2020
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form
] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
OR
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The registrant had
Documents incorporated by reference:
Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 11, 2021 (Part III)
TABLE OF CONTENTS
Page
Commonly Used Abbreviations……………………………………………………………………….
1
Item
PART I
1 and 2.
Business and Properties ......................................................................................................
2
Corporate Structure ........................................................................................................
2
Segment and Geographic Information ...........................................................................
2
Alaska .......................................................................................................................
4
Lower 48 ...................................................................................................................
7
Canada ......................................................................................................................
9
Europe, Middle East and North Africa .....................................................................
10
Asia Pacific ...............................................................................................................
12
Other International ....................................................................................................
15
Competition ...................................................................................................................
18
Human Capital Management .........................................................................................
18
General ...........................................................................................................................
22
1A.
Risk Factors ........................................................................................................................
23
1B.
Unresolved Staff Comments ...............................................................................................
32
3.
Legal Proceedings ...............................................................................................................
32
4.
Mine Safety Disclosures .....................................................................................................
33
Information About our Executive Officers .........................................................................
33
PART II
5.
Market for Registrant’s Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities ............................................................................
35
7.
Management’s Discussion and Analysis of Financial Condition and
Results of Operations .....................................................................................................
37
7A.
Quantitative and Qualitative Disclosures About Market Risk ............................................
77
8.
Financial Statements and Supplementary Data ...................................................................
80
9.
Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure .......................................................................................................
179
9A.
Controls and Procedures .....................................................................................................
179
9B.
Other Information ...............................................................................................................
179
PART III
10.
Directors, Executive Officers and Corporate Governance ..................................................
180
11.
Executive Compensation ....................................................................................................
180
12.
Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters ..........................................................................................
180
13.
Certain Relationships and Related Transactions, and Director Independence....................
180
14.
Principal Accounting Fees and Services .............................................................................
180
PART IV
15.
Exhibits, Financial Statement Schedules ............................................................................
181
Signatures ...........................................................................................................................
191
1
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
SAB
staff accounting bulletin
MBOED
thousands of barrels of oil
VIE
variable interest entity
equivalent per day
MMBOED
millions of barrels of oil
equivalent per day
Miscellaneous
MMBTU
million British thermal units
EPA
Environmental Protection Agency
MMCFD
million cubic feet per day
ESG
Environmental, Social and
Corporate Governance
EU
European Union
Industry
FERC
Federal Energy Regulatory
CBM
coalbed methane
Commission
E&P
exploration and production
GHG
greenhouse gas
FEED
front-end engineering and design
HSE
health, safety and environment
FPS
floating production system
ICC
International Chamber of
FPSO
floating production, storage and
Commerce
offloading
ICSID
World Bank’s International
G&G
geological and geophysical
Centre for Settlement of
JOA
joint operating agreement
Investment Disputes
LNG
liquefied natural gas
IRS
Internal Revenue Service
NGLs
natural gas liquids
OTC
over-the-counter
OPEC
Organization of Petroleum
NYSE
New York Stock Exchange
Exporting Countries
SEC
U.S. Securities and Exchange
PSC
production sharing contract
Commission
PUDs
proved undeveloped reserves
TSR
total shareholder return
SAGD
steam-assisted gravity drainage
U.K.
United Kingdom
WCS
Western Canada Select
U.S.
United States of America
WTI
West Texas Intermediate
2
PART I
Unless otherwise indicated, “the company,” “we,” “our,” “us” and “ConocoPhillips” are used in this report to
refer to the businesses of ConocoPhillips and its consolidated subsidiaries. Items 1 and 2—Business and
Properties, contain forward-looking statements including, without limitation, statements relating to our plans,
strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the
Private Securities Litigation Reform Act of 1995. The words “anticipate,” “estimate,” “believe,” “budget,”
“continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,”
“expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar
expressions identify forward-looking statements. The company does not undertake to update, revise or correct
any forward-looking information unless required to do so under the federal securities laws. Readers are
cautioned that such forward-looking statements should be read in conjunction with the company’s disclosures
under the headings “Risk Factors” beginning on page 23 and “CAUTIONARY STATEMENT FOR THE
PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION
REFORM ACT OF 1995,” beginning on page
Items 1 and 2. BUSINESS AND PROPERTIES
CORPORATE STRUCTURE
ConocoPhillips is an independent E&P company headquartered in Houston, Texas with operations and
activities in 15 countries. Our diverse, low cost of supply portfolio includes resource-rich unconventional
plays in North America; conventional assets in North America, Europe, and Asia; LNG developments; oil
sands assets in Canada; and an inventory of global conventional and unconventional exploration prospects. On
December 31, 2020, we employed approximately 9,700 people worldwide and had total assets of $63 billion.
ConocoPhillips was incorporated in the state of Delaware on November 16, 2001, in connection with, and in
anticipation of, the merger between Conoco Inc. and Phillips Petroleum Company. The merger between
Conoco and Phillips was consummated on August 30, 2002.
On January 15, 2021, we completed the acquisition of Concho Resources Inc. (Concho), an independent oil
and gas exploration and production company with operations in New Mexico and West Texas focused on the
Permian Basin. For additional information related to this transaction, see Note 25—Acquisition of Concho
Resources Inc., in the Notes to Consolidated Financial Statements.
SEGMENT AND GEOGRAPHIC INFORMATION
We manage our operations through six operating segments, defined by geographic region: Alaska; Lower 48;
Canada; Europe, Middle East and North Africa; Asia Pacific; and Other International. Effective with the third
quarter of 2020, we restructured our segments to align with changes to our internal organization. The Middle
East business was realigned from the Asia Pacific and Middle East segment to the Europe and North
Africa segment. The segments have been renamed the Asia Pacific segment and the Europe, Middle East and
North Africa segment. We have revised segment information disclosures and segment performance metrics
presented within our results of operations for the current and prior years. For operating segment and
geographic information, see Note 24—Segment Disclosures and Related Information, in the Notes to
Consolidated Financial Statements.
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on a worldwide
basis. At December 31, 2020, our operations were producing in the U.S., Norway, Canada, Australia,
Indonesia, Malaysia, Libya, China and Qatar.
3
The information listed below appears in the “Oil and Gas Operations” disclosures following the Notes to
Consolidated Financial Statements and is incorporated herein by reference:
●
Proved worldwide crude oil, NGLs, natural gas and bitumen reserves.
●
Net production of crude oil, NGLs, natural gas and bitumen.
●
Average sales prices of crude oil, NGLs, natural gas and bitumen.
●
Average production costs per BOE.
●
Net wells completed, wells in progress and productive wells.
●
Developed and undeveloped acreage.
The following table is a summary of the proved reserves information included in the “Oil and Gas Operations”
disclosures following the Notes to Consolidated Financial Statements. Approximately 80 percent of our
proved reserves are in countries that belong to the Organization for Economic Cooperation and Development.
Natural gas reserves are converted to BOE based on a 6:1 ratio: six MCF of natural gas converts to one BOE.
See Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion
of factors that will enhance the understanding of the following summary reserves table.
Millions of Barrels of Oil Equivalent
Net Proved Reserves at December 31
2020
2019
2018
Crude oil
Consolidated operations
2,051
2,562
2,533
Equity affiliates
68
73
78
Total Crude Oil
2,119
2,635
2,611
Natural gas liquids
Consolidated operations
340
361
349
Equity affiliates
36
39
42
Total Natural Gas Liquids
376
400
391
Natural gas
Consolidated operations
1,011
1,209
1,265
Equity affiliates
621
736
760
Total Natural Gas
1,632
1,945
2,025
Bitumen
Consolidated operations
332
282
236
Total Bitumen
332
282
236
Total consolidated operations
3,734
4,414
4,383
Total equity affiliates
725
848
880
Total company
4,459
5,262
5,263
4
Total production, including Libya, of 1,127 MBOED decreased 221 MBOED or 16 percent in 2020 compared
with 2019, primarily due to:
●
Normal field decline.
●
The divestiture of our U.K. assets in the third quarter of 2019 and our Australia-West assets in the
second quarter of 2020.
●
Production curtailments of approximately 80 MBOED, primarily from North American operated
assets and Malaysia.
●
Lower production in Libya due to the forced shutdown of the Es Sider export terminal and other
eastern export terminals after a period of civil unrest.
The decrease in production during 2020 was partly offset by:
●
New wells online in the Lower 48, Canada, Norway, Alaska and China.
Production excluding Libya for 2020 was 1,118 MBOED. Adjusting for estimated curtailments of
approximately 80 MBOED; closed acquisitions and dispositions; and excluding Libya, production for 2020
would have been 1,176 MBOED, a decrease of 15 MBOED compared with 2019 production. This decrease
was primarily due to normal field decline, partly offset by new wells online in the Lower 48, Canada, Norway,
Alaska and China. Production from Libya averaged 9 MBOED as it was in force majeure during a significant
portion of the year.
Our worldwide annual average realized price decreased 34 percent from $48.78 per BOE in 2019 to $32.15 per
BOE in 2020 primarily due to lower realized crude oil, natural gas and bitumen prices. Our worldwide annual
average crude oil price decreased 35 percent, from $60.99 per barrel in 2019 to $39.54 per barrel in 2020. Our
worldwide annual average natural gas price decreased 32 percent, from $5.03 per MCF in 2019 to $3.41 per
MCF in 2020. Average annual bitumen prices decreased 75 percent, from $31.72 per barrel in 2019 to $8.02
per barrel in 2020.
ALASKA
The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas and NGLs.
We are the largest crude oil producer in Alaska and have major ownership interests in two of North America’s
largest oil fields located on Alaska’s North Slope: Prudhoe Bay and Kuparuk. We also have a 100 percent
interest in the Alpine Field, located on the Western North Slope. Additionally, we are one of Alaska’s largest
owners of state, federal and fee exploration leases, with approximately 1.3 million net undeveloped acres at
year-end 2020. Alaska operations contributed 28 percent of our consolidated liquids production and 1 percent
of our consolidated natural gas production.
2020
Crude Oil
NGL
Natural Gas
Total
Interest
Operator
MBD
MBD
MMCFD
MBOED
Average Daily Net Production
Greater Prudhoe Area
36.1
%
Hilcorp
68
16
4
84
Greater Kuparuk Area
89.2-94.7
ConocoPhillips
74
-
2
74
Western North Slope
100.0
ConocoPhillips
39
-
4
40
Total Alaska
181
16
10
198
Greater Prudhoe Area
The Greater Prudhoe Area includes the Prudhoe Bay Field and five satellite fields, as well as the Greater Point
McIntyre Area fields. Prudhoe Bay, the largest oil field on Alaska’s North Slope, is the site of a large
waterflood and enhanced oil recovery operation, as well as a gas plant which processes natural gas to recover
5
NGLs before reinjection into the reservoir. Prudhoe Bay’s satellites are Aurora, Borealis, Polaris, Midnight
Sun and Orion, while the Point McIntyre, Niakuk, Raven, Lisburne and North Prudhoe Bay State fields are
part of the Greater Point McIntyre Area.
In 2020, development activity included both rotary and coiled-tubing drilling through April, resulting in ten
wells drilled and brought online. In response to the oil price collapse, the second half of 2020 saw a reduction
in rig activity. Average net production increased from 81 MBOED in 2019 to 84 MBOED in 2020.
Greater Kuparuk Area
We operate the Greater Kuparuk Area, which consists of the Kuparuk Field and four satellite fields: Tarn,
Tabasco, Meltwater and West Sak. Kuparuk is located 40 miles west of the Prudhoe Bay Field. Field
installations include three central production facilities which separate oil, natural gas and water, as well as a
seawater treatment plant. Development drilling at Kuparuk consists of rotary-drilled wells and horizontal
multi-laterals from existing well bores utilizing coiled-tubing drilling.
We operated both a rotary and a coiled-tubing drilling rig in the first half of 2020, resulting in seven operated
wells drilled and brought online in 2020. In response to the oil price collapse, the second half of 2020 saw a
reduction in rig activity. Average net production decreased from 86 MBOED in 2019 to 74 MBOED in 2020.
Western North Slope
On the Western North Slope, we operate the Colville River Unit, which includes the Alpine Field and three
satellite fields: Nanuq, Fiord and Qannik. The Alpine Field is located 34 miles west of the Kuparuk Field. In
2020, an extended-reach drilling rig was delivered to the Alpine CD2 drillsite. This rig is North America’s
largest mobile land rig and is expected to commence drilling operations in 2021.
The Greater Mooses Tooth Unit is the first unit established entirely within the NPR-A. In 2017, we began
construction in the unit with two drill sites; Greater Mooses Tooth #1 (GMT-1) and Greater Mooses Tooth #2
(GMT-2). GMT-1 achieved first oil in 2018 and completed drilling in 2019. In 2020, the second of three
construction seasons for GMT-2 was completed and drilling operations are expected to commence in 2021
with first oil later in the year.
We operated both a rotary and a coiled-tubing drilling rig in the Western North Slope during 2020, resulting in
five operated wells drilled and brought online. In response to the oil price collapse, the second half of 2020
saw a reduction in rig activity. Average net production decreased from 51 MBOED in 2019 to 40 MBOED in
2020.
Production Curtailments
In response to the oil price collapse that began in early 2020, we curtailed operated production—in the Greater
Kuparuk Area and Western North Slope—by 8 MBOED in 2020. For more information related to the 2020
industry downturn and our response, please see Item 7. Management’s Discussion and Analysis of Financial
Condition and Results of Operations.
Alaska North Slope Gas
In 2016, we, along with affiliates of Exxon Mobil Corporation, BP p.l.c. and Alaska Gasline Development
Corporation (AGDC), a state-owned corporation, completed preliminary FEED technical work for a potential
LNG project which would liquefy and export natural gas from Alaska’s North Slope and deliver it to market.
In 2016, we, along with the affiliates of ExxonMobil and BP, indicated our intention not to progress into the
next phase of the project due to changes in the economic environment, however, AGDC decided to continue on
its own, focusing primarily on permitting efforts. Currently, AGDC is in the process of seeking new sponsors
for the project. Given current market conditions, we no longer believe the project will advance and since there
is no current market, we recorded a before-tax impairment of $841 million for the entire associated carrying
value of capitalized undeveloped leasehold costs and an equity method investment related to our Alaska North
Slope Gas asset. We remain willing to sell our Alaska North Slope Gas to interested parties on a competitive
basis if a market materializes in the future. For additional information related to this impairment, See Note
7—Suspended Wells and Exploration Expenses, in the Notes to Consolidated Financial Statements.
6
Exploration
Appraisal of the Willow Discovery in the Bear Tooth Unit in the National Petroleum Reserve-Alaska (NPR-A)
continued with the drilling of two of four planned appraisal wells before the early cancellation of the 2020
program as part of our COVID-19 response. The reduced 2020 appraisal program consisted of drilling a
horizontal well in the eastern portion of the field, informing the reservoir’s connectivity, and a vertical well in
the field’s southern extent, reducing the original oil in place uncertainty. The initial development plan for the
Willow Discovery, approved in the fourth quarter, does not include the Cassin Discovery from 2013; therefore,
we recognized dry hole expense for two previously suspended Cassin wells in 2020.
In 2020, exploration of the Harpoon Complex—Harpoon, Lower Harpoon and West Harpoon—commenced.
One exploration well of a planned three-well program was drilled before the early cancellation of our 2020
winter drilling season in response to COVID-19. The well was expensed as a dry hole after evaluations
confirmed the well intersected sub-commercial volumes of hydrocarbons in the upper Harpoon interval which
will not be developed. Future exploration plans include returning to the Harpoon Complex to explore the
remaining potential.
In late 2018, we commenced appraisal of the Putu Discovery with a long-reach well from existing Alpine CD4
infrastructure. In 2019 and 2020 the long reach CD4 appraisal and supporting injector well finished drilling
and testing. Production and injectivity tests confirmed development and waterflood feasibility of the reservoir.
The project transitioned from appraisal to development in early 2020. Development planning is ongoing.
A 3-D seismic survey was completed in 2020 over a 234-mile area on state and federal lands. We are currently
evaluating this seismic data for future exploration opportunities.
Transportation
We transport the petroleum liquids produced on the North Slope to Valdez, Alaska through an 800-mile
pipeline that is part of Trans-Alaska Pipeline System (TAPS). We have a 29.5 percent ownership interest in
TAPS, and we also have ownership interests in and operate the Alpine, Kuparuk and Oliktok pipelines on the
North Slope.
Our wholly owned subsidiary, Polar Tankers, Inc., manages the marine transportation of our North Slope
production, using five company-owned, double-hulled tankers, and charters third-party vessels as necessary.
The tankers deliver oil from Valdez, Alaska, primarily to refineries on the west coast of the U.S.
7
LOWER 48
On January 15, 2021, we completed the acquisition of Concho. This transaction significantly increases our
Permian position by adding complementary acreage across the Delaware and Midland basins. The production
and acreage figures and the property descriptions below do not reflect this recently closed acquisition. For
additional information related to this acquisition, see Note 25—Acquisition of Concho Resources Inc., in the
Notes to Consolidated Financial Statements.
The Lower 48 segment consists of operations located in the contiguous U.S. and the Gulf of Mexico.
Organized into the Gulf Coast and Great Plains business units, at year-end 2020 we held 10.1 million net
onshore and offshore acres, with a portfolio of low cost of supply, shorter cycle time, resource-rich
unconventional plays, and conventional production from legacy assets. Based on 2020 production volumes,
the Lower 48 is the company’s largest segment and contributed 40 percent of our consolidated liquids
production and 44 percent of our consolidated natural gas production.
2020
Crude Oil
NGL
Natural Gas
Total
Interest
Operator
MBD
MBD
MMCFD
MBOED
Average Daily Net Production
Eagle Ford
Various
%
Various
103
46
228
186
Gulf of Mexico
Various
Various
7
1
6
9
Gulf Coast—Other
Various
Various
3
-
7
4
113
47
241
199
Bakken
Various
Various
53
10
92
78
Permian Unconventional
Various
Various
33
12
113
64
Permian Conventional
Various
Various
12
2
42
21
Anadarko Basin
Various
Various
1
3
50
13
Wyoming/Uinta
Various
Various
-
-
44
8
Niobrara*
Various
Various
1
-
3
2
100
27
344
186
Total Lower 48
213
74
585
385
*Disposed in March 2020. See Note 4
—
Acquisitions and Dispositions in the Notes to Consolidated Financial Statements for additional
information.
Onshore
At December 31, 2020, we held 10.1 million net acres of onshore conventional and unconventional acreage in
the Lower 48, the majority of which is either held by production or owned by the company. Our
unconventional holdings total approximately 1.3 million net acres in the following areas:
●
610,000 net acres in the Bakken, located in North Dakota and eastern Montana.
●
200,000 net acres in the Eagle Ford, located in South Texas.
●
170,000 net acres in the Permian, located in West Texas and southeastern New Mexico.
●
300,000 net acres in other areas with unconventional potential.
8
In response to the oil price collapse that began in early 2020, we curtailed production in the Lower 48 by
approximately 55 MBOED in 2020. For more information related to the 2020 industry downturn and our
response, please see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of
Operations. These production curtailments contributed to lower production in 2020 compared with 2019 from
our three focus areas:
●
Eagle Ford—We operated five rigs on average in the Eagle Ford during 2020, resulting in 154
operated wells drilled and 71 operated wells brought online. Production decreased 14 percent in 2020
compared with 2019, averaging 186 MBOED and 216 MBOED, respectively.
●
Bakken—We operated an average of two rigs during the year in the Bakken and participated in
additional development activities operated by co-venturers. We continued our pad drilling with 57
operated wells drilled during the year and 29 operated wells brought online. Production decreased 20
percent in 2020 compared with 2019, averaging 78 MBOED and 97 MBOED, respectively.
●
Permian Basin—The Permian Basin is a combination of legacy conventional and unconventional
assets. We operated one rig during the full year and another rig during parts of the year in the Permian
Basin, resulting in 16 operated wells drilled and 16 operated wells brought online. Production
decreased 1 percent in 2020 compared with 2019, averaging 85 MBOED and 86 MBOED,
respectively.
Gulf of Mexico
At year-end 2020, our portfolio of producing properties in the Gulf of Mexico totaled approximately 60,000
net acres. A majority of the production consists of three fields operated by co-venturers:
●
15.9 percent interest in the unitized Ursa Field located in the Mississippi Canyon Area.
●
15.9 percent interest in the Princess Field, a northern subsalt extension of the Ursa Field.
●
12.4 percent interest in the unitized K2 Field, comprised of seven blocks in the Green Canyon Area.
Dispositions
In the first quarter of 2020, we completed the sale of our Waddell Ranch interests in the Permian Basin and our
Niobrara interests. Production from these dispositions was immaterial to the Lower 48 segment in 2020. For
additional information on these transactions, see Note 4—Asset Acquisitions and Dispositions, in the Notes to
Consolidated Financial Statements.
Facilities
●
Lost Cabin Gas Plant—We operate and own a 60 percent interest in the Lost Cabin Gas Plant, a 246
MMCFD capacity natural gas processing facility in Lysite, Wyoming. The plant is currently operating at
less than capacity due to a fire in December 2018. Restoration efforts are ongoing and anticipated to be
completed in the first half of 2021. The expected production loss in 2021 is immaterial to the segment.
●
Helena Condensate Processing Facility—We operate and own the Helena Condensate Processing Facility,
a 110 MBD condensate processing plant located in Kenedy, Texas.
●
Sugarloaf Condensate Processing Facility—We operate and own an 87.5 percent interest in the Sugarloaf
Condensate Processing Facility, a 30 MBD condensate processing plant located near Pawnee, Texas.
●
Bordovsky Condensate Processing Facility—We operate and own the Bordovsky Condensate Processing
Facility, a 15 MBD condensate processing plant located in Kenedy, Texas. This facility is currently being
decommissioned.
9
CANADA
Our Canadian operations consist of the Surmont oil sands development in Alberta and the liquids-rich
Montney unconventional play in British Columbia. In 2020, operations in Canada contributed 9 percent of our
consolidated liquids production and 3 percent of our consolidated natural gas production.
2020
Crude Oil
NGL
Natural Gas
Bitumen
Total
Interest
Operator
MBD
MBD
MMCFD
MBD
MBOED
Average Daily Net
Production
Surmont
50.0
%
ConocoPhillips
-
-
-
55
55
Montney
100.0
ConocoPhillips
6
2
40
-
15
Total Canada
6
2
40
55
70
Surmont
Our bitumen resources in Canada are produced via an enhanced thermal oil recovery method called SAGD,
whereby steam is injected into the reservoir, effectively liquefying the heavy bitumen, which is recovered and
pumped to the surface for further processing. We hold approximately 600,000 net acres of land in the
Athabasca Region of northeastern Alberta.
The Surmont oil sands leases are located approximately 35 miles south of Fort McMurray, Alberta. Surmont
is a 50/50 joint venture with Total S.A. that offers long-lived, sustained production. We are focused on
structurally lowering costs, reducing GHG intensity and optimizing asset performance.
In response to the oil price collapse that began in early 2020, we voluntarily curtailed production at Surmont
by approximately 12 MBOED in 2020. For more information related to the 2020 industry downturn and our
response, please see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of
Operations.
Montney
In August 2020, we completed the acquisition of additional Montney acreage from Kelt Exploration. This
acquisition consisted primarily of undeveloped properties, including 140,000 net acres in the liquids-rich Inga
Fireweed asset Montney zone, which is directly adjacent to our existing Montney position. We now hold
approximately 300,000 net acres in the Montney play with a 100 percent working interest. For additional
information related to the Kelt Exploration acquisition, please see Note 4—Acquisitions and Dispositions, in
the Notes to Consolidated Financial Statements.
Following the completion of third-party offtake facilities, our newly commissioned processing facility and
production from our 2019 drilling program came online in February 2020. In 2020, development activity
consisted of drilling 14 horizontal wells and completing 18 wells. Overall, 23 wells came online in 2020. In
2021, appraisal drilling and completions activity will continue to further explore the area’s resource potential.
Exploration
Our primary exploration focus is assessing our Montney acreage. Additionally, we have exploration acreage in
the Mackenzie Delta/Beaufort Sea Region and the Arctic Islands.
10
EUROPE, MIDDLE EAST AND NORTH AFRICA
The Europe, Middle East and North Africa segment consists of operations principally located in the Norwegian
sector of the North Sea; the Norwegian Sea; Qatar; Libya; and commercial and terminalling operations in the
U.K. In 2020, operations in Europe, Middle East and North Africa contributed 13 percent of our consolidated
liquids production and 20 percent of our consolidated natural gas production.
Norway
2020
Crude Oil
NGL
Natural Gas
Total
Interest
Operator
MBD
MBD
MMCFD
MBOED
Average Daily Net Production
Greater Ekofisk Area
30.7-35.1
%
ConocoPhillips
46
2
39
55
Heidrun
24.0
Equinor
12
1
32
18
Aasta Hansteen
10.0
Equinor
-
-
82
14
Troll
1.6
Equinor
2
-
54
11
Alvheim
20.0
Aker BP
8
-
13
10
Visund
9.1
Equinor
2
1
40
10
Other
Various
Equinor
8
-
10
9
Total Norway
78
4
270
127
The Greater Ekofisk Area is located approximately 200 miles offshore Stavanger, Norway, in the North Sea,
and comprises four producing fields: Ekofisk, Eldfisk, Embla and Tor. The Tor II redevelopment achieved
first production in December 2020. Crude oil is exported to Teesside, England, and the natural gas is exported
to Emden, Germany. The Ekofisk and Eldfisk fields consist of several production platforms and facilities,
with development drilling continuing over the coming years.
The Heidrun Field is located in the Norwegian Sea. Produced crude oil is stored in a floating storage unit and
exported via shuttle tankers. Part of the natural gas is currently injected into the reservoir for optimization of
crude oil production, some gas is transported for use as feedstock in a methanol plant in Norway, in which we
own an 18 percent interest, and the remainder is transported to Europe via gas processing terminals in Norway.
Aasta Hansteen is a gas and condensate field located in the Norwegian Sea. Produced condensate is loaded
onto shuttle tankers and transported to market. Gas is transported through the Polarled gas pipeline to the
onshore Nyhamna processing plant for final processing prior to export to market.
The Troll Field lies in the northern part of the North Sea and consists of the Troll A, B and C platforms. The
natural gas from Troll A is transported to Kollsnes, Norway. Crude oil from floating platforms Troll B and
Troll C is transported to Mongstad, Norway, for storage and export.
The Alvheim Field is located in the northern part of the North Sea near the border with the U.K. sector, and
consists of a FPSO vessel and subsea installations. Produced crude oil is exported via shuttle tankers, and
natural gas is transported to the Scottish Area Gas Evacuation (SAGE) Terminal at St. Fergus, Scotland,
through the SAGE Pipeline.
Visund is an oil and gas field located in the North Sea and consists of a floating drilling, production and
processing unit, and subsea installations. Crude oil is transported by pipeline to a nearby third-party field for
storage and export via tankers. The natural gas is transported to a gas processing plant at Kollsnes, Norway,
through the Gassled transportation system.
We also have varying ownership interests in two other producing fields in the Norway sector of the North Sea.
11
Exploration
A well we participated in during 2019, Canela, was expensed as a dry hole in 2020 after post drill analysis.
In 2020, we completed the third well of a three-well operated exploration campaign in Block 25/7 in the North
Sea with the Hasselbaink Well. The Hasselbaink Well encountered insufficient hydrocarbons and was
expensed as a dry hole in 2020. In the second half of 2020 we completed a two-well operated exploration
campaign in the Norwegian Sea with the Warka and Slagugle wells. Both the Warka and Slagugle wells
encountered hydrocarbons and will be evaluated for future appraisal programs.
We were awarded three new exploration licenses; PL1045, PL1047 and PL1064; and two acreage additions,
PL917B and PL1009B. Additionally, we exchanged our interest in the PL938 exploration license for
increased interest in the PL1047 exploration license.
Transportation
We own a 35.1 percent interest in the Norpipe Oil Pipeline System, a 220-mile pipeline which carries crude oil
from Ekofisk to a crude oil stabilization and NGLs processing facility in Teesside, England.
Facilities
We operate and have a 40.25 percent ownership interest in an oil terminal at Teesside, England to support our
Norway operations.
Qatar
2020
Crude Oil
NGL
Natural
Gas
Total
Interest
Operator
MBD
MBD
MMCFD
MBOED
Average Daily Net Production
Qatargas Operating
QG3
30.0
%
Company Limited
13
8
371
83
Total Qatar
13
8
371
83
QG3 is an integrated development jointly owned by Qatar Petroleum (68.5 percent), ConocoPhillips
(30 percent) and Mitsui & Co., Ltd. (1.5 percent). QG3 consists of upstream natural gas production facilities,
which produce approximately 1.4 billion gross cubic feet per day of natural gas from Qatar’s North Field over
a 25-year life, in addition to a 7.8 million gross tonnes-per-year LNG facility. LNG is shipped in leased LNG
carriers destined for sale globally.
QG3 executed the development of the onshore and offshore assets as a single integrated development with
Qatargas 4 (QG4), a joint venture between Qatar Petroleum and Royal Dutch Shell plc. This included the joint
development of offshore facilities situated in a common offshore block in the North Field, as well as the
construction of two identical LNG process trains and associated gas treating facilities for both the QG3 and
QG4 joint ventures. Production from the LNG trains and associated facilities is combined and shared.
12
Libya
2020
Crude Oil
NGL
Natural Gas
Total
Interest
Operator
MBD
MBD
MMCFD
MBOED
Average Daily Net Production
Waha Concession
16.3
%
Waha Oil Co.
