10-K
CONOCOPHILLIPS (COP)
2020
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington,
D.C. 20549
Form
10-K
(Mark One)
[
X
]
ANNUAL REPORT PURSUANT
TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended
December 31, 2020
OR
[
]
TRANSITION REPORT PURSUANT
TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from
to
Commission file number:
001-32395
ConocoPhillips
(Exact name of registrant as specified in its
charter)
Delaware
01-0562944
(State or other jurisdiction of
(I.R.S. Employer
incorporation or organization)
Identification No.)
925 N. Eldridge Parkway
Houston
,
TX
77079
(Address of principal executive offices)
(Zip Code)
Registrant's telephone number, including
area code:
281
-
293-1000
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Trading symbols
Name of each exchange on which registered
Common Stock, $.01 Par Value
COP
New York Stock Exchange
7% Debentures due 2029
CUSIP—718507BK1
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
[x]
Yes
[ ] No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
[ ] Yes
[x]
No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such
reports), and (2) has been subject to such filing requirements for the past 90 days. [x]
Yes
[ ] No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted
pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that
the registrant was required to submit such files).
[x]
Yes
[ ] No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller
reporting company, or an emerging growth company.
See the definitions of “large accelerated filer,” “accelerated filer,” “smaller
reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
[x]
Accelerated filer [
]
Non-accelerated filer [
]
Smaller reporting company
[
]
Emerging
growth company
[
]
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for
complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [
]
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the
effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b))
by the registered public accounting firm that prepared or issued its audit report. [
x
]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). [
] Yes
[x]
No
The aggregate market value of common stock held by non-affiliates of the registrant on June 30, 2020, the last business day of the
registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $42.02, was $
45.1
billion.
The registrant had
1,354,734,727
shares of common stock outstanding at January 31, 2021.
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
75.
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
- 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
Total Gulf Coast
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
Total Great Plains
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
®
LNG
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
*
and Ethnicity
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
*While we present male and female, we acknowledge this is not fully encompassing
of all gender identities.
**"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
.
23
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.
24
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.
was appointed Executive Vice President and Chief Financial Officer as of September
2020, having previously served as President,
Asia Pacific & Middle East since April 2015.
Prior to that, he
was Vice President, Corporate Planning & Development since May 2012.
34
Ellen R. DeSanctis
was appointed Senior Vice President, Corporate Relations as of January 2019,
having
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
was appointed Executive Vice President and Chief Operating Officer as of January 2019,
having
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
was appointed Senior Vice President, Strategy, Exploration and Technology as of
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
was appointed Senior Vice President, Global Operations as of August
2020,
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
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
ConocoPhillips’ common stock is traded on the
New York Stock Exchange, under the symbol “COP.”
Cash Dividends Per Share
Dividends
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
listing.
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
that May Yet Be
Total Number of
Price Paid
Announced Plans
Purchased Under the
Period
Shares Purchased
*
Per Share
or Programs
Plans or Programs
October 1-31, 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
75.
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
(MBOED)
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
(millions of dollars)
$
(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
(MBOED)
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
(millions of dollars)
$
(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
(MBOED)
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
(MBOED)
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 sales prices include unutilized transportation costs.
**Average prices for sales of bitumen produced excludes additional value realized from the purchase and sale of third-party volumes for
optimization of our
pipeline capacity between Canada and the U.S. Gulf
Coast.
Our Canadian operations consist of the Surmont
oil sands development in Alberta and the liquids-rich
Montney unconventional play in British Columbia.
In 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
(millions of dollars)
$
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
(MBOED)
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
(MBOED)
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.
63
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.
64
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.
66
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.
67
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
Conference of the Parties to the United
Nations Framework Convention on Climate
Change, setting out a process for achieving
global
emission reductions.
The new administration has recommitted
the United States to the Paris
Agreement, and a significant number of U.S. state
and local governments and major corporations
headquartered in the U.S. have also announced
related commitments.
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
Rate
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
$
18,784
32,567
36,417
Equity in earnings of affiliates
432
779
1,074
Gain on dispositions
549
1,966
1,063
Other income (loss)
(509)
1,358
173
Total Revenues and
Other Income
19,256
36,670
38,727
Costs and Expenses
Purchased commodities
8,078
11,842
14,294
Production and operating expenses
4,344
5,322
5,213
Selling, general and administrative expenses
430
556
401
Exploration expenses
1,457
743
369
Depreciation, depletion and amortization
5,521
6,090
5,956
Impairments
813
405
27
Taxes other than income
taxes
754
953
1,048
Accretion on discounted liabilities
252
326
353
Interest and debt expense
806
778
735
Foreign currency transaction (gains) losses
(72)
66
(17)
Other expenses
13
65
375
Total Costs and Expenses
22,396
27,146
28,754
Income (loss) before income taxes
(3,140)
9,524
9,973
Income tax provision (benefit)
(485)
2,267
3,668
Net income (loss)
(2,655)
7,257
6,305
Less: net income attributable to noncontrolling interests
(46)
(68)
(48)
Net Income (Loss) Attributable to ConocoPhillips
$
(2,701)
7,189
6,257
Net Income (Loss) Attributable to ConocoPhillips Per Share
of Common Stock
(dollars)
Basic
$
(2.51)
6.43
5.36
Diluted
(2.51)
6.40
5.32
Average Common
Shares Outstanding
(in thousands)
Basic
1,078,030
1,117,260
1,166,499
Diluted
1,078,030
1,123,536
1,175,538
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)
7,257
6,305
Other comprehensive income (loss)
Defined benefit plans
Prior service credit (cost) arising during the period
29
-
(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)
117
146
279
Net change
(93)
91
129
Nonsponsored plans*
1
(3)
(1)
Income taxes on defined benefit plans
20
(2)
(42)
Defined benefit plans, net of tax
(75)
51
39
Unrealized holding gain on securities
2
-
-
Unrealized gain on securities, net of tax
2
-
-
Foreign currency translation adjustments
209
699
(645)
Income taxes on foreign currency translation adjustments
3
(4)
3
Foreign currency translation adjustments, net of tax
212
695
(642)
Other Comprehensive Income (Loss), Net of
Tax
139
746
(603)
Comprehensive Income (Loss)
(2,516)
8,003
5,702
Less: comprehensive income attributable to noncontrolling interests
(46)
(68)
(48)
Comprehensive Income (Loss) Attributable to ConocoPhillips
$
(2,562)
7,935
5,654
*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
$
2,991
5,088
Short-term investments
3,609
3,028
Accounts and notes receivable (net of allowance of $
4
and $
13
, respectively)
2,634
3,267
Accounts and notes receivable—related parties
120
134
Investment in Cenovus Energy
1,256
2,111
Inventories
1,002
1,026
Prepaid expenses and other current assets
454
2,259
Total Current Assets
12,066
16,913
Investments and long-term receivables
8,017
8,687
Loans and advances—related parties
114
219
Net properties, plants and equipment
(net of accumulated DD&A of $
62,213
and $
55,477
, respectively)
39,893
42,269
Other assets
2,528
2,426
Total Assets
$
62,618
70,514
Liabilities
Accounts payable
$
2,669
3,176
Accounts payable—related parties
29
24
Short-term debt
619
105
Accrued income and other taxes
320
1,030
Employee benefit obligations
608
663
Other accruals
1,121
2,045
Total Current Liabilities
5,366
7,043
Long-term debt
14,750
14,790
Asset retirement obligations and accrued environmental costs
5,430
5,352
Deferred income taxes
3,747
4,634
Employee benefit obligations
1,697
1,781
Other liabilities and deferred credits
1,779
1,864
Total Liabilities
32,769
35,464
Equity
Common stock (
2,500,000,000
shares authorized at $
0.01
par value)
Issued (2020—
1,798,844,267
shares; 2019—
1,795,652,203
shares)
Par value
18
18
Capital in excess of par
47,133
46,983
Treasury stock (at cost: 2020—
730,802,089
shares; 2019—
710,783,814
shares)
(47,297)
(46,405)
Accumulated other comprehensive loss
(5,218)
(5,357)
Retained earnings
35,213
39,742
Total Common
Stockholders’ Equity
29,849
34,981
Noncontrolling interests
-
69
Total Equity
29,849
35,050
Total Liabilities and Equity
$
62,618
70,514
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)
7,257
6,305
Adjustments to reconcile net income (loss) to net cash provided by
operating activities
Depreciation, depletion and amortization
5,521
6,090
5,956
Impairments
813
405
27
Dry hole costs and leasehold impairments
1,083
421
95
Accretion on discounted liabilities
252
326
353
Deferred taxes
(834)
(444)
283
Undistributed equity earnings
645
594
152
Gain on dispositions
(549)
(1,966)
(1,063)
Unrealized (gain) loss on investment in Cenovus Energy
855
(649)
437
Other
43
(351)
(246)
Working
capital adjustments
Decrease in accounts and notes receivable
521
505
235
Decrease (increase) in inventories
(25)
(67)
86
Decrease (increase) in prepaid expenses and other current assets
76
37
(55)
Decrease in accounts payable
(249)
(378)
(52)
Increase (decrease) in taxes and other accruals
(695)
(676)
421
Net Cash Provided by Operating Activities
4,802
11,104
12,934
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
1,317
3,012
1,082
Net sales (purchases) of investments
(658)
(2,910)
1,620
Collection of advances/loans—related parties
116
127
119
Other
(26)
(108)
154
Net Cash Used in Investing Activities
(4,121)
(6,618)
(3,843)
Cash Flows From Financing Activities
Issuance of debt
300
-
-
Repayment of debt
(254)
(80)
(4,995)
Issuance of company common stock
(5)
(30)
121
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
5,362
6,151
6,536
Cash, Cash Equivalents and Restricted Cash at End of Period
$
3,315
5,362
6,151
Restricted cash of $
94
million and $
230
million is included in the “Prepaid expenses and other current assets” and “Other assets”
lines,
respectively, of our Consolidated Balance Sheet as of December 31, 2020.
Restricted cash of $
90
million and $
184
million is included in the “Prepaid expenses and other current assets” and “Other assets”
lines,
respectively, of our Consolidated Balance Sheet as of December 31, 2019.
See Notes to Consolidated Financial Statements.
90
Consolidated Statement of Changes in Equity
ConocoPhillips
Millions of Dollars
Attributable to ConocoPhillips
Common Stock
Par
Value
Capital in
Excess of
Par
Treasury
Stock
Accum. Other
Comprehensive
Income (Loss)
Retained
Earnings
Non-
Controlling
Interests
Total
Balances at December 31, 2017
$
18
46,622
(39,906)
(5,518)
29,391
194
30,801
Net income
6,257
48
6,305
Other comprehensive loss
(603)
(603)
Dividends paid ($
1.16
per share of common stock)
(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
257
257
Changes in Accounting Principles*
58
(278)
(220)
Other
3
4
7
Balances at December 31, 2018
$
18
46,879
(42,905)
(6,063)
34,010
125
32,064
Net income
7,189
68
7,257
Other comprehensive income
746
746
Dividends paid ($
1.34
per share of common stock)
(1,500)
(1,500)
Repurchase of company common stock
(3,500)
(3,500)
Distributions to noncontrolling interests and other
(128)
(128)
Distributed under benefit plans
104
104
Changes in Accounting Principles**
(40)
40
-
Other
3
4
7
Balances at December 31, 2019
$
18
46,983
(46,405)
(5,357)
39,742
69
35,050
Net income (loss)
(2,701)
46
(2,655)
Other comprehensive income
139
139
Dividends paid ($
1.69
per share of common stock)
(1,831)
(1,831)
Repurchase of company common stock
(892)
(892)
Distributions to noncontrolling interests and other
(32)
(32)
Disposition
(84)
(84)
Distributed under benefit plans
150
150
Other
3
1
4
Balances at December 31, 2020
$
18
47,133
(47,297)
(5,218)
35,213
-
29,849
*Cumulative effect of the adoption of ASC Topic 606, "Revenue from Contracts with Customers," and ASU No. 2016-01, "Recognition
and Measurement of
Financial Assets and Liabilities," at January 1, 2018.
**Cumulative effect of the adoption of ASU No. 2018-02, "Reclassification
of Certain Tax Effects from Accumulated Other Comprehensive Income."
See Notes to Consolidated Financial Statements.
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.
Payment is typically due within 30 days or
less.
Revenues associated with transactions commonly
called buy/sell contracts, in which the
purchase and sale
of inventory with the same counterparty are entered
into “in contemplation” of one another, are combined
and reported net (i.e., on the same income statement
line).
■
Shipping and Handling Costs
—We typically incur shipping and handling costs prior to control
transferring to the customer and account for these
activities as fulfillment costs.
Accordingly, we include
shipping and handling costs in production and operating
expenses for production activities.
Transportation costs related to marketing activities are recorded
in purchased commodities.
Freight costs
billed to customers are treated as a component of the
transaction price and recorded as a component
of
revenue when the customer obtains control.
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.
We do not apply hedge accounting
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
We adopted the provisions of FASB ASU No. 2016-13, “Measurement of Credit Losses on Financial
Instruments,” (ASC Topic 326) and its amendments, beginning January 1, 2020. This ASU, as amended, sets
forth the current expected credit loss model, a new forward-looking impairment model for certain financial
instruments measured at amortized cost basis based on expected losses rather than incurred losses. This ASU,
as amended, which primarily applies to our accounts receivable, also requires credit losses related to available-
for-sale debt securities to be recorded through an allowance for credit losses. The adoption of this ASU did
not have a material impact to our financial statements. The majority of our receivables are due within 30 days
or less. We monitor the credit quality of our counterparties through review of collections, credit ratings, and
other analyses. We develop our estimated allowance for credit losses primarily using an aging method and
analyses of historical loss rates as well as consideration of current and future conditions that could impact our
counterparties’ credit quality and liquidity.
96
Note 3—Inventories
Inventories at December 31 were:
Millions of Dollars
2020
2019
Crude oil and natural gas
$
461
472
Materials and supplies
541
554
$
1,002
1,026
Inventories valued on the LIFO basis totaled
$
282
million and $
286
million at December 31, 2020 and 2019,
respectively.
In the first quarter of 2020, we recorded a lower
of cost or market adjustment of $
228
million to
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 $
87
million and $
155
million at
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 $
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.
For additional information related to this
transaction, see Note
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 $
382
million after customary adjustments, plus the
assumption of $
31
million in financing obligations
associated with partially owned infrastructure.
This acquisition consisted primarily
of undeveloped properties
and included
140,000
net acres in the liquids-rich Inga Fireweed asset
Montney zone, which is directly
adjacent to our existing Montney position.
The transaction increased
our Montney acreage position to
approximately
295,000
net acres with a
100
percent working interest.
This agreement was accounted for as an
asset acquisition resulting in the recognition of $
490
million of PP&E; $
77
million of ARO and accrued
environmental costs; and $
31
million of financing obligations recorded primarily
to long-term debt.
Results of
operations for the Montney asset are reported in our
Canada segment.
Assets Sold
In February 2020, we sold our Waddell Ranch interests in the Permian Basin for $
184
million after customary
adjustments.
No
gain or loss was recognized on the sale.
Results of operations for the Waddell Ranch
interests sold were reported in our Lower 48 segment.
In March 2020, we completed the sale of our
Niobrara interests for approximately $
359
million after
customary adjustments and recognized a before-tax
loss on disposition of $
38
million.
At the time of
disposition, our interest in Niobrara had a net carrying
value of $
397
million, consisting primarily of
97
$
433
million of PP&E and $
34
million of ARO. The before-tax losses associated
with our interests in
Niobrara, including the loss on disposition noted above
and an impairment of $
386
million recorded when we
signed an agreement to sell our interests in
the fourth quarter of 2019, were $
25
million and $
372
million for
the years ended December 31, 2020 and 2019,
respectively. The before-tax earnings associated with our
interests in Niobrara for the year ended December
31, 2018 was $
35
million.
Results of operations for the
Niobrara interests sold were reported in our
Lower 48 segment.
In May 2020, we completed the divestiture
of our subsidiaries that held our Australia-West assets and
operations, and based on an effective date of January
1, 2019, we received proceeds of $
765
million with an
additional $
200
million due upon final investment decision
of the proposed Barossa development project.
We
recognized a before-tax gain of $
587
million related to this transaction in 2020.
At the time of disposition, the
net carrying value of the subsidiaries sold was approximately
$
0.2
billion, excluding $
0.5
billion of cash.
The
net carrying value consisted primarily of $
1.3
billion of PP&E and $
0.1
billion of other current assets offset by
$
0.7
billion of ARO, $
0.3
billion of deferred tax liabilities, and $
0.2
billion of other liabilities.
