021, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2021, based
on criteria established in Internal Control–Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (2013 framework) and our report dated February 17, 2022, expressed
an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an
opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered
with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S.
federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the
PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial statements are free of material
misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of
material misstatement of the financial statements, whether due to error or fraud, and performing procedures that
respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and
disclosures in the financial statements. Our audits also included evaluating the accounting principles used and
significant estimates made by management, as well as evaluating the overall presentation of the financial
statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the
consolidated financial statements that were communicated or required to be communicated to the Audit and
Finance Committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial
statements and (2) involved our especially challenging, subjective or complex judgments. The communication of
critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a
whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the
critical audit matters or on the accounts or disclosures to which they relate.
77
ConocoPhillips 2021 10-K
Accounting for asset retirement obligations for certain offshore properties
Description of
the Matter
At December 31, 2021, the asset retirement obligation (ARO) balance totaled $5.9 billion. As
further described in Note 8, the Company records AROs in the period in which they are
incurred, typically when the asset is installed at the production location. The estimation of
obligations related to certain offshore assets requires significant judgment given the
magnitude and higher estimation uncertainty related to plugging and abandonment of wells
and removal and disposal of offshore oil and gas platforms, facilities and pipelines costs
(collectively, removal costs). Furthermore, given certain of these assets are nearing the end
of their operations, the impact of changes in these AROs may result in a material impact to
earnings given the relatively short remainin g useful lives of the assets.
Auditing the Company’s AROs for the obligations identified above is complex and highly
judgmental due to the significant estimation required by management in determining the
obligations. In particular, the estimates were sensitive to significant subjective assumptions
such as removal cost estimates and end of field life, which are affected by expectations
about future market or economic conditions.
How We
Addressed the
Matter in Our
Audit
We obtained an understanding, evaluated the design and tested the operating effectiveness
of the Company’s internal controls over its ARO estimation process, including management’s
review of the significant assumptions that have a material effect on the determination of the
obligations. We also tested management’s controls over the completeness and accuracy of
the financial data used in the valuation.
To test the AROs for the obligations identified above, our audit procedures included, among
others, assessing the significant assumptions and inputs used in the valuation, including
removal cost estimates and end of field life assumptions. For example, we evaluated
removal cost estimates by comparing to settlements and recent removal activities and costs.
We also compared end of field life assumptions to production forecasts.
Depreciation, depletion and amortization of proved oil and gas properties, plants and
equipment
Description of
the Matter
At December 31, 2021, the net book value of the Company’s proved oil and gas properties,
plants and equipment (PP&E) was $52 billion, and depreciation, depletion and amortization
(DD&A) expense was $7.0 billion for the year then ended. As described in Note 1, under the
successful efforts method of accounting, DD&A of PP&E on producing hydrocarbon
properties and steam-assisted gravity drainage facilities and certain pipeline and liquified
natural gas assets (those which are expected to have a declining utilization pattern) are
determined by the unit-of-production method. The unit-of-production method uses proved
oil and gas reserves, as estimated by the Company’s internal reservoir engineers.
Proved oil and gas reserve estimates are based on geological and engineering assessments
of in-place hydrocarbon volumes, the production plan, historical extraction recovery and
processing yield factors, installed plant operating capacity and approved operating limits.
Significant judgment is required by the Company’s internal reservoir engineers in evaluating
geological and engineering data when estimating proved oil and gas reserves. Estimating
proved oil and gas reserves also requires the selection of inputs, including oil and gas price
assumptions, future operating and capital costs assumptions and tax rates by jurisdiction,
among others. Because of the complexity involved in estimating proved oil and gas reserves,
management also used an independent petroleum engineering consulting firm to perform a
review of the processes and controls used by the Company’s internal reservoir engineers to
determine estimates of proved oil and gas reserves.
ConocoPhillips 2021 10-K
Auditing the Company’s DD&A calculation is complex because of the use of the work of the
internal reservoir engineers and the independent petroleum engineering consulting firm and
the evaluation of management’s determination of the inputs described above used by the
internal reservoir engineers in estimating proved oil and gas reserves.
How We
Addressed the
Matter in Our
Audit
We obtained an understanding, evaluated the design and tested the operating effectiveness
of the Company’s internal controls over its processes to calculate DD&A, including
management’s controls over the completeness and accuracy of the financial data provided
to the internal reservoir engineers for use in estimating proved oil and gas reserves.
Our audit procedures included, among others, evaluating the professional qualifications and
objectivity of the Company’s internal reservoir engineers primarily responsible for
overseeing the preparation of the proved oil and gas reserve estimates and the independent
petroleum engineering consulting firm used to review the Company’s processes and
controls. In addition, in assessing whether we can use the work of the internal reservoir
engineers, we evaluated the completeness and accuracy of the financial data and inputs
described above used by the internal reservoir engineers in estimating proved oil and gas
reserves by agreeing them to source documentation and we identified and evaluated
corroborative and contrary evidence. We also tested the accuracy of the DD&A calculation,
including comparing the proved oil and gas reserve amounts used in the calculation to the
Company’s reserve report.
Valuation and recognition of proved and unproved oil & gas properties acquired in
business combinations
Description of
the Matter
During 2021, the Company closed its acquisition of Concho Resources Inc. and its acquisition
of Permian assets from Shell Enterprises LLC resulting in the recognition of proved and
unproved oil and gas properties within net properties, plants and equipment of $18.9 billion
and $8.6 billion, respectively. As described in Note 3, the transactions were accounted for as
business combinations under FASB ASC 805 using the acquisition method, which requires
assets acquired and liabilities assumed to be measured at their acquisition date fair values.
Oil and gas properties were valued using a discounted cash flow approach based on market
participant assumptions and third party valuation experts were engaged by the Company to
prepare fair value estimates. Significant inputs to the valuation of proved and unproved oil
and gas properties include estimates of future commodity price assumptions and production
profiles of reserve estimates, the pace of drilling plans, future operating costs and discount
rates using a market -based weighted average cost of capital.
Auditing the Company's accounting for its valuation of proved and unproved oil and gas
properties is complex and considerably judgmental due to the significant estimation
required by management of reserves and resources associated with the acquired assets and
the sensitivity of significant assumptions used in determining the fair value. In evaluating
the reasonableness of management’s estimates and assumptions used, the audit testing
procedures performed required a high degree of auditor judgment and additional effort,
including involving internal specialists.
How We
Addressed the
Matter in Our
Audit
We obtained an understanding, evaluated the design and tested the operating effectiveness
of the Company’s internal controls over its process to estimate the fair value of the acquired
proved and unproved oil and gas properties, including management’s review of the
significant assumptions used as inputs to the fair value calculations and final recording of
the analysis.
79
ConocoPhillips 2021 10-K
To test the estimated fair value of the acquired proved and unproved oil and gas properties,
our audit procedures included, among others, evaluating the significant assumptions used
and testing the completeness and accuracy of the underlying data supporting the significant
assumptions. For example, we compared certain significant assumptions to current industry,
third-party data and historical results for reasonableness. We also performed sensitivity
analyses of significant assumptions, to evaluate the extent of their impact to the fair value
calculation. In addition, we involved our valuation specialists to assist with certain significant
assumptions included in the fair value estimate. Furthermore, we evaluated the professional
qualifications and objectivity of the third party valuation specialist engaged by the Company
to prepare the fair value of the acquired proved and unproved oil and gas properties.
/s/ Ernst & Young LLP
We have served as ConocoPhillips’ auditor since 1949.
Houston, Texas
February 17, 2022
ConocoPhillips 2021 10-K
Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of ConocoPhillips
Opinion on Internal Control over Financial Reporting
We have audited ConocoPhillips’ internal control over financial reporting as of December 31, 2021, based on
criteria established in Internal Control –Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, ConocoPhillips
(the Company) maintained, in all material respects, effective internal control over financial reporting as of
December 31, 2021, based on the COSO criteria. As indicated under the heading “Assessment of Internal Control
Over Financial Reporting” in the accompanying Reports of Management, management’s assessment of and
conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of
the assets acquired from Shell Enterprise LLC, which is included in the 2021 consolidated financial statements of
ConocoPhillips and constituted approximately 10 percent of consolidated total assets as of December 31, 2021.
Our audit of internal control over financial reporting of ConocoPhillips also did not include an evaluation of the
internal control over financial reporting of the assets acquired from Shell Enterprise LLC.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2021 and 2020, the
related consolidated income statement, consolidated statements of comprehensive income, changes in equity and
cash flows for each of the three years in the period ended December 31, 2021, and the related notes and our
report dated February 17, 2022, expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and
for its assessment of the effectiveness of internal control over financial reporting included under the heading
“Assessment of Internal Control Over Financial Reporting” in the accompanying “Reports of Management.” Our
responsibility is to express an opinion on the Company’s internal control over financial reporting based on our
audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect
to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the
Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting
was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a
material weakness exists, testing and evaluating the design and operating effectiveness of internal control based
on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We
believe that our audit provides a reasonable basis for our opinion.
81
ConocoPhillips 2021 10-K
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles. A company’s internal control over financial reporting
includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable
assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company are being made
only in accordance with authorizations of management and directors of the company; and (3) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the
company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.
/s/
February 17, 2022
Financial Statements
ConocoPhillips 2021 10-K
Consolidated Income Statement ConocoPhillips
Years Ended December 31
Millions of Dollars
2021
2020
2019
Revenues and Other Income
Sales and other operating revenues
$
Equity in earnings of affiliates
Gain on dispositions
Other income (loss)
(509 )
Total Revenues and Other Income
Costs and Expenses
Purchased commodities
Production and operating expenses
Selling, general and administrative expenses
Exploration expenses
Depreciation, depletion and amortization
Impairments
Taxes other than income taxes
Accretion on discounted liabilities
Interest and debt expense
Foreign currency transaction (gains) losses
(22 )
(72 )
Other expenses
Total Costs and Expenses
Income (loss) before income taxes
(3,140 )
Income tax provision (benefit)
(485 )
Net income (loss)
(2,655 )
Less: net income attributable to noncontrolling interests
(46 )
(68 )
Net Income (Loss) Attributable to ConocoPhillips
$
(2,701 )
Net Income (Loss) Attributable to ConocoPhillips Per Share
of Common Stock
(dollars)
Basic
$
(2.51 )
Diluted
(2.51 )
Average Common Shares Outstanding
(in thousands)
Basic
Diluted
See Notes to Consolidated Financial Statements.
Financial Statements
83
ConocoPhillips 2021 10-K
Consolidated Statement of Comprehensive Income ConocoPhillips
Years Ended December 31
Millions of Dollars
2021
2020
2019
Net Income (Loss)
$
(2,655 )
Other comprehensive income (loss)
Defined benefit plans
Prior service credit arising during the period
Reclassification adjustment for amortization of prior
service credit included in net income (loss)
(38 )
(32 )
(35 )
Net change
(38 )
(3 )
(35 )
Net actuarial gain (loss) arising during the period
(210 )
(55 )
Reclassification adjustment for amortization of net
actuarial losses included in net income (loss)
Net change
(93 )
Nonsponsored plans*
(3 )
Income taxes on defined benefit plans
(108 )
(2 )
Defined benefit plans, net of tax
(75 )
Unrealized holding gain (loss) on securities
(2 )
Reclassification adjustment for loss included in net income
(1 )
Income taxes on unrealized holding loss on securities
Unrealized holding gain (loss) on securities, net of tax
(2 )
Foreign currency translation adjustments
(124 )
Income taxes on foreign currency translation adjustments
(4 )
Foreign currency translation adjustments, net of tax
(124 )
Other Comprehensive Income, Net of Tax
Comprehensive Income (Loss)
(2,516 )
Less: comprehensive income attributable to noncontrolling interests
(46 )
(68 )
Comprehensive Income (Loss) Attributable to ConocoPhillips
$
(2,562 )
*Plans for which ConocoPhillips is not the primary obligor—primarily those administered by equity affiliates.
See Notes to Consolidated Financial Statements.
Financial Statements
ConocoPhillips 2021 10-K
Consolidated Balance Sheet ConocoPhillips
At December 31
Millions of Dollars
2021
2020
Assets
Cash and cash equivalents
$
Short-term investments
Accounts and notes receivable (net of allowance of $
, respectively)
Accounts and notes receivable—related parties
Investment in Cenovus Energy
Inventories
Prepaid expenses and other current assets
Total Current Assets
Investments and long-term receivables
Loans and advances—related parties
Net properties, plants and equipment
(net of accumulated DD&A of $
, respectively)
Other assets
Total Assets
$
Liabilities
Accounts payable
$
Accounts payable—related parties
Short-term debt
Accrued income and other taxes
Employee benefit obligations
Other accruals
Total Current Liabilities
Long-term debt
Asset retirement obligations and accrued environmental costs
Deferred income taxes
Employee benefit obligations
Other liabilities and deferred credits
Total Liabilities
Equity
Common stock (
Issued (2021—
Par value
Capital in excess of par
Treasury stock (at cost: 2021—
(50,920 )
(47,297 )
Accumulated other comprehensive loss
(4,950 )
(5,218 )
Retained earnings
Total Equity
Total Liabilities and Equity
$
See Notes to Consolidated Financial Statements.
Financial Statements
85
ConocoPhillips 2021 10-K
Consolidated Statement of Cash Flows ConocoPhillips
Years Ended December 31
Millions of Dollars
2021
2020
2019
Cash Flows From Operating Activities
Net income (loss)
$
(2,655 )
Adjustments to reconcile net income (loss) to net cash provided by
operating activities
Depreciation, depletion and amortization
Impairments
Dry hole costs and leasehold impairments
Accretion on discounted liabilities
Deferred taxes
(834 )
(444 )
Undistributed equity earnings
Gain on dispositions
(486 )
(549 )
(1,966 )
(Gain) loss on CVE common shares
(1,040 )
(649 )
Other
(788 )
(351 )
Working capital adjustments
Decrease (increase) in accounts and notes receivable
(2,500 )
Increase in inventories
(160 )
(25 )
(67 )
Decrease (increase) in prepaid expenses and other current
assets
(649 )
Increase (decrease) in accounts payable
(249 )
(378 )
Increase (decrease) in taxes and other accruals
(695 )
(676 )
Net Cash Provided by Operating Activities
Cash Flows From Investing Activities
Capital expenditures and investments
(5,324 )
(4,715 )
(6,636 )
Working capital changes associated with investing activities
(155 )
(103 )
Acquisition of businesses, net of cash acquired
(8,290 )
Proceeds from asset dispositions
Net sales (purchases) of investments
(658 )
(2,910 )
Collection of advances/loans—related parties
Other
(26 )
(108 )
Net Cash Used in Investing Activities
(8,544 )
(4,121 )
(6,618 )
Cash Flows From Financing Activities
Issuance of debt
Repayment of debt
(505 )
(254 )
(80 )
Issuance of company common stock
(5 )
(30 )
Repurchase of company common stock
(3,623 )
(892 )
(3,500 )
Dividends paid
(2,359 )
(1,831 )
(1,500 )
Other
(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
(2,047 )
(789 )
Cash, cash equivalents and restricted cash at beginning of period
Cash, Cash Equivalents and Restricted Cash at End of Period
$
Restricted cash of $
respectively, of our Consolidated Balance Sheet as of December 31, 2021.
Restricted cash of $
respectively, of our Consolidated Balance Sheet as of December 31, 2020.
See Notes to Consolidated Financial Statements.
Financial Statements
ConocoPhillips 2021 10-K
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
$
(42,905 )
(6,063 )
Net income
Other comprehensive loss
Dividends declared—ordinary ($
(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
Changes in Accounting Principles*
(40 )
Other
Balances at December 31, 2019
$
(46,405 )
(5,357 )
Net income (loss)
(2,701 )
(2,655 )
Other comprehensive income
Dividends declared—ordinary ($
(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
Other
Balances at December 31, 2020
$
(47,297 )
(5,218 )
Net income
Other comprehensive income
Dividends declared
Ordinary ($
(2,359 )
(2,359 )
Variable return of cash ($
(260 )
(260 )
Acquisition of Concho
Repurchase of company common stock
(3,623 )
(3,623 )
Distributed under benefit plans
Other
Balances at December 31, 2021
$
(50,920 )
(4,950 )
*Cumulative effect of the adoption of ASU No. 2018-02, "Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income."
See Notes to Consolidated Financial Statements.
Notes to Consolidated Financial Statements
87
ConocoPhillips 2021 10-K
Notes to Consolidated Financial Statements
Note 1—Accounting Policies
●
Consolidation Principles and Investments
—Our consolidated financial statements include the accounts of
majority-owned, controlled subsidiaries and, if applicable, variable interest entities where we are the
primary beneficiary. The equity method is used to account for investments in affiliates in which we have
the ability to exert significant influence over the affiliates’ operating and financial policies. When we do
not have the ability to exert significant influence, the investment is measured at fair value except when
the investment does not have a readily determinable fair value. For those exceptions, it will be measured
at cost minus impairment, plus or minus observable price changes in orderly transactions for an identical
or similar investment of the same issuer. Undivided interests in oil and gas joint ventures, pipelines,
natural gas plants and terminals are consolidated on a proportionate basis. Other securities and
investments are generally carried at cost. We manage our operations through
defined by geographic region: Alaska; Lower 48; Canada; Europe, Middle East and North Africa; Asia
Pacific; and Other International.
●
Foreign Currency Translation
—Adjustments resulting from the process of translating foreign functional
currency financial statements into U.S. dollars are included in accumulated other comprehensive loss in
common stockholders’ equity. Foreign currency transaction gains and losses are included in current
earnings. Some of our foreign operations use their local currency as the functional currency.
●
Use of Estimates
—The preparation of financial statements in conformity with U.S. GAAP requires
management to make estimates and assumptions that affect the reported amounts of assets, liabilities,
revenues and expenses and the disclosures of contingent assets and liabilities. Actual results could differ
from these estimates.
●
Revenue Recognition
—Revenues associated with the sales of crude oil, bitumen, natural gas, LNG, NGLs
and other items are recognized at the point in time when the customer obtains control of the asset. In
evaluating when a customer has control of the asset, we primarily consider whether the transfer of legal
title and physical delivery has occurred, whether the customer has significant risks and rewards of
ownership and whether the customer has accepted delivery and a right to payment exists. These
products are typically sold at prevailing market prices. We allocate variable market-based consideration
to deliveries (performance obligations) in the current period as that consideration relates specifically to
our efforts to transfer control of current period deliveries to the customer and represents the amount we
expect to be entitled to in exchange for the related products.
Revenues associated with transactions commonly called buy/sell contracts, in which the purchase and
sale of inventory with the same counterparty are entered into “in contemplation” of one another, are
combined and reported net (i.e., on the same income statement line).
●
Shipping and Handling Costs
—We typically incur shipping and handling costs prior to control transferring
to the customer and account for these activities as fulfillment costs. Accordingly, we include shipping and
handling costs in production and operating expenses for production activities. Transportation costs
related to marketing activities are recorded in purchased commodities. Freight costs billed to customers
are treated as a component of the transaction price and recorded as a component of revenue when the
customer obtains control.
●
Cash Equivalents
—Cash equivalents are highly liquid, short-term investments that are readily convertible
to known amounts of cash and have original maturities of 90 days or less from their date of purchase.
They are carried at cost plus accrued interest, which approximates fair value.
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
●
Short-Term Investments
—Short-term investments include investments in bank time deposits and
marketable securities (commercial paper and government obligations) which are carried at cost plus
accrued interest and have original maturities of greater than 90 days but within one year or when the
remaining maturities are within one year. We also invest in financial instruments classified as available
for sale debt securities which are carried at fair value. Those instruments are included in short-term
investments when they have remaining maturities within one year as of the balance sheet date.
●
Long-Term Investments in Debt Securities
—Long-term investments in debt securities includes financial
instruments classified as available for sale debt securities with remaining maturities greater than one year
as of the balance sheet date. They are carried at fair value and presented within the “Investments and
long-term receivables” line of our consolidated balance sheet.
●
Inventories
—We have several valuation methods for our various types of inventories and consistently use
the following methods for each type of inventory. The majority of our commodity-related inventories are
recorded at cost using the LIFO basis. We measure these inventories at the lower-of-cost-or-market in
the aggregate. Any necessary lower-of-cost-or-market write-downs at year end are recorded as
permanent adjustments to the LIFO cost basis. LIFO is used to better match current inventory costs with
current revenues. Costs include both direct and indirect expenditures incurred in bringing an item or
product to its existing condition and location, but not unusual/nonrecurring costs or research and
development costs. Materials, supplies and other miscellaneous inventories, such as tubular goods and
well equipment, are valued using various methods, including the weighted-average -cost method and the
FIFO method, consistent with industry practice.