8
-
5
9
Total Libya
8
-
5
9
The Waha Concession consists of multiple concessions and encompasses nearly 13 million gross acres in the
Sirte Basin. Our production operations in Libya and related oil exports have periodically been interrupted over
the last several years due to the shutdown of the Es Sider crude oil export terminal. In 2020, we had five crude
liftings from Es Sider, compared with 19 crude liftings from Es Sider in 2019. Production ceased in February
2020, due to a forced shutdown of the Es Sider export terminal and other eastern export terminals after a
period of civil unrest. In October 2020, force majeure was lifted allowing production operations and related oil
exports to resume.
ASIA PACIFIC
The Asia Pacific segment has exploration and production operations in China, Indonesia, Malaysia and
Australia. In 2020, operations in the Asia Pacific segment contributed 10 percent of our consolidated liquids
production and 32 percent of our consolidated natural gas production.
Australia
2020
Crude Oil
NGL
Natural Gas
Total
Interest
Operator
MBD
MBD
MMCFD
MBOED
Average Daily Net Production
ConocoPhillips/
Australia Pacific LNG
37.5
%
Origin Energy
-
-
684
114
Bayu-Undan*
56.9
ConocoPhillips
2
1
87
17
Total Australia and Timor-Leste
2
1
771
131
*This asset was disposed in May 2020. See Note 4—Asset Acquisitions and Dispositions in the Notes to Consolidated Financial Statements for
additional information.
Australia Pacific LNG
Australia Pacific LNG Pty Ltd (APLNG), our joint venture with Origin Energy Limited and China
Petrochemical Corporation (Sinopec), 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.
As of December 31, 2020, APLNG has an outstanding balance of $6.2 billion on a $8.5 billion project finance
facility. Project finance interest payments are bi-annual, concluding September 2030.
13
For additional information, see Note 5—Investments, Loans and Long-Term Receivables and Note 11—
Guarantees, in the Notes to Consolidated Financial Statements.
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 in 2020, increasing our interest to 80 percent. The required government approvals for the
transfer of this interest were obtained in June 2020. We plan to conduct a 3-D seismic survey in the second
half of 2021, subject to governmental approval of a recently submitted Environmental Plan.
Dispositions
In May 2020, we completed the divestiture of our subsidiaries that held our Australia-West assets and
operations. These subsidiaries held a 37.5 percent interest in the Barossa Project and Caldita Field, a 56.9
percent interest in the Darwin LNG Facility and Bayu-Undan Field, and a 40 percent interest in the Greater
Poseidon Fields. Production from the beginning of the year through the disposition date in May 2020 averaged
43 MBOED. See Note 4—Asset Acquisitions and Dispositions in the Notes to Consolidated Financial
Statements for additional information.
Indonesia
2020
Crude Oil
NGL
Natural Gas
Total
Interest
Operator
MBD
MBD
MMCFD
MBOED
Average Daily Net Production
South Sumatra
54
%
ConocoPhillips
2
-
290
50
Total Indonesia
2
-
290
50
During 2020, 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.
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 2-D seismic acquisition program. After completion of prospect evaluation, both PSC
contractors decided to relinquish rights and return this block to the government.
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.
14
China
2020
Crude Oil
NGL
Natural Gas
Total
Interest
Operator
MBD
MBD
MMCFD
MBOED
Average Daily Net Production
Penglai
49.0
%
CNOOC
30
-
-
30
Total China
30
-
-
30
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.
Wellhead Platform J Project in the Penglai 19-9 Field achieved first production in 2016. This project consisted
of 62 wells that have all been completed and brought online as of December 2020.
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 for two wellhead platforms and in
2020 for the third wellhead platform. This project could include up to 186 wells, 91 of which have been
completed and brought online as of December 2020.
The Phase 4A Project in the Penglai 25-6 Field consists of one new wellhead platform and achieved first
production in December 2020. This project could include up to 62 new wells, two of which have been
completed and brought online as of December 2020.
Panyu
We have a production license for Panyu 4-1 in Block 15/34. If a development occurs, our production license is
for 15 years upon commencement of production.
Exploration
Exploration activities in the Bohai Penglai Field during 2020 consisted of two successful appraisal wells
supporting future developments in the Bohai Bay Block 11/05.
We fulfilled our exploration well commitment in Panyu 4-1 in early 2020. No further exploration well
operations are planned.
Malaysia
2020
Crude Oil
NGL
Natural Gas
Total
Interest
Operator
MBD
MBD
MMCFD
MBOED
Average Daily Net Production
Gumusut
29.0
%
Shell
21
-
-
21
Malikai
35.0
Shell
11
-
-
11
Kebabangan (KBB)
30.0
KPOC
1
-
52
10
Siakap North-Petai
21.0
PTTEP
2
-
-
2
Total Malaysia
35
-
52
44
We have varying stages of exploration, development and production activities across 1.5 million net acres in
Malaysia, with working interests in five PSCs. Three of these PSCs are located in waters off the eastern
Malaysian state of Sabah: Block G, Block J and the Kebabangan Cluster (KBBC). We operate two exploration
blocks, Block WL4-00 and SK304 in waters off the eastern Malaysian state of Sarawak.
15
Block J
Gumusut
We currently have a 29 percent working interest in the Gumusut Field following the redetermination of the
Block J and Block K Malaysia Unit in 2017. Gumusut Phase 2 first oil was achieved in 2019. Development
drilling associated with Gumusut Phase 3 is planned to commence in the fourth quarter of 2021 with the first
of four planned wells. First oil is anticipated in 2022.
KBBC
The KBBC PSC grants us a 30 percent working interest in the KBB, Kamunsu East and Kamunsu East
Upthrown Canyon gas and condensate fields. In 2020, we recognized dry hole expense and impaired the
associated carrying value of unproved properties in the Kamunsu East Field that is no longer in our
development plans.
KBB
During 2019, KBB tied-in to a nearby third-party floating LNG vessel which provided increased gas offtake
capacity. Production from the field has been reduced since January 2020, due to the rupture of a third-party
pipeline which carries gas production from KBB to market. The pipeline operator has initiated repairs with no
production expected to flow through the full length of the pipeline during 2021.
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, a six-
well drilling campaign, commenced in 2020, with first oil anticipated in 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, a four-well program, is anticipated in the fourth quarter of 2021.
Production Curtailments
We experienced production curtailments of 4 MBOED in 2020.
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 drilling is planned
for 2021.
In 2018, we were awarded a 50 percent working interest and operatorship of Block SK304 encompassing 2.1
million gross acres offshore Sarawak. We acquired 3-D seismic over the acreage and completed processing of
this data in 2019. Exploration drilling is planned for 2021.
In June 2020, we relinquished our 50 percent interest in Block SK 313, a 1.4 million gross-acre exploration
block offshore Sarawak.
OTHER INTERNATIONAL
The Other International segment includes exploration activities in Colombia and Argentina and 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.
16
Colombia
We have an 80 percent operated interest in the Middle Magdalena Basin Block VMM-3. The block extends
over approximately 67,000 net acres and contains the Picoplata-1 Well, which completed drilling in 2015 and
testing in 2017. Plug and abandonment activity started during 2018 and completed in 2019. 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. As part of a case brought forward by environmental groups, the
Highest Administrative Court granted a preliminary injunction temporarily suspending hydraulic fracturing
activities until the substance of the case is decided. As a result, we filed two separate Force Majeure requests
before the relevant authority for both blocks, which were granted. We have no immediate plans to perform
under existing contracts, therefore, the Picoplata-1 Well was recorded to dry hole expense and we fully
impaired the capitalized undeveloped leasehold costs associated with our Colombia assets during 2020.
Chile
In September 2020, we notified the operator of our decision to exit our 49 percent interest in the Coiron Block,
located in the Magallanes Basin in southern Chile. We are working with local authorities to finalize our
withdrawal from this block.
Argentina
We have a 50 percent nonoperated interest in El Turbio Este Block, within the Austral Basin in southern
Argentina. Following the acquisition and processing of 3-D seismic covering approximately 500 square miles
in 2019, planned activities in 2020 were delayed due to the impact of COVID-19 and force majeure in the
block.
We have a 50 percent non-operated interest in the Bandurria Norte and Aguada Federal blocks within the
Neuquen Basin in central Argentina. Following a successful production test of two horizontal wells on the
Aguada Federal Block, we increased our interest from 45 to 50 percent in April 2020 where two horizontal
wells continued production testing throughout the year. Preparation for a 2021 work program is ongoing.
Venezuela and Ecuador
For discussion of our contingencies in Venezuela and Ecuador, see Note 12—Contingencies and
Commitments, in the Notes to Consolidated Financial Statements.
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,
Europe and Asia. 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, Australia, Asia,
Africa and Europe. These commodities are primarily sold under contracts with prices based on market indices,
adjusted for location, quality and transportation.
17
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.
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.
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. Globally, our primary OSRO is Oil Spill Response Ltd.
based in the U.K., with facilities in several other countries and the ability to respond anywhere in the world. 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 Ves sel System for the Alaska North Slope and Prince
William Sound, respectively. Internationally, we maintain memberships in various regional OSROs including
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, produce
heavy oil economically with less emissions, improve the efficiency of our exploration program, increase
recoveries from our legacy fields, and implement sustainability measures.
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 and four new products announced in 2020 that expand the scope of LNG
licensing.
RESERVES
We have not filed any information with any other federal authority or agency with respect to our estimated
total proved reserves at December 31, 2020. No difference exists between our estimated total proved reserves
for year-end 2019 and year-end 2018, which are shown in this filing, and estimates of these reserves shown in
a filing with another federal agency in 2020.
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 1.1 trillion cubic feet of natural gas and 156 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
18
reserves; and PUDs. See the disclosure on “Proved Undeveloped Reserves” in the “Oil and Gas Operations”
section following the Notes to Consolidated Financial Statements, for information on the development of
PUDs.
COMPETITION
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. Based on statistics published in the September 7, 2020, issue of the
Oil and Gas Journal
, we were the
third-largest U.S.-based oil and gas company in worldwide liquids production and reserves and one of the top
ten U.S. companies measured by worldwide natural gas production and reserves in 2019. 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 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 our stakeholders, internally and externally. 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 human capital
management philosophies and tracking our progress. The ELT and Board of Directors engage often on
workforce-related topics. Our human capital management 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. We take a broad view of human capital management
that begins with offering a compelling culture and includes programs and processes necessary for ensuring we
have an engaged workforce with the skills to meet our business needs. The key elements of our human capital
management are described below.
COVID-19 Response
In 2020, a significant effort was undertaken to address the ongoing COVID-19 pandemic. In the very early
stages of the pandemic, we adopted and embraced three company-wide priorities to guide our activities in the
midst of COVID-19: to protect our employees, 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. We transitioned to a remote work
environment for periods of time to ensure the safety of our employees, partners and the community, and then
implemented rigorous cleaning and disinfecting processes and rigorous mitigation protocols to keep our
workforce safe, including temperature scans, social distancing, face covering requirements and increased
sanitation as employees returned to the office setting.
19
Culture of Feedback and Engagement
Our human capital management approach recognizes that a compelling culture and an engaged workforce are
powerful determinants of business success. Beginning in 2019, we launched a coordinated, multi-year, global
employee feedback program called “Perspectives.” In mid-2019 we administered our first Perspectives survey,
which received an 86 percent employee response rate and yielded more than 35,000 comments. We achieved
an employee satisfaction score that, on a 100-point scale, was 5 points higher than general industry and 11
points higher than our energy peers who used the same platform. Importantly, the quantitative and qualitative
survey data were used by leaders across the company to identify and analyze relative strengths and gaps and to
develop action plans to address gaps.
We intended to repeat the comprehensive Perspectives survey in 2020; however, in light of the COVID-19
pandemic and the significant industry downturn, we elected to defer the full survey until 2021 and instead
focused our 2020 feedback program on the specific topic of Diversity and Inclusion (D&I). The survey
“Perspectives Pulse: D&I” also received a high response rate with over 10,000 comments. The ELT and an
internal D&I Council are responsible for analyzing the survey data to identify D&I strengths and gaps, and to
use the findings to establish 2021 D&I priorities and action plans. The company’s D&I commitment, activities
and programs are described below.
Diversity and Inclusion
Our commitment to D&I is foundational to our SPIRIT Values and our stated company-wide D&I goal is to
have “a diverse culture of belonging where everyone feels valued.” We believe a diverse workforce and an
inclusive environment that reflects different backgrounds, experiences, ideas and perspectives drives
innovation, employee satisfaction and overall company performance. We hold our entire workforce
accountable for creating and sustaining an inclusive work environment. Our leaders are accountable for
having personal D&I goals each year and we believe senior leadership involvement is critical for achieving
meaningful progress on D&I.
The ELT has ultimate accountability for advancing our D&I commitment through a governance structure that
includes an ELT-level D&I Champion, a global D&I Council consisting of senior leaders from across the
company and organization-wide D&I goals. Leaders meet regularly with each other and with the workforce to
discuss challenges, opportunities, best practices and progress. In addition, our D&I plans and progress are
reviewed regularly with the Board of Directors.
In 2018, the company established three pillars to guide our D&I activities: leadership accountability, employee
awareness, and processes and programs. Since then, we have established corporate priorities annually under
each of these areas. In 2020 we also published our first D&I Annual Report internally and we expect to update
this report periodically as an important part of holding ourselves accountable for progressing our D&I goals
throughout ConocoPhillips. Some of our key D&I actions and accomplishments over the past few years
include:
●
Publishing our first D&I Dashboards internally which contain key D&I statistics for our global and
U.S. employees at year-end for the periods 2015-2019;
●
Launching a company-wide platform for our workforce to talk openly about D&I;
●
Expanding our workforce recognition programs to include a prestigious “SPIRIT Award” for D&I
advocates;
●
Implementing a “how rating” and an upward feedback process as part of our performance
management system to hold our workforce and our leaders accountable for D&I;
●
Broadening our D&I-related training resources; and
●
Advocating for broad participation in, and awareness of our extensive network of employee resource
groups, which drew participation from over 5,000 people in 2020.
20
We recognize that achieving our D&I goals require the visible actions described above, but also requires a
clear linkage to the daily activities of our workforce. These activities include:
●
Educating managers on inclusive hiring practices;
●
Conducting immersive D&I training for senior leaders and influencers;
●
Examining our Talent Management Teams’ processes to eradicate bias within our selection and
succession efforts;
●
Working with partners to connect veterans and individuals with disabilities with employment;
●
Promoting inclusion of employees with disabilities through a robust accommodation process available
to all employees;
●
Ensuring diverse internal and external candidate slates; and
●
Creating balanced interview teams to mitigate any unconscious bias in our hiring processes.
We actively monitor diversity metrics on a global basis. In addition to our internal dashboards, we publicly
report our representation of women and minorities in leadership roles. We have also committed to publicly
disclose ConocoPhillips’ Consolidated EEO-1 Report effective upon our next submission to the U.S. Equal
Employment Opportunity Commission in 2021. Tables of 2020 employee demographics by gender and
ethnicity, and by country, are shown below:
2020 Employees by Gender
*
Male
Female
Non-POC
**
POC
All Employees
73
%
27
%
75
%
25
%
All Leadership
77
23
81
19
Top Leadership
81
19
87
13
Junior Leadership
76
24
78
22
**"POC" refers to People of Color or racial and ethnic minorities self-reported in the U.S.
Note: percentages based on year-end 2020 employee count of 9,700.
2020 Employees by Country
Percent of Total
USA
59
%
Norway
19
Canada
8
Indonesia
6
Great Britain
3
Australia
3
China
1
Other Global Locations
1
100
Our human capital management approach addresses programs and processes necessary for ensuring an
engaged workforce with the skills to meet our business needs. We take a holistic view of human capital
management that addresses each of the critical components of workforce planning. These are described in
more detail below.
Hiring & Retention
Our success depends on having the right workforce to meet our business needs. Attracting and retaining a
skilled, engaged and diverse workforce is a top priority. We conduct routine personnel needs assessments with
leaders to ensure we have the organizational capacity and capabilities to execute our business plans. We’ve
21
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. To attract qualified, diverse
candidates for full-time positions or internships, we recruit from a number of universities in the U.S. By
attending conferences and recruiting at Hispanic-serving institutions and historically black colleges and
universities, we have extended a broader outreach to potential diverse candidates.
We closely monitor recruitment metrics through our university dashboards in areas such as gender, ethnicity
and university acceptance rates to help guide decisions and best practices. These are disclosed internally
through our D&I Dashboards to ensure greater transparency. In addition, voluntary turnover metrics are
routinely tracked and disclosed to guide our retention activities, as necessary.
2020 Hiring & Retention Metrics (U.S.)
Percent of Total
University hire acceptance
85
%
Interns acceptance
74
Diversity hiring - Women
29
Diversity hiring - POC
28
Total voluntary attrition
3
Talent Development
We employ a comprehensive approach for ensuring our workforce is adequately prepared for their
responsibilities and also to advance their career. 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 rating to assess behaviors to ensure they are in line
with our SPIRIT values.
ConocoPhillips has established core leadership competencies that provide a common baseline of knowledge,
skills, abilities, and behaviors to support employee performance, growth, and success. All supervisors have
access to a voluntary 360-feedback tool to receive feedback on their strengths and opportunities relative to
these competencies. We offer training on a broad range of technical and professional skills, from data
analytics to communication skills.
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 2020, our U.S. parental leave benefit increased from two weeks to six weeks
and combined with our maternity benefit (eight weeks), new birth mothers are eligible for up to 14 weeks of
paid leave.
22
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.
Compensation Risk Mitigation
ConocoPhillips has 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
utilized under each incentive compensation program. As a result of this review, management concluded the
risks arising from our compensation policies and practices are not reasonably likely to have a material adverse
effect on ConocoPhillips. As part of the Board of Directors’ oversight of ConocoPhillips’ 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 ConocoPhillips.
GENERAL
At the end of 2020, we held a total of 1,038 active patents in 50 countries worldwide, including 419 active
U.S. patents. During 2020, we received 65 patents in the U.S. and 69 foreign patents. Our products and
processes generated licensing revenues of $16 million related to activity in 2020. The overall profitability of
any business segment is not dependent on any single patent, trademark, license, franchise or concession.
Health, Safety and Environment
Our HSE organization provides tools and support to our business units and staff groups to help them ensure
world class HSE performance. The framework through which we safely manage our operations, the HSE
Management System Standard, emphasizes process safety, risk management, emergency preparedness and
environmental performance, with an intense focus on process and occupational safety. In support of the goal
of zero incidents, HSE milestones and criteria are established annually to drive strong safety and
environmental performance. Progress toward these milestones and criteria are measured and reported. HSE
audits are conducted on business functions periodically, and improvement actions are established and tracked
to completion. We have designed processes relating to sustainable development in our economic,
environmental and social performance. Our processes, related tools and requirements focus on water,
biodiversity and climate change, as well as social and stakeholder issues.
The environmental information contained in Management’s Discussion and Analysis of Financial Condition
and Results of Operations on pages 64 through 69 under the captions “Environmental” and “Climate Change”
is incorporated herein by reference. It includes information on expensed and capitalized environmental costs
for 2020 and those expected for 2021 and 2022.
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
.
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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
We have been negatively affected and may continue to be negatively affected by the prolonged drop in
commodity prices that began in early 2020.
The oil and gas business is fundamentally a commodity business and our revenues, operating results and future
rate of growth are highly dependent on the prices we receive for crude oil, bitumen, natural gas, NGLs and
LNG. Such prices can fluctuate widely depending upon global events or conditions that affect supply and
demand, most of which are out of our control. Since early 2020, there has been a precipitous decrease in
demand for oil globally, largely caused by the dramatic decrease in travel and commerce resulting from the
COVID-19 pandemic. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results
of Operations, for additional information on commodity prices and how we have been impacted. There is no
assurance of when or if commodity prices will return to pre-COVID-19 levels, and if they do return to pre-
COVID levels, how long they will remain at those levels. The speed and extent of any recovery remains
uncertain and is subject to various risk factors, including the duration, impact and actions taken to stem the
proliferation of the COVID-19 pandemic, the extent to which those nations party to the OPEC plus production
agreement decide to increase production of crude oil, bitumen, natural gas and NGLs and other factors
described herein. Even after a recovery, 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, NGL and LNG prices may have a material adverse effect on our
revenues, earnings, cash flows and liquidity, and may also affect the amount of dividends we elect to declare
and pay on our common stock. As a result of the oil market downturn that began in early 2020, we suspended
our share repurchase program. 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, NGLs and LNG 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 2020, we recognized several impairments, which are described in Note 7—
Suspended Wells and Exploration Expenses and Note 8—Impairments, in the Notes to Consolidated Financial
Statements, due to changes in assumptions for commodity prices and development plans. If the outlook for
commodity prices remains low relative to historic levels, and as we continue to optimize our investments and
exercise capital flexibility, it is reasonably likely we will incur future impairments to long-lived assets used in
operations, investments in nonconsolidated entities accounted for under the equity method and unproved
properties. If oil and gas prices persist at depressed levels, our reserve estimates may decrease further, which
could incrementally increase the rate used to determine DD&A expense on our unit-of-production method
properties. See Item 7. Management’s Discussion and Analysis for further examination of DD&A rate impacts
versus comparative periods. 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.
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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. According to the National Bureau of Economic
Research, as a result of the pandemic and its broad reach across the entire economy, the U.S. entered a
recession in early 2020 and the timing, pace and extent of the recovery is still unknown. 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. In addition, despite
approval of vaccines to immunize against COVID-19, the speed at which such vaccinations will be available to
the public, the public’s willingness to be inoculated and the effectiveness of the vaccine (including to variants)
still remain unknown. As a result, the full impact of the COVID-19 pandemic 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.
We have already been impacted by the COVID-19 pandemic. See Item 7. Management’s Discussion and
Analysis of Financial Condition and Results of Operations, 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:
●
Continued reduced demand for our products as a result of prolonged reductions in travel and
commerce, even if restrictions are lifted;
●
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;
●
Business interruptions resulting from a portion of our workforce continuing to telecommute, as well as
the implementation and maintenance of protections for employees commuting for work, such as
personnel screenings and self-quarantines before or after travel; 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.
25
Unless we successfully add to our existing proved reserves, our future crude oil, bitumen, natural gas and
NGL production will decline, resulting in an adverse impact to our business.
The rate of production from upstream fields generally declines as reserves are depleted. If we do not conduct
successful exploration and development activities, or, through engineering studies, optimize production
performance or identify additional or secondary recovery reserves, our proved reserves will decline materially
as we produce crude oil, bitumen, natural gas and NGLs, and our business will experience reduced cash flows
and results of operations. Any cash conservation efforts we may undertake as a result of commodity price
declines may further limit our ability to replace depleted reserves.
The exploration and production of oil and gas is a highly competitive industry.
The exploration and production of crude oil, bitumen, natural gas and NGLs is a highly competitive business.
We compete with private, public and state-owned companies in all facets of the exploration and production
business, including to locate and obtain new sources of supply and to produce crude oil, bitumen, natural gas
and NGLs in an efficient, cost-effective manner. Some of our competitors are larger and have greater
resources than we do or may be willing to incur a higher level of risk than we are willing to incur to obtain
potential sources of supply. 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 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. 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. 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
26
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.
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, crude oil spills, severe weather, geological events, labor disputes,
armed hostilities, terrorist attacks, sabotage, civil unrest or cyber attacks. Our operations may also be
adversely affected by unavailability, interruptions or accidents involving services or infrastructure required to
develop, produce, process or transport our production, such as contract labor, drilling rigs, pipelines, railcars,
tankers, barges or other infrastructure. Our operations are subject to the additional hazards of pollution,
releases of toxic gas 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. Further, 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.
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;
●
Carbon taxes;
●
The handling, use, storage, transportation, disposal and cleanup of hazardous materials and hazardous
and nonhazardous wastes;
●
The dismantlement, abandonment and restoration of our 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.
27
We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation
expenditures as a result of these laws and regulations. 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 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, carbon taxes, restrictive permitting, increased fuel efficiency
standards and incentives or mandates for renewable energy. For example, in December 2015, the U.S. joined
the international community at the 21st Conference of the Parties of the United Nations Framework
Convention on Climate Change in Paris that prepared an agreement requiring member countries to review and
represent a progression in their intended GHG emission reduction goals every five years beginning in 2020.
While the U.S. previously withdrew from the Paris Agreement, 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 their intention to satisfy these commitments. In
addition, our operations continue in countries around the world which are party to, and have not announced an
intent to withdraw from, 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 October 2020, we announced the adoption of a Paris-aligned climate risk framework, whereby we
committed to a reduction of our gross operated (scope 1 and 2) emissions intensity, with an ambition to
achieve net zero by 2050 from operated emissions. We also endorsed the World Bank Zero Routine Flaring by
2030 initiative, with an ambition to meet that goal by 2025 and reaffirmed our commitment to advocate for
reduction of scope 3 emissions intensity 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, potentially resulting in the reduction to the
economic end-of-field life of certain assets and an impairment of the associated net book value.
Increasing attention to global climate change has also resulted in pressure 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, in 2019 Norway’s Government Pension Fund
announced it would reduce its investment exposure to companies that explore for oil and gas, and in 2020 a
number of major financial institutions announced that they would no longer finance oil and gas exploration
projects in the Arctic. 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 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 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
28
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.
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 could be adversely impacted, and demand for our products could fall.
For more information on legislation or precursors for possible regulation relating to global climate change that
affect or could affect our operations and a description of the company’s response, see the “Contingencies—
Climate Change” section of Management’s Discussion and Analysis of Financial Condition and Results of
Operations.
Domestic and worldwide political and economic developments could damage our operations and materially
reduce our profitability and cash flows.
Actions of the U.S., state, local and foreign governments, through sanctions, tax and other legislation,
executive order and commercial restrictions, could reduce our operating profitability both in the U.S. and
abroad. In certain locations, restrictions on our operations; 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. The change in control of Congress and the
White House because of the 2020 election increases the possibility of the promulgation of more stringent
regulations of our operations and the enactment of tax law changes that may adversely affect the fossil fuel
industry. In addition, the current administration may use the Congressional Review Act to repeal the
regulations finalized in the last five months of the prior administration. 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. On January 27, 2021, the new administration signed an executive order
directing the Secretary of the Interior to stop issuing new oil and gas leases on federal lands, allowing time to
review and reset the Federal Government’s oil and gas leasing program. Existing production and permits
already issued on Federal lands were not impacted by this order. If this temporary moratorium were to be
extended indefinitely, we believe we can mitigate the impact for a considerable period of time with our current
permits and adjusting our development plans across our diverse acreage position.
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
29
costs and delays, curtailments, limitations or prohibitions could have a material adverse effect on our business,
prospects, results of operations, financial condition and liquidity.
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 PDVSA or the ICSID Award against the Government
of Venezuela; or to obtain or maintain 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 48 percent of our hydrocarbon production was derived from production outside the U.S. in
2020, and 42 percent of our proved reserves, as of December 31, 2020, were located outside the U.S. We are
subject to risks associated with operations in 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. 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.
Risks Related to Our Acquisition of Concho
Combining our business with Concho’s may be more difficult, costly or time-consuming than expected and
we may fail to realize the anticipated benefits of the Merger, which may adversely affect our business results
and negatively affect the value of our common stock.
Our acquisition of Concho (the Merger) involved the combination of two companies which, until the
completion of the Merger, operated as independent public companies. The success of the Merger will depend
on, among other things, the ability of our two companies to combine our businesses in a manner that adds
value to shareholders. However, there can be no assurances that our respective businesses can be integrated
successfully, and we will be required to devote significant management attention and resources to the
integration process. We must achieve the anticipated improvement in free cash flow generation and returns
and achieve the planned cost savings without adversely affecting current revenues or compromising the
disciplined investment philosophy to maximize value for shareholders.
There are a large number of processes, policies, procedures, operations and technologies and systems that must
be integrated, and although we expect that the elimination of duplicative costs, strategic benefits, and
additional income, as well as the realization of other efficiencies related to the integration of the business, may
offset incremental transaction and Merger-related costs over time, we may encounter difficulties in the
integration and any net benefit may not be achieved in the near term or at all. It is possible that the integration
process could take longer than originally anticipated and could result in the loss of key employees; the loss of
commercial and vendor partners; the disruption of our ongoing businesses; inconsistencies in standards,
controls, procedures and policies; unexpected integration issues; and higher than expected integration costs.
An inability to realize the full extent of the anticipated benefits of the Merger and the other transactions
contemplated by the Merger Agreement, as well as any delays encountered in the integration process, could
have an adverse effect upon the revenues, level of expenses and operating results of ConocoPhillips, which
may adversely affect the value of our common stock.
30
The market value of our common stock could decline if large amounts of our common stock are sold now
that the Concho acquisition has been consummated.
We issued shares of ConocoPhillips common stock to former Concho stockholders. Former Concho
stockholders may decide not to hold the shares of ConocoPhillips common stock that they received in the
Merger, and ConocoPhillips stockholders may decide to reduce their investment in ConocoPhillips as a result
of the changes to ConocoPhillips’ investment profile as a result of the Merger. Other Concho stockholders,
such as funds with limitations on their permitted holdings of stock in individual issuers, may be required to sell
the shares of ConocoPhillips common stock that they received in the Merger. Such sales of ConocoPhillips
common stock could have the effect of depressing the market price for ConocoPhillips common stock.
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.
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.
In particular, in August 2018, we entered into a settlement agreement with Petróleos de Venezuela, S.A.