The before-tax
earnings associated with the subsidiaries sold,
including the gain on disposition noted above,
were $
851
million, $
372
million and $
364
million for the years ended December 31,
2020, 2019 and 2018, respectively.
Production from the beginning of the year through
the disposition date in May 2020 averaged
43
MBOED.
Results of operations for the subsidiaries
sold were reported in our Asia Pacific segment.
2019
Assets Sold
In January 2019, we entered into agreements to sell
our
12.4
percent ownership interests in the Golden
Pass
LNG Terminal and Golden Pass Pipeline.
We also entered into agreements to amend our contractual
obligations for retaining use of the facilities.
As a result of entering into these agreements, we recorded
a
before-tax impairment of $
60
million in the first quarter of 2019 which is included
in the “Equity in earnings
of affiliates” line on our consolidated income statement.
We completed the sale in the second quarter of 2019.
Results of operations for these assets were reported
in our Lower 48 segment.
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 $
2.675
billion plus interest and customary adjustments,
with an effective date of January 1, 2018.
On September 30, 2019, we completed the sale for
proceeds of $
2.2
billion and recognized a $
1.7
billion
before-tax and $
2.1
billion after-tax gain associated with this transaction
in 2019.
Together the subsidiaries
sold indirectly held our exploration and production
assets in the U.K.
At the time of disposition, the net
carrying value was approximately $
0.5
billion, consisting primarily of $
1.6
billion of PP&E, $
0.5
billion of
cumulative foreign currency translation adjustments,
and $
0.3
billion of deferred tax assets, offset by $
1.8
billion of ARO and negative $
0.1
billion of working capital.
The before-tax earnings associated with the
subsidiaries sold, including the gain on dispositions
noted above, were $
2.1
billion and $
0.9
billion for the
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 $
52
million upon the closing of the sale of
our
30
percent interest in the Greater Sunrise Fields
to the government of Timor-Leste for $
350
million.
The
Greater Sunrise Fields were included in our Asia
Pacific segment.
In the fourth quarter of 2019, we sold our interests
in the Magnolia field and platform for net proceeds
of $
16
million and recognized a before-tax gain of $
82
million.
At the time of sale, the net carrying value consisted
of $
4
million of PP&E offset by $
70
million of ARO.
The Magnolia results of operations were reported
within
our Lower 48 segment.
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 $
112
million.
No
gain or loss was recognized on the sale.
In the second quarter of 2018, we
completed the sale of a package of largely undeveloped acreage
in the Lower 48 segment for net proceeds
of
$
105
million and
no
gain or loss was recognized on the sale.
In the third quarter of 2018, we completed a
noncash exchange of undeveloped acreage in
the Lower 48 segment.
The transaction was recorded at fair
value resulting in the recognition of a $
56
million gain.
In the fourth quarter of 2018, we sold several
packages of undeveloped acreage in the Lower
48 segment for total net proceeds of $
162
million and
recognized gains of approximately $
140
million.
On October 31, 2018, we completed the sale of
our interests in the Barnett to Lime Rock Resources
for $
196
million after customary adjustments and recognized
a loss of $
5
million. We recorded an impairment of $87
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 $
201
million, consisting of $
250
million of PP&E and $
49
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 $
59
million for the year ended December 31, 2018.
The
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
16.5
percent of our
24
percent interest in the BP-operated Clair Field
in the U.K.
We retained a
7.5
percent
interest in the field.
At the same time, we acquired BP’s
39.2
percent nonoperated interest in the Greater
Kuparuk Area in Alaska, including their
38
percent interest in the Kuparuk Transportation Company (Kuparuk
Assets).
The transaction was recorded at a fair value
of $
1,743
million and was cash neutral except for
customary adjustments which resulted in net
proceeds of $
253
million.
At closing, our interest in the Clair
Field had a net carrying value of approximately
$
1,028
million consisting primarily of $
1,553
million of
PP&E, $
485
million of deferred tax liabilities, and $
59
million of AROs.
We recognized a before-tax gain of
$
715
million on the transaction.
The 2018 before-tax earnings associated
with our
16.5
percent interest in the
Clair Field, including the recognized gain, were $
748
million. Results of operations for our interest
in the Clair
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
22
percent nonoperated interest in the Western
North Slope of Alaska, as well as its interest
in the Alpine Transportation Pipeline for $
386
million, after
customary adjustments.
This transaction was accounted for as a business
combination resulting in the
recognition of approximately $
297
million of proved property and $
114
million of unproved property within
PP&E, $
20
million of inventory, $
14
million of investments, and $
59
million of AROs. These assets are
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 $
1,490
million,
comprised of the fair value of $
1,743
million associated with the disposed
16.5
percent of our
24
percent
interest in the Clair Field, reduced by the net proceeds
of $
253
million.
Accordingly, we recorded
approximately $
1.9
billion to proved property within PP&E, $
42
million to inventory, $
15
million to
investments, $
374
million of AROs, and a $
100
million decrease to net working capital.
The Kuparuk Assets
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
$
7,596
8,234
Loans and advances—related parties
114
219
Long-term receivables
137
243
Long-term investments in debt securities
217
133
Other investments
67
77
$
8,131
8,906
Equity Investments
Affiliated companies in which we had a significant
equity investment at December 31, 2020, included:
●
APLNG—
37.5
percent owned joint venture with Origin Energy (
37.5
percent) and Sinopec (
25
percent)—
to produce CBM from the Bowen and Surat basins in Queensland, Australia, as well as process
and export
LNG.
●
Qatar Liquefied Gas Company Limited (3) (QG3)—30 percent owned
joint venture with affiliates of Qatar
Petroleum (
68.5
percent) and Mitsui & Co., Ltd. (
1.5
percent)—produces and liquefies natural gas from
Qatar’s North Field, as well as exports LNG.
Summarized 100 percent earnings information
for equity method investments in affiliated companies,
combined, was as follows:
Millions of Dollars
2020
2019
2018
Revenues
$
7,931
11,310
11,654
Income before income taxes
1,843
3,726
3,660
Net income
1,426
3,085
3,244
Summarized 100 percent balance sheet information
for equity method investments in affiliated
companies,
combined, was as follows:
Millions of Dollars
2020
2019
Current assets
$
2,579
3,289
Noncurrent assets
35,257
38,905
Current liabilities
2,110
2,603
Noncurrent liabilities
18,099
22,168
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
$
41
million related to the undistributed earnings
of
affiliated companies.
Dividends received from affiliates were $
1,076
million, $
1,378
million and
$
1,226
million in 2020, 2019 and 2018, respectively.
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 $
8.5
billion project finance facility in 2012.
The $8.5
billion project finance facility was initially composed
of financing agreements executed by APLNG
with the
Export-Import Bank of the United States for approximately
$
2.9
billion, the Export-Import Bank of China for
approximately $
2.7
billion, and a syndicate of Australian and international
commercial banks for
approximately $
2.9
billion.
All amounts were drawn from the facility.
APLNG made its first principal and
interest repayment in March 2017 and is scheduled
to make
bi-annual
payments until March 2029.
APLNG made a voluntary repayment of $
1.4
billion to the Export-Import Bank of China
in September 2018.
At the same time, APLNG obtained a United
States Private Placement (USPP) bond facility
of $
1.4
billion.
APLNG made its first interest payment related to
this facility in March 2019, and principal
payments are
scheduled to commence in September 2023,
with
bi-annual
payments due on the facility until September
2030.
During the first quarter of 2019, APLNG refinanced
$
3.2
billion of existing project finance debt through two
transactions.
As a result of the first transaction, APLNG
obtained a commercial bank facility of $
2.6
billion.
APLNG made its first principal and interest
repayment in September 2019 with
bi-annual
payments due on the
facility until March 2028.
Through the second transaction, APLNG obtained
a USPP bond facility of $
0.6
billion.
APLNG made its first interest payment in September
2019, and principal payments are scheduled
to
commence in September 2023, with
bi-annual
payments due on the facility until
September 2030.
In conjunction with the $
3.2
billion debt obtained during the first quarter
of 2019 to refinance existing project
finance debt, APLNG made voluntary repayments
of $
2.2
billion and $
1.0
billion to a syndicate of Australian
and international commercial banks and the Export-Import
Bank of China, respectively.
At December 31, 2020, a balance of $
6.2
billion was outstanding on the facilities.
See Note 11—Guarantees,
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 $
6,560
million,
resulting in a not other than temporary impairment
of $
112
million.
We will continue to monitor the
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 $
6,672
million.
The historical cost basis of our
37.5
percent share of net assets on the books
of APLNG was $
6,242
million,
resulting in a basis difference of $
430
million on our books.
The basis difference, which is substantially all
associated with PP&E and subject to amortization,
has been allocated on a relative fair value
basis to
individual 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 $
41
million, $
36
million and $
44
million, respectively, representing the amortization of this basis
difference on currently producing licenses.
QG3
QG3 is a joint venture that owns an integrated
large-scale LNG project located in Qatar.
We provided project
financing, with a current outstanding balance
of $
220
million as described below under “Loans and
Long-
Term Receivables.”
At December 31, 2020, the book value of our equity
method investment in QG3,
excluding the project financing, was $
742
million.
We have terminal and pipeline use agreements with Golden
Pass LNG Terminal and affiliated Golden Pass Pipeline near Sabine Pass, Texas, intended to provide us with
terminal and pipeline capacity for the receipt,
storage and regasification of LNG purchased
from QG3.
We
previously held a
12.4
percent interest in Golden Pass LNG Terminal and Golden Pass Pipeline, but
we sold
those interests in the second quarter of 2019 while
retaining the basic use agreements.
Currently,
the LNG
from QG3 is being sold to markets outside of
the U.S.
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 $
220
million in project financing to
QG3.
We own a
30
percent interest in QG3, for which we
use the equity method of accounting.
The other
participants in the project are affiliates of Qatar Petroleum
and Mitsui.
QG3 secured project financing of
$
4.0
billion in December 2005, consisting of $
1.3
billion of loans from export credit agencies
(ECA), $
1.5
billion from commercial banks, and $
1.2
billion from ConocoPhillips.
The ConocoPhillips loan facilities have
substantially the same terms as the ECA and commercial
bank facilities.
On December 15, 2011, QG3
achieved financial completion and all project loan facilities
became nonrecourse to the project participants.
Semi-annual
repayments began in January 2011 and will extend through July
2022.
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
50
percent nonoperated interest in the FCCL
Partnership, as
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
16.9
percent of issued
and outstanding Cenovus Energy common stock.
The fair value and cost basis of our investment
in
208
million Cenovus Energy common shares was $
1.96
billion based on a price of $
9.41
per share on the NYSE on
the closing date.
At December 31, 2020, the investment included on
our consolidated balance sheet was $
1.26
billion and is
carried at fair value.
The fair value of the
208
million Cenovus Energy common shares reflects
the closing
price of $
6.04
per share on the NYSE on the last trading
day of the quarter, a decrease of $
855
million from its
fair value of $
2.11
billion at December 31, 2019.
The decrease in fair value resulted in a net
unrealized loss
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 $
649
million and an unrealized loss of $
437
million, respectively.
See Note
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
10
percent of the issued and outstanding Cenovus
Energy
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
$
1,020
856
853
Additions pending the determination of proved reserves
164
239
140
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
$
682
1,020
*
856
*Includes $
313
million of assets held for sale in Australia at December
31, 2019.
For additional details on suspended wells charged to dry hole expense, see the
Exploration Expenses section of this Note.
The following table provides an aging of suspended
well balances at December 31:
Millions of Dollars
2020
2019
2018
Exploratory well costs capitalized for a period
of one year or less
$
156
206
145
Exploratory well costs capitalized for a period
greater than one year
526
814
711
Ending balance
$
682
1,020
*
856
Number of projects with exploratory well costs
capitalized for a
period greater than one year
22
23
24
*Includes $
313
million of assets held for sale in Australia at December
31, 2019.
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)
240
190
50
-
Surmont—Canada
(1)
120
4
31
85
Narwhal Trend—Alaska
(1)
52
52
-
-
PL782S—Norway
(1)
22
22
-
-
WL4-00—Malaysia
(1)
17
17
-
-
NC 98—Libya
(2)
13
-
9
4
Other of $10 million or less each
(1)(2)
62
26
19
17
Total
$
526
311
109
106
(1)Additional appraisal wells planned.
(2)Appraisal drilling complete; costs being incurred to assess development.
Exploration Expenses
The charges discussed below are included in the “Exploration
expenses” line on our consolidated income
statement.
2020
In our Alaska segment, we recorded a before-tax impairment
of $
828
million for the entire associated carrying
value of capitalized undeveloped leasehold costs
related to our Alaska North Slope Gas asset.
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 $
84
million for dry hole costs of a previously suspended
well and an impairment of
the associated capitalized undeveloped leasehold carrying
value.
In our Asia Pacific segment, we recorded before-tax
expense of $
50
million related to dry hole costs of a
previously suspended well and an impairment
of the associated capitalized undeveloped
leasehold carrying
value associated with the Kamunsu East Field
in Malaysia that is no longer in our development
plans.
2019
In our Lower 48 segment, we recorded a before-tax impairment
of $
141
million for the associated carrying
value of capitalized undeveloped leasehold costs
and dry hole expenses of $
111
million before-tax due to our
decision to discontinue exploration activities
related to our Central Louisiana Austin Chalk acreage.
104
Note 8—Impairments
During 2020, 2019 and 2018, we recognized the
following before-tax impairment charges:
Millions of Dollars
2020
2019
2018
Alaska
$
-
-
20
Lower 48
804
402
63
Canada
3
2
9
Europe, Middle East and North Africa
6
1
(79)
Asia Pacific
-
-
14
$
813
405
27
2020
During 2020, we recorded impairments of $
813
million, primarily related to certain
non-core assets in the
Lower 48.
Due to a significant decrease in the outlook for
current and long-term natural gas prices in early
2020, we recorded impairments of $
523
million, primarily for the Wind River Basin operations area,
consisting of developed properties in the
Madden Field and the Lost Cabin Gas Plant, in
the first quarter of
2020.
Additionally, due primarily to changes in development plans solidified in
the last quarter of 2020, we
recognized additional impairments of $
287
million in the Lower 48 during the fourth
quarter.
See Note 14—
Fair Value Measurement, for additional information.
2019
In the Lower 48, we recorded impairments
of $
402
million, primarily related to developed properties
in our
Niobrara asset which were written down to fair value
less costs to sell.
See Note 4—Asset Acquisitions and
Dispositions,
for additional information on this disposition.
2018
In Alaska, we recorded impairments of $
20
million primarily due to cancelled projects.
In the Lower 48, we recorded impairments
of $
63
million, primarily related to developed properties
in our
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 $
79
million,
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
$
5,573
6,206
Accrued environmental costs
180
171
Total asset retirement obligations and accrued environmental costs
5,753
6,377
Asset retirement obligations and accrued environmental
costs due within one year*
(323)
(1,025)
Long-term asset retirement obligations and accrued
environmental costs
$
5,430
5,352
*Classified as a current liability on the balance sheet under “Other accruals.” For
2019, $
741
million relates to assets which were held for sale
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
$
6,206
7,908
Accretion of discount
248
322
New obligations
262
155
Changes in estimates of existing obligations
(307)
50
Spending on existing obligations
(116)
(229)
Property dispositions
(771)
(1,920)
Foreign currency translation
51
(80)
Balance at December 31
$
5,573
6,206
106
Accrued Environmental Costs
Total accrued environmental costs at December 31, 2020 and 2019, were $
180
million and $
171
million,
respectively.
We had accrued environmental costs of $
116
million and $
112
million at December 31, 2020 and 2019,
respectively, related to remediation activities in the U.S. and Canada.
We had also accrued in Corporate and
Other $
48
million and $
47
million of environmental costs associated
with sites no longer in operation at
December 31, 2020 and 2019, respectively.
In addition, $
16
million and $
12
million were included at both
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
30
years.
Expected expenditures for environmental obligations
acquired in various business combinations
are discounted
using a weighted-average
5
percent discount factor, resulting in an accrued balance for acquired
environmental
liabilities of $
106
million at December 31, 2020.
The expected future undiscounted payments
related to the
portion of the accrued environmental costs that
have been discounted are: $
23
million in 2021, $
17
million in
2022, $
18
million in 2023, $
3
million in 2024, $
2
million in 2025, and $
103
million for all future years
after 2025.