●
Fair Value Measurements
—Assets and liabilities measured at fair value and required to be categorized
within the fair value hierarchy are categorized into one of three different levels depending on the
observability of the inputs employed in the measurement. Level 1 inputs are quoted prices in active
markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices
included within Level 1 for the asset or liability, either directly or indirectly through market -corroborated
inputs. Level 3 inputs are unobservable inputs for the asset or liability reflecting significant modifications
to observable related market data or our assumptions about pricing by market participants.
●
Derivative Instruments
—Derivative instruments are recorded on the balance sheet at fair value. If the
right of offset exists and certain other criteria are met, derivative assets and liabilities with the same
counterparty are netted on the balance sheet and the collateral payable or receivable is netted against
derivative assets and derivative liabilities, respectively.
Recognition and classification of the gain or loss that results from recording and adjusting a derivative to
fair value depends on the purpose for issuing or holding the derivative. Gains and losses from derivatives
not accounted for as hedges are recognized immediately in earnings. We do not apply hedge accounting
to our derivative instruments.
●
Oil and Gas Exploration and Development
—Oil and gas exploration and development costs are
accounted for using the successful efforts method of accounting.
Property Acquisition Costs
—Oil and gas leasehold acquisition costs are capitalized and included in
the balance sheet caption PP&E. Leasehold impairment is recognized based on exploratory
experience and management’s judgment. Upon achievement of all conditions necessary for reserves
to be classified as proved, the associated leasehold costs are reclassified to proved properties.
Exploratory Costs
—Geological and geophysical costs and the costs of carrying and retaining
undeveloped properties are expensed as incurred. Exploratory well costs are capitalized, or
“suspended,” on the balance sheet pending further evaluation of whether economically recoverable
reserves have been found. If economically recoverable reserves are not found, exploratory well costs
are expensed as dry holes. If exploratory wells encounter potentially economic quantities of oil and
Notes to Consolidated Financial Statements
89
ConocoPhillips 2021 10-K
gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the
reserves and the economic and operating viability of the project is being made. For complex
exploratory discoveries, it is not unusual to have exploratory wells remain suspended on the balance
sheet for several years while we perform additional appraisal drilling and seismic work on the
potential oil and gas field or while we seek government or co-venturer approval of development
plans or seek environmental permitting. Once all required approvals and permits have been
obtained, the projects are moved into the development phase, and the oil and gas resources are
designated as proved reserves.
Management reviews suspended well balances quarterly, continuously monitors the results of the
additional appraisal drilling and seismic work, and expenses the suspended well costs as dry holes
when it judges the potential field does not warrant further investment in the near term.
Development Costs
—Costs incurred to drill and equip development wells, including unsuccessful
development wells, are capital ized.
Depletion and Amortization
—Leasehold costs of producing properties are depleted using the unit-of-
production method based on estimated proved oil and gas reserves. Amortization of development
costs is based on the unit-of-production method using estimated proved developed oil and gas
reserves.
●
Capitalized Interest
—Interest from external borrowings is capitalized on major projects with an expected
construction period of one year or longer. Capitalized interest is added to the cost of the underlying asset
and is amortized over the useful lives of the assets in the same manner as the underlying assets.
●
Depreciation and Amortization
—Depreciation and amortization of PP&E on producing hydrocarbon
properties and SAGD facilities and certain pipeline and LNG assets (those which are expected to have a
declining utilization pattern), are determined by the unit-of-production method. Depreciation and
amortization of all other PP&E are determined by either the individual-unit-straight-line method or the
group-straight-line method (for those individual units that are highly integrated with other units).
●
Impairment of Properties, Plants and Equipment
—Long-lived assets used in operations are assessed for
impairment whenever changes in facts and circumstances indicate a possible significant deterioration in
the future cash flows expected to be generated by an asset group. If there is an indication the carrying
amount of an asset may not be recovered, a recoverability test is performed using management’s
assumptions for prices, volumes and future development plans. If the sum of the undiscounted cash
flows before income-taxes is less than the carrying value of the asset group, the carrying value is written
down to estimated fair value and reported as an impairment in the period in which the determination is
made. Individual assets are grouped for impairment purposes at the lowest level for which there are
identifiable cash flows that are largely independent of the cash flows of other groups of assets—generally
on a field-by-field basis for E&P assets. Because there usually is a lack of quoted market prices for long-
lived assets, the fair value of impaired assets is typically determined based on the present values of
expected future cash flows using discount rates and prices believed to be consistent with those used by
principal market participants, or based on a multiple of operating cash flow validated with historical
market transactions of similar assets where possible.
The expected future cash flows used for impairment reviews and related fair value calculations are based
on estimated future production volumes, commodity prices, operating costs and capital decisions,
considering all available evidence at the date of review. The impairment review includes cash flows from
proved developed and undeveloped reserves, including any development expenditures necessary to
achieve that production. Additionally, when probable and possible reserves exist, an appropriate risk-
adjusted amount of these reserves may be included in the impairment calculation.
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
Long-lived assets committed by management for disposal within one year are accounted for at the lower
of amortized cost or fair value, less cost to sell, with fair value determined using a binding negotiated
price, if available, or present value of expected future cash flows as previously described.
●
Maintenance and Repairs
—Costs of maintenance and repairs, which are not significant improvements,
are expensed when incurred.
●
Property Dispositions
—When complete units of depreciable property are sold, the asset cost and related
accumulated depreciation are eliminated, with any gain or loss reflected in the “Gain on dispositions” line
of our consolidated income statement. When partial units of depreciable property are disposed of or
retired which do not significantly alter the DD&A rate, the difference between asset cost and salvage
value is charged or credited to accumulated depreciation.
●
Asset Retirement Obligations and Environmental Costs
—The
fair value of legal obligations to retire and
remove long-lived assets are recorded in the period in which the obligation is incurred (typically when the
asset is installed at the production location). Fair value is estimated using a present value approach,
incorporating assumptions about estimated amounts and timing of settlements and impacts of the use of
technologies.
Environmental expenditures are expensed or capitalized, depending upon their future economic benefit.
Expenditures relating to an existing condition caused by past operations, and those having no future
economic benefit, are expensed. Liabilities for environmental expenditures are recorded on an
undiscounted basis (unless acquired through a business combination, which we record on a discounted
basis) when environmental assessments or cleanups are probable and the costs can be reasonably
estimated. Recoveries of environmental remediation costs from other parties are recorded as assets
when their receipt is probable and estimable.
●
Impairment of Investments in Nonconsolidated Entities
—Investments in nonconsolidated entities are
assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has
occurred. When such a condition is judgmentally determined to be other than temporary, the carrying
value of the investment is written down to fair value. The fair value of the impaired investment is based
on quoted market prices, if available, or upon the present value of expected future cash flows using
discount rates and prices believed to be consistent with those used by principal market participants, plus
market analysis of comparable assets owned by the investee, if appropriate.
●
Guarantees
—The fair value of a guarantee is determined and recorded as a liability at the time the
guarantee is given. The initial liability is subsequently reduced as we are released from exposure under
the guarantee. We amortize the guarantee liability over the relevant time period, if one exists, based on
the facts and circumstances surrounding each type of guarantee. In cases where the guarantee term is
indefinite, we reverse the liability when we have information indicating the liability is essentially relieved
or amortize it over an appropriate time period as the fair value of our guarantee exposure declines over
time. We amortize the guarantee liability to the related income statement line item based on the nature
of the guarantee. When it becomes probable that we will have to perform on a guarantee, we accrue a
separate liability if it is reasonably estimable, based on the facts and circumstances at that time. We
reverse the fair value liability only when there is no further exposure under the guarantee.
●
Share-Based Compensation
—We recognize share -based compensation expense over the shorter of the
service period (i.e., the stated period of time required to earn the award) or the period beginning at the
start of the service period and ending when an employee first becomes eligible for retirement. We have
elected to recognize expense on a straight-line basis over the service period for the entire award, whether
the award was granted with ratable or cliff vesting.
Notes to Consolidated Financial Statements
91
ConocoPhillips 2021 10-K
●
Income Taxes
—Deferred income taxes are computed using the liability method and are provided on all
temporary differences between the financial reporting basis and the tax basis of our assets and liabilities,
except for deferred taxes on income and temporary differences related to the cumulative translation
adjustment considered to be permanently reinvested in certain foreign subsidiaries and foreign corporate
joint ventures. Allowable tax credits are applied currently as reductions of the provision for income taxes.
Interest related to unrecognized tax benefits is reflected in interest and debt expense, and penalties
related to unrecognized tax benefits are reflected in production and operating expenses.
●
Taxes Collected from Customers and Remitted to Governmental Authorities
—Sales and value-added
taxes are recorded net.
●
Net Income (Loss) Per Share of Common Stock
—Basic net income (loss) per share of common stock is
calculated based upon the daily weighted-average number of common shares outstanding during the
year. Also, this
calculation includes fully vested stock and unit awards that have not yet been issued as
common stock, along with an adjustment to net income (loss) for dividend equivalents paid on unvested
unit awards that are considered participating securities. Diluted net income per share of common stock
includes unvested stock, unit or option awards granted under our compensation plans and vested but
unexercised stock options, but only to the extent these instruments dilute net income per share, primarily
under the treasury-stock method. Diluted net loss per share, which is calculated the same as basic net
loss per share, does not assume conversion or exercise of securities that would have an antidilutive effect.
Treasury stock is excluded from the daily weighted -average number of common shares outstanding in
both calculations. The earnings per share impact of the participating securities is immaterial.
Note 2—Inventories
Inventories at December 31 were:
Millions of Dollars
2021
2020
Crude oil and natural gas
$
Materials and supplies
Total inventories
$
Inventories valued on the LIFO basis
$
The estimated excess of current replacement cost over LIFO cost of inventories was approximately $
and $
Note 3—Asset Acquisitions and Dispositions
All gains or losses on asset dispositions are reported before-tax and are included net in the “Gain on dispositions”
line on our consolidated income stat ement. All cash proceeds and payments are included in the “Cash Flows From
Investing Activities” section of our consolidated statement of cash flows.
During the year, we completed the acquisitions of Concho Resources Inc. (Concho) and of Shell Enterprises LLC’s
(Shell) Permian assets. The acquisitions were accounted for as business combinations under FASB Topic ASC 805
using the acquisition method, which requires assets acquired and liabilities assumed to be measured at their
acquisition date fair values. Fair value measurements were made for acquired assets and liabilities, and
adjustments to those measurements may be made in subsequent periods, up to one year from the acquisition date
as we identify new information about facts and circumstances that existed as of the acquisition date to consider.
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
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 $
exchanged for each outstanding share of Concho common stock.
Total Consideration
Number of shares exchanged
$
$
**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 $
identifiable assets and liabilities based on their fair values as of January 15, 2021.
Assets Acquired
Millions of Dollars
Cash and cash equivalents
$
Accounts receivable, net
Inventories
Prepaid expenses and other current assets
Investments and long-term receivables
Net properties, plants and equipment
Other assets
Total assets acquired
$
Liabilities Assumed
Accounts payable
$
Accrued income and other taxes
Employee benefit obligations
Other accruals
Long-term debt
Asset retirement obligations and accrued environmental costs
Deferred income taxes
Other liabilities and deferred credits
Total liabilities assumed
$
Net assets acquired
$
Notes to Consolidated Financial Statements
93
ConocoPhillips 2021 10-K
With the completion of the Concho transaction, we acquired proved and unproved properties of approximately
$
We recognized approximately $
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
$
Selling, general and administration expenses
Exploration expenses
Taxes other than income taxes
Other expenses
$
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 $
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 $
million and $
include a before- and after-tax loss of $
contracts. The before-tax loss is recorded within “Total Revenues and Other Income” on our consolidated income
statement.
Acquisition of Shell Permian Assets
In December 2021, we completed our acquisition of Shell assets in the Permian based Delaware Basin. The
accounting close date used for reporting purposes was December 31, 2021. Assets acquired include approximately
$
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 $
billion was allocated to the identifiable assets and liabilities based on their fair values at the acquisition date.
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
Assets Acquired
Millions of Dollars
Accounts receivable, net
$
Inventories
Net properties, plants and equipment
Other assets
Total assets acquired
$
Liabilities Assumed
Accounts payable
$
Accrued income and other taxes
Other accruals
Asset retirement obligations and accrued environmental costs
Other liabilities and deferred credits
Total liabilities assumed
$
Net assets acquired
$
With the completion of the Shell Permian transaction, we acquired proved and unproved properties of
approximately $
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
$
Income (loss) before income taxes
Net Income (Loss) attributable to ConocoPhillips
Earnings per share:
Basic net loss
$
Diluted net loss
Millions of Dollars
Year Ended December 31, 2020
Pro forma
Pro forma
Pro forma
As reported
Concho
Shell
Combined
Total Revenues and Other Income
$
Income (loss) before income taxes
(3,140 )
(247 )
(2,600 )
Net Income (Loss) attributable to ConocoPhillips
(2,701 )
(189 )
(2,392 )
Earnings per share:
Basic net loss
$
(2.51 )
(1.75 )
Diluted net loss
(2.51 )
(1.75 )
Notes to Consolidated Financial Statements
95
ConocoPhillips 2021 10-K
The unaudited supplemental pro forma financial information is presented for illustration purposes only and is not
necessarily indicative of the operating results that would have occurred had the transactions been completed on
January 1, 2020, nor is it necessarily indicative of future operating results of the combined entity. The unaudited
pro forma financial information for the twelve-month period ending December 31, 2020 is a result of combining
the consolidated income statement of ConocoPhillips with the results of Concho and the assets acquired from
Shell. The pro forma results do not include transaction-related costs, nor any cost savings anticipated as a result of
the transactions. The pro forma results include adjustments from Concho’s historical results to reverse
impairment expense of $
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
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.
Assets Sold
In 2020, we completed the sale of our Australia -West asset and operations. The sales agreement entitled us to a
$
2021, FID was announced and as such, we recognized a $
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 $
operations related to this transaction are reflected in our Asia Pacific segment.
In the second half of 2021, we sold our interests in certain noncore assets in our Lower 48 segment for
approximately $
$
tax loss on disposition of $
International segment.
In 2021, we recorded contingent payments of $
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
. The term for contingent payments in our Canada segment ends on May 16, 2022. In our Lower 48
segment, the
. The term for contingent payments in our Lower 48
segment goes through 2023.
Planned Dispositions
In December 2021, we entered into an agreement to sell two subsidiaries holding our Indonesia assets and
operations to MedcoEnergi for $
2021. The subsidiaries hold our
(PSC) and a
approximately $
quarter, and as of December 31, 2021, we have reclassified $
current assets” and $
before-tax earnings associated with our Indonesia subsidiaries were $
the years ended December 31, 2021, 2020 and 2019, respectively . This transaction is expected to close in early
2022, subject to regulatory approvals and other specific conditions precedent. Results of operations for the
subsidiaries to be sold are reported within our Asia Pacific segment.
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
In January 2022, we entered into an agreement to sell our interests in certain noncore assets in the Lower 48
segment for $
quarter of 2022.
2020
Asset Acquisition
In August 2020, we completed the acquisition of additional Montney acreage in Canada from Kelt Exploration Ltd.
for $
associated with partially owned infrastructure. This acquisition consisted primarily of undeveloped properties and
included
existing Montney position. The transaction increased our Montney acreage position to approximately
acres with a
the recognition 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 $
adjustments.
sold were reported in our Lower 48 segment.
In March 2020, we completed the sale of our Niobrara interests for approximately $
adjustments and recognized a before-tax loss on disposition of $
in Niobrara had a net carrying value of $
ARO. The before-tax losses associated with our interests in Niobrara, including the loss on disposition noted above
and an impairment of $
quarter of 2019, were $
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 $
tax gain of $
subsidiaries sold was approximately $
primarily of $
deferred tax liabilities, and $
sold, including the gain on disposition noted above, were $
December 31, 2020 and 2019, respectively. Production from the beginning of the year through the disposition
date in May 2020 averaged
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
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 $
consolidated income statement. We completed the sale in the second quarter of 2019. Results of operations for
these assets were reported in our Lower 48 segment.
Notes to Consolidated Financial Statements
97
ConocoPhillips 2021 10-K
In April 2019, we entered into an agreement to sell two ConocoPhillips U.K. subsidiaries to Chrysaor E&P Limited
for $
September 30, 2019, we completed the sale for proceeds of $
and $
held our exploration and production assets in the U.K. At the time of disposition, the net carrying value was
approximately $
translation adjustments, and $
billion of working capital. The before-tax earnings associated with the subsidiaries sold, including the gain on
dispositions noted above, was $
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 $
percent interest in the Greater Sunrise Fields to the government of Timor-Leste for $
Sunrise Fields were included in our Asia Pacific segment.
In the fourth quarter of 2019, we sold our interests in the Magnolia field and platform for net proceeds of $
million and recognized a before-tax gain of $
million of PP&E offset by $
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
$
Loans and advances—related parties
Long-term receivables
Long-term investments in debt securities
Other investments
$
Equity Investments
Affiliated companies in which we had a significant equity investment at December 31, 2021, included:
●
APLNG—
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)—
QatarEnergy (
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
$
Income before income taxes
Net income
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
Summarized 100 percent balance sheet information for equity method investments in affiliated companies,
combined, was as follows:
Millions of Dollars
2021
2020
Current assets
$
Noncurrent assets
Current liabilities
Noncurrent liabilities
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 $
companies. Dividends received from affiliates were $
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 $
drawn from the facility. APLNG achieved financial completion on its original $
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
facilities. APLNG made its first principal and interest repayment in March 2017 and is scheduled to make
payments until September 2030. At December 31, 2021, a balance of $
During the fourth quarter of 2021, Origin Energy Limited agreed to the sale of
for $
exercising our preemption right under the APLNG Shareholders Agreement to purchase an additional
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 $
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 $
December 31, 2021. This carrying value is included in the “Investments and long-term receivables” line on our
consolidated balance sheet.
Notes to Consolidated Financial Statements
99
ConocoPhillips 2021 10-K
The historical cost basis of our
resulting in a basis difference of $
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 $
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 $
2021, the book value of our equity method investment in QG3, excluding the project financing, was $
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
Terminal and Golden Pass Pipeline, but we sold those interests in the second quarter of 2019 while retaining the
basic use agreements. Currently, the LNG from QG3 is being sold to markets outside of the U.S.
Loans
As part of our normal ongoing business operations and consistent with industry practice, we enter into numerous
agreements with other parties to pursue business opportunities. Included in such activity are loans to certain
affiliated and non-affiliated companies.
At December 31, 2021, significant loans to affiliated companies include $
which is recorded within the “Accounts and notes receivable—related parties” line on our consolidated balance
sheet. QG3 secured project financing of $
export credit agencies (ECA), $
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.
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)
Ownership of issued and outstanding common stock
%
Closing price on NYSE on last trading day ($/share)
$
Fair Value (millions of dollars)
$
During 2021, we began to dispose of CVE shares, selling
$
are presented within “Cash Flows from Investing Activities” on our consolidated statement of cash flows. Subject
to market conditions, we intend to continue to decrease our investment.
All gains and losses are recognized within “Other income (loss)” on our consolidated income statement.
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
Millions of Dollars
2021
2020
2019
Total Net gain (loss) on equity securities
$
(855 )
Less: Net gain (loss) on equity securities sold during the period
Unrealized gain (loss) on equity securities still held at
$
(855 )
Note 6—Suspended Wells and Exploration Expenses
The following table reflects the net changes in suspended exploratory well costs during 2021, 2020 and 2019:
Millions of Dollars
2021
2020
2019
Beginning balance at January 1
$
Additions pending the determination of proved reserves
Reclassifications to proved properties
(42 )
(11 )
Sales of suspended wells
(313 )
(54 )
Charged to dry hole expense
(32 )
(147 )
(10 )
Ending balance at December 31
$
*
*Includes $
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
$
Exploratory well costs capitalized for a period greater than one year
Ending balance
$
*
*Includes $
Number of projects with exploratory well costs capitalized for a period
greater than one year
Notes to Consolidated Financial Statements
101
ConocoPhillips 2021 10-K
The following table provides a further aging of those exploratory well costs that have been capitalized for more
than one year since the completion of drilling as of December 31, 2021:
Millions of Dollars
Suspended Since
Total
2018-2020
2015-2017
2004-2014
Willow—Alaska
(1)
Surmont—Canada
(1)
PL 1009—Norway
(1)
PL 891—Norway
(1)
Narwhal Trend—Alaska
(1)
WL4-00—Malaysia
(1)
PL782S—Norway
(1)
NC 98—Libya
(2)
Other of $10 million or less each
(1)(2)
Total
$
(1)Additional appraisal wells planned.
(2)Appraisal drilling complete; costs being incurred to assess development.
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 $
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 $
capitalized undeveloped leasehold carrying value.
In our Asia Pacific segment, we recorded before-tax expense of $
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 $
capitalized undeveloped leasehold costs and dry hole expenses of $
discontinue exploration activities related to our Central Louisiana Austin Chalk acreage.