(PDVSA) providing for the payment of approximately $2 billion over a five-year period in connection with an
arbitration award issued by the International Chamber of Commerce (ICC) Tribunal in favor of ConocoPhillips
on a contractual dispute arising from Venezuela’s expropriation of our interests in the Petrozuata and Hamaca
heavy oil ventures and other pre-expropriation fiscal measures. We have collected approximately $0.8 billion
of the $2.0 billion settlement to date and PDVSA has defaulted on its remaining payment obligations under
31
this agreement. We are therefore incurring additional costs as we seek to recover any unpaid amounts under
the agreement. Additionally, in March 2019, an ICSID arbitration tribunal issued an award unanimously
ordering the government of Venezuela to pay ConocoPhillips approximately $8.7 billion in compensation for
the government’s unlawful expropriation of the company’s investments in Venezuela in 2007. ConocoPhillips
has filed requests for recognition of the award in several jurisdictions. On August 29, 2019, the ICSID tribunal
issued a decision rectifying the award and reducing it by approximately $227 million. The award now stands
at $8.5 billion plus interest. The government of Venezuela is seeking annulment of the award before another
panel at ICSID and annulment proceedings are underway. No amounts have been collected as a result of this
award yet.
Our ability to declare and pay dividends and repurchase shares is subject to certain considerations.
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.
We expect to continue to pay quarterly dividends to our stockholders; however, our Board of Directors may
reduce our 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.
Additionally, as of December 31, 2020, $14.5 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, and we may do so again in the future.
Any downward revision in the amount of dividends we pay to stockholders or the number 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 may choose to undertake.
We regularly review our portfolio and pursue growth through acquisitions and seek to divest non-core 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) difficulties in integrating the operations, technologies, products and personnel of the
acquired assets or businesses; (iii) the inability to dispose of non-core assets and businesses on satisfactory
terms and conditions; and (iv) 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.
32
Our technologies, systems and networks may be subject to cyber attacks.
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 cyber security 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)
corrupted or unusable, threats to the security of our facilities and infrastructure as well as those of third-parties
with whom we do business 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 cyber breach of these
operating systems, or of the networks 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 or make it difficult or impossible to accurately account for production and settle transactions.
Although we have experienced occasional breaches of our cyber security, none of these breaches have had a
material effect on our business, operations or reputation. As cyber attacks continue to evolve, 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 various 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 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, significant litigation exposure and legal
liability or regulatory fines, penalties or intervention. Any of these could materially and adversely affect our
business, results of operations or financial condition. 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 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.
Item 1B. UNRESOLVED STAFF COMMENTS
None.
Item 3.
LEGAL PROCEEDINGS
The following is a description of reportable legal proceedings, 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. Nevertheless, such proceedings are reported pursuant to
SEC regulations.
On April 30, 2012, the separation of our downstream business was completed, creating two independent
energy companies: ConocoPhillips and Phillips 66. In connection with the separation, we entered into an
Indemnification and Release Agreement, which provides for cross-indemnities between Phillips 66 and us and
33
established procedures for handling claims subject to indemnification and related matters, such as legal
proceedings. We have included matters where we remain or have subsequently become a party to a
proceeding relating to Phillips 66, in accordance with SEC regulations. We do not expect any of those matters
to result in a net claim against us.
Matters Previously Reported—Phillips 66
In May 2012, the Illinois Attorney General's office filed and notified ConocoPhillips of a complaint with
respect to operations at the Phillips 66 WRB Wood River Refinery alleging violations of the Illinois
groundwater standards and a third-party's hazardous waste permit. The complaint seeks remediation of area
groundwater; compliance with the hazardous waste permit; enhanced pipeline and tank integrity measures;
additional spill reporting; and yet-to-be specified amounts for fines and penalties.
Item 4.
MINE SAFETY DISCLOSURES
Not applicable.
INFORMATION ABOUT OUR EXECUTIVE OFFICERS
Name
Position Held
Age*
Catherine A. Brooks
Vice President and Controller
55
William L. Bullock, Jr.
Executive Vice President and Chief Financial Officer
56
Ellen R. DeSanctis
Senior Vice President, Corporate Relations
64
Matt J. Fox
Executive Vice President and Chief Operating Officer
60
Ryan M. Lance
Chairman of the Board of Directors and Chief Executive Officer
58
Timothy A. Leach
Executive Vice President, Lower 48
61
Andrew D. Lundquist
Senior Vice President, Government Affairs
60
Dominic E. Macklon
Senior Vice President, Strategy, Exploration and Technology
51
Nicholas G. Olds
Senior Vice President, Global Operations
51
Kelly B. Rose
Senior Vice President, Legal, General Counsel
54
*On February 16, 2021.
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 11, 2021. Set forth below is information about the executive officers.
Catherine A. Brooks
was appointed Vice President and Controller as of January 2019, having previously
served as General Auditor since August 2018. Prior to serving as General Auditor, she was Assistant
Controller from February 2016 to August 2018. She became Manager, Finance & Performance Analysis in
April 2014 and served in that role until February 2016. Ms. Brooks previously held the position of Manager,
External Reporting from May 2010 to April 2014.
William L. Bullock, Jr.
2020, having previously served as President, Asia Pacific & Middle East since April 2015. Prior to that, he
was Vice President, Corporate Planning & Development since May 2012.
34
Ellen R. DeSanctis
previously served as Vice President, Investor Relations and Communications since May 2012. Prior to that,
she was employed by Petrohawk Energy Corp. where she served as Senior Vice President, Corporate
Communications since 2010.
Matt J. Fox
previously served as Executive Vice President, Strategy, Exploration and Technology since March 2016 and
Executive Vice President, Exploration and Production, from May 2012 to March 2016. Prior to that, he was
employed by Nexen, Inc., where he served as Executive Vice President, International since 2010.
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
August 2020, having previously served as President, Lower 48 since June 2018. Prior to that, he served as
Vice President, Corporate Planning & Development since January 2017 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 Vice President, Corporate Planning & Development since June 2018. Prior to
that, he served as Vice President, Mid-Continent Business Unit in the 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.
35
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
2020
2019
First
$
0.420
0.305
Second
0.420
0.305
Third
0.420
0.305
Fourth
0.430
0.420
Number of Stockholders of Record at January 31, 2021*
40,483
*In determining the number of stockholders, we consider clearing agencies and security position listings as one stockholder for each agency
The declaration of dividends is subject to the discretion of our Board of Directors, and may be affected by
various factors, including our future earnings, financial condition, capital requirements, levels of indebtedness,
credit ratings and other considerations our Board of Directors deems relevant. Our Board of Directors has
adopted a quarterly dividend declaration policy providing that the declaration of any dividends will be
determined quarterly by the Board of Directors taking into account such factors as our business model,
prevailing business conditions and our financial results and capital requirements, without a predetermined
annual net income payout ratio.
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, 2020
4,805,220
$
34.68
4,805,220
$
14,483
November 1-30, 2020
-
-
-
14,483
December 1-31, 2020
-
-
-
14,483
4,805,220
$
34.68
4,805,220
*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, 2020, we had repurchased $10.5
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. See “Item 1A—Risk Factors – Our ability to declare and pay dividends and
repurchase shares is subject to certain considerations.”
36
Stock Performance Graph
The following graph shows the cumulative TSR for ConocoPhillips’ common stock in each of the five years
from December 31, 2015 to December 31, 2020. 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. For the 2019 Stock
Performance Graph, Noble Energy was also presented within the peer group. However, due to Chevron’s
acquisition of Noble Energy completed in 2020, Noble Energy’s performance has been excluded from all five
years of the peer group performance.
The comparison assumes $100 was invested on December 31, 2015, 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.
37
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 an independent E&P company with operations and activities in 15 countries. Our diverse,
low cost of supply portfolio includes resource-rich unconventional plays in North America; conventional
assets in North America, Europe and Asia; LNG developments; oil sands assets in Canada; and an inventory of
global conventional and unconventional exploration prospects. Headquartered in Houston, Texas, at
December 31, 2020, we employed approximately 9,700 people worldwide and had total assets of $63 billion.
Completed Acquisition of Concho Resources Inc.
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. The
addition of complementary acreage in the Delaware and Midland Basins creates a sizeable Permian presence to
augment our leading unconventional positions in the Eagle Ford and Bakken in the Lower 48 and the Montney
in Canada.
Consideration for the all-stock transaction was valued at $13.1 billion, in which 1.46 shares of ConocoPhillips
common stock was exchanged for each outstanding share of Concho common stock, resulting in the issuance
of approximately 286 million shares of ConocoPhillips common stock. We also assumed $3.9 billion in
aggregate principal amount of outstanding debt for Concho, which was recorded at fair value of $4.7 billion as
of the closing date. The combined companies are expected to capture approximately $750 million of annual
cost and capital savings by 2022. For additional information related to this transaction, see Note 25—
Acquisition of Concho Resources Inc. in the Notes to Consolidated Financial Statements.
Overview
The energy landscape changed dramatically in 2020 with simultaneous demand and supply shocks that drove
the industry into a severe downturn. The demand shock was triggered by the COVID-19 pandemic, which
continues to have unprecedented social and economic consequences. Mitigation efforts to stop the spread of
this highly-contagious disease include stay-at-home orders and business closures that caused sharp
contractions in economic activity worldwide. The supply shock was triggered by disagreements between
OPEC and Russia, beginning in early March 2020, which resulted in significant supply coming onto the
38
market and an oil price war. These dual demand and supply shocks caused oil prices to collapse as we exited
the first quarter of 2020.
As we entered the second quarter of 2020, predictions of COVID-19 driven global oil demand losses
intensified, with forecasts of unprecedented demand declines. Based on these forecasts, OPEC plus nations
held an emergency meeting, and in April they announced a coordinated production cut that was unprecedented
in both its magnitude and duration. The OPEC plus agreement spans from May 2020 until April 2022, with
the volume of production cuts easing over time. Additionally, non-OPEC plus countries, including the U.S.,
Canada, Brazil and other G-20 countries, announced organic reductions to production through the release of
drilling rigs, frac crews, normal field decline and curtailments. Despite these planned production decreases,
the supply cuts were not timely enough to overcome significant demand decline. Futures prices for April WTI
closed under $20 a barrel for the first time since 2001, followed by May WTI settling below zero on the day
before futures contracts expiry, as holders of May futures contracts struggled to exit positions and avoid taking
physical delivery. As storage constraints approached, spot prices in April for certain North American
landlocked grades of crude oil were in the single digits or even negative for particularly remote or low-grade
crudes, while waterborne priced crudes such as Brent sold at a relative advantage. The extreme volatility
experienced in the first half of the year settled down in the second half of the year, with WTI crude oil prices
exiting the year near $50 per barrel.
Since the start of the severe downturn, we have closely monitored the market and taken prudent actions in
response to this situation. We entered 2020 in a position of relative strength, with cash and cash equivalents of
more than $5 billion, short-term investments of $3 billion, and an undrawn credit facility of $6 billion, totaling
approximately $14 billion in available liquidity. Additionally, we had several entity and asset sales
agreements in place, which generated $1.3 billion in proceeds from dispositions during 2020. For more
information about the sales of our Australia-West and non-core Lower 48 assets, see Note 4—Asset
Acquisitions and Dispositions in the Notes to Consolidated Financial Statements. This relative advantage
allowed us to be measured in our response to the sudden change in business environment.
In March, we announced an initial set of actions to address the downturn and followed up with additional
actions in April. The combined announcements reflected a reduction in our 2020 operating plan capital of $2.3
billion, a reduction to our operating costs of $600 million and suspension of our share repurchase program.
These actions decreased uses of cash by approximately $5 billion in 2020. We also established a framework
for evaluating our assets and implementing economic production curtailments considering the weakness in oil
prices during the second quarter of 2020, which resulted in taking an additional significant step of voluntarily
curtailing production, predominantly from operated North American assets. Due to our strong balance sheet,
we were in an advantaged position to forgo some production and cash flow in anticipation of receiving higher
cash flows for those volumes in the future.
In the second quarter, we curtailed production by an estimated 225 MBOED, with 145 MBOED of the
curtailments from the Lower 48, 40 MBOED from Alaska and 30 MBOED from our Surmont operation in
Canada. The remainder of the second-quarter curtailments were primarily in Malaysia. Other industry
operators also cut production and development plans and as we progressed through the second quarter, certain
stay-at-home restrictions eased, which partially restored lost demand, and WTI and Brent prices exited the
second quarter around $40 per barrel. Based on our economic framework, we began restoring production from
voluntary curtailments in July, and with oil stabilizing around $40 per barrel, we ended our curtailment
program during the third quarter. Curtailments in the third quarter averaged approximately 90 MBOED, with
65 MBOED attributable to the Lower 48 and 15 MBOED to Surmont.
In August 2020, we acquired additional Montney acreage for cash consideration of $382 million, after
customary post-closing adjustments. We also assumed $31 million in financing obligations for associated
partially owned infrastructure. This acquisition consisted primarily of undeveloped properties and included
140,000 net acres in the liquids-rich Inga Fireweed asset Montney zone, which is directly adjacent to our
existing Montney position. The transaction increased our Montney acreage position to approximately 295,000
net acres with a 100 percent working interest. See Note 4—Acquisitions and Dispositions in the Notes to
Consolidated Financial Statements for additional information.
39
In October 2020, we announced an increase to our quarterly dividend from $0.42 per share to $0.43 per share
and resumed share repurchases before suspending our share repurchase program upon entry into our definitive
agreement to acquire Concho. We resumed shares repurchases in February 2021 after completion of our
Concho acquisition. We ended the year with over $12 billion of liquidity, comprised of $3.0 billion in cash
and cash equivalents, $3.6 billion in short-term investments, and available borrowings under our credit facility
of $5.7 billion.
Our expectation is that commodity prices will remain cyclical and volatile, and a successful business strategy
in the E&P industry must be resilient in lower price environments, at the same time retaining upside during
periods of higher prices. While we are not impervious to current market conditions, we believe our decisive
actions over the last several years of focusing on free cash flow generation, high-grading our asset base,
lowering the cost of supply of our investment resource portfolio, and strengthening our balance sheet have put
us in a strong relative position compared to our independent E&P peers. We remain committed to the core
principles of our value proposition, namely, free cash flow generation, a strong balance sheet, commitment to
differential returns of and on capital, and ESG leadership.
Our workforce and operations have adjusted to mitigate the impacts of the COVID-19 pandemic. We have
operations in remote areas with confined spaces, such as offshore platforms, the North Slope of Alaska, Curtis
Island in Australia, western Canada and Indonesia, where viruses could rapidly spread. Personnel are asked to
perform a self-assessment for symptoms of illness each day and, when appropriate, are subject to more
restrictive measures before traveling to and working on location. Staffing levels in certain operating locations
have been reduced to minimize health risk exposure and increase social distancing. A portion of our office
staff have continued to work successfully remotely, with offices around the world carefully designing and
executing a flexible, phased reentry, following national, state and local guidelines. These mitigation measures
have thus far been effective at reducing business operation disruptions. Workforce health and safety remains
the overriding driver for our actions and we have demonstrated our ability to adapt to local conditions as
warranted.
The marketing and supply chain side of our business has also adapted in response to COVID-19. Our
commercial organization managed transportation commitments during our voluntary curtailment program.
Our supply chain function is proactively working with vendors to ensure the continuity of our business
operations, monitor distressed service and materials providers, capture deflation opportunities, and pursue cost
reduction efforts. We also enhanced our focus on counterparty risk monitoring during this period and
requested credit assurances when applicable.
Operationally, we remain focused on safely executing the business. In 2020, production of 1,127 MBOED
generated cash provided by operating activities of $4.8 billion. We invested $4.7 billion into the business in
the form of capital expenditures, including $0.5 billion of acquisition capital, and paid dividends to
shareholders of $1.8 billion. Production decreased 221 MBOED or 16 percent in 2020, compared to 2019.
Production excluding Libya for 2020 was 1,118 MBOED. Adjusting for estimated curtailments of
approximately 80 MBOED; closed acquisitions and dispositions; and excluding Libya, production for 2020
would have been 1,176 MBOED, a decrease of 15 MBOED compared with 2019 production. This decrease
was primarily due to normal field decline, partly offset by new wells online in the Lower 48, Canada, Norway,
Alaska and China. Production from Libya averaged 9 MBOED as it was in force majeure during a significant
portion of the year.
Key Operating and Financial Summary
Significant items during 2020 and recent announcements included the following:
●
Enhanced both our portfolio and financial framework through the acquisition of Concho in an all-stock
transaction, as well as purchasing bolt-on acreage in Canada and Lower 48.
●
Full-year production, excluding Libya, of 1,118 MBOED; curtailed approximately 80 MBOED during the
year.
40
●
Cash provided by operating activities was $4.8 billion.
●
Generated $1.3 billion in disposition proceeds from non-core asset sales.
●
Distributed $1.8 billion in dividends and repurchased $0.9 billion of shares.
●
Ended the year with cash and cash equivalents totaling $3.0 billion and short-term investments of $3.6
billion, equaling $6.6 billion in ending cash and cash equivalents and short-term investments.
●
Announced two significant discoveries in Norway and achieved first production at Tor II; continued
appraisal drilling and started up first pads and related infrastructure in Montney.
●
Adopted a Paris-aligned climate risk framework with ambition to achieve net -zero operated emissions by
2050 as part of our commitment to ESG excellence.
●
Recognized impairments of proved and unproved properties totaling $1.3 billion after-tax.
Business Environment
Brent crude oil prices averaged $42 per barrel in 2020, compared with $64 per barrel in 2019. The energy
industry has periodically experienced this type of volatility due to fluctuating supply-and-demand conditions
and such volatility may persist for the foreseeable 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 foundational principles that underpin our value
proposition; free cash flow generation, a strong balance sheet, commitment to differential returns of and on
capital, and ESG leadership.
Operational and Financial Factors Affecting Profitability
The focus areas we believe will drive our success through the price cycles include:
●
Free cash flow generation. This is a core principle of our value proposition. Our goal is to achieve
strong free cash flow by exercising capital discipline, controlling our costs, and safely and reliably
delivering production. Throughout the price cycles, we expect to make capital investments sufficient
to sustain production. Free cash flow provides funds that are available to return to shareholders,
strengthen the balance sheet to deliver on our priorities through the price cycles, or reinvest back into
the business for future cash flow expansion.
o
Maintain capital allocation discipline. We participate in a commodity price-driven and
capital-intensive industry, with varying lead times from when an investment decision is made
to the time an asset is operational and generates cash flow. As a result, we must invest
significant capital dollars to explore for new oil and gas fields, 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 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, price related inflation and
G&A. In setting our capital plans, we exercise a rigorous approach that evaluates projects
using this 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 pay the existing dividend. Additional capital may be allocated toward growth, but
discipline will be maintained.
In February 2021, we announced 2021 operating plan capital for the combined company of
$5.5 billion. The plan includes $5.1 billion to sustain current production and $0.4 billion for
investment in major projects, primarily in Alaska, in addition to ongoing exploration
appraisal activity.
The operating plan capital budget of $5.5 billion is expected to deliver production from the
combined company of approximately 1.5 MMBOED in 2021. This production guidance
excludes Libya.
41
o
Control costs and expenses. Controlling operating and overhead costs, without compromising
safety and environmental stewardship, is a high priority. We monitor these costs using
various methodologies that are reported to senior management monthly, on both an absolute-
dollar basis and a per-unit basis. 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 impacts our ability to
deliver strong cash from operations. In 2020, our production and operating expenses were 18
percent lower than 2019, primarily due to decreased wellwork and transportation costs
resulting from production curtailments across our North American operated assets as well as
the absence of costs related to our U.K. and Australia-West divestitures. For more
information related to our U.K. and Australia-West divestitures, see note 4—Acquisitions and
Dispositions in the Notes to Consolidated Financial Statements.
At the time of the Concho acquisition announcement in October 2020, we announced planned
cost reductions and quantified $350 million of annual expense savings expected to be
achieved by 2022. These reductions included approximately $150 million due to streamlining
our internal organization to appropriate levels given the current industry environment and
recent asset sales; $100 million of G&A and G&G due to a refocused exploration program;
and $100 million of redundant G&A costs on a combined basis related to the Concho
acquisition. Subsequent to the transaction announcement, we identified $250 million of
further cost reductions from the combined companies to be achieved by 2022.
o
Optimize our portfolio. In January 2021, we completed the acquisition of Concho and
significantly increased our unconventional portfolio with years of low cost of supply
investments. The addition of complementary acreage in the Delaware and Midland basins
creates a sizeable Permian presence to augment our leading unconventional positions in the
Eagle Ford and Bakken in the Lower 48. We added to our unconventional Montney position
with an asset acquisition that consisted primarily of undeveloped properties directly adjacent
to our existing acreage.
These acquisitions followed several non-core asset sales earlier in the year including
Australia-West in our Asia Pacific segment, and Niobrara and Waddell Ranch in the Lower
48. We managed the portfolio well during a turbulent year, with asset sales entered at the end
of 2019 generating $1.3 billion of proceeds from dispositions in the first half of 2020,
followed by opportunistic acquisitions of unconventional assets in the second half of 2020
after commodity prices had dropped. We will continue to evaluate our assets to determine
whether they compete for capital within our portfolio and will optimize the portfolio as
necessary, directing capital towards the most competitive investments.
●
A strong balance sheet. We believe balance sheet strength is critical in a cyclical business such as
ours. Our strong operating performance buffered by a solid balance sheet enables us to deliver on our
priorities through the price cycles. Our priorities include execution of our development plans,
maintaining a growing dividend, and returning competitive returns of capital to shareholders.
●
Commitment to differential returns of and on capital. We believe in delivering value to our
shareholders via a growing, sustainable dividend supplemented by additional returns of capital,
including share repurchases. In 2020, we paid dividends on our common stock of approximately $1.8
billion and repurchased $0.9 billion of our common stock. Combined, our dividend and repurchases
represented 57 percent of our net cash provided by operating activities. Since we initiated our current
share repurchase program in late 2016, we have repurchased 189 million shares for $10.5 billion,
which represents approximately 15 percent of shares outstanding as of September 30, 2016. As of
December 31, 2020, $14.5 billion of repurchase authority remained of the $25 billion share repurchase
program our Board of Directors had authorized. Repurchases are made at management’s discretion,
42
at prevailing prices, subject to market conditions and other factors. See “Item 1A—Risk Factors Our
ability to declare and pay dividends and repurchase shares is subject to certain considerations.”
In October 2020, we announced that our Board of Directors approved an increase to our quarterly
dividend of $0.42 per share to $0.43 per share. In February 2021, we resumed share repurchases after
the completion of our Concho acquisition.
●
ESG Leadership. Safety and environmental stewardship, including the operating integrity of our
assets, remain our highest priorities, and 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 both the local and global environment and
systematically manage risk to drive sustainable business growth. Demonstrating our commitment to
sustainability and environmental stewardship, in October 2020, we announced our adoption of a Paris-
aligned climate risk framework as part of our continued leadership in ESG excellence. This
comprehensive climate risk strategy should enable us to sustainably meet global energy demand while
delivering competitive returns through the energy transition. We have set a target to reduce our gross
operated (scope 1 and 2) emissions intensity by 35 to 45 percent from 2016 levels by 2030, with an
ambition to achieve net zero by 2050 for operated emissions. We are advocating for reduction of
scope 3 end-use emissions intensity through our support for a U.S. carbon price and reaffirmed our
commitment to the Climate Leadership Council. We have joined the World Bank Flaring Initiative to
work towards zero routine flaring of gas by 2030 and are the first U.S.-based oil and gas company to
adopt a Paris-aligned climate risk strategy.
●
Add to our proved reserve base. We primarily add to our proved reserve base in three ways:
o
Purchases of increased interests in existing fields and acquisitions.
o
Application of new technologies and processes to improve recovery from existing fields.
o
Successful exploration, exploitation and development of 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.
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 negative 86 percent in 2020, reflecting the impact of lower prices, which reduced
reserves by approximately 600 MMBOE. Our organic reserve replacement, which excluded a net
decrease of 7 MMBOE from sales and purchases, was negative 84 percent in 2020.
In the three years ended December 31, 2020, our reserve replacement was 59 percent, primarily
impacted by lower prices in 2020. Our organic reserve replacement during the three years ended
December 31, 2020, which excluded a net increase of 89 MMBOE related to sales and purchases, was
53 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 replace our production over subsequent years.
43
●
Apply technical capability. We leverage our knowledge and technology to create value and safely
deliver on our plans. Technical strength is part of our heritage and allows us to economically convert
additional resources to reserves, achieve greater operating efficiencies and reduce our environmental
impact. Companywide, we continue to leverage knowledge of technological successes across our
operations.
We have embraced the digital transformation and are using digital innovations to work and operate
more efficiently. Predictive analytics have been adopted in our operations and planning process.
Artificial intelligence, machine learning and deep learning are being used for emissions monitoring,
seismic advancements and advanced controls in our field operations.
●
Attract, develop and retain a talented work force. We strive to attract, develop and retain individuals
with the knowledge and skills to successfully execute our business strategy in a manner exemplifying
our core values and ethics. We offer university internships across multiple disciplines to attract the
best early career talent. We also recruit experienced hires to fill critical skills and maintain a broad
range of expertise and experience. We promote continued learning, development and technical
training through structured development programs designed to enhance the technical and functional
skills of our employees.
Other Factors Affecting Profitability
Other significant factors that can affect our profitability include:
●
Energy commodity prices. Our earnings and operating cash flows generally correlate with industry
price levels for crude oil and natural gas. Industry 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
and other producing countries, environmental laws, tax regulations, governmental policies 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:
Brent crude oil prices averaged $41.68 per barrel in 2020, a decrease of 35 percent compared with
$64.30 per barrel in 2019. Similarly, WTI crude oil prices decreased 31 percent from $57.02 per
barrel in 2019 to $39.37 per barrel in 2020. Crude oil prices were lower due to the dual demand and
supply shocks. The demand shock was triggered by the COVID-19 pandemic, which continues to
have unprecedented social and economic consequences. The supply shock was triggered by
44
disagreements between OPEC and Russia, beginning in early March 2020, which resulted in
significant supply coming onto the market and created higher inventory levels.
Henry Hub natural gas prices decreased 21 percent from an average of $2.63 per MMBTU in 2019 to
$2.08 per MMBTU in 2020. Henry Hub prices were depressed due to high storage levels and weak
demand.
Our realized bitumen price decreased 75 percent from an average of $31.72 per barrel in 2019 to $8.02
per barrel in 2020. The decrease was largely driven by weakness in WTI, reflective of impacts from
the COVID-19 pandemic. The WCS differential to WTI at Hardisty remained fairly flat as
curtailment orders imposed by the Alberta Government, which limited production from the province,
continued throughout 2020. 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 decreased 34 percent from $48.78
per BOE in 2019 to
$32.15
per BOE in 2020 primarily due to lower 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.
●
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, or a decision to dispose of an asset leads to a write-down
to its fair value. We may also invest large amounts of money in exploration which, if exploratory
drilling proves unsuccessful, could lead to a material impairment of leasehold values. 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 additional information on our impairments,
see Note 7—Suspended Wells and Exploration Expenses and Note 8—Impairments, in the Notes to
Consolidated Financial Statements.
●
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 the U.S. Civil
unrest or strained relationships with governments 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.
45
Outlook
Production and Capital
In February 2021, we announced 2021 operating plan capital for the combined company of $5.5 billion. The
plan includes $5.1 billion to sustain current production and $0.4 billion for investment in major projects,
primarily in Alaska, in addition to ongoing exploration appraisal activity.
The operating plan capital budget of $5.5 billion is expected to deliver production from the combined company
of approximately 1.5 MMBOED in 2021. This production guidance excludes Libya.
Restructuring
As a result of the acquisition of Concho, we commenced a restructuring program in the first quarter of 2021 in
association with combining the operations of the two companies. We expect to incur significant non-recurring
transaction and acquisition-related costs in 2021 for employee severance payments; incremental pension
benefit costs related to the workforce reductions; employee retention costs; employee relocations; fees paid to
financial, legal, and accounting advisors; and filing fees. We currently cannot estimate these costs, as well as
other unanticipated items, and expect to recognize the majority of these expenses in the first quarter of 2021.
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.
46
RESULTS OF OPERATIONS
Effective with the third quarter of 2020, we have restructured our segments to align with changes to our
internal organization. The Middle East business was realigned from the Asia Pacific and Middle East segment
to the Europe and North Africa segment. The segments have been renamed the Asia Pacific segment and the
Europe, Middle East and North Africa segment. We have revised segment information disclosures and
segment performance metrics presented within our results of operations for the current and prior years.
This section of the Form 10-K discusses year-to-year comparisons between 2020 and 2019. For discussion of
year-to-year comparisons between 2019 and 2018, see "Management's Discussion and Analysis of Financial
Condition and Results of Operations" in Exhibit 99.1
—
, Item 7 filed with our Form 8-K filed on November 16,
2020.
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
2020
2019
2018
Alaska
$
(719)
1,520
1,814
Lower 48
(1,122)
436
1,747
Canada
(326)
279
63
Europe, Middle East and North Africa
448
3,170
2,594
Asia Pacific
962
1,483
1,342
Other International
(64)
263
364
Corporate and Other
(1,880)
38
(1,667)
Net income (loss) attributable to ConocoPhillips
$
(2,701)
7,189
6,257
2020 vs. 2019
Net income (loss) attributable to ConocoPhillips decreased $9.9 billion in 2020. The decrease was mainly due
to:
●
Lower realized commodity prices.
●
Lower sales volumes due to normal field decline, asset dispositions and production curtailments. For
additional information related to dispositions, see Note 4—Asset Acquisitions and Dispositions in the
Notes to Consolidated Financial Statements.
●
The absence of a $2.1 billion after-tax gain associated with the completion of the sale of two
ConocoPhillips U.K. subsidiaries. For additional information, see Note 4—Asset Acquisitions and
Dispositions in the Notes to Consolidated Financial Statements.
●
An unrealized loss of $855 million after-tax on our Cenovus Energy (CVE) common shares in 2020,
as compared to a $649 million after-tax unrealized gain on those shares in 2019.