107
Note 10—Debt
Long-term debt at December 31 was:
Millions of Dollars
2020
2019
9.125
% Debentures due 2021
$
123
123
2.4
% Notes due 2022
329
329
7.65
% Debentures due 2023
78
78
3.35
% Notes due 2024
426
426
8.2
% Debentures due 2025
134
134
3.35
% Notes due 2025
199
199
6.875
% Debentures due 2026
67
67
4.95
% Notes due 2026
1,250
1,250
7.8
% Debentures due 2027
203
203
7.375
% Debentures due 2029
92
92
7
% Debentures due 2029
200
200
6.95
% Notes due 2029
1,549
1,549
8.125
% Notes due 2030
390
390
7.2
% Notes due 2031
575
575
7.25
% Notes due 2031
500
500
7.4
% Notes due 2031
500
500
5.9
% Notes due 2032
505
505
4.15
% Notes due 2034
246
246
5.95
% Notes due 2036
500
500
5.951
% Notes due 2037
645
645
5.9
% Notes due 2038
600
600
6.5
% Notes due 2039
2,750
2,750
4.3
% Notes due 2044
750
750
5.95
% Notes due 2046
500
500
7.9
% Debentures due 2047
60
60
Floating rate notes due 2022 at
1.12
% –
2.81
% during 2020 and
2.81
% –
3.58
% during 2019
500
500
Marine Terminal Revenue Refunding Bonds due 2031 at
0.1
% –
7.5
% during
2020 and
1.08
% –
2.45
% during 2019
265
265
Industrial Development Bonds due 2035 at
0.11
% –
7.5
% during 2020 and
1.08
% –
2.45
% during 2019
18
18
Commercial Paper at
0.08
% –
0.23
% during 2020
300
Other
38
17
Debt at face value
14,292
13,971
Finance leases
891
720
Net unamortized premiums, discounts and
debt issuance costs
186
204
Total debt
15,369
14,895
Short-term debt
(619)
(105)
Long-term debt
$
14,750
14,790
108
Maturities of long-term borrowings, inclusive
of net unamortized premiums and discounts,
in 2021 through
2025 are: $
619
million, $
1,001
million, $
259
million, $
579
million and $
465
million, respectively.
We have a revolving credit facility totaling $
6.0
billion with an expiration date of May 2023.
Our revolving
credit facility may be used for direct bank borrowings,
the issuance of letters of credit totaling
up to $
500
million,
or as support for our commercial paper program.
The revolving credit facility is broadly syndicated
among financial institutions and does not contain
any material adverse change provisions or any covenants
requiring maintenance of specified financial
ratios or credit ratings.
The facility agreement contains a cross-
default provision relating to the failure to pay principal
or interest on other debt obligations of $
200
million or
more by ConocoPhillips, or any of its consolidated
subsidiaries.
The amount of the facility is not subject to
redetermination prior to its expiration date.
Credit facility borrowings may bear interest at
a margin above rates offered by certain designated banks in the
London interbank market or at a margin above the overnight
federal funds rate or prime rates offered by
certain designated banks in the U.S.
The agreement calls for commitment fees
on available, but unused,
amounts.
The agreement also contains early termination
rights if our current directors or their approved
successors cease to be a majority of the Board
of Directors.
The revolving credit facility supports our ability
to issue up to $
6.0
billion of commercial paper, which is
primarily a funding source for short-term working capital
needs.
Commercial paper maturities are generally
limited to
90 days
.
We issued $
300
million of commercial paper in the third
quarter of 2020, which is
included in the short-term debt on our consolidated
balance sheet.
With $
300
million of commercial paper
outstanding and
no
direct borrowings or letters of credit,
we had access to $
5.7
billion in available borrowing
capacity under our revolving credit facility
at December 31, 2020.
We had
no
direct borrowings, letters of
credit, nor outstanding commercial paper as
of December 31, 2019.
At both December 31, 2020 and 2019, we had
$
283
million of certain variable rate demand
bonds (VRDBs)
outstanding with maturities ranging through 2035.
The VRDBs are redeemable at the option
of the
bondholders on any business day.
If they are ever redeemed, we have the ability
and intent
to refinance on a
long-term basis, therefore, the VRDBs are included
in the “Long-term debt” line on our consolidated
balance
sheet.
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 $
4.7
billion on the acquisition
date. On December 7, 2020, we launched a debt
exchange offer which 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.
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
37.5
percent ownership
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
10 years
.
Our maximum exposure under this guarantee is
approximately $
170
million
and may become payable if an enforcement action
is commenced by the project finance lenders
against APLNG.
At December 31, 2020, the carrying value
of this guarantee is approximately $
14
million.
●
In conjunction with our original purchase of an ownership
interest in APLNG from Origin Energy in
October 2008, we agreed to reimburse Origin
Energy for our share of the existing contingent liability
arising under guarantees of an existing obligation
of APLNG to deliver natural gas under
several sales
agreements with remaining terms of
1 to 21 years
.
Our maximum potential liability for future
payments, or cost of volume delivery, under these guarantees is estimated to
be $
770
million ($
1.4
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
16 to
25 years or the life of the venture
.
Our maximum potential amount of future payments
related to these
guarantees is approximately $
130
million and would become payable if APLNG
does not perform.
At
December 31, 2020, the carrying value of these
guarantees was approximately $
7
million.
Other Guarantees
We have other guarantees with maximum future potential payment amounts totaling
approximately
$
730
million, which consist primarily of
guarantees of the residual value of leased office buildings,
guarantees
of the residual value of corporate aircraft,
and a guarantee for our portion of a joint venture’s project finance
reserve accounts.
These guarantees have remaining terms
of one to
six years
and would become payable if
certain asset values are lower than guaranteed
amounts at the end of the lease or contract
term, business
conditions decline at guaranteed entities,
or as a result of nonperformance of contractual
terms by guaranteed
parties.
At December 31, 2020, the carrying value of these
guarantees was approximately $
11
million.
Indemnifications
Over the years, we have entered into agreements to
sell ownership interests in certain legal
entities, joint
ventures and assets that gave rise to qualifying
indemnifications.
These agreements include indemnifications
for taxes and environmental liabilities.
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 $
50
million.
We amortize the
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
$
249
million (issued as direct bank letters of
credit) related to various purchase commitments
for materials,
supplies, commercial activities and services incident
to the ordinary conduct of business.
In 2007, ConocoPhillips was unable to reach
agreement with respect to the empresa
mixta structure mandated
by the Venezuelan government’s Nationalization Decree.
As a result, Venezuela’s
national oil company,
Petróleos de Venezuela, S.A. (PDVSA), or its affiliates, directly assumed control over ConocoPhillips’
interests in the Petrozuata and Hamaca heavy oil
ventures and the offshore Corocoro development project.
In
response to this expropriation, ConocoPhillips
initiated international arbitration on November 2,
2007, with the
ICSID.
On September 3, 2013, an ICSID arbitration tribunal
held that Venezuela unlawfully expropriated
ConocoPhillips’ significant oil investments
in June 2007.
On January 17, 2017, the Tribunal reconfirmed the
decision that the expropriation was unlawful.
In March 2019, the Tribunal unanimously ordered the
government of Venezuela to pay ConocoPhillips approximately $
8.7
billion in compensation for the
government’s unlawful expropriation of the company’s investments in Venezuela in 2007.
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 $
227
million.
The award now stands
at $
8.5
billion plus interest.
The government of Venezuela sought annulment of the award before ICSID, and
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 $
2
billion
under their
agreements in connection with the expropriation of the projects and other pre-expropriation fiscal measures. In
August 2018, ConocoPhillips entered into a settlement with PDVSA to recover the full amount of this ICC
award, plus interest through the payment period, including initial payments totaling approximately $500
million within a period of 90 days from the time of signing of the settlement agreement. The balance of the
settlement is to be paid quarterly over a period of four and a half years.
To date, ConocoPhillips has received
approximately $
754
million.
Per the settlement, PDVSA recognized the
ICC award as a judgment in various
jurisdictions, and ConocoPhillips agreed to suspend
its legal enforcement actions.
ConocoPhillips sent notices
of default to PDVSA on October 14 and November
12, 2019, and to date PDVSA has failed
to cure its breach.
As a result, ConocoPhillips has resumed legal enforcement
actions.
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 $
33
million plus interest under the Corocoro contracts.
ConocoPhillips is seeking recognition and enforcement
of the award in various jurisdictions.
ConocoPhillips
has ensured that all the actions related to the award
meet all appropriate U.S. regulatory requirements,
including those related to any applicable sanctions
imposed by the U.S. against Venezuela.
The Office of Natural Resources Revenue (ONRR) has
conducted audits of ConocoPhillips’
payment of
royalties on federal lands and has issued multiple
orders to pay additional royalties to the federal
government.
ConocoPhillips 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
$
90
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—$
7
million; 2022—$
7
million; 2023—$
7
million; 2024—$
7
million; 2025—$
7
million; and 2026 and
after—$
51
million.
Total payments under the agreements were $
25
million in 2020, $
25
million in 2019 and
$
39
million in 2018.
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
$
229
288
Other assets
26
34
Liabilities
Other accruals
202
283
Other liabilities and deferred credits
18
28
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
$
19
141
45
Other income (loss)
4
4
7
Purchased commodities
11
(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
$
2
1
Liabilities
Other accruals
16
20
Other liabilities and deferred credits
-
8
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)
16
1
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
-
4
Sell British pound, buy euro
GBP
5
-
Sell Canadian dollar, buy U.S. dollar
CAD
370
1,337
115
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
.
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
$
597
759
Demand Deposits
1,133
1,483
Time Deposits
1 to 90 days
1,225
2,030
2,859
1,395
91 to 180 days
448
465
Within one year
13
-
One year through five years
1
-
Commercial Paper
1 to 90 days
-
413
-
1,069
U.S. Government Obligations
1 to 90 days
23
394
-
-
$
2,978
5,079
3,320
2,929
1
-
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
$
-
1
130
59
143
99
Commercial Paper
13
8
155
30
U.S. Government Obligations
-
-
4
10
13
15
U.S. Government Agency
Obligations
17
-
Foreign Government Obligations
2
-
Asset-backed Securities
-
-
41
19
$
13
9
289
99
216
133
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
$
271
159
273
159
Commercial paper
168
38
168
38
U.S. government obligations
17
25
17
25
U.S. government agency obligations
17
-
17
-
Foreign government obligations
2
-
2
-
Asset-backed securities
41
19
41
19
$
516
241
518
241
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 $
422
million.
Gross realized gains and losses included in earnings
from
those sales and redemptions were negligible.
The cost of securities sold and redeemed
is determined using the
specific identification method.
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.
Certain of our derivative instruments contain provisions that require us to post collateral if the derivative
exposure exceeds a threshold amount. We have contracts with fixed threshold amounts and other contracts
with variable threshold amounts that are contingent on our credit rating. The variable threshold amounts
typically decline for lower credit ratings, while both the variable and fixed threshold amounts typically revert
to zero if we fall below investment grade. Cash is the primary collateral in all contracts; however, many also
permit us to post letters of credit as collateral, such as transactions administered through the New York
Mercantile Exchange.
The aggregate fair value of all derivative
instruments with such credit risk-related contingent
features that were
in a liability position on December 31, 2020 and
December 31, 2019, was $
25
million and $
79
million,
respectively.
For these instruments,
no collateral
was posted as of December 31, 2020 or December
31, 2019.
If our credit rating had been downgraded below
investment grade on December 31, 2020,
we would have been
required to post $
23
million of additional collateral, either with
cash or letters of credit.
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
$
1,256
-
-
1,256
2,111
-
-
2,111
Investments in debt securities
17
501
-
518
25
216
-
241
Commodity derivatives
142
101
12
255
172
114
36
322
Total assets
$
1,415
602
12
2,029
2,308
330
36
2,674
Liabilities
Commodity derivatives
$
120
91
9
220
174
115
22
311
Total liabilities
$
120
91
9
220
174
115
22
311
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
$
255
2
253
157
96
10
86
Liabilities
220
1
219
157
62
4
58
December 31, 2019
Assets
$
322
3
319
193
126
4
122
Liabilities
311
4
307
193
114
12
102
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)
March 31, 2020
$
65
-
-
65
522
December 31, 2020
268
-
-
268
287
Year
ended December 31, 2019
Net PP&E (held for sale)
November 30, 2019
$
194
194
-
-
351
December 31, 2019
166
166
-
-
28
Equity Method Investments
March 31, 2019
171
171
-
-
60
May 31, 2019
30
-
30
-
95
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
$
65
Discounted cash
flow
Natural gas production
(MMCFD)
8.4
-
55.2
(
22.9
)
Natural gas price outlook*
($/MMBTU)
$
2.67
- $
9.17
($
5.68
)
Discount rate**
7.9
%
-
9.1
% (
8.3
%)
*Henry Hub natural gas price outlook based on a combination of external
pricing service companies' outlooks for years 2022-2034; future
prices escalated at
2.2
%
annually after year 2034.
**Determined as the weighted average cost of capital of a group
of peer companies, adjusted for risks where
appropriate.
Fair Value
(Millions of
Dollars)
Valuation
Technique
Unobservable Inputs
Range
(Arithmetic Average)
December 31, 2020
Central Basin Platform
$
244
Discounted cash
flow
Commodity production
(MBOED)
0.5
-
12.7
(
3.4
)
Commodity price outlook*
($/BOE)
$
37.35
- $
115.29
($
73.80
)
Discount rate**
6.8
%
-
7.7
% (
7.4
%)
*Commodity price outlook based on a combination of external pricing
service companies' and our internal outlook for years
2023-2050; future prices escalated at
2.0% annually after year 2050.
**Determined as the weighted average cost of capital of a group
of peer companies, adjusted for risks where
appropriate.
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
$
1,256
2,111
1,256
2,111
Commodity derivatives
88
125
88
125
Investments in debt securities
518
241
518
241
Loans and advances—related parties
220
339
220
339
Financial liabilities
Total debt, excluding finance leases
14,478
14,175
19,106
18,108
Commodity derivatives
59
106
59
106
Commodity Derivatives
At December 31, 2020, commodity derivative
assets and liabilities are presented net with $
10
million in
obligations to return cash collateral and $
4
million of rights to reclaim cash collateral,
respectively.
At
December 31, 2019, commodity derivative assets
and liabilities are presented net with $
4
million in
obligations to return cash collateral and $
12
million of rights to reclaim cash collateral,
respectively.
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
1,795,652,203
1,791,637,434
1,785,419,175
Distributed under benefit plans
3,192,064
4,014,769
6,218,259
End of year
1,798,844,267
1,795,652,203
1,791,637,434
Held in Treasury
Beginning of year
710,783,814
653,288,213
608,312,034
Repurchase of common stock
20,018,275
57,495,601
44,976,179
End of year
730,802,089
710,783,814
653,288,213
Preferred Stock
We have authorized
500
million shares of preferred stock, par value
$
0.01
per share,
none
of which was issued
or outstanding at December 31, 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 $
69
million of equity outstanding in the same joint
ventures.
Repurchase of Common Stock
In late 2016, we initiated our current share repurchase
program, which has a current total program
authorization of $
25
billion of our common stock.
Cost of share repurchases were $
892
million, $
3,500
million, $
2,999
million in 2020, 2019 and 2018, respectively.
Share repurchases were suspended in the second
and third quarters of 2020 in response to the economic
downturn.
In the fourth quarter of 2020, we resumed
share repurchases, repurchasing $
0.2
billion of shares in October, until suspending further repurchases
upon
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
189
million shares at a cost of $
10,517
million, as of December 31, 2020.
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,
we have elected to adopt the optional practical expedient not
to separate lease components apart from non-lease components for accounting purposes.
This policy election
has been adopted for each of the company’s leased asset classes existing
as of the effective date and subject to
the transition provisions of ASC Topic 842 and will be applied to all new or
modified leases executed on or
after January 1, 2019.
For contractual arrangements executed in subsequent
periods involving a new leased
asset class, the company will determine at
contract inception whether it will apply the
optional practical
expedient to the new leased asset class.
Leases are evaluated for classification as operating
or finance leases at the commencement date of the
lease
and right-of-use assets and corresponding liabilities
are recognized on our consolidated balance sheet
based on
the present value of future lease payments relating
to the use of the underlying asset during the
lease term.
Future lease payments include variable lease payments
that depend upon an index or rate using
the index or
rate at the commencement date and probable
amounts owed under residual value guarantees.
The amount of
future lease payments may be increased to include
additional payments related to lease extension, termination,
and/or purchase options when the company has
determined, at or subsequent to lease commencement,
generally due to limited asset availability
or operating commitments, it is reasonably
certain of exercising such
options.
We use our incremental borrowing rate as the discount rate in determining the
present value of future
lease payments, unless the interest rate
implicit in the lease arrangement is readily determinable.