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
Note 7—Impairments
During 2021, 2020 and 2019, we recognized the following before-tax impairment charges:
Millions of Dollars
2021
2020
2019
Alaska
$
Lower 48
(8 )
Canada
Europe, Middle East and North Africa
(24 )
Asia Pacific
$
2021
We recorded an impairment of $
See
In our Lower 48 segment, we recorded a credit to impairment of $
previously sold asset, in which we retained the ARO liability. This was offset by recorded impairments of $
million during the fourth quarter of 2021, related to certain noncore assets due to changes in development plans.
In our Europe, Middle East and North Africa segment, we recorded a credit to impairment of $
decreased ARO estimates on fields in Norway which ceased production and were fully depreciated in prior years.
2020
We recorded impairments of $
significant decrease in the outlook for current and long-term natural gas prices in early 2020, we recorded
impairments of $
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 $
2019
In the Lower 48, we recorded impairments of $
Niobrara asset which were written down to fair value less costs to sell.
Note 8—Asset Retirement Obligations and Accrued Environmental Costs
Asset retirement obligations and accrued environmental costs at December 31 were:
Millions of Dollars
2021
2020
Asset retirement obligations
$
Accrued environmental costs
Total asset retirement obligations and accrued environmental costs
Asset retirement obligations and accrued environmental costs due within one year*
(359 )
(323 )
Long-term asset retirement obligations and accrued environmental costs
$
*Classified as a current liability on the balance sheet under “Other accruals.”
Notes to Consolidated Financial Statements
103
ConocoPhillips 2021 10-K
Asset Retirement Obligations
We record the fair value of a liability for an ARO when it is incurred (typically when the asset is installed at the
production location). When the liability is initially recorded, we capitalize the associated asset retirement cost by
increasing the carrying amount of the related PP&E. If, in subsequent periods, our estimate of this liability
changes, we will record an adjustment to both the liability and PP&E. Over time, the liability increases for the
change in its present value, while the capitalized cost depreciates over the useful life of the related asset.
Reductions to estimated liabilities for assets that are no longer producing are recorded as a credit to impairment, if
the asset had been previously impaired, or as a credit to DD&A, if the asset had not been previously impaired .
We have numerous AROs we are required to perform under law or contract once an asset is permanently taken
out of service. Most of these obligations are not expected to be paid until several years, or decades, in the future
and will be funded from general company resources at the time of removal. Our largest individual obligations
involve plugging and abandonment of wells and removal and disposal of offshore oil and gas platforms around the
world, as well as oil and gas production facilities and pipelines in Alaska.
During 2021 and 2020, our overall ARO changed as follows:
Millions of Dollars
2021
2020
Balance at January 1
$
Accretion of discount
New obligations
Changes in estimates of existing obligations
(113 )
(307 )
Spending on existing obligations
(164 )
(116 )
Property dispositions
(108 )
(771 )
Foreign currency translation
(55 )
Balance at December 31
$
Accrued Environmental Costs
Total accrued environmental costs at December 31, 2021 and 2020, were $
respectively.
We had accrued environmental costs of $
respectively, related to remediation activities in the U.S. and Canada. We had also accrued in Corporate and Other
$
2021 and 2020, respectively. In addition, both December 31, 2021 and 2020, included a $
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
Expected expenditures for environmental obligations acquired in various business combinations are discounted
using a weighted-average
liabilities of $
portion of the accrued environmental costs that have been discounted are $
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
Note 9—Debt
Long-term debt at December 31 was:
Millions of Dollars
2021
2020
% Debentures due 2021
$
% Notes due 2022
% Debentures due 2023
% Notes due 2024
% Debentures due 2025
% Notes due 2025
% Debentures due 2026
% Notes due 2026
% Debentures due 2027
% Notes due 2027
% Notes due 2027
% Notes due 2028
% Notes due 2028
% Debentures due 2029
% Debentures due 2029
% Notes due 2029
% Notes due 2030
% Notes due 2031
% Notes due 2031
% Notes due 2031
% Notes due 2031
% Notes due 2031
% Notes due 2032
% Notes due 2034
% Notes due 2036
% Notes due 2037
% Notes due 2038
% Notes due 2039
% Notes due 2044
% Notes due 2046
% Debentures due 2047
% Notes due 2047
% Notes due 2048
% Notes due 2048
Floating rate notes due 2022 at
% –
% during 2021 and
% –
% during 2020
Marine Terminal Revenue Refunding Bonds due 2031 at
% –
% during
% –
% during 2020
Industrial Development Bonds due 2035 at
% –
% during 2021 and
% –
% during 2020
Commercial Paper at
% –
% during 2021
Other
Debt at face value
Finance leases
Net unamortized premiums, discounts and debt issuance costs
Total debt
Short-term debt
(1,200 )
(619 )
Long-term debt
$
Notes to Consolidated Financial Statements
105
ConocoPhillips 2021 10-K
On January 15, 2021, we completed the acquisition of Concho in an all-stock transaction. In the acquisition, we
assumed Concho’s publicly traded debt, with an outstanding principal balance of $
at fair value of $
approximately $
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 $
percent, or approximately $
the same interest rates and maturity dates as the Concho senior notes. The portion not exchanged, approximately
$
treated as a debt modification for accounting purposes resulting in a portion of the unamortized fair value
adjustment of the Concho senior notes allocated to the new debt issued by ConocoPhillips on the settlement date
of the exchange. The new debt issued in the exchange is fully and unconditionally guaranteed by ConocoPhillips
Company.
We have a revolving credit facility totaling $
facility may be used for direct bank borrowings, the issuance of letters of credit totaling up to $
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 $
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 $
funding source for short-term working capital needs. Commercial paper maturities are generally limited to
. With no commercial paper outstanding and
$
direct borrowings, letters of credit, and $
For information on Finance Leases,
The current credit ratings on our long-term debt are:
●
.
●
.
●
.
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 $
outstanding with maturities ranging through 2035. The VRDBs are redeemable at the option of the bondholders
on any business day. If they are ever redeemed, we have the ability and intent to refinance on a long-term basis,
therefore, the VRDBs are included in the “Long-term debt” line on our consolidated balance sheet.
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
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
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
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 $
●
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 $
($
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
guarantees is approximately $
December 31, 2021, the carrying value of these guarantees was approximately $
Other Guarantees
We have other guarantees with maximum future potential payment amounts totaling approximately $
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
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 $
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 $
maximum amounts of future payments are generally unlimited. Although it is reasonably possible future
payments may exceed amounts recorded, due to the nature of the indemnifications, it is not possible to make a
reasonable estimate of the maximum potential amount of future payments.
for additional
information about environmental liabilities.
Notes to Consolidated Financial Statements
107
ConocoPhillips 2021 10-K
Note 11—Contingencies and Commitments
A number of lawsuits involving a variety of claims arising in the ordinary course of business have been filed against
ConocoPhillips. We also may be required to remove or mitigate the effects on the environment of the placement,
storage, disposal or release of certain chemical, mineral and petroleum substances at various active and inactive
sites. We regularly assess the need for accounting recognition or disclosure of these contingencies. In the case of
all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable
and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within
the range is a better estimate than any other amount, then the low end of the range is accrued. We do not reduce
these liabilities for potential insurance or third-party recoveries. We accrue receivables for insurance or other
third-party recoveries when applicable. With respect to income tax-related contingencies, we use a cumulative
probability-weighted loss accrual in cases where sustaining a tax position is less than certain.
,
for
additional information about income tax -related contingencies.
Based on currently available information, we believe it is remote that future costs related to known contingent
liability exposures will exceed current accruals by an amount that would have a material adverse impact on our
consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both
with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes
include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future
environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup
costs, the unknown time and extent of such remedial actions that may be required, and the determination of our
liability in proportion to that of other responsible parties. Estimated future costs related to tax and legal matters
are subject to change as events evolve and as additional information becomes available during the administrative
and litigation processes.
Environmental
We are subject to international, federal, state and local environmental laws and regulations and record accruals for
environmental liabilities based on management’s best estimates . These estimates are based on currently available
facts, existing technology, and presently enacted laws and regulations, taking into account stakeholder and
business considerations. When measuring environmental liabilities, we also consider our prior experience in
remediation of contaminated sites, other companies’ cleanup experience, and data released by the U.S. EPA or
other organizations. We consider unasserted claims in our determination of environmental liabilities, and we
accrue them in the period they are both probable and reasonably estimable.
Although liability of those potentially responsible for environmental remediation costs is generally joint and
several for federal sites and frequently so for other sites, we are usually only one of many companies cited at a
particular site. Due to the joint and several liabilities, we could be responsible for all cleanup costs related to any
site at which we have been designated as a potentially responsible party. We have been successful to date in
sharing cleanup costs with other financially sound companies. Many of the sites at which we are potentially
responsible are still under investigation by the EPA or the agency concerned. Prior to actual cleanup, those
potentially responsible normally assess the site conditions, apportion responsibility and determine the appropriate
remediation. In some instances, we may have no liability or may attain a settlement of liability. Where it appears
that other potentially responsible parties may be financially unable to bear their proportional share, we consider
this inability in estimating our potential liability, and we adjust our accruals accordingly. As a result of various
acquisitions in the past, we assumed certain environmental obligations. Some of these environmental obligations
are mitigated by indemnifications made by others for our benefit, and some of the indemnifications are subject to
dollar limits and time limits.
We are currently participating in environmental assessments and cleanups at numerous federal Superfund and
comparable state and international sites. After an assessment of environmental exposures for cleanup and other
costs, we make accruals on an undiscounted basis (except those acquired in a purchase business combination,
which we record on a discounted basis) for planned investigation and remediation activities for sites where it is
probable future costs will be incurred and these costs can be reasonably estimated. We have not reduced these
accruals for possible insurance recoveries. In the future, we may be involved in additional environmental
assessments, cleanups and proceedings. See
,
for a summary of our accrued environmental liabilities.
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
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 $
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
$
Venezuela in 2007. On August 29, 2019, the ICSID Tribunal issued a decision rectifying the award and reducing it
by approximately $
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 $
with the expropriation of the projects and other pre-expropriation fiscal measures.
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 $
million in connection with the ICC award. ConocoPhillips has ensured that the settlement and any actions taken in
enforcement thereof meet all appropriate U.S. regulatory requirements, including those related to any applicable
sanctions imposed by the U.S. against Venezuela.
Notes to Consolidated Financial Statements
109
ConocoPhillips 2021 10-K
In 2016, ConocoPhillips filed a separate and independent arbitration under the rules of the ICC against PDVSA
under the contracts that had established the Corocoro Project. On August 2, 2019, the ICC Tribunal awarded
ConocoPhillips approximately $
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
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
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
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 $
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—$
2023—$
Total payments under the agreements were $
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
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
$
Other assets
Liabilities
Other accruals
Other liabilities and deferred credits
The gains (losses) from commodity derivatives incurred, and the line items where they appear on our consolidated
income statement were:
Millions of Dollars
2021
2020
2019
Sales and other operating revenues
$
(228 )
Other income (loss)
Purchased commodities
(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 $
December 31, 2022. During 2021, we recognized a loss on settlement of the contracts for $
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 $
million during 2021. Cash settlements related to the derivative contracts are presented within “Cash Flows From
Operating Activities” on our consolidated statement of cash flows.
Notes to Consolidated Financial Statements
111
ConocoPhillips 2021 10-K
The table below summarizes our material net exposures resulting from outstanding commodity derivative
contracts:
Open Position
Long/(Short)
2021
2020
Commodity
Natural gas and power (billions of cubic feet equivalent)
Fixed price
(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
$
Liabilities
Other accruals
The (gains) losses from foreign currency exchange derivatives incurred and the line item where they appear
on our consolidated income statement were:
Millions of Dollars
2021
2020
2019
Foreign currency transaction (gains) losses
$
(5 )
(40 )
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
Sell British pound, buy euro
GBP
Sell Canadian dollar, buy U.S. dollar
CAD
Buy Canadian dollar, sell U.S. dollar
CAD
Buy Australian dollar, sell U.S. dollar
AUD
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
.
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
$
Demand Deposits
Time Deposits
1 to 90 days
91 to 180 days
Within one year
One year through five years
U.S. Government Obligations
1 to 90 days
$
Notes to Consolidated Financial Statements
113
ConocoPhillips 2021 10-K
The following investments in debt securities classified as available for sale are carried at fair value on our
consolidated balance sheet at December 31, 2021 and 2020:
Millions of Dollars
Carrying Amount
Cash and Cash
Equivalents
Short-Term
Investments
Investments and Long-
Term Receivables
2021
2020
2021
2020
2021
2020
Major Security Type
Corporate Bonds
$
Commercial Paper
U.S. Government Obligations
U.S. Government Agency
Foreign Government Obligations
Asset-backed Securities
$
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
$
Commercial Paper
U.S. Government Obligations
U.S. Government Agency Obligations
Foreign Government Obligations
Asset-Backed Securities
$
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 $
losses included in earnings from those sales and redemptions were negligible. The cost of securities sold and
redeemed is determined using the specific identification method.
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
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.
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 $
For these instruments,
no
rating had been downgraded below investment grade on December 31, 2021, we would have been required to
post $
Note 13—Fair Value Measurement
We carry a portion of our assets and liabilities at fair value that are measured at the reporting date using an exit
price (i.e., the price that would be received to sell an asset or paid to transfer a liability) and disclosed according to
the quality of valuation inputs under the fair value hierarchy.
The classification of an asset or liability is based on the lowest level of input significant to its fair value. Those that
are initially classified as Level 3 are subsequently reported as Level 2 when the fair value derived from unobservable
inputs is inconsequential to the overall fair value, or if corroborated market data becomes available. Assets and
liabilities initially reported as Level 2 are subsequently reported as Level 3 if corroborated market data is no longer
available. There were no material transfers into or out of Level 3 during 2021 or 2020.
Notes to Consolidated Financial Statements
115
ConocoPhillips 2021 10-K
Recurring Fair Value Measurement
Financial assets and liabilities reported at fair value on a recurring basis primarily include our investment in CVE
common shares, our investment s in debt securities classified as available for sale, and commodity derivatives.
●
Level 1 derivative assets and liabilities primarily represent exchange -traded futures and options that are
valued using unadjusted prices available from the underlying exchange. Level 1 also includes our investment
in common shares of CVE, which is valued using quotes for shares on the NYSE, and our investments in U.S.
government obligations classified as available for sale debt securities, which are valued using exchange prices.
●
Level 2 derivative assets and liabilities primarily represent OTC swaps, options and forward purchase and sale
contracts that are valued using adjusted exchange prices, prices provided by brokers or pricing service
companies that are all corroborated by market data. Level 2 also includes our investments in debt securities
classified as available for sale including investments in corporate bonds, commercial paper, asset-backed
securities, U.S. government agency obligations and foreign government obligations that are valued using
pricing provided by brokers or pricing service companies that are corroborated with market data.
●
Level 3 derivative assets and liabilities consist of OTC swaps, options and forward purchase and sale contracts
where a significant portion of fair value is calculated from underlying market data that is not readily available.
The derived value uses industry standard methodologies that may consider the historical relationships among
various commodities, modeled market prices, time value, volatility factors and other relevant economic
measures. The use of these inputs results in management’s best estimate of fair value. Level 3 activity was
not material for all periods presented.
The following table summarizes the fair value hierarchy for gross financial assets and liabilities (i.e., unadjusted
where the right of setoff exists for commodity derivatives accounted for at fair value on a recurring basis):
Millions of Dollars
December 31, 2021
December 31, 2020
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
Assets
Investment in Cenovus Energy
$
Investments in debt securities
Commodity derivatives
Total assets
$
Liabilities
Commodity derivatives
$
Total liabilities
$
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
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
$
Liabilities
December 31, 2020
Assets
$
Liabilities
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)
$
Equity Method Investments
Year ended December 31, 2020
Net PP&E (held for use)
$
Net PP&E (held for use)
During 2021 and 2020, the estimated fair value of certain noncore assets included in our Lower 48 segment
declined to amounts below the carrying values. The carrying values were written down to fair value. The fair
values were estimated based on internal discounted cash flow models using the following estimated assumptions:
estimated future production, an outlook of future prices from a combination of exchanges (short-term) coupled
with pricing service companies and our internal outlook (long-term), future operating costs and capital
expenditures, and a discount rate believed to be consistent with those used by principal market participants.
The
range and arithmetic average of significant unobservable inputs used in the Level 3 fair value measurements for
significant assets were as follows:
Notes to Consolidated Financial Statements
117
ConocoPhillips 2021 10-K
Fair Value
(Millions of
Dollars)
Valuation
Technique
Unobservable Inputs
Range
(Arithmetic Average)
December 31, 2021
Lower 48 Gulf Coast and
Rockies noncore field
$
Discounted
cash flow
Commodity production
(MBOED)
)
Commodity price outlook*
($/BOE)
$
)
Discount rate**
% -
% (
%)
*Commodity price outlook based on a combination of external pricing service companies' and our internal outlook for years 2024-2050; future prices escalated at
% annually after year 2050.
**Determined as the weighted average cost of capital of a group of peer companies, adjusted for risks where appropriate.
Fair Value
(Millions of
Dollars)
Valuation
Technique
Unobservable Inputs
Range
(Arithmetic Average)
March 31, 2020
Wind River Basin
$
Discounted
cash flow
Natural gas production
(MMCFD)
)
Natural gas price outlook*
($/MMBTU)
$
)
Discount rate**
% -
% (
%)
*Henry Hub natural gas price outlook based on a combination of external pricing service companies' outlooks for years 2022-2034; future prices escalated at
%
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
$
Discounted
cash flow
Commodity production
(MBOED)
)
Commodity price outlook*
($/BOE)
$
($
)
Discount rate**
% -
% (
%)
*Commodity price outlook based on a combination of external pricing service companies' and our internal outlook for years 2023-2050; future prices escalated at
% 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
for $
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 $
.
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
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:
investment in CVE common shares.
●
Investments in debt securities classified as available for sale: The fair value of investments in debt
securities categorized as Level 1 in the fair value hierarchy is measured using exchange prices. The fair
value of investments in debt securities categorized as Level 2 in the fair value hierarchy is measured using
pricing provided by brokers or pricing service companies that are corroborate d with market data.
.
●
Loans and advances—related parties: The carrying amount of floating-rate loans approximates fair value.
The fair value of fixed-rate loan activity is measured using market observable data and is categorized as
Level 2 in the fair value hierarchy.
●
Accounts payable (including related parties) and floating-rate debt: The carrying amount of accounts
payable and floating-rate debt reported on the balance sheet approximates fair value.
●
Fixed-rate debt: The estimated fair value of fixed-rate debt is measured using prices available from a
pricing service that is corroborated by market data; therefore, these liabilities are categorized as Level 2 in
the fair value hierarchy.
●
Commercial paper: The carrying amount of our commercial paper instruments approximates fair value
and is reported on the balance sheet as short-term debt
.
The following table summarizes the net fair value of financial instruments (i.e., adjusted where the right of setoff
exists for commodity derivatives):
Millions of Dollars
Carrying Amount
Fair Value
2021
2020
2021
2020
Financial assets
Investment in CVE common shares
$
Commodity derivatives
Investments in debt securities
Loans and advances—related parties
Financial liabilities
Total debt, excluding finance leases
Commodity derivatives
Commodity Derivatives
At December 31, 2021, commodity derivative assets and liabilities are presented net with
cash collateral and $
derivative assets and liabilities are presented net with $
$
Notes to Consolidated Financial Statements
119
ConocoPhillips 2021 10-K
Note 14—Equity
Common Stock
The changes in our shares of common stock, as categorized in the equity section of the balance sheet, were:
Shares
2021
2020
2019
Issued
Beginning of year
Acquisition of Concho
Distributed under benefit plans
End of year
Held in Treasury
Beginning of year
Repurchase of common stock
End of year
Preferred Stock
We have authorized
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 $
proceeds of which have been applied to share repurchases. Share repurchases since inception of our current
program totaled
Note 15—Non-Mineral Leases
The company primarily leases office buildings and drilling equipment, as well as ocean transport vessels, tugboats,
corporate aircraft, and other facilities and equipment. Certain leases include escalation clauses for adjusting rental
payments to reflect changes in price indices and other leases include payment provisions that vary based on the
nature of usage of the leased asset. Additionally, the company has executed certain leases that provide it with the
option to extend or renew the term of the lease, terminate the lease prior to the end of the lease term, or
purchase the leased asset as of the end of the lease term. In other cases, the company has executed lease
agreements that require it to guarantee the residual value of certain leased office buildings. For additional
information about guarantees,
.
There are no significant restrictions imposed on us by the lease
agreements with regard to dividends, asset dispositions or borrowing ability.