●
A $648 million after-tax impairment for the associated carrying value of capitalized undeveloped
leasehold costs and an equity method investment related to our Alaska North Slope Gas asset. For
additional information, see Note 7—Suspended Wells and Exploration Expenses, in the Notes to
Consolidated Financial Statements.
●
Increased impairments
primarily related to developed properties in our non-core assets which were
written down to fair value due to lower commodity prices and development plan changes. For
additional information, see Note 8—Impairments and Note 14—Fair Value Measurement in the Notes
to Consolidated Financial Statements.
●
The absence of other income of $317 million after-tax related to our settlement agreement with
PDVSA.
47
These decreases in net income (loss) were partly offset by:
●
Lower production and operating expenses, primarily due to the absence of costs related to our U.K.
and Australia-West divestitures and decreased wellwork and transportation costs resulting from
production curtailments across our North American operated assets.
●
A $597 million after-tax gain on dispositions related to our Australia-West divestiture.
●
Lower DD&A expenses, primarily due to lower volumes related to normal field decline and
production curtailments as well as impacts of our Australia-West and U.K. divestitures. Partly
offsetting this decrease, was higher DD&A expenses due to price-related downward reserve revisions.
Income Statement Analysis
2020 vs. 2019
Sales and other operating revenues decreased 42 percent in 2020, mainly due to lower realized commodity
prices and lower sales volumes. Sales volumes decreased due to normal field decline, production curtailments
from our North American operated assets and the divestiture of our U.K. assets in the third quarter of 2019 and
our Australia-West assets in the second quarter of 2020.
Equity in earnings of affiliates decreased $347 million in 2020, primarily due to lower earnings from QG3 and
APLNG because of lower LNG prices. Partly offsetting this decrease was the absence of impairments related
to equity method investments in our Lower 48 segment of $155 million and the absence of a $118 million
deferred tax adjustment at QG3, reported in our Europe, Middle East and North Africa segment.
Gain on dispositions decreased $1.4 billion in 2020, primarily due to the absence of a $1.7 billion before-tax
gain associated with the completion of the sale of two ConocoPhillips U.K. subsidiaries. Partly offsetting the
decrease was a $587 million before-tax gain associated with our Australia-West divestiture. For more
information related to these dispositions, see Note 4—Asset Acquisitions and Dispositions in the Notes to
Consolidated Financial Statements.
Other income (loss) decreased $1.9 billion in 2020, primarily due to a before-tax unrealized loss of $855
million on our CVE common shares in 2020, and the absence of a $649 million before-tax unrealized gain on
those shares in 2019. Additionally, other income (loss) decreased due to the absence of $325 million before-
tax related to our settlement agreement with PDVSA.
For discussion of our CVE shares, see Note 6—Investment in Cenovus Energy in the Notes to Consolidated
Financial Statements. For discussion of our PDVSA settlement, see Note 12—Contingencies and
Commitments in the Notes to Consolidated Financial Statements.
Purchased commodities decreased 32 percent in 2020, primarily due to lower natural gas and crude oil prices;
lower crude oil and natural gas volumes purchased; and the divestiture of our U.K. assets in the third quarter of
2019 and our Australia-West assets in the second quarter of 2020.
Production and operating expenses decreased $978 million in 2020, primarily due to reduced activities and
transportation costs associated with lower activity across our North American operated assets in response to
the low commodity price environment and the absence of costs related to our U.K. and Australia-West
divestitures.
Selling, general and administrative expenses decreased $126 million in 2020, primarily due to lower costs
associated with compensation and benefits, including mark to market impacts of certain key employee
compensation programs.
48
Exploration expenses increased $714 million in 2020, primarily due to an $828 million before-tax impairment
for the entire carrying value of capitalized undeveloped leasehold costs related to our Alaska North Slope Gas
asset. Partly offsetting this increase, was the absence of a $141 million before-tax leasehold impairment
expense due to our decision to discontinue exploration activities in the Central Louisiana Austin Chalk trend.
For additional information, see Note 7—Suspended Wells and Exploration Expenses, in the Notes to
Consolidated Financial Statements.
Impairments increased $408 million in 2020, primarily related to developed properties in our non-core assets
which were written down to fair value due to lower commodity prices and development plan changes. For
additional information, see Note 8—Impairments and Note 14—Fair Value Measurement in the Notes to
Consolidated Financial Statements.
Taxes other than income taxes decreased $199 million in 2020, primarily due to lower commodity prices and
volumes.
Foreign currency transaction (gains) losses decreased $138 million in 2020, due to gains recognized from
foreign currency derivatives and other foreign currency remeasurements. For additional information, see Note
13—Derivative and Financial Instruments in the Notes to Consolidated Financial Statements.
See Note 18—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our
income tax provision (benefit) and effective tax rate.
49
Summary Operating Statistics
2020
2019
2018
Average Net Production
Crude oil (MBD)
Consolidated Operations
555
692
639
Equity affiliates
13
13
14
Total crude oil
568
705
653
Natural gas liquids (MBD)
Consolidated Operations
97
107
95
Equity affiliates
8
8
7
Total natural gas liquids
105
115
102
Bitumen (MBD)
55
60
66
Natural gas (MMCFD)
Consolidated Operations
1,339
1,753
1,743
Equity affiliates
1,055
1,052
1,031
Total natural gas
2,394
2,805
2,774
Total Production
1,127
1,348
1,283
Dollars Per Unit
Average Sales Prices
Crude oil (per bbl)
Consolidated Operations
$
39.56
60.98
68.03
Equity affiliates
39.02
61.32
72.49
Total crude oil
39.54
60.99
68.13
Natural gas liquids (per bbl)
Consolidated Operations
12.90
18.73
29.03
Equity affiliates
32.69
36.70
45.69
Total natural gas liquids
14.61
20.09
30.48
Bitumen (per bbl)
8.02
31.72
22.29
Natural gas (per mcf)
Consolidated Operations
3.17
4.25
5.40
Equity affiliates
3.71
6.29
6.06
Total natural gas
3.41
5.03
5.65
Millions of Dollars
Worldwide Exploration Expenses
General and administrative; geological and geophysical,
lease rental, and other
$
374
322
274
Leasehold impairment
868
221
56
Dry holes
215
200
39
$
1,457
743
369
50
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on a worldwide
basis. At December 31, 2020, our operations were producing in the U.S., Norway, Canada, Australia,
Indonesia, China, Malaysia, Qatar and Libya.
2020 vs. 2019
Total production, including Libya, of 1,127 MBOED decreased 221 MBOED or 16 percent in 2020 compared
with 2019, primarily due to:
●
Normal field decline.
●
The divestiture of our U.K. assets in the third quarter of 2019 and our Australia-West assets in the
second quarter of 2020.
●
Production curtailments of approximately 80 MBOED, primarily from North American operated
assets and Malaysia, in response to the low crude oil price environment.
●
Less production in Libya due to the forced shutdown of the Es Sider export terminal and other eastern
export terminals after a period of civil unrest.
The decrease in production during 2020 was partly offset by:
●
New wells online in the Lower 48, Canada, Norway, Alaska and China.
Production excluding Libya for 2020 was 1,118 MBOED. Adjusting for estimated curtailments of
approximately 80 MBOED and closed acquisitions and dispositions, production for 2020 would have been
1,176 MBOED, a decrease of 15 MBOED compared with 2019. This decrease was primarily due to normal
field decline, partly offset by new wells online in the Lower 48, Canada, Norway, Alaska and China.
Production from Libya averaged 9 MBOED as it was in force majeure during a significant portion of the year.
51
Alaska
2020
2019
2018
Net Income (Loss) Attributable to ConocoPhillips
$
(719)
1,520
1,814
Average Net Production
Crude oil (MBD)
181
202
171
Natural gas liquids (MBD)
16
15
14
Natural gas (MMCFD)
10
7
6
Total Production
198
218
186
Average Sales Prices
Crude oil ($ per bbl)
$
42.12
64.12
70.86
Natural gas ($ per mcf)
2.91
3.19
2.48
The Alaska segment primarily explores for, produces, transports and markets crude oil, NGLs and natural gas.
In 2020, Alaska contributed 28 percent of our consolidated liquids production and less than 1 percent of our
consolidated natural gas production.
2020 vs. 2019
Net Income (Loss) Attributable to ConocoPhillips
Alaska reported a loss of $719 million in 2020, compared with earnings of $1,520 million in 2019. Earnings
were negatively impacted by:
●
Lower realized crude oil prices.
●
A $648 million after-tax impairment associated with the carrying value of our Alaska North Slope Gas
assets. For additional information, see Note 7—Suspended Wells and Exploration Expenses, in the
Notes to Consolidated Financial Statements.
●
Lower sales volumes, primarily due to normal field decline and production curtailments at our
operated assets on the North Slope—the Greater Kuparuk Area (GKA) and Western North Slope
(WNS).
●
Higher DD&A expenses, primarily from increased DD&A rates due to price-related downward
reserve revisions, partly offset by lower production volumes.
●
Increased exploration expenses, primarily due to higher dry hole costs and expenses related to the
early cancellation of our winter exploration program.
Earnings were positively impacted by:
●
Lower production and operating expenses, primarily associated with lower transportation and
terminaling costs as well as lower activities across our assets.
Production
Average production decreased 20 MBOED in 2020 compared with 2019, primarily due to:
●
Normal field decline.
●
Production curtailments at our operated assets on the North Slope—GKA and WNS—of 8 MBOED
in response to the low crude oil price environment.
These production decreases were partly offset by:
●
Lower downtime due to the absence of planned turnarounds at the Greater Prudhoe Area.
●
New wells online at our operated assets on the North Slope—GKA and WNS.
52
Lower 48
2020
2019
2018
Net Income (Loss) Attributable to ConocoPhillips
$
(1,122)
436
1,747
Average Net Production
Crude oil (MBD)
213
266
229
Natural gas liquids (MBD)
74
81
69
Natural gas (MMCFD)
585
622
596
Total Production
385
451
397
Average Sales Prices
Crude oil ($ per bbl)
$
35.17
55.30
62.99
Natural gas liquids ($ per bbl)
12.13
16.83
27.30
Natural gas ($ per mcf)
1.65
2.12
2.82
The Lower 48 segment consists of operations located in the contiguous U.S. and the Gulf of Mexico. During
2020, the Lower 48 contributed 40 percent of our consolidated liquids production and 44 percent of our
consolidated natural gas production.
2020 vs. 2019
Net Income (Loss) Attributable to ConocoPhillips
Lower 48 reported a loss of $1,122 million in 2020, compared with earnings of $436 million in 2019.
Earnings were negatively impacted by:
●
Lower realized crude oil, NGL and natural gas prices.
●
Lower crude oil sales volumes due to normal field decline and production curtailments.
●
Higher impairments, primarily related to developed properties in our non-core assets which were
written down to fair value due to lower commodity prices and development plan changes. See Note
8—Impairments and Note 14—Fair Value Measurement, for additional information.
Earnings were positively impacted by:
●
Lower exploration expenses, primarily due to the absence of a combined $197 million after-tax of
leasehold impairment and dry hole costs associated with our decision to discontinue exploration
activities in the Central Louisiana Austin Chalk.
●
Lower DD&A expenses, primarily due to normal field decline and production curtailments, partly
offset by increased DD&A rates due to price-related downward reserve revisions.
●
Lower production and operating expenses, primarily due to lower activities driven by production
curtailments in response to the low price environment and disposition impacts.
●
Lower taxes other than income taxes, primarily due to lower realized prices and volumes.
Production
Total average production decreased 66 MBOED in 2020 compared with 2019, primarily due to:
●
Normal field decline.
●
Production curtailments of approximately 55 MBOED in response to the low crude oil price
environment.
These production decreases were partly offset by:
●
New wells online from the Eagle Ford, Permian and Bakken.
53
Canada
2020*
2019**
2018**
Net Income (Loss) Attributable to ConocoPhillips
(millions of dollars)
$
(326)
279
63
Average Net Production
Crude oil (MBD)
6
1
1
Natural gas liquids (MBD)
2
-
1
Bitumen (MBD)
55
60
66
Natural gas (MMCFD)
40
9
12
Total Production
70
63
70
Average Sales Prices
Crude oil ($ per bbl)
$
23.57
40.87
48.73
Natural gas liquids ($ per bbl)
5.41
19.87
43.70
Bitumen ($ per bbl)
8.02
31.72
22.29
Natural gas ($ per mcf)
1.21
0.49
1.00
**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 2020, Canada contributed 9 percent of our consolidated
liquids production and 3 percent of our consolidated natural gas production.
2020 vs. 2019
Net Income (Loss) Attributable to ConocoPhillips
Canada operations reported a loss of $326 million in 2020 compared with earnings of $279 million in 2019.
Earnings decreased mainly due to:
●
Lower realized bitumen prices.
●
Higher DD&A expenses, primarily due to increased volumes and DD&A rates from Montney production.
●
Lower bitumen sales due to production curtailments at Surmont.
Earnings were positively impacted by:
●
Increased Montney production from Pad 1 & 2 wells online and partial year production from the Kelt
acquisition completed in August of 2020.
Production
Total average production increased 7 MBOED in 2020 compared with 2019. The production increase was
primarily due to:
●
Increased liquids and natural gas production from Montney Pad 1 & 2 wells online and partial year
production from the Kelt acquisition completed in August of 2020.
●
Decreased mandated production curtailments imposed by the Alberta government.
The production increase was partly offset by:
●
Lower bitumen production, primarily due to voluntary curtailments at Surmont in response to the low price
environment of 12 MBOED.
54
Europe, Middle East and North Africa
2020
2019*
2018*
Net Income Attributable to ConocoPhillips
$
448
3,170
2,594
Consolidated Operations
Average Net Production
Crude oil (MBD)
86
138
149
Natural gas liquids (MBD)
4
7
8
Natural gas (MMCFD)
275
478
503
Total Production
136
224
241
Average Sales Prices
Crude oil ($ per bbl)
$
43.30
64.94
70.71
Natural gas liquids ($ per bbl)
23.27
29.37
36.87
Natural gas ($ per mcf)
3.23
4.92
7.65
*Prior periods have been updated to reflect the Middle East Business Unit moving from Asia Pacific to the Europe, Middle East and North Africa
segment. See Note 24—Segment Disclosures and Related Information in the Notes to Consolidated Financial Statements for additional
information.
The Europe, Middle East and North Africa segment consists of operations principally located in the Norwegian
sector of the North Sea; the Norwegian Sea; Qatar; Libya; and commercial and terminalling operations in the
U.K. In 2020, our Europe, Middle East and North Africa operations contributed 13 percent of our consolidated
liquids production and 20 percent of our consolidated natural gas production.
2020 vs. 2019
Net Income Attributable to ConocoPhillips
Earnings for Europe, Middle East and North Africa operations of $448 million decreased $2,722 million in
2020 compared with 2019. The decrease in earnings was primarily due to:
●
The absence of a $2.1 billion after-tax gain associated with the completion of the sale of two
ConocoPhillips U.K. subsidiaries. For additional information, see Note 4—Asset Acquisitions and
Dispositions in the Notes to Consolidated Financial Statements.
●
Lower equity in earnings of affiliates, primarily due to lower LNG sales prices.
●
Lower realized crude oil prices in Norway.
In the fourth quarter of 2020, the effective tax rate within our equity method investment in the Europe, Middle
East and North Africa segment increased.
Consolidated Production
Average consolidated production decreased 88 MBOED in 2020, compared with 2019. The decrease was
mainly due to:
●
The absence of production related to our U.K. disposition in the third quarter of 2019.
●
Lower volumes from Libya due to a cessation of production following a period of civil unrest.
●
Normal field decline.
These production decreases were partly offset by:
●
New wells online in Norway.
55
Asia Pacific
2020
2019*
2018*
Net Income Attributable to ConocoPhillips
(millions of dollars)
$
962
1,483
1,342
Consolidated Operations
Average Net Production
Crude oil (MBD)
69
85
89
Natural gas liquids (MBD)
1
4
3
Natural gas (MMCFD)
429
637
626
Total Production
141
196
196
Average Sales Prices
Crude oil ($ per bbl)
$
42.84
65.02
70.93
Natural gas liquids ($ per bbl)
33.21
37.85
47.20
Natural gas ($ per mcf)
5.39
5.91
6.15
*Prior periods have been updated to reflect the Middle East Business Unit moving from Asia Pacific to the Europe, Middle East and North Africa
segment. See Note 24—Segment Disclosures and Related Information in the Notes to Consolidated Financial Statements for additional
information.
The Asia Pacific segment has operations in China, Indonesia, Malaysia and Australia. During 2020, Asia Pacific
contributed 10 percent of our consolidated liquids production and 32 percent of our consolidated natural gas
production.
2020 vs. 2019
Net Income Attributable to ConocoPhillips
Asia Pacific reported earnings of $962 million in 2020, compared with $1,483 million in 2019. The decrease in
earnings was mainly due to:
●
Lower sales volumes, primarily from lower LNG sales due to the Australia-West divestiture; lower
crude oil sales volumes in Malaysia, primarily due to production curtailments; and lower crude oil sales
volumes in China due to the expiration of the Panyu production license. For more information related to
our Australia-West divestiture, see Note 4—Asset Acquisitions and Dispositions in the Notes to
Consolidated Financial Statements.
●
Lower realized commodity prices.
●
Lower equity in earnings of affiliates from APLNG, mainly due to lower LNG sales prices.
●
The absence of a $164 million income tax benefit related to deepwater incentive tax credits from the
Malaysia Block G.
Earnings were positively impacted by:
●
A $597 million after-tax gain on disposition related to our Australia-West divestiture.
Consolidated Production
Average consolidated production decreased 28 percent in 2020, compared with 2019. The decrease was
primarily due to:
●
The divestiture of our Australia-West assets.
●
Normal field decline.
●
Higher unplanned downtime due to the rupture of a third-party pipeline impacting gas production from
the Kebabangan Field in Malaysia.
●
The expiration of the Panyu production license in China.
●
Production curtailments of 4 MBOED in Malaysia.
56
These production decreases were partly offset by:
●
Development activity at Bohai Bay in China and Gumusut in Malaysia.
Other International
2020
2019
2018
Net Income (Loss) Attributable to ConocoPhillips
(millions of dollars)
$
(64)
263
364
The Other International segment includes exploration activities in Colombia and Argentina and 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.
2020 vs. 2019
Other International operations reported a loss of $64 million in 2020, compared with earnings of $263 million
in 2019. The decrease in earnings was primarily due to:
●
The absence of $317 million after-tax in other income from a settlement award with PDVSA
associated with prior operations in Venezuela. For additional information related to this settlement
award, see Note 12—Contingencies and Commitments, in the Notes to Consolidated Financial
Statements.
●
Increased exploration expenses, primarily due to dry hole costs and a full impairment of capitalized
undeveloped leasehold costs in Colombia.
57
Corporate and Other
Millions of Dollars
2020
2019
2018
Net Income (Loss) Attributable to ConocoPhillips
Net interest
$
(662)
(604)
(680)
Corporate general and administrative expenses
(200)
(252)
(91)
Technology
(26)
123
109
Other
(992)
771
(1,005)
$
(1,880)
38
(1,667)
2020 vs. 2019
Net interest consists of interest and financing expense, net of interest income and capitalized interest. Net
interest expense increased $58 million in 2020 compared with 2019, primarily due to lower interest income
related to lower cash and cash equivalent balances and yield.
Corporate G&A expenses include compensation programs and staff costs. These costs decreased by $52
million in 2020 compared with 2019, primarily due to 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 and LNG. Earnings from Technology decreased by $149 million in 2020 compared with 2019,
primarily due to lower 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, unrealized holding gains or losses on equity securities, and
pension settlement expense. Earnings in “Other” decreased by $1,763 million in 2020 compared with 2019,
primarily due to:
●
An unrealized loss of $855 million after-tax on our CVE common shares in 2020, compared with a
$649 million after-tax unrealized gain in 2019.
●
The absence of a $151 million tax benefit related to the revaluation of deferred tax assets following
finalization of rules related to the 2017 Tax Cuts and Jobs Act. See Note 18—Income Taxes, in the
Notes to Consolidated Financial Statements, for additional information related to the 2017 Tax Cuts
and Jobs Act.
58
CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
Millions of Dollars
Except as Indicated
2020
2019
2018
Net cash provided by operating activities
$
4,802
11,104
12,934
Cash and cash equivalents
2,991
5,088
5,915
Short-term investments
3,609
3,028
248
Short-term debt
619
105
112
Total debt
15,369
14,895
14,968
Total equity
29,849
35,050
32,064
Percent of total debt to capital*
34
%
30
32
Percent of floating-rate debt to total debt
7
%
5
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 2020, the primary uses of
our available cash were $4,715 million to support our ongoing capital expenditures and investments program;
$1,831 million to pay dividends on our common stock; $892 million to repurchase our common stock; and
$658 million for net purchase of investments. During 2020, cash and cash equivalents decreased by $2,097
million to $2,991 million.
We entered the year with a strong balance sheet including cash and cash equivalents of over $5 billion, short-
term investments of $3 billion, and an undrawn credit facility of $6 billion, totaling approximately $14 billion
in available liquidity. This strong foundation allowed us to be measured in our response to the sudden change
in business environment as we exited the first quarter of 2020. In response to the oil market downturn that
began in early 2020, we announced the following capital, share repurchase and operating cost reductions. We
reduced our 2020 operating plan capital expenditures by a total of $2.3 billion, or approximately thirty-five
percent of the original guidance. We suspended our share repurchase program, further reducing cash outlays
by approximately $2 billion. We also reduced our operating costs by approximately $0.6 billion, or roughly
ten percent of the original 2020 guidance. Collectively, these actions represent a reduction in 2020 cash uses of
approximately $5 billion versus the original operating plan.
Considering the weakness in oil prices during the second quarter of 2020, we established a framework for
evaluating and implementing economic curtailments, which resulted in taking an additional significant step of
curtailing production, predominantly from operated North American assets. Due to our strong balance sheet,
we were in an advantaged position to forgo some production and cash flow in anticipation of receiving higher
cash flows for those volumes in the future. Based on our economic criteria, we began restoring production
from voluntary curtailments in July, and with oil prices stabilizing around $40 per barrel, we ended our
curtailment program by the end of the third quarter.
In the fourth quarter of 2020, we resumed share repurchases, repurchasing $0.2 billion of shares in October,
before suspending our share repurchase program upon entry into a definitive agreement to acquire Concho.
We resumed share repurchases in February 2021 after completion of our Concho acquisition.
As of December 31, 2020, we had cash and cash equivalents of $3.0 billion, short-term investments of $3.6
billion, and available borrowing capacity under our credit facility of $5.7 billion, totaling over $12 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.
59
Significant Changes in Capital
Operating Activities
During 2020, cash provided by operating activities was $4,802 million, a 57 percent decrease from 2019. The
decrease was primarily due to lower realized commodity prices, normal field decline, production curtailments,
the divestiture of our U.K. and Australia-West assets, and the absence in 2020 of collections under our
settlement agreement with PDVSA, partially offset by lower production and operating expenses.
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 1,127 MBOED in 2020. Full-year production excluding Libya averaged 1,118
MBOED in 2020. Adjusting for estimated curtailments of approximately 80 MBOED; closed acquisitions and
dispositions; and excluding Libya; production for 2020 was 1,176 MBOED. Production in 2021 is expected to
be approximately 1.5 MMBOED, reflecting the impact from the Concho acquisition. 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; 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, as shown in our supplemental reserve table disclosures. Our reserve replacement was negative 86
percent in 2020, reflecting the impact of lower prices, which reduced reserves by approximately 600 MMBOE.
Our organic reserve replacement, which excluded a net decrease of 7 MMBOE from sales and purchases, was
negative 84 percent in 2020.
In the three years ended December 31, 2020, our reserve replacement was 59 percent, reflecting the impact of
lower prices in 2020. Our organic reserve replacement during the three years ended December 31, 2020,
which excluded a net increase of 89 MMBOE related to sales and purchases, was 53 percent.
For additional information about our 2021 capital budget, see the “2021 Capital Budget” section within
“Capital Resources and Liquidity” and for additional information on proved reserves, including both
developed and undeveloped reserves, see the “Oil and Gas Operations” section of this report.
As discussed in the “Critical Accounting Estimates” section, engineering estimates of proved reserves are
imprecise; therefore, each year reserves may be revised upward or downward 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 reserve quantities in the future.
Investing Activities
In 2020, we invested $4.7 billion in capital expenditures, of which $0.5 billion consisted of strategic
acquisitions, including additional Montney acreage. Capital expenditures invested in 2019 and 2018 were $6.6
billion and $6.8 billion, respectively. For information about our capital expenditures and investments, see the
“Capital Expenditures and Investments” section.
60
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 price downturns and to capture opportunities outside a given operating plan may be invested in
instruments with maturities greater than one year. For additional information, see Note 1–Accounting Policies
and Note 13–Derivative and Financial Instruments, in the Notes to Consolidated Financial Statements.
Investing activities in 2020 included net purchases of $658 million of investments, of which $420 million was
invested in short-term instruments and $238 million was invested in long-term instruments. Investing
activities in 2019 included net purchases of $2.9 billion of investments, of which $2.8 billion was invested in
short-term instruments and $0.1 billion was invested in long-term instruments. For additional information, see
Note 13—Derivative and Financial Instruments, in the Notes to Consolidated Financial Statements.
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, with another $200 million payment due upon final
investment decision of the proposed Barossa development project. We also received proceeds of $359 million
and $184 million for 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.
Proceeds from assets sales in 2018 were $1.1 billion, including several non-core assets in the Lower 48, as
well as the sale of a ConocoPhillips subsidiary which held 16.5 percent of our 24 percent interest in the Clair
Field in the U.K. For additional information on our dispositions, see Note 4—Asset Acquisitions and
Dispositions in the Notes to Consolidated Financial Statements.
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 the 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 $300 million of commercial paper outstanding and no
direct borrowings or letters of credit, we had $5.7 billion in available borrowing capacity under the revolving
credit facility at December 31, 2020. We may consider issuing additional commercial paper in the future to
supplement our cash position.
In October 2020, Moody’s affirmed its rating of our senior long-term debt of “A3” with a “stable” outlook, and
affirmed its rating of our short-term debt as “Prime-2.” In January 2021, Fitch affirmed its rating of our long-
term debt as “A” with a “stable” outlook and affirmed its rating of our short-term debt as “F1+.” On January
25, 2021, S&P revised the industry risk assessment for the E&P industry to ‘Moderately High’ from
61
‘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 downgraded its rating of our short-term debt from “A-1” to “A-2.” 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, 2020 and 2019, we had direct bank letters of credit of $249 million
and $277 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.
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. On December 7, 2020, we launched an offer to exchange
Concho’s publicly traded debt for debt issued by ConocoPhillips. The exchange offer settled on February 8,
2021. Of the approximately $3.9 billion in aggregate principal amount of Concho’s notes subject to the
exchange offer, 98 percent, or approximately $3.8 billion, was tendered and exchanged for new debt issued by
ConocoPhillips. There were no impacts to ConocoPhillips’ credit ratings as a result of the debt exchange. For
additional information, see Note 10—Debt and Note 25—Acquisition of Concho Resources Inc., in the Notes
to Consolidated Financial Statements.
Shelf Registration
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.
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.
In March of 2020, the SEC adopted amendments to simplify the financial disclosure requirements for
guarantors and issuers of guaranteed securities registered under Rule 3-10 of Regulation S-X. Based on our
evaluation of our existing guarantee relationships, we qualify for the transition to alternative disclosures. We
elected early voluntary compliance with the final amendments beginning in the third quarter of 2020.
Accordingly, condensed consolidating information by guarantor and issuer of guaranteed securities will no
longer be reported, and alternative disclosures of summarized financial information for the consolidated
Obligor Group is presented. 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.
62
●
Non-Obligated Subsidiaries are excluded from this presentation.
Transactions and balances reflecting activity between the Obligors and Non-Obligated Subsidiaries are
presented separately below:
Summarized Income Statement Data
Millions of Dollars
2020
Revenues and Other Income
$
8,375
Income (loss) before income taxes
(2,999)
Net income (loss)
(2,701)
Net Income (Loss) Attributable to ConocoPhillips
(2,701)
Summarized Balance Sheet Data
Millions of Dollars
December 31, 2020
Current assets
$
8,535
Amounts due from Non-Obligated Subsidiaries, current
440
Noncurrent assets
37,180
Amounts due from Non-Obligated Subsidiaries, noncurrent
7,730
Current liabilities
3,797
Amounts due to Non-Obligated Subsidiaries, current
1,365
Noncurrent liabilities
18,627
Amounts due to Non-Obligated Subsidiaries, noncurrent
3,972
Capital Requirements
For information about our capital expenditures and investments, see the “Capital Expenditures and
Investments” section.
Our debt balance at December 31, 2020, was $15,369 million, an increase of $474 million from the balance at
December 31, 2019. Maturities of debt (including payments for finance leases) due in 2021 of $601 million,
excluding net unamortized premiums and discounts, will be paid from current cash balances and cash
generated by operations. For more information on Debt, see Note 10—Debt, in the Notes to Consolidated
Financial Statements.
We believe in delivering value to our shareholders via a growing and sustainable dividend supplemented by
additional returns of capital, including share repurchases. In 2020, we paid $1,831 million, $1.69 per share of
common stock, in dividends. This is an increase over 2019 and 2018, when we paid $1.34 and $1.16 per share
of common stock, respectively. In February 2021, we announced a quarterly dividend of $0.43 per share,
payable March 1, 2021, to stockholders of record at the close of business on February 12, 2021.
In late 2016, we initiated our current share repurchase program, which has a current total program
authorization of $25 billion of our common stock. Cost of share repurchases were $892 million, $3,500
million and $2,999 million in 2020, 2019 and 2018, respectively. Share repurchases since inception of our
current program totaled 189 million shares at a cost of $10,517 million, as of December 31, 2020. In the
fourth quarter of 2020, we suspended share repurchases upon entry into a definitive agreement to acquire
Concho. We resumed share repurchases in February 2021 after the completion of our Concho acquisition.