Lease
payments that vary subsequent to the commencement
date based on future usage levels, the nature
of leased
asset activities, or certain other contingencies are
not included in the measurement of lease
right-of-use assets
and corresponding liabilities.
We have elected not to record assets and liabilities on our consolidated balance
sheet for lease arrangements with terms of 12 months
or less.
We often enter into leasing arrangements acting in the capacity as operator for and/or
on behalf of certain oil
and gas joint ventures of undivided interests.
If the lease arrangement can be legally enforced only
against us
as operator and there is no separate arrangement to
sublease the underlying leased asset
to our coventurers, we
recognize at lease commencement a right-of-use
asset and corresponding lease liability on our
consolidated
balance sheet on a gross basis.
While we record lease costs on a gross basis in
our consolidated income
statement and statement of cash flows, such costs
are offset by the reimbursement we receive from our
coventurers for their share of the lease cost as the underlying
leased asset is utilized in joint venture activities.
As a result, lease cost is presented in our consolidated
income statement and statement of cash flows
on a
proportional basis.
If we are a nonoperating coventurer, we recognize a right-of-use
asset and corresponding
lease liability only if we were a specified contractual
party to the lease arrangement and the arrangement
could
be legally enforced against us.
In this circumstance, we would recognize both
the right-of-use asset and
corresponding lease liability on our consolidated
balance sheet on a proportional basis
consistent with our
undivided interest ownership in the related joint
venture.
The company has historically recorded certain
finance leases executed by investee companies
accounted for
under the proportionate consolidation method of
accounting on its consolidated balance sheet
on a proportional
basis consistent with its ownership interest
in the investee company.
In addition, the company has historically
recorded finance lease assets and liabilities
associated with certain oil and gas joint ventures
on a proportional
basis pursuant to accounting guidance applicable
prior to January 1, 2019.
In accordance with the transition
provisions of ASC Topic 842, and since we have elected to adopt the package
of optional transition-related
practical expedients, the historical accounting treatment
for these leases has been carried forward
and is subject
to reconsideration upon the modification or
other required reassessment of the arrangements
prior to lease term
expiration.
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
$
1,375
1,039
Accumulated DD&A
(721)
(649)
Net PP&E
*
654
390
Prepaid expenses and other current assets
$
-
40
Other assets
783
896
Lease Liabilities
Short-term debt
**
$
168
87
Other accruals
226
347
Long-term debt
***
723
633
Other liabilities and deferred credits
559
585
Total lease liabilities
$
785
891
932
720
*
Includes proportionately consolidated finance lease assets of $
258
million at December 31, 2020 and $
335
million at December 31, 2019.
** Includes proportionately consolidated finance lease liabilities of
$
97
million at December 31, 2020 and $
56
million at December 31, 2019.
*** Includes proportionately consolidated finance lease liabilities of $
522
million at December 31, 2020 and $
579
million at December 31,
2019.
The following table summarizes our lease costs
for 2020 and 2019:
Millions of Dollars
2020
2019
Lease Cost
*
Operating lease cost
$
321
341
Finance lease cost
Amortization of right-of-use assets
163
99
Interest on lease liabilities
34
37
Short-term lease cost
**
42
77
Total lease cost
***
$
560
554
* The amounts presented in the table above have not been adjusted to reflect amounts recovered or reimbursed from oil and gas coventurers.
** Short-term leases are not recorded on our consolidated balance sheet.
*** Variable lease cost and sublease income are immaterial for the periods presented and therefore are not included in the table above
.
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
6.11
5.19
Finance leases
7.12
8.70
Weighted-average discount rate (percent)
Operating leases
2.78
3.10
Finance leases
4.27
5.53
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
$
232
203
Operating cash flows from finance leases
11
27
Financing cash flows from finance leases
255
81
Right-of-use assets obtained in exchange for
operating lease liabilities
$
250
499
Right-of-use assets obtained in exchange for
finance lease liabilities
426
26
*The amounts presented in the table above have not been adjusted to reflect amounts recovered or reimbursed from oil and gas coventurers.
In
addition, pursuant to other applicable accounting guidance, lease
payments made in connection with preparing another asset for its intended use
are reported in the "Cash Flows From Investing Activities" section of our consolidated statement of cash flows.
The following table summarizes future lease
payments for operating and finance leases
at December 31, 2020:
Millions of Dollars
Operating
Leases
Finance
Leases
Maturity of Lease Liabilities
2021
$
245
213
2022
155
162
2023
116
148
2024
94
113
2025
55
87
Remaining years
200
320
Total
*
865
1,043
Less: portion representing imputed interest
(80)
(152)
Total lease liabilities
$
785
891
*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
$
253
Less: sublease rentals
(16)
$
237
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
$
2,319
3,880
2,136
3,438
216
218
Service cost
85
54
79
69
2
1
Interest cost
66
85
79
97
6
8
Plan participant contributions
-
1
-
2
18
20
Plan amendments
-
2
-
-
(30)
-
Actuarial loss
319
398
278
387
7
27
Benefits paid
(241)
(151)
(253)
(147)
(49)
(59)
Curtailment
-
2
-
(69)
-
-
Recognition of termination benefits
-
3
-
1
-
-
Foreign currency exchange rate change
-
129
-
102
-
1
Benefit obligation at December 31
*
$
2,548
4,403
2,319
3,880
170
216
*Accumulated benefit obligation portion of above at
December 31:
$
2,359
4,095
2,161
3,594
Change in Fair Value of Plan Assets
Fair value of plan assets at January 1
$
1,591
4,306
1,336
3,358
-
-
Actual return on plan assets
321
416
273
529
-
-
Company contributions
99
60
235
464
31
39
Plan participant contributions
-
1
-
2
18
20
Benefits paid
(241)
(151)
(253)
(147)
(49)
(59)
Foreign currency exchange rate change
-
161
-
100
-
-
Fair value of plan assets at December 31
$
1,770
4,793
1,591
4,306
-
-
Funded Status
$
(778)
390
(728)
426
(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
$
-
746
-
765
-
-
Current liabilities
(56)
(11)
(21)
(6)
(39)
(42)
Noncurrent liabilities
(722)
(345)
(707)
(333)
(131)
(174)
Total recognized
$
(778)
390
(728)
426
(170)
(216)
Weighted-Average Assumptions Used to
Determine Benefit Obligations at
December 31
Discount rate
2.30
%
1.80
3.25
2.35
2.15
3.10
Rate of compensation increase
4.00
3.10
4.00
3.35
Interest crediting rate for applicable benefits
2.10
-
4.10
-
Weighted-Average Assumptions Used to
Determine Net Periodic Benefit Cost for
Years
Ended December 31
Discount rate
3.05
%
2.35
3.95
2.90
3.10
4.05
Expected return on plan assets
5.80
3.60
5.80
4.10
Rate of compensation increase
4.00
3.35
4.00
3.65
Interest crediting rate for applicable benefits
4.10
-
4.35
-
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
$
2,548
391
2,319
355
Fair value of plan assets
1,770
35
1,591
44
Pension Plans with Accumulated Benefit
Obligation in
Excess of Plan Assets
Accumulated benefit obligation
$
2,359
338
2,161
299
Fair value of plan assets
1,770
35
1,591
44
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
$
467
326
479
227
14
8
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)
51
(7)
(27)
Amortization of actuarial (gain) loss included
in income (loss)*
95
21
116
32
1
(2)
Net change during the period
$
12
(99)
37
83
(6)
(29)
Prior service credit (cost) arising during the
period
$
-
(1)
-
-
30
-
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
$
85
54
79
69
83
81
2
1
1
Interest cost
66
85
79
97
99
107
6
8
8
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)
51
22
54
32
53
31
1
(2)
(1)
Settlements loss (gain)
44
(1)
62
-
196
-
-
-
-
Net periodic benefit cost
$
161
14
200
58
317
59
(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 $
43
million in 2020, $
62
million in 2019, and $
196
million in
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
$
43
million, resulting in a corresponding decrease
to other comprehensive income.
This is primarily a result of
a decrease in the discount rate from
2.90
percent at December 31, 2018 to
1.80
percent at September 30, 2019
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
10
percent of the unamortized balance each year.
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
7
percent in
2021 that declines to
5
percent by 2028.
The measurement of the U.S. post-65 retiree
medical accumulated
postretirement benefit obligation assumes an ultimate
health care cost trend rate of
4
percent achieved in 2021
that increases to
5
percent by 2028.
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
28
percent equity
securities,
68
percent debt securities,
3
percent real estate and
1
percent other.
Generally, the plan investments
are publicly traded, therefore minimizing liquidity
risk in the portfolio.
The following is a description of the valuation methodologies
used for the pension plan assets.
There have
been no changes in the methodologies used at
December 31, 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
$
94
million and consisted of $
233
million in debt securities, less $
139
million for the accumulated
benefit obligation covered by the contract.
At December 31, 2019, the participating interest
in the
annuity contract was valued at $
95
million and consisted of $
235
million in debt securities, less
$
140
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.
$
-
3
5
8
-
-
-
-
International
99
-
-
99
-
-
-
-
Mutual funds
72
-
-
72
235
734
-
969
Debt securities
Corporate
-
1
-
1
-
-
-
-
Mutual funds
-
-
-
-
455
-
-
455
Cash and cash equivalents
-
-
-
-
74
-
-
74
Derivatives
-
-
-
-
6
-
-
6
Real estate
-
-
-
-
-
-
142
142
Total in fair value hierarchy
$
171
4
5
180
770
734
142
1,646
Investments measured at net asset value*
Equity securities
Common/collective trusts
$
678
2,962
Debt securities
Common/collective trusts
730
67
Cash and cash equivalents
8
-
Real estate
79
112
Total**
$
171
4
5
1,675
770
734
142
4,787
*In accordance with FASB ASC Topic
715, “Compensation—Retirement Benefits,” certain investments that are to be measured at fair value
using the net asset value per share (or its equivalent) practical expedient
have not been classified in the fair value hierarchy.
The fair value
amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the Change in
Fair Value of Plan Assets.
**Excludes the participating interest in the insurance annuity contract with a net
asset of $
94
million and net receivables related to security
transactions of $
7
million.
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.
$
94
-
7
101
435
-
-
435
International
98
-
-
98
266
-
-
266
Mutual funds
93
-
-
93
245
267
-
512
Debt securities
Government
-
-
-
-
1,412
-
-
1,412
Corporate
-
2
-
2
-
-
-
-
Mutual funds
-
-
-
-
392
-
-
392
Cash and cash equivalents
-
-
-
-
98
-
-
98
Derivatives
-
-
-
-
11
-
-
11
Real estate
-
-
-
-
-
-
132
132
Total in fair value hierarchy
$
285
2
7
294
2,859
267
132
3,258
Investments measured at net asset value*
Equity securities
Common/collective trusts
$
457
167
Debt securities
Common/collective trusts
637
760
Cash and cash equivalents
25
-
Real estate
83
112
Total**
$
285
2
7
1,496
2,859
267
132
4,297
*In accordance with FASB ASC Topic
715, “Compensation—Retirement Benefits,” certain investments that are to be measured at fair value
using the net asset value per share (or its equivalent) practical expedient
have not been classified in the fair value hierarchy.
The fair value
amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the Change in
Fair Value of Plan Assets.
**Excludes the participating interest in the insurance annuity contract with a
net asset of $
95
million and net receivables related to security
transactions of $
9
million.
Level 3 activity was not material for all
periods.
Our funding policy for U.S. plans is to contribute
at least the minimum required by the Employee
Retirement
Income Security Act of 1974 and the Internal
Revenue Code of 1986, as amended.
Contributions to foreign
plans are dependent upon local laws and tax regulations.
In 2021, we expect to contribute approximately $
265
million to our domestic qualified and nonqualified
pension and postretirement benefit plans and $
75
million to
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
$
532
147
25
2022
289
151
21
2023
248
156
18
2024
232
162
16
2025
215
166
14
2026–2030
845
897
53
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
$
23
48
53
Accruals
14
(1)
70
Benefit payments
(13)
(24)
(73)
Foreign currency translation adjustments
-
-
(2)
Balance at December 31
$
24
23
48
Of the remaining balance at December 31, 2020,
$
8
million is classified as short-term.
Defined Contribution Plans
Most U.S. employees are eligible to participate
in the ConocoPhillips Savings Plan (CPSP).
Employees can
deposit up to
75
percent of their eligible pay, subject to statutory limits, in the CPSP to
a choice of
approximately
17
investment options.
Employees who participate in the CPSP and contribute
1
percent of
their eligible pay receive a
6
percent company cash match with a potential
company discretionary cash
contribution of up to
6
percent.
Effective January 1, 2019, new employees, rehires, and
employees that elected
to opt out of Title II are eligible to receive a Company Retirement
Contribution (CRC) of
6
percent of eligible
pay into their CPSP.
After
three years
of service with the company, the employee is
100
percent vested in any
CRC.
Company contributions charged to expense for the
CPSP and predecessor plans were $
62
million in
2020, $
82
million in 2019, and $
82
million in 2018.
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 $
25
million in 2020, $
30
million in 2019, and $
31
million in 2018.
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
79
million shares of our
common stock for compensation to our employees
and directors; however, as of the effective date of the Plan,
(i) any shares of common stock available for future
awards under the prior plans and (ii)
any shares of common
stock represented by awards granted under the 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
79
million shares available for issuance
under the Plan, no more than
40
million shares of
common stock are available for incentive stock
options.
The Human Resources and Compensation Committee
of our Board of Directors is authorized to determine
the types, terms, conditions and limitations
of awards
granted.
Awards may be granted in the form of, but not limited to, stock options, restricted 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
$
159
274
265
Tax benefit
40
71
64
Stock Options
—
Stock options granted under the provisions of the Plan and prior plans permit purchase of our
common stock at exercise prices equivalent to the average fair market value of ConocoPhillips common stock
on the date the options were granted. The options have terms of 10 years and generally vest ratably, with one-
third of the options awarded vesting and becoming exercisable on each anniversary date following the date of
grant. Options awarded to certain employees already eligible for retirement vest within six months of the grant
date, but those options do not become exercisable until the end of the normal vesting period. Beginning in
2018, stock option grants were discontinued and replaced with three-year, time-vested restricted stock units
which generally will be cash-settled
for 2018 and 2019 awards and stock-settled for 2020
awards.
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
18,040,197
$
54.11
$
206
Exercised
(1,111,805)
38.80
23
Forfeited
(5,867)
49.76
Expired or cancelled
-
Outstanding at December 31, 2020
16,922,525
$
55.12
$
22
Vested at December 31, 2020
16,922,525
$
55.12
$
22
Exercisable at December 31, 2020
16,922,525
$
55.12
$
22
The weighted-average remaining contractual term
of outstanding options, vested options and exercisable
options at December 31, 2020, were all
3.66
years.
The aggregate intrinsic value of options exercised
was $
39
million in 2019 and $
94
million in 2018.
During 2020, we received $
43
million in cash and realized a tax benefit
of $
9
million from the exercise of
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—
Generally, restricted stock units are granted annually under the provisions of the Plan
and vest in an aggregate installment on the third anniversary of the grant date. In addition, restricted stock
units granted under the Plan for a variable long-term incentive program vest ratably in three equal annual
installments beginning on the first anniversary of the grant date. Restricted stock units are also granted ad hoc
to attract or retain key personnel, and the terms and conditions under which these restricted stock units vest
vary by award
.
Stock-Settled
Upon vesting, these restricted stock units are settled by issuing one share of ConocoPhillips common stock per
135
unit. Units awarded to retirement eligible employees vest six months from the grant date; however, those units
are not issued as common stock until the earlier of separation from the company or the end of the regularly
scheduled vesting period. Until issued as stock, most recipients of the restricted stock units receive a cash
payment of a dividend equivalent that is charged to retained earnings. Executive recipients receive an accrued
reinvested dividend equivalent, subject to the terms and conditions of the award, that is charged to retained
earnings. The grant date fair market value of these restricted stock units is deemed equal to the average
ConocoPhillips stock price on the grant date. The grant date fair market value of units that do not receive a
dividend equivalent while unvested is deemed equal to the average ConocoPhillips stock price on the grant
date, less the net present value of the dividends that will not be received
.
The following summarizes our stock-settled stock
unit activity for the year ended December
31, 2020:
Weighted-Average
Millions of Dollars
Stock Units
Grant Date Fair Value
Total Fair Value
Outstanding at December 31, 2019
6,223,046
$
55.99
Granted
2,890,840
57.40
Forfeited
(127,181)
55.84
Issued
(2,554,720)
50.16
$
143
Outstanding at December 31, 2020
6,431,985
$
58.94
Not Vested at December 31, 2020
4,230,413
59.01
At December 31, 2020,
the remaining unrecognized compensation
cost from the unvested stock-settled units
was $
101
million, which will be recognized over
a weighted-average period of
1.71
years, the longest period
being
2.14
years.