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
Certain arrangements may contain both lease and non-lease components and we determine if an arrangement is
or contains a lease at contract inception. We adopted the provisions of FASB ASU No. 2016-02, “Leases” (ASC
Topic 842) and its amendments, beginning January 1, 2019. This ASU superseded the requirements in FASB ASC
Topic 840 “Leases” (ASC Topic 840). Only the lease components of these contractual arrangements are subject to
the provisions of ASC Topic 842, and any non-lease components are subject to other applicable accounting
guidance; however, we have elected to adopt the optional practical expedient not to separate lease components
apart from non-lease components for accounting purposes. This policy election has been adopted for each of the
company’s leased asset classes existing as of the effective date and subject to the transition provisions of ASC
Topic 842 and will be applied to all new or modified leases executed on or after January 1, 2019. For contractual
arrangements executed in subsequent periods involving a new leased asset class, the company will determine at
contract inception whether it will apply the optional practical expedient to the new leased asset class.
Leases are evaluated for classification as operating or finance leases at the commencement date of the lease and
right-of-use assets and corresponding liabilities are recognized on our consolidated balance sheet based on the
present value of future lease payments relating to the use of the underlying asset during the lease term. Future
lease payments include variable lease payments that depend upon an index or rate using the index or rate at the
commencement date and probable amounts owed under residual value guarantees. The amount of future lease
payments may be increased to include additional payments related to lease extension, termination, and/or
purchase options when the company has determined, at or subsequent to lease commencement, generally due to
limited asset availability or operating commitments, it is reasonably certain of exercising such options. We use our
incremental borrowing rate as the discount rate in determining the present value of future lease payments, unless
the interest rate implicit in the lease arrangement is readily determinable. Lease payments that vary subsequent
to the commencement date based on future usage levels, the nature of leased asset activities, or certain other
contingencies are not included in the measurement of lease right-of-use assets and corresponding liabilities. We
have elected not to record assets and liabilities on our consolidated balance sheet for lease arrangements with
terms of 12 months or less.
We often enter into leasing arrangements acting in the capacity as operator for and/or on behalf of certain oil and
gas joint ventures of undivided interests. If the lease arrangement can be legally enforced only against us as
operator and there is no separate arrangement to sublease the underlying leased asset to our coventurers, we
recognize at lease commencement a right-of-use asset and corresponding lease liability on our consolidated
balance sheet on a gross basis. While we record lease costs on a gross basis in our consolidated income statement
and statement of cash flows, such costs are offset by the reimbursement we receive from our coventurers for their
share of the lease cost as the underlying leased asset is utilized in joint venture activities. As a result, lease cost is
presented in our consolidated income statement and statement of cash flows on a proportional basis. If we are a
nonoperating coventurer, we recognize a right-of-use asset and corresponding lease liability only if we were a
specified contractual party to the lease arrangement and the arrangement could be legally enforced against us. In
this circumstance, we would recogni ze both the right-of-use asset and corresponding lease liability on our
consolidated balance sheet on a proportional basis consistent with our undivided interest ownership in the related
joint venture.
The company has historically recorded certain finance leases executed by investee companies accounted for under
the proportionate consolidation method of accounting on its consolidated balance sheet on a proportional basis
consistent with its ownership interest in the investee company. In addition, the company has historically recorded
finance lease assets and liabilities associated with certain oil and gas joint ventures on a proportional basis
pursuant to accounting guidance applicable prior to January 1, 2019. In accordance with the transition provisions
of ASC Topic 842, and since we have elected to adopt the package of optional transition-related practical
expedients, the historical accounting treatment for these leases has been carried forward and is subject to
reconsideration upon the modification or other required reassessment of the arrangements prior to lease term
expiration.
Notes to Consolidated Financial Statements
121
ConocoPhillips 2021 10-K
The following table summarizes the right-of-use assets and lease liabilities for both the operating and finance
leases on our consolidated balance sheet as of December 31:
Millions of Dollars
2021
2020
Operating
Leases
Finance
Leases
Operating
Leases
Finance
Leases
Right-of-Use Assets
Properties, plants and equipment
Gross
$
Accumulated DD&A
(857 )
(721 )
Net PP&E
*
Prepaid expenses and other current assets
$
Other assets
Lease Liabilities
Short-term debt
**
$
Other accruals
Long-term debt
***
Other liabilities and deferred credits
Total lease liabilities
$
* Includes proportionately consolidated finance lease assets of $
*** Includes proportionately consolidated finance lease liabilities of $
2020.
The following table summarizes our lease costs:
Millions of Dollars
2021
2020
2019
Lease Cost
*
Operating lease cost
$
Finance lease cost
Amortization of right-of-use assets
Interest on lease liabilities
Short-term lease cost
**
Total lease cost
***
$
* The amounts presented in the table above have not been adjusted to reflect amounts recovered or reimbursed from oil and gas
coventurers.
** Short-term leases are not recorded on our consolidated balance sheet.
*** Variable lease cost and sublease income are immaterial for the periods presented and therefore are not included in the table above
.
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
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
Finance leases
Weighted-average discount rate (percent)
Operating leases
Finance leases
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
$
Operating cash flows from finance leases
Financing cash flows from finance leases
Right-of-use assets obtained in exchange for operating lease liabilities
$
Right-of-use assets obtained in exchange for finance lease liabilities
*The amounts presented in the table above have not been adjusted to reflect amounts recovered or reimbursed from oil and gas coventurers.
In addition, pursuant to other applicable accounting guidance, lease payments made in connection with preparing another asset for its
intended use are reported in the "Cash Flows From Investing Activities" section of our consolidated statement of cash flows.
The following table summarizes future lease payments for operating and finance leases at December 31, 2021:
Millions of Dollars
Operating
Leases
Finance
Maturity of Lease Liabilities
2022
$
2023
2024
2025
2026
Remaining years
Total
*
Less: portion representing imputed interest
(62 )
(189 )
Total lease liabilities
$
*Future lease payments for operating and finance leases commencing on or after January 1, 2019, also include payments related to non-lease
components in accordance with our election to adopt the optional practical expedient not to separate lease components apart from non-lease
components for accounting purposes. In addition, future payments related to operating and finance leases proportionately consolidated by the
company have been included in the table on a proportionate basis consistent with our respective ownership interest in the underlying investee
company or oil and gas venture.
Notes to Consolidated Financial Statements
123
ConocoPhillips 2021 10-K
Note 16—Employee Benefit Plans
Pension and Postretirement Plans
An analysis of the projected benefit obligations for our pension plans and accumulated benefit obligations for
our postretirement health and life insurance plans follows:
Millions of Dollars
Pension Benefits
Other Benefits
2021
2020
2021
2020
U.S.
Int’l.
U.S.
Int’l.
Change in Benefit Obligation
Benefit obligation at January 1
$
Service cost
Interest cost
Plan participant contributions
Plan amendments
(30 )
Actuarial (gain) loss
(117 )
(176 )
(16 )
Benefits paid
(654 )
(162 )
(241 )
(151 )
(40 )
(49 )
Curtailment
Recognition of termination benefits
Foreign currency exchange rate change
(81 )
Benefit obligation at December 31
*
$
*Accumulated benefit obligation portion of above at
$
Change in Fair Value of Plan Assets
Fair value of plan assets at January 1
$
Actual return on plan assets
Company contributions
Plan participant contributions
Benefits paid
(654 )
(162 )
(241 )
(151 )
(40 )
(49 )
Foreign currency exchange rate change
(86 )
Fair value of plan assets at December 31
$
Funded Status
$
(260 )
(778 )
(137 )
(170 )
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
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
$
Current liabilities
(29 )
(15 )
(56 )
(11 )
(34 )
(39 )
Noncurrent liabilities
(232 )
(288 )
(722 )
(345 )
(103 )
(131 )
Total recognized
$
(260 )
(778 )
(137 )
(170 )
Weighted-Average Assumptions Used to
Determine Benefit Obligations at
December 31
Discount rate
%
Rate of compensation increase
Interest crediting rate for applicable benefits
Weighted-Average Assumptions Used to
Determine Net Periodic Benefit Cost for
Years Ended December 31
Discount rate
%
Expected return on plan assets
Rate of compensation increase
Interest crediting rate for applicable benefits
For both U.S. and international pension plans, the overall expected long-term rate of return is developed from the
expected future return of each asset class, weighted by the expected allocation of pension assets to that asset
class. We rely on a variety of independent market forecasts in developing the expected rate of return for each
class of assets.
During 2021, the actuarial gains related to the benefit obligations for U.S. and international plans were primarily
related to an increase in the discount rates. During 2020 and 2019, the actuarial losses related to the benefit
obligations for U.S. and international plans were primarily related to a decrease in the discount rates.
Notes to Consolidated Financial Statements
125
ConocoPhillips 2021 10-K
The following tables summarize information related to the Company's pension plans with projected and
accumulated benefit obligations in excess of the fair value of the plans' assets:
Millions of Dollars
Pension Benefits
2021
2020
U.S.
Int’l.
U.S.
Int’l.
Pension Plans with Projected Benefit Obligation in
Excess of Plan Assets
Projected benefit obligation
$
Fair value of plan assets
Pension Plans with Accumulated Benefit Obligation in
Excess of Plan Assets
Accumulated benefit obligation
$
Fair value of plan assets
Included in accumulated other comprehensive income (loss) at December 31 were the following before-tax
amounts that had not been recognized in net periodic benefit cost:
Millions of Dollars
Pension Benefits
Other Benefits
2021
2020
2021
2020
U.S.
Int’l.
U.S.
Int’l.
Unrecognized net actuarial loss (gain)
$
(1 )
Unrecognized prior service cost (credit)
(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
$
(83 )
(120 )
(7 )
Amortization of actuarial loss included
in income (loss)*
Net change during the period
$
(99 )
(6 )
Prior service credit (cost) arising during the
period
$
(1 )
Amortization of prior service (credit)
included in income (loss)
(1 )
(1 )
(37 )
(31 )
Net change during the period
$
(1 )
(2 )
(37 )
(1 )
*Includes settlement (gains) losses recognized in 2021 and 2020.
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
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
$
Interest cost
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)
(2 )
Settlements loss (gain)
(1 )
Curtailment loss
Net periodic benefit cost
$
(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 $
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
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
declines to
benefit obligation assumes a health care cost trend rate of
2028.
Notes to Consolidated Financial Statements
127
ConocoPhillips 2021 10-K
Plan Assets
We follow a policy of broadly diversifying pension plan assets across asset classes and individual holdings. As a
result, our plan assets have no significant concentrations of credit risk. Asset classes that are considered
appropriate include U.S. equities, non-U.S. equities, U.S. fixed income, non-U.S. fixed income, real estate and
private equity investments. Plan fiduciaries may consider and add other asset classes to the investment program
from time to time. The target allocations for plan assets are
securities,
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 $
consisted of $
covered by the contract. At December 31, 2020, the participating interest in the annuity contract was
valued at $
accumulated benefit obligation covered by the contract. The participating interest is not available for
meeting general pension benefit obligations in the near term. No future company contributions are
required and no new benefits are being accrued under this insurance annuity contract.
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
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.
$
International
Mutual funds
Debt securities
Corporate
Mutual funds
Cash and cash equivalents
Real estate
Total in fair value hierarchy
$
Investments measured at net asset value*
Equity securities
Common/collective trusts
$
Debt securities
Common/collective trusts
Cash and cash equivalents
Real estate
Total**
$
**Excludes the participating interest in the insurance annuity contract with a net asset of $
Notes to Consolidated Financial Statements
129
ConocoPhillips 2021 10-K
The fair values of our pension plan assets at December 31, by asset class were as follows:
Millions of Dollars
U.S.
International
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
2020
Equity securities
U.S.
$
International
Mutual funds
Debt securities
Corporate
Mutual funds
Cash and cash equivalents
Derivatives
Real estate
Total in fair value hierarchy
$
Investments measured at net asset value*
Equity securities
Common/collective trusts
$
Debt securities
Common/collective trusts
Cash and cash equivalents
Real estate
Total**
$
**Excludes the participating interest in the insurance annuity contract with a net asset of $
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 $
to our domestic qualified and nonqualified pension and postretirement benefit plans and $
international qualified and nonqualified pension and postretirement benefit plans.
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
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
$
2023
2024
2025
2026
2027–2031
The following table summarizes our severance accrual activity:
Millions of Dollars
2021
2020
2019
Balance at January 1
$
Accruals
(1 )
Benefit payments
(116 )
(13 )
(24 )
Balance at December 31
$
Accruals include severance costs associated with our company-wide restructuring program. Of the remaining
balance at December 31, 2021, $
Defined Contribution Plans
Most U.S. employees are eligible to participate in the ConocoPhillips Savings Plan (CPSP). Employees can deposit
up to
Employees who participate in the CPSP and contribute
cash match with a potential company discretionary cash contribution of up to
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
charged to expense for the CPSP and predecessor plans were $
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
$
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
-year life, the Plan allows the issuance of up to
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
Compensation Committee of our Board of Directors is authorized to determine the types, terms, conditions and
limitations of awards granted. Awards may be granted in the form of, but not limited to, stock options, restricted
Notes to Consolidated Financial Statements
131
ConocoPhillips 2021 10-K
stock units and performance share units to employees and non-employee directors who contribute to the
company’s continued success and profitability.
Total share-based compensation expense is measured using the grant date fair value for our equity-classified
awards and the settlement date fair value for our liability-classified awards. We recognize share -based
compensation expense over the shorter of the service period (i.e., the stated period of time required to earn the
award); or the period beginning at the start of the service period and ending when an employee first becomes
eligible for retirement, but not less than six months, as this is the minimum period of time required for an award to
not be subject to forfeiture. Our share-based compensation programs generally provide accelerated vesting (i.e., a
waiver of the remaining period of service required to earn an award) for awards held by employees at the time of
their retirement. Some of our share-based awards vest ratably (i.e., portions of the award vest at different times)
while some of our awards cliff vest (i.e., all of the award vests at the same time). We recognize expense on a
straight-line basis over the service period for the entire award, whether the award was granted with ratable or cliff
vesting.
Compensation Expense
—Total share-based compensation expense recognized in net income (loss) and the
associated tax benefit were:
Millions of Dollars
2021
2020
2019
Compensation cost
$
Tax benefit
Stock Options
—Stock options granted under the provisions of the Plan and prior plans permit purchase of our
common stock at exercise prices equivalent to the average fair market value of ConocoPhillips common stock on
the date the options were granted. The options have terms of 10 years and generally vest ratably, with one-third
of the options awarded vesting and becoming exercisable on each anniversary date following the date of grant.
Options awarded to certain employees already eligible for retirement vest within six months of the grant date, but
those options do not become exercisable until the end of the normal vesting period. Beginning in 2018, stock
option grants were discontinued and replaced with three-year, time-vested restricted stock units which generally
will be cash-settled 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
$
$
Exercised
(3,846,361 )
Expired or cancelled
(1,102,381 )
Outstanding at December 31, 2021
$
$
Vested at December 31, 2021
$
$
Exercisable at December 31, 2021
$
$
The weighted-average remaining contractual term of outstanding options, vested options and exercisable options
at December 31, 2021, were all
2020 and $
During 2021, we received $
options. At December 31, 2021, all outstanding stock options were fully vested and there was no remaining
compensation cost to be recorded.
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
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
$
Granted
Forfeited
(566,047 )
Issued
(2,810,730 )
$
Outstanding at December 31, 2021
$
Not Vested at December 31, 2021
At December 31, 2021, the remaining unrecognized compensation cost from the unvested stock-settled units was
$
years. The weighted-average grant date fair value of stock unit awards granted during 2020 and 2019 was $
and $
, respectively. The total fair value of stock units issued during 2020 and 2019 was $
$
Cash-Settled
Cash settled executive restricted stock units granted in 2018 and 2019 replaced the stock option program. These
restricted stock units, subject to elections to defer, will be settled in cash equal to the fair market value of a share
of ConocoPhillips common stock per unit on the settlement date and are classified as liabilities on the balance
sheet. Units awarded to retirement eligible employees vest six months from the grant date; however, those units
are not settled until the earlier of separation from the company or the end of the regularly scheduled vesting
period. Compensation expense is initially measured using the average fair market value of ConocoPhillips common
stock and is subsequently adjusted, based on changes in the ConocoPhillips stock price through the end of each
subsequent reporting period, through the settlement date. Recipients receive an accrued reinvested dividend
equivalent that is charged to compensation expense. The accrued reinvested dividend is paid at the time of
settlement, subject to the terms and conditions of the award. Beginning with executive restricted stock units
granted in 2020 awards will be settled in stock.
Notes to Consolidated Financial Statements
133
ConocoPhillips 2021 10-K
The following summarizes our cash -settled stock unit activity for the year ended December 31, 2021:
Weighted-Average
Millions of Dollars
Stock Units
Grant Date Fair Value
Total Fair Value
Outstanding at December 31, 2020
$
Granted
Forfeited
(2,927 )
Issued
(396,398 )
$
Outstanding at December 31, 2021
$
Not Vested at December 31, 2021
At December 31, 2021, there was
cash-settled units. The weighted-average grant date fair value of stock unit awards granted during 2020 and 2019
were $
, respectively. The total fair value of stock units issued during 2020 and 2019 were
negligible and $
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
$
Issued
(287,881 )
$
Outstanding at December 31, 2021
$
Not Vested at December 31, 2021
$
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
At December 31, 2021, there was
stock-settled performance share s. The weighted-average grant date fair value of stock-settled PSUs granted
during 2020 and 2019 was $
, respectively. The total fair value of stock-settled PSUs issued during
2020 and 2019 was $
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
$
Granted
Settled
(1,080,078 )
$
Outstanding at December 31, 2021
$
At December 31, 2021, all outstanding cash-settled performance awards were fully vested and there was
remaining compensation cost to be recorded. The weighted-average grant date fair value of cash-settled PSUs
granted during 2020 and 2019 was $
, respectively. The total fair value of cash-settled
performance share awards settled during 2020 and 2019 was $
Notes to Consolidated Financial Statements
135
ConocoPhillips 2021 10-K
From inception of the Performance Share Program through 2013, approved PSU awards were granted after the
conclusion of performance periods. Beginning in February 2014, initial target PSU awards are issued near the
beginning of new performance periods. These initial target PSU awards will terminate at the end of the
performance periods and will be settled after the performance periods have ended. Also in 2014, initial target PSU
awards were issued for open performance periods that began in prior years. For the open performance period
beginning in 2012, the initial target PSU awards terminated at the end of the three-year performance period and
were replaced with approved PSU awards. For the open performance period beginning in 2013, the initial target
PSU awards terminated at the end of the three-year performance period and were settled after the performance
period ended. There is no effect on recognition of compensation expense.
Other
—In addition to the above active programs, we have outstanding shares of restricted stock and restricted
stock units that were either issued as part of our non-employee director compensation program for current and
former members of the company’s Board of Directors, as part of an executive compensation program that has
been discontinued or acquired as a result of an acquisition. Generally, the recipients of the restricted shares or
units receive a dividend or dividend equivalent.
The following summarizes the aggregate activity of these restricted shares and units for the year ended
December 31, 2021:
Weighted-Average
Millions of Dollars
Stock Units
Grant Date Fair Value
Total Fair Value
Outstanding at December 31, 2020
$
Granted
Cancelled
(1,948 )
Issued
(149,488 )
$
Outstanding at December 31, 2021
$
Not Vested at December 31, 2021
$
At December 31, 2021, the remaining compensation cost from the unvested restricted stock was $
which will be recognized over a weighted-average period of
weighted-average grant date fair value of awards granted during 2020 and 2019 was $
,
respectively. The total fair value of awards issued during 2020 and 2019 was $
respectively.
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
Note 17—Income Taxes
Components of income tax provision (benefit) were:
Millions of Dollars
2021
2020
2019
Income Taxes
Federal
Current
$
Deferred
(625 )
(113 )
Foreign
Current
Deferred
(70 )
(323 )
State and local
Current
(4 )
Deferred
(139 )
(8 )
Total tax provision (benefit)
$
(485 )
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
$
Inventory
Other
Total deferred tax liabilities
Deferred Tax Assets
Benefit plan accruals
Asset retirement obligations and accrued environmental costs
Investments in joint ventures
Other financial accruals and deferrals
Loss and credit carryforwards
Other
Total deferred tax assets
Less: valuation allowance
(8,342 )
(9,965 )
Total deferred tax assets net of valuation allowance
Net deferred tax liabilities
$
At December 31, 2021, noncurrent assets and liabilities included deferred taxes of $
respectively. At December 31, 2020, noncurrent assets and liabilities included deferred taxes of $
$
At December 31, 2021, the loss and credit carryforward deferred tax assets were primarily related to U.S. foreign
tax credit carryforwards of $
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 $
Notes to Consolidated Financial Statements
137
ConocoPhillips 2021 10-K
The following table shows a reconciliation of the beginning and ending deferred tax asset valuation allowance for
for 2021, 2020 and 2019:
Millions of Dollars
2021
2020
2019
Balance at January 1
$
Charged to expense (benefit)
(45 )
(225 )
Other*
(1,578 )
(709 )
Balance at December 31
$
*Represents changes due to originating deferred tax asset that have no impact to our effective tax rate, acquisitions/dispositions/revisions and
the effect of translating foreign financial statements.