Repurchases are made at management’s discretion, at prevailing prices, subject to market conditions and other
factors.
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Our dividend and share repurchase programs are subject to numerous considerations, including market
conditions, management discretion and other factors. See “Item 1A—Risk Factors
–
Our ability to declare and
pay dividends and repurchase shares is subject to certain considerations.”
In addition to the requirements above, we have contractual obligations for the purchase of goods and services
of approximately $8,123 million. We expect to fulfill $2,805 million of these obligations in 2021. These
figures exclude purchase commitments for jointly owned fields and facilities where we are not the operator.
Purchase obligations of $5,237 million 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 $2,290 million 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 Expenditures and Investments
Millions of Dollars
2020
2019
2018
Alaska
$
1,038
1,513
1,298
Lower 48
1,881
3,394
3,184
Canada
651
368
477
Europe, Middle East and North Africa
600
708
877
Asia Pacific
384
584
718
Other International
121
8
6
Corporate and Other
40
61
190
Capital Program
$
4,715
6,636
6,750
Our capital expenditures and investments for the three-year period ended December 31, 2020 totaled $18.1
billion. The 2020 expenditures supported key exploration and developments, primarily:
●
Development and appraisal in the Lower 48, including Eagle Ford, Permian, and Bakken.
●
Appraisal and development activities in Alaska related to the Western North Slope; development
activities in the Greater Kuparuk Area and the Greater Prudhoe Area.
●
Development and exploration activities across assets in Norway.
●
Appraisal activities in liquids-rich plays and optimization of oil sands development in Canada.
●
Continued development activities in China, Malaysia, and Indonesia.
●
Exploration activities in Argentina.
2021 CAPITAL BUDGET
In February 2021, we announced 2021 operating plan capital for the combined company of $5.5 billion. The
plan includes $5.1 billion to sustain current production and $0.4 billion for investment in major projects,
primarily in Alaska, in addition to ongoing exploration appraisal activity.
The operating plan capital budget of $5.5 billion is expected to deliver production from the combined company
of approximately 1.5 MMBOED in 2021. This production guidance excludes Libya.
For information on PUDs and the associated costs to develop these reserves, see the “Oil and Gas Operations”
section in this report.
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Contingencies
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.
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. For information on other contingencies, see “Critical Accounting
Estimates” and Note 12—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.
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 and
claims of alleged environmental contamination from historic operations. 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. See Note 18—Income Taxes, in the Notes to Consolidated Financial Statements, for
additional information about income tax-related contingencies.
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.
65
●
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.
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 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, 2020, there were 15 sites around the U.S. in which we were identified as a potentially
responsible party under CERCLA and comparable state laws.
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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 $393 million in 2020 and are expected to be about $435 million per year
in 2021 and 2022. Capitalized environmental costs were $161 million in 2020 and are expected to be about
$210 million per year in 2021 and 2022.
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, 2020, our balance sheet included total accrued environmental costs of $180 million,
compared with $171 million at December 31, 2019, 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.
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Climate Change
Continuing political and social attention to the issue of global climate change has resulted in a broad range of
proposed or promulgated state, national and international laws focusing on GHG reduction. These proposed or
promulgated laws apply or could apply in countries where we have interests or may have interests in the future.
Laws in this field continue to evolve, and while it is not possible to accurately estimate either a timetable for
implementation or our future compliance costs relating to implementation, such laws, if enacted, could have a
material impact on our results of operations and financial condition. Examples of legislation and precursors
for possible regulation that do or could affect our operations include:
●
European Emissions Trading Scheme (ETS), the program through which many of the EU member
states are implementing the Kyoto Protocol. Our cost of compliance with the EU ETS in 2020 was
approximately $7 million 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 2020 was
approximately $2 million.
●
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 established a goal of reducing the 2012 levels in methane emissions
from the oil and gas industry by 40 to 45 percent by 2025.
●
Carbon taxes in certain jurisdictions. Our cost of compliance with Norwegian carbon tax legislation
in 2020 was approximately $29 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 $3.5 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.
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.
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.
68
●
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.
Climate Change Litigation
Beginning in 2017, governmental and other entities in several states in the U.S. have filed lawsuits against oil
and gas companies, including ConocoPhillips, seeking compensatory damages and equitable relief to abate
alleged climate change impacts. Additional lawsuits with similar allegations are expected to be filed. The
amounts claimed by plaintiffs are unspecified and the legal and factual issues involved in these cases are
unprecedented. ConocoPhillips believes these lawsuits are factually and legally meritless and are an
inappropriate vehicle to address the challenges associated with climate change and will vigorously defend
against such lawsuits.
Several Louisiana parishes and the State of Louisiana have filed 43 lawsuits under Louisiana’s State and Local
Coastal Resources Management Act (SLCRMA) against oil and gas companies, including ConocoPhillips,
seeking compensatory damages for contamination and erosion of the Louisiana coastline allegedly caused by
historical oil and gas operations. ConocoPhillips entities are defendants in 22 of the lawsuits and will
vigorously defend against them. Because Plaintiffs’ SLCRMA theories are unprecedented, there is uncertainty
about these claims (both as to scope and damages) and any potential financial impact on the company.
Company Response to Climate-Related Risks
The company has responded by putting in place a Sustainable Development Risk Management Standard
covering the assessment and registering 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 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 own or control.
●
Scope 2 emissions are 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.
69
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. We have set a target to reduce our gross operated (scope 1 and 2) emissions
intensity by 35 to 45 percent from 2016 levels by 2030, 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 gas by 2030.
●
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.
●
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.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in conformity with GAAP requires management to select appropriate
accounting policies and to make estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses. See Note 1—Accounting Policies, in the Notes to Consolidated Financial
Statements, 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, along with the discussion of
deferred tax asset valuation allowances in this report, 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 exploratory 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
70
and gas reserves have been recognized.
Property Acquisition Costs
For individually significant leaseholds, management periodically assesses for impairment based on exploration
and drilling efforts to date. For relatively small 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 and pools that leasehold information with others in the geographic area. 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.
At year-end 2020, the remaining $2.4 billion of net capitalized unproved property costs consisted primarily of
individually significant leaseholds, mineral rights held in perpetuity by title ownership, exploratory wells
currently being drilled, suspended exploratory wells, and capitalized interest. Of this amount, approximately
$1.9 billion is concentrated in 10 major development areas, the majority of which are not expected to move to
proved properties in 2021. Management periodically assesses individually significant leaseholds for
impairment based on the results of exploration and drilling efforts and the outlook for commercialization.
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.
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. 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 a determination is made the well did not encounter potentially
economic oil and gas quantities, the well costs are expensed as a dry hole and reported in exploration expense.
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 a dry hole when it determines
the potential field does not warrant further investment in the near term. Criteria utilized in making this
determination include evaluation of the reservoir characteristics and hydrocarbon properties, expected
development costs, ability to apply existing technology to produce the reserves, fiscal terms, regulations or
contract negotiations, and our expected return on investment.
At year-end 2020, total suspended well costs were $682 million, compared with $1,020 million at year-end
2019. For additional information on suspended wells, including an aging analysis, see Note 7—Suspended
Wells and Exploration Expenses, in the Notes to Consolidated Financial Statements.
71
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.
Proved reserve estimates are adjusted annually in the fourth quarter and during the year if significant changes
occur, and take into account recent production and subsurface information about each field. Also, as required
by current authoritative guidelines, the estimated future date when an asset will reach the end of its economic
life is based on 12-month average prices and current costs. This date estimates when production will end and
affects the amount of estimated reserves. Therefore, as prices and cost levels change from year to year, the
estimate of proved reserves also changes. Generally, our proved reserves decrease as prices decline and
increase as prices rise.
Our proved reserves include estimated quantities related to PSCs, reported under the “economic interest”
method, as well as variable-royalty regimes, and are subject to fluctuations in commodity prices; recoverable
operating expenses; and capital costs. If costs remain stable, reserve quantities attributable to recovery of costs
will change inversely to changes in commodity prices. We would expect reserves from these contracts to
decrease when product prices rise and increase when prices decline.
The estimation of proved developed reserves also is important to the income statement because the proved
developed 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 2020, the net book value of productive PP&E
subject to a unit-of-production calculation was approximately $33 billion and the DD&A recorded on these
assets in 2020 was approximately $5.3 billion. The estimated proved developed reserves for our consolidated
operations were 3.2 billion BOE at the end of 2019 and 2.5 billion BOE at the end of 2020. 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 2020 would have increased by an estimated $588 million.
Impairments
Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances
indicate a possible significant deterioration in 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, upon review, 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 impairments 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
72
costs and capital decisions, considering all available information at the date of review. Differing assumptions
could affect the timing and the amount of an impairment in any period. See Note 8—Impairments, in the
Notes to Consolidated Financial Statements, for additional information.
Investments in nonconsolidated entities accounted for under the equity method are assessed for impairment
whenever changes in the facts and circumstances indicate a loss in value has occurred. Such evidence of a loss
in value might include our inability to recover the carrying amount, the lack of sustained earnings capacity
which would justify the current investment amount, or a current fair value less than the investment’s carrying
amount. When such a condition is judgmentally determined to be other than temporary, an impairment charge
is recognized for the difference between the investment’s carrying value and its estimated fair value. When
determining whether a decline in value is other than temporary, management considers factors such as the
length of time and extent of the decline, the investee’s financial condition and near-term prospects, and our
ability and intention to retain our investment for a period that will be sufficient to allow for any anticipated
recovery in the market value of the investment. Since quoted market prices are usually not available, the fair
value is typically based on the present value of expected future cash flows using discount rates and prices
believed to be consistent with those used by principal market participants, plus market analysis of comparable
assets owned by the investee, if appropriate. Differing assumptions could affect the timing and the amount of
an impairment of an investment in any period. See the “APLNG” section of Note 5—Investments, Loans and
Long-Term Receivables, in the Notes to Consolidated Financial Statements, for additional information.
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. The fair values
of obligations for dismantling and removing these facilities are recorded as a liability and an increase to PP&E
at the time of installation of the asset based on estimated discounted costs. Fair value is estimated using a
present value approach, incorporating assumptions about estimated amounts and timing of settlements and
impacts of the use of technologies. Estimating future asset removal costs requires significant judgement. Most
of these removal obligations are many years, or decades, in the future and the contracts and regulations often
have vague descriptions of what removal practices and criteria must be met when the removal event actually
occurs. The carrying value of our asset retirement obligation estimate is sensitive to inputs such as asset
removal technologies and costs, regulatory and other compliance considerations, expenditure timing, and other
inputs into valuation of the obligation, including discount and inflation rates, which are all subject to change
between the time of initial recognition of the liability and future settlement of our obligation.
Normally, changes in asset removal obligations are reflected in the income statement as increases or decreases
to DD&A over the remaining life of the assets. However, for assets at or nearing the end of their operations, as
well as previously sold assets for which we retained the asset removal obligation, an increase in the asset
removal obligation can result in an immediate charge to earnings, because any increase in PP&E due to the
increased obligation would immediately be subject to impairment, due to the low fair value of these properties.
In addition to asset removal obligations, under the above or similar contracts, permits and regulations, we have
certain environmental-related projects. These are primarily related to remediation activities required by
Canada and various states within the U.S. at exploration and production sites. Future environmental
remediation costs are difficult to estimate because they are subject to change due to such factors as the
uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be
required, and the determination of our liability in proportion to that of other responsible parties. See Note 9—
Asset Retirement Obligations and Accrued Environmental Costs, in the Notes to Consolidated Financial
Statements, for additional information.
73
Projected Benefit Obligations
Determination of the projected benefit obligations for our defined benefit pension and postretirement plans are
important to the recorded amounts for such obligations on the balance sheet and to the amount of benefit
expense in the income statement. 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. For Employee Retirement Income Security Act-
governed pension plans, the actuary exercises fiduciary care on behalf of plan participants in the determination
of the judgmental assumptions used in determining required company contributions into the plans. Due to
differing objectives and requirements between financial accounting rules and the pension plan funding
regulations promulgated by governmental agencies, the actuarial methods and assumptions for the two
purposes differ in certain important respects. 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
$1,200 million. 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
$110 million, while a 100 basis-point decrease in the return on plan assets assumption would increase annual
benefit expense by $80 million. In determining the discount rate, we use yields on high-quality fixed income
investments matched to the estimated benefit cash flows of our plans. We are also exposed to the possibility
that lump sum retirement benefits taken from pension plans during the year could exceed the total of service
and interest components of annual pension expense and trigger accelerated recognition of a portion of
unrecognized net actuarial losses and gains. These benefit payments are based on decisions by plan
participants and are therefore difficult to predict. In the event there is a significant reduction in the expected
years of future service of present employees or the elimination of the accrual of defined benefits for some or all
of their future services for a significant number of employees, we could recognize a curtailment gain or loss.
See Note 17—Employee Benefit Plans, in the Notes to Consolidated Financial Statements, for additional
information.
Contingencies
A number of claims and lawsuits are made against the company arising in the ordinary course of business.
Management exercises judgment related to accounting and disclosure of these claims which includes losses,
damages, and underpayments associated with environmental remediation, tax, contracts, and other legal
disputes. As we learn new facts concerning contingencies, we reassess our position both with respect to
amounts recognized and disclosed considering changes to the probability of additional losses and potential
exposure. However, actual losses can and do vary from estimates for a variety of reasons including legal,
arbitration, or other third-party decisions; settlement discussions; evaluation of scope of damages;
interpretation of regulatory or contractual terms; expected timing of future actions; and proportion of liability
shared with other responsible parties. Estimated future costs related to contingencies are subject to change as
events evolve and as additional information becomes available during the administrative and litigation
processes. For additional information on contingent liabilities, see the “Contingencies” section within “Capital
Resources and Liquidity” and Note 12—Contingencies and Commitments, in the Notes to Consolidated
Financial Statements.
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
74
will not be realized. In assessing the need for adjustments to existing valuation allowances, we consider all
available positive and negative evidence. Positive evidence includes reversals of temporary differences,
forecasts of future taxable income, assessment of future business assumptions and applicable tax planning
strategies that are prudent and feasible. Negative evidence includes losses in recent years as well as the
forecasts of future net income (loss) in the realizable period. In making our assessment regarding valuation
allowances, we weight the evidence based on objectivity. Numerous judgments and assumptions are inherent
in the determination of future taxable income, including factors such as future operating conditions and the
assessment of the effects of foreign taxes on our U.S. federal income taxes (particularly as related to prevailing
oil and gas prices). See Note 18—Income Taxes for additional information, in the Notes to Consolidated
Financial Statements.
We regularly assess and, if required, establish accruals for uncertain tax positions that could result from
assessments of additional tax by taxing jurisdictions in countries where we operate. We recognize a tax benefit
from an uncertain tax position when it is more likely than not that the position will be sustained upon
examination, based on the technical merits of the position. These accruals for uncertain tax positions are
subject to a significant amount of judgment and are reviewed and adjusted on a periodic basis in light of
changing facts and circumstances considering the progress of ongoing tax audits, court proceedings, changes in
applicable tax laws, including tax case rulings and legislative guidance, or expiration of the applicable statute
of limitations. See Note 18—Income Taxes for additional information, in the Notes to Consolidated Financial
Statements.
75
CAUTIONARY STATEMENT FOR THE PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of
1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of
historical fact included or incorporated by reference in this report, including, without limitation, statements
regarding our future financial position, business strategy, budgets, projected revenues, projected costs and
plans, objectives of management for future operations, the anticipated benefits of the transaction between us
and Concho, the anticipated impact of the transaction on the combined company’s business and future
financial and operating results, the expected amount and the timing of synergies from the transaction 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.
●
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.
●
Failure to complete definitive agreements and feasibility studies for, and to complete construction of,
76
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,
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 the potential for litigation related to the transaction with
Concho, 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.
●
Our inability to liquidate the common stock issued to us by Cenovus Energy as part of our sale of
certain assets in western Canada at prices we deem acceptable, or 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.
●
Our ability to successfully integrate Concho’s business.
●
The risk that the expected benefits and cost reductions associated with the transaction with Concho
may not be fully achieved in a timely manner, or at all.
●
The risk that we will be unable to retain and hire key personnel.
●
Unanticipated difficulties or expenditures relating to integration with Concho.
●
Uncertainty as to the long-term value of our common stock.
●
The diversion of management time on integration-related matters.
●
The factors generally described in Item 1A—Risk Factors in this 2020 Annual Report on Form 10-K
and any additional risks described in our other filings with the SEC.
77
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, 2020, 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, 2020 and 2019, was immaterial to our
consolidated cash flows and net income attributable to ConocoPhillips.
78
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 cashflows associated
with fixed rate debt, unless we elect to repurchase or retire such debt prior to maturity.
Millions of Dollars Except as Indicated
Debt
Fixed
Average
Floating
Average
Rate
Interest
Rate
Interest
Expected Maturity Date
Maturity
Rate
Maturity
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
Year -End 2019
2020
$
-
-
%
$
-
-
%
2021
140
6.24
-
-
2022
343
2.54
500
2.81
2023
106
7.20
-
-
2024
456
3.52
-
-
Remaining years
12,143
6.25
283
1.65
Total
$
13,188
$
783
Fair value
$
17,325
$
783
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, 2020 and 2019, 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, 2020, we had outstanding foreign currency exchange forward contracts to sell $0.45 billion
CAD at $0.748 CAD against the U.S. dollar. At December 31, 2019, we had outstanding foreign currency
exchange forward contracts to sell $1.35 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, 2020 and December 31, 2019, were a before-tax loss of $16 million and $28 million,
79
respectively. Based on an adverse hypothetical 10 percent change in the December 2020 and December 2019
exchange rate, this would result in an additional before-tax loss of $39 million and $115 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.
The gross notional and fair value of these positions at December 31, 2020 and 2019, were as follows:
In Millions
Foreign Currency Exchange Derivatives
Notional
Fair Value*
2020
2019
2020
2019
Sell Canadian dollar, buy U.S. dollar
CAD
450
1,350
(16)
(28)
Buy Canadian dollar, sell U.S. dollar
CAD
80
13
2
-
Sell British pound, buy euro
GBP
8
-
-
-
Buy British pound, sell euro
GBP
3
4
-
-
*Denominated in USD.
For additional information about our use of derivative instruments, see Note 13—Derivative and Financial
Instruments, in the Notes to Consolidated Financial Statements.
80
Item 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CONOCOPHILLIPS
INDEX TO FINANCIAL STATEMENTS
Page
Reports of Management ...........................................................................................................................
81
Reports of Independent Registered Public Accounting Firm .................................................................
82
Consolidated Income Statement for the years ended December 31, 2020, 2019 and 2018 ....................
86
Consolidated Statement of Comprehensive Income for the years ended
December 31, 2020, 2019 and 2018 ..................................................................................................
87
Consolidated Balance Sheet at December 31, 2020 and 2019 ................................................................
88
Consolidated Statement of Cash Flows for the years ended December 31, 2020, 2019 and 2018 .........
89
Consolidated Statement of Changes in Equity for the years ended
December 31, 2020, 2019 and 2018 ..................................................................................................
90
Notes to Consolidated Financial Statements ............................................................................................
91
Supplementary Information
Oil and Gas Operations ..............................................................................................................
151
81
Reports of Management
Management prepared, and is responsible for, the consolidated financial statements and the other information
appearing in this annual report. The consolidated financial statements present fairly the company’s financial
position, results of operations and cash flows in conformity with accounting principles generally accepted in
the United States. In preparing its consolidated financial statements, the company includes amounts that are
based on estimates and judgments management believes are reasonable under the circumstances. The
company’s financial statements have been audited by Ernst & Young LLP, an independent registered public
accounting firm appointed by the Audit and Finance Committee of the Board of Directors and ratified by
stockholders. Management has made available to Ernst & Young LLP all of the company’s financial records
and related data, as well as the minutes of stockholders’ and directors’ meetings.
Assessment of Internal Control Over Financial Reporting
Management is also responsible for establishing and maintaining adequate internal control over financial
reporting. ConocoPhillips’ internal control system was designed to provide reasonable assurance to the
company’s management and directors regarding the preparation and fair presentation of published financial
statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those
systems determined to be effective can provide only reasonable assurance with respect to financial statement
preparation and presentation.
Management assessed the effectiveness of the company’s internal control over financial reporting as of
December 31, 2020. 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, 2020.
Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of
December 31, 2020, 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
82
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, 2020 and 2019, 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, 2020, 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 at December 31, 2020 and 2019, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 2020, 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, 2020,
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 16, 2021,
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.
83
Accounting for asset retirement obligations for certain offshore properties
Description of
the Matter
At December 31, 2020, the asset retirement obligation (ARO) balance totaled $5.6
billion. As further described in Note 9, 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 certain obligations related to deepwater offshore assets requires
significant judgment given the magnitude of these removal costs and higher estimation
uncertainty related to the removal plan and costs. Furthermore, given certain of these
assets are nearing the end of their operations, the impact of changes in these AROs may
result in a material impact to earnings given the relatively short remaining useful lives of
the assets.
Auditing the Company’s AROs for the obligations identified above is complex and
highly judgmental due to the significant estimation required by management in
determining the obligations. In particular, the estimates were sensitive to significant
subjective assumptions such as removal cost estimates and end of field life, which are
affected by expectations about future market or economic conditions.
How We
Addressed the
Matter in Our
Audit
We obtained an understanding, evaluated the design and tested the operating
effectiveness of the Company’s internal controls over its ARO estimation process,
including management’s review of the significant assumptions that have a material effect
on the determination of the obligations. We also tested management’s controls over the
completeness and accuracy of the financial data used in the valuation.
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. We involved our internal specialists in testing the Company’s methodology to
estimate removal costs.
Depreciation, depletion and amortization and impairment of properties, plants and
equipment
Description of
the Matter
At December 31, 2020, the net book value of the Company’s properties, plants and
equipment (PP&E) was $39.9 billion, and depreciation, depletion and amortization
(DD&A) expense and impairment expense were $5.5 billion and $0.8 billion,
respectively, 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 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. PP&E used in operations is assessed by management for
impairment when 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 value of an asset may not be recovered, the Company
compares undiscounted cash flows before income taxes to the carrying value of the asset
group. If the expected undiscounted cash flows before income taxes are lower than the
carrying value of the asset group, the carrying value is written down to estimated fair
value.
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
84
operating limits. Additionally, the expected future cash flows used for impairment
reviews and related fair value calculations are based on future production volumes of
estimated oil and gas reserves. Significant judgment is required by the Company’s
internal reservoir engineers in evaluating geological and engineering data when
estimating oil and gas reserves. Estimating 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 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.
Auditing the Company’s DD&A and impairment calculations 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 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
and impairments, including management’s controls over the completeness and accuracy
of the financial data provided to the internal reservoir engineers for use in estimating 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 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 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 and impairment
calculations, including comparing the oil and gas reserve amounts used in the
calculations to the Company’s reserve report.
/s/ Ernst & Young LLP
We have served as ConocoPhillips’ auditor since 1949.
Houston, Texas
February 16, 2021
85
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, 2020, 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, 2020,
based on the COSO criteria.
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, 2020 and 2019, 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, 2020, and the related notes and our report dated
February 16, 2021, 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.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles. A company’s internal control over financial reporting
includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable
assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company are being made
only in accordance with authorizations of management and directors of the company; and (3) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s
assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may
deteriorate.
/s/ Ernst & Young LLP
Houston, Texas
February 16, 2021
86
Consolidated Income Statement
ConocoPhillips
Years Ended December 31
Millions of Dollars
2020
2019
2018
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
(72 )
(17 )
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 )
(48 )
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.
87
Consolidated Statement of Comprehensive Income
ConocoPhillips
Years Ended December 31
Millions of Dollars
2020
2019
2018
Net Income (Loss)
$
(2,655 )
Other comprehensive income (loss)
Defined benefit plans
Prior service credit (cost) arising during the period
(7 )
Reclassification adjustment for amortization of prior
service credit included in net income (loss)
(32 )
(35 )
(40 )
Net change
(3 )
(35 )
(47 )
Net actuarial loss arising during the period
(210 )
(55 )
(150 )
Reclassification adjustment for amortization of net
actuarial losses included in net income (loss)
Net change
(93 )
Nonsponsored plans*
(3 )
(1 )
Income taxes on defined benefit plans
(2 )
(42 )
Defined benefit plans, net of tax
(75 )
Unrealized holding gain on securities
Unrealized gain on securities, net of tax
Foreign currency translation adjustments
(645 )
Income taxes on foreign currency translation adjustments
(4 )
Foreign currency translation adjustments, net of tax
(642 )
Other Comprehensive Income (Loss), Net of Tax
(603 )
Comprehensive Income (Loss)
(2,516 )
Less: comprehensive income attributable to noncontrolling interests
(46 )
(68 )
(48 )
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.
88
Consolidated Balance Sheet
ConocoPhillips
At December 31
Millions of Dollars
2020
2019
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 (2020—
Par value
Capital in excess of par
Treasury stock (at cost: 2020—
(47,297 )
(46,405 )
Accumulated other comprehensive loss
(5,218 )
(5,357 )
Retained earnings
Total Common Stockholders’ Equity
Noncontrolling interests
Total Equity
Total Liabilities and Equity
$
See Notes to Consolidated Financial Statements.
89
Consolidated Statement of Cash Flows
ConocoPhillips
Years Ended December 31
Millions of Dollars
2020
2019
2018
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
(549 )
(1,966 )
(1,063 )
Unrealized (gain) loss on investment in Cenovus Energy
(649 )
Other
(351 )
(246 )
Working capital adjustments
Decrease in accounts and notes receivable
Decrease (increase) in inventories
(25 )
(67 )
Decrease (increase) in prepaid expenses and other current assets
(55 )
Decrease in accounts payable
(249 )
(378 )
(52 )
Increase (decrease) in taxes and other accruals
(695 )
(676 )
Net Cash Provided by Operating Activities
Cash Flows From Investing Activities
Capital expenditures and investments
(4,715 )
(6,636 )
(6,750 )
Working capital changes associated with investing activities
(155 )
(103 )
(68 )
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
(4,121 )
(6,618 )
(3,843 )
Cash Flows From Financing Activities
Issuance of debt
Repayment of debt
(254 )
(80 )
(4,995 )
Issuance of company common stock
(5 )
(30 )
Repurchase of company common stock
(892 )
(3,500 )
(2,999 )
Dividends paid
(1,831 )
(1,500 )
(1,363 )
Other
(26 )
(119 )
(123 )
Net Cash Used in Financing Activities
(2,708 )
(5,229 )
(9,359 )
Effect of Exchange Rate Changes on Cash, Cash Equivalents and
Restricted Cash
(20 )
(46 )
(117 )
Net Change in Cash, Cash Equivalents and Restricted Cash
(2,047 )
(789 )
(385 )
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, 2020.
Restricted cash of $
respectively, of our Consolidated Balance Sheet as of December 31, 2019.
See Notes to Consolidated Financial Statements.
90
Consolidated Statement of Changes in Equity
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, 2017
$
(39,906 )
(5,518 )
Net income
Other comprehensive loss
(603 )
(603 )
Dividends paid ($
(1,363 )
(1,363 )
Repurchase of company common stock
(2,999 )
(2,999 )
Distributions to noncontrolling interests and other
(121 )
(121 )
Distributed under benefit plans
Changes in Accounting Principles*
(278 )
(220 )
Other
Balances at December 31, 2018
$
(42,905 )
(6,063 )
Net income
Other comprehensive income
Dividends paid ($
(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 paid ($
(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 )
91
Notes to Consolidated Financial Statements
ConocoPhillips
Note 1—Accounting Policies
■
Consolidation Principles and Investments
—Our consolidated financial statements include the accounts
of majority-owned, controlled subsidiaries and variable interest entities where we are the primary
beneficiary. The equity method is used to account for investments in affiliates in which we have the
ability to exert significant influence over the affiliates’ operating and financial policies. When we do not
have the ability to exert significant influence, the investment is measured at fair value except when the
investment does not have a readily determinable fair value. For those exceptions, it will be measured at
cost minus impairment, plus or minus observable price changes in orderly transactions for an identical or
similar investment of the same issuer. Undivided interests in oil and gas joint ventures, pipelines, natural
gas plants and terminals are consolidated on a proportionate basis. Other securities and investments are
generally carried at cost.
We manage our operations through six operating segments, defined by geographic region: Alaska; Lower
48; Canada; Europe, Middle East and North Africa; Asia Pacific; and Other International. For additional
information, see Note 24—Segment Disclosures and Related Information.
The unrealized (gain) loss on investment in Cenovus Energy included on our consolidated statement of
cash flows, previously reflected on the line item “Other” within net cash provided by operating activities,
has been reclassified in the comparative periods to conform with the current period’s presentation.
■
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 accounting principles
generally accepted in the U.S. 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.
92
■
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.
■
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.
on 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
93
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
gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the
reserves and the economic and operating viability of the project is being made. For complex
exploratory discoveries, it is not unusual to have exploratory wells remain suspended on the balance
sheet for several years while we perform additional appraisal drilling and seismic work on the
potential oil and gas field or while we seek government or co-venturer approval of development plans
or seek environmental permitting. Once all required approvals and permits have been obtained, the
projects are moved into the development phase, and the oil and gas resources are designated as proved
reserves.
Management reviews suspended well balances quarterly, continuously monitors the results of the
additional appraisal drilling and seismic work, and expenses the suspended well costs as dry holes
when it judges the potential field does not warrant further investment in the near term. See Note 7—
Suspended Wells and Exploration Expenses, for additional information on suspended wells.
Development Costs
—Costs incurred to drill and equip development wells, including unsuccessful
development wells, are capitalized.