The weighted-average grant date fair value
of stock unit awards granted during 2019 and
2018 was $
67.77
and $
52.45
, respectively.
The total fair value of stock units issued during
2019 and 2018 was
$
225
million and $
154
million, respectively.
Cash-Settled
Cash settled executive restricted stock units granted in 2018 and 2019 replaced the stock option program.
These restricted stock units, subject to elections to defer, will be settled in cash equal to the fair market value
of a share of ConocoPhillips common stock per unit on the settlement date and are classified as liabilities on
the balance sheet. Units awarded to retirement eligible employees vest six months from the grant date;
however, those units are not settled until the earlier of separation from the company or the end of the regularly
scheduled vesting period. Compensation expense is initially measured using the average fair market value of
ConocoPhillips common stock and is subsequently adjusted, based on changes in the ConocoPhillips stock
price through the end of each subsequent reporting period, through the settlement date. Recipients receive an
accrued reinvested dividend equivalent that is charged to compensation expense. The accrued reinvested
dividend is paid at the time of settlement, subject to the terms and conditions of the award. Beginning with
executive restricted stock units granted in 2020 awards will be settled in stock.
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
596,991
$
64.54
Granted
24,437
41.59
Forfeited
(5,622)
40.01
Issued
(1,191)
40.20
$
-
Outstanding at December 31, 2020
614,615
$
39.95
Not Vested at December 31, 2020
121,696
39.95
At December 31, 2020,
the remaining unrecognized compensation
cost from the unvested cash-settled units
was $
1
million, which will be recognized over a
weighted-average period of
1
year, the longest period being
1.12
years.
The weighted-average grant date fair value of
stock unit awards granted during 2019
and 2018
were $
68.20
and $
53.68
, respectively.
The total fair value of stock units issued during
2019 and 2018 were $
6
million and $
1
million, respectively.
Performance Share Program
—Under the Plan, we also annually grant restricted
performance share units
(PSUs) to senior management.
These PSUs are authorized three years prior to
their effective grant date (the
performance period).
Compensation expense is initially measured
using the average fair market value of
ConocoPhillips common stock and is subsequently
adjusted, based on changes in the ConocoPhillips
stock
price through the end of each subsequent reporting
period, through the grant date for stock-settled
awards and
the settlement date for cash-settled awards.
Stock-Settled
For performance periods beginning before 2009, PSUs do not vest until the employee becomes eligible for
retirement by reaching age 55 with five years of service, and restrictions do not lapse until the employee
separates from the company. With respect to awards for performance periods beginning in 2009 through 2012,
PSUs do not vest until the earlier of the date the employee becomes eligible for retirement by reaching age 55
with five years of service or five years after the grant date of the award, and restrictions do not lapse until the
earlier of the employee’s separation from the company or five years after the grant date (although recipients
can elect to defer the lapsing of restrictions until separation). We recognize compensation expense for these
awards beginning on the grant date and ending on the date the PSUs are scheduled to vest. Since these awards
are authorized three years prior to the grant date, for employees eligible for retirement by or shortly after the
grant date, we recognize compensation expense over the period beginning on the date of authorization and
ending on the date of grant. Until issued as stock, recipients of the PSUs receive a quarterly cash payment of a
dividend equivalent that is charged to retained earnings. Beginning in 2013, PSUs authorized for future grants
will vest, absent employee election to defer, upon settlement following the conclusion of the three-year
performance period. We recognize compensation expense over the period beginning on the date of
authorization and ending on the conclusion of the performance period. PSUs are settled by issuing one share
of ConocoPhillips common stock per unit.
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
2,024,824
$
50.55
Granted
26,244
58.61
Forfeited
-
Issued
(314,340)
51.15
$
13
Outstanding at December 31, 2020
1,736,728
$
50.56
Not Vested at December 31, 2020
3,191
$
48.61
At December 31, 2020,
the remaining unrecognized compensation
cost from unvested stock-settled
performance share awards was
zero
.
The weighted-average grant date fair value of
stock-settled PSUs granted
during 2019 and 2018 was $
68.90
and $
53.28
, respectively.
The total fair value of stock-settled PSUs issued
during 2019 and 2018 was $
25
million and $
29
million, respectively.
Cash-Settled
In connection with and immediately following the
separation of our Downstream businesses
in 2012, grants of
new PSUs, subject to a shortened performance
period, were authorized.
Once granted, these PSUs vest, absent
employee election to defer, on the earlier of five years after
the grant date of the award or the date the
employee becomes eligible for retirement.
For employees eligible for retirement by or shortly
after the grant
date, we recognize compensation expense
over the period beginning on the date of authorization
and ending on
the date of grant.
Otherwise, we recognize compensation expense
beginning on the grant date and ending on
the date the PSUs are scheduled to vest.
These PSUs are settled in cash equal to the fair
market value of a
share of ConocoPhillips common stock per unit
on the settlement date and thus are classified
as liabilities on
the balance sheet.
Until settlement occurs, recipients of the PSUs receive
a quarterly cash payment of a
dividend equivalent that is charged to compensation expense.
Beginning in 2013, PSUs authorized for future grants
will vest upon settlement following the conclusion
of the
three-year performance period.
We recognize compensation expense over the period beginning on the date of
authorization and ending at the conclusion of
the performance period.
These PSUs will be settled in cash equal
to the fair market value of a share of ConocoPhillips
common stock per unit on the settlement date
and are
classified as liabilities on the balance sheet.
For performance periods beginning before
2018, during the
performance period, recipients of the PSUs do
not receive a quarterly cash payment of a dividend
equivalent,
but after the performance period ends, until
settlement in cash occurs, recipients of the PSUs
receive a
quarterly cash payment of a dividend equivalent
that is charged to compensation expense.
For the performance
period beginning in 2018, recipients of the PSUs
receive an accrued reinvested dividend equivalent
that is
charged to compensation expense.
The accrued reinvested dividend is paid at
the time of settlement, subject to
the terms and conditions of the award.
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
609,274
$
64.54
Granted
1,491,098
58.61
Forfeited
-
Settled
(1,975,843)
58.54
$
116
Outstanding at December 31, 2020
124,529
$
39.95
At December 31, 2020, all outstanding cash-settled
performance awards were fully vested and there
was
no
remaining compensation cost to be recorded.
The weighted-average grant date fair value
of cash-settled PSUs
granted during 2019 and 2018 was $
68.90
and $
53.28
, respectively.
The total fair value of cash-settled
performance share awards settled during 2019
and 2018 was $
171
million and $
22
million, respectively.
From inception of the Performance Share Program
through 2013, approved PSU awards
were granted after the
conclusion of performance periods.
Beginning in February 2014, initial target PSU awards are issued near the
beginning of new performance periods. These initial target PSU awards will terminate at the end of the
performance periods and will be settled after the performance periods have ended. Also in 2014, initial target
PSU awards were issued for open performance periods that began in prior years. For the open performance
period beginning in 2012, the initial target PSU awards terminated at the end of the three-year performance
period and were replaced with approved PSU awards. For the open performance period beginning in 2013, the
initial target PSU awards terminated at the end of the three-year performance period and were settled after the
performance period ended.
There is no effect on recognition of compensation expense.
Other
—In addition to the above active programs,
we have outstanding shares of restricted stock and
restricted
stock units that were either issued as part of
our non-employee director compensation program
for current and
former members of the company’s Board of Directors 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
991,908
$
47.24
Granted
77,824
51.46
Cancelled
(1,336)
23.09
Issued
(98,297)
45.57
$
6
Outstanding at December 31, 2020
970,099
$
47.78
At December 31, 2020, all outstanding restricted
stock and restricted stock units were fully vested
and there
was
no
remaining compensation cost to be recorded.
The weighted-average grant date fair value of awards
granted during 2019 and 2018 was $
63.58
and $
62.01
, respectively.
The total fair value of awards issued
during 2019 and 2018 was $
11
million and $
17
million, respectively.
139
Note 18—Income Taxes
Components of income tax expense (benefit)
were:
Millions of Dollars
2020
2019
2018
Income Taxes
Federal
Current
$
3
18
4
Deferred
(625)
(113)
545
Foreign
Current
350
2,545
3,273
Deferred
(70)
(323)
(166)
State and local
Current
(4)
148
108
Deferred
(139)
(8)
(96)
$
(485)
2,267
3,668
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
$
7,744
8,660
Inventory
64
35
Other
242
234
Total deferred tax liabilities
8,050
8,929
Deferred Tax Assets
Benefit plan accruals
540
542
Asset retirement obligations and accrued environmental
costs
2,262
2,339
Investments in joint ventures
1,653
1,722
Other financial accruals and deferrals
907
777
Loss and credit carryforwards
8,904
8,968
Other
365
345
Total deferred tax assets
14,631
14,693
Less: valuation allowance
(9,965)
(10,214)
Total deferred tax assets net of valuation allowance
4,666
4,479
Net deferred tax liabilities
$
3,384
4,450
At December 31, 2020, noncurrent assets and liabilities
included deferred taxes of $
363
million and
$
3,747
million, respectively.
At December 31, 2019, noncurrent assets and liabilities
included deferred taxes
of $
184
million and $
4,634
million, respectively.
At December 31, 2020,
the loss and credit carryforward deferred tax
assets were primarily related to U.S.
foreign tax credit carryforwards of $
7
billion and various jurisdictions net
operating loss and credit
carryforwards of $
1.9
billion.
If not utilized, U.S. foreign tax credits and net operating
losses will begin to
expire in 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
$
10,214
3,040
1,254
Charged to expense (benefit)
460
(225)
(26)
Other*
(709)
7,399
1,812
Balance at December 31
$
9,965
10,214
3,040
*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 $
151
million of net deferred tax assets.
Correspondingly, we recorded $
6,642
million of existing
foreign tax credit carryovers where recognition
was previously considered to be remote.
Present legislation
still makes their realization unlikely and therefore
these credits have been offset with a full valuation
allowance.
At December 31, 2020, unremitted income
considered to be permanently reinvested in certain
foreign
subsidiaries and foreign corporate joint ventures
totaled approximately $
3,982
million.
Deferred income taxes
have not been provided on this amount, as
we do not plan to initiate any action that would
require the payment
of income taxes.
The estimated amount of additional tax, primarily
local withholding tax, that would be
payable on this income if distributed is approximately
$
199
million.
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
$
1,177
1,081
882
Additions based on tax positions related to the current
year
6
9
268
Additions for tax positions of prior years
67
120
43
Reductions for tax positions of prior years
(34)
(22)
(73)
Settlements
(9)
(9)
(35)
Lapse of statute
(1)
(2)
(4)
Balance at December 31
$
1,206
1,177
1,081
Included in the balance of unrecognized tax benefits
for 2020, 2019 and 2018 were $
1,128
million,
$
1,100
million and $
1,081
million, respectively, which, if recognized, would impact our effective tax rate.
The
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 $
46
million,
$
42
million and $
45
million, respectively, net of accrued income taxes.
Interest and penalties resulted in a
reduction to earnings of $
4
million in 2020, a benefit to earnings of $
3
million in 2019, and a benefit to
earnings of $
4
million in 2018, respectively.
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)
4,704
2,867
114.2
%
49.4
28.7
Foreign
447
4,820
7,106
(14.2)
50.6
71.3
$
(3,140)
9,524
9,973
100.0
%
100.0
100.0
Federal statutory income tax
$
(659)
2,000
2,095
21.0
%
21.0
21.0
Non-U.S. effective tax rates
194
1,399
1,766
(6.2)
14.7
17.7
Tax Legislation
-
-
(10)
-
-
(0.1)
Australia disposition
(349)
-
-
11.1
-
-
U.K. disposition
-
(732)
(150)
-
(7.7)
(1.5)
Recovery of outside basis
(22)
(77)
(21)
0.7
(0.8)
(0.2)
Adjustment to tax reserves
18
9
(4)
(0.6)
0.1
-
Adjustment to valuation allowance
460
(225)
(26)
(14.6)
(2.4)
(0.3)
State income tax
(112)
123
135
3.6
1.3
1.4
Malaysia Deepwater Incentive
-
(164)
-
-
(1.7)
-
Enhanced oil recovery credit
(6)
(27)
(99)
0.2
(0.3)
(1.0)
Other
(9)
(39)
(18)
0.3
(0.4)
(0.2)
$
(485)
2,267
3,668
15.5
%
23.8
36.8
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 $
587
million with an associated tax benefit of
$
10
million and resulted in the de-recognition of deferred
tax assets resulting in $
92
million of tax expense.
The
disposition also generated an Australia capital
loss tax benefit of $
313
million which has been fully offset by a
valuation allowance.
Due to changes in the fair market value of Cenovus
Energy common shares, the
valuation allowance was increased by $
178
million to offset the expected capital loss.
Our effective tax rate for 2019 was favorably impacted
by the sale of two of our U.K. subsidiaries.
The
disposition generated a before-tax gain of more than
$
1.7
billion with an associated tax benefit of $
335
142
million. The disposition generated a U.S. capital
loss of approximately $
2.1
billion which has generated a U.S.
tax benefit of approximately $
285
million. The remaining U.S. capital loss
has been recorded as a deferred tax
asset fully offset with a valuation
allowance.
See Note 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 $
164
million.
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
16.5
percent of our
24
percent interest in the BP-operated Clair Field
in the U.K.
The
disposition generated a before-tax gain of $
715
million with no associated tax cost.
See Note 4—Asset
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 $
120
million and a decrease to our accrued income
and other taxes liability of
$
124
million.
Legislation in other jurisdictions did not have
a material impact to ConocoPhillips.
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)
39
-
(642)
(603)
Cumulative effect of adopting ASU No. 2016-01*
-
58
-
58
December 31, 2018
(361)
-
(5,702)
(6,063)
Other comprehensive income
51
-
695
746
Cumulative effect of adopting ASU No. 2018-02**
(40)
-
-
(40)
December 31, 2019
(350)
-
(5,007)
(5,357)
Other comprehensive income (loss)
(75)
2
212
139
December 31, 2020
$
(425)
2
(4,795)
(5,218)
*We adopted ASU No. 2016-01, "Recognition and Measurement of Financial Assets and Liabilities," beginning
January 1, 2018.
**We adopted ASU No. 2018-02, "Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income," beginning January
1, 2019.
During 2019, we recognized $
483
million of foreign currency translation adjustments
related to the completion
of our sale of two ConocoPhillips U.K. subsidiaries.
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
$
72
88
Above amounts are included in the computation of net periodic benefit cost
and
are presented net of tax expense of:
$
13
23
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)
205
395
Increase (decrease) in assets and liabilities
acquired in a nonmonetary
exchange*
Accounts receivable
-
-
(44)
Inventories
-
-
42
Investments and long-term receivables
-
-
15
PP&E
-
-
1,907
Other long-term assets
-
-
(9)
Accounts payable
-
-
7
Accrued income and other taxes
-
-
40
Cash Payments
Interest
$
785
810
772
Income taxes
905
2,905
2,976
Net Sales (Purchases) of Investments
Short-term investments purchased
$
(12,435)
(4,902)
(1,953)
Short-term investments sold
12,015
2,138
3,573
Investments and long-term receivables purchased
(325)
(146)
-
Investments and long-term receivables sold
87
-
-
$
(658)
(2,910)
1,620
*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 $
330
million and $
430
million in 2019 and 2018, respectively, from PDVSA under a settlement
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 $
262
million from Ecuador in 2018, as
installment payments related to an agreement
reached with Ecuador in 2017.
In 2019, we made a $
324
million contribution to our U.K. pension plan.
We made discretionary payments to
our domestic qualified pension plan of $
120
million in 2018.
144
Note 21—Other Financial Information
Millions of Dollars
2020
2019
2018
Interest and Debt Expense
Incurred
Debt
$
788
799
838
Other
73
36
67
861
835
905
Capitalized
(55)
(57)
(170)
Expensed
$
806
778
735
Other Income (Loss)
Interest income
$
100
166
97
Unrealized gains (losses) on Cenovus Energy common shares*
(855)
649
(437)
Other, net
246
543
513
$
(509)
1,358
173
*See Note 6—Investment in Cenovus Energy, for additional information.