Valuation allowances have been established to reduce deferred tax assets to an amount that will, more likely than
not, be realized. At December 31, 2021, we have maintained a valuation allowance with respect to substantially all
U.S. foreign tax credit carryforwards as well as certain net operating loss carryforwards for various jurisdictions.
During 2021, the valuation allowance movement charged to earnings primarily relates to the fair value
measurement of our CVE common shares that are not expected to be realized, and the expected realization of
certain U.S. tax attributes associated with our planned disposition of our Indonesia assets. This is partially offset
by Australian tax benefits associated with our impairment of APLNG that we do not expect to be realized. Other
movements are primarily related to valuation allowances on expiring tax attributes. Based on our historical
taxable income, expectations for the future, and available tax-planning strategies, management expects deferred
tax assets, net of valuation allowances, will primarily be realized as offsets to reversing deferred tax liabilities. For
more information on our pending Indonesia disposition
During 2020, the valuation allowance movement charged to earnings primarily related to capital losses in Australia
and to the fair value measurement of our CVE common shares that are not expected to be realized. Other
movements are primarily related to valuation allowances on expiring tax attributes.
On December 2, 2019, the Internal Revenue Service finalized foreign tax credit regulations related to the 2017 Tax
Cuts and Jobs Act. Due to the finalization of these regulations, in the fourth quarter of 2019 we recognized $
million of net deferred tax assets. Correspondingly, we recorded $
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 $
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 $
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
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
$
Additions based on tax positions related to the current year
Additions for tax positions of prior years
Reductions for tax positions of prior years
(5 )
(34 )
(22 )
Settlements
(9 )
(9 )
Lapse of statute
(48 )
(1 )
(2 )
Balance at December 31
$
Included in the balance of unrecognized tax benefits for 2021, 2020 and 2019 were $
and $
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.
At December 31, 2021, 2020 and 2019, accrued liabilities for interest and penalties totaled $
and $
earnings of $
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 $
outside tax basis previously offset by a full reserve.
Notes to Consolidated Financial Statements
139
ConocoPhillips 2021 10-K
The amounts of U.S. and foreign income (loss) before income taxes, with a reconciliation of tax at the federal
statutory rate to the provision for income taxes, were:
Millions of Dollars
Percent of Pre-Tax Income (Loss)
2021
2020
2019
2021
2020
2019
Income (loss) before income taxes
United States
$
(3,587 )
%
Foreign
(14.2 )
$
(3,140 )
%
Federal statutory income tax
$
(659 )
%
Non-U.S. effective tax rates
(6.2 )
Tax impact of debt restructuring
Australia disposition
(349 )
U.K. disposition
(732 )
(7.7 )
Recovery of outside basis
(55 )
(22 )
(77 )
(0.4 )
(0.8 )
Adjustment to tax reserves
(11 )
(0.1 )
(0.6 )
Adjustment to valuation allowance
(45 )
(225 )
(0.4 )
(14.6 )
(2.4 )
State income tax
(112 )
Malaysia Deepwater Incentive
(164 )
(1.7 )
Enhanced oil recovery credit
(99 )
(6 )
(27 )
(0.8 )
(0.3 )
Other
(11 )
(9 )
(39 )
(0.1 )
(0.4 )
Tota l
$
(485 )
%
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 $
ability to utilize the U.S. foreign tax credit and capital loss carryforward due to our anticipated disposition of our
Indonesia entities of $
tax impact of the impairment of our APLNG investment of $
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 $
the de-recognition of deferred tax assets resulting in $
Australia capital loss tax benefit of $
changes in the fair market value of CVE common shares, the valuation allowance was increased by $
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 $
disposition generated a U.S. capital loss of approximately $
approximately $
with a valuation allowance.
During 2019, we received final partner approval in Malaysia Block G to claim certain deepwater tax credits. As a
result, we recorded an income tax benefit of $
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
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)
Cumulative effect of adopting ASU No. 2018-02*
(40 )
(40 )
December 31, 2019
(350 )
(5,007 )
(5,357 )
Other comprehensive income
(75 )
December 31, 2020
(425 )
(4,795 )
(5,218 )
Other comprehensive income (loss)
(2 )
(124 )
December 31, 2021
$
(31 )
(4,919 )
(4,950 )
2019.
During 2019, we recognized $
our sale of two ConocoPhillips U.K. subsidiaries.
The following table summarizes reclassifications out of accumulated other comprehensive loss during the years
ended December 31:
Millions of Dollars
2021
2020
Defined Benefit Plans
$
Above amounts are included in the computation of net periodic benefit cost and
are presented net of tax expense of:
$
See Note 16.
Notes to Consolidated Financial Statements
141
ConocoPhillips 2021 10-K
Note 19—Cash Flow Information
Millions of Dollars
2021
2020
2019
Noncash Investing Activities
Increase (decrease) in PP&E related to an increase (decrease) in asset
retirement obligations
$
(116 )
Cash Payments
Interest
$
Income taxes
Net Sales (Purchases) of Investments
Short-term investments purchased
$
(5,554 )
(12,435 )
(4,902 )
Short-term investments sold
Investments and long-term receivables purchased
(279 )
(325 )
(146 )
Investments and long-term receivables sold
$
(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 $
$
We collected $
Tribunal in 2018. For more information on these settlements,
See
sheet associated with our Concho acquisition.
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
Note 20—Other Financial Information
Millions of Dollars
2021
2020
2019
Interest and Debt Expense
Incurred
Debt
$
Other
Capitalized
(62 )
(55 )
(57 )
Expensed
$
Other Income (Loss)
Interest income
$
Gain (loss) on investment in Cenovus Energy*
(855 )
Other, net
$
(509 )
*See Note 5.
Research and Development Expenditures
—expensed
$
Shipping and Handling Costs
$
Foreign Currency Transaction (Gains) Losses
—after-tax
Alaska
$
Lower 48
Canada
(1 )
(7 )
Europe, Middle East and North Africa
(11 )
(15 )
Asia Pacific
(11 )
Other International
Corporate and Other
(7 )
(31 )
$
(16 )
(62 )
Millions of Dollars
2021
2020
Properties, Plants and Equipment
Proved properties*
$
**
Unproved properties*
Other
Gross properties, plants and equipment
Less: Accumulated depreciation, depletion and amortization
(64,735 )
**
(62,213 )
Net properties, plants and equipment
$
*Proved and Unproved properties increased by $
**Excludes assets classified as held for sale at December 31, 2021. See Note 3.
Notes to Consolidated Financial Statements
143
ConocoPhillips 2021 10-K
Note 21—Related Party Transactions
Our related parties primarily include equity method investments and certain trusts for the benefit of employees.
For disclosures on trusts for the benefit of employees,
Significant transactions with our equity affiliates were:
Millions of Dollars
2021
2020
2019
Operating revenues and other income
$
Purchases
Operating expenses and selling, general and administrative expenses
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
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
$
Revenue from contracts outside the scope of ASC Topic 606
Physical contracts meeting the definition of a derivative
Financial derivative contracts
(262 )
(55 )
(97 )
Consolidated sales and other operating revenues
$
Revenues from contracts outside the scope of ASC Topic 606 relate primarily to physical gas contracts at market
prices which qualify as derivatives accounted for under ASC Topic 815, “Derivatives and Hedging,” and for which
we have not elected NPNS. There is no significant difference in contractual terms or the policy for recognition of
revenue from these contracts and those within the scope of ASC Topic 606. The following disaggregation of
revenues is provided in conjunction with
Millions of Dollars
2021
2020
2019
Revenue from Outside the Scope of ASC Topic 606
by Segment
Lower 48
$
Canada
Europe, Middle East and North Africa
Physical contracts meeting the definition of a derivative
$
Millions of Dollars
2021
2020
2019
Revenue from Outside the Scope of ASC Topic 606
by Product
Crude oil
$
Natural gas
Other
Physical contracts meeting the definition of a derivative
$
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
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.
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 $
with customers within the scope of ASC Topic 606 and those that are outside the scope of ASC Topic 606.
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
Millions of Dollars
Contract Liabilities
At December 31, 2020
$
Contractual payments received
Revenue recognized
(62 )
At December 31, 2021
$
Amounts Recognized in the Consolidated Balance Sheet at December 31, 2021
Current liabilities
$
Notes to Consolidated Financial Statements
145
ConocoPhillips 2021 10-K
Note 23—Segment Disclosures and Related Information
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on a worldwide
basis. We manage our operations through
region: Alaska; Lower 48; Canada; Europe, Middle East and North Africa; Asia Pacific; and Other International.
Corporate and Other represents income and costs not directly associated with an operating segment, such as most
interest expense, premiums on early retirement of debt, corporate overhead and certain technology activities,
including licensing revenues. Corporate assets include all cash and cash equivalents and short-term investments.
We evaluate performance and allocate resources based on net income (loss) attributable to ConocoPhillips.
Segment accounting policies are the same as those in
. Intersegment sales are at prices that approximate
market.
In 2021, we completed our acquisition of Concho, an independent oil and gas exploration and production company
with operations across New Mexico and West Texas as well as our acquisition of Shell’s Permian assets in the Texas
Delaware Basin. The accounting close date of the Shell transaction , used for reporting purposes, was December
31, 2021. Results of operations for Concho and assets acquired from Shell are included in our Lower 48 segment.
Certain transaction and restructuring costs associated with these acquisitions are included in our Corporate and
Other segment.
Analysis of Results by Operating Segment
Millions of Dollars
2021
2020
2019
Sales and Other Operating Revenues
Alaska
$
Intersegment eliminations
(11 )
Alaska
Lower 48
Intersegment eliminations
(12 )
(51 )
(46 )
Lower 48
Canada
Intersegment eliminations
(1,583 )
(405 )
(1,141 )
Canada
Europe, Middle East and North Africa
Intersegment eliminations
(2 )
Europe, Middle East and North Africa
Asia Pacific
Other International
Corporate and Other
Consolidated sales and other operating revenues
$
The market for our products is large and diverse, therefore, our sales and other operating revenues are not
dependent upon any single customer.
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
Millions of Dollars
2021
2020
2019
Depreciation, Depletion, Amortization and Impairments
Alaska
$
Lower 48
Canada
Europe, Middle East and North Africa
Asia Pacific
Other International
Corporate and Other
Consolidated depreciation, depletion, amortization and impairments
$
Equity in Earnings of Affiliates
Alaska
$
(7 )
Lower 48
(18 )
(11 )
(159 )
Canada
Europe, Middle East and North Africa
Asia Pacific
Other International
Corporate and Other
Consolidated equity in earnings of affiliates
$
Income Tax Provision (Benefit)
Alaska
$
(256 )
Lower 48
(378 )
Canada
(185 )
(43 )
Europe, Middle East and North Africa
Asia Pacific
Other International
(53 )
(20 )
Corporate and Other
(282 )
(76 )
(233 )
Consolidated income tax provision (benefit)
$
(485 )
Net Income (Loss) Attributable to ConocoPhillips
Alaska
$
(719 )
Lower 48
(1,122 )
Canada
(326 )
Europe, Middle East and North Africa
Asia Pacific
Other International
(107 )
(64 )
Corporate and Other
(210 )
(1,880 )
Consolidated net income (loss) attributable to ConocoPhillips
$
(2,701 )
Notes to Consolidated Financial Statements
147
ConocoPhillips 2021 10-K
Millions of Dollars
2021
2020
2019
Investments in and Advances to Affiliates
Alaska
$
Lower 48
Canada
Europe, Middle East and North Africa
Asia Pacific
Other International
Corporate and Other
Consolidated investments in and advances to affiliates
$
Total Assets
Alaska
$
Lower 48
Canada
Europe, Middle East and North Africa
Asia Pacific
Other International
Corporate and Other
Consolidated total assets
$
Capital Expenditures and Investments
Alaska
$
Lower 48
Canada
Europe, Middle East and North Africa
Asia Pacific
Other International
Corporate and Other
Consolidated capital expenditures and investments
$
Interest Income and Expense
Interest income
Alaska
$
Lower 48
Canada
Europe, Middle East and North Africa
Asia Pacific
Other International
Corporate and Other
Interest and debt expense
Corporate and Other
$
Sales and Other Operating Revenues by Product
Crude oil
$
Natural gas
Natural gas liquids
Other*
Consolidated sales and other operating revenues by product
$
*Includes LNG and bitumen.
Notes to Consolidated Financial Statements
ConocoPhillips 2021 10-K
Geographic Information
Millions of Dollars
Sales and Other Operating Revenues
(1)
Long-Lived Assets
(2)
2021
2020
2019
2021
2020
2019
United States
$
Australia and Timor-Leste
Canada
China
Indonesia
(3)
Libya
Malaysia
Norway
United Kingdom
Other foreign countries
Worldwide consolidated
$
(1) Sales and other operating revenues are attributable to countries based on the location of the selling operation.
(2) Defined as net PP&E plus equity investments and advances to affiliated companies.
(3) Met held for sale criteria in 2021 in conjunction with our agreement to sell our subsidiary holding our Indonesia assets.
Supplementary Data
149
ConocoPhillips 2021 10-K
Oil and Gas Operations
(Unaudited)
In accordance with FASB ASC Topic 932, “Extractive Activities—Oil and Gas,” and regulations of the SEC, we are
making certain supplemental disclosures about our oil and gas exploration and production operations.
These disclosures include information about our consolidated oil and gas activities and our proportionate share of
our equity affiliates’ oil and gas activities in our operating segments. As a result, amounts reported as equity
affiliates in Oil and Gas Operations may differ from those shown in the individual segment disclosures reported
elsewhere in this report. Our disclosures by geographic area include the U.S., Canada, Europe, Asia Pacific/Middle
East (inclusive of equity affiliates) , and Africa.
As required by current authoritative guidelines, the estimated future date when an asset will be permanently shut
down for economic reasons is based on historical 12-month first-of-month average prices and current costs. This
estimated date when production will end affects the amount of estimated reserves. Therefore, as prices and cost
levels change from year to year, the estimate of proved reserves also changes. Generally, our proved reserves
decrease as prices decline and increase as prices rise.
Our proved reserves include estimated quantities related to PSCs, which are reported under the “economic
interest” method, as well as variable-royalty regimes, and are subject to fluctuations in commodity prices,
recoverable operating expenses and capital costs. If costs remain stable, reserve quantities attributable to
recovery of costs will change inversely to changes in commodity prices. For example, if prices increase, then our
applicable reserve quantities would decline. At December 31, 2021, approximately 4 percent of our total proved
reserves were under PSCs, located in our Asia Pacific/Middle East geographic reporting area, and 5 percent of our
total proved reserves were under a variable-royalty regime, located in our Canada geographic reporting area.
Reserves Governance
The recording and reporting of proved reserves are governed by criteria established by regulations of the SEC and
FASB. Proved reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data,
can be estimated with reasonable certainty to be economically producible—from a given date forward, from
known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior
to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is
reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The
project to extract the hydrocarbons must have commenced or the operator must be reasonably certain it will
commence the project within a reasonable time.
Proved reserves are further classified as either developed or undeveloped. Proved developed reserves are proved
reserves that can be expected to be recovered through existing wells with existing equipment and operating
methods, or in which the cost of the required equipment is relatively minor compared with the cost of a new well,
and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if
the extraction is by means not involving a well. Proved undeveloped reserves are proved reserves expected to be
recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is
required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development
spacing areas that are reasonably certain of production when drilled, unless evidence provided by reliable
technologies exists that establishes reasonable certainty of economic producibility at greater distances. As defined
by SEC regulations, reliable technologies may be used in reserve estimation when they have been demonstrated in
the field to provide reasonably certain results with consistency and repeatability in the formation being evaluated
or in an analogous formation. The technologies and data used in the estimation of our proved reserves include, but
are not limited to, performance-based methods, volumetric -based methods, geologic maps, seismic interpretation,
well logs, well test data, core data, analogy and statistical analysis.
Supplementary Data
ConocoPhillips 2021 10-K
We have a company -wide, comprehensive, SEC-compliant internal policy that governs the determination and
reporting of proved reserves. This policy is applied by the geoscientists and reservoir engineers in our business
units around the world. As part of our internal control process, each business unit’s reserves processes and
controls are reviewed annually by an internal team which is headed by the company’s Manager of Reserves
Compliance and Reporting. This team, composed of internal reservoir engineers, geoscientists, finance personnel
and a senior representative from DeGolyer and MacNaughton (D&M), a third -party petroleum engineering
consulting firm, reviews the business units’ reserves for adherence to SEC guidelines and company policy through
on-site visits, teleconferences and review of documentation. In addition to providing independent reviews, this
internal team also ensures reserves are calculated using consistent and appropriate standards and procedures.
This team is independent of business unit line management and is responsible for reporting its findings to senior
management. The team is responsible for communicating our reserves policy and procedures and is available for
internal peer reviews and consultation on major projects or technical issues throughout the year. All of our proved
reserves held by consolidated companies and our share of equity affiliates have been estimated by ConocoPhillips.
During 2021, our processes and controls used to assess over 90 percent of proved reserves as of December 31,
2021, were reviewed by D&M. The purpose of their review was to assess whether the adequacy and effectiveness
of our internal processes and controls used to determine estimates of proved reserves are in accordance with SEC
regulations. In such review, ConocoPhillips’ technical staff presented D&M with an overview of the reserves data,
as well as the methods and assumptions used in estimating reserves. The data presented included pertinent
seismic information, geologic maps, well logs, production tests, material balance calculations, reservoir simulation
models, well performance data, operating procedures and relevant economic criteria. Management’s intent in
retaining D&M to review its processes and controls was to provide objective third-party input on these processes
and controls. D&M’s opinion was the general processes and controls employed by ConocoPhillips in estimating its
December 31, 2021, proved reserves for the properties reviewed are in accordance with the SEC reserves
definitions. D&M’s report is included as Exhibit 99 of this Annual Report on Form 10-K.
The technical person primarily responsible for overseeing the processes and internal controls used in the
preparation of the company’s reserves estimates is the Manager of Reserves Compliance and Reporting. This
individual holds a master’s degree in petroleum engineering. He is a member of the Society of Petroleum
Engineers with over 25 years of oil and gas industry experience and has held positions of increasing responsibility
in reservoir engineering, subsurface and asset management in the U.S. and several international field locations.
Engineering estimates of the quantities of proved reserves are inherently imprecise. See the “Critical Accounting
Estimates” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for
additional discussion of the sensitivities surrounding these estimates.
Supplementary Data
151
ConocoPhillips 2021 10-K
Proved Reserves
Years Ended
Crude Oil
December 31
Millions of Barrels
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Total
Developed and Undeveloped
Consolidated operations
End of 2018
1,233
703
1,936
4
246
159
188
2,533
Revisions
40
(36)
4
(1)
18
(5)
23
39
Improved recovery
7
-
7
-
-
-
-
7
Purchases
-
1
1
-
-
-
-
1
Extensions and discoveries
25
226
251
2
-
11
-
264
Production
(74)
(95)
(169)
-
(36)
(31)
(14)
(250)
Sales
-
(2)
(2)
-
(30)
-
-
(32)
End of 2019
1,231
797
2,028
5
198
134
197
2,562
Revisions
(297)
(126)
(423)
(2)
4
(4)
(3)
(428)
Improved recovery
-
-
-
-
-
3
-
3
Purchases
-
5
5
3
-
-
-
8
Extensions and discoveries
10
108
118
3
-
-
-
121
Production
(65)
(77)
(142)
(2)
(28)
(25)
(3)
(200)
Sales
-
(14)
(14)
(1)
-
-
-
(15)
End of 2020
879
693
1,572
6
174
108
191
2,051
Revisions
209
(52)
157
2
14
37
6
216
Improved recovery
1
-
1
-
-
-
-
1
Purchases
-
691
691
-
-
-
-
691
Extensions and discoveries
10
289
299
5
2
1
-
307
Production
(64)
(160)
(224)
(3)
(29)
(24)
(13)
(293)
Sales
-
(9)
(9)
-
-
-
-
(9)
End of 2021
1,035
1,452
2,487
10
161
122
184
2,964
Equity affiliates
End of 2018
-
-
-
-
-
78
-
78
Revisions
-
-
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
-
Production
-
-
-
-
-
(5)
-
(5)
Sales
-
-
-
-
-
-
-
-
End of 2019
-
-
-
-
-
73
-
73
Revisions
-
-
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
-
Production
-
-
-
-
-
(5)
-
(5)
Sales
-
-
-
-
-
-
-
-
End of 2020
-
-
-
-
-
68
-
68
Revisions
-
-
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
-
Production
-
-
-
-
-
(5)
-
(5)
Sales
-
-
-
-
-
-
-
-
End of 2021
-
-
-
-
-
63
-
63
Total company
End of 2018
1,233
703
1,936
4
246
237
188
2,611
End of 2019
1,231
797
2,028
5
198
207
197
2,635
End of 2020
879
693
1,572
6
174
176
191
2,119
End of 2021
1,035
1,452
2,487
10
161
185
184
3,027
Supplementary Data
ConocoPhillips 2021 10-K
Years Ended
Crude Oil
December 31
Millions of Barrels
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Total
Developed
Consolidated operations
End of 2018
1,058
346
1,404
2
192
113
185
1,896
End of 2019
1,048
334
1,382
3
149
94
181
1,809
End of 2020
765
263
1,028
6
129
77
175
1,415
End of 2021
912
916
1,828
4
122
98
171
2,223
Equity affiliates
End of 2018
-
-
-
-
-
78
-
78
End of 2019
-
-
-
-
-
73
-
73
End of 2020
-
-
-
-
-
68
-
68
End of 2021
-
-
-
-
-
63
-
63
Undeveloped
Consolidated operations
End of 2018
175
357
532
2
54
46
3
637
End of 2019
183
463
646
2
49
40
16
753
End of 2020
114
430
544
-
45
31
16
636
End of 2021
123
536
659
6
39
24
13
741
Equity affiliates
End of 2018
-
-
-
-
-
-
-
-
End of 2019
-
-
-
-
-
-
-
-
End of 2020
-
-
-
-
-
-
-
-
End of 2021
-
-
-
-
-
-
-
-
Notable changes in proved crude oil reserves in the three years ended December 31, 2021, included:
●
Revisions
: In 2021, Alaska upward revisions were primarily driven by higher prices. Downward revisions in Lower 48 were
due to development timing for specific well locations from unconventional plays of 203 million barrels and technical
revisions of 35 million barrels, partially offset by upward revisions due to higher prices of 115 million barrels and additional
infill drilling in the unconventional plays of 71 million barrels. Upward revisions in Europe were primarily due to higher
prices. In Asia Pacific/Middle East, increases were due to higher prices of 21 million barrels and technical revisions of 16
million barrels.