Depletion and Amortization
—Leasehold costs of producing properties are depleted using the unit-
of-production method based on estimated proved oil and gas reserves. Amortization of intangible
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
—PP&E 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 such as for prices, volumes and future development plans. If, upon review, 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 of the impairment 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. 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.
The expected future cash flows used for impairment reviews and related fair value calculations are based
on estimated future production volumes, prices and costs, considering all available evidence at the date of
review. The impairment review includes cash flows from proved developed and undeveloped reserves,
94
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.
■
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.
■
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 less than complete 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. When the liability is initially recorded, we capitalize this 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 is increased for the
change in its present value, and the capitalized cost in PP&E is depreciated 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. For additional information, see Note 9—Asset Retirement Obligations and
Accrued Environmental Costs.
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.
■
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
95
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.
■
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—Changes in Accounting Principles
96
Note 3—Inventories
Inventories at December 31 were:
Millions of Dollars
2020
2019
Crude oil and natural gas
$
Materials and supplies
$
Inventories valued on the LIFO basis totaled $
respectively. In the first quarter of 2020, we recorded a lower of cost or market adjustment of $
our crude oil and natural gas inventories, which is included in the “Purchased commodities” line on our
consolidated income statement. Commodity prices have since improved. The estimated excess of current
replacement cost over LIFO cost of inventories was approximately $
December 31, 2020 and 2019, respectively.
Note 4—Asset Acquisitions and Dispositions
All gains or losses on asset dispositions are reported before-tax and are included net in the “Gain on
dispositions” line on our consolidated income statement. All cash proceeds and payments are included in the
“Cash Flows From Investing Activities” section of our consolidated statement of cash flows.
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 focused in
the Permian Basin. Total consideration for the all-stock transaction was valued at $
shares of ConocoPhillips common stock was exchanged for each outstanding share of Concho common stock,
resulting in the issuance of approximately
assumed $
value of $
25—Acquisition of Concho Resources Inc.
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
adjacent to our existing Montney position. The transaction increased our Montney acreage position to
approximately
asset acquisition resulting in the recognition of $
environmental costs; and $
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.
interests sold were reported in our Lower 48 segment.
In March 2020, we completed the sale of our Niobrara interests for approximately $
customary adjustments and recognized a before-tax loss on disposition of $
disposition, our interest in Niobrara had a net carrying value of $
97
$
Niobrara, including the loss on disposition noted above and an impairment of $
signed an agreement to sell our interests in the fourth quarter of 2019, were $
the years ended December 31, 2020 and 2019, respectively. The before-tax earnings associated with our
interests in Niobrara for the year ended December 31, 2018 was $
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 $
additional $
recognized a before-tax gain of $
net carrying value of the subsidiaries sold was approximately $
net carrying value consisted primarily of $
$
earnings associated with the subsidiaries sold, including the gain on disposition noted above, were $
million, $
Production from the beginning of the year through the disposition date in May 2020 averaged
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
LNG Terminal and Golden Pass Pipeline. We also entered into agreements to amend our contractual
obligations for retaining use of the facilities. As a result of entering into these agreements, we recorded a
before-tax impairment of $
of affiliates” line on our consolidated income statement. We completed the sale in the second quarter of 2019.
Results of operations for these assets were reported in our Lower 48 segment. See Note 14—Fair Value
Measurement for additional information.
In April 2019, we entered into an agreement to sell two ConocoPhillips U.K. subsidiaries to Chrysaor E&P
Limited for $
On September 30, 2019, we completed the sale for proceeds of $
before-tax and $
sold indirectly held our exploration and production assets in the U.K. At the time of disposition, the net
carrying value was approximately $
cumulative foreign currency translation adjustments, and $
billion of ARO and negative $
subsidiaries sold, including the gain on dispositions noted above, were $
years ended December 31, 2019 and 2018, respectively. Results of operations for the U.K. were reported
within our Europe, Middle East and North Africa segment.
In the second quarter of 2019, we recognized an after-tax gain of $
our
Greater Sunrise Fields were included in our Asia Pacific segment.
In the fourth quarter of 2019, we sold our interests in the Magnolia field and platform for net proceeds of $
million and recognized a before-tax gain of $
of $
our Lower 48 segment.
98
2018
Assets Sold
In the first quarter of 2018, we completed the sale of certain properties in the Lower 48 segment for net
proceeds of $
completed the sale of a package of largely undeveloped acreage in the Lower 48 segment for net proceeds of
$
noncash exchange of undeveloped acreage in the Lower 48 segment. The transaction was recorded at fair
value resulting in the recognition of a $
packages of undeveloped acreage in the Lower 48 segment for total net proceeds of $
recognized gains of approximately $
On October 31, 2018, we completed the sale of our interests in the Barnett to Lime Rock Resources for $
million after customary adjustments and recognized a loss of $
million in 2018 to reduce the net carrying value of the Barnett to fair value. At the time of the disposition, our
interest in Barnett had a net carrying value of $
million of AROs. The before-tax loss associated with our interests in the Barnett, including both the
impairment and loss on disposition noted above, was $
Barnett results of operations were included in our Lower 48 segment.
On December 18, 2018, we completed the sale of a ConocoPhillips subsidiary to BP. The subsidiary held
interest in the field. At the same time, we acquired BP’s
Kuparuk Area in Alaska, including their
Assets). The transaction was recorded at a fair value of $
customary adjustments which resulted in net proceeds of $
Field had a net carrying value of approximately $
PP&E, $
$
Clair Field, including the recognized gain, were $
Field are reported within our Europe, Middle East and North Africa segment and the Kuparuk Assets were
included in our Alaska segment.
Acquisitions
In May 2018, we completed the acquisition of Anadarko’s
North Slope of Alaska, as well as its interest in the Alpine Transportation Pipeline for $
customary adjustments. This transaction was accounted for as a business combination resulting in the
recognition of approximately $
PP&E, $
included in our Alaska segment.
As discussed in the Clair Field transaction with BP above, we acquired BP’s Kuparuk Assets on December 18,
2018. The transaction was accounted for as an asset acquisition with a net acquisition cost of $
comprised of the fair value of $
interest in the Clair Field, reduced by the net proceeds of $
approximately $
investments, $
are included in our Alaska segment.
99
Note 5—Investments, Loans and Long-Term Receivables
Components of investments, loans and long-term receivables at December 31 were:
Millions of Dollars
2020
2019
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, 2020, 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)—30 percent owned joint venture with affiliates of Qatar
Petroleum (
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
2020
2019
2018
Revenues
$
Income before income taxes
Net income
Summarized 100 percent balance sheet information for equity method investments in affiliated companies,
combined, was as follows:
Millions of Dollars
2020
2019
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, 2020, retained earnings included $
affiliated companies. Dividends received from affiliates were $
$
100
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 $
billion project finance facility was initially composed of financing agreements executed by APLNG with the
Export-Import Bank of the United States for approximately $
approximately $
approximately $
interest repayment in March 2017 and is scheduled to make
APLNG made a voluntary repayment of $
At the same time, APLNG obtained a United States Private Placement (USPP) bond facility of $
APLNG made its first interest payment related to this facility in March 2019, and principal payments are
scheduled to commence in September 2023, with
During the first quarter of 2019, APLNG refinanced $
transactions. As a result of the first transaction, APLNG obtained a commercial bank facility of $
APLNG made its first principal and interest repayment in September 2019 with
facility until March 2028. Through the second transaction, APLNG obtained a USPP bond facility of $
billion. APLNG made its first interest payment in September 2019, and principal payments are scheduled to
commence in September 2023, with
In conjunction with the $
finance debt, APLNG made voluntary repayments of $
and international commercial banks and the Export-Import Bank of China, respectively.
At December 31, 2020, a balance of $
for additional information.
During the fourth quarter of 2020, the estimated fair value of our investment in APLNG declined to an amount
below carrying value, primarily due to the weakening of the U.S. dollar relative to the Australian dollar. Based
on a review of the facts and circumstances surrounding this decline in fair value, we concluded the impairment
was not other than temporary under the guidance of FASB ASC Topic 323, “Investments – Equity Method and
Joint Ventures.” In reaching this conclusion, we primarily considered: (1) the volatility and uncertainty in
commodity and exchange rate markets; (2) the intent and ability of ConocoPhillips to retain our investment in
APLNG; and (3) the short length of time and extent to which fair value has been less than carrying value (fair
value exceeded carrying value as of September 30, 2020). Fair value has been estimated based on an internal
discounted cash flow model 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), operating and capital expenditures, a market outlook of foreign exchange
rates provided by a third party, and a discount rate believed to be consistent with those used by principal
market participants.
At December 31, 2020, the fair value of our investment in APLNG was estimated to be $
resulting in a not other than temporary impairment of $
relationship between the carrying value and fair value of APLNG. Should we determine in the future there has
been a loss in the value of our investment that is other than temporary, we would record an impairment of our
equity investment, calculated as the total difference between carrying value and fair value as of the end of the
reporting period.
101
At December 31, 2020, the carrying value of our equity method investment in APLNG was $
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 exploration and production license areas owned by APLNG, some of which are not currently in
production. Any future additional payments are expected to be allocated in a similar manner. Each
exploration license area will periodically be reviewed for any indicators of potential impairment, which, if
required, would result in acceleration of basis difference amortization. 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 2020, 2019 and 2018 was after-tax
expense of $
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 $
Term Receivables.” At December 31, 2020, the book value of our equity method investment in QG3,
excluding the project financing, was $
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
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. For additional information, see Note 4—Asset
Acquisitions and Dispositions.
Loans and Long-Term Receivables
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
and long-term receivables to certain affiliated and non-affiliated companies. Loans are recorded when cash is
transferred or seller financing is provided to the affiliated or non-affiliated company pursuant to a loan
agreement. The loan balance will increase as interest is earned on the outstanding loan balance and will
decrease as interest and principal payments are received. Interest is earned at the loan agreement’s stated
interest rate. Loans and long-term receivables are assessed for impairment when events indicate the loan
balance may not be fully recovered.
At December 31, 2020, significant loans to affiliated companies include $
QG3. We own a
participants in the project are affiliates of Qatar Petroleum and Mitsui. QG3 secured project financing of
$
billion from commercial banks, and $
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.
The long-term portion of these loans is included in the “Loans and advances—related parties” line on our
consolidated balance sheet, while the short-term portion is in “Accounts and notes receivable—related parties.”
102
Note 6—Investment in Cenovus Energy
On May 17, 2017, we completed the sale of our
well as the majority of our western Canada gas assets, to Cenovus Energy. Consideration for the transaction
included 208 million Cenovus Energy common shares, which, at closing, approximated
and outstanding Cenovus Energy common stock. The fair value and cost basis of our investment in
million Cenovus Energy common shares was $
the closing date.
At December 31, 2020, the investment included on our consolidated balance sheet was $
carried at fair value. The fair value of the
price of $
fair value of $
recorded within the “Other income (loss)” line of our consolidated income statement for the year ended
December 31, 2020 relating to the shares held at the reporting date. For the years ended 2019 and 2018, we
recorded an unrealized gain of $
14—Fair Value Measurement and Note 21—Other Financial Information, for additional information. Subject
to market conditions, we intend to decrease our investment over time through market transactions, private
agreements or otherwise.
On January 4, 2021, Cenovus Energy completed its all-stock acquisition of Husky Energy Inc. As a result of
this transaction, our investment now approximates
common stock.
Note 7—Suspended Wells and Exploration Expenses
The following table reflects the net changes in suspended exploratory well costs during 2020, 2019 and 2018:
Millions of Dollars
2020
2019
2018
Beginning balance at January 1
$
Additions pending the determination of proved reserves
Reclassifications to proved properties
(42 )
(11 )
(37 )
Sales of suspended wells
(313 )
(54 )
(93 )
Charged to dry hole expense
(147 )
(10 )
(7 )
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
2020
2019
2018
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
$
*
Number of projects with exploratory well costs capitalized for a
period greater than one year
*Includes $
103
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, 2020:
Millions of Dollars
Suspended Since
Total
2017–2019
2014–2016
2004–2013
NPRA—Alaska
(1)
Surmont—Canada
(1)
Narwhal Trend—Alaska
(1)
PL782S—Norway
(1)
WL4-00—Malaysia
(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. In 2016, we,
along with affiliates of Exxon Mobil Corporation, BP p.l.c. and Alaska Gasline Development Corporation
(AGDC), a state-owned corporation, completed preliminary FEED technical work for a potential LNG project
which would liquefy and export natural gas from Alaska’s North Slope and deliver it to market. In 2016, we,
along with the affiliates of ExxonMobil and BP, indicated our intention not to progress into the next phase of
the project due to changes in the economic environment; however, AGDC decided to continue on its own,
focusing primarily on permitting efforts. Currently, AGDC is in the process of seeking new sponsors for the
project. Given current market conditions, we no longer believe the project will advance and, 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. We have no immediate plans to perform under existing contracts; therefore, in 2020, we recorded a
before-tax expense totaling $
the associated capitalized undeveloped leasehold carrying value.
In our Asia Pacific segment, we recorded before-tax expense of $
previously suspended well and an impairment of the associated capitalized undeveloped leasehold carrying
value associated with the Kamunsu East Field in Malaysia that is no longer in our development plans.
2019
In our Lower 48 segment, we recorded a before-tax impairment of $
value of capitalized undeveloped leasehold costs and dry hole expenses of $
decision to discontinue exploration activities related to our Central Louisiana Austin Chalk acreage.
104
Note 8—Impairments
During 2020, 2019 and 2018, we recognized the following before-tax impairment charges:
Millions of Dollars
2020
2019
2018
Alaska
$
Lower 48
Canada
Europe, Middle East and North Africa
(79 )
Asia Pacific
$
2020
During 2020, we recorded impairments of $
Lower 48. Due to a significant decrease in the outlook for current and long-term natural gas prices in early
2020, we recorded impairments of $
consisting of developed properties in the Madden Field and the Lost Cabin Gas Plant, in the first quarter of
2020. Additionally, due primarily to changes in development plans solidified in the last quarter of 2020, we
recognized additional impairments of $
Fair Value Measurement, for additional information.
2019
In the Lower 48, we recorded impairments of $
Niobrara asset which were written down to fair value less costs to sell. See Note 4—Asset Acquisitions and
Dispositions, for additional information on this disposition.
2018
In Alaska, we recorded impairments of $
In the Lower 48, we recorded impairments of $
Barnett asset which were written down to fair value less costs to sell, partly offset by a revision to reflect
finalized proceeds on a separate transaction.
In our Europe, Middle East and North Africa segment, we recorded a credit to impairment of $
primarily due to decreased ARO estimates on fields in the U.K. which ceased production and were impaired in
prior years, partly offset by an increased ARO estimate on a field in Norway which ceased production.
105
Note 9—Asset Retirement Obligations and Accrued Environmental Costs
Asset retirement obligations and accrued environmental costs at December 31 were:
Millions of Dollars
2020
2019
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*
(323 )
(1,025 )
Long-term asset retirement obligations and accrued environmental costs
$
*Classified as a current liability on the balance sheet under “Other accruals.” For 2019, $
as of December 31, 2019, and subsequently sold in 2020. For additional information see Note 4—Asset Acquisitions and Dispositions.
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.
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 2020 and 2019, our overall ARO changed as follows:
Millions of Dollars
2020
2019
Balance at January 1
$
Accretion of discount
New obligations
Changes in estimates of existing obligations
(307 )
Spending on existing obligations
(116 )
(229 )
Property dispositions
(771 )
(1,920 )
Foreign currency translation
(80 )
Balance at December 31
$
106
Accrued Environmental Costs
Total accrued environmental costs at December 31, 2020 and 2019, 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 $
December 31, 2020 and 2019, respectively. In addition, $
December 31, 2020 and 2019, respectively, where the company has been named a potentially responsible party
under the Federal Comprehensive Environmental Response, Compensation and Liability Act, or similar state
laws. Accrued environmental liabilities are expected to be paid over periods extending up to
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: $
2022, $
after 2025.
107
Note 10—Debt
Long-term debt at December 31 was:
Millions of Dollars
2020
2019
% 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
% Debentures due 2029
% Debentures due 2029
% Notes due 2029
% Notes due 2030
% 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
Floating rate notes due 2022 at
% –
% during 2020 and
% –
% during 2019
Marine Terminal Revenue Refunding Bonds due 2031 at
% –
% during
% –
% during 2019
Industrial Development Bonds due 2035 at
% –
% during 2020 and
% –
% during 2019
Commercial Paper at
% –
% during 2020
Other
Debt at face value
Finance leases
Net unamortized premiums, discounts and debt issuance costs
Total debt
Short-term debt
(619 )
(105 )
Long-term debt
$
108
Maturities of long-term borrowings, inclusive of net unamortized premiums and discounts, in 2021 through
2025 are: $
We have a revolving credit facility totaling $
credit facility may be used for direct bank borrowings, the issuance of letters of credit totaling up to $
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 $
more by ConocoPhillips, or any of its consolidated subsidiaries. The amount of the facility is not subject to
redetermination prior to its expiration date.
Credit facility borrowings may bear interest at a margin above rates offered by certain designated banks in the
London interbank market or at a margin above the overnight federal funds rate or prime rates offered by
certain designated banks in the U.S. The 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 $
primarily a funding source for short-term working capital needs. Commercial paper maturities are generally
limited to
. We issued $
included in the short-term debt on our consolidated balance sheet. With $
outstanding and
capacity under our revolving credit facility at December 31, 2020. We had
credit, nor outstanding commercial paper as of December 31, 2019.
At both December 31, 2020 and 2019, 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.
For information on Finance Leases, see Note 16—Non-Mineral Leases.
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, which was recorded at fair value of $
date. On December 7, 2020, we launched a debt exchange offer which settled on February 8, 2021. Of the
approximately $
percent, or approximately $
The new debt received in the exchange is fully and unconditionally guaranteed by ConocoPhillips Company.
In conjunction with the exchange offer, Concho successfully solicited consents to amend each of the
indentures governing the Concho notes to eliminate certain covenants, restrictive provisions, events of default
and the requirements for certain Concho subsidiaries to make future guarantees. For additional information on
the acquisition see Note 25—Acquisition of Concho Resources Inc.
Note 11—Guarantees
At December 31, 2020, 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.
109
APLNG Guarantees
At December 31, 2020, 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
2020 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
. Our maximum exposure under this guarantee is approximately $
and may become payable if an enforcement action is commenced by the project finance lenders
against APLNG. At December 31, 2020, the carrying value of this guarantee is approximately $
million.
●
In conjunction with our original purchase of an ownership interest in APLNG from Origin Energy in
October 2008, we agreed to reimburse Origin Energy for our share of the existing contingent liability
arising under guarantees of an existing obligation of APLNG to deliver natural gas under several sales
agreements with remaining terms of
. Our maximum potential liability for future
payments, or cost of volume delivery, under these guarantees is estimated to be $
billion in the event of intentional or reckless breach) and would become payable if APLNG fails to
meet its obligations under these agreements and the obligations cannot otherwise be mitigated. Future
payments are considered unlikely, as the payments, or cost of volume delivery, would only be
triggered if APLNG does not have enough natural gas to meet these sales commitments and if the co-
venturers 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
. Our maximum potential amount of future payments related to these
guarantees is approximately $
December 31, 2020, the carrying value of these guarantees was approximately $
Other Guarantees
We have other guarantees with maximum future potential payment amounts totaling approximately
$
of the residual value of corporate aircraft, and a guarantee for our portion of a joint venture’s project finance
reserve accounts. These guarantees have remaining terms of one to
certain asset values are lower than guaranteed amounts at the end of the lease or contract term, business
conditions decline at guaranteed entities, or as a result of nonperformance of contractual terms by guaranteed
parties. At December 31, 2020, 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. Most of these indemnifications are related to tax issues and the
majority of these expire in 2021. Those related to environmental issues have terms that are generally indefinite
and the maximum amounts of future payments are generally unlimited. The carrying amount recorded for
these indemnifications at December 31, 2020, was approximately $
indemnification liability over the relevant time period the indemnity is in effect, if one exists, based on the
facts and circumstances surrounding each type of indemnity. In cases where the indemnification term is
indefinite, we will reverse the liability when we have information the liability is essentially relieved or
amortize the liability over an appropriate time period as the fair value of our indemnification exposure
declines. 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, see Note 12—Contingencies and
Commitments.
110
Note 12—Contingencies and Commitments
A number of lawsuits involving a variety of claims arising in the ordinary course of business have been filed
against ConocoPhillips. We also may be required to remove or mitigate the effects on the environment of the
placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active
and inactive sites. We regularly assess the need for accounting recognition or disclosure of these
contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a
liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be
reasonably estimated and no amount within the range is a better estimate than any other amount, then the low
end of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries.
We accrue receivables for insurance or other third-party recoveries when applicable. With respect to income
tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a
tax position is less than certain. See Note 18—Income Taxes, 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. When we prepare
our consolidated financial statements, we record accruals for environmental liabilities based on management’s
best estimates, using all information that is available at the time. We measure estimates and base liabilities 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
111
not reduced these accruals for possible insurance recoveries. In the future, we may be involved in additional
environmental assessments, cleanups and proceedings. See Note 9—Asset Retirement Obligations and
Accrued Environmental Costs, for a summary of our accrued environmental liabilities.
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 and
claims of alleged environmental contamination from historic operations. 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, 2020, we had performance obligations secured by letters of credit of
$
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 $
government’s unlawful expropriation of the company’s investments in Venezuela in 2007. ConocoPhillips has
filed a request for recognition of the award in several jurisdictions. On August 29, 2019, the ICSID Tribunal
issued a decision rectifying the award and reducing it by approximately $
at $
annulment proceedings are underway.
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 $
approximately $
jurisdictions, and ConocoPhillips agreed to suspend its legal enforcement actions. ConocoPhillips sent notices
of default to PDVSA on October 14 and November 12, 2019, and to date PDVSA has failed to cure its breach.
As a result, ConocoPhillips has resumed legal enforcement actions. ConocoPhillips has ensured that the
112
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.
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 $
ConocoPhillips is seeking recognition and enforcement of the award in various jurisdictions. ConocoPhillips
has ensured that all the actions related to the award meet all appropriate U.S. regulatory requirements,
including those related to any applicable sanctions imposed by the U.S. against Venezuela.
The Office of Natural Resources Revenue (ONRR) has conducted audits of ConocoPhillips’ payment of
royalties on federal lands and has issued multiple orders to pay additional royalties to the federal government.
ConocoPhillips has appealed these orders and strongly objects to the ONRR claims. The appeals are pending
with the Interior Board of Land Appeals (IBLA), except for one order that is the subject of a lawsuit
ConocoPhillips filed in 2016 in New Mexico federal court after its appeal was denied by the IBLA.
Beginning in 2017, governmental and other entities in several states in the U.S. have filed lawsuits against oil
and gas companies, including ConocoPhillips, seeking compensatory damages and equitable relief to abate
alleged climate change impacts. Additional lawsuits with similar allegations are expected to be filed. The
amounts claimed by plaintiffs are unspecified and the legal and factual issues involved in these cases are
unprecedented. ConocoPhillips believes these lawsuits are factually and legally meritless and are an
inappropriate vehicle to address the challenges associated with climate change and will vigorously defend
against such lawsuits.
Several Louisiana parishes and the State of Louisiana have filed 43 lawsuits under Louisiana’s State and Local
Coastal Resources Management Act (SLCRMA) against oil and gas companies, including ConocoPhillips,
seeking compensatory damages for contamination and erosion of the Louisiana coastline allegedly caused by
historical oil and gas operations. ConocoPhillips entities are defendants in 22 of the lawsuits and will
vigorously defend against them. Because Plaintiffs’ SLCRMA theories are unprecedented, there is uncertainty
about these claims (both as to scope and damages) and any potential financial impact on the company.
In 2016, ConocoPhillips, through its subsidiary, The Louisiana Land and Exploration Company LLC,
submitted claims as the largest private wetlands owner in Louisiana within the settlement claims
administration process related to the oil spill in the Gulf of Mexico in April 2010. In July 2020, the claims
administrator issued an award to the company which, after fees and expenses, totaled approximately $
million, and was received in the third quarter of 2020.
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. Phillips
Petroleum Company, a legacy company of ConocoPhillips, held a 25 percent interest in this lease and operated
these facilities, but sold its interest approximately 30 years ago. ConocoPhillips has not had any connection to
the operation or production on this lease since that time. ConocoPhillips is challenging this order.
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
the company’s business. The aggregate amounts of estimated payments under these various agreements are:
2021—$
after—$
$
113
Note 13—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,
realized and unrealized 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. 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
2020
2019
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
2020
2019
2018
Sales and other operating revenues
$
Other income (loss)
Purchased commodities
(118 )
(41 )
The table below summarizes our material net exposures resulting from outstanding commodity derivative
contracts:
Open Position
Long/(Short)
2020
2019
Commodity
Natural gas and power (billions of cubic feet equivalent)
Fixed price
(20)
(5)
Basis
(10)
(23)
114
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 recorded as operating activities on our consolidated statement of cash flows. We do not
apply hedge accounting to 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
2020
2019
Assets
Prepaid expenses and other current assets
$
Liabilities
Other accruals
Other liabilities and deferred credits
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
2020
2019
2018
Foreign currency transaction (gains) losses
$
(40 )
We had the following net notional position of outstanding foreign currency exchange derivatives:
In Millions
Notional Currency
2020
2019
Foreign Currency Exchange Derivatives
Buy British pound, sell euro
GBP
Sell British pound, buy euro
GBP
Sell Canadian dollar, buy U.S. dollar
CAD
115
.
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, 2020 and 2019:
Millions of Dollars
Carrying Amount
Cash and Cash
Equivalents
Short-Term
Investments
Investments and Long-
Term Receivables
2020
2019
2020
2019
2020
2019
Cash
$
Demand Deposits
Time Deposits
1 to 90 days
91 to 180 days
Within one year
One year through five years
Commercial Paper
1 to 90 days
U.S. Government Obligations
1 to 90 days
$
116
The following investments in debt securities classified as available for sale are carried on our consolidated
balance sheet at fair value as of December 31, 2020 and 2019:
Millions of Dollars
Carrying Amount
Cash and Cash
Equivalents
Short-Term
Investments
Investments and Long-
Term Receivables
2020
2019
2020
2019
2020
2019
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 greater than one year through five years.
The following table summarizes the amortized cost basis and fair value of investments in debt securities
classified as available for sale:
Millions of Dollars
Amortized Cost Basis
Fair Value
2020
2019
2020
2019
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, 2020 and December 31, 2019, total unrealized losses for debt securities classified as
available for sale with net losses were negligible. Additionally, as of December 31, 2020 and December 31,
2019, 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 year ended December 31, 2020, proceeds from sales and redemptions of investments in debt securities
classified as available for sale were $
those sales and redemptions were negligible. The cost of securities sold and redeemed is determined using the
specific identification method.
117
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, government debt securities, time deposits with major international banks and
financial institutions, and high-quality corporate bonds. Our long-term investments in debt securities are
placed in high-quality corporate bonds, U.S. government and government agency obligations, foreign
government obligations, and asset-backed securities.
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. At our option, 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, 2020 and December 31, 2019, was $
respectively. For these instruments,
no collateral
If our credit rating had been downgraded below investment grade on December 31, 2020, we would have been
required to post $
Note 14—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 following hierarchy:
●
Level 1: Quoted prices (unadjusted) in an active market for identical assets or liabilities.
●
Level 2: Inputs other than quoted prices that are directly or indirectly observable.
●
Level 3: Unobservable inputs that are significant to the fair value of assets or liabilities.
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
118
corroborated market data is no longer available. There were no material transfers into or out of Level 3 during
2020 or 2019.
Recurring Fair Value Measurement
Financial assets and liabilities reported at fair value on a recurring basis primarily include our investment in
Cenovus Energy common shares, our investments in debt securities classified as available for sale, and
commodity derivatives.
●
Level 1 derivative assets and liabilities primarily represent exchange-traded futures and options that are
valued using unadjusted prices available from the underlying exchange. Level 1 also includes our
investment in common shares of Cenovus Energy, 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, 2020
December 31, 2019
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
$
119
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, 2020
Assets
$
Liabilities
December 31, 2019
Assets
$
Liabilities
At December 31, 2020 and December 31, 2019, 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, 2020
Net PP&E (held for use)
$
Year ended December 31, 2019
Net PP&E (held for sale)
$
Equity Method Investments
Net PP&E (held for use)
During 2020, the estimated fair value of certain non-core 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:
120
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**
% -
% (
%)
%
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
2.0% annually after year 2050.
**Determined as the weighted average cost of capital of a group of peer companies, adjusted for risks where appropriate.
Net PP&E (held for sale)
Net PP&E held for sale was written down to fair value, less costs to sell. The fair value of the assets were
determined by their negotiated selling prices (Level 1). For additional information see Note 4—Asset
Acquisitions and Dispositions.
Equity Method Investments
During 2019, certain equity method investments were determined to have fair values below their carrying
amounts, and the impairments were considered to be other than temporary under the guidance of FASB ASC
Topic 323. Investments using Level 1 inputs were written down to fair value, less costs to sell, determined by
negotiated selling prices. For additional information, see Note 4—Asset Acquisitions and Dispositions and
Note 5—Investments, Loans and Long-Term Receivables. An investment using Level 2 inputs was
determined to have a fair value below its carrying value, and was written down to fair value.
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.
121
●
Investment in Cenovus Energy: See Note 6—Investment in Cenovus Energy for a discussion of the
carrying value and fair value of our investment in Cenovus Energy common shares.
●
Investments in debt securities classified as available for sale: The fair value of investments in debt
securities categorized as Level 1 in the fair value hierarchy is measured using exchange prices. The
fair value of investments in debt securities categorized as Level 2 in the fair value hierarchy is
measured using pricing provided by brokers or pricing service companies that are corroborated with
market data. See Note 13—Derivatives and Financial Instruments, for additional information.