Research and Development Expenditures
—expensed
$
75
82
78
Shipping and Handling Costs
$
857
1,008
1,075
Foreign Currency Transaction (Gains) Losses
—after-tax
Alaska
$
-
-
-
Lower 48
-
-
-
Canada
(7)
5
(11)
Europe, Middle East and North Africa
(15)
-
(26)
Asia Pacific
(11)
31
3
Other International
2
1
-
Corporate and Other
(31)
21
21
$
(62)
58
(13)
Millions of Dollars
2020
2019
Properties, Plants and Equipment
Proved properties
$
94,312
88,284
*
Unproved properties
4,141
3,980
*
Other
3,653
5,482
Gross properties, plants and equipment
102,106
97,746
Less: Accumulated depreciation, depletion and amortization
(62,213)
(55,477)
*
Net properties, plants and equipment
$
39,893
42,269
*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
$
79
89
98
Purchases
-
38
98
Operating expenses and selling, general and administrative
expenses
63
65
60
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
information on loans to affiliated companies.
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
$
13,662
26,106
28,098
Revenue from contracts outside the scope of ASC
Topic 606
Physical contracts meeting the definition of a derivative
5,177
6,558
8,218
Financial derivative contracts
(55)
(97)
101
Consolidated sales and other operating revenues
$
18,784
32,567
36,417
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
$
3,966
4,989
6,358
Canada
727
691
629
Europe, Middle East and North Africa
484
878
1,231
Physical contracts meeting the definition of a derivative
$
5,177
6,558
8,218
146
Millions of Dollars
2020
2019
2018
Revenue from Outside the Scope of ASC Topic 606
by Product
Crude oil
$
395
804
1,112
Natural gas
4,339
5,313
6,734
Other
443
441
372
Physical contracts meeting the definition of a derivative
$
5,177
6,558
8,218
Practical Expedients
Typically,
our commodity sales contracts are less than
12 months in duration; however, in certain specific
cases may extend longer, which may be out to the end of
field life.
We have long-term commodity sales
contracts which use prevailing market prices at the time of delivery, and under these contracts, the market-
based variable consideration for each performance obligation (i.e., delivery of commodity) is allocated to each
wholly unsatisfied performance obligation within the contract.
Accordingly,
we have applied the practical
expedient allowed in ASC Topic 606 and do not disclose the aggregate amount of the transaction price
allocated to performance obligations or when we expect to recognize revenues that are unsatisfied (or partially
unsatisfied) as of the end of the reporting period.
Receivables and Contract Liabilities
Receivables from Contracts with Customers
At December 31, 2020, the “Accounts and
notes receivable” line on our consolidated
balance sheet included
trade receivables of $
1,827
million compared with $
2,372
million at December 31, 2019, and included both
contracts with customers within the scope of ASC
Topic 606 and those that are outside the scope of ASC
Topic 606.
We typically receive payment within 30 days or less (depending on the terms of the invoice) once
delivery is made.
Revenues that are outside the scope of ASC Topic 606 relate primarily to
physical gas sales
contracts at market prices for which we do not
elect NPNS and are therefore accounted for
as a derivative
under ASC Topic 815.
There is little distinction in the nature
of the customer or credit quality of trade
receivables associated with gas sold under contracts
for which NPNS has not been elected
compared with trade
receivables where NPNS has been elected.
Contract Liabilities from Contracts with Customers
We have entered into contractual arrangements where we license proprietary technology to customers related
to the optimization process for operating LNG plants. The agreements typically provide for negotiated
payments to be made at stated milestones. The payments are not directly related to our performance under the
contract and are recorded as deferred revenue to be recognized as revenue when the customer can utilize and
benefit from their right to use the license. Payments are received in installments over the construction period.
Millions of Dollars
Contract Liabilities
At December 31, 2019
$
80
Contractual payments received
17
At December 31, 2020
$
97
Amounts Recognized in the Consolidated
Balance Sheet at December 31, 2020
Current liabilities
$
56
Noncurrent liabilities
41
$
97
We expect to recognize the contract liabilities as of December 31, 2020, as revenue during 2021 and 2022.
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
operating segments, which are primarily defined
by geographic
region: Alaska; Lower 48; Canada; Europe,
Middle East and North Africa; Asia Pacific;
and Other
International.
Corporate and Other represents income and costs
not directly associated with an operating
segment, such as
most interest expense, premiums on early retirement
of debt, corporate overhead and certain technology
activities, including licensing revenues.
Corporate assets include all cash and cash
equivalents and short-term
investments.
We evaluate performance and allocate resources based on net income (loss) attributable
to ConocoPhillips.
Segment accounting policies are the same as those
in Note 1—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
$
3,408
5,483
5,740
Intersegment eliminations
(11)
-
-
Alaska
3,397
5,483
5,740
Lower 48
9,872
15,514
17,029
Intersegment eliminations
(51)
(46)
(40)
Lower 48
9,821
15,468
16,989
Canada
1,666
2,910
3,184
Intersegment eliminations
(405)
(1,141)
(1,160)
Canada
1,261
1,769
2,024
Europe, Middle East and North Africa
1,919
5,101
6,635
Intersegment eliminations
(2)
-
-
Europe, Middle East and North Africa
1,917
5,101
6,635
Asia Pacific
2,363
4,525
4,861
Other International
7
-
-
Corporate and Other
18
221
168
Consolidated sales and other operating revenues
$
18,784
32,567
36,417
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
$
996
805
760
Lower 48
3,358
3,224
2,370
Canada
342
232
324
Europe, Middle East and North Africa
775
887
1,041
Asia Pacific
809
1,285
1,382
Other International
-
-
-
Corporate and Other
54
62
106
Consolidated depreciation, depletion, amortization
and impairments
$
6,334
6,495
5,983
Equity in Earnings of Affiliates
Alaska
$
(7)
7
6
Lower 48
(11)
(159)
1
Canada
-
-
-
Europe, Middle East and North Africa
311
470
744
Asia Pacific
137
461
323
Other International
2
-
-
Corporate and Other
-
-
-
Consolidated equity in earnings of affiliates
$
432
779
1,074
Income Tax Provision (Benefit)
Alaska
$
(256)
472
376
Lower 48
(378)
137
474
Canada
(185)
(43)
(96)
Europe, Middle East and North Africa
136
1,425
2,259
Asia Pacific
294
501
728
Other International
(20)
8
30
Corporate and Other
(76)
(233)
(103)
Consolidated income tax provision (benefit)
$
(485)
2,267
3,668
Net Income (Loss) Attributable to ConocoPhillips
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)
Consolidated net income (loss) attributable
to ConocoPhillips
$
(2,701)
7,189
6,257
149
Millions of Dollars
2020
2019
2018
Investments in and Advances to Affiliates
Alaska
$
62
83
86
Lower 48
25
35
378
Canada
-
-
-
Europe, Middle East and North Africa
918
1,070
1,311
Asia Pacific
6,705
7,265
7,565
Other International
-
-
-
Corporate and Other
-
-
-
Consolidated investments in and advances to affiliates
$
7,710
8,453
9,340
Total Assets
Alaska
$
14,623
15,453
14,648
Lower 48
11,932
14,425
14,888
Canada
6,863
6,350
5,748
Europe, Middle East and North Africa
8,756
9,269
11,276
Asia Pacific
11,231
13,568
14,758
Other International
226
285
89
Corporate and Other
8,987
11,164
8,573
Consolidated total assets
$
62,618
70,514
69,980
Capital Expenditures and Investments
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
Consolidated capital expenditures and investments
$
4,715
6,636
6,750
Interest Income and Expense
Interest income
Alaska
$
-
-
-
Lower 48
-
-
-
Canada
-
-
-
Europe, Middle East and North Africa
5
11
12
Asia Pacific
7
6
5
Other International
-
-
-
Corporate and Other
88
149
80
Interest and debt expense
Corporate and Other
$
806
778
735
Sales and Other Operating Revenues by
Product
Crude oil
$
9,736
18,482
19,571
Natural gas
6,427
8,715
10,720
Natural gas liquids
528
814
1,114
Other*
2,093
4,556
5,012
Consolidated sales and other operating revenues
by product
$
18,784
32,567
36,417
*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
$
13,230
21,159
22,740
24,034
26,566
26,838
Australia and Timor-Leste
605
1,647
1,798
6,676
7,228
9,301
Canada
1,261
1,769
2,024
6,385
5,769
5,333
China
460
772
836
1,491
1,447
1,380
Indonesia
689
875
886
464
605
669
Libya
155
1,103
1,142
670
668
679
Malaysia
610
1,230
1,346
1,501
1,871
2,327
Norway
1,426
2,349
2,886
5,294
5,258
5,582
United Kingdom
336
1,649
2,606
1
2
1,583
Other foreign countries
12
14
153
1,087
1,308
1,346
Worldwide consolidated
$
18,784
32,567
36,417
47,603
50,722
55,038
(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
October 18, 2020
, 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
1.46
for shares of ConocoPhillips common
stock, for total consideration of $
13.1
billion.
This resulted in issuance of
286
million shares, representing
approximately
21
percent of the outstanding shares of ConocoPhillips
common stock upon completion of the
transaction.
We also assumed Concho’s outstanding debt of $
3.9
billion in aggregate principal amount, recorded
at fair
value of $
4.7
billion on the transaction closing date.
On December 7, 2020, we launched a debt
exchange offer
which settled on February 8, 2021, for
98
percent of Concho’s historical notes.
The historical notes issued by
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 of Concho common stock
issued and outstanding (in thousands)*
194,243
Number of shares of Concho stock awards outstanding
(in thousands)*
1,599
Number of shares exchanged
195,842
Exchange ratio
1.46
Additional shares of ConocoPhillips common stock
issued as consideration (in thousands)
285,929
Average price per share of ConocoPhillips common stock**
$
45.9025
Total Consideration (Millions)
$
13,125
*Outstanding as of January 15, 2021.
**Based on the ConocoPhillips average stock price on January
15, 2021.
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:
In 2018, Alaska purchases were due to the
Greater Kuparuk Area and Western North Slope acquisitions.
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
81
and is incorporated herein by reference.
Report of Independent Registered Public Accounting
Firm
This report is included in Item 8 on page
85
and is incorporated herein by reference.
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
(within the Investors>Corporate Governance
section)
.
Any
waivers of the Code of Ethics must be approved, in
advance, by our full Board of Directors.
Any amendments
to, or waivers from, the Code of Ethics that apply
to our executive officers and directors will be posted on the
“Corporate Governance” section of our internet
website.
All other information required by Item 10 of
Part III will be included in our Proxy Statement
relating to our
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
80
, 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
182
through 190, are filed as part
of this annual report.
182
CONOCOPHILLIPS
INDEX TO EXHIBITS
Exhibit
Number
Description
2.1
Separation and Distribution Agreement Between ConocoPhillips and Phillips 66, dated April 26,
2012 (incorporated by reference to Exhibit 2.1 to the Current Report of ConocoPhillips on Form 8-
K filed on May 1, 2012; File No. 001-32395).
2.2†‡
Purchase and Sale Agreement, dated March 29, 2017, by and among ConocoPhillips
Company, ConocoPhillips Canada Resources Corp., ConocoPhillips Canada Energy
Partnership, ConocoPhillips Western Canada Partnership, ConocoPhillips Canada (BRC)
Partnership, ConocoPhillips Canada E&P ULC, and Cenovus Energy Inc. (incorporated by
reference to Exhibit 2.1 to the Quarterly Report on Form 10-Q for the quarter ended March
31, 2017 filed by ConocoPhillips on May 4, 2017).
2.3†‡
Asset Purchase and Sale Agreement Amending Agreement, dated as of May 16, 2017, by and
among ConocoPhillips Company, ConocoPhillips Canada Resources Corp., ConocoPhillips Canada
Energy Partnership, ConocoPhillips Western Canada Partnership, ConocoPhillips Canada (BRC)
Partnership, ConocoPhillips Canada E&P ULC, and Cenovus Energy Inc. (incorporated by
reference to Exhibit 2.2 to the Current Report of ConocoPhillips on Form 8-K filed on May 18,
2.4
Agreement and Plan of Merger, dated as of October 18, 2020, among ConocoPhillips, Falcon
Merger Sub Corp. and Concho Resources Inc. (incorporated by reference to Exhibit 2.1 to the
Current Report of ConocoPhillips on Form 8-K filed on October 19, 2020; File No. 001-32395).
3.1
Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the
Quarterly Report of ConocoPhillips on Form 10-Q for the quarterly period ended June 30, 2008;
3.2
Certificate of Designations of Series A Junior Participating Preferred Stock of ConocoPhillips
(incorporated by reference to Exhibit 3.2 to the Current Report of ConocoPhillips on Form 8-K filed
on August 30, 2002; File No. 000-49987).
3.3
Amended and Restated By-Laws of ConocoPhillips, as amended and restated as of October 9, 2015
(incorporated by reference to Exhibit 3.1 to the Current Report of ConocoPhillips on Form 8-K filed
on October 13, 2015; File No. 001-32395).
ConocoPhillips and its subsidiaries are parties
to several debt instruments under which the total
amount of securities authorized does not exceed
10 percent of the total assets of ConocoPhillips
and
its subsidiaries on a consolidated basis.
Pursuant to paragraph 4(iii)(A) of Item 601(b)
of
Regulation S-K, ConocoPhillips agrees to furnish
a copy of such instruments to the SEC upon
request.
4.1
Description of Securities of the Registrant (incorporated by reference to Exhibit 4.1 to the Annual
Report of ConocoPhillips on Form 10-K for the year ended December 31, 2019; File No. 001-
183
10.1
1986 Stock Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.11 to the
Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002;
10.2
1990 Stock Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.12 to the
Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002;
10.3
Annual Incentive Compensation Plan of Phillips Petroleum Company (incorporated by reference to
Exhibit 10.13 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).
10.4
Incentive Compensation Plan of Phillips Petroleum Company (incorporated by reference to Exhibit
10(g) to the Annual Report of ConocoPhillips Company on Form 10-K for the year ended
December 31, 1999; File No. 001-00720).
10.5
Amendment and Restatement of ConocoPhillips Supplemental Executive Retirement Plan, dated
http://www.sec.gov/Archives/edgar/data/1163165/000119312512325680/d358543dex1014.htm
(incorporated by reference to Exhibit 10.14 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-32395).
10.7
Omnibus Securities Plan of Phillips Petroleum Company (incorporated by reference to Exhibit
10.19 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002;
10.8
Key Employee Missed Credited Service Retirement Plan of ConocoPhillips (incorporated by
reference to Exhibit 10.10 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2005; File No. 001-32395).
10.9
Phillips Petroleum Company Stock Plan for Non-Employee Directors (incorporated by reference to
Exhibit 10.22 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).
10.10.1
Amended and Restated ConocoPhillips Key Employee Supplemental Retirement Plan, dated
January 1, 2020 (incorporate by reference to Exhibit 10.10.1 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2019; File No. 001-32395).
10.10.2
Eighth Amendment to Retirement Plans as amended and restated effective January 1, 2016
(incorporated by reference to Exhibit 10.1 to the Quarterly Report of ConocoPhillips on Form 10-Q
for the quarter ended June 30, 2018; File No. 001-32395).
10.11.1
Amended and Restated Defined Contribution Make-Up Plan of ConocoPhillips—Title I, dated
January 1, 2020 (incorporated by reference to Exhibit 10.11.1 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2019; File No. 001-32395).
10.11.2
Amended and Restated Defined Contribution Make-Up Plan of ConocoPhillips—Title II, dated
January 1, 2020 (incorporated by reference to Exhibit 10.11.2 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2019; File No. 001-32395).
10.12
2002 Omnibus Securities Plan of Phillips Petroleum Company (incorporated by reference to Exhibit
10.26 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002;
184
10.15
Deferred Compensation Plan for Non-Employee Directors of ConocoPhillips (incorporated by
reference to Exhibit 10.17 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2005; File No. 001-32395).
10.16.1
Rabbi Trust Agreement dated December 17, 1999 (incorporated by reference to Exhibit 10.11 of the
Annual Report of ConocoPhillips Holding Company on Form 10-K for the year ended
December 31, 1999; File No. 001-14521).
10.16.2
Amendment to Rabbi Trust Agreement dated February 25, 2002 (incorporated by reference to
Exhibit 10.39.1 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).
10.16.3
Phillips Petroleum Company Grantor Trust Agreement, dated June 1, 1998 (incorporated by
reference to Exhibit 10.17.3 to the Annual Report of ConocoPhillips on Form 10-K for the year
ended December 31, 2015; File No. 001-32395).
10.16.4
First Amendment to the Trust Agreement under the Phillips Petroleum Company Grantor Trust
Agreement, dated May 3, 1999 (incorporated by reference to Exhibit 10.17.4 to the Annual Report
of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-32395).