In 2020, Alaska downward revisions were primarily driven by lower prices of 243 million barrels and development plan
changes of 54 million barrels. Downward revisions in Lower 48 were due to lower prices of 89 million barrels and
development timing for specific well locations from unconventional plays of 82 million barrels, partially offset by upward
technical revisions and additional infill drilling in the unconventional plays of 45 million barrels.
In 2019, Alaska upward revisions were due to cost and technical revisions of 74 million barrels, partially offset by downward
price revisions of 34 million barrels. Upward revisions in Europe and Africa were primarily due to infill drilling and technical
revisions. Downward revisions in Lower 48 were due to changes in development timing for specific well locations from the
unconventional plays of 71 million barrels and price revisions of 22 million barrels, partially offset by upward revisions
related to infill drilling and improved well performance of 57 million barrels.
Supplementary Data
153
ConocoPhillips 2021 10-K
●
Purchases
:
In 2021, Lower 48 purchases were due to the Concho and Shell Permian acquisitions.
●
Extensions and discoveries
: In 2021, extensions and discoveries in Lower 48 were due to planned development to add
specific well locations from the unconventional plays which more than offset the decreases resulting from development
plan timing in the revisions category.
In 2020, extensions and discoveries in Lower 48 were due to planned development to add specific well locations from the
unconventional plays which more than offset the decreases resulting from development plan timing in the revisions
category.
In 2019, extensions and discoveries in Lower 48 were due to planned development to add specific well locations from the
unconventional plays which more than offset the decreases in the revisions category. In Asia Pacific/Middle East, increases
were due to sanctioning of development programs in China and Malaysia.
●
Sales
: In 2019, Europe sales represent the disposition of the U.K. assets.
Supplementary Data
ConocoPhillips 2021 10-K
Years Ended
Natural Gas Liquids
December 31
Millions of Barrels
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Total
Developed and Undeveloped
Consolidated operations
End of 2018
106
222
328
1
17
3
349
Revisions
(1)
(11)
(12)
-
3
(1)
(10)
Improved recovery
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
Extensions and discoveries
-
62
62
1
-
-
63
Production
(5)
(28)
(33)
-
(3)
(1)
(37)
Sales
-
-
-
-
(4)
-
(4)
End of 2019
100
245
345
2
13
1
361
Revisions
-
(26)
(26)
-
1
(1)
(26)
Improved recovery
-
-
-
-
-
-
-
Purchases
-
2
2
2
-
-
4
Extensions and discoveries
-
41
41
1
-
-
42
Production
(6)
(27)
(33)
(1)
(2)
-
(36)
Sales
-
(5)
(5)
-
-
-
(5)
End of 2020
94
230
324
4
12
-
340
Revisions
(6)
213
207
-
1
-
208
Improved recovery
-
-
-
-
-
-
-
Purchases
-
72
72
-
-
-
72
Extensions and discoveries
-
82
82
2
-
-
84
Production
(6)
(50)
(56)
(1)
(2)
-
(59)
Sales
-
(1)
(1)
-
-
-
(1)
End of 2021
82
546
628
5
11
-
644
Equity affiliates
End of 2018
-
-
-
-
-
42
42
Revisions
-
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
Production
-
-
-
-
-
(3)
(3)
Sales
-
-
-
-
-
-
-
End of 2019
-
-
-
-
-
39
39
Revisions
-
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
Production
-
-
-
-
-
(3)
(3)
Sales
-
-
-
-
-
-
-
End of 2020
-
-
-
-
-
36
36
Revisions
-
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
Production
-
-
-
-
-
(3)
(3)
Sales
-
-
-
-
-
-
-
End of 2021
-
-
-
-
-
33
33
Total company
End of 2018
106
222
328
1
17
45
391
End of 2019
100
245
345
2
13
40
400
End of 2020
94
230
324
4
12
36
376
End of 2021
82
546
628
5
11
33
677
Supplementary Data
155
ConocoPhillips 2021 10-K
Years Ended
Natural Gas Liquids
December 31
Millions of Barrels
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Total
Developed
Consolidated operations
End of 2018
106
97
203
-
15
3
221
End of 2019
100
99
199
1
10
1
211
End of 2020
94
83
177
4
9
-
190
End of 2021
82
334
416
3
9
-
428
Equity affiliates
End of 2018
-
-
-
-
-
42
42
End of 2019
-
-
-
-
-
39
39
End of 2020
-
-
-
-
-
36
36
End of 2021
-
-
-
-
-
33
33
Undeveloped
Consolidated operations
End of 2018
-
125
125
1
2
-
128
End of 2019
-
146
146
1
3
-
150
End of 2020
-
147
147
-
3
-
150
End of 2021
-
212
212
2
2
-
216
Equity affiliates
End of 2018
-
-
-
-
-
-
-
End of 2019
-
-
-
-
-
-
-
End of 2020
-
-
-
-
-
-
-
End of 2021
-
-
-
-
-
-
-
Notable changes in proved NGL reserves in the three years ended December 31, 2021, included:
●
Revisions
: In 2021, upward revisions in Lower 48 were due to conversion of acquired Concho Permian two-stream contracts
to a three-stream (crude oil, natural gas and natural gas liquids) basis, adding 182 million barrels, additional infill drilling in
the unconventional plays of 44 million barrels, technical revisions of 21 million barrels and higher prices of 28 million
barrels, partially offset by downward revisions related to development timing for specific well locations from
unconventional plays of 62 million barrels.
In 2020, downward revisions in Lower 48 were due to lower prices of 33 million barrels and development timing for specific
well locations from unconventional plays of 20 million barrels, partially offset by upward technical revisions and additional
infill drilling in the unconventional plays of 27 million barrels.
In 2019, downward revisions in Lower 48 were due to changes in development timing for specific well locations from the
unconventional plays of 32 million barrels and price revisions of 11 million barrels, partially offset by upward revisions
related to infill drilling and improved well performance of 32 million barrels.
●
Purchases
: In 2021, Lower 48 purchases were due to the Shell Permian acquisition.
●
Extensions and discoveries
: In 2021, extensions and discoveries in Lower 48 were due to planned development to add
specific well locations from the unconventional plays which more than offset the decreases in the revisions category.
In 2020, extensions and discoveries in Lower 48 were due to planned development to add specific well locations from the
unconventional plays , which more than offset the decreases in the revisions category.
In 2019, extensions and discoveries in Lower 48 were due to planned development to add specific well locations from the
unconventional plays , which more than offset the decreases in the revisions category.
●
Sales
: In 2019, Europe sales represent the disposition of the U.K. assets.
Supplementary Data
ConocoPhillips 2021 10-K
Years Ended
Natural Gas
December 31
Billions of Cubic Feet
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Total
Developed and Undeveloped
Consolidated operations
End of 2018
2,736
2,318
5,054
26
1,212
1,079
214
7,585
Revisions
30
(113)
(83)
(2)
160
147
21
243
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
2
2
-
-
-
-
2
Extensions and discoveries
7
483
490
23
-
1
-
514
Production
(85)
(252)
(337)
(4)
(178)
(250)
(11)
(780)
Sales
-
(7)
(7)
-
(298)
-
-
(305)
End of 2019
2,688
2,431
5,119
43
896
977
224
7,259
Revisions
(607)
(439)
(1,046)
(15)
39
103
2
(917)
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
74
74
29
-
-
-
103
Extensions and discoveries
-
304
304
33
2
-
-
339
Production
(85)
(231)
(316)
(16)
(112)
(171)
(2)
(617)
Sales
-
(39)
(39)
-
-
(58)
-
(97)
End of 2020
1,996
2,100
4,096
74
825
851
224
6,070
Revisions
715
41
756
15
54
60
-
885
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
2,438
2,438
-
-
-
-
2,438
Extensions and discoveries
-
822
822
46
2
-
-
870
Production
(86)
(473)
(559)
(30)
(113)
(147)
(7)
(856)
Sales
-
(270)
(270)
-
-
-
-
(270)
End of 2021
2,625
4,658
7,283
105
768
764
217
9,137
Equity affiliates
End of 2018
-
-
-
-
-
4,564
-
4,564
Revisions
-
-
-
-
-
(7)
-
(7)
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
252
-
252
Production
-
-
-
-
-
(388)
-
(388)
Sales
-
-
-
-
-
-
-
-
End of 2019
-
-
-
-
-
4,421
-
4,421
Revisions
-
-
-
-
-
(382)
-
(382)
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
2
-
2
Extensions and discoveries
-
-
-
-
-
78
-
78
Production
-
-
-
-
-
(395)
-
(395)
Sales
-
-
-
-
-
-
-
-
End of 2020
-
-
-
-
-
3,724
-
3,724
Revisions
-
-
-
-
-
247
-
247
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
116
-
116
Production
-
-
-
-
-
(390)
-
(390)
Sales
-
-
-
-
-
-
-
-
End of 2021
-
-
-
-
-
3,697
-
3,697
Total company
End of 2018
2,736
2,318
5,054
26
1,212
5,643
214
12,149
End of 2019
2,688
2,431
5,119
43
896
5,398
224
11,680
End of 2020
1,996
2,100
4,096
74
825
4,575
224
9,794
End of 2021
2,625
4,658
7,283
105
768
4,461
217
12,834
Supplementary Data
157
ConocoPhillips 2021 10-K
Years Ended
Natural Gas
December 31
Billions of Cubic Feet
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Total
Developed
Consolidated operations
End of 2018
2,720
1,427
4,147
17
1,052
758
214
6,188
End of 2019
2,601
1,398
3,999
30
697
843
224
5,793
End of 2020
1,961
1,051
3,012
74
598
806
224
4,714
End of 2021
2,579
3,100
5,679
52
679
688
217
7,315
Equity affiliates
End of 2018
-
-
-
-
-
4,059
-
4,059
End of 2019
-
-
-
-
-
3,898
-
3,898
End of 2020
-
-
-
-
-
3,293
-
3,293
End of 2021
-
-
-
-
-
3,204
-
3,204
Undeveloped
Consolidated operations
End of 2018
16
891
907
9
160
321
-
1,397
End of 2019
87
1,033
1,120
13
199
134
-
1,466
End of 2020
35
1,049
1,084
-
227
45
-
1,356
End of 2021
46
1,558
1,604
53
89
76
-
1,822
Equity affiliates
End of 2018
-
-
-
-
-
505
-
505
End of 2019
-
-
-
-
-
523
-
523
End of 2020
-
-
-
-
-
431
-
431
End of 2021
-
-
-
-
-
493
-
493
Natural gas production in the reserves table may differ from gas production (delivered for sale) in our statistics disclosure, primarily
because the quantities above include gas consumed in production operations.
Quantities consumed in production operations are
not significant in the periods presented. The value of net production consumed in operations is not reflected in net revenues and
production expenses, nor do the volumes impact the respective per unit metrics.
Reserve volumes include natural gas to be consumed in operations of 2,748 Bcf, 2,286 Bcf and 3,141 Bcf, as of December 31, 2021,
2020 and 2019, respectively. These volumes are not included in the calculation of our Standardized Measure of Discounted Future
Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities.
Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.
Notable changes in proved natural gas reserves in the three years ended December 31, 2021, included:
●
Revisions
: In 2021, upward revisions in Alaska were due to higher prices of 587 Bcf and technical revisions of 128 Bcf. In
Lower 48, upward revisions of 614 Bcf were due to higher prices, additional infill drilling in the unconventional plays of 277
Bcf and technical revisions of 60 Bcf, partially offset by downward revisions due to development timing for specific well
locations from unconventional plays of 498 Bcf and conversion of previously acquired Permian two-stream contracted
volumes to a three-stream (crude oil, natural gas and natural gas liquids) basis of 412 Bcf. Upward revisions in Canada were
due to higher prices of 29 Bcf, partially offset by downward revisions due to technical revisions of 14 Bcf. In Europe,
upward revisions were primarily due to higher prices. Upward revisions in our consolidated operations in Asia
Pacific/Middle East were due to technical revisions of 76 Bcf, partially offset by price revisions of 16 Bcf. In our equity
affiliates in Asia Pacific/Middle East, upward revisions were due to higher prices of 124 Bcf and technical and cost revisions
of 123 Bcf.
In 2020,
downward revisions in Alaska were primarily due to lower prices. In Lower 48, downward revisions of 372 Bcf were
due to lower prices and 154 Bcf were due to development timing for specific well locations from unconventional plays,
partially offset by technical revisions of 87 Bcf. Downward revisions in our equity affiliates in Asia Pacific/Middle East were
Supplementary Data
ConocoPhillips 2021 10-K
due to lower prices of 426 Bcf, partially offset by performance revisions of 44 Bcf. Upward revisions in our consolidated
operations in Asia Pacific/Middle East were due to technical revisions of 88 Bcf and price revisions of 15 Bcf.
In 2019, upward revisions in Europe were due to technical and cost revisions. In Asia Pacific/Middle East upward revisions
were primarily due to the Indonesia Corridor PSC term extension. Downward revisions in Lower 48 were due to changes in
development timing for specific well locations from the unconventional plays of 207 Bcf and price revisions of 125 Bcf,
partially offset by upward revisions related to infill drilling and improved well performance of 219 Bcf.
●
Purchases
: In 2021, Lower 48 purchases were due to the Concho and Shell Permian acquisitions.
In 2020, Canada purchases were due to the acquisition of additional Montney acreage.
●
Extensions and discoveries
: In 2021, extensions and discoveries in Lower 48 were due to planned development to add
specific well locations from the unconventional plays which more than offset the decreases resulting from development
plan timing in the revisions category. Extensions and discoveries in Canada were primarily driven by ongoing drilling
successes in Montney.
In 2020,
extensions and discoveries in Lower 48 were due to planned development to add specific well locations from the
unconventional plays which more than offset the decreases resulting from development plan timing in the revisions
category. Extensions and discoveries in Canada were primarily driven by ongoing drilling successes in Montney.
In 2019, extensions and discoveries in Lower 48 were due to planned development to add specific well locations from the
unconventional plays which more than offset the decreases in the revisions category. Extensions and discoveries in our
equity affiliates were due to ongoing development in APLNG.
●
Sales
: In 2021, Lower 48 sales represent the disposition of noncore assets.
In 2020, Asia Pacific/Middle East sales represent the disposition of the Australia -West assets.
In 2019, Europe sales represent the disposition of the U.K. assets.
Supplementary Data
159
ConocoPhillips 2021 10-K
Years Ended
Bitumen
December 31
Millions of Barrels
Canada
Developed and Undeveloped
Consolidated operations
End of 2018
236
Revisions
37
Improved recovery
-
Purchases
-
Extensions and discoveries
31
Production
(22)
Sales
-
End of 2019
282
Revisions
(15)
Improved recovery
-
Purchases
-
Extensions and discoveries
85
Production
(20)
Sales
-
End of 2020
332
Revisions
(50)
Improved recovery
-
Purchases
-
Extensions and discoveries
-
Production
(25)
Sales
-
End of 2021
257
Equity affiliates
End of 2018
-
Revisions
-
Improved recovery
-
Purchases
-
Extensions and discoveries
-
Production
-
Sales
-
End of 2019
-
Revisions
-
Improved recovery
-
Purchases
-
Extensions and discoveries
-
Production
-
Sales
-
End of 2020
-
Revisions
-
Improved recovery
-
Purchases
-
Extensions and discoveries
-
Production
-
Sales
-
End of 2021
-
Total company
End of 2018
236
End of 2019
282
End of 2020
332
End of 2021
257
Supplementary Data
ConocoPhillips 2021 10-K
Years Ended
Bitumen
December 31
Millions of Barrels
Canada
Developed
Consolidated operations
End of 2018
155
End of 2019
187
End of 2020
117
End of 2021
150
Equity affiliates
End of 2018
-
End of 2019
-
End of 2020
-
End of 2021
-
Undeveloped
Consolidated operations
End of 2018
81
End of 2019
95
End of 2020
215
End of 2021
107
Equity affiliates
End of 2018
-
End of 2019
-
End of 2020
-
End of 2021
-
Notable changes in proved bitumen reserves in the three years ended December 31, 2021, included:
●
Revisions
: In 2021, downward revisions of 64 million barrels were driven by changes in carbon tax costs
and 39 million barrels due to changes in development timing for specific pad locations from the Surmont
development program, partially offset by upward revisions from price of 53 million barrels.
In 2020,
downward revisions in Canada were due to changes in development timing for specific pad
locations from the Surmont development program of 12 million barrels with the remaining revisions
primarily related to lower prices.
In 2019, upward revisions in Canada were due to technical revisions in Surmont of 70 million barrels,
partially offset by downward revisions due to changes in development timing for specific pad locations
from the Surmont development program of 31 million barrels.
●
Extensions and discoveries
: In 2020,
extensions and discoveries in Canada were primarily due to planned
development to add specific pad locations from the Surmont development program, which more than
offset the decrease in the revisions category.
In 2019, extensions and discoveries in Canada were due to planned development to add specific pad
locations from the Surmont development program, which offset the decrease in the revisions category of
31 million barrels.