●
Loans and advances—related parties: The carrying amount of floating-rate loans approximates fair
value. The fair value of fixed-rate loan activity is measured using market observable data and is
categorized as Level 2 in the fair value hierarchy. See Note 5—Investments, Loans and Long-Term
Receivables, for additional information.
●
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. See Note 10—Debt, for additional
information
.
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
2020
2019
2020
2019
Financial assets
Investment in Cenovus Energy
$
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, 2020, commodity derivative assets and liabilities are presented net with $
obligations to return cash collateral and $
December 31, 2019, commodity derivative assets and liabilities are presented net with $
obligations to return cash collateral and $
122
Note 15—Equity
Common Stock
The changes in our shares of common stock, as categorized in the equity section of the balance sheet, were:
Shares
2020
2019
2018
Issued
Beginning of year
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
or outstanding at December 31, 2020 or 2019.
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, 2020, we had no
noncontrolling interests. At December 31, 2019, we had $
ventures.
Repurchase of Common Stock
In late 2016, we initiated our current share repurchase program, which has a current total program
authorization of $
million, $
and third quarters of 2020 in response to the economic downturn. In the fourth quarter of 2020, we resumed
share repurchases, repurchasing $
entry into a definitive agreement to acquire Concho. In February 2021, we resumed share repurchases
following our Concho acquisition. Share repurchases since inception of our current program totaled
million shares at a cost of $
Note 16—Non-Mineral Leases
The company primarily leases office buildings and drilling equipment, as well as ocean transport vessels,
tugboats, corporate aircraft, and other facilities and equipment. Certain leases include escalation clauses for
adjusting rental payments to reflect changes in price indices and other leases include payment provisions that
vary based on the nature of usage of the leased asset. Additionally, the company has executed certain leases
that provide it with the option to extend or renew the term of the lease, terminate the lease prior to the end of
the lease term, or purchase the leased asset as of the end of the lease term. In other cases, the company has
executed lease agreements that require it to guarantee the residual value of certain leased office buildings. For
additional information about guarantees, see Note 11—Guarantees. There are no significant restrictions
imposed on us by the lease agreements with regard to dividends, asset dispositions or borrowing ability.
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”
123
(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,
has been adopted for each of the company’s leased asset classes existing as of the effective date and subject to
the transition provisions of ASC Topic 842 and will be applied to all new or modified leases executed on or
after January 1, 2019. For contractual arrangements executed in subsequent periods involving a new leased
asset class, the company will determine at contract inception whether it will apply the optional practical
expedient to the new leased asset class.
Leases are evaluated for classification as operating or finance leases at the commencement date of the lease
and right-of-use assets and corresponding liabilities are recognized on our consolidated balance sheet based on
the present value of future lease payments relating to the use of the underlying asset during the lease term.
Future lease payments include variable lease payments that depend upon an index or rate using the index or
rate at the commencement date and probable amounts owed under residual value guarantees. The amount of
future lease payments may be increased to include additional payments related to lease extension, termination,
and/or purchase options when the company has determined, at or subsequent to lease commencement,
generally due to limited asset availability or operating commitments, it is reasonably certain of exercising such
options. We use our incremental borrowing rate as the discount rate in determining the present value of future
lease payments, unless the interest rate implicit in the lease arrangement is readily determinable. Lease
payments that vary subsequent to the commencement date based on future usage levels, the nature of leased
asset activities, or certain other contingencies are not included in the measurement of lease right-of-use assets
and corresponding liabilities. We have elected not to record assets and liabilities on our consolidated balance
sheet for lease arrangements with terms of 12 months or less.
We often enter into leasing arrangements acting in the capacity as operator for and/or on behalf of certain oil
and gas joint ventures of undivided interests. If the lease arrangement can be legally enforced only against us
as operator and there is no separate arrangement to sublease the underlying leased asset to our coventurers, we
recognize at lease commencement a right-of-use asset and corresponding lease liability on our consolidated
balance sheet on a gross basis. While we record lease costs on a gross basis in our consolidated income
statement and statement of cash flows, such costs are offset by the reimbursement we receive from our
coventurers for their share of the lease cost as the underlying leased asset is utilized in joint venture activities.
As a result, lease cost is presented in our consolidated income statement and statement of cash flows on a
proportional basis. If we are a nonoperating coventurer, we recognize a right-of-use asset and corresponding
lease liability only if we were a specified contractual party to the lease arrangement and the arrangement could
be legally enforced against us. In this circumstance, we would recognize both the right-of-use asset and
corresponding lease liability on our consolidated balance sheet on a proportional basis consistent with our
undivided interest ownership in the related joint venture.
The company has historically recorded certain finance leases executed by investee companies accounted for
under the proportionate consolidation method of accounting on its consolidated balance sheet on a proportional
basis consistent with its ownership interest in the investee company. In addition, the company has historically
recorded finance lease assets and liabilities associated with certain oil and gas joint ventures on a proportional
basis pursuant to accounting guidance applicable prior to January 1, 2019. In accordance with the transition
provisions of ASC Topic 842, and since we have elected to adopt the package of optional transition-related
practical expedients, the historical accounting treatment for these leases has been carried forward and is subject
to reconsideration upon the modification or other required reassessment of the arrangements prior to lease term
expiration.
124
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
2020
2019
Operating
Leases
Finance
Leases
Operating
Leases
Finance
Leases
Right-of-Use Assets
Properties, plants and equipment
Gross
$
Accumulated DD&A
(721 )
(649 )
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 $
The following table summarizes our lease costs for 2020 and 2019:
Millions of Dollars
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.
*** Variable lease cost and sublease income are immaterial for the periods presented and therefore are not included in the table above
.
125
The following table summarizes the lease terms and discount rates as of December 31:
2020
2019
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 for 2020 and 2019:
Millions of Dollars
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, 2020:
Millions of Dollars
Operating
Leases
Finance
Maturity of Lease Liabilities
2021
$
2022
2023
2024
2025
Remaining years
Total
*
Less: portion representing imputed interest
(80 )
(152 )
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.
126
For the year ended December 31, 2018 operating lease rental expense pursuant to ASC Topic 840 was:
Millions of Dollars
Total rentals
$
Less: sublease rentals
(16 )
$
Note 17—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
2020
2019
2020
2019
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 loss
Benefits paid
(241 )
(151 )
(253 )
(147 )
(49 )
(59 )
Curtailment
(69 )
Recognition of termination benefits
Foreign currency exchange rate change
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
(241 )
(151 )
(253 )
(147 )
(49 )
(59 )
Foreign currency exchange rate change
Fair value of plan assets at December 31
$
Funded Status
$
(778 )
(728 )
(170 )
(216 )
127
Millions of Dollars
Pension Benefits
Other Benefits
2020
2019
2020
2019
U.S.
Int’l.
U.S.
Int’l.
Amounts Recognized in the
Consolidated Balance Sheet at
December 31
Noncurrent assets
$
Current liabilities
(56 )
(11 )
(21 )
(6 )
(39 )
(42 )
Noncurrent liabilities
(722 )
(345 )
(707 )
(333 )
(131 )
(174 )
Total recognized
$
(778 )
(728 )
(170 )
(216 )
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 pensions, 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.
128
The following tables set forth information related to the Company’s pension plans with projected and
accumulated benefit obligations in excess of the fair value of the plans’ assets as of December 31, 2020 and
2019:
Millions of Dollars
Pension Benefits
2020
2019
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
2020
2019
2020
2019
U.S.
Int’l.
U.S.
Int’l.
Unrecognized net actuarial loss
$
Unrecognized prior service credit
(2 )
(182 )
(183 )
Millions of Dollars
Pension Benefits
Other Benefits
2020
2019
2020
2019
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 )
(79 )
(7 )
(27 )
Amortization of actuarial (gain) loss included
in income (loss)*
(2 )
Net change during the period
$
(99 )
(6 )
(29 )
Prior service credit (cost) arising during the
period
$
(1 )
Amortization of prior service cost (credit)
included in income (loss)
(1 )
(2 )
(31 )
(33 )
Net change during the period
$
(2 )
(2 )
(1 )
(33 )
*Includes settlement (gains) losses recognized in 2020 and 2019.
129
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
2020
2019
2018
2020
2019
2018
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
(85 )
(145 )
(74 )
(138 )
(114 )
(155 )
Amortization of prior
service credit
(1 )
(2 )
(5 )
(31 )
(33 )
(35 )
Recognized net actuarial
loss (gain)
(2 )
(1 )
Settlements loss (gain)
(1 )
Net periodic benefit cost
$
(22 )
(26 )
(27 )
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 $
2018 as lump-sum benefit payments from certain U.S. and international pension plans exceeded the sum of
service and interest costs for those plans and led to recognition of settlement losses.
During 2020 and 2019, the actuarial losses related to the benefit obligation for U.S. and international plans
were primarily related to a decrease in the discount rates.
The sale of two ConocoPhillips U.K. subsidiaries completed during the third quarter of 2019 led to a
significant reduction of future services of active employees in certain international pension plans, resulting in a
curtailment. In conjunction with the recognition of the curtailment, the fair market values of pension plan
assets were updated, the pension benefit obligation was remeasured, and the net pension asset decreased by
$
a decrease in the discount rate from
offset by a decrease in the pension benefit obligation from curtailment.
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 nonpension 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
2021 that declines to
postretirement benefit obligation assumes an ultimate health care cost trend rate of
that increases to
130
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,
are publicly traded, therefore minimizing liquidity risk in the portfolio.
The following is a description of the valuation methodologies used for the pension plan assets. There have
been no changes in the methodologies used at December 31, 2020 and 2019.
●
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, 2020, the participating interest in the annuity contract was valued at
$
benefit obligation covered by the contract. At December 31, 2019, the participating interest in the
annuity contract was valued at $
million for the accumulated benefit obligation covered by the contract. The participating interest is
not available for meeting general pension benefit obligations in the near term. No future company
contributions are required and no new benefits are being accrued under this insurance annuity
contract.
131
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 $
132
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
2019
Equity securities
U.S.
$
International
Mutual funds
Debt securities
Government
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 2021, we expect to contribute approximately $
million to our domestic qualified and nonqualified pension and postretirement benefit plans and $
our international qualified and nonqualified pension and postretirement benefit plans.
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.
2021
$
2022
2023
2024
2025
2026–2030
133
Severance Accrual
The following table summarizes our severance accrual activity for 2020, 2019 and 2018:
Millions of Dollars
2020
2019
2018
Balance at January 1
$
Accruals
(1 )
Benefit payments
(13 )
(24 )
(73 )
Foreign currency translation adjustments
(2 )
Balance at December 31
$
Of the remaining balance at December 31, 2020, $
Defined Contribution Plans
Most U.S. employees are eligible to participate in the ConocoPhillips Savings Plan (CPSP). Employees can
deposit up to
approximately
their eligible pay receive a
contribution of up to
to opt out of Title II are eligible to receive a Company Retirement Contribution (CRC) of
pay into their CPSP. After
CRC. Company contributions charged to expense for the CPSP and predecessor plans were $
2020, $
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. Over its
10
-year life, the Plan allows the issuance of up to
common stock for compensation to our employees and directors; however, as of the effective date of the Plan,
(i) any shares of common stock available for future awards under the prior plans and (ii) any shares of common
stock represented by awards granted under the 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, and no new awards shall be granted under the prior
plans. Of the
common stock are available for incentive stock options. The Human Resources and Compensation Committee
of our Board of Directors is authorized to determine the types, terms, conditions and limitations of awards
granted. Awards may be granted in the form of, but not limited to, stock options, restricted 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).
134
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 for the years ended December 31 were as follows:
Millions of Dollars
2020
2019
2018
Compensation cost
$
Tax benefit
Stock Options
—
The following summarizes our stock option activity for the year ended December 31, 2020:
Millions of Dollars
Weighted-Average
Aggregate
Options
Exercise Price
Intrinsic Value
Outstanding at December 31, 2019
$
$
Exercised
(1,111,805 )
Forfeited
(5,867 )
Expired or cancelled
Outstanding at December 31, 2020
$
$
Vested at December 31, 2020
$
$
Exercisable at December 31, 2020
$
$
The weighted-average remaining contractual term of outstanding options, vested options and exercisable
options at December 31, 2020, were all
million in 2019 and $
During 2020, we received $
options. At December 31, 2020, all outstanding stock options were fully vested and there was no remaining
compensation cost to be recorded.
Stock Unit Program—
.
Stock-Settled
135
.
The following summarizes our stock-settled stock unit activity for the year ended December 31, 2020:
Weighted-Average
Millions of Dollars
Stock Units
Grant Date Fair Value
Total Fair Value
Outstanding at December 31, 2019
$
Granted
Forfeited
(127,181 )
Issued
(2,554,720 )
$
Outstanding at December 31, 2020
$
Not Vested at December 31, 2020
At December 31, 2020, the remaining unrecognized compensation cost from the unvested stock-settled units
was $
being
2018 was $
, respectively. The total fair value of stock units issued during 2019 and 2018 was
$
Cash-Settled
136
The following summarizes our cash-settled stock unit activity for the year ended December 31, 2020:
Weighted-Average
Millions of Dollars
Stock Units
Grant Date Fair Value
Total Fair Value
Outstanding at December 31, 2019
$
Granted
Forfeited
(5,622 )
Issued
(1,191 )
$
Outstanding at December 31, 2020
$
Not Vested at December 31, 2020
At December 31, 2020, the remaining unrecognized compensation cost from the unvested cash-settled units
was $
were $
, respectively. The total fair value of stock units issued during 2019 and 2018 were $
million 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
137
The following summarizes our stock-settled Performance Share Program activity for the year ended
December 31, 2020:
Weighted-Average
Millions of Dollars
Stock Units
Grant Date Fair Value
Total Fair Value
Outstanding at December 31, 2019
$
Granted
Forfeited
Issued
(314,340 )
$
Outstanding at December 31, 2020
$
Not Vested at December 31, 2020
$
At December 31, 2020, the remaining unrecognized compensation cost from unvested stock-settled
performance share awards was
. The weighted-average grant date fair value of stock-settled PSUs granted
during 2019 and 2018 was $
, respectively. The total fair value of stock-settled PSUs issued
during 2019 and 2018 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.
138
The following summarizes our cash-settled Performance Share Program activity for the year ended
December 31, 2020:
Weighted-Average
Millions of Dollars
Stock Units
Grant Date Fair Value
Total Fair Value
Outstanding at December 31, 2019
$
Granted
Forfeited
Settled
(1,975,843 )
$
Outstanding at December 31, 2020
$
At December 31, 2020, 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 2019 and 2018 was $
, respectively. The total fair value of cash-settled
performance share awards settled during 2019 and 2018 was $
From inception of the Performance Share Program through 2013, approved PSU awards were granted after the
conclusion of performance periods.
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 or as part of an executive compensation program that
has been discontinued. 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, 2020:
Weighted-Average
Millions of Dollars
Stock Units
Grant Date Fair Value
Total Fair Value
Outstanding at December 31, 2019
$
Granted
Cancelled
(1,336 )
Issued
(98,297 )
$
Outstanding at December 31, 2020
$
At December 31, 2020, all outstanding restricted stock and restricted stock units were fully vested and there
was
granted during 2019 and 2018 was $
, respectively. The total fair value of awards issued
during 2019 and 2018 was $
139
Note 18—Income Taxes
Components of income tax expense (benefit) were:
Millions of Dollars
2020
2019
2018
Income Taxes
Federal
Current
$
Deferred
(625 )
(113 )
Foreign
Current
Deferred
(70 )
(323 )
(166 )
State and local
Current
(4 )
Deferred
(139 )
(8 )
(96 )
$
(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
2020
2019
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
(9,965 )
(10,214 )
Total deferred tax assets net of valuation allowance
Net deferred tax liabilities
$
At December 31, 2020, noncurrent assets and liabilities included deferred taxes of $
million and
$
of $
million and $
At December 31, 2020, the loss and credit carryforward deferred tax assets were primarily related to U.S.
foreign tax credit carryforwards of $
carryforwards of $
expire in 2021.
140
The following table shows a reconciliation of the beginning and ending deferred tax asset valuation allowance
for
for 2020, 2019 and 2018:
Millions of Dollars
2020
2019
2018
Balance at January 1
$
Charged to expense (benefit)
(225 )
(26 )
Other*
(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. Certain items in the prior year have been reclassed to conform with the current year
presentation, with no impacts to beginning and ending balances.
Valuation allowances have been established to reduce deferred tax assets to an amount that will, more likely
than not, be realized. At December 31, 2020, 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 2020, the valuation allowance movement charged to earnings primarily relates to
capital losses in Australia and to the fair value measurement of our Cenovus Energy common shares that are
not expected 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.
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 $
foreign tax credit carryovers where recognition was previously considered to be remote. Present legislation
still makes their realization unlikely and therefore these credits have been offset with a full valuation
allowance.
At December 31, 2020, unremitted income considered to be permanently reinvested in certain foreign
subsidiaries and foreign corporate joint ventures totaled approximately $
have not been provided on this amount, as we do not plan to initiate any action that would require the payment
of income taxes. The estimated amount of additional tax, primarily local withholding tax, that would be
payable on this income if distributed is approximately $
The following table shows a reconciliation of the beginning and ending unrecognized tax benefits for 2020,
2019 and 2018:
Millions of Dollars
2020
2019
2018
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
(34 )
(22 )
(73 )
Settlements
(9 )
(9 )
(35 )
Lapse of statute
(1 )
(2 )
(4 )
Balance at December 31
$
Included in the balance of unrecognized tax benefits for 2020, 2019 and 2018 were $
$
141
balance of the unrecognized tax benefits increased in 2019 mainly due to the treatment of our PDVSA
settlement. The balance of the unrecognized tax benefits increased in 2018 mainly due to the treatment of
distributions from certain foreign subsidiaries. See Note 12—Contingencies and Commitments, for more
information on the PDVSA settlement.
At December 31, 2020, 2019 and 2018, accrued liabilities for interest and penalties totaled $
$
reduction to earnings of $
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: U.K. (2015), Canada (2014), U.S. (2014) and Norway (2019).
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. 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.
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)
2020
2019
2018
2020
2019
2018
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 Legislation
(10 )
(0.1 )
Australia disposition
(349 )
U.K. disposition
(732 )
(150 )
(7.7 )
(1.5 )
Recovery of outside basis
(22 )
(77 )
(21 )
(0.8 )
(0.2 )
Adjustment to tax reserves
(4 )
(0.6 )
Adjustment to valuation allowance
(225 )
(26 )
(14.6 )
(2.4 )
(0.3 )
State income tax
(112 )
Malaysia Deepwater Incentive
(164 )
(1.7 )
Enhanced oil recovery credit
(6 )
(27 )
(99 )
(0.3 )
(1.0 )
Other
(9 )
(39 )
(18 )
(0.4 )
(0.2 )
$
(485 )
%
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 Cenovus Energy common shares. The
Australia-West disposition generated a before-tax gain of $
million and resulted in the de-recognition of deferred tax assets resulting in $
disposition also generated an Australia capital loss tax benefit of $
valuation allowance. Due to changes in the fair market value of Cenovus Energy common shares, the
valuation allowance was increased by $
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 $
142
million. The disposition generated a U.S. capital loss of approximately $
tax benefit of approximately $
asset fully offset with a valuation allowance. See Note 4—Asset Acquisitions and Dispositions, for additional
information on the disposition.
During the third quarter of 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 $
The decrease in the effective tax rate for 2018 was primarily due to the impact of the Clair Field disposition in
the U.K. and our overall income position, partially offset by our change in mix of income among taxing
jurisdictions. Our effective tax rate for 2018 was favorably impacted by the sale of a U.K. subsidiary to BP.
The subsidiary held
disposition generated a before-tax gain of $
Acquisitions and Dispositions, for additional information on the disposition.
As a result of the COVID-19 pandemic and the resulting economic uncertainty, many countries in which we
operate, including Australia, Canada, Norway and the U.S., have enacted responsive tax legislation. During
the second quarter, Norway enacted legislation to accelerate the recovery of capital expenditures and allow
immediate monetization of tax losses. As a result, in the second quarter of 2020, we recorded an increase to
our net deferred tax liability of $
$
Note 19—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
Loss on
Securities
Foreign
Currency
Translation
Accumulated
Other
Comprehensive
Loss
December 31, 2017
$
(400 )
(58 )
(5,060 )
(5,518 )
Other comprehensive income (loss)
(642 )
(603 )
Cumulative effect of adopting ASU No. 2016-01*
-
-
December 31, 2018
(361 )
(5,702 )
(6,063 )
Other comprehensive income
-
Cumulative effect of adopting ASU No. 2018-02**
(40 )
-
-
(40 )
December 31, 2019
(350 )
(5,007 )
(5,357 )
Other comprehensive income (loss)
(75 )
December 31, 2020
$
(425 )
(4,795 )
(5,218 )
1, 2019.
During 2019, we recognized $
of our sale of two ConocoPhillips U.K. subsidiaries. For additional information related to this disposition, see
Note 4—Asset Acquisitions and Dispositions.
143
The following table summarizes reclassifications out of accumulated other comprehensive loss during the years
ended December 31:
Millions of Dollars
2020
2019
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 17—Employee Benefit Plans, for additional information.
Note 20—Cash Flow Information
Millions of Dollars
2020
2019
2018
Noncash Investing Activities
Increase (decrease) in PP&E related to an increase (decrease) in asset
retirement obligations
$
(116 )
Increase (decrease) in assets and liabilities acquired in a nonmonetary
exchange*
Accounts receivable
(44 )
Inventories
Investments and long-term receivables
PP&E
Other long-term assets
(9 )
Accounts payable
Accrued income and other taxes
Cash Payments
Interest
$
Income taxes
Net Sales (Purchases) of Investments
Short-term investments purchased
$
(12,435 )
(4,902 )
(1,953 )
Short-term investments sold
Investments and long-term receivables purchased
(325 )
(146 )
Investments and long-term receivables sold
$
(658 )
(2,910 )
*See Note 4—Asset Acquisitions and Dispositions.
The following items are included in the “Cash Flows from Operating Activities” section of our consolidated
cash flows.
We collected $
agreement related to an award issued by the ICC Tribunal in 2018. For more information on these settlements,
see Note 12—Contingencies and Commitments. We collected $
installment payments related to an agreement reached with Ecuador in 2017.
In 2019, we made a $
our domestic qualified pension plan of $
144
Note 21—Other Financial Information
Millions of Dollars
2020
2019
2018
Interest and Debt Expense
Incurred
Debt
$
Other
Capitalized
(55 )
(57 )
(170 )
Expensed
$
Other Income (Loss)
Interest income
$
Unrealized gains (losses) on Cenovus Energy common shares*
(855 )
(437 )
Other, net
$
(509 )
*See Note 6—Investment in Cenovus Energy, for additional information.
Research and Development Expenditures
—expensed
$
Shipping and Handling Costs
$
Foreign Currency Transaction (Gains) Losses
—after-tax
Alaska
$
Lower 48
Canada
(7 )
(11 )
Europe, Middle East and North Africa
(15 )
(26 )
Asia Pacific
(11 )
Other International
Corporate and Other
(31 )
$
(62 )
(13 )
Millions of Dollars
2020
2019
Properties, Plants and Equipment
Proved properties
$
*
Unproved properties
*
Other
Gross properties, plants and equipment
Less: Accumulated depreciation, depletion and amortization
(62,213 )
(55,477 )
*
Net properties, plants and equipment
$
*Excludes assets classified as held for sale at December 31, 2019. See Note 4
—
Asset Acquisitions and Dispositions, for additional information.
145
Note 22—Related Party Transactions
Our related parties primarily include equity method investments and certain trusts for the benefit of employees.
For disclosures on trusts for the benefit of employees, see Note 17
—
Employee Benefit Plans.
Significant transactions with our equity affiliates were:
Millions of Dollars
2020
2019
2018
Operating revenues and other income
$
Purchases
Operating expenses and selling, general and administrative expenses
Net interest income*
(5 )
(13 )
(14 )
*We paid interest to, or received interest from, various affiliates. See Note 5—Investments, Loans and Long-Term Receivables, for additional
Note 23—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
2020
2019
2018
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
(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 Note 24—Segment Disclosures and Related
Information:
Millions of Dollars
2020
2019
2018
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
$
146
Millions of Dollars
2020
2019
2018
Revenue from Outside the Scope of ASC Topic 606
by Product
Crude oil
$
Natural gas
Other
Physical contracts meeting the definition of a derivative
$
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, 2020, the “Accounts and notes receivable” line on our consolidated balance sheet included
trade receivables of $
contracts with customers within the scope of ASC Topic 606 and those that are outside the scope of ASC
Topic 606.
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, 2019
$
Contractual payments received
At December 31, 2020
$
Amounts Recognized in the Consolidated Balance Sheet at December 31, 2020
Current liabilities
$
Noncurrent liabilities
$
There was no revenue recognized during the year ended December 31, 2020.
147
Note 24—Segment Disclosures and Related Information
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and NGLs on a worldwide
basis. We manage our operations through
six
region: Alaska; Lower 48; Canada; Europe, Middle East and North Africa; Asia Pacific; and Other
International.
Corporate and Other represents income and costs not directly associated with an operating segment, such as
most interest expense, premiums on early retirement of debt, corporate overhead and certain technology
activities, including licensing revenues. Corporate assets include all cash and cash equivalents and short-term
investments.
We evaluate performance and allocate resources based on net income (loss) attributable to ConocoPhillips.
Segment accounting policies are the same as those in Note 1—Accounting Policies. Intersegment sales are at
prices that approximate market.
Effective with the third quarter of 2020, we restructured our segments to align with changes to our internal
organization. The Middle East business was realigned from the Asia Pacific and Middle East segment to the
Europe and North Africa segment. The segments have been renamed the Asia Pacific segment and the Europe,
Middle East and North Africa segment. We have revised segment information disclosures and segment
performance metrics presented within our results of operations for the current and prior comparative periods.
Analysis of Results by Operating Segment
Millions of Dollars
2020
2019
2018
Sales and Other Operating Revenues
Alaska
$
Intersegment eliminations
(11 )
Alaska
Lower 48
Intersegment eliminations
(51 )
(46 )
(40 )
Lower 48
Canada
Intersegment eliminations
(405 )
(1,141 )
(1,160 )
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.
148
Millions of Dollars
2020
2019
2018
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
(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 )
(96 )
Europe, Middle East and North Africa
Asia Pacific
Other International
(20 )
Corporate and Other
(76 )
(233 )
(103 )
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
(64 )
Corporate and Other
(1,880 )
(1,667 )
Consolidated net income (loss) attributable to ConocoPhillips
$
(2,701 )
149
Millions of Dollars
2020
2019
2018
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.
150
Geographic Information
Millions of Dollars
Sales and Other Operating Revenues
(1)
Long-Lived Assets
(2)
2020
2019
2018
2020
2019
2018
United States
$
Australia and Timor-Leste
Canada
China
Indonesia
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.
Note 25—Acquisition of Concho Resources Inc.
On
, we entered into a definitive agreement to acquire Concho in an all-stock transaction.
The transaction closed on January 15, 2021 and as defined under the terms of the transaction agreement, each
share of Concho common stock was exchanged at a fixed ratio of
stock, for total consideration of $
approximately
transaction.
We also assumed Concho’s outstanding debt of $
value of $
which settled on February 8, 2021, for
Concho were exchanged for new notes issued by ConocoPhillips, which are fully and unconditionally
guaranteed by ConocoPhillips Company. For further discussion about the debt exchange, see Note 10 – Debt.
As of the acquisition date, January 15, 2021, the fair value of consideration transferred is summarized below:
Total Consideration
Number of shares exchanged
1.46
$
$
**Based on the ConocoPhillips average stock price on January 15, 2021.
The transaction will be accounted for as a business combination under the acquisition method of accounting.
The total purchase price will be allocated to identifiable assets acquired and the liabilities assumed based on
151
their fair values as of the closing date. We are currently in the process of finalizing the initial accounting for
this transaction and provisional fair value measurements will be made in the first quarter of 2021. We may
adjust the measurements in subsequent periods, up to one year from the acquisition date as we identify
additional information to complete the necessary analysis.
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, 2020, approximately 6 percent of our total
proved reserves were under PSCs, located in our Asia Pacific/Middle East geographic reporting area, and 8
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
152
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.
We have a companywide, 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 2020, our processes and controls used to assess over 90 percent of proved reserves as of December 31,
2020, 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, 2020, 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.
153
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 2017
937
707
1,644
1
296
185
196
2,322
Revisions
72
(90)
(18)
2
24
6
5
19
Improved recovery
2
-
2
-
-
-
-
2
Purchases
233
1
234
-
-
-
-
234
Extensions and discoveries
48
179
227
2
2
1
-
232
Production
(59)
(82)
(141)
(1)
(40)
(33)
(13)
(228)
Sales
-
(12)
(12)
-
(36)
-
-
(48)
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
Equity affiliates
End of 2017
-
-
-
-
-
83
-
83
Revisions
-
-
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
-
Production
-
-
-
-
-
(5)
-
(5)
Sales
-
-
-
-
-
-
-
-
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
Total company
End of 2017
937
707
1,644
1
296
268
196
2,405
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
154
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 2017
828
315
1,143
1
190
121
196
1,651
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
Equity affiliates
End of 2017
-
-
-
-
-
83
-
83
End of 2018
-
-
-
-
-
78
-
78
End of 2019
-
-
-
-
-
73
-
73
End of 2020
-
-
-
-
-
68
-
68
Undeveloped
Consolidated operations
End of 2017
109
392
501
-
106
64
-
671
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
Equity affiliates
End of 2017
-
-
-
-
-
-
-
-
End of 2018
-
-
-
-
-
-
-
-
End of 2019
-
-
-
-
-
-
-
-
End of 2020
-
-
-
-
-
-
-
-
Notable changes in proved crude oil reserves in the three years ended December 31, 2020, included:
●
Revisions
: 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.