10.16.5
Second Amendment to the Trust Agreement under the Phillips Petroleum Company Grantor Trust
Agreement, dated January 15, 2002 (incorporated by reference to Exhibit 10.17.5 to the Annual
Report of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-
10.16.6
Third Amendment to the Trust Agreement under the Phillips Petroleum Company Grantor Trust
Agreement, dated October 5, 2006 (incorporated by reference to Exhibit 10.17.6 to the Annual
Report of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-
10.16.7
Fourth Amendment to the Trust Agreement under the ConocoPhillips Company Grantor Trust
Agreement, dated May 1, 2012 (incorporated by reference to Exhibit 10.17.7 to the Annual Report
of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-32395).
10.16.8
Fifth Amendment to the Trust Agreement under the ConocoPhillips Company Grantor Trust
Agreement, dated May 20, 2015 (incorporated by reference to Exhibit 10.17.8 to the Annual Report
of ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-32395).
10.17.1
ConocoPhillips Directors’ Charitable Gift Program (incorporated by reference to Exhibit 10.40 to
the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2003;
10.17.2
First and Second Amendments to the ConocoPhillips Directors’ Charitable Gift Program
(incorporated by reference to Exhibit 10 to the Quarterly Report of ConocoPhillips on Form 10-Q
for the quarterly period ended June 30, 2008; File No. 001-32395).
10.18
ConocoPhillips Matching Gift Plan for Directors and Executives (incorporated by reference to
Exhibit 10.41 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2003; File No. 000-49987).
10.19.1
Amended and Restated Key Employee Deferred Compensation Plan of ConocoPhillips—Title I,
dated January 1, 2020 (incorporated by reference to Exhibit 10.19.1 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2019; File No. 001-32395).
185
10.19.2
Amended and Restated Key Employee Deferred Compensation Plan of ConocoPhillips—Title II,
dated January 1, 2020 (incorporated by reference to Exhibit 10.19.2 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2019; File No. 001-32395).
10.20
Amendment and Restatement of ConocoPhillips Key Employee Change in Control Severance Plan,
effective January 1, 2014 (incorporated by reference to Exhibit 10.21 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2013; File No. 001-32395).
10.21
ConocoPhillips Executive Severance Plan (incorporated by reference to Exhibit 10.23 to the Annual
Report of ConocoPhillips on Form 10-K for the year ended December 31, 2008; File No. 001-
10.22.1
2004 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference
to Appendix C of ConocoPhillips’ Proxy Statement on Schedule 14A relating to the 2004 Annual
Meeting of Shareholders; File No. 000-49987).
10.22.2
Form of Stock Option Award Agreement under the Stock Option and Stock Appreciation Rights
Program under the 2004 Omnibus Stock and Performance Incentive Plan of ConocoPhillips
(incorporated by reference to Exhibit 10.26 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2008; File No. 001-32395).
10.22.3
Form of Performance Share Unit Award Agreement under the Performance Share Program under
the 2004 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by
reference to Exhibit 10.27 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2008; File No. 001-32395).
10.23
Omnibus Amendments to certain ConocoPhillips employee benefit plans, adopted December 7,
2007 (incorporated by reference to Exhibit 10.30 to the Annual Report of ConocoPhillips on Form
10-K for the year ended December 31, 2007; File No. 001-32395).
10.24
2009 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference
to Appendix A of ConocoPhillips’ Proxy Statement on Schedule 14A relating to the 2009 Annual
Meeting of Shareholders; File No. 001-32395).
10.25.1
2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference
to Appendix A of ConocoPhillips’ Proxy Statement on Schedule 14A relating to the 2011 Annual
Meeting of Shareholders; File No. 001-32395).
10.25.2
Form of Stock Option Award Agreement under the Stock Option and Stock Appreciation Rights
Program under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips,
effective February 9, 2012 (incorporated by reference to Exhibit 10 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended March 31, 2012; File No. 001-32395).
10.25.3
Form of Restricted Stock Award Agreement under the Restricted Stock Program under the 2011
Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated September 18, 2012
(incorporated by reference to Exhibit 10.26.5 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2012; File No. 001-32395).
10.25.4
Form of Performance Share Unit Agreement under the Restricted Stock Program under the 2011
Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 5, 2013
(incorporated by reference to Exhibit 10.26.6 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2012; File No. 001-32395).
186
10.25.6
Form of Restricted Stock Award Agreement under the Restricted Stock Program under the 2011
Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 5, 2013
(incorporated by reference to Exhibit 10.26.8 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2012; File No. 001-32395).
10.25.7
Form of Stock Option Award Agreement under the Stock Option and Stock Appreciation Rights
Program under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated
February 5, 2013 (incorporated by reference to Exhibit 10.26.9 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2012; File No. 001-32395).
10.25.8
Form of Make-Up Grant Award Agreement under the 2011 Omnibus Stock and Performance
Incentive Plan of ConocoPhillips, dated January 1, 2012 (incorporated by reference to Exhibit 10.1
Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2013;
10.25.9
Form of Key Employee Award Agreement, as part of the ConocoPhillips Stock Option Program
granted under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated
February 18, 2014 (incorporated by reference to Exhibit 10.1 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File No. 001-32395).
10.25.10
Form of Key Employee Award Agreement, as part of the ConocoPhillips Stock Option Program
granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated
February 16, 2016 (incorporated by reference to Exhibit 10.26.12 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-32395).
10.25.11
Form of Key Employee Award Agreement, as part of the ConocoPhillips Restricted Stock Program
granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated
February 16, 2016 (incorporated by reference to Exhibit 10.26.14 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2015; File No. 001-32395).
10.25.12
Form of Performance Period IX Award Agreement, as part of the ConocoPhillips Performance
Share Program granted under the 2011 Omnibus Stock and Performance Incentive Plan of
ConocoPhillips, dated February 18, 2014 (incorporated by reference to Exhibit 10.3 to the Quarterly
Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File No. 001-
10.25.14
Form of Performance Period X Award Agreement, as part of the ConocoPhillips Performance Share
Program granted under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips,
dated February 18, 2014 (incorporated by reference to Exhibit 10.5 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File No. 001-32395).
10.25.17
Form of Inducement Grant Award Agreement under the 2011 Omnibus Stock and Performance
Incentive Plan of ConocoPhillips, dated March 31, 2014 (incorporated by reference to Exhibit 10.11
to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2014; File
10.25.18
Form of Performance Share Unit Award Terms and Conditions for Performance Period 18, as part
of the ConocoPhillips Performance Share Program granted under the 2014 Omnibus Stock and
Performance Incentive Plan of ConocoPhillips, dated February 13, 2018 (incorporated by reference
to Exhibit 10.26.24 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2017; File No. 001-32395).
187
10.26.1
2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference
to Exhibit 10.1 to the Current Report of ConocoPhillips on Form 8-K filed on May 14, 2014; File
10.26.2
Form of Key Employee Award Terms and Conditions, as part of the ConocoPhillips Targeted
Variable Long Term Incentive Program, granted under the 2014 Omnibus Stock and Performance
Incentive Plan of ConocoPhillips, dated September 3, 2015 (incorporated by reference to Exhibit
10.1 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended September 30,
10.26.3
Form of Retention Award Terms and Conditions, as part of the Restricted Stock Unit Award,
granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips
(incorporated by reference to Exhibit 10.1 to the Quarterly Report of ConocoPhillips on Form 10-Q
for the quarter ended March 31, 2015; File No. 001-32395).
10.26.4
Form of Non-Employee Director Restricted Stock Units Terms and Conditions, as part of the
Deferred Compensation Plan for Non-Employee Directors of ConocoPhillips, dated January 15,
2016 (incorporated by reference to Exhibit 10.3 to the Quarterly Report of ConocoPhillips on Form
10-Q for the quarter ended March 31, 2016; File No. 001-32395).
10.26.7
Form of Key Employee Award Terms and Conditions, as part of the ConocoPhillips Stock Option
Program granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips,
dated February 14, 2017 (incorporated by reference to Exhibit 10.1 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended March 31, 2017; File No. 001-32395).
10.26.8
Form of Performance Share Unit Award Terms and Conditions for Performance Period 17, as part
of the ConocoPhillips Performance Share Program granted under the 2014 Omnibus Stock and
Performance Incentive Plan of ConocoPhillips, dated February 14, 2017 (incorporated by reference
to Exhibit 10.2 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended
March 31, 2017; File No. 001-32395).
10.26.9
Form of Performance Share Unit Award Terms and Conditions for Performance Period 17 for
eligible employees on the Canada payroll, as part of the ConocoPhillips Performance Share Program
granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated
February 14, 2017 (incorporated by reference to Exhibit 10.3 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended March 31, 2017; File No. 001-32395).
10.26.10
Form of Key Employee Award Terms and Conditions as part of the ConocoPhillips Restricted Stock
Program granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips,
dated February 14, 2017 (incorporated by reference to Exhibit 10.4 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended March 31, 2017; File No. 001-32395).
10.26.11
Form of Key Employee Award Terms and Conditions as part of the ConocoPhillips Executive
Restricted Stock Unit Program granted under the 2014 Omnibus Stock and Performance Incentive
Plan of ConocoPhillips, dated February 13, 2018 (incorporated by reference to Exhibit 10.27.12 to
the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2017; File No.
10.26.12
Form of Key Employee Award Terms and Conditions for eligible employees on the Canada payroll,
as part of the ConocoPhillips Executive Restricted Stock Unit Program granted under the 2014
Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 13, 2018
(incorporated by reference to Exhibit 10.27.13 to the Annual Report of ConocoPhillips on Form 10-
K for the year ended December 31, 2017; File No. 001-32395).
188
10.26.13
Form of Key Employee Award Terms and Conditions as part of the ConocoPhillips Restricted Stock
Program granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips,
dated February 13, 2018 (incorporated by reference to Exhibit 10.27.14 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2017; File No. 001-32395).
10.26.14
Form of Retention Award Terms and Conditions, 2017 revision, as part of the Restricted Stock Unit
Award, granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips
(incorporated by reference to Exhibit 10.27.15 to the Annual Report of ConocoPhillips on Form 10-
K for the year ended December 31, 2017; File No. 001-32395).
10.26.15
Form of Key Employee Award Terms and Conditions as part of the ConocoPhillips Restricted Stock
Unit Program granted under the 2014 Omnibus Stock and Performance Incentive Plan of
ConocoPhillips, dated February 14, 2019.
10.27
Amended and Restated 409A Annex to Nonqualified Deferred Compensation Arrangements of
ConocoPhillips, dated January 1, 2020 (incorporated by reference to Exhibit 10.27 to the Annual
Report of ConocoPhillips on Form 10-K for the year ended December 31, 2019; File No. 001-
10.28
Amendment, Change of Sponsorship, and Restatement of Certain Nonqualified Deferred
Compensation Plans of ConocoPhillips, dated April 19, 2012 (incorporated by reference to Exhibit
10.10 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012;
10.29
Amendment and Restatement of the Burlington Resources Inc. Management Supplemental Benefits
Plan, dated April 19, 2012 (incorporated by reference to Exhibit 10.9 to the Quarterly Report of
ConocoPhillips on Form 10-Q for the quarter ended June 30, 2012; File No. 001-32395).
10.30
Amendment and Restatement of Deferred Compensation Trust Agreement for Non-Employee
Directors of Phillips Petroleum Company, dated June 23, 1995 (incorporated by reference to Exhibit
10.2 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended March 31, 2016;
10.30.1
Successor Trustee Agreement of the Deferred Compensation Trust Agreement for Non-Employee
Directors of ConocoPhillips dated July 31, 2020 (incorporated by reference to Exhibit 10.1 to the
Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended September 30, 2020; File
10.30.2
First Amendment to the Successor Trust Agreement of the Deferred Compensation Trust Agreement
for Non-Employee Directors of ConocoPhillips, dated August 4, 2020 (incorporated by reference to
Exhibit 10.2 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended
September 30, 2020; File No. 001-32395).
10.31
Indemnification and Release Agreement between ConocoPhillips and Phillips 66, dated April 26,
2012 (incorporated by reference to Exhibit 10.1 to the Current Report of ConocoPhillips on Form 8-
K filed on May 1, 2012; File No. 001-32395).
10.32
Intellectual Property Assignment and License Agreement between ConocoPhillips and Phillips 66,
dated April 26, 2012 (incorporated by reference to Exhibit 10.2 to the Current Report of
ConocoPhillips on Form 8-K filed on May 1, 2012; File No. 001-32395).
189
10.33
Tax Sharing Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012 (incorporated
by reference to Exhibit 10.3 to the Current Report of ConocoPhillips on Form 8-K filed on May 1,
10.34
Employee Matters Agreement between ConocoPhillips and Phillips 66, dated April 12, 2012
(incorporated by reference to Exhibit 10.4 to the Current Report of ConocoPhillips on Form 8-K
filed on May 1, 2012; File No. 001-32395).
10.35
Transition Services Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012
(incorporated by reference to Exhibit 10.5 to the Current Report of ConocoPhillips on Form 8-K
filed on May 1, 2012; File No. 001-32395).
10.36
ConocoPhillips Clawback Policy dated October 3, 2012 (incorporated by reference to Exhibit 10.3
to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended September 30, 2012;
10.37
Term Loan Agreement, between ConocoPhillips, as borrower, ConocoPhillips Company, as
guarantor, Toronto Dominion (Texas) LLC, as administrative agent and the banks party thereto,
with TD Securities (USA) LLC, as lead arranger and bookrunner, dated March 18, 2016
(incorporated by reference to Exhibit 10.1 to the Current Report of ConocoPhillips on Form 8-K
filed on March 21, 2016; File No. 001-32395).
10.38
Company Retirement Contribution Make-Up Plan of ConocoPhillips, dated December 28, 2018
(incorporated by reference to Exhibit 10.39 to the Annual Report of ConocoPhillips on Form 10-K
for the year ended December 31, 2019; File No. 001-32395).
10.40
Form of Key Employee Award Terms and Conditions, as part of the ConocoPhillips Targeted
Variable Long Term Incentive Program, granted under the 2014 Omnibus Stock and Performance
Incentive Plan of ConocoPhillips, dated September 23, 2019 (incorporated by reference to Exhibit
10.1 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended September 30,
10.41
ConocoPhillips Executive Restricted Stock Unit Program, dated February 11, 2020 (incorporated by
reference to Exhibit 10.1 to the Quarter Report of ConocoPhillips on Form 10-Q for the quarter
ended March 31, 2020; File No. 001-32395).
10.42
Letter agreement with Don E. Wallette, Jr. dated August 3, 2020 (incorporated by reference to
Exhibit 10.1 to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarter ended June 30,
21*
List of Subsidiaries of ConocoPhillips.
22
*
Subsidiary Guarantors of Guaranteed Securities
23.1*
23.2*
Consent of DeGolyer and MacNaughton.
31.1*
Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange
31.2*
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange
190
32*
Certifications pursuant to 18 U.S.C. Section 1350.
99*
Report of DeGolyer and MacNaughton.
101.INS*
Inline XBRL Instance Document.
101.SCH*
Inline XBRL Schema Document.
101.CAL*
Inline XBRL Calculation Linkbase Document.
101.DEF*
Inline XBRL Definition Linkbase Document.
101.LAB*
Inline XBRL Labels Linkbase Document.
101.PRE*
Inline XBRL Presentation Linkbase Document.
104*
Cover Page Interactive Data File (formatted as Inline XBRL
and contained in Exhibit
101).
*
Filed herewith.
†
The schedules to this exhibit have been omitted pursuant to Item 601(b)(2) of Regulation S-K.
ConocoPhillips agrees to
furnish a copy of any schedule omitted from this exhibit to the SEC upon request.
‡
ConocoPhillips has previously been granted confidential treatment for certain portions of this exhibit pursuant to Rule 24b-2
under the Securities Exchange Act of 1934, as amended.
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
d123120dex21
1
Exhibit 21
SUBSIDIARY LISTING
OF CONOCOPHILLIPS
Listed below are subsidiaries
of the registrant at December 31,
2020.
Certain subsidiaries are
omitted
since such companies
considered in the aggregate do not constitute
a significant subsidiary.
Company Name
Incorporation
Location
Ashford Energy Capital
Limited
Cayman
Islands
BROG LP LLC
Delaware
Burlington Resources International
Inc.
Delaware
Burlington Resources LLC
Delaware
Burlington Resources Offshore
Inc.
Delaware
Burlington Resources Oil &
Gas Company
LP
Delaware
Burlington Resources Trading
LLC
Delaware
Conoco
Development
Services
Inc.
Delaware
Conoco
Funding Company
Nova Scotia
Conoco
Petroleum Operations Inc.
Delaware
ConocoPhillips (Grissik) Ltd.
Bermuda
ConocoPhillips (U.K.)