Supplementary Data
161
ConocoPhillips 2021 10-K
Years Ended
Total Proved Reserves
December 31
Millions of Barrels of Oil Equivalent
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Total
Developed and Undeveloped
Consolidated operations
End of 2018
1,795
1,312
3,107
245
465
342
224
4,383
Revisions
44
(67)
(23)
36
48
19
26
106
Improved recovery
7
-
7
-
-
-
-
7
Purchases
-
2
2
-
-
-
-
2
Extensions and discoveries
26
368
394
38
-
11
-
443
Production
(93)
(165)
(258)
(23)
(68)
(74)
(16)
(439)
Sales
-
(3)
(3)
-
(85)
-
-
(88)
End of 2019
1,779
1,447
3,226
296
360
298
234
4,414
Revisions
(398)
(226)
(624)
(20)
12
13
(3)
(622)
Improved recovery
-
-
-
-
-
3
-
3
Purchases
-
19
19
10
-
-
-
29
Extensions and discoveries
10
200
210
95
-
-
-
305
Production
(85)
(142)
(227)
(25)
(49)
(55)
(3)
(359)
Sales
-
(25)
(25)
(1)
-
(10)
-
(36)
End of 2020
1,306
1,273
2,579
355
323
249
228
3,734
Revisions
322
168
490
(45)
23
47
6
521
Improved recovery
1
-
1
-
-
-
-
1
Purchases
-
1,169
1,169
-
-
-
-
1,169
Extensions and discoveries
10
508
518
15
3
1
-
537
Production
(84)
(289)
(373)
(35)
(50)
(48)
(14)
(520)
Sales
-
(54)
(54)
-
-
-
-
(54)
End of 2021
1,555
2,775
4,330
290
299
249
220
5,388
Equity affiliates
End of 2018
-
-
-
-
-
880
-
880
Revisions
-
-
-
-
-
(1)
-
(1)
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
42
-
42
Production
-
-
-
-
-
(73)
-
(73)
Sales
-
-
-
-
-
-
-
-
End of 2019
-
-
-
-
-
848
-
848
Revisions
-
-
-
-
-
(63)
-
(63)
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
13
-
13
Production
-
-
-
-
-
(73)
-
(73)
Sales
-
-
-
-
-
-
-
-
End of 2020
-
-
-
-
-
725
-
725
Revisions
-
-
-
-
-
42
-
42
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
19
-
19
Production
-
-
-
-
-
(73)
-
(73)
Sales
-
-
-
-
-
-
-
-
End of 2021
-
-
-
-
-
713
-
713
Total company
End of 2018
1,795
1,312
3,107
245
465
1,222
224
5,263
End of 2019
1,779
1,447
3,226
296
360
1,146
234
5,262
End of 2020
1,306
1,273
2,579
355
323
974
228
4,459
End of 2021
1,555
2,775
4,330
290
299
962
220
6,101
Supplementary Data
ConocoPhillips 2021 10-K
Years Ended
Total Proved Reserves
December 31
Millions of Barrels of Oil Equivalent
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Total
Developed
Consolidated operations
End of 2018
1,617
681
2,298
160
382
244
221
3,305
End of 2019
1,582
666
2,248
197
275
236
218
3,174
End of 2020
1,186
521
1,707
140
238
211
212
2,508
End of 2021
1,424
1,767
3,191
166
244
212
207
4,020
Equity affiliates
End of 2018
-
-
-
-
-
796
-
796
End of 2019
-
-
-
-
-
761
-
761
End of 2020
-
-
-
-
-
653
-
653
End of 2021
-
-
-
-
-
631
-
631
Undeveloped
Consolidated operations
End of 2018
178
631
809
85
83
98
3
1,078
End of 2019
197
781
978
99
85
62
16
1,240
End of 2020
120
752
872
215
85
38
16
1,226
End of 2021
131
1,008
1,139
124
55
37
13
1,368
Equity affiliates
End of 2018
-
-
-
-
-
84
-
84
End of 2019
-
-
-
-
-
87
-
87
End of 2020
-
-
-
-
-
72
-
72
End of 2021
-
-
-
-
-
82
-
82
Natural gas reserves are converted to barrels of oil equivalent (BOE) based on a 6:1 ratio: six MCF of natural gas converts to one
BOE.
Proved Undeveloped Reserves
The following table shows changes in total proved undeveloped reserves for 2021:
Proved Undeveloped Reserves
Millions of Barrels of
Oil Equivalent
End of 2020
1,298
Revisions
(167)
Improved recovery
1
Purchases
158
Extensions and discoveries
448
Sales
-
Transfers to proved developed
(288)
End of 2021
1,450
Downward revisions were driven by changes in development timing of 389 MMBOE primarily in North America and negative
bitumen revisions in Canada due to changes in carbon tax costs of 65 MMBOE, partially offset by upward revisions for Lower 48 infill
drilling of 162 MMBOE and higher prices of 125 MMBOE.
Purchases were driven by Lower 48 due to the Concho acquisition.
Supplementary Data
163
ConocoPhillips 2021 10-K
Extensions and discoveries were largely driven by an addition of 399 MMBOE in Lower 48 for the continued development of
unconventional plays. The remaining extensions and discoveries were driven by the continued development planned in the other
geographic regions.
Transfers to proved developed reserves were driven by the ongoing development of our assets. Approximately 65 percent of the
transfers were from the development of our Lower 48 unconventional plays. The remainder of transfers were from development
across the other geographic regions.
At December 31, 2021, our PUDs represented 24 percent of total proved reserves, compared with 29 percent at December 31, 2020.
Costs incurred for the year ended December 31, 2021, relating to the development of PUDs were $3.8 billion. A portion of our costs
incurred each year relates to development projects where the PUDs will be converted to proved developed reserves in future years.
At the end of 2021, approximately 93 percent of total PUDs were under development or scheduled for development within five
years of initial disclosure, including all of our Lower 48 PUDs. The remaining PUDs are in major development areas which are
currently producing and within our Canada and Asia Pacific/Middle East geographic areas.
Results of Operations
The company’s results of operations from oil and gas activities for the years 2021, 2020 and 2019 are shown in the following tables.
Non-oil and gas activities, such as pipeline and marine operations, LNG operations, crude oil and gas marketing activities, and the
profit element of transportation operations in which we have an ownership interest are excluded. Additional information about
selected line items within the results of operations tables is shown below:
●
Sales include sales to unaffiliated entities attributable primarily to the company’s net working interests and royalty
interests. Sales are net of fees to transport our produced hydrocarbons beyond the production function to a final delivery
point using transportation operations which are not consolidated.
●
Transportation costs reflect fees to transport our produced hydrocarbons beyond the production function to a final delivery
point using transportatio n operations which are consolidated.
●
Other revenues include gains and losses from asset sales, certain amounts resulting from the purchase and sale of
hydrocarbons, and other miscellaneous income.
●
Production costs include costs incurred to operate and maintain wells, related equipment and facilities used in the
production of petroleum liquids and natural gas.
●
Taxes other than income taxes include production, property and other non-income taxes.
●
Depreciation of support equipment is reclassified as applicable.
●
Other related expenses include inventory fluctuations, foreign currency transaction gains and losses and other
miscellaneous expenses.
Supplementary Data
ConocoPhillips 2021 10-K
Results of Operations
Year Ended
Millions of Dollars
December 31, 2021
Lower
Total
Asia Pacific/
Other
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Areas
Total
Consolidated operations
Sales
$
4,832
14,093
18,925
1,219
3,568
2,525
917
-
27,154
Transfers
4
-
4
-
-
-
-
-
4
Transportation costs
(626)
-
(626)
-
-
-
-
-
(626)
Other revenues
14
135
149
323
(5)
237
141
(161)
684
Total revenues
4,224
14,228
18,452
1,542
3,563
2,762
1,058
(161)
27,216
Production costs excluding taxes
1,073
2,414
3,487
518
487
466
43
-
5,001
Taxes other than income taxes
442
937
1,379
23
36
91
1
1
1,531
Exploration expenses
80
98
178
39
21
51
2
15
306
Depreciation, depletion and
amortization
864
4,053
4,917
383
844
787
35
-
6,966
Impairments
5
(8)
(3)
6
(24)
7
-
-
(14)
Other related expenses
(31)
12
(19)
(22)
(42)
4
4
12
(63)
Accretion
71
47
118
10
70
26
-
-
224
1,720
6,675
8,395
585
2,171
1,330
973
(189)
13,265
Income tax provision (benefit)
378
1,467
1,845
145
1,673
494
870
(53)
4,974
Results of operations
$
1,342
5,208
6,550
440
498
836
103
(136)
8,291
Equity affiliates
Sales
$
-
-
-
-
-
745
-
-
745
Transfers
-
-
-
-
-
1,797
-
-
1,797
Transportation costs
-
-
-
-
-
-
-
-
-
Other revenues
-
-
-
-
-
5
-
-
5
Total revenues
-
-
-
-
-
2,547
-
-
2,547
Production costs excluding taxes
-
-
-
-
-
329
-
-
329
Taxes other than income taxes
-
-
-
-
-
824
-
-
824
Exploration expenses
-
-
-
-
-
268
-
-
268
Depreciation, depletion and
amortization
-
-
-
-
-
593
593
Impairments
-
-
-
-
-
718
-
-
718
Other related expenses
-
-
-
-
-
3
-
-
3
Accretion
-
-
-
-
-
17
-
-
17
-
-
-
-
-
(205)
-
-
(205)
Income tax provision (benefit)
-
-
-
-
-
(42)
-
-
(42)
Results of operations
$
-
-
-
-
-
(163)
-
-
(163)
Supplementary Data
165
ConocoPhillips 2021 10-K
Year Ended
Millions of Dollars
December 31, 2020
Lower
Total
Asia Pacific/
Other
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Areas
Total
Consolidated operations
Sales
$
2,944
3,421
6,365
230
1,560
1,717
129
-
10,001
Transfers
4
-
4
-
-
191
-
-
195
Transportation costs
(587)
-
(587)
-
-
(19)
-
-
(606)
Other revenues
(1)
(20)
(21)
40
(21)
576
11
10
595
Total revenues
2,360
3,401
5,761
270
1,539
2,465
140
10
10,185
Production costs excluding taxes
1,058
1,399
2,457
366
417
478
21
2
3,741
Taxes other than income taxes
296
263
559
16
30
42
3
1
651
Exploration expenses
1,099
73
1,172
40
52
71
13
108
1,456
Depreciation, depletion and
amortization
840
2,544
3,384
335
755
808
8
-
5,290
Impairments
-
804
804
3
5
-
-
-
812
Other related expenses
46
5
51
5
(58)
(25)
(29)
2
(54)
Accretion
72
46
118
8
73
33
-
-
232
(1,051)
(1,733)
(2,784)
(503)
265
1,058
124
(103)
(1,943)
Income tax provision (benefit)
(271)
(430)
(701)
(191)
116
277
88
(20)
(431)
Results of operations
$
(780)
(1,303)
(2,083)
(312)
149
781
36
(83)
(1,512)
Equity affiliates
Sales
$
-
-
-
-
-
483
-
-
483
Transfers
-
-
-
-
-
1,205
-
-
1,205
Transportation costs
-
-
-
-
-
-
-
-
-
Other revenues
-
-
-
-
-
8
-
-
8
Total revenues
-
-
-
-
-
1,696
-
-
1,696
Production costs excluding taxes
-
-
-
-
-
289
-
-
289
Taxes other than income taxes
-
-
-
-
-
502
-
-
502
Exploration expenses
-
-
-
-
-
20
-
-
20
Depreciation, depletion and
amortization
-
-
-
-
-
569
-
-
569
Impairments
-
-
-
-
-
-
-
-
-
Other related expenses
-
-
-
-
-
(2)
-
-
(2)
Accretion
-
-
-
-
-
15
-
-
15
-
-
-
-
-
303
-
-
303
Income tax provision (benefit)
-
-
-
-
-
39
-
-
39
Results of operations
$
-
-
-
-
-
264
-
-
264
Supplementary Data
ConocoPhillips 2021 10-K
Year Ended
Millions of Dollars
December 31, 2019
Lower
Total
Asia Pacific/
Other
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Areas
Total
Consolidated operations
Sales
$
4,883
6,356
11,239
709
3,207
3,032
919
-
19,106
Transfers
4
-
4
-
-
449
-
-
453
Transportation costs
(629)
-
(629)
-
-
(41)
-
-
(670)
Other revenues
61
78
139
86
1,785
12
101
326
2,449
Total revenues
4,319
6,434
10,753
795
4,992
3,452
1,020
326
21,338
Production costs excluding taxes
1,235
1,578
2,813
380
741
619
70
(8)
4,615
Taxes other than income taxes
308
437
745
18
32
54
3
(2)
850
Exploration expenses
97
430
527
32
69
80
5
33
746
Depreciation, depletion and
amortization
700
2,804
3,504
230
842
1,172
37
-
5,785
Impairments
-
402
402
2
1
-
-
-
405
Other related expenses
(12)
116
104
(38)
(42)
58
22
10
114
Accretion
62
49
111
7
142
43
-
-
303
1,929
618
2,547
164
3,207
1,426
883
293
8,520
Income tax provision (benefit)
444
147
591
(74)
591
458
833
7
2,406
Results of operations
$
1,485
471
1,956
238
2,616
968
50
286
6,114
Equity affiliates
Sales
$
-
-
-
-
-
599
-
-
599
Transfers
-
-
-
-
-
2,229
-
-
2,229
Transportation costs
-
-
-
-
-
-
-
-
-
Other revenues
-
-
-
-
-
31
-
-
31
Total revenues
-
-
-
-
-
2,859
-
-
2,859
Production costs excluding taxes
-
-
-
-
-
335
-
-
335
Taxes other than income taxes
-
-
-
-
-
820
-
-
820
Exploration expenses
-
-
-
-
-
-
-
-
-
Depreciation, depletion and
amortization
-
-
-
-
-
579
-
-
579
Impairments
-
-
-
-
-
-
-
-
-
Other related expenses
-
-
-
-
-
11
-
-
11
Accretion
-
-
-
-
-
16
-
-
16
-
-
-
-
-
1,098
-
-
1,098
Income tax provision (benefit)
-
-
-
-
-
170
-
-
170
Results of operations
$
-
-
-
-
-
928
-
-
928
Supplementary Data
167
ConocoPhillips 2021 10-K
Statistics
Net Production
2021
2020
2019
Thousands of Barrels Daily
Crude Oil
Consolidated operations
Alaska
178
181
202
Lower 48
447
213
266
United States
625
394
468
Canada
8
6
1
Europe
81
78
100
Asia Pacific
65
69
85
Africa
37
8
38
Total consolidated operations
816
555
692
Equity affiliates—
Asia Pacific/Middle East
13
13
13
Total company
829
568
705
Delaware Basin Area (Lower 48)*
162
28
24
Greater Prudhoe Area (Alaska)*
67
68
66
Natural Gas Liquids
Consolidated operations
Alaska
16
16
15
Lower 48
110
74
81
United States
126
90
96
Canada
4
2
-
Europe
4
4
7
Asia Pacific
-
1
4
Total consolidated operations
134
97
107
Equity affiliates—
Asia Pacific/Middle East
8
8
8
Total company
142
105
115
Delaware Basin Area (Lower 48)*
27
11
11
Greater Prudhoe Area (Alaska)*
16
15
15
Bitumen
Consolidated operations—
Canada
69
55
60
Total company
69
55
60
Natural Gas
Millions of Cubic Feet Daily
Consolidated operations
Alaska
16
10
7
Lower 48
1,340
585
622
United States
1,356
595
629
Canada
80
40
9
Europe
298
270
447
Asia Pacific
360
429
637
Africa
15
5
31
Total consolidated operations
2,109
1,339
1,753
Equity affiliates—
Asia Pacific/Middle East
1,053
1,055
1,052
Total company
3,162
2,394
2,805
Delaware Basin Area (Lower 48)*
584
99
86
Greater Prudhoe Area (Alaska)*
12
4
4
*At year-end 2021, the Delaware Basin Area in Lower 48 contained more than 15 percent of our total proved reserves. At year-end 2021, 2020
and 2019, the Greater Prudhoe Area in Alaska contained more than 15 percent of our total proved reserves.
Supplementary Data
ConocoPhillips 2021 10-K
Average Sales Prices
2021
2020
2019
Crude Oil Per Barrel
Consolidated operations
Alaska*
$
60.81
33.72
55.85
Lower 48
66.12
35.17
55.30
United States
64.53
34.48
55.54
Canada
56.38
23.57
40.87
Europe
68.94
42.80
65.12
Asia Pacific
70.36
42.84
65.02
Africa
69.06
48.64
64.47
Total international
68.85
42.39
64.85
Total consolidated operations
65.53
36.69
58.51
Equity affiliates
—Asia Pacific/Middle East
69.45
39.02
61.32
Total operations
65.59
36.75
58.57
Natural Gas Liquids Per Barrel
Consolidated operations
Lower 48
$
30.63
12.13
16.83
United States
30.63
12.13
16.85
Canada
31.18
5.41
19.87
Europe
43.97
23.27
29.37
Asia Pacific
-
33.21
37.85
Total international
37.50
20.25
32.29
Total consolidated operations
31.04
12.90
18.73
Equity affiliates
—Asia Pacific/Middle East
54.16
32.69
36.70
Total operations
32.45
14.61
20.09
Bitumen Per Barrel
Consolidated operations—
Canada
$
37.52
8.02
**
31.72
Natural Gas Per Thousand Cubic Feet
Consolidated operations
Alaska
$
2.81
2.91
3.19
Lower 48
4.38
1.65
2.12
United States
4.38
1.66
2.12
Canada
2.54
1.21
0.49
Europe
13.75
3.23
4.92
Asia Pacific*
6.56
5.27
5.73
Africa
3.73
3.71
4.87
Total international
8.91
4.31
5.35
Total consolidated operations
6.00
3.13
4.19
Equity affiliates
—Asia Pacific/Middle East
5.31
3.71
6.29
Total operations
5.77
3.38
4.99
*Average sales prices for Alaska crude oil and Asia Pacific natural gas above reflect a reduction for transportation costs in which we
have an ownership interest that are incurred subsequent to the terminal point of the production function. Accordingly, the average sales prices
differ from those discussed in Item 7 of Management's Discussion and Analysis of Financial Condition and Results of Operations.
**Average sales prices include unutilized transportation costs.
Supplementary Data
169
ConocoPhillips 2021 10-K
2021
2020
2019
Average Production Costs Per Barrel of Oil Equivalent*
Consolidated operations
Alaska
$
14.92
14.60
15.52
Lower 48
8.48
9.93
9.59
United States
9.78
11.51
11.52
Canada
15.10
14.29
16.53
Europe
9.88
8.97
11.22
Asia Pacific
10.21
9.26
8.74
Africa
2.95
6.38
4.46
Total international
10.53
10.11
10.26
Total consolidated operations
9.99
10.99
10.99
Equity affiliates—
Asia Pacific/Middle East
4.60
4.01
4.68
Average Production Costs Per Barrel—Bitumen
Consolidated operations—
Canada
$
13.41
12.45
13.74
Taxes Other Than Income Taxes Per Barrel of Oil Equivalent
Consolidated operations
Alaska
$
6.15
4.08
3.87
Lower 48
3.29
1.87
2.65
United States
3.87
2.62
3.05
Canada
0.67
0.62
0.78
Europe
0.73
0.65
0.48
Asia Pacific
1.99
0.81
0.76
Africa
0.07
0.91
0.19
Total international
1.06
0.72
0.60
Total consolidated operations
3.06
1.91
2.03
Equity affiliates—
Asia Pacific/Middle East
11.52
6.96
11.46
Depreciation, Depletion and Amortization Per Barrel of Oil Equivalent
Consolidated operations
Alaska
$
12.02
11.59
8.80
Lower 48
14.24
18.05
17.03
United States
13.79
15.86
14.35
Canada
11.16
13.08
10.00
Europe
17.13
16.24
12.75
Asia Pacific
17.25
15.66
16.55
Africa
2.40
2.43
2.36
Total international
14.25
15.01
12.99
Total consolidated operations
13.92
15.54
13.78
Equity affiliates—
Asia Pacific/Middle East
8.29
7.89
8.09
*Includes bitumen.
Supplementary Data
ConocoPhillips 2021 10-K
Development and Exploration Activities
The following two tables summarize our net interest in productive and dry exploratory and development wells in
the years ended December 31, 2021, 2020 and 2019. A “development well” is a well drilled within the proved area
of a reservoir to the depth of a stratigraphic horizon known to be productive. An “exploratory well” is a well drilled
to find and produce crude oil or natural gas in an unknown field or a new reservoir within a proven field.
Exploratory wells also include wells drilled in areas near or offsetting current production, or in areas where well
density or production history have not achieved statistical certainty of results. Excluded from the exploratory well
count are stratigraphic -type exploratory wells, primarily relating to oil sands delineation wells located in Canada
and CBM test wells located in Asia Pacific/Middle East.
Net Wells Completed
Productive
Dry
2021
2020
2019
2021
2020
2019
Exploratory
Consolidated operations
Alaska
-
-
7
1
3
-
Lower 48
87
3
35
-
-
6
United States
87
3
42
1
3
6
Canada
12
23
-
-
-
-
Europe
-
-
1
-
1
Asia Pacific/Middle East
*
1
*
1
Africa
-
-
-
-
-
Other areas
-
-
-
-
-
Total consolidated operations
99
26
44
1
3
8
Equity affiliates
Asia Pacific/Middle East
3
8
8
-
-
-
Total equity affiliates
3
8
8
-
-
-
Development
Consolidated operations
Alaska
1
7
12
-
-
-
Lower 48
339
127
255
-
-
-
United States
340
134
267
-
-
-
Canada
2
-
2
-
-
-
Europe
7
7
6
-
-
-
Asia Pacific/Middle East
21
16
21
-
-
-
Africa
1
2
2
-
-
-
Other areas
-
-
-
-
-
-
Total consolidated operations
371
159
298
-
-
-
Equity affiliates
Asia Pacific/Middle East
30
109
106
-
-
-
Total equity affiliates
30
109
106
-
-
-
*Our total proportionate interest was less than one.
Supplementary Data
171
ConocoPhillips 2021 10-K
The table below represents the status of our wells drilling at December 31, 2021, and includes wells in the
process of drilling or in active completion. It also represents gross and net productive wells, including producing
wells and wells capable of production at December 31, 2021.