In 2018, downward revisions in Lower 48 were primarily due to changes in development timing for specific well
locations from the unconventional plays and are more than offset by increases in planned well locations in the
unconventional plays in the extensions and discoveries category. Downward revisions in Lower 48 due to development
timing were partially offset by higher prices. Revisions in Alaska, Europe and Asia Pacific/Middle East were primarily
due to higher prices.
●
Purchases:
155
●
Extensions and discoveries
: 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.
In 2018, extensions and discoveries in Lower 48 were primarily due to changes in the development strategy to add
specific well locations from the unconventional plays. Extensions and discoveries in Alaska were driven by drilling
success in Western North Slope.
●
Sales
: In 2019, Europe sales represent the disposition of the U.K. assets. In 2018, Europe sales were due to the
disposition of a subsidiary that held 16.5 percent of our 24 percent interest in the Clair Field in the U.K.
156
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 2017
106
224
330
1
18
5
354
Revisions
5
(25)
(20)
-
1
(1)
(20)
Improved recovery
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
Extensions and discoveries
-
69
69
-
1
-
70
Production
(5)
(25)
(30)
-
(3)
(1)
(34)
Sales
-
(21)
(21)
-
-
-
(21)
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
Equity affiliates
End of 2017
-
-
-
-
-
45
45
Revisions
-
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
Production
-
-
-
-
-
(3)
(3)
Sales
-
-
-
-
-
-
-
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
Total company
End of 2017
106
224
330
1
18
50
399
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
157
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 2017
106
101
207
1
16
2
226
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
Equity affiliates
End of 2017
-
-
-
-
-
45
45
End of 2018
-
-
-
-
-
42
42
End of 2019
-
-
-
-
-
39
39
End of 2020
-
-
-
-
-
36
36
Undeveloped
Consolidated operations
End of 2017
-
123
123
-
2
3
128
End of 2018
-
125
125
1
2
-
128
End of 2019
-
146
146
1
3
-
150
End of 2020
-
147
147
-
3
-
150
Equity affiliates
End of 2017
-
-
-
-
-
-
-
End of 2018
-
-
-
-
-
-
-
End of 2019
-
-
-
-
-
-
-
End of 2020
-
-
-
-
-
-
-
Notable changes in proved NGL reserves in the three years ended December 31, 2020, included:
●
Revisions
: 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.
In 2018, downward revisions in Lower 48 were primarily due to changes in development timing for specific well
locations from the unconventional plays and are more than offset by increases in planned well locations in the
unconventional plays in the extensions and discoveries category.
●
Extensions and discoveries
: 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.
In 2018, extensions and discoveries in Lower 48 were primarily due to changes in the development strategy to add
specific well locations from the unconventional plays.
●
Sales
: In 2019, Europe sales represent the disposition of the U.K. assets. In 2018, Lower 48 sales were primarily due to
the disposition of our interests in the Barnett.
158
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 2017
2,320
2,533
4,853
11
1,217
1,298
224
7,603
Revisions
150
(283)
(133)
9
86
4
-
(34)
Improved recovery
-
-
-
-
-
-
-
-
Purchases
335
1
336
-
-
-
-
336
Extensions and discoveries
2
527
529
11
110
23
-
673
Production
(71)
(237)
(308)
(5)
(188)
(246)
(10)
(757)
Sales
-
(223)
(223)
-
(13)
-
-
(236)
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
Equity affiliates
End of 2017
-
-
-
-
-
4,303
-
4,303
Revisions
-
-
-
-
-
280
-
280
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
362
-
362
Production
-
-
-
-
-
(381)
-
(381)
Sales
-
-
-
-
-
-
-
-
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
Total company
End of 2017
2,320
2,533
4,853
11
1,217
5,601
224
11,906
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
159
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 2017
2,310
1,597
3,907
11
997
945
224
6,084
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
Equity affiliates
End of 2017
-
-
-
-
-
4,044
-
4,044
End of 2018
-
-
-
-
-
4,059
-
4,059
End of 2019
-
-
-
-
-
3,898
-
3,898
End of 2020
-
-
-
-
-
3,293
-
3,293
Undeveloped
Consolidated operations
End of 2017
10
936
946
-
220
353
-
1,519
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
Equity affiliates
End of 2017
-
-
-
-
-
259
-
259
End of 2018
-
-
-
-
-
505
-
505
End of 2019
-
-
-
-
-
523
-
523
End of 2020
-
-
-
-
-
431
-
431
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 2,286 Bcf, 3,141 Bcf, and 3,131 Bcf as of December 31,
2020, 2019 and 2018, 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, 2020, included:
●
Revisions
: 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 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.
160
In 2018, downward revisions in Lower 48 were primarily due to changes in development timing for specific well
locations from the unconventional plays and are more than offset by increases in planned well locations in the
unconventional plays in the extensions and discoveries category. Downward revisions in Lower 48 due to development
timing were partially offset by higher prices. Revisions in Alaska, Canada, Europe and our equity affiliates in Asia
Pacific/Middle East were primarily due to higher prices.
●
Purchases
: In 2020, Canada purchases were due to the acquisition of additional Montney acreage.
In 2018, Alaska purchases were due to the Greater Kuparuk Area and Western North Slope acquisitions.
●
Extensions and discoveries
: 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.
In 2018, extensions and discoveries in Lower 48 were primarily due to changes in the development strategy to add
specific well locations from the unconventional plays. Extensions and discoveries in Canada, Europe and our equity
affiliates in Asia Pacific/Middle East were primarily driven by ongoing drilling successes in Montney, Norway and
APLNG, respectively.
●
Sales
: 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.
In 2018, Lower 48 sales were primarily due to the disposition of our interest in Barnett.
161
Years Ended
Bitumen
December 31
Millions of Barrels
Canada
Developed and Undeveloped
Consolidated operations
End of 2017
250
Revisions
10
Improved recovery
-
Purchases
-
Extensions and discoveries
-
Production
(24)
Sales
-
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
Equity affiliates
End of 2017
-
Revisions
-
Improved recovery
-
Purchases
-
Extensions and discoveries
-
Production
-
Sales
-
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
-
Total company
End of 2017
250
End of 2018
236
End of 2019
282
End of 2020
332
162
Years Ended
Bitumen
December 31
Millions of Barrels
Canada
Developed
Consolidated operations
End of 2017
154
End of 2018
155
End of 2019
187
End of 2020
117
Equity affiliates
End of 2017
-
End of 2018
-
End of 2019
-
End of 2020
-
Undeveloped
Consolidated operations
End of 2017
96
End of 2018
81
End of 2019
95
End of 2020
215
Equity affiliates
End of 2017
-
End of 2018
-
End of 2019
-
End of 2020
-
Notable changes in proved bitumen reserves in the three years ended December 31, 2020, included:
●
Revisions
: 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.
In 2018, revisions were primarily due to higher prices at Surmont.
●
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.
163
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 2017
1,430
1,353
2,783
254
517
406
233
4,193
Revisions
102
(161)
(59)
12
40
5
6
4
Improved recovery
2
-
2
-
-
-
-
2
Purchases
289
1
290
-
-
-
-
290
Extensions and discoveries
48
335
383
4
21
6
-
414
Production
(76)
(146)
(222)
(25)
(75)
(75)
(15)
(412)
Sales
-
(70)
(70)
-
(38)
-
-
(108)
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
Equity affiliates
End of 2017
-
-
-
-
-
845
-
845
Revisions
-
-
-
-
-
46
-
46
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
60
-
60
Production
-
-
-
-
-
(71)
-
(71)
Sales
-
-
-
-
-
-
-
-
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
Total company
End of 2017
1,430
1,353
2,783
254
517
1,251
233
5,038
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
164
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 2017
1,319
682
2,001
158
372
281
233
3,045
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
Equity affiliates
End of 2017
-
-
-
-
-
802
-
802
End of 2018
-
-
-
-
-
796
-
796
End of 2019
-
-
-
-
-
761
-
761
End of 2020
-
-
-
-
-
653
-
653
Undeveloped
Consolidated operations
End of 2017
111
671
782
96
145
125
-
1,148
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
Equity affiliates
End of 2017
-
-
-
-
-
43
-
43
End of 2018
-
-
-
-
-
84
-
84
End of 2019
-
-
-
-
-
87
-
87
End of 2020
-
-
-
-
-
72
-
72
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 2020:
Proved Undeveloped Reserves
Millions of Barrels of
Oil Equivalent
End of 2019
1,327
Revisions
(205)
Improved recovery
3
Purchases
7
Extensions and discoveries
304
Sales
-
Transfers to proved developed
(138)
End of 2020
1,298
Downward revisions were driven by changes in development timing of 137 MMBOE primarily in North America and lower
prices of 103 MMBOE, partially offset by upward revisions for infill drilling of 35 MMBOE primarily in Lower 48 and Europe.
Extensions and discoveries were largely driven by an addition of 196 MMBOE in Lower 48 for the continued development of
unconventional plays. The remaining extensions and discoveries were driven by the continued development planned in Canada,
Asia Pacific/Middle East and Alaska.
165
Transfers to proved developed reserves were driven by the ongoing development of our assets. Approximately half of the
transfers were from the development of our Lower 48 unconventional plays. The remainder of transfers were from development
across the Alaska, Asia Pacific/Middle East and Europe regions.
At December 31, 2020, our PUDs represented 29 percent of total proved reserves, compared with 25 percent at December 31,
2019. Costs incurred for the year ended December 31, 2020, relating to the development of PUDs were $3.2 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 2020, more than 97 percent of total PUDs were under development or scheduled for development within five
years of initial disclosure, including our PUDs in North America. The remaining PUDs are in major development areas which
are currently producing and within our Asia Pacific/Middle East geographic area.
Results of Operations
The company’s results of operations from oil and gas activities for the years 2020, 2019 and 2018 are shown in the following
tables. Non-oil and gas activities, such as pipeline and marine operations, LNG operations, crude oil and gas marketing
activities, and the profit element of transportation operations in which we have an ownership interest are excluded. Additional
information about selected line items within the results of operations tables is shown below:
●
Sales include sales to unaffiliated entities attributable primarily to the company’s net working interests and royalty
interests. Sales are net of fees to transport our produced hydrocarbons beyond the production function to a final
delivery point using transportation operations which are not consolidated.
●
Transportation costs reflect fees to transport our produced hydrocarbons beyond the production function to a final
delivery point using transportation operations which are consolidated.
●
Other revenues include gains and losses from asset sales, certain amounts resulting from the purchase and sale of
hydrocarbons, and other miscellaneous income.
●
Production costs include costs incurred to operate and maintain wells, related equipment and facilities used in the
production of petroleum liquids and natural gas.
●
Taxes other than income taxes include production, property and other non-income taxes.
●
Depreciation of support equipment is reclassified as applicable.
●
Other related expenses include inventory fluctuations, foreign currency transaction gains and losses and other
miscellaneous expenses.
166
Results of Operations
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
167
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
168
Year Ended
Millions of Dollars
December 31, 2018
Lower
Total
Asia Pacific/
Other
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Areas
Total
Consolidated operations
Sales
$
4,816
6,573
11,389
582
4,449
3,177
950
-
20,547
Transfers
5
-
5
-
-
545
-
-
550
Transportation costs
(722)
-
(722)
-
-
(45)
-
-
(767)
Other revenues
335
213
548
164
737
6
110
432
1,997
Total revenues
4,434
6,786
11,220
746
5,186
3,683
1,060
432
22,327
Production costs excluding taxes
964
1,533
2,497
417
856
646
62
2
4,480
Taxes other than income taxes
357
432
789
21
33
95
3
-
941
Exploration expenses
59
176
235
21
57
43
(4)
20
372
Depreciation, depletion and
amortization
616
2,279
2,895
313
1,070
1,186
33
-
5,497
Impairments
1
64
65
9
(78)
14
-
-
10
Other related expenses
16
63
79
56
(62)
(19)
1
(1)
54
Accretion
56
51
107
7
178
39
-
-
331
2,365
2,188
4,553
(98)
3,132
1,679
965
411
10,642
Income tax provision (benefit)
419
466
885
(114)
1,354
683
926
(8)
3,726
Results of operations
$
1,946
1,722
3,668
16
1,778
996
39
419
6,916
Equity affiliates
Sales
$
-
-
-
-
-
758
-
-
758
Transfers
-
-
-
-
-
2,018
-
-
2,018
Transportation costs
-
-
-
-
-
-
-
-
-
Other revenues
-
-
-
-
-
(6)
-
-
(6)
Total revenues
-
-
-
-
-
2,770
-
-
2,770
Production costs excluding taxes
-
-
-
-
-
321
-
-
321
Taxes other than income taxes
-
-
-
-
-
804
-
-
804
Exploration expenses
-
-
-
-
-
-
-
-
-
Depreciation, depletion and
-
-
-
-
amortization
-
-
-
-
-
640
-
-
640
Impairments
-
-
-
-
-
-
-
-
-
Other related expenses
-
-
-
-
-
(4)
-
-
(4)
Accretion
-
-
-
-
-
15
-
-
15
-
-
-
-
-
994
-
-
994
Income tax provision (benefit)
-
-
-
-
-
103
-
-
103
Results of operations
$
-
-
-
-
-
891
-
-
891
169
Statistics
Net Production
2020
2019
2018
Thousands of Barrels Daily
Crude Oil
Consolidated operations
Alaska
181
202
171
Lower 48
213
266
229
United States
394
468
400
Canada
6
1
1
Europe
78
100
113
Asia Pacific
69
85
89
Africa
8
38
36
Total consolidated operations
555
692
639
Equity affiliates—
Asia Pacific/Middle East
13
13
14
Total company
568
705
653
Greater Prudhoe Area (Alaska)*
68
66
71
Natural Gas Liquids
Consolidated operations
Alaska
16
15
14
Lower 48
74
81
69
United States
90
96
83
Canada
2
-
1
Europe
4
7
8
Asia Pacific
1
4
3
Total consolidated operations
97
107
95
Equity affiliates—
Asia Pacific/Middle East
8
8
7
Total company
105
115
102
Greater Prudhoe Area (Alaska)*
15
15
14
Bitumen
Consolidated operations—
Canada
55
60
66
Total company
55
60
66
Natural Gas
Millions of Cubic Feet Daily
Consolidated operations
Alaska
10
7
6
Lower 48
585
622
596
United States
595
629
602
Canada
40
9
12
Europe
270
447
475
Asia Pacific
429
637
626
Africa
5
31
28
Total consolidated operations
1,339
1,753
1,743
Equity affiliates—
Asia Pacific/Middle East
1,055
1,052
1,031
Total company
2,394
2,805
2,774
Greater Prudhoe Area (Alaska)*
4
4
5
*At year-end 2020 and 2019, the Greater Prudhoe Area in Alaska contained more than 15 percent of our total proved reserves.
170
Average Sales Prices
2020
2019
2018
Crude Oil Per Barrel
Consolidated operations
Alaska*
$
33.72
55.85
60.23
Lower 48
35.17
55.30
62.99
United States
34.48
55.54
61.75
Canada
23.57
40.87
48.73
Europe
42.80
65.12
70.98
Asia Pacific
42.84
65.02
70.93
Africa
48.64
64.47
69.83
Total international
42.39
64.85
70.67
Total consolidated operations
36.69
58.51
65.01
Equity affiliates
—Asia Pacific/Middle East
39.02
61.32
72.49
Total operations
36.75
58.57
65.17
Natural Gas Liquids Per Barrel
Consolidated operations
Lower 48
$
12.13
16.83
27.30
United States
12.13
16.85
27.30
Canada
5.41
19.87
43.70
Europe
23.27
29.37
36.87
Asia Pacific
33.21
37.85
47.20
Total international
20.25
32.29
40.00
Total consolidated operations
12.90
18.73
29.03
Equity affiliates
—Asia Pacific/Middle East
32.69
36.70
45.69
Total operations
14.61
20.09
30.48
Bitumen Per Barrel
Consolidated operations—
Canada
$
8.02
**
31.72
22.29
Natural Gas Per Thousand Cubic Feet
Consolidated operations
Alaska
$
2.91
3.19
2.48
Lower 48
1.65
2.12
2.82
United States
1.66
2.12
2.82
Canada
1.21
0.49
1.00
Europe
3.23
4.92
7.79
Asia Pacific*
5.27
5.73
5.95
Africa
3.71
4.87
4.84
Total international
4.31
5.35
6.64
Total consolidated operations
3.13
4.19
5.33
Equity affiliates
—Asia Pacific/Middle East
3.71
6.29
6.06
Total operations
3.38
4.99
5.60
*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.
171
2020
2019
2018
Average Production Costs Per Barrel of Oil Equivalent*
Consolidated operations
Alaska
$
14.60
15.52
14.20
Lower 48
9.93
9.59
10.58
United States
11.51
11.52
11.73
Canada
14.29
16.53
16.32
Europe
8.97
11.22
11.73
Asia Pacific
9.26
8.74
9.03
Africa
6.38
4.46
4.14
Total international
10.11
10.26
10.72
Total consolidated operations
10.99
10.99
11.26
Equity affiliates—
Asia Pacific/Middle East
4.01
4.68
4.56
Average Production Costs Per Barrel—Bitumen
Consolidated operations—
Canada
$
12.45
13.74
13.59
Taxes Other Than Income Taxes Per Barrel of Oil Equivalent
Consolidated operations
Alaska
$
4.08
3.87
5.26
Lower 48
1.87
2.65
2.98
United States
2.62
3.05
3.71
Canada
0.62
0.78
0.82
Europe
0.65
0.48
0.45
Asia Pacific
0.81
0.76
1.33
Africa
0.91
0.19
0.20
Total international
0.72
0.60
0.82
Total consolidated operations
1.91
2.03
2.37
Equity affiliates—
Asia Pacific/Middle East
6.96
11.46
11.41
Depreciation, Depletion and Amortization Per Barrel of Oil Equivalent
Consolidated operations
Alaska
$
11.59
8.80
9.07
Lower 48
18.05
17.03
15.73
United States
15.86
14.35
13.60
Canada
13.08
10.00
12.25
Europe
16.24
12.75
14.66
Asia Pacific
15.66
16.55
16.58
Africa
2.43
2.36
2.21
Total international
15.01
12.99
14.06
Total consolidated operations
15.54
13.78
13.82
Equity affiliates—
Asia Pacific/Middle East
7.89
8.09
9.09
*Includes bitumen.
172
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, 2020, 2019 and 2018. 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
2020
2019
2018
2020
2019
2018
Exploratory
Consolidated operations
Alaska
-
7
6
3
-
-
Lower 48
3
35
45
-
6
1
United States
3
42
51
3
6
1
Canada
23
-
2
-
-
-
Europe
-
1
*
*
1
*
Asia Pacific/Middle East
*
1
2
*
1
-
Africa
-
-
-
*
-
*
Other areas
-
-
-
*
-
-
Total consolidated operations
26
44
55
3
8
1
Equity affiliates
Asia Pacific/Middle East
8
8
6
-
-
2
Total equity affiliates
8
8
6
-
-
2
Development
Consolidated operations
Alaska
7
12
11
-
-
-
Lower 48
127
255
254
-
-
-
United States
134
267
265
-
-
-
Canada
-
2
1
-
-
-
Europe
7
6
9
-
-
-
Asia Pacific/Middle East
16
21
12
-
-
-
Africa
2
2
1
-
-
-
Other areas
-
-
-
-
-
-
Total consolidated operations
159
298
288
-
-
-
Equity affiliates
Asia Pacific/Middle East
109
106
75
-
-
-
Total equity affiliates
109
106
75
-
-
-
*Our total proportionate interest was less than one.
173
The table below represents the status of our wells drilling at December 31, 2020, 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, 2020.
Wells at December 31, 2020
Productive
In Progress
Oil
Gas
Gross
Net
Gross
Net
Gross
Net
Consolidated operations
Alaska
5
5
1,576
946
-
-
Lower 48
459
240
9,382
4,149
4,182
1,678
United States
464
245
10,958
5,095
4,182
1,678
Canada
24
24
196
103
169
164
Europe
16
3
476
79
59
2
Asia Pacific/Middle East
15
7
337
160
38
18
Africa
7
1
850
139
10
2
Other areas
14
7
-
-
-
-
Total consolidated operations
540
287
12,817
5,576
4,458
1,864
Equity affiliates
Asia Pacific/Middle East
139
32
-
-
4,898
1,154
Total equity affiliates
139
32
-
-
4,898
1,154
Acreage at December 31, 2020
Thousands of Acres
Developed
Undeveloped
Gross
Net
Gross
Net
Consolidated operations
Alaska
659
472
1,345
1,336
Lower 48
3,228
1,974
10,215
8,165
United States
3,887
2,446
11,560
9,501
Canada
293
214
3,417
1,946
Europe
430
50
966
366
Asia Pacific/Middle East
921
421
9,015
5,704
Africa
358
58
12,545
2,049
Other areas
-
-
996
545
Total consolidated operations
5,889
3,189
38,499
20,111
Equity affiliates
Asia Pacific/Middle East
1,026
245
3,820
860
Total equity affiliates
1,026
245
3,820
860
174
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
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
2018
Consolidated operations
Unproved property acquisition
$
119
126
245
126
-
-
-
-
371
Proved property acquisition
2,227
16
2,243
6
-
-
-
-
2,249
2,346
142
2,488
132
-
-
-
-
2,620
Exploration
203
500
703
90
65
82
(6)
41
975
Development
718
2,715
3,433
301
703
773
16
-
5,226
$
3,267
3,357
6,624
523
768
855
10
41
8,821
Equity affiliates
Unproved property acquisition
$
-
-
-
-
-
-
-
-
-
Proved property acquisition
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Exploration
-
-
-
-
-
22
-
-
22
Development
-
-
-
-
-
206
-
-
206
$
-
-
-
-
-
228
-
-
228
175
Capitalized Costs
At December 31
Millions of Dollars
Lower
Total
Asia Pacific/
Other
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Areas
Total
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
2019
Consolidated operations
Proved property
$
20,957
37,491
58,448
6,673
14,113
14,566
924
-
94,724
Unproved property
1,429
1,055
2,484
1,149
87
501
123
290
4,634
22,386
38,546
60,932
7,822
14,200
15,067
1,047
290
99,358
Accumulated depreciation,
depletion and amortization
9,419
26,294
35,713
2,050
9,017
10,253
379
9
57,421
$
12,967
12,252
25,219
5,772
5,183
4,814
668
281
41,937
Equity affiliates
Proved property
$
-
-
-
-
-
9,996
-
-
9,996
Unproved property
-
-
-
-
-
2,223
-
-
2,223
-
-
-
-
-
12,219
-
-
12,219
Accumulated depreciation,
depletion and amortization
-
-
-
-
-
6,390
-
-
6,390
$
-
-
-
-
-
5,829
-
-
5,829
176
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities
In accordance with SEC and FASB requirements, amounts were computed using 12-month average prices (adjusted only for
existing contractual terms) and end-of-year costs, appropriate statutory tax rates and a prescribed 10 percent discount factor.
Twelve-month average prices are calculated as the unweighted arithmetic average of the first-day-of-the-month price for each
month within the 12-month period prior to the end of the reporting period. For all years, continuation of year-end economic
conditions was assumed. The calculations were based on estimates of proved reserves, which are revised over time as new data
becomes available. Probable or possible reserves, which may become proved in the future, were not considered. The
calculations also require assumptions as to the timing of future production of proved reserves and the timing and amount of
future development costs, including dismantlement, and future production costs, including taxes other than income taxes.
While due care was taken in its preparation, we do not represent that this data is the fair value of our oil and gas properties, or a
fair estimate of the present value of cash flows to be obtained from their development and production.
Discounted Future Net Cash Flows
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.
177
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
Millions of Dollars
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Total
2018
Consolidated operations
Future cash inflows
$
82,072
56,922
138,994
6,039
26,989
16,368
16,434
204,824
Less:
Future production costs
42,755
21,363
64,118
4,099
8,567
5,705
1,336
83,825
Future development costs
10,053
12,136
22,189
606
7,608
1,995
507
32,905
Future income tax provisions
5,538
4,418
9,956
7,102
2,873
13,492
33,423
Future net cash flows
23,726
19,005
42,731
1,334
3,712
5,795
1,099
54,671
10 percent annual discount
10,349
6,461
16,810
426
371
1,132
498
19,237
Discounted future net cash flows
$
13,377
12,544
25,921
908
3,341
4,663
601
35,434
Equity affiliates
Future cash inflows
$
-
-
-
-
-
33,606
-
33,606
Less:
Future production costs
-
-
-
-
-
16,449
-
16,449
Future development costs
-
-
-
-
-
1,228
-
1,228
Future income tax provisions
-
-
-
-
-
3,147
-
3,147
Future net cash flows
-
-
-
-
-
12,782
-
12,782
10 percent annual discount
-
-
-
-
-
4,853
-
4,853
Discounted future net cash flows
$
-
-
-
-
-
7,929
-
7,929
Total company
Discounted future net cash flows
$
13,377
12,544
25,921
908
3,341
12,592
601
43,363
178
Sources of Change in Discounted Future Net Cash Flows
Millions of Dollars
Consolidated Operations
Equity Affiliates
Total Company
2020
2019
2018
2020
2019
2018
2020
2019
2018
Discounted future net cash flows
at the beginning of the year
$
27,372
35,434
20,609
7,170
7,929
4,395
34,542
43,363
25,004
Changes during the year
Revenues less production
costs for the year
(5,198)
(13,424)
(14,909)
(897)
(1,673)
(1,651)
(6,095)
(15,097)
(16,560)
Net change in prices and
production costs
(34,307)
(13,538)
25,391
(4,769)
(422)
4,559
(39,076)
(13,960)
29,950
Extensions, discoveries and
improved recovery, less
estimated future costs
887
2,985
4,574
22
260
382
909
3,245
4,956
Development costs for the year
3,593
5,333
5,197
192
239
271
3,785
5,572
5,468
Changes in estimated future
development costs
754
559
(1,141)
(205)
(21)
14
549
538
(1,127)
Purchases of reserves in place,
less estimated future costs
1
10
3,033
(3)
-
-
(2)
10
3,033
Sales of reserves in place,
less estimated future costs
(302)
(1,997)
(1,531)
-
-
-
(302)
(1,997)
(1,531)
Revisions of previous quantity
estimates
(2,299)
2,099
(365)
(42)
69
62
(2,341)
2,168
(303)
Accretion of discount
3,984
5,144
3,055
804
869
485
4,788
6,013
3,540
Net change in income taxes
10,189
4,767
(8,479)
590
(80)
(588)
10,779
4,687
(9,067)
Total changes
(22,698)
(8,062)
14,825
(4,308)
(759)
3,534
(27,006)
(8,821)
18,359
Discounted future net cash flows
at year end
$
4,674
27,372
35,434
2,862
7,170
7,929
7,536
34,542
43,363
●
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.
179
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, 2020, 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, 2020.
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
Item 9B. OTHER INFORMATION
None.
180
PART III
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information regarding our executive officers appears in Part I of this report on page 33.
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
.
waivers of the Code of Ethics must be approved, in advance, by our full Board of Directors. Any amendments
to, or waivers from, the Code of Ethics that apply to our executive officers and directors will be posted on the
“Corporate Governance” section of our internet website.
All other information required by Item 10 of Part III will be included in our Proxy Statement relating to our
2021 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2021, 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 2021
Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2021, 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 2021
Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2021, 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 2021
Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2021, 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 2021
Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before April 30, 2021, 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 2021 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.
181
PART IV
Item 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULE
S
(a)
1.
Financial Statements and Supplementary Data
The financial statements and supplementary information listed in the Index to Financial Statements,
which appears on page
, are filed as part of this annual report.
2.
Financial Statement Schedule
s
All financial statement schedules are omitted because they are not required, not significant, not
applicable or the information is shown in another schedule, the financial statements or the notes to
consolidated financial statements.
3.
Exhibits
The exhibits listed in the Index to Exhibits, which appears on pages
of this annual report.
182
CONOCOPHILLIPS
INDEX TO EXHIBITS
Exhibit
Number
Description
2.1
2.2†‡
2.3†‡
2.4
3.1
3.2
3.3
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
183
10.1
10.2
10.3
10.4
10.5
10.7
10.8
10.9
10.10.1
10.10.2
10.11.1
10.11.2
10.12
184
10.15
10.16.1
10.16.2
10.16.3
10.16.4
10.16.5
10.16.6
10.16.7
10.16.8
10.17.1
10.17.2
10.18
10.19.1
185
10.19.2
10.20
10.21
10.22.1
10.22.2
10.22.3
10.23
10.24
10.25.1
10.25.2
10.25.3
10.25.4
186
10.25.6
10.25.7
10.25.8
10.25.9
10.25.10
10.25.11
10.25.12
10.25.14
10.25.17
10.25.18
187
10.26.1
10.26.2
10.26.3
10.26.4
10.26.7
10.26.8
10.26.9
10.26.10
10.26.11
10.26.12
188
10.26.13
10.26.14
10.26.15
10.27
10.28
10.29
10.30
10.30.1
10.30.2
10.31
10.32
189
10.33
10.34
10.35
10.36
10.37
10.38
10.40
10.41
10.42
21*
22
*
23.1*
23.2*
31.1*
31.2*
190
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.
†
furnish a copy of any schedule omitted from this exhibit to the SEC upon request.
‡
under the Securities Exchange Act of 1934, as amended.
191
SIGNATURES
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 16, 2021
/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 16, 2021, 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/ Catherine A. Brooks
Vice President and Controller
Catherine A. Brooks
(Principal accounting officer)
192
/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