Marketing and
Trading Limited
United Kingdom
ConocoPhillips Alaska II, Inc.
Delaware
ConocoPhillips Alaska, Inc.
Delaware
ConocoPhillips Angola 36
Ltd.
Cayman
Islands
ConocoPhillips Angola 37
Ltd.
Cayman
Islands
ConocoPhillips ANS
Marketing Company
Delaware
ConocoPhillips Argentina
Ventures
S.R.L.
Argentina
ConocoPhillips Asia
Venture
s
Pte. Ltd.
Singapore
ConocoPhillips Australia
Investments
Pty Ltd
Australia
ConocoPhillips Australia
Pacific LNG Pty Ltd
Western
Australia
ConocoPhillips Bohai
Limited
Bahamas
ConocoPhillips Canada
(BRC) Partnership
Alberta
ConocoPhillips Canada
Marketing &
Trading ULC
Alberta
ConocoPhillips Canada
Resources Corp.
Alberta
ConocoPhillips China
Inc.
Liberia
ConocoPhillips Chittim
Operating LLC
Delaware
ConocoPhillips Colombia
Ventures
Ltd.
Cayman
Islands
ConocoPhillips Company
Delaware
ConocoPhillips Funding Ltd.
Bermuda
ConocoPhillips Gulf
of Paria B.V.
Netherlands
ConocoPhillips Hamaca
B.V.
Netherlands
ConocoPhillips Indonesia
Holding Ltd.
British Virgin
Islands
ConocoPhillips Libya Waha
Ltd.
Cayman
Islands
ConocoPhillips Norge
Delaware
ConocoPhillips North Caspian
Ltd.
Liberia
ConocoPhillips Norway
Funding Ltd.
Bermuda
2
Company Name
Incorporation
Location
ConocoPhillips Petroleum Holdings
B.V.
Netherlands
ConocoPhillips Qatar
Funding Ltd.
Cayman
Islands
ConocoPhillips Qatar
Ltd.
Cayman
Islands
ConocoPhillips Sabah
Gas Holdings Limited
Cayman
Islands
ConocoPhillips Sabah
Gas Ltd.
Cayman
Islands
ConocoPhillips Sabah
Holdings Limited
Cayman
Islands
ConocoPhillips Sabah
Ltd.
Bermuda
ConocoPhillips Skandinavia
AS
Norway
ConocoPhillips Surmont
Partnership
Alberta
ConocoPhillips Transportation
Alaska, Inc.
Delaware
Inexco
Oil Company
Delaware
Phillips Coal Company
Nevada
Phillips International
Investments, Inc.
Delaware
Phillips Investment
Company LLC
Nevada
Phillips Petroleum
International
Corporation
LLC
Delaware
Phillips Petroleum
International
Investment
Company LLC
Delaware
Polar Tankers,
Inc.
Delaware
Sooner Insurance
Company
Vermont
The Louisiana
Land and Exploration
Company LLC
Maryland
d123120dex22
1
Exhibit 22
SUBSIDIARY GUARANTORS
OF GUARANTEED SECURITIES
Listed below are subsidiaries
serving as an issuer
or guarantor,
as applicable, for outstanding
publicly held
debt securities.
Company Name
Incorporation Location
ConocoPhillips
Delaware
ConocoPhillips Company
Delaware
Burlington Resources LLC
Delaware
d123120dex231
Exhibit 23.1
CONSENT OF INDEPENDENT
REGISTERED
PUBLIC
ACCOUNTING
FIRM
We consent to the incorporation by
reference in the
following Registration Statements:
●
ConocoPhillips
Form
S
-
3
File
No.
333
-
240978
●
ConocoPhillips
Form
S
-
4
File
No.
333
-
130967
●
ConocoPhillips
Form
S
-
4
File
No.
333
-
250183
●
ConocoPhillips
Form
S
-
8
File
No.
333
-
130967
●
ConocoPhillips
Form
S
-
8
File
No.
333
-
98681
●
ConocoPhillips
Form
S
-
8
File
No.
333
-
116216
●
ConocoPhillips
Form
S
-
8
File
No.
333
-
133101
●
ConocoPhillips
Form
S
-
8
File
No.
333
-
159318
●
ConocoPhillips
Form
S
-
8
File
No.
333
-
171047
●
ConocoPhillips
Form
S
-
8
File
No.
333
-
174479
●
ConocoPhillips
Form
S
-
8
File
No.
333
-
196349
●
ConocoPhillips
Form
S
-
8
File
No.
333
-
250183
of our reports dated
February 16, 2021, with respect
to the consolidated
financial statements
of
ConocoPhillips, and the
effectiveness of
internal control over financial reporting
of ConocoPhillips,
included in this
Annual Report (Form 10-K) of ConocoPhillips
for the year ended
December 31, 2020.
/s/ Ernst & Young LLP
Houston, Texas
February 16, 2021
d123120dex232
Exhibit 23.2
DeGolyer
and MacNaughton
5001
Spring
Valley
Road
Suite 800 East
Dallas, Texas 75244
February 16, 2021
ConocoPhillips
925 N. Eldridge Parkway
Houston, Texas 77079
Ladies and
Gentlemen:
We hereby consent to the
use of the name
DeGolyer and
MacNaughton, to
references to
DeGolyer and
MacNaughton
as an independent
petroleum engineering consulting
firm in ConocoPhillips’
Annual Report
on Form 10-K
for the year ended
December 31, 2020, under
the “Part II” heading
“Item 8.
Financial
Statements and
Supplementary Data”
and subheading
“Reserves
Governance”
and under the
“Part IV”
heading “Item 15. Exhibits, Financial
Statement Schedules”
and subheading
“Index to Exhibits,” and
to the
inclusion of our process
review letter report dated
February 16, 2021 (our Report), as
an exhibit to
ConocoPhillips’ Annual Report
on Form 10-K
for the year ended
December 31, 2020.
We also consent
to
the incorporation by reference
of our Report in
the Registration
Statements filed by ConocoPhillips
on Form
S-3
(File No. 333-240978), Form S-4
(File Nos.
333-130967 and
333-250183),
and Form S-8
(File Nos.
333-98681, 333-116216, 333-133101, 333-159318,
333-171047,
333-174479, 333-196349,
333-130967,
and
333-250183).
Very truly yours,
/s/ DeGolyer
and MacNaughton
DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F
-
716
d123120dex311
Exhibit 31.1
CERTIFICATION
I, Ryan
M. Lance, certify that:
1.
I have
reviewed this annual report on Form 10
-K
of ConocoPhillips;
2.
Based on my knowledge,
this report does not contain
any untrue
statement of a material fact
or omit to
state a material
fact
necessary to make the statements made,
in
light of the circumstances
under which
such statements
were
made,
not misleading with respect to the period covered by
this report;
3.
Based on my knowledge,
the financial statements,
and other financial information
included in
this report,
fairly present in all material
respects the financial condition,
results of operations
and cash
flows of the
registrant as of, and
for, the periods presented in this report;
4.
The registrant’s
other certifying
officer and
I are responsible for establishing and
maintaining disclosure
controls and
procedures (as defined in Exchange Act Rules
13a
-15(e) and 15d
-15(e))
and internal control
over financial
reporting (as defined in Exchange
Act Rules 13a
-15(f) and 15d
-15(f))
for the registrant and
have:
(a)
Designed such disclosure
controls and procedures,
or caused
such disclosure controls and
procedures to be designed
under our supervision, to ensure
that
material information
relating to
the
registrant, including its
consolidated
subsidiaries, is made known to us by others within those
entities, particularly during
the period in which this report
is being prepared;
(b)
Designed such internal
control over financial
reporting, or caused such internal control over
financial
reporting to be designed under our
supervision, to provide reasonable
assurance regarding
the reliability of financial
reporting and the preparation
of financial statements for external
purposes in accordance
with
generally accepted
accounting principles;
(c)
Evaluated
the effectiveness of the registrant’s disclosure controls
and procedures
and presented
in
this report our conclusions
about
the effectiveness of the disclosure controls and
procedures, as of
the end of the period covered
by this report based
on such evaluation;
and
(d)
Disclosed in this report any
change in the registrant’s
internal control over
financial
reporting that
occurred during the registrant’s
most recent
fiscal quarter (the registrant’s
fourth fiscal quarter
in
the case of an annual
report) that has
materially affected,
or is reasonably likely to materially
affect,
the registrant’s internal control over financial
reporting; and
5.
The registrant’s
other certifying
officer and
I have disclosed, based on our most
recent evaluation
of
internal control over financial
reporting, to the registrant’s
auditors and
the audit committee
of the
registrant’s board
of directors (or persons performing the
equivalent
functions):
(a)
All significant deficiencies
and material weaknesses
in
the design or operation
of internal control
over financial
reporting which are reasonably
likely to adversely affect
the registrant’s ability to
record, process, summarize
and report financial information;
and
(b)
Any fraud,
whether or not material, that
involves management
or other employees who have a
significant role in the registrant’s
internal control over financial
reporting.
February 16, 2021
/s/ Ryan M.
Lance
Ryan
M. Lance
Chairman
and
Chief Executive Officer
d123120dex312
Exhibit 31.2
CERTIFICATION
I, William L.
Bullock, Jr.,
certify that:
1.
I have
reviewed this annual report on Form 10
-K
of ConocoPhillips;
2.
Based on my knowledge,
this report does not contain
any untrue
statement of a material fact
or omit to
state a material
fact
necessary to make the statements made,
in
light of the circumstances
under which
such statements
were
made,
not misleading with respect to the
period covered by this report;
3.
Based on my knowledge,
the financial statements,
and other financial information
included in
this report,
fairly present in all material
respects the financial condition,
results of operations
and cash
flows of the
registrant as of, and
for, the periods presented in this report;
4.
The registrant’s
other certifying
officer and
I are responsible for establishing and
maintaining disclosure
controls and
procedures (as defined in Exchange Act Rules
13a
-15(e) and 15d
-15(e))
and internal control
over financial
reporting (as defined in Exchange
Act Rules 13a
-15(f) and 15d
-15(f))
for the registrant and
have:
(a)
Designed such disclosure
controls and procedures,
or caused
such disclosure controls and
procedures to be designed
under our supervision,
to ensure that
material information
relating to
the
registrant, including its
consolidated
subsidiaries, is made known to us by others within those
entities, particularly during
the period in which this report
is being prepared;
(b)
Designed such internal
control over financial
reporting, or caused such internal control over
financial
reporting to be designed under our
supervision, to provide reasonable
assurance regarding
the reliability of financial
reporting and the preparation
of financial statements
for external
purposes in accordance
with
generally accepted
accounting principles;
(c)
Evaluated
the effectiveness of the registrant’s disclosure controls
and procedures
and presented
in
this report our conclusions
about
the effectiveness
of the disclosure controls and procedures, as of
the end of the period covered
by this report based
on such evaluation;
and
(d)
Disclosed in this report any
change in the registrant’s
internal control over
financial
reporting that
occurred during the registrant’s
most recent
fiscal quarter (the registrant’s
fourth fiscal quarter
in
the case of an annual
report) that has materially affected,
or is reasonably likely to materially
affect,
the registrant’s internal control over financial
reporting; a
nd
5.
The registrant’s
other certifying
officer and
I have disclosed, based on our most
recent evaluation
of
internal control over financial
reporting, to the registrant’s
auditors and
the audit committee
of the
registrant’s board
of directors (or persons pe
rforming the equivalent
functions):
(a)
All significant deficiencies
and material weaknesses
in
the design or operation
of internal control
over financial
reporting which are reasonably
likely to adversely affect
the registrant’s ability to
record, process, summarize
and report financial information;
and
(b)
Any fraud,
whether or not material, that
involves management
or other employees who have a
significant role in the registrant’s
internal control over financial
reporting.
February 16, 2021
/s/ William
L. Bullock, Jr.
William L. Bullock,
Jr.
Executive Vice
President and
Chief Financial Officer
d123120dex32
Exhibit 32
CERTIFICATIONS
PURSUANT TO 18 U.S.C.
SECTION 1350
In connection
with the Annual Report of ConocoPhillips (the
Company)
on Form 10-K for the period ended
December 31, 2020,
as filed with the U.S. Securities
and Exchange
Commission on the date
hereof (the
Report), each
of the undersigned hereby certifies, pursuant
to 18 U.S.C. Section 1350, as adopted
pursuant to
Section 906 of the Sarbanes
-Oxley
Act of 2002, that
to their
knowledge:
(1)
The Report fully complies with
the requirements of Sections
13(a) or 15(d) of the
Securities
Exchange
Act of 1934; and
(2)
The information
contained in the
Report fairly presents, in
all material respects, the
financial
condition and
results of operations
of the Company.
February 16, 2021
/s/ Ryan M. Lance
Ryan
M. Lance
Chairman
and
Chief Executive Officer
/s/ William
L. Bullock, Jr.
William L. Bullock,
Jr.
Executive Vice
President and
Chief Financial Officer
d123120dex99
Exhibit 99
DeGolyer and
MacNaughton
5001 Spring Valley
Road
Suite 800 East
Dallas, Texas
75244
February 16, 2021
ConocoPhillips
925 N. Eldridge Parkway
Houston,
Texas
77079
Re: SEC Process Review
Ladies and Gentlemen:
Pursuant to your request,
DeGolyer and
MacNaughton
has performed a process review of the
processes and
controls used by ConocoPhillips in preparing its internal estimates
of proved reserves,
as of December 31, 2020. This
process review,
which is contemplated
by Item 1202 (a)(8) of
Regulation S–K of
the United States Securities
and Exchange
Commission (SEC), has been performed
specifically to address the adequacy
and effectiveness of ConocoPhillips’ internal processes
and
controls relative to
its estimation
of proved reserves in compliance
with Rules 4–10(a)
(1)–(32) of
Regulation S–X
of the SEC.
DeGolyer and
MacNaughton
has participated as an independent
member of the internal
ConocoPhillips Reserves
Compliance
Assessment Team
in
reviews and
discussions with each
of the
relevant ConocoPhillips
business units relative to SEC
proved reserves estimation.
DeGolyer and
MacNaughton
has participated in the review of all major
fields in all countries in which
ConocoPhillips holds proved
reserves worldwide. ConocoPhillips
has indicated
that
these reserves
represent over 90 percent of
its estimated
total proved reserves as of December 31, 2020.
The reviews with ConocoPhillips’
technical staff
involved presentations
and discussions of a) basic
reservoir data,
including
seismic data,
well-log
data,
pressure and production
tests, core analysis,
pressure-volume
-temperature data, and production
history, b) technical methods
employed in SEC
proved reserves estimation,
including performance
analysis,
geology, mapping,
and volumetric
estimates, c) economic
analysis, and d) commercial assessment,
including
the legal
basis for the
interest in the reserves, primarily
related to lease agreements
and other petroleum
license
agreements,
such as concession
and production
sharing
agre
ements.
ConocoPhillips
February 16, 2021
Page 2 of 2
A field examination
was not considered necessary
for the purposes of this review of ConocoPhillips’
processes and
controls.
It is DeGolyer and
MacNaughton’s
opinion that
ConocoPhillips’
estimates
of proved reserves for the
properties reviewed were
prepared
by the use of recognized geologic and
engineering methods
generally accepted
by the petroleum industry.
The method
or combination of methods
used in
the
analysis of each
reservoir was tempered
by ConocoPhillips’ experience with similar reservoirs,
stage
of development,
quality and
completeness of basic data, and
production history. It is DeGolyer and
MacNaughton’s
opinion that
the general processes and controls employed
by ConocoPhillips in
estimating its December
31, 2020, proved
reserves for the properties reviewed are
in accordance
with
the SEC reserves definitions.
This process review of ConocoPhillips’
procedures and
methods
does not constitute
a review, study,
or independent
audit of ConocoPhillips’ estimated
proved reserves and corresponding future
net
revenues. This process review is not
intended to indicate that
DeGolyer
and MacNaughton
is
offering
any opinion as to the
reasonableness
of the reserves estimates reported by ConocoPhillips.
DeGolyer and
MacNaughton
is
an independent
petroleum engineering
consulting firm that
has been
providing petroleum consulting
services throughout
the world since 1936. Neither DeGolyer and
MacNaughton
nor any employee
who participated in this project has any
financial interest, including
stock ownership, in
ConocoPhillips. DeGolyer and
MacNaughton’s
fees were not contingent on the
results of its evaluation.
Very
truly yours,
/s/ DeGolyer and
MacNaughton
DeGOLYER
and MacNAUGHTON
Texas
Registered Engineering Firm F-716
/s/ Charles
F. Boyette
Charles F.
Boyette,
P.E.
President
and COO
DeGolyer and MacNaughton