Wells at December 31, 2021
Productive
In Progress
Oil
Gas
Gross
Net
Gross
Net
Gross
Net
Consolidated operations
Alaska
2
1
1,602
940
-
-
Lower 48
665
337
16,306
8,015
5,091
2,211
United States
667
338
17,908
8,955
5,091
2,211
Canada
18
15
186
94
149
149
Europe
11
1
494
84
59
2
Asia Pacific/Middle East
15
7
351
166
38
18
Africa
7
1
858
140
10
2
Other areas
-
-
-
-
-
-
Total consolidated operations
718
362
19,797
9,439
5,347
2,382
Equity affiliates
Asia Pacific/Middle East
130
25
-
-
4,908
1,171
Total equity affiliates
130
25
-
-
4,908
1,171
Acreage at December 31, 2021
Thousands of Acres
Developed
Undeveloped
Gross
Net
Gross
Net
Consolidated operations
Alaska
663
479
1,341
1,329
Lower 48
4,096
2,538
10,514
8,233
United States
4,759
3,017
11,855
9,562
Canada
297
219
3,433
1,948
Europe
430
50
938
371
Asia Pacific/Middle East
921
421
10,451
6,930
Africa
358
58
12,545
2,049
Other areas
-
-
156
125
Total consolidated operations
6,765
3,765
39,378
20,985
Equity affiliates
Asia Pacific/Middle East
1,039
248
3,807
856
Total equity affiliates
1,039
248
3,807
856
Supplementary Data
ConocoPhillips 2021 10-K
Costs Incurred
Year Ended
Millions of Dollars
December 31
Lower
Total
Asia Pacific/
Other
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Areas
Total
2021
Consolidated operations
Unproved property acquisition
$
1
11,261
11,262
4
-
-
-
-
11,266
Proved property acquisition
-
16,101
16,101
1
-
-
-
-
16,102
1
27,362
27,363
5
-
-
-
-
27,368
Exploration
84
765
849
80
31
51
2
40
1,053
Development
949
2,461
3,410
175
398
433
24
-
4,440
$
1,034
30,588
31,622
260
429
484
26
40
32,861
Equity affiliates
Unproved property acquisition
$
-
-
-
-
-
-
-
-
-
Proved property acquisition
-
-
-
-
-
-
-
-
-
-
-
Exploration
-
-
-
-
-
5
-
-
5
Development
-
-
-
-
-
21
-
-
21
$
-
-
-
-
-
26
-
-
26
2020
Consolidated operations
Unproved property acquisition
$
4
10
14
378
-
3
-
9
404
Proved property acquisition
-
62
62
129
-
-
-
-
191
4
72
76
507
-
3
-
9
595
Exploration
287
116
403
218
110
32
4
38
805
Development
745
1,758
2,503
102
451
427
18
-
3,501
$
1,036
1,946
2,982
827
561
462
22
47
4,901
Equity affiliates
Unproved property acquisition
$
-
-
-
-
-
-
-
-
-
Proved property acquisition
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Exploration
-
-
-
-
-
12
-
-
12
Development
-
-
-
-
-
282
-
-
282
$
-
-
-
-
-
294
-
-
294
2019
Consolidated operations
Unproved property acquisition
$
101
45
146
14
-
-
-
197
357
Proved property acquisition
1
116
117
-
-
115
-
-
232
102
161
263
14
-
115
-
197
589
Exploration
281
390
671
200
119
66
8
39
1,103
Development
1,125
3,028
4,153
215
625
486
22
-
5,501
$
1,508
3,579
5,087
429
744
667
30
236
7,193
Equity affiliates
Unproved property acquisition
$
-
-
-
-
-
62
-
-
62
Proved property acquisition
-
-
-
-
-
-
-
-
-
-
-
-
-
-
62
-
-
62
Exploration
-
-
-
-
-
23
-
-
23
Development
-
-
-
-
-
171
-
-
171
$
-
-
-
-
-
256
-
-
256
Supplementary Data
173
ConocoPhillips 2021 10-K
Capitalized Costs
At December 31
Millions of Dollars
Lower
Total
Asia Pacific/
Other
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Areas
Total
2021
Consolidated operations
Proved property
$
22,750
58,561
81,311
7,380
14,514
12,226
966
-
116,397
Unproved property
1,402
7,704
9,106
1,517
155
92
114
9
10,993
24,152
66,265
90,417
8,897
14,669
12,318
1,080
9
127,390
Accumulated depreciation,
depletion and amortization
11,945
29,975
41,920
2,749
10,166
9,240
422
9
64,506
$
12,207
36,290
48,497
6,148
4,503
3,078
658
-
62,884
Equity affiliates
Proved property
$
-
-
-
-
-
10,357
-
-
10,357
Unproved property
-
-
-
-
-
2,162
-
-
2,162
-
-
-
-
-
12,519
-
-
12,519
Accumulated depreciation,
depletion and amortization
-
-
-
-
-
8,539
-
-
8,539
$
-
-
-
-
-
3,980
-
-
3,980
2020
Consolidated operations
Proved property
$
21,819
37,452
59,271
7,255
14,931
11,913
942
94,312
Unproved property
1,398
631
2,029
1,529
151
89
114
229
4,141
23,217
38,083
61,300
8,784
15,082
12,002
1,056
229
98,453
Accumulated depreciation,
depletion and amortization
11,098
27,948
39,046
2,431
10,015
8,567
387
9
60,455
$
12,119
10,135
22,254
6,353
5,067
3,435
669
220
37,998
Equity affiliates
Proved property
$
-
-
-
-
-
10,310
-
-
10,310
Unproved property
-
-
-
-
-
2,187
-
-
2,187
-
-
-
-
-
12,497
-
-
12,497
Accumulated depreciation,
depletion and amortization
-
-
-
-
-
6,959
-
-
6,959
$
-
-
-
-
-
5,538
-
-
5,538
Supplementary Data
ConocoPhillips 2021 10-K
Standardized Measure of Discounted Future Net Cash Flows Relatin g to Proved Oil and Gas Reserve Quantities
In accordance with SEC and FASB requirements, amounts were computed using 12-month average prices (adjusted only for existing
contractual terms) and end-of-year costs, appropriate statutory tax rates and a prescri bed 10 percent discount factor. Twelve-
month average prices are calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within
the 12-month period prior to the end of the reporting period. For all years, continuation of year -end economic conditions was
assumed. The calculations were based on estimates of proved reserves, which are revised over time as new data becomes available.
Probable or possible reserves, which may become proved in the future, were not considered. The calculations also require
assumptions as to the timing of future production of proved reserves and the timing and amount of future development costs,
including dismantlement, and future production costs, including taxes other than income taxes.
While due care was taken in its preparation, we do not represent that this data is the fair value of our oil and gas properties, or a fair
estimate of the present value of cash flows to be obtained from their development and production.
Discounted Future Net Cash Flows
Millions of Dollars
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Total
2021
Consolidated operations
Future cash inflows
$
65,910
125,197
191,107
10,847
21,670
11,583
15,778
250,985
Less:
Future production costs
34,444
43,034
77,478
4,960
6,090
4,987
801
94,316
Future development costs
8,033
13,386
21,419
923
3,960
1,314
413
28,029
Future income tax provisions
5,310
13,167
18,477
117
8,345
1,542
13,506
41,987
Future net cash flows
18,123
55,610
73,733
4,847
3,275
3,740
1,058
86,653
10 percent annual discount
7,963
22,290
30,253
1,639
696
930
440
33,958
Discounted future net cash flows
$
10,160
33,320
43,480
3,208
2,579
2,810
618
52,695
Equity affiliates
Future cash inflows
$
-
-
-
-
-
27,851
-
27,851
Less:
Future production costs
-
-
-
-
-
15,491
-
15,491
Future development costs
-
-
-
-
-
1,649
-
1,649
Future income tax provisions
-
-
-
-
-
3,071
-
3,071
Future net cash flows
-
-
-
-
-
7,640
-
7,640
10 percent annual discount
-
-
-
-
-
2,640
-
2,640
Discounted future net cash flows
$
-
-
-
-
-
5,000
-
5,000
Total company
Discounted future net cash flows
$
10,160
33,320
43,480
3,208
2,579
7,810
618
57,695
Supplementary Data
175
ConocoPhillips 2021 10-K
Millions of Dollars
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada*
Europe
Middle East
Africa
Total
2020
Consolidated operations
Future cash inflows
$
30,145
31,533
61,678
4,198
9,857
7,940
9,997
93,670
Less:
Future production costs
22,905
17,582
40,487
4,316
4,770
3,838
1,277
54,688
Future development costs
7,932
12,799
20,731
750
3,688
1,289
461
26,919
Future income tax provisions
-
376
376
-
267
1,075
7,571
9,289
Future net cash flows
(692)
776
84
(868)
1,132
1,738
688
2,774
10 percent annual discount
(1,501)
(820)
(2,321)
(396)
117
406
294
(1,900)
Discounted future net cash flows
$
809
1,596
2,405
(472)
1,015
1,332
394
4,674
Equity affiliates
Future cash inflows
$
-
-
-
-
-
17,284
-
17,284
Less:
Future production costs
-
-
-
-
-
10,239
-
10,239
Future development costs
-
-
-
-
-
1,186
-
1,186
Future income tax provisions
-
-
-
-
-
1,728
-
1,728
Future net cash flows
-
-
-
-
-
4,131
-
4,131
10 percent annual discount
-
-
-
-
-
1,269
-
1,269
Discounted future net cash flows
$
-
-
-
-
-
2,862
-
2,862
Total company
Discounted future net cash flows
$
809
1,596
2,405
(472)
1,015
4,194
394
7,536
*Undiscounted future net cash flows related to the proved oil and gas reserves disclosed for Canada for the year ending December 31, 2020, are negative due to the
inclusion of asset retirement costs and certain indirect costs in the calculation of the standardized measure of discounted future net cash flows. These costs are not
required to be included in the economic limit test for proved developed reserves as defined in Regulation S-X Rule 4-10. Future net cash flows for Canada were also
impacted by lower 12-month average pricing for bitumen and crude oil in 2020. Commodity prices have since improved in the current environment.
Supplementary Data
ConocoPhillips 2021 10-K
Millions of Dollars
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Total
2019
Consolidated operations
Future cash inflows
$
70,341
53,400
123,741
8,244
16,919
13,084
15,582
177,570
Less:
Future production costs
40,464
22,194
62,658
4,525
5,843
5,162
1,314
79,502
Future development costs
9,721
14,083
23,804
577
4,143
2,179
484
31,187
Future income tax provisions
3,904
2,793
6,697
-
4,201
1,931
12,747
25,576
Future net cash flows
16,252
14,330
30,582
3,142
2,732
3,812
1,037
41,305
10 percent annual discount
6,571
4,311
10,882
1,198
558
835
460
13,933
Discounted future net cash flows
$
9,681
10,019
19,700
1,944
2,174
2,977
577
27,372
Equity affiliates
Future cash inflows
$
-
-
-
-
-
31,671
-
31,671
Less:
Future production costs
-
-
-
-
-
16,157
-
16,157
Future development costs
-
-
-
-
-
1,218
-
1,218
Future income tax provisions
-
-
-
-
-
3,086
-
3,086
Future net cash flows
-
-
-
-
-
11,210
-
11,210
10 percent annual discount
-
-
-
-
-
4,040
-
4,040
Discounted future net cash flows
$
-
-
-
-
-
7,170
-
7,170
Total company
Discounted future net cash flows
$
9,681
10,019
19,700
1,944
2,174
10,147
577
34,542
Supplementary Data
177
ConocoPhillips 2021 10-K
Sources of Change in Discounted Future Net Cash Flows
Millions of Dollars
Consolidated Operations
Equity Affiliates
Total Company
2021
2020
2019
2021
2020
2019
2021
2020
2019
Discounted future net cash flows
at the beginning of the year
$
4,674
27,372
35,434
2,862
7,170
7,929
7,536
34,542
43,363
Changes during the year
Revenues less production
costs for the year
(20,000)
(5,198)
(13,424)
(1,389)
(897)
(1,673)
(21,389)
(6,095)
(15,097)
Net change in prices and
production costs
50,956
(34,307)
(13,538)
3,822
(4,769)
(422)
54,778
(39,076)
(13,960)
Extensions, discoveries and
improved recovery, less
estimated future costs
10,420
887
2,985
(44)
22
260
10,376
909
3,245
Development costs for the year
4,396
3,593
5,333
91
192
239
4,487
3,785
5,572
Changes in estimated future
development costs
(33)
754
559
(104)
(205)
(21)
(137)
549
538
Purchases of reserves in place,
less estimated future costs
17,833
1
10
-
(3)
-
17,833
(2)
10
Sales of reserves in place,
less estimated future costs
(468)
(302)
(1,997)
-
-
-
(468)
(302)
(1,997)
Revisions of previous quantity
estimates
2,985
(2,299)
2,099
178
(42)
69
3,163
(2,341)
2,168
Accretion of discount
964
3,984
5,144
344
804
869
1,308
4,788
6,013
Net change in income taxes
(19,032)
10,189
4,767
(760)
590
(80)
(19,792)
10,779
4,687
Total changes
48,021
(22,698)
(8,062)
2,138
(4,308)
(759)
50,159
(27,006)
(8,821)
Discounted future net cash flows
at year end
$
52,695
4,674
27,372
5,000
2,862
7,170
57,695
7,536
34,542
●
The net change in prices and production costs is the beginning-of-year reserve-production forecast multiplied by the net annual
change in the per-unit sales price and production cost, discounted at 10 percent.
●
Purchases and sales of reserves in place, along with extensions, discoveries and improved recovery, are calculated using
production forecasts of the applicable reserve quantities for the year multiplied by the 12-month average sales prices, less
future estimated costs, discounted at 10 percent.
●
Revisions of previous quantity estimates are calculated using production forecast changes for the year, including changes in the
timing of production, multiplied by the 12-month average sales prices, less future estimated costs, discounted at 10 percent.
●
The accretion of discount is 10 percent of the prior year’s discounted future cash inflows, less future production and
development costs.
●
The net change in income taxes is the annual change in the discounted future income tax provisions.
ConocoPhillips 2021 10-K
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
Report of Independent Registered Public Accounting Firm
This report is included in Item 8 on page 76 and is incorporated herein by reference.
Item 9B. Other Information
None.
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
179
ConocoPhillips 2021 10-K
Part III
Item 10. Directors, Executive Officers and Corporate Governance
Information regarding our executive officers appears in Part I of this report on page 30.
Code of Business Ethics and Conduct for Directors and Employees
We have a Code of Business Ethics and Conduct for Directors and Employees (Code of Ethics), including our
principal executive officer, principal financial officer, principal accounting officer and persons performing similar
functions. We have posted a copy of our Code of Ethics on the “Corporate Governance” section of our internet
website at
www.conocophillips.com
.
Code of Ethics must be approved, in advance, by our full Board of Directors. Any amendments to, or waivers from,
the Code of Ethics that apply to our executive officers and directors will be posted on the “Corporate Governance”
section of our internet website.
All other information required by Item 10 of Part III will be included in our Proxy Statement relating to our 2022
Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2022, and is
incorporated herein by reference.*
Item 11. Executive Compensation
Information required by Item 11 of Part III will be included in our Proxy Statement relating to our 2022 Annual
Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2022, and is incorporated
herein by reference.*
Item 12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
Information required by Item 12 of Part III will be included in our Proxy Statement relating to our 2022 Annual
Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2022, and is incorporated
herein by reference.*
Item 13. Certain Relationships and Related Transactions, and Director
Independence
Information required by Item 13 of Part III will be included in our Proxy Statement relating to our 2022 Annual
Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2022, and is incorporated
herein by reference.*
Item 14. Principal Accounting Fees and Services
Information required by Item 14 of Part III will be included in our Proxy Statement relating to our 2022 Annual
Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2022, and is incorporated
herein by reference.*
_________________________
*Except for information or data specifically incorporated herein by reference under Items 10 through 14, other information and data appearing
in our 2022 Proxy
Statement are not deemed to be a part of this Annual Report on Form 10-K or deemed to be filed with the Commission as a
part of this report.
ConocoPhillips 2021 10-K
Part IV
Item 15. Exhibits, Financial Statement Schedules
(a) 1. Financial Statements and Supplementary Data
The financial statements and supplementary information listed in the Index to Financial Statements,
which appears on page
, are filed as part of this annual report.
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.
The exhibits listed in the Index to Exhibits, which appears on pages
this annual report.
181
ConocoPhillips 2021 10-K
ConocoPhillips
Index to Exhibits
Incorporated by Reference
Exhibit
No.
Description
Exhibit
Form
File No.
2.1
2.1
8-K
001-32395
2.2†‡
2.1
10-Q
001-32395
2.3†‡
2.2
8-K
001-32395
2.4
2.1
8-K
001-32395
3.1
3.1
10-Q
001-32395
3.2
3.2
8-K
000-49987
3.3
3.1
8-K
001-32395
3.4*
ConocoPhillips and its subsidiaries are parties to several debt instruments
under which the total amount of securities authorized does not exceed
10 percent of the total assets of ConocoPhillips and its subsidiaries on a
consolidated basis. Pursuant to paragraph 4(iii)(A) of Item 601(b) of
Regulation S-K, ConocoPhillips agrees to furnish a copy of such instruments to
the SEC upon request.
4.1
4.1
10-K
001-32395
10.1
10.11
10-K
004-49987
10.2
10.12
10-K
004-49987
10.5
10.14
10-Q
001-32395
10.7
10.19
10-K
004-49987
10.10.1
10.10.1
10-K
001-32395
10.10.2
10.1
10-Q
001-32395
ConocoPhillips 2021 10-K
10.11.1
10.11.1
10-K
001-32395
10.11.2
10.11.2
10-K
001-32395
10.12
10.26
10-K
000-49987
10.15
10.17
10-K
001-32395
10.16.1
10.11
10-K
001-14521
10.16.2
10.39.1
10-K
000-49987
10.16.3
10.17.3
10-K
001-32395
10.16.4
10.17.4
10-K
001-32395
10.16.5
10.17.5
10-K
001-32395
10.16.6
10.17.6
10-K
001-32395
10.16.7
10.17.7
10-K
001-32395
10.16.8
10.17.8
10-K
001-32395
10.17.1
10.40
10-K
000-49987
10.17.2
10
10-Q
001-32395
10.19.1
10.19.1
10-K
001-32395
10.19.2
10.19.2
10-K
001-32395
10.20
10.21
10-K
001-32395
10.20.1*
10.22.1
Schedule
14A
Proxy
000-49987
10.22.2
10.26
10-K
001-32395
10.22.3
10.27
10-K
001-32395
10.23
10.30
10-K
001-32395
183
ConocoPhillips 2021 10-K
10.24
Schedule
14A
Proxy
001-32395
10.25.1
Schedule
14A
Proxy
001-32395
10.25.2
10
10-Q
001-32395
10.25.4
10.26.6
10-K
001-32395
10.25.7
10.26.9
10-K
001-32395
10.25.8
10.2
10-Q
001-32395
10.25.9
10.1
10-Q
001-32395
10.25.10
10.26.12
10-K
001-32395
10.25.12
10.3
10-Q
001-32395
10.25.14
10.5
10-Q
001-32395
10.25.17
10.11
10-Q
001-32395
10.25.18
10.26.24
10-K
001-32395
10.26.1
10.1
8-K
001-32395
10.26.4
10.3
10-Q
001-32395
10.26.7
10.1
10-Q
001-32395
ConocoPhillips 2021 10-K
10.26.11
10.27.12
10-K
001-32395
10.26.13
10.27.14
10-K
001-32395
10.26.14
10.27.15
10-K
001-32395
10.26.15
10.27.16
10-K
001-32395
10.27
10.27
10-K
001-32395
10.29
10.9
10-Q
001-32395
10.30.1
10.1
10-Q
001-32395
10.30.2
10.2
10-Q
001-32395
10.31
10.1
8-K
001-32395
10.32
10.2
8-K
001-32395
10.33
10.3
8-K
001-32395
10.34
10.4
8-K
001-32395
10.36
10.3
10-Q
001-32395
10.37
10.1
8-K
001-32395
10.38
10.39
10-K
001-32395
10.40
10.1
10-Q
001-32395
10.41
10.1
10-Q
001-32395
185
ConocoPhillips 2021 10-K
10.42
10.1
10-Q
001-32395
10.43
10.3
10-Q
001-32395
10.44
10.1
10-Q
001-32395
10.45
10.2
10-Q
001-32395
10.46
10.1
10-Q
001-32395
10.47*
21*
22*
23.1*
23.2*
31.1*
31.2*
32*
99*
101.INS*
Inline XBRL Instance Document.
101.SCH*
Inline XBRL Schema Document.
101.CAL*
Inline XBRL Calculation Linkbase Document.
101.DEF*
Inline XBRL Definition Linkbase Document.
101.LAB*
Inline XBRL Labels Linkbase Document.
101.PRE*
Inline XBRL Presentation Linkbase Document.
104*
Cover Page Interactive Data File (formatted as Inline XBRL and contained in
Exhibit 101).
*
Filed herewith.
†
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